Vol. 78 Thursday, 

No. 75 April 18, 2013 

Part II 

Department of Energy 

10 CFR Part 431 

Energy Conservation Program: Energy Conservation Standards for 

Distribution Transformers; Final Rule 


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23336 Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 

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 morestringent 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. 

DATES: The effective date of this rule is 

June 17, 2013. 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=EERE2010-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: 

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. Email: 

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. Email: 

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 

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 

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 

a. Core Steel 

b. Small Manufacturers 

c. Conversion Costs 

6. Manufacturer Interviews 


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1For editorial reasons, upon codification in the 

U.S. Code, Parts B and C were redesignated as Parts 

A and A–1, respectively. 

2A 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. 

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). 

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 

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 

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), Public Law 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 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 Table I.1 

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 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 preamble, 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 liquidimmersed 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 stakeholders 


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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* Adopted TSL 

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* Adopted TSL 

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* Adopted TSL 

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. 

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 

(%) 

Liquid-immersed ................................. 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 

Medium-voltage dry-type .................... 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. 

TABLE I.5—ELECTRICAL EFFICIENCIES FOR ALL LIQUID-IMMERSED DISTRIBUTION TRANSFORMER EQUIPMENT CLASSES

[Compliance starting January 1, 2016] 

Equipment Class 1 Equipment Class 2 

kVA % kVA % 

Standards by kVA and Equipment Class 

10 .................................................................................. 98.70 15 ................................................................................. 98.65 


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TABLE I.5—ELECTRICAL EFFICIENCIES FOR ALL LIQUID-IMMERSED DISTRIBUTION TRANSFORMER EQUIPMENT CLASSES— 

Continued 

[Compliance starting January 1, 2016] 

Equipment Class 1 Equipment Class 2 

kVA % kVA % 

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] 

Equipment Class 3 Equipment Class 4 

kVA % kVA % 

Standards by kVA and Equipment Class 

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 

TABLE I.7—ELECTRICAL EFFICIENCIES FOR ALL MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMER EQUIPMENT

CLASSES

[Compliance starting January 1, 2016] 

Equipment 

Class 5 

Equipment 

Class 6 

Equipment 

Class 7 

Equipment 

Class 8 

Equipment 

Class 9 

Equipment 

Class 10 

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

Standards by kVA and Equipment Class 

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 


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23340 Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 

4For 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. 

5A 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. 

A. Benefits and Costs to Customers 4

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 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 

2011$ 

Median payback period 

years 

Liquid-Immersed 

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 

TABLE I.8—IMPACTS OF TODAY’S

STANDARDS ON CUSTOMERS OF DISTRIBUTION TRANSFORMERS—Continued 

Design line 

Average 

LCC 

savings 

2011$ 

Median payback period 

years 

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. Impact on Manufacturers 

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 liquidimmersed, medium-voltage dry-type, 

and low-voltage dry-type 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 lowvoltage 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. National Benefits 

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. 

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. 

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. 

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 


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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. 

TABLE I.9—SUMMARY OF NATIONAL ECONOMIC BENEFITS AND COSTS OF DISTRIBUTION TRANSFORMER ENERGY

CONSERVATION STANDARDS—Continued 

Category 

Present value 

billion 

2011$ 

Discount rate 

% 

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 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 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. 


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23342 Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 

9For editorial reasons, upon codification in the 

U.S. Code, Parts B and C were redesignated as Parts 

A and A–1, respectively. 

10EPACT 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 

TABLE I.10—ANNUALIZED BENEFITS AND COSTS OF AMENDED STANDARDS FOR DISTRIBUTION TRANSFORMERS SOLD IN

2016–2045 

Discount rate 

% 

Million 2011$/year 

Primary estimate * Low net benefits estimate * High net benefits estimate * 

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 ($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 

381 to 1044 325 to 988 400 to 1063. 

7 561 504 579. 

3% plus CO2

range 

771 to 1434 675 to 1338 803 to 1466. 

3% 950 854 982. 

* 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 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. 

** 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. 

† 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. Conclusion 

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. 

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. 

A. Authority 

Title III, Part B of the Energy Policy 

and Conservation Act of 1975 (EPCA or 

the Act), Public Law 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.9 The Energy Policy Act of 

1992 (EPACT 1992), Public Law 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), Public Law 109–58, amended 

EPCA to establish energy conservation 

standards for low-voltage dry-type 

distribution transformers.10 (42 U.S.C. 

6295(y)) 


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Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 23343 

Transformers’’ published by the National Electrical 

Manufacturers Association (NEMA TP 1–2002). 

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), 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 

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 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 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 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 


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23344 Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 

11EPACT 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). 

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. 

B. Background 

1. Current Standards 

On August 8, 2005, EPACT 2005 

amended EPCA to establish energy 

conservation standards for low-voltage 

dry-type distribution transformers 

(LVDTs).11 (EPACT 2005, Section 

135(c); 42 U.S.C. 6295(y)) The standard 

levels for low-voltage dry-type 

distribution transformers appear in 

Table II.1. 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. 

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 liquidimmersed distribution transformers and 

medium-voltage 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 test-procedure. 10 CFR part 431, subpart K, 

appendix A. 


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12The ANOPR published in July 2004 is available 

at: http://www.regulations.gov/#!documentDetail;

D=EERE-2006-STD-0099-0069. 

13These analyses are available in the docket 

folder at: http://www.regulations.gov/

#!docketDetail;D=EERE-2006-STD-0099. 

