After a regulatory action has been completed, Executive Order 12866 requires agencies 

to identify the substantive changes between the draft submitted to Office of Information 

and Regulatory Affairs (OIRA) for review and the action subsequently announced, and to 

identify those changes made at the suggestion or recommendation of OIRA. The 

document below provides more information.
1

[6450-01-P]

DEPARTMENT OF ENERGY

10 CFR Part 431

[Docket No. EERE–2010–BT–STD–0048]

RIN: 1904-AC04

Energy Conservation Program: Energy Conservation Standards for Distribution 

Transformers

AGENCY: Office of Energy Efficiency and Renewable Energy, Department of Energy.

ACTION: Final rule.

SUMMARY: The Energy Policy and Conservation Act of 1975 (EPCA), as amended, 

prescribes energy conservation standards for various consumer products and certain 

commercial and industrial equipment, including distribution transformers. EPCA also 

requires the U.S. Department of Energy (DOE) to determine whether more-stringent 

standards would be technologically feasible and economically justified, and would save a 

significant amount of energy. In this final rule, DOE is adopting more-stringent energy 

conservation standards for distribution transformers. It has determined that the amended 

energy conservation standards for this equipment would result in significant conservation 

of energy, and are technologically feasible and economically justified. 
2

DATES: The effective date of this rule is [INSERT DATE 60 DAYS AFTER DATE 

OF PUBLICATION IN THE FEDERAL REGISTER]. 

Compliance with the amended standards established for distribution transformers in this

final rule is required as of January 1, 2016.

ADDRESSES: The docket for this rulemaking is available for review at 

www.regulations.gov, including Federal Register notices, framework documents, public 

meeting attendee lists and transcripts, comments, negotiated rulemaking, and other 

supporting documents/materials. All documents in the docket are listed in the 

www.regulations.gov index. However, not all documents listed in the index may be 

publicly available, such as information that is exempt from public disclosure. 

A link to the docket web page can be found at: 

http://www.regulations.gov/#!docketDetail;rpp=10;po=0;D=EERE-2010-BT-STD-0048. 

The regulations.gov web page will contain simple instructions on how to access all 

documents, including public comments, in the docket.

For further information on how to review the docket, contact Ms. Brenda Edwards 

at (202) 586-2945 or by email: Brenda.Edwards@ee.doe.gov.

FOR FURTHER INFORMATION CONTACT: 
3

James Raba, U.S. Department of Energy, Office of Energy Efficiency and 

Renewable Energy, Building Technologies Program, EE-2J, 1000 Independence Avenue, 

SW., Washington, DC, 20585-0121. Telephone: (202) 586-8654. E-mail: 

Distribution_Transformers@ee.doe.gov.

Ami Grace-Tardy, U.S. Department of Energy, Office of the General Counsel, 

GC-71, 1000 Independence Avenue, SW., Washington, DC, 20585-0121. Telephone: 

(202) 586-5709. E-mail: Ami.Grace-Tardy@hq.doe.gov.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Summary of the Final Rule and Its Benefits

A. Benefits and Costs to Customers

B. Impact on Manufacturers

C. National Benefits

D. Conclusion

II. Introduction

A. Authority

B. Background

1. Current Standards

2. History of Standards Rulemaking for Distribution Transformers

III. General Discussion

A. Test Procedures

1. General

2. Multiple kVA Ratings

3. Dual/Multiple Basic Impulse Level

4. Dual/Multiple-Voltage Primary Windings

5. Dual/Multiple-Voltage Secondary Windings

6. Loading

B. Technological Feasibility

1. General

2. Maximum Technologically Feasible Levels

C. Energy Savings
4

1. Determination of Savings

2. Significance of Savings

D. Economic Justification

1. Specific Criteria

a. Economic Impact on Manufacturers and Consumers

b. Life-Cycle Costs

c. Energy Savings

d. Lessening of Utility or Performance of Equipment

e. Impact of Any Lessening of Competition

f. Need for National Energy Conservation

g. Other Factors

2. Rebuttable Presumption

IV. Methodology and Discussion of Related Comments

A. Market and Technology Assessment

1. Scope of Coverage

a. Definitions

b. Underground and Surface Mining Transformer Coverage

c. Step-Up Transformers

d. Low-Voltage Dry-Type Distribution Transformers

e. Negotiating Committee Discussion of Scope

2. Equipment Classes

a. Less-Flammable Liquid-Immersed Transformers

b. Pole-Mounted Liquid-Immersed Distribution Transformers

c. Network and Vault Liquid-Immersed Distribution Transformers

d. BIL Ratings in Liquid-Immersed Distribution Transformers

e. Data Center Transformers

f. Noise and Vibration

g. Multivoltage Capability

h. Consumer Utility

3. Technology Options

a. Core Deactivation

b. Symmetric Core

c. Intellectual Property

d. Core Construction Technique

B. Screening Analysis

1. Nanotechnology Composites

C. Engineering Analysis

1. Engineering Analysis Methodology

2. Representative Units

3. Design Option Combinations

4. A and B Loss Value Inputs

5. Materials Prices

6. Markups

a. Factory Overhead
5

b. Labor Costs

c. Shipping Costs

7. Baseline Efficiency and Efficiency Levels

8. Scaling Methodology

a. kVA Scaling

b. Phase Count Scaling

9. Material Availability

10. Primary Voltage Sensitivities

11. Impedance

12. Size and Weight

D. Markups Analysis

E. Energy Use Analysis

F. Life-Cycle Cost and Payback Period Analysis

1. Modeling Transformer Purchase Decision

2. Inputs Affecting Installed Cost

a. Equipment Costs

b. Installation Costs

3. Inputs Affecting Operating Costs

a. Transformer Loading

b. Load Growth Trends

c. Electricity Costs

d. Electricity Price Trends

e. Standards Compliance Date

f. Discount Rates

g. Lifetime

h. Base Case Efficiency

i. Inputs to Payback Period Analysis

j. Rebuttable-Presumption Payback Period

G. National Impact Analysis—National Energy Savings and Net Present Value 

Analysis

1. Shipments

2. Efficiency Trends

3. National Energy Savings

4. Equipment Price Forecast

5. Net Present Value of Customer Benefit

H. Customer Subgroup Analysis

I. Manufacturer Impact Analysis

1. Overview

2. Product and Capital Conversion Costs

a. Product Conversion Costs

b. Capital Conversion Costs

3. Markup Scenarios

4. Other Key GRIM Inputs

5. Discussion of Comments
6

a. Core Steel

b. Small Manufacturers

c. Conversion Costs

6. Manufacturer Interviews

7. Sub-Group Impact Analysis

J. Employment Impact Analysis

K. Utility Impact Analysis

L. Emissions Analysis

M. Monetizing Carbon Dioxide and Other Emissions Impacts

1. Social Cost of Carbon

a. Monetizing Carbon Dioxide Emissions

b. Social Cost of Carbon Values Used in Past Regulatory Analyses

c. Current Approach and Key Assumptions

2. Valuation of Other Emissions Reductions

N. Labeling Requirements

O. Discussion of Other Comments

1. Supplementary Trial Standard Levels

2. Efficiency Levels

3. Impact of Standards on Transformer Refurbishment

4. Alternative Means of Saving Energy

5. Alternative Rulemaking Procedures

6. Proposed Standards — Weighting of Benefits vs. Burdens

a. General Comments

b. Standards on Liquid-Immersed Distribution Transformers

c. Standards on Low-Voltage Dry-Type Distribution Transformers

d. Standards on Medium-Voltage Dry-Type Distribution Transformers

e. Response to Comments on Standards Proposed in Notice of Proposed 

Rulemaking

V. Analytical Results and Conclusions

A. Trial Standard Levels

B. Economic Justification and Energy Savings

1. Economic Impacts on Customers

a. Life-Cycle Cost and Payback Period

b. Customer Subgroup Analysis

c. Rebuttable Presumption Payback

2. Economic Impact on Manufacturers

a. Industry Cash-Flow Analysis Results

b. Impacts on Employment

c. Impacts on Manufacturing Capacity

d. Impacts on Subgroups of Manufacturers

e. Cumulative Regulatory Burden

3. National Impact Analysis

a. Significance of Energy Savings

b. Net Present Value of Customer Costs and Benefits
7

c. Indirect Impacts on Employment

4. Impact on Utility or Performance of Equipment

5. Impact of Any Lessening of Competition

6. Need of the Nation to Conserve Energy

7. Summary of National Economic Impacts

8. Other Factors

C. Conclusion

1. Benefits and Burdens of Trial Standard Levels Considered for Liquid-Immersed 

Distribution Transformers

2. Benefits and Burdens of Trial Standard Levels Considered for Low-Voltage DryType Distribution Transformers

3. Benefits and Burdens of Trial Standard Levels Considered for Medium-Voltage 

Dry-Type Distribution Transformers

4. Summary of Benefits and Costs (Annualized) of Today’s Standards

VI. Procedural Issues and Regulatory Review

A. Review Under Executive Orders 12866 and 13563

B. Review Under the Regulatory Flexibility Act

1. Statement of the need for, and objectives of, the rule

2. Summary of and responses to the significant issues raised by the public 

comments, and a statement of any changes made as a result of such comments

3. Description and Estimated Number of Small Entities Regulated

a. Methodology for Estimating the Number of Small Entities

b. Distribution Transformer Industry Structure

c. Comparison between Large and Small Entities

4. Description and Estimate of Compliance Requirements

a. Liquid-Immersed

b. Low-Voltage Dry-Type.

c. Medium-Voltage Dry-Type.

d. Summary of Compliance Impacts

5. Steps Taken to Minimize Impacts on Small Entities and Reasons Why Other 

Significant Alternatives to Today’s Final Rule Were Rejected

6. Duplication, Overlap, and Conflict with Other Rules and Regulations

7. Significant Alternatives to Today’s Rule

8. Significant Issues Raised by Public Comments

9. Steps DOE Has Taken to Minimize the Economic Impact on Small 

Manufacturers

C. Review Under the Paperwork Reduction Act

D. Review Under the National Environmental Policy Act of 1969

E. Review Under Executive Order 13132

F. Review Under Executive Order 12988

G. Review Under the Unfunded Mandates Reform Act of 1995

H. Review Under the Treasury and General Government Appropriations Act, 1999

I. Review Under Executive Order 12630

J. Review Under the Treasury and General Government Appropriations Act, 2001
8

K. Review Under Executive Order 13211

L. Review Under the Information Quality Bulletin for Peer Review

M. Congressional Notification

VII. Approval of the Office of the Secretary

I. Summary of the Final Rule and Its Benefits

Title III, Part B of the Energy Policy and Conservation Act of 1975 (EPCA or the 

Act), Pub. L. 94-163 (42 U.S.C. 6291-6309, as codified), established the Energy 

Conservation Program for Consumer Products Other Than Automobiles. Part C of Title 

III of EPCA (42 U.S.C. 6311–6317) established a similar program for “Certain Industrial 

Equipment,” including distribution transformers.1

Table I.1

Pursuant to EPCA, any new or 

amended energy conservation standard that DOE prescribes for certain equipment, such 

as distribution transformers, shall be designed to achieve the maximum improvement in 

energy efficiency that DOE determines is technologically feasible and economically 

justified. (42 U.S.C. 6295(o)(2)(A), 6316(a)) Furthermore, any new or amended standard 

must result in significant conservation of energy. (42 U.S.C. 6295(o)(3)(B), 6316(a)) In 

accordance with these and other statutory provisions addressed in this rulemaking, DOE 

is adopting amended energy conservation standards for distribution transformers. The 

amended standards are summarized in through Table I.3. Table I.4 shows the 

mapping of trial standard levels (TSLs) to energy efficiency levels (ELs)2

, and Table I.5

through Table I.8 show the standards in terms of minimum electrical efficiency. These 

 1 For editorial reasons, upon codification in the U.S. Code, Parts B and C were redesignated as Parts A and 

A-1, respectively. 2 A detailed description of the mapping of trial standard level to energy efficiency levels can be found in 

the Technical Support Document, chapter 10 section 10.2.2.3.
9

amended standards apply to all equipment that is listed in Table I.1 and manufactured in, 

or imported into, the United States on or after January 1, 2016. As discussed in section 

IV.C.8 of this notice, any distribution transformer having a kilovolt-ampere (kVA) rating 

falling between the kVA ratings shown in the tables shall meet a minimum energy 

efficiency level calculated by a linear interpolation of the minimum efficiency 

requirements of the kVA ratings immediately above and below that rating.3

For the reasons discussed in this preamble, particularly in Section V, DOE is 

adopting TSL 1 for liquid-immersed distribution transformers. DOE acknowledges the 

input of various stakeholders in support of a more stringent energy conservation standard 

for liquid-immersed distribution transformers. DOE notes that the potential for 

significant disruption in the steel supply market at higher efficiency levels was a key 

element in adopting TSL 1 in this rulemaking. DOE will monitor the steel and liquidimmersed distribution transformer markets and by no later than 2016, determine whether 

interim changes to market conditions, particularly the supply chain for amorphous steel, 

justify re-evaluating the efficiency standards adopted in today’s rulemaking.

Although DOE proposed TSL 1 for low-voltage dry-type distribution 

transformers, DOE is adopting in this final rule TSL 2 for such transformers for the 

reasons discussed in greater detail in Section IV.I.5.B. DOE acknowledges that various 

 3 kVA, an abbreviation for kilovolt-ampere, is a capacity metric used by industry to classify transformers. A 

transformer’s kVA rating represents its output power when it is fully loaded (i.e., 100 percent).
10

stakeholders argued that concerns regarding small manufacturers should not be a barrier 

to adopting TSL 3 because small manufacturers have the option of either sourcing cores 

from third parties or investing in mitering machines. DOE will monitor the low-voltage 

dry-type distribution transformer market, and by no later than 2016, determine whether 

market conditions justify re-evaluating the efficiency standards adopted in today’s 

rulemaking.

Table I.1. Energy Conservation Standards for Liquid-Immersed Distribution 

Transformers (Compliance Starting January 1, 2016)

Equipment 

Classes Design Line Type Phase Count BIL* AdoptedTSL

1 1, 2 and 3 Liquid-immersed 1 All 1

2 4 and 5 Liquid-immersed 3 All 1

* BIL means “basic impulse insulation level” and measures how resistant a transformer’s insulation is to 

large voltage transients.

Table I.2. Energy Conservation Standards for Low-Voltage Dry-Type Distribution 

Transformers (Compliance Starting January 1, 2016)

Equipment 

Class Design Line Type Phase Count BIL* AdoptedTSL

3 6 Low-voltage dry-type 1 ≤ 10 kV 2

4 7 and 8 Low-voltage dry-type 3 ≤ 10 kV 2

* BIL means “basic impulse insulation level” and measures how resistant a transformer’s insulation is to 

large voltage transients.

Table I.3. Energy Conservation Standards for Medium-Voltage Dry-Type

Distribution Transformers (Compliance Starting January 1, 2016)

Equipment 

Class

Design Line Type Phase 

Count BIL* AdoptedTSL

5 9 and 10 Medium-voltage dry-type 1 25-45 kV 2

6 9 and 10 Medium-voltage dry-type 3 25-45 kV 2

7 11 and 12 Medium-voltage dry-type 1 46-95 kV 2

8 11 and 12 Medium-voltage dry-type 3 46-95 kV 2

9 13A and 13B Medium-voltage dry-type 1 ≥96 kV 2

10 13A and 13B Medium-voltage dry-type 3 ≥96 kV 2

* BIL means “basic impulse insulation level” and measures how resistant a transformer’s insulation is to 

large voltage transients.

Comment [A1]: Change recommended by OMB.
11

Table I.4. Trial Standard Level to Energy Efficiency Level Mapping for 

Distribution Transformer Energy Conservation Standards

Type Design 

Line

Phase 

Count TSL Energy Efficiency Level Efficiency (%)

Liquidimmersed

1 1

1

1 (0.4 actual)* 99.11

2 1 Base (0.5 actual)* 98.95

3 1 1 (1.1 actual)* 99.49

4 3 1 99.16

5 3 1 99.48

Low-voltage 

dry-type

6 1

2

Base 98.00

7 3 3 98.60

8 3 2 99.02

Mediumvoltage drytype

9 3

2

1 98.93

10 3 2 99.37

11 3 1 98.81

12 3 2 99.30

13A 3 1 98.69

13B 3 2 99.28

* Because of scaling, actual efficiency values unavoidably differ from nominal EL values.
12

Table I.5 Electrical Efficiencies for All Liquid-Immersed Distribution Transformer 

Equipment Classes (Compliance Starting January 1, 2016)

Standards by kVA and Equipment Class

Equipment Class 1 Equipment Class 2

kVA % kVA %

10 98.70 15 98.65

15 98.82 30 98.83

25 98.95 45 98.92

37.5 99.05 75 99.03

50 99.11 112.5 99.11

75 99.19 150 99.16

100 99.25 225 99.23

167 99.33 300 99.27

250 99.39 500 99.35

333 99.43 750 99.40

500 99.49 1,000 99.43

667 99.52 1,500 99.48

833 99.55 2,000 99.51

2,500 99.53

Table I.6 Electrical Efficiencies for All Low-Voltage Dry-Type Distribution 

Transformer Equipment Classes (Compliance Starting January 1, 2016)

Standards by kVA and Equipment Class

Equipment Class 3 Equipment Class4

kVA % kVA %

15 97.70 15 97.89

25 98.00 30 98.23

37.5 98.20 45 98.40

50 98.30 75 98.60

75 98.50 112.5 98.74

100 98.60 150 98.83

167 98.70 225 98.94

250 98.80 300 99.02

333 98.90 500 99.14

750 99.23

1,000 99.28
13

Table I.7 Electrical Efficiencies for All Medium-Voltage Dry-Type Distribution 

Transformer Equipment Classes (Compliance Starting January 1, 2016)

Standards by kVA and Equipment Class

Equipment 

Class 5

Equipment 

Class 6

Equipment 

Class 7

Equipment 

Class 8

Equipment 

Class 9

Equipment 

Class 10

kVA % kVA % kVA % kVA % kVA % kVA %

15 98.10 15 97.50 15 97.86 15 97.18

25 98.33 30 97.90 25 98.12 30 97.63

37.5 98.49 45 98.10 37.5 98.30 45 97.86

50 98.60 75 98.33 50 98.42 75 98.13

75 98.73 112.5 98.52 75 98.57 112.5 98.36 75 98.53

100 98.82 150 98.65 100 98.67 150 98.51 100 98.63

167 98.96 225 98.82 167 98.83 225 98.69 167 98.80 225 98.57

250 99.07 300 98.93 250 98.95 300 98.81 250 98.91 300 98.69

333 99.14 500 99.09 333 99.03 500 98.99 333 98.99 500 98.89

500 99.22 750 99.21 500 99.12 750 99.12 500 99.09 750 99.02

667 99.27 1,000 99.28 667 99.18 1,000 99.20 667 99.15 1,000 99.11

833 99.31 1,500 99.37 833 99.23 1,500 99.30 833 99.20 1,500 99.21

2,000 99.43 2,000 99.36 2,000 99.28

2,500 99.47 2,500 99.41 2,500 99.33

A. Benefits and Costs to Customers4

Table I.8 summarizes DOE’s evaluation of the economic impacts of today’s 

standards on customers who purchase distribution transformers, as measured by the 

average life-cycle cost (LCC) savings and the median payback period (PBP). DOE 

measures the impacts of standards relative to a base case that reflects likely trends in the 

distribution transformer market in the absence of amended standards. The base case 

predominantly consists of products at the baseline efficiency levels evaluated for each 

representative unit, which correspond to the existing energy conservation standards for 

 4 For purposes of this document, the “consumers” of distribution transformers are referred to as 

“customers.” Customers refer to electric utilities in the case of liquid-immersed transformers, and to 

utilities and building owners in the case of dry-type transformers.
14

distribution transformers. (Throughout this document, “distribution transformers” are also 

referred to as simply “transformers.”)

Table I.8 Impacts of Today’s Standards on Customers of Distribution Transformers

Design Line Average LCC Savings Median Payback Period 

2011$

Liquid-Immersed

years

1 72 18.2

2 66 5.9

3 2,753 8.6

4 967 7.0

5 4,289 6.3

Low-voltage dry-type**

6 N/A* N/A*

7 1,678 3.6

8 2,588 7.7

Medium-voltage dry-type

9 787 2.6

10 4,455 8.6

11 996 10.6

12 6,790 8.5

13A -27 16.1

13B 4,346 12.2

*No customers are impacted by today’s standard because there is no change from the minimum efficiency 

standard for design line 6.

** See section IV.A.3.d for discussion of core construction technique.

B.

The industry net present value (INPV) is the sum of the discounted cash flows to 

the industry from the base year through the end of the analysis period (2012 to 2045). 

Using a real discount rate of 7.4 percent for liquid-immersed distribution transformers, 9 

percent for medium-voltage dry-type distribution transformers, and 11.1 percent for lowvoltage dry-type distribution transformers, DOE estimates that the INPV for 

manufacturers of liquid-immersed, medium-voltage dry-type, and low-voltage dry-type

Impact on Manufacturers

Comment [A2]: Change recommended by OMB.
15

distribution transformers is $575.1 million, $68.7 million, and $237.6 million, 

respectively, in 2011$. Under the standards of today’s rule, DOE expects that 

manufacturers of liquid-immersed units may lose as much as 8.4 percent of their INPV, 

which is approximately $48.2 million; medium-voltage manufacturers may lose as much 

as 4.2 percent of their INPV, which is approximately $2.9 million; and low-voltage 

manufacturers may lose as much as 4.7 percent of their INPV, which is approximately 

$11.1 million. Additionally, based on DOE’s interviews with the manufacturers of 

distribution transformers, DOE does not expect any plant closings or significant loss of 

employment.

C.

DOE’s analyses indicate that today’s standards would save a significant amount 

of energy. The lifetime savings for equipment purchased in the 30-year period that begins 

in the year of compliance with amended standards (2016–2045) amounts to 3.63 quads. 

This is equivalent to 3.7 percent of total U.S. energy use in 2011.

National Benefits

The cumulative net present value (NPV) of total customer costs and savings of

today’s standards for distribution transformers, in 2011$, ranges from $3.4 billion (at a 7-

percent discount rate) to $12.9 billion (at a 3-percent discount rate). This NPV expresses 

the estimated total value of future operating-cost savings minus the estimated increased 

equipment costs for equipment purchased in 2016–2045, discounted to 2012. 

Comment [A3]: Change recommended by OMB.
16

In addition, today’s standards would have significant environmental benefits. The 

energy savings would result in cumulative emission reductions of 264.7 million metric 

tons (Mt)5 of carbon dioxide (CO2), 223.3.thousand tons of nitrogen oxides (NOX), 182.9

thousand tons of sulfur dioxide (SO2), and 0.6 ton of mercury (Hg).6

The value of the CO2 reductions is calculated using a range of values per metric 

ton of CO2 (otherwise known as the Social Cost of Carbon, or SCC) developed by a 

recent interagency process. The derivation of the SCC values is discussed in section 

IV.M. DOE estimates the net present monetary value of the CO2 emissions reduction is 

between $0.80 billion and $13.31 billion, expressed in 2011$ and discounted to 2012. 

DOE also estimates the net present monetary value of the NOX emissions reduction, 

expressed in 2011$ and discounted to 2012, is $93.2 million at a 7-percent discount rate 

and $234.1 million at a 3-percent discount rate.7

Table I.9 summarizes the national economic costs and benefits expected to result 

from today’s standards for distribution transformers.

 5 A metric ton is equivalent to 1.1 short tons. Results for NOX and Hg are presented in short tons. 6 DOE calculated emissions reductions relative to the Annual Energy Outlook (AEO) 2011 Reference case, 

which incorporated projected effects of all emissions regulations promulgated as of January 31, 2011, 

including the Clean Air Interstate Rule (CAIR, 70 FR 25162 (May 12, 2005)). Subsequent regulations, 

including the CAIR replacement rule, the Cross-State Air Pollution Rule (76 FR 48208 (August 8, 2011)), 

do not appear in the projection.

7 DOE has decided to await further guidance regarding consistent valuation and reporting of Hg emissions 

before it monetizes Hg in its rulemakings.
17

Table I.9 Summary of National Economic Benefits and Costs of Distribution 

Transformer Energy Conservation Standards

Category

Present 

Value

Billion 

2011$

Discount 

Rate

%

Benefits

Operating Cost Savings 6.30 7

18.2 3

CO2 reduction monetized value ($4.9/t case)* 0.80 5

CO2 reduction monetized value ($22.3/t case)* 4.38 3

CO2 reduction monetized value ($36.5/t case)* 7.51 2.5

CO2 reduction monetized value ($67.6/t case)* 13.31 3

NOX reduction monetized value ($2,591/ton)** 0.09 7

0.23 3

Total benefits†

10.77 7

22.8 3

Costs

Incremental installed costs 2.89 7

5.22 3

Net Benefits

Including CO2 and NOX reduction monetized value 7.88 7

17.6 3

* The CO2 values represent global monetized values of the SCC in 2011$ in 2011 under several scenarios. 

The values of $4.9, $22.3, and $36.5/per metric ton (t) are the averages of SCC distributions calculated 

using 5%, 3%, and 2.5% discount rates, respectively. The value of $67.6/t represents the 95th percentile of 

the SCC distribution calculated using a 3% discount rate. The SCC time series used by DOE incorporate an 

escalation factor.

** The value represents the average of the low and high NOX values used in DOE’s analysis.

† Total benefits for both the 3% and 7% cases are derived using the series corresponding to SCC value of 

$22.3/t.

The benefits and costs of today’s standards, for equipment sold in 2016-2045, can 

also be expressed in terms of annualized values. The annualized monetary values are the 

sum of: (1) the annualized national economic value of the benefits from customer 

operation of equipment that meets today’s standards (consisting primarily of operating 
18

cost savings from using less energy, minus increases in equipment purchase and 

installation costs, which is another way of representing customer NPV), and (2) the 

annualized monetary value of the benefits of emission reductions, including CO2

emission reductions.8

Although combining the values of operating cost savings and CO2 emission 

reductions provides a useful perspective, two issues should be considered. First, the 

national operating cost savings are domestic U.S. customer monetary savings that occur 

as a result of market transactions, whereas the value of CO2 reductions is based on a 

global value. Second, the assessments of operating cost savings and CO2 savings are 

performed using different methods that employ different time frames for analysis. The 

national operating cost savings is measured for the lifetime of distribution transformers 

shipped in 2016 –2045. The SCC values, on the other hand, reflect the present value of 

some future climate-related impacts resulting from the emission of one ton of carbon 

dioxide in each year. Those impacts continue well beyond 2100.

Estimates of annualized benefits and costs of today’s standards are shown in 

Table I.10. The results under the primary estimate are as follows. (All monetary values 

 8 DOE used a two-step calculation process to convert the time-series of costs and benefits into annualized 

values. First, DOE calculated a present value in 2012, the year used for discounting the NPV of total 

consumer costs and savings, for the time-series of costs and benefits using discount rates of three and seven 

percent for all costs and benefits except for the value of CO2 reductions. For the latter, DOE used a range of 

discount rates, as shown in Table I.10. From the present value, DOE then calculated the fixed annual 

payment over a 30-year period (2016 through 2045) that yields the same present value. The fixed annual 

payment is the annualized value. Although DOE calculated annualized values, this does not imply that the 

time-series of cost and benefits from which the annualized values were determined is a steady stream of

payments.
19

below are expressed in 2011$.) Using a 7-percent discount rate for benefits and costs 

(other than CO2 reduction, for which DOE used a 3-percent discount rate along with the 

SCC series corresponding to a value of $22.3/ton in 2011), the cost of the standards in 

today’s rule is $266 million per year in increased equipment costs, while the benefits are 

$581 million per year in reduced equipment operating costs, $237 million in CO2

reductions, and $8.60 million in reduced NOX emissions. In this case, the net benefit 

amounts to $561 million per year. Using a 3-percent discount rate for all benefits and 

costs (and the SCC series corresponding to a value of $22.3/ton in 2011), the cost of the 

standards in today’s rule is $282 million per year in increased equipment costs, while the 

benefits are $983 million per year in reduced operating costs, $237 million in CO2

reductions, and $12.67 million in reduced NOX emissions. In this case, the net benefit 

amounts to $950 million per year.

Table I.10 Annualized Benefits and Costs of Amended Standards for Distribution 

Transformers Sold in 2016–2045

Discount 

Rate

%

Primary 

Estimate*

Low Net 

Benefits 

Estimate*

High Net 

Benefits 

Estimate*

Million 2011$/year

Benefits

Operating cost savings

7% 581 559 590

3% 983 930 1003
20

CO2 reduction monetized value 

($4.9/t case)** 5% 57.7 57.7 57.7

CO2 reduction monetized value 

($22.3/t case)** 3% 237 237 237

CO2 reduction monetized value 

($36.5/t case)** 2.5% 377 377 377

CO2 reduction monetized value 

($67.6/t case)** 3% 721 721 721

NOX reduction monetized value 

($2,591/ton)**

7% 8.60 8.60 8.60

3% 12.67 12.67 12.67

Total benefits†

7% plus CO2 

range

648 to 1311 625 to 1288 656 to 1319

7% 827 805 836

3% plus CO2 

range

1053 to 1716 1000 to 1663 1074 to 1737

3% 1233 1179 1253

Costs

Incremental equipment costs

7% 266 300 257

3% 282 325 271

Net Benefits

Total†

7% plus CO2 

range

385381 to 

10481044

329325 to 

992988

404400 to 

10671063

7% 561 504 579

3% plus CO2 

range

771 to 1434 675 to 1338 803 to 1466

3% 950 854 982

Comment [A4]: Change recommended by OMB.
21

* This table presents the annualized costs and benefits associated with transformers shipped in 2016−2045. 

These results include benefits to customers that accrue after 2045 from equipment purchased in 2016 −2045. 

Costs incurred by manufacturers, some of which may be incurred in preparation for the rule, are not 

directly included, but are indirectly included as part of incremental equipment costs. The Primary, Low 

Benefits, and High Benefits estimates utilize projections of energy prices from the AEO2012

** The CO2 values represent global monetized values of the SCC, in 2011$, in 2011 under several 

scenarios. The values of $4.9, $22.3, and $36.5 per metric ton are the averages of SCC distributions 

calculated using 5%, 3%, and 2.5% discount rates, respectively. The value of $67.6/t represents the 95th

percentile of the SCC distribution calculated using a 3% discount rate. The SCC time series used by DOE 

incorporate an escalation factor. The value for NOX (in 2011$) is the average of the low and high values 

used in DOE’s analysis.

Reference 

case, Low Estimate, and High Estimate, respectively. In addition, incremental equipment costs reflect a 

constant equipment price trend in the Primary Estimate, an increasing price trend in the Low Benefits 

Estimate, and a declining price trend in the High Benefits Estimate. The methods used to derive projected 

price trends are explained in section IV.F.2.

† Total Benefits for both the 3% and 7% cases are derived using the series corresponding to SCC value of 

$22.3/t. In the rows labeled “7% plus CO2 range” and “3% plus CO2 range,” the operating cost and NOX

benefits are calculated using the labeled discount rate, and those values are added to the full range of CO2

values.

D.

Based on the analyses culminating in this final rule, DOE found the benefits to the 

nation of the standards (energy savings, consumer LCC savings, positive NPV of 

customer benefit, and emission reductions) outweigh the burdens (loss of INPV and LCC 

increases for some users of this equipment). DOE has concluded that the standards in 

today’s final rule represent the maximum improvement in energy efficiency that is 

technologically feasible and economically justified, and would result in significant 

conservation of energy.

Conclusion

II. Introduction 

The following section briefly discusses the statutory authority underlying today’s 

final rule, as well as some of the relevant historical background related to the 

establishment of today’s amended standards.
22

A.

Title III, Part B of the Energy Policy and Conservation Act of 1975 (EPCA or the 

Act), Pub. L. 94-163 (42 U.S.C. 6291-6309, as codified), established the Energy 

Conservation Program for “Consumer Products Other Than Automobiles.” Part C of Title 

III of EPCA (42 U.S.C. 6311–6317) established a similar program for “Certain Industrial 

Equipment,” including distribution transformers.

Authority

9 The Energy Policy Act of 1992 

(EPACT 1992), Pub. L. 102-486, amended EPCA and directed the Department of Energy

to prescribe energy conservation standards for those distribution transformers for which 

DOE determines such standards would be technologically feasible, economically 

justified, and would result in significant energy savings. (42 U.S.C. 6317(a)) The Energy 

Policy Act of 2005 (EPACT 2005), Pub. L. 109-58, amended EPCA to establish energy 

conservation standards for low-voltage dry-type distribution transformers.10 (42 U.S.C. 

6295(y)) 

For those distribution transformers for which DOE determines that energy 

conservation standards are warranted, the DOE test procedures must be the “Standard 

Test Method for Measuring the Energy Consumption of Distribution Transformers”

prescribed by the National Electrical Manufacturers Association (NEMA TP 2-1998), 

 9 For editorial reasons, upon codification in the U.S. Code, Parts B and C were redesignated as Parts A and 

A-1, respectively. 10 EPACT 2005 established that the efficiency of a low-voltage dry-type distribution transformer 

manufactured on or after January 1, 2007 shall be the Class I Efficiency Levels for distribution 

transformers specified in Table 4-2 of the “Guide for Determining Energy Efficiency for Distribution 

Transformers” published by the National Electrical Manufacturers Association (NEMA TP 1-2002).
23

subject to review and revision by the Secretary of Energy in accordance with certain 

criteria and conditions. (42 U.S.C. 6293(b)(10), 6314(a)(2)-(3) and 6317(a)(1)) 

Manufacturers of such covered equipment must use the prescribed DOE test procedure as 

the basis for certifying to DOE that their equipment complies with the applicable energy 

conservation standards adopted under EPCA and when making representations to the 

public regarding the energy use or efficiency of those types of equipment. (42 U.S.C. 

6314(d)) The DOE test procedures for distribution transformers appear at title 10 of the 

Code of Federal Regulations (CFR) part 431, subpart K, appendix A. 

DOE is required to follow certain statutory criteria for prescribing amended 

standards for covered equipment. As indicated above, any amended standard for covered 

equipment must be designed to achieve the maximum improvement in energy efficiency 

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

6316(a)) Furthermore, DOE may not adopt any standard that would not result in the 

significant conservation of energy. (42 U.S.C. 6295(o)(3) and 6316(a)) Moreover, DOE 

may not prescribe a standard: (1) for certain equipment, including distribution 

transformers, if no test procedure has been established for the equipment, or (2) if DOE 

determines by rule that the amended standard is not technologically feasible or 

economically justified. (42 U.S.C. 6295(o)(3) and 6316(a)) In deciding whether an 

amended standard is economically justified, DOE must determine whether the benefits of 

the standard exceed its burdens. (42 U.S.C. 6295(o)(2)(B)(i) and 6316(a)) DOE must 
24

make this determination after receiving comments on the proposed standard, and by 

considering, to the greatest extent practicable, the following seven factors:

1. The economic impact of the standard on manufacturers and customers of the 

equipment subject to the standard;

2. The savings in operating costs throughout the estimated average life of the 

covered equipment in the type (or class) compared to any increase in the price, initial 

charges, or maintenance expenses for the covered products that are likely to result from 

the imposition of the standard; 

3. The total projected amount of energy, or as applicable, water, savings likely to 

result directly from the imposition of the standard;

4. Any lessening of the utility or the performance of the covered equipment likely 

to result from the imposition of the standard;

5. The impact of any lessening of competition, as determined in writing by the 

Attorney General, that is likely to result from the imposition of the standard;

6. The need for national energy and water conservation; and

7. Other factors the Secretary of Energy (Secretary) considers relevant. (42 U.S.C. 

6295(o)(2)(B)(i) and 6316(a))

EPCA, as codified, also contains what is known as an “anti-backsliding” 

provision, which prevents the Secretary from prescribing any amended standard that 

either increases the maximum allowable energy use or decreases the minimum required 
25

energy efficiency of a covered product. (42 U.S.C. 6295(o)(1) and 6316(a)) Also, the 

Secretary may not prescribe an amended or new standard if interested persons have 

established by a preponderance of the evidence that the standard is likely to result in the 

unavailability in the United States of any covered product type (or class) of performance 

characteristics (including reliability, features, sizes, capacities, and volumes) that are 

substantially the same as those generally available in the United States. (42 U.S.C. 

6295(o)(4) and 6316(a))

Further, EPCA, as codified, establishes a rebuttable presumption that a standard is 

economically justified if the Secretary finds that the additional cost to the customer of 

purchasing equipment complying with an energy conservation standard level will be less 

than three times the value of the energy savings during the first year that the customer 

will receive as a result of the standard, as calculated under the applicable test procedure. 

See 42 U.S.C. 6295(o)(2)(B)(iii) and 6316(a).

Additionally, 42 U.S.C. 6295(q)(1), as applied to covered equipment under 42 

U.S.C. 6316(a), specifies requirements when promulgating a standard for a type or class 

of covered equipment that has two or more subcategories. DOE must specify a different 

standard level than that which applies generally to such type or class of equipment for 

any group of covered equipment that has the same function or intended use if DOE 

determines that equipment within such group: (A) consumes a different kind of energy 

from that consumed by other covered equipment within such type (or class); or (B) has a 
26

capacity or other performance-related feature which other equipment within such type (or 

class) does not have and such feature justifies a higher or lower standard. (42 U.S.C. 

6295(q)(1) and 6316(a)) In determining whether a performance-related feature justifies a 

different standard for a group of equipment, DOE must consider such factors as the utility 

to the customer of such a feature and other factors DOE deems appropriate. Id. Any rule 

prescribing such a standard must include an explanation of the basis on which such 

higher or lower level was established. (42 U.S.C. 6295(q)(2) and 6316(a))

Federal energy conservation requirements generally supersede State laws or 

regulations concerning energy conservation testing, labeling, and standards. (42 U.S.C. 

6297(a)–(c) and 6316(a)) DOE may, however, grant waivers of Federal preemption for 

particular State laws or regulations, in accordance with the procedures and other 

provisions set forth under 42 U.S.C. 6297(d)).

DOE has also reviewed this regulation pursuant to Executive Order (EO) 13563, 

issued on January 18, 2011 (76 FR 3281, January 21, 2011). EO 13563 is supplemental to 

and explicitly reaffirms the principles, structures, and definitions governing regulatory 

review established in EO 12866. To the extent permitted by law, agencies are required by 

EO 13563 to: (1) propose or adopt a regulation only upon a reasoned determination that 

its benefits justify its costs (recognizing that some benefits and costs are difficult to 

quantify); (2) tailor regulations to impose the least burden on society, consistent with 

obtaining regulatory objectives, taking into account, among other things, and to the extent 
27

practicable, the costs of cumulative regulations; (3) select, in choosing among alternative 

regulatory approaches, those approaches that maximize net benefits (including potential 

economic, environmental, public health and safety, and other advantages; distributive 

impacts; and equity); (4) to the extent feasible, specify performance objectives, rather 

than specifying the behavior or manner of compliance that regulated entities must adopt; 

and (5) identify and assess available alternatives to direct regulation, including providing 

economic incentives to encourage the desired behavior, such as user fees or marketable 

permits, or providing information upon which choices can be made by the public.

DOE emphasizes as well that EO 13563 requires agencies to use the best 

available techniques to quantify anticipated present and future benefits and costs as 

accurately as possible. In its guidance, the Office of Information and Regulatory Affairs 

has emphasized that such techniques may include identifying changing future compliance 

costs that might result from technological innovation or anticipated behavioral changes. 

For the reasons stated in the preamble, DOE believes that today’s final rule is consistent 

with these principles, including the requirement that, to the extent permitted by law, 

benefits justify costs and that net benefits are maximized. Consistent with EO 13563, and 

the range of impacts analyzed in this rulemaking, the energy efficiency standard adopted 

herein by DOE achieves maximum net benefits.
28

B.

1. Current Standards

Background

On August 8, 2005, EPACT 2005 amended EPCA to establish energy 

conservation standards for low-voltage dry-type distribution transformers (LVDTs).11

Table II.1

(EPACT 2005, Section 135(c); 42 U.S.C. 6295(y)) The standard levels for low-voltage 

dry-type distribution transformers appear in . See Table I.6 above for today’s 

amended LVDT standards.

Table II.1: Federal Energy Conservation Standards for Low-Voltage Dry-Type

Distribution Transformers

Single-Phase Three-Phase

kVA Efficiency % kVA Efficiency %

15 97.7 15 97.0

25 98.0 30 97.5

37.5 98.2 45 97.7

50 98.3 75 98.0

75 98.5 112.5 98.2

100 98.6 150 98.3

167 98.7 225 98.5

250 98.8 300 98.6

333 98.9 500 98.7

750 98.8

1,000 98.9

Note: Efficiencies are determined at the following reference conditions: (1) for no-load losses, at the 

temperature of 20 °C, and (2) for load losses, at the temperature of 75 °C and 35% of nameplate load.

 11 EPACT 2005 established that the efficiency of a low-voltage dry-type distribution transformer 

manufactured on or after January 1, 2007, shall be the Class I Efficiency Levels for distribution

transformers specified in Table 4-2 of the “Guide for Determining Energy Efficiency for Distribution 

Transformers” published by the National Electrical Manufacturers Association (NEMA TP 1-2002).

Comment [A5]: Change recommended by OMB.
29

DOE incorporated these standards into its regulations, along with the standards 

for several other types of products and equipment, in a final rule published on October 

18, 2005. 70 FR 60407, 60416–60417. These standards appear at 10 CFR 431.196(a).

On October 12, 2007, DOE published a final rule that established energy 

conservation standards for liquid-immersed distribution transformers and mediumvoltage dry-type distribution transformers, which are shown in Table II.2 and Table II.3, 

respectively. 72 FR 58190, 58239-40. These standards are codified at 10 CFR 431.196(b) 

and (c). See Tables I.5 and I.7 above for today’s amended liquid-immersed and mediumvoltage dry-type (MVDT) standards.

Table II.2 Federal Energy Conservation Standards for Liquid-Immersed 

Distribution Transformers

Single-Phase Three-Phase

kVA Efficiency % kVA Efficiency %

10 98.62 15 98.36

15 98.76 30 98.62

25 98.91 45 98.76

37.5 99.01 75 98.91

50 99.08 112.5 99.01

75 99.17 150 99.08

100 99.23 225 99.17

167 99.25 300 99.23

250 99.32 500 99.25

333 99.36 750 99.32

500 99.42 1,000 99.36

667 99.46 1,500 99.42

833 99.49 2,000 99.46

2,500 99.49

Note: All efficiency values are at 50% of nameplate-rated load, determined according to the DOE testprocedure. 10 CFR part 431, subpart K, appendix A.

Comment [A6]: Change recommended by OMB.
30

Table II.3 Federal Energy Conservation Standards for Medium-Voltage Dry-Type

Distribution Transformers

Single-Phase Three-Phase

BIL* BIL

20–45 kV 46–95 kV ≥96 kV 20–45 kV 46–95 kV ≥96 kV

kVA Efficiency 

%

Efficiency 

%

Efficiency 

% kVA Efficiency %

Efficiency 

%

Efficiency 

%

15 98.10 97.86 15 97.50 97.18

25 98.33 98.12 30 97.90 97.63

37.5 98.49 98.30 45 98.10 97.86

50 98.60 98.42 75 98.33 98.12

75 98.73 98.57 98.53 112.5 98.49 98.30

100 98.82 98.67 98.63 150 98.60 98.42

167 98.96 98.83 98.80 225 98.73 98.57 98.53

250 99.07 98.95 98.91 300 98.82 98.67 98.63

333 99.14 99.03 98.99 500 98.96 98.83 98.80

500 99.22 99.12 99.09 750 99.07 98.95 98.91

667 99.27 99.18 99.15 1,000 99.14 99.03 98.99

833 99.31 99.23 99.20 1,500 99.22 99.12 99.09

2,000 99.27 99.18 99.15

2,500 99.31 99.23 99.20

* BIL means “basic impulse insulation level.”

Note: All efficiency values are at 50% of nameplate rated load, determined according to the DOE testprocedure. 10 CFR part 431, subpart K, appendix A.

2. History of Standards Rulemaking for Distribution Transformers

In a notice published on October 22, 1997 (62 FR 54809), DOE stated that it had 

determined that energy conservation standards were warranted for electric distribution 

transformers, relying in part on two reports by DOE’s Oak Ridge National Laboratory 

(ORNL). In 2000, DOE issued and took comment on its Framework Document for 

Distribution Transformer Energy Conservation Standards Rulemaking, describing its 

proposed approach for developing standards for distribution transformers, and held a 

public meeting to discuss the framework document. The document is available at: 

http://www.regulations.gov/#!docketDetail;dct=FR%252BPR%252BN%252BO%252BS

R;rpp=10;po=0;D=EERE-2006-STD-0099.
31

On July 29, 2004, DOE published an advance notice of proposed rulemaking

(ANOPR) for distribution transformer standards. 12 69 FR 45375. In August 2005, DOE 

issued draft analyses on which it planned to base the standards for liquid-immersed and 

medium-voltage dry-type distribution transformers, along with supporting

documentation. 13

On April 27, 2006, DOE published its Final Rule on Test Procedures for 

Distribution Transformers. The rule: (1) established the procedure for sampling and 

testing distribution transformers so that manufacturers can make representations as to 

their efficiency, as well as establish that they comply with Federal standards; and (2) 

outlined the procedure the Department of Energy would follow should it initiate an 

enforcement action against a manufacturer. 71 FR 24972 (codified at 10 CFR 431.198).

On August 4, 2006, DOE published a NOPR in which it proposed energy 

conservation standards for distribution transformers (the 2006 NOPR). 71 FR 44355. 

Concurrently, DOE also issued a technical support document (TSD) that incorporated the 

analyses it had performed for the proposed rule.14

 12 The ANOPR published in July 2004 is available at: 

http://www.regulations.gov/#!documentDetail;D=EERE-2006-STD-0099-0069. 

13 These analyses are available in the docket folder at:

http://www.regulations.gov/#!docketDetail;D=EERE-2006-STD-0099 14 The NOPR TSD published in August 2006 is available at: 

http://www.regulations.gov/#!documentDetail;D=EERE-2006-STD-0099-0140.
32

Some commenters asserted that DOE’s proposed standards might adversely affect 

replacement of distribution transformers in certain space-constrained (e.g., vault) 

installations. In response, DOE issued a notice of data availability and request for 

comments on this and another issue. 72 FR 6186 (February 9, 2007) (the NODA). In the 

NODA, DOE sought comment on whether it should include in the LCC analysis potential 

costs related to size constraints of distribution transformers installed in vaults, and 

requested comments on linking energy efficiency levels for three-phase liquid-immersed 

units with those of single-phase units. 72 FR 6189. Based on comments on the 2006 

NOPR and the NODA, DOE created new TSLs to address the treatment of three-phase 

units and single-phase units and incorporated increased installation costs for polemounted and vault transformers. In October 2007, DOE published a final rule that created 

the current energy conservation standards for liquid-immersed and medium-voltage drytype distribution transformers. 72 FR 58190 (October 12, 2007) (the 2007 Final Rule) 

(codified at 10 CFR 431.196(b)-(c)). The preamble to the rule included additional, 

detailed background information on the history of that rulemaking. 72 FR 58194-96.

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 rule. Several additional parties were permitted to intervene in support of 

those 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 
33

EPCA and of the National Environmental Policy Act (NEPA), as amended (42 U.S.C. 

4321 et seq.) DOE and the petitioners subsequently entered into a settlement agreement 

to resolve the petitions. The settlement agreement outlined an expedited timeline for the 

Department of Energy to determine whether to amend the energy conservation standards 

for liquid-immersed and medium-voltage dry-type distribution transformers. Under the 

original settlement agreement, DOE was required to publish by October 1, 2011, either a 

determination that the standards for those distribution transformers do not need to be 

amended or a NOPR that includes any new proposed standards and that meets all 

applicable requirements of EPCA and NEPA. Under an amended settlement agreement, 

the October 1, 2011, deadline for a DOE determination or proposed rule was extended to 

February 1, 2012. If DOE finds that amended standards are warranted, DOE agreed to

publish a final rule containing such amended standards by October 1, 2012. Today’s final 

rule satisfies the amended settlement agreement.

On March 2, 2011, DOE published in the Federal Register a notice of public 

meeting and availability of its preliminary TSD for the distribution transformer energy 

conservation standards rulemaking, wherein DOE discussed and received comments on 

issues such as equipment classes that DOE would analyze in consideration of amending 

the energy conservation standards, the analytical framework, models and tools it is using 

to evaluate potential standards, the results of its preliminary analysis, and potential 

standard levels. 76 FR 11396. The notice is available on the above-referenced DOE 

website. To expedite the rulemaking process, DOE began at the preliminary analysis 
34

stage because it believed that many of the same methodologies and data sources that were

used during the 2007 final rule remain valid. On April 5, 2011, DOE held a public 

meeting to discuss the preliminary TSD. Representatives of manufacturers, trade 

associations, electric utilities, energy conservation organizations, Federal regulators, and 

other interested parties attended this meeting. In addition, other interested parties 

submitted written comments about the TSD addressing a range of issues. Those 

comments are discussed in the following sections of the final rule. 

On July 29, 2011, DOE published in the Federal Register a notice of intent to 

establish a subcommittee under DOE’s Energy Efficiency and Renewable Energy 

Advisory Committee (ERAC), in accordance with the Federal Advisory Committee Act 

and the Negotiated Rulemaking Act, to negotiate proposed Federal standards for the 

energy efficiency of medium-voltage dry-type and liquid- immersed distribution 

transformers. 76 FR 45471. Stakeholders strongly supported a consensual rulemaking 

effort. DOE decided that a negotiated rulemaking would result in a better-informed 

NOPR. On August 12, 2011, DOE published in the Federal Register a similar notice of 

intent to negotiate proposed Federal standards for the energy efficiency of low-voltage 

dry-type distribution transformers. 76 FR 50148. The purpose of both subcommittees was 

to discuss and, if possible, reach consensus on a proposed rule for the energy efficiency 

of distribution transformers. 
35

The ERAC subcommittee for medium-voltage liquid-immersed, and dry-type 

distribution transformers consisted of representatives of parties, listed below, having a 

defined stake in the outcome of the proposed standards and included:

• ABB Inc.

• AK Steel Corporation

• American Council for an Energy-Efficient Economy

• American Public Power Association

• Appliance Standards Awareness Project

• ATI-Allegheny Ludlum

• Baltimore Gas and Electric 

• Cooper Power Systems

• Earthjustice

• Edison Electric Institute

• Fayetteville Public Works Commission

• Federal Pacific Company

• Howard Industries Inc.

• LakeView Metals

• Efficiency and Renewables Advisory Committee member

• Metglas, Inc.

• National Electrical Manufacturers Association

• National Resources Defense Council

• National Rural Electric Cooperative Association

• Northwest Power and Conservation Council

• Pacific Gas and Electric Company

• Progress Energy

• Prolec-GE

• U.S. Department of Energy

The ERAC subcommittee for medium-voltage liquid-immersed, and dry-type 

distribution transformers held meetings in 2011 on September 15 through 16, October 12 

through 13, November 8 through 9, and November 30 through December 1; the ERAC 

subcommittee also held public webinars on November 17 and December 14. The 
36

meetings were open to the public. During the September 15, 2011, meeting, the 

subcommittee agreed to its rules of procedure, ratified its schedule of the remaining 

meetings, and defined the procedural meaning of consensus. The subcommittee defined 

consensus as unanimous agreement from all present subcommittee members. 

Subcommittee members were allowed to abstain from voting for an efficiency level; in 

such cases their votes counted neither toward nor against the consensus.

DOE presented its draft engineering, life-cycle cost, and national impacts analysis 

and results. During the meetings of October 12 through 13, 2011, DOE presented its 

revised analysis and heard from subcommittee members on a number of topics. During 

the meetings on November 8 through 9, 2011, DOE presented its revised analysis, 

including life-cycle cost sensitivities based on excluding ZDMH and amorphous steel as 

core materials. During the meetings on November 30 through December 1, 2011, DOE 

presented its revised analysis based on 2011 core-material prices. 

At the conclusion of the final meeting, subcommittee members presented their 

efficiency level recommendations. For medium-voltage liquid-immersed distribution 

transformers, the energy efficiency Advocates, represented by the Appliance Standards 

Awareness Project (ASAP), recommended efficiency level (also referred to as “EL”) 2

for all design lines (also referred to as “DLs”). The National Electrical Manufacturers 

Association (NEMA) and AK Steel recommended EL 1 for all DLs except for DL 2, for 

which no change from the current standard was recommended. Edison Electric Institute 
37

(EEI) and ATI Allegheny Ludlum recommended EL1 for DLs 1, 3, and 4 and no change 

from the current standard or a proposed standard of less than EL 1 for DLs 2 and 5. 

Therefore, the subcommittee did not arrive at consensus regarding proposed standard 

levels for medium-voltage liquid-immersed distribution transformers. 

For medium-voltage dry-type distribution transformers, the subcommittee arrived 

at consensus and recommended a proposed standard of EL2 for DLs 11 and 12, from 

which the proposed standards for DLs 9, 10, 13A, and 13B would be scaled. Transcripts 

of the all subcommittee meetings (for all transformer types) and all data and materials 

presented at the subcommittee meetings are available via a link under the DOE website 

at:http://www.regulations.gov/#!docketDetail;D=EERE-2010-BT-STD-0048. 

The ERAC subcommittee held meetings in 2011 on September 28, October 13-

14, November 9, and December 1-2 for low-voltage distribution transformers. The ERAC 

subcommittee also held webinars on November 21, 2011, and December 20, 2011. The 

meetings were open to the public. During the September 28, 2011, meeting, the 

subcommittee agreed to its rules of procedure, finalized the schedule of the remaining 

meetings, and defined the procedural meaning of consensus. The subcommittee defined 

consensus as unanimous agreement from all present subcommittee members. 

Subcommittee members were allowed to abstain from voting for an efficiency level; their 

votes counted neither toward nor against the consensus.
38

The ERAC subcommittee for low-voltage distribution transformers consisted of 

representatives of parties having a defined stake in the outcome of the proposed standards

and included:

• AK Steel Corporation

• American Council for an Energy-Efficient Economy

• Appliance Standards Awareness Project

• ATI-Allegheny Ludlum

• EarthJustice

• Eaton Corporation

• Federal Pacific Company

• Lakeview Metals

• Efficiency and Renewables Advisory Committee member

• Metglas, Inc.

• National Electrical Manufacturers Association

• Natural Resources Defense Council

• ONYX Power

• Pacific Gas and Electric Company

• Schneider Electric

• U.S. Department of Energy

DOE presented its draft engineering, life-cycle cost and national impacts analysis 

and results. During the meeting of October 14, 2011, DOE presented its revised analysis 

and heard from subcommittee members on various topics. During the meeting of 

November 9, 2011, DOE presented its revised analysis. During the meeting of December 

1, 2011, DOE presented its revised analysis based on 2011 core-material prices. 

At the conclusion of the final meeting, subcommittee members presented their 

energy efficiency level recommendations. For low-voltage dry-type distribution 
39

transformers, the Advocates, represented by ASAP, recommended EL4 for all DLs;

NEMA recommended EL 2 for DLs 7 and 8, and no change from the current standard for 

DL 6. EEI, AK Steel and ATI Allegheny Ludlum recommended EL 1 for DLs 7 and 8, 

and no change from the current standard for DL 6. The subcommittee did not arrive at 

consensus regarding a proposed standard for low-voltage dry-type distribution 

transformers. 

DOE published a NOPR on February 10, 2012, which proposed amended 

standards for all three transformer types. 77 FR 7282. Medium-voltage dry-type

distribution transformers were proposed at the negotiating committee’s consensus level. 

Liquid-immersed distribution transformers were proposed at TSL 1. Low-voltage drytype distribution transformers were proposed at TSL 1. In the NOPR, DOE sought 

comment on a number of issues related to the rulemaking.15

Following publication of the NOPR, DOE received several comments expressing 

a desire to see some of the NOPR suggestions extended and analyzed for liquidimmersed distribution transformers. In response, DOE generated a supplementary NOPR 

analysis with three additional TSLs. The three TSLs presented were based on possible 

new equipment classes for pole-mounted distribution transformers, network/vault-based 

distribution transformers, and those with high basic impulse level (BIL) ratings. On June 

4, 2012 DOE published a notice announcing the availability of this supplementary 

 15 On February 24, 2012, DOE published a technical correction to the NOPR, amending and adding values 

in certain tables in the NOPR. 77 FR 10997. 

Comment [A7]: FN recommended by OMB.
40

analysis16 and of a public meeting to be held on June 20, 2012 to present and receive 

feedback on it. DOE also generated an additional TSL in a June 18, 2012 analysis 

published on DOE’s website.

III. General Discussion 

A.

DOE published its test procedure for distribution transformers in the 

Test Procedures 

Federal Register

as a final rule on April 27, 2006. 71 FR 24972. Section 7(c) of the Process Rule17

indicates that DOE will issue a final test procedure, if one is needed, prior to issuing a 

proposed rule for energy conservation standards. Under 42 U.S.C. 6314(a)(1), at least 

every seven years, DOE must evaluate whether to amend test procedures for each class 

of commercial equipment based on whether an amended test procedure would more 

accurately or fully comply with the requirements that test procedures be reasonably 

designed to produce test results that reflect energy efficiency, energy use, and estimated 

operating costs during a representative average use cycle, and that the test procedures are 

not unduly burdensome to conduct.18

 16 77 FR 32916

Any determination that a test procedure amendment 

is not required under this standard must be published in the Federal Register. (42 U.S.C. 

6314(a)(1)(A)(ii)) 

17 The Process Rule provides guidance on how DOE conducts its energy conservation standards 

rulemakings, including the analytical steps and sequencing of rulemaking stages (such as test procedures 

and energy conservation standards). (10 CFR Part 430, subpart C, appendix A).

18 In addition, if the test procedure determines estimated annual operating costs, such procedure must meet 

additional requirements at 42 U.S.C. 6314(a)(3).
41

As detailed below, in today’s notice, DOE determines that an amended test procedure 

is not necessary because the 2006 test procedure is reasonably designed to produce test 

results that reflect energy efficiency and energy use, and an amended test procedure that 

more precisely measures energy efficiency and energy use for every possible distribution 

transformer configuration would be unduly burdensome to conduct.

1. General

Several parties commented on the test procedure for distribution transformers. 

The California Investor Owned Utilities (CA IOUs) commented that DOE should not 

modify the test procedure. (CA IOUs, No. 189 at p. 1) Today’s rule contains no test 

procedure amendments, but the rule does clarify the test procedure’s application in 

response to comments. Based on the comments discussed below, DOE may revisit the 

issue of test procedures in a future proceeding.

NEMA commented that because of variability in process, materials, and testing, 

manufacturers must “overdesign” transformers in order to have confidence that their 

products will meet standards. (NEMA, No. 170 at p. 3) DOE notes that its compliance 

procedures already contain allowances for statistical variation as a result of measurement, 

laboratory, and testing procedure variability. Manufacturers are also required to take 

certification sampling plans and tolerances into account when developing their certified 

ratings after testing a sample of minimum units from the production of a basic model. 
42

The represented efficiency equation essentially allows a manufacturer to “represent” a 

basic model of distribution transformer as having achieved a higher efficiency than 

calculated through testing the minimum sample for certification. DOE is not adopting any 

modifications to its certification or enforcement sampling procedures in this final rule, 

but it may further address them in a separate proceeding at a later date if it finds such 

practices to be overly strict or generous.

Additionally, Schneider Electric commented that DOE’s test procedure is 

inadequate or ambiguous in several areas, including test environment drafts, ambient 

method internal temperatures, test environment ambient temperature variation, ambient 

method test delays, coordination of coil and ambient test methods, temperature data 

records, and application of voltage or current. (Schneider, No. 180 at p. 12) DOE 

appreciatesexamined the commenttest procedure components identified by Schneider 

Electric and notesdetermined that, at this time, no change to the test procedure is 

necessary to address the issues raised. Further, the existing test procedure, which was , 

statutorily-prescribed by statute,test procedure is an established industry standard familiar 

to manufacturers. DOE may explore further opportunities for improvement to the test 

procedure in a future rulemakingcontinues to believe that the procedure is reasonably 

designed to produce test results that reflect energy efficiency and energy use without

being unduly burdensome to conduct. Comment [A8]: Change recommended by OMB.
43

Finally, DOE’s present sampling plans require a minimum number of units be 

tested in order to calculate the represented efficiency of a basic model. (10 CFR 429.47 

(a)). Prolec-GE commented that DOE’s compliance protocols allow too small a statistical 

variation, particularly because silicon steel sees a greater variation in losses than does the 

amorphous variety. (Prolec-GE, No. 177 at p. 17) To the extent Prolec-GE is concerned 

about the variability in their production, DOE notes that the statistical sampling plans 

allow for manufacturers to increase the sample size, which should help better characterize 

the variability association with the production. DOE’s existing sampling plans are a 

balance between manufacturing burden associated with testing and accurately 

characterizing the efficiency of a given basic model based on a sample of the production. 

While DOE is not adopting any changes to its existing sampling plans in today’s final 

rule, DOE welcomes data showing the production variability for different types and 

efficiencies of distribution transformers to help better inform any changes that may be 

considered in a separate and future proceeding.

2. Multiple kVA Ratings

The current test procedure is not specific regarding which kVA rating should be 

used to assess compliance in the case of distribution transformers that have more than one 

rating. Though less common in distribution transformers than in other types of 

transformers (e.g., “power” or “substation” transformers), active cooling measures such 

as fans or pumps are sometimes used to aid cooling. Greater heat dissipation capacity 

means that the transformer can be safely operated at higher loading levels for longer 
44

periods of time. Active cooling components generally carry much shorter lifetimes than 

the transformer itself, however, and the failure of any cooling component would expose 

the transformer at-large to premature failure due to elevated temperatures. Accordingly, 

distribution transformers rarely contain such components and, when they do, rarely make 

use of them except in occasional overload situations. As a result, they play little role in 

the design of the transformer or in a transformer’s ability to operate efficiently even when 

equipped.

Apart from ratings corresponding to active cooling, transformers may also carry 

additional ratings (i.e., above the “base rating”) corresponding to passive cooling and 

reflecting different temperature rises. A transformer would be rated for higher kVA if 

allowed to rise to a greater temperature and, by extension, dissipate more energy.

DOE sought comment on whether the test procedure needs greater specificity 

with respect to multiple kVA ratings. No party argued that distribution transformers 

should comply with standards at any ratings corresponding to active cooling, for the 

reasons discussed above. Four manufacturers (Howard Industries, Cooper Power 

Systems, Prolec-GE, and Schneider Electric), one trade organization (NEMA), and one 

utility (Progress Energy) all commented that compliance should be based exclusively on 

a transformer’s “base” rating, or the rating that corresponds to the lowest temperature 

rise. (Prolec-GE, No. 177 at p. 6; Schneider, No. 180 at p. 2; PEMCO, No. 183 at p. 2; 

PE, No. 192 at p. 3; HI, No. 151 at p. 12; NEMA, No. 170 at pp. 6−7) ABB argued that 
45

compliance should be based on a transformer’s base rating and on any others (if any) 

corresponding to passive cooling. (ABB, No. 158 at pp. 2−4) HVOLT commented that 

the term “passive cooling” may not be sufficient to clarify DOE’s intent because some 

transformers have more than one rating which may be achieved with passive cooling. 

(HVOLT, No. 146 at p. 49)

Though prevalent in certain types of larger transformers, active cooling is not a 

significant feature in the design or operation of distribution transformers. Distribution 

transformers are seldom equipped with active cooling features or designed to make use of 

them. Additionally, units which are equipped with such features are rarely operated using 

them. As a result, active cooling features bear little influence on transformer efficiency 

and are not appropriate for use in measuring energy efficiency. Similarly, transformers 

with more than one rating corresponding to passive cooling will experience reduced 

equipment lifetime when operated at those high ratings and are therefore best evaluated at 

their lowest, “base” rating. DOE clarifies today that manufacturers should use a 

transformer’s base kVA rating to assess compliance. For distribution transformers with 

more than one kVA rating, base kVA rating means the kVA rating that corresponds to the 

lowest temperature rise that actively removes heat from the distribution transformer

without engagement of any fans, pumps, or other equipment. It is the base kVA rating 

and the base kVA rating only, which manufacturers should base their certified ratings on 

and on which DOE will assess compliance. In no case should a distribution transformer 
46

be certified using any kVA rating corresponding to heat removal or enhanced convection 

by auxiliary equipment.

