Thursday,

July 29, 2004

Part 11

Department of

Energy

Office of Energy Efficiency and

Renewable Energy

10 CFR Part 430

Energy Conservation Program for

Commercial and Industrial Equipment:

Energy Conservation Standards for

Distribution Transformers; Proposed Rule

 EE-RM/STD-00-550 COMMENT 53.1

Thursday, 

July 29, 2004 

Part II 

#53.1 

Department of 

Energy 

Office of Energy Efficiency and 

Renewable Energy 

10 CFR Part 430 

Energy Conservation Program for 

Commercial and Industrial Equipment: 

Energy Conservation Standards for 

Distribution Transformers; Proposed Rule 
45376 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

DEPARTMENT OF ENERGY

Office of Energy Efficiency and

Renewable Energy

10 CFR Part 430

[Docket No. EE-RM/STD-00-550]

RIN 1904-AB08

Energy Conservation Program for

Commercial and Industrial Equipment:

Energy Conservation Standards for

Distribution Transformers

AGENCY : Office of Energy Efficiency and

Renewable Energy, Department of

Energy.

ACTION: Advance notice of proposed

rulemaking, public meeting and

webcast.

SUMMARY: The Energy Policy and

Conservation Act (EPCA or the Act)

authorizes the Department of Energy

(DOE or the Department) to establish

energy conservation standards for

various consumer products and

commercial and industrial equipment,

including distribution transformers, if

DOE determines that energy

conservation standards would be

technologically feasible and

economically justified, and would result

in significant energy savings. The

Department publishes this Advance

Notice of Proposed Rulemaking

(ANOPR) to consider establishing

energy conservation standards for

distribution transformers and to

announce a public meeting to receive

comments on a variety of issues.

DATE: The Department will hold a

webcast on August 10, 2004 from 1 p.m.

to 4 p.m. If you are interested in

participating in this event, please

inform Sandy Beall at (202) 586-7574.

The Department will hold a public

meeting on September 28, 2004, starting

at 9 a.m., in Washington, DC. The

Department must receive requests to

speak at the public meeting no later

than 4 p.m., September 14, 2004. The

Department must receive a signed

original and an electronic copy of

statements to be given at the public

meeting no later than 4 p.m., September

21, 2004.

The Department will accept

comments, data, and information

regarding the ANOPR before or after the

public meeting, but no later than

November 9, 2004. See section IV,

"Public Participation," of this ANOPR

for details.

ADDRESSES : The public meeting will be

held at the U.S. Department of Energy,

Forrestal Building, Room 1E-245, 1000

Independence Avenue, SW.,

Washington, DC. (Please note that

foreign nationals visiting DOE

Headquarters are subject to advance

security screening procedures, requiring

a 30-day advance notice. If you are a

foreign national and wish to participate

in the workshop, please inform DOE of

this fact as soon as possible by

contacting Ms. Brenda Edwards-Jones at

(202) 586-2945 so that the necessary

procedures can be completed.)

You may submit comments, identified

by docket number EE-RM/STD-00-550

and/or RIN number 1904-ABO8, by any

of the following methods:

o Federal eRulemaking Portal: http://

www.regulations.gov. Follow the

instructions for submitting comments.

o E-mail: TransformerANOPR

Comment@ee.doe.gov. Include EE-RM/

STD-00-550 and/or RIN 1904-AB08 in

the subject line of the message.

o Mail: Ms. Brenda Edwards-Jones,

U.S. Department of Energy, Building

Technologies Program, Mailstop EE-2J,

ANOPR for Distribution Transformers,

EE-RM/STD-00-550 and/or RIN 1904-

AB08, 1000 Independence Avenue, SW.,

Washington, DC, 20585-0121.

Telephone: (202) 586-2945. Please

submit one signed paper original.

o Hand Delivery/Courier: Ms. Brenda

Edwards-Jones, U.S. Department of

Energy, Building Technologies Program,

Room 1J-018, 1000 Independence

Avenue, SW., Washington, DC, 20585.

Instructions: All submissions received

must include the agency name and

docket number or Regulatory

Information Number (RIN) for this

rulemaking. For detailed instructions on

submitting comments and additional

information on the rulemaking process,

see section IV of this document (Public

Participation).

Docket: For access to the docket to

read background documents or

comments received, go to the U.S.

Department of Energy, Forrestal

Building, Room 1J-018 (Resource Room

of the Building Technologies Program),

1000 Independence Avenue, SW.,

Washington, DC, (202) 586-9127,

between 9 a.m. and 4 p.m., Monday

through Friday, except Federal holidays.

Please call Ms. Brenda Edwards-Jones at

the above telephone number for

additional information regarding

visiting the Resource Room. Please note:

The Department's Freedom of

Information Reading Room (Room 1E190 at the Forrestal Building) is no

longer housing rulemaking materials.

FOR FURTHER INFORMATION CONTACT: Ron

Lewis, Project Manager, Energy

Conservation Standards for Distribution

Transformers, Docket No. EE-RM/STD00-550, EE-2J / Forrestal Building, U.S.

Department of Energy, Office of

Building Technologies, EE-2J, 1000

Independence Avenue SW.,

Washington, DC, 20585-0121, (202)

586-8423. E-mail:

Ronald.Lewis@ee.doe.gov.

Thomas B. DePriest, Esq., U.S.

Department of Energy, Office of General

Counsel, Forrestal Building, Mail

Station GC-72, 1000 Independence

Avenue, SW., Washington, DC, 20585,

(202) 586-9507. E-mail:

Thomas.DePriest@hq.doe.gov.

SUPPLEMENTARY INFORMATION:

I. Introduction

A. Purpose of the ANOPR

B. Summary of the Analysis

1. Engineering Analysis

2. Life-Cycle Cost and Payback Period

Analyses

3. National Impact Analysis

C. Authority

D. Background

1. History of Standards Rulemaking for

Distribution Transformers

2. Process Improvement

3. Test Procedure

If. Distribution Transformer Analyses

A. Market and Technology Assessment

1. Definition of a Distribution Transformer

a. Changes to, and Retention of, Provisions

in the Framework Document Definition

b. Exclusions Discussed in the Test

Procedure Reopening Notice

c. Additional Exclusions Drawn from

NEMA TP 1

d. Distribution Transformer Definition

e. Exclusions Not Incorporated

2. Product Classes

3. Market Assessment

4. Technology Assessment

B. Screening Analysis

C. Engineering Analysis

1. Approach Taken in the Engineering

Analysis

2. Simplifying the Analysis

3. Developing the Engineering Analysis

Inputs

4. Energy Efficient Design Issues

5. Engineering Analysis Results

D. Energy Use and End-Use Load

Characterization

E. Markups for Equipment Price

Determination

F. Life-Cycle Cost and Payback Period

Analyses

1. Approach Taken in the Life-Cycle Cost

Analysis

2. Life-Cycle Cost Inputs

a. Effective Date of Standard

b. Candidate Standard Levels

c. Baseline and Standard Design Selection

d. Power Factor

e. Load Growth

f. Electricity Costs

g. Electricity Price Trends

h. Equipment Lifetime

i. Maintenance Costs

j. Discount Rates

3. Payback Period

4. Life-Cycle Cost and Payback Period

Results

G. Shipments Analysis

1. Shipments Model

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45376 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

DEPARTMENT OF ENERGY 

Office of Energy Efficiency and 

Renewable Energy 

10 CFR Part 430 

[Docket No. EE-RM/STD-OO-550j 

RIN 1904-AB08 

Energy Conservation Program for 

Commercial and Industrial Equipment: 

Energy Conservation Standards for 

Distribution Transformers 

AGENCY: Office of Energy Efficiency and 

Renewable Energy, Department of 

Energy. 

ACTION: Advance notice of proposed 

rulemaking, public meeting and 

webcast. 

SUMMARY: The Energy Policy and 

Conservation Act (EPCA or the Act) 

authorizes the Department of Energy 

(DOE or the Department) to establish 

energy conservation standards for 

various consumer products and 

commercial and industrial equipment, 

including distribution transformers, if 

DOE determines that energy 

conservation standards would be 

technologically feasible and 

economically justified, and would result 

in significant energy savings. The 

Department publishes this Advance 

Notice of Proposed Rulemaking 

(ANOPR) to consider establishing 

energy conservation standards for 

distribution transformers and to 

announce a public meeting to receive 

comments on a variety of issues. 

DATE: The Department will hold a 

web cast on August 10, 2004 from 1 p.m. 

to 4 p.m. If you are interested in 

participating in this event, please 

inform Sandy Beall at (202) 586-7574. 

The Department will hold a public 

meeting on September 28, 2004, starting 

at 9 a.m., in Washington, DC. The 

Department must receive requests to 

speak at the public meeting no later 

than 4 p.m., September 14, 2004. The 

Department must receive a signed 

original and an electronic copy of 

statements to be given at the public 

meeting no later than 4 p.m., September 

21,2004. 

The Department will accept 

comments, data, and information 

regarding the ANOPR before or after the 

public meeting, but no later than 

November 9,2004. See section IV, 

"Public Participation," ofthis ANOPR 

for details. 

ADDRESSES: The public meeting will be 

held at the U.S. Department of Energy, 

Forrestal Building, Room lE-245, 1000 

Independence Avenue, SW., 

Washington, DC. (Please note that 

foreign nationals visiting DOE 

Headquarters are subject to advance 

security screening procedures, requiring 

a 30-day advance notice. If you are a 

foreign national and wish to participate 

in the workshop, please inform DOE of 

this fact as soon as possible by 

contacting Ms. Brenda Edwards-Jones at 

(202) 586-2945 so that the necessary 

procedures can be completed.) 

You may submit comments, identified 

by docket number EE-RM/STD-00-550 

and/or RIN number 1904-AB08, by any 

of the following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the 

instructions for submitting comments. 

• E-mail: TransformerANOPR 

Comment@ee.doe.gov. Include EE-RM/ 

STD-00-550 and/or RIN 1904-AB08 in 

the subject line of the message. 

D Mail: Ms. Brenda Edwards-Jones, 

U.S. Department of Energy, Building 

Technologies Program, Mailstop EE-2J, 

ANOPR for Distribution Transformers, 

EE-RMISTD-00-550 and/or RIN 1904-

AB08, 1000 Independence Avenue, SW., 

Washington, DC, 20585-0121. 

Telephone: (202) 586-2945. Please 

submit one signed paper original. 

• Hand Delivery!Courier: Ms. Brenda 

Edwards-Jones, U.S. Department of 

Energy, Building Technologies Program, 

Room lJ-018, 1000 Independence 

Avenue, SW., Washington, DC, 20585. 

Instructions: All submissions received 

must include the agency name and 

docket number or Regulatory 

Information Number (RIN) for this 

rulemaking. For detailed instructions on 

submitting comments and additional 

information on the rulemaking process, 

see section IV of this document (Public 

Participation). 

Docket: For access to the docket to 

read background documents or 

comments received, go to the U.S. 

Department of Energy, Forrestal 

Building, Room IJ-018 (Resource Room 

of the Building Technologies Program), 

1000 Independence Avenue, SW., 

Washington, DC, (202) 586-9127, 

between 9 a.m. and 4 p.m., Monday 

through Friday, except Federal holidays. 

Please call Ms. Brenda Edwards-Jones at 

the above telephone number for 

additional information regarding 

visiting the Resource Room. Please note: 

The Department's Freedom of 

Information Reading Room (Room lE190 at the Forrestal Building) is no 

longer housing rulemaking materials. 

FOR FURTHER INFORMATION CONTACT: Ron 

Lewis, Project Manager, Energy 

Conservation Standards for Distribution 

Transformers, Docket No. EE-RM/STD00-550, EE-2J / Forrestal Building, U.S. 

Department of Energy, Office of 

Building Technologies, EE-2J, 1000 

Independence Avenue SW., 

Washington, DC, 20585-0121, (202) 

586-8423. E-mail: 

Ronald.Lewis@ee.doe.gov. 

Thomas B. DePriest, Esq., U.S. 

Department of Energy, Office of General 

Counsel, Forrestal Building, Mail 

Station GC-72, 1000 Independence 

Avenue, SW., Washington, DC, 20585, 

(202) 586-9507. E-mail: 

Thomas.DePriest@hq.doe.gov. 

SUPPLEMENTARY INFORMATION: 

I. Introduction 

A. Purpose of the ANOPR 

B. Summary of the Analysis 

1. Engineering Analysis 

2. Life-Cycle Cost and Payback Period 

Analyses 

3. National Impact Analysis 

C. Authority 

D. Background 

1. History of Standards Rulemaking for 

Distribution Transformers 

2. Process Improvement 

3. Test Procedure 

II. Distribution Transformer Analyses 

A. Market and Technology Assessment 

1. Definition of a Distribution Transformer 

a. Changes to, and Retention of, Provisions 

in the Framework Document Definition 

b. Exclusions Discussed in the Test 

Procedure Reopening Notice 

c. Additional Exclusions Drawn from 

NEMA TP1 

d. Distribution Transformer Definition 

e. Exclusions Not Incorporated 

2. Product Classes 

3. Market Assessment 

4. Technology Assessment 

B. Screening Analysis 

C. Engineering Analysis 

1. Approach Taken in the Engineering 

Analysis 

2. Simplifying the Analysis 

3. Developing the Engineering Analysis 

Inputs 

4. Energy Efficient Design Issues 

5. Engineering Analysis Results 

D. Energy Use and End-Use Load 

Characterization 

E. Markups for Equipment Price 

Determination 

F. Life-Cycle Cost and Payback Period 

Analyses 

1. Approach Taken in the Life-Cycle Cost 

Analysis 

2. Life-Cycle Cost Inputs 

a. Effective Date of Standard 

b. Candidate Standard Levels 

c. Baseline and Standard Design Selection 

d. Power Factor 

e. Load Growth 

f. Electricity Costs 

g. Electricity Price Trends 

h. Equipment Lifetime 

i. Maintenance Costs 

j. Discount Rates 

3. Payback Period 

4. Life-Cycle Cost and Payback Period 

Results 

G. Shipments Analysis 

1. Shipments Model 
Federal Register / Vol. 69, No. 145 / Thursday, July 29, 2004 / Proposed Rules

2. Shipments Model Inputs

3. Shipments Model Results

H. National Impact Analysis

1. Method

2. National Energy Savings

a. National Energy Savings Overview

b. National Energy Savings Inputs

3. Net Present Value Calculation

a. Net Present Value Overview

b. Net Present Value Inputs

4. National Energy Savings and Net Present

Value Results

a. National Energy Savings and Net Present

Value from Candidate Standard Levels

I. Life-Cycle Cost Sub-Group Analysis

J. Manufacturer Impact Analysis

1. Sources of Information for the

Manufacturer Impact Analysis

2. Industry Cash Flow Analysis

3. Manufacturer Sub-Group Analysis

4. Competitive Impacts Assessment

5. Cumulative Regulatory Burden

K. Utility Impact Analysis

L. Employment Impact Analysis

M. Environmental Assessment

N. Regulatory Impact Analysis

III. Proposed Standards Scenarios

IV. Public Participation

A. Attendance at Public Meeting

B. Procedure for Submitting Requests to

Speak

C. Conduct of Public Meeting

D. Submission of Comments

E. Issues on Which DOE Seeks Comment

1. Definition and Coverage

2. Product Classes

3. Engineering Analysis Inputs

4. Design Option Combinations

5. The 0.75 Scaling Rule

6. Modeling of Transformer Load Profiles

7. Distribution Chain Markups

8. Discount Rate Selection and Use

9. Baseline Determination Through

Purchase Evaluation Formulae

10. Electricity Prices

11. Load Growth Over Time

12. Life-Cycle Cost Sub-Groups

13. Utility Deregulation Impacts

V. Regulatory Review and Procedural

Requirements

VI. Approval of the Office of the Secretary

I. Introduction

A. Purpose of the ANOPR

The purpose of this ANOPR is to

provide interested persons with an

opportunity to comment on:

(i) The product classes that the

Department is planning to analyze;

(ii) The analytical framework, models,

and tools (e.g. life-cycle cost (LCC) and

national energy savings (NES)

spreadsheets) used by the Department in

performing analyses of the impacts of

energy conservation standards;

(iii) The results of the engineering

analysis, the LCC and payback period

(PBP) analyses, and the national impact

analysis presented in the ANOPR

Technical Support Document (TSD):

Energy Efficiency Standards for

Commercial and Industrial Equipment:

Electric Distribution Transformers; and

(iv) The candidate energy

conservation standard levels that the

Department has developed from these

analyses.

B. Summary of the Analysis

The Energy Policy and Conservation

Act (42 U.S.C. 6317) authorizes DOE to

consider establishing energy

conservation standards for various

consumer products and commercial and

industrial equipment, including

distribution transformers, which are the

subject of this ANOPR.

The Department conducted eight

analyses for this ANOPR: Market and

technology assessment, screening

analysis, engineering analysis, energy

use and end-use load characterization,

markups for equipment price

determination, LCC and PBP analyses,

shipments analysis, and national impact

analysis. Three of the above analyses

produce key results while the other five

produce intermediate inputs. The three

key analyses conducted are summarized

briefly below: (1) Engineering; (2) lifecycle cost and payback periods; and (3)

national impacts.

1. Engineering Analysis

The engineering analysis estimates

the relationship between cost and

efficiency for selected distribution

transformers. The Department

structured the engineering analysis

around 13 groupings (termed

"engineering design lines') of similarly

built distribution transformers. The

Department then identified one

representative unit from each grouping,

conducted software design runs on

those units, estimated the material and

labor costs, and calculated the

performance of each design. Markups

were applied to the manufacturer costs

to arrive at the manufacturer's selling

price. In this way, the Department

constructed manufacturer-selling-price

versus efficiency curves for the

representative units from each of the 13

engineering design lines. These

relationship curves are a critical input

to the LCC analysis.

2. Life-Cycle Cost and Payback Period

Analyses

The life-cycle costs (LCC) and

payback period (PBP) analyses

determine the economic impact of

potential standards on individual

consumers. LCC and PBP calculations

are conducted on each of the

representative units from the 13

engineering design lines. The LCC

calculation considers the total installed

cost of equipment manufactured to

comply with potential energy efficiency

standards (equipment purchase price

45377

plus installation cost), the operating

expenses of such equipment (energy and

maintenance costs), the lifetime of the

equipment, and uses the discount rate

that reflects the consumer cost of capital

to put the LCC in current year dollars.

The PBP is a calculation to determine

the period of time necessary to recover

the higher purchase price of more

efficient transformers through the

operating cost savings. The PBP analysis

provides a simplified estimate of the

PBP as the incremental cost of a more

efficient transformer divided by the first

year operating savings. Both the LCC

and PBP analyses consider that the

consumer is an electric utility or

commercial/industrial entity,

responsible for both the purchase price

and operating costs of the distribution

transformer.

The foundation of the LCC and PBP

analyses is the transformer design and

cost information from the engineering

analysis. Most other inputs to the LCC

and PBP analyses are characterized by

probability distributions. These input

probability distributions, combined

with a baseline scenario of current

market conditions, generate probability

distributions of LCC and PBP results

using Monte Carlo statistical analysis

methods.

One of the most critical inputs to the

LCC and PBP analyses is the price of

electricity. The Department derived two

sets of electricity prices to estimate

annual energy expenses: A tariff-based

estimate to characterize the prices to the

commercial and industrial owners of

dry-type transformers and a utilitymarket-based estimate to characterize

the electricity costs to owners, which

are typically utilities, of liquidimmersed transformers.

3. National Impact Analysis

The national impact analysis assesses

the net present value (NPV) of national

economic impacts as well as the NES.

The Department calculated both the

NES and NPV for a given standard level

as the difference between a base case

(without new standards) and a

standards case (with standards).

National annual energy consumption by

distribution transformers considered by

the Department is determined by

multiplying the number of distribution

transformers in use by the average unit

energy consumption. Cumulative energy

savings are the sum of the annual NES

results calculated over specified time

periods. The national NPV is the sum

over time of the discounted net cost

savings due to energy savings associated

with a proposed standard. The

Department calculated net savings each

year as the difference between total

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register! Vol. 69, No. 145/ Thursday, July 29, 2004/ Proposed Rules 45377 

2. Shipments Model Inputs 

3. Shipments Model Results 

H. National Impact Analysis 

1. Method 

2. National Energy Savings 

a. National Energy Savings Overview 

b. National Energy Savings Inputs 

3. Net Present Value Calculation 

a. Net Present Value Overview 

b. Net Present Value Inputs 

4. National Energy Savings and Net Present 

Value Results 

a. National Energy Savings and Net Present 

Value from Candidate Standard Levels 

I. Life-Cycle Cost Sub-Group Analysis 

J. Manufacturer Impact Analysis 

1. Sources of Information for the 

Manufacturer Impact Analysis 

2. Industry Cash Flow Analysis 

3. Manufacturer Sub-Group Analysis 

4. Competitive Impacts Assessment 

5. Cumulative Regulatory Burden 

K. Utility Impact Analysis 

L. Employment Impact Analysis 

M. Environmental Assessment 

N. Regulatory Impact Analysis 

III. Proposed Standards Scenarios 

IV. Public Participation 

A. Attendance at Public Meeting 

B. Procedure for Submitting Requests to 

Speak 

C. Conduct of Public Meeting 

D. Submission of Comments 

E. Issues on Which DOE Seeks Comment 

1. Definition and Coverage 

2. Product Classes 

3. Engineering Analysis Inputs 

4. Design Option Combinations 

5. The 0.75 Scaling Rule 

6. Modeling of Transformer Load Profiles 

7. Distribution Chain Markups 

8. Discount Rate Selection and Use 

9. Baseline Determination Through 

Purchase Evaluation Formulae 

10. Electricity Prices 

11. Load Growth Over Time 

12. Life-Cycle Cost Sub-Groups 

13. Utility Deregulation Impacts 

V. Regulatory Review and Procedural 

Requirements 

VI. Approval of the Office of the Secretary 

1. Introduction 

A. Purpose of the ANOPR 

The purpose of this ANOPR is to 

provide interested persons with an 

opportunity to comment on: (i) The product classes that the 

Department is planning to analyze; 

(ii) The analytical framework, models, 

and tools (e.g. life-cycle cost (LCC) and 

national energy savings (NES) 

spreadsheets) used by the Department in 

performing analyses of the impacts of 

energy conservation standards; 

(iii) The results of the engineering 

analysis, the LCC and payback period 

(PBP) analyses, and the national impact 

analysis presented in the ANOPR 

Technical Support Document (TSD): 

Energy Efficiency Standards for 

Commercial and Industrial Equipment: 

Electric Distribution Transformers; and 

(iv) The candidate energy 

conservation standard levels that the 

Department has developed from these 

analyses. 