14The NOPR TSD published in August 2006 is 

available at: http://www.regulations.gov/

#!documentDetail;D=EERE-2006-STD-0099-0140. 

TABLE II.3—FEDERAL ENERGY CONSERVATION STANDARDS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION

TRANSFORMERS

kVA 

Single-phase 

kVA 

Three-phase 

BIL* BIL 

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

Efficiency 

% 

Efficiency 

% 

Efficiency 

% 

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 test-procedure. 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%252BSR;

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

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 mediumvoltage 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

Some commenters asserted that DOE’s 

proposed standards might adversely 

affect replacement of distribution 

transformers in certain spaceconstrained (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 pole-mounted and vault 

transformers. In October 2007, DOE 

published a final rule that created the 

current energy conservation standards 

for liquid-immersed and mediumvoltage dry-type 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 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 liquidVerDate Mar<15>2010 19:23 Apr 17, 2013 Jkt 229001 PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 E:\FR\FM\18APR2.SGM 18APR2

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23346 Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 

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 Web site. To expedite the 

rulemaking process, DOE began at the 

preliminary analysis 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. 

The ERAC subcommittee for mediumvoltage 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 EnergyEfficient 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 mediumvoltage 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 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 (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 Web site at: http:// 

www.regulations.gov/ 

#!docketDetail;D=EERE-2010-BT-STD0048. 

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 


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15On February 24, 2012, DOE published a 

technical correction to the NOPR, amending and 

adding values in certain tables in the NOPR. 77 FR 

10997. 

16 77 FR 32916. 

17The 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). 

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. 

The ERAC subcommittee for lowvoltage 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 EnergyEfficient 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 corematerial prices. 

At the conclusion of the final meeting, 

subcommittee members presented their 

energy efficiency level 

recommendations. For low-voltage drytype distribution 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 drytype 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 dry-type 

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 liquid-immersed 

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 analysis 16 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 Web site. 

III. General Discussion 

A. Test Procedures 

DOE published its test procedure for 

distribution transformers in the Federal 

Register as a final rule on April 27, 

2006. 71 FR 24972. Section 7(c) of the 

Process Rule 17 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 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)) 

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. 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. 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, 


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coordination of coil and ambient test 

methods, temperature data records, and 

application of voltage or current. 

(Schneider, No. 180 at p. 12) DOE 

examined the test procedure 

components identified by Schneider 

Electric and determined that, at this 

time, no change to the test procedure is 

necessary to address the issues raised. 

Further, the existing, statutorilyprescribed test procedure is an industry 

standard familiar to manufacturers. DOE 

continues 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. 

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 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 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 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 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 


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19 IEEE C57.12.00–2010. 

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) 

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 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 

standard 19 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 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; ProlecGE, 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. 

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 low-voltage 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, No. 182 at p. 3) Finally, MGLW 

and the Copper Development 


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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. 

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. Technological Feasibility 

1. General 

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 

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 (maxtech) energy efficiency level through its 

engineering analysis. The max-tech 

design incorporates the most efficient 

materials, such as core 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. Energy Savings 

1. Determination of 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. 

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 

electricity, 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 electricity. To convert 

site electricity 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, 768 F.2d 1355, 1373 (DC 

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). 

D. Economic Justification 

1. Specific Criteria 

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 shortterm 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 


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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. 

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 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 

lessen the utility or performance of the 

equipment under consideration in the 

rulemaking. 

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 final rule. 

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 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). 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 


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21BT stands for DOE’s Building Technologies 

Program (http://www1.eere.energy.gov/buildings/). 

22The 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. 23See 10 CFR 431.196. 

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 Web site: 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 

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. Market and Technology Assessment 

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. 

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: Liquidimmersed, 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). 

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 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 

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 standards 23

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 

liquid-immersed and medium-voltage 

dry-type transformers, both DOE 

coverage and that of NEMA’s TP–1 

standard extends to 833 kVA for singlephase units and 2500 kVA for threephase units. For low-voltage dry-type 

units, both DOE coverage and that of 

NEMA’s Premium specification extends 

to 333 kVA for single-phase units and 


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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 

three-phase transformers with wyeconnected phase windings or singlephase transformers that are rated for 

externally connecting in a wye 

configuration, where the phase-to-phase 

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 three-phase 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: 

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 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) 

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 


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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 

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. 

(Prolec-GE, No. 146 at pp. 55–56) 

However, Earthjustice commented that 

simply requiring 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 stepup 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; ProlecGE, No. 177 at p. 7) PEMCO commented 

that no action was necessary 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 has an input voltage of 

600 V or less; is air-cooled; and 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 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 


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24See chapter 5 of the TSD for further discussion 

of equipment classes. 

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 (lowvoltage, single-phase dry-type) and EC4 

(low-voltage, three-phase dry-type). 

With standards thereby established for 

low-voltage dry-type distribution 

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, liquidimmersed’’ (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, drytype 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). 

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 drytype 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 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, padmounted, and possibly other types of 


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liquid-immersed 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, 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 polemounted 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 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 liquidimmersed 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 polemounted 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 liquidimmersed transformers should be 

considered in 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; ConEd, 

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 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) 

Other stakeholders noted that while 

network and vault transformers could 

experience dimensional problems at 

higher efficiencies, these problems are 


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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 nonnetworked 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 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 drytype 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 as BIL increases, a 

greater volume of core material is 

needed, adding both expense and noload 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 

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 150 kV BIL class. Transformers 

having an insulation system designed to 

withstand 150 kV BIL and either a lineto-ground or line-to-neutral voltage that 

is 19 kV (e.g. 34500GY/19920 or 19920 

Delta) or greater would be required to 

qualify as a true 150 kV 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 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 liquidimmersed 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 


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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. 