3. Dual/Multiple Basic Impulse Level

Distribution transformers may be built such that different winding configurations 

carry different BIL ratings. In the past, MVDT transformers were placed into equipment 

classes by BIL rating (among other criteria) and the question arose of which rating (if 

there were more than one) should be used to assess compliance. Currently, DOE requires 

distribution transformers to comply with standards using the BIL rating of the winding 

configuration that produces the greatest losses. (10 CFR part 431, subpart K, appendix A)

BIL rating offers additional utility in the form of increased resistance to large 

voltage transients arising, for example, from lightning strikes, but requires some design 

compromises that affect efficiency, primarily with respect to winding clearances. A 

transformer rated for a given BIL must be designed as such, even if the windings may be 

reconfigured such that they carry a lower rating. For this reason, Progress Energy, 

PEMCO, NEMA, Cooper Power Systems, Power Partners, and Howard Industries all 

commented that transformers with multiple BIL ratings should comply only at the highest 

BIL for which they are rated. (HI, No. 151 at p. 12; Power Partners, No. 155 at p. 1–2; 

Cooper, No. 165 at p. 2; NEMA, No. 170 at p. 7; Prolec-GE, No. 177 at p. 6; PEMCO, 

No. 183 at p. 2; PE, No. 192 at p. 3) ABB commented that transformers should meet the 
47

efficiency levels of all of its rated BILs, because there is no way to know in advance how 

a transformer will be operated over its lifetime. (ABB, No. 158 at p. 4) 

Although DOE agrees there is no way to be sure how a distribution transformer 

will be operated over its lifetime, it does not believe multiple BIL ratings currently 

present an energy conservation standards circumvention risk. Designing transformers to 

higher BIL ratings adds cost and consumers would be unlikely to utilize them unless 

genuinely required by the application.

DOE clarifies that transformers may be certified at any BIL for which they are 

rated, including the highest BIL ratings. This does nothing to change DOE’s requirement 

that distribution transformers comply in the configuration that produces the greatest 

losses, however, even if that configuration itself does not carry the highest BIL rating. 

For example, a MVDT distribution transformer may have two winding configurations, 

respectively BIL rated at 60 kV and 125 kV. Although the distribution transformer must 

meet only the 125 kV standards, it may produce greater losses (and thus need to be 

certified) in the 60 kV configuration.

4. Dual/Multiple-Voltage Primary Windings

Currently, DOE requires manufacturers to comply with energy conservation 

standards while the distribution transformer’s primary windings (“primaries”) are in the 

configuration that produces the highest losses. (10 CFR part 431, subpart K, appendix A)
48

DOE understands that, in contrast to the secondary windings, reconfigurable 

primaries typically exhibit a larger variation in efficiency between series and primary 

connections. Such transformers are often purchased with the intent of upgrading the local 

power grid to a higher operating voltage and lowered overall system losses.

Several parties commented on the matter of primary winding configurations in 

response to the NOPR. Kentucky Association of Electric Cooperatives (KAEC), Cooper 

Power Systems, NEMA, and Progress Energy commented that it is least burdensome for 

manufacturers if they can report losses in the same configuration in which the 

transformers are shipped, which by Institute of Electrical and Electronics Engineers 

(IEEE) standards must be the series configuration. (KAEC, No. 149 at p. 2; NEMA, No. 

170 at p. 6; PE, No. 192 at p. 10; PE, No. 192 at p. 2; Prolec-GE, No. 177 at p. 5; 

Schneider, No. 180 at p. 2; Schneider, No. 180 at p. 8; Cooper Power Systems, No. 222 at 

p. 3) Howard Industries and Prolec-GE commented that manufacturers should be allowed 

to test distribution transformers with their primaries in any configuration. (HI, No. 151 at 

p. 12; Prolec-GE, No. 177 at p. 5) Utilities Baltimore Gas and Electric and 

Commonwealth Edison supported testing in the configuration in which the transformer 

will ultimately be used. (BG&E, No. 182 at p. 2; ComEd, No. 184 at p. 2)

ABB submitted comments and data explaining that the ratios of the losses of 

different winding positions varied considerably and, as a result, that there was no reliable 
49

way to predict which configuration would carry the lowest losses. ABB and the 

California IOUs supported maintaining the test procedure’s current requirements. (ABB, 

No. 158 at p. 2; CA IOUs, No. 189 at pp. 1−2)

DOE is concerned that the primary winding configuration can have a significant 

impact on energy consumption and that by relaxing the restriction of compliance in the 

configuration producing the highest losses, any forecasted energy savings may be 

diminished. DOE is not modifying any test procedure requirements in today’s rule, but 

may reexamine the topic in a dedicated test procedure rulemaking in the future.

5. Dual/Multiple-Voltage Secondary Windings

DOE understands that some distribution transformers may be shipped with 

reconfigurable secondary windings, and that certain configurations may have different 

efficiencies. Currently, DOE requires distribution transformers to be tested in the 

configuration that exhibits the highest losses. Whereas the IEEE standard19 requires a 

distribution transformer to be shipped with the windings in series, a manufacturer testing 

for compliance might need to disassemble the unit, reconfigure the windings, and 

reassemble the unit for shipping at added time and expense.

Several parties commented on the matter of reconfigurable secondary windings. 

Cooper Power Systems, KAEC, NEMA, Progress Energy, and Schneider Electric 

 19 IEEE C57.12.00-2010.
50

supported conducting testing with windings in series, as is the IEEE convention and as 

would produce the highest voltage. (Cooper, No. 165 at pp. 1−2, 6 No. 222 at p. 3; HI, 

No. 151 at p. 12; KAEC, No. 149 at p. 2; NEMA, No. 170 at p. 6; PE, No. 192 at p. 10; 

PE, No. 192 at p. 2; Schneider, No. 180 at p. 2; Schneider, No. 180 at p. 8)

Power Partners and Prolec-GE commented that testing should be permitted in any 

winding configuration at the discretion of the manufacturer. (Power Partners, No. 155 at 

p. 1; Prolec-GE, No. 177 at pp. 3−4)

Additionally, ABB and the California IOUs commented that there was no way of 

knowing which position would produce the greatest losses and, therefore, the test 

procedure should remain unchanged with respect to winding configuration requirements. 

(ABB, No. 158 at p. 2; CA IOUs, No. 189 at p. 1−2)

DOE is concerned that secondary windings may have significantly different losses 

in various configurations and that, furthermore, there is no reliable way to predict in 

which configuration the transformer will be operated over the majority of its lifetime. Just 

as with dual/multiple primary windings, changing the requirement of testing in the 

configuration producing the highest losses, may diminish forecasted energy savings. As a 

result, DOE is not modifying any test procedure requirements in today’s rule, but may 

reexamine the topic in a dedicated test procedure rulemaking in the future.
51

6. Loading

Currently, DOE requires that both liquid-immersed and medium-voltage dry-type

distribution transformers comply with standards at 50 percent loading and that lowvoltage dry-type distribution transformers comply at 35 percent loading. DOE wishes to 

clarify that the loading discussed herein pertains only to that which manufacturers must 

use to test their equipment. DOE’s economic analysis uses loading distributions that 

attempt to reflect the most recent understanding of the United States electrical grid. DOE 

does not believe that all (or the average of all) customers utilize transformers at the 

required test procedure loading values.

Several parties commented on the appropriateness of these test loading values. 

ABB, ComEd, Cooper, EEI, Howard, KAEC, NEMA, NRECA, PEMCO, Prolec-GE, and 

Schneider all commented that the values were appropriate and should continue to be 

used. (ABB, No. 158 at p. 5; ComEd, No. 184 at p. 2; Cooper, No. 165 at p. 2; EEI, No. 

185 at p. 4; HI, No. 151 at p. 12; KAEC, No. 149 at p. 3; NEMA, No. 170 at p. 12; 

NRECA, No. 172 at p. 4; PEMCO, No. 183 at p. 2; Prolec-GE, No. 177 at p. 7; 

Schneider, No. 180 at p. 3)

Progress Energy commented that it believed the current values suffice for the 

present but that DOE should further explore the topic in the future. (PE, No. 192 at p. 3)

BG&E commented that utilities had oversized transformers in the past due to lack of 

ability to accurately monitor loading and that loading will increase in the future. (BG&E, 
52

No. 182 at p. 3) Finally, MGLW and the Copper Development Association commented 

that DOE should use a test procedure that requires measurements at several loading levels 

and reporting of efficiency as a weighted average of those. (MLGW, No. 133 at p. 2; 

CDA, No. 153 at p. 4)

DOE understands that distribution transformers experience a range of loading 

levels when installed in the field. DOE understands that the majority of stakeholders, 

including manufacturers and utilities, support retention of the current testing 

requirements and DOE determined that its existing test procedure provides results that are 

representative of the performance of distribution transformers in normal use. Although 

DOE may examine the topic of potential loading points in a dedicated test procedure 

rulemaking in the future, at this time, DOE does not believe that the potential 

improvement in testing precision outweighs the complexity and the burden of requiring 

testing at different loadings depending on each individual transformer’s characteristics.

B.

1. General

Technological Feasibility 

In each standards rulemaking, DOE conducts a screening analysis based on 

information it has gathered on all current technology options and prototype designs that 

could improve the efficiency of the products that are the subject of the rulemaking. As the 

first step in such analysis, DOE develops a list of technology options for consideration in 

consultation with manufacturers, design engineers, and other interested parties. DOE then 
53

determines which of these means for improving efficiency are technologically feasible. 

DOE considers technologies incorporated in commercially available products or in 

working prototypes to be technologically feasible. 10 CFR 430, subpart C, appendix A, 

section 4(a)(4)(i) There are distribution transformers available at all of the energy 

efficiency levels considered in today’s final rule. Therefore, DOE believes all of the 

energy efficiency levels adopted by today’s final rulemaking are technologically feasible.

Once DOE has determined that particular technology options are technologically 

feasible, it further evaluates each of them in light of the following additional screening 

criteria: (1) practicability to manufacture, install, or service; (2) adverse impacts on 

product utility or availability; and (3) adverse impacts on health or safety. For further 

details on the screening analysis for this rulemaking, see chapter 4 of the final rule TSD. 

2. Maximum Technologically Feasible Levels

When DOE considers an amended standard for a type or class of covered 

equipment, it must determine the maximum improvement in energy efficiency or 

maximum reduction in energy use that is technologically feasible for that equipment. (42 

U.S.C. 6295(p)(1); 42 U.S.C. 6316(a)) While developing the energy conservation 

standards for liquid-immersed and medium-voltage dry-type distribution transformers 

that were codified under 10 CFR 431.196, DOE determined the maximum 

technologically feasible (max-tech) energy efficiency level through its engineering 

analysis. The max-tech design incorporates the most efficient materials, such as core 
54

steels and winding materials, and applied design parameters that create designs at the 

highest efficiencies achievable at the time. 71 FR 44362 (August 4, 2006) and 72 FR 

58196 (October 12, 2007). DOE used those designs to establish max-tech levels for its 

LCC analysis, then scaled them to other kVA ratings within a given design line to 

establish max-tech efficiencies for all the distribution transformer kVA ratings. For 

today’s rule, DOE determined max-tech in exactly the same manner.

C.

1. Determination of Savings

Energy Savings 

For each TSL, DOE projected energy savings from the products that are the 

subject of this rulemaking purchased in the 30-year period that begins in the year of 

compliance with amended standards (2016–2045). The savings are measured over the 

entire lifetime of products purchased in the 30-year period.20 DOE quantified the energy 

savings attributable to each TSL as the difference in energy consumption between each 

standards case and the base case. The base case represents a projection of energy 

consumption in the absence of amended mandatory efficiency standards, and considers 

market forces and policies that affect demand for more efficient products.

 20 In the past DOE presented energy savings results for only the 30-year period that begins in the year of 

compliance. In the calculation of economic impacts, however, DOE considered operating cost savings 

measured over the entire lifetime of products purchased in the 30-year period. Because some transformers 

sold in 2045 will reach the maximum transformer lifetime of 60 years, DOE calculated economic impacts

through 2105. DOE has chosen to modify its presentation of national energy savings to be consistent with 

the approach used for its national economic analysis.

Comment [A9]: Footnote changes recommended 

by OMB.
55

DOE used its national impact analysis (NIA) spreadsheet model to estimate 

energy savings from amended standards for the products that are the subject of this 

rulemaking. The NIA spreadsheet model calculates energy savings in site 

energyelectricity, which is the energy directly consumed by transformers at the locations 

where they are used. DOE reports national energy savings on an annual basis in terms of 

the primary energy savings, which is the savings in the energy that is used to generate 

and transmit the site energyelectricity. To convert site energyelectricity to primary 

energy, DOE derived annual conversion factors from the model used to prepare the 

Energy Information Administration’s (EIA) Annual Energy Outlook 2012 (AEO 2012). 

Recent data suggests that electricity related losses, which includes conversion from the 

primary fuel source and the transmission of electricity, is about twice that of site 

electricity use.

2. Significance of Savings

As noted above, 42 U.S.C. 6295(o)(3)(B) prevents DOE from adopting a standard 

for covered equipment if such a standard would not result in significant energy savings. 

While EPCA does not define the term “significant,” the U.S. Court of Appeals for the 

District of Columbia, in Natural Resources Defense Council v. Herrington

Comment [A10]: Changes recommended by 

OMB.

, 768 F.2d 

1355, 1373 (D.C. Cir. 1985), indicated that Congress intended “significant” energy 

savings in this context to be savings that were not “genuinely trivial.” The energy savings 

for all of the TSLs considered in this rulemaking are non-trivial and, therefore, DOE 

considers them significant within the meaning of EPCA section 325(o).
56

D.

1. Specific Criteria

Economic Justification

As noted previously, EPCA requires DOE to evaluate seven factors to determine 

whether a potential energy conservation standard is economically justified. (42 U.S.C. 

6295(o)(2)(B)(i)) The following sections describe how DOE has addressed each of the 

seven factors in this rulemaking.

a. Economic Impact on Manufacturers and Consumers

In determining the impacts of an amended standard on manufacturers, DOE first 

determines the quantitative impacts using an annual cash-flow approach. This includes 

both a short-term assessment, based on the cost and capital requirements during the 

period between the issuance of a regulation and when entities must comply with the 

regulation, and a long-term assessment for a 30-year analysis period. The industry-wide 

impacts analyzed include INPV (which values the industry on the basis of expected 

future cash flows), cash flows by year, changes in revenue and income. Second, DOE 

analyzes and reports the impacts on different types of manufacturers, paying particular 

attention to impacts on small manufacturers. See section VI.B for further discussion.

Third, DOE considers the impact of standards on domestic manufacturer employment and 

manufacturing capacity, as well as the potential for standards to result in plant closures 

and loss of capital investment. Finally, DOE takes into account cumulative impacts of 

various DOE regulations and other regulatory requirements on manufacturers.

Comment [A11]: Change recommended by 

OMB.
57

For individual customers, measures of economic impact include the changes in 

LCC and the PBP associated with new or amended standards. The LCC, which is 

separately specified in EPCA as one of the seven factors to be considered in determining 

the economic justification for a new or amended standard (42 U.S.C. 

6295(o)(2)(B)(i)(II)), is discussed in the following section. For customers in the 

aggregate, DOE also calculates the national NPV of the economic impacts on customers 

over the forecast period applicable to a particular rulemaking.

b. Life-Cycle Costs

The LCC is the sum of the purchase price of a type of equipment (including its 

installation) and the operating expense (including energy and maintenance and repair 

expenditures) discounted over the lifetime of the equipment. The LCC savings for the 

considered energy efficiency levels are calculated relative to a base case that reflects 

likely trends in the absence of amended standards. The LCC analysis requires a variety of 

inputs, such as equipment prices, equipment energy consumption, energy prices, 

maintenance and repair costs, equipment lifetime, and customer discount rates. DOE 

assumed in its analysis that customers will purchase the considered equipment in 2016. 

To account for uncertainty and variability in specific inputs, such as equipment

lifetime and discount rate, DOE uses a distribution of values with probabilities attached 

to each value. A distinct advantage of this approach is that DOE can identify the 
58

percentage of customers estimated to receive LCC savings or experience an LCC 

increase, in addition to the average LCC savings associated with a particular standard 

level. In addition to identifying ranges of impacts, DOE evaluates the LCC impacts of 

potential standards on identifiable subgroups of customers that may be disproportionately 

affected by a national standard.

c. Energy Savings

Although significant conservation of energy is a separate statutory requirement 

for imposing an energy conservation standard, EPCA requires DOE, in determining the 

economic justification of a standard, to consider the total energy savings that are expected 

to result directly from the standard. (42 U.S.C. 6295(o)(2)(B)(i)(III)) DOE uses the NIA 

spreadsheet results in its consideration of total projected energy savings. 

d. Lessening of Utility or Performance of Equipment

In establishing classes of equipment, and in evaluating design options and the 

impact of potential standard levels, DOE sought to develop standards for distribution 

transformers that would not lessen the utility or performance of the equipment. (42 

U.S.C. 6295(o)(2)(B)(i)(IV)) None of the TSLs presented in today’s final rule would 

substantially reducelessen the utility or performance of the equipment under 

consideration in the rulemaking.

Comment [A12]: Change recommended by 

OMB.
59

e. Impact of Any Lessening of Competition

EPCA directs DOE to consider any lessening of competition that is likely to result 

from standards. It also directs the Attorney General of the United States (Attorney 

General) to determine the impact, if any, of any lessening of competition likely to result 

from a proposed standard and to transmit such determination to the Secretary, together 

with an analysis of the nature and extent of the impact. (42 U.S.C. 6295(o)(2)(B)(i)(V) 

and (B)(ii)) DOE transmitted a copy of its proposed rule and NOPR TSD to the Attorney 

General with a request that the Department of Justice (DOJ) provide its determination on 

this issue. DOJ’s response, that the proposed energy conservation standards are unlikely 

to have a significant adverse impact on competition, is reprinted at the end of this notice.

f. Need for National Energy Conservation

Certain benefits of the amended standards for distribution transformers are likely 

to be reflected in improvements to the security and reliability of the Nation’s energy 

system. Reductions in the demand for electricity may also result in reduced costs for 

maintaining the reliability of the Nation’s electricity system. DOE conducted a utility 

impact analysis, described in section IV.K to estimate how standards may affect the 

Nation’s needed power generation capacity. (See 42 U.S.C. 6295(o)(2)(B)(i)(VI))

Energy savings from the amended standards are also likely to result in 

environmental benefits in the form of reduced emissions of air pollutants and greenhouse 

gases associated with energy production. DOE reports the environmental effects from 
60

today’s standards, and from each TSL it considered, in chapter 15 of the TSD for the final 

rule. DOE also reports estimates of the economic value of emissions reductions resulting 

from the considered TSLs (see section IV.M of this final rule). 

g. Other Factors

EPCA allows the Secretary of Energy, in determining whether a standard is 

economically justified, to consider any other factors that the Secretary of Energy 

considers relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) Under this provision, DOE has also 

considered the matter of electrical steel availability. This factor is discussed further in 

sections IV.C.9.and IV.I.5.a.

2. Rebuttable Presumption

As set forth in 42 U.S.C. 6295(o)(2)(B)(iii), EPCA creates a rebuttable 

presumption that an energy conservation standard is economically justified if the 

additional cost to the customer of a type of equipment that meets the standard is less than 

three times the value of the first-year of energy savings resulting from the standard, as 

calculated under the applicable DOE test procedure. DOE’s LCC and PBP analyses 

generate values used to calculate the PBP for consumers of potential amended energy 

conservation standards. These analyses include, but are not limited to, the three-year PBP 

contemplated under the rebuttable presumption test. However, DOE routinely conducts 

an economic analysis that considers the full range of impacts to the customer, 

manufacturer, Nation, and environment, as required under 42 U.S.C. 6295(o)(2)(B)(i). 
61

The results of that analysis serve as the basis for DOE to definitively evaluate the 

economic justification for a potential standard level (thereby supporting or rebutting the 

results of any three-year PBP analysis). The rebuttable presumption payback calculation 

is discussed in sections IV.F.3.j and V.B.1.c of this final rule.

IV. Methodology and Discussion of Related Comments

DOE used two spreadsheet tools to estimate the impact of today’s amended 

standards. The first spreadsheet calculates LCCs and PBPs of potential new energy 

conservation standards. The second provides shipments forecasts and calculates impacts 

of potential new energy conservation standards on national NES and NPV. DOE also 

assessed manufacturer impacts, largely through use of the Government Regulatory 

Impact Model (GRIM). The two spreadsheets are available online at the rulemaking 

website:

http://www1.eere.energy.gov/buildings/appliance_standards/product.aspx/productid/66.

Additionally, DOE estimated the impacts of energy conservation standards for 

distribution transformers on utilities and the environment using a version of the Energy 

Information Administration’s (EIA’s) National Energy Modeling System (NEMS) for the 

utility and environmental analyses. The NEMS model simulates the energy sector of the 

U.S. economy. EIA uses NEMS to prepare its Annual Energy Outlook (AEO), a widely 

known energy forecast for the United States. The version of NEMS used for appliance 
62

standards analysis, called NEMS-BT,

21 is based on the AEO version with minor 

modifications.22 The NEMS-BT offers a sophisticated picture of the effect of standards 

because it accounts for the interactions between the various energy supply and demand 

sectors and the economy as a whole.

A.

For the market and technology assessment, DOE develops information that 

provides an overall picture of the market for the equipment concerned, including the 

purpose of the equipment, the industry structure, and market characteristics. This activity 

includes both quantitative and qualitative assessments, based primarily on publicly 

available information. The subjects addressed in the market and technology assessment 

for this rulemaking included scope of coverage, definitions, equipment classes, types of 

equipment sold and offered for sale, and technology options that could improve the 

energy efficiency of the equipment under examination. Chapter 3 of the TSD contains 

additional discussion of the market and technology assessment.

Market and Technology Assessment

 21BT stands for DOE’s Building Technologies Program (http://www1.eere.energy.gov/buildings/).

22 The EIA allows the use of the name “NEMS” to describe only an AEO version of the model without any 

modification to code or data. Because the present analysis entails some minor code modifications and runs 

the model under various policy scenarios that deviate from AEO assumptions, the name “NEMS-BT” refers 

to the model as used here. For more information on NEMS, refer to The National Energy Modeling 

System: An Overview, DOE/EIA–0581 (98) (Feb.1998), available at: 

http://tonto.eia.doe.gov/FTPROOT/forecasting/058198.pdf.
63

1. Scope of Coverage

This section addresses the scope of coverage for today’s final rule, stating what

equipment will be subject to amended standards.

a. Definitions

Today’s standards rulemaking concerns distribution transformers, which include 

three categories: liquid-immersed, low-voltage dry-type (LVDT), and medium-voltage 

dry-type (MVDT). The definition of a distribution transformer was presented in EPACT 

2005, then further refined by DOE when it was codified into 10 CFR 431.192 by the 

April 27, 2006, final rule for distribution transformer test procedures (71 FR 24972) as 

follows:

Distribution transformer

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

means a transformer that:

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

(3) is rated for operation at a frequency of 60 Hz; and

(4) has a capacity of 10 kVA to 2,500 kVA for liquid-immersed units and 15 kVA 

to 2,500 kVA for dry-type units; but

(5) The term distribution transformer

(i) autotransformer;

does not include a transformer that is an:

(ii) drive (isolation) transformer;

(iii) grounding transformer;

(iv) machine-tool (control) transformer;
64

(v) non-ventilated 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.

Additional detail on the definitions of each of these excluded transformers, which 

are defined at 10 CFR 431.192, can found in chapter 3 of the TSD.

Many stakeholders expressed support for the defined scope of coverage presented 

in the NOPR. (ABB, No. 158 at p. 5; Cooper, No. 165 at p.2; HI, No. 151 at p. 12; 

KAEC, No. 149 at p. 4; NEMA, No. 170 at p. 8; PEMCO, No. 183 at p. 2; Prolec-GE, 

No. 177 at p. 7) NRECA pointed out that while some of its members might purchase 

distribution transformers outside the scope of coverage so few of these types of 

transformers are made it does not warrant a change in coverage. (NRECA, No. 172 at p. 

4-5) Progress Energy agreed, noting that while utilities will occasionally purchase 

transformers outside of this range, it is a very small percentage of the total number of 

distribution transformers purchased. (PE, No. 192 at p. 4) EEI was not aware of any of 
65

member that purchased units outside of the current defined kVA range. (EEI, No. 185 at 

p. 5) Finally, BG&E and ComEd noted that DOE has spent a significant amount of time 

developing efficiency levels for each kVA size and that therefore they supported the 

current scope. (BG&E, No. 182 at p. 3; ComEd, No. 184 at p. 3) Power Partners was also 

in support of the current scope, but noted that if separate product classes were established 

for overhead transformers and network/vault transformers the kVA scope for those 

product classes should be aligned with the specific requirements for those product 

standards. (Power Partners, No. 155 at p. 3)

Several stakeholders expressed that additional kVA ranges should be added to the 

scope of coverage. Specifically, Schneider Electric requested that for LVDT products, the 

following kVA ranges would add value to the national impact benefits: 1kVA through 

500kVA single phase and 3kVA through 1500kVA three phase. (Schneider, No. 180 at p. 

4) Similarly, CDA requested an increased range, urging DOE to extend its kVA coverage 

to sizes about 2,500 kVA . (CDA, No. 153 at p. 2)

Earthjustice expressed concern over sealed and non-ventilating transformers. It 

felt that these products represented a potential loophole for smaller transformers in DL7 

and noted that DOE should revise its definition to ensure these units do not displace 

covered units. (Earthjustice, No. 195 at p. 6) Similarly, Earthjustice noted revisions to the 

definition of “uninterruptible power supply transformer might be necessary” as some 

manufacturers are selling exempt UPS units, that are otherwise not covered, for general 
66

purpose applications at a cost of 30-40 percent lower than covered transformers.

(Earthjustice, No. 195 at p. 6) CDA requested that DOE seek legislation to expand its 

scope to include power transformers. (CDA, No. 153 at p. 2)

Schneider Electric requested that DOE reevaluate several definitions in its scope 

of coverage. First, it asked that DOE address its tap ranges and the determination of 

covered equipment versus products versus exempt equipment to possibly capture further 

energy savings. Second, it requested that DOE re-evaluate special impedance 

transformers and ranges. Finally, it noted that because low voltage is limited to 600 volts 

and below, market conditions have created multiple voltages in the 1.2kV class of 

equipment, but current standards23 require this equipment to be evaluated as medium 

voltage or excluded since the secondary voltage is limited to less than 600 volts.

(Schneider, No. 180 at p. 12) Schneider believes that these equipment groups and 

definitions require reconsideration to prevent circumvention of standards and capture 

further energy savings. 

DOE appreciates the comment on its scope of coverage. With respect to kVA, 

DOE’s current standards are consistent with several NEMA publications. For liquidimmersed and medium-voltage dry-type transformers, both DOE coverage and that of 

NEMA’s TP-1 standard extends to 833 kVA for single-phase units and 2500 kVA for 

three-phase units. For low-voltage dry-type units, both DOE coverage and that of 

 23 See 10 CFR 431.196.
67

NEMA’s Premium specification extends to 333 kVA for single-phase units and 1000 

kVA for three-phase units. DOE cites these documents as evidence that its kVA scope is 

consistent with industry understanding. DOE may revise its understanding in the future as 

the market evolves, but for today’s rule maintains the kVA scope proposed in the NOPR.

For sealed and nonventilating transformers, uninterruptible power supply 

transformers, special impedance transformers, and those with tap ranges of greater than 

twenty percent, DOE notes that these types of equipment are specifically excluded from 

standards under EPCA, as amended, 42 USC 6291 (35)(B)(ii)), as codified at 10 CFR 

431.192. 

Cooper Power systems requested clarification on several points relating to scope 

of coverage. Some transformers are built with the ability to output at multiple voltages, 

any number of which may fall within DOE’s scope of coverage. For transformers having 

multiple nominal voltage ratings that straddle the present boundaries of DOE’s scope of 

coverage (i.e., a secondary voltage of 600/1200 volts), Cooper recommended that DOE 

clarify whether the entire distribution transformer is exempt from efficiency standards. 

Cooper felt it was unclear if both configurations would have to meet the efficiency 

standard, neither would meet the standard, or only the secondary voltage of 600 would 

have to meet the standard. (Cooper Power Systems, No. 222 at p. 3) Second, for threephase transformers with wye-connected phase windings or single-phase transformers that 

are rated for externally connecting in a wye configuration, where the phase- to- phase 
68

voltage exceeds the present boundaries of the definition of distribution transformer, 

Cooper requested that DOE clarify that these units are exempt from the standard because 

the secondary voltage exceeds 600 volts. (Cooper Power Systems, No. 222 at p. 3)

DOE clarifies that the definition of distribution transformer refers to a transformer 

having an output voltage of 600 volts or less, not having only an output voltage of less 

than 600 volts. If the transformer has an output of 600 volts or below and meets the other 

requirements of the definition, DOE considers it to be a distribution transformer within 

the scope of coverage and therefore subject to standards. This applies equally to 

transformers with split secondary windings (as in Cooper’s first example) and to threephase transformers where the delta connection may fall below 601 volts and the wye 

connection may not. DOE also clarifies that once it is determined that a transformer is 

subject to standards, DOE’s test procedure requires that a transformer comply with the 

standard when tested in the configuration that produces the greatest losses, regardless of 

whether that configuration alone would have placed the transformer at-large within the 

scope of coverage under 10 CFR 431.192.

b. Underground and Surface Mining Transformer Coverage

In the October 12, 2007, final rule on energy conservation standards for 

distributions transformers, DOE codified into 10 CFR 431.192 the definition of an 

underground mining distribution transformer as follows:
69

Underground mining distribution transformer means a medium-voltage dry-type

distribution transformer that is built only for installation in an underground mine or inside 

equipment for use in an underground mine, and that has a nameplate which identifies the 

transformer as being for this use only. 72 FR 58239.

In that same final rule, DOE also clarified that although it believed those 

transformers were within its scope of coverage, it was not establishing energy 

conservation standards for underground mining transformers. At the time, DOE 

recognized that the mining transformers were subject to unique and extreme dimensional 

constraints that impact their efficiency and performance capabilities. Therefore, DOE 

established a separate equipment class for mining transformers and stated that it might

consider energy conservation standards for such transformers at a later date. Although 

DOE did not establish energy conservation standards for such transformers, it also did not 

add underground mining transformers to the list of excluded transformers in the 

definition of a distribution transformer. DOE maintained that it had the authority to cover 

such equipment if, during a later analysis, it found technologically feasible and 

economically justified energy conservation standard levels. 72 FR 58197.

Several stakeholders commented on DOE’s definition for mining transformers

during the current rulemaking. Joy Global Surface Mining recommended that surface 

mining transformers be added to the exemption list under the following definition:

“Surface mining transformer is a medium-voltage dry-type distribution transformer that is 
70

built only for installation in a surface mine, on-board equipment for use in a surface mine 

or for equipment used for digging or drilling above ground. It shall have a nameplate 

which identifies the transformer as being for this use only.” (Joy Global Surface Mining, 

No. 214 at p. 1) ABB and PEMCO agreed that ordinary (i.e., non-surface) mining 

transformers should be moved to the exclusion list in 10 CFR 431.192 (5). (ABB, No. 

158 at p.5; PEMCO, No. 183 at p. 2) PEMCO felt strongly that underground mining 

transformers should be in the list of transformers excluded from the efficiency standard, 

pointing out that “underground mining transformers require the use of much heavier 

cores and thus have an even larger reason to be excluded than some product types already 

excluded.” (PEMCO, No. 183 at p. 2) NEMA commented that all underground mining 

transformers should be made exempt from the DOE energy efficiency regulation for 

MVDT due to the special circumstances they must operate under; dimensions and weight 

are critical for these products, and to reduce the weight and size these transformers are 

operated near full load, therefore, compliance with DOE regulation will not optimize 

efficiency. (NEMA, No. 170 at p. 11) Cooper Power suggested that DOE expand the 

definition of mining transformers to include both liquid filled and dry-type transformers, 

and specify that this only applies to transformers used inside the mine itself; Cooper 

supports the exclusion of these transformers from efficiency standards. (Cooper, No. 165 

at p. 2) ABB asserted that the definition of mining transformers should be expanded to 

include transformers used for digging or tunneling. Furthermore, ABB asserted that such

equipment should be moved to the exclusion list in 10 CFR 431.192 (5). (ABB, No. 158 

at p. 6)
71

DOE has learned from comments received throughout the rulemaking that mining 

transformers are subject to several constraints that are not usually concerns for 

transformers used in general power distribution. Because space is critical in mines, an 

underground mining transformer may be at a considerable disadvantage in meeting an 

efficiency standard. Underground mining transformers are further disadvantaged by the 

fact that they must supply power at several output voltages simultaneously. For today’s 

rule, DOE will again set no standards for underground mining transformers but expands 

this treatment to include surface mining transformers. Moreover, as commenters point 

out, surface mining transformers are used to operate specialized machinery which carries 

space constraints of its own. Furthermore, mining transformers in general perform a role 

that may differ from general power distribution in many regards, including lifetime, 

loading, and often the need to supply power at several voltages simultaneously. As DOE 

had intended its prior determination regarding mining transformers to apply to all mining 

activities, for today’s rule, DOE will again set no standards for underground mining 

transformers but clarify that this determination also applies to surface mining 

transformers. Thus, DOE has amended the definition of “mining transformer” to include 

surface mining transformers.

In view of the above, DOE recognizes a potential means to circumvent energy 

efficiency standards requirements for distribution transformers. Therefore, DOE 

continues to leave both underground and surface mining transformers off of the list of 
72

distribution transformers that are not covered under 10 CFR 431.192, but instead reserve 

a separate equipment class for mining transformers. DOE may set standards in the future 

if it believes that underground or surface mining transformers are being purchased as a 

way to circumvent energy conservation standards for distribution transformers otherwise 

covered under 10 CFR 431.192.

c. Step-Up Transformers

In the 2012 NOPR, DOE proposed to continue to not set standards for step-up 

transformers, as these transformers are not ordinarily considered to be performing a 

power distribution function. However, DOE was aware that step-up transformers may be 

able to be used in place of step-down transformers (i.e., by operating them backwards) 

and may represent a potential means to circumvent any energy efficiency requirements as 

standards increase. In the NOPR, DOE requested comment regarding this issue.

Many stakeholders expressed support for adding step-up transformers to the scope 

of coverage. Howard Industries commented that there is no practical reason for excluding 

these transformers, and that DOE should require step-up transformers to meet the same 

efficiency as step-down, as long as either the output or input voltage is 600 volts or less. 

They expressed concern that eliminating these transformers would present a potential 

loophole. (HI, No. 151 at p. 12) Prolec-GE agreed, noting that to eliminate this loophole, 

step-up transformers should at least indicate their purpose on their nameplates. (ProlecGE, No. 146 at pp. 55−56) However, Earthjustice commented that simply requiring 
73

nameplates for these transformers would be unlikely to deter some users from installing 

step-up transformers in place of covered transformers. They expressed their concern that 

DOE had not addressed potential loopholes that had been identified in the rulemaking.

(Earthjustice, No, 195 at pp. 5−6) Advocates agreed with comments made during 

negotiations arguing that step-up transformers should be covered by new standards due to 

similarities to distribution transformer that could easily lead to substitution and 

circumvention. (Advocates, No. 186 pp. 5−6) Finally, Berman Economics commented 

that because step-up transformers had not been included in the 2007 final rule, leaving 

them uncovered may lead to unintended circumvention. (Berman Economics, No. 221 at 

p. 7) 

Other stakeholders expressed their support for DOE’s decision to not separately 

define and set standards for step-up transformers. (Cooper, No. 165 at p. 2; NEMA, No. 

170 at p. 8; BG&E, No. 182 at p. 3) APPA and EEI agreed, pointing out that while in 

emergency conditions one can occasionally see a step-up transformer used as a step-down 

transformer, these situations are rare and overall do not result in significant transformer 

efficiency loss. (APPA, No. 191 at p. 6; EEI, No. 185 at p. 5-6) Progress Energy 

commented similarly, noting that they do not purchase step-up transformers for use as 

step-down transformers. (PE, No. 192 at p. 4) ABB and Prolec-GE agreed with the 

decision to not set separate standards for step-up transformers but requested that these 

transformers be identified on their nameplate uniformly across the industry. (ABB, No. 

158 at p. 6; Prolec-GE, No. 177 at p. 7) PEMCO commented that no action was necessary 
74

as the product class falls outside the current definition of a distribution transformer.

(PEMCO, No. 183 at p. 2) Schneider Electric sought clarification given the existing 

definition in section 431.192 and noted that the current standards do not exclude step-up 

LVDT transformers as written. (Schneider, No. 180 at p. 4)

For today’s rule, DOE continues to consider step-up transformers as equipment 

that is not covered, because they do not perform a function traditionally viewed as power 

distribution. Transformer coverage is not determined simply based on whether the 

transformer is stepping voltage up or down. DOE clarifies that liquid-immersed step-up 

transformers usually fall outside of the rulemaking scope of coverage because of limits 

on input and output voltage, and not because they are excluded per se. Liquid-immersed 

and medium-voltage dry-type transformers tend to fall within DOE’s scope of coverage 

only if stepping down voltage because the input voltage upper limit (34.5 kV) is much 

greater than the output voltage limit (600 V). No such distinction exists for LVDT 

transformers, which are covered for input and output voltages of 600 V or below,

regardless of whether stepping voltage up or down. Nonetheless, because of the 

circumvention risk, DOE will monitor the use of step-up transformers and consider 

establishing standards for them, if warranted. 

d. Low-Voltage Dry-Type Distribution Transformers

10 CFR 431.192 defines the term “low-voltage dry-type distribution transformer”

to be a distribution transformer that:
75

(1) has an input voltage of 600 V or less;

(2) is air-cooled; and

(3) does not use oil as a coolant.

Because EPACT 2005 prescribed standards for LVDTs, which DOE incorporated 

into its regulations at 70 FR 60407 (October 18, 2005) (codified at 10 CFR 431.196(a)), 

LVDTs were not included in the 2007 standards rulemaking. As a result, the settlement 

agreement following the publication of the 2007 final rule does not affect LVDT 

standards. Without regard to whether DOE may have a statutory obligation to review 

standards for LVDTs, DOE has analyzed all three transformer types and is proposing 

standards for each in this rulemaking.

e. Negotiating Committee Discussion of Scope

Negotiation participants noted that both network/vault transformers and “data 

center” transformers may experience disproportionate difficulty in achieving higher 

efficiencies because of certain features that may affect consumer utility. (ABB, Pub. Mtg. 

Tr., No. 89 at p. 245) In the NOPR, DOE reprinted definitions for these terms, which 

were proposed at various points by committee members. 77 FR 7301. DOE sought

comment in its NOPR about whether it would be appropriate to establish separate 

equipment classes for any of the following types and, if so, how such classes might be 

defined such that it was not financially advantageous for customers to purchase 
76

transformers in either class for general use. Please see IV.A.2.c for further discussion of

DOE’s equipment classes in today’s final rule.

2. Equipment Classes

DOE divides covered equipment into classes by: (a) the type of energy used; (b) 

the capacity; and/or (c) any performance-related features that affect consumer utility or 

efficiency. (42 U.S.C. 6295(q)) Different energy conservation standards may apply to 

different equipment classes (ECs). For the preliminary and NOPR analyses, DOE 

analyzed the same 10 ECs as were used in the previous distribution transformers energy 

conservation standards rulemaking.

24 These 10 equipment classes subdivided the 

population of distribution transformers by:

(a) type of transformer insulation—liquid-immersed or dry-type, 

(b) number of phases—single or three,

(c) voltage class—low or medium (for dry-type units only), and

(d) basic impulse insulation level (for medium-voltage dry-type units only).

On August 8, 2005, the President signed into law EPACT 2005, which contained 

a provision establishing energy conservation standards for two of DOE’s equipment 

classes—EC3 (low-voltage, single-phase dry-type) and EC4 (low-voltage, three-phase 

dry-type). With standards thereby established for low-voltage dry-type distribution 

 24 See chapter 5 of the TSD for further discussion of equipment classes.
77

transformers, DOE no longer considered these two equipment classes for standards 

during the 2007 final rule. In today’s rulemaking, however, DOE has decided to address 

all three types of distribution transformers and is establishing new standards for all three 

types of distribution transformers, including low-voltage dry-type distribution 

transformers. Table IV.1 presents the ten equipment classes proposed in the NOPR and 

finalized in this rulemaking and provides the associated kVA range with each.

Table IV.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 15-833 kVA

6 Dry-type Medium Three 20-45kV 15-2500 kVA

7 Dry-type Medium Single 46-95kV 15-833 kVA

8 Dry-type Medium Three 46-95kV 15-2500 kVA

9 Dry-type Medium Single ≥ 96kV 75-833 kVA

10 Dry-type Medium Three ≥ 96kV 225-2,500 kVA

a. Less-Flammable Liquid-Immersed Transformers

During the previous rulemaking, DOE solicited comments about 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, 
78

liquid-immersed” (LFLI) transformers, these units are marketed to some applications 

where a fire would be especially costly and traditionally served by the dry-type market, 

such as indoor applications.

During preliminary interviews with manufacturers, DOE was informed that LFLI 

transformers might offer the same utility as dry-type transformers since they were 

unlikely to catch fire. Manufacturers also stated that LFLI transformers could have a 

minor efficiency disadvantage relative to traditional liquid-immersed transformers 

because their more viscous insulating fluid requires more internal ducting to properly 

circulate.

In the October 2007 standards final rule, 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 liquidimmersed) was a performance-related feature that affects the energy efficiency of the 

equipment and, therefore, dry-type and liquid-immersed should be analyzed separately. 

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).
79

DOE revisited the issue in this rulemaking 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, combining LFLIs and dry-types into one equipment class may 

result in standard levels that dry-type units are unable to meet. Therefore, DOE decided 

not to analyze LFLI transformers in the same equipment classes as dry-type distribution 

transformers.

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 because their 

higher temperature tolerance may allow the unit to be downsized and run hotter than 

mineral oil units. For these reasons, DOE believes that LFLI transformers would not be 
80

disproportionately affected by standards set in the liquid-immersed equipment classes. 

Therefore, DOE did not consider LFLI in a separate equipment class.

b. Pole-Mounted Liquid-Immersed Distribution Transformers

During negotiations and in response to the NOPR, several parties raised the 

question of whether pole-mounted, pad-mounted, and possibly other types of liquidimmersed transformers should be considered in separate equipment classes. For example,

pole-mounted distribution transformers may carry differential incremental cost 

characteristics and face different size and weight constraints than transformers mounted 

on the ground. They may also have different features, and experience different loading 

conditions than some other transformer types. These type of questions led DOE to request 

comment in the NOPR on whether pole-mounted distribution transformers warranted 

consideration in a separate equipment classes. A number of parties responded. In 

response to suggestions in these comments, DOE gave more detailed consideration to 

separating pole-mounted distribution transformers in a supplementary NOPR analysis, 

announced in a June 4, 2012, Notice of Public Meeting and Data Availability. 77 FR 

32916.

APPA, ASAP, BG&E, ComEd, Howard, Progress Energy, Pepco, and Power 

Partners all supported separation of pole-mounted transformers into separate equipment 

classes for the above-mentioned reasons. Size and weight was the most commonly-cited 

reason. (APPA, No. 191 at p. 7, No. 237 at p. 3; ASAP, No. 146 at pp. 69–70; BG&E, 
81

No. 146 at p. 69, No. 182 at p. 4; ComEd, No. 184 at p. 8, No. 227 at p. 2; HI, No. 151 at 

p. 4, No. 226 at p. 1; PE, No. 192 at p. 5, Pepco, No. 146 at p. 68, No. 145 at pp. 2−3;

Power Partners, No. 155 at p. 2)

ABB, NEMA, Berman Economics, Cooper, EEI, AK Steel, and KAEC stated that 

the increase in standards did not warrant separate treatment of pole-mounted 

transformers, stating that separation adds complexity to the regulation and does not allow 

manufacturers of both pole-mounted and other types of liquid-immersed distribution 

transformers to standardize manufacturing and design practices across product lines. 

(ABB, No. 158 at p. 6; Berman Economics, No. 150 at p. 19, No. 221 at p. 4; Cooper, 

No. 165 at p. 3; EEI, No. 229 at p. 2; AK Steel, No. 230 at p. 3; KAEC, No. 149 at p. 4; 

NEMA, No. 170 at p. 12)

The Advocates, NEMA, and Prolec-GE commented that separation may be 

warranted but only if DOE opted for higher standards than were proposed in the NOPR.

(Advocates, No. 158 at p. 13; Prolec-GE, No. 177 at p. 3; NEMA, No. 170 at p. 14) 

NEMA further noted that the matter was complicated and that there were 

advantages to both approaches. (NEMA, No. 225 at p. 4) Finally, EEI and NRECA

commented that DOE should explore the matter but in the next rulemaking for 

distribution transformers. (EEI, No. 185 at p. 7; NRECA, No. 172 at p. 7) NRECA 
82

supported the concept of separation, but this support was qualified by concerns that DOE 

might raise the efficiency levels. (NRECA, No. 172 at pp. 5−6)

Based on the array of views on this issue and the potential energy and cost 

savings to weigh, DOE conducted further analysis of this of liquid-immersed 

transformers issue and presented the findings of its supplementary analysis at a public 

meeting on June 20, 2012. 77 FR 32916 (June 4, 2012). In today’s rule, DOE has chosen 

not to separate pad and pole-mounted transformers. DOE’s concerns about steel 

competitiveness and availability were not resolved through comments in response to both 

the NOPR and the supplemental analysis. Moreover, the comments did not demonstrate 

that establishing standards for transformers separated by those on pads and those on poles 

was superior to the approach taken in the proposed rule. Therefore, DOE chose not to 

finalize separate standards for pad-mounted transformers in today’s final rule. However , 

DOE appreciates the concerns about allowing manufacturers to standardize 

manufacturing and design practices across product lines. DOE may consider establishing 

separate equipment classes for pole-mounted distribution transformers in the future, but 

at present believes the equipment class structure proposed in the NOPR to be justified for

today’s final rule.

c. Network and Vault Liquid-Immersed Distribution Transformers

During negotiations, several parties raised the question of whether network, vault, 

and possibly other types of liquid-immersed transformers should be considered in 
83

separate equipment classes. In the 2012 NOPR, DOE considered separating these types of 

transformers and sought comment from manufacturers on this matter. 

In response to the NOPR, many stakeholders commented on separation of

network and vault transformers into new equipment classes. Several stakeholders 

expressed support for separate equipment classes for network and vault transformers,

noting that they agreed with the definition put forth by the negotiations working group.

(ABB, No. 158 at p. 6; Adams Electrical Coop, No. 163 at p. 2; APPA, no. 191 at p. 6; 

BG&E, No. 182 at p. 3; BG&E, No. 223 at p. 2; CFCU, No. 190 at p. 1; ComEd, No. 184 

at p. 4; EEI, No. 229 at p. 2; KAEC, No. 149 at p.4; NEMA, No. 146 at p. 67; NEMA, 

No. 170 at p. 11; NRECA, No. 172 at p. 5; NRECA, No. 228 at pp. 2−3; Power Partners, 

No. 155 at p. 2) Stakeholders felt that this separate equipment class should have 

efficiency standards that are unchanged from the levels that have been in effect since 

January 1, 2010, set in the 2007 final rule. (Cooper, No. 165 at p. 3; Cooper Power 

Systems, No. 222 at p. 4; EEI, No. 185 at p. 3; NEMA, No. 170 at p. 8; PE, No. 192 at p. 

5; Prolec-GE, No. 177 at pp. 7, 12; PE, No. 192 at p. 8)

Many manufacturers noted that network/vault transformers should be separated

based on the tight size and space restrictions placed on them. (NEMA, No. 225 at p. 3; 

Prolec-GE, No. 146 at p. 15; ABB, No. 158 at p. 9) In many cases, manufacturers stated 

that higher efficiency transformers cannot fit into existing vaults and still maintain 

required safety and maintenance clearance. (NEMA, No. 170 at p. 3) Stakeholders argued 
84

that any increase in size due to increased efficiency standards would eliminate any 

economic benefit from higher efficiency due to the extremely high costs of modifying 

existing vault or other underground infrastructure in urban areas. (Adams Electric Coop, 

No. 163 at p. 2; BG&E, No. 223 at pp. 2−3; ConEd, No. 184 at p. 4; NRECA, No. 172 at 

p. 3; Pepco, No. 145 at p. 23; ABB, No. 158 at p. 9; Howard Industries, No. 226 at pp. 

1−2; APPA, No. 191 at p. 4; Pepco, No. 145 at p. 3; ConEd, No. 236 at pp. 1−2) Others 

pointed out that expansion of vaults and manholes in city environments is sometimes

even physically impossible due to space constraints. (ConEd, No. 184 at p. 4) Howard 

Industries noted that often American National Standards Institute (ANSI) standards 

govern the sizes of these types of transformers based on established maximum 

dimensional constraints due to vault sizing. (HI, No. 151 at p. 3) Prolec-GE commented 

that the application of these transformers not only requires them to be compact, but also 

built to a much higher level of ruggedness and durability. (Prolec-GE, No. 238 at pp. 

1−2) 

Con Edison, who is the largest user of network- and vault-based distribution 

transformers in the United States, pointed out that while it agrees with separation of 

network-based transformers, modifications were needed to the definition presented in 

Appendix 1-A to include transformers purchased by Con Edison, who is the largest user 

of network- and vault-based distribution transformers in the United States. (ConEd, No. 

236 at p. 2)
85

Other stakeholders noted that while network and vault transformers could 

experience dimensional problems at higher efficiencies, these problems are diminished at 

lower levels. Berman Economics notes that “the de minimis increase in efficiency 

proposed by DOE in this NOPR do not appear to warrant any such special treatment.”

(Berman Economics, No. 150 at p. 21) ASAP agreed, noting that if the final rule

efficiency levels stayed as modest as those in the NOPR then separation was not 

necessary. (ASAP, No. 146 at pp. 66−67)

Multiple stakeholders expressed hesitation about separating vault transformers. 

Berman Economics recommended that DOE consider a separate class for network 

transformers only, as the additional electronics and protections required of a networked 

transformer likely would make it an uneconomic substitute for a non-networked 

transformer, an argument that could not be made for vault transformers. (Berman 

Economics, No. 221 at p. 5) Furthermore, Advocates pointed out that vault transformers 

may be a compliance loophole/risk and, at minimum, nameplate marking that reads “For 

installation in a vault only,” should be required for this equipment. (Advocates, No. 235 

at p. 4) Others noted that the idea of vault transformers being used as substitutes for padmounted transformers is “fraught with over-simplifications and faulty assumptions.”

(APPA, No. 237 at pp. 2−3) They believed that substitution would not occur if DOE 

defined and carved out network and vault transformers per the IEEE definitions. (APPA, 

No. 237 at pp. 2−3) It was also pointed out that utilities pay as much as two times as 
86

much for a vault transformer as for pad-mounted units of similar capacity, (EEI, No. 229 

at p. 5)

DOE appreciates the attention and depth of thought given by stakeholders to this 

nuanced rulemaking issue. At this time, DOE believes that establishing a new equipment 

class for network and vault based transformers is unnecessary. It is DOE’s understanding 

that there is no technical barrier that prevents network and vault based transformers from 

achieving the same levels of efficiency as other liquid-immersed distribution 

transformers. However, DOE does understand that there are additional costs, besides 

those to the physical transformer, which may be incurred when a replacement transformer 

is significantly larger than the original transformer and does not allow for the necessary 

space and maintenance clearances. Rather than establishing a new equipment class, DOE 

has considered the costs for such vault replacements in the NIA. Please see section X.

Therefore, as stated, DOE is not establishing a new equipment class for these transformer 

types, but may consider doing so in a future rulemaking.

d. BIL Ratings in Liquid-Immersed Distribution Transformers

During negotiations, several parties raised the question of whether liquidimmersed distribution transformers should have standards set according to BIL rating, as 

do medium-voltage dry-type distribution transformers. (ABB, Pub. Mtg. Tr., No. 89 at p. 

218) Other parties responded in response to the NOPR with suggestions about how to 

address BIL ratings in liquid-immersed distribution transformers. NEMA pointed out that 
87

as BIL increases, a greater volume of core material is needed, adding both expense and

no-load losses. (NEMA, No. 170 at p. 4) Cooper agreed with separation by BIL, pointing 

out that “standards by BIL level will help differentiate transformers that require more 

insulation and that are less efficient by nature.” (Cooper, No. 165 at p. 3) Howard 

Industries opined that it felt 200 kV BIL and higher transformers should have their own 

category whose efficiency levels were capped at those set in the 2007 Final Rule. It noted 

that high BIL ratings require additional insulation to meet American National Standards 

Institute (ANSI) requirements and such additional insulation limits the achievable 

efficiency for these transformers. (HI, No. 151 at p. 12) Berman Economics supported 

separation, and commented that DOE could split at 200 kV if these transformers would 

not be cheaper than 150 BIL transformers at the newly set standard. (Berman Economics, 

No. 221 at p. 6) BG&E does not purchase 200 kV BIL transformers but supported 

maintaining the current 2007 Final Rule efficiency levels for these transformers due to 

construction and weight limitations. (BG&E, No. 223 at p. 2) 

Several stakeholders felt that separate standards should be set for all transformers 

with a BIL of 150 kV or higher. (NRECA, No. 228 at p. 3; Advocates No. 235 at pp. 4−5; 

EEI, No. 229 at pp. 5−6; APPA, No. 237 at p. 3) Stakeholders who supported a split at 

150 kV felt that all transformers with BILs above this level should not have increasing 

standards in this rule; the standards should remain at efficiency levels set in the 2007 

final rule. (NEMA, No. 225 at p. 3-4; Howard Industries, No. 226 at p. 2) Prolec-GE 

pointed out that a class of only 200 kV and above is of extremely limited volume and 
88

provides no benefit, stating that there is a significant step up in cost for higher 

efficiencies at 150 kV BIL. (Prolec-GE, No. 238 at p. 2) “To prevent substitution of 

higher BIL rated transformers as a means of circumventing the efficiency standard, 

Cooper recommends using coil voltage as a defining criterion for the 150kV BIL class.

Transformers having an insulation system designed to withstand 150 kV BIL and either a 

line-to-ground or line-to-neutral voltage that is 19kV (e.g. 34500GY/19920 or 19920 

Delta) or greater would be required to qualify as a true 150kV BIL distribution 

transformer.” (Cooper Power Systems, No. 222 at pp. 3−4)

NEMA and KAEC recommended that the efficiency levels proposed in the NOPR 

be set for liquid-immersed transformers at 95 kV BIL and below only, while all other 

BILs remain at the current standard. (NEMA, No. 170 at p. 10; KAEC, No. 149 at p. 5) 

Prolec-GE agreed that the liquid-immersed transformers should be separated at 95 kV 

BIL and below and above 95 kV. It also suggested that DOE add more design lines for 

these equipment classes, as it did not believe the scaling was accurate. (Prolec-GE, No. 

177 at p. 8) Power Partners commented that there should be several BIL divisions for 

liquid-immersed distribution transformers and suggested that DOE have equipment 

classes for the following: 7200/12470Y 95BIL, 14400/2490Y 125BIL, 19920/34500Y 

150BIL, and 34500 200 BIL. (Power Partners, No. 155 at p. 3)

Several stakeholders supported the concept of exploring how BIL affects 

efficiency but felt that it was not a significant enough issue to delay publication of this 
89

rule. They proposed that DOE investigate this concept in the next rulemaking. (PE, No. 

192 at p.6; NRECA, No. 172 at p. 6; EEI, No. 185 at p. 8; ComEd, No. 184 at p. 10; 

BG&E, No. 182 at p. 5; APPA, No. 191 at p. 7) Similarly, ABB commented that at the 

current proposed levels, ABB does not recommend moving to a separate BIL range for 

liquid-immersed transformers. If efficiency levels were to increase, ABB would support a 

change, but did not feel it is warranted with the proposed levels. (ABB, No. 158 at p. 7) 

HVOLT agreed that at proposed levels, separating by BIL was likely not needed, and 

pointed out that efficiency impacts of varied BIL were smaller in liquid-immersed 

transformers than in dry-type transformers. (HVOLT, No. 146 at p. 73) 

DOE appreciates all of the input regarding separating standards for different BIL 

ratings of liquid-immersed distribution transformers. Similar to network- and vault-based 

transformers, DOE may give strong consideration to establishing equipment classes by 

BIL rating when considering increased future standards, but does not perceive a strong 

technological need for such separation at the efficiency levels under consideration in 

today’s rule and does not, therefore, establish separate equipment classes for liquidimmersed distribution transformers by BIL rating.

e. Data Center Transformers

During negotiations, participants noted that data center transformers may 

experience disproportionate difficulty in achieving higher efficiencies due to certain 

features that may affect consumer utility. In the NOPR, DOE proposed the definition 
90

below for data center transformers and sought comment both on the definition itself, and 

whether to separate data center transformers into their own equipment class. It noted that

separation, the equipment classes must be defined such that it would not be financially 

advantageous for consumers to purchase data center transformers for general use. 

i. Data center transformer means a three-phase low-voltage dry-type distribution 

transformer that—

(i) is designed for use in a data center distribution system and has a 

nameplate identifying the transformer as being for this use only;

(ii) has a maximum peak energizing current (or in-rush current) less 

than or equal to four times its rated full load current multiplied by 

the square root of 2, as measured under the following conditions—

1. during energizing of the transformer without external devices 

attached to the transformer that can reduce inrush current;

2. the transformer shall be energized at zero +/- 3 degrees voltage 

crossing of a phase. Five consecutive energizing tests shall be 

performed with peak inrush current magnitudes of all phases 

recorded in every test. The maximum peak inrush current 

recorded in any test shall be used;

3. the previously energized and then de-energized transformer 

shall be energized from a source having available short circuit 
91

current not less than 20 times the rated full load current of the 

winding connected to the source; and

4. the source voltage shall not be less than 5 percent of the rated 

voltage of the winding energized; and 

(vii) is manufactured with at least two of the following other attributes:

1. listed as a Nationally Recognized Testing Laboratory (NRTL), 

under the Occupational Safety and Health Administration, U.S. 

Department of Labor, for a K-factor rating greater than K-4, as 

defined in Underwriters Laboratories (UL) Standard 1561: 

2011 Fourth Edition, Dry-Type General Purpose and Power

Transformers;

2. temperature rise less than 130°C with class 22025 insulation or 

temperature rise less than 110°C with class 20026

3. a secondary winding arrangement that is not delta or wye 

(star);

insulation;

4. copper primary and secondary windings;

5. an electrostatic shield; or 

6. multiple outputs at the same voltage a minimum of 15° apart, 

which when summed together equal the transformer’s input 

kVA capacity.

 25 International Electrotechnical Commission Standard 60085 Electrical Insulation- Thermal Evaluation and 

Designation, 3rd edition, 2004 ,page 11 table 1 26 International Electrotechnical Commission Standard 60085 Electrical Insulation- Thermal Evaluation and 

Designation, 3rd edition, 2004 ,page 11 table 1
92

Several stakeholders responded to the request for comment on data center 

transformers. HVOLT agreed with the idea of creating a separate equipment class for 

data center transformers, but noted that “the concept of the inrush current held to four 

times rating is not accurate.” (HVOLT, No. 146 at p. 65) NEMA and KAEC supported 

the establishment of a separate equipment class for data center transformers as well as the 

definition developed by the working group and recommended that the efficiency levels 

for this new class remain at EL0, which is equivalent to the levels of NEMA’s standard 

TP-1 2002. (NEMA, No. 170, at p. 9; KAEC, No. 149 at p. 4 NEMA, No. 170 at p. 5) 

ABB agreed, noting that it supported the definition developed by the working group and 

a separate equipment class for LVDT data center transformers. (ABB, No. 158 at p. 6)

Cooper Power supported the definition, and recommended that the efficiency level for 

these transformers remain at the baseline. (Cooper, no. 165 at p. 3) NRECA noted that 

few of its members serve data centers and that it does not have any data on load factors 

and peak responsibility factors for data centers, but pointed to Uptime Institute and 

Lawrence Berkeley National Laboratories as sources that may have such data available.

(NRECA, No. 172 at p. 5) Howard Industries commented that this proposal would not 

directly affect it or its products and until further information is given it could give no 

response on whether or, so had not there is a necessity for establishing a separate 

equipment class at this time. (HI, No. 151 at p. 3) Finally, Cooper power suggested that, 

if a separate definition for data center transformers is adopted, a 75 percent load level 

should be used in the test procedure. (Cooper, No. 165 at p. 3)
93

DOE appreciates the comments received about data center transformers. In

today’s rule, DOE is not establishing separate equipment classes for data center 

transformers for several reasons. First, after reviewing the proposed definition with 

technical experts, DOE has come to believe that not all of the listed clauses in the 

definition are directly related to efficiency as it would pertain to the specific operating 

environment of a data center. For example, the requirement for copper windings would 

seem generally to aid efficiency rather than hinder it. Second, DOE believes that there 

may be risk of circumvention of standards and that a transformer may be built to satisfy 

the data center definition without significant added expense. Third, DOE understands that 

operators of data centers are generally themselves interested in equipment with high 

efficiencies because they often face large electricity costs. If that were true, they may be 

purchasing at or above today’s standard and be unaffected by the rule. Finally, DOE 

understands that the most significant technical requirement of data center transformers to 

be related to inrush current. In the worst possible case, DOE understands that operators of 

data center transformers can (and perhaps already do) take measures to limit inrush 

current external to the transformer. For these reasons, DOE is not establishing a separate 

equipment class for data center transformers in today’s rule. 

f. Noise and Vibration

Progress Energy recommended to DOE that “any change in efficiency 

requirements fully investigates the impact of higher sound levels and/or vibration.” (PE 
94

No, 92 at p. 10) Progress Energy noted that higher sound or vibration levels or both will 

be of significant concern where users are nearby. (PE, No. 192 at p. 10) Southern 

California Edison reported that it had experienced ferroresonance issues with amorphous 

core transformers in the past. Further, it expressed ferroresonance concerns about lower 

loss designs with M2 core steel. (Southern California Edison, No. 239 at p. 1) However, 

neither EEI nor APPA were aware of vibration or acoustic noise issues associated with 

higher efficiency transformers but conceded that, if there were to be ferroresonance

issues with higher efficiency transformers, it could impact customer satisfaction, 

especially in residential areas. (EEI, No. 185 at p. 19; APPA, No. 191 at p. 13-14) Cooper 

Power Systems commented that it did not expect that the new standards as proposed will 

have any negative effect on performance or increase vibration or acoustic noise. (Cooper, 

No. 165 at p. 6)

DOE understands that, in certain applications, noise, and vibration, or harshness 

(NVH) could be especially problematic. However, based on comments, DOE does not 

believe that NVH concerns would be significant under the efficiency levels proposed and 

it does not propose to establish equipment classes using NVH as criteria for today’s rule. 

DOE notes that several manufacturers offer technologies that reduce NVH in cases where 

it may be of unusual concern.
95

g. Multivoltage Capability

As discussed in section IIII.A, many distribution transformers have primary and 

secondary windings that may be reconfigured to accommodate multiple voltages. In some 

configurations, the transformer may operate less efficiently.

NEMA commented that DOE should exclude from further consideration 

transformers with multiple primary windings, because they are disadvantaged in meeting 

higher efficiencies. (NEMA, No. 225 at p. 6) On the other hand, Prolec-GE commented 

that dual voltage distribution transformers should be included and treated the same as 

high BIL units, and expressed concern about 7200 X 14400 volt transformers where it 

could be less expensive for a user to purchase the dual voltage unit than to purchase a 

14400 volt single voltage unit. Further, Prolec-GE believes that this issue is limited to 

simpler dual voltage ratings where the ratio of the two primary voltages is exactly 2:1, 

and that this potential loophole was not intended under the proposed regulations. (ProlecGE, No. 238 at p. 2)

For the reason outlined in view of this Prolec-GE comment, DOE is not

establishing equipment classes by multivoltage capability in today’s final rule. 