B. Summary of the Analysis 

The Energy Policy and Conservation 

Act (42 U.S.C. 6317) authorizes DOE to 

consider establishing energy 

conservation standards for various 

consumer products and commercial and 

industrial equipment, including 

distribution transformers, which are the 

subject of this ANOPR. 

The Department conducted eight 

analyses for this ANOPR: Market and 

technology assessment, screening 

analysis, engineering analysis, energy 

use and end-use load characterization, 

markups for equipment price 

determination, LCC and PBP analyses, 

shipments analysis, and national impact 

analysis. Three of the above analyses 

produce key results while the other five 

produce intermediate inputs. The three 

key analyses conducted are summarized 

briefly below: (1) Engineering; (2) lifecycle cost and payback periods; and (3) 

national impacts. 

1. Engineering Analysis 

The engineering analysis estimates 

the relationship between cost and 

efficiency for selected distribution 

transformers. The Department 

structured the engineering analysis 

around 13 groupings (termed 

"engineering design lines') of similarly 

built distribution transformers. The 

Department then identified one 

representative unit from each grouping, 

conducted software design runs on 

those units, estimated the material and 

labor costs, and calculated the 

performance of each design. Markups 

were applied to the manufacturer costs 

to arrive at the manufacturer's selling 

price. In this way, the Department 

constructed manufacturer-selling-price 

versus efficiency curves for the 

representative units from each of the 13 

engineering design lines. These 

relationship curves are a critical input 

to the LCC analysis. 

2. Life-Cycle Cost and Payback Period 

Analyses 

The life-cycle costs (LCC) and 

payback period (PBP) analyses 

determine the economic impact of 

potential standards on individual 

consumers. LCC and PBP calculations 

are conducted on each of the 

representative units from the 13 

engineering design lines. The LCC 

calculation considers the total installed 

cost of equipment manufactured to 

comply with potential energy efficiency 

standards (equipment purchase price 

plus installation cost), the operating 

expenses of such equipment (energy and 

maintenance costs), the lifetime of the 

equipment, and uses the discount rate 

that reflects the consumer cost of capital 

to put the LCC in current year dollars. 

The PBP is a calculation to determine 

the period of time necessary to recover 

the higher purchase price of more 

efficient transformers through the 

operating cost savings. The PBP analysis 

provides a simplified estimate of the 

PBP as the incremental cost of a more 

efficient transformer divided by the first 

year operating savings. Both the LCC 

and PBP analyses consider that the 

consumer is an electric utility or 

commercial/industrial entity, 

responsible for both the purchase price 

and operating costs of the distribution 

transformer. 

The foundation of the LCC and PBP 

analyses is the transformer design and 

cost information from the engineering 

analysis. Most other inputs to the LCC 

and PBP analyses are characterized by 

probability distributions. These input 

probability distributions, combined 

with a baseline scenario of current 

market conditions, generate probability 

distributions of LCC and PBP results 

using Monte Carlo statistical analysis 

methods. 

One of the most critical inputs to the 

LCC and PBP analyses is the price of 

electricity. The Department derived two 

sets of electricity prices to estimate 

annual energy expenses: A tariff-based 

estimate to characterize the prices to the 

commercial and industrial owners of 

dry-type transformers and a utilitymarket-based estimate to characterize 

the electricity costs to owners, which 

are typically utilities, of liquidimmersed transformers. 

3. National Impact Analysis 

The national impact analysis assesses 

the net present value (NPV) of national 

economic impacts as well as the NES. 

The Department calculated both the 

NES and NPV for a given standard level 

as the difference between a base case 

(without new standards) and a 

standards case (with standards). 

National annual energy consumption by 

distribution transformers considered by 

the Department is determined by 

multiplying the number of distribution 

transformers in use by the average unit 

energy consumption. Cumulative energy 

savings are the sum ofthe annual NES 

results calculated over specified time 

periods. The national NPV is the sum 

over time of the discounted net cost 

savings due to energy savings associated 

with a proposed standard. The 

Department calculated net savings each 

year as the difference between total 
45378 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

operating cost savings and increases in

total installed costs for each candidate

standard level. Cumulative NPV savings

are the sum of the annual NPV

calculated over specified time periods.

One of the most critical inputs to the

NES and NPV calculation is the

shipments forecast. The Department

developed shipment projections for the

base case and the candidate standard

levels. The default scenario for both

calculations differs between liquidimmersed and dry-type transformers.

For liquid-immersed transformers, the

Department determined that shipment

projections in the standards cases would

be slightly lower than those for the base

case due to the higher installed cost of

the more energy efficient distribution

transformers in the standards case. For

dry-type transformers, the Department

determined that there would be no

difference in shipment projections

between the base case and standards

cases.

Table 1.1 summarizes the

methodologies, key inputs and

assumptions for each ANOPR analysis

area. The table also presents the sections

in this document that contain the

analysis results.

TABLE 1.1 .-IN-DEPTH TECHNICAL ANALYSES CONDUCTED FOR THE ANOPR

Analysis area Methodology Key inputs Key assumptions ANOPR section for results

Engineering .... Simplify population for anal- ( 1) Material costs for con- Maximum technologically fea- Section II.C.5; presented in

ysis; create design option struction; (2) Design toler- sible design for liquid-im- the TSD, Chapter 5.

combinations ; use design ances . mersed is amorphous core,

software to prepare a range for a dry-type is laserof efficiency designs . scribed.

LCC and PBP Transformer-by-transformer (1) Cost /efficiency relation- (1) Liquid-immersed subject Section II.F.4; results also

analysis using representa - ship from engineering anal- to utility industry econom- presented in the TSD,

tive models from simplified ysis; (2) Baseline deter- ics; (2) Dry-type subject to Chapter 8.

design lines. mination from purchase de- commercial/industrial ecocision model ; (3) Electricity nomics.

prices and tariffs.

National im- Distribution transformer costs (1) Design line-to-product Section II.H.4; results also

pact anal- and energy consumption class mapping ; (2) 0.75 presented in the TSD,

ysis. forecasted to 2035; com- power scaling rule. Chapter 10.

bined with LCC results and

mapped to product classes

(1) Average values from the

LCC analysis; ( 2) Historical

shipment shipments estimate.

The Department consulted with

stakeholders and published preliminary

findings during the development and

execution of the analyses shown in

Table I.1. The Department invites

further input from stakeholders on the

methodologies, inputs, and assumptions

presented in this document.

C. Authority

Title III of EPCA established an

energy conservation program for

consumer products other than

automobiles. Amendments expanded

Title III of EPCA to include certain

commercial and industrial equipment,

including distribution transformers. (42

U.S.C. 6311 et seq.) Specifically the

Department's authority for this ANOPR

is in 42 U.S.C. 6317.

Before the Department determines

whether to adopt a proposed energy

conservation standard, it will first

solicit comments on the proposed

standard. The Department will consider

designing any new or amended standard

to achieve the maximum improvement

in energy efficiency that is

technologically feasible and

economically justified. (42 U.S.C. 6295

(o)(2)(A) and 42 U.S.C. 6317(c)) If a

proposed standard is not designed to

achieve the maximum improvement in

energy efficiency or the maximum

reduction in energy use that is

technologically feasible, DOE will state

the reasons for this in the proposed rule.

To determine whether economic

justification exists, the Department will

review comments on the proposal and

determine whether the benefits of the

proposed standard exceed its burdens to

the greatest extent practicable, while

considering the following seven factors

(see 42 U.S.C. 6295 (o)(2)(B)):

(1) The economic impact of the

standard on manufacturers and

consumers of products subject to the

standard;

(2) The savings in operating costs

throughout the estimated average life of

the covered products in the type (or

class) compared to any increase in the

price, initial charges, or maintenance

expenses for the covered products

which are likely to result from the

imposition of the standard;

(3) The total projected amount of

energy * * * savings likely to result

directly from the imposition of the

standard;

(4) Any lessening of the utility or the

performance of the covered products

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

conservation; and

(7) Other factors the Secretary

considers relevant.

D. Background

1. History of Standards Rulemaking for

Distribution Transformers

On October 22, 1997, the Secretary of

Energy issued a determination that

"based on its analysis of the information

now available, the Department has

determined that energy conservation

standards for transformers appear to be

technologically feasible and

economically justified, and are likely to

result in significant savings." 62 FR

54809.

The Secretary's determination was

based, in part, on analyses conducted by

the Department of Energy's Oak Ridge

National Laboratory (ORNL). In July

1996, ORNL published a report entitled

Determination Analysis of Energy

Conservation Standards for Distribution

Transformers, ORNL-6847, which

assessed options for setting energy

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45378 Federal Register/Vol. 69, No. 145 I Thursday, July 29, 2004/Proposed Rules 

operating cost savings and increases in 

total installed costs for each candidate 

standard level. Cumulative NPV savings 

are the sum ofthe annual NPV 

calculated over specified time periods. 

One of the most critical inputs to the 

NES and NPV calculation is the 

shipments forecast. The Department 

developed shipment projections for the 

base case and the candidate standard 

levels. The default scenario for both 

calculations differs between liquidimmersed and dry-type transformers. 

For liquid-immersed transformers, the 

Department determined that shipment 

projections in the standards cases would 

be slightly lower than those for the base 

case due to the higher installed cost of 

the more energy efficient distribution 

transformers in the standards case. For 

dry-type transformers, the Department 

determined that there would be no 

difference in shipment projections 

between the base case and standards 

cases. 

Table 1.1 summarizes the 

methodologies, key inputs and 

assumptions for each ANOPR analysis 

area. The table also presents the sections 

in this document that contain the 

analysis results. 

TABLE 1.1 .-IN-DEPTH TECHNICAL ANALYSES CONDUCTED FOR THE ANOPR 

Analysis area Methodology 

Engineering .... Simplify population for analysis; create design option 

combinations; use design 

software to prepare a range 

of efficiency deSigns. 

LCC and PBP Transformer-by-transformer 

analysis using representative models from Simplified 

design lines. 

National im- Distribution transformer costs 

pact anal- and energy consumption 

ysis. forecasted to 2035; combined with LCC results and 

mapped to product classes 

(1) Average values from the 

LCC analysis; (2) Historical 

shipment shipments estimate. 

The Department consulted with 

stakeholders and published preliminary 

findings during the development and 

execution of the analyses shown in 

Table I.1. The Department invites 

further input from stakeholders on the 

methodologies, inputs, and assumptions 

presented in this document. 

C. Authority 

Title III of EPCA established an 

energy conservation program for 

consumer products other than 

automobiles. Amendments expanded 

Title III of EPCA to include certain 

commercial and industrial equipment, 

including distribution transformers. (42 

U.S.C. 6311 et seq.) Specifically the 

Department's authority for this ANOPR 

is in 42 U.S.C. 6317. 

Before the Department determines 

whether to adopt a proposed energy 

conservation standard, it will first 

solicit comments on the proposed 

standard. The Department will consider 

designing any new or amended standard 

to achieve the maximum improvement 

in energy efficiency that is 

technologically feasible and 

economically justified. (42 U.S.C. 6295 

(0)(2)(A) and 42 U.S.C. 6317(c)) If a 

proposed standard is not designed to 

achieve the maximum improvement in 

Key inputs Key assumptions ANOPR section for results 

(1) Material costs for con- Maximum technologically fea- Section II.C.5; presented in 

struction; (2) Design toler- sible design for liquid-im- the TSD, Chapter 5. 

ances. mersed is amorphous core, 

for a dry-type is laserscribed. 

(1) Cost lefficiency relation- (1) Liquid-immersed subject Section II.F.4; results also 

ship from engineering anal- to utility industry econom- presented in the TSD, 

ysis; (2) Baseline deter- ics; (2) Dry-type subject to Chapter 8. 

mination from purchase de- commercial/industrial ecocision model; (3) Electricity nomics. 

prices and tariffs. 

(1) Design line-to-product Section II.H.4; results also 

class mapping; (2) 0.75 presented in the TSD, 

power scaling rule. Chapter 10. 

energy efficiency or the maximum 

reduction in energy use that is 

technologically feasible, DOE will state 

the reasons for this in the proposed rule. 

To determine whether economic 

justification exists, the Department will 

review comments on the proposal and 

determine whether the benefits of the 

proposed standard exceed its burdens to 

the greatest extent practicable, while 

considering the following seven factors 

(see 42 U.S.C. 6295 (0)(2)(B)): 

(1) The economic impact ofthe 

standard on manufacturers and 

consumers of products subject to the 

standard; 

(2) The savings in operating costs 

throughout the estimated average life of 

the covered products in the type (or 

class) compared to any increase in the 

price, initial charges, or maintenance 

expenses for the covered products 

which are likely to result from the 

imposition of the standard; 

(3) The total projected amount of 

energy * * * savings likely to result 

directly from the imposition of the 

standard; 

(4) Any lessening of the utility or the 

performance of the covered products 

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 

conservation; and 

(7) Other factors the Secretary 

considers relevant. 

D. Background 

1. History of Standards Rulemaking for 

Distribution Transformers 

On October 22,1997, the Secretary of 

Energy issued a determination that 

"based on its analysis of the information 

now available, the Department has 

determined that energy conservation 

standards for transformers appear to be 

technologically feasible and 

economically justified, and are likely to 

result in significant savings." 62 FR 

54809. 

The Secretary's determination was 

based, in part, on analyses conducted by 

the Department of Energy's Oak Ridge 

National Laboratory (ORNL). In July 

1996, ORNL published a report entitled 

Determination Analysis of Energy 

Conservation Standards for Distribution 

Transformers, ORNL-6847, which 

assessed options for setting energy 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

conservation standards. That report was

based on information from annual sales

data, average load data, and surveys of

existing and potential transformer

efficiencies obtained from several

organizations.

In September 1997, ORNL published

a second report entitled Supplement to

the "Determination Analysis" (ORNL6847) and Analysis of the NEMA

Efficiency Standard for Distribution

Transformers, ORNL-6925. This report

assessed the suggested efficiency levels

contained in the then-newly published

National Electrical Manufacturers

Association (NEMA) Standards

Publication No. TP 1-1996, Guide for

Determining Energy Efficiency for

Distribution Transformers, along with

the efficiency levels previously

considered by the Department in the

determination study. The latest

downloadable version of TP 1 is

available at the NEMA Web site: http:/

/www.nema. org/index-nema.cfm/1427/

47168E11-AA56-4B4E9F329B339C23F115/. In its

supplemental assessment, ORNL used a

more accurate analytical model and

better transformer market and loading

data developed following the

publication of ORNL-6827.

Downloadable versions of both ORNL

reports are available on the DOE Web

site at: http://www.eere.energy.gov/

buildings/appli ance_stan Bard s/

distribution _ tra n s f orm ers. h tm 1.

As a result of this positive

determination, in 2000, the Department

developed a Framework Document for

Distribution Transformer Energy

Conservation Standards Rulemaking,

describing the procedural and analytic

approaches that the Department

anticipated using to evaluate the

establishment of energy conservation

standards for distribution transformers.

This document is also available on the

aforementioned DOE Web site. On

November 1, 2000, the Department held

a public workshop on the framework

document to discuss the proposed

analytical framework. Manufacturers,

trade associations, electric utilities,

environmental advocates, regulators,

and other interested parties attended the

framework document workshop,

actively participating in discussions and

showing their willingness to work with

DOE on the process of analyzing

possible efficiency standards. The major

issues discussed were: definition of

covered transformer products; definition

of product classes; possible proprietary

(patent) issues regarding amorphous

metal; ties between efficiency

improvements and installation costs;

baseline and possible efficiency levels;

base case trends under deregulation;

transformer costs versus transformer

prices; appropriate LCC sub-groups;

LCC methods, e.g., total owning cost

(TOC); loading levels; utility impact

analysis vis-a-vis deregulation; scope of

environmental assessment; and

harmonization of standards with other

countries.

Stakeholder comments submitted

during the framework document

comment period elaborated upon the

issues raised at the meeting and also

addressed the following issues: Options

for the screening analysis; approaches

for the engineering analysis; discount

rates; electricity prices; the number and

basis for the efficiency levels to be

analyzed; the NES and NPV analyses;

the analysis of the effects of a potential

standard on employment; the

manufacturer impact assessment; and

the timing of the analyses. The

Department worked with its contractors

to address these issues as well as those

raised during the framework document

workshop.

As part of the information gathering

and sharing process, the Department

met with manufacturers of liquidimmersed and dry-type distribution

transformers during the first quarter of

2002. The Department met with

companies that produced all types of

distribution transformers, ranging from

small to large manufacturers, and

including both NEMA and non-NEMA

members. The Department had four

objectives for these meetings: (1) Solicit

feedback on the methodology and

findings presented in the draft

engineering analysis update report that

the Department posted on its Web site

December 17, 2001; (2) get information

and comments on production costs and

manufacturing processes presented in

the December 17, 2001, draft

engineering analysis update report; (3)

provide an opportunity, early in the

rulemaking process, to express specific

concerns to the Department; and (4)

foster cooperation between the

manufacturers and the Department.

There were five general issues

discussed at each of these manufacturer

site meetings: (1) Company overview

and product offerings; (2) the structure

of the engineering analysis, including

the engineering design lines, which

represent groupings of similarly built

distribution transformers; (3) design

option combinations for each of the

representative transformers from the

engineering design lines; (4) use of

Optimized Program Services (OPS)

distribution transformer design

software; and (5) the 0.75 scaling rule,

used to scale the costs and efficiencies

of the representative units within each

of the engineering design lines.

45379

The Department incorporated the

information gathered at the meetings

into its engineering analysis, which is

described in more detail in the

engineering analysis part of this ANOPR

(section II.C), as well as in Chapter 5 of

the TSD. Following the publication of

the ANOPR and the ANOPR public

meeting, the Department may hold

additional meetings with manufacturers

as part of the consultative process for

the manufacturer impact analysis (see

section II.J).

As part of its pre-ANOPR analysis

process, the Department posted several

draft reports on its Web site to solicit

stakeholder input. These reports are:

® The Department's initial

engineering analysis for design line 1

(Distribution Transformer Rulemaking,

Engineering Analysis Update, posted

December 17, 2001). This document

contains preliminary results of the

engineering analysis for design line 1.

® The Department's initial screening

analysis (Screening Analysis, posted

March 5, 2002). This document

discusses various design options for

improving the energy efficiency of

distribution transformers and describes

the reasons for eliminating certain

design options from consideration.

® The Department's draft LCC

analysis for design line 1 (Distribution

Transformer Rulemaking, Life Cycle

Cost Analysis, Design Line 1, posted

June 6, 2002). This document discusses

the methodology and structure of the

LCC analysis used for liquid-immersed

transformers, along with the basis for

various input values and assumptions. It

also presents example results from the

LCC analysis on a 50 kVA unit.

• The Department's revised

engineering analysis for design line 1

(posted June 6, 2002, as Appendix B to

the LCC report listed above). This

appendix presents a revision of the

engineering analysis that the

Department originally circulated in

December 2001.

® The Department's engineering

analysis for medium-voltage dry-type

distribution transformers (Distribution

Transformer Standards Rulemaking,

Draft Report for Review, Engineering

Analysis for Dry-type Distribution

Transformers and Results on Design

Line 9, posted August 23, 2002). This

document contains preliminary results

of the engineering analysis for design

line 9.

® The Department's draft LCC

analysis for design line 9 (Distribution

Transformer Standards Rulemaking,

Draft Report for Review, Dry-type

Distribution Transformers, Life Cycle

Cost Analysis on Design Line 9, posted

October 4, 2002). This document

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register / Vol. 69, No. 145/ Thursday, July 29, 2004/Proposed Rules 45379 

conservation standards. That report was 

based on information from annual sales 

data, average load data, and surveys of 

existing and potential transformer 

efficiencies obtained from several 

organizations. 

In September 1997, ORNL published 

a second report entitled Supplement to 

the "Determination Analysis" (ORNL6847) and Analysis of the NEMA 

Efficiency Standard for Distribution 

Transformers, ORNL-6925. This report 

assessed the suggested efficiency levels 

contained in the then-newly published 

National Electrical Manufacturers 

Association (NEMA) Standards 

Publication No. TP 1-1996, Guide for 

Determining Energy Efficiency for 

Distribution Transformers, along with 

the efficiency levels previously 

considered by the Department in the 

determination study. The latest 

downloadable version of TP 1 is 

available at the NEMA Web site: http:/ 

/www.nema.org/index_nema.cfm/1427/ 

4 7168Ell-AA5 6-4B4E9F329B339C23Fl15i. In its 

supplemental assessment, ORNL used a 

more accurate analytical model and 

better transformer market and loading 

data developed following the 

publication of ORNL-6827. 

Downloadable versions of both ORNL 

reports are available on the DOE Web 

site at: http://www.eere.energy.gov/ 

buildings/appliance_standards/ 

distribution_transformers.html. 

As a result of this positive 

determination, in 2000, the Department 

developed a Framework Document for 

Distribution Transformer Energy 

Conservation Standards Rulemaking, 

describing the procedural and analytic 

approaches that the Department 

anticipated using to evaluate the 

establishment of energy conservation 

standards for distribution transformers. 

This document is also available on the 

aforementioned DOE Web site. On 

November 1,2000, the Department held 

a public workshop on the framework 

document to discuss the proposed 

analytical framework. Manufacturers, 

trade associations, electric utilities, 

environmental advocates, regulators, 

and other interested parties attended the 

framework document workshop, 

actively participating in discussions and 

showing their willingness to work with 

DOE on the process of analyzing 

possible efficiency standards. The major 

issues discussed were: definition of 

covered transformer products; definition 

of product classes; possible proprietary 

(patent) issues regarding amorphous 

metal; ties between efficiency 

improvements and installation costs; 

baseline and possible efficiency levels; 

base case trends under deregulation; 

transformer costs versus transformer 

prices; appropriate LCC sub-groups; 

LCC methods, e.g., total owning cost 

(TOC); loading levels; utility impact 

analysis vis-a-vis deregulation; scope of 

environmental assessment; and 

harmonization of standards with other 

countries. 