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 liquid-immersed 

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 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 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 220 25 insulation or 

temperature rise less than 110°C with 

class 200 26 insulation; 

3. a secondary winding arrangement 

that is not delta or wye (star); 

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. 

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) 

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 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 


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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. 

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. 

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/vaultbased, 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. 

3. Technology Options 

The technology assessment provides 

information about existing technology 

options to construct more energyefficient 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) Highergrade 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. 

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) ................................................................ Lower ................ Higher ............... Higher. 

Decreasing volts per turn ............................................................................................ Lower ................ 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 .................................................................................................. Higher ............... Lower ................ Lower. 

Increasing volts per turn .............................................................................................. Higher ............... 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, HYDROQuebec offered more information on 

their iron-based amorphous alloy 

ribbon. It noted that it has two 

technologies to produce this amorphous 


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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 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, highthroughput, 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, 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 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 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. 

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. 

DOE understands that, because of 

zero-sequence fluxes associated with 

wye-wye connected transformers, 

symmetric core designs are best suited 

to delta-delta or delta-wye connections. 

While traditional cores can circumvent 

the problem of zero-sequence fluxes by 

introducing a fourth or fifth unwound 

leg, core symmetry makes extra legs 

inherently impractical. 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 


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tertiary winding in a symmetric core 

design. 

DOE understands that symmetric core 

designs are more challenging to 

manufacture and require specialized 

equipment that is currently uncommon 

in the industry. However, DOE did not 

find a reasonable basis to screen this 

technology option out of the analysis, 

and is aware of at least one 

manufacturer producing dry-type 

symmetric core designs commercially in 

the United States. 

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 

[Percentage changes] 

Core losses 

W 

Core weight 

lb Labor hours 

.

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 costefficiency 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 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 

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, they 

pointed out that the presence of a delta 

tertiary winding on a wye-wye threephase 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 


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27Except for the amorphous design options, 

because DOE eliminates consideration of 

amorphous cores in butt-lapped and other stacked 

configurations in its screening analysis. 

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 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. 

d. Core Construction Technique 

DOE examines a number of core 

construction techniques in its 

engineering analysis, including buttlapping, full mitering, step-lap mitering, 

and distributed gap wound 

construction. Particularly in the lowvoltage 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 buttlapped 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 buttlapping is not possible beyond EL 2. For 

design lines 6 and 8, the topic of buttlapping is less consequential. All of 

DOE’s design line 6 analysis is centered 

around butt-lapping,27 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 buttlapping 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 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) 

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 buttlapped core construction in today’s rule 

to extend through EL 3 in DL 7. 

B. Screening Analysis 

DOE uses the following four screening 

criteria to determine which design 

options are suitable for further 

consideration in a standards 

rulemaking: 

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. 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 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 


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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 Removal ...................................... Technological feasibility. 

High-Temperature Insulating Material ...................................................... Technological feasibility. 

Solid-State (Power Electronics) Technology ............................................ Technological feasibility; Practicability to manufacture, install, and 

service. 

Nanotechnology Composites .................................................................... Technological feasibility. 

Chapter 4 of 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, 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 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. Engineering Analysis 

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. 

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 

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 


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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 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). 

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, 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 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 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. 


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28A 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. 

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. 

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, single-phase 15–333 25 kVA, 150 °C, single-phase, 60Hz, 480V primary, 120/240V secondary, 10kV BIL. 

4 ........ 7 ....... Dry-type, low-voltage, three-phase .. 15–150 75 kVA, 150 °C, three-phase, 60Hz, 480V primary, 208Y/120V secondary, 10kV BIL. 

8 ....... Dry-type, low-voltage, three-phase .. 225–1000 300 kVA, 150 °C, three-phase, 60Hz, 480V Delta primary, 208Y/120V 

secondary, 10kV BIL. 

6 ........ 9 ....... Dry-type, medium-voltage, threephase, 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, threephase, 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, threephase, 46–95kV BIL.15–500 300 kVA, 150 °C, three-phase, 60Hz, 12470V primary, 480Y/277V secondary, 95kV BIL. 

12 ..... Dry-type, medium-voltage, threephase, 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, threephase, 96–150kV BIL.75–833 300 kVA, 150 °C, three-phase, 60Hz, 24940V primary, 480Y/277V secondary, 125kV BIL. 

13B ... Dry-type, medium-voltage, threephase, 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 given DL. 

For each design option combination 

chosen, DOE evaluates 518 designs 

based on different A and B factor 28

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. 

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 

dry-type representative units that are 


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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. 

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 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 

medium-voltage 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 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 buttlapped 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 

consulted with technical design experts, 

and they confirmed butt-lapping was 

technically feasible through EL 3. In 

addition, as detailed in section IV.A.3, 

DOE received public comment 

supporting this conclusion and did not 

receive public comments directly 

refuting this conclusion. (See, e.g., 

ASAP, No. 186 at pp. 3, 7–8; Eaton, No. 

157 at p. 2; 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 

$249 million (in 2011$). 

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, wellcapitalized 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 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 


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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 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 fiveyear 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. 