Nevertheless, DOE may consider doing so in future rulemakings, or consider 

modification of the test procedure as discussed in III.A.4, Dual/Multiple-Voltage Primary 

Windings.
96

h. Consumer Utility

A primary consideration in establishment of equipment classes is whether or not 

the equipment under consideration offers differential utility to the consumer. DOE sought 

comment on the establishment of a number of equipment classes, including polemounted, data-center, network/vault-based, and high BIL distribution transformers to 

explore whether stakeholders believed equipment utility could be affected. ABB 

commented that the levels proposed in the NOPR were unlikely to reduce equipment 

performance or utility. (ABB, No. 158 at p. 10)

Although most stakeholder discussion of space-constrained applications centered 

around network/vault-based distribution transformers, Howard Industries mentioned 

another compact application – “ranchrunners” – and requested a separate equipment class 

for such units (HI, No. 151 at p. 5) Based on the limited data submitted, DOE does not 

understand ranchrunners to be used in applications where even minimal size increases 

would necessarily trigger great cost increases. Furthermore, DOE does not believe large 

size or weight increases are likely at the standard levels under consideration. DOE may 

consider further consideration of the impact of increased size and weight in future 

rulemakings, but is not establishing separate equipment classes for ranchrunners in 

today’s final rule.
97

3. Technology Options

The technology assessment provides information about existing technology 

options 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 technology options to improve efficiency include: (1) higher-grade electrical 

core steels, (2) 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 IV.2

Further detail on these technology options can be found in chapter 3 of the final rule

TSD.
98

Table IV.2 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:

Increasing core cross-sectional area (CSA)

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:

Decreasing core CSA

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.

HYDRO-Quebec (IREQ) notified DOE that a new iron-based amorphous alloy 

ribbon for distribution transformers was developed that has enhanced magnetic properties 

while remaining ductile after annealing. Further, IREQ noted that a distribution 

transformer assembly using this technology has been developed. (IREQ, No. 10 at pp. 

1−2)

In response to the NOPR, HYDRO-Quebec offered more information on their 

iron-based amorphous alloy ribbon. It noted that it has two technologies to produce this 

amorphous ribbon: (1) a continuous in-line annealing of an amorphous ribbon moving 

forward at several meters per second and giving a curved shape to the ribbon that remains 

flexible afterwards and can easily be wound into a toroidal core with excellent soft 
99

magnetic properties, and (2) a new kernel topology for an electrical distribution 

transformer compromising a magnetic core made by rolling up the flexible annealed 

amorphous metal ribbon around the coil. (HQ, No. 125 at p. 1) Hydro-Quebec explains

that production of this rolled-up-core transformer technology is automated, and the 

automated continuous production process makes the product cost competitive with 

foreign production. “As for Hydro-Quebec’s flexible ribbon, the annealing technology is 

compatible with implementation of compact, high-throughput, automated, and continuous 

production processes directly at the casting plant and would thereby benefit from the 

same advantages pertaining to amorphous steels.” (HQ, No. 125 at p. 2)

DOE understands that Hydro-Quebec and others worldwide are conducting 

research on cost-effective manufacture of amorphous core transformers, and believes that 

such efforts may ultimately save energy and economically benefit consumers. At the 

present, however, DOE does not understand such technology to necessarily enable 

achievement of higher efficiency levels. Furthermore, DOE did not attempt to model such 

technology in its engineering analysis because it could not obtain data on what such 

technology costs when applied at commercial scales.

a. Core Deactivation

As noted previously, core deactivation technology employs the concept that a 

system of smaller transformers can replace a single, larger transformer. For example, 
100

three 25 kVA transformers operating in parallel could replace a single 75 kVA 

transformer. 

DOE understands that winding losses are proportionally smaller at lower load 

factors, but for any given current, a smaller transformer will experience greater winding 

losses than 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 operate in parallel in this sort of system, but cost considerations would imply there is 

an optimal number.

In response to the NOPR, Progress Energy Carolinas, Inc., They further noted that 

the response time of core deactivation systems might impair power quality by increasing 

the transformer impedance during the initial cycles of motor starting events. (PE, No. 171 

at p.1) DOE spoke 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 

Comment [A13]: Change recommended by 

OMB.
101

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

activated and deactivated in response to load demands. In response to load demand 

changes, a special unit controls the transformers and activates and/or deactivates them in 

real-time.

Although core deactivation technology has some potential to save energy over a 

real-world loading cycle, 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

liquid-immersed and MVDT transformers, and 35 percent for LVDT. The real gain in 

efficiency for core deactivation technology comes at loading points below the root mean 

square (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.

In response to the NOPR, Progress Energy Carolinas, Inc. commented that core 

deactivation is not a proven technology and would subject utility customers to lower 

reliability. It further noted that the response time of core deactivation systems might 

impair power quality by increasing the transformer impedance during the initial cycles of 

motor starting events. (PE, No. 171 at p.1) Comment [A14]: Change recommended by 

OMB.
102

DOE acknowledges that operating a core deactivation bank of transformers 

instead of a single unit may save energy and lower LCC for certain consumers. At 

present, however, DOE is adopting the position that each of the constituent transformers 

must comply with the energy conservation standards under the scope of the rulemaking.

b. Symmetric Core

DOE understands that several companies worldwide are commercially producing 

three-phase 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 a traditional core, the center leg is magnetically 

distinguishable from the other two because it has a shorter average flux path to each leg. 

In a symmetric core, however, no leg is magnetically distinguishable from the other two.

One manufacturer of symmetric core transformers cited several advantages to its

design. 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 seen 

limited cost and efficiency data for only 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.
103

DOE understands that, because of zero-sequence fluxes associated with wye-wye 

connected transformers, symmetric core designs are best suited to delta-delta or deltawye 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. 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 would come 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 
104

out of the analysis, and is aware of at least one manufacturer producing dry-type 

symmetric core designs commercially in the United States.

For the preliminary analysis, DOE lacked the data necessary to perform a 

thorough engineering analysis of symmetric core designs. To generate a cost-efficiency 

relationship for symmetric core design transformers, DOE made several assumptions. 

DOE adjusted its traditional core design models 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 IV.3 indicates the range of potential 

adjustments for each variable that DOE considered and the mean value used in the 

analysis.

Table IV.3 Symmetric Core Design Adjustments

Range Core Losses W Core Weight lb 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 the 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 

(DLs). Based on its research, DOE believes that the losses associated with the tertiary 

winding may offset the benefits of the symmetric core design and that the tertiary 
105

winding will add cost to the design. Therefore, 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 attempts to consider all designs that are technologically feasible and 

practicable to manufacture and believes that symmetric core designs can meet these 

criteria. However, DOE was not able to obtain or produce sufficient data to modify its 

analysis of symmetric cores after the preliminary analysis. For this reason, DOE did not 

consider symmetric core designs as part of the NOPR analysis. 

In response to the NOPR, several manufacturers expressed support for excluding 

symmetric core designs from DOE’s analysis. ComEd, EEI, Progress Energy, NRECA, 

and APPA all commented that they were pleased to see symmetric core designs excluded 

from the NOPR analysis. (ComEd, No. 184 at p. 11; EEI, No. 185 at p. 9; APPA, No. 191 

at p. 9; PE, No. 192 at p. 7; NRECA, No. 172 at p. 7) BG&E recommended that 

symmetric core designs not be included in the final rule based on previous comments that 

highlighted significant issues with the proposed designs. (BG&E, No. 182 at p. 5) Cooper 

Power pointed out that symmetric core designs have not proven themselves in the market 

place, and therefore should be excluded in terms of their technological feasibility.

(Cooper, No. 165 at p. 4) Similarly, Prolec-GE saw many issues with the use of 
106

symmetric core in medium-voltage liquid-filled transformers, and did not believe that this 

technology offered benefits. (Prolec-GE, No. 177 at p. 10)

ABB and NEMA both observed that any information regarding symmetric core 

technology for distribution transformers is currently considered strategic and proprietary 

and cannot be entered into the public record at this time. (ABB, No. 158 at p. 7) NEMA 

argued further that while it is important for DOE to understand the potential of emerging 

technologies, such technologies should not be introduced into the regulation until they 

have proven themselves in the marketplace; symmetric core designs are currently of low 

penetration in the industry and have not been proven to offer potential for efficiency 

improvement. (NEMA, No. 170 at p. 11)

Howard Industries commented that symmetric core technology is not appropriate 

for the majority of the U.S. distribution transformer market, noting that this style of 

design results in much deeper tanks and larger pads as well as a new winding 

configuration. It also pointed out that symmetric core designs are patented by 

Hexaformer AB, in Sweden, and manufacturing this technology requires a license from 

Hexaformer. Overall, they feel that the cost to adapt to this technology would be large, 

impractical, and time consuming. (HI, No. 151 at p. 12) Progress Energy Carolinas, Inc. 

concurred with Howard Industries that the winding configuration for symmetric core 

designs would be problematic. They pointed out that the delta tertiary winding needed 

will be subject to thermal failure, and increase the losses of the transformer. Furthermore, 
107

they pointed out that the presence of a delta tertiary winding on a wye-wye three-phase 

distribution transformer will provide a source for zero-sequence currents to ground faults 

on the source distribution system, resulting in backfeed and, consequently, a potentially 

hazardous situation. (PE, No. 171 at p. 1)

Finally, Schneider Electric asserted that the efficiency levels proposed in the 

NOPR are not high enough to lead manufacturers to evaluate symmetric core technology. 

It commented that, to fully explore these and other technologies, the implementation time 

and efficiency levels must be increased. It was Schneider Electric’s opinion that further,

increasing the levels in small increments and only giving four years to transition does not 

allow for proper research and development to be completed to properly comment on any 

new technology. (Schneider, No. 180 at p. 5)

In response to the NOPR, DOE did not receive any data that would force

reconsideration of the symmetric core analysis conducted during the preliminary analysis. 

Stakeholders expressed support for the exclusion of this technology from the NOPR 

analysis. For all of the above reasons, DOE does not consider symmetric core designs as 

part of the final rule analysis.

c. Intellectual Property

In setting standards, DOE seeks to analyze the efficiency potentials of 

commercially available technologies and working prototypes, as well as the availability 
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of those technologies to the market at-large. If certain market participants own 

intellectual property that enables them to reach efficiencies that other participants 

practically cannot, amended standards may reduce the competitiveness of the market.

In the case of distribution transformers, stakeholders have raised potential 

intellectual property concerns surrounding both symmetric core technology and 

amorphous metals in particular. DOE currently understands that symmetric core 

technology itself is not proprietary, but that one of the more commonly employed 

methods of production is the property of the Swedish company Hexaformer AB. 

However, Hexaformer AB’s method is not the only one capable of producing symmetric 

cores. Moreover, Hexaformer AB and other companies owning intellectual property 

related to the manufacture of symmetric core designs have demonstrated an eagerness to 

license such technology to others that are using it to build symmetric core transformers 

commercially today.

DOE understands that symmetric core technology may ultimately offer a lowercost path to higher efficiency, at least in certain applications, and that few symmetric 

cores are produced in the United States. However, DOE notes again that it has been 

unable to secure data that are sufficiently robust for use as the basis for an energy 

conservation standard, but encourages interested parties to submit data that would assist 

in DOE’s analysis of symmetric core technology in future rulemakings.
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d. Core Construction Technique

DOE examines a number of core construction techniques in its engineering 

analysis, including butt-lapping, full mitering, step-lap mitering, and distributed gap 

wound construction. Particularly in the low-voltage dry-type market, where some smaller 

manufacturers may not own large mitering machines, core construction methodology is 

of concern. In the NOPR, DOE did not examine butt-lapped core construction as a design 

option for design line 7 for steel grades above M6 and, as a result, found only butt-lapped 

designs are feasible through EL 2. Since the NOPR, however, DOE has reassessed the 

assumption that butt-lapping is not possible beyond EL 2. For design lines 6 and 8, the 

topic of butt-lapping is less consequential. All of DOE’s design line 6 analysis is centered 

around butt-lapping27, while the use of mitering for larger LVDT units (represented by 

design line 8) is prevalent in both the market and DOE’s analysis.

DOE received several comments on core construction method as it relates to 

design line 7. During the negotiated rulemaking, ASAP commented that DOE should 

further explore whether butt-lapping was possible beyond EL 2. (ASAP, No. 146 at p. 

135, pp. 25−26) HVOLT, a power and distribution transformer consulting company,

commented that butt-lapping could probably get very close to EL 3, but not be the most 

cost competitive choice at that level. (HVOLT, No. 146 at p. 135) ASAP also commented 

 27 Except for the amorphous design options, because DOE eliminates consideration of amorphous cores in 

butt-lapped and other stacked configurations in its screening analysis.
110

that DOE should explore more design options in the interest of creating a smoother curve, 

and that butt-lapped options should be among them. (ASAP, No. 146 at pp. 24−25) 

In response to the NOPR, ASAP, two manufacturers of LVDTs, and California 

Investor-Owned Utilities urged DOE to reconsider the technological assumptions 

(including butt-lapping capabilities at higher TSLs) behind its TSL 1 proposal. ASAP 

stated that it believed a more careful consideration of the record and a more thorough 

investigation of the impacts on small, domestic manufacturers would lead DOE to TSL 3, 

noting that many manufacturers supported at least TSL 2 during the negotiated 

rulemaking and believed that TSL 2 could be attained using butt-lapping. (ASAP, No. 

186 at pp. 3, 7-8) Eaton generally recommended that DOE standardize efficiency levels 

to EL 3 (i.e., NEMA Premium®), stating that such efficiency levels are realistic using 

current technology and are very close to the standards DOE proposed in the NOPR. 

(Eaton, No. 157 at p. 2) The California IOUs commented that DOE should revise its 

analysis to reflect that core construction techniques are currently used to produce 

efficiencies higher than TSL 1 for both small and large manufacturers. (CA IOUs, No. 

189 at p. 2) The group of utilities also stated that NEMA lists 11 manufacturers 

committed to delivering LVDTs at NEMA Premium® efficiency levels, including both 

large and small manufacturers. (CA IOUs, No. 189 at p. 2) Schneider Electric reiterated 

its support of efficiency levels higher than those proposed in the NOPR. (Schneider, No. 

180 at p. 1) 
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DOE understands that the ability to produce transformers using a variety of 

construction techniques is important to preserving design flexibility. After receiving the 

above-referenced comments on the NOPR, DOE consulted with technical design experts 

and learned that butt-lapping is technologically feasible for DL 7 through EL 3. DOE 

revises its understanding of the limits of butt-lapped core construction in today’s rule to 

extend through EL 3 in DL 7.

B.

DOE uses the following four screening criteria to determine which design options 

are suitable for further consideration in a standards rulemaking: 

Screening Analysis

1. Technological feasibility. Technologies incorporated in commercial products or 

in working prototypes will be considered to be technologically feasible.

2. Practicability to manufacture, install, and service. If mass production of a 

technology in commercial products 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 standards, then that technology will be 

considered practicable to manufacture, install, and service.

3. Impacts on product utility to consumers

Comment [A15]: Changes recommended by 

OMB.

. If a technology is determined to have 

significant adverse impact on the utility of the product to significant subgroups of 

consumers, or result in the unavailability of any covered product type with 

Formatted: Indent: First line: 0"
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performance characteristics (including reliability), features, sizes, capacities, and 

volumes that are substantially the same as products generally available in the 

United States at the time, it will not be considered further.

4. Safety of technologies. If it is determined that a technology will have 

significant adverse impacts on health or safety, it will not be considered further. 

(10 CFR part 430, subpart C, appendix A)

In the preliminary analysis, DOE identified the technologies for improving 

distribution transformer efficiency that were under consideration. DOE developed this 

initial list of 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. In the 

engineering analysis, DOE only considered those design options that satisfied the four 

screening criteria. The design options that DOE did not consider because they were 

screened out are summarized in Table IV.4.

Table IV.4 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 Technological feasibility
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Removal

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 the TSD discusses each of these screened-out design options in more 

detail. The chapter also includes a list of emerging technologies that could impact future 

distribution transformer manufacturing costs.

1. Nanotechnology Composites

DOE is aware that materials science research is being conducted into the use of 

nanoscale engineering to improve certain properties of materials used in transformers.

Nanotechnology is the manipulation of matter on an atomic and molecular scale. Such 

materials have small-scale structures created through novel manufacturing techniques 

that may give rise to improved properties (e.g., higher resistivity in steel) not natively 

present in the bulk material. At present, DOE has not learned of any such materials that 

meet DOE’s criteria of being practicable to manufacture and does not consider 

nanotechnology composites in its engineering analysis.

Many stakeholders were supportive of DOE’s decision to exclude nanotechnology 

from their analysis in the NOPR. Howard Industries and Cooper Power both expressed 

that nanotechnology is not a proven technology in the field of distribution transformers; 

nanotechnology is still in the research phase and further development would be required 

prior to being viable in the distribution transformer field. (HI, No. 151 at p. 12; Cooper, 
114

No. 165 at p. 4) Prolec-GE agreed, pointing out that this technology is “still in its infancy 

and there is not enough public information to make a practicable analysis if benefits 

exist.” (Prolec-GE, No. 177 at p. 11) While NRECA, EEI and APPA all expressed 

interest in the development of advanced technologies that could result in more efficient 

transformers, they agree with the above stakeholders that this technology is not currently 

available for distribution transformers. (NRECA, No. 172 at p. 7; APPA, no. 191 at p. 9;

EEI, No. 185 at p. 9; BG&E, No. 182 at p. 5) ComEd and Progress Energy noted that, 

due to lack of availability, nanotechnology composites should not be included in DOE’s 

final rule. (ComEd, No. 184 at p. 11; PE, No. 192 at p. 7)

Stakeholders also noted that information on nanotechnology is not currently 

readily available. ABB pointed out that any information regarding the application and 

design of nanotechnology in distribution transformers is considered strategic and 

proprietary and that these composites are not currently commercially available in the 

distribution transformer market. (ABB, No. 158 at p. 7) NEMA agreed, stating, “this 

technology is in its infancy. Information regarding an individual manufacturer’s 

application of this technology is considered strategic and proprietary and cannot be 

divulged in the public record at this time.” (NEMA, No. 170 at p. 11)

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 
115

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. Therefore, DOE does not consider nanotechnology composites in the today’s

rulemaking.

C.

The engineering analysis develops cost-efficiency relationships for the equipment 

that are the subject of a rulemaking by estimating manufacturer costs of achieving 

increased efficiency levels. DOE uses manufacturing costs to determine retail prices for 

use in the LCC analysis and MIA. 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. The engineering analysis also 

determines the maximum technologically feasible (“max-tech”) energy efficiency level.

Engineering Analysis

DOE must consider those distribution transformers that are designed to achieve 

the maximum improvement in energy efficiency that the Secretary of Energy determines 

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

Therefore, an important role of the engineering analysis is 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 
116

design options comprising the maximum technologically feasible level must have been 

physically demonstrated in 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 this rulemaking is based on the design-option 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 2007 final 

rule for distribution transformers.

1. Engineering Analysis Methodology

When developing its engineering analysis for distribution transformers, DOE 

divided the covered equipment into equipment classes. As discussed, distribution 
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transformers are classified by insulation type (liquid immersed or dry type), number of 

phases (single or three), primary voltage (low voltage or medium voltage for dry-type

distribution transformers) and basic impulse insulation level (BIL) rating (for dry types). 

Using these transformer design characteristics, DOE developed ten equipment classes. 

Within each of these equipment classes, DOE further classified distribution transformers 

by their kilovolt-ampere (kVA) rating. These kVA ratings are essentially size categories, 

indicating the power handling capacity of the transformers. For DOE’s rulemaking, there 

are over 100 kVA ratings across all ten equipment classes.

DOE recognized that it would be impractical to conduct a detailed engineering 

analysis on all kVA ratings, so it sought to develop an approach that simplified the 

analysis while retaining reasonable levels of accuracy. DOE consulted with industry 

representatives and transformer design engineers to develop an understanding of the 

construction principles for distribution transformers. It found that many of the units share 

similar designs and construction methods. Thus, DOE simplified the analysis by creating 

engineering design lines (DLs), which group kVA ratings based on similar principles of 

design and construction. The DLs subdivide the equipment classes in order to improve 

the accuracy of the engineering analysis. These DLs differentiate the transformers by 

insulation type (liquid immersed or dry type), number of phases (single or three), and 

primary insulation levels for medium-voltage dry-type distribution transformers (three 

different BIL levels). 
118

After developing its DLs, DOE then selected one representative unit from each 

DL for study, greatly reducing the number of units for direct analysis. For each 

representative unit, DOE generated hundreds of unique designs by contracting with 

Optimized Program Services, Inc. (OPS), a software company specializing in transformer 

design since 1969. The OPS software used three primary inputs that it received from 

DOE: (1) a design option combination, which included core steel grade, primary and 

secondary conductor material, and core configuration; (2) a loss valuation combination; 

and (3) material prices. For each representative unit, DOE examined anywhere from 8 to 

16 design option combinations and for each design option combination, the OPS software 

generated 518 designs based on unique loss valuation combinations. These loss valuation 

combinations are known in industry as A and B evaluation combinations and represent a 

customer’s present value of future losses in a transformer core and winding, respectively. 

For each design option combination and A and B combination, the OPS software 

generated an optimized transformer design based on the material prices that were also 

part of the inputs. Consequently, DOE obtained thousands of transformer designs for 

each representative unit. The performance of these designs ranged in efficiency from a 

baseline level, equivalent to the current distribution transformer energy conservation 

standards, to a theoretical max-tech efficiency level.

After generating each design, DOE used the outputs of the OPS software to help 

create a manufacturer selling price (MSP). The material cost outputs of the OPS software, 

along with labor estimates, were marked up for scrap factors, factory overhead, shipping, 
119

and non-production costs to generate a MSP for each design. Thus, DOE obtained a cost 

versus efficiency relationship for each representative unit. Finally, after DOE had 

generated the MSPs versus efficiency relationship for each representative unit, it 

extrapolated the results to the other, unanalyzed, kVA ratings within that same 

engineering design line.

PEMCO commented that DOE generated too many designs, and that many were 

impractical or unlikely to sell. (PEMCO, No. 183 at p. 1) EMS Consulting made an 

opposite remark, that DOE’s chosen methodology omits many possible solutions. (EMS, 

No. 178 at p. 5) Finally, NEMA commented that the “steepness” of some of DOE’s 

curves were lower than was shown by some manufacturers, ABB in particular. (NEMA, 

No. 170 at p. 4, p. 3) In other words, NEMA questioned whether cost might rise more 

quickly with efficiency than DOE’s analysis suggested. Conversely, ATI Allegheny 

commented that DOE did excellent work on the engineering analysis. (ATI, No. 181 at p. 

1)

DOE acknowledges both that it may not have analyzed every possible design and 

that, conversely, some designs would be unlikely to be considered by many purchasers, 

but notes that the goal of the engineering analysis is to both explore the limits of design 

possibility and establish a cost/efficiency behavior. The Life-Cycle Cost and Payback 

Period Analysis, in turn, examines which of the designs would be cost-effective for 

individual purchasers. It would not be practical to attempt to analyze every possible 
120

physical design. Regarding NEMA’s comments, DOE is always seeking constructive 

feedback to aid in the accuracy of its engineering analysis, but cautions that comparisons 

between designs must be made carefully in order to be sure that they remain valid across 

a wide variety of market forces and construction techniques. A manufacturer’s cost of 

producing higher-efficiency units in today’s market may be different than the cost of 

meeting those same efficiencies after establishment of energy conservation standards, 

which may lead to production at higher volumes.

2. Representative Units

For the preliminary analysis, DOE analyzed 13 DLs that cover the range of 

equipment classes within the distribution transformer market. Within each DL, DOE 

selected a representative unit to analyze in the engineering analysis. A representative unit 

is meant to be an idealized unit typical of those used in high volume applications.

In view of comments received from stakeholders throughout the analysis period, 

DOE slightly modified its representative units for the NOPR analysis. For the NOPR, 

DOE analyzed the same 13 representative units as in the preliminary analysis, but also 

added a design line, and therefore representative unit, by splitting the former design line 

13 into two new design lines, 13A and 13B. This new representative unit allows DOE’s 

analysis to better reflect the behavior of high kVA, high BIL medium-voltage dry-type

units and is shown in Table IV.5. The representative units selected by DOE were chosen 

because they comprise high volume segments of the market for their respective design 
121

lines and also provide, in DOE’s view, a reasonable basis for scaling to the unanalyzed 

kVA ratings. DOE chooses certain designs to analyze as representative of a particular 

design line or design lines because it is impractical to analyze all possible designs in the 

scope of coverage for this rulemaking. DOE also notes that as a part of the negotiations 

process, DOE worked directly with multiple interested parties to develop a new scaling 

methodology for the NOPR that addresses some of the interested party concerns 

regarding scaling.
122

Table IV.5 Engineering Design Lines (DLs) and Representative Units for NOPR 

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, 95kV BIL

2 Liquid-immersed, single-phase, 

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

120/240V secondary, round tank, 125 kV BIL

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

277V secondary, 150kV BIL

2

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

primary, 208Y/120V secondary, 95kV BIL

5 Liquid-immersed, three-phase 750–2500

1500 kVA, 65°C, three-phase, 60Hz, 

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

125 kV BIL

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

13A Dry-type, medium-voltage, 

three-phase, 96-150kV BIL 75–833 300 kVA, 150°C, three-phase, 60Hz, 24940V primary, 

480Y/277V secondary, 125kV BIL

13B Dry-type, medium-voltage, 

three-phase, 96-150kV BIL 225–2500 2000 kVA, 150°C, three-phase, 60Hz, 24940V 

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

* EC means equipment class (see Chapter 3 of the TSD). DOE did not select any representative units from 

the single-phase medium-voltage equipment classes (EC5, EC7 and EC9), but calculated the analytical 

results for EC5, EC7, and EC9 based on the results for their three-phase counterparts.

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 
123

given DL. For each design option combination chosen, DOE evaluates 518 designs based 

on different A and B factor28 combinations. For the engineering analysis, DOE reused 

many of the design option combinations that were analyzed in the 2007 final rule for 

distribution transformers. 72 FR 58190 (October 12, 2007).

For the preliminary analysis, DOE considered a design option combination that 

uses an amorphous steel core for each of the dry-type design lines, whereas DOE’s 2007 

final rule did not consider amorphous steel designs for the dry-type design lines. Instead, 

DOE had considered H-0 domain refined (H-0 DR) steel as the maximumtechnologically feasible design. However, DOE is aware that amorphous steel designs are 

now used in dry-type distribution transformers. Therefore, DOE considered amorphous 

steel designs for each of the dry-type transformer design lines in the preliminary analysis.

During preliminary interviews with manufacturers, DOE received comment 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 even more expensive compared to 

aluminum.

 28 A and B factors correspond to loss valuation and are used by DOE to generate distribution transformers 

with a broad range of performance and design characteristics.
124

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

efficiency values between the lowest efficiency amorphous designs and the next highest 

efficiency designs. In an effort to close that gap for the preliminary analysis, DOE 

evaluated ZDMH and M2 core steel as the highest efficiency designs below amorphous 

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

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

DOE incorporated these supplementary designs into the reference case (i.e., 

DOE’s default set of assumptions without any sensitivity analysis) for the NOPR 

analysis. Additionally, DOE aimed to consider the most popular design option 

combinations, and the design option combinations that yield the greatest improvements in 

efficiency. While DOE was unable to consider all potential design option combinations, it 

did consider multiple designs for each representative unit and considered additional 

design options in its NOPR analysis based on stakeholder comments.

As for wound core designs, DOE did consider analyzing them for all of its drytype representative units that are 300 kVA or less in the NOPR. However, based on 

limited availability in the United States, DOE did not believe that it was feasible to 

include these designs in their final engineering results. For similar availability reasons, 

DOE chose to exclude its wound core ZDMH and M3 designs from its low-voltage drytype analysis. Based on how uncommon these designs are in the current market, DOE 
125

believes that it would be unrealistic to include them in engineering curves without major 

adjustments. 

DOE did not consider wound core designs for DLs 10, 12, and 13B because they 

are 1500 kVA and larger. DOE understands that conventional wound core designs in 

these large kVA ratings will emit an audible “buzzing” noise, and will experience an 

efficiency penalty that grows with kVA rating such that stacked core is more attractive. 

DOE notes, however, that it does consider a wound core amorphous design in each of the 

dry-type design lines.

DOE did opt to add two design option combinations that incorporate M-grade 

steels that have become popular choices at the current standard levels. For all mediumvoltage dry-type design lines (9-13B), DOE added a design option combination of an M4 

step-lap mitered core with aluminum primary and secondary windings. For design line 8, 

DOE added a design option combination of an M6 fully mitered core with aluminum 

primary and secondary windings. DOE understands both combinations to be prevalent 

baseline options in the present transformer market.

For the NOPR analysis, DOE also made the decision to remove certain high flux 

density designs from DL7 to be consistent with designs submitted by manufacturers.29

 29 During the negotiations process, DOE’s subcontractor, Navigant Consulting, Inc. (Navigant), participated 

in a bidirectional exchange of engineering data with industry representatives in an effort to validate the 

OPS designs generated for the engineering analysis.
126

There is a variety of reasons that manufacturers would choose to limit flux density (e.g., 

vibration, noise). Further detail on this change can be found in chapter 5 of the TSD. The 

design remains that way for today’s final rule.

In response to the NOPR, Eaton noted that this rule provides many design 

options, and allows for the use of various designs and different grades of steel, but 

encouraged DOE to standardize the efficiency levels to NEMA Premium® (i.e., EL 3).

(Eaton, No. 157 at p. 2) Although Schneider supported the LVDT efficiency levels 

proposed by DOE in the NOPR, the company stated in its NOPR comments that it still 

supports efficiency levels higher than those proposed in the NOPR (as evidenced by 

discussions during the negotiated rulemaking meetings.) (Schneider, No. 180 at p. 1)

ASAP commented that it perceived there to be a “gap” in the DL 7 data, and that 

DOE should seek to fill that gap by exploring other design option combinations 

corresponding to butt-lapped core construction. (ASAP, No. 146 at p. 24-25, 135) In 

response, DOE first generated analysis for two additional design option combinations: an 

M4 core with aluminum windings and an M3 core with copper windings. DOE includes 

both sets of results in its final rule engineering analysis. In general, DOE notes that 

preservation of a number of design options was a strong consideration in selection of the 

final standard. Second, given these two new design lines discussed above, DOE revisited 

the question of whether DL 7 for LVDTs was achievable by manufacturers with butt 

lapping techniques in order to avoid purchasing mitering equipment. Specifically, DOE 

Comment [A16]: Changes recommended by 

OMB.
127

consulted with technical design experts, and they confirmed butt-lapping was technically 

feasible through EL 3. In addition, DOEas detailed in section IV.A.3, DOE received 

public comment supporting this conclusion and did not receive public comments directly 

refuting this conclusion. Consequently, DOE modified the LVDT standard proposed from 

TSL 1 to TSL(See, e.g., ASAP, No. 186 at pp. 3, 7-8; Eaton, No. 157 at p. 2 in today’s 

final rule.; CA IOUs, No. 189 at p. 2)

Consequently, DOE modified the LVDT standard proposed from TSL 1 to TSL 2 

in today’s final rule.

DL 7 analysis illustrating the possibility of constructing butt-lapped cores at EL3 

led DOE to reconsider the impacts to small manufacturers. DOE originally assumed that 

a small manufacturer without the equipment needed to construct mitered cores would 

have to either invest in such equipment at considerable expense, source cores from a third 

party, or exit that market. As explained in Section IV.I.1, DOE calculates the net present 

value of the industry (“INPV”) in attempting to quantify impacts to manufacturers under 

different scenarios. During the NOPR, DOE calculated LVDT INPV to be between $200 

million and $235 million (in 2011$). In today’s final rule, that figure rises to $227 million 

to $249 million (in 2011$). Although TSL 2 differs between the NOPR and the final rule 

in that DL6 is held at baseline, this difference does not significantly affect INPV results 

because DOE analyzes only butt-lapped design option combination for DL6 under either 

the NOPR or the final rule scenario.

Comment [A17]: Changes recommended by 

OMB.

Comment [A18]: Change recommended by 

OMB.
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In addition, as described in the NOPR and as DOE confirmed for the final rule, 

DOE understands that the majority of the LVDT market volume is currently imported, 

much of it from large, well-capitalized manufacturers in Mexico. Furthermore, many 

small businesses operating inside the United States cater to niches outside of DOE’s 

scope of coverage, and would not be directly affected by the rule. Finally, DOE spoke 

with several small domestic manufacturers and learned that some are already able to 

miter cores, and would make the decision to butt-lap or miter at EL3 based on economics 

and without facing large capital investment decisions. More detail can be found in 

Section IV.I.5.b.

4. A and B Loss Value Inputs

As discussed, one of the primary inputs to the OPS software is an A and B 

combination for customer loss evaluation. In the preliminary analysis, DOE generated 

each transformer design in the engineering analysis based upon an optimized lowest total 

owning cost evaluation for a given combination of A and B values. Again, the A and B 

values represent the present value of future core and coil losses, respectively and DOE 

generated designs for over 500 different A and B value combinations for each of the 

design option combinations considered in the analysis.

DOE notes that the designs created in the engineering analysis span a range of 

costs and efficiencies for each design option combination considered in the analysis. This 

range of costs and efficiencies is determined by the range of A and B factors used to 
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generate the designs. Although DOE does not generate a design for every possible A and 

B combination, because there are infinite variations, DOE believes that its 500-plus 

combinations have created a sufficiently broad design space. By using so many A and B 

factors, DOE is confident that it produces the lowest first cost design for a given 

efficiency level and also the lowest total owning cost design. Furthermore, although all 

distribution transformer customers do not purchase based on total owning cost, the A and 

B combination is still a useful tool that allows DOE to generate a large number of designs 

across a broad range of efficiencies and costs for a particular design line. Finally, OPS 

noted at the public meeting that its design software requires A and B values as inputs. 

(OPS, Pub. Mtg. Tr., No. 34 at p. 123) For all of these reasons, DOE continued to use A 

and B factors from the NOPR to generate the range of designs for the final rule 

engineering analysis.

5. Materials Prices

In distribution transformers, the primary materials costs come from electrical steel 

used for the core and the aluminum or copper conductor used for the primary and 

secondary winding. As these are commodities whose prices frequently fluctuate 

throughout a year and over time, DOE attempted to account for these fluctuations by 

examining prices over multiple years. For the preliminary analysis, DOE conducted the 

engineering analysis analyzing materials price information over a five-year time period 

from 2006-2010, all in constant 2010$. Whereas DOE used a five-year average price in 

the 2007 final rule for distribution transformers, for the preliminary analysis in this 
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rulemaking, DOE selected one year from its five-year time frame as its reference case, 

namely 2010. Additionally, DOE considered high and low materials price sensitivities 

from that same five-year time frame, 2008 and 2006 respectively.

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

preliminary analysis because of feedback from manufacturers during interviews. 

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 did not believe a five-year 

average price would be the best indicator, and recommended using the current materials 

prices.

To estimate its materials prices, DOE spoke with manufacturers, suppliers, and 

industry experts to determine the prices paid for each raw material used in a distribution 

transformer in each of the five years between 2006 and 2010. While prices fluctuate 

during the year and can vary from manufacturer to manufacturer depending on a number 

of variables, such as the purchase quantity, DOE attempted to develop an average 

materials price for the year based on the price a medium to large manufacturer would 

pay.
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With the onset of the negotiations, DOE was presented with an opportunity to 

implement a 2011 materials price case based on data it had gathered before and during 

the negotiation proceedings. Relative to the 2010 case, the 2011 prices were lower for all 

steels, particularly M2 and lower grade steels.

For the NOPR, DOE reviewed its materials prices during interviews with 

manufacturers and industry experts and revised its materials prices for copper and 

aluminum conductors. DOE derived these prices by adding a processing cost increment 

to the underlying index price. DOE determined the current 2011 index price from the

LME and COMEX, two well-known commodities benchmarks. These indices only had 

current 2011 values available, so DOE used the producer price index for copper and 

aluminum to convert the 2011 index price into prices for the time period of 2006–2010. 

DOE then applied a unique processing cost adder to the index price for each of its 

conductor groupings. To derive the adder price, DOE compared the difference in the 

LME index price to the 2011 price paid by manufacturers, and applied this difference to 

the index price in each year. DOE inquired with many manufacturers, both large and 

small, to derive these prices. Materials price cases for the final rule are identical to those 

of the NOPR. Further detail can be found in chapter 5 of the TSD.

DOE reviewed core steel prices with manufacturers and industry experts and 

found them to be accurate within the range of prices paid by manufacturers in 2010. 
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However, based on feedback in negotiations, DOE adjusted steel prices for M4 grade 

steels and lower grade steels.

Several stakeholders commented on the material prices used in the NOPR. ABB, 

NRECA, and NEMA all noted that the material costs appeared to be too low, both for 

2010 and 2011. (ABB, No. 158 at pp. 7−8; NEMA, No. 170 at p. 11; NRECA, No. 146 at 

p. 159) Similarly, Prolec-GE pointed out that, as the economy recovers, demand for these 

materials will increase, as will their prices. They agreed that DOE’s material price 

projections were too low. (Prolec-GE, No. 177 at p. 11) ATI specifically noted that 

DOE’s price for M3 steel was too low in the 2011 price scenario, and commented that 

this price is a very important one in the analysis. (ATI, No. 146 at pp. 74−75) Progress 

Energy concurred, noting that the price of silicon core steel in DOE’s analysis was lower 

than actual prices, and recommended that DOE revise all their material prices. (PE, No. 

192 at p. 7) Cooper and HI agreed with these stakeholders that DOE’s material prices 

were too low, specifically pointing out that surcharges need to be included to more 

accurately reflect real world prices. (Cooper, No. 165 at p. 4; HI, No. 151 at p. 12) 

APPA did not disagree with DOE’s material prices, but pointed out that if DOE 

choose to update them, they should update wholesale electric prices to the most recent 

year available as well. (APPA, No. 191 at p. 9) BG&E and ComEd agreed, pointing out 

“base costs, for both material and wholesale energy, should reflect from the most recent 

published data for the most recent year.” (BG&E No. 182 at p. 5; ComEd, No. 184 at p. 
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11) ASAP commented that DOE should re-optimize its engineering analysis with respect 

to the new pricing to find the most accurate results. (ASAP, No. 146 at p. 153)

DOE notes that because it analyzes such a large breadth of designs, its 

engineering analysis is less sensitive to changes in materials prices than it otherwise 

would be. DOE performed a sensitivity analysis during the preliminary analysis phase of 

the rulemaking in order to understand the magnitude of the effect of a change in material 

prices and found it to be very small. The differential pricing between the designs, upon 

which the LCC, NIA, and other economics results are based, are even less sensitive. DOE 

believes its conclusions would not vary between either case.

DOE appreciates the above-listed feedback from commenters, however, for 

today’s rule, DOE continues to use the 2010 and 2011 materials prices that were first 

included in the NOPR as reference case scenarios, which is the most recent and accurate 

information available to DOE. DOE presents both cases as recent examples of how the 

steel market fluctuates and uses both to derive economic results. It also considered high 

and low price scenarios based on the 2008 and 2006 materials prices, respectively, but 

adjusted the prices in each of these years to consider greater diversity in materials prices. 

For the high price scenario, DOE increased the 2008 prices by 25 percent, and for the low 

price scenario, DOE decreased the 2006 prices by 25 percent as additional sensitivity 

analyses. DOE believes that these price sensitivities accurately account for any pricing 
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discrepancies experienced by smaller or larger manufacturers, and adequately consider 

potential price fluctuations.

For the engineering analysis, DOE did not attempt to forecast future materials 

prices. DOE continued to use the 2010 materials price in the reference case scenario, 

added a 2011 reference scenario, and also considered high and low sensitivities to 

account for any potential fluctuations in materials prices. The LCC and NIA consider a 

scenario, however, in which transformer prices increase in the future based on increasing 

materials prices, among other variables. Further detail on this scenario can be found in 

chapter 8 of the TSD.

6. 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. Nonproduction cost includes the cost of selling, general and administrative items (market 

research, advertising, sales representatives, and 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. DOE utilized 
135

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

transformer. These markups are outlined in greater detail in chapter 5 of the TSD.

DOE interviewed manufacturers of distribution transformers and related products 

to learn about markups, among other topics, and observed a number of very different 

practices. In absence of a consensus, DOE attempted to adapt manufacturer feedback to 

inform its current modeling methodology while acknowledging that it may not reflect the 

exact methodology of many manufacturers. DOE feels that it is necessary to model 

markups, however, since there are costs other than material and labor that affect final 

manufacturer selling price. The following sections describe various facets of DOE’s 

markups for distribution transformers.

a. Factory Overhead

DOE uses a factory overhead markup to account for all indirect costs associated 

with production, indirect materials and energy use (e.g., annealing furnaces), taxes, and 

insurance. In the preliminary analysis, DOE derived the cost for factory overhead by 

applying a 12.5 percent markup to direct material production costs.

In the preliminary analysis, DOE applied the same factory overhead markup to its 

prefabricated amorphous cores as it did to its other design options where the 

manufacturer was assumed to produce the core. Since the factory overhead markup 

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

For today’s rule, DOE continued to apply the same factory overhead markup to 

prefabricated amorphous cores as to other cores built in-house. This approach is 

consistent with the suggestion of the manufacturers, and DOE notes that factory overhead 

for a given design applies to many items aside from the core production. Furthermore, 

since DOE already accounts for decreased labor hours in its designs using prefabricated 

amorphous cores, but also considers an increased core price based on a prefabricated core 

rather than the raw amorphous material, it already accounts for the tradeoffs associated 

with developing the core in-house versus out-sourced.

During negotiations, DOE learned from both manufacturers of transformers and 

manufacturers of transformer cores that mitering and, to a greater extent, step-lap 

mitering result in a per-pound cost of finished cores higher than the per-pound cost of

butt-lapped units built to the same specifications. (ONYX, Pub. Mtg. Tr., No. 30 at p. 43) 

In view of the manufacturer comments, DOE understands that butt-lapping is common at 

baseline efficiencies in today’s low-voltage market.

In response, DOE opted to increase mitering costs for both low- and mediumvoltage dry-type designs. In the medium-voltage case, DOE incorporated a processing 
137

cost of 10 cents per core pound for step-lap mitering. In the low-voltage case, DOE 

incorporated a processing cost of 10 cents per core pound for ordinary mitering and 20 

cents per core pound for step-lap mitering. DOE used different per pound adders for steplap mitering for medium-voltage and low-voltage units because the base case design 

option for each is different. For low-voltage units, DOE modeled butt-lapped designs at 

the baseline efficiency level whereas ordinary mitering was modeled at the baseline for 

medium-voltage. Therefore, using a step-lap mitered core represents a more significant 

change in technology for low-voltage dry-type transformers than for medium-voltage 

transformers, necessitating higher markup.

b. Labor Costs

In the preliminary analysis, DOE accounted for additional labor and material costs 

for large (≥1500 kVA), dry-type designs using amorphous metal. The additional labor 

costs accounted for special handling considerations, since the amorphous material is very 

thin and can be difficult to work with in such a large core. They also accounted for extra 

bracing that is necessary for large, wound core, dry-type designs in order to prevent short 

circuit problems.

In response to interested party feedback, DOE applied an incremental increase in 

core assembly time to amorphous designs in the liquid-immersed design line 5 (1500 

kVA). This additional core assembly time of 10 hours is consistent with DOE’s treatment 

of amorphous designs in large, dry-type design lines. However, DOE did not account for 
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additional hardware costs for bracing in the liquid-immersed designs using amorphous 

cores. This is because DOE already accounts for bracing costs for all of its liquidimmersed designs, which use wound cores, in its analysis. DOE determined that it 

adequately accounted for these bracing costs in the smaller kVA sizes using amorphous 

designs, and thus only made the change to the large (≥1500 kVA) design lines. DOE did 

not model varying incremental cost increases starting with zero for large amorphous 

designs, as the Northwest Energy Efficiency Alliance (NEEA) and Northwest Power and 

Conservation Council (NPCC) suggested, noting that the impact of these incremental 

costs are often very minor for large, expensive transformer designs. (NEEA, No. 11 at p. 

7) Following discussion with Federal Pacific and other manufacturers of medium- and 

low-voltage transformers, DOE explored its estimates of labor hours and increased those 

relating to core assembly for design lines 6-13B. Details on the specific values of the 

adjustments can be found in chapter 5 of the TSD.

c. Shipping Costs

During its interviews with manufacturers in the preliminary analysis, DOE was 

informed that manufacturers often 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 in 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.
139

In the 2007 final rule, 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 delivering 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 was estimated to be 

$0.22 per pound of the transformer’s total weight. DOE derived the $0.22 per pound by 

relying on the shipping costs developed in its 2007 final rule, when DOE collected a 

sample of shipping quotations for transporting transformers. In that rulemaking, DOE 

estimated shipping costs as $0.20 per pound based on an average shipping distance of 

1,000 miles. For the preliminary analysis, DOE updated the cost to $0.22 per pound 

based on the price index for freight shipping between 2007 and 2010. Additional detail 

on these shipping costs can be found in chapter 5 and chapter 8 of the TSD.

For the NOPR, DOE revised its shipping cost estimate to account for the rising 

cost of diesel fuel. DOE adjusted its previous shipping cost of $0.20 (in 2006 dollars) 

from the 2007 final rule to a 2011 cost based on the producer price index for No. 2 diesel 

fuel. This yielded a shipping cost of $0.28 per pound. DOE also retained its shipping cost 
140

calculation based on the weight of the transformer to differentiate the shipping costs 

between lighter and heavier, typically more efficient, designs.

In the preliminary analysis, DOE applied a non-production markup to all cost 

components, including shipping costs, to derive the MSP. DOE based this cost treatment 

on the assumption that manufacturers would mark up the shipping costs when calculating 

their final selling price. The resulting shipping costs were, as stated, approximately four 

to eight percent of total MSP.

Based on comments received and DOE’s additional research into the treatment of 

shipping costs through manufacturer interviews, DOE decided to retain the shipping costs 

in its calculation of MSP, but not to apply any markups to the shipping cost component. 

Therefore, shipping costs were added separately into the MSP calculation, but not 

included in the cost basis for the non-production markup. The resulting shipping costs 

were still in line with the estimate of four to eight percent of MSP for all the dry-type 

design lines. For the liquid-immersed design lines, the shipping costs ranged from six to 

twelve percent of MSP and averaged about nine percent of MSP. This practice was 

retained for the final rule.

7. Baseline Efficiency and Efficiency Levels

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

unit. Within the efficiency range, DOE developed designs that approximate a continuous 
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function of efficiency. However, DOE only analyzes incremental impacts of increased 

efficiency by comparing discrete efficiency benchmarks to a baseline efficiency level. 

The baseline efficiency level evaluated for each representative unit is the existing energy 

conservation standard level of efficiency for distribution transformers established either 

in DOE’s 2007 final rule for medium-voltage transformers or by EPACT 2005 for lowvoltage transformers. The incrementally higher efficiency benchmarks are referred to as 

“efficiency levels” (ELs) and, along with MSP values, characterize the cost-efficiency 

relationship above the baseline. 

For today’s rule, DOE considered several criteria when setting ELs. 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 requirement as a 150 kVA three-phase 

transformer. This approach is consistent with DOE’s methodology from the 2007 final 

rule and from the preliminary analysis of this rulemaking. Therefore, DOE selected 

equivalent ELs for several of the representative units that have equivalent per-phase kVA 

ratings.

Second, DOE selected equally spaced ELs 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.
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Finally, DOE adjusted the position of some of the equally spaced ELs and 

examined additional ELs. These minor adjustments to the equally spaced ELs allowed 

DOE to consider important efficiency values based on the results of the software designs. 

For example, DOE adjusted some ELs slightly up or down in efficiency to consider the 

maximum efficiency potential of non-amorphous design options. Other ELs were added 

to consider important benchmark efficiencies, such as the NEMA Premium® efficiency 

levels for LVDT distribution transformers. Last, DOE considered additional ELs to 

characterize the maximum-technologically feasible design for representative units where 

the harmonized per-phase efficiency value would have been unachievable for one of the 

representative units. 

Although DOE’s current test procedure specifies a load value at which to test 

transformers, DOE recognizes that different consumers see real-world loadings that may 

be higher or lower. In those cases, consumers may choose a transformer offering a lower 

LCC even when faced with a higher first cost. If DOE’s cost/efficiency design cloud 

were redrawn to reflect loadings other than those specified in the test procedure, different 

designs would migrate to the optimum frontier of the cloud. Additionally, although 

DOE’s engineering analysis reflects a range of transformers costs for a given EL, the 

LCC analysis only selects transformer designs near the lowest cost point.
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8. Scaling Methodology

a. kVA Scaling

For today’s rule, DOE performed a 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 to 

develop inputs to the national impacts analysis. The technique it used to extrapolate the 

findings of 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 with the ratio of their kVA ratings raised to the 0.75 

power. The relationship is valid where the optimum efficiency loading points of the two 

transformers being scaled are the same. DOE used the same methodology to scale its 

findings during the 2007 final rule on distribution transformers.

Because it is not practical to directly analyze every combination of design options 

and kVAs under the rulemaking’s scope of coverage, DOE selected a smaller number of 

units it believed to be representative of the larger scope. Many of the current design lines 

use representative units retained from the 2007 final rule with minor modifications. To 

generate efficiency values for kVA values not directly analyzed, DOE employed a 

scaling methodology based on physical principles (overviewed in Appendix 5B) and 

widely used by industry in various forms. DOE’s scaling methodology is an 

approximation and, as with any approximation, can suffer in accuracy as it is extended 

further from its reference value.
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Additionally, DOE modified the way it splices extrapolations from each 

representative unit to cover equipment classes at large. Previously, DOE extrapolated 

curves from individual data points and blended them near the boundaries to set standards. 

Currently, DOE fits a single curve through all available data points in a space and 

believes that the resulting curve is smoother and offers a more robust scaling behavior 

over the covered kVA range.

DOE received a number of comments on the matter of scaling across kVA ranges. 

Cooper Power Systems supported the use of the .75 exponent, though noted that it may 

not hold for higher kVA values. (Cooper, No. 165 at p. 4) MGLW commented that for 

single-phase pad-mounted distribution transformers the exponent may approach .75, but 

that it was not accurate for single-phase pole-mounted distribution transformers, whose 

curve would be of polynomial form. (MLGW, No. 127 at p. 1) PEMCO proposed to use a 

curve in logarithmic space, which would create an even more complex behavior in linear 

coordinates. (PEMCO, No. 183 at p. 2) Progress Energy commented that DOE should 

avoid scaling altogether, and instead use data from vendors. (PE, No. 192 at p. 6) ABB, 

APPA, BG&E, EEI, Howard, NEMA, NRECA, Power Partners, Prolec-GE, 

Commonwealth Edison, and Schneider all commented that DOE’s general approach was 

sound, but that the accuracy of the procedure may be improved with more data-validated 

modeling. (ABB, No. 158 at p. 7; APPA, No. 191 at pp. 7–8; APPA, No. 237 at p. 3; 

BG&E, No. 182 at p. 5; EEI, No. 185 at p. 9; HI, No. 151 at p. 12; NEMA, No. 170 at p. 
145

10; NRECA, No. 172 at p. 6; Power Partners, No. 155 at p. 3; Prolec-GE, No. 146 at pp. 

82 – 83; Prolec-GE, No. 177 at p. 10; ComEd, No. 184 at p. 10; Schneider, No. 180 at p. 

5)

In the case of equipment class 1, which addresses single-phase liquid-immersed 

distribution transformers, some stakeholders expressed confusion on the scaling. Because 

this equipment class contains three design lines and because DOE is deriving a standard 

using a straight line in logarithmic space, it is possible that the three ELs, one from each 

design line) may not fall exactly in- line. In that case, as occurred for equipment class one 

with TSL 1, DOE best fit a straight line through three points. APPA, EEI, Berman 

Economics, NRECA, Pepco, and the Advocates both commented that because DOE did 

not propose a standard that aligned with each of these ELs, the economic results were not 

exact. (APPA, No. 191 at p. 3; Berman Economics, No. 150 at p. 2; NRECA, No. 2; 

Pepco, No. 145 at pp. 1 – 2; Advocates, No. 186 at pp. 9−10) DOE thanks the 

commenters for making that clear, and has revised its presentation of final rule economic 

results accordingly. 

For today’s rule, DOE finds the NOPR methodology well-supported by a large 

number of stakeholders and continues to employ it. DOE believes transformers are 

approximately well-modeled as power-law devices. In other words, attributes of the 

devices should grow in proportion to the size raised to a constant power. The ideal, 

mathematically derived value of that exponent is .75, but in practice transformers may 

not be constructed ideally and other effects may drive the exponent above or below .75. 
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DOE believes allowing the exponent to float from .75 where justified may help to 

account for certain size-dependent effects not always well captured by the theoretical .75 

result.

b. Phase Count Scaling

In the 2007 final rule, DOE covered both single- and three-phase transformers and 

harmonized standards across phases. More specifically, DOE set standards such that a 

single-phase transformer of a certain type (e.g., liquid immersed) and kVA rating (e.g., 

100) would be required to meet the same standard as would a three-phase transformer of 

the same type and three times the kVA rating (in this example, 300 kVA liquid

immersed). In certain cases, DOE believes there is sound technological basis for doing 

so. For example, three-phase liquid-immersed distribution transformers mounted on poles 

are frequently constructed using three single-phase cores inside of a single housing. 

Although miscellaneous losses may vary slightly (e.g., bus losses) across three- and 

single-phase pole-mounted units, one would expect the core-and-coil efficiencies to be 

identical for a similar construction choices such as steel grade, winding grade, core 

geometry, etc.

In many other cases, however, there may not be a strong technical basis for 

strongly coupling single- and three-phase standards. Several parties commented on the 

matter in response to the NOPR.
147

Howard Industries and Power Partners both supported linking single- and threephase standards, as was done in the 2007 final rule. (HI, No. 151 at p. 12; Power Partners, 

No. 155 at p. 3) ABB, APPA, Cooper, NEMA, Progress Energy, Prolec-GE, and 

Schneider, however, argued that construction differences resulted in there being no 

logical reason to link the two standards, and that any standards should be derived from 

independent analysis of each. (ABB, No. 158 at p. 7; APPA, No. 191 at p. 7; Cooper, No. 

165 at p. 3; NEMA, No. 170 at p. 10; NEMA, No. 170 at p. 3; PE, No. 192 at p. 6; 

Prolec-GE, No. 146 at p. 85; Prolec-GE, No. 177 at p. 9; Schneider, No. 180 at p. 5)

In today’s rule, DOE follows the convention of the NOPR and does not impose 

the constraint that single- and three-phase efficiencies must be linked. DOE notes, 

however, that standards were harmonized across phase counts in the case of single-phase 

MVDT equipment classes, where market volume is minimal and direct analysis of such 

units a lower priority.

9. Material Availability

Throughout this rulemaking, DOE received several comments expressing concern 

over the availability of materials, including core steel and conductors, needed to build 

energy efficient distribution transformers. These issues pertain to a global scarcity of 

materials as well as issues of materials access for small manufacturers.
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DOE is aware that many core steels, including amorphous steels, have constraints 

on their supply and presents an analysis of global steel supply in TSD appendix 3-A.

10. Primary Voltage Sensitivities

DOE understands that primary voltage and the accompanying BIL may 

increasingly affect efficiency of liquid-immersed transformers as standards rise. DOE 

may conduct primary voltage sensitivity analysis in order to better quantify the effects of 

BIL and primary voltage on efficiency, and may use such information to consider 

establishing equipment classes by BIL rating for liquid-immersed distribution 

transformers.

11. Impedance

In the engineering analysis, DOE only considered transformer designs with 

impedances within the normal impedance ranges specified in Table 1 and Table 2 of 10 

CFR 431.192. These impedances represent the typical range of impedance that is used for 

a given liquid-immersed or dry-type transformer based on its kVA rating and whether it 

is single-phase or three-phase.

Several stakeholders expressed concern over efficiency standards that could 

potentially cause changes in impedance. Progress Energy, BG&E, NEMA and ComEd all 

commented that the increased efficiency levels in the 2010 standards resulted in changes 

in impedance values. (PE, No. 192 at p. 11; BG&E, No. 182 at p.10; ComEd, No. 184 at 
149

p. 15; NEMA, No. 170 at pp. 18−19) “Manufacturers are already having challenges with 

transformer designs that meet the efficiencies required in the Final Rule dated October 

12, 2007, the minimum impedance requirement of 5.3% and weight limit of 3,600 

lbs....for select ComEd designs...only one of five suppliers from which ComEd is 

currently purchasing can meet the efficiency, impedance and weight requirements.” 

(ComEd, No. 184 at p. 15) Howard Industries concurred that changes in efficiency 

standards may also change impedance, commenting that for SPS type designs higher 

efficiency levels typically bring lower impedance which leads to short circuit let-through 

current. (HI, No. 151 at p. 12) BG&E also noted that if higher efficiency standards drive 

impedance ranges outside of the IEEE required range, utilities will be forced to change 

out a whole block of transformers, even if only one is directly affected, to ensure 

matching impedances and a safe, reliable installation. (BG&E, No. 182 at p. 10) NRECA 

and APPA second this point, noting that transformers must meet IEEE standards 

concerning impedance values while simultaneously meeting or exceeding the DOE 

minimum efficiency standards. (NRECA, No. 172 at p. 11; APPA, No. 191 at p. 14) 

Schneider Electric pointed out that changes in impedance levels impact the voltage drop 

of the system and potential increased impedance due to higher efficiency designs could 

impact overall energy conservation; the impact in line losses from the increased

impedance could offset any benefits obtained in the transformer. (Schneider, No. 180 at 

p. 11) ABB expressed concern that the X/R ratio could rise with increasing standards 

which could result in higher losses in the distribution system as a whole. It is ABB’s

opinion that if there is an applicable industry standard for a specific transformer then the 
150

X cannot be adjusted as easily and will result in an increased X/R. (ABB, No. 158 at p. 

10) Furthermore, it noted that as efficiency increases, resistance decreases, causing a 

higher X/R ratio. They commented that if there is no applicable industry standard on a 

specific transformer for impedance values, the X could be offset to correlate with the 

change in R, however, this would lead to an increase in the percent [voltage] regulation30

and higher losses in the transformer. If there is an industry standard, the X cannot be 

adjusted as easily and will result in an increased X/R. (ABB, No. 158 at p. 10) ConEd 

also pointed out that higher efficiencies may lead to higher inrush currents, which may 

require installation of more robust and costly distribution components to be installed 

which would increase costs. (ConEd, No. 236 at p. 4)

On the other hand, various stakeholders claimed that there was no direct 

relationship between impedance and efficiency levels. EEI commented that they would 

be concerned if higher standards would make it more difficult for manufacturers to meet 

the necessary requirements for impedance, inrush current and X/R ratio, but noted that 

they are not currently aware of any existing direct relationship. (EEI, No. 185 at p. 20) 

Prolec-GE agreed, noting that they did not see any issues with inrush, X/R ratios, or 

impedance at the levels proposed in the NOPR. (Prolec-GE, No. 177 at p. 16) 

For today’s rule, DOE continued to consider only designs within the normal 

impedance ranges used in the preliminary analysis. DOE believes that this demonstrates 

 30 In other words, how well a transformer maintains output voltage as load increases.
151

the possibility of manufacturing a variety of impedances at efficiencies well in excess of 

those adopted in today’s rule. While certain applications may have specifications that are 

more stringent than these normal impedance ranges, DOE believes that the majority of 

applications are able to tolerate impedances within these ranges. Since DOE considers a 

wide array of designs within the normal impedance ranges, it adequately accounts for the 

cost considerations of higher and lower impedance tolerances. Furthermore, DOE 

believes the standards under consideration in the NOPR to be of modest enough increase 

to minimize serious concern with respect to impedance and X/R ratio.

12. Size and Weight

In the preliminary analysis, DOE did not constrain the weight of its designs. DOE 

accounted for the full weight of each design generated by the optimization software based 

on its materials and hardware. Similarly, DOE let several dimensional measurements of 

its designs vary based on the optimal core/coil dimensions plus space factors. However, 

DOE did hold certain tank and enclosure dimensions constant for its design lines. Most 

notably, DOE fixed the height dimension on all of its rectangular tank transformers. For 

each design that had variable dimensions, DOE accounted for the additional cost of 

installing the unit, where applicable.

For today’s engineering analysis, DOE did not restrict its designs based on a limit 

for size or weight beyond the fixed height measurements it was already considering for 

the rectangular tank sizes. DOE understands that larger transformers may require 
152

additional installation costs such as a new pole change-out or vault expansion. To the 

extent that it had data on these additional costs, DOE accounted for them in its LCC 

analysis, as described in section IV.F. However, DOE did not choose to limit its design 

specifications based on a specific size or weight constraint.

Nonetheless, DOE notes that the majority of its designs are within weight 

constraints suggested by stakeholders. In design line 2, over 95 percent of DOE’s designs 

are below 650 pounds. In design line 3, over 62 percent of DOE’s designs are below 

3,600 pounds, and when only the designs with the lowest first cost are considered, nearly 

74 percent of the designs are less than 3,600 pounds. The majority of the designs that 

exceed 3,600 pounds are at the maximum efficiency levels using an amorphous core 

steel.

DOE worked with manufacturers to explore the magnitude of the effect of longer 

buses and leads and found it to be small relative to the gap between efficiency levels. 

Nonetheless, DOE made small upward adjustments to bus and lead losses of all mediumvoltage dry-type design lines. Details on the specific values of the adjustments made can 

be found in chapter 5 of the TSD.

D.

The markups analysis develops appropriate markups in the distribution chain to 

convert the estimates of manufacturer selling price derived in the engineering analysis to 

Markups Analysis
153

customer prices. In the preliminary analysis, DOE determined the distribution channels 

for distribution transformers, their shares of the market, and the markups associated with 

the main parties in the distribution chain, distributors, contractors and electric utilities.

Based on comments from interested parties, for the NOPR DOE added a new 

distribution channel to represent the direct sale of transformers to utilities, which account 

for approximately 80 percent of liquid-immersed transformer shipments. Howard 

Industries and Prolec-GE agreed with DOE's estimate that 80 percent of transformers are 

sold by manufacturers to utilities. (HI, No. 151 at p. 8; Prolec-GE, No. 177 at p. 13) For 

the final rule, DOE retained this distribution channel. 

DOE developed average distributor and contractor markups by examining the 

installation and contractor cost estimates provided by RS Means Electrical Cost Data 

2011.

31 DOE developed separate markups for baseline equipment (baseline markups) and 

for the incremental cost of more-efficient equipment (incremental markups). Incremental 

markups are coefficients that relate the change in the installation cost due to the increase 

equipment weight of some higher-efficiency models. 

Chapter 6 of the final rule TSD provides additional detail on the markups 

analysis.

 31 RSMeans Electrical Cost Data 2011; 2010; J.H. Chiang, C. Babbitt.
154

E.

The energy use analysis produced energy use estimates and end-use load shapes 

for distribution transformers. The energy use estimates enable evaluation of energy 

savings from the operation of distribution transformer equipment at various efficiency 

levels, while the end-use load characterization allows evaluation of the impact on 

monthly and peak demand for electricity.

Energy Use Analysis

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 I2

R 

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/industrial entities 

use mainly dry type), DOE performed two separate end-use load analyses to evaluate 

distribution transformer efficiency. The analysis for liquid-immersed 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 commercial and industrial 

customers, so the energy and cost savings estimates are based on monthly building-level 
155

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 commercial/industrial building 

data.

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.

Transformer loading is an important factor in determining which types of 

transformer designs will deliver a specified efficiency, and for calculating transformer 

losses. For the NOPR, DOE estimated a range of loading for different types of 

transformers based on analysis done for the 2007 final rule. During the negotiations the 

load distributions were presented and found to be reasonable by the parties. In addition, 

data submitted by Moon Lake Electric during the negotiations were used to validate the 

load models for single-phase liquid-immersed distribution transformers. 
156

For the NOPR, higher-capacity three-phase liquid-immersed and medium-voltage 

dry-type transformers were loaded at 20 to 66 percent, and smaller capacity single-phase 

medium-voltage liquid-immersed transformers were loaded at 20 to 60 percent. Lowvoltage dry-type transformers were loaded at 3 to 45 (mean of 25) percent.