Stakeholder comments submitted 

during the framework document 

comment period elaborated upon the 

issues raised at the meeting and also 

addressed the following issues: Options 

for the screening analysis; approaches 

for the engineering analysis; discount 

rates; electricity prices; the number and 

basis for the efficiency levels to be 

analyzed; the NES and NPV analyses; 

the analysis of the effects of a potential 

standard on employment; the 

manufacturer impact assessment; and 

the timing of the analyses. The 

Department worked with its contractors 

to address these issues as well as those 

raised during the framework document 

workshop. 

As part of the information gathering 

and sharing process, the Department 

met with manufacturers of liquidimmersed and dry-type distribution 

transformers during the first quarter of 

2002. The Department met with 

companies that produced all types of 

distribution transformers, ranging from 

small to large manufacturers, and 

including both NEMA and non-NEMA 

members. The Department had four 

objectives for these meetings: (1) Solicit 

feedback on the methodology and 

findings presented in the draft 

engineering analysis update report that 

the Department posted on its Web site 

December 17,2001; (2) get information 

and comments on production costs and 

manufacturing processes presented in 

the December 17,2001, draft 

engineering analysis update report; (3) 

provide an opportunity, early in the 

rulemaking process, to express specific 

concerns to the Department; and (4) 

foster cooperation between the 

manufacturers and the Department. 

There were five general issues 

discussed at each of these manufacturer 

site meetings: (1) Company overview 

and product offerings; (2) the structure 

of the engineering analysis, including 

the engineering design lines, which 

represent groupings of similarly built 

distribution transformers; (3) design 

option combinations for each of the 

representative transformers from the 

engineering design lines; (4) use of 

Optimized Program Services (OPS) 

distribution transformer design 

software; and (5) the 0.75 scaling rule, 

used to scale the costs and efficiencies 

of the representative units within each 

of the engineering design lines. 

The Department incorporated the 

information gathered at the meetings 

into its engineering analysis, which is 

described in more detail in the 

engineering analysis part of this ANOPR 

(section ILC), as well as in Chapter 5 of 

the TSD. Following the publication of 

the ANOPR and the ANOPR public 

meeting, the Department may hold 

additional meetings with manufacturers 

as part of the consultative process for 

the manufacturer impact analysis (see 

section II.]). 

As part of its pre-ANOPR analysis 

process, the Department posted several 

draft reports on its Web site to solicit 

stakeholder input. These reports are: .. The Department's initial 

engineering analysis for design line 1 

(Distribution Transformer Rulemaking, 

Engineering Analysis Update, posted 

December 17, 2001). This document 

contains preliminary results of the 

engineering analysis for design line 1. 

• The Department's initial screening 

analysis (Screening Analysis, posted 

March 5, 2002). This document 

discusses various design options for 

improving the energy efficiency of 

distribution transformers and describes 

the reasons for eliminating certain 

design options from consideration. .. The Department's draft LCC 

analysis for design line 1 (Distribution 

Transformer Rulemaking, Life Cycle 

Cost Analysis, Design Line 1, posted 

June 6, 2002). This document discusses 

the methodology and structure of the 

LCC analysis used for liquid-immersed 

transformers, along with the basis for 

various input values and assumptions. It 

also presents example results from the 

LCC analysis on a 50 kVA unit. • The Department's revised 

engineering analysis for design line 1 

(posted June 6,2002, as Appendix B to 

the LCC report listed above). This 

appendix presents a revision of the 

engineering analysis that the 

Department originally circulated in 

December 2001. • The Department's engineering 

analysis for medium-voltage dry-type 

distribution transformers (Distribution 

Transformer Standards Rulemaking, 

Draft Report for Review, Engineering 

Analysis for Dry-type Distribution 

Transformers and Results on Design 

Line 9, posted August 23, 2002). This 

document contains preliminary results 

of the engineering analysis for design 

line 9. .. The Department's draft LCC 

analysis for design line 9 (Distribution 

Transformer Standards Rulemaking, 

Draft Report for Review, Dry-type 

Distribution Transformers, Life Cycle 

Cost Analysis on Design Line 9, posted 

October 4, 2002). This document 
45380 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

discusses the methodology and

structure of the LCC analysis for drytype transformers, along with the basis

for various input values and

assumptions. It also presents sample

results from the LCC analysis on a 300

kVA unit.

The Department also posted several

spreadsheets while preparing for the

ANOPR for early stakeholder review

and comment:

® ANOPR engineering analysis results

spreadsheets for all 13 design lines

(posted April 4, 2003). These

spreadsheets summarize the cost and

performance of all the designs in the

Department's engineering database. One

spreadsheet contains the engineering

analysis results of the liquid-immersed

design lines, and the other contains the

dry-type design lines.

® ANOPR LCC spreadsheets for all 13

design lines (posted May 14, 2003).

These spreadsheets are used by the

Department to calculate the LCC and

PBP. The Department conducted a

webcast on October 17, 2002, presenting

and explaining the basic LCC

spreadsheet to stakeholders.

The Department developed two

spreadsheet tools for this rulemaking.

The first spreadsheet tool calculates

LCC and payback periods. Thirteen

different LCC and payback period

spreadsheets were developed to capture

variations in the distribution

transformer market. The second

spreadsheet tool calculates impacts of

candidate standards at various levels on

shipments and calculates the NES and

NPV at various standard levels. These

spreadsheets are posted on the

Department's website along with the

complete TSD documenting the

analyses supporting this ANOPR.

2. Process Improvement

Although the Procedures,

Interpretations and Policies for

Consideration of New or Revised Energy

Conservation Standards for Consumer

Products (the "Process Rule"), 10 CFR

Part 430, Subpart C, Appendix A,

applies to consumer products, in its

Notice of Determination for Distribution

Transformers, the Department stated its

intent to adhere in this rulemaking to

the provisions of the Process Rule,

where applicable. 62 FR 54817. In Table

1.2, the Department presents the

analyses it intends to conduct in its

evaluation of standards for distribution

transformers.

TABLE 1.2.-DISTRIBUTION TRANSFORMERS ANALYSES IN ACCORDANCE WITH THE PROCESS RULE

ANOPR NOPR Final rule

Market and technology assessment ...................

Screening analysis .............................................

Engineering analysis ..........................................

Energy use and end-use load characterization

Markups for equipment price determination .......

Life-cycle cost and payback period analyses ....

Shipments analysis ............................................

National impact analysis.

The analyses in Table 1.2 reflect

methodological improvements made in

accordance with the Process Rule,

including the development of economic

models and analytical tools. For

example, this ANOPR uses the full

range of consumer marginal energy rates

which are the energy rates that

correspond to incremental changes in

energy use. The LCC analysis also

defines a range of energy price forecasts

for each fuel used in the economic

analyses, and defines a range of primary

energy conversion factors and

associated emission reductions based on

the generation displaced by energy

efficiency standards. If timely new data,

models, or tools that enhance the

development of standards become

available, they will be incorporated into

this rulemaking.

3. Test Procedure

A test procedure outlines the method

by which manufacturers will determine

the efficiency of their distribution

transformers, and thereby assess

compliance with an energy conservation

standard. On February 10, 1998, the

Department held a workshop on the

development of a test procedure for

distribution transformers.

Representatives from NEMA,

Revised ANOPR analyses

Life-cycle cost sub-group analysis

Manufacturer impact analysis

Utility impact analysis

Employment impact analysis

Environmental assessment

Regulatory impact analysis

manufacturers, utilities, Federal and

State agencies, the Canadian

government, and other interested parties

attended the workshop. The Department

presented and discussed draft test

procedures based on recognized

industry standards. A transcript of the

workshop is available at the Building

Technologies Program's Resource Room,

which is located in Room 1J-018 and is

open from 9:00 a.m. to 4:00 p.m.,

Monday through Friday.

In 1998, NEMA developed and

published NEMA Standard TP 2-1998,

Standard Test Method for Measuring the

Energy Consumption of Distribution

Transformers. This publication presents

the American National Standards

Institute/ Institute of Electrical and

Electronics Engineers (ANSI/IEEE)

industry standard test methods for

measuring transformer efficiency, and

provides a compliance section that

describes how manufacturers can

demonstrate that their transformers

meet the NEMA Standard TP 1

efficiency ratings.

On November 12, 1998, the

Department published a Notice of

Proposed Rulemaking (NOPR) for a

distribution transformer test procedure;

the NOPR solicited comments from

stakeholders and announced a public

Revised analyses.

workshop. 63 FR 63360. The NOPR

proposed that DOE either incorporate

parts of the recognized industry testing

standards, or simply adopt NEMA

Standard TP 2-1998.

The Department held a public

workshop on the proposed test

procedure rule on January 6, 1999.

Based on the comments received and

issues raised, the Department concluded

that additional analysis was necessary.

On June 23, 1999, the Department

reopened the comment period on the

proposed rule. 64 FR 33431. This

second comment period raised issues

and solicited comments on the

suitability of NEMA Standard TP 2-

1998 for use as the DOE test procedure,

the definition of a distribution

transformer, the sampling plan to

demonstrate compliance, and the

suitability of the proposed "basic

model" definition. The Department is

issuing a Supplemental Notice of

Proposed Rulemaking (SNOPR) for the

test procedure, addressing these

comments.

While the process of developing and

finalizing a test procedure is ongoing,

the Department is working to ensure

that activities being conducted under

the test procedure SNOPR and the

standards rulemaking ANOPR are

 EE-RM/STD-00-550 COMMENT 53.1

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45380 Federal Register IVoI. 69, No. 145 I Thursday, July 29, 2004 I Proposed Rules 

discusses the methodology and 

structure of the LCC analysis for drytype transformers, along with the basis 

for various input values and 

assumptions. It also presents sample 

results from the LCC analysis on a 300 

kVA unit. 

The Department also posted several 

spreadsheets while preparing for the 

ANOPR for early stakeholder review 

and comment: 

• ANOPR engineering analysis results 

spreadsheets for all 13 design lines 

(posted April 4, 2003). These 

spreadsheets summarize the cost and 

performance of all the designs in the 

Department's engineering database. One 

spreadsheet contains the engineering 

analysis results of the liquid-immersed 

design lines, and the other contains the 

dry-type design lines. 

• ANOPR LCC spreadsheets for all 13 

design lines (posted May 14, 2003). 

These spreadsheets are used by the 

Department to calculate the LCC and 

PBP. The Department conducted a 

webcast on October 17,2002, presenting 

and explaining the basic Lec 

spreadsheet to stakeholders. 

The Department developed two 

spreadsheet tools for this rulemaking. 

The first spreadsheet tool calculates 

LCC and payback periods. Thirteen 

different LCC and payback period 

spreadsheets were developed to capture 

variations in the distribution 

transformer market. The second 

spreadsheet tool calculates impacts of 

candidate standards at various levels on 

shipments and calculates the NES and 

NPV at various standard levels. These 

spreadsheets are posted on the 

Department's website along with the 

complete TSD documenting the 

analyses supporting this ANOPR. 

2. Process Improvement 

Although the Procedures, 

Interpretations and Policies for 

Consideration of New or Revised Energy 

Conservation Standards for Consumer 

Products (the "Process Rule"), 10 CFR 

Part 430, Subpart C, Appendix A, 

applies to consumer products, in its 

Notice of Determination for Distribution 

Transformers, the Department stated its 

intent to adhere in this rulemaking to 

the provisions ofthe Process Rule, 

where applicable. 62 FR 54S17. In Table 

1.2, the Department presents the 

analyses it intends to conduct in its 

evaluation of standards for distribution 

transformers. 

TABLE 1.2.-DISTRIBUTION TRANSFORMERS ANALYSES IN ACCORDANCE WITH THE PROCESS RULE 

ANOPR 

Market and technology assessment .................. . 

Screening analysis ............................................ . 

Engineering analysis ......................................... . 

Energy use and end-use load characterization 

Markups for equipment price determination ...... . 

Life-cycle cost and payback period analyses .. .. 

Shipments analysis ........................................... . 

National impact analysis. 

The analyses in Table 1.2 reflect 

methodological improvements made in 

accordance with the Process Rule, 

including the development of economic 

models and analytical tools. For 

example, this ANOPR uses the full 

range of consumer marginal energy rates 

which are the energy rates that 

correspond to incremental changes in 

energy use. The LCC analysis also 

defines a range of energy price forecasts 

for each fuel used in the economic 

analyses, and defines a range of primary 

energy conversion factors and 

associated emission reductions based on 

the generation displaced by energy 

efficiency standards. If timely new data, 

models, or tools that enhance the 

development of standards become 

available, they will be incorporated into 

this rulemaking. 

3. Test Procedure 

A test procedure outlines the method 

by which manufacturers will determine 

the efficiency of their distribution 

transformers, and thereby assess 

compliance with an energy conservation 

standard. On February 10, 1995, the 

Department held a workshop on the 

development of a test procedure for 

distribution transformers. 

Representatives from NEMA, 

NOPR 

Revised ANOPR analyses 

Life-cycle cost sub-group analysis 

Manufacturer impact analysis 

Utility impact analysis 

Employment impact analysis 

Environmental assessment 

Regulatory impact analysis 

manufacturers, utilities, Federal and 

State agencies, the Canadian 

government, and other interested parties 

attended the workshop. The Department 

presented and discussed draft test 

procedures based on recognized 

industry standards. A transcript of the 

workshop is available at the Building 

Technologies Program's Resource Room, 

which is located in Room IJ-OlS and is 

open from 9:00 a.m. to 4:00 p.m., 

Monday through Friday. 

In 1995, NEMA developed and 

published NEMA Standard TP 2-199S, 

Standard Test Method for Measuring the 

Energy Consumption of Distribution 

Transformers. This publication presents 

the American National Standards 

Institute/Institute of Electrical and 

Electronics Engineers (ANSI/IEEE) 

industry standard test methods for 

measuring transformer efficiency, and 

provides a compliance section that 

describes how manufacturers can 

demonstrate that their transformers 

meet the NEMA Standard TP 1 

efficiency ratings. 

On November 12, 1995, the 

Department published a Notice of 

Proposed Rulemaking (NOPR) for a 

distribution transformer test procedure; 

the NOPR solicited comments from 

stakeholders and announced a public 

Final rule 

Revised analyses. 

workshop. 63 FR 63360. The NOPR 

proposed that DOE either incorporate 

parts of the recognized industry testing 

standards, or simply adopt NEMA 

Standard TP 2-199S. 

The Department held a public 

workshop on the proposed test 

procedure rule on January 6, 1999. 

Based on the comments received and 

issues raised, the Department concluded 

that additional analysis was necessary. 

On June 23,1999, the Department 

reopened the comment period on the 

proposed rule. 64 FR 33431. This 

second comment period raised issues 

and solicited comments on the 

suitability of NEMA Standard TP 2-

1995 for use as the DOE test procedure, 

the definition of a distribution 

transformer, the sampling plan to 

demonstrate compliance, and the 

suitability ofthe proposed "basic 

model" definition. The Department is 

issuing a Supplemental Notice of 

Proposed Rulemaking (SNOPR) for the 

test procedure, addressing these 

comments. 

While the process of developing and 

finalizing a test procedure is ongoing, 

the Department is working to ensure 

that activities being conducted under 

the test procedure SNOPR and the 

standards rulemaking ANOPR are 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

synchronized. For example, some of the

comments provided by stakeholders

through prior public consultation

processes on the test procedure

contributed directly to the formulation

of the distribution transformer

definition proposed in this ANOPR.

II. Distribution Transformer Analyses

This section includes a general

introduction to each analysis section

and a discussion of relevant issues

addressed in comments received from

interested parties.

A. Market and Technology Assessment

When the Department begins a

standards rulemaking, it develops

information on the industry structure

and market characteristics of the

product concerned. This activity

consists of both quantitative and

qualitative efforts based primarily on

publicly available information. The

issues addressed in this market and

technology assessment include the

product definition, product classes,

manufacturers, retail market trends, and

regulatory and non-regulatory programs.

This information serves as resource

material for use throughout the

rulemaking.

1. Definition of a Distribution

Transformer

Section 346 of EPCA authorizes the

Department to consider and determine

whether an energy conservation

standard for "distribution transformers"

would be technologically feasible and

economically justified, and would result

in significant energy savings. (42 U.S.C.

6317(a)(1)) But the statute does not

define "distribution transformer." At

the framework document workshop, the

Department interpreted the term

"distribution transformer" to mean:

"Transformers designed to continuously

transfer electrical energy either single

phase or three phase from a primary

distribution circuit to a secondary

distribution circuit, within a secondary

distribution circuit, or to a consumer's

service circuit; limited to transformers

with primary voltage of 480 V to 35 kV,

a secondary voltage of 120 V to 600 V,

a frequency of 55-65 Hz, and a capacity

of 10 kVA to 2500 kVA for liquidimmersed transformers or 5 kVA to 2500

kVA for dry-type transformers." The

Department subsequently revised this

definition based on input from

stakeholders, information on

transformers commonly understood to

be "distribution transformers," and

consideration of whether energy

conservation standards for such

transformers would result in significant

energy savings. The revised proposed

definition of a distribution transformer

is given in section II.A.1.d.

a. Changes to, and Retention of,

Provisions in the Framework Document

Definition

The proposed definition of a

distribution transformer eliminates the

lower limits of 480 V and 120 V, on

primary voltage and secondary voltage

respectively. In its written comments,

NEMA advocated that the Department

have no lower limits on the primary and

secondary voltages of the transformers it

evaluates for standards, reflecting the

coverage of NEMA TP 1. (NEMA, No. 7

at p. 4 and No. 19 at p. 2) The American

Council for an Energy Efficient

Economy (ACEEE) agreed with the

Department's working definition

presented at the framework document

workshop, and commented that the

scope should be as broad as possible at

this stage of the rulemaking. (ACEEE,

No. 14 at p. 1) ACEEE strongly disagreed

with a comment made during the

framework document workshop

recommending that the lower threshold

for the primary voltage be raised above

480 V. (Public Hearing Transcript, No.

2MM at pp. 27-28) ACEEE pointed out

that the Department's Determination

Analysis prepared by ORNL showed

substantial energy savings resulted from

transformers operating in the low

voltage class. (ACEEE, No. 14 at p. 1)

Consistent with NEMA and ACEEE's

comments, the Department is concerned

that defining a distribution transformer

as having a minimum primary and/or

secondary voltage may result in

eliminating certain distribution

transformers from consideration in the

standards rulemaking. The Department

also believes that it can include other

elements in its definition of

"distribution transformer" to ensure

that its test procedures and standards

for transformers would cover only

products that are truly "distribution

transformers." Therefore, the

Department removed the lower bounds

on primary and secondary voltage from

the definition of distribution

transformer.

With regard to the framework

document workshop's capacity criteria

for defining a distribution transformer

(10 to 2500 kVA for liquid-immersed

units and 5 to 2500 kVA for dry-type

units), the Department received

comment that 5 kVA and 10 kVA singlephase, dry-type units are not normally

used for distribution purposes, but

rather are almost always used in

specialized applications related to the

consumption of electricity (i.e., power

supplies). (NEMA, No. 7 at p. 4) At the

framework document workshop, ABB

45381

commented that 5 and 10 kVA dry-type

units "just don't make any sense when

somebody considers the concept of

distribution." (Public Hearing

Transcript, No. 2MM at p. 28) To

accommodate this input, the

Department's revised definition of a

distribution transformer proposes a

lower capacity limit for dry-type units

of 15 kVA, excluding dry-type

transformers with ratings of 5 and 10

kVA from the standards rulemaking.

The Department seeks comment from

other stakeholders on whether such

transformers should be classified as

distribution transformers, and whether

it should adopt a different lower

capacity limit for dry-type units in the

definition of distribution transformer.

The framework document workshop's

definition also included "[t]ransformers

designed to continuously transfer

electrical energy either single phase or

three phase from a primary distribution

circuit to a secondary distribution

circuit, within a secondary distribution

circuit, or to a consumer's service

circuit" (DOE presentation at

Framework Document Workshop, No.

2CC at p. 7) The Department is

concerned that these criteria may be too

vague and imprecise and subject to

misinterpretation, and may fail to

establish clearly which transformers are,

and which are not, covered under EPCA

as distribution transformers. This would

particularly affect parties that work with

distribution transformers in non-utility

applications, where the terminology in

these criteria, for example, "to a

consumer's service circuit" may be

inapplicable or meaningless. NEMA

advocated that the Department adopt a

definition of distribution transformer

that aligns with the scope of NEMA TP

1. (NEMA, No. 7 at p. 4) The scope

provision of TP 1 states that the

standard applies to transformers

meeting numerical criteria (e.g., voltage,

kVA) and then lists specific types of

transformers to which the standard does

not apply.

The Department has decided to follow

the NEMA TP 1 approach in defining a

distribution transformer. In addition to

having numerical criteria, DOE's

proposed definition lists types of

transformers that are made for

applications unrelated to the

distribution of electricity, or for which

standards would not produce significant

energy savings, and clarifies that they

are not "distribution transformers"

subject to regulation by the Department.

Such a definition is clearer, more

precise, and less subject to

misinterpretation than the framework

document workshop's proposed

definition. Although the list of excluded

 EE-RM/STD-00-550 COMMENT 53.1

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45381 

synchronized. For example, some ofthe 

comments provided by stakeholders 

through prior public consultation 

processes on the test procedure 

contributed directly to the formulation 

of the distribution transformer 

definition proposed in this ANOPR. 

II. Distribution Transformer Analyses 

This section includes a general 

introduction to each analysis section 

and a discussion of relevant issues 

addressed in comments received from 

interested parties. 

A. Market and Technology Assessment 

When the Department begins a 

standards rulemaking, it develops 

information on the industry structure 

and market characteristics of the 

product concerned. This activity 

consists of both quantitative and 

qualitative efforts based primarily on 

publicly available information. The 

issues addressed in this market and 

technology assessment include the 

product definition, product classes, 

manufacturers, retail market trends, and 

regulatory and non-regulatory programs. 

This information serves as resource 

material for use throughout the 

rulemaking. 