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. 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. (ProlecGE, 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. 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 

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 


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engineering analysis by considering the 

full range of production costs and nonproduction costs. The full production 

cost is a combination of direct labor, 

direct materials, and overhead. The 

overhead contributing to full production 

cost includes indirect labor, indirect 

material, maintenance, depreciation, 

taxes, and insurance related to company 

assets. Non-production cost includes the 

cost of selling, general and 

administrative items (market research, 

advertising, sales representatives, 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 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 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 inhouse 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 

medium-voltage dry-type designs. In the 

medium-voltage case, DOE incorporated 

a processing cost of 10 cents per core 

pound for step-lap mitering. In the lowvoltage 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 step-lap 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, drytype 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 liquidimmersed 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 additional 

hardware costs for bracing in the liquidimmersed designs using amorphous 

cores. This is because DOE already 

accounts for bracing costs for all of its 

liquid-immersed 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. 

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 


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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 

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 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 low-voltage 

transformers. The incrementally higher 

efficiency benchmarks are referred to as 

‘‘efficiency levels’’ (ELs) and, along with 

MSP values, characterize the costefficiency 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. 

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 maximumtechnologically 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. 

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 singlephase 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. 10; NRECA, No. 172 at p. 6; 

Power Partners, No. 155 at p. 3; ProlecGE, 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 liquidimmersed 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. 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 polemounted 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 threephase standards. Several parties 

commented on the matter in response to 

the NOPR. 

Howard Industries and Power 

Partners both supported linking singleand three-phase 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. 

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 liquidimmersed 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; 


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30 In other words, how well a transformer 

maintains output voltage as load increases. 

BG&E, No. 182 at p.10; ComEd, No. 184 

at 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 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] regulation 30 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. (ProlecGE, 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 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 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 medium-voltage 

dry-type design lines. Details on the 

specific values of the adjustments made 

can be found in chapter 5 of the TSD. 

D. Markups Analysis 

The markups analysis develops 

appropriate markups in the distribution 

chain to convert the estimates of 

manufacturer selling price derived in 

the engineering analysis to 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 


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23372 Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 

31RSMeans Electrical Cost Data 2011; 2010; J.H. 

Chiang, C. Babbitt. 

32 1992 Commercial Building Energy 

Consumption and Expenditures Survey (CBECS); 

1995; U.S. Department of Energy—Energy 

Information Administration; http:// 

www.eia.doe.gov/emeu/cbecs/microdat.html. 

33Manufacturing Energy Consumption Survey 

(MECS); 2006 U.S. Department of Energy—Energy 

Information Administration; http://www.eia.gov/ 

emeu/mecs/contents.html. 

Electrical Cost Data 2011.31 DOE 

developed separate markups for 

baseline equipment (baseline markups) 

and for the incremental cost of moreefficient equipment (incremental 

markups). Incremental markups are 

coefficients that relate the change in the 

installation cost due to the increase 

equipment weight of some higherefficiency models. 

Chapter 6 of the final rule TSD 

provides additional detail on the 

markups analysis. 

E. Energy Use Analysis 

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. 

The energy used by distribution 

transformers is characterized by two 

types of losses. The first are no-load 

losses, which are also known as core 

losses. No-load losses are roughly 

constant and exist whenever the 

transformer is energized (i.e., connected 

to live power lines). The second are load 

losses, which are also known as 

resistance or I2R losses. Load losses vary 

with the square of the load being served 

by the transformer. 

Because the application of 

distribution transformers varies 

significantly by type of transformer 

(liquid immersed or dry type) and 

ownership (electric utilities own 

approximately 95 percent of liquidimmersed 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 

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 liquidimmersed distribution transformers. 

For the NOPR, higher-capacity threephase liquid-immersed and mediumvoltage 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. Low-voltage 

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 liquidimmersed transformers and closer to 60 

percent for three-phase liquid-immersed 

transformers. (Cooper, No. 165 at p. 5) 

EEI stated that higher capacity threephase 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 

single-phase liquid-immersed 

transformers using submitted data, so it 

retained the loading used in the NOPR 

for the final rule. For three-phase liquidimmersed transformers, DOE 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 Survey data for 

the years 1992 and 1995 were used, as 

these are the only years for which 

monthly customer electricity 

consumption (kWh) and peak demand 

(kW) are provided. To account for 

changes in the distribution of building 

floor space by building type and size, 

the weights defined in the 1992 and 

1995 building samples were rescaled to 

reflect the distribution in the most 

recent (2003) CBECS survey. CBECS 

covers primarily commercial buildings, 

but a significant fraction of transformers 

are shipped to industrial building 

owners. To account for this in the 

sample, data from the 2006 

Manufacturing Energy Consumption 

Survey (MECS) 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. 


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34Customers refer to electric utilities in the case 

of liquid-immersed transformers, and to utilities 

and building owners in the case of dry-type 

transformers. 

F. Life-Cycle Cost and Payback Period 

Analysis 

DOE conducts LCC and PBP analyses 

to evaluate the economic impacts on 

individual customers of potential energy 

conservation standards for distribution 

transformers.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 basecase efficiency levels. The base-case 

estimate reflects 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.16 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. 

TABLE IV.6—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 and a markup to cover installation labor, pole 

replacement costs for design line 2 and equipment wear and tear.

Added pole replacement cost for 

design line 3. 

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 liquid-immersed transformers, 2% for low-voltage drytype 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 liquid-immersed and 0% per year for dry-type 

transformers.

No change. 

Power factor .................................... Assumed to be unity .............................................................................. No change. 

Annual energy use and demand ..... Derived from a statistical hourly load simulation for liquid-immersed 

transformers, and estimated from the 1992 and 1995 Commercial 

Building Energy Consumption Survey 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.

No change. 

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 liquid-immersed 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. 