Cooper stated that the average loading used for liquid-filled transformers was 

underestimated, and historical utility evaluation factors suggest 50 percent loading for 

single-phase liquid-immersed transformers and closer to 60 percent for three-phase 

liquid-immersed transformers. (Cooper, No. 165 at p. 5) EEI stated that higher capacity 

three-phase distribution transformers are likely to be serving large industrial facilities 

with higher loading factors. (EEI, No. 185 at p. 14) Utilities stakeholders responded with 

a wide range of average loading values that they have on their distribution transformers: 

ComEd stated that its aggregated load factors range from approximately 40 to 70 percent

depending on the customer class. (ComEd, No. 184 at p. 2) MLGW stated that its average 

aggregated load factor was approximately 17 percent across its distribution system. 

(MLGW, No. 133 at p. 1) PEPCO agreed that the average aggregate load factors 

presented in the NOPR were a good compromise and that they should not be changed. 

(PEMCO, No.183 at p.2)

As previously mentioned, DOE was able to validate its load models for singlephase liquid-immersed transformers using submitted data, so it retained the loading used 

in the NOPR for the final rule. For three-phase liquid-immersed transformers, DOE 
157

believes that the comment from Cooper does not provide an adequate basis for changing 

the loading range that was viewed as reasonable by the parties to the negotiation and the 

loading values provided by utilities comport with DOE’s estimated loadings.

Dry-type distribution 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 and the customer’s marginal prices.

The customer sample of dry-type distribution transformer owners was taken from 

the EIA Commercial Buildings Energy Consumption Survey (CBECS) databases.32

 32 1992 Commercial Building Energy Consumption and Expenditures Survey (CBECS); 1995; U.S. 

Department of Energy – Energy Information Administration; 

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 

http://www.eia.doe.gov/emeu/cbecs/microdat.html.
158

Energy Consumption Survey (MECS)33 were used to estimate the amount of floor space 

of buildings that might use the type of transformer covered by the rulemaking. The 

statistical weights assigned to the building sample were rescaled to reflect this additional 

floor space. Only the weighting of large buildings were rescaled.

F.

DOE conducts LCC and PBP analyses to evaluate the economic impacts on 

individual customers of potential energy conservation standards for distribution 

transformers.

Life-Cycle Cost and Payback Period Analysis

34 The LCC is the total customer expense over the life of a type of 

equipment, consisting of purchase and installation costs plus operating costs (expenses 

for energy use, maintenance and repair). To compute the operating costs, DOE discounts 

future operating costs to the time of purchase and sums them over the lifetime of the 

equipment. The PBP is the estimated amount of time (in years) it takes customers to 

recover the increased purchase cost (including installation) of a more efficient type of 

equipment through lower operating costs. DOE calculates the PBP by dividing the 

change in purchase cost (normally higher) due to a more stringent standard by the change 

in average annual operating cost (normally lower) that results from the standard.

For any given efficiency level, DOE measures the PBP and the change in LCC 

relative to an estimate of the base-case efficiency levels. The base-case estimate reflects 

 33 Manufacturing Energy Consumption Survey (MECS); 2006 U.S. Department of Energy – Energy 

Information Administration; http://www.eia.gov/emeu/mecs/contents.html . 34 Customers refer to electric utilities in the case of liquid-immersed transformers, and to utilities and 

building owners in the case of dry-type transformers.
159

the market in the absence of amended energy conservation standards, including the 

market for equipment that exceeds the current energy conservation standards.

Equipment price, installation cost, and baseline and standard affect the installed 

cost of the equipment. Transformer loading, load growth, power factor, annual energy use 

and demand, electricity costs, electricity price trends, and maintenance costs affect the 

operating cost. The compliance date of the standard, the discount rate, and the lifetime of 

equipment affect the calculation of the present value of annual operating cost savings 

from a proposed standard. Table IV.1 below summarizes the major inputs to the LCC and 

PBP analysis, and whether those inputs were revised for the final rule.

DOE calculated the LCC and PBP for a representative sample (a distribution) of 

individual transformers. In this manner, DOE’s analysis explicitly recognized that there is 

both variability and uncertainty in its inputs. DOE used Monte Carlo simulations to 

model the distributions of inputs. The Monte Carlo process statistically captures input 

variability and distribution without testing all possible input combinations. Therefore, 

while some atypical situations may not be captured in the analysis, DOE believes the 

analysis captures an adequate range of situations in which transformers operate.
160

Table IV.1 Key Inputs for the LCC and PBP Analysis 

Inputs NOPR Description Changes for the Final Rule

Affecting Installed Costs

Equipment price Derived by multiplying 

manufacturer selling price (from 

the engineering analysis) by 

distributor markup and 

contractor markup plus sales tax 

for dry-type transformers. For 

liquid-immersed transformers, 

DOE used manufacturer selling 

price plus small distributor 

markup plus sales tax. Shipping 

costs were included for both 

types of transformers.

No change.

Installation cost Includes a weight-specific 

component derived from RS 

Means Electrical Cost Data 

2011

Added pole replacement cost for 

design line 3.

and a markup to cover 

installation labor, pole 

replacement costs for design line 

2 and equipment wear and tear.

Baseline and 

standard design 

selection

The selection of baseline and 

standard-compliant transformers 

depends on customer behavior. 

The fraction of purchases 

evaluated was 10% for liquidimmersed transformers, 2% for 

low-voltage dry-type and 2% for 

medium-voltage dry-type

transformers.

No change.

Affecting Operating Costs

Transformer 

loading

Modeled loading as a function 

of transformer capacity and 

utility customer density. 

No change

Load growth 0.5% per year for liquidimmersed and 0% per year for 

dry-type transformers.

No change.

Power factor Assumed to be unity. No change.
161

Inputs NOPR Description Changes for the Final Rule

Annual energy 

use and demand

Derived from a statistical hourly 

load simulation for liquidimmersed transformers, and 

estimated from the 1992 and 

1995 Commercial Building 

Energy Consumption Survey 

No change.

data for dry-type transformers 

using factors derived from 

hourly load data. Load losses 

varied as the square of the load 

and were equal to rated load 

losses at 100% loading.

Electricity costs Derived from tariff-based and 

hourly based electricity prices. 

Capacity costs provided extra 

value for reducing losses at 

peak. 

No change.

Electricity price 

trend

Obtained from Annual Energy 

Outlook 2011 (AEO2011

Updated to AEO 2012. Price 

trends for liquid-immersed 

transformers are based on a mix 

of generating fuel prices.

).

Maintenance 

cost

Annual maintenance cost did not 

vary as a function of efficiency.

No change.

Compliance date Assumed to be 2016. No change.

Discount rates Mean real discount rates ranged 

from 3.7% for owners of liquidimmersed transformers to 4.6% 

for dry-type transformer owners.

No change

Lifetime Distribution of lifetimes, with 

mean lifetime for both liquid 

and dry-type transformers 

assumed to be 32 years.

No change.

The following sections contain brief discussions of comments on the inputs and key 

assumptions of DOE’s LCC and PBP analysis and explain how DOE took these 

comments into consideration.
162

1. Modeling Transformer Purchase Decision

The LCC spreadsheet uses a purchase-decision model that specifies which of the 

hundreds of designs in the engineering database are likely to be selected by transformer 

purchasers to meet a given efficiency level. The engineering analysis yielded a costefficiency relationship in the form of manufacturer selling prices, no-load losses, and load 

losses for a wide range of realistic transformer designs. This set of data provides the LCC 

model with a distribution of transformer design choices. 

DOE used an approach that focuses on the selection criteria customers are known 

to use when purchasing transformers. Those criteria include first costs, as well as what is 

known in the transformer industry as total owning cost (TOC). The TOC method 

combines first costs with the cost of losses. Purchasers of distribution transformers, 

especially in the utility sector, have long used the TOC method to determine which 

transformers to purchase. 

The utility industry developed TOC evaluation as an easy-to-use tool to reflect the 

unique financial environment faced by each transformer purchaser. To express variation 

in such factors as the cost of electric energy, and capacity and financing costs, the utility 

industry developed a range of evaluation factors, called A and B values, to use in their 

calculations. A and B are the equivalent first costs of the no-load and load losses (in 

$/watt), respectively. 
163

DOE used evaluation rates as follows: 10 percent of liquid-immersed transformers

were evaluated, 2 percent of low-voltage dry-type transformers were evaluated, and 2 

percent of medium-voltage dry-type transformers were evaluated. The transformer 

selection approach is discussed in detail in chapter 8 of the final rule TSD.

2. Inputs Affecting Installed Cost

a. Equipment Costs

In the LCC and PBP analysis, the equipment costs faced by distribution 

transformer purchasers are derived from the MSPs estimated in the engineering analysis 

and the overall markups estimated in the markups analysis.

To forecast a price trend for the NOPR, DOE derived an inflation-adjusted index 

of the PPI for electric power and specialty transformer manufacturing from 1967 to 2010. 

These data show a long-term decline from 1975 to 2003, and then a steep increase since 

then. DOE believes that there is considerable uncertainty as to whether the recent trend 

has peaked, and would be followed by a return to the previous long-term declining trend, 

or whether the recent trend represents the beginning of a long-term rising trend due to 

global demand for distribution transformers and rising commodity costs for key 

transformer components. Given the uncertainty, DOE chose to use constant prices (2010 

levels) for both its LCC and PBP analysis and the NIA. For the NIA, DOE also analyzed 

the sensitivity of results to alternative transformer price forecasts. 
164

DOE did not receive comments on the most appropriate trend to use for real 

transformer prices, and it retained the approach used for the NOPR for today’s final rule.

b. Installation Costs

Higher efficiency distribution transformers tend to be larger and heavier than less 

efficient designs. The degree of weight increase depends on how the design is modified 

to improve efficiency. In the NOPR analysis, DOE estimated the increased cost of 

installing larger, heavier transformers based on estimates of labor cost by transformer 

capacity from Electrical Cost Data 2011 Book by RSMeans.

35 DOE retained the same 

approach for the final rule. DOE’s analysis of increase in installation labor costs as 

transformer weight increases is described in detail in chapter 6 of the final rule TSD.

For pole-mounted transformers, represented by design lines (DL) 2 and 3, the 

increased weight may lead to situations where the pole needs to be replaced to support 

the additional weight of the transformer. This in turn leads to an increase in the 

installation cost. To account for this effect in the analysis, three steps are needed:

The first step is to determine whether the pole needs to be changed. This depends 

on the weight of the existing transformer compared to the weight of the transformer under 

a proposed efficiency level, and on assumptions about the load-bearing capacity of the 

pole. In the NOPR analysis, it was assumed that a pole change-out will only be necessary 

 35J.H. Chiang, C. Babbitt ; RSMeans Electrical Cost Data 2011; 2010.
165

if the weight increase is larger than 15 percent of the weight of the baseline unit, which 

DOE used to represent the existing transformer, and more than 150 pounds heavier for a 

design line 2 transformer, and 1,418 pounds heavier for a design line 3 transformer. 

While EEI stated that it may take less than a 1,418 pound increase for a design line 3 

distribution transformer to require a pole change out (EEI, No. 229 at p. 2), neither EEI 

nor its members provided comments to support a different value. Therefore, DOE 

believes there is not a compelling reason to change from the approach used in the NOPR. 

Utility poles are primarily made of wood. Both ANSI36 and the National Electrical Safety 

Code (NESC)

37 provide guidelines on how to estimate the strength of a pole based on the 

tree species, pole circumference and other factors. Natural variability in wood growth 

leads to a high degree of variability in strength values across a given pole class. Thus, 

NESC also provides guidelines on reliability, which result in an acceptable probability 

that a given pole will exceed the minimal required design strength. Because poles are 

sized to cope with large wind stresses and potential accumulation of snow and ice, this 

results in “over-sizing” of the pole relative to the load by a factor of two to four. 

Accounting for this “over-sizing,” DOE estimated that the total fraction of pole 

replacements would not exceed 25 percent of the total population. Chapter 6 of the final 

rule TSD explains the approach used to arrive at this figure.

 36 American National Standards Institute (ANSI), Wood Poles – Specifications and Dimension, ANSI 

O5.1.2008, 2008.

37 Institute of Electrical and Electronics Engineers (IEEE), 2012 National Electrical Safety Code (NESC), 

IEEE C2-2012, 2012.
166

HI commented that there very likely will be a sizeable number of situations where 

a new pole may be required, but it noted that DOE’s assumption that up to 25 percent of 

the total pole-mounted transformer population may require pole replacements is probably 

a reasonable figure. (HI, No. 151 at p. 8) EEI, APPA and NRECA suggested that the pole 

change-out fraction be increased to as high as 50 percent to 75 percent of units located in 

cities with populations of at least 25,000. (EEI, No. 185 at p. 14; NRECA, No. 172 at p. 

10; APPA, No. 191 at p. 12) EEI, NRECA, and APPA did not provide evidence or 

rationale to support their suggestion of a higher change-out fraction for urban utilities in 

their comments. Therefore, DOE believes there is not a compelling reason to change 

from the approach used in the NOPR.

The second step is to determine the cost of a pole change-out. In the NOPR phase, 

specific examples of pole change-out costs were submitted by the sub-committee. These 

examples were consistent with data taken from the RSMeans Building Construction Cost 

database.38

 38 J.H. Chiang, C. Babbitt; RSMeans Electrical Cost Data 2011; 2010.

Based on this information, for design line 2 with a capacity of 25 kVA, a 

triangular distribution was used to estimate pole change-out costs, with a lower limit at 

$2,025 and an upper limit at $5,999. For design line 3 with a capacity of 500 kVA, DOE 

used a similar distribution with a lower limit of $5,877 and an upper limit of $13,274 for 

pole replacement, and a distribution with a lower limit of $5,877 and an upper limit of 

$16,899 for multi-pole (platform) replacement. These costs are in addition to the weightbased installation cost described above. 
167

Utility poles have a finite lifetime so, in some cases, pole change-out due to 

increased transformer weight should be counted as an early replacement of the pole; i.e.,

it is not correct to attribute the full cost of pole replacement to the transformer purchase. 

Equivalently, if a pole is changed out when a transformer is replaced, it will have a longer 

lifetime relative to the pole it replaces, which offsets some of the cost of the pole 

installation. To account for this effect, pole installation costs are multiplied by a factor 

n/pole-lifetime, which approximately represents the value of the additional years of life. 

The parameter n is chosen from a flat distribution between 1 and the pole lifetime, which 

is assumed to be 30 years.39

DOE received a number of comments on pole replacement costs. Westar stated that 

it costs them approximately $2,330 to replace an existing pole with a 50‐foot Class 1 pole

for a 100 kVA distribution transformer, which might be the new norm for residential 

areas. It added that whenever they replace a pole they would lose NESC grandfathering 

for that structure and have to redo everything on the pole to bring it up to the current 

NESC code, instead of merely switching out the transformer. This results in additional 

labor. (Westar, No. 169 at p. 2) BG&E commented that DOE’s methodology may not 

reflect the true costs of pole change-outs, as pole replacement costs quoted by industry 

experts are either estimates or they reflect actual costs from previous years. In BG&E’s 

 39 As the LCC represents the costs associated with purchase of a single transformer, to account for multiple 

transformers mounted on a single pole, the pole cost should also be divided by a factor representing the 

average number of transformers per pole. No data is currently available on the fraction of poles that have 

more than one transformer, so this factor is not included.
168

experience, actual costs tend to exceed the estimates by a significant amount (20 to 60

percent). In 2011, its average pole replacement cost was $7,100, which includes the cost 

of the new pole along with any replacement material used during the installation.

(BG&E, No. 223 at p. 2) ComEd also stated that DOE may have underestimated the cost 

of pole change-outs. At ComEd, the average pole replacement cost is in the range of 

$4,000-$5,000, which includes the cost of the new pole along with any replacement 

material and labor. (ComEd, No. 184 at p. 13) Progress Energy stated that it realized 

average pole replacement costs of $2,200 during 2011, but it noted that during the 

negotiated meetings, utilities reported pole replacement costs upwards of $12,000. 

Progress Energy recommended that DOE continue to use the pole replacement costs that 

they have been using so that the final rule will not be delayed. (Progress Energy, No. 192 

at p. 9) EEI suggested that DOE increase the pole change-out cost estimates to a range of 

values (or a weighted average) provided by EEI member companies. (EEI, No. 185 at p. 

14)

The information that DOE received regarding average pole replacement costs was of 

limited use because most of the utilities did not provide their average pole replacement 

costs for the transformer capacities used in the analysis. However, DOE notes that the 

pole replacement costs mentioned in the above comments fall within the range of costs 

that DOE used for its pole-mounted design lines (design lines 2 and 3). DOE recognizes 

that there may be some cases where the pole replacement cost may be outside this range, 

but these would account for a very small fraction of situations.
169

Westar stated that when mounting a bank of three‐phase transformers on a pole, if 

the weight increased beyond 2,000 pounds per position (which wouldn’t be out of the 

realm of possibility for a transformer using amorphous core steel), they would need to 

use a 500kVA pad mount. (Westar, No. 169 at p. 2) DOE recognizes that in some 

situations pole replacement may not be an acceptable option to utilities when replacing 

transformers. DOE believes that the range of installation costs that it used for pole 

replacement, in combination with the weight-based installation costs, captures the cost of 

situations where a pad mount would be needed.

Westar commented that a new design for a pad-mounted transformer could require 

larger fiberglass pads than they currently use, or they would have to start pouring a 

concrete pad for each pad mount. (Westar, No. 169 at p. 3) DOE believes that the 

installation costs it used for pad-mounted transformers, which range from $2,169 for 

design line 1 (at 50 kVA) to $8,554 for design line 5 (at 1500 kVA), encompass the 

situation described by Westar.

3. Inputs Affecting Operating Costs

a. Transformer Loading

DOE’s assumptions about loading of different types of transformers are described 

in section IV.E. DOE generally estimated that the loading of larger capacity distribution 

transformers is greater than the loading on smaller capacity transformers. 
170

b. Load Growth Trends

The LCC analysis takes into account the projected operating costs for distribution 

transformers many years into the future. This projection requires an estimate of how the 

electrical load on transformers will change over time. In the NOPR analysis, for dry-type 

transformers, DOE assumed no-load growth, while for liquid-immersed transformers 

DOE used as the default scenario a one-percent-per-year load growth. It applied the loadgrowth factor to each transformer beginning in 2016. To explore the LCC sensitivity to 

variations in load growth, DOE included in the model the ability to examine scenarios 

with zero percent, one percent, and two percent load growth. 

DOE did not receive comments regarding its load-growth assumptions, and it 

retained the assumptions described above for the final rule analysis.

c. Electricity Costs

DOE used estimates of electricity prices and costs to place a value on transformer 

losses. For the NOPR, DOE performed two types of analyses. One investigated the nature 

of hourly transformer loads, their correlation with the overall utility system load, and 

their correlation with hourly electricity costs and prices. Another estimated the impacts of 

transformer loads and resultant losses on monthly electricity usage, demand, and 

electricity bills. DOE used the hourly analysis for liquid-immersed transformers, which 

are owned predominantly by utilities that pay costs that vary by the hour. DOE used the 
171

monthly analysis for dry-type transformers, which typically are owned by commercial 

and industrial establishments that receive monthly electricity bills.

For the hourly price analysis, DOE used marginal costs of electricity, which are the 

costs to utilities for the last kilowatt-hour of electricity produced. The general structure 

of the hourly marginal cost equation divides the costs of electricity to utilities into

capacity components and energy cost components, which are respectively applied as 

marginal demand and energy charges for the purpose of determining the value of 

transformer electrical losses. For each component, DOE estimated the economic value for 

both no-load losses and load losses.

Commenting on DOE’s hourly price analysis, NRECA stated that marginal energy 

prices recover the system generation capacity costs, and demand charges are not needed 

to collect capacity charges. (NRECA, No. 156 at pp. 4-5) It added that use of demand 

charges introduces bias towards improved cost-effectiveness of more efficient 

transformers. (NRECA, No. 156 at p. 7)

DOE disagrees with NRECA’s position that demand charges are not needed to 

collect capacity charges. DOE agrees that marginal energy prices in a single priceclearing auction can provide for recovery of some amount of generation capacity cost, but 

it is unlikely that an energy-only market (one that relies only on market incentives for 
172

investment) would provide for full recovery of system generation capacity costs.40 Even 

with the addition of revenues from an ancillary services market, recovery would likely 

still fall below the full amount of generation capacity cost for a new generator. Indeed, 

recent market evaluation reports by the Midwest Independent System Operator (ISO) and 

California ISO (CAISO) demonstrate that energy and ancillary service market prices in 

those markets are far below the levels that would be necessary to fully compensate a new 

generation owner for their generation capacity cost.41 PJM (a regional transmission 

operator in the eastern U.S.) addresses the gap between the full going-forward costs42 and 

the revenues from energy and ancillary services markets through the addition of a 

separate capacity market.43 Most other regions use similar capacity markets or require 

load serving entities (LSEs) to contract for specified amounts of capacity. Examples of 

operating regions that use capacity markets or require acquisition of specified levels of 

capacity include CAISO,44 MISO,45 and ISO New England.46

 40On an "Energy Only" Electricity Market Design For Resource Adequacy, 2005; William W. Hogan; 

http://www.ferc.gov/EventCalendar/files/20060207132019-hogan_energy_only_092305.pdf.

NRECA acknowledges the 

41 CAISO 2011 Market Issues and Performance Report, pp. 45-48,

http://www.caiso.com/Documents/2011AnnualReport-MarketIssues-Performance.pdf.

MISO 2010 State of the Market Report Executive Summary, Executive Summary, p. viii,

https://www.midwestiso.org/Library/Repository/Report/IMM/2010%20State%20of%20the%20Market%20

Report.pdf. 42 The term "going forward costs" includes, but is not limited to, all costs associated with fuel 

transportation and fuel supply, administrative and general, and operation and maintenance on a power 

plant. http://law.onecle.com/california/utilities/390.html. 43 A Review of Generation Compensation and Cost Elements in the PJM Markets, 2009, p. 30, 

http://www.pjm.com/~/media/committees-groups/committees/mrc/20100120/20100120-item-02-review-ofgeneration-costs-and-compensation.ashx. 44 CAISO 2011, p. 181, http://www.caiso.com/Documents/2011AnnualReport-MarketIssuesPerformance.pdf. 45 MISO 2010, p. viii; 

https://www.midwestiso.org/Library/Repository/Report/IMM/2010%20State%20of%20the%20Market%20

Report.pdf. 46 ISO New England 2010 Annual Markets Report, p. 33,
173

existence of capacity markets, but implies that the capacity payments can be ignored 

because their purpose is to reduce price volatility. (NRECA, No, 156 at p. 5) DOE 

disagrees with this position because ISOs have stated that the capacity markets and 

contracts are needed to maintain system reliability, not just mitigate price volatility.47

Whether an area has a capacity market or capacity requirements, a reduction in 

electricity demand due to more efficient transformers would lower the amount of capacity 

purchases required by LSEs, which would lower capacity procurement costs. DOE’s

application of demand charges captures these lower procurement costs.

DOE acknowledges that not all electricity markets have structured capacity 

markets or capacity requirements. The Electric Reliability Council of Texas (ERCOT), an 

energy-only market without set requirements for generation capacity procurement, is 

premised on the energy market and the ancillary service markets being able to provide 

sufficient revenues to attract new market entrants as needed. The expectation is that as 

reserve margins decline, market prices would increase to provide the needed revenues for 

new investment. In the long-term, absent the cessation of demand growth, one would 

 http://www.iso-ne.com/markets/mkt_anlys_rpts/annl_mkt_rpts/2010/amr10_final_060311.pdf. 47 ISO New England 2010, p. 33, http://www.isone.com/markets/mkt_anlys_rpts/annl_mkt_rpts/2010/amr10_final_060311.pdf.

PJM 2009, p. 29, http://www.pjm.com/~/media/committees-groups/committees/mrc/20100120/20100120-

item-02-review-of-generation-costs-and-compensation.ashx.

CAISO 2011, p. 181, http://www.caiso.com/Documents/2011AnnualReport-MarketIssuesPerformance.pdfhttp://www.caiso.com/Documents/2011AnnualReport-MarketIssues-Performance.pdf.

NYISO 2010, p. 156; 

http://www.nyiso.com/public/markets_operations/documents/studies_reports/index.jsp. 
174

expect market revenues to equal the full cost of a new market entrant.48 Given past 

market behavior, however, the market revenues will likely be relatively low over many 

hours and extremely high during a limited number of price spike hours. Accurate 

modeling and forecasting of price spikes is an extremely difficult task. For the ERCOT

region, DOE believes that its capacity cost approach is an appropriate proxy to capture 

the high price spikes that can occur in energy-only markets. 

Many publicly owned utilities (POU) are not required to participate in capacity 

markets or mandated to attain specified amounts of generation capacity. Capacity 

attainment is at the sole discretion of those POU’s governing bodies, but DOE expects 

that POUs would continue to build or contract with sufficient capacity to provide reliable 

service to their customers. As this capacity procurement will impose a cost that is 

incremental to the utility’s system marginal energy cost, the use of capacity costs is also 

appropriate for evaluation of transformer economics for these utilities.

Although DOE believes it is appropriate to include demand charges, for the final 

rule, DOE reviewed its capacity cost methodology and found that the demand charges 

used in the NOPR analysis were too high. In the NOPR, demand charges were based on 

the full fixed cost of new generation. For the final rule, the revised demand charges are 

based on the full cost of new generation net of the revenues that the generator could earn 

 48 If an energy-only market is functioning properly, it must be able to provide sufficient revenues to incent 

new market entrants over the long term. Failure to incent sufficient generation to provide adequate 

reliability would likely force a market redesign or the introduction of new LSE obligations such as resource 

adequacy requirements. 
175

from the hourly energy market. This quantification of capacity costs net of market 

revenues is consistent with the design of the nation’s capacity markets, including PJM 

RPM Capacity Market49 and the ISO-NE Forward Capacity Market.50 In addition, this 

method is used to develop marginal costs for the evaluation of distributed resources, 

energy efficiency, and demand response programs in regions without organized capacity 

markets, such as California.51 The modifications for the final rule significantly reduce the 

capacity cost used in the LCC analysis. The approach is described further in chapter 8 of 

the final rule TSD.

In the NOPR, to value the capacity costs, DOE used advanced coal technology to 

reflect generation capacity costs for no-load loss generation. NRECA stated that 

substituting the capacity cost of a combustion turbine/combined-cycle plant for the 

avoided cost of a new coal-fired plant appears to reduce the savings and costeffectiveness of the more-efficient transformer designs. (NRECA, No. 156 at p. 9) DOE 

agrees with NRECA’s criticism of the approach used for the NOPR. For the final rule 

DOE assumed that capacity costs for no-load loss generation depend on the type of 

generation that is built, and that these losses are served by base load capacity. DOE 

estimated the capacity cost by assuming that marginal capacity is added in the 

proportions 40 percent coal, 40 percent natural gas combined-cycle, and 20 percent wind. 

These proportions are based on the capacity mix estimated in the AEO 2011

 49 PJM 2009, Executive Summary p. 6.

projection.

50 ISO-NE 2010, p. 33; http://www.isone.com/markets/mkt_anlys_rpts/annl_mkt_rpts/2010/amr10_final_060311.pdf. 51 See http://docs.cpuc.ca.gov/efile/PD/162141.pdf.
176

d. Electricity Price Trends

For the relative change in electricity prices in future years, DOE relied on price 

forecasts from the Energy Information Administration (EIA) Annual Energy Outlook

(AEO). For the final rule analysis, DOE used price forecasts from AEO 2012. 

In the NOPR, to project the relative change in electricity prices for liquidimmersed transformers, DOE used the average electricity prices from AEO 2011. 

NRECA stated that gas-fired combustion turbines and combined cycle units are being 

used to service base loads today, as well as meeting peak demand (NRECA, No. 156 at p. 

9), and EEI asserted that natural gas is the marginal fuel "a lot" of the time (EEI, No. 

0051-0030 at p. 108). DOE agrees with both of these statements. For the final rule, DOE 

assumed that future production cost of electricity for utilities, the primary owners of 

liquid-immersed transformers, would be influenced by the price of fuel for generation 

(i.e., coal and natural gas.) To estimate the relative change in the price to produce 

electricity in future years in today’s rule, DOE applied separate price trends to both noload and load losses. DOE used the sales weighted price trend of both natural gas and 

coal to estimate the relative price change for no-load losses; and natural gas only to 

estimate the relative price change for load losses. These trends are based on the AEO 

2012 projections and are described in greater detail in chapter 8 of the TSD.
177

Appendix 8-D of this final rule TSD provides a sensitivity analysis for equipment 

of a sub-set of representative design lines. These analysis shows that the effect of changes 

in electricity price trends, compared to changes in other analysis inputs, is relatively 

small.

e. Standards Compliance Date

DOE calculated customer impacts as if each new distribution transformer 

purchase occurs in the year that manufacturers must comply with the standard. As 

discussed in section II.A, if DOE finds that amended standards for distribution 

transformers are warranted, DOE agreed to publish a final rule containing such amended 

standards by October 1, 2012. The compliance date of January 1, 2016, provides 

manufacturers with over three years to prepare for the amended standards. 

f. Discount Rates

The discount rate is the rate at which future expenditures are discounted to 

estimate their present value. DOE employs a two-step approach in calculating discount 

rates for analyzing customer economic impacts. The first step is to assume that the actual 

customer cost of capital approximates the appropriate customer discount rate. The second 

step is to use the capital asset pricing model (CAPM) to calculate the equity capital 

component of the customer discount rate. For the preliminary analysis, DOE estimated a 

statistical distribution of commercial customer discount rates that varied by transformer 

type by calculating the cost of capital for the different types of transformer owners.
178

More detail regarding DOE’s estimates of commercial customer discount rates is 

provided in chapter 8 of the final rule TSD.

g. Lifetime

DOE defined distribution transformer life as the age at which the transformer 

retires from service. For the NOPR analysis, DOE estimated, based on a report by Oak 

Ridge National Laboratory,52 that the average life of distribution transformers is 32 years. 

This lifetime estimate includes a constant failure rate of 0.5 percent/year due to lightning 

and other random failures unrelated to transformer age, and an additional corrosive 

failure rate of 0.5 percent/year starting at year 15. DOE did not receive any comments on 

transformer lifetime and it retained the NOPR approach for the final rule.

h. Base Case Efficiency

To determine an appropriate base case against which to compare various potential

standard levels, DOE used the purchase-decision model described in section IV.F.1. For 

the base case, initially transformer purchasers are allowed to choose among the entire 

range of transformers at each design line. Transformers are chosen based on either lowest 

first cost, or if the purchaser is an evaluator, on lowest Total Owning Cost (TOC). During 

the negotiations (see section II.B.2) manufacturers and utilities stated that ZDMH is not 

 52 Barnes. Determination Analysis of Energy Conservation Standards for Distribution Transformers. 

ORNL-6847. 1996.
179

currently used in North America, so designs using ZDMH as a core steel were excluded 

from the base case.

i. Inputs to Payback Period Analysis

The payback period is the amount of time it takes the consumer to recover the 

additional installed cost of more efficient products, compared to baseline products, 

through energy cost savings. Payback periods are expressed in years. Payback periods 

that exceed the life of the product mean that the increased total installed cost is not 

recovered in reduced operating expenses.

The inputs to the PBP calculation are the total installed cost of the product to the 

customer for each efficiency level and the average annual operating expenditures for each 

efficiency level. The PBP calculation uses the same inputs as the LCC analysis, except 

that discount rates are not needed. 

j. Rebuttable-Presumption Payback Period

As noted above, EPCA, as amended, establishes a rebuttable presumption that a 

standard is economically justified if the Secretary finds that the additional cost to the 

consumer of purchasing a product complying with an energy conservation standard level 

will be less than three times the value of the energy (and, as applicable, water) savings 

during the first year that the consumer will receive as a result of the standard, as 

calculated under the test procedure in place for that standard. (42 U.S.C. 
180

6295(o)(2)(B)(iii)) For each considered efficiency level, DOE determines the value of the 

first year’s energy savings by calculating the quantity of those savings in accordance with 

the applicable DOE test procedure, and multiplying that amount by the average energy 

price forecast for the year in which compliance with the amended standards would be 

required.

G.

DOE’s NIA assessed the national energy savings (NES) and the national NPV of 

total customer costs and savings that would be expected to result from amended standards 

at specific efficiency levels. (“Customer” refers to purchasers of the equipment being

regulated.)

National Impact Analysis—National Energy Savings and Net Present Value Analysis

To make the analysis more accessible and transparent to all interested parties, 

DOE used an MS Excel spreadsheet model to calculate the energy savings and the 

national customer costs and savings from each TSL.53

 53 DOE understands that MS Excel is the most widely used spreadsheet calculation tool in the United States 

and there is general familiarity with its basic features. Thus, DOE’s use of MS Excel as the basis for the 

spreadsheet models provides interested parties with access to the models within a familiar context. In 

addition, the TSD and other documentation that DOE provides during the rulemaking help explain the 

models and how to use them, and interested parties can review DOE’s analyses by changing various input 

quantities within the spreadsheet.

DOE used the NIA spreadsheet to

calculate the NES and NPV, based on the annual energy consumption and total installed 

cost data from the energy use characterization and the LCC analysis. DOE forecasted the 

energy savings, energy cost savings, equipment costs, and NPV of customer benefits for 

each product class for equipment sold from 2016 through 2045. The forecasts provided 
181

annual and cumulative values for all four output parameters. In addition, DOE analyzed 

scenarios that used inputs from the AEO 2012 Low Economic Growth and High 

Economic Growth cases. These cases have higher and lower energy price trends 

compared to the reference case. NIA results based on these cases are presented in 

appendix 10-B of the final rule TSD.

DOE evaluated the impacts of amended standards for distribution transformers by 

comparing base-case projections with standards-case projections. The base-case 

projections characterize energy use and customer costs for each equipment class in the 

absence of amended energy conservation standards. DOE compared these projections 

with projections characterizing the market for each equipment class if DOE were to adopt 

amended standards at specific energy efficiency levels (i.e., the standards cases) for that 

class.

Table IV.2 and Table IV.3 summarize all the major NOPR inputs to the shipments 

analysis and the NIA, and whether those inputs were revised for the final rule. 
182

Table IV.2 Inputs for the Shipments Analysis

Input NOPR Description Changes for Final

Rule

Shipments data Third-party expert (HVOLT) for 2009. No change.

Shipments forecast 2016-2045: Based on AEO 2011 Updated to AEO 

2012

.

Dry-type/liquidimmersed market sharesBased on EIA’s electricity sales data and 

AEO2011

Updated to AEO 

. 2012

Regular replacement 

market

Based on a survival function constructed 

from a Weibull distribution function 

normalized to produce a 32-year mean 

lifetime.*

No change.

Elasticities, liquidimmersedFor liquid-immersed transformers:

 • Low: 0.00

 • Medium: -0.04

 • High: -0.20

No change.

Elasticities, dry-type For dry-type transformers:

• Low: 0.00

• Medium: -0.02

• High: -0.20

No change.

* Source: ORNL 6804/R1, The Feasibility of Replacing or Upgrading Utility Distribution Transformers 

During Routine Maintenance, page D-1.
183

Table IV.3 Inputs for the National Impact Analysis

Input NOPR Description Changes for the Final Rule

Shipments Annual shipments from shipments model. No change.

Compliance date of 

standard

January 1, 2016 No change.

Equipment Classes Separate ECs for single- and three-phase liquidimmersed distribution transformersNo change

Base case efficiencies Constant efficiency through 2044. Equal to 

weighted-average efficiency in 2016.

No change.

Standards case 

efficiencies

Constant efficiency at the specified standard level 

from 2016 to 2044.

No change.

Annual energy 

consumption per unit

Average rated transformer losses are obtained 

from the LCC analysis, and are then scaled for 

different size categories, weighted by size market 

share, and adjusted for transformer loading (also 

obtained from the LCC analysis).

No change.

Total installed cost per 

unit

Weighted-average values as a function of 

efficiency level (from LCC analysis).

No change.

Electricity expense per 

unit

Energy and capacity savings for the two types of 

transformer losses are each multiplied by the

corresponding average marginal costs for capacity 

and energy, respectively, for the two types of 

losses (marginal costs are from the LCC analysis).

No change.

Escalation of 

electricity prices

AEO 2011 forecasts (to 2035) and extrapolation Updated to AEO 2012

for 2044 and beyond.

Electricity site-tosource conversionA time series conversion factor; includes electric 

generation, transmission, and distribution losses. 

No change

Discount rates 3% and 7% real. No change.

Present year 2010. 2012.

1. Shipments

DOE projected transformer shipments for the base case by assuming that longterm 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 
184

manufactured as expressed by the U.S. Department of Commerce, Bureau of Economic 

Analysis (BEA), transformer quantity index. DOE 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 not 

sufficient data to calibrate model parameters within an acceptable margin of error. Hence, 

DOE developed the transformer shipments projection by assuming that annual 

transformer shipments growth is equal to growth in electricity consumption as given by 

the AEO 2012 forecast through 2035. For the years from 2036 to 2045, DOE extrapolated 

the AEO 2012 forecast with the growth rate of electricity consumption from 2025 to 

2035. 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 recent market shares for different design and size categories. Chapter 9 of the final 

rule TSD provides a detailed description of how DOE projected shipments for each of the 

equipment classes in today’s final rule.

DOE recognizes that increase in transformer prices due to standards may cause 

changes in purchase of new transformers. Although the general trend of utility 

transformer purchases is determined by increases in generation, utilities conceivably 

exercise some discretion in how much transformer capacity to buy – the amount of “overcapacity” to purchase. In addition, some utilities may choose to refurbish transformers 

rather than purchase a new transformer if the price of the latter increases significantly.
185

To capture the customer response to transformer price increase, DOE estimated 

the customer price elasticity of demand. In DOE’s estimation of the purchase price 

elasticity, it used a logit function to characterize the utilities' response to the price of a 

unit capacity of transformer. The functional form captures what can be called an average 

price elasticity of demand with a term to capture the estimation error, which accounts for 

all other effects. Although DOE was not able to explicitly model the replace versus 

refurbish decision due to lack of necessary data, the price elasticity should account for 

any decrease in the shipments due to a decision on the customer's part to refurbish 

transformers as opposed to purchasing a new unit. DOE’s approach is described in 

chapter 9 of the final rule TSD. Comments on the issue of replacing versus refurbishing 

are discussed in section IV.O.3 of this notice.

2. Efficiency Trends

DOE did not include any base case efficiency trend in its shipments and national 

energy savings models. AEO forecasts show no long term trend in transmission and 

distribution losses, which are indicative of transformer efficiency. DOE estimates that the 

probability of an increasing efficiency trend and the probability of a decreasing efficiency 

trend are approximately equal, and therefore assumed no trend in base case or standards 

case efficiency. 
186

3. National Energy Savings

For each year in the forecast period, DOE calculates the national energy savings 

for each standard level by multiplying the stock of products affected by the energy 

conservation standards by the per-unit annual energy savings. Cumulative energy savings 

are the sum of the NES for each year.

To estimate national energy savings, DOE uses a multiplicative factor to convert 

site energy consumption into primary energy consumption (the energy required to 

convert and deliver the site energy). This conversion factor accounts for the energy used 

at power plants to generate electricity and losses in transmission and distribution. The 

conversion factor varies over time because of projected changes in the power plant types 

projected to provide electricity to the country. The factors that DOE developed are 

marginal values, which represent the response of the system to an incremental decrease in 

consumption associated with standards. For today’s rule, DOE used annual conversion 

factors based on the version of NEMS that corresponds to AEO 2012, which provides 

energy forecasts through 2035. For 2036–2047, DOE used conversion factors that remain 

constant at the 2035 values.

Section 1802 of EPACT 2005 directed DOE to contract a study with the National 

Academy of Science (NAS) to examine whether the goals of energy efficiency standards 

are best served by measuring energy consumed, and efficiency improvements, at the 

actual point of use or through the use of the full-fuel-cycle, beginning at the source of 
187

energy production. (Pub. L. No. 109-58 (August 8, 2005)). NAS appointed a committee 

on “Point-of-Use and Full-Fuel-Cycle Measurement Approaches to Energy Efficiency 

Standards” to conduct the study, which was completed in May 2009. The NAS 

committee defined full-fuel-cycle energy consumption as including, in addition to site 

energy use: energy consumed in the extraction, processing, and transport of primary fuels 

such as coal, oil, and natural gas; energy losses in thermal combustion in power 

generation plants; and energy losses in transmission and distribution to homes and 

commercial buildings.

In evaluating the merits of using point-of-use and full-fuel-cycle (FFC) measures, 

the NAS committee noted that DOE uses what the committee referred to as “extended 

site” energy consumption to assess the impact of energy use on the economy, energy 

security, and environmental quality. The extended site measure of energy consumption 

includes the energy consumed during the generation, transmission, and distribution of 

electricity but, unlike the full-fuel-cycle measure, does not include the energy consumed 

in extracting, processing, and transporting primary fuels. A majority of the NAS 

committee concluded that extended site energy consumption understates the total energy 

consumed to make an appliance operational at the site. As a result, the NAS committee 

recommended that DOE consider shifting its analytical approach over time to use a fullfuel-cycle measure of energy consumption when assessing national and environmental 

impacts, especially with respect to the calculation of greenhouse gas (GHG) emissions. 

For those appliances that use multiple fuels, the NAS committee indicated that measuring 
188

full-fuel-cycle energy consumption would provide a more complete picture of energy 

consumed and permit comparisons across many different appliances, as well as an 

improved assessment of impacts.

In response to the NAS committee recommendations, on August 18, 2011, DOE 

announced its intention to use full-fuel-cycle measures of energy use and greenhouse gas 

and other emissions in the national impact analyses and emissions analyses included in 

future energy conservation standards rulemakings. 76 FR 51282 While DOE stated in 

that notice that it intended to use the Greenhouse Gases, Regulated Emissions, and 

Energy Use in Transportation (GREET) model to conduct the analysis, it also said it 

would review alternative methods, including the use of NEMS. After evaluating both 

models and the approaches discussed in the August 18, 2011 notice, DOE has determined 

NEMS is a more appropriate tool for this specific use. Therefore, DOE intends to use the 

NEMS model, rather than the GREET model, to conduct future FFC analyses. 77 FR 

49701 (Aug. 17, 2012). DOE did not incorporate FFC measures into today’s final rule 

because it did not want to introduce a new method in the final phase of a rulemaking.

Rather, in today’s rule, DOE continues to use its standard measures of energy use and 

greenhouse gas and other emissions in the national impact analyses and emissions 

analyses.

4. Equipment Price Forecast

As noted in section IV.F.2, DOE assumed no change in transformer prices over 

the 2016−2045 period. In addition, DOE conducted sensitivity analysis using alternative 
189

price trends. Based on PPI data for electric power and specialty transformer 

manufacturing, DOE developed one forecast in which prices decline after 2010, and one 

in which prices rise. These price trends, and the NPV results from the associated 

sensitivity cases, are described in appendix 10-C of the final rule TSD.

5. Net Present Value of Customer Benefit

The inputs for determining the net present value (NPV) of the total costs and 

benefits experienced by consumers of considered appliances are: (1) total annual installed 

cost; (2) total annual savings in operating costs; and (3) a discount factor. DOE calculates 

net savings each year as the difference between the base case and each standards case in 

total savings in operating costs and total increases in installed costs. DOE calculates 

operating cost savings over the life of each product shipped during the forecast period.

In calculating the NPV, DOE multiplies the net savings in future years by a 

discount factor to determine their present value. DOE estimates the NPV using both a 3-

percent and a 7-percent real discount rate, in accordance with guidance provided by the 

Office of Management and Budget (OMB) to Federal agencies on the development of 

regulatory analysis.54

 54 OMB Circular A-4 (Sept. 17, 2003), section E, “Identifying and Measuring Benefits and Costs. Available 

at: 

The discount rates for the determination of NPV are in contrast to 

the discount rates used in the LCC analysis, which are designed to reflect a consumer’s 

perspective. The 7-percent real value is an estimate of the average before-tax rate of 

return to private capital in the U.S. economy. The 3-percent real value represents the 

www.whitehouse.gov/omb/memoranda/m03-21.html.
190

“social rate of time preference,” which is the rate at which society discounts future 

consumption flows to their present value.

H.

In analyzing the potential impacts of new or amended standards, DOE evaluates 

impacts on identifiable groups (i.e., subgroups) of customers that may be 

disproportionately affected by a national standard. 

Customer Subgroup Analysis

A number of parties expressed specific concerns about size and space constraints 

for network/vault transformers. (BG&E, No. 182 at p. 6; ComEd, No. 184 at p. 11; 

Pepco, No. 145 at pp. 2−3; PE, No. 192 at p. 8; Prolec-GE, No. 177 at p. 12)

For today's final rule, DOE evaluated purchasers of vault-installed transformers 

(mainly utilities concentrated in urban areas), represented by design lines 4 and 5, as a 

customer subgroup, and examined the impact of standards on these groups using the 

methodology of the LCC and PBP analysis. DOE examined the impacts of larger 

transformer volume with regard to costs for vault enlargement. DOE assumed that if the 

volume of a unit in a standard case is larger than the median volume of transformer 

designs for the particular design line, a vault modification would be warranted. To 

estimate the cost, DOE compared the difference in volume between the unit selected in 

the base case against the unit selected in the standard case, and applied fixed and variable 

costs. In the 2007 final rule, DOE estimated the fixed cost as $1,740 per transformer and 
191

the variable cost as $26 per transformer cubic foot.55 For today’s notice, these costs were 

adjusted to 2011$ using the chained price index for non-residential construction for 

power and communications to $1886 per transformer and $28 per transformer cubic foot.

DOE considered instances where it may be extremely difficult to modify existing vaults 

by adding a very high vault replacement cost option to the LCC spreadsheet. Under this 

option, the fixed cost is $30,000 and the variable cost is $733 per transformer cubic foot. 

The customer subgroup analysis is discussed in detail in chapter 11 of the final rule

TSD.

I.

1. Overview

Manufacturer Impact Analysis

DOE performed a manufacturer impact analysis (MIA) to estimate the financial 

impact of amended energy conservation standards on manufacturers of distribution 

transformers and to calculate the impact of such standards on employment and 

manufacturing capacity. The MIA has both quantitative and qualitative aspects. The 

quantitative part of the MIA primarily relies on the Government Regulatory Impact 

Model (GRIM), an industry cash-flow model with inputs specific to this rulemaking. The 

key GRIM inputs are data on the industry cost structure, product costs, shipments, and 

assumptions about markups and conversion expenditures. The key output is the INPV. 

Different sets of shipment and markup assumptions (scenarios) will produce different 

 55 See section 7.3.5 of the 2007 final rule TSD, available at 

http://www1.eere.energy.gov/buildings/appliance_standards/commercial/pdfs/transformer_fr_tsd/chapter7.

pdf.
192

results. The qualitative part of the MIA addresses factors such as product characteristics, 

impacts on particular sub-groups of firms, and important market and product trends. The 

complete MIA is outlined in chapter 12 of the TSD.

2. Product and Capital Conversion Costs

New and amended energy conservation standards will cause manufacturers to 

incur conversion costs to bring their production facilities and product designs into 

compliance. For the MIA, DOE classified these conversion costs into two major groups: 

(1) product conversion costs and (2) capital conversion costs. DOE’s estimates of the 

product and capital conversion costs for distribution transformers can be found in section 

V.B.2.a of today’s final rule and in chapter 12 of the TSD.

a. Product Conversion Costs

Product conversion costs are investments in research, development, testing, 

marketing, and other non-capitalized costs necessary to make product designs comply 

with the new or amended energy conservation standard. DOE based its estimates of the 

product conversion costs that would be required to meet each TSL on information 

obtained from manufacturer interviews, the engineering analysis, and the NIA shipments 

analysis. For the distribution transformer industry, a large portion of product conversion 

costs will be related to the production of amorphous cores, which would require the 

development of new designs, materials management, and safety measures. Procurement 
193

of such technical expertise may be particularly difficult for manufacturers without 

experience using amorphous steel. 

b. Capital Conversion Costs

Capital conversion costs are investments in property, plant, and equipment 

necessary to adapt or change existing production facilities such that new equipment

designs can be fabricated and assembled. For capital conversion costs, DOE prepared 

bottom-up estimates of the costs required to meet standards at each TSL for each design 

line. To do this, DOE used equipment cost estimates provided by manufacturers and 

equipment suppliers, an understanding of typical manufacturing processes developed 

during interviews and in consultation with subject matter experts, and the properties 

associated with different core and winding materials. Major drivers of capital conversion 

costs include changes in core steel type (and thickness), core weight, core stack height, 

and core construction techniques, all of which are interdependent and can vary by 

efficiency level. DOE uses estimates of the core steel quantities needed for each steel 

type, as well as the most likely core construction techniques, to model the additional 

equipment the industry would need to meet the efficiencies embodied by each TSL.

3. Markup Scenarios

In the NOPR MIA, DOE modeled two standards-case markup scenarios to 

represent the uncertainty regarding the potential impacts on prices and profitability for 

manufacturers following the implementation of amended energy conservation standards: 
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(1) a preservation of gross margin percentage markup scenario, and (2) a preservation of 

operating profit markup scenario. These scenarios lead to different markups values, 

which, when applied to the inputted MPCs, result in varying revenue and cash flow 

impacts. While DOE has modified several inputs to the GRIM for today’s final rule, it 

continues to analyze these two markup scenarios for the final rule. For a complete 

discussion, see the NOPR or chapter 12 of the TSD.

4. Other Key GRIM Inputs

Key inputs to the GRIM characterize the distribution transformer industry cost 

structure, investments, shipments, and markups. For today’s final rule, DOE made 

several updates to the GRIM to reflect changes in these inputs since publication of the 

NOPR. Specifically, DOE incorporated changes made in the engineering analysis and 

NIA, including updates to the MPCs, shipment forecasts, and shipment efficiency 

distributions. In addition, DOE made minor changes to its conversion cost methodology 

in response to comments as described below. These updated inputs affected the values 

calculated for the conversion costs and markups described above, as well as the INPV 

results presented in section V.B.2.

5. Discussion of Comments

The following section discusses a number of comments DOE received on the 

February 2012 NOPR MIA methodology. DOE has grouped the comments into the 
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following topics: core steel, small manufacturers, conversion costs, and benefits versus

burdens. 

a. Core Steel

The issue of core steel is critical to this rulemaking. This section discusses 

comments related to steel price projections, steel mix and competition between suppliers, 

and steel supply and production capacity. Most of these issues are highly interconnected.

Steel Prices. Several stakeholders commented on the steel prices used by DOE. 

Prolec-GE believes that the steel supply assessment in appendix 3A of the TSD was too 

optimistic about supply and price in a post-recession global environment and that any 

analysis for higher than current level efficiencies should evaluate a much higher range of 

material price variance that what DOE used in the NOPR. (Prolec-GE, No. 52 at p. 13) 

APPA notes that the analysis in appendix 3A of the TSD provides good information 

about prices from 2006 to 2010, but it does not include information about the significant 

increase in prices compared to 2002−2003 levels. 

Northeast Energy Efficiency Partnerships argued that, when faced with 

competition, conventional high-grade electrical steel prices could come down and 

compete effectively with the more efficient amorphous materials. (NEEP, No. 193 at p. 

3) Earthjustice expressed similar sentiments, stating that the analysis conducted by DOE 

on DL1 presents an unrealistic picture of the LCC impacts of meeting TSLs 2 and 3 with 
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conventional steels in that design line because competitive pressure from amorphous 

metal will likely reduce the price for grain-oriented electrical steels and, therefore, 

improve the LCC savings for consumers. (Earthjustice, No. 195 at p. 1-3)

DOE recognizes that steel prices have proven highly volatile in the past and could 

continue to fluctuate in the future for a variety of reasons, including macroeconomic 

factors, competition among steel suppliers, trade policy and raw material prices. With

respect to Earthjustice’s comment, while DOE agrees that the LCC is highly sensitive to 

relative steel price assumptions at certain TSLs, DOE notes that a decline in silicon 

transformer prices would be unlikely to materially change the slope of the silicon steel 

transformer cost curve. Therefore, the incremental costs (and LCC savings) would not 

change significantly. To NEEP’s comment, DOE agrees that competition between 

silicon steel suppliers, the incumbent amorphous metal suppliers and new market entrants 

will impact future prices. However, DOE does not believe it is possible to predict the 

relative movements in these prices. Throughout the negotiation process, stakeholders 

have argued for different price points for different steels under different scenarios. The 

eventual relative prices of steels in the out years will be in part subject to the 

aforementioned market forces, the direction and magnitude of which cannot be known at 

this time. For these reasons, DOE performed a sensitivity analysis that included a wide 

range of potential core steel prices to evaluate their impact on LCC savings as discussed 

in section V.B.3.
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Diversity of Steel Mix and Competition. Most stakeholders stated a preference 

for a market in which traditional and amorphous steel could effectively compete, but 

there was disagreement over which efficiency level would strike that balance, particularly 

for liquid-immersed distribution transformers. The various steel types that are available 

on the market for distribution transformers are listed in Table 5.10 in chapter 5 of the 

TSD. Stakeholders generally sought a standard that would allow manufacturers to use a 

diversity of electrical steels that are cost-competitive and economically feasible. This 

issue is critical to stakeholders for several reasons, including what some worried would 

be a lack of amorphous steel supply, a transition to a market that currently has only one

global supplier with significant capacity, as well as forced conversion costs associated 

with the manufacturing of amorphous steel cores. 

Both APPA and Adams Electric Cooperative (AEC) commented that it is 

important that DOE preserve the competitive market by allowing both grain-oriented 

steel and amorphous core transformers to be price competitive. APPA and AEC are 

concerned about the availability and price of the core materials if only one product is 

competitively viable because this will affect jobs for traditional steel manufacturers and 

also small transformer manufacturers that may not be able to afford or have the expertise 

to convert their plants to accommodate amorphous core construction. (APPA, No. 191 at 

p. 5; AEC, No. 163 at p.3) Wisconsin Electric also stated that it is important to have a 

mix of suppliers available to keep the price of amorphous steel in check and to mitigate 
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the risk of unforeseen situations, such as natural disasters. (Wisconsin Electric, No. 168 

at p.2) 

Some stakeholders, in particular ACEEE, ASAP, NRDC, and Northwest Power 

and Conservation Council (NPCC), asserted that competition can still be maintained at 

efficiency levels higher than those proposed in the NOPR. These stakeholders believe 

that TSL 1 favors silicon steel and will, therefore, raise the price for silicon steel while 

relegating amorphous steel to niche status, relative to a higher TSL. They noted that 

industry sources and press accounts confirm that electrical steel is a very high profit 

margin product and the lack of strong competition for M3 in the current market appears 

to be contributing to very high M3 prices. (Advocates, No. 186 at p. 10) Therefore, the 

Advocates argued that a modified TSL 4 (EL2 for all design lines) for liquid-immersed 

transformers could be met using either amorphous metal or silicon steel, thereby 

increasing competition. ASAP had suggested during the NOPR public meeting that 

moving into a market where there would be three domestically based competitors would 

be a better competitive outcome than the status quo of two competitors who have the 

lion’s share of the market. (ASAP, No. 146 at p. 38) In response to the supplementary 

analysis of June 20, 2012, the Advocates suggested the adoption of TSL C, which they 

believed would provide for robust competition among core material suppliers. 

(Advocates, No. 235 at p. 1) They also noted that TSL D, which consists of EL 2 for padmounted transformers and EL 1 for pole-mounted transformers, would favor the 

continued use of grain oriented electrical steel for the majority of the market and allow 
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silicon steel and amorphous metal to reach rough cost parity for pad-mounted

transformers. (Advocates, No. 235 at p. 4) ACEEE, ASAP, NRDC, and NPCC further 

cited some transformer manufacturers as saying TSL 4 or 3.5 (EL 2 or EL 1.5) for liquidimmersed transformers would lead to robust competition because a market currently 

served by two steel suppliers (AK Steel and ATI Allegheny Ludlum) would then be 

served by three since the amorphous metal supplier (Metglas) could compete. 

(Advocates, No. 186 at p. 10-11) Additional amorphous metal suppliers may also enter 

the market because barriers to entry into amorphous metal transformer production are, 

according to Metglas, quite limited. (Metglas, No. 102 at p. 2) Also, based on the results 

of an analysis conducted by an industry expert for ASAP, the Advocates believe that it 

would be very unlikely that TSL 4 standards from the NOPR for liquid-immersed 

transformers would result in amorphous metal market share exceeding 20 percent in the 

near- and medium-term due to the current dominant position of silicon steel, inertia in 

utility decision making, and the ability of steel makers to lower prices to protect against 

market share erosion. Furthermore, increases in the standards for LVDT and MVDT 

transformers, which have markets where amorphous metal does not compete and is not

expected to compete at the levels proposed by DOE, will increase silicon steel tonnage. 

In the longer term, silicon steel manufacturers can make strategic investment decisions 

that will enable them to compete, such as increasing production of High B steel or 

entering amorphous metal production. (Advocates, No. 186 at pp. 12−13) Berman 

Economics also argued that competition between traditional and amorphous steel is still 

possible with higher standards for liquid-immersed transformers because, according to
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shipments data from ABB, TSL 4 has the greatest diversity of core materials. (Berman 

Economics, No. 221 at p. 7)

On the other hand, many stakeholders believe that competition among steel 

suppliers will not be possible at levels higher than those proposed in the NOPR. At the 

NOPR public meeting, ATI stated that the proposed standards maintain a competitive 

balance between alternative materials and grain-oriented electrical steel, which has 

adequate supply from annual global production levels exceeding two million metric tons 

and price competition from several producers. (ATI, No. 146 at p. 18) ATI believes that 

higher standards will result in cost-effective design options limited to amorphous metal 

cores for liquid-immersed transformers. Such a situation would cost U.S. jobs, increase 

the risk of supply shortages and disruptions, and create a non-competitive market for new 

liquid-immersed designs which ATI expects will eliminate any projected LCC savings. 

(ATI, No. 54 at p. 2) Furthermore, ATI stated that even TSL 1 may have adverse impacts 

on competition because the efficiency levels assigned to design lines 2 and 5 in TSL 1 

were set well above the crossover point for competition between multiple core materials 

and therefore the implementation of TSL 1 would curtail the availability of multiple 

options for core material choices for liquid- immersed transformers. ATI did not support 

any of the new TSLs proposed in DOE’s supplementary analysis, which were higher than 

TSL 1 and which would, according to ATI, have significant impacts on the 

competitiveness of grain-oriented electrical steel and result in nearly complete conversion 

of the liquid-immersed market to amorphous cores. (ATI Allegheny, No. 218 at p. 1) 
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Instead, ATI proposed an alternative TSL which consists of what it believes are more 

accurate crossover points for the liquid-immersed design lines: EL 1.3 for DL 1, EL 0 for 

DL2, EL 0.7 for DL 3, EL 1 for DL 4, and EL 0.7 for DL 5. (ATI Allegheny, No. 218 at 

p. 1) 

Cooper Power stated that the currently proposed efficiency levels are at the 

maximum levels that allow use of both silicon and amorphous core steels. Higher 

efficiency levels will tip the market in favor of amorphous materials that are not available 

in the quantities needed and do not have the desired diversity of suppliers to maintain a 

healthy market. (Cooper Power, No. 165 at p. 4) Cooper Power had found through one of 

its analyses that the crossover point at which transformer price is equivalent between M3 

and amorphous was at EL 0.5 for all design lines 1,3,4, and 5 and EL 0.25 for DL2. 

According to Cooper Power, the best choice for raising the efficiency levels and keeping 

both M3 core steel and amorphous core steel competitive with one another would be to 

choose EL 0.5. (Cooper Power Systems, No. 222 at p. 2) During the NOPR public 

meeting, Cooper Power commented that, past EL 1, it is no longer a level playing field 

between amorphous and silicon core steel. (Cooper Power, No. 146, at p. 49-50) HVOLT 

also commented that the crossover point between M3 and amorphous is at EL 1, and it’s 

a hard move to amorphous past that level. (HVOLT, No. 146 at p. 51) The United Auto 

Workers (UAW) is concerned that requiring efficiency levels beyond TSL-1 for liquidimmersed transformers would impose unwarranted conversion costs on transformer 

producers, force the use of amorphous metals that are not available in adequate supply, 
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and create significant anticompetitive market power for the producer of amorphous metal 

electrical steel. (UAW, No. 194 at p. 2) EEI is very concerned about the availability of 

steels if DOE decides to increase any efficiency levels above those proposed in the 

NOPR because, as DOE’s life-cycle analyses have shown, the “tipping” point where 

many domestic steelmakers are not competitive is usually at levels that are equal to or 

less than TSL 1 for liquid-immersed transformers. Domestic steelmakers agreed, 

explaining that the anticompetitive ramifications of a decision to promulgate a standard 

greater than TSL 1 for the liquid-immersed market would not be economically justified. 

According to AK Steel and ATI, since amorphous metal is currently competitive but may 

not be in sufficient supply, and non-amorphous manufacturers may not be able to 

compete with amorphous metal on a first-cost basis beyond TSL 1, any decision by DOE 

to promulgate a standard greater than TSL 1 would transfer significant market power, 

including potential price increases, to the maker of amorphous metal. (AK Steel and ATI, 

No. 188 at p. 2-3) AK Steel also commented that DOE should finalize a standard 

equivalent to TSL 1 from the NOPR rather than adopt the new TSLs A through D

proposed in the supplementary analysis because it believes that the new TSLs, which are 

more stringent, would have significant anticompetitive effects that will harm both electric 

utilities and the public through increased prices. (AK Steel, No. 230 at p. 12 - 13) NEMA 

supports the currently proposed efficiency levels because higher levels will tip the scale 

in favor of amorphous materials that are not available in the quantities needed and do not 

have the desired diversity of suppliers to maintain a healthy market. (NEMA, No. 170 at 

p. 14) In response to the supplementary analysis, NEMA argued that the new TSLs (with 
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the exception of TSL A if DL 2 remains at EL 0) would all result in steel supply 

shortages or a bias in favor of amorphous. (NEMA, No. 225 at p. 4) AEC believes that 

DOE appropriately balanced high transformer efficiency with a viable competitive 

market in the NOPR. (AEC, No. 163 at p. 3) NRECA agreed, stating that DOE has 

achieved the correct balance of high transformer efficiency while maintaining a viable 

competitive market, because any efficiency level above those recommended in the NOPR 

will greatly impact competition and, therefore, affect jobs for steel manufacturers and 

small transformer manufacturers that may not have the resources to convert their plants to 

accommodate amorphous core construction. (NRECA, No. 228 at p. 4) Likewise, the 

United Steelworkers Union (USW) supports the currently proposed efficiency levels 

because they allow end-users to choose between competing technologies rather than 

relying on a single option. (USW, No. 148 at p. 2)

DOE recognizes the importance of maintaining a competitive market for 

transformer steel supply in which traditional steel and amorphous steel suppliers can both 

participate. This was a critical consideration in DOE’s assessment of the rule’s impact on 

competition. As with the discussion on future prices, the precise “crossover point” is 

variable depending on a number of factors, including firm pricing strategies, global 

demand and supply, trade policy, market entry, and economies of scale among producers 

and consumers of the core steel. The magnitudes of these potential influences on the 

cross-over point cannot be precisely known in advance.
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DOE attempted to survey manufacturers about the mix of core steel used currently 

for transformers meeting various efficiency levels and also queried the industry about 

their expectations for core steel mix at those efficiencies should the next DOE standard 

require them. However, beyond those presentations made publicly by various 

manufacturers during the negotiations—which demonstrated conflicting views on the 

“crossover point”— DOE could not gather sufficient data to calculate manufacturer 

expectations of the crossover point at various TSLs. While several stakeholders have 

pointed to the “tipping point” shown by the LCC’s steel selection analysis as evidence 

that the market will transition to amorphous entirely for some design lines, DOE repeats 

here that not every possible design was analyzed and that the LCC tool is highly sensitive 

to price assumptions which have been shown to be extremely variable over time and 

among suppliers. Balancing all of the evidence in this docket, DOE believes that the 

levels established by today’s final rule will maintain a choice of steel mix for the 

industry. As discussed in the weighing of benefits and burdens section (section IV.I.5.d), 

DOE remains concerned about the potential for significant disruption in the steel supply 

market at levels higher than those established by today’s rule.