1. Definition of a Distribution 

Transformer 

Section 346 of EPCA authorizes the 

Department to consider and determine 

whether an energy conservation 

standard for "distribution transformers" 

would be technologically feasible and 

economically justified, and would result 

in significant energy savings. (42 U.S.C. 

6317(a)(1)) But the statute does not 

define "distribution transformer." At 

the framework document workshop, the 

Department interpreted the term 

"distribution transformer" to mean: 

"Transformers designed to continuously 

transfer electrical energy either single 

phase or three phase from a primary 

distribution circuit to a secondary 

distribution circuit, within a secondary 

distribution circuit, or to a consumer's 

service circuit; limited to transformers 

with primary voltage of 480 V to 35 kV, 

a secondary voltage of 120 V to 600 V, 

a frequency of 55-65 Hz, and a capacity 

of 10 kVA to 2500 kVA for liquidimmersed transformers or 5 kVA to 2500 

kV A for dry-type transformers." The 

Department subsequently revised this 

definition based on input from 

stakeholders, information on 

transformers commonly understood to 

be "distribution transformers," and 

consideration of whether energy 

conservation standards for such 

transformers would result in significant 

energy savings. The revised proposed 

definition of a distribution transformer 

is given in section II.A.l.d. 

a. Changes to, and Retention of, 

Provisions in the Framework Document 

Definition 

The proposed definition of a 

distribution transformer eliminates the 

lower limits of 480 V and 120 V, on 

primary voltage and secondary voltage 

respectively. In its written comments, 

NEMA advocated that the Department 

have no lower limits on the primary and 

secondary voltages of the transformers it 

evaluates for standards, reflecting the 

coverage of NEMA TP 1. (NEMA, No.7 

at p. 4 and No. 19 at p. 2) The American 

Council for an Energy Efficient 

Economy (ACEEE) agreed with the 

Department's working definition 

presented at the framework document 

workshop, and commented that the 

scope should be as broad as possible at 

this stage of the rulemaking. (ACEEE, 

No. 14 at p. 1) ACEEE strongly disagreed 

with a comment made during the 

framework document workshop 

recommending that the lower threshold 

for the primary voltage be raised above 

480 V. (Public Hearing Transcript, No. 

2MM at pp. 27-28) ACEEE pointed out 

that the Department's Determination 

Analysis prepared by ORNL showed 

substantial energy savings resulted from 

transformers operating in the low 

voltage class. (ACEEE, No. 14 at p. 1) 

Consistent with NEMA and ACEEE's 

comments, the Department is concerned 

that defining a distribution transformer 

as having a minimum primary and/or 

secondary voltage may result in 

eliminating certain distribution 

transformers from consideration in the 

standards rulemaking. The Department 

also believes that it can include other 

elements in its definition of 

"distribution transformer" to ensure 

that its test procedures and standards 

for transformers would cover only 

products that are truly "distribution 

transformers." Therefore, the 

Department removed the lower bounds 

on primary and secondary voltage from 

the definition of distribution 

transformer. 

With regard to the framework 

document workshop'S capacity criteria 

for defining a distribution transformer 

(10 to 2500 kVA for liquid-immersed 

units and 5 to 2500 kVA for dry-type 

units), the Department received 

comment that 5 kVA and 10 kVA singlephase, dry-type units are not normally 

used for distribution purposes, but 

rather are almost always used in 

specialized applications related to the 

consumption of electricity (i.e., power 

supplies). (NEMA, No.7 at p. 4) At the 

framework document workshop, ABB 

commented that 5 and 10 kVA dry-type 

units "just don't make any sense when 

somebody considers the concept of 

distribution." (Public Hearing 

Transcript, No. 2MM at p. 28) To 

accommodate this input, the 

Department's revised definition of a 

distribution transformer proposes a 

lower capacity limit for dry-type units 

of 15 kVA, excluding dry-type 

transformers with ratings of 5 and 10 

kVA from the standards rulemaking. 

The Department seeks comment from 

other stakeholders on whether such 

transformers should be classified as 

distribution transformers, and whether 

it should adopt a different lower 

capacity limit for dry-type units in the 

definition of distribution transformer. 

The framework document workshop's 

definition also included "[tlransformers 

designed to continuously transfer 

electrical energy either single phase or 

three phase from a primary distribution 

circuit to a secondary distribution 

circuit, within a secondary distribution 

circuit, or to a consumer's service 

circuit" (DOE presentation at 

Framework Document Workshop, No. 

2CC at p. 7) The Department is 

concerned that these criteria may be too 

vague and imprecise and subject to 

misinterpretation, and may fail to 

establish clearly which transformers are, 

and which are not, covered under EPCA 

as distribution transformers. This would 

particularly affect parties that work with 

distribution transformers in non-utility 

applications, where the terminology in 

these criteria, for example, "to a 

consumer's service circuit" may be 

inapplicable or meaningless. NEMA 

advocated that the Department adopt a 

definition of distribution transformer 

that aligns with the scope of NEMA TP 

1. (NEMA, No.7 at p. 4) The scope 

provision of TP 1 states that the 

standard applies to transformers 

meeting numerical criteria (e.g., voltage, 

kVA) and then lists specific types of 

transformers to which the standard does 

not apply. 

The Department has decided to follow 

the NEMA TP 1 approach in defining a 

distribution transformer. In addition to 

having numerical criteria, DOE's 

proposed definition lists types of 

transformers that are made for 

applications unrelated to the 

distribution of electricity, or for which 

standards would not produce significant 

energy savings, and clarifies that they 

are not "distribution transformers" 

subject to regulation by the Department. 

Such a definition is clearer, more 

precise, and less subject to 

misinterpretation than the framework 

document workshop's proposed 

definition. Although the list of excluded 
45382 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

transformers is quite similar to that in

NEMA TP 1, DOE has modified it

slightly.' The Department added

definitions for each of these excluded

transformers. The Department invites

stakeholders to comment on the new

distribution transformer definition, the

revised scope, the exemptions list, and

the exemptions list definitions.

The following transformers were

identified in the test procedure NOPR as

not-being distribution transformers:

grounding transformers, machine-tool

(control) transformers, regulating

transformers, testing transformers, and

welding transformers. 63 FR 63370.

These transformers are listed as

exclusions in the scope provision of

NEMA TP 1, and they are not

considered in the Department's analysis.

Therefore the Department continues to

exclude them from its proposed

definition of a "distribution

transformer."

The test procedure NOPR also

excluded "converter and rectifier

transformers with more than two

windings per phase" from the definition

of distribution transformer and provided

definitions for these transformers. 63 FR

63370. Comments submitted to the

Department on the test procedure NOPR

and the test procedure reopening notice

supported these exclusions, as well as

the exclusion of rectifier transformers

with less than three windings. The

Department now believes that the

specific exclusion of converter

transformers is unnecessary. The

definition of distribution transformer

includes an upper limit on capacity of

2500 kVA, and it is the Department's

understanding that a transformer

connected to a converter, i.e., a

converter transformer, always has a

r The proposed definition of "distribution

transformer" incorporates almost verbatim 13 of the

17 exclusions set forth in NEMA TP 1. (The list of

exclusions from TP 1 appears on page one of the

document.) NEMA TP 1, however, also excludes

"transformers designed for high harmonics" and

"harmonic transformers," but today's proposed

definition addresses these transformers by

excluding "harmonic mitigating transformers" and

certain "K-factor" (harmonic tolerating)

transformers. In addition, although TP I excludes

"retrofit transformers" and "regulation

transformers," the proposed rule excludes neitherthe former for reasons discussed in the ANOPR text

and the latter because DOE believe they are more

accurately described as "regulating transformers,"

which are already in the list of exclusions in NEMA

TP 1. In addition, NEMA TP 1 excludes "nondistribution transformers, such as UPS

[uninterruptible power supply] transformers."

Although the proposed definition excludes

uninterruptible power supply transformers, the

portion of this exclusion referring to "nondistribution transformers" is vague and the

Department believes its inclusion in the regulations

would undercut the precision achieved by listing

specific types of transformers as being excluded

from the definition of "distribution transformer."

capacity far above this level. Thus,

converter transformers are excluded due

to the upper-bound on the kVA range of

a distribution transformer. The

Department is also proposing to adopt

the definition of "rectifier transformer"

that was recently incorporated into IEEE

C57.12.80-2002, Clause 3.379, rather

than the definition proposed in the test

procedure NOPR. The Department

believes the IEEE definition will be

more widely understood and accepted,

without any loss of technical precision.

b. Exclusions Discussed in the Test

Procedure Reopening Notice

The test procedure reopening notice

stated that the Department was inclined

to exclude autotransformers, and

transformers with tap ranges greater

than 15 percent, from the definition of

distribution transformer. 64 FR 33433-

34. The notice identified comments in

the test procedure NOPR that advocated

these exclusions and the Department's

reasons for favoring them. The

Department received no comments

opposed to these exclusions. Therefore,

these exclusions are included in the

proposed definition.

The Department also discussed in the

test procedure reopening notice whether

it should exclude sealed or nonventilated transformers, special

impedance transformers, and harmonic

transformers from the definition of

distribution transformer. 64 FR 33433-

34. Each of these types of transformer

could be considered to be a distribution

transformer. The Department stated in

the reopening notice that it did not find

persuasive the reasons commenters had

advanced for excluding these products,

and that it intended to include them

unless it received additional

information adequate to justify their

exclusion. Concerning non-ventilated or

sealed transformers, NEMA commented

that the unique features of these

transformers could pose a hardship for

some manufacturers in testing them,

and that they are a small part of the

market for distribution transformers.

(NEMA, No. 46 at p. 5) Given their small

market share, it appears that adopting

standards for non-ventilated or sealed

transformers would not result in

significant energy savings. Thus, DOE is

excluding them from the proposed

definition of distribution transformer.

The Department specifically requests

comments, however, on whether such

exclusion is warranted.

With respect to special impedance

distribution transformers, NEMA stated

that they have much higher load losses

than standard impedance distribution

transformers, and are designed to meet

unusual performance functions. (NEMA,

No. 46 at p. 5) NEMA also asserted that,

because they are relatively expensive to

build, a lack of Federal efficiency

standards for these products would not

cause them to be manufactured and sold

in increased volumes as substitutes for

standard distribution transformers that

were subject to standards. (NEMA, No.

45 at p. 2) The Department agrees with

these points. It also believes that the

market for these products is very small

and that therefore regulating them

would not result in significant energy

savings. For these reasons, the

Department is excluding special

impedance transformers from its

definition of a distribution transformer.

The Department questions the validity

of NEMA's claim that any transformer

with an impedance outside the range of

four to eight percent is a special

impedance transformer. To address this

issue, the Department is proposing a

definition for "special impedance

transformer" that incorporates tables

which set forth the normal impedance

range at each standard kVA rating for

liquid-immersed and dry-type

transformers. DOE would consider any

transformer built with an impedance

rating outside the ranges defined as

normal is considered special

impedance, and is excluded from the

definition of distribution transformer.

The Department requests comments

from stakeholders, particularly

manufacturers, on the normal

impedance ranges shown in these tables

(see Tables II.1 and 11.2) of "special

impedance transformers."

The Department understands that

there are two types of harmonic

distribution transformers, those that

correct harmonics (harmonic mitigating

transformers) and those that simply

tolerate, and do not correct, harmonics

(called harmonic-tolerating or K-factor

transformers). Two companies requested

that DOE exclude harmonic-mitigating

transformers from the standards

rulemaking. (MIRUS International, No.

10 at p. 1; Hammond Power Solutions,

No. 11 at p. 1) The companies requested

the exclusion because these

transformers have three or six windings

per phase, and the complexity of the

windings and the need to limit the

temperature rise created by the

harmonics when the transformer is in

service makes it extremely difficult for

them to meet an efficiency standard.

The Department agrees with these

comments, also noting that harmonicmitigating transformers are designed for

special conditions and provide a unique

customer utility. The Department

believes few of these transformers exist

in the distribution system, regulating

them would save little energy, and

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45382 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

transformers is quite similar to that in 

NEMA TP 1, DOE has modified it 

slightly,1 The Department added 

definitions for each of these excluded 

transformers. The Department invites 

stakeholders to comment on the new 

distribution transformer definition, the 

revised scope, the exemptions list, and 

the exemptions list definitions. 

The following transformers were 

identified in the test procedure NOPR as 

noLbeing distribution transformers: 

grounding transformers, machine-tool 

(control) transformers, regulating 

transformers, testing transformers, and 

welding transformers. 63 FR 63370. 

These transformers are listed as 

exclusions in the scope provision of 

NEMA TP 1, and they are not 

considered in the Department's analysis. 

Therefore the Department continues to 

exclude them from its proposed 

definition of a "distribution 

transformer. " 

The test procedure NOPR also 

excluded "converter and rectifier 

transformers with more than two 

windings per phase" from the definition 

of distribution transformer and provided 

definitions for these transformers. 63 FR 

63370. Comments submitted to the 

Department on the test procedure NOPR 

and the test procedure reopening notice 

supported these exclusions, as well as 

the exclusion of rectifier transformers 

with less than three windings. The 

Department now believes that the 

specific exclusion of converter 

transformers is unnecessary. The 

definition of distribution transformer 

includes an upper limit on capacity of 

2500 kVA, and it is the Department's 

understanding that a transformer 

connected to a converter, i.e., a 

converter transformer, always has a 

1 The proposed definition of" distribution 

transformer" incorporates almost verbatim 13 of the 

17 exclusions set forth in NEMA TP 1. (The list of 

exclusions from TP 1 appears on page one of the 

document.) NEMA TP 1, however, also excludes 

"transformers designed for high harmonics" and 

"harmonic transformers," but today's proposed 

definition addresses these transformers by 

excluding "harmonic mitigating transformers" and 

certain "K-factor" (harmonic tolerating) 

transformers. In addition, although TP 1 excludes 

"retrofit transformers" and "regulation 

transformers," the proposed rule excludes neitherthe former for reasons discussed in the ANOPR text 

and the latter because DOE believe they are more 

accurately described as "regulating transformers," 

which are already in the list of exclusions in NEMA 

TP 1. In addition, NEMA TP 1 excludes "nondistribution transformers, such as UPS 

[uninterruptible power supply] transformers." 

Although the proposed definition excludes 

uninterruptible power supply transformers, the 

portion of this exclusion referring to "nondistribution transformers" is vague and the 

Department believes its inclusion in the regulations 

would undercut the precision achieved by listing 

specific types of transformers as being excluded 

from the definition of" distribution transformer." 

capacity far above this level. Thus, 

converter transformers are excluded due 

to the upper-bound on the kVA range of 

a distribution transformer. The 

Department is also proposing to adopt 

the definition of "rectifier transformer" 

that was recently incorporated into IEEE 

C57.12.80-2002, Clause 3.379, rather 

than the definition proposed in the test 

procedure NOPR. The Department 

believes the IEEE definition will be 

more widely understood and accepted, 

without any loss of technical precision. 

b. Exclusions Discussed in the Test 

Procedure Reopening Notice 

The test procedure reopening notice 

stated that the Department was inclined 

to exclude autotransformers, and 

transformers with tap ranges greater 

than 15 percent, from the definition of 

distribution transformer. 64 FR 33433-

34. The notice identified comments in 

the test procedure NOPR that advocated 

these exclusions and the Department's 

reasons for favoring them. The 

Department received no comments 

opposed to these exclusions. Therefore, 

these exclusions are included in the 

proposed definition. 

The Department also discussed in the 

test procedure reopening notice whether 

it should exclude sealed or nonventilated transformers, special 

impedance transformers, and harmonic 

transformers from the definition of 

distribution transformer. 64 FR 33433-

34. Each ofthese types of transformer 

could be considered to be a distribution 

transformer. The Department stated in 

the reopening notice that it did not find 

persuasive the reasons commenters had 

advanced for excluding these products, 

and that it intended to include them 

unless it received additional 

information adequate to justify their 

exclusion. Concerning non-ventilated or 

sealed transformers, NEMA commented 

that the unique features of these 

transformers could pose a hardship for 

some manufacturers in testing them, 

and that they are a small part of the 

market for distribution transformers. 

(NEMA, No. 46 at p. 5) Given their small 

market share, it appears that adopting 

standards for non-ventilated or sealed 

transformers would not result in 

significant energy savings. Thus, DOE is 

excluding them from the proposed 

definition of distribution transformer. 

The Department specifically requests 

comments, however, on whether such 

exclusion is warranted. 

With respect to special impedance 

distribution transformers, NEMA stated 

that they have much higher load losses 

than standard impedance distribution 

transformers, and are designed to meet 

unusual performance functions. (NEMA, 

No. 46 at p. 5) NEMA also asserted that, 

because they are relatively expensive to 

build, a lack of Federal efficiency 

standards for these products would not 

cause them to be manufactured and sold 

in increased volumes as substitutes for 

standard distribution transformers that 

were subject to standards. (NEMA, No. 

45 at p. 2) The Department agrees with 

these points. It also believes that the 

market for these products is very small 

and that therefore regulating them 

would not result in significant energy 

savings. For these reasons, the 

Department is excluding special 

impedance transformers from its 

definition of a distribution transformer. 

The Department questions the validity 

ofNEMA's claim that any transformer 

with an impedance outside the range of 

four to eight percent is a special 

impedance transformer. To address this 

issue, the Department is proposing a 

definition for "special impedance 

transformer" that incorporates tables 

which set forth the normal impedance 

range at each standard kVA rating for 

liquid-immersed and dry-type 

transformers. DOE would consider any 

transformer built with an impedance 

rating outside the ranges defined as 

normal is considered special 

impedance, and is excluded from the 

definition of distribution transformer. 

The Department requests comments 

from stakeholders, particularly 

manufacturers, on the normal 

impedance ranges shown in these tables 

(see Tables II.l and II.2) of "special 

impedance transformers." 

The Department understands that 

there are two types of harmonic 

distribution transformers, those that 

correct harmonics (harmonic mitigating 

transformers) and those that simply 

tolerate, and do not correct, harmonics 

(called harmonic-tolerating or K-factor 

transformers). Two companies requested 

that DOE exclude harmonic-mitigating 

transformers from the standards 

rulemaking. (MIRUS International, No. 

10 at p. 1; Hammond Power Solutions, 

No. 11 at p. 1) The companies requested 

the exclusion because these 

transformers have three or six windings 

per phase, and the complexity of the 

windings and the need to limit the 

temperature rise created by the 

harmonics when the transformer is in 

service makes it extremely difficult for 

them to meet an efficiency standard. 

The Department agrees with these 

comments, also noting that harmonicmitigating transformers are designed for 

special conditions and provide a unique 

customer utility. The Department 

believes few of these transformers exist 

in the distribution system, regulating 

them would save little energy, and 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

excluding them would be unlikely to

create loopholes in the regulation.

Consequently, the Department is

excluding harmonic-mitigating

transformers from this rulemaking.

The situation with harmonic

tolerating (K-factor) transformers is not

so clear cut. These transformers are

designed for use in industrial situations

where electronic devices can cause

transformer losses that are much higher

than normal, and they are designed to

accommodate such losses without

excessive temperature rise. But the

Department found that it can be

economically viable to use K-factor

distribution transformers that have low

K-factors and relatively low efficiencies,

instead of regular distribution

transformers with higher efficiencies in

standard applications. For example, as

of 1999, Minnesota adopted a building

code requirement that all distribution

transformers installed in the State meet

the NEMA TP 1 efficiency levels, with

an exemption for specific transformers

excluded from TP 1, including K-factor

transformers (see Chapter 3 of TSD).

These K-4 transformers had efficiencies

that were not only below the levels

mandated by NEMA TP 1, they were

also below the prevailing efficiency

levels of conventional transformers that

had been installed in Minnesota before

the State's adoption of TP 1. As the K

rating of K-factor transformers increases,

however, they become increasingly

sophisticated and expensive to produce,

and their share of the total transformer

market diminishes. Thus, the risk that

high K-factor rated transformers would

be used in place of more efficient

transformers declines, and the potential

energy savings from regulating them

becomes insignificant.

Above the K-4 rating, K-9 and K-13

are the next higher standard K-factor

rated transformers. The Department

believes that while K-9 products are a

small part of the market, it is uncertain

whether, absent standards for them, K9 distribution transformers would

replace transformers that are subject to

standards (as happened in Minnesota

with K-4 transformers). The Department

is aware that K-factor transformers at K13 and higher are significantly more

expensive than conventional

transformers, and believes it is very

unlikely they would be purchased in

place of distribution transformers

subject to standards. Thus, the

Department's proposed definition

excludes transformers with a K-factor

rating of K-13 or higher, and includes

K-factor transformers with lower Kfactor ratings (e.g., K-4 and K-9). The

Department specifically invites

comments on this issue.

Finally, the Department believes that

"retrofit distribution transformer" could

refer to any transformer that replaces an

existing distribution transformer. That

said, the Department understands that

the phrase may refer to a distribution

transformer that replaces an existing

transformer. This replacement

transformer design may specify that the

primary and secondary terminals are

compatible with existing switchgear, or

that the transformer incorporates

necessary features or performance

characteristics that differ from

conventional designs. Comments on the

test procedure NOPR asserted that the

Department's exclusions from the

definition of distribution transformer

should provide for situations where

existing distribution transformers

cannot be replaced with more efficient

retrofit transformers, which generally

would be larger or configured

differently from the existing

transformers. In the reopening notice of

the test procedure, the Department

requested further, more detailed

information on this issue. 64 FR 33434.

The Department has not received such

information. Clearly, retrofit

distribution transformers are

distribution transformers, but the

Department lacks the basis for creating

an exclusion for them in the proposed

definition. The Department requests

stakeholder comment on this issue,

specifically information on the nature of

and dimensional restrictions for retrofit

transformers.

c. Additional Exclusions Drawn From

NEMA TP 1

In addition to excluding from the

Department's scope the types of

transformers discussed in sections

II.A.1.a and b of this ANOPR, NEMA TP

1 also excludes drive (isolation),

traction-power, and uninterruptible

power supply transformers. A drive or

isolation transformer is a type of

distribution transformer that is specially

designed to accommodate added loads

of drive-created harmonics and

mechanical stresses caused by an

alternating current or direct current

motor drive. Although intrinsically they

have lower efficiencies than

conventional distribution transformers,

DOE understands that they also have

low sales volumes. Therefore, the

Department believes that issuing

standards for this product would not

result in significant energy savings and

is proposing to exclude them from the

definition of distribution transformer. In

addition, the Department notes that

there are many kinds of drive

transformers, and developing the varied

test methods and multiple standard

45383

levels necessary to achieve even the

limited energy savings possible for this

product would be a complex

undertaking.