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35 J.H. Chiang, C. Babbitt ; RSMeans Electrical 

Cost Data 2011; 2010. 

36American 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. 

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. 

1. Modeling Transformer Purchase 

Decision 

The LCC spreadsheet uses a purchasedecision 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. 

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 inflationadjusted 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. 

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 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 ANSI 36 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. 

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 changeout costs were submitted by the subcommittee. These examples were 

consistent with data taken from the 


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38 J.H. Chiang, C. Babbitt; RSMeans Electrical Cost 

Data 2011; 2010. 

39As 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. 

RSMeans Building Construction Cost 

database.38 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 weight-based 

installation cost described above. 

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 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 changeouts. 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 polemounted 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. 

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. 

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 load-growth 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 liquidimmersed transformers, which are 

owned predominantly by utilities that 

pay costs that vary by the hour. DOE 

used the 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 


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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. 

41CAISO 2011 Market Issues and Performance 

Report, pp. 45–48, http://www.caiso.com/

Documents/2011AnnualReport-MarketIssuesPerformance.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%20Report.pdf. 

42The 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. 

43A 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-of-generation-costs-and-compensation.ashx. 

44CAISO 2011, p. 181, http://www.caiso.com/

Documents/2011AnnualReport-MarketIssuesPerformance.pdf. 

45MISO 2010, p. viii; https:// 

www.midwestiso.org/Library/Repository/Report/

IMM/2010%20State%20of%20the%20Market%

20Report.pdf. 

46 ISO New England 2010 Annual Markets Report, 

p. 33, 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.pdf. NYISO 2010, p. 156; http:// 

www.nyiso.com/public/markets_operations/

documents/studies_reports/index.jsp. 

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. 

49PJM 2009, Executive Summary p. 6. 

50 ISO–NE 2010, p. 33; http://www.iso-ne.com/ 

markets/mkt_anlys_rpts/annl_mkt_rpts/2010/ 

amr10_final_060311.pdf. 

51See http://docs.cpuc.ca.gov/efile/PD/ 

162141.pdf. 

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 

price-clearing 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 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 costs 42 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 NRECA 

acknowledges the 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 energyonly 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 

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 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 Market 49 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 


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52Barnes. Determination Analysis of Energy 

Conservation Standards for Distribution 

Transformers. ORNL–6847. 1996. 

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 combinedcycle, and 20 percent wind. These 

proportions are based on the capacity 

mix estimated in the AEO 2011 

projection. 

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 liquidimmersed 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 no-load 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. 

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. 

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 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. 

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. National Impact Analysis—National 

Energy Savings and Net Present Value 

Analysis 

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 


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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. 

levels. (‘‘Customer’’ refers to purchasers 

of the equipment being regulated.) 

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 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 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.27 and Table IV.38 

summarize all the major NOPR inputs to 

the shipments analysis and the NIA, and 

whether those inputs were revised for 

the final rule. 

TABLE IV.7—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/liquid-immersed market 

shares.

Based 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, liquid-immersed ................. For 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. 

TABLE IV.8—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 liquid-immersed distribution transformers.No 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 for 2044 and beyond .......... Updated to AEO 2012. 

Electricity site-to-source conversion .... A 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. 


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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 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. 

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 

preamble. 

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. 

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 energy production. (Pub. L. 109–58 

(August 8, 2005)). NAS appointed a 

committee on ‘‘Point-of-Use and FullFuel-Cycle Measurement Approaches to 

Energy Efficiency Standards’’ to conduct 

the study, which was completed in May 

2009. The NAS committee defined fullfuel-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 full-fuel-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 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 fullfuel-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, 


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54OMB Circular A–4 (Sept. 17, 2003), section E, 

‘‘Identifying and Measuring Benefits and Costs. 

Available at: www.whitehouse.gov/omb/ 

memoranda/m03-21.html. 

55See 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. 

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 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

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 ‘‘social rate of time 

preference,’’ which is the rate at which 

society discounts future consumption 

flows to their present value. 

H. Customer Subgroup Analysis 

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. 

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; ProlecGE, 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 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 $1,886 

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. Manufacturer Impact Analysis 

1. Overview 

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 

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 noncapitalized 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 of 

such technical expertise may be 

particularly difficult for manufacturers 


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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 bottomup 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: (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 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 highgrade 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 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. 

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 


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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 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 pad-mounted 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 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 

liquid-immersed 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 liquidimmersed 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 

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 noncompetitive market for new liquidimmersed 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 liquidimmersed market to amorphous cores. 

(ATI Allegheny, No. 218 at p. 1) Instead, 

ATI proposed an alternative TSL which 

consists of what it believes are more 

accurate crossover points for the liquidimmersed 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 liquid-immersed transformers 

would impose unwarranted conversion 

costs on transformer producers, force 

the use of amorphous metals that are not 

available in adequate supply, and create 

significant anticompetitive market 

power for the producer of amorphous 

metal electrical steel. (UAW, No. 194 at 


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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 liquidimmersed transformers. Domestic 

steelmakers agreed, explaining that the 

anticompetitive ramifications of a 

decision to promulgate a standard 

greater than TSL 1 for the liquidimmersed 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 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. 

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. 