As for the conversion costs that may be required should some manufacturers 

decide to begin making, or to increase production of, amorphous core transformers, DOE 

accounts for them in the GRIM analysis. 
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Supply and Capacity. The ability of core steel producers to increase supply if 

necessary is another related key issue discussed by stakeholders. Some stakeholders were 

concerned that suppliers may not have the capacity to produce certain steels in quantities 

great enough to meet demand at higher efficiency levels, while other stakeholders 

believed that suppliers will be fully capable of expanding capacity as needed.

Several stakeholders expressed concerns about utilities being unable to serve 

customers due to steel supply constraints in the distribution chain. EEI stated that its 

members do not want to repeat the situation they faced in 2006-2008 when there were 

transformer shortages and utilities were told that there would be delays of months or even 

years before certain transformers would be available. (EEI, No. 185 at p. 10) APPA noted 

that the threat of transformer rationing may return in an improved economy and hamper 

the ability of utilities to meet their obligation to serve customers. (APPA, No. 191 at p. 

10) Likewise, Consolidated Edison believes that the possible requirement to use higher 

grade core steels in order to achieve higher efficiencies may result in supply scarcity, 

increased costs, and tough competition for these materials after recovery from the global 

recession. (ConEd, No. 236 at p. 4) Commonwealth Edison Company is very concerned 

about the availability of a quality steel supply for the transformer manufacturing industry 

and that a limited supply of transformers will have a significant negative effect on the 

company’s ability to provide safe and reliable electric service to its customers. (ComEd, 

No. 184 at p. 11) Howard Industries is also concerned about the limited availability of 

critical core materials such as M2 and amorphous, which could pose a large risk to the 
206

transformer and utility industries and may become a particularly troublesome issue if the 

economy and housing markets return to more normal levels. (Howard Industries, No. 226 

at p. 2) In addition, the USW stated that the number of transformer producers with the 

equipment to build reliable transformers with amorphous ribbon cores is relatively small. 

Therefore, a sudden transition to amorphous ribbon would result in a fragile supply chain 

for distribution transformers, potentially leading to large cost increases and supply 

shortages that would place the security of the U.S. electrical transmission grid at risk. 

(USW, No. 148 at p. 2) ATI stated during the NOPR public meeting that a scenario in 

which grain-oriented electrical steel is not available as a core material option could result 

in a long-term situation where no domestic companies would produce the strategically 

important material for transformers that are the critical link in the U.S. electrical grid. 

(ATI, No. 146 at p. 19)

Some stakeholders also emphasized the importance of being able to use M3 steel, 

which is more readily available than other more efficient steels. Prolec-GE noted that 

silicon steel grades above M3 have significant supply limitations and predicted no change 

in that situation for the foreseeable future. Therefore, Prolec-GE continues to see the need 

for a balanced approach to higher efficiencies such that M3 silicon steel and amorphous 

metal can compete for a share of the liquid-immersed market, which would allow 

manufacturers to have a sufficient supply of these materials to serve customer 

requirements. (Prolec-GE, No. 52 at pp. 11−12) Progress Energy also stated that M2 core 

steel is in short supply because it is only a small part of a silicon core steel producer’s 
207

output and M3 and M4 grades of core steel should be required for 85 percent or more of 

any required efficiency level so that utilities will not face shortage situations that would 

have negative impacts on grid reliability. (Progress Energy, No. 192 at pp. 7−8) 

Likewise, Power Partners voiced concern about the U.S. supply of core steel should DOE 

adopt an efficiency that requires the use of grades better than M3. Power Partners stated 

that the current domestic capacity for M2 will not support 100 percent of all liquidimmersed transformers and, therefore, recommended that DOE only consider efficiency 

levels that can be attained with M3 core steel with no loss evaluation. The grades better 

than M3 should be employed when the utility loss evaluation justifies its use. (Power 

Partners, No. 155 at pp. 3−4) Southern California Edison has stated that greater market 

demand for M2 core steel may create supply shortages and result in high steel prices. 

(Southern California Edison, No. 239 at p. 1) According to Central Moloney, M2 and 

higher grades of steel are premium products within the steel manufacturing process which 

comprise no more than 15 percent of overall steel production. Central Moloney is 

concerned that the marketplace will not be able to support the demand of these premium 

products if efficiency levels are increased. (Central Moloney, No. 224 at pp. 1−2) 

Stakeholders have also expressed several concerns regarding the availability of 

steels supplied by foreign vendors, especially amorphous steel. Both Commonwealth 

Edison Company and Baltimore Gas and Electric Company stated that the overseas 

procurement of steel could result in specification issues and that there could be a negative 

impact on the U.S. electric grid if DOE sets a standard that requires the use of a specific 
208

core steel that is not readily available in the domestic market and which does not have a 

proven track record. (ComEd, No. 184 at p. 12 and BG&E, No. 182 at p. 7) Power 

Partners has stated that grades of grain-oriented electrical steel better than M2 for wound 

core applications are only available from international sources and supply capacity is 

very limited. (Power Partners, No. 155 at pp. 3−4) In addition, Progress Energy is 

concerned that amorphous and mechanically scribed core steel will not be available in 

sufficient quantities because domestic transformer vendors rely on basically one 

amorphous core steel provider. This supplier may not have the capacity to provide 

enough amorphous material to meet demand from all U.S. transformer manufacturers as 

well as overseas business if the efficiency levels are increased beyond EL 1 for liquidimmersed distribution transformers. (Progress Energy, No. 192 at pp. 7−8) ABB has 

indicated that amorphous steel is a sole source product for the U.S., and, as demand 

increases for it, there could be a tight global supply as well as upward price pressure. 

(ABB, No. 158 at p. 8) ABB has also expressed concerns about mechanically scribed 

steel. This type of steel has only four global suppliers, and its availability may be subject 

to international trade restrictions. (ABB, No. 158 at p. 8) According to Cooper Power 

Systems, ZDMH is in large part unavailable in the U.S. and should therefore represent 

only a small fixed percentage of overall usage. (Cooper Power Systems, No. 222 at p. 2) 

However, some stakeholders are more confident that the supply of higher 

efficiency steels would increase to meet demand due to higher standards. ACEEE, 

ASAP, NRDC, and NPCC believe that it is highly unlikely that amorphous production 
209

will not expand in response to higher standards because: (1) the U.S. producer of 

amorphous metal has demonstrated its ability to add capacity over the past several years 

as producers of high-value electricity (e.g., wind producers) have favored amorphous 

metal products, and (2) other manufacturers are exploring amorphous production and 

there are no legal barriers to entry for new competitors. (Advocates, No. 186 at p. 11) The 

Advocates also noted that one of the largest global suppliers of silicon steel for 

transformers, POSCO (formerly Pohang Iron and Steel Company), is entering the 

amorphous metal market. The company approved a plan for commercializing amorphous 

metal production in 2010 and will soon begin production and marketing of amorphous 

metal with plans to produce up to 1 kiloton (kt) in 2012, 5 kt in 2013, and 10 kt in 2014. 

(Advocates, No. 235 at p. 3) Schneider Electric stated that, with the exception of 

amorphous, there are sufficient suppliers worldwide (Europe and Asia) who have either 

increased capacity or who have near term plans to increase capacity to meet the growing 

demand for high‐grade steels. The company feels it is better to allow global market 

conditions to dictate business plans rather than the DOE because manufacturing and 

freight costs play a lesser role than supply and demand in determining the final price for 

high-grade steels, whether domestic or foreign, as long as there are sufficient suppliers 

worldwide. (Schneider, No. 180 at p. 6) In addition, Hydro-Quebec has stated that the 

equipment for making amorphous steels is mainly used to serve the distribution 

transformer market, which allows amorphous steel to be less influenced by other nontransformer markets that may impact steel price and availability. Amorphous steel 

production lines are also much smaller than silicon steel lines, thereby allowing 
210

amorphous steel makers to add production capacity by small increments with relatively 

low capital expenditures and in a relatively short time frame. Hydro-Quebec therefore 

believes that amorphous steel production can be tightly connected with increasing 

demand. (Hydro-Quebec, No. 125 at p. 2) Metglas, has also stated that an increase in 

capacity to even 100 percent of 2016 demand would only require an approximately 

$200M investment in amorphous metal casting capacity and an even smaller total 

industry investment by core/transformer makers in amorphous metal transformer 

manufacturing capacity. Metglas further stated that it has a technology transfer program 

to assist any U.S. transformer maker in quickly progressing into production of amorphous 

metal-based transformers. (Metglas, No. 102 at p. 2) Berman Economics supports 

Metglas’ position, arguing that Metglas has demonstrated its willingness and capability to 

increase capacity as a result of the 2007 Final Rule and should be expected to do so 

again, particularly considering the financial resources available to Metglas from its 

parent, Hitachi. Moreover, since there are no patent restrictions on amorphous steel, there 

is nothing to prevent silicon steel from diversifying to include an amorphous line should 

it choose to do so. (Berman Economics, No. 150 at p. 10) Berman Economics also 

believes that DOE improperly assumes that increased use of amorphous will reduce 

silicon steel production in an effort to ensure that silicon steel production does not suffer 

profit losses as amorphous becomes more competitive. Additionally, Earthjustice claimed 

that DOE did not rationally analyze the potential impacts associated with steel production 

capacity constraints because, according to the NOPR, adopting TSLs 2 or 3 for liquidimmersed transformers would lead to shortages of amorphous metal such that grain-
211

oriented electrical steel cores would have to be used in non‐cost‐effective applications, 

but in the TSD, those TSLs would split the market between amorphous and grainoriented steels and DOE expects minimal core steel capacity issues at TSLs that do not 

force the entire market into amorphous steel usage. (Earthjustice, No. 195 at pp. 1−2) 

DOE is aware that there is currently only one global supplier of amorphous steel 

with any significant capacity and that the parent company is foreign-owned (although a 

substantial share of its production takes place domestically through its U.S. subsidiary). 

At the same time, a few other steel producers have announced plans to begin, or have 

recently begun, very limited production of amorphous metal. DOE is also aware that 

there are only a few suppliers for mechanically scribed steel and that some of these 

suppliers are also foreign-owned. Given the lack of suppliers of domain-refined (e.g., H0, 

ZDMH) and amorphous steels, DOE agrees that the amended energy conservation 

standards should provide manufacturers with the option to cost-effectively use grainoriented silicon steels, which have fewer supply constraints. This would help ensure that 

utilities have access to transformers, particularly in the event of stronger economic 

growth (a driver of transformer demand) or a natural disaster, both concerns raised by 

commenters. Furthermore, DOE understands that M2 cannot be produced at the 

quantities equivalent to current M3 yields due to the nature of the silicon steel production 

process. Given these facts, DOE concluded that a standard that could not be achieved by 

M3 would not be economically justified. On the other hand, DOE also acknowledges that 

the current amorphous supplier may be able to expand capacity to meet additional 
212

demand and a few other companies have begun the initial stages of developing capacity. 

The eventual steel quality and production capacity of these emerging amorphous sources 

are unknown at this time. Therefore, DOE has been careful in selecting a TSL that would 

allow manufacturers to use not only amorphous and mechanically scribed steel,that is 

currently produced in limited quantities, but also grain-oriented steels. 

DOE believes that the Earthjustice comment that DOE did not rationally analyze 

the potential impacts associated with steel production capacity constraints actually refers 

to two related but separate issues in the NOPR and NOPR TSD. In the TSD, DOE 

explains that the availability of total core steel would not be an issue until TSL 4 because 

both conventional and amorphous steels would be available to use until that point. In the 

NOPR, DOE explains that the availability of amorphous steel may be an issue at TSLs 2 

and 3, and that manufacturers may need to use other types of steels, such as M3, which 

are not the lowest cost options. These statements are not contradictory because, although

amorphous steel capacity may not be able to expand to meet all demand at TSLs 2 and 3, 

that does not imply that total core steel capacity would be insufficient because 

manufacturers still have the option of using M3 or M2 or other steels at these levels. 

b. Small Manufacturers

An important area of discussion among stakeholders is the impact of energy 

efficiency standards on small manufacturers. At the NOPR public meeting, ASAP had 
213

suggested that DOE should do additional work to better document and understand the 

scale of the impacts on small manufacturers. (ASAP, No. 146 at p. 170)

Some stakeholders expressed concern that standards higher than those proposed in 

the NOPR would have a significant negative impact on small manufacturers. NEMA is 

very concerned with the possibility that higher efficiency standards will negatively 

impact small manufacturing facilities and may drive some small companies, in particular 

LVDT transformer manufacturers, out of business. (NEMA, No. 170 at pp. 4, 8) In 

addition, at least one small NEMA manufacturer of liquid-immersed distribution 

transformers has reported that it cannot stay in business at levels higher than EL1. 

(NEMA, No. 170 at p. 6) APPA is also concerned about small manufacturer impacts 

resulting from the use of amorphous steel, stating that small transformer manufacturers 

that may not be able to afford or have the expertise to convert their plants to 

accommodate amorphous core construction may be forced to go out of business. (APPA, 

No. 191 at p. 5) HVOLT commented that producing stacked core products with mitering 

would take millions of dollars and small manufacturers in some states cannot afford that 

investment, and may be forced to go out of business. (HVOLT, No. 146 at pp. 50−51) 

Furthermore, at higher efficiency levels, even if small manufacturers can continue to use 

butt-lapping, they may not be able to sell their transformers at a price where material 

costs are recovered. (HVOLT, No. 146 at p. 151)
214

However, other stakeholders have suggested that small manufacturer effects have 

been overemphasized in DOE’s analysis. ACEEE, ASAP, NRDC, and NPCC disagreed 

with DOE’s small business analysis, claiming that it overstates impacts on small business 

manufacturers of LVDT transformers. The NOPR record and an investigation by the 

Advocates indicate that the vast majority of covered transformers are manufactured by a 

handful of large manufacturers with all of their major production facilities in Mexico. 

Since small, domestic manufacturers cannot compete on price with Mexican production 

facilities, domestic manufacturers focus on specialty transformers which are generally 

outside the scope of the regulation or on high-efficiency offerings. (Advocates, No. 186 

at pp. 5−6) Furthermore, even if DOE finds that there are a significant number of small 

manufacturers with U.S. production facilities making covered LVDT transformers, the 

Advocates suggest that DOE should still adopt TSL 3 because any small manufacturer 

with long term viability in the distribution transformer market can build compliant 

transformers. DOE’s record indicates that the least-cost option for building LVDT 

transformers at TSL 3 entails step-lap mitering and some small manufacturers already 

have mitering equipment. The Advocates commented that for companies that currently 

lack mitering machines, industry experts have testified that a step lap mitering machine 

costs between $0.5 million and $1 million, which is a small investment that should be 

well within reach for viable manufacturing companies, even if they are small. The 

Advocates also indicate that DOE may have placed too much emphasis on small business 

impacts in its decision-making criteria. Companies also have the option of sourcing their 

cores from third party suppliers, who can obtain better materials prices than all but the 
215

largest transformer makers, regardless of the efficiency levels chosen. In fact, they cite to 

the NOPR to support the notion that market pressures are already likely to be pushing 

small transformer manufacturers to purchase sourced cores regardless of the efficiency 

levels adopted. (Advocates, No. 186 at p. 6) Furthermore, although small manufacturers 

may not get the same treatment from steel suppliers as large manufacturers do, small 

manufacturers will face this disadvantage regardless of the standard level chosen. 

(Advocates, No. 186 at p. 5)

Similar sentiments were expressed by California Investor Owned Utilities (CA 

IOUs). According to the CA IOUs, although DOE repeatedly emphasizes the concern that 

small manufacturers may be disproportionately impacted by higher standard levels and 

leans on this concern as justification for selecting TSL 1 for low-voltage dry-type

transformers, there are actually very few small manufacturers in this market and those 

small manufacturers that do exist primarily focus on design lines that are exempted from 

coverage. The CA IOUs commented that some small manufacturers that do produce 

covered transformers are focusing on high efficiency NEMA Premium® transformers, 

indicating that smaller manufacturers are already capable of producing higher efficiency 

transformers. Furthermore, small manufacturers could source their cores, and many are 

currently doing so today, which offsets any need to upgrade core construction equipment. 

(CA IOUs, No. 189 at pp. 2−3) 
216

Also, Earthjustice has commented that DOE has arbitrarily relied on impacts on 

small manufacturers in rejecting stronger standards for low‐voltage dry‐type (LVDT) 

units despite there being few, if any, small manufacturers of this equipment who are 

likely to be impacted. DOE has not explained why sourcing cores is not an acceptable 

option for any small manufacturer and, given the evidence in the TSD that sourcing cores 

is a more profitable approach for small manufacturers of LVDTs, DOE’s reliance on the 

adverse financial impacts to small manufacturers associated with producing such cores 

in‐house in rejecting stronger LVDT standards is unreasonable. (Earthjustice, No. 195 at 

pp. 3−5)

NEEP has suggested that DOE should not sacrifice large national benefits to 

provide ill-defined benefits for a small number of manufacturers. Even if some domestic 

small manufacturers may be affected by the new standards, DOE should do a more 

comprehensive analysis of how much the standards would impact those small 

manufacturers. The investments needed to meet new standards may be affordable for 

companies which have covered transformers as a significant part of their business, and 

companies that have covered transformers as a small portion of their business may 

choose to exit this part of the market or source their cores. (NEEP, No. 193 at pp.4−5) 

DOE understands that small companies face additional challenges from an 

increase in standards because they are more likely to have lower production volumes, 
217

fewer engineering resources, a lack of purchasing power for high performance steels, and 

less access to capital. 

For liquid-immersed distribution transformers, DOE does not believe that small 

manufacturers will face significant capital conversion costs at TSL 1 because they can 

continue to produce silicon steel cores using M3 or better grades rather than invest in 

amorphous technology should they make that business decision. Alternatively, they could 

source their cores, a common industry practice. 

For the LVDT market, DOE conducted further analysis based on comments 

received on the NOPR to reevaluate the impact of higher standards on small 

manufacturers. Although there may not be many small LVDT manufacturers that produce 

covered equipment in the U.S. and small manufacturers may hold only a low percentage 

of market share, the Department of Energy does consider impacts on small manufacturers 

to be a significant factor in determining an appropriate standard level. As discussed in the 

engineering analysis, because commenters suggested that EL3, the efficiency level 

selected at TSL 2 for DL7 (equivalent to NEMA Premium®), could be achieved with a 

butt-lap design, DOE further investigated the efficiency limits of butt-lapping potential. 

The primary reason that DOE proposed TSL 1 over TSL 2 in the NOPR was because it 

did not appear that TSL 2 could be met using butt-lapping technology, which would have 

caused undue hardship on small manufacturers that utilize this technology. However, in 

response to comments from the NOPR, DOE analyzed additional design option 
218

combinations using butt-lapping technology for DL 7 in its engineering analysis and 

determined that EL 3 can still be achieved without the need for mitering by using higher 

grade steels. While these would likely not be the designs of choice for high-volume 

manufacturers because the capital cost of a mitering machine has a much lower per unit 

cost given their larger volumes, this option may allow low-volume players, such as small 

manufacturers, to avoid investing in mitering machines or sourcing their cores due to 

financial constraints. . However, at TSL 3 and higher, manufacturers may not be able to 

continue using butt-lapping technology with steels that are readily available. 

Although sourced cores may be the most cost-effective strategy in the near term, 

some manufacturers indicated during interviews that production of cores is an important 

part of the value chain and that they could ill-afford to cede it to third parties. On the 

other hand, some manufacturers indicated they are able to successfully compete because 

of their sourcing strategies, not in spite of them, because they can meet a variety of 

customer needs more quickly and cheaply than would otherwise be possible. Particularly 

because most small U.S. LVDT manufacturers are heavily involved in the transformer 

market not otherwise covered by statute, which constitutes roughly 50 percent of all 

LVDT sales, DOE believes that sourcing DOE-covered mitered cores represents a viable 

strategic alternative for small LVDT manufacturers, given that it is a common industry 

business strategy for low volume product lines.
219

In conclusion, DOE believes that TSL 2, the level established by today’s standards, 

affords small LVDT transformer manufacturers with several strategic paths to 

compliance: (1) investing in mitering capability, (2) continuing to use low-capital buttlap core designs with higher grade steels, (3) sourcing cores from third-party core 

manufacturers, or (4) focus on the exempt portion of the market. 

c. Conversion Costs

Berman Economics questioned DOE’s methodology for calculating conversion 

costs, which was described in section IV.I.3.c of the NOPR. Berman argued that DOE 

provided unreasonable estimates of conversion costs because DOE based estimates on an 

arbitrary percent of total R&D expenditures across all equipment regulated by DOE. 

Therefore, the conversion cost estimates are not relevant to the proposed regulatory 

action. (Berman Economics, No. 150 at pp. 14−15)

In response, the percentages that DOE used to determine product conversion costs 

for liquid-immersed transformer manufacturers were based solely on information relevant 

to the distribution transformer industry, not for all equipment regulated by DOE. DOE’s 

estimates for product conversion expenses for liquid-immersed distribution transformer 

manufacturers would be based upon the extent to which the industry would need to 

convert to amorphous technology. This methodology is similar to the one used for the 

2007 final rule but modified to reflect feedback from manufacturers during interviews 
220

and to consider the technology required to meet the efficiency levels from the current 

rulemaking. 

Berman Economics also commented that DOE’s estimates of stranded assets were 

illogical for production, financial, and corporate strategy reasons. From a production 

perspective, there is likely to be a net increase in demand for silicon steel at EL 2 for

liquid-immersed transformers so assets such as annealing ovens would not be stranded. 

Berman Economics stated most annealing ovens are very old and have already been 

depreciated, and manufacturing investment may be expensed in the year purchased 

according to current tax laws, so the cost of all recently purchased annealing ovens has 

already been recovered. From a strategic perspective, if a manufacturer chooses not to 

offer an amorphous line of products, DOE should not put itself in a position to favor that 

manufacturer’s strategy over another. Furthermore, Berman Economics stated that DOE 

based stranded assets on an arbitrary percent of new capital conversion costs which may 

have been a holdover from the decision on microwave ovens. (Berman Economics, No.

150 at pp. 15−16)

DOE agrees that the calculations in the NOPR for stranded assets were incorrectly 

derived in the GRIM and has revised the model for the final rule. For the final rule, 

stranded assets in the standards case are derived from the share of the industry’s net 

property, plant and equipment (PPE) that is estimated to no longer be useful due to 
221

energy conservation standards. The change has no substantial effect on the overall 

results. See TSD chapter 12 for more details.

Berman Economics also stated that DOE has overestimated capital conversion 

costs because the Department assumed a 100 percent front-load in investment prior to the 

2016 effective date rather than a least-cost method of financing, such as a long-term loan.

(Berman Economics, No. 150 at p. 16)

Accounting for investments in the time frame between the effective date of 

today’s rule and the rule compliance date is the accepted methodology vetted during the 

preliminary analysis and the standard model used for DOE rulemakings. This 

methodology also considers the possibility that some manufacturers, such as small 

manufacturers, may have difficulty obtaining loans. 

In addition, Berman Economics argued that an increased market demand for 

amorphous steel relative to silicon steel may reduce investment expenditures rather than 

increase them because the annealing oven for an amorphous steel core costs substantially 

less than the annealing oven for a silicon steel core. Some transformer manufacturers may 

also be able to source cores, which, Berman Economics stated, DOE incorrectly 

considered an undesirable market activity. Berman Economics noted that an outsourcing 

opportunity allows manufacturers to specialize, use cash for other strategic purposes, and 

pursue multiple objectives. (Berman Economics, No. 150 at pp. 16−17)
222

DOE takes into account conversion costs associated with a given TSL. While the 

cost of a single annealing oven for an amorphous steel core may be less than the cost of a 

single annealing oven for a silicon steel core, other factors, particularly throughput levels, 

associated tooling, and the R&D expenses allocated to the development of new designs 

and production processes, also drive conversion costs calculations. 

With respect to core sourcing, as with the above discussion related to the LVDT 

market, DOE notes that it is not making any judgment on the value of one business 

strategy versus another. Whether sourcing cores is a viable option for any given 

manufacturer is a decision for each manufacturer in the context of its unique 

environment. However, during interviews, some manufacturers indicated that production 

of cores is an important part of the value chain and doubted their long-term viability 

should they outsource that function.

Finally, Berman Economics has noted that the logic explained by DOE that more 

stringent levels of efficiency are associated with larger adverse industry impacts does not 

hold true in the GRIM, which indicates that the model contains a multiplicity of unknown 

logic errors and its results must be viewed as spurious. (Berman Economics, No. 150 at p. 

18)
223

Although higher efficiency levels are often correlated with greater adverse 

industry impacts, certain offsetting factors based on DOE’s markup assumptions may 

result in deviations from this pattern. For example, in the preservation of gross margin 

percentage scenario, DOE applied a single uniform “gross margin percentage” markup 

across all efficiency levels so that, as production costs increase with efficiency, the 

absolute dollar markup increases as well. Therefore, the highest efficiency levels do not 

result in the highest drop in INPV because manufacturers are able to compensate for 

higher conversion costs by charging higher prices.

6. Manufacturer Interviews

DOE interviewed manufacturers representing approximately 65 percent of liquidimmersed distribution transformer sales, 75 percent of medium-voltage dry-type

transformer sales, and 50 percent of low-voltage dry-type transformer sales. These 

interviews were in addition to those DOE conducted as part of the engineering analysis. 

DOE outlined the key issues for the rulemaking for manufacturers in the NOPR. 77 FR 

7282 (February 10, 2012). DOE considered the information received during these 

interviews in the development of the NOPR and this final rule.

7. Sub-Group Impact Analysis

DOE identified small manufacturers as a subgroup in the MIA. DOE describes the 

impacts on small manufacturers in section VI.B. below.
224

J.

Employment impacts include direct and indirect impacts. Direct employment 

impacts are any changes in the number of employees of manufacturers of the equipment

subject to standards, their suppliers, and related service firms. The MIA addresses those 

impacts. Indirect employment impacts are changes in national employment that occur due 

to the shift in expenditures and capital investment caused by the purchase and operation 

of more efficient appliances. Indirect employment impacts from standards consist of the 

jobs created or eliminated in the national economy, other than in the manufacturing sector 

being regulated, due to: (1) reduced spending by end users on energy; (2) reduced 

spending on new energy supply by the utility industry; (3) increased consumer spending 

on the purchase of new equipment; and (4) the effects of those three factors throughout 

the economy. DOE’s employment impact analysis addresses these impacts. No public 

comments were received on this analysis.

Employment Impact Analysis

One method for assessing the possible effects on the demand for labor of such

shifts in economic activity is to compare sector employment statistics developed by the 

Labor Department’s Bureau of Labor Statistics (BLS). BLS regularly publishes its 

estimates of the number of jobs per million dollars of economic activity in different 

sectors of the economy, as well as the jobs created elsewhere in the economy by this 

same economic activity. Data from BLS indicate that expenditures in the utility sector 

generally create fewer jobs (both directly and indirectly) than expenditures in other 
225

sectors of the economy.56 There are many reasons for these differences, including wage 

differences and the fact that the utility sector is more capital-intensive and less laborintensive than other sectors. Energy conservation standards have the effect of reducing 

consumer utility bills. Because reduced consumer expenditures for energy likely lead to 

increased expenditures in other sectors of the economy, the general effect of efficiency 

standards is to shift economic activity from a less labor-intensive sector (i.e., the utility 

sector) to more labor-intensive sectors (e.g., the retail and service sectors). Thus, based 

on the BLS data alone, DOE believes net national employment may increase because of 

shifts in economic activity resulting from amended standards for transformers.

For the standard levels considered in today’s final rule, DOE estimated indirect 

national employment impacts using an input/output model of the U.S. economy called 

Impact of Sector Energy Technologies version 3.1.1 (ImSET). ImSET is a specialpurpose version of the “U.S. Benchmark National Input-Output” (I–O) model, which was 

designed to estimate the national employment and income effects of energy-saving 

technologies. The ImSET software includes a computer-based I–O model having 

structural coefficients that characterize economic flows among the 187 sectors. ImSET’s 

national economic I–O structure is based on a 2002 U.S. benchmark table, specially 

aggregated to the 187 sectors most relevant to industrial, commercial, and residential 

building energy use. DOE notes that ImSET is not a general equilibrium forecasting 

model, and understands the uncertainties involved in projecting employment impacts, 

 56 See Bureau of Economic Analysis, Regional Multipliers: A User Handbook for the Regional InputOutput Modeling System (RIMS II). Washington, DC. U.S. Department of Commerce, 1992.
226

especially changes in the later years of the analysis. Because ImSET does not incorporate

price changes, the employment effects predicted by ImSET may over-estimate actual job 

impacts over the long run. For the final rule, DOE used ImSET only to estimate shortterm employment impacts.

For more details on the employment impact analysis, see chapter 13 of the final 

rule TSD. 

K.

The utility impact analysis estimates several important effects on the utility 

industry that would result from the adoption of new or amended standards. To calculate 

this, DOE first obtained the energy savings inputs associated with efficiency 

improvements to the considered products from the NIA. Then, DOE used that data in the 

NEMS-BT model to generate forecasts of electricity consumption, electricity generation 

by plant type, and electric generating capacity by plant type, that would result from each 

TSL. Finally, DOE calculates the utility impact analysis by comparing the results at each 

TSL to the latest 

Utility Impact Analysis

AEO Reference case. For the final rule, the estimated impacts for the 

considered standards are the differences between values derived from NEMS–BT and the 

values in the AEO 2012 reference case. 

Chapter 14 of the final rule TSD describes the utility impact analysis. No public 

comments were received on this analysis.
227

L.

In the emissions analysis, DOE estimated the reduction in power sector emissions 

of CO2, SO2, NOX, and Hg from amended energy conservation standards for distribution 

transformers. DOE used the NEMS–BT computer model, which is run similarly to the 

Emissions Analysis

AEO NEMS, except that distribution transformers energy use is reduced by the amount 

of energy saved (by fuel type) due to each TSL. The inputs of national energy savings 

come from the NIA spreadsheet model, while the output is the forecasted physical 

emissions. The net benefit of each TSL is the difference between the forecasted emissions 

estimated by NEMS–BT at each TSL 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. For today’s rule, DOE used the version of 

NEMS-BT based on AEO 2012, which generally represents current legislation and 

environmental regulations, including recent government actions, for which implementing 

regulations were available as of December 31, 2011.

SO2 emissions from affected electric generating units (EGUs) are subject to 

nationwide and regional emissions cap and trading programs. 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. were

also limited under the Clean Air Interstate Rule (CAIR), which created an allowancebased trading program that operates along with the Title IV program. 70 FR 25162 (May 
228

12, 2005) CAIR was remanded to the U.S. Environmental Protection Agency (EPA) by 

the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in 2008, but 

it remained in effect. On July 6, 2011 EPA issued a replacement for CAIR, the CrossState Air Pollution Rule (CSAPR). 76 FR 48208 (August 8, 2011). The version of 

NEMS-BT used for today’s rule assumes the implementation of CSAPR.57

The attainment of emissions caps typically is flexible among EGUs and is 

enforced through the use of emissions allowances and tradable permits. Under existing 

EPA regulations, 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. In past rulemakings, 

DOE recognized that there was uncertainty about the effects of efficiency standards on 

SO2 emissions covered by the existing cap-and-trade system, but it concluded that no 

reductions in power sector emissions would occur for SO2 as a result of standards.

Beginning in 2015, however, SO2 emissions will fall as a result of the Mercury 

and Air Toxics Standards (MATS) for power plants, which were announced by EPA on 

December 21, 2011. 77 FR 9304 (Feb. 16, 2012). In the final MATS rule, EPA 

established a standard for hydrogen chloride as a surrogate for acid gas hazardous air 

 57 On December 30, 2011, the D.C. Circuit stayed the new rules while a panel of judges reviews them, and 

told EPA to continue administering CAIR. See EME Homer City Generation, LP v. EPA, Order, No. 11-

1302, Slip Op. at *2 (D.C. Cir. Dec. 30, 2011). On August 21, 2012, the D.C. Circuit vacated CSAPR. 

See EME Homer City Generation, LP v. EPA, No. 11-1302, 2012 WL 3570721 at *24 (D.C. Cir. Aug. 21, 

2012). The court ordered EPA to continue administering CAIR. AEO 2012 had been finalized prior to both 

these decisions, however. DOE understands that CAIR and CSAPR are similar with respect to their effect 

on emissions impacts of energy efficiency standards.
229

pollutants (HAP), and also established a standard for SO2 (a non-HAP acid gas) as an 

alternative equivalent surrogate standard for acid gas HAP. The same controls are used 

to reduce HAP and non-HAP acid gas; thus, SO2 emissions will be reduced as a result of 

the control technologies installed on coal-fired power plants to comply with the MATS 

requirements for acid gas. AEO 2012 assumes that, in order to continue operating, coal 

plants must have either flue gas desulfurization or dry sorbent injection systems installed 

by 2015. Both technologies, which are used to reduce acid gas emissions, also reduce 

SO2 emissions. Under the MATS, NEMS shows a reduction in SO2 emissions when 

electricity demand decreases (e.g., as a result of energy efficiency standards). Emissions 

will be far below the cap that would be established by CSAPR, so it is unlikely that 

excess SO2 emissions allowances resulting from the lower electricity demand would be

needed or used to permit offsetting increases in SO2 emissions by any regulated EGU.

Therefore, DOE believes that efficiency standards will reduce SO2 emissions in 2015 and 

beyond.

Under CSAPR, there is a cap on NOx emissions in 28 eastern States and the 

District of Columbia. Energy conservation standards are expected to have little effect on 

NOx emissions in those States covered by CSAPR because excess NOx emissions 

allowances resulting from the lower electricity demand could be used to permit offsetting 

increases in NOx emissions. However, standards would be expected to reduce NOx

emissions in the States not affected by the caps, so DOE estimated NOx emissions 

reductions from the standards considered in today’s rule for these States.
230

The MATS limit mercury emissions from power plants, but they do not include 

emissions caps and, as such, DOE’s energy conservation standards would likely reduce 

Hg emissions. For this rulemaking, DOE estimated mercury emissions reductions using 

the NEMS-BT based on AEO 2012, which incorporates the MATS.

Chapter 15 of the final rule TSD provides further information on the emissions 

analysis.

M.

As part of the development of this rule, DOE considered the estimated monetary 

benefits from the reduced emissions of CO2 and NOX that are expected to result from 

each of the considered TSLs. To make this calculation similar to the calculation of the 

NPV of customer benefit, DOE considered the reduced emissions expected to result over 

the lifetime of equipment shipped in the forecast period for each TSL. This section 

summarizes the basis for the monetary values used for CO2 and NOX emissions and 

presents the values considered in this rulemaking.

Monetizing Carbon Dioxide and Other Emissions Impacts 

For CO2, DOE is relying on a set of values for the social cost of carbon (SCC) that 

was developed by a government interagency process. A summary of the basis for those 

values is provided below, and a more detailed description of the methodologies used is 

provided as an appendix to chapter 16 of the final rule TSD.
231

1. Social Cost of Carbon

Under section 1(b)(6) of Executive Order 12866, 58 FR 51735 (Oct. 4, 1993), 

agencies must, to the extent permitted by law, “assess both the costs and the benefits of 

the intended regulation and, recognizing that some costs and benefits are difficult to 

quantify, propose or adopt a regulation only upon a reasoned determination that the 

benefits of the intended regulation justify its costs.” The purpose of the SCC estimates 

presented here is to allow agencies to incorporate the monetized social benefits of 

reducing CO2 emissions into cost-benefit analyses of regulatory actions that have small, 

or “marginal,” impacts on cumulative global emissions. The estimates are presented with 

an acknowledgement of the many uncertainties involved and with a clear understanding 

that they should be updated over time to reflect increasing knowledge of the science and 

economics of climate impacts.

As part of the interagency process that developed the SCC estimates, technical 

experts from numerous agencies met on a regular basis to consider public comments, 

explore the technical literature in relevant fields, and discuss key model inputs and 

assumptions. The main objective of this process was to develop a range of SCC values 

using a defensible set of input assumptions grounded in the existing scientific and 

economic literatures. In this way, key uncertainties and model differences transparently 

and consistently inform the range of SCC estimates used in the rulemaking process.
232

a. Monetizing Carbon Dioxide Emissions

The SCC is an estimate of the monetized damages associated with an incremental 

increase in carbon dioxide emissions in a given year. It is intended to include (but is not 

limited to) changes in net agricultural productivity, human health, property damages from 

increased flood risk, and the value of ecosystem services. Estimates of the SCC are 

provided in dollars per metric ton of carbon dioxide.

When attempting to assess the incremental economic impacts of carbon dioxide 

emissions, the analyst faces a number of serious challenges. A recent report from the 

National Research Council58 points out that any assessment will suffer from uncertainty,

speculation, and lack of information about: (1) future emissions of greenhouse gases; (2) 

the effects of past and future emissions on the climate system; (3) the impact of changes 

in climate on the physical and biological environment; and (4) the translation of these 

environmental impacts into economic damages. As a result, any effort to quantify and 

monetize the harms associated with climate change will raise serious questions of 

science, economics, and ethics and should be viewed as provisional.

Despite the serious limits of both quantification and monetization, SCC estimates 

can be useful in estimating the social benefits of reducing carbon dioxide emissions. 

Consistent with the directive quoted above, the purpose of the SCC estimates presented 

 58 National Research Council. “Hidden Costs of Energy: Unpriced Consequences of Energy Production and 

Use.” National Academies Press: Washington, D.C. 2009.
233

here is to make it possible for agencies to incorporate the social benefits from reducing 

carbon dioxide emissions into cost-benefit analyses of regulatory actions that have small, 

or “marginal,” impacts on cumulative global emissions. Most Federal regulatory actions 

can be expected to have marginal impacts on global emissions.

For such policies, the agency can estimate the benefits from reduced (or costs 

from increased) emissions in any future year by multiplying the change in emissions in 

that year by the SCC value appropriate for that year. The net present value of the benefits 

can then be calculated by multiplying each of these future benefits by an appropriate 

discount factor and summing across all affected years. This approach assumes that the 

marginal damages from increased emissions are constant for small departures from the 

baseline emissions path, an approximation that is reasonable for policies that have effects 

on emissions that are small relative to cumulative global carbon dioxide emissions. For

policies that have a large (non-marginal) impact on global cumulative emissions, there is 

a separate question of whether the SCC is an appropriate tool for calculating the benefits 

of reduced emissions. This concern is not applicable to this rulemaking, and DOE does 

not attempt to answer that question here.

It is important to emphasize that the interagency process is committed to updating 

these estimates as the science and economic understanding of climate change and its 

impacts on society improves over time. Specifically, the interagency group has set a 

preliminary goal of revisiting the SCC values at such time as substantially updated 
234

models become available, and to continue to support research in this area. In the 

meantime, the interagency group will continue to explore the issues raised by this 

analysis and consider public comments as part of the ongoing interagency process.

b. Social Cost of Carbon Values Used in Past Regulatory Analyses

To date, economic analyses for Federal regulations have used a wide range of 

values to estimate the benefits associated with reducing carbon dioxide emissions. In the 

model year 2011 CAFE final rule, the Department of Transportation (DOT) used both a 

“domestic” SCC value of $2 per metric ton of CO2 and a “global” SCC value of $33 per 

metric ton of CO2 for 2007 emission reductions (in 2007$), increasing both values at 2.4 

percent per year. It also included a sensitivity analysis at $80 per metric ton of CO2.59 A 

domestic SCC value is meant to reflect the value of damages in the United States 

resulting from a unit change in carbon dioxide emissions, while a global SCC value is 

meant to reflect the value of damages worldwide.

A 2008 regulation proposed by DOT assumed a domestic SCC value of $7 per 

metric ton of CO2 (in 2006$, with a range of $0 to $14 for sensitivity analysis) for 2011 

emission reductions, also increasing at 2.4 percent per year.60

 59 See Average Fuel Economy Standards Passenger Cars and Light Trucks Model Year 2011, 74 FR 14196 

(March 30, 2009) (final rule); Final Environmental Impact Statement Corporate Average Fuel Economy 

Standards, Passenger Cars and Light Trucks, Model Years 2011-2015 at 3-90 (Oct. 2008) (Available at: 

A regulation for packaged 

http://www.nhtsa.gov/fuel-economy). 60 See Average Fuel Economy Standards, Passenger Cars and Light Trucks, Model Years 2011-2015, 73 

FR 24352 (May 2, 2008) (proposed rule); Draft Environmental Impact Statement Corporate Average Fuel 

Economy Standards, Passenger Cars and Light Trucks, Model Years 2011-2015 at 3-58 (June 2008) 

(Available at: http://www.nhtsa.gov/fuel-economy).
235

terminal air conditioners and packaged terminal heat pumps finalized by DOE in October 

of 2008 used a domestic SCC range of $0 to $20 per metric ton CO2 for 2007 emission 

reductions (in 2007$). 73 FR 58772, 58814 (Oct. 7, 2008). In addition, EPA’s 2008 

Advance Notice of Proposed Rulemaking on Regulating Greenhouse Gas Emissions 

Under the Clean Air Act identified what it described as “very preliminary” SCC 

estimates subject to revision. 73 FR 44354 (July 30, 2008). EPA’s global mean values 

were $68 and $40 per metric ton CO2 for discount rates of approximately 2 percent and 3 

percent, respectively (in 2006$ for 2007 emissions).

In 2009, an interagency process was initiated to offer a preliminary assessment of 

how best to quantify the benefits from reducing carbon dioxide emissions. To ensure 

consistency in how benefits are evaluated across agencies, the Administration sought to 

develop a transparent and defensible method, specifically designed for the rulemaking 

process, to quantify avoided climate change damages from reduced CO2 emissions. The 

interagency group did not undertake any original analysis. Instead, it combined SCC 

estimates from the existing literature to use as interim values until a more comprehensive 

analysis could be conducted. The outcome of the preliminary assessment by the 

interagency group was a set of five interim values: global SCC estimates for 2007 (in 

2006$) of $55, $33, $19, $10, and $5 per ton of CO2. These interim values represent the 

first sustained interagency effort within the U.S. government to develop an SCC for use

in regulatory analysis. The results of this preliminary effort were presented in several 

proposed and final rules and were offered for public comment in connection with 
236

proposed rules, including the joint EPA-DOT fuel economy and CO2 tailpipe emission 

proposed rules.

c. Current Approach and Key Assumptions 

Since the release of the interim values, the interagency group reconvened on a 

regular basis to generate improved SCC estimates, which were considered for this 

proposed rule. Specifically, the group considered public comments and further explored 

the technical literature in relevant fields. The interagency group relied on three integrated 

assessment models (IAMs) commonly used to estimate the SCC: the FUND, DICE, and 

PAGE models.61 These models are frequently cited in the peer-reviewed literature and 

were used in the last assessment of the Intergovernmental Panel on Climate Change. Each 

model was given equal weight in the SCC values that were developed.

Each model takes a slightly different approach to model how changes in 

emissions result in changes in economic damages. A key objective of the interagency 

process was to enable a consistent exploration of the three models while respecting the 

different approaches to quantifying damages taken by the key modelers in the field. An 

extensive review of the literature was conducted to select four sets of input parameters for 

these models: climate sensitivity, socio-economic and emissions trajectories, and 

discount rates. A probability distribution for climate sensitivity was specified as an input 

into all three models. In addition, the interagency group used a range of scenarios for the 

 61 The models are described in appendix 15-A of the final rule TSD.
237

socio-economic parameters and a range of values for the discount rate. All other model 

features were left unchanged, relying on the model developers’ best estimates and 

judgments.

The interagency group selected four SCC values for use in regulatory analyses. 

Three values are based on the average SCC from three integrated assessment models, at 

discount rates of 2.5 percent, 3 percent, and 5 percent. The fourth value, which represents 

the 95th percentile SCC estimate across all three models at a 3-percent discount rate, is 

included to represent higher-than-expected impacts from temperature change further out 

in the tails of the SCC distribution. For emissions (or emission reductions) that occur in 

later years, these values grow over time, as depicted in Table IV.6. 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,62 although preference is 

given to consideration of the global benefits of reducing CO2 emissions.

Table IV.6 Social Cost of CO2, 2010–2050 (in 2007 dollars per metric ton)

Year

Discount Rate 

5% 3% 2.5% 3%

Average Average Average 95th Percentile

2010 4.7 21.4 35.1 64.9

2015 5.7 23.8 38.4 72.8

2020 6.8 26.3 41.7 80.7

2025 8.2 29.6 45.9 90.4

2030 9.7 32.8 50.0 100.0

 62 It is recognized that this calculation for domestic values is approximate, provisional, and highly 

speculative.
238

2035 11.2 36.0 54.2 109.7

2040 12.7 39.2 58.4 119.3

2045 14.2 42.1 61.7 127.8

2050 15.7 44.9 65.0 136.2

It is important to recognize that a number of key uncertainties remain, and that 

current SCC estimates should be treated as provisional and revisable since they will 

evolve with improved scientific and economic understanding. The interagency group also 

recognizes that the existing models are imperfect and incomplete. The National Research 

Council report mentioned above points out that there is tension between the goal of 

producing quantified estimates of the economic damages from an incremental metric ton 

of carbon and the limits of existing efforts to model these effects. There are a number of 

concerns and problems that should be addressed by the research community, including 

research programs housed in many of the agencies participating in the interagency 

process to estimate the SCC.

DOE recognizes the uncertainties embedded in the estimates of the SCC used for 

cost-benefit analyses. As such, DOE and others in the U.S. Government intend to 

periodically review and reconsider those estimates to reflect increasing knowledge of the 

science and economics of climate impacts, as well as improvements in modeling. In this 

context, statements recognizing the limitations of the analysis and calling for further 

research take on exceptional significance.
239

In summary, in considering the potential global benefits resulting from reduced 

CO2 emissions, DOE used the most recent values identified by the interagency process, 

adjusted to 2011$ using the GDP price deflator. For each of the four cases specified, the 

values used for emissions in 2011 were $4.9, $22.3, $36.5, and $67.6 per metric ton 

avoided (values expressed in 2011$).63 To monetize the CO2 emissions reductions 

expected to result from amended standards for distribution transformers, DOE used the 

values identified in Table A1 of the “Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866,” which is reprinted in appendix 16-A of the final 

rule TSD, appropriately escalated to 2011$. To calculate a present value of the stream of 

monetary values, DOE discounted the values in each of the four cases using the specific 

discount rate that had been used to obtain each SCC value.

2. Valuation of Other Emissions Reductions

As noted above, new or amended energy conservation standards would reduce 

NOX emissions in those 22 States that are not affected by the CAIR. DOE estimated the 

monetized value of NOX emissions reductions resulting from each of the TSLs 

considered for today’s rule using a range of dollar per ton values cited by OMB.64

 63 Table A1 presents SCC values through 2050. For DOE’s calculation, it derived values after 2050 using 

the 3-percent per year escalation rate used by the interagency group.

 These 

values, which range from $370 per ton to $3,800 per ton of NOX from stationary sources, 

measured in 2001$ (equivalent to a range of $450 to $4,623 per ton in 2011$), are based 

64 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, D.C. Page 64.
240

on estimates of the mortality-based benefits of NOX reductions from stationary sources 

made by EPA. In accordance with OMB guidance, DOE conducted two calculations of 

the monetary benefits derived using each of the above values for NOX, one using a 

discount rate of 3 percent and the other using a discount rate of 7 percent. 65

Commenting on the NOPR, APPA stated that DOE has significantly overstated 

the environmental benefits from NOX reduction attributed to the efficiency levels in the 

proposed rule. APPA suggested that DOE use emissions allowance prices from EPA's 

Clean Air Interstate Rule and the NOx Budget Trading Program, which averaged $15.89 

per ton in 2011. (APPA, No. 191 at p. 2)

In response, DOE disagrees with APPA’s claim that “[t]hese emissions markets 

and their subsequent prices were designed to monetize the environmental cost of 

polluting in its entirety.” Emissions allowance prices in any given market are a function

of several factors, including the stringency of the regulations and the costs of complying 

with regulations, as well as the initial allocation of allowances. The prices do not reflect 

the potential damages caused by emissions that still take place. There is extensive

literature on valuation of benefits of reducing air pollutants, including valuation of 

 65 OMB, Circular A-4: Regulatory Analysis (Sept. 17, 2003).
241

reduced NOx emissions from electricity generation.66 The values that DOE has used are 

consistent with the estimates in the literature.

DOE has decided to await further guidance regarding consistent valuation and 

reporting of Hg emissions before it monetizes Hg in its rulemakings.

N.

In the NOPR, DOE responded to comments regarding the classification and 

labeling of rectifier and testing transformers. In response to these comments, DOE 

acknowledged that the proposed additions to the definitions helped to clarify “rectifier” 

and “testing transformers” and proposed to amend the definitions accordingly. 

Labeling Requirements

Cooper Power expressed support for the plan DOE set forth in the NOPR to 

clarify rectifier and testing transformers. (Cooper, No. 165 at p. 2) Howard Industries 

also expressed support, noting that while they do not manufacture rectifier or testing 

transformers, they find DOE’s nameplate request to “indicate that they are for such 

purposes exclusively” to be acceptable. (HI, No. 151 at p. 12) Earthjustice commented 

that the addition of labeling requirements for rectifier and testing transformers can help 

prevent misapplication of these exempt products, but they feel additional changes, such 

as requiring any print or electronic marketing for such units to indicate their use 

 66 See e.g., Burtraw, Dallas, Karen Palmer, Ranjit Bharvirkar, and Anthony Paul (2001). Cost-Effective 

Reduction of NOx Emissions from Electricity Generation. Discussion Paper 00-55REV. Resources for the 

Future, Washington, DC.
242

specifically, may also be necessary to ensure enforcement. (Earthjustice, No. 195 at p. 5;

Earthjustice No. 146 at p. 44) However, Progress Energy commented that rectifier and 

testing transformers are already very specialized and usually more expensive than 

distribution transformers; therefore, there is a very low chance of a utility attempting to 

replace a distribution transformer with one of these transformers. (PE, No. 192 at p. 4) 

APPA concurred, noting that they were unaware of rectifier or testing transformers being 

used as a loophole. (APPA, No. 191 at p. 6) Similarly, HVOLT pointed out that the 

physical differences between rectifier and distribution transformers would be fairly 

obvious without a nameplate marking. Furthermore, they feel that adding the word 

“rectifier” to the nameplate would only add more congestion. (HVOLT, No. 146 at p. 46)

In response to the NOPR, many stakeholders expressed their support for clearly 

identifying transformers excluded from DOE standards through a standardized labeling 

system. ABB recommended that the text “DOE Excluded: transformer type” be included 

on the nameplate for all of the excluded type transformers, and suggested that this 

labeling requirement be added to CFR part 429. (ABB, No. 158 at p. 5) ABB also noted 

that they agree with the proposal to not set standards for step-up transformers, and that all 

step-up transformers be identified on the nameplate with uniform language. (ABB, No. 

158 at p. 6) NEMA agreed with ABB, stating that “labeling should be applied in a 

consistent manner for all designated non-regulated distribution transformers” and 

suggested the following language be used: “This _____Transformer is NOT intended for 

use as a Distribution Transformer per 10 CFR 431.192” (NEMA, No. 170 at p. 7) Prolec-
243

GE and PEMCO expressed similar ideas, both commenting that all excluded transformers 

should be identified by type and indicate that they are excluded from standards.

(PEMCO, No. 183 at p. 2; Prolec-GE, No. 177 at p. 7) Schneider concurred, stating “all 

non-regulated transformers should require labeling – not just rectifier and testing 

transformers.” (Schneider, No. 180 at p.3) 

Prolec-GE encouraged DOE to establish labeling requirements or guidelines for 

covered products for use in the United States. They believed that, at present, without 

specifications for labeling products, those charged with certification, compliance and 

enforcement would have difficulty identifying which products were to meet which 

standards a difficult time with inconsistent labeling. (Prolec-GE, No. 177 at pp. 16−17) 

Schneider Electric also expressed that regulated products should have labeling rules with 

the following language “DOE 10 CFR PART 431 COMPLIANT.” Schneider would also 

like DOE certification regulations (10 CFR 429) expanded to include non-regulated 

products. (Schneider, No. 180 at p. 3) 

GE commented that refurbished units should be labeled as such and have the 

original manufacturer’s nameplate removed. (GE, No. 146 at p. 114) 

DOE had initially considered amending the definitions of “rectifier transformer” 

and “testing transformer” to include a labeling requirement. Commenters, however, have 

pointed out that a number of transformer types would benefit from a clear set of labeling 
244

requirements, which could aid manufacturers, consumers, and DOE itself in determining 

whether a given sample is covered or determined by the manufacturer as meeting the 

standards. Given the breadth of the issue, DOE makes no changes to labeling 

requirements in today’s rule, but may address the matter of distribution transformer 

labeling in a future rulemaking. DOE appreciates the comments and feedback regarding 

labeling supplied by the stakeholders. Issues regarding labeling, compliance, and 

enforcement may, however, be considered in a different proceeding.

O.

Comments DOE received in response to the NOPR analysis on the soundness and 

validity of the methodologies and data DOE used are discussed in previous parts of 

section IV. Other stakeholder comments in response to the NOPR addressed specific 

issues associated with amended standards for transformers. DOE addresses these other 

comments below.

Discussion of Other Comments 

1. Supplementary Trial Standard Levels 

DOE created TSLs that each consist of specific efficiency levels for a set of 

design lines. For the NOPR, DOE examined seven TSLs for liquid-immersed distribution 

transformers, six TSLs for low-voltage dry-type distribution transformers, and five TSLs 

for medium-voltage dry-type distribution transformers. 
245

For liquid-immersed distribution transformers, joint comments submitted by 

ASAP, ACEEE, NRDC and NPCC recommended that DOE modify TSL 4 to represent 

their collective final position from the Negotiated Rulemaking, which advocated 

including EL 2 for all liquid-immersed distribution transformer design lines. (In the 

NOPR, DOE misstated and analyzed the Advocates collective final position from the 

Negotiated Rulemaking as EL3 for all liquid-immersed distribution transformer design 

lines.). They also recommended that DOE examine a TSL 3.5 level, which would 

correspond to EL 1.5 across the board. (ASAP, ACEEE, NRDC, NPCC, No. 186 at p. 9)

In response to these comments DOE considered four new TSLs, labeled A, B, C

and D, to explore possible energy savings below EL 2. TSL C, consisting of EL 2 for all 

liquid-immersed distribution transformer design lines, correctly represents the collective 

final position of ASAP, ACEEE, NRDC, and NPCC in the negotiations. DOE presented 

these new TSLs to stakeholders at a public meeting on June 20, 2012.

Several parties stated that these new TSLs, while being technologically feasible,

would present issues due to increased transformer size and weight. NRECA, Howard 

Industries, and NEMA stated that this issue would increase the frequency of pole 

replacement by utilities. (NRECA, No. 228 at p. 2; HI, No.218 at p.1; NEMA, No. 225 at 

p. 6) Central Maloney commented that their designs at the new TSLs exceeded customer 

weight specifications for their single-phase, pole-mounted distribution transformers at 

various kVA capacities. (CM, No.224 at p.3) Others stated that the economic benefits of 
246

TSLs B through D could only be realized with core steels other than M3 (NEMA, No. 

225 at pp. 4, 5; ATI No. 218 at p. 1), which could transfer significant market power to 

producers of SA1 core steel (AK, No.230 at p. 4) and lead to unintended anti-competitive 

results. (ATI, No. 218 at p. 1; AK, No. 230 at p. 5) 

DOE concluded that all of these new TSLs would result in similar burdens as the 

TSLs 2, and 3 that were analyzed in the NOPR. As discussed further in section 5.C.1 of 

this final rule, all of these TSLs would face issues regarding the type of steel used in 

liquid-immersed transformers. DOE is concerned that the current supplier of amorphous 

steel, together with others that might enter the market, would not be able to increase 

production of amorphous steel rapidly enough to supply the amounts that might be 

needed by transformer manufacturers before 2015. Although the industry can 

manufacture liquid-immersed distribution transformers at TSL 3 from M3 or lower grade 

steels, the positive LCC and national impacts results are based on lowest first-cost 

designs, which include amorphous steel for all the design lines analyzed. If manufacturers 

were to meet standards at TSL 3 using M3 or lower grade steels, DOE’s analysis shows 

that the LCC impacts are negative. Given that the recommended TSLs face similar issues 

as TSL 3, DOE did not incorporate them into the final rule.

2. Efficiency Levels

ASAP, ACEEE, NRDC and NPCC stated that DOE has not evaluated the 

potential impacts of the proposed standards for liquid-immersed distribution transformers 
247

since the proposed standard levels are not the same as the levels in TSL 1 for equipment 

class 1. They said that DOE’s final standard must be based on analysis and results for the 

actual efficiency levels established by the final rule. (ASAP, ACEEE, NRDC, NPCC, No. 

186 at p. 9) Similarly, NEEP stated that the proposed TSL 1 for liquid-immersed 

distribution transformers did not have all the corresponding ELs for the various design 

lines. It noted that DOE proposed 98.95 percent for design line 2, which does not 

correspond to any EL. (NEEP, No. 193 at p. 2) 

In response to these comments, for this final rule, DOE analyzed the actual 

efficiency ratings proposed in the NOPR for equipment class 1 (single-phase liquidimmersed transformers) at TSL 1. These efficiencies are 99.11 percent for design line 1, 

98.95 percent for design line 2, and 99.49 percent for design line 3. These efficiencies 

correspond to EL 0.4 for design line 1, EL 0.5 for design line 2, and EL 1.1 for design 

line 3.

The TSLs that DOE used for the final rule are presented in section V.A of this 

notice. DOE notes that, for the final rule, it has slightly modified the definition of TSL 2 

for low-voltage dry-type distribution transformers from the NOPR definition. Where 

previously DL 6 had been at EL 3 in TSL 2, in today’s rule DL 6 is held at the baseline 

because DOE did not find positive economic benefits to the consumer above that level. 

Small, single-phase transformers tend to be lightly-loaded and have a more difficult time 
248

than their larger, three-phase counterparts recovering increases in first cost. DOE believes 

this change provides increased customer benefits with TSL 2.

3. Impact of Standards on Transformer Refurbishment 

A number of parties expressed concern that amended standards on transformers

would induce use of rebuilt or refurbished distribution transformers rather than the more 

expensive new transformers. (HI, No.151 at pp. 9, 12; Cooper, No. 165 at p. 5; ProlecGE, No. 177 at p. 14; ComEd, No. 184 at p. 13; Westar, No. 169 at p. 3) Several parties 

stated that the higher the initial cost increase due to energy efficiency standards, the 

higher the likelihood that utilities will use more recycled equipment. (EEI, No. 185 at p. 

17; APPA, No. 191 at p. 12; Progress Energy, No. 192 at p. 9) BG&E stated that if new 

transformer requirements significantly increase costs, it may consider purchasing 

refurbished designs to address the size and weight problems of transformers meeting the 

standard. (BG&E, No. 182 at p. 9) Fort Collins Utilities commented that it would be 

purchasing fewer new transformers and re-winding more of its existing transformer units. 

(CFCU, No. 190 at p. 3)

Some parties specifically stated that setting standards for liquid-immersed 

distribution transformers greater than TSL 1 would increase the use of less-efficient, 

refurbished transformers, and this would reduce the energy savings from such standards.

(NEMA, No. 170 at p. 3; USW, No. 188 at pp. 4, 18−19) AEC and NRECA stated that if 

DOE raises standards above the levels proposed in the NOPR, it is likely that costs will 
249

increase dramatically, increasing the likelihood that more existing transformers will be 

recycled via refurbishment, rewinding, or rebuilding. (AEC, No. 163 at p. 3; NRECA, 

No. 172 at p. 3) 

Several parties stated that rebuilt or refurbished transformers would be less 

efficient than new transformers and, therefore, the energy saving goals of standards 

would be undermined. (HI, No. 151 at pp. 9, 12; Cooper, No. 165 at p. 5; Prolec-GE, No. 

177 at p. 14) AEC and NRECA stated that, in some cases, the efficiency of transformers 

may actually increase as a result of refurbishment or rewinding, but the efficiency of the 

refurbished transformer will most likely not meet the proposed efficiency levels. (AEC, 

No. 163 at p. 3; NRECA, No. 172 at p. 3) HI requested that DOE seek authority over the 

refurbished/repair industry to minimize use of lower-efficiency transformers. (HI, No. 

151 at p. 11)

DOE acknowledges that a significant increase in the cost of new transformers 

could encourage growth in the use of refurbished transformers by some utilities, and that 

refurbished transformers likely would be less efficient than new transformers meeting 

today’s standards. Although DOE was not able to explicitly model the likely extent of 

refurbishing at each considered TSL, it did include in its shipments analysis a price 

elasticity parameter that captures the response of the market to higher costs in a general 

way (see chapter 9 of the final rule TSD). Furthermore, DOE believes that the costs of 

new transformers meeting today’s standards, which are approximately 3.0 percent (design 
250

line 2) and 13.1 percent (design line 3) higher than today’s typical single-phase liquidimmersed distribution transformers, and approximately 6.9 percent (design line 4) and 

12.6 percent (design line 5) higher than today’s typical three-phase liquid-immersed 

transformers, would not be so high as to induce a significant level of refurbishing instead 

of replacement.

Earthjustice asserted that “the statute leaves room for DOE to regulate the 

efficiency of rebuilt transformers” and that “it is reasonable for DOE to determine that 

rewound transformers are ‘new covered products’ subject to energy conservation

standards if the title of the rewound transformer is then transferred to an end-user.”

(Earthjustice No.195 at p. 6) Other commenters reached opposite conclusions regarding 

whether DOE has the authority to regulate refurbished or rewound transformers. AEC 

agreed with statements made by DOE’s Office of the General Counsel during 

negotiations that existing and recycled transformers are not “covered” equipment and 

would not have to meet the proposed energy efficiency standards for new products that 

are “covered.” (AEC No. 163 at p. 3)

DOE has analyzed this issue for many years. For instance, in its August 4, 2006,

NOPR, DOE summarized its legal authority to regulate new, used and refurbished 

transformers and sought public comment on the issue. 71 FR 44356, 44366-67. In that 

notice, DOE noted that for the entire history of its appliance and commercial equipment 

energy conservation standards program, DOE has not sought to regulate used units that 
251

have been reconditioned or rebuilt, or that have undergone major repairs. DOE stated that 

given there is no legislative history to ascertain Congressional intent and the potential 

ambiguity of the statutory language, this conclusion was based on detailed analysis and 

interpretation of numerous statutory provisions in the EPCA, namely 42 U.S.C. 6302, 

6316(a) and 6317(a)(1). Importantly, DOE analyzed the meaning of a “newly covered 

product” and whether a refurbished transformer could nonetheless fall under this 

definition. (42 USC sec. 6302) The most reasonable interpretation of the statutory 

definition is that Congress intended that this provision apply to newly manufactured 

products and equipment the title of which has not passed for the first time to a consumer 

of the product. This conclusion was reiterated in the October 12, 2007 final rule. (72 FR 

58203) And this remains DOE’s position today. The issue was raised during the 

negotiations, and again, DOE emphasized that refurbished transformers were not 

“covered” equipment as defined by EPCA. (DOE No. 95 at p. 95) Despite DOE’s lack of 

legal authority, DOE has continued to evaluate the degree to which utilities may purchase 

a refurbished product rather than a new transformer, as discussed above.

4. Alternative Means of Saving Energy

Rockwood Electric commented that a more effective means of saving energy than 

requiring energy conservation in the distribution transformers themselves would be to 

require that power distribution occur at higher voltages and thereby reduce resistive 

losses. (Rockwood Electric, No. 167 at p. 1) CFCU advocated that DOE seek more costeffective means of finding efficiency in electric distribution systems than by increasing 
252

efficiency standards for distribution transformers. (CFCU, No. 190 at p. 2) DOE has no 

plans to address distribution voltage ratings in the present rulemaking, and does not 

consider the possibility to fall within its scope of coverage.

5. Alternative Rulemaking Procedures

Prior to publication of the NOPR, DOE held a series of negotiating sessions to 

discuss standards for all three types of distribution transformer under the Negotiated 

Rulemaking Act. The negotiating parties succeeded in arriving at a consensus standard 

for medium-voltage dry-type transformers, which is adopted in today’s rule. Such 

adoption was supported by a broad spectrum of parties as discussed previously 

(Advocates, 4/10/12 comment at p. 2) Several parties commented on the negotiated 

rulemaking process.

Despite praising the consensus agreement on the medium-voltage-dry-type units, 

the Advocates commented that overall the process “produced virtually no benefits.” 