As for traction-power transformers,

these are designed to supply power to

railway trains or municipal transit

systems at frequencies of 162/3 or 25 Hz

in an alternating current circuit or as a

rectifier transformer. These transformers

are excluded from the proposed

definition of distribution transformer by

provisions discussed above that exclude

both transformers operating at these low

frequencies as well as rectifier

transformers. Therefore, DOE need not

consider additional specific exclusions

for these transformers.

Finally, an uninterruptable power

supply transformer is not a distribution

transformer. It does not step down

voltage, but rather it is a component of

a power conditioning device. The

uninterruptable power supply

transformer is used as part of the

electric supply system for sensitive

equipment that cannot tolerate system

interruptions or distortions, and

counteracts such irregularities.

Therefore, the Department will exclude

uninterruptable power supply

transformers from the distribution

transformer definition.

d. Distribution Transformer Definition

As noted above, the Department's

proposed definition of "distribution

transformer" is accompanied by specific

definitions for each of the transformers

excluded from the overall definition.

This will clarify which transformers are

covered by the standards in this

rulemaking . For seven of the

transformers excluded from the

Department's definition of a distribution

transformer, definitions were adapted

from IEEE C57 . 12.80-2002:

autotransformers, grounding

transformers, machine-tool (control)

transformers, non-ventilated

transformers, rectifier transformers,

regulating transformers , and sealed

transformers. For K-factor transformers,

the definition is adapted from

Underwriters Laboratories (UL) UL1561

and UL1562 . The Department developed

its own definitions for drive (isolation),

the harmonic mitigating, specialimpedance, testing, tap ranges greater

than 15 percent, uninterruptible power

supply and welding transformers based

on industry catalogues, practice and

nomenclature.

The Department proposes the

following definition for a distribution

transformer:

Distribution transformer means a

transformer with a primary voltage of

equal to, or less than, 35 kV; a

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register / Vol. 69, No. 145/ Thursday, July 29, 2004/Proposed Rules 45383 

excluding them would be unlikely to 

create loopholes in the regulation. 

Consequently, the Department is 

excluding harmonic-mitigating 

transformers from this rulemaking. 

The situation with harmonic 

tolerating (K-factor) transformers is not 

so clear cut. These transformers are 

designed for use in industrial situations 

where electronic devices can cause 

transformer losses that are much higher 

than normal, and they are designed to 

accommodate such losses without 

excessive temperature rise. But the 

Department found that it can be 

economically viable to use K-factor 

distribution transformers that have low 

K-factors and relatively low efficiencies, 

instead of regular distribution 

transformers with higher efficiencies in 

standard applications. For example, as 

of 1999, Minnesota adopted a building 

code requirement that all distribution 

transformers installed in the State meet 

the NEMA TP 1 efficiency levels, with 

an exemption for specific transformers 

excluded from TP 1, including K-factor 

transformers (see Chapter 3 of TSD). 

These K-4 transformers had efficiencies 

that were not only below the levels 

mandated by NEMA TP 1, they were 

also below the prevailing efficiency 

levels of conventional transformers that 

had been installed in Minnesota before 

the State's adoption of TP 1. As the K 

rating of K-factor transformers increases, 

however, they become increasingly 

sophisticated and expensive to produce, 

and their share of the total transformer 

market diminishes. Thus, the risk that 

high K-factor rated transformers would 

be used in place of more efficient 

transformers declines, and the potential 

energy savings from regulating them 

becomes insignificant. 

Above the K-4 rating, K-9 and K-13 

are the next higher standard K-factor 

rated transformers. The Department 

believes that while K-9 products are a 

small part of the market, it is uncertain 

whether, absent standards for them, K9 distribution transformers would 

replace transformers that are subject to 

standards (as happened in Minnesota 

with K-4 transformers). The Department 

is aware that K-factor transformers at K13 and higher are significantly more 

expensive than conventional 

transformers, and believes it is very 

unlikely they would be purchased in 

place of distribution transformers 

subject to standards. Thus, the 

Department's proposed definition 

excludes transformers with a K-factor 

rating ofK-13 or higher, and includes 

K-factor transformers with lower Kfactor ratings (e.g., K-4 and K-9). The 

Department specifically invites 

comments on this issue. 

Finally, the Department believes that 

"retrofit distribution transformer" could 

refer to any transformer that replaces an 

existing distribution transformer. That 

said, the Department understands that 

the phrase may refer to a distribution 

transformer that replaces an existing 

transformer. This replacement 

transformer design may specify that the 

primary and secondary terminals are 

compatible with existing switchgear, or 

that the transformer incorporates 

necessary features or performance 

characteristics that differ from 

conventional designs. Comments on the 

test procedure NOPR asserted that the 

Department's exclusions from the 

definition of distribution transformer 

should provide for situations where 

existing distribution transformers 

cannot be replaced with more efficient 

retrofit transformers, which generally 

would be larger or configured 

differently from the existing 

transformers. In the reopening notice of 

the test procedure, the Department 

requested further, more detailed 

information on this issue. 64 FR 33434. 

The Department has not received such 

information. Clearly, retrofit 

distribution transformers are 

distribution transformers, but the 

Department lacks the basis for creating 

an exclusion for them in the proposed 

definition. The Department requests 

stakeholder comment on this issue, 

specifically information on the nature of 

and dimensional restrictions for retrofit 

transformers. 

c. Additional Exclusions Drawn From 

NEMA TP 1 

In addition to excluding from the 

Department's scope the types of 

transformers discussed in sections 

II.A.l.a and b ofthis ANOPR, NEMA TP 

1 also excludes drive (isolation), 

traction-power, and uninterruptible 

power supply transformers. A drive or 

isolation transformer is a type of 

distribution transformer that is specially 

designed to accommodate added loads 

of drive-created harmonics and 

mechanical stresses caused by an 

alternating current or direct current 

motor drive. Although intrinsically they 

have lower efficiencies than 

conventional distribution transformers, 

DOE understands that they also have 

low sales volumes. Therefore, the 

Department believes that issuing 

standards for this product would not 

result in significant energy savings and 

is proposing to exclude them from the 

definition of distribution transformer. In 

addition, the Department notes that 

there are many kinds of drive 

transformers, and developing the varied 

test methods and multiple standard 

levels necessary to achieve even the 

limited energy savings possible for this 

product would be a complex 

undertaking. 

As for traction-power transformers, 

these are designed to supply power to 

railway trains or municipal transit 

systems at frequencies of 162

13 or 25 Hz 

in an alternating current circuit or as a 

rectifier transformer. These transformers 

are excluded from the proposed 

definition of distribution transformer by 

provisions discussed above that exclude 

both transformers operating at these low 

frequencies as well as. rectifier 

transformers. Therefore, DOE need not 

consider additional specific exclusions 

for these transformers. 

Finally, an uninterruptable power 

supply transformer is not a distribution 

transformer. It does not step down 

voltage, but rather it is a component of 

a power conditioning device. The 

uninterruptable power supply 

transformer is used as part of the 

electric supply system for sensitive 

equipment that cannot tolerate system 

interruptions or distortions, and 

counteracts such irregularities. 

Therefore, the Department will exclude 

uninterruptable power supply 

transformers from the distribution 

transformer definition. 

d. Distribution Transformer Definition 

As noted above, the Department's 

proposed definition of "distribution 

transformer" is accompanied by specific 

definitions for each of the transformers 

excluded from the overall definition. 

This will clarify which transformers are 

covered by the standards in this 

rulemaking. For seven of the 

transformers excluded from the 

Department's definition of a distribution 

transformer, definitions were adapted 

from IEEE C57.12.80-2002: 

autotransformers, grounding 

transformers, machine-tool (control) 

transformers, non-ventilated 

transformers, rectifier transformers, 

regulating transformers, and sealed 

transformers. For K-factor transformers, 

the definition is adapted from 

Underwriters Laboratories (UL) UL1561 

and UL1562. The Department developed 

its own definitions for drive (isolation), 

the harmonic mitigating, specialimpedance, testing, tap ranges greater 

than 15 percent, uninterruptible power 

supply and welding transformers based 

on industry catalogues, practice and 

nomenclature. 

The Department proposes the 

following definition for a distribution 

transformer: 

Distribution transformer means a 

transformer with a primary voltage of 

equal to, or less than, 35 kV; a 
45384 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

secondary voltage equal to, or less than,

600 V; a frequency of 55-65 Hz; and a

capacity of 10 kVA to 2500 kVA for

liquid-immersed units and 15 kVA to

2500 kVA for dry-type units, and does

not include the following types of

transformers: (1) Autotransformer; (2)

drive (isolation) transformer; (3)

grounding transformer; (4) harmonic

mitigating transformer; (5) K-factor

transformer; (6) machine-tool (control)

transformer; (7) non-ventilated

transformer; (8) rectifier transformer; (9)

regulating transformer; (10) sealed

transformer; (11) special-impedance

transformer; (12) testing transformer;

(13) transformer with tap range greater

than 15 percent; (14) uninterruptible

power supply transformer; or (15)

welding transformer.

Autotransformer means a transformer

that: (a) Has one physical winding that

consists of a series winding part and a

common winding part; (b) has no

isolation between its primary and

secondary circuits; and (c) during stepdown operation, has a primary voltage

that is equal to the total of the series and

common winding voltages, and a

secondary voltage that is equal to the

common winding voltage.

Drive (isolation) transformer means a

transformer that: (a) isolates an electric

motor from the line; (b) accommodates

the added loads of drive-created

harmonics; and (c) is designed to

withstand the additional mechanical

stresses resulting from an alternating

current adjustable frequency motor

drive or a direct current motor drive.

Grounding transformer means a threephase transformer intended primarily to

provide a neutral point for systemgrounding purposes, either by means of:

(a) A grounded wye primary winding

and a delta secondary winding; or (b) an

autotransformer with a zig-zag winding

arrangement.

Harmonic mitigating transformer

means a transformer designed to cancel

or reduce the harmonics drawn by

computer equipment and other nonlinear power electronic loads.

K -factor transformer means a

transformer with a K-factor of 13 or

greater that is designed to tolerate the

additional eddy-current losses resulting

from harmonics drawn by non-linear

loads, usually when the ratio of the nonlinear load to the linear load is greater

than 50 percent.

Machine-tool (control) transformer

means a transformer that is equipped

with a fuse or other overcurrent

protection device, and is generally used

for the operation of a solenoid,

contactor, relay, portable tool, or

localized lighting.

Non-ventilated transformer means a

transformer constructed so as to prevent

external air circulation through the coils

of the transformer while operating at

zero gauge pressure.

Rectifier transformer means a

transformer that operates at the

fundamental frequency of an

alternating-current system and that is

designed to have one or more output

windings connected to a rectifier.

Regulating Transformer means a

transformer that varies the voltage, the

phase angle, or both voltage and phase

angle, of an output circuit and

compensates for fluctuation of load and

input voltage, phase angle or both

voltage and phase angle.

Sealed Transformer means a

transformer designed to remain

hermetically sealed under specified

conditions of temperature and pressure.

Special-impedance transformer

means any transformer built to operate

at an impedance outside of the normal

impedance range for that transformer's

kVA rating. The normal impedance

range for each kVA rating is shown in

Tables II.1 and 11.2:

TABLE 11.1.-NORMAL IMPEDANCE

RANGES FOR LIQUID-IMMERSED

TRANSFORMERS

kVA Impedance

(%)

Single-Phase Transformers

10 ..........................................

15 ..........................................

25 ..........................................

37.5 .......................................

50 ..........................................

75 ..........................................

100 ........................................

167 ........................................

250 ........................................

333 ........................................

500 ........................................

667 ........................................

833 ........................................

Three-Phase Transformers

1.0-4.5

1.0-4.5

1.0-4.5

1.0-4.5

1.5-4.5

1.5-4.5

1.5-4.5

1.5-4.5

1.5-6.0

1.5-6.0

1.5-7.0

5.0-7.5

5.0-7.5

15 .......................................... 1.0-4.5

30 .......................................... 1.0-4.5

45 .......................................... 1.0-4.5

75 .......................................... 1.0-5.0

112.5 ..................................... 1.2-6.0

150 ........................................ 1.2-6.0

225 ........................................ 1.2-6.0

300 ........................................ 1.2-6.0

500 ........................................ 1.5-7.0

750 ........................................ 5.0-7.5

1000 ...................................... 5.0-7.5

1500 ...................................... 5.0-7.5

2000 ...................................... 5.0-7.5

2500 ...................................... 5.0-7.5

TABLE 11.2.-NORMAL IMPEDANCE

RANGES FOR DRY-TYPE TRANSFORMERS

kVA Impedance

(%)

Single-Phase Transformers

15 ..........................................

25 ..........................................

37.5 .......................................

50 ..........................................

75 ..........................................

100 ........................................

167 ........................................

250 ........................................

333 ........................................

500 ........................................

667 ........................................

833 ........................................

Three-Phase Transformers

1.5-6.0

1.5-6.0

1.5-6.0

1.5-6.0

2.0-7.0

2.0-7.0

2.5-8.0

3.5-8.0

3.5-8.0

3.5-8.0

5.0-8.0

5.0-8.0

15 .......................................... 1.5-6.0

30 .......................................... 1.5-6.0

45 .......................................... 1.5-6.0

75 .......................................... 1.5-6.0

112.5 ..................................... 1.5-6.0

150 ........................................ 1.5-6.0

225 ........................................ 3.0-7.0

300 ........................................ 3.0-7.0

500 ........................................ 4.5-8.0

750 ........................................ 5.0-8.0

1000 ...................................... 5.0-8.0

1500 ...................................... 5.0-8.0

2000 ...................................... 5.0-8.0

2500 ...................................... 5.0-8.0

Testing Transformer means a

transformer used in a circuit to produce

a specific voltage or current for the

purpose of testing electrical equipment.

This type of transformer is also

commonly known as an instrument

transformer.

Transformer with Tap Range greater

than 15 percent means a transformer

with a tap range in the primary winding

greater than the range accomplished

with six 2.5-percent taps, 3 above and

3 below the rated primary voltage (e.g.,

6 times 2.5 percent = 15 percent).

Uninterruptible Power Supply

Transformer means a transformer that

supplies power to an uninterruptible

power system, which in turn supplies

power to loads that are sensitive to

power failure, power sags, over-voltage,

switching transients, line noise, and

other power quality factors.

Welding Transformer means a

transformer designed for use in arc

welding equipment or resistance

welding equipment.

e. Exclusions Not Incorporated

Howard Industries, Edison Electric

Institute (EEI), Southern Company, and

TXU Electric and Gas all submitted

comments requesting that liquid-filled

transformers be excluded from the

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45384 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

secondary voltage equal to, or less than, 

600 V; a frequency of 55-65 Hz; and a 

capacity of 10 kVA to 2500 kVA for 

liquid-immersed units and 15 kVA to 

2500 kVA for dry-type units, and does 

not include the following types of 

transformers: (1) Autotransformer; (2) 

drive (isolation) transformer; (3) 

grounding transformer; (4) harmonic 

mitigating transformer; (5) K-factor 

transformer; (6) machine-tool (control) 

transformer; (7) non-ventilated 

transformer; (8) rectifier transformer; (9) 

regulating transformer; (10) sealed 

transformer; (11) special-impedance 

transformer; (12) testing transformer; 

(13) transformer with tap range greater 

than 15 percent; (14) uninterruptible 

power supply transformer; or (15) 

welding transformer. 

Autotransformer means a transformer 

that: (a) Has one physical winding that 

consists of a series winding part and a 

common winding part; (b) has no 

isolation between its primary and 

secondary circuits; and (c) during stepdown operation, has a primary voltage 

that is equal to the total of the series and 

common winding voltages, and a 

secondary voltage that is equal to the 

common winding voltage. 

Drive (isolation) transformer means a 

transformer that: (a) isolates an electric 

motor from the line; (b) accommodates 

the added loads of drive-created 

harmonics; and (c) is designed to 

withstand the additional mechanical 

stresses resulting from an alternating 

current adjustable frequency motor 

drive or a direct current motor drive. 

Grounding transformer means a threephase transformer intended primarily to 

provide a neutral point for systemgrounding purposes, either by means of: 

(a) A grounded wye primary winding 

and a delta secondary winding; or (b) an 

autotransformer with a zig-zag winding 

arrangement. 

Harmonic mitigating transformer 

means a transformer designed to cancel 

or reduce the harmonics drawn by 

computer equipment and other nonlinear power electronic loads. 

K-factor transformer means a 

transformer with a K-factor of 13 or 

greater that is designed to tolerate the 

additional eddy-current losses resulting 

from harmonics drawn by non-linear 

loads, usually when the ratio of the nonlinear load to the linear load is greater 

than 50 percent. 

Machine-tool (control) transformer 

means a transformer that is equipped 

with a fuse or other overcurrent 

protection device, and is generally used 

for the operation of a solenoid, 

contactor, relay, portable tool, or 

localized lighting. 

Non-ventilated transformer means a 

transformer constructed so as to prevent 

external air circulation through the coils 

of the transformer while operating at 

zero gauge pressure. 

Rectifier transformer means a 

transformer that operates at the 

fundamental frequency of an 

alternating-current system and that is 

designed to have one or more output 

windings connected to a rectifier. 

Regulating Transformer means a 

transformer that varies the voltage, the 

phase angle, or both voltage and phase 

angle, of an output circuit and 

compensates for fluctuation of load and 

input voltage, phase angle or both 

voltage and phase angle. 

Sealed Transformer means a 

transformer designed to remain 

hermetically sealed under specified 

conditions of temperature and pressure. 

Special-impedance transformer 

means any transformer built to operate 

at an impedance outside of the normal 

impedance range for that transformer's 

kVA rating. The normal impedance 

range for each kVA rating is shown in 

Tables 11.1 and II.2: 

TABLE 1I.1.-NoRMAL IMPEDANCE 

RANGES FOR liQUID-IMMERSED 

TRANSFORMERS 

kVA Impedance 

(%) 

Single-Phase Transformers 

10 ......................................... . 15 ......................................... . 25 ......................................... . 37.5 ...................................... . 50 ......................................... . 75 ......................................... . 100 ...................................... .. 167 ....................................... . 250 ....................................... . 333 ....................................... . 500 ....................................... . 667 ....................................... . 833 ....................................... . 

Three-Phase Transformers 

15 ........................................ .. 30 ......................................... . 45 ......................................... . 75 ......................................... . 112.5 .................................... . 150 ...................................... .. 225 ....................................... . 300 ...................................... .. 500 ....................................... . 750 ....................................... . 1000 ..................................... . 1500 .................................... .. 2000 ..................................... . 2500 ..................................... . 

1.0-4.5 

1.0-4.5 

1.0-4.5 

1.0-4.5 

1.5-4.5 

1.5-4.5 

1.5-4.5 

1.5-4.5 

1.5-6.0 

1.5-6.0 

1.5-7.0 

5.0-7.5 

5.0-7.5 

1.0-4.5 

1.0-4.5 

1.0-4.5 

1.0-5.0 

1.2--6.0 

1.2-6.0 

1.2-6.0 

1.2-6.0 

1.5-7.0 

5.0-7.5 

5.0-7.5 

5.0-7.5 

5.0-7.5 

5.0-7.5 

TABLE 11.2.-NoRMAL IMPEDANCE 

RANGES FOR DRY-TYPE TRANSFORMERS 

kVA Impedance 

(%) 

Single-Phase Transformers 

15 ......................................... . 25 ......................................... . 37.5 ..................................... .. 50 ......................................... . 75 ......................................... . 100 ...................................... .. 167 ...................................... .. 250 ...................................... .. 333 ....................................... . 500 ....................................... . 667 ....................................... . 833 ....................................... . 

Three-Phase Transformers 

15 ......................................... . 30 ......................................... . 45 ......................................... . 75 ......................................... . 112.5 ................................... .. 150 ....................................... . 225 ....................................... . 300 ...................................... .. 500 ....................................... . 750 ....................................... . 1000 .................................... .. 1500 ..................................... . 2000 ..................................... . 2500 ..................................... . 

1.5-6.0 

1.5-6.0 

1.5-6.0 

1.5-6.0 

2.0-7.0 

2.0-7.0 

2.5-8.0 

3.5-8.0 

3.5-8.0 

3.5-8.0 

5.0-8.0 

5.0-8.0 

1.5-6.0 

1.5-6.0 

1.5-6.0 

1.5-6.0 

1.5-6.0 

1.5-6.0 

3.0-7.0 

3.0-7.0 

4.5-8.0 

5.0-8.0 

5.0-8.0 

5.0-8.0 

5.0-8.0 

5.0-8.0 

Testing Transformer means a 

transformer used in a circuit to produce 

a specific voltage or current for the 

purpose of testing electrical equipment. 

This type of transformer is also 

commonly known as an instrument 

transformer. 

Transformer with Tap Range greater 

than 15 percent means a transformer 

with a tap range in the primary winding 

greater than the range accomplished 

with six 2.5-percent taps, 3 above and 

3 below the rated primary voltage (e.g., 

6 times 2.5 percent = 15 percent). 

Uninterruptible Power Supply 

Transformer means a transformer that 

supplies power to an uninterruptible 

power system, which in turn supplies 

power to loads that are sensitive to 

power failure, power sags, over-voltage, 

switching transients, line noise, and 

other power quality factors. 