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 

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 


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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. ProlecGE 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 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 liquid-immersed 

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 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 liquid-immersed 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 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 highgrade 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 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. (HydroQuebec, 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 


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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 

liquid-immersed transformers would 

lead to shortages of amorphous metal 

such that grain-oriented electrical steel 

cores would have to be used in noncost-effective applications, but in the 

TSD, those TSLs would split the market 

between amorphous and grain-oriented 

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 foreignowned (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 foreignowned. 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 

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 grainoriented 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 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 buttlapping, they may not be able to sell 

their transformers at a price where 

material costs are recovered. (HVOLT, 

No. 146 at p. 151) 

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 


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small business impacts in its decisionmaking criteria. Companies also have 

the option of sourcing their cores from 

third party suppliers, who can obtain 

better materials prices than all but the 

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) 

Also, Earthjustice has commented that 

DOE has arbitrarily relied on impacts on 

small manufacturers in rejecting 

stronger standards for low-voltage drytype (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, 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 

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 DOEcovered 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. 

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 butt-lap 

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 


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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 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 

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 leastcost 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) 

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) 

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 liquid-immersed distribution 

transformer sales, 75 percent of 

medium-voltage dry-type transformer 

sales, and 50 percent of low-voltage drytype 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. 

J. Employment Impact Analysis 

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. 


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56See Bureau of Economic Analysis, Regional 

Multipliers: A User Handbook for the Regional 

Input-Output Modeling System (RIMS II). 

Washington, DC. U.S. Department of Commerce, 

1992. 

57On 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. 

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 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 

labor-intensive 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 special-purpose version of 

the ‘‘U.S. Benchmark National InputOutput’’ (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, 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. Utility Impact Analysis 

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 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. 

L. Emissions Analysis 

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 

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 (DC). SO2 emissions from 28 

eastern States and DC 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 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 Cross-State 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 

pollutants (HAP), and also established a 

standard for SO2 (a non-HAP acid gas) 

as an alternative equivalent surrogate 


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58National Research Council. ‘‘Hidden Costs of 

Energy: Unpriced Consequences of Energy 

Production and Use.’’ National Academies Press: 

Washington, DC 2009. 

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. 

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. Monetizing Carbon Dioxide and 

Other Emissions Impacts 

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. 

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. 

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. 

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 

Council 58 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 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. 


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59See 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: http://www.nhtsa.gov/fuel-economy). 

60See 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). 

61The models are described in appendix 15–A of 

the final rule TSD. 

62 It is recognized that this calculation for 

domestic values is approximate, provisional, and 

highly speculative. 

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 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

A regulation for packaged 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 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 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 higherthan-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.9. 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. 


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63Table 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. 

64U.S. Office of Management and Budget, Office 

of Information and Regulatory Affairs, 2006 Report 

to Congress on the Costs and Benefits of Federal 

Regulations and Unfunded Mandates on State, 

Local, and Tribal Entities, Washington, DC Page 64. 

65OMB, Circular A–4: Regulatory Analysis (Sept. 

17, 2003). 

66See 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. 

TABLE IV.9—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 

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. 

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 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 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 

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. Labeling Requirements 

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. 


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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 

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-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 part 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 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. Discussion of Other Comments 

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. 

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 liquidimmersed distribution transformers, six 

TSLs for low-voltage dry-type 

distribution transformers, and five TSLs 

for medium-voltage dry-type 

distribution transformers. 

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 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 anticompetitive 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 


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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 liquidimmersed 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 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 

liquid-immersed 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 

preamble. DOE notes that, for the final 

rule, it has slightly modified the 

definition of TSL 2 for low-voltage drytype 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 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; Prolec-GE, 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 lessefficient, 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 

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 line 

2) and 13.1 percent (design line 3) 

higher than today’s typical single-phase 

liquid-immersed 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 


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units that 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 

cost-effective means of finding 

efficiency in electric distribution 

systems than by increasing 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 mediumvoltage 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-drytype 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) 

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 

well-balanced, 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 

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-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 lowvoltage dry-type and medium-voltage 

liquid-immersed transformers. They 

stated that higher standards than those 


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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 potential 

energy savings and recommended 

higher standards for both liquidimmersed 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 grainoriented steels will also expand as a 

result of higher standards for lowvoltage 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) 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 liquidimmersed 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 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) 

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 

liquid-immersed 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 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 pole-mounted transformers. 

(EEI, No. 185 at p. 11) A number of 

electric utilities made similar 

comments. (BG&E, No. 182 at p. 6; 


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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; ProlecGE, 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 noncompetitive market for new mediumvoltage liquid-type designs that would 

eliminate projected LCC savings. (ATI, 

No. 54 at p. 2) Steelmakers commented 

that promulgating energy conservation 

standards greater than TSL 1 for liquidimmersed 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 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) 

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 

low-voltage 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) 

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 DryType Distribution Transformers 

The Advocates expressed support for 

the proposed standards for mediumvoltage 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 singlephase 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 


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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 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. 

V. Analytical Results and Conclusions 

A. Trial Standard Levels 

Table V.1 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 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 cost-competitive 

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 DRY-TYPE TRANSFORMERS BY

DESIGN LINE

Design line Baseline 

TSL 

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 


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TABLE V.3—EFFICIENCY VALUES OF THE TRIAL STANDARD LEVELS FOR MEDIUM-VOLTAGE DRY-TYPE 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. Economic Justification and Energy 

Savings 

1. Economic Impacts on Customers 

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, higherefficiency 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 preamble 

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 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. 

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. 


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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. 

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 


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TABLE V.10—SUMMARY LIFE-CYCLE COST AND PAYBACK PERIOD RESULTS FOR DESIGN LINE 7 REPRESENTATIVE UNIT— 

Continued 

Trial standard level 

1 2 3 4 5 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. 

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. 

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. 


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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. 

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 


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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 rebuttablepresumption 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. 