(Advocates, No. 186 at p. 14) In contrast, NEMA commented that the process was 

extremely valuable and resulted in a better analysis. (NEMA, No. 170 at p. 2) Eaton 

remarked that the negotiation process improved the resulting proposal for LVDT 

distribution transformers and was a more efficient vehicle for considering stakeholder 

input. (Eaton, No. 157 at p. 2) Progress Energy recommended that the spirit of the 

negotiating committee be retained indefinitely through formation of a task force of 

stakeholders that could advise DOE in the future. (PE, No. 192 at p. 2)
253

DOE appreciates feedback on the negotiation process and will consider its use in 

appropriate future rulemakings. Currently, DOE has no plans to form a task force on 

distribution transformer standards.

6. Proposed Standards — Weighting of Benefits vs. Burdens

DOE received many comments that supported or criticized the Department’s 

weighing of the benefits and burdens in its selection of the proposed levels, particularly 

for liquid-immersed and low-voltage dry type transformers. The first section below 

presents general comments on all of the transformer superclasses, and the following 

sections present comments specifically on each of the superclasses. The final section 

presents a response to the comments by DOE.

a. General Comments

Many stakeholders expressed their support for the standards proposed by DOE.

(AK, No. 146 at p. 143; ATI, No. 146 at p. 7; ATI, No. 181 at p. 1-2; CDA, No. 153 at p. 

1; ComEd, No. 184 at p. 1; Cooper, No. 165 at p. 1; DE, No. 179 at p. 1; JEC, No. 173 at

p. 2; KAEC, No. 126 at p. 1-2; KAEC, No. 149 at p. 7; NEMA, No. 146 at p. 146; 

NRECA, No. 146 at p. 158; PECO, No. 196 at p. 1; UAW, No. 194 at p. 1; USW, No. 

148 at p. 1; Adams Electrical Coop, No. 13) Others pointed out that these levels are wellbalanced, allowing cold rolled grain-oriented steel (CRGO)/amorphous competition, 

energy savings, and benefits to consumers without unduly harming manufacturers. (ATI, 

No. 146 at p. 9; Cooper, No. 143 at p. 1; Cooper, No. 146 at p. 13-14; (FedPac, No. 132 
254

at p. 1 and pp. 3-4; HVOLT, No. 144 at p. 1 and pp. 10-11; NEMA, No. 146 at p. 12-13; 

Prolec-GE, No. 146 at p. 14-15; Schneider, No. 180 at p. 1; USW, No. 148 at p. 1 ) Other 

parties agreed, noting that a higher standard would cause a transition to amorphous steel, 

and urged DOE not to move to higher standard levels, as the proposed standards are the 

highest justified levels. (USW, No. 148 at p. 2; Weststar, No. 169 at p. 1 and p. 4; Adams 

Electrical Coop, No. 163 at p. 1; APPA, No. 191 at p. 2; Steelmakers, No. 188 at p. 2; 

PECO, No. 196 at p. 1; NEMA, No. 170 at p. 2; MTEMC, No. 210 at p. 1; EEI, No. 185 

at p. 2; BG&E, No. 182 at p. 2; BSE, No. 152 at p. 1) ATI agreed, noting that the NOPR 

efficiency levels are the proper levels to ensure M3 and amorphous metals are cost 

competitive with each other. (ATI No. 181 at p. 2) KAEC commented that increased 

standards could pose a threat to small manufacturers. (KAEC, No. 126 at p. 2) BSE

commented that an increase in standards would increase the capital expense of the 

transformer, which will in turn have a negative impact on rates that consumers are 

charged for their electricity with very minimal gains in efficiency. (BSE, No. 152 at p. 1) 

NEMA noted that there are no utility problems at the current proposed levels. (NEMA, 

No. 170 at p. 13) Steelmakers commented that DOE’s proposal for liquid-immersed 

transformers correctly states that the standards it is proposing will not lessen the utility or 

performance of distribution transformers, while noting that increasing standards would 

negatively impact utility. (Steelmakers, No. 188 at pp. 15-16) AEC and NRECA both 

noted that under any revised analysis, DOE should not consider increasing the proposed 

efficiency levels, as the evidence has shown that there would be many negative impacts 

on domestic steelmakers, domestic transformer manufacturers, electric utilities, and end-
255

use customers. (AEC, No. 163 at p. 1; NRECA, No. 172 at pp. 2, 6) NRECA supported 

the proposed efficiency levels in the NOPR as they minimize the concerns associated 

with size and weight issues. (NRECA, No. 172 at p. 8) APPA members recommend that 

the proposed efficiency levels should be viewed as the maximum achievable levels.

(APPA, No. 191 at p. 2)

Other parties believe that DOE should choose more stringent efficiency levels. 

ASAP, ACEEE, NRDC and NPCC stated that a more thorough consideration of the 

record and completion of critical missing or incomplete analyses will lead DOE to the 

conclusion that higher standards are justified for both low-voltage dry-type and mediumvoltage liquid-immersed transformers. They stated that higher standards than those 

proposed would yield shorter paybacks for consumers and much larger environmental 

and energy system benefits. The Advocates noted that other major countries, including 

China and India, make use of amorphous core transformers to a greater degree than does 

the United States. (Advocates, No. 186 at pp. 2-3) Metglas requested that DOE revise the 

proposed regulation because it deprives consumers of billions of dollars in potential 

energy savings and millions of tons of harmful pollution reductions by favoring older, 

less efficient transformer designs over innovative U.S.-made energy-efficient 

technologies. (Metglas, No. 102 at p. 3)

EMS Consulting commented that DOE’s rationale for setting lower standards to 

minimize impact on the distribution transformer industry will cost the country significant 
256

potential energy savings and recommended higher standards for both liquid-immersed 

and low-voltage dry-type transformers. Based on EMS’ calculations, a standard set 

between EL 1.5 and EL 2 for liquid-immersed transformers would allow the nation to 

gain additional energy savings while increasing demand for grain-oriented steels and 

creating a new market for amorphous steel. The market for grain-oriented steels will also 

expand as a result of higher standards for low-voltage dry-type transformers, which may 

be able to achieve EL 3 with M4/M5 material and butt-lap cores or EL 4 with step-lap 

mitering, and the investment required by industry to meet EL 4 is well-justified 

considering benefits to end users. (EMS, No. 178 at p. 8)

Some stakeholders commented that the proposed standards were too high and 

were not economically justified. (WE, No. 168 at p. 1,3; Sioux Valley Energy, No. 159 at 

p. 1; Polk-Burnett Electric Cooperative, No. 175 at p. 1; PJE, No. 202 at p. 1; MEC, No. 

161 at p. 1; East Miss. EPA, No. 166 at p. 1; Central Electric Power Coop, No. 176 at p. 

1) Specifically, stakeholders noted that the proposed standards would cause hardships to 

electricity consumers. (KEC, No. 164 at p. 1; BEC, No. 204 at p. 1; BEC, No. 205 at p. 1; 

CHELCO, No. 203 at p. 1) East Central Energy agreed, noting that the proposed 

standards achieve little to no benefit and would cost extra for manufacturers. (East 

Central Energy, No. 160 at p. 1) BEC pointed out that the cost savings were overstated in 

the NOPR. (BEC, No. 205 at p. 1) Westar Energy commented that they were hesitant to 

support even an increase to EL1 for liquid-immersed units. (Westar, No. 169 at p. 1) 
257

CCED noted that the standards proposed in the NOPR were without merit and the 

existing 2010 standards should be maintained instead. (CCED, No. 174 at p. 3) 

Some stakeholders expressed opinions about how steel availability should factor 

into the standards that DOE chooses. Progress Energy urged DOE not to set a standard 

that would result in the use of specific steels that have questionable supply availability, 

noting that M3 and M4 grades of core steel should be required for 85 percent or more of 

any required efficiency level. (PE, No. 192 at p. 7-8) Earthjustice felt that DOE failed to 

rationally analyze the potential impacts associated with steel production capacity 

constraints while deciding on standard levels. (Earthjustice, No. 195 at p. 1) The 

Advocates noted that in the long term, amorphous steel is likely to predominate in the 

transformer market due to higher efficiency. They commented that countries such as 

China and India are fostering a transition to highly efficient transformers and more 

amorphous steel is used in these countries than in the United States. (Advocates, No. 186 

at pp. 13-14)

b. Standards on Liquid-Immersed Distribution Transformers

The Advocates felt that DOE emphasized the worst-case scenario for 

manufacturer impacts when rejecting TSL 2 and TSL 3 for liquid-immersed transformers. 

(Advocates, No. 186 at p. 12) They noted that at TSL 4 for liquid-immersed transformers, 

potential costs to manufacturers are still far less than potential benefits to consumers. 

(Advocates, No. 186 at p. 11) The Advocates stated that DOE estimates that TSL 4 could 
258

result in a potential loss of industry value of 12 percent under the "maintenance of 

profits" scenario, a potential impact well within the norm of DOE estimates for other 

standards rulemakings. (Advocates, No. 186 at p. 3) The Advocates stated that a standard 

in the range of TSL 3.5 to TSL 4 would promote robust competition between silicon steel 

and amorphous metal, maximizing benefits for consumers and producing much larger 

energy savings for the Nation. They stated that TSL 4 or 3.5 can be met even if 

amorphous metal supplies do not increase. They added that if DOE feels that more time 

would provide greater confidence that supply of amorphous steel could increase to help

meet market needs triggered by a TSL 3.5 or TSL 4 standard, they would not object to 

moving the effective date of today’s rule a year or two further into the future. (Advocates, 

No. 186 at pp. 9-11)

At the NOPR public meeting, ASAP commented that the standard levels proposed 

for liquid-immersed transformers are far below the point that would maximize consumer 

benefits because DOE put an inordinate amount of weight on manufacturer impacts to the 

detriment of consumer benefits. (ASAP, No. 146 at p. 27) They also commented that 

DOE placed significant weight on steel manufacturer impacts but did not conduct a more 

detailed analysis on those impacts, in particular one which includes employment at each 

TSL for steel manufacturers. (ASAP, No. 146 at p. 143) ASAP recommended that DOE 

select EL 2 for liquid-immersed units. (ASAP, No. 146 at p. 18)
259

Berman Economics stated that DOE’s rationale for choosing TSL 1 for liquidimmersed transformers, that a higher standard would require an unacceptable increase in 

cost to industry, suggests that DOE prefers that consumers pay more money than to 

require additional investment on the part of manufacturers. (Berman Economics, No. 150 

at p. 2-3) Berman Economics also argues that DOE’s rejection of EL 2 for liquidimmersed transformers is an indication that DOE is focused on avoiding competition for 

silicon steel even at the cost of energy and consumer savings and environmental 

preservation. (Berman Economics, No. 150 at p. 4) EMS recommended a level between 

EL 1.5 and EL 2.0. (EMS, No. 178 at p. 7)

Several stakeholders felt that DOE relied on impacts on small manufacturers too 

heavily, and noted that small manufacturers can build up to TSL 3. (Earthjustice, No. 195 

at p. 2; Advocates, No. 186 at p. 11; NEEP, No. 193 at p. 1; ASAP, No. 146 at pp. 26-27; 

CA IOUs, No. 189 at p. 3) 

Some stakeholders stated that setting higher standards may result in reduced 

benefits to consumers. EEI stated that utilities are concerned that if standards are set so 

high that transformer manufacturers need to use steels with possible supply constraints, 

there may be negative impacts on the electrical grid, which would have a negative impact 

on consumers. (EEI, No. 185 at p. 13) 

EEI stated that several members expressed concern that the more efficient 

transformers will be larger in size (height, width, and depth), which will have an impact 
260

for all retrofit situations, and they would have much larger weights, which would increase 

costs in terms of installation and pole structural integrity for retrofits of existing polemounted transformers. (EEI, No. 185 at p. 11) A number of electric utilities made similar 

comments. (BG&E, No. 182 at p. 6; ComEd, No. 184 at p. 11; EMEPA, No. 166 at p. 1; 

PECO, No. 196 at p. 1; Pepco, No. 145 at p. 3; WE, No. 168 at p. 3; Westar, No. 169 at p. 

2) Howard Industries also stated that the increased size and weight will sometimes be a 

constraint and result in increased costs. (HI, No. 151 at p. 7)

A number of parties expressed specific concerns about size and space constraints 

for network/vault transformers. (BG&E, No. 182 at p. 6; ComEd, No. 184 at p. 11;

Pepco, No. 145 at pp. 2-3; PE, No. 192 at p. 8; Prolec-GE, No. 177 at p. 12) These 

concerns lead several parties to recommend a separate equipment class for network/vault 

transformers. (DOE addresses this issue in section IV.A.2.) EEI and several electric 

utilities stated that efficiency standards for network/vault transformers should be the 

same as the efficiency levels that have been in effect since January 1, 2010. (EEI, No. 

185 at p. 3; Pepco, No. 145 at p. 2; PE, No. 192 at p. 8; Prolec-GE, No. 177 at p. 12) 

Northern Wasco supported the DOE proposal for liquid-immersed units and 

believed anything beyond would not be cost-effective. (NWC, No. 147 at p. 1) UAW 

agreed, noting that any level above TSL 1 would not be economically justified. (UAW, 

No. 194 at p. 2) ATI stated that efficiency levels in excess of the NOPR proposal would 

create a non-competitive market for new medium-voltage liquid-type designs that would 
261

eliminate projected LCC savings. (ATI, No. 54 at p. 2) Steelmakers commented that 

promulgating energy conservation standards greater than TSL 1 for liquid-immersed 

transformers would transfer significant competitive power to the sole maker of 

amorphous metal. (Steelmakers, No. 188 at pp. 9-10)

After the supplementary analysis was presented, which included the new TSLs 

described in section IV.O.1, a handful of stakeholders recommended that DOE adopt one 

of the TSLs presented in the supplementary analysis. The Advocates recommended that 

DOE adopt TSL C, following the supplementary rulemaking process, to increase energy 

savings relative to the levels proposed in the NOPR and increase life cycle cost savings. 

(Advocates, No. 235 at p. 2) They added that if DOE wants to foster a more gradual 

market growth for amorphous metal, TSL D would achieve such an outcome by lowering 

the standard for pole type transformers, but would still approach the national savings of 

TSL C. (Advocates, No. 235 at p. 1) Berman Economics agreed that TSL C or D should 

be selected as they provide the best balance. (Berman Economics, No. 221 at p. 1) 

NEMA stated that TSL A was the only level presented in the supplementary rulemaking 

that met the three principles that they applied during the rulemaking process to select 

levels, but suggested that the level be moved to EL 0 for design line 2. (NEMA, No. 225 

at p. 4) Prolec-GE expressed their support for TSL A as well, believing that these 

efficiency levels provide additional energy savings while preserving manufacturers’ 

ability to use both silicon and amorphous steel to meet the demand of the market. In the 

absence of TSL A, they recommended TSL 2 as the maximum possible alternative, which 
262

they noted would result in higher cost and heavier and larger pole units. (Prolec-GE, No. 

238 at p. 3) 

c. Standards on Low-Voltage Dry-Type Distribution Transformers

The Advocates stated that for LVDT transformers, DOE rejected TSL 3 despite 

its own economic analysis showing greater net consumer savings, and mean paybacks of 

five to twelve years, well within a transformer’s typical 30-year lifespan. (Advocates, No. 

186 at p. 3) They stated that a more thorough investigation of impacts on domestic small 

manufacturers and a better balancing of public benefits and manufacturer impacts will 

lead DOE to adopt TSL 3, the maximum level which yields net present value benefits for 

consumers and can incontrovertibly be achieved using silicon steel cores. They said that 

if DOE rejects TSL 3, the agency should at least adopt TSL 2, which represents the 

NEMA Premium® level (30 percent reduction in losses) for all transformers. They added 

that DOE overestimated the savings from the proposed standards (i.e., TSL 1).

(Advocates, No. 186 at pp. 3-4) However, they recommend that if TSL 3 is not adopted, 

TSL 2 should be chosen, as a number of manufacturers are already committed to 

manufacturing at NEMA Premium®. (Advocates, No. 186 at p. 7-8) ASAP commented 

that DOE should select EL 4 for DL7 and DL8. (ASAP, No. 146 at p. 19) EMS stated 

that low-voltage dry-type standards should be set at TSL 2 or TSL 3. (EMS, No. 178 at p. 

7)
263

CA IOUs stated that TSL 3 is the highest achievable efficiency level at which 

low-voltage dry-type distribution transformers can be constructed using grain-oriented 

steel, and they recommend that DOE consider adopting standards at this level. They 

noted that while DOE expresses concern that small manufacturers are disproportionately 

impacted by standards for low-voltage dry-type transformers, DOE’s analysis shows that 

there are actually very few small manufacturers in this market, and that those small 

manufacturers that do exist in the market primarily focus on design lines that are 

exempted from coverage. (CA IOUs, No. 189 at pp. 2-3)

Schneider Electric and FedPac both expressed support for the low-voltage dry 

type proposed standards in the NOPR. (FedPac, No. 132 at p. 2; Schneider, No. 180 at p. 

1) FedPac noted that the proposed standards may be slightly high for 3-phase above 150 

kVA and may put small manufacturers at risk due to potentially large capital investments 

necessary to remain in business at these levels. (FedPac, No. 132 at pp. 2-3)

Some stakeholders demonstrated support for NEMA Premium® levels for lowvoltage dry-type transformers. Eaton noted that NEMA Premium® represents an 

opportunity to produce efficiency gains and encourage new technologies and 

recommended adopting NEMA Premium® for DL7 and DL8. (Eaton, No. 157 at p. 2) 

NEEP pointed out that industry parties suggested higher efficiency on the record during 

negotiations, including NEMA Premium®. (NEEP, No. 193 at p. 5) 
264

NEMA recommended that DOE select ELs 0, 2 and 2 for DLs 6, 7 and 8, 

respectively. NEMA noted that NEMA Premium® was still in development. (NEMA, No. 

170 at p. 5) NEMA expressed concern that high efficiency standards for LVDT 

transformers would hurt small U.S. manufacturers. (NEMA, No. 170 at p. 5)

d. Standards on Medium-Voltage Dry-Type Distribution Transformers

The Advocates expressed support for the proposed standards for medium-voltage 

dry-type (MVDT) transformers. (The Advocates, No. 186 at p. 2) FedPac noted that the 

DOE was correct in its NOPR decision to not increase standards for single-phase 

MVDTs. (FedPac, No. 132 at p. 2)

NEMA made specific recommendations for medium-voltage, dry type 

transformers. First, it recommended for DL13 that the efficiency level allow for 10

percent more loss that DL12, as these are high BIL transformers. Second, it noted that for 

single-phase transformers the single-phase efficiency should be less than the three-phase 

efficiency by a maximum of 30 percent higher losses and should not exceed 2010 

standard. (NEMA, No. 170 at p. 4)

NEMA stated that for medium-voltage dry-type transformers used in high-rise 

buildings, it recommended different treatment because of size and weight limitations 

(elevator capacity) in existing installations. It stated that manufacturers are confident that 

the sizes and weights of the high-rise MVDT transformer in compliance with the current 
265

standards can continue to be used without significant problems, but going to any higher 

efficiency levels for high-rise MVDT transformers will adversely impact the continued 

installation and replacement of this type of transformer. (NEMA, No. 170 at p. 4) BG&E 

and ComEd also stated that designs that increase the size and weight of dry-type 

transformers could prohibit replacement of existing units used in high-rise buildings.

(BG&E, No. 182 at p. 6; ComEd, No. 184 at p. 11)

e. Response to Comments on Standards Proposed in Notice of Proposed Rulemaking

DOE acknowledges the comments described above and has taken them into 

account in developing today’s final rule. As stated previously, DOE seeks to set the 

highest energy conservation standards that are technologically feasible, economically 

justified, and that will result in significant energy savings. In section V.C, DOE explains 

why it has adopted the standards established by this final rule, and it addresses the issues 

raised in the preceding comments. DOE agrees with many of the concerns associated 

with higher efficiency transformers, and these considerations contributed to the selection 

of today’s standards. In particular, DOE believes that the increase in medium-voltage 

dry-type distribution transformer size and weight for the efficiency levels in today's final 

rule, which were unanimously agreed to by the negotiation committee, will not adversely 

impact the continued installation and replacement of these transformers.
266

V. Analytical Results and Conclusions

A.

Table V.1

Trial Standard Levels 

through Table V.3 present the TSLs analyzed and the corresponding 

efficiency level for the representative unit in each transformer design line. The mapping 

of TSLs to corresponding efficiency levels for each design line is described in detail in 

chapter 10, section 10.2.2.3 of the final rule TSD. The baseline in the tables is equal to 

the current energy conservation standards. 

For liquid-immersed distribution transformers, the efficiency levels in each TSL 

can be characterized as follows: TSL 1 represents an increase in efficiency where a 

diversity of electrical steels are cost-competitive and economically feasible for all design 

lines; TSL 2 represents EL1 for all design lines; TSL 3 represents the maximum 

efficiency level achievable with M3 core steel; TSL 4 represents the maximum NPV with 

7 percent discounting; TSL 5 represents EL 3 for all design lines; TSL 6 represents the 

maximum source energy savings with positive NPV with 7 percent discounting; and TSL 

7 represents the maximum technologically feasible level (max tech). 

For low-voltage dry-type distribution transformers, the efficiency levels in each 

TSL can be characterized as follows: TSL 1 represents the maximum efficiency level 

achievable with M6 core steel; TSL 2 represents EL 3 for design line 7, EL 2 for design 

line 8 and no efficiency increase for design line 6; TSL 3 represents the maximum EL 

achievable using butt-lap miter core manufacturing for single-phase distribution 
267

transformers, and full miter core manufacturing for three-phase distribution transformers; 

TSL 4 represents the maximum NPV with 7 percent discounting; TSL 5 represents the 

maximum source energy savings with positive NPV with 7 percent discounting; and TSL 

6 represents the maximum technologically feasible level (max tech).

For medium-voltage dry-type distribution transformers based on the 

subcommittee consensus detailed in section II.B.2, above, the efficiency levels in each 

TSL can be characterized as follows: TSL 1 represents EL1 for all design lines; TSL 2 

represents an increase in efficiency where a diversity of electrical steels are costcompetitive and economically feasible for all design lines; TSL 3 represents the 

maximum NPV with 7 percent discounting; TSL 4 represents the maximum source 

energy savings with positive NPV with 7 percent discounting; and TSL 5 represents the 

maximum technologically feasible level (max tech).

Table V.1 Efficiency Values of the Trial Standard Levels for Liquid-Immersed 

Transformers by Design Line

Design 

Line Baseline

TSL

1 2 3 4 5 6 7

Percent

1 99.08 99.11 99.16 99.16 99.22 99.25 99.31 99.50

2 98.91 98.95 99.00 99.00 99.07 99.11 99.18 99.41

3 99.42 99.49 99.48 99.51 99.57 99.54 99.61 99.73

4 99.08 99.16 99.16 99.16 99.22 99.25 99.31 99.60

5 99.42 99.48 99.48 99.51 99.57 99.54 99.61 99.69

Table V.2. Efficiency Values of the Trial Standard Levels for Low-Voltage DryType Transformers by Design Line

Design Baseline TSL
268

Line 1 2 3 4 5 6

Percent

6 98.00 98.00 98.00 98.80 99.17 99.17 99.44

7 98.00 98.47 98.60 98.80 99.17 99.17 99.44

8 98.60 99.02 99.02 99.25 99.44 99.58 99.58

Table V.3. Efficiency Values of the Trial Standard Levels for Medium-Voltage DryType Transformers by Design Line

Design 

Line Baseline

TSL

1 2 3 4 5

Percent

9 98.82 98.93 98.93 99.04 99.04 99.55

10 99.22 99.29 99.37 99.37 99.37 99.63

11 98.67 98.81 98.81 99.13 99.13 99.50

12 99.12 99.21 99.30 99.46 99.46 99.63

13A 98.63 98.69 98.69 99.04 99.84 99.45

13B 99.15 99.19 99.28 99.28 99.28 99.52

B.

1. Economic Impacts on Customers

Economic Justification and Energy Savings

a. Life-Cycle Cost and Payback Period

To evaluate the net economic impact of standards on transformer customers, DOE 

conducted LCC and PBP analyses for each TSL. In general, higher-efficiency equipment 

would affect customers in two ways: (1) annual operating expense would decrease, and 

(2) purchase price would increase. Section IV.F.2 of this notice discusses the inputs 

DOE used for calculating the LCC and PBP. The LCC and PBP results are calculated 

from transformer cost and efficiency data that are modeled in the engineering analysis 

(section IV.C). During the negotiated rulemaking, DOE presented separate transformer 
269

cost data based on 2010 and 2011 material prices to the committee members. DOE 

conducted its LCC and PBP analysis utilizing both the 2010 and 2011 material price cost 

data. The average results of these two analyses are presented here.

For each design line, the key outputs of the LCC analysis are a mean LCC savings 

and a median PBP relative to the base case, as well as the fraction of customers for which 

the LCC will decrease (net benefit), increase (net cost), or exhibit no change (no impact) 

relative to the base-case product forecast. No impacts occur when the base-case equals or 

exceeds the efficiency at a given TSL. Table V.4 through Table V.17 show the key 

results for each transformer design line.

Table V.4 Summary Life-Cycle Cost and Payback Period Results for Design Line 1 

Representative Unit

Trial Standard Level

1 2 3 4** 5** 6 7

Efficiency (%) 99.11 99.16 99.16 99.22 99.25 99.31 99.50

Transformers with Net 

LCC Cost (%)* 37.3 44.2 44.2 7.0 7.0 11.2 42.6

Transformers with Net 

LCC Benefit (%)* 62.5 55.6 55.6 92.9 92.9 88.8 57.4

Transformers with No 

Change in LCC (%)* 0.2 0.2 0.2 0.2 0.2 0.0 0.0

Mean LCC Savings ($) 83 153 153 696 696 618 365

Median PBP (Years) 17.7 24.7 24.7 10.8 10.8 13.7 24.6

* Rounding may cause some items to not total 100 percent

** The results are the same for these TSLs because in both cases customers are expected to purchase the 

least cost transformer designs that meet the EL. The least cost transformer designs are the same for TSLs 4 

and 5.
270

Table V.5 Summary Life-Cycle Cost and Payback Period Results for Design Line 2 

Representative Unit

Trial Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.95 99.00 99.00 99.07 99.11 99.18 99.41

Transformers with Net 

LCC Cost (%)* 41.5 18.2 18.2 11.4 13.1 17.8 67.2

Transformers with Net 

LCC Benefit (%)* 55.2 81.8 81.8 88.6 86.9 82.2 32.8

Transformers with No 

Change in LCC (%)* 3.4 0.0 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 66 278 278 343 330 311 -579

Median PBP (Years) 5.9 9.9 9.9 11.1 13.0 15.5 31.6

* Rounding may cause some items to not total 100 percent

Table V.6 Summary Life-Cycle Cost and Payback Period Results for Design Line 3 

Representative Unit 

Trial Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.49 99.48 99.51 99.57 99.54 99.61 99.73

Transformers with Net 

LCC Cost (%)* 14.5 13.9 12.0 4.0 5.3 4.0 29.9

Transformers with Net 

LCC Benefit (%)* 84.2 84.8 86.9 95.9 94.7 96.0 70.1

Transformers with No 

Change in LCC (%)* 1.3 1.3 1.2 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 2709 2407 3526 5527 5037 6942 4491

Median PBP (Years) 8.5 8.3 5.8 6.5 6.4 7.2 19.1

* Rounding may cause some items to not total 100 percent

Table V.7 Summary Life-Cycle Cost and Payback Period Results for Design Line 4 

Representative Unit 

Trial Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.16 99.16 99.16 99.19 99.22 99.25 99.50

Transformers with Net 

LCC Cost (%)* 6.6 6.6 6.6 7.6 2.5 2.5 5.9

Transformers with Net 

LCC Benefit (%)* 92.8 92.8 92.8 91.8 96.9 96.9 94.1

Transformers with No 

Change in LCC (%)* 0.6 0.6 0.6 0.6 0.6 0.6 0.0

Mean LCC Savings ($) 977 977 977 1212 3603 3603 4349

Median PBP (Years) 7.0 7.0 7.0 9.1 5.6 5.6 10.2

* Rounding may cause some items to not total 100 percent
271

Table V.8 Summary Life-Cycle Cost and Payback Period Results for Design Line 5 

Representative Unit 

Trial Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.48 99.48 99.51 99.57 99.54 99.61 99.69

Transformers with Net 

LCC Cost (%)* 30.5 30.5 19.9 9.8 14.8 9.1 41.9

Transformers with Net 

LCC Benefit (%)* 69.1 69.1 80.0 90.2 85.2 91.0 58.1

Transformers with No 

Change in LCC (%)* 0.4 0.4 0.1 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 3668 3668 6852 10382 8616 12014 4619

Median PBP (Years) 6.5 6.5 6.5 9.1 8.5 11.4 22.5

* Rounding may cause some items to not total 100 percent

Table V.9 Summary Life-Cycle Cost and Payback Period Results for Design Line 6 

Representative Unit

Trial Standard Level

1 2 3 4 5 6

Efficiency (%) 98.00 98.00 98.93 99.17 99.17 99.44

Transformers with Net LCC Cost (%)* 0.0 0.0 16.5 37.8 37.8 96.6

Transformers with Net LCC Benefit (%)* 0.0 0.0 83.5 62.2 62.2 3.4

Transformers with No Change in LCC (%)* 100.0 100.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 0 0 325 148 148 -992

Median PBP (Years) 0.0 0.0 12.4 15.7 15.7 31.7

* Rounding may cause some items to not total 100 percent

Table V.10 Summary Life-Cycle Cost and Payback Period Results for Design Line 

7 Representative Unit

Trial Standard Level

1 2 3 4 5 6

Efficiency (%) 98.47 98.60 98.80 99.17 99.17 99.44

Transformers with Net Increase in LCC (%)* 1.5 1.3 1.7 3.3 3.3 45.6

Transformers with Net LCC Savings (%)* 98.4 98.7 98.3 96.7 96.7 54.4

Transformers with No Impact on LCC (%)* 0.1 0.1 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 1526 1678 1838 2280 2280 212

Median PBP (Years) 3.9 3.6 4.1 6.3 6.3 16.8

* Rounding may cause some items to not total 100 percent
272

Table V.11 Summary Life-Cycle Cost and Payback Period Results for Design Line 

8 Representative Unit 

Trial Standard Level

1 2 3 4 5 6

Efficiency (%) 99.02 99.02 99.25 99.44 99.58 99.58

Transformers with Net Increase in LCC (%)* 4.7 4.7 13.3 9.0 79.3 79.3

Transformers with Net LCC Savings (%)* 95.3 95.3 86.7 91.0 20.7 20.7

Transformers with No Impact on LCC (%)* 0.0 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 2588 2588 2724 4261 -2938 -2938

Median PBP (Years) 7.7 7.7 11.3 10.1 22.5 22.5

* Rounding may cause some items to not total 100 percent

Table V.12 Summary Life-Cycle Cost and Payback Period Results for Design Line 

9 Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 98.93 98.93 99.04 99.04 99.55

Transformers with Net Increase in LCC (%)* 3.6 3.6 5.9 5.9 57.4

Transformers with Net LCC Savings (%)* 83.2 83.2 94.1 94.1 42.6

Transformers with No Impact on LCC (%)* 13.3 13.3 0.0 0.0 0.0

Mean LCC Savings ($) 787 787 1514 1514 -299

Median PBP (Years) 2.6 2.6 6.1 6.1 18.5

* Rounding may cause some items to not total 100 percent

Table V.13 Summary Life-Cycle Cost and Payback Period Results for Design Line 

10 Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 99.29 99.37 99.37 99.37 99.63

Transformers with Net Increase in LCC (%)* 0.7 17.9 17.9 17.9 88.8

Transformers with Net LCC Savings (%)* 98.8 82.1 82.1 82.1 11.2

Transformers with No Impact on LCC (%)* 0.5 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 4604 4455 4455 4455 -14727

Median PBP (Years) 1.1 8.6 8.6 8.6 27.5

* Rounding may cause some items to not total 100 percent
273

Table V.14 Summary Life-Cycle Cost and Payback Period Results for Design Line 

11 Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 98.81 98.81 99.13 99.13 99.50

Transformers with Net Increase in LCC (%)* 21.9 21.9 25.9 25.9 82.7

Transformers with Net LCC Savings (%)* 78.1 78.1 74.1 74.1 17.4

Transformers with No Impact on LCC (%)* 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 996 996 1849 1849 -4166

Median PBP (Years) 10.6 10.6 13.6 13.6 24.1

* Rounding may cause some items to not total 100 percent

Table V.15 Summary Life-Cycle Cost and Payback Period Results for Design Line 

12 Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 99.21 99.30 99.46 99.46 99.63

Transformers with Net Increase in LCC (%)* 7.1 7.6 17.1 17.1 85.4

Transformers with Net LCC Savings (%)* 92.9 92.4 82.9 82.9 14.6

Transformers with No Impact on LCC (%)* 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 4537 6790 8594 8594 -14496

Median PBP (Years) 6.0 8.5 12.3 12.3 24.7

* Rounding may cause some items to not total 100 percent

Table V.16 Summary Life-Cycle Cost and Payback Period Results for Design Line 

13A Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 98.69 98.69 98.84 99.04 99.45

Transformers with Net Increase in LCC (%)* 54.2 54.2 45.5 66.3 98.5

Transformers with Net LCC Savings (%)* 45.8 45.8 54.5 33.7 1.5

Transformers with No Impact on LCC (%)* 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) -27 -27 311 -1019 -12053

Median PBP (Years) 16.1 16.1 16.2 20 35.3

* Rounding may cause some items to not total 100 percent
274

Table V.17 Summary Life-Cycle Cost and Payback Period Results for Design Line 

13B Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 99.19 99.28 99.28 99.28 99.52

Transformers with Net Increase in LCC (%)* 30.5 27.3 27.3 27.3 70.4

Transformers with Net LCC Savings (%)* 69.3 72.7 72.7 72.7 29.6

Transformers with No Impact on LCC (%)* 0.2 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 2494 4346 4346 4346 -6823

Median PBP (Years) 4.5 12.2 12.2 12.2 20.6

* Rounding may cause some items to not total 100 percent

b. Customer Subgroup Analysis

In the customer subgroup analysis, DOE estimated the LCC impacts of the 

distribution transformer TSLs on purchasers of vault-installed transformers (primarily 

urban utilities). DOE included only the three-phase liquid-immersed design lines in this 

analysis, since those types account for the vast majority of vault-installed transformers. 

Table V.18 shows the mean LCC savings at each TSL for this customer subgroup.

Chapter 11 of the final rule TSD explains DOE’s method for conducting the 

customer subgroup analysis and presents the detailed results of that analysis.

Table V.18 Comparison of Mean Life-Cycle Cost Savings for Liquid-Immersed 

Transformers Purchased by Consumer Subgroup (2011$)

Design 

Line Trial Standard Level

1 2 3 4 5 6 7

Medium Vault Replacement Subgroup

4 -1236 -1236 -1236 -3078 -759 -759 -377

5 2387 2387 -6183 -4421 -6156 -2905 4619

All Customers

4 977 977 977 1212 3603 3603 4349

5 3668 3668 6852 10382 8616 12014 4619
275

c. Rebuttable Presumption Payback 

As discussed in section IV.F.3.j, EPCA establishes a rebuttable presumption that 

an energy conservation standard is economically justified if the increased purchase cost 

for equipment that meets the standard is less than three times the value of the first-year 

energy savings resulting from the standard. (42 U.S.C. 6295(o)(2)(B)(iii), 6316(a)) DOE 

calculated a rebuttable-presumption PBP for each TSL to determine whether DOE could 

presume that a standard at that level is economically justified. As required by EPCA, 

DOE based the calculations on the assumptions in the DOE test procedure for distribution 

transformers. (42 U.S.C. 6295(o)(2)(B)(iii), 6316(a)) As a result, DOE calculated a single 

rebuttable-presumption payback value, and not a distribution of PBPs, for each TSL.

Table V.19 and Table V.21 show the rebuttable-presumption PBPs for the considered 

TSLs. The rebuttable presumption is fulfilled in those cases where the PBP is three years 

or less. However, DOE routinely conducts an economic analysis that considers the full 

range of impacts to the customer, manufacturer, Nation, and environment, as required 

under 42 U.S.C. 6295(o)(2)(B)(i). The results of that analysis serve as the basis for DOE 

to definitively evaluate the economic justification for a potential standard level (thereby 

supporting or rebutting the results of any three-year PBP analysis). Section V.C addresses 

how DOE considered the range of impacts to select today’s standard.
276

Table V.19 Rebuttable-Presumption Payback Periods (years) for Liquid-Immersed 

Distribution Transformers

Desig

n Line

Rated 

Capacit

y 

Trial Standard Level

kVA 1 2 3 4 5 6 7

1 50 17.5 17.7 17.7 12.5 12.5 14.9 20.0

2 25 22.5 20.7 20.7 16.5 17.1 18.3 34.2

3 500 9.1 9.0 9.0 7.6 8.0 7.5 16.9

4 150 8.1 8.1 8.1 5.5 5.5 5.5 17.5

5 1500 13.1 13.1 8.4 8.5 8.7 10.0 19.9

Table V.20 Rebuttable-Presumption Payback Periods (years) for Low-Voltage DryType Distribution Transformers

Design 

Line

Rated 

Capacity 

Trial Standard Level

kVA 1 2 3 4 5 6

6 25 0.0 0.0 12.5 14.5 14.5 25.7

7 75 3.8 3.5 4.0 6.1 6.1 14.1

8 300 6.5 6.5 10.0 9.3 19.4 19.4

Table V.21 Rebuttable-Presumption Payback Periods (years) for Medium-Voltage 

Dry-Type Distribution Transformers

Design 

Line

Rated 

Capacity 

Trial Standard Level

kVA 1 2 3 4 5

9 300 1.8 1.8 4.2 4.2 14.1

10 1500 1.3 5.5 5.5 5.5 19.9

11 300 10.0 10.0 12.7 12.7 18.3

12 1500 5.9 7.3 11.5 11.5 19.7

13A 300 12.7 12.7 12.5 21.4 27.9

13B 2000 5.7 10.4 10.4 10.4 18.7
277

2. Economic Impact on Manufacturers

For the MIA in the February 2012 NOPR, DOE used changes in INPV to 

compare the direct financial impacts of different TSLs on manufacturers (77 FR 7282,

February 10, 2012). DOE used the GRIM to compare the INPV of the base case (no new 

or amended energy conservation standards) to that of each TSL. The INPV is the sum of 

all net cash flows discounted by the industry’s cost of capital (discount rate) to the base 

year. The difference in INPV between the base case and the standards case is an estimate 

of the economic impacts that implementing that standard level would have on the 

distribution transformer industry. For today’s final rule, DOE continues to use the 

methodology presented in the NOPR at 77 FR 7282(February 10, 2012).

a. Industry Cash-Flow Analysis Results

The tables below depict the financial impacts (represented by changes in INPV) 

of amended energy standards on manufacturers as well as the conversion costs that DOE 

estimates manufacturers would incur at each TSL. The effect of amended standards on 

INPV was analyzed separately for each type of distribution transformer manufacturer: 

liquid-immersed, medium-voltage dry-type, and low-voltage dry-type. To evaluate the 

range of cash flow impacts on the distribution transformer industry, DOE modeled two 

different scenarios using different assumptions for markups that correspond to the range 

of anticipated market responses to new and amended standards. These assumptions 

correspond to the bounds of a range of market responses that DOE anticipates could 

occur in the standards case (i.e., where new and amended energy conservation standards 
278

apply). Each of the two scenarios results in a unique set of cash flows and corresponding 

industry values at each TSL. The February 2012 NOPR discusses each of these scenarios 

in full, and they are also presented in chapter 12 of the TSD.

The MIA results for liquid-immersed distribution transformers are as follows:

Table V.22 Manufacturer Impact Analysis for Liquid-Immersed Distribution 

Transformers - Preservation of Operating Profit Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5 6 7

INPV 2011$ 

M 575.1 526.9 465.9 461.7 389.0 382.1 358.4 181.6

Change in 

INPV

2011$ 

M (48.2) (109.3) (113.4) (186.1) (193.0) (216.7) (393.5)

% (8.4) (19.0) (19.7) (32.4) (33.6) (37.7) (68.4)

Capital 

Conversion 

Costs

2011$ 

M 25.3 57.8 60.6 92.8 96.2 101.5 124.5

Product 

Conversion 

Costs

2011$ 

M 24.2 65.2 65.7 96.1 96.1 96.1 96.1

Total 

Conversion 

Costs

2011$ 

M 49.4 123.0 126.3 188.9 192.3 197.7 220.6

*Note: Parentheses indicate negative values.

Table V.23 Manufacturer Impact Analysis for Liquid-Immersed Distribution 

Transformers - Preservation of Gross Margin Percentage Markup

Units Base 

Case

Trial Standard Level

1 2 3 4 5 6 7

INPV 2011$ 

M 575.1 551.6 508.1 506.2 477.8 473.8 486.6 575.6

Change in 

INPV

2011$ 

M (23.5) (67.0) (68.9) (97.3) (101.4) (88.5) 0.5

% (4.1) (11.7) (12.0) (16.9) (17.6) (15.4) 0.1

Capital 

Conversion 

Costs

2011$ 

M 25.3 57.8 60.6 92.8 96.2 101.5 124.5

Product 

Conversion 

Costs

2011$ 

M 24.2 65.2 65.7 96.1 96.1 96.1 96.1

Total 

Conversion 

Costs

2011$ 

M 49.4 123.0 126.3 188.9 192.3 197.7 220.6
279

At TSL 1, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from −$48.2 million to −$23.5 million, corresponding 

to a change in INPV of −8.4 percent to −4.1 percent. At this level, industry free cash flow 

is estimated to decrease by approximately 54.4 percent to $16.4 million, compared to the 

base-case value of $36.0 million in the year before the compliance date (2015).

While TSL 1 can be met with traditional steels, including M3, in all design lines, 

amorphous core transformers will be incrementally more competitive on a first cost basis. 

According to manufacturer interviews, this would likely induce some manufacturers to 

gradually build amorphous steel transformer production capacity. Because the production 

process for amorphous cores is entirely separate from that of silicon steel cores, large 

investments in new capital, including new core cutting equipment and annealing ovens 

will be required. Additionally, a great deal of testing, prototyping, design and 

manufacturing engineering resources will be required because most manufacturers have 

relatively little experience, if any, with amorphous steel transformers. These capital and 

production conversion expenses lead to a reduction in cash flow in the years preceding 

the standard. In the lower-bound scenario, DOE assumes manufacturers can only 

maintain annual operating profit in the standards case. Therefore, these conversion 

investments, and manufacturers’ higher working capital needs associated with more 

expensive transformers, drain cash flow and lead to a greater reduction in INPV, when 

compared to the upper-bound scenario. In the upper bound scenario, DOE assumes 
280

manufacturers will be able to fully markup and pass on the higher product costs, leading 

to higher operating income. This higher operating income essentially offsets the 

conversion costs and the increase in working capital requirements, leading to a negligible 

change in INPV at TSL1 in the upper-bound scenario.

At TSL 2, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from −$109.3 million to −$67.0 million, 

corresponding to a change in INPV of −19.0 percent to −11.7 percent. At this level, 

industry free cash flow is estimated to decrease by approximately 133.7 percent to −$12.1

million, compared to the base-case value of $36.0 million in the year before the 

compliance date (2015).

TSL 2 requires the same efficiency levels as TSL 1, except for DL 2, which is 

increased from baseline to EL1. EL1, as opposed to the baseline efficiency, could induce 

manufacturers to build more amorphous capacity, when compared to TSL 1, because 

amorphous core transformers become incrementally more cost competitive. Because DL2 

represents the largest share of core steel usage of all design lines, this has a significant 

impact on investments. There are more severe impacts on industry in the lower-bound 

profitability scenario when these greater one-time cash outlays are coupled with slight 

margin pressure. In the high-profitability scenario, manufacturers are able to maintain 

gross margins, mitigating the adverse cash flow impacts of the increased investment in 

working capital (associated with more expensive transformers).
281

At TSL 3, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from −$113.4 million to −$68.9 million, 

corresponding to a change in INPV of −19.7 percent to −12.0 percent. At this level, 

industry free cash flow is estimated to decrease by approximately 137.6 percent to −$13.6

million, compared to the base-case value of $36.0 million in the year before the 

compliance date (2015).

TSL 3 results are similar to TSL 2 results because the efficiency levels are the 

same except for DL3 and DL5, which each increase to EL 2 under TSL 3. The increase 

in stringency makes amorphous core transformers slightly more cost competitive in these 

DLs, according to the engineering analysis, which would likely increase amorphous core

transformer capacity needs − all other things being equal − and drive more investment to 

meet the standards.

At TSL 4, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from −$186.1 million to −$97.3 million, 

corresponding to a change in INPV of −32.4 percent to −16.9 percent. At this level, 

industry free cash flow is estimated to decrease by approximately 206.6 percent to −$38.4

million, compared to the base-case value of $36.0 million in the year before the 

compliance date (2015).
282

During interviews, manufacturers expressed differing views on whether the 

efficiency levels embodied in TSL 4 would shift the market away from silicon steels 

entirely. Because DL3 and DL5 must meet EL4 at this TSL, DOE expects the majority 

of the market would shift to amorphous core transformers at TSL 4 and above. Even 

assuming a sufficient supply of amorphous steel were available, TSL 4 and above would 

require a dramatic build up in amorphous core transformer production capacity. DOE 

believes this wholesale transition away from silicon steels could seriously disrupt the 

market, drive small businesses to either source their cores or exit the market, and lead 

even large businesses to consider moving production offshore or exiting the market 

altogether. The negative impacts are again driven by the large conversion costs 

associated with new amorphous steel production lines. If the higher first costs at TSL 4 

drive more utilities to refurbish rather than replace failed transformers, a scenario many 

manufacturers predicted at the efficiency levels and prices embodied in TSL 4, reduced 

transformer sales could cause further declines in INPV. 

At TSL 5, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from −$193.0 million to −$101.4 million, or a change 

in INPV of −33.6 percent to −17.6 percent. At this level, industry free cash flow is 

estimated to decrease by approximately 210.8 percent to −$39.9 million, compared to the 

base-case value of $36.0 million in the year before the compliance date (2015).
283

TSL 5 would likely shift the entire market to amorphous core transformers, 

leading to even greater investment needs than TSL 4, and further driving the adverse 

impacts discussed above.

At TSL 6, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from −$216.7 million to −$88.5 million, 

corresponding to a change in INPV of −37.7 percent to −15.4 percent. At this level, 

industry free cash flow is estimated to decrease by approximately 217.5 percent to −$42.3

million, compared to the base-case value of $36.0 million in the year before the 

compliance date (2015).

The impacts at TSL 6 are similar to those DOE expects at TSL 5, except that 

slightly more amorphous core production capacity will be needed because TSL 6-

compliant transformers will have somewhat heavier cores and thus require more 

amorphous steel. This leads to slightly greater capital expenditures at TSL 6 compared to 

TSL 5.

At TSL 7, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from −$393.5 million to $0.5 million, corresponding 

to a change in INPV of −68.4 percent to 0.1 percent. At this level, industry free cash flow 

is estimated to decrease by approximately 246.2 percent to −$52.7 million, compared to 

the base-case value of $36.0 million in the year before the compliance date (2015).
284

The impacts at TSL 7 are similar to those DOE expects at TSL 6, except that 

slightly more amorphous core production capacity will be needed because TSL 7-

compliant transformers will have somewhat heavier cores and thus require more 

amorphous steel. This leads to slightly greater capital expenditures at TSL 7 compared to 

TSL 6, incrementally reducing industry value.

The MIA results for low-voltage dry-type distribution transformers are as follows:

Table V.24 Manufacturer Impact Analysis Low-Voltage Dry-Type Distribution 

Transformers - Preservation of Operating Profit Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5 6

INPV 2011

$ M 237.6 229.6 226.5 219.0 198.7 190.8 159.0 

Change in 

INPV

2011

$ M (8.0) (11.1) (18.6) (38.9) (46.8) (78.6)

% (3.4) (4.7) (7.8) (16.4) (19.7) (33.1)

Capital 

Conversion 

Costs

2011

$ M 4.5 5.3 12.0 28.5 30.7 45.6 

Product 

Conversion 

Costs

2011

$ M 2.9 3.6 5.0 8.0 8.0 8.0 

Total 

Conversion 

Costs

2011

$ M 7.4 9.0 17.0 36.5 38.7 53.6 

* Note: Parentheses indicate negative values.

Table V.25 Manufacturer Impact Analysis Low-Voltage Dry-Type Distribution 

Transformers - Preservation of Gross Margin Percentage Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5 6

INPV 2011

$ M 237.6 252.4 249.4 265.7 279.9 298.6 356.6 

Change in 

INPV

2011

$ M 14.8 11.8 28.1 42.3 61.0 118.9 

% 6.2 5.0 11.8 17.8 25.7 50.1 
285

Capital 

Conversion 

Costs

2011

$ M 4.5 5.3 12.0 28.5 30.7 45.6 

Product 

Conversion 

Costs

2011

$ M 2.9 3.6 5.0 8.0 8.0 8.0 

Total 

Conversion 

Costs

2011

$ M 7.4 9.0 17.0 36.5 38.7 53.6 

*Note: Parentheses indicate negative values.

At TSL 1, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from −$8.0 million to $14.8 million, corresponding to 

a change in INPV of −3.4 percent to 6.2 percent. At this level, industry free cash flow is 

estimated to decrease by approximately 5.0 percent to $14.5 million, compared to the 

base-case value of $15.2 million in the year before the compliance date (2015).

TSL 1 provides many design paths for manufacturers to comply. DOE’s 

engineering analysis indicates manufacturers can continue to use the low-capital butt-lap 

core designs, meaning investment in mitering or wound core capability is not necessary. 

Manufacturers can use higher-quality grain oriented steels in butt-lap designs to meet 

TSL1, source some or all cores, or invest in modified mitering capability (if they do not 

already have it).

At TSL 2, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from −$11.1 million to $11.8 million, corresponding 

to a change in INPV of −4.7 percent to 5.0 percent. At this level, industry free cash flow 
286

is estimated to decrease by approximately 9.1 percent to $13.8 million, compared to the 

base-case value of $15.2 million in the year before the compliance date (2015).

TSL 2 differs from TSL1 in that DL7 must meet EL3, up from EL2. Comments 

received from the NOPR and consultations with technical experts suggest that butt-lap 

technology can still be used to achieve EL 3 for DL 7. However, DOE expects the high 

volume manufacturers which supply most of the market to employ mitered cores at this 

efficiency level. Therefore, the increase in conversion costs for DL 7, which represents 

more than three-quarters of the market by core weight in this superclass, is primarily 

driven by the need to purchase additional core cutting equipment to accommodate the 

production of larger, mitered cores. Furthermore, manufacturers also indicated that there 

would be a reduced burden at TSL 2 relative to TSL 1 because they would be able to 

standardize the use of NEMA Premium® (with the exception of DL 6).

At TSL 3, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from −$18.6 to $28.1 million, corresponding to a 

change in INPV of −7.8 percent to 11.8 percent. At this level, industry free cash flow is 

estimated to decrease by approximately 31.9 percent to $10.4 million, compared to the 

base-case value of $15.2 million in the year before the compliance date (2015).

TSL3 represents EL4 for DL6, DL7, and DL8. Although manufacturers may be 

able to meet EL4 using M4 steel, comments and interviews suggest uncertainty about the 
287

ability of M4 to meet EL 4 for all design lines. Manufacturers may be forced to use 

higher-grade and thinner steels like M3, H1, and H0. However, these thinner steels, in 

combination with larger cores, will dramatically slow production throughput and 

therefore require the industry to expand capacity to maintain current shipments. This is 

the reason for the increase in conversion costs. In the lower-bound profitability scenario, 

when DOE assumes the industry cannot fully pass on incremental costs, these 

investments and the higher working capital needs drain cash flow and lead to the negative 

impacts shown in the preservation of operating profit scenario. In the high-profitability 

scenario, impacts are slightly positive because DOE assumes manufacturers are able to 

fully recoup their conversion expenditures through higher operating cash flow. 

At TSL 4, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from −$38.9 million to $42.3 million, corresponding 

to a change in INPV of −16.4 percent to 17.8 percent. At this level, industry free cash 

flow is estimated to decrease by approximately 87.2 percent to $1.9 million, compared to 

the base-case value of $15.2 million in the year before the compliance date (2015).

TSL 4 and higher would create significant challenges for the industry and likely 

disrupt the marketplace. DOE’s conversion costs at TSL 4 assume the industry will 

entirely convert to amorphous wound core technology to meet the efficiency standards. 

Few manufacturers of distribution transformers in this superclass have any experience 

with amorphous steel or wound core technology and would face a steep learning curve. 
288

This is reflected in the large conversion costs and adverse impacts on INPV in the 

Preservation of Operating Profit scenario. Most manufacturers DOE interviewed 

expected many low-volume manufacturers to exit the DOE-covered market altogether if 

amorphous steel was required to meet the standard. As such, DOE believes TSL 4 could 

lead to greater consolidation than the industry would experience at lower TSLs.

At TSL 5, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from −$46.8 million to $61.0 million, corresponding 

to a change in INPV of −19.7 percent to 25.7 percent. At this level, industry free cash 

flow is estimated to decrease by approximately 93.9 percent to $0.9 million, compared to 

the base-case value of $15.2 million in the year before the compliance date (2015).

The impacts at TSL 5 are similar to those DOE expects at TSL 4, except that 

slightly more amorphous core production capacity will be needed because TSL 5-

compliant transformers will have somewhat heavier cores and thus require more 

amorphous steel. This leads to slightly greater capital expenditures at TSL 5 compared to 

TSL 4.

At TSL 6, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from −$78.6 million to $118.9 million, corresponding 

to a change in INPV of −33.1 percent to 50.1 percent. At this level, industry free cash 
289

flow is estimated to decrease by approximately 138 percent to −$5.8 million, compared to 

the base-case value of $15.2 million in the year before the compliance date (2015).

The impacts at TSL 6 are similar to those DOE expects at TSL 5, except that 

slightly more amorphous core production capacity will be needed because TSL 6-

compliant transformers will have somewhat heavier cores and thus require more 

amorphous steel. This leads to slightly greater capital expenditures at TSL 6 compared to 

TSL 5.

The MIA results for medium-voltage dry-type distribution transformers are as 

follows:

Table V.26 Manufacturer Impact Analysis Medium-Voltage Dry-Type Distribution 

Transformers - Preservation of Operating Profit Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5

INPV 2011

$ M 68.7 67.3 65.7 57.9 58.0 34.5

Change in 

INPV

2011

$ M (1.4) (2.9) (10.7) (10.7) (34.1)

% (2.0) (4.2) (15.6) (15.5) (49.7)

Capital 

Conversion 

Costs

2011

$ M 0.2 0.5 3.9 3.9 13.9

Product 

Conversion 

Costs

2011

$ M 2.0 2.0 3.7 3.7 8.2

Total 

Conversion 

Costs

2011

$ M 2.2 2.6 7.7 7.7 22.1

*Note: Parentheses indicate negative values.
290

Table V.27 Manufacturer Impact Analysis Medium-Voltage Dry-Type Distribution 

Transformers - Preservation of Gross Margin Percentage Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5

INPV 2011$ 

M 68.7 69.3 71.7 74.4 74.3 81.5

Change in 

INPV

2011$ 

M 0.7 3.0 5.7 5.6 12.9

% 1.0 4.4 8.3 8.2 18.7

Capital 

Conversion 

Costs

2011$ 

M 0.2 0.5 3.9 3.9 13.9

Product 

Conversion 

Costs

2011$ 

M 2.0 2.0 3.7 3.7 8.2

Total 

Conversion 

Costs

2011$ 

M 2.2 2.6 7.7 7.7 22.1

*Note: Parentheses indicate negative values.

At TSL 1, DOE estimates impacts on INPV for medium-voltage dry-type

distribution transformer manufacturers to range from −$1.4 million to $0.7 million, 

corresponding to a change in INPV of −2.0 percent to 1.0 percent. At this level, industry

free cash flow is estimated to decrease by approximately 2.3 percent to $4.3 million, 

compared to the base-case value of $4.4 million in the year before the compliance date 

(2015).

TSL 1 represents EL1 for all MVDT design lines. For DL12, the largest design 

line by core steel usage, manufacturers have a variety of steels available to them, 

including M4, the most common steel in the superclass. Additionally, the vast majority 

of the market already uses step-lap mitering technology. Therefore, DOE anticipates 

only moderate conversion costs for the industry, mainly associated with slower 

throughput due to larger cores. Some manufacturers may need to slightly expand
291

capacity to maintain throughput and/or modify equipment to manufacturer with greater 

precision and tighter tolerances. In general, however, conversion expenditures should be 

relatively minor compared to INPV. For this reason, TSL 1 yields relatively minor 

adverse changes to INPV in the standards case.

At TSL 2 (the consensus recommendation from the negotiating committee), DOE 

estimates impacts on INPV for medium-voltage dry-type distribution transformer 

manufacturers to range from −$2.9 million to $3.0 million, corresponding to a change in 

INPV of −4.2 percent to 4.4 percent. At this level, industry free cash flow is estimated to 

decrease by approximately 6.0 percent to $4.2 million, compared to the base-case value 

of $4.4 million in the year before the compliance date (2015).

Compared to TSL 1, TSL 2 requires EL2, rather than EL1, in DLs 10, 12, and 

13B. Because M4 (as well as the commonly used H1) can still be employed to meet 

these levels, DOE expects similar results at TSL 2 as at TSL 1. Slightly greater 

conversion costs will be required as the compliant transformers will have heavier cores, 

all other things being equal, meaning additional capacity may be necessary depending on 

each manufacturer’s current capacity utilization rate. As with TSL 1, TSL 2 will not 

require significant changes to most manufacturers production processes because the 

thickness of the steels will not change significantly, if at all.
292

At TSL 3, DOE estimates impacts on INPV for medium-voltage dry-type

distribution transformer manufacturers to range from −$10.7 million to $5.7 million, 

corresponding to a change in INPV of −15.6 percent to 8.3 percent. At this level, industry

free cash flow is estimated to decrease by approximately 53.4 to $2.1 million, compared 

to the base-case value of $4.4 million in the year before the compliance date (2015).

At TSL 4, DOE estimates impacts on INPV for medium-voltage dry-type

distribution transformer manufacturers to range from−$10.7 million to $5.6 million, 

corresponding to a change in INPV of −15.5 percent to 8.2 percent. At this level, industry

free cash flow is estimated to decrease by approximately −53.4 percent to $2.1 million, 

compared to the base-case value of $4.4 million in the year before the compliance date 

(2015).

TSL 3 and TSL 4 require EL2 for DL9 and DL10, but EL4 for DL11 through 

DL13B, which hold the majority of the volume. Several manufacturers were concerned 

TSL 3 would require some of the high volume design lines to use H1 or H0, or transition 

entirely to amorphous wound cores (with which the industry has experience). Without a 

cost effective M-grade steel option, the industry could face severe disruption. Even 

assuming a sufficient supply of Hi-B steel, which is generally used and priced for the 

power transformer market, relatively large expenditures would be required in R&D and 

engineering as most manufacturers would have to move production to steel with which 

they have little experience. DOE estimates total conversion costs would more than 
293

double at TSL 3, relative to TSL 2. If, based on the movement of steel prices, EL4 can be 

met cost competitively only through the use of amorphous steel or an exotic design with 

little or no current place in scale manufacturing, manufacturers would face significant 

challenges that DOE believes would lead to consolidation and likely cause many lowvolume manufacturers to exit the product line. 

At TSL 5, DOE estimates impacts on INPV for medium-voltage dry-type

distribution transformer manufacturers to range from −$34.1 million to $12.9 million, 

corresponding to a change in INPV of −49.7 percent to 18.7 percent. At this level, 

industry free cash flow is estimated to decrease by approximately 189.1 percent to −$3.9

million, compared to the base-case value of $4.4 million in the year before the 

compliance date (2015).

TSL 5 represents max-tech and yields results similar to but more severe than TSL 

4 results. The engineering analysis shows that the entire market must convert to 

amorphous wound cores at TSL 5. Because the industry has no experience with wound 

core technology, and little, if any, experience with amorphous steel, this transition would 

represent a tremendous challenge for industry. Interviews suggest most manufacturers 

would exit the market rather altogether or source their cores rather than make the 

investments in plant, equipment, and the R&D required to meet such levels. 
294

b. Impacts on Employment

Liquid-Immersed. Based on interviews with manufacturers and other industry 

research, DOE estimates that there are roughly 5,000 employees associated with DOEcovered liquid-immersed distribution transformer production and some three-quarters of 

these workers are located domestically. DOE does not expect large changes in domestic 

employment to occur due to today’s standard. Manufacturers generally agreed that 

amorphous core steel production is more labor-intensive and would require greater labor 

expenditures than tradition steel core production. So long as domestic plants are not 

relocated outside the country, DOE expects moderate increases in domestic employment 

at TSL1 and TSL2. There could be a small drop in employment at small, domestic 

manufacturing firms if small manufacturers began sourcing cores. This employment 

would presumably transfer to the core makers, some of whom are domestic and some of 

whom are foreign. There is a risk that higher energy conservation standards that largely 

require the use of amorphous steel could cause even large manufacturers who are 

currently producing transformers in the U.S. to evaluate offshore options. Faced with the 

prospect of wholesale changes to their production process, large investments and stranded 

assets, some manufacturers expect to strongly consider shifting production offshore at 

TSL 3 due to the increased labor expenses associated with the production processes 

required to make amorphous steel cores. In summary, at TSLs 1 and 2, DOE does not 

expect significant impacts on employment, but at TSL 3 or greater, which would require 

more investment, the impact is very uncertain.
295

Low-Voltage Dry-Type. Based on interviews with manufacturers, DOE 

estimates that there are approximately 2,200 employees associated with DOE-covered 

LVDT production. Approximately 75 percent of these employees are located outside of 

the U.S. Typically, high volume units are made in Mexico, taking advantage of lower 

labor rates, while custom designs are made closer to the manufacturer’s customer base or 

R&D centers. DOE does not expect large changes in domestic employment to occur due 

to today’s standard. Most production already occurs outside the U.S. and, by and large, 

manufacturers agreed that most design changes necessary to meet higher energy 

conservation standards would increase labor expenditures, not decrease them. If, 

however, small manufacturers began sourcing cores instead of manufacturing them inhouse, there could be a small drop in employment at these firms. This employment would 

presumably transfer to the core makers, some of whom are domestic and some of whom 

are foreign. In summary, DOE does not expect significant changes to domestic LVDT 

industry employment levels as a result of today’s standards. Higher TSLs may lead to 

small declines in domestic employment as more firms will be challenged with what 

amounts to clean-sheet redesigns. Facing the prospect of green field investments, these 

manufacturers may elect to make those investments in lower-labor cost countries.67

Medium-Voltage Dry-Type. Based on interviews with manufacturers, DOE 

estimates that there are approximately 1,850 employees associated with DOE-covered 

 67 A green field investment is a form of foreign direct investment where a parent company starts a new 

venture in a foreign country by constructing new operational facilities from the ground up.
296

MVDT production. Approximately 75 percent of these employees are located 

domestically. With the exception of TSLs that require amorphous cores, manufacturers 

agreed that most design changes necessary to meet higher standards would increase labor 

expenditures, not decrease them, but current production equipment would not be 

stranded, mitigating the incentive to move production offshore. Corroborating this, the 

largest manufacturer and domestic employer in this market has indicated that the standard 

in this final rule, will not cause their company to reconsider production location. As such, 

DOE does not expect significant changes to domestic MVDT industry employment levels 

as a result of the standard in today’s final rule. For TSLs that would require amorphous 

cores, DOE does anticipate significant changes to domestic MVDT industry employment 

levels.

c. Impacts on Manufacturing Capacity 

Based on manufacturer interviews, DOE believes that there is significant excess 

capacity in the distribution transformer market. Shipments in the industry are well down 

from their peak in 2007, according to manufacturers. Therefore, DOE does not believe 

there would be any production capacity constraints at TSLs that do not require dramatic 

transitions to amorphous cores. For those TSLs that require amorphous cores in 

significant volumes, DOE believes there is potential for capacity constraints in the near 

term due to limitations on core steel availability. However, for the levels in today’s rule, 

DOE does not foresee any capacity constraints.
297

d. Impacts on Subgroups of Manufacturers

Small manufacturers, niche equipment manufacturers, and manufacturers 

exhibiting a cost structure substantially different from the industry average could be 

affected disproportionately. Therefore, using average cost assumptions to develop an 

industry cash-flow estimate is inadequate to assess differential impacts among 

manufacturer subgroups. DOE considered small manufacturers as a subgroup in the MIA.