Welding Transformer means a 

transformer designed for use in arc 

welding equipment or resistance 

welding equipment. 

e. Exclusions Not Incorporated 

Howard Industries, Edison Electric 

Institute (EEl), Southern Company, and 

TXU Electric and Gas all submitted 

comments requesting that liquid-filled 

transformers be excluded from the 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

rulemaking. (Howard Industries, No. 4

at p. 2; EEI, No. 6 at p. 1; Southern

Company, No. 8 at p. 5; TXU Electric

and Gas, No. 12 at p. 1) One reason cited

for EEI's request is the fact that in a

deregulated electricity market, the

energy saving benefits will accrue to the

energy service provider, while the

additional capital equipment cost will

be borne by the utility distribution

company. (EEI, No. 6 at pp. 2-3)

Southern Company requested that

liquid-immersed transformers be

excluded from the rulemaking because

the energy savings potential is only onequarter the total energy savings estimate

in the Determination Analysis, and

because many utilities choose to buy

transformers below TP 1 levels for their

own economic reasons. (Southern

Company, No. 8 at p. 5)

The Natural Resources Defense

Council (NRDC) countered these

requests in their comments, noting that

at the framework document workshop,

several commenters identified a trend

stemming from restructuring in the

electric utility industry, which is

causing fewer and fewer electricity

providers to use a lowest TOC method

for purchasing transformers, thereby

causing liquid-immersed transformer

efficiencies to decline. NRDC sees this

trend as a market failure that requires

Federal standards to correct the

problem. (NRDC, No. 5 at p. 4) NRDC

urged DOE to consider the widest

possible scope for transformer efficiency

standards in doing its analysis. (NRDC,

No. 5 at p. 6)

At this time, the Department is not

excluding liquid-immersed transformers

from the scope of the rulemaking. The

Department is charged with determining

whether standards for distribution

transformers are technologically feasible

and economically justified and would

result in significant energy savings. No

one has argued that liquid-immersed

transformers are not distribution

transformers, and therefore that they fall

outside the scope of the Department's

statutory authority. Furthermore, DOE is

not able to conclude, based on the data

and information available to it, that

standards for liquid-immersed

transformers are not technologically

feasible nor economically justified, or

that standards for this equipment would

not result in significant energy savings.

Thus, the Department will be

investigating whether the inclusion of

liquid-immersed standards is warranted.

2. Product Classes

In general, when evaluating and

establishing energy efficiency standards,

the Department divides covered

products into classes by: (a) the type of

energy used; (b) capacity; and (c)

performance-related features that affect

consumer utility or efficiency. Different

energy efficiency standards may apply

to different product classes. The

Department has received some guidance

from stakeholders on establishing

appropriate product classes for the

population of distribution transformers.

Howard Industries stated that liquidimmersed distribution transformers

should not be categorized with dry-type

distribution transformers. (Howard

Industries, No. 4 at p. 2) Cooper Power

Systems believes that the Department

should set one standard for all

distribution transformers and not treat

liquid-immersed and dry-type

transformers separately. (Cooper Power

Systems, No. 34 at p. 1) The Department

recognizes that liquid-immersed and

dry-type units have different physical

construction and different end-use

applications. Generally, liquidimmersed units are filled with mineral

oil and are used in outdoor installations

(e.g., concrete pad or pole-mounted).

The Department recognizes that drytype units are generally used for indoor

applications and must comply with the

safety requirements of the National

Electrical Code (ANSI/National Fire

Protection Association Standard 70).

Due to these differences in performancerelated features that affect consumer

utility, the Department is tentatively

planning to have separate efficiency

standards for liquid-immersed and drytype distribution transformers, and to

treat them as two distinct product

classes.

NEMA recommended that the

Department use the product classes

given in TP 1, which are based on the

type of transformer (liquid or dry), the

number of phases (1 or 3), voltage (low

or medium) and the kVA rating. (NEMA,

No. 7 at p. 5) ACEEE supported the

Department's use of the product classes

in TP 1, since this standard is now

extensively used by manufacturers, the

ENERGY STAR" program administered

by DOE and the Environmental

Protection Agency (EPA), and voluntary

programs operated by utilities and other

organizations in association with the

Consortium for Energy Efficiency's

transformer initiative. (ACEEE, No. 14 at

p. 2) The Department agrees with these

comments and intends to use NEMA TP

1 product classes for all transformers

except medium-voltage, dry-type units.

NEMA noted in a comment that

medium-voltage, dry-type transformers

may be separated into two groups, based

on their Basic Impulse Insulation Level

(BIL). (NEMA, No. 7 at p. 6) At that

time, NEMA indicated it was

considering revising TP 1-1996 and

45385

splitting the standard levels for

medium-voltage, dry-types into two

groups. NEMA later confirmed that it

did adopt this modification for TP 1-

2002, establishing one standard for

medium-voltage, dry-types less than or

equal to 60 kV BIL and a separate

standard for those units greater than 60

kV BIL. (NEMA, No. 26 at p. 1)

The Department understands that the

reason for this revision to TP 1 is that

the efficiency of a dry-type, mediumvoltage transformer varies in part due to

the level of insulation in its windings

(the BIL rating). If one efficiency level

were assigned to all BIL levels, it would

be a relatively weak standard for low

BIL ratings and an extremely difficult

standard for higher BIL ratings.

Implementing one standard across all

dry-type, medium-voltage BIL ratings

could result in driving the market

toward a BIL rating lower than it would

otherwise be in the absence of a

standard.

However, at this time, the Department

is concerned that simply using two BIL

groupings as used in TP 1-2002 (<60 kV

BIL and >60 kV BIL) may not result in

appropriate efficiency levels for all

types of medium-voltage, dry-type

transformers. Thus, for the ANOPR, the

Department based its analysis on a

slightly finer resolution of BIL levels

and created three classifications: 20-45

kV BIL, 46-95 kV BIL, and >96 kV BIL.

In this way, candidate standard levels

will be more accurately suited to the

covered transformers. The Department

requests comments from stakeholders

on this decision to create three BIL

classifications rather than the two in

NEMA's TP 1-2002.

TXU Electric and Gas recommended

that the Department separate liquidimmersed and dry-type distribution

transformers, and then further separate

liquid-immersed transformers into

commercial and industrial end users,

and residential end users. (TXU Electric

and Gas, No. 12 at p. 5) TXU Electric

and Gas made this recommendation

because it believes the loading profiles

of a transformer supplying a residential

load versus one supplying a commercial

or an industrial load could be

dramatically different. The Department

cannot accommodate this request as

standards cannot be promulgated

separately based on the particular uses

made by individual users. However, the

Department does address sectoral (enduser) issues such as load profiles and

energy prices in the LCC analysis (see

Chapter 8 of the TSD).

Table 11.3 presents the Department's

proposed product classes.

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register/Vol. 69, No. 145 I Thursday, July 29, 2004 I Proposed Rules 45385 

rulemaking. (Howard Industries, No.4 

at p. 2; EEl, No.6 at p. 1; Southern 

Company, No.8 at p. 5; TXU Electric 

and Gas, No. 12 at p. 1) One reason cited 

for EEl's request is the fact that in a 

deregulated electricity market, the 

energy saving benefits will accrue to the 

energy service provider, while the 

additional capital equipment cost will 

be borne by the utility distribution 

company. (EEl, No.6 at pp. 2-3) 

Southern Company requested that 

liquid-immersed transformers be 

excluded from the rulemaking because 

the energy savings potential is only onequarter the total energy savings estimate 

in the Determination Analysis, and 

because many utilities choose to buy 

transformers below TP 1 levels for their 

own economic reasons. (Southern 

Company, No.8 at p. 5) 

The Natural Resources Defense 

Council (NRDC) countered these 

requests in their comments, noting that 

at the framework document workshop, 

several commenters identified a trend 

stemming from restructuring in the 

electric utility industry, which is 

causing fewer and fewer electricity 

providers to use a lowest TOC method 

for purchasing transformers, thereby 

causing liquid-immersed transformer 

efficiencies to decline. NRDC sees this 

trend as a market failure that requires 

Federal standards to correct the 

problem. (NRDC, No.5 at p. 4) NRDC 

urged DOE to consider the widest 

possible scope for transformer efficiency 

standards in doing its analysis. (NRDC, 

No.5 at p. 6) 

At this time, the Department is not 

excluding liquid-immersed transformers 

from the scope of the rulemaking. The 

Department is charged with determining 

whether standards for distribution 

transformers are technologically feasible 

and economically justified and would 

result in significant energy savings. No 

one has argued that liquid-immersed 

transformers are not distribution 

transformers, and therefore that they fall 

outside the scope of the Department's 

statutory authority. Furthermore, DOE is 

not able to conclude, based on the data 

and information available to it, that 

staridards for liquid-immersed 

transformers are not technologically 

feasible nor economically justified, or 

that standards for this equipment would 

not result in significant energy savings. 

Thus, the Department will be 

investigating whether the inclusion of 

liquid-immersed standards is warranted. 

2. Product Classes 

In general, when evaluating and 

establishing energy efficiency standards, 

the Department divides covered 

products into classes by: (a) the type of 

energy used; (b) capacity; and (c) 

performance-related features that affect 

consumer utility or efficiency. Different 

energy efficiency standards may apply 

to different product classes. The 

Department has received some guidance 

from stakeholders on establishing 

appropriate product classes for the 

population of distribution transformers. 

Howard Industries stated that liquidimmersed distribution transformers 

should not be categorized with dry-type 

distribution transformers. (Howard 

Industries, No.4 at p. 2) Cooper Power 

Systems believes that the Department 

should set one standard for all 

distribution transformers and not treat 

liquid-immersed and dry-type 

transformers separately. (Cooper Power 

Systems, No. 34 at p. 1) The Department 

recognizes that liquid-immersed and 

dry-type units have different physical 

construction and different end-use 

applications. Generally, liquidimmersed units are filled with mineral 

oil and are used in outdoor installations 

(e.g., concrete pad or pole-mounted). 

The Department recognizes that drytype units are generally used for indoor 

applications and must comply with the 

safety requirements of the National 

Electrical Code (ANSI/National Fire 

Protection Association Standard 70). 

Due to these differences in performancerelated features that affect consumer 

utility, the Department is tentatively 

planning to have separate efficiency 

standards for liquid-immersed and drytype distribution transformers, and to 

treat them as two distinct product 

classes. 

NEMA recommended that the 

Department use the product classes 

given in TP 1, which are based on the 

type of transformer (liquid or dry), the 

number of phases (1 or 3), voltage (low 

or medium) and the kV A rating. (NEMA, 

No.7 at p. 5) ACEEE supported the 

Department's use ofthe product classes 

in TP 1, since this standard is now 

extensively used by manufacturers, the 

ENERGY STAR" program administered 

by DOE and the Environmental 

Protection Agency (EPA), and voluntary 

programs operated by utilities and other 

organizations in association with the 

Consortium for Energy Efficiency's 

transformer initiative. (ACEEE, No. 14 at 

p. 2) The Department agrees with these 

comments and intends to use NEMA TP 

1 product classes for all transformers 

except medium-voltage, dry-type units. 

NEMA noted in a comment that 

medium-voltage, dry-type transformers 

may be separated into two groups, based 

on their Basic Impulse Insulation Level 

(BIL). (NEMA, No.7 at p. 6) At that 

time, NEMA indicated it was 

considering revising TP 1-1996 and 

splitting the standard levels for 

medium-voltage, dry-types into two 

groups. NEMA later confirmed that it 

did adopt this modification for TP 1-

2002, establishing one standard for 

medium-voltage, dry-types less than or 

equal to 60 kV BIL and a separate 

standard for those units greater than 60 

kV BIL. (NEMA, No. 26 at p. 1) 

The Department understands that the 

reason for this revision to TP 1 is that 

the efficiency of a dry-type, mediumvoltage transformer varies in part due to 

the level of insulation in its windings 

(the BIL rating). If one efficiency level 

were assigned to all BIL levels, it would 

be a relatively weak standard for low 

BIL ratings and an extremely difficult 

standard for higher BIL ratings. 

Implementing one standard across all 

dry-type, medium-voltage BIL ratings 

could result in driving the market 

toward a BIL rating lower than it would 

otherwise be in the absence of a 

standard. 

However, at this time, the Department 

is concerned that simply using two BIL 

groupings as used in TP 1-2002 «60 kV 

BIL and >60 kV BIL) may not result in 

appropriate efficiency levels for all 

types of medium-voltage, dry-type 

transformers. Thus, for the ANOPR, the 

Department based its analysis on a 

slightly finer resolution of BIL levels 

and created three classifications: 20-45 

kV BIL, 46-95 kV BIL, and >96 kV BIL. 

In this way, candidate standard levels 

will be more accurately suited to the 

covered transformers. The Department 

requests comments from stakeholders 

on this decision to create three BIL 

classifications rather than the two in 

NEMA's TP 1-2002. 

TXU Electric and Gas recommended 

that the Department separate liquidimmersed and dry-type distribution 

transformers, and then further separate 

liquid-immersed transformers into 

commercial and industrial end users, 

and residential end users. (TXU Electric 

and Gas, No. 12 at p. 5) TXU Electric 

and Gas made this recommendation 

because it believes the loading profiles 

of a transformer supplying a residential 

load versus one supplying a commercial 

or an industrial load could be 

dramatically different. The Department 

cannot accommodate this request as 

standards cannot be promulgated 

separately based on the particular uses 

made by individual users. However, the 

Department does address sectoral (enduser) issues such as load profiles and 

energy prices in the LCC analysis (see 

Chapter 8 of the TSD). 

Table II.3 presents the Department's 

proposed product classes. 
45386 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

TABLE 11.3.-PROPOSED DISTRIBUTION TRANSFORMER PRODUCT CLASSES

Number Insulation Voltage Phases BIL rating kVA range

1 ......................... Liquid-Im- Medium ............ Single ............... ................................................ 10-833 kVA

mersed.

2 ......................... Liquid-Im- Medium ............ Three ................ ................................................ 15-2500 kVA

mersed.

3 ......................... Dry-Type .......... Low .................. Single ............... ................................................ 15-333 kVA

4 ......................... Dry-Type .......... Low .................. Three ................ ................................................ 15-1000 kVA

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

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

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

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

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

10 ....................... Dry-Type .......... Medium ............ Three ................ _96kV BIL ................................... 225-2500 kVA

3. Market Assessment

The liquid-immersed transformer

market accounted for 77 percent of the

distribution transformers sold in the

United States in 2001 (on a unit basis).

These transformers accounted for 74

percent of the distribution transformer

capacity measured in megavolt-amperes

(MVA), and 78 percent of the dollar

value of the 2001 shipments. On a unit

basis, more than 90 percent of the

liquid-immersed shipments are singlephase units. However, these singlephase units tend to have lower kVA

ratings than the three-phase units,

which are more than half of the total

MVA capacity shipped of liquidimmersed distribution transformers in

2001.

In the dry-type market, low-voltage,

three-phase distribution transformers

dominate, accounting for 91 percent of

units and 78 percent of MVA shipped.

Medium-voltage, three-phase units

accounted for only one percent of the

units shipped, but were 18 percent of

MVA shipments in 2001. The lowvoltage, single-phase units were about 7

percent of the dry-type units shipped;

however, because their kVA ratings tend

to be small, they only accounted for

about 3.5 percent of the cumulative drytype MVA shipments in 2001. Mediumvoltage, single-phase units occupy a

small part of the market, representing

less than one-half of one percent of both

units and MVA shipped. A detailed

estimate of total national shipments of

distribution transformers for 2001 can

be found in the shipments analysis,

section II.G and in Chapter 9 of the TSD.

Market characteristics related to

efficiency trends indicate that

distribution transformer efficiencies are

decreasing. ORNL identified this trend

for dry-type transformers in its

Determination Analysis, noting that

over the last two decades, efficiency of

dry-type units has declined. ORNL

indicated that part of the reason for this

trend was a focus on lowest first-cost

units, because contractors purchasing

the units would not benefit directly

from the energy savings. For liquidimmersed distribution transformers,

NEMA commented that a few years ago

nearly 100 percent of utility

transformers sold met or exceeded the

TP 1 efficiency standard. NEMA

estimates that in the liquid-immersed

market, the percentage of TP 1

compliant units in 2002 dropped to

about 50 percent. (NEMA, No. 26 at p.

3) NEMA's comment is consistent with

comments made at the framework

document workshop by TXU Electric

and Gas and Southern Company that

deregulation of electric utilities is

shifting the liquid-immersed market

toward less efficient, lower first-cost

distribution transformers. (Public

Hearing Transcript, No. 2MM at pp. 66-

69) The Department is concerned that

the liquid-immersed market may be

following the dry-type market, moving

toward less energy efficient units.

4. Technology Assessment

The technology assessment provides

the technical background and structure

on which the engineering analysis is

based. The Department based its list of

technologically feasible design options

on input from manufacturers,

component suppliers, trade

publications, and technical papers. The

technology assessment for this

rulemaking incorporates input from

eight manufacturers and one component

supplier visited by the Department, as

well as written comments.

Table 11.4 is adapted from the ORNL

study, Determination Analysis of Energy

Conservation Standards for Distribution

Transformers, ORNL-6847, 1996. This

table summarizes the methods of

making a transformer more efficient by

reducing the number of watts lost in the

core (no-load) and winding (load), and

the associated inter-relational issues.

The engineering analysis examined the

options shown in this table (see Chapter

5 of the TSD).

Nearly all the energy consumed by

distribution transformers is lost in the

core and the winding assemblies. Design

modifications that reduce losses in the

core may cause an increase in winding

losses; conversely, modifications to the

design that reduce losses in the

windings may increase losses in the

core.

TABLE II.4.-OPTIONS AND IMPACTS OF INCREASING TRANSFORMER EFFICIENCY

No-load losses

To decrease no-load losses

Use lower-loss core materials .........................................

Decrease flux density by: ........... ....................................

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

(b) Decreasing volts per turn ...................................

Decrease flux path length by decreasing conductor

CSA.

Lower .................................

Lower .................................

Lower .................................

Lower .................................

Load losses

No change* ........................

Higher ................................

Higher ................................

Higher ................................

Higher.

Higher.

Higher.

Lower.

Cost impact

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45386 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

TABLE 11.3.-PROPOSED DISTRIBUTION TRANSFORMER PRODUCT CLASSES 

Number Insulation Voltage Phases BIL rating kVA range 

Liquid-Immersed. 

Medium ............ Single .............. . 10-833 kVA 

2 ........................ . Liquid-Im- Medium ............ Three .............. .. 15-2500 kVA 

mersed. 

3 ........................ . Dry-Type ........ .. Low ................ .. Single .............. . 15-333 kVA 

15-1000 kVA 

15-833 kVA 

15-2500 kVA 

15-833 kVA 

15-2500 kVA 

75-833 kVA 

225-2500 kV A 

4 ........................ . Dry-Type ........ .. Low ................ .. Three .............. .. 

5 ........................ . Dry-Type ........ .. Medium 

6 ........................ . Dry-Type ........ .. Medium 

7 ........................ . Dry-Type ........ .. Medium 

8 ........................ . Dry-Type ........ .. Medium 

9 ........................ . Dry-Type ........ .. Medium 

10 ...................... . Dry-Type ........ .. Medium 

3. Market Assessment 

The liquid-immersed transformer 

market accounted for 77 percent of the 

distribution transformers sold in the 

United States in 2001 (on a unit basis). 

These transformers accounted for 74 

percent of the distribution transformer 

capacity measured in megavolt-amperes 

(MVA), and 78 percent ofthe dollar 

value of the 2001 shipments. On a unit 

basis, more than 90 percent of the 

liquid-immersed shipments are singlephase units. However, these singlephase units tend to have lower kVA 

ratings than the three-phase units, 

which are more than half of the total 

MVA capacity shipped of liquidimmersed distribution transformers in 

2001. 

In the dry-type market, low-voltage, 

three-phase distribution transformers 

dominate, accounting for 91 percent of 

units and 78 percent of MVA shipped. 

Medium-voltage, three-phase units 

accounted for only one percent ofthe 

units shipped, but were 18 percent of 

MVA shipments in 2001. The lowvoltage, single-phase units were about 7 

percent of the dry-type units shipped; 

however, because their kVA ratings tend 

to be small, they only accounted for 

about 3.5 percent of the cumulative drytype MVA shipments in 2001. Mediumvoltage, single-phase units occupy a 

small part of the market, representing 

less than one-half of one percent of both 

units and MVA shipped. A detailed 

estimate of total national shipments of 

Single .............. . 20-45kV BIL .............................. . 

Three .............. .. 20-45kV BIL .............................. . 

Single .............. . 46-95kV BIL .............................. . 

Three .............. .. 46-95kV BIL .............................. . 

Single .............. . 296kV BIL .................................. . 

Three .............. .. 296kV BIL .................................. . 

distribution transformers for 2001 can 

be found in the shipments analysis, 

section I1.G and in Chapter 9 of the TSD. 

Market characteristics related to 

efficiency trends indicate that 

distribution transformer efficiencies are 

decreasing. ORNL identified this trend 

for dry-type transformers in its 

Determination Analysis, noting that 

over the last two decades, efficiency of 

dry-type units has declined. ORNL 

indicated that part of the reason for this 

trend was a focus on lowest first-cost 

units, because contractors purchasing 

the units would not benefit directly 

from the energy savings. For liquidimmersed distribution transformers, 

NEMA commented that a few years ago 

nearly 100 percent of utility 

transformers sold met or exceeded the 

TP 1 efficiency standard. NEMA 

estimates that in the liquid-immersed 

market, the percentage of TP 1 

compliant units in 2002 dropped to 

about 50 percent. (NEMA, No. 26 at p. 

3) NEMA's comment is consistent with 

comments made at the framework 

document workshop by TXU Electric 

and Gas and Southern Company that 

deregulation of electric utilities is 

shifting the liquid-immersed market 

toward less efficient, lower first-cost 

distribution transformers. (Public 

Hearing Transcript, No. 2MM at pp. 66-

69) The Department is concerned that 

the liquid-immersed market may be 

following the dry-type market, moving 

toward less energy efficient units. 

4. Technology Assessment 

The technology assessment provides 

the technical background and structure 

on which the engineering analysis is 

based. The Department based its list of 

technologically feasible design options 

on input from manufacturers, 

component suppliers, trade 

publications, and technical papers. The 

technology assessment for this 

rulemaking incorporates input from 

eight manufacturers and one component 

supplier visited by the Department, as 

well as written comments. 

Table 11.4 is adapted from the ORNL 

study, Determination Analysis of Energy 

Conservation Standards for Distribution 

Transformers, ORNL-6847, 1996. This 

table summarizes the methods of 

making a transformer more efficient by 

reducing the number of watts lost in the 

core (no-load) and winding (load), and 

the associated inter-relational issues. 

The engineering analysis examined the 

options shown in this table (see Chapter 

5 of the TSD). 