TABLE V.19—REBUTTABLE-PRESUMPTION PAYBACK PERIODS (YEARS) FOR LIQUID-IMMERSED DISTRIBUTION

TRANSFORMERS

Design line Rated capacity 

kVA 

Trial standard level 

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 DRY-TYPE DISTRIBUTION

TRANSFORMERS

Design line Rated capacity kVA 

Trial standard level 

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 kVA 

Trial standard level 

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 

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 drytype, 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 apply). 

Each of the two scenarios results in a 


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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 

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 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 highprofitability 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). 

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 


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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). 

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 basecase value of $36.0 million in the year 

before the compliance date (2015). 

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). 

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 drytype 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 

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. 


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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 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 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. 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 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: 


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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. 

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 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. 

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 HiB 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 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 


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67A 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. 

would face significant challenges that 

DOE believes would lead to 

consolidation and likely cause many 

low-volume 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. 

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 DOE-covered liquidimmersed 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. 

Low-Voltage Dry-Type. Based on 

interviews with manufacturers, DOE 

estimates that there are approximately 

2,200 employees associated with DOEcovered 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 in-house, 

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 cleansheet 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 DOEcovered 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. 

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 


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68Chapter 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. 

69EPCA 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. 

70OMB Circular A–4, section E (Sept. 17, 2003). 

Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4. 

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 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 

quads 

Liquid-immersed ....................................... 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 .................... ....................

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 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 Table V.29. 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 

quads 

Liquid-immersed ....................................... 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 .................... ....................

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 beforetax 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 


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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. 

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 

billion 2011$ 

Liquid-immersed ............... 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 ....................

Medium-voltage dry-type 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$ 

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 dry-type ........ 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. 

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 


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peak-load periods. As a measure of this 

reduced demand, 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 

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) .... 7.06 13.29 25.65 25.65 38.69 ........................ ........................

Hg (tons) ...................... 0.02 0.04 0.10 0.10 0.14 ........................ ........................

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 

95th-percentile 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 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 *

Million 2011$ 

Liquid-Immersed 

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 


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TABLE V.33—ESTIMATES OF GLOBAL PRESENT VALUE OF CO2 EMISSIONS REDUCTION UNDER DISTRIBUTION

TRANSFORMER TRIAL STANDARD LEVELS—Continued 

TSL 

5% discount 

rate, average *

3% discount 

rate, average *

2.5% discount rate, 

average *

3% discount 

rate, 95th 

percentile *

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 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. 

TABLE V.34—ESTIMATES OF PRESENT

VALUE OF NOX EMISSIONS REDUCTION UNDER DISTRIBUTION TRANSFORMER TRIAL STANDARD LEVELS

TSL 3% discount 

rate 

7% discount 

rate 

Million 2011$ 

Liquid-Immersed 

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 

TABLE V.34—ESTIMATES OF PRESENT

VALUE OF NOX EMISSIONS REDUCTION UNDER DISTRIBUTION TRANSFORMER TRIAL STANDARD LEVELS— 

Continued 

TSL 3% discount 

rate 

7% discount 

rate 

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 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 seven-percent 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. 


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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 ** 

Billion 2011$ 

1 ....................................................................................... 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 ** 

Billion 2011$ 

1 ....................................................................................... 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. 

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 ** 

Billion 2011$ 

1 ....................................................................................... 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 ** 

Billion 2011$ 

1 ....................................................................................... 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. 


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** 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. 

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 ** 

Billion 2011$ 

1 ....................................................................................... 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 ** 

Billion 2011$ 

1 ....................................................................................... 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 values, on the other hand, reflect 

the present value of future climaterelated 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 (grainoriented) electrical steels, but this 

would result in distribution 

transformers that are unlikely to be costcompetitive with the often moreefficient 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. Conclusion 

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 


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burdens to the greatest extent 

practicable, in light of the seven 

statutory factors discussed previously. 

(42 U.S.C. 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. 

1. Benefits and Burdens of Trial 

Standard Levels Considered for LiquidImmersed 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 quads.

0.92 ................. 1.56 ................. 1.76 ................. 3.31 ................. 3.30 ................. 4.09 ................. 7.01 

NPV of Consumer Benefits 2011$ billion 

3% discount rate 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 

2011$ million.

13 to 138 ......... 24 to 242 ......... 26 to 263 ......... 44 to 454 ......... 44 to 452 ......... 51 to 525 ......... 78 to 799 

NOX ¥ 7% discount rate 

2011$ million.

6 to 57 ............. 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. 

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 2011$ 

Design line 1 ..... 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 


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TABLE V.39—SUMMARY OF ANALYTICAL RESULTS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS: MANUFACTURER

AND CONSUMER IMPACTS—Continued 

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7 

Consumer Median PBP years 

Design line 1 ..... 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. 

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 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 liquidimmersed 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. 


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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 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 

demand). Thus, the current availability 

is far below the amount that would be 

required to meet the U.S. liquidimmersed 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 liquidimmersed 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. 

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 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 liquidimmersed 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 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 


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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. 

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 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. liquidimmersed 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. 

In view of the foregoing, DOE 

concludes that, at TSL 4 for liquidimmersed 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 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 liquidimmersed 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 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. 

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 


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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 liquidimmersed 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 

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. 

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 

liquid-immersed distribution 

transformers at TSL 1. Table V.40 

presents the energy conservation 

standards for liquid-immersed 

distribution transformers. 