For a discussion of the impacts on the small manufacturer subgroup, see the Regulatory 

Flexibility Analysis in section VI.B and chapter 12 of the final rule TSD.

e. Cumulative Regulatory Burden

While any one regulation may not impose a significant burden on 

manufacturers, the combined effects of recent or impending regulations may have serious 

consequences for some manufacturers, groups of manufacturers, or an entire industry. 

Assessing the impact of a single regulation may overlook this cumulative regulatory 

burden. In addition to energy conservation standards, other regulations can significantly 

affect manufacturers’ financial operations. Multiple regulations affecting the same 

manufacturer can strain profits and lead companies to abandon product lines or markets 

with lower expected future returns than competing products. For these reasons, DOE

conducts an analysis of cumulative regulatory burden as part of its rulemakings 

pertaining to appliance efficiency. During previous stages of this rulemaking, DOE 

identified a number of requirements in addition to amended energy conservation 

standards for distribution transformers. The Department did not receive comments 
298

regarding cumulative regulatory burden issues for the NOPR. DOE addresses the full 

details of the cumulative regulatory burden analysis in chapter 12 of the final rule TSD.

3. National Impact Analysis

a. Significance of Energy Savings

For each TSL, DOE projected energy savings for transformers purchased in the 

30-year period that begins in the year of compliance with amended standards (2016–

2045). The savings are measured over the entire lifetime of products purchased in the 30-

year period, which in the case of transformers extends through 2105. DOE quantified the 

energy savings attributable to each TSL as the difference in energy consumption between 

each standards case and the base case. Table V.28 presents the estimated energy savings 

for each considered TSL. The approach used is further described in section IV.G.

68

Table V.28 Cumulative National Energy Savings for Distribution Transformer Trial 

Standard Levels for Units Sold in 2016–2045

Trial Standard Level

1 2 3 4 5 6 7

Liquid-immersed

quads

0.92 1.56 1.76 3.31 3.30 4.09 7.01

Low-voltage dry-type 2.28 2.43 3.05 4.39 4.48 4.94

Medium-voltage dry-type 0.15 0.29 0.53 0.53 0.84

 68 Chapter 10 of the TSD presents tables that show the magnitude of the energy savings discounted at rates 

of 3 percent and 7 percent. Discounted energy savings represent a policy perspective in which energy 

savings realized farther in the future are less significant than energy savings realized in the nearer term.
299

For this rulemaking, DOE undertook a sensitivity analysis using nine rather than 

30 years of product shipments. The choice of a nine-year period is a proxy for the 

timeline in EPCA for the review of the energy conservation standard established in this 

final rule and potential revision of and compliance with a new standard for distribution 

transformers.69

Table V.29

 This timeframe may not be statistically relevant with regard to the 

product lifetime, product manufacturing cycles or other factors specific to distribution 

transformers. Thus, this information is presented for informational purposes only and is 

not indicative of any change in DOE’s analytical methodology. The NES results based 

on a nine-year analytical period are presented in . The impacts are counted 

over the lifetime of products purchased in 2016–2024.

Table V.29 Cumulative National Energy Savings for Distribution Transformer Trial 

Standard Levels for Units Sold in 2016–2024

Trial Standard Level

1 2 3 4 5 6 7

Liquid-immersed

quads

0.25 0.42 0.47 0.90 0.90 1.12 1.93

Low-voltage dry-type 0.63 0.67 0.85 1.22 1.24 1.38

Medium-voltage dry-type 0.04 0.08 0.15 0.15 0.23

 69 EPCA requires DOE to review its standards at least once every 6 years, and requires, for certain 

products, a 3 year period after any new standard is promulgated before compliance is required, except that 

in no case may any new standards be required within 6 years of the compliance date of the previous 

standards. While adding a 6-year review to the 3-year compliance period adds up to 9 years, DOE notes 

that it may undertake reviews at any time within the 6 year period and that the 3-year compliance date may 

yield to the 6-year backstop. A 9-year analysis period may not be appropriate given the variability that 

occurs in the timing of standards reviews and the fact that for some products, the compliance period is 5 

years rather than 3 years.
300

b. Net Present Value of Customer Costs and Benefits

DOE estimated the cumulative NPV of the total costs and savings for customers 

that would result from the TSLs considered for distribution transformers. In accordance 

with OMB’s guidelines on regulatory analysis,70 DOE calculated the NPV using both a 7-

percent and a 3-percent real discount rate. The 7-percent rate is an estimate of the average 

before-tax rate of return on private capital in the U.S. economy, and reflects the returns 

on real estate and small business capital as well as corporate capital. This discount rate 

approximates the opportunity cost of capital in the private sector (OMB analysis has 

found the average rate of return on capital to be near this rate). The three-percent rate 

reflects the potential effects of standards on private consumption (e.g., through higher 

prices for products and reduced purchases of energy). This rate represents the rate at 

which society discounts future consumption flows to their present value. It can be 

approximated by the real rate of return on long-term government debt (i.e., yield on 

United States Treasury notes), which has averaged about 3 percent for the past 30 years.

Table V.30 shows the customer NPV results for each TSL considered. In each 

case, the impacts cover the lifetime of equipment purchased in 2016–2045. 

 70 OMB Circular A-4, section E (Sept. 17, 2003). Available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4. 
301

Table V.30 Net Present Value of Customer Benefits for Distribution Transformers 

Trial Standard Levels for Units Sold in 2016–2045 

Discount 

Rate %

Trial Standard Level

1 2 3 4 5 6 7

Liquidimmersed

billion 2011$

3 3.12 4.82 5.62 10.78 10.19 10.27 -8.50

7 0.58 0.69 0.91 1.92 1.60 0.74 -12.97

Low-voltage 

dry-type

3 8.38 9.04 10.38 13.65 11.80 5.17

7 2.45 2.67 2.82 3.34 2.22 -1.92

Mediumvoltage drytype

3 0.49 0.79 1.12 1.12 -0.20

7 0.13 0.17 0.12 0.12 -0.89

The results shown in the table reflect the default equipment price trend, which 

uses constant prices. DOE conducted an NPV sensitivity analysis using alternative price 

trends. DOE developed one forecast in which prices decline after 2010, and one in which 

prices rise. The NPV results from the associated sensitivity cases are described in 

appendix 10-C of the final rule TSD.

The NPV results based on the aforementioned nine-year analytical period are 

presented in Table V.31. The impacts are counted over the lifetime of equipment

purchased in 2016–2024. As mentioned previously, this information is presented for 

informational purposes only and is not indicative of any change in DOE’s analytical 

methodology or decision criteria. 

Table V.31 Net Present Value of Customer Benefits for Distribution Transformers 

Trial Standard Levels for Units Sold in 2016–2024 

Discount 

Rate %

Trial Standard Level

1 2 3 4 5 6 7

billion 2011$
302

Liquid-Immersed

3 1.09 1.67 1.95 3.77 3.55 3.55 -3.49

7 0.26 0.31 0.41 0.88 0.73 0.29 -6.56

Low-voltage drytype

3 3.02 3.26 3.73 4.88 4.19 1.70

7 1.19 1.30 1.37 1.60 1.04 -1.04

Medium-voltage 

dry-type

3 0.18 0.28 0.39 0.39 -0.11

7 0.07 0.08 0.05 0.05 -0.46

c. Indirect Impacts on Employment 

DOE expects energy conservation standards for distribution transformers to 

reduce energy costs for equipment owners, and the resulting net savings to be redirected 

to other forms of economic activity. Those shifts in spending and economic activity could 

affect the demand for labor. As described in section IV.J, DOE used an input/output 

model of the U.S. economy to estimate indirect employment impacts of the TSLs that 

DOE considered in this rulemaking. DOE understands that there are uncertainties 

involved in projecting employment impacts, especially changes in the later years of the 

analysis. Therefore, DOE generated results for near-term time frames (2016–2020), 

where these uncertainties are reduced. 

The results suggest that today’s standards are likely to have negligible impact on 

the net demand for labor in the economy. The net change in jobs is so small that it would 

be imperceptible in national labor statistics and might be offset by other, unanticipated 

effects on employment. Chapter 13 of the final rule TSD presents detailed results.
303

4. Impact on Utility or Performance of Equipment

DOE believes that the standards in today’s rule will not lessen the utility or 

performance of distribution transformers. 

5. Impact of Any Lessening of Competition 

DOE has also considered any lessening of competition that is likely to result from 

new and amended standards. The Attorney General determines the impact, if any, of any 

lessening of competition likely to result from a proposed standard, and transmits such 

determination to the Secretary of Energy, together with an analysis of the nature and 

extent of such impact. (42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii))

To assist the Attorney General in making such a determination, DOE has 

provided the Department of Justice (DOJ) with copies of this notice and the TSD for 

review. DOE considered DOJ’s comments on the proposed rule in preparing the final 

rule.

6. Need of the Nation to Conserve Energy 

Enhanced energy efficiency, where economically justified, improves the Nation’s 

energy security, strengthens the economy, and reduces the environmental impacts or 

costs of energy production. Reduced electricity demand due to energy conservation 

standards is also likely to reduce the cost of maintaining the reliability of the electricity 

system, particularly during peak-load periods. As a measure of this reduced demand, 
304

chapter 14 in the final rule TSD presents the estimated reduction in generating capacity in 

2045 for the TSLs that DOE considered in this rulemaking.

Energy savings from standards for distribution transformers could also produce 

environmental benefits in the form of reduced emissions of air pollutants and greenhouse 

gases associated with electricity production. Table V.32 provides DOE’s estimate of 

cumulative CO2, NOX, and Hg emissions reductions projected to result from the TSLs 

considered in this rulemaking. DOE reports annual CO2, NOX, and Hg emissions 

reductions for each TSL in chapter 15 of the final rule TSD.

Table V.32 Cumulative Emissions Reduction Estimated for Distribution 

Transformer Trial Standard Levels 

Trial Standard Level

1 2 3 4 5 6 7

Liquid-Immersed

CO2 (million metric tons) 82.2 143.1 156.5 274.6 273.4 321.8 501.8

NOX (thousand tons) 69.3 120.6 131.8 231.1 230.1 270.8 421.9

SO2 (thousand tons) 52.0 90.0 98.4 173.0 172.4 203.2 318.0

Hg (tons) 0.2 0.3 0.3 0.6 0.6 0.7 1.1

Low-Voltage Dry-Type

CO2 (million metric tons) 151.3 161.6 203.0 292.8 297.6 319.3

NOX (thousand tons) 127.6 136.4 171.3 247.0 251.0 269.3

SO2 (thousand tons) 110.1 117.6 147.8 213.2 216.7 232.4

Hg (tons) 0.4 0.4 0.5 0.8 0.8 0.8

Medium-Voltage Dry-Type
305

As part of the analysis for this rule, DOE estimated monetary benefits likely to 

result from the reduced emissions of CO2 and NOX that DOE estimated for each of the 

TSLs considered. As discussed in section IV.M, DOE used values for the SCC developed 

by an interagency process. The four sets of SCC values resulting from that process 

(expressed in 2011$) are represented by $4.9/metric ton (the average value from a 

distribution that uses a 5-percent discount rate), $22.3/metric ton (the average value from 

a distribution that uses a 3-percent discount rate), $36.5/metric ton (the average value 

from a distribution that uses a 2.5-percent discount rate), and $67.6/metric ton (the 95thpercentile value from a distribution that uses a 3-percent discount rate). These values 

correspond to the value of emission reductions in 2011; the values for later years are 

higher due to increasing damages as the projected magnitude of climate change increases. 

Table V.33 presents the global value of CO2 emissions reductions at each TSL. 

For each of the four cases, DOE calculated a present value of the stream of annual values 

using the same discount rate as was used in the studies upon which the dollar-per-ton 

CO2 (million metric tons) 11.2 20.9 40.7 40.7 61.3

NOX (thousand tons) 9.34 17.7 34.2 34.2 51.5

SOs (thousand tons) 7.06 13.29 25.65 25.65 38.69

Hg (tons) 0.02 0.04 0.10 0.10 0.14
306

values are based. DOE calculated domestic values as a range from 7 percent to 23 percent 

of the global values, and these results are presented in chapter 16 of the final rule TSD.

Table V.33 Estimates of Global Present Value of CO2 Emissions Reduction under 

Distribution Transformer Trial Standard Levels

TSL

5% discount 

rate, average*

3% discount 

rate, average*

2.5% discount 

rate, average*

3% discount 

rate, 95th

percentile*

Liquid-Immersed

Million 2011$

1 259 1,390 2,377 4,230 

2 454 2,428 4,151 7,390 

3 494 2,649 4,530 8,060 

4 855 4,609 7,891 14,024 

5 851 4,588 7,855 13,960 

6 991 5,366 9,195 16,325 

7 1,515 8,266 14,190 25,144 

Low-Voltage Dry-Type

1 450 2,470 4,245 7,512

2 480 2,637 4,532 8,020

3 603 3,313 5,694 10,075

4 870 4,779 8,214 14,535

5 884 4,857 8,348 14,771

6 949 5,211 8,956 15,847

Medium-Voltage Dry-Type

1 35 188 321 571 

2 65 350 599 1,065 

3 126 680 1,164 2,067 

4 126 680 1,164 2,067 

5 190 1,024 1,755 3,117 

DOE is well aware that scientific and economic knowledge about the contribution 

of CO2 and other greenhouse gas (GHG) emissions to changes in the future global 
307

climate and the potential resulting damages to the world economy continues to evolve 

rapidly. Thus, any value placed on reducing CO2 emissions in this rulemaking is subject 

to change. DOE, together with other Federal agencies, will continue to review various 

methodologies for estimating the monetary value of reductions in CO2 and other GHG 

emissions. This ongoing review will consider the comments on this subject that are part 

of the public record for this and other rulemakings, as well as other methodological 

assumptions and issues. However, consistent with DOE’s legal obligations, and taking 

into account the uncertainty involved with this particular issue, DOE has included in this 

final rule the most recent values and analyses resulting from the ongoing interagency 

review process.

DOE also estimated a range for the cumulative monetary value of the economic 

benefits associated with NOX emissions reductions anticipated to result from amended 

standards for distribution transformers. The low and high dollar-per-ton values that DOE 

used are discussed in section IV.M. Table V.34 presents the cumulative present values for 

each TSL calculated using seven-percent and three-percent discount rates.
308

Table V.34 Estimates of Present Value of NOX Emissions Reduction under 

Distribution Transformer Trial Standard Levels

TSL 3% discount rate 7% discount rate

Liquid-Immersed

Million 2011$

1 13 to 138 6 to 57

2 24 to 242 10 to 100

3 26 to 263 11 to 109

4 44 to 454 18 to 185

5 44 to 452 18 to 184

6 51 to 525 21 to 211

7 78 to 799 31 to 314

Low-Voltage Dry-Type

1 23 to 238 9 to 92

2 25 to 254 10 to 99

3 31 to 319 12 to 124

4 45 to 460 17 to 179

5 45 to 468 18 to 182

6 49 to 502 19 to 195

Medium-Voltage Dry-Type

1 2 to 18 1 to 7

2 3 to 34 1 to 14

3 6 to 67 3 to 27

4 6 to 67 3 to 27

5 10 to 100 4 to 41

7. Summary of National Economic Impacts

The NPV of the monetized benefits associated with emissions reductions can be 

viewed as a complement to the NPV of the customer savings calculated for each TSL 

considered in this rulemaking. Table V.35 through Table V.37 present the NPV values 

that result from adding the estimates of the potential economic benefits resulting from 
309

reduced CO2 and NOX emissions in each of four valuation scenarios to the NPV of 

customer savings calculated for each TSL considered in this rulemaking, at both a sevenpercent and three-percent discount rate. The CO2 values used in the columns of each table 

correspond to the four sets of SCC values discussed above.

Table V.35 Liquid-Immersed Distribution Transformers: Net Present Value of 

Customer Savings Combined with Net Present Value of Monetized Benefits from 

CO2 and NOX Emissions Reductions 

TSL

Customer NPV at 3% Discount Rate added with:

SCC Value of 

$4.9/t CO2

* and 

Low Value for 

NOX

**

SCC Value of 

$22.3/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$36.5/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$67.6/t CO2

* and 

High Value for 

NOX

**

1

Billion 2011$

3.4 4.6 5.6 7.5

2 5.3 7.4 9.1 12.5

3 6.1 8.4 10.3 13.9

4 11.7 15.6 18.9 25.3

5 11.1 15.0 18.3 24.6

6 11.3 15.9 19.8 27.1

7 -6.9 0.2 6.1 17.4

TSL

Customer NPV at 7% Discount Rate added with:

SCC Value of 

$4.9/t CO2

* and 

Low Value for 

NOX

**

SCC Value of 

$22.3/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$36.5/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$67.6/t CO2

* and 

High Value for 

NOX

**

1

Billion 2011$

0.8 2.0 3.0 4.9

2 1.2 3.2 4.9 8.2

3 1.4 3.6 5.5 9.1

4 2.8 6.6 9.9 16.1

5 2.5 6.3 9.6 15.7

6 1.8 6.2 10.1 17.3

7 -11.4 -4.5 1.4 12.5

* These label values represent the global SCC in 2011, in 2011$. The present values have been calculated 

with scenario-consistent discount rates. 

** Low Value corresponds to $450 per ton of NOX emissions. Medium Value corresponds to $2,537 per ton 

of NOX emissions. High Value corresponds to $4,623 per ton of NOX emissions.
310

Table V.36 Low-Voltage Dry-Type Distribution Transformers: Net Present Value of 

Customer Savings Combined with Net Present Value of Monetized Benefits from 

CO2 and NOX Emissions Reductions 

TSL

Customer NPV at 3% Discount Rate added with:

SCC Value of 

$4.9/t CO2

* and 

Low Value for 

NOX

**

SCC Value of 

$22.3/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$36.5/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$67.6/t CO2

* and 

High Value for 

NOX

**

1

Billion 2011$

8.8 11.0 12.8 16.1

2 9.5 11.8 13.7 17.3

3 11.0 13.9 16.3 20.8

4 14.6 18.7 22.1 28.6

5 12.7 16.9 20.4 27.0

6 6.2 10.7 14.4 21.5

TSL

Customer NPV at 7% Discount Rate added with:

SCC Value of 

$4.9/t CO2

* and 

Low Value for 

NOX

**

SCC Value of 

$22.3/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$36.5/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$67.6/t CO2

* and 

High Value for 

NOX

**

1

Billion 2011$

2.9 5.0 6.7 10.0

2 3.2 5.4 7.3 10.8

3 3.4 6.2 8.6 13.0

4 4.2 8.2 11.7 18.1

5 3.1 7.2 10.7 17.2

6 -1.0 3.4 7.1 14.1

* These label values represent the global SCC in 2011, in 2011$. The present values have been calculated 

with scenario-consistent discount rates. 

** Low Value corresponds to $450 per ton of NOX emissions. Medium Value corresponds to $2,537 per ton 

of NOX emissions. High Value corresponds to $4,623 per ton of NOX emissions.
311

Table V.37 Medium-Voltage Dry-Type Distribution Transformers: Net Present 

Value of Customer Savings Combined with Net Present Value of Monetized Benefits 

from CO2 and NOX Emissions Reductions

TSL

Customer NPV at 3% Discount Rate added with:

SCC Value of 

$4.9/t CO2

* and 

Low Value for 

NOX

**

SCC Value of 

$22.3/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$36.5/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$67.6/t CO2

* and 

High Value for 

NOX

**

1

Billion 2011$

0.5 0.7 0.8 1.1

2 0.9 1.2 1.4 1.9

3 1.3 1.8 2.3 3.3

4 1.3 1.8 2.3 3.3

5 0.0 0.9 1.6 3.0

TSL

Customer NPV at 7% Discount Rate added with:

SCC Value of 

$4.9/t CO2

* and 

Low Value for 

NOX

**

SCC Value of 

$22.3/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$36.5/t CO2

* and 

Medium Value for 

NOX

**

SCC Value of 

$67.6/t CO2

* and 

High Value for 

NOX

**

1

Billion 2011$

0.2 0.3 0.5 0.7

2 0.2 0.5 0.8 1.2

3 0.2 0.8 1.3 2.2

4 0.2 0.8 1.3 2.2

5 -0.7 0.2 0.9 2.3

* These label values represent the global SCC in 2011, in 2011$. The present values have been calculated 

with scenario-consistent discount rates. 

** Low Value corresponds to $450 per ton of NOX emissions. Medium Value corresponds to $2,537 per ton 

of NOX emissions. High Value corresponds to $4,623 per ton of NOX emissions.

Although adding the value of customer savings to the values of emission 

reductions provides a valuable perspective, two issues should be considered. First, the 

national operating cost savings are domestic U.S. customer monetary savings that occur 

as a result of market transactions, while the value of CO2 reductions is based on a global 

value. Second, the assessments of operating cost savings and the SCC are performed with 

different methods that use quite different time frames for analysis. The national operating 

cost savings is measured for the lifetime of products shipped in 2016–2045. The SCC 
312

values, on the other hand, reflect the present value of future climate-related impacts 

resulting from the emission of one metric ton of CO2 in each year. These impacts 

continue well beyond 2100.

8. Other Factors 

The Secretary of Energy, in determining whether a standard is economically 

justified, may consider any other factors that the Secretary deems to be relevant. (42 

U.S.C. 6295(o)(2)(B)(i)(VII)) 

Electrical steel is a critical consideration in the design and manufacture of 

distribution transformers, amounting for more than 60 percent of the distribution 

transformers mass in some designs. Rapid changes in the supply or pricing of certain 

grades can seriously hinder manufacturers’ abilities to meet the market demand and, as a 

result, this rulemaking has extensively examined the effects of electrical steel supply and 

availability.

DOE’s most important conclusion from this examination is that several energy 

efficiency levels in each design line are attainable only by using amorphous steel, which 

is currently produced by only one supplier in any significant volume and that supplier at 

present does not have enough capacity to supply the industry at all-amorphous standard 

levels. Several more energy efficiency levels are reachable with the top grades of 

conventional (grain-oriented) electrical steels, but this would result in distribution 
313

transformers that are unlikely to be cost-competitive with the often more-efficient 

amorphous units. As stated above, switching to amorphous steel is not practicable as 

there are availability concerns with amorphous steel.

Distribution transformers are also highly customized products. Manufacturers 

routinely build only one or a handful of units of a particular design and require flexibility 

with respect to construction materials to remain competitive. Setting a standard that either 

technologically or economically required amorphous material would both eliminate a 

large amount of design flexibility and expose the industry to enormous risk with respect 

to supply and pricing of core steel. For both reasons, DOE considered electrical steel 

availability to be a significant factor in determining which TSLs were economically 

justified.

C.

When considering proposed standards, the new or amended energy conservation 

standard that DOE adopts for any type (or class) of covered equipment shall be designed 

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

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

6295(o)(2)(A)) In determining whether a standard is economically justified, the Secretary 

must determine whether the benefits of the standard exceed its burdens to the greatest 

extent practicable, in light of the seven statutory factors discussed previously. (42 U.S.C. 

Conclusion
314

6295(o)(2)(B)(i)) The new or amended standard must also “result in significant 

conservation of energy.” (42 U.S.C. 6295(o)(3)(B))

For today’s rulemaking, DOE considered the impacts of standards at each TSL, 

beginning with the max-tech level, to determine whether that level was economically 

justified. Where the max-tech level was not justified, DOE then considered the next most 

efficient level and undertook the same evaluation until it reached the highest efficiency 

level that is technologically feasible, economically justified and saves a significant 

amount of energy.

To aid the reader in understanding the benefits and/or burdens of each TSL, tables 

in this section summarize the quantitative analytical results for each TSL, based on the 

assumptions and methodology discussed herein. The efficiency levels contained in each 

TSL are described in section V.A. In addition to the quantitative results presented in the 

tables, DOE also considers other burdens and benefits that affect economic justification. 

These include the impacts on identifiable subgroups of customers who may be 

disproportionately affected by a national standard, and impacts on employment. Section 

V.B.1 presents the estimated impacts of each TSL for the considered subgroup. DOE 

discusses the impacts on employment in transformer manufacturing in section V.B.2.b, 

and discusses the indirect employment impacts in section V.B.3.c.
315

1. Benefits and Burdens of Trial Standard Levels Considered for Liquid-Immersed 

Distribution Transformers 

Table V.38 and Table V.39 summarize the quantitative impacts estimated for each 

TSL for liquid-immersed distribution transformers.

Table V.38 Summary of Analytical Results for Liquid-Immersed Distribution 

Transformers: National Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7

National Energy 

Savings 0.92 quads 1.56 1.76 3.31 3.30 4.09 7.01

NPV of Consumer Benefits

3% discount rate

2011$ billion

3.12 4.82 5.62 10.78 10.19 10.27 -8.50

7% discount rate 0.58 0.69 0.91 1.92 1.60 0.74 -12.97

Cumulative Emissions Reduction

CO2 (million 

metric tons) 82.2 143.1 156.5 274.6 273.4 321.8 501.8

NOX (thousand 

tons) 69.3 120.6 131.8 231.1 230.1 270.8 421.9

SO2 (thousand 

tons) 52.0 90.0 98.4 173.0 172.4 203.2 318.0

Hg (tons) 0.2 0.3 0.3 0.6 0.6 0.7 1.1

Value of Emissions Reduction

CO2 2011$ 

million

259 to 

* 4230

454 to 

7390

494 to 

8060

855 to 

14024

851 to 

13960

991 to 

16325

1515 to 

25144

NOX – 3% 

discount rate 13 to 138

2011$ million

24 to 242 26 to 263 44 to 

454

44 to 

452

51 to 

525

78 to 

799

NOX – 7% 

discount rate 6 to 57

2011$ million

10 to 100 11 to 109 18 to 

185

18 to 

184

21 to 

211

31 to 

314

* Range of the economic value of CO2 reductions is based on estimates of the global benefit of reduced 

CO2 emissions.
316

Table V.39 Summary of Analytical Results for Liquid-Immersed Distribution 

Transformers: Manufacturer and Consumer Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7

Manufacturer Impacts

Industry NPV 2011$ 

million

527 to 

552

466 to 

508

462 to 

506

389 to 

478

382 to 

474

358 to 

487

181 to 

576

Industry NPV % 

change

(8.4) to 

(4.1)

(19.0) to 

(11.7)

(19.7) to 

(12.0)

(32.4) to 

(16.9)

(33.6) to 

(17.6)

(37.7) to 

(15.4)

(68.4) to 

0.1

Consumer Mean LCC Savings 

Design line 1

2011$

83 153 153 696 696 618 365

Design line 2 66 278 278 343 330 311 -579

Design line 3 2709 2407 3526 5527 5037 6942 4491

Design line 4 977 977 977 1212 3603 3603 4349

Design line 5 3668 3668 6852 10382 8616 12014 4619
317

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7

Consumer Median PBP 

Design line 1

years

17.7 24.7 24.7 10.8 10.8 13.7 24.6

Design line 2 5.9 9.9 9.9 11.1 13.0 15.5 31.6

Design line 3 8.5 8.3 5.8 6.5 6.4 7.2 19.1

Design line 4 7.0 7.0 7.0 9.1 5.6 5.6 10.2

Design line 5 6.5 6.5 6.5 9.1 8.5 11.4 22.5

Distribution of Consumer LCC Impacts

Design line 1

Net Cost % 37.3 44.2 44.2 7.0 7.0 11.2 42.6

Net Benefit % 62.5 55.6 55.6 92.9 92.9 88.8 57.4

No Impact % 0.2 0.2 0.2 0.2 0.2 0.0 0.0

Design line 2

Net Cost % 41.5 18.2 18.2 11.4 13.1 17.8 67.2

Net Benefit % 55.2 81.8 81.8 88.6 86.9 82.2 32.8

No Impact % 3.4 0.0 0.0 0.0 0.0 0.0 0.0

Design line 3

Net Cost (%) 14.5 13.9 12.0 4.0 5.3 4.0 29.9

Net Benefit (%) 84.2 84.8 86.9 95.9 94.7 96.0 70.1

No Impact (%) 1.3 1.3 1.2 0.0 0.0 0.0 0.0

Design line 4

Net Cost (%) 6.6 6.6 6.6 7.6 2.5 2.5 5.9

Net Benefit (%) 92.8 92.8 92.8 91.8 96.9 96.9 94.1

No Impact (%) 0.6 0.6 0.6 0.6 0.6 0.6 0.0

Design line 5

Net Cost (%) 30.5 30.5 19.9 9.8 14.8 9.1 41.9

Net Benefit (%) 69.1 69.1 80.0 90.2 85.2 91.0 58.1

No Impact (%) 0.4 0.4 0.1 0.0 0.0 0.0 0.0

First, DOE considered TSL 7, the most efficient level (max tech), which would 

save an estimated total of 7.01 quads of energy, an amount DOE considers significant. 

TSL 7 has an estimated NPV of customer benefit of −$12.97 billion using a 7 percent 

discount rate, and −$8.50 billion using a 3 percent discount rate. 
318

The cumulative emissions reductions at TSL 7 are 501.0 million metric tons of 

CO2, 421.9 thousand tons of NOX, 318.0 thousand tons of SO2, and 1.1 tons of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 7 ranges from $1,515

million to $25,144 million. 

At TSL 7, the average LCC impact ranges from −$579 for design line 2 to $4,619

for design line 5. The median PBP ranges from 31.6 years for design line 2 to 10.2 years 

for design line 4. The share of customers experiencing a net LCC benefit ranges from 

32.8 percent for design line 2 to 70.1 percent for design line 3.

At TSL 7, the projected change in INPV ranges from a decrease of $394 million 

to an increase of $0.5 million. If the decrease of $394 million were to occur, TSL 7 could 

result in a net loss of 68.4 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 7, there is a risk of very large negative impacts on 

manufacturers due to the substantial capital and engineering costs they would incur and 

the market disruption associated with the likely transition to a market entirely served by 

amorphous steel. Additionally, if manufacturers’ concerns about their customers 

rebuilding rather than replacing transformers at the price points projected for TSL 7 are 

realized, new transformer sales would suffer and make it even more difficult to recoup 

investments in amorphous transformer production capacity. DOE also has concerns about 
319

the competitive impact of TSL 7 on the electrical steel industry, as only one proven 

supplier of amorphous ribbon currently serves the U.S. market. 

In view of the foregoing, DOE concludes that, at TSL 7 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive average customer LCC 

savings, generating capacity reductions, emission reductions, and the estimated monetary 

value of the emissions reductions would be outweighed by the potential multi-billion 

dollar negative net economic cost, the economic burden on customers as indicated by 

large PBPs, significant increases in installed cost, and the large percentage of customers 

who would experience LCC increases, the capital and engineering costs that could result 

in a large reduction in INPV for manufacturers, and the risk that manufacturers may not 

be able to obtain the quantities of amorphous steel required to meet standards at TSL 7. 

Consequently, DOE has concluded that TSL 7 is not economically justified. 

Next, DOE considered TSL 6, which would save an estimated total of 4.09 quads 

of energy, an amount DOE considers significant. TSL 6 has an estimated NPV of 

customer benefit of $0.74 billion using a 7 percent discount rate, and $10.27 billion using 

a 3 percent discount rate. 

The cumulative emissions reductions at TSL 6 are 321.8 million metric tons of 

CO2, 270.8 thousand tons of NOX, 203.2 thousand tons of SO2, and 0.7 ton of Hg. The 
320

estimated monetary value of the CO2 emissions reductions at TSL 6 ranges from $991

million to $16,325 million. 

At TSL 6, the average LCC impact ranges from $311 for design line 2 to $12,014

for design line 5. The median PBP ranges from 5.6 years for design line 4 to 15.5 years 

for design line 2. The share of customers experiencing a net LCC benefit ranges from 

82.2 percent for design line 2 to 96.9 percent for design line 4.

At TSL 6, the projected change in INPV ranges from a decrease of $217 million 

to a decrease of $89 million. If the decrease of $217 million were to occur, TSL 6 could 

result in a net loss of 37.7 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 6, DOE recognizes the risk of very large negative 

impacts on manufacturers due to the large capital and engineering costs and the market 

disruption associated with the likely transition to a market entirely served by amorphous 

steel. Additionally, if manufacturers’ concerns about their customers rebuilding rather 

than replacing their transformers at the price points projected for TSL 6 are realized, new 

transformer sales would suffer and make it even more difficult to recoup investments in 

amorphous transformer production capacity. 

The energy savings under TSL 6 are achievable only by using amorphous steel,

which only one supplier currently produces in any significant volume (annual production 

capacity of approximately 100,000 tons, the vast majority of which serves global 
321

demand). Thus, the current availability is far below the amount that would be required to 

meet the U.S. liquid-immersed transformer market demand of approximately 250,000 

tons. Electrical steel is a critical consideration in the manufacture of distribution 

transformers, accounting for more than 60 percent of the transformer's mass in some 

designs. DOE is concerned that the current supplier, together with others that might enter 

the market, would not be able to increase production of amorphous steel rapidly enough 

to supply the amounts that would be needed by transformer manufacturers before 2015. 

Therefore, setting a standard that requires amorphous material would expose the industry 

to enormous risk with respect to core steel supply. DOE also has concerns about the 

competitive impact of TSL 6 on the electrical steel industry. TSL 6 could jeopardize the 

ability of silicon steels to compete with amorphous metal, which risks upsetting 

competitive balance among steel suppliers and between them and their customers.

In view of the foregoing, DOE concludes that, at TSL 6 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average customer LCC savings, generating capacity reductions, emission 

reductions, and the estimated monetary value of the CO2 emissions reductions would be 

outweighed by the capital and engineering costs that could result in a large reduction in 

INPV for manufacturers, and the risk that manufacturers may not be able to obtain the 

quantities of amorphous steel required to meet standards at TSL 6. Consequently, DOE

has concluded that TSL 6 is not economically justified.
322

Next, DOE considered TSL 5, which would save an estimated total of 3.30 quads 

of energy, an amount DOE considers significant. TSL 5 has an estimated NPV of 

customer benefit of $1.60 billion using a 7 percent discount rate, and $10.19 billion using 

a 3 percent discount rate. 

The cumulative emissions reductions at TSL 5 are 273.4 million metric tons of 

CO2, 230.1 thousand tons of NOX, 172.4 thousand tons of SO2, and 0.6 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 5 ranges from $851

million to $13,960 million. 

At TSL 5, the average LCC impact ranges from $330 for design line 2 to$8,616

for design line 5. The median PBP ranges from 5.6 years for design line 4 to 13.0 years 

for design line 2. The share of customers experiencing a net LCC benefit ranges from 

85.2 percent for design line 5 to 96.9 percent for design line 4.

At TSL 5, the projected change in INPV ranges from a decrease of $193 million 

to a decrease of $101 million. If the decrease of $193 million were to occur, TSL 5 could 

result in a net loss of 33.6 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 5, DOE recognizes the risk of very large negative 

impacts on manufacturers due to the large capital and engineering costs they would incur 

and the market disruption associated with the likely transition to a market almost entirely 

served by amorphous steel. Additionally, if manufacturers’ concerns about their 
323

customers rebuilding rather than replacing transformers at the price points projected for 

TSL 5 are realized, new transformer sales would suffer and make it even more difficult to 

recoup investments in amorphous core transformer production capacity. 

Similar to TSL 6 as described above, the energy savings under TSL 5 are 

achievable only by using amorphous steel, which is currently available from only one 

supplier with significant volume and that supplier’s production capacity of 100,000 tons

is far below what would be required to meet market demand for electrical steel. DOE is 

concerned that the current supplier, together with others that might enter the market, 

would not be able to increase production of amorphous steel rapidly enough to supply the 

amounts that would be needed by transformer manufacturers before 2015. Therefore, 

setting a standard that requires amorphous material would expose the industry to 

enormous risk with respect to core steel supply. TSL 5 could jeopardize the ability of 

silicon steels to compete with amorphous metal, which risks upsetting competitive 

balance among steel suppliers and between them and their customers. 

In view of the foregoing, DOE concludes that, at TSL 5 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average customer LCC savings, generating capacity reductions, emission 

reductions, and the estimated monetary value of the CO2 emissions reductions would be 

outweighed by the capital and engineering costs that could result in a large reduction in 

INPV for manufacturers, and the risk that manufacturers may not be able to obtain the 
324

quantities of amorphous steel required to meet standards at TSL 5. Consequently, DOE 

has concluded that TSL 5 is not economically justified. 

Next, DOE considered TSL 4, which would save an estimated total of 3.31 quads 

of energy, an amount DOE considers significant. TSL 4 has an estimated NPV of 

customer benefit of $1.92 billion using a 7 percent discount rate, and $10.78 billion using 

a 3 percent discount rate. 

The cumulative emissions reductions at TSL 4 are 274.6 million metric tons of 

CO2, 231.1 thousand tons of NOX, 173.0 thousand tons of SO2, and 0.6 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 4 ranges from $855

million to $14,024 million. 

At TSL 4, the average LCC impact ranges from $343 for design line 2 to $10,382

for design line 5. The median PBP ranges from 11.1 years for design line 2 to 6.5 years 

for design line 3. The share of customers experiencing a net LCC benefit ranges from 

88.6 percent for design line 2 to 95.9 percent for design line 4.

At TSL 4, the projected change in INPV ranges from a decrease of $186 million 

to a decrease of $97 million. If the decrease of $186 million were to occur, TSL 4 could 

result in a net loss of 32.4 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 4, DOE recognizes the risk of large negative impacts 
325

on manufacturers due to the substantial capital and engineering costs they would incur. 

Additionally, if manufacturers’ concerns about their customers rebuilding rather than 

replacing transformers at the price points projected for TSL 4 are realized, new 

transformer sales would suffer and make it even more difficult to recoup investments in 

amorphous core transformer production capacity. 

DOE is also concerned that TSL 4, like the higher TSLs, will require amorphous 

steel to be competitive in many applications and at least a few design lines. As stated 

previously, the available supply of amorphous steel is well below the amount that would 

likely be required to meet the U.S. liquid-immersed distribution transformer market 

demand. DOE is concerned that the current supplier, together with others that might enter 

the market, would not be able to increase production of amorphous steel rapidly enough 

to supply the amounts that would be needed by transformer manufacturers before 2015.

Therefore, setting a standard that requires amorphous material would expose the industry 

to enormous risk with respect to core steel supply.

In addition, depending on how steel prices react to a standard, DOE believes TSL 

4 could threaten the viability of a place in the market for conventional steel. Therefore, as 

with higher TSLs, DOE has concerns about the competitive impact of TSL 4 on the 

electrical steel manufacturing industry. 
326

In view of the foregoing, DOE concludes that, at TSL 4 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average customer LCC savings, generating capacity reductions, emission 

reductions, and the estimated monetary value of the CO2 emissions reductions would be 

outweighed by the capital and engineering costs that could result in a large reduction in 

INPV for manufacturers, and the risk that manufacturers may not be able to obtain the 

quantities of amorphous steel required to meet standards at TSL 4. Consequently, DOE 

has concluded that TSL 4 is not economically justified.

Next, DOE considered TSL 3, which would save an estimated total of 1.76 quads 

of energy, an amount DOE considers significant. TSL 3 has an estimated NPV of 

customer benefit of $0.91 billion using a 7 percent discount rate, and $6.62 billion using a 

3 percent discount rate. 

The cumulative emissions reductions at TSL 3 are 156.5 million metric tons of 

CO2, 131.8 thousand tons of NOX, 98.4 thousand tons of SO2, and 0.3 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 3 ranges from $494

million to $8,060 million.

At TSL 3, the average LCC impact ranges from $153 for design line 1 to $6,852

for design line 5. The median PBP ranges from 24.7 years for design line 1 to 5.8 years 
327

for design line 3. The share of customers experiencing a net LCC benefit ranges from 

55.6 percent for design line 1 to 92.8 percent for design line 4.

At TSL 3, the projected change in INPV ranges from a decrease of $113 million 

to a decrease of $69 million. If the decrease of $113 million were to occur, TSL 3 could 

result in a net loss of 19.7 percent in INPV to manufacturers. At TSL 3, DOE recognizes 

the risk of large negative impacts on manufacturers due to the large capital and 

engineering costs they would incur.

Although the industry can manufacture liquid-immersed distribution transformers 

at TSL 3 from M3 or lower grade steels, the positive LCC and national impacts results 

described above are based on lowest first-cost designs, which include amorphous steel for 

all the design lines analyzed. As is the case with higher TSLs, DOE is concerned that the 

current supplier, together with others that might enter the market, would not be able to 

increase production of amorphous steel rapidly enough to supply the amounts that would 

be needed by transformer manufacturers before 2015. If manufacturers were to meet 

standards at TSL 3 using M3 or lower grade steels, DOE’s analysis shows that the LCC 

impacts are negative.71

In view of the foregoing, DOE concludes that, at TSL 3 for liquid-immersed

distribution transformers, the benefits of energy savings, positive NPV of customer 

 71 DOE conducted a sensitivity analysis where LCC results are presented for liquid-immersed transformers 

without amorphous steel; see appendix 8-C in the final rule TSD.
328

benefit, positive average customer LCC savings, generating capacity reductions, emission 

reductions, and the estimated monetary value of the CO2 emissions reductions would be 

outweighed by the capital and engineering costs that could result in a large reduction in 

INPV for manufacturers, and the risk that manufacturers may not be able to obtain the 

quantities of amorphous steel required to meet standards at TSL 3 in a cost-effective 

manner. Consequently, DOE has concluded that TSL 3 is not economically justified.

Next, DOE considered TSL 2, which would save an estimated total of 1.56 quads 

of energy, an amount DOE considers significant. TSL 2 has an estimated NPV of 

customer benefit of $0.69 billion using a 7-percent discount rate, and $4.82 billion using 

a 3-percent discount rate. 

The cumulative emissions reductions at TSL 2 are 143.1 million metric tons of 

CO2, 120.6 thousand tons of NOX, 90.0 thousand tons of SO2, and 0.3 ton of Hg. The 

estimated monetary value of the CO2 emissions reduction at TSL 2 ranges from $454

million to $7,390 million. 

At TSL 2, the average LCC impact ranges from $153 for design line 1 to $3,668

for design line 5. The median PBP ranges from 24.7 years for design line 1 to 6.5 years 

for design line 5. The share of customers experiencing a net LCC benefit ranges from 

55.6 percent for design line 1 to 92.8 percent for design line 4.
329

At TSL 2, the projected change in INPV ranges from a decrease of $110 million 

to a decrease of $67 million. If the decrease of $110 million were to occur, TSL 2 could 

result in a net loss of 19 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 2, DOE recognizes the risk of negative impacts on 

manufacturers due to the significant capital and engineering costs they would incur.

Although the industry can manufacture liquid-immersed transformers at TSL 2 

from M3 or lower grade steels, the positive LCC and national impacts results described 

above are based on lowest first-cost designs, which include amorphous steel for design 

line 2. This design line represents approximately 44 percent of all liquid-immersed 

transformer shipments by MVA. Amorphous steel is currently available in significant 

volume from one supplier whose annual production capacity is below the amount that 

would be required to meet the demand for design line 2 under TSL 2. DOE is concerned 

that the current supplier, together with others that might enter the market, would not be 

able to increase production of amorphous steel rapidly enough to supply the amounts that 

would be needed by transformer manufacturers before 2015. If manufacturers were to 

meet standards at TSL 2 using M3 or lower grade steels, DOE’s analysis shows that the 

LCC impacts would be negative.

In view of the foregoing, DOE concludes that, at TSL 2 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average customer LCC savings, generating capacity reductions, emission 
330

reductions, and the estimated monetary value of the CO2 emissions reductions would be 

outweighed by the capital and engineering costs that could result in a reduction in INPV 

for manufacturers, and the risk that manufacturers may not be able to obtain the 

quantities of amorphous steel required to meet standards at TSL 2 in a cost-effective 

manner. Consequently, DOE has concluded that TSL 2 is not economically justified.

Next, DOE considered TSL 1, which would save an estimated total of 0.92 quad 

of energy, an amount DOE considers significant. TSL 1 has an estimated NPV of 

customer benefit of $0.58 billion using a 7-percent discount rate, and $3.12 billion using 

a 3-percent discount rate. 

The cumulative emissions reductions at TSL 1 are 82.2 million metric tons of 

CO2, 69.3 thousand tons of NOX, 52.0 thousand tons of SO2, and 0.2 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 1 ranges from $259 

million to $4,230 million. 

At TSL 1, the average LCC impact ranges from $83 for design line 2 to $3,668

for design line 5. The median PBP ranges from 17.7 years for design line 1 to 5.9 years 

for design line 2. The share of customers experiencing a net LCC benefit ranges from 

55.2 percent for design line 2 to 92.8 percent for design line 4.
331

At TSL 1, the projected change in INPV ranges from a decrease of $48 million to 

a decrease of $24 million. If the decrease of $48 million were to occur, TSL 1 could 

result in a net loss of 8.4 percent in INPV to manufacturers of liquid-immersed 

distribution transformers.

The energy savings under TSL 1 are achievable without using amorphous steel. 

Therefore, the aforementioned risks that manufacturers may not be able to obtain the 

quantities of amorphous steel required to meet standards are not present under TSL 1.

After considering the analysis and weighing the benefits and the burdens, DOE 

has concluded that at TSL 1 for liquid-immersed distribution transformers, the benefits of 

energy savings, positive NPV of customer benefit, positive average customer LCC 

savings, generating capacity reductions, emission reductions, and the estimated monetary 

value of the emissions reductions would outweigh the potential reduction in INPV for 

manufacturers. 

In view of the foregoing, DOE has concluded that TSL 1 would save a significant 

amount of energy and is technologically feasible and economically justified. For the 

above considerations, DOE today adopts the energy conservation standards for liquidimmersed distribution transformers at TSL 1. Table V.40 presents the energy 

conservation standards for liquid-immersed distribution transformers.
332

Table V.40 Energy Conservation Standards for Liquid-Immersed Distribution 

Transformers

Electrical Efficiency by kVA and Equipment Class

Equipment Class 1 Equipment Class 2

kVA % kVA %

10 98.70 15 98.65

15 98.82 30 98.83

25 98.95 45 98.92

37.5 99.05 75 99.03

50 99.11 112.5 99.11

75 99.19 150 99.16

100 99.25 225 99.23

167 99.33 300 99.27

250 99.39 500 99.35

333 99.43 750 99.40

500 99.49 1000 99.43

667 99.52 1500 99.48

833 99.55 2000 99.51

2500 99.53

2. Benefits and Burdens of Trial Standard Levels Considered for Low-Voltage DryType Distribution Transformers

Table V.41 and Table V.42 summarize the quantitative impacts estimated for each 

TSL for low-voltage dry-type distribution transformers.

Table V.41 Summary of Analytical Results for Low-Voltage Dry-Type Distribution 

Transformers: National Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6
333

National Energy 

Savings (quads) 2.28 2.43 3.05 4.39 4.48 4.94

NPV of Customer Benefits (2011$ billion)

3% discount rate 8.38 9.04 10.38 13.65 11.80 5.17

7% discount rate 2.45 2.67 2.82 3.34 2.22 -1.92

Cumulative Emissions Reduction

CO2 (million 

metric tons) 151.3 161.6 203.0 292.8 297.6 319.3

NOX (thousand 

tons) 127.6 136.4 171.3 247.0 251.0 269.3

SO2 (thousand 

tons) 110.1 117.6 147.8 213.2 216.7 232.4

Hg (tons) 0.4 0.4 0.5 0.8 0.8 0.8

Value of Emissions Reduction (2011$ million)

CO2* 450 to 

7512

480 to 

8020

603 to 

10075

870 to 

14535

884 to 

14771

949 to 

15847

NOX – 3% 

discount rate 23 to 238 25 to 254 31 to 319 45 to 460 45 to 468 49 to 502

NOX – 7% 

discount rate 9 to 92 10 to 99 12 to 124 17 to 179 18 to 182 19 to 195

* Range of the economic value of CO2 reductions is based on estimates of the global benefit of reduced 

CO2 emissions.
334

Table V.42 Summary of Analytical Results for Low-Voltage Dry-Type Distribution 

Transformers: Manufacturer and Consumer Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6

Manufacturer Impacts

Industry NPV (2011$ 

million)

230 to 

252

227 to 

249

219 to 

266

199 to 

280

191 to 

299

159 to 

357

Industry NPV (% change) (3.4) to 

6.2

(4.7) to 

5.0

(7.8) to 

11.8

(16.4) to 

17.8

(19.7) to 

25.7

(33.1) to 

50.1

Consumer Mean LCC Savings (2011$)

Design line 6 0 0 325 148 148 -992

Design line 7 1526 1678 1838 2280 2280 212

Design line 8 2588 2588 2724 4261 -2938 -2938

Consumer Median PBP (years)

Design line 6 0.0 0.0 12.4 15.7 15.7 31.7

Design line 7 3.9 3.6 4.1 6.3 6.3 16.8

Design line 8 7.7 7.7 11.3 10.1 22.5 22.5

Distribution of Consumer LCC Impacts

Design line 6

Net Cost (%) 0.0 0.0 16.5 37.8 37.8 96.6

Net Benefit (%) 0.0 0.0 83.5 62.2 62.2 3.4

No Impact (%) 100.0 100.0 0.0 0.0 0.0 0.0

Design line 7

Net Cost (%) 1.5 1.3 1.7 3.3 3.3 45.6

Net Benefit (%) 98.4 98.7 98.3 96.7 96.7 54.4

No Impact (%) 0.1 0.1 0.0 0.0 0.0 0.0

Design line 8

Net Cost (%) 4.7 4.7 13.3 9.0 79.3 79.3

Net Benefit (%) 95.3 95.3 86.7 91.0 20.7 20.7

No Impact (%) 0.0 0.0 0.0 0.0 0.0 0.0

First, DOE considered TSL 6, the most efficient level (max tech), which would 

save an estimated total of 4.94 quads of energy, an amount DOE considers significant. 

TSL 6 has an estimated NPV of customer benefit of -$1.92 billion using a 7-percent 

discount rate, and $5.17 billion using a 3-percent discount rate. 
335

The cumulative emissions reductions at TSL 6 are 319.3 million metric tons of 

CO2, 269.3 thousand tons of NOX, 232.4 thousand tons of SO2, and 0.8 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 6 ranges from $949

million to $15,847 million. 

At TSL 6, the average LCC impact ranges from -$2,938 for design line 8 to $212

for design line 7. The median PBP ranges from 31.7 years for design line 6 to 16.8 years 

for design line 7. The share of customers experiencing a net LCC benefit ranges from 3.4

percent for design line 6 to 54.4 percent for design line 7.

At TSL 6, the projected change in INPV ranges from a decrease of $79 million to 

an increase of $119 million. If the decrease of $79 million occurs, TSL 6 could result in a 

net loss of 33.1 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 6, DOE recognizes the risk of very large negative impacts on the 

industry. TSL 6 would require manufacturers to scrap nearly all production assets and 

create transformer designs with which most, if not all, have no experience. DOE is 

concerned, in particular, about large impacts on small businesses, which may not be able 

to procure sufficient volume of amorphous steel at competitive prices, if at all. 

In view of the foregoing, DOE concludes that, at TSL 6 for low-voltage dry-type

distribution transformers, the benefits of energy savings, generating capacity reductions, 
336

emission reductions, and the estimated monetary value of the CO2 emissions reductions 

would be outweighed by the economic burden on customers (as indicated by negative 

average LCC savings, large PBPs, and the large percentage of customers who would 

experience LCC increases at design line 6 and design line 8), the potential for very large 

negative impacts on the manufacturers, and the potential burden on small manufacturers. 

Consequently, DOE has concluded that TSL 6 is not economically justified.

Next, DOE considered TSL 5, which would save an estimated total of 4.48 quads 

of energy, an amount DOE considers significant. TSL 5 has an estimated NPV of 

customer benefit of $2.22 billion using a 7 percent discount rate, and $11.80 billion using 

a 3 percent discount rate. 

The cumulative emissions reductions at TSL 5 are 297.6 million metric tons of 

CO2, 251.0 thousand tons of NOX, 216.7 thousand tons of SO2, and 0.8 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 5 ranges from $884

million to $14,771 million. 

At TSL 5, the average LCC impact ranges from -$2,938 for design line 8 to 

$2,280 for design line 7. The median PBP ranges from 22.5 years for design line 8 to 6.3

years for design line 7. The share of customers experiencing a net LCC benefit ranges 

from 20.7 percent for design line 8 to 96.7 percent for design line 7.
337

At TSL 5, the projected change in INPV ranges from a decrease of $47 million to 

an increase of $61 million. If the decrease of $47 million occurs, TSL 5 could result in a 

net loss of 19.7 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 5, DOE recognizes the risk of very large negative impacts on the 

industry. TSL 5 would require manufacturers to scrap nearly all production assets and 

create transformer designs with which most, if not all, have no experience. DOE is 

concerned, in particular, about large impacts on small businesses, which may not be able 

to procure sufficient volume of amorphous steel at competitive prices, if at all.

In view of the foregoing, DOE concludes that, at TSL 5 for low-voltage dry-type

distribution transformers, the benefits of energy savings, generating capacity reductions, 

emission reductions, and the estimated monetary value of the CO2 emissions reductions 

would be outweighed by the economic burden on customers at design line 8 (as indicated 

by negative average LCC savings, large PBPs, and the large percentage of customers who 

would experience LCC increases), the potential for very large negative impacts on the 

manufacturers, and the potential burden on small manufacturers. Consequently, DOE has 

concluded that TSL 5 is not economically justified.

Next, DOE considered TSL 4, which would save an estimated total of 4.39 quads 

of energy, an amount DOE considers significant. TSL 4 has an estimated NPV of 

customer benefit of $3.34 billion using a 7-percent discount rate, and $13.65 billion using 

a 3-percent discount rate. 
338

The cumulative emissions reductions at TSL 4 are 292.8 million metric tons of 

CO2, 247.0 thousand tons of NOX, 213.2 thousand tons of SO2, and 0.8 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 4 ranges from $870

million to $14,535 million.

At TSL 4, the average LCC impact ranges from $148 for design line 6 to $4,261

for design line 8. The median PBP ranges from 15.7 years for design line 6 to 6.3 years 

for design line 7. The share of customers experiencing a net LCC benefit ranges from 

62.2 percent for design line 6 to 96.7 percent for design line 7.

At TSL 4, the projected change in INPV ranges from a decrease of $39 million to 

an increase of $42 million. If the decrease of $39 million occurs, TSL 4 could result in a 

net loss of 16.4 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 4, DOE recognizes the risk of very large negative impacts on the 

industry. As with the higher TSLs, TSL 4 would require manufacturers to scrap nearly all 

production assets and create transformer designs with which most, if not all, have no 

experience. DOE is concerned, in particular, about large impacts on small businesses, 

which may not be able to procure sufficient volume of amorphous steel at competitive 

prices, if at all.
339

Additionally, TSL 4 requires significant investment in advanced core construction 

equipment such are step-lap mitering machines or wound core production lines, as butt 

lap designs, even with high-grade designs, are unlikely to comply. Given their more 

limited engineering resources and capital, small businesses may find it difficult to make 

these designs at competitive prices and may have to exit the market. At the same time, 

however, those small manufacturers may be able to source their cores—and many are 

doing so to a significant extent currently—which could mitigate impacts.

In view of the forgoing, DOE concludes that, at TSL 4 for low-voltage dry-type

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average LCC savings, generating capacity reductions, emission 

reductions, and the estimated monetary value of the CO2 emissions reductions would be 

outweighed by the potential for very large negative impacts on the manufacturers, and the 

potential burden on small manufacturers. Consequently, DOE has concluded that TSL 4 

is not economically justified.

Next, DOE considered TSL 3, which would save an estimated total of 3.05 quads 

of energy, an amount DOE considers significant. TSL 3 has an estimated NPV of 

customer benefit of $2.82 billion using a 7-percent discount rate, and $10.38 billion using 

a 3-percent discount rate. 
340

The cumulative emissions reductions at TSL 3 are 203.0 million metric tons of 

CO2, 171.3 thousand tons of NOX, 147.8 thousand tons of SO2, and 0.5 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 3 ranges from $603 

million to $10,075 million.

At TSL 3, the average LCC impact ranges from $325 for design line 6 to $2,724 

for design line 8. The median PBP ranges from 12.4 years for design line 6 to 4.1 years 

for design line 7. The share of customers experiencing a net LCC benefit ranges from 

83.5 percent for design line 6 to 98.3 percent for design line 7.

At TSL 3, the projected change in INPV ranges from a decrease of $19 million to 

an increase of $28 million. If the decrease of $19 million occurs, TSL 3 could result in a 

net loss of 7.8 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 3, DOE recognizes the risk of negative impacts on the industry, 

particularly the small manufacturers. While TSL 3 could likely be met with M4 steel, 

DOE’s analysis shows that this design option is at the edge of its technical feasibility at 

the efficiency levels comprised by TSL 3. Although these levels could be met with M3 or 

better steels, DOE is concerned that a significant number of small manufacturers would 

be unable to acquire these steels in sufficient supply and quality to compete. 

Additionally, TSL 3 requires significant investment in advanced core construction 

equipment such are step-lap mitering machines or wound core production lines, as butt 
341

lap designs, even with high-grade designs, are unlikely to comply. Given their more 

limited engineering resources and capital, small businesses may find it difficult to make 

these designs at competitive prices and may have to exit the market. At the same time, 

however, those small manufacturers may be able to source their cores—and many are 

doing so to a significant extent currently—which could mitigate impacts. 

In view of the foregoing, DOE concludes that, at TSL 3 for low-voltage dry-type

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average LCC savings, generating capacity reductions, emission 

reductions, and the estimated monetary value of the CO2 emissions reductions would be 

outweighed by the risk of negative impacts on the industry, particularly the small 

manufacturers. Consequently, DOE has concluded that TSL 3 is not economically 

justified.

Next, DOE considered TSL 2, which would save an estimated total of 2.43 quads 

of energy, an amount DOE considers significant. TSL 2 has an estimated NPV of 

customer benefit of $2.67 billion using a 7-percent discount rate, and $9.04 billion using 

a 3-percent discount rate. 

The cumulative emissions reductions at TSL 2 are 161.6 million metric tons of 

CO2, 136.4 thousand tons of NOX, 117.6 thousand tons of SO2, and 0.4 ton of Hg. The 
342

estimated monetary value of the CO2 emissions reductions at TSL 2 ranges from $480 

million to $8,020 million. 

At TSL 2, the average LCC impact ranges from $0 for design line 6 to $2,588 for 

design line 8. The median PBP ranges from 7.7 years for design line 8 to 0 years for 

design line 6. The share of customers experiencing a net LCC benefit ranges from 0 

percent for design line 6 to 98.7 percent for design line 7.

At TSL 2, the projected change in INPV ranges from a decrease of $11 million to an 

increase of $12 million. If the decrease of $11 million occurs, TSL 2 could result in a net 

loss of 4.7 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 2, manufacturers have the option of continuing to produce 

transformers using butt-lap technology, investing in mitering equipment, or sourcing their 

cores. Furthermore, since TSL 2 represents EL 3 for DL 7 and EL 2 for DL 8 (and 

baseline for DL 6), manufacturers may benefit from being able to standardize to NEMA 

Premium® levels for low-voltage dry-type distribution transformers.

After considering the analysis and weighing the benefits and the burdens, DOE 

has concluded that at TSL 2 for low-voltage dry-type distribution transformers, the 

benefits of energy savings, NPV of customer benefit, positive customer LCC impacts, 

emissions reductions and the estimated monetary value of the emissions reductions would 

outweigh the risk of small negative impacts on the manufacturers. In particular, DOE has 
343

concluded that TSL 2 would save a significant amount of energy and is technologically 

feasible and economically justified. For the reasons given above, DOE today adopts the 

energy conservation standards for low-voltage dry-type distribution transformers at TSL 

2. Table V.43 presents the energy conservation standards for low-voltage dry-type

distribution transformers.

Table V.43 Energy Conservation Standards for Low-Voltage Dry-Type Distribution 

Transformers

Electrical Efficiency by kVA and Equipment Class

Equipment Class 3 Equipment Class 4

kVA % kVA %

15 97.70 15 97.89

25 98.00 30 98.23

37.5 98.20 45 98.40

50 98.30 75 98.60

75 98.50 112.5 98.74

100 98.60 150 98.83

167 98.70 225 98.94

250 98.80 300 99.02

333 98.90 500 99.14

750 99.23

1000 99.28

3. Benefits and Burdens of Trial Standard Levels Considered for Medium-Voltage 

Dry-Type Distribution Transformers 

Table V.44 and Table V.45 summarize the quantitative impacts estimated for each 

TSL for medium-voltage dry-type distribution transformers.
344

Table V.44 Summary of Analytical Results for Medium-Voltage Dry-Type

Distribution Transformers: National Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

National Energy Savings (quads) 0.15 0.29 0.53 0.53 0.84

NPV of Consumer Benefits (2011$ billion

3% discount rate

)

0.49 0.79 1.12 1.12 -0.20

7% discount rate 0.13 0.17 0.12 0.12 -0.89

Cumulative Emissions Reduction

CO2 (million metric tons) 11.2 20.9 40.7 40.7 61.3

NOX (thousand tons) 9.34 17.7 34.2 34.2 51.5

SO2 (thousand tons) 7.1 13.3 25.7 25.7 38.7

Hg (tons) 0.02 0.04 0.10 0.10 0.14

Value of Emissions Reduction (2011$ million)

CO2* 35 to 

571

65 to 

1065

126 to 

2067

126 to 

2067

190 to 

3117

NOX – 3% discount rate 2 to 18 3 to 34 6 to 67 6 to 67 10 to 100

NOX – 7% discount rate 1 to 7 1 to 14 3 to 27 3 to 27 4 to 41

* Range of the economic value of CO2 reductions is based on estimates of the global benefit of 

reduced CO2 emissions.

Table V.45 Summary of Analytical Results for Medium-Voltage Dry-Type

Distribution Transformers: Manufacturer and Consumer Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

Manufacturer Impacts

Industry NPV (2011$ million) 67 to 69 66 to 72 58 to 74 58 to 74 35 to 82

Industry NPV (% change) (2.0) to 

1.0

(4.2) to 

4.4

(15.6) to 

8.3

(15.5) to 

8.2

(49.7) to 

18.7

Consumer Mean LCC Savings (2011$)

Design line 9 787 787 1514 1514 -299

Design line 10 4604 4455 4455 4455 -14727

Design line 11 996 996 1849 1849 -4166

Design line 12 4537 6790 8594 8594 -14496

Design line 13A -27 -27 311 -1019 -12053

Design line 13B 2494 4346 4346 4346 -6823

Consumer Median PBP (years)

Design line 9 2.6 2.6 6.1 6.1 18.5

Design line 10 1.1 8.6 8.6 8.6 27.5
345

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

Design line 11 10.6 10.6 13.6 13.6 24.1

Design line 12 6.0 8.5 12.3 12.3 24.7

Design line 13A 16.1 16.1 16.2 20 35.3

Design line 13B 4.5 12.2 12.2 12.2 20.6

Distribution of Consumer LCC Impacts

Design line 9

Net Cost (%) 3.6 3.6 5.9 5.9 57.4

Net Benefit (%) 83.2 83.2 94.1 94.1 42.6

No Impact (%) 13.3 13.3 0.0 0.0 0.0

Design line 10

Net Cost (%) 3.6 3.6 5.9 5.9 57.4

Net Benefit (%) 83.2 83.2 94.1 94.1 42.6

No Impact (%) 13.3 13.3 0.0 0.0 0.0

Design line 11

Net Cost (%) 21.9 21.9 25.9 25.9 82.7

Net Benefit (%) 78.1 78.1 74.1 74.1 17.4

No Impact (%) 0.0 0.0 0.0 0.0 0.0

Design line 12

Net Cost (%) 7.1 7.6 17.1 17.1 85.4

Net Benefit (%) 92.9 92.4 82.9 82.9 14.6

No Impact (%) 0.0 0.0 0.0 0.0 0.0

Design line 13A

Net Cost (%) 54.2 54.2 45.5 66.3 98.5

Net Benefit (%) 45.8 45.8 54.5 33.7 1.5

No Impact (%) 0.0 0.0 0.0 0.0 0.0

Design line 13B

Net Cost (%) 30.5 27.3 27.3 27.3 70.4

Net Benefit (%) 69.3 72.7 72.7 72.7 29.6

No Impact (%) 0.2 0.0 0.0 0.0 0.0

First, DOE considered TSL 5, the most efficient level (max tech), which would 

save an estimated total of 0.84 quad of energy, an amount DOE considers significant. 
346

TSL 5 has an estimated NPV of customer benefit of -$0.89 billion using a 7-percent 

discount rate, and -$0.20 billion using a 3-percent discount rate.

The cumulative emissions reductions at TSL 5 are 61.3 million metric tons of 

CO2, 51.5 thousand tons of NOX, 38.7 thousand tons of SO2, and 0.14 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 5 ranges from $190

million to $3,117 million. 

At TSL 5, the average LCC impact ranges from -$14,727 for design line 10 to -

299 for design line 9. The median PBP ranges from 35.3 years for design line 13A to 18.5

years for design line 9. The share of customers experiencing a net LCC benefit ranges 

from 1.5 percent for design line 13A to 42.6 percent for design line 9.

At TSL 5, the projected change in INPV ranges from a decrease of $34 million to 

an increase of $13 million. If the decrease of $34 million occurs, TSL 5 could result in a 

net loss of 49.7 percent in INPV to manufacturers of medium-voltage dry-type

distribution transformers. At TSL 5, DOE recognizes the risk of very large negative 

impacts on industry because they would likely be forced to move to amorphous core steel

technology, with which there is no experience in this market.72

 72 See section IV.I.5.a for further detail.
347

In view of the foregoing, DOE concludes that, at TSL 5 for medium-voltage drytype distribution transformers, the benefits of energy savings, generating capacity 

reductions, emission reductions, and the estimated monetary value of the emissions 

reductions would be outweighed by the negative NPV of customer benefit, the economic 

burden on customers (as indicated by negative average LCC savings, large PBPs, and the 

large percentage of customers who would experience LCC increases), and the risk of 

very large negative impacts on the manufacturers. Consequently, DOE has concluded that 

TSL 5 is not economically justified.

Next, DOE considered TSL 4, which would save an estimated total of 0.53 quad 

of energy, an amount DOE considers significant. TSL 4 has an estimated NPV of 

customer benefit of $0.12 billion using a 7-percent discount rate, and $1.12 billion using 

a 3-percent discount rate.

The cumulative emissions reductions at TSL 4 are 40.7 million metric tons of 

CO2, 34.2 thousand tons of NOX, 25.7 thousand tons of SO2, and 0.1 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 4 ranges from $126 

million to $2,067 million.

At TSL 4, the average LCC impact ranges from −$1019 for design line 13A to 

$8,594 for design line 12. The median PBP ranges from 20.0 years for design line 13B to 
348

6.1 years for design line 9. The share of customers experiencing a net LCC benefit ranges 

from 33.7 percent for design line 13A to 94.1 percent for design line 9.

At TSL 4, the projected change in INPV ranges from a decrease of $11 million to 

an increase of $6 million. If the decrease of $11 million occurs, TSL 4 could result in a 

net loss of 15.5 percent in INPV to manufacturers of medium-voltage dry-type

distribution transformers. At TSL 4, DOE recognizes the risk of very large negative 

impacts on most manufacturers in the industry who have little experience with the steels 

that would be required. Small businesses, in particular, with limited engineering 

resources, may not be able to convert their lines to employ thinner steels and may be 

disadvantaged with respect to access to key materials, including Hi-B steels.

In view of the foregoing, DOE concludes that, at TSL 4 for medium-voltage drytype distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive impacts on consumers (as indicated by positive average LCC savings, 

favorable PBPs, and the large percentage of customers who would experience LCC 

benefits), emission reductions, and the estimated monetary value of the emissions 

reductions would be outweighed by the risk of very large negative impacts on the 

manufacturers, particularly small businesses. Consequently, DOE has concluded that TSL 

4 is not economically justified.
349

Next, DOE considered TSL 3, which would save an estimated total of 0.53 quad 

of energy, an amount DOE considers significant. TSL 3 has an estimated NPV of 

customer benefit of $0.12 billion using a 7-percent discount rate, and $1.12 billion using 

a 3-percent discount rate.

The cumulative emissions reductions at TSL 3 are 40.7 million metric tons of 

CO2, 34.2 thousand tons of NOX, 25.7 thousand tons of SO2, and 0.1 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 3 ranges from $126

million to $2,067 million.

At TSL 3, the average LCC impact ranges from $311 for design line 13A to 

$8594 for design line 12. The median PBP ranges from 16.2 years for design line 13A to 

6.1 years for design line 9. The share of customers experiencing a net LCC benefit ranges 

from 54.5 percent for design line 13A to 94.1 percent for design line 9.

At TSL 3, the projected change in INPV ranges from a decrease of $11 million to 

an increase of $6 million. If the decrease of $11 million occurs, TSL 3 could result in a 

net loss of 15.6 percent in INPV to manufacturers of medium-voltage dry-type

transformers. At TSL 3, DOE recognizes the risk of large negative impacts on most 

manufacturers in the industry who have little experience with the steels that would be 

required. As with TSL 4, small businesses, in particular, with limited engineering 
350

resources, may not be able to convert their lines to employ thinner steels and may be 

disadvantaged with respect to access to key materials, including Hi-B steels.

In view of the foregoing, DOE concludes that, at TSL 3 for medium-voltage drytype distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive impacts on consumers (as indicated by positive average LCC savings, 

favorable PBPs, and the large percentage of customers who would experience LCC 

benefits), emission reductions, and the estimated monetary value of the emissions 

reductions would be outweighed by the risk of large negative impacts on the 

manufacturers, particularly small businesses. Consequently, DOE has concluded that TSL 

3 is not economically justified.

Next, DOE considered TSL 2, which would save an estimated total of 0.29 quads 

of energy, an amount DOE considers significant. TSL 2 has an estimated NPV of 

customer benefit of $0.17 billion using a 7-percent discount rate, and $0.79 billion using 

a 3-percent discount rate.

The cumulative emissions reductions at TSL 2 are 20.9 million metric tons of 

CO2, 17.7 thousand tons of NOX, 13.3 thousand tons of SO2, and 0.04 ton of Hg. The 

estimated monetary value of the CO2 emissions reductions at TSL 2 ranges from $65

million to $1,065 million.
351

At TSL 2, the average LCC impact ranges from $−27 for design line 13A to 

$6,790 for design line 12. The median PBP ranges from 16.1 years for design line 13A to 

2.6 years for design line 9. The share of customers experiencing a net LCC benefit ranges 

from 45.8 percent for design line 13A to 92.4 percent for design line 12.

At TSL 2, the projected change in INPV ranges from a decrease of $3 million to 

an increase of $3 million. If the decrease of $3 million occurs, TSL 2 could result in a net 

loss of 4.2 percent in INPV to manufacturers of medium-voltage dry-type distribution 

transformers. At TSL 2, DOE recognizes the risk of small negative impacts if 

manufacturers are unable to recoup investments made to meet the standard.

After considering the analysis and weighing the benefits and the burdens, DOE 

has concluded that at TSL 2 for medium-voltage dry-type distribution transformers, the 

benefits of energy savings, positive NPV of customer benefit, positive impacts on 

consumers (as indicated by positive average LCC savings for five of the six design lines, 

favorable PBPs, and the large percentage of customers who would experience LCC 

benefits), emission reductions, and the estimated monetary value of the emissions 

reductions would outweigh the risk of small negative impacts if manufacturers are unable 

to recoup investments made to meet the standard. In particular, DOE has concluded that 

TSL 2 would save a significant amount of energy and is technologically feasible and 

economically justified. In addition, DOE notes that TSL 2 corresponds to the standards 

that were agreed to by the DOE Efficiency and Renewables Advisory Committee 
352

(ERAC) subcommittee, as described in section II.B.2. Based on the above considerations, 

DOE today adopts the energy conservation standards for medium-voltage dry-type

distribution transformers at TSL 2. Table V.46 presents the energy conservation 

standards for medium-voltage dry-type distribution transformers.

Table V.46 Energy Conservation Standards for Medium-Voltage Dry-Type

Distribution Transformers

Electrical Efficiency by kVA and Equipment Class

Equipment 

Class 5

Equipment 

Class 6

Equipment 

Class 7

Equipment 

Class 8

Equipment 

Class 9

Equipment 

Class 10

kVA % kVA % kVA % kVA % kVA % kVA %

15 98.10 15 97.50 15 97.86 15 97.18

25 98.33 30 97.90 25 98.12 30 97.63

37.5 98.49 45 98.10 37.5 98.30 45 97.86

50 98.60 75 98.33 50 98.42 75 98.13

75 98.73 112.5 98.52 75 98.57 112.5 98.36 75 98.53

100 98.82 150 98.65 100 98.67 150 98.51 100 98.63

167 98.96 225 98.82 167 98.83 225 98.69 167 98.80 225 98.57

250 99.07 300 98.93 250 98.95 300 98.81 250 98.91 300 98.69

333 99.14 500 99.09 333 99.03 500 98.99 333 98.99 500 98.89

500 99.22 750 99.21 500 99.12 750 99.12 500 99.09 750 99.02

667 99.27 1000 99.28 667 99.18 1000 99.20 667 99.15 1000 99.11

833 99.31 1500 99.37 833 99.23 1500 99.30 833 99.20 1500 99.21

2000 99.43 2000 99.36 2000 99.28

2500 99.47 2500 99.41 2500 99.33

4. Summary of Benefits and Costs (Annualized) of Today’s Standards

The benefits and costs of today’s standards can also be expressed in terms of 

annualized values. The annualized monetary values are the sum of: (1) the annualized 

national economic value of the benefits from operating products that meet today’s

standards (consisting primarily of operating cost savings from using less energy, minus 
353

increases in equipment purchase costs, which is another way of representing customer 

NPV); and (2) the monetary value of the benefits of emission reductions, including CO2

emission reductions.73 The value of the CO2 reductions is calculated using a range of 

values per metric ton of CO2 developed by a recent interagency process. 

Although combining the values of operating savings and CO2 reductions provides 

a useful perspective, two issues should be considered. First, the national operating 

savings are domestic U.S. customer monetary savings that occur as a result of market 

transactions while the value of CO2 reductions is based on a global value. Second, the 

assessments of operating cost savings and SCC are performed with different methods that 

use different time frames for analysis. The national operating cost savings is measured for 

the lifetime of products shipped in 2016–2045. The SCC values, on the other hand, 

reflect the present value of future climate-related impacts resulting from the emission of 

one metric ton of CO2 in each year. These impacts continue well beyond 2100.

Table V.47 shows the annualized values for today’s standards for distribution 

transformers. The results for the primary estimate are as follows. Using a 7-percent 

 73 DOE used a two-step calculation process to convert the time-series of costs and benefits into annualized 

values. First, DOE calculated a present value in 2012, the year used for discounting the NPV of total 

consumer costs and savings, for the time-series of costs and benefits using discount rates of 3 and 7 percent

for all costs and benefits except for the value of CO2 reductions. For the latter, DOE used a range of 

discount rates, as shown in Table V.47. From the present value, DOE then calculated the fixed annual 

payment over a 30-year period that yields the same present value. The fixed annual payment is the 

annualized value. Although DOE calculated annualized values, this does not imply that the time-series of 

cost and benefits from which the annualized values were determined would be a steady stream of payments.
354

discount rate for benefits and costs (other than CO2 reduction, for which DOE used a 3-

percent discount rate along with the SCC series corresponding to a value of $22.3/ton in 

2011), the cost of the standards in today’s rule is $266 million per year in increased 

equipment costs, while the benefits are $581 million per year in reduced equipment 

operating costs, $237 million in CO2 reductions, and $8.60 million in reduced NOX

emissions. In this case, the net benefit amounts to $561 million per year. Using a 3-

percent discount rate for all benefits and costs (and the SCC series corresponding to a 

value of $22.3/ton in 2011), the cost of the standards in today’s rule is $282 million per 

year in increased equipment costs, while the benefits are $983 million per year in reduced 

operating costs, $237 million in CO2 reductions, and $12.67 million in reduced NOX

emissions. In this case, the net benefit amounts to $950 million per year.

Table V.47 Annualized Benefits and Costs of Standards for Distribution 

Transformers Sold in 2016–2045

Discount 

Rate

%

Primary 

Estimate*

Low Net 

Benefits 

Estimate*

High Net 

Benefits 

Estimate*

Million 2011$/year

Benefits

Operating cost savings

7% 581 559 590

3% 983 930 1003

CO2 reduction monetized value 

($4.9/t case)** 5% 57.7 57.7 57.7

CO2 reduction monetized value 

($22.3/t case)** 3% 237 237 237

CO2 reduction monetized value 

($36.5/t case)** 2.5% 377 377 377

CO2 reduction monetized value 

($67.6/t case)** 3% 721 721 721

NOX reduction monetized value 7% 8.60 8.60 8.60
355

($2,591/ton)** 3% 12.67 12.67 12.67

Total benefits†

7% plus CO2 

range

648 to 1311 625 to 1288 656 to 1319

7% 827 805 836

3% plus CO2 

range

1053 to 1716 1000 to 1663 1074 to 1737

3% 1233 1179 1253

Costs

Incremental equipment costs

7% 266 300 257

3% 282 325 271

Net Benefits

Total†

7% plus CO2 

range

385381 to 

10481044

329325 to 

992988

404400 to 

10671063

7% 561 504 579

3% plus CO2 

range

771 to 1434 675 to 1338 803 to 1466

3% 950 854 982

* The Primary, Low Net Benefits, and High Net Benefits Estimates utilize forecasts of energy prices from 

the AEO 2012

** The CO2 values represent global monetized values of the SCC, in 2011$, in 2011 under several 

scenarios. The values of $4.9, $22.3, and $36.5 per metric ton are the averages of SCC distributions 

calculated using 5%, 3%, and 2.5% discount rates, respectively. The value of $67.6/t represents the 95th

percentile of the SCC distribution calculated using a 3% discount rate. The SCC time series used by DOE 

incorporate an escalation factor. The value for NOX (in 2011$) is the average of the low and high values 

used in DOE’s analysis.

reference case, Low Economic Growth case, and High Economic Growth case, respectively. 

In addition, incremental product costs reflect no change in the Primary estimate, rising product prices in the 

Low Net Benefits estimate, and declining product prices in the High Net Benefits estimate. 

† Total Benefits for both the 3% and 7% cases are derived using the series corresponding to SCC value of 

$22.3/t. In the rows labeled “7% plus CO2 range” and “3% plus CO2 range,” the operating cost and NOX

benefits are calculated using the labeled discount rate, and those values are added to the full range of CO2

values.

VI. Procedural Issues and Regulatory Review

A.

Section 1(b)(1) of Executive Order 12866, “Regulatory Planning and Review,” 58 

FR 51735 (Oct. 4, 1993), requires each agency to identify the problem that it intends to 

address, including, where applicable, the failures of private markets or public institutions 

Review Under Executive Orders 12866 and 13563

Comment [A19]: Changes recommended by 

OMB.
356

that warrant new agency action, as well as to assess the significance of that problem. The 

problems addressed by today’s standards are as follows: 

(1) There is a lack of consumer information and/or information processing capability 

about energy efficiency opportunities in the commercial equipment market.

(2) There is asymmetric information (one party to a transaction has more and better 

information than the other) and/or high transactions costs (costs of gathering 

information and effecting exchanges of goods and services).

(3) There are some external benefits resulting from improved energy efficiency of 

distribution transformers that are not captured by the users of such equipment. 

These benefits include externalities related to environmental protection and 

energy security that are not reflected in energy prices, such as reduced emissions 

of greenhouse gases.

The specific market failure that the energy conservation standard addresses for 

distribution transformers is that a substantial portion of distribution transformer 

purchasers are not evaluating the cost of transformer losses when they make distribution 

transformer purchase decisions. Consequently, distribution transformers are being 

purchased that do not provide the minimum LCC to the equipment owners.

For distribution transformers, the Institute of Electronic and Electrical Engineers 

Inc. (IEEE) has documented voluntary guidelines for the economic evaluation of 
357

distribution transformer losses, IEEE PC57.12.33/D8. These guidelines document 

economic evaluation methods for distribution transformers that are common practice in 

the utility industry. But while economic evaluation of transformer losses is common, it is 

not a universal practice. DOE collected information during the course of the previous 

energy conservation standard rulemaking to estimate the extent to which distribution 

transformer purchases are evaluated. Data received from NEMA indicated that these 

guidelines or similar criteria are applied to approximately 75 percent of liquid-immersed 

distribution transformer purchases, 50 percent of small capacity medium-voltage dry-type

transformer purchases, and 80 percent of large capacity medium-voltage dry-type

transformer purchases. Therefore, 25 percent, 50 percent, and 20 percent of such

purchases in these segments do not employ economic evaluation of transformer losses. 

These are the portions of the distribution transformer market in which there is market 

failure. Today’s energy conservation standards would eliminate from the market those 

distribution transformers designs that are purchased on a purely minimum first cost basis, 

but which would not likely be purchased by equipment buyers when the economic value 

of equipment losses are properly evaluated. 

In addition, DOE has determined that today’s regulatory action is an 

“economically significant regulatory action” under section 3(f)(1) of Executive Order 

12866. Accordingly, section 6(a)(3) of the Executive Order requires that DOE prepare a 

regulatory impact analysis (RIA) on today’s rule and that the Office of Information and 

Regulatory Affairs (OIRA) in the Office of Management and Budget (OMB) review this 
358

rule. DOE presented to OIRA for review the draft rule and other documents prepared for 

this rulemaking, including the RIA, and has included these documents in the rulemaking 

record. The assessments prepared pursuant to Executive Order 12866 can be found in the 

technical support document for this rulemaking.

DOE has also reviewed this regulation pursuant to Executive Order 13563, issued 

on January 18, 2011 (76 FR 3281, Jan. 21, 2011). EO 13563 is supplemental to and 

explicitly reaffirms the principles, structures, and definitions governing regulatory review 

established in Executive Order 12866. To the extent permitted by law, agencies are 

required by Executive Order 13563 to: (1) propose or adopt a regulation only upon a 

reasoned determination that its benefits justify its costs (recognizing that some benefits 

and costs are difficult to quantify); (2) tailor regulations to impose the least burden on 

society, consistent with obtaining regulatory objectives, taking into account, among other 

things, and to the extent practicable, the costs of cumulative regulations; (3) select, in 

choosing among alternative regulatory approaches, those approaches that maximize net 

benefits (including potential economic, environmental, public health and safety, and other 

advantages; distributive impacts; and equity); (4) to the extent feasible, specify 

performance objectives, rather than specifying the behavior or manner of compliance that 

regulated entities must adopt; and (5) identify and assess available alternatives to direct 

regulation, including providing economic incentives to encourage the desired behavior, 

such as user fees or marketable permits, or providing information upon which choices can 

be made by the public. 
359

DOE emphasizes as well that Executive Order 13563 requires agencies to use the 

best available techniques to quantify anticipated present and future benefits and costs as 

accurately as possible. In its guidance, the Office of Information and Regulatory Affairs 

has emphasized that such techniques may include identifying changing future compliance 

costs that might result from technological innovation or anticipated behavioral changes. 

For the reasons stated in the preamble, DOE believes that today’s final rule is consistent 

with these principles, including the requirement that, to the extent permitted by law, 

benefits justify costs and that net benefits are maximized.

B.

The Regulatory Flexibility Act (5 U.S.C. 601 

Review Under the Regulatory Flexibility Act

et seq.) requires preparation of an 

initial regulatory flexibility analysis (IRFA) for any rule that by law must be proposed for 

public comment, and a final regulatory flexibility analysis (FRFA) for any such rule that 

an agency adopts as a final rule, unless the agency certifies that the rule, if promulgated, 

will not have a significant economic impact on a substantial number of small entities. As 

required by Executive Order 13272, “Proper Consideration of Small Entities in Agency 

Rulemaking,” 67 FR 53461 (August 16, 2002), DOE published procedures and policies 

on February 19, 2003, to ensure that the potential impacts of its rules on small entities are 

properly considered during the rulemaking process. 68 FR 7990. DOE has made its 

procedures and policies available on the Office of the General Counsel’s website 

(http://energy.gov/gc/office-general-counsel). DOE reviewed the February 2012 NOPR 
360

and today’s final rule under the provisions of the Regulatory Flexibility Act and the 

procedures and policies published on February 19, 2003.

As presented and discussed in the following sections, the FRFA describes 

potential impacts on small manufacturers associated with the required product and capital 

conversion costs at each TSL and discusses alternatives that could minimize these 

impacts. Chapter 12 of the TSD contains more information about the impact of this 

rulemaking on manufacturers.

1. Statement of the need for, and objectives of, the rule

The reasons why DOE is establishing the standards in today’s final rule and the 

objectives of these standards are provided elsewhere in the preamble and not 

repeated here. 

2. Summary of and responses to the significant issues raised by the public comments, 

and a statement of any changes made as a result of such comments

This FRFA incorporates the IRFA and public comments received on the IRFA 

and the economic impacts of the rule. DOE provides responses to these comments in the 

discussion below on the compliance impacts of the rule and elsewhere in the preamble. 

DOE modified the standards adopted in today’s final rule in response to comments 

received, including those from small businesses, as described in the preamble.
361

3. Description and Estimated Number of Small Entities Regulated

a. Methodology for Estimating the Number of Small Entities

For manufacturers of distribution transformers, the Small Business 

Administration (SBA) has set a size threshold, which defines those entities classified as 

“small businesses” for the purposes of the statute. DOE used the SBA’s small business 

size standards to determine whether any small entities would be subject to the 

requirements of the rule. 65 FR 30836, 30848 (May 15, 2000), as amended at 65 FR 

53533, 53544 (Sept. 5, 2000) and codified at 13 CFR part 121. The size standards are 

listed by NAICS code and industry description and are available at

http://www.sba.gov/sites/default/files/files/Size_Standards_Table.pdf

. Distribution transformer manufacturing is classified under NAICS 335311, “Power, 

Distribution and Specialty Transformer Manufacturing.” The SBA sets a threshold of 750 

employees or less for an entity to be considered as a small business for this category.

In the February 2012 NOPR, DOE identified approximately 10 liquid-immersed 

distribution transformer manufacturers, 14 LVDT manufacturers, and 17 MVDT 

manufacturers of covered equipment that can be considered small businesses. 77 FR 7282 

(February 10, 2012). Of the liquid-immersed distribution transformer small business 

manufacturers, DOE was able to reach and discuss potential standards with six of the 10 

small business manufacturers. Of the LVDT manufacturers, DOE was able to contact and 

discuss potential standards with seven of the 14 small business manufacturers. Of the 

MVDT manufacturers, DOE was able to reach and discuss potential standards with five 
362

of the 17 small business manufacturers. DOE also obtained information about small 

business impacts while interviewing large manufacturers.

b. Distribution Transformer Industry Structure

Six major manufacturers supply more than 80 percent of the market for liquidimmersed transformers. None of the major manufacturers of distribution transformers

covered in this rulemaking are considered to be small businesses. The vast majority of 

shipments are manufactured domestically. Electric utilities compose the customer base 

and typically buy on first-cost. Many small manufacturers position themselves towards 

the higher end of the market or in particular product niches, such as network transformers 

or harmonic mitigating transformers, but, in general, competition is based on price after a 

given unit’s specifications are prescribed by a customer.

Liquid Immersed.

Four major manufacturers supply more than 80 percent of the market for lowvoltage dry-type transformers. None of the major manufacturers of LVDT distribution 

transformers covered in this rulemaking are small businesses. The customer base rarely 

purchases on efficiency and is very first-cost conscious, which, in turn, places a premium 

on economies of scale in manufacturing. DOE estimates approximately 80 percent of the 

market is served by imports, mostly from Canada and Mexico. Many of the small 

businesses that compete in the low-voltage dry-type market produce specialized 

Low-Voltage Dry-Type. 
363

transformers that are not covered under standards. Roughly 50 percent of the market by 

revenue is not covered under DOE standards. This market is much more fragmented than 

the one serving DOE-covered LVDT transformers. 

In the DOE-covered LVDT market, low-volume manufacturers typically do not 

compete directly with large manufacturers using business models similar to those of their 

bigger rivals because scale disadvantages in purchasing and production are usually too 

great a barrier in this portion of the market. The exceptions to this rule are those 

companies that also compete in the medium-voltage market and, to some extent, are able 

to leverage that experience and production economies. More typically, low-volume 

manufacturers focus their operations on one or two parts of the value chain—rather than 

all of it—and focus on market segments outside of the high-volume baseline efficiency 

market.

In terms of operations, some small firms focus on the engineering and design of 

transformers and source the production of the cores or even the whole transformer, while 

other small firms focus on just production and rebrand for companies that offer broader 

solutions through their own sales and distribution networks. 

In terms of market focus, many small firms compete entirely in distribution 

transformer markets that are not covered by statute. DOE did not attempt to contact 

companies operating solely in this very fragmented market. Of those that do compete in 
364

the DOE-covered market, a few small businesses reported a focus on the high-end of the 

market, often selling NEMA Premium® (equivalent to EL3, EL3, and EL2 for DL6, DL7 

and DL8, respectively) or better transformers as retrofit opportunities. Others focus on 

particular applications or niches, like data centers, and become well-versed in the unique 

needs of a particular customer base. 

The medium-voltage dry-type transformer market is relatively consolidated with 

one large company holding a substantial share of the market. Electric utilities and 

industrial users make up most of the customer base and typically buy on first-cost or 

features other than efficiency. DOE estimates that at least 75 percent of production occurs 

domestically. Several manufacturers also compete in the power transformer market. Like 

the LVDT industry, most small business manufacturers in the MVDT industry often 

produce transformers not covered under DOE standards. DOE estimates that 10 percent 

of the market is not covered under standards.

Medium-Voltage Dry-Type.

c. Comparison between Large and Small Entities

Small distribution transformer manufacturers differ from large manufacturers in 

several ways that affect the extent to which they would be impacted by the proposed 

standards. Characteristics of small manufacturers include: lower production volumes, 

fewer engineering resources, less technical expertise, lack of purchasing power for high 

performance steels, and less access to capital.
365

Lower production volumes are the root cause of most small business 

disadvantages, particularly for a small manufacturer that is vertically integrated. A lowervolume manufacturer’s conversion costs would need to be spread over fewer units than a

larger competitor. Thus, unless the small business can differentiate its product in some 

way that earns a price premium, the small business is a “price taker” and experiences a 

reduction in profit per unit relative to the large manufacturer. Therefore, because much of 

the same equipment would need to be purchased by both large and small manufacturers 

in order to produce transformers (in-house) at higher TSLs, undifferentiated small 

manufacturers would face a greater variable cost penalty because they must depreciate 

the one-time conversion expenditures over fewer units.

Smaller companies are also more likely to have more limited engineering 

resources and they often operate with lower levels of design and manufacturing 

sophistication. Smaller companies typically also have less experience and expertise in 

working with more advanced technologies, such as amorphous core construction in the 

liquid-immersed market or step-lap mitering in the dry-type markets. Standards that 

required these technologies could strain the engineering resources of these small 

manufacturers if they chose to maintain a vertically integrated business model.

Small distribution transformer manufacturers can also be at a disadvantage due to 

their lack of purchasing power for high performance materials. If more expensive steels 
366

are needed to meet standards and steel cost grows as a percentage of the overall product 

cost, small manufacturers who pay higher per pound prices would be disproportionately 

impacted. 

Last, small manufacturers typically have less access to capital, which may be 

needed by some to cover the conversion costs associated with new technologies. 

4. Description and Estimate of Compliance Requirements 

a. Liquid-Immersed 

Based on interviews with manufacturers in the liquid-immersed market, DOE 

does not believe small manufacturers will face significant capital conversion costs at the 

levels established in today’s rulemaking. DOE expects small manufacturers of liquidimmersed distribution transformers to continue to produce silicon steel cores, rather than 

invest in amorphous technology. While silicon steel designs capable of achieving TSL 1 

would get larger, and thus reduce throughput, most manufacturers said the industry in 

general has substantial excess capacity due to the recent economic downturn. Therefore, 

DOE believes TSL 1 would not require the typical small manufacturer to invest in 

additional capital equipment. However, small manufacturers may incur some engineering 

and product design costs associated with re-optimizing their production processes around 

new baseline equipment. DOE estimates TSL 1 would require industry product 

conversion costs of only one-half of one year’s annual industry R&D expenses. Because 

these one-time costs are relatively fixed per manufacturer, they impact smaller 
367

manufacturers disproportionately (compared to larger manufacturers). The table below 

illustrates this effect:

Table VI.1 Estimated Product Conversion Costs as a Percentage of Annual R&D 

Expense

Product Conversion 

Cost

Product Conversion Cost as a 

Percentage of Annual R&D 

Expense

Typical Large Manufacturer $1.34 M 20%

Typical Small Manufacturer $1.34 M 222%

While the costs disproportionately impact small manufactures, the standard levels, 

as stated above, do not require small manufacturers to invest in entirely different 

production processes nor do they require steels or core construction techniques with 

which these manufacturers are not familiar. A range of design options would still be 

available. 

b. Low-Voltage Dry-Type.

Small manufacturers have several options available to them at TSL2 based on 

individual economic determinations. They may choose to: (1) source their cores, (2) 

fabricate cores with butt-lapping technology and higher-grade steel, (3) buy a mitering 

machine (enabling them to build mitered cores with lower-grade steel than would be 

otherwise required), or (4) exit a product line. 
368

Compared to higher TSLs, TSL 2 provides many more design paths for small 

manufacturers to comply. At TSL 2, the level adopted in today’s notice, DOE’s 

engineering analysis indicates that the efficiency level represented by TSL 2 for DL7 (the 

high-volume line) could be met without mitering through the use of butt-lapping highergrade steels. It is uncertain whether small manufacturers would elect to butt-lap with 

higher grade steel rather than source their cores or invest in mitering equipment, but each 

option remains a viable path to compliance. With respect to the other paths to 

compliance, DOE notes that roughly half of the small business LVDT manufacturers 

DOE interviewed already have mitering capability. DOE estimates half of all cores in 

small business DL7 transformers are currently sourced, according to transformer and core 

manufacturer interviews, as third-party core manufacturers already often have significant 

variable cost advantages through bulk steel purchasing power and greater production 

efficiencies due to higher volumes.

Each business’ ultimate decision on how it will ultimately comply depends on its 

production volumes, the relative steel prices it faces, its position in the value chain, and 

whether it currently has mitering technology in-house, among other factors. Because a 

small business may ultimately make the business decision to build mitered cores at TSL 

2, DOE estimates the cost of such a strategy to conservatively bound the compliance 

impact. Below DOE compares the relative impact on a small business of the scenario in 

which a small manufacturer elects to purchase a new mitering machine (rather than 

continue to butt-lap with higher grade steel or source its core production). Based on 
369

interviews with small businesses and core manufacturers, DOE believes this to be a 

conservative assessment of compliance costs, as many small businesses currently source 

a large share of their cores. DOE estimates capital conversion costs of $0.75 million and 

product conversion costs of $0.2 million for a typical manufacturer, based on 

manufacturer and equipment supplier interviews, would be incurred if small businesses 

without mitering equipment chose to invest in it. Because of the largely fixed nature of 

these one-time conversion expenditures that distribution transformer manufacturers 

would incur as a result of standards, small manufacturers who choose to invest to 

maintainin in-house productionmitering capability will likely be disproportionately 

impacted (compared to large manufacturers). Based on information gathered in 

interviews, DOE estimates that three small manufacturers would invest in mitering 

equipment as result of this rule. As Table VI.2 indicates, small manufacturers face a 

greater relative hurdle in complying with standards should they opt to continue to 

maintain core production in-house. 

Table VI.2 Estimated Capital and Product Conversion Costs as a Percentage of 

Annual Capital Expenditures and R&D Expense

Capital Conversion 

Cost as a Percentage 

of Annual Capital 

Expenditures

Product Conversion

Cost as a Percentage 

of Annual R&D 

Expense

Total Conversion 

Cost as a Percentage 

of Annual EBIT

Large Manufacturer 37% 10% 15%

Small Manufacturer 137% 44% 70%

As demonstrated in the table above, the investments required to meet TSL 2

disproportionately impact small businesses. However, DOE’s capital conversion costs 

Comment [A20]: Changes recommended by 

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370

estimates in the table above assume that small businesses are currently producing their 

cores in-house, and will choose to do so in the future, rather than source them from thirdparty core manufactures who often have significant cost advantages through bulk steel 

purchasing power and greater production efficiencies due to higher volumes. Currently,

many small businesses DOE interviewed already source a large percentage of their cores 

and many indicated that they expected such a For more than half of the small 

businesses DOE interviewed, it is already standard practice to source a large percentage 

of their DOE-covered cores on an ongoing basis or quickly do so when steel prices merit 

such a strategy. Furthermore, small businesses are currently more likely to source cores 

for NEMA Premium® units than standard units. Many small businesses indicated that 

they expect the continuance of this strategy would be the low-cost option under higher 

standards. Therefore, the impacts in the table are not representative of the strategy

expectedDOE expects to be employed by many small manufacturers, but only those 

choosing to invest in mitering equipment.

For all of the reasons discussed, DOE believes the capital expenditures it 

estimated aboveCompared to higher TSLs, TSL 2 provides many more design paths for 

small manufacturers to comply. As noted in the methodology and results sections of this 

notice. DOE’s engineering analysis indicates that the efficiency level represented by 

TSL 2 for DL7 (the high-volume line) could be met without mitering through the use of 

higher-grade steels. It is uncertain whether small manufacturers would elect such a design 

option rather than sourcing their cores or investing in mitering equipment, but it remains 

Formatted: Indent: First line: 0.3"
371

another viable path to compliance. DOE notes that roughly half of the small business 

LVDT manufacturers DOE interviewed already have mitering capability. For all of the 

reasons discussed, DOE believes the capital expenditures it assumed for small businesses 

are likely conservative and that small businesses have a variety of technical and strategic 

paths to continue to compete in the market at TSL 2.

c. Medium-Voltage Dry-Type. 

Based on its engineering analysis and interviews, DOE expects relatively minor 

capital expenditures for the industry to meet TSL 2. DOE understands that the market is 

already standardized on step-lap mitering, so manufacturers will not need to make major 

investments for more advanced core construction. Furthermore, TSL 2 does not require a 

change to much thinner steels such as M3 or H0. The industry can use M4 and H1, 

thicker steels with which it has much more experience and which are easier to employ in 

the stacked-core production process that dominates the medium-voltage market. 

However, some investment will be required to maintain capacity as some manufacturers 

will likely migrate towards more M4 and H1 steel and away from the slightly thicker M5, 

which is also common. Additionally, design options at TSL 2 typically have larger cores, 

also slowing throughput. Therefore, some manufacturers may need to invest in additional 

production equipment. Alternatively, depending on each company’s availability capacity, 

manufacturers could employ additional production shifts, rather than invest in additional 

capacity.

Comment [A21]: Changes recommended by 

OMB.
372

For the medium-voltage dry-type market, at TSL 2, the level proposed in today’s 

notice, DOE estimates low capital and product conversion costs that are relatively fixed

for both small and large manufacturers. Similar to the low-voltage dry-type market, small 

manufacturers will likely be disproportionately impacted compared to large 

manufacturers due to the fixed nature of the conversion expenditures. Table VI.3

illustrates the relative impacts on small and large manufacturers.

Table VI.3 Estimated Capital and Product Conversion Costs as a Percentage of

Annual Capital Expenditures and R&D Expense

Capital Conversion 

Cost as a Percentage 

of Annual Capital 

Expenditures

Product Conversion 

Cost as a Percentage 

of Annual R&D 

Expense

Total Conversion Cost 

as a Percentage of 

Annual EBIT

Large Manufacturer 3% 9% 8%

Small Manufacturer 40% 117% 98%

d. Summary of Compliance Impacts

The compliance impacts on small businesses are discussed above for low-voltage 

dry-type, medium-voltage dry-type, and liquid-filled distribution transformer 

manufacturers. Although the conversion costs required can be considered substantial for

both large and small companies, the impacts could be relatively greater for a typical small 

manufacturer because of much lower production volumes and the relatively fixed nature 

of the R&D and capital investments required. 

5. Steps Taken to Minimize Impacts on Small Entities and Reasons Why Other 

Significant Alternatives to Today’s Final Rule Were Rejected
373

DOE modified the standards established in today’s final rule from those proposed 

in the February 2012 NOPR as discussed previously and based on comments and 

additional test data received from interested parties. 

The previous discussion also analyzes impacts on small businesses that would 

result from the other TSLs DOE considered. Though TSLs lower than the adopted TSL 

are expected to reduce the impacts on small entities, DOE is required by EPCA to 

establish standards that achieve the maximum improvement in energy efficiency that are 

technically feasible and economically justified, and result in a significant conservation of 

energy. Thus, DOE rejected the lower TSLs.

In addition to the other TSLs being considered, the TSD includes a regulatory 

impact analysis (chapter 17) that discusses the following policy alternatives: (1) no 

standard, (2) consumer rebates, (3) consumer tax credits, (4) manufacturer tax credits, 

and (5) early replacement. DOE does not intend to consider these alternatives further 

because they are either not feasible to implement, or not expected to result in energy 

savings as large as those that would be achieved by the standard levels under 

consideration. Thus, DOE rejected these alternatives and is adopting the standards set 

forth in this rulemaking.
374

6. Duplication, Overlap, and Conflict with Other Rules and Regulations

DOE is not aware of any rules or regulations that duplicate, overlap, or conflict 

with the rule being finalized today.

7. Significant Alternatives to Today’s Rule 

The discussion above analyzes impacts on small businesses that would result from 

the other TSLs DOE considered. Though TSLs lower than the selected TSLs are expected 

to reduce the impacts on small entities, DOE is required by EPCA to establish standards 

that achieve the maximum improvement in energy efficiency that are technically feasible 

and economically justified, and result in a significant conservation of energy. Therefore,

DOE rejected the lower TSLs. 

In addition to the other TSLs being considered, the TSD includes a regulatory 

impact analysis (chapter 17) that discusses the following policy alternatives: (1) 

consumer rebates, (2) consumer tax credits, and (3) manufacturer tax credits. DOE does 

not intend to consider these alternatives further because they either are not feasible to 

implement or are not expected to result in energy savings as large as those that would be 

achieved by the standard levels under consideration. 

8. Significant Issues Raised by Public Comments

DOE’s MIA suggests that, while TSL1, TSL1, and TSL 2 present greater 

difficulties for small businesses than lower levels in the liquid-immersed, LVDT, and 
375

MVDT classes, respectively, the impacts at higher TSLs would be greater. DOE expects 

that small businesses will generally be able to profitably compete at the TSL selected in 

today’s rulemaking.. DOE’s MIA is based on its interviews of both small and large 

manufacturers, and consideration of small business impacts explicitly enters into DOE’s 

choice of the TSLs selected in this final rule. 

DOE also notes that today’s standards can be met with a variety of materials, 

including multiple core steels and both copper and aluminum windings. Because today’s

TSLs can be met with a variety of materials, DOE does not expect that material 

availability issues will be a problem for the industry that results from this rulemaking. 

9. Steps DOE Has Taken to Minimize the Economic Impact on Small Manufacturers

In consideration of the benefits and burdens of standards, including the burdens 

posed to small manufacturers, DOE concluded that TSL1 is the highest level that can be 

justified for liquid- immersed and medium-voltage dry-type transformers and TSL2 is the 

highest level that can be justified for low-voltage dry-type transformers. As explained in 

part 6 of the IRFA, “Significant Alternatives to the Rule,” DOE explicitly considered the 

impacts on small manufacturers of liquid-immersed and dry-type transformers in 

selecting the TSLs in today’s rulemaking, rather than selecting a higher trial standard 

level. It is DOE’s belief that levels at TSL3 or higher would place excessive burdens on 

small manufacturers of medium-voltage dry-type transformers, as would TSL 2 or higher 

for liquid-immersed and medium-voltage dry-type transformers. Such burdens would 
376

include large product redesign costs and also operational problems associated with the 

extremely thin laminations of core steel that would be needed to meet these levels and 

advanced core construction equipment and tooling for mitering, or wound-core designs. 

Similarly, for medium-voltage dry-type, the steels and construction techniques likely to 

be used at TSL 2 are already commonplace in the market, whereas TSL 3 would likely 

trigger a more dramatic shift to thinner and more exotic steels, to which many small 

businesses have limited access. Lastly, DOE is confident that TSL1 for the liquidimmersed distribution transformer market would not require small manufacturers to 

invest in amorphous steel technology, which could put them at a significant disadvantage. 

Section VI.B discusses how small business impacts entered into DOE’s selection 

of today’s standards for distribution transformers. DOE made its decision regarding 

standards by beginning with the highest level considered and successively eliminating 

TSLs until it found a TSL that is both technologically feasible and economically justified, 

, taking into account other EPCA criteria. Because DOE believes that the TSLs selected

are economically justified (including consideration of small business impacts), the 

reduced impact on small businesses that would have been realized in moving to lower 

efficiency levels was not considered in DOE’s decision (but the reduced impact on small 

businesses that is realized in moving down to TSL2 from TSL3 (in the case of mediumvoltage dry-type and low-voltage dry-type) and to TSL1 from TSL2 (in the case of 

liquid-immersed) was explicitly considered in the weighing of benefits and burdens).
377

C.

Manufacturers of distribution transformers must certify to DOE that their 

equipment complies with any applicable energy conservation standards. In certifying 

compliance, manufacturers must test their equipment according to the DOE test 

procedures for distribution transformers, including any amendments adopted for those 

test procedures. DOE has established regulations for the certification and recordkeeping 

requirements for all covered consumer products and commercial equipment, including 

distribution transformers. (76 FR 12422 (March 7, 2011). The collection-of-information 

requirement for the certification and recordkeeping is subject to review and approval by 

OMB under the Paperwork Reduction Act (PRA). This requirement has been approved 

by OMB under OMB control number 1910-1400. Public reporting burden for the 

certification is estimated to average 20 hours per response, including the time for 

reviewing instructions, searching existing data sources, gathering and maintaining the 

data needed, and completing and reviewing the collection of information. 

Review Under the Paperwork Reduction Act

Notwithstanding any other provision of the law, no person is required to respond 

to, nor shall any person be subject to a penalty for failure to comply with, a collection of 

information subject to the requirements of the PRA, unless that collection of information 

displays a currently valid OMB Control Number.

D.

Pursuant to the National Environmental Policy Act (NEPA) of 1969, DOE has 

determined that the rule fits within the category of actions included in Categorical 

Review Under the National Environmental Policy Act of 1969 
378

Exclusion (CX) B5.1 and otherwise meets the requirements for application of a CX. See 

10 CFR Part 1021, App. B, B5.1(b); 1021.410(b) and Appendix B, B(1)-(5). The rule fits 

within the category of actions because it is a rulemaking that establishes energy 

conservation standards for consumer products or industrial equipment, and for which 

none of the exceptions identified in CX B5.1(b) apply. Therefore, DOE has made a CX 

determination for this rulemaking, and DOE does not need to prepare an Environmental 

Assessment or Environmental Impact Statement for this rule. DOE’s CX determination 

for this rule is available at http://cxnepa.energy.gov/ or link directly to 

http://energy.gov/nepa/downloads/cx-007852-categorical-exclusion-determination.

E.

Executive Order 13132, “Federalism.” 64 FR 43255 (Aug. 10, 1999) imposes 

certain requirements on Federal agencies formulating and implementing policies or 

regulations that preempt State law or that have Federalism implications. The Executive 

Order requires agencies to examine the constitutional and statutory authority supporting 

any action that would limit the policymaking discretion of the States and to carefully 

assess the necessity for such actions. The Executive Order also requires agencies to have 

an accountable process to ensure meaningful and timely input by State and local officials 

in the development of regulatory policies that have Federalism implications. On March 

14, 2000, DOE published a statement of policy describing the intergovernmental 

consultation process it will follow in the development of such regulations. 65 FR 13735. 

EPCA governs and prescribes Federal preemption of State regulations as to energy 

Review Under Executive Order 13132
379

conservation for the products that are the subject of today’s final rule. States can petition 

DOE for exemption from such preemption to the extent, and based on criteria, set forth in 

EPCA. (42 U.S.C. 6297) No further action is required by Executive Order 13132.

F.

With respect to the review of existing regulations and the promulgation of new 

regulations, section 3(a) of Executive Order 12988, “Civil Justice Reform,” imposes on 

Federal agencies the general duty to adhere to the following requirements: (1) eliminate 

drafting errors and ambiguity; (2) write regulations to minimize litigation; and (3) 

provide a clear legal standard for affected conduct rather than a general standard and 

promote simplification and burden reduction. 61 FR 4729 (Feb. 7, 1996). Section 3(b) of 

Executive Order 12988 specifically requires that Executive agencies make every 

reasonable effort to ensure that the regulation: (1) clearly specifies the preemptive effect, 

if any; (2) clearly specifies any effect on existing Federal law or regulation; (3) provides 

a clear legal standard for affected conduct while promoting simplification and burden 

reduction; (4) specifies the retroactive effect, if any; (5) adequately defines key terms; 

and (6) addresses other important issues affecting clarity and general draftsmanship under 

any guidelines issued by the Attorney General. Section 3(c) of Executive Order 12988 

requires Executive agencies to review regulations in light of applicable standards in 

section 3(a) and section 3(b) to determine whether they are met or it is unreasonable to 

meet one or more of them. DOE has completed the required review and determined that, 

Review Under Executive Order 12988
380

to the extent permitted by law, this final rule meets the relevant standards of Executive 

Order 12988.

G.

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA) requires each 

Federal agency to assess the effects of Federal regulatory actions on State, local, and 

Tribal governments and the private sector. Pub. L. 104-4, sec. 201 (codified at 2 U.S.C. 

1531). For an amended regulatory action likely to result in a rule that may cause the 

expenditure by State, local, and Tribal governments, in the aggregate, or by the private 

sector of $100 million or more in any one year (adjusted annually for inflation), section 

202 of UMRA requires a Federal agency to publish a written statement that estimates the 

resulting costs, benefits, and other effects on the national economy. (2 U.S.C. 1532(a), 

(b)) The UMRA also requires a Federal agency to develop an effective process to permit 

timely input by elected officers of State, local, and Tribal governments on a “significant 

intergovernmental mandate,” and requires an agency plan for giving notice and 

opportunity for timely input to potentially affected small governments before establishing 

any requirements that might significantly or uniquely affect small governments. On 

March 18, 1997, DOE published a statement of policy on its process for 

intergovernmental consultation under UMRA. 62 FR 12820. DOE’s policy statement is 

also available at 

Review Under the Unfunded Mandates Reform Act of 1995

http://energy.gov/gc/office-general-counsel.
381

DOE has concluded that this final rule would likely require expenditures of $100 

million or more by the private sector. Such expenditures may include: (1) investment in 

research and development and in capital expenditures by distribution transformer 

manufacturers in the years between the final rule and the compliance date for the new 

standards, and (2) incremental additional expenditures by consumers to purchase higherefficiency distribution transformers, starting at the compliance date for the applicable 

standard.

Section 202 of UMRA authorizes a Federal agency to respond to the content 

requirements of UMRA in any other statement or analysis that accompanies the final rule. 

2 U.S.C. 1532(c). The content requirements of section 202(b) of UMRA relevant to a 

private sector mandate substantially overlap the economic analysis requirements that 

apply under section 325(o) of EPCA and Executive Order 12866. The 

SUPPLEMENTARY INFORMATION section of the final rule and the “Regulatory 

Impact Analysis” section of the TSD for this final rule respond to those requirements. 

Under section 205 of UMRA, the Department is obligated to identify and consider 

a reasonable number of regulatory alternatives before promulgating a rule for which a 

written statement under section 202 is required. 2 U.S.C. 1535(a). DOE is required to 

select from those alternatives the most cost-effective and least burdensome alternative 

that achieves the objectives of the rule unless DOE publishes an explanation for doing 

otherwise, or the selection of such an alternative is inconsistent with law. As required by 
382

42 U.S.C. 6295 (o), 6316(a), and 6317(a)(1), today’s final rule would establish energy 

conservation standards for distribution transformers that are designed to achieve the 

maximum improvement in energy efficiency that DOE has determined to be both 

technologically feasible and economically justified. A full discussion of the alternatives 

considered by DOE is presented in the “Regulatory Impact Analysis” chapter of the TSD 

for today’s final rule.

H.

Section 654 of the Treasury and General Government Appropriations Act, 1999 

(Pub. L. 105-277) requires Federal agencies to issue a Family Policymaking Assessment 

for any rule that may affect family well-being. This rule would not have any impact on 

the autonomy or integrity of the family as an institution. Accordingly, DOE has 

concluded that it is not necessary to prepare a Family Policymaking Assessment.

Review Under the Treasury and General Government Appropriations Act, 1999

I.

DOE has determined, under Executive Order 12630, “Governmental Actions and 

Interference with Constitutionally Protected Property Rights” 53 FR 8859 (March 18, 

1988), that this regulation would not result in any takings that might require 

compensation under the Fifth Amendment to the U.S. Constitution.

Review Under Executive Order 12630
383

J.

Section 515 of the Treasury and General Government Appropriations Act, 2001 

(44 U.S.C. 3516, note) provides for Federal agencies to review most disseminations of 

information to the public under guidelines established by each agency pursuant to general 

guidelines issued by OMB. OMB’s guidelines were published at 67 FR 8452 (February

22, 2002), and DOE’s guidelines were published at 67 FR 62446 (October 7, 2002). DOE 

has reviewed today’s final rule under the OMB and DOE guidelines and has concluded 

that it is consistent with applicable policies in those guidelines.

Review Under the Treasury and General Government Appropriations Act, 2001

K.

Executive Order 13211, “Actions Concerning Regulations That Significantly 

Affect Energy Supply, Distribution, or Use” 66 FR 28355 (May 22, 2001), requires 

Federal agencies to prepare and submit to OIRA at OMB, a Statement of Energy Effects

for any significant energy action. A “significant energy action” is defined as any action 

by an agency that promulgates or is expected to lead to promulgation of a final rule, and 

that: (1) is a significant regulatory action under Executive Order 12866, or any successor 

order; and (2) is likely to have a significant adverse effect on the supply, distribution, or 

use of energy, or (3) is designated by the Administrator of OIRA as a significant energy 

action. For any significant energy action, the agency must give a detailed statement of 

any adverse effects on energy supply, distribution, or use should the proposal be 

implemented, and of reasonable alternatives to the action and their expected benefits on 

energy supply, distribution, and use.

Review Under Executive Order 13211
384

DOE has concluded that today’s regulatory action, which sets forth energy 

conservation standards for distribution transformers, is not a significant energy action 

because the amended standards are not likely to have a significant adverse effect on the 

supply, distribution, or use of energy, nor has it been designated as such by the 

Administrator at OIRA. Accordingly, DOE has not prepared a Statement of Energy 

Effects for the final rule.

L.

On December 16, 2004, OMB, in consultation with the Office of Science and 

Technology Policy (OSTP), issued its Final Information Quality Bulletin for Peer Review 

(the Bulletin). 70 FR 2664 (January 14, 2005). The Bulletin establishes that certain 

scientific information shall be peer reviewed by qualified specialists before it is 

disseminated by the Federal Government, including influential scientific information 

related to agency regulatory actions. The purpose of the bulletin is to enhance the quality 

and credibility of the Government’s scientific information. Under the Bulletin, the energy 

conservation standards rulemaking analyses are “influential scientific information,” 

which the Bulletin defines as scientific information the agency reasonably can determine 

will have, or does have, a clear and substantial impact on important public policies or 

private sector decisions. 70 FR 2667.

Review Under the Information Quality Bulletin for Peer Review 
385

In response to OMB’s Bulletin, DOE conducted formal in-progress peer reviews 

of the energy conservation standards development process and analyses and has prepared 

a Peer Review Report pertaining to the energy conservation standards rulemaking 

analyses. Generation of this report involved a rigorous, formal, and documented 

evaluation using objective criteria and qualified and independent reviewers to make a 

judgment as to the technical/scientific/business merit, the actual or anticipated results, 

and the productivity and management effectiveness of programs and/or projects. The 

“Energy Conservation Standards Rulemaking Peer Review Report” dated February 2007 

has been disseminated and is available at the following Web site: 

www1.eere.energy.gov/buildings/appliance_standards/peer_review.html.

M.

As required by 5 U.S.C. 801, DOE will report to Congress on the promulgation of 

this rule prior to its effective date. The report will state that it has been determined that 

the rule is a “major rule” as defined by 5 U.S.C. 804(2).

Congressional Notification
88

VII. Approval of the Office of the Secretary

The Secretary of Energy has approved publication of today’s final rule.

List of Subjects in 10 CFR Part 431

Administrative practice and procedure, Confidential business information, Energy 

conservation, Reporting and recordkeeping requirements.

Issued in Washington, DC, on April 9, 2013.

________________________________

David Danielson

Assistant Secretary of Energy

Energy Efficiency and Renewable Energy
386

For the reasons set forth in the preamble, DOE amends part 431 of chapter II, of 

title 10 of the Code of Federal Regulations, to read as set forth below: 

PART 431 - ENERGY EFFICIENCY PROGRAM FOR CERTAIN 

COMMERCIAL AND INDUSTRIAL EQUIPMENT

1. The authority citation for part 431 continues to read as follows: 

Authority: 42 U.S.C. 6291–6317. 

2. Section 431.192 is amended by:

a. Removing the definition of “underground mining distribution transformer” and

b. Adding in alphabetical order, the definition for “mining distribution transformer”

to read as follows:

§ 431.192 Definitions.

* * * * *

Mining distribution transformer means a medium-voltage dry-type distribution 

transformer that is built only for installation in an underground mine or surface mine, 

inside equipment for use in an underground mine or surface mine, on-board equipment 

for use in an underground mine or surface mine, or for equipment used for digging, 
387

drilling, or tunneling underground or above ground, and that has a nameplate which 

identifies the transformer as being for this use only.

* * * * *

3. Section 431.196 is revised to read as follows:

§ 431.196 Energy conservation standards and their effective dates.

(a) Low-Voltage Dry-Type Distribution Transformer

Single-Phase

s. (1) The efficiency of a 

low-voltage, dry-type distribution transformer manufactured on or after January 1, 2007, 

but before January 1, 2016, shall be no less than that required for the applicable kVA 

rating in the table below. Low-voltage dry-type distribution transformers with kVA 

ratings not appearing in the table shall have their minimum efficiency level determined 

by linear interpolation of the kVA and efficiency values immediately above and below 

that kVA rating.

Three-Phase

kVA % kVA %

15 97.7 15 97.0

25 98.0 30 97.5

37.5 98.2 45 97.7

50 98.3 75 98.0

75 98.5 112.5 98.2

100 98.6 150 98.3

167 98.7 225 98.5

250 98.8 300 98.6

333 98.9 500 98.7

750 98.8

1000 98.9

Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE 

Test Method for Measuring the Energy Consumption of Distribution Transformers under Appendix A to 

Subpart K of 10 CFR part 431. 
388

(2) The efficiency of a low-voltage dry-type distribution transformer 

manufactured on or after January 1, 2016, shall be no less than that required for their

kVA rating in the table below. Low-voltage dry-type distribution transformers with kVA 

ratings not appearing in the table shall have their minimum efficiency level determined 

by linear interpolation of the kVA and efficiency values immediately above and below 

that kVA rating.

Single-Phase Three-Phase

kVA Efficiency (%) kVA Efficiency (%)

15 97.70 15 97.89

25 98.00 30 98.23

37.5 98.20 45 98.40

50 98.30 75 98.60

75 98.50 112.5 98.74

100 98.60 150 98.83

167 98.70 225 98.94

250 98.80 300 99.02

333 98.90 500 99.14

750 99.23

1000 99.28

Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE 

Test Method for Measuring the Energy Consumption of Distribution Transformers under Appendix A to 

Subpart K of 10 CFR part 431.

(b) Liquid-Immersed Distribution Transformer

Single-Phase

s. (1) The efficiency of a liquidimmersed distribution transformer manufactured on or after January 1, 2010, but before 

January 1, 2016, shall be no less than that required for their kVA rating in the table 

below. Liquid-immersed distribution transformers with kVA ratings not appearing in the 

table shall have their minimum efficiency level determined by linear interpolation of the 

kVA and efficiency values immediately above and below that kVA rating.

Three-Phase
389

kVA Efficiency (%) kVA Efficiency (%)

10 98.62 15 98.36

15 98.76 30 98.62

25 98.91 45 98.76

37.5 99.01 75 98.91

50 99.08 112.5 99.01

75 99.17 150 99.08

100 99.23 225 99.17

167 99.25 300 99.23

250 99.32 500 99.25

333 99.36 750 99.32

500 99.42 1000 99.36

667 99.46 1500 99.42

833 99.49 2000 99.46

2500 99.49

Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE 

Test - Procedure, Appendix A to Subpart K of 10 CFR part 431.

(2) The efficiency of a liquid-immersed distribution transformer manufactured on 

or after January 1, 2016, shall be no less than that required for their kVA rating in the 

table below. Liquid-immersed distribution transformers with kVA ratings not appearing 

in the table shall have their minimum efficiency level determined by linear interpolation 

of the kVA and efficiency values immediately above and below that kVA rating.
390

Single-Phase Three-Phase

kVA Efficiency (%) kVA Efficiency (%)

10 98.70 15 98.65

15 98.82 30 98.83

25 98.95 45 98.92

37.5 99.05 75 99.03

50 99.11 112.5 99.11

75 99.19 150 99.16

100 99.25 225 99.23

167 99.33 300 99.27

250 99.39 500 99.35

333 99.43 750 99.40

500 99.49 1000 99.43

667 99.52 1500 99.48

833 99.55 2000 99.51

2500 99.53

Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE 

Test Method for Measuring the Energy Consumption of Distribution Transformers under Appendix A to 

Subpart K of 10 CFR part 431. 

(c) Medium-Voltage Dry-Type Distribution Transformers

(1) The efficiency of a medium-voltage dry-type distribution transformer 

manufactured on or after January 1, 2010, but before January 1, 2016, shall be no less 

than that required for their kVA and BIL rating in the table below. Medium-voltage drytype distribution transformers with kVA ratings not appearing in the table shall have their 

minimum efficiency level determined by linear interpolation of the kVA and efficiency 

values immediately above and below that kVA rating.

.
391

Single-Phase Three-Phase

BIL* BIL

20–45 kV 46–95 kV ≥96 kV 20–45 kV 46–95 kV ≥96 kV

kVA Efficiency 

(%)

Efficiency 

(%)

Efficiency 

(%) kVA Efficiency (%)

Efficiency 

(%)

Efficiency 

(%)

15 98.10 97.86 - 15 97.50 97.18 -

25 98.33 98.12 - 30 97.90 97.63 -

37.5 98.49 98.30 - 45 98.10 97.86 -

50 98.60 98.42 - 75 98.33 98.12 -

75 98.73 98.57 98.53 112.5 98.49 98.30 -

100 98.82 98.67 98.63 150 98.60 98.42 -

167 98.96 98.83 98.80 225 98.73 98.57 98.53

250 99.07 98.95 98.91 300 98.82 98.67 98.63

333 99.14 99.03 98.99 500 98.96 98.83 98.80

500 99.22 99.12 99.09 750 99.07 98.95 98.91

667 99.27 99.18 99.15 1000 99.14 99.03 98.99

833 99.31 99.23 99.20 1500 99.22 99.12 99.09

2000 99.27 99.18 99.15

2500 99.31 99.23 99.20

*BIL means basic impulse insulation level

Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE 

Test Method for Measuring the Energy Consumption of Distribution Transformers under Appendix A to 

Subpart K of 10 CFR part 431.

(2) The efficiency of a medium- voltage dry-type distribution transformer 

manufactured on or after January 1, 2016, shall be no less than that required for their

kVA and BIL rating in the table below. Medium-voltage dry-type distribution 

transformers with kVA ratings not appearing in the table shall have their minimum 

efficiency level determined by linear interpolation of the kVA and efficiency values 

immediately above and below that kVA rating.
392

Single-Phase Three-Phase

BIL* BIL

20–45 kV 46–95 kV ≥96 kV 20–45 kV 46–95 kV ≥96 kV

kVA Efficiency 

(%)

Efficiency 

(%)

Efficiency 

(%) kVA Efficiency (%)

Efficiency 

(%)

Efficiency 

(%)

15 98.10 97.86 - 15 97.50 97.18 -

25 98.33 98.12 - 30 97.90 97.63 -

37.5 98.49 98.30 - 45 98.10 97.86 -

50 98.60 98.42 - 75 98.33 98.13 -

75 98.73 98.57 98.53 112.5 98.52 98.36 -

100 98.82 98.67 98.63 150 98.65 98.51 -

167 98.96 98.83 98.80 225 98.82 98.69 98.57

250 99.07 98.95 98.91 300 98.93 98.81 98.69

333 99.14 99.03 98.99 500 99.09 98.99 98.89

500 99.22 99.12 99.09 750 99.21 99.12 99.02

667 99.27 99.18 99.15 1000 99.28 99.20 99.11

833 99.31 99.23 99.20 1500 99.37 99.30 99.21

2000 99.43 99.36 99.28

2500 99.47 99.41 99.33

* BIL means basic impulse insulation level

Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE 

Test Method for Measuring the Energy Consumption of Distribution Transformers under Appendix A to 

Subpart K of 10 CFR part 431.

(d) Mining Distribution Transformers. [Reserved]
393

Appendix

[The following letter from the Department of Justice will not appear in the Code of 

Federal Regulations.]

U.S. Department of Justice

Antitrust Division

Joseph F. Wayland

Acting Assistant Attorney General

RFK Main Justice Building

950 Pennsylvania Ave., NW

Washington, D.C. 20530-0001

(202)514-2401 / (202)616-2645 (Fax)

September 24, 2012

Eric J. Fygi

Deputy General Counsel 

Department of Energy 

Washington, DC 20585

Dear Deputy General Counsel Fygi:

I am responding to your August 16, 2012 letter seeking the views of the Attorney General 

about the potential impact on competition of proposed energy conservation standards for 

certain types of distribution transformers, namely medium-voltage, dry-type and liquidimmersed distribution transformers, as well as low-voltage, dry-type distribution 

transformers. Your request was submitted under Section 325(o)(2)(B)(i)(V) of the 

Energy Policy and Conservation Act, as amended (ECPA), 42 U.S.C.

6295(o)(2)(B)(i)(V), which requires the Attorney General to make a determination of the

impact of any lessening of competition that is likely to result from the imposition of 

proposed energy conservation standards. The Attorney General's responsibility for 

responding to requests from other departments about the effect of a program on 

competition has been delegated to the Assistant Attorney General for the Antitrust 

Division in 28 CFR § 0.40(g).

In conducting its analysis the Antitrust Division examines whether a proposed standard 

may lessen competition, for example, by substantially limiting consumer choice, by 

placing certain manufacturers at an unjustified competitive disadvantage, or by inducing 

avoidable inefficiencies in production or distribution of particular products. A lessening 

of competition could result in higher prices to manufacturers and consumers, and perhaps 

thwart the intent of the revised standards by inducing substitution to less efficient 

products.
394

We have reviewed the proposed standards contained in the Notice of Proposed 

Rulemaking (77 Fed. Reg. 7282, February 10, 2012) (NOPR). We have also reviewed 

supplementary information submitted to the Attorney General by the Department of

Energy. The NOPR proposed Trial Standard Level 2 for medium-voltage, dry-type 

distribution transformers, which was arrived at through a consensus agreement among a 

diverse array of stakeholders as part of a negotiated rulemaking, and Trial Standard Level

1 for medium-voltage, liquid-immersed and low-voltage, dry-type distribution 

transformers, after no consensus was reached as part of a negotiated rulemaking. Our 

review has focused on the standards DOE has proposed adopting. We have not 

determined the impact on competition of more stringent standards than those proposed in 

the NOPR.

Based on this review, our conclusion is that the proposed energy conservation standards 

for medium-voltage, dry-type and liquid-immersed distribution transformers, as well as 

low-voltage, dry-type distribution transformers, are unlikely to have a significant adverse 

impact on competition. In reaching our conclusion, we note that the proposed energy 

standards for medium-voltage, dry-type distribution transformers were arrived at through 

a consensus agreement among a diverse array of stakeholders.

Sincerely,

Joseph F. Wayland