Nearly all the energy consumed by 

distribution transformers is lost in the 

core and the winding assemblies. Design 

modifications that reduce losses in the 

core may cause an increase in winding 

losses; conversely, modifications to the 

design that reduce losses in the 

windings may increase losses in the 

core. 

TABLE 11.4.-0PTIONS AND IMPACTS OF INCREASING TRANSFORMER EFFICIENCY 

No-load losses Load losses Cost impact 

To decrease no-load losses 

Use lower-loss core materials ......................................... Lower ................................. No change' ........................ Higher. 

Decrease flux density by: .............................................. .. 

(a) Increasing core cross-sectional area (CSA) ....... Lower ................................. Higher ................................ Higher. 

(b) Decreasing volts per turn ................................... Lower ................................. Higher ................................ Higher. 

Decrease flux path length by decreasing conductor Lower ................................. Higher ........ ........................ Lower. 

CSA. 
e

Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

TABLE 11.4.-OPTIONS AND IMPACTS OF INCREASING TRANSFORMER EFFICIENCY-Continued

No-load losses

Use lower-loss conductor material ..................................

Decrease current density by increasing conductor CSA

Decrease current path length by: ....................................

(a) Decreasing core CSA .........................................

(b) Increasing volts per turn .....................................

To decrease load losses

No change .........................

Higher ................................

Higher ................................

Higher ................................

"Amorphous-core materials would result in higher load losses.

B. Screening Analysis

The purpose of the screening analysis

is to identify design options that

improve distribution transformer

efficiency and to determine which

options to evaluate and which options

to screen out. The Department consults

with industry, technical experts, and

other interested parties in developing a

list of design options for consideration.

It then applies the following set of

screening criteria to determine which

design options are unsuitable for further

consideration in the rulemaking (10 CFR

Part 430, Subpart C, Appendix A at

4(a)(4) and 5(b)):

(1) Technological feasibility.

Technologies incorporated in

commercial products or in working

prototypes will be considered

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 standard, then that technology

will be considered practicable to

manufacture, install and service;

(3) Adverse impacts on product utility

or product availability. 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 U.S. at the

time, it will not be considered further;

and

(4) Adverse impacts on health or

safety. If it is determined that a

technology will have significant adverse

impacts on health or safety, it will not

be considered further.

By applying these screening criteria to

a comprehensive list of design options,

the Department developed the following

list of efficiency-related enhancements

to examine in the engineering analysis:

Load losses

Lower .................................

Lower .................................

Lower .................................

Lower .................................

e Differing conductor coil materials:

aluminum and copper in wire and foil

configurations;

e Differing core materials: cold-rolled,

high-silicon (CRHiSi) steel; CRHiSi

domain-refined steels; and amorphous

materials in wound core;

e Varying design dimensions: flux

density (B); current density (J); volts/

turn; voltage spacings; frame/coil

dimensions; shape; cooling channels

(number and location); insulating

materials; and shell or core form,

stacked or wound; and

e Using different construction

techniques: core cutting; core stacking;

core lapping or butting of joints; coil

winding; and low voltage-high voltage

winding pattern.

The Department is not considering the

following design options because they

do not meet one or more of the

aforementioned four screening criteria:

Silver as a conductor material; hightemperature superconductors;

amorphous core material in stacked core

configuration; carbon composite

materials for heat removal; hightemperature insulating material; and

solid-state (power electronics)

technology. Discussion of the

application of the screening criteria to

these design options appears in Chapter

4 of the TSD.

The Department received stakeholder

comments relating to the screening

analysis during and after the

Distribution Transformer Framework

Workshop, November 1, 2000. One issue

raised by ABB during the workshop

related to screening out sole-source

technology. The Department responded

by stating that it would not set a

standard that required sole-source

technology for compliance. (Public

Hearing Transcript, No. 2MM at pp. 96-

98) ABB also commented that an "offthe-wall" technology (e.g.,

superconductors) should be screened

out. NRDC responded to ABB by

observing that technologies often are

more realistic than they initially appear.

(Public Hearing Transcript, No. 2MM at

pp. 98-104) However, upon further

analysis and consultation with experts

Higher.

Higher.

Lower.

Lower.

45387

Cost impact

(see Chapter 4 of the TSD), the

Department made the decision to screen

out superconducting materials.

In its written comments submitted to

the Department for the framework

document, NEMA commented that

superconducting winding and power

electronics should be screened out.

(NEMA, No. 7 at p. 7) The Department

considered these as it analyzed all the

design options available to make

transformers more efficient, and agreed

that both superconducting material and

solid-state (power electronics) should be

screened out.

C. Engineering Analysis

The purpose of the engineering

analysis is to evaluate a range of

transformer efficiency levels and

associated manufacturing costs. The

engineering analysis considers

technologies and design option

combinations not eliminated in the

screening analysis. The LCC analysis

uses the cost-efficiency relationships

developed in the engineering analysis.

The Department typically structures

its engineering analysis around one of

three methodologies. These are: (1) The

design-option approach, calculating the

incremental costs of adding specific

design options to a baseline model; (2)

the efficiency-level approach,

calculating the relative costs of

achieving energy efficiency

improvements; and/or (3) the reverseengineering or cost-assessment

approach, which involves a "bottomsup" manufacturing cost assessment

based on a detailed bill of materials

derived from transformer tear-downs. At

the framework document workshop, the

Department solicited comments to

determine which would be the best

approach to follow in the engineering

analysis.

1. Approach Taken in the Engineering

Analysis

There was no clear consensus among

the respondents at the November 2000

framework document workshop

regarding the most appropriate

approach to pursue in the engineering

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45387 

TABLE 11.4.-0PTIONS AND IMPACTS OF INCREASING TRANSFORMER EFFICIENCy-Continued 

No-load losses Load losses Cost impact 

To decrease load losses 

Use lower-loss conductor material ................................. . No change ......................... Lower ......... ........................ Higher. 

Decrease current density by increasing conductor CSA Higher ................................ Lower ......... ........................ Higher. 

Decrease current path length by: ................................... . 

(a) Decreasing core CSA ........................................ . Higher ................................ Lower ......... ........................ Lower. 

(b) Increasing volts per tum .................................... . Higher ................................ Lower ......... ........................ Lower. 

*Amorphous-core materials would result in higher load losses. 

B. Screening Analysis 

The purpose of the screening analysis 

is to identify design options that 

improve distribution transformer 

efficiency and to determine which 

options to evaluate and which options 

to screen out. The Department consults 

with industry, technical experts, and 

other interested parties in developing a 

list of design options for consideration. 

It then applies the following set of 

screening criteria to determine which 

design options are unsuitable for further 

consideration in the rulemaking (10 CFR 

Part 430, Subpart C, Appendix A at 

4(a)(4) and 5(b)): 

(1) Technological feasibility. 

Technologies incorporated in 

commercial products or in working 

prototypes will be considered 

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 standard, then that technology 

will be considered practicable to 

manufacture, install and service; 

(3) Adverse impacts on product utility 

or product availability. 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 U.S. at the 

time, it will not be considered further; 

and 

(4) Adverse impacts on health or 

safety. If it is determined that a 

technology will have significant adverse 

impacts on health or safety, it will not 

be considered further. 

By applying these screening criteria to 

a comprehensive list of design options, 

the Department developed the following 

list of efficiency-related enhancements 

to examine in the engineering analysis: 

.. Differing conductor coil materials: 

aluminum and copper in wire and foil 

configurations; 

., Differing core materials: cold-rolled, 

high-silicon (CRHiSi) steel; CRHiSi 

domain-refined steels; and amorphous 

materials in wound core; 

.. Varying design dimensions: flux 

density (B); current density (J); volts/ 

turn; voltage spacings; frame/coil 

dimensions; shape; cooling channels 

(number and location); insulating 

materials; and shell or core form, 

stacked or wound; and 

.. Using different construction 

techniques: core cutting; core stacking; 

core lapping or butting of joints; coil 

winding; and low voltage-high voltage 

winding pattern. 

The Department is not considering the 

following design options because they 

do not meet one or more of the 

aforementioned four screening criteria: 

Silver as a conductor material; hightemperature superconductors; 

amorphous core material in stacked core 

configuration; carbon composite 

materials for heat removal; hightemperature insulating material; and 

solid-state (power electronics) 

technology. Discussion ofthe 

application of the screening criteria to 

these design options appears in Chapter 

4 of the TSD. 

The Department received stakeholder 

comments relating to the screening 

analysis during and after the 

Distribution Transformer Framework 

Workshop, November 1, 2000. One issue 

raised by ABB during the workshop 

related to screening out sole-source 

technology. The Department responded 

by stating that it would not set a 

standard that required sole-source 

technology for compliance. (Public 

Hearing Transcript, No. 2MM at pp. 96-

98) ABB also commented that an "offthe-wall" technology (e.g., 

superconductors) should be screened 

out. NRDC responded to ABB by 

observing that technologies often are 

more realistic than they initially appear. 

(Public Hearing Transcript, No. 2MM at 

pp. 98-104) However, upon further 

analysis and consultation with experts 

(see Chapter 4 of the TSD), the 

Department made the decision to screen 

out superconducting materials. 

In its written comments submitted to 

the Department for the framework 

document, NEMA commented that 

superconducting winding and power 

electronics should be screened out. 

(NEMA, No.7 at p. 7) The Department 

considered these as it analyzed all the 

design options available to make 

transformers more efficient, and agreed 

that both superconducting material and 

solid-state (power electronics) should be 

screened out. 

e. Engineering Analysis 

The purpose of the engineering 

analysis is to evaluate a range of 

transformer efficiency levels and 

associated manufacturing costs. The 

engineering analysis considers 

technologies and design option 

combinations not eliminated in the 

screening analysis. The LCC analysis 

uses the cost-efficiency relationships 

developed in the engineering analysis. 

The Department typically structures 

its engineering analysis around one of 

three methodologies. These are: (1) The 

design-option approach, calculating the 

incremental costs of adding specific 

design options to a baseline model; (2) 

the efficiency-level approach, 

calculating the relative costs of 

achieving energy efficiency 

improvements; and/or (3) the reverseengineering or cost-assessment 

approach, which involves a "bottomsup" manufacturing cost assessment 

based on a detailed bill of materials 

derived from transformer tear-downs. At 

the framework document workshop, the 

Department solicited comments to 

determine which would be the best 

approach to follow in the engineering 

analysis. 

1. Approach Taken in the Engineering 

Analysis 

There was no clear consensus among 

the respondents at the November 2000 

framework document workshop 

regarding the most appropriate 

approach to pursue in the engineering 
45388 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

analysis. NEMA believes that the

efficiency-level approach is by far the

superior method, noting that both the

design-option and cost-assessment

approaches require the estimation of

manufacturing costs by people who are

not experts in the art and science of

transformer design and manufacturing.

NEMA recommended the efficiencylevel approach, where manufacturers

provide data on the relationship

between cost and efficiency. (NEMA,

No. 7 at p. 8) TXU Electric and Gas

agreed with NEMA that the efficiencylevel approach would be the most

appropriate for this product. (TXU

Electric and Gas, No. 12 at p. 6)

ACEEE recommended that the

Department follow the cost assessment

approach, as it has proven more

accurate and reliable in prior

rulemakings. (ACEEE, No. 14 at p. 3)

However, the Department did not

consider this recommendation feasible,

as the cost assessment approach would

require purchasing large quantities of

distribution transformers, disassembling

them, and determining the additional

cost involved in making one design

more efficient than another. As the

energy efficiency of a transformer is

linked to its core dimensions, number of

turns, and other design modifications,

including alternative core steels or

winding materials, this approach would

be extremely expensive and difficult to

implement, while maintaining sufficient

levels of accuracy.

While studying the various

approaches and respondents' comments

relating to the engineering analysis, the

Department learned that the transformer

manufacturing industry commonly uses

computer software to design a

distribution transformer to fill a

customer's order. The software-design

approach is founded on market

dynamics, described in Chapter 3 of the

TSD, where customers issue

performance characteristics in a contract

tender and manufacturers compete for

the award based on designs they

generate using their computer software

and current material costs. The

Department used transformer design

software to create a database of

distribution transformer designs

spanning a range of efficiencies, while

tracking all the modifications to the

core, coil, labor, and other key cost

components. This method is referred to

as the "modified design-option

approach" because the design software

calculates the incremental costs of

improving or changing a design or

changing the combination of materials

to improve the efficiency. The

Department selected software developed

by an independent company not

associated with any one manufacturer or

manufacturer's association. This

company, OPS, conducted the design

runs spanning a range of efficiencies for

the Department's engineering analysis.

The Department published a draft

engineering analysis update report in

December 2001, incorporating the initial

design runs from OPS on one of the

representative units. The Department

received comments from manufacturers,

consultants, and other stakeholders

suggesting revisions to the software

input parameters and assumptions. The

losses reported for the evaluated designs

were found to be too high, particularly

in comparison to other publicly

available data as found in the ORNL

Determination Analysis report or an

ENERGY STAR® / NEMA TP 1 unit.

(AK Steel, No. 18 at pp. 1-2) Similarly,

core destruction factors were high, in

the range of 12 to 20 percent. (AK Steel,

No. 18 at p. 2) The Department

discussed these comments with OPS,

and made modifications to the software

inputs to correct for the high losses and

destruction factor. AK Steel also

suggested that OPS review its core

lamination factors, which appeared to

be low and somewhat inconsistent. (AK

Steel, No. 18 at p. 3) The Department

consulted with OPS and adjusted the

lamination factors to make them

consistent and bring them more in line

with industry factors. NEMA

commented that its members would

comment directly on the draft analysis

when they hosted plant visits from the

Department in early 2002. (NEMA, No.

19 at p. 2) At these meetings,

manufacturers made recommendations

to the Department to fine-tune the OPS

software and adjust some of the material

prices and markups. In total, the

Department met with eight transformer

manufacturers and one component

supplier in early 2002, not all of which

are NEMA members.2 The Department

worked with OPS to incorporate these

revisions to the software inputs before

conducting the ANOPR computer

design runs.

The Department published revised,

draft liquid-immersed engineering

analysis results on June 5, 2002, as an

2 During the first quarter of 2002, the Department

met with eight distribution transformer

manufacturers, including ABB Power Technology

Products Division USA (both a liquid-immersed

plant and a dry-type plant), Acme Electric

Corporation, Cooper Power Industries, Federal

Pacific Transformer Company, Howard Industries

Inc., Jefferson Electric Inc., Kuhlman Electric

Corporation, and Square-D Company. The

Department also met with AK Steel, a core steel

manufacturer. Together, representatives of these

nine companies contributed more than 60 hours of

presentations, interviews, and plant tours to the

Department's engineering analysis.

appendix to the report Distribution

Transformer Rulemaking-Life-Cycle

Cost Analysis, Design Line 1. AK Steel

submitted comments on the revised

draft engineering analysis, indicating

that the temperature rise in all three

example designs included in the

appendix were reported to be 55°C

rather than the expected 65°C. (AK

Steel, No. 36 at p. 1) The Department

investigated this problem and learned

that the temperature rise reported in the

documentation was not the temperature

rise used in the software design

program. The designs were created

using a 20°C ambient and 65°C

temperature rise; however, when the

design specification report was created,

a 30°C ambient temperature had been

mistakenly entered, which forced the

reported temperature rise to be 55°C.

Thus, the design was created with a

65°C rise, but inadvertently reported as

55°C. This typographical error was

confirmed upon careful review of the

design reports and documentation

produced for the appendix of the draft

report.

The Department also published a draft

engineering analysis, Distribution

Transformer Standards Rulemaking,

Draft Report for Review, Engineering

Analysis for Dry-type Distribution

Transformers and Results on Design

Line 9, on August 23, 2002, which

provided preliminary results on one of

the dry-type representative units. An

AK Steel comment on the designs

presented in this report noted a

typographical error concerning a

parenthetical description of H-0 core

steel as a laser-scribed M3, when in fact

H-0 is a 9-mil high permeability grainoriented steel produced in a laserscribed condition. (AK Steel, No. 29 at

p. 1) AK Steel also found that the core

destruction factors were high for these

designs, ranging between 24 percent and

38 percent. (AK Steel, No. 29 at p. 2)

The Department discussed this with

OPS, and modified the software inputs

to reduce the core destruction factors.

AK Steel also noted that the core

stacking rate used in the designs was

four inches per hour, and showed that

the rate should not be constant, but

should vary with the thickness of the

core steel. (AK Steel, No. 29 at p. 1) The

Department acknowledges that this is a

simplification in the engineering

analysis of dry-type distribution

transformers that was implemented after

discussing with OPS the labor estimate

part of the manufacturing cost.

However, labor assembly times vary

widely across all the dry-type

manufacturing companies in the United

States (due to differing levels of

 EE-RM/STD-00-550 COMMENT 53.1

45388 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

analysis. NEMA believes that the 

efficiency-level approach is by far the 

superior method, noting that both the 

design-option and cost-assessment 

approaches require the estimation of 

manufacturing costs by people who are 

not experts in the art and science of 

transformer design and manufacturing. 

NEMA recommended the efficiencylevel approach, where manufacturers 

provide data on the relationship 

between cost and efficiency. (NEMA, 

No.7 at p. 8) TXU Electric and Gas 

agreed with NEMA that the efficiencylevel approach would be the most 

appropriate for this product. (TXU 

Electric and Gas, No. 12 at p. 6) 

ACEEE recommended that the 

Department follow the cost assessment 

approach, as it has proven more 

accurate and reliable in prior 

rulemakings. (ACEEE, No. 14 at p. 3) 

However, the Department did not 

consider this recommendation feasible, 

as the cost assessment approach would 

require purchasing large quantities of 

distribution transformers, disassembling 

them, and determining the additional 

cost involved in making one design 

more efficient than another. As the 

energy efficiency of a transformer is 

linked to its core dimensions, number of 

turns, and other design modifications, 

including alternative core steels or 

winding materials, this approach would 

be extremely expensive and difficult to 

implement, while maintaining sufficient 

levels of accuracy. 

While studying the various 

approaches and respondents' comments 

relating to the engineering analysis, the 

Department learned that the transformer 

manufacturing industry commonly uses 

computer software to design a 

distribution transformer to fill a 

customer's order. The software-design 

approach is founded on market 

dynamics, described in Chapter 3 ofthe 

TSD, where customers issue 

performance characteristics in a contract 

tender and manufacturers compete for 

the award based on designs they 

generate using their computer software 

and current material costs. The 

Department used transformer design 

software to create a database of 

distribution transformer designs 

spanning a range of efficiencies, while 

tracking all the modifications to the 

core, coil, labor, and other key cost 

components. This method is referred to 

as the "modified design-option 

approach" because the design software 

calculates the incremental costs of 

improving or changing a design or 

changing the combination of materials 

to improve the efficiency. The 

Department selected software developed 

by an independent company not 

associated with anyone manufacturer or 

manufacturer's association. This 

company, OPS, conducted the design 

runs spanning a range of efficiencies for 

the Department's engineering analysis. 

The Department published a draft 

engineering analysis update report in 

December 2001, incorporating the initial 

design runs from OPS on one of the 

representative units. The Department 

received comments from manufacturers, 

consultants, and other stakeholders 

suggesting revisions to the software 

input parameters and assumptions. The 

losses reported for the evaluated designs 

were found to be too high, particularly 

in comparison to other publicly 

available data as found in the ORNL 

Determination Analysis report or an 

ENERGY STAR® / NEMA TP 1 unit. 

(AK Steel, No. 18 at pp. 1-2) Similarly, 

core destruction factors were high, in 

the range of 12 to 20 percent. (AK Steel, 

No. 18 at p. 2) The Department 

discussed these comments with OPS, 

and made modifications to the software 

inputs to correct for the high losses and 

destruction factor. AK Steel also 

suggested that OPS review its core 

lamination factors, which appeared to 

be low and somewhat inconsistent. (AK 

Steel, No. 18 at p. 3) The Department 

consulted with OPS and adjusted the 

lamination factors to make them 

consistent and bring them more in line 

with industry factors. NEMA 

commented that its members would 

comment directly on the draft analysis 

when they hosted plant visits from the 

Department in early 2002. (NEMA, No. 

19 at p. 2) At these meetings, 

manufacturers made recommendations 

to the Department to fine-tune the OPS 

software and adjust some of the material 

prices and markups. In total, the 

Department met with eight transformer 

manufacturers and one component 

supplier in early 2002, not all of which 

are NEMA members.2 The Department 

worked with OPS to incorporate these 

revisions to the software inputs before 

conducting the ANOPR computer 

design runs. The Department published revised, 

draft liquid-immersed engineering 

analysis results on June 5, 2002, as an 

2 During the first quarter of 2002. the Department 

met with eight distribution transformer 

manufacturers, including ABB Power Technology 

Products Division USA (both a liquid-immersed 

plant and a dry-type plant). Acme Electric 

Corporation. Cooper Power Industries. Federal 

Pacific Transformer Company, Howard Industries 

Inc., Jefferson Electric Inc., Kuhlman Electric 

Corporation, and Square-D Company. The 

Department also met with AK Steel, a core steel 

manufacturer. Together, representatives of these 

nine companies contributed more than 60 hours of 

presentations, interviews, and plant tours to the 

Department's engineering analysis. 

appendix to the report Distribution 

Transformer Rulemaking-Life-Cycle 

Cost Analysis, Design Line 1. AK Steel 

submitted comments on the revised 

draft engineering analysis, indicating 

that the temperature rise in all three 

example designs included in the 

appendix were reported to be 55°C 

rather than the expected 65°C. (AK 

Steel, No. 36 at p. 1) The Department 

investigated this problem and learned 

that the temperature rise reported in the 

documentation was not the temperature 

rise used in the software design 

program. The designs were created 

using a 20°C ambient and 65°C 

temperature rise; however, when the 

design specification report was created, 

a 30°C ambient temperature had been 

mistakenly entered, which forced the 

reported temperature rise to be 55°C. 

Thus, the design was created with a 

65°C rise, but inadvertently reported as 

55°C. This typographical error was 

confirmed upon careful review of the 

design reports and documentation 

produced for the appendix of the draft 

report. 

The Department also published a draft 

engineering analysis, Distribution 

Transformer Standards Rulemaking, 

Draft Report for Review, Engineering 

Analysis for Dry-type Distribution 

Transformers and Results on Design 

Line 9, on August 23, 2002, which 

provided preliminary results on one of 

the dry-type representative units. An 

AK Steel comment on the designs 

presented in this report noted a 

typographical error concerning a 

parenthetical description of H-O core 

steel as a laser-scribed M3, when in fact 

H-O is a 9-mil high permeability grainoriented steel produced in a laserscribed condition. (AK Steel, No. 29 at 

p. 1) AK Steel also found that the core 

destruction factors were high for these 

designs, ranging between 24 percent and 

38 percent. (AK Steel, No. 29 at p. 2) 

The Department discussed this with 

OPS, and modified the software inputs 

to reduce the core destruction factors. 

AK Steel also noted that the core 

stacking rate used in the designs was 

four inches per hour, and showed that 

the rate should not be constant, but 

should vary with the thickness of the 

core steel. (AK Steel, No. 29 at p. 1) The 

Department acknowledges that this is a 

simplification in the engineering 

analysis of dry-type distribution 

transformers that was implemented after 

discussing with OPS the labor estimate 

part of the manufacturing cost. 

However, labor assembly times vary 

widely across all the dry-type 

manufacturing companies in the United 

States (due to differing levels of 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

automation). By using one value for the

core stacking rate, the Department

approximates what the labor costs are

for an average transformer company

rather than any one in particular. The

Department invites further comments on

the issue of stacking rates and use of

differential times for varying

thicknesses of core steels.

2. Simplifying the Analysis

NEMA has 99 different efficiency

levels in its TP 1-2002 document,

covering both liquid-immersed and drytype distribution transformers, singleand three-phase ratings, and spanning

the kVA ranges and insulation levels.

NEMA commented that there are too

many classes on which to conduct

detailed analyses, and the Department

should select a limited number of

representative units for detailed

analysis. (NEMA, No. 7 at p. 5) The

Department agrees that it would be

impractical to conduct a detailed

analysis of the cost-efficiency

relationships on each kVA rating of

distribution transformers, and worked to

develop an approach that would

simplify the analysis while keeping a

sufficient degree of technical accuracy.

The Department consulted with

industry representatives and

transformer design engineers, and

developed an understanding of the

construction techniques typically

employed in the transformer

manufacturing industry. It found that

many of the kVA ratings share similar

design and construction principles,

such that within a given product class

of transformers (as defined in section

II.A.2), some units would have similar

methods of construction.

Building on this understanding, the

Department drafted and proposed

"engineering design lines," grouping

together certain kVA ratings within subdivisions of the proposed product

classes. These proposed engineering

design lines published in the December

2001 draft report were in response to a

request from ACEEE asking the

Department to prepare and publish

preliminary analyses as soon as possible

to allow stakeholders to review and

comment on the rulemaking process.

45389

(ACEEE, No. 14 at p. 3) Based on

stakeholder feedback and the meetings

held with the manufacturers in early

2002, the Department arrived at a final

set of thirteen engineering design lines

that group together kVA ratings within

product classes, thereby covering all the

kVA ratings shown in TP 1.

Table 11.5 illustrates the relationship

between the proposed product classes

and the engineering design lines.

Several of the product classes are subdivided into two or more engineering

design lines, enabling the Department to

have more accurate results when

studying the cost-efficiency

relationship. None of the engineering

design lines span across two product

classes. However, three of the product

classes (numbers 5, 7 and 9, all drytype, medium-voltage, single-phase)

have such low shipment volume that

the Department decided to scale

analysis results from the three-phase,

medium-voltage, dry-type units to cover

these product classes. This scaling

operation involves simply dividing the

analysis findings by three.

TABLE 11.5.-MAPPING OF PROPOSED PRODUCT CLASSES TO ENGINEERING DESIGN LINES

Distribution transformer product class kVA range Engineering design lines

1. Liquid-immersed, medium-voltage, single-phase ...................... 10-833 DL 1: 10-100 kVA, Rectangular

DL 2: 10-100 kVA, Round

DL 3: 167-833 kVA

2. Liquid-immersed, medium-voltage, three-phase ........................ 15-2500 DL 4: 15-500 kVA

DL 5: 750-2500 kVA

3. Dry-type, low-voltage, single-phase ........................................... 15-333 DL 6: 15-333 kVA

4. Dry-type, low-voltage, three phase ............................................ 15-1000 DL 7:15-150 kVA

DL 8: 225-1000 kVA

5. Dry-type, medium-voltage, single-phase, 20-45 kV BIL ........... 15-833 (DL 9/3: 15-167 kVA)*

(DL 10/3: 250-833 kVA)*

6. Dry-type, medium-voltage, three-phase , 20-45 kV BIL ............ 15-2500 DL 9: 15-500 kVA

DL 10: 750-2500 kVA

7. Dry-type, medium-voltage, single-phase, 46-95 kV BIL ........... 15-833 (DL 11/3: 15-167 kVA)*

(DL 12/3: 250-833 kVA)*

8. Dry-type, medium-voltage , three-phase, 46-95 kV BIL ............ 15-2500 DL 11: 15-500 kVA

DL 12: 750-2500 kVA

9. Dry-type, medium-voltage , single-phase, ?96 kV BIL ............... 75-833 (DL 13/3: 75-833 kVA)*

10. Dry-type, medium-voltage, three-phase, ?96 kV BIL .............. 225-2500 DL 13: 225-2500 kVA

*Due to the low shipment volume in these three product classes , the Department decided to scale the results of analysis on the three-phase

medium-voltage (MV) dry-type distribution transformers to these single -phase units, by dividing the results of the three-phase analysis by three to

adjust to single -phase.

From each of the thirteen engineering

design lines, the Department selected

one representative unit to study in

detail in both the engineering and the

LCC analysis. Once these two analyses

were complete, the Department scaled

the findings on these units to all the

other kVA ratings within each of the

thirteen design lines using the 0.75

scaling rule (see Chapter 5 in the TSD).

This rule states that for similarly

designed transformers, construction

costs and watt losses scale to the ratio

of kVA ratings raised to the 0.75 power.

Square D informed DOE of this fact

during a public hearing about the

Department's test procedure rulemaking

held on January 6, 1999. Square D stated

that the material content, as well as the

losses, scale to the three-quarter power

of kVA. (Public Hearing Transcript, No.

47 at p. 158)

The selection of the thirteen

representative units was based on

inputs from multiple sources. For

example, NEMA suggested that six kVA

ratings should form the nucleus of the

representative units for further analysis.

(NEMA, No. 7 at p. 5) Of these, the

Department selected four units for its

engineering analysis: a liquid-filled, 50

kVA, single-phase, pad-mounted

transformer was used for design line 1;

a liquid-filled, 25 kVA, single-phase,

pole-mounted transformer was used for

design line 2; a dry-type, 75 kVA, lowvoltage, three-phase transformer was

used for design line 7; and a dry-type,

2000 kVA, medium-voltage, three-phase

transformer was used for design line 13.

The two other recommended ratings

(500 kVA and 2000 kVA three-phase,

 EE-RM/STD-00-550 COMMENT 53.1

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45389 

automation). By using one value for the 

core stacking rate, the Department 

approximates what the labor costs are 

for an average transformer company 

rather than anyone in particular. The 

Department invites further comments on 

the issue of stacking rates and use of 

differential times for varying 

thicknesses of core steels. 

2. Simplifying the Analysis 

NEMA has 99 different efficiency 

levels in its TP 1-2002 document, 

covering both liquid-immersed and drytype distribution transformers, singleand three-phase ratings, and spanning 

the kV A ranges and insulation levels. 

NEMA commented that there are too 

many classes on which to conduct 

detailed analyses, and the Department 

should select a limited number of 

representative units for detailed 

analysis. (NEMA, No.7 at p. 5) The 

Department agrees that it would be 

impractical to conduct a detailed 

analysis ofthe cost-efficiency 

relationships on each kV A rating of 

distribution transformers, and worked to 

develop an approach that would 

simplify the analysis while keeping a 

sufficient degree oftechnical accuracy. 

The Department consulted with 

industry representatives and 

transformer design engineers, and 

developed an understanding of the 

construction techniques typically 

employed in the transformer 

manufacturing industry. It found that 

many of the kVA ratings share similar 

design and construction principles, 

such that within a given product class 

of transformers (as defined in section 

II.A.2), some units would have similar 

methods of construction. 

Building on this understanding, the 

Department drafted and proposed 

"engineering design lines," grouping 

together certain kVA ratings within subdivisions of the proposed product 

classes. These proposed engineering 

design lines published in the December 

2001 draft report were in response to a 

request from ACEEE asking the 

Department to prepare and publish 

preliminary analyses as soon as possible 

to allow stakeholders to review and 

comment on the rulemaking process. 

(ACEEE, No. 14 at p. 3) Based on 

stakeholder feedback and the meetings 

held with the manufacturers in early 

2002, the Department arrived at a final 

set of thirteen engineering design lines 

that group together kVA ratings within 

product classes, thereby covering all the 

kVA ratings shown in TP 1. 

Table II.5 illustrates the relationship 

between the proposed product classes 

and the engineering design lines. 

Several ofthe product classes are subdivided into two or more engineering 

design lines, enabling the Department to 

have more accurate results when 

studying the cost-efficiency 

relationship. None ofthe engineering 

design lines span across two product 

classes. However, three ofthe product 

classes (numbers 5, 7 and 9, all drytype, medium-voltage, single-phase) 

have such low shipment volume that 

the Department decided to scale 

analysis results from the three-phase, 

medium-voltage, dry-type units to cover 

these product classes. This scaling 

operation involves simply dividing the 

analysis findings by three. 

TABLE 1I.5.-MAPPING OF PROPOSED PRODUCT CLASSES TO ENGINEERING DESIGN liNES 

Distribution transformer product class kVA range Engineering design lines 

1. Liquid-immersed, medium-voltage, single-phase ..................... . 10-833 DL 1: 10-100 kVA, Rectangular 

DL 2: 10-100 kVA, Round 

DL 3: 167-833 kVA 

2. Liquid-immersed, medium-voltage, three-phase ...................... .. 15-2500 DL 4: 15-500 kVA 

DL 5: 750-2500 kVA 

3. Dry-type, low-voltage, single-phase .......................................... . 15-333 DL 6: 15-333 kVA 

4. Dry-type, low-voltage, three phase .......................................... .. 15-1000 DL 7: 15-150 kVA 

DL 8: 225-1000 kVA 

5. Dry-type, medium-voltage, single-phase, 20-45 kV BIL ......... .. 15-833 (DL 9/3: 15-167 kVA)* 

6. Dry-type, medium-voltage, three-phase, 20-45 kV BIL .......... .. 

(DL 10/3: 250-833 kVA)* 

15-2500 DL 9: 15-500 kVA 

DL 10: 750-2500 kVA 

7. Dry-type, medium-voltage, single-phase, 46-95 kV BIL .......... . 15-833 (DL 11/3: 15-167 kVA)* 

8. Dry-type, medium-voltage, three-phase, 46-95 kV BIL .......... .. 

(DL 12/3: 250-833 kVA)* 

15-2500 DL 11: 15-500 kV A 

DL 12: 750-2500 kVA 

9. Dry-type, medium-voltage, single-phase, 2!96 kV BIL ............. .. 75-833 (DL 13/3: 75-833 kVA)* 

10. Dry-type, medium-voltage, three-phase, 2!96 kV BIL ............ .. 225-2500 DL 13: 225-2500 kVA 

*Due to the low shipment volume in these three product classes, the Department decided to scale the results of analysis on the three-phase 

medium-voltage (MV) dry-type distribution transformers to these single-phase units, by dividing the results of the three-phase analysis by three to 

adjust to single-phase. 

From each of the thirteen engineering 

design lines, the Department selected 

one representative unit to study in 

detail in both the engineering and the 

LCC analysis. Once these two analyses 

were complete, the Department scaled 

the findings on these units to all the 

other kVA ratings within each of the 

thirteen design lines using the 0.75 

scaling rule (see Chapter 5 in the TSD). 

This rule states that for similarly 

designed transformers, construction 

costs and watt losses scale to the ratio 

of kVA ratings raised to the 0.75 power. 

Square D informed DOE of this fact 

during a public hearing about the 

Department's test procedure rulemaking 

held on January 6,1999. Square D stated 

that the material content, as well as the 

losses, scale to the three-quarter power 

of kV A. (Public Hearing Transcript, No. 

47 at p. 158) 

The selection of the thirteen 

representative units was based on 

inputs from multiple sources. For 

example, NEMA suggested that six kV A 

ratings should form the nucleus of the 

representative units for further analysis. 

(NEMA, No.7 at p. 5) Of these, the 

Department selected four units for its 

engineering analysis: a liquid-filled, 50 

kVA, single-phase, pad-mounted 

transformer was used for design line 1; 

a liquid-filled, 25 kVA, single-phase, 

pole-mounted transformer was used for 

design line 2; a dry-type, 75 kVA, lowvoltage, three-phase transformer was 

used for design line 7; and a dry-type, 

2000 kVA, medium-voltage, three-phase 

transformer was used for design line 13. 

The two other recommended ratings 

(500 kV A and 2000 kVA three-phase, 
45390 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

liquid-immersed transformers) did not

fit well with the structure of the design

lines. The Department did not select the

liquid-filled, 500 kVA, three-phase, padmounted transformer because liquidfilled, three-phase units span two design

lines, ranging from 15 to 500 kVA

(design line 4), and from 750 to 2500

kVA (design line 5). To keep any scaling

error to a minimum, the Department

selected representative units from

around the middle of the kVA ranges of

each engineering design line. The

Department's decision to split the threephase, liquid-immersed units into two

separate design lines came after input

was received from manufacturers during

the 2002 site visits and analysis by the

Department's technical team. Thus, a

150 kVA, three-phase, liquid-immersed

unit was selected for design line 4

instead of the NEMA-recommended 500

kVA unit. Similarly, a 1500 kVA, threephase, liquid-immersed transformer was

selected instead of the NEMArecommended 2000 kVA transformer for

design line 5.

For the dry-type distribution

transformer design lines, the

representative units were selected

following meetings held with

manufacturers in early 2002.

Manufacturers recommended the ratings

chosen because they were either the

mid-point of a design line's kVA range

(minimizing any scaling error

introduced by the 0.75 scaling rule) or

the selected rating represented a high

volume kVA rating. Following the

demarcation of the product classes (see

Table 11.3), dry-type distribution

transformers constitute eight

engineering design lines, grouped by

kVA and BIL rating. As discussed in

section II.A.2 on product classes, the

Department learned that using different

BIL ratings would be necessary to

capture the important differences in the

cost-efficiency relationships between

units. If a single efficiency standard

were set across all medium-voltage, drytype BIL ratings, it would be a

comparatively weak standard for lower

BIL ratings and a difficult (if not

impossible) standard for a higher BIL

rating. NEMA recognized this problem

in its TP 1-1996 document; when it

published the revised TP 1 in 2002, it

divided medium-voltage, dry-types into

two groups: 560 kV BIL and >60 kV BIL.

Based on comments the Department

received during its manufacturer site

visits in early 2002, the Department

elected to use three BIL groups for the

ANOPR: 545 kV BIL, 46-95 kV BIL and

?96 kV BIL. This additional

disaggregation enables the Department

to propose more accurate efficiency

standards for the appropriate BIL rating,

thereby reducing the possibility of

ineffectual standards on lower BIL

ratings or excessive standards on higher

BIL ratings. The Department invites

comment from stakeholders on this

decision to have more dry-type BIL

categories than NEMA's TP 1-2002.

Manufacturers also informed the

Department during their meetings that

differences in BIL ratings are only

important for medium-voltage, dry-type

distribution transformers. Separate

standards by BIL rating are not required

for the liquid-immersed or the lowvoltage, dry-type units.

Once DOE became aware of the

importance of BIL ratings for mediumvoltage, dry-type distribution

transformers, it selected some

representative units for design lines 9

through 13 with BIL ratings slightly

higher than conventional levels for the

specified primary voltages. The

Department made these selections after

discussions with several manufacturers,

to ensure that efficiency standards

would not excessively penalize

customers purchasing transformers built

with primaries operating at higher-thannormal BIL levels. For example, the

representative unit from design line 9 is

a 300 kVA, three-phase, dry-type

transformer with a 4160 V primary

voltage. This primary voltage would

normally be built with a 30 kV BIL;

however, for a particular application

there could be exposure to higher than

normal voltage surges resulting from

switchgear, and transformer specifiers

may choose to order this unit with a 45

kV or even a 60 kV BIL. If the

Department established the minimum

efficiency standard based on a 30 kV

BIL, it could restrict the manufacturer's

ability to manufacture a compliant 45

kV BIL or 60 kV BIL unit. To

accommodate this concern of

manufacturers, the Department selected

slightly higher than normal BIL ratings

for each of the representative units in

design line 9 through 13 for the

specified primary voltages.

Table 11.6 presents the Department's

thirteen engineering design lines and

the representative units selected from

each design line for analysis. Note that

for the liquid-immersed, mediumvoltage, single-phase distribution

transformers, design line 1 represents

rectangular tank units from 10 to 100

kVA while design line 2 covers the same

kVA range, but represents cylindrical

tank designs. The Department analyzed

these two common methods of

manufacturing this type of transformer

to capture any economic variability that

may result from different core/coil

construction techniques or tank costs.

TABLE 11.6.-ENGINEERING DESIGN LINES AND REPRESENTATIVE UNITS FOR ANALYSIS

DL Type of distribution transformer kVA range Voltage taps Secondary

voltages

Engineering design line representative unit

1 ............. Liquid-immersed, medium-voltage , 10-100 ±2-2.5% .............. 240/120 to 600V 50kVA, 65°C, single-phase, 60Hz,

single-phase, rectangular tank. 7200V primary, 240/120V secondary, rectangular tank

2 ............. Liquid-immersed , medium-voltage, 10-100 ±2-2.5% .............. 120/240 to 600V 25kVA, 65°C, single-phase, 60Hz,

single-phase, round tank. 24940GrdY/14400V primary, 120/

240V secondary, round tank

3 ............. Liquid-immersed, medium-voltage , 167-833 ±2-2.5% .............. 120/240 to 600 V 500kVA, 65°C, single-phase, 60Hz,

single-phase. 14400/24940YV primary, 277/

480YV secondary

4 ............. Liquid-immersed, medium-voltage, 15-500 ±2-2.5% .............. 208Y/120 to 600V 150kVA, 65°C, three-phase, 60Hz,

three-phase. 12470Y/7200V primary, 208Y/

120V secondary

5 ............. Liquid-immersed, medium-voltage, 750-2500 ±2-2.5% .............. 208Y/120 to 1500kVA, 65°C, three-phase, 60Hz,

three-phase. 600Y/347V. 24940GrdY/14400V primary,

480Y/277V secondary

6 ............. Dry-type , low-voltage, single-phase 15-333 Universal` ............ 120/240 to 600V 25kVA, 150°C, single-phase, 60Hz,

480V primary, 120/240V secondarv. 10kV BIL

 EE-RM/STD-00-550 COMMENT 53.1

#53. 

45390 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

liquid-immersed transformers) did not 

fit well with the structure of the design 

lines. The Department did not select the 

liquid-filled, 500 kVA, three-phase, padmounted transformer because liquidfilled, three-phase units span two design 

lines, ranging from 15 to 500 kVA 

(design line 4), and from 750 to 2500 

kVA (design line 5). To keep any scaling 

error to a minimum, the Department 

selected representative units from 

around the middle of the kVA ranges of 

each engineering design line. The 

Department's decision to split the threephase, liquid-immersed units into two 

separate design lines came after input 

was received from manufacturers during 

the 2002 site visits and analysis by the 

Department's technical team. Thus, a 

150 kVA, three-phase, liquid-immersed 

unit was selected for design line 4 

instead of the NEMA-recommended 500 

kVA unit. Similarly, a 1500 kVA, threephase, liquid~immersed transformer was 

selected instead ofthe NEMArecommended 2000 kVA transformer for 

design line 5. 

For the dry-type distribution 

transformer design lines, the 

representative units were selected 

following meetings held with 

manufacturers in early 2002. 

Manufacturers recommended the ratings 

chosen because they were either the 

mid-point of a design line's kVA range 

(minimizing any scaling error 

introduced by the 0.75 scaling rule) or 

the selected rating represented a high 

volume kVA rating. Following the 

demarcation of the product classes (see 

Table 11.3), dry-type distribution 

transformers constitute eight 

engineering design lines, grouped by 

kVA and BIL rating. As discussed in 

section II.A.2 on product classes, the 

Department learned that using different 

BIL ratings would be necessary to 

capture the important differences in the 

cost-efficiency relationships between 

units. If a single efficiency standard 

were set across all medium-voltage, drytype BIL ratings, it would be a 

comparatively weak standard for lower 

BIL ratings and a difficult (if not 

impossible) standard for a higher BIL 

rating. NEMA recognized this problem 

in its TP 1-1996 document; when it 

published the revised TP 1 in 2002, it 

divided medium-voltage, dry-types into 

two groups: $;60 kV BIL and >60 kV BIL. 

Based on comments the Department 

received during its manufacturer site 

visits in early 2002, the Department 

elected to use three BIL groups for the 

ANOPR: $;45 kV BIL, 46-95 kV BIL and 

:2:96 kV BIL. This additional 

disaggregation enables the Department 

to propose more accurate efficiency 

standards for the appropriate BIL rating, 

thereby reducing the possibility of 

ineffectual standards on lower BIL 

ratings or excessive standards on higher 

BIL ratings. The Department invites 

comment from stakeholders on this 

decision to have more dry-type BIL 

categories than NEMA's TP 1-2002. 

Manufacturers also informed the 

Department during their meetings that 

differences in BIL ratings are only 

important for medium-voltage, dry-type 

distribution transformers. Separate 

standards by BIL rating are not required 

for the liquid-immersed or the lowvoltage, dry-type units. 

Once DOE became aware of the 

importance of BIL ratings for mediumvoltage, dry-type distribution 

transformers, it selected some 

representative units for design lines 9 

through 13 with BIL ratings slightly 

higher than conventional levels for the 

specified primary voltages. The 

Department made these selections after 

discussions with several manufacturers, 

to ensure