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 LowVoltage Dry-Type Distribution 

Transformers 

Table V.41 and Table V.42 summarize 

the quantitative impacts estimated for 

each TSL for low-voltage dry-type 

distribution transformers. 


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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 

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. 

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. 

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 


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23420 Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 

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, 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. 

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. 

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. 

Additionally, TSL 4 requires 

significant investment in advanced core 

construction equipment such are steplap 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. 

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 


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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 steplap 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 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 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 

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 lowvoltage 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. 


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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 

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 


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72See section IV.I.5.a for further detail. 

TABLE V.45—SUMMARY OF ANALYTICAL RESULTS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS: 

MANUFACTURER AND CONSUMER IMPACTS—Continued 

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 

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. 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

In view of the foregoing, DOE 

concludes that, at TSL 5 for mediumvoltage dry-type 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 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 mediumvoltage 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, 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. 

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 


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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 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 mediumvoltage 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, 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. 

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 mediumvoltage 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 (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. 


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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 


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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. 

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 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 climaterelated 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 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 

% 

Million 2011$/year 

Primary estimate * 

Low net 

benefits 

estimate * 

High net 

benefits 

estimate * 

.............................................. 

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 ($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 ............. 381 to 1044 ...... 325 to 988 ........ 400 to 1063. 

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 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. 

** 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. 

† 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. 


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Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 23427 

VI. Procedural Issues and Regulatory 

Review 

A. Review Under Executive Orders 

12866 and 13563 

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 

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 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 liquidimmersed 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 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. 

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. Review Under the Regulatory 

Flexibility Act 

The Regulatory Flexibility Act (5 

U.S.C. 601 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 Web site (http:// 

energy.gov/gc/office-general-counsel). 

DOE reviewed the February 2012 NOPR 

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 


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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. 

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 liquidimmersed 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 of the 17 small business 

manufacturers. DOE also obtained 

information about small business 

impacts while interviewing large 

manufacturers. 

b. Distribution Transformer Industry 

Structure 

Liquid Immersed. 

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. 

Low-Voltage Dry-Type. 

Four major manufacturers supply 

more than 80 percent of the market for 

low-voltage 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 lowvoltage dry-type market produce 

specialized 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 highvolume 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 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. 

Medium-Voltage Dry-Type. 

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. 

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. 

Lower production volumes are the 

root cause of most small business 


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disadvantages, particularly for a small 

manufacturer that is vertically 

integrated. A lower-volume 

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 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 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 buttlapping 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. 

Compared to higher TSLs, TSL 2 

provides many more design paths for 

small manufacturers to comply. 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 higher-grade 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 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, 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 in in-house mitering 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. 


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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 

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 DOE 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 above 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 mediumvoltage 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. 

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 lowvoltage dry-type, medium-voltage drytype, 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 

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. 

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. 


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Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 23431 

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 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 liquidimmersed and medium-voltage dry-type 

transformers and TSL2 is the highest 

level that can be justified for lowvoltage 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 liquidimmersed 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 drytype transformers, as would TSL 2 or 

higher for liquid-immersed and 

medium-voltage dry-type transformers. 

Such burdens would 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 liquid-immersed 

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 medium-voltage 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). 

C. Review Under the Paperwork 

Reduction Act 

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-ofinformation 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. 

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. Review Under the National 

Environmental Policy Act of 1969 

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 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/cx007852-categorical-exclusiondetermination. 

E. Review Under Executive Order 13132 

Executive Order 13132, ‘‘Federalism.’’ 

64 FR 43255 (Aug. 10, 1999) imposes 

certain requirements on Federal 


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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 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. Review Under Executive Order 12988 

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, to 

the extent permitted by law, this final 

rule meets the relevant standards of 

Executive Order 12988. 

G. Review Under the Unfunded 

Mandates Reform Act of 1995 

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 http:// 

energy.gov/gc/office-general-counsel. 

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 

higher-efficiency 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 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. Review Under the Treasury and 

General Government Appropriations 

Act, 1999 

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. 

I. Review Under Executive Order 12630 

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. 

J. Review Under the Treasury and 

General Government Appropriations 

Act, 2001 

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 


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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. 

K. Review Under Executive Order 13211 

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. 

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. Review Under the Information 

Quality Bulletin for Peer Review 

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. 

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. Congressional Notification 

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). 

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. 

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, 

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 

Transformers. (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. 

Single-phase Three-phase 

kVA % kVA % 

15 .................................................................................. 97.7 15 ................................................................................. 97.0 


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Single-phase Three-phase 

kVA % kVA % 

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. 

(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 

Transformers. (1) The efficiency of a 

liquid-immersed 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. 

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 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. 


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Federal Register / Vol. 78, No. 75 / Thursday, April 18, 2013 / Rules and Regulations 23435 

(2) The efficiency of a liquidimmersed 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. 

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. Mediumvoltage 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 

BIL* 

kVA 

BIL 

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

Efficiency 

(%) 

Efficiency 

(%) 

Efficiency 

(%) 

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 mediumvoltage 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. Mediumvoltage 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. 


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Single-phase Three-phase 

kVA 

BIL* 

kVA 

BIL 

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

Efficiency 

(%) 

Efficiency 

(%) 

Efficiency 

(%) 

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] 

Appendix 

Note: 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, drytype and liquid-immersed 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. 

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 mediumvoltage, dry-type distribution transformers 

were arrived at through a consensus 

agreement among a diverse array of 

stakeholders. 

Sincerely, 

Joseph F. Wayland 

[FR Doc. 2013–08712 Filed 4–17–13; 8:45 am] 

BILLING CODE 6450–01–P 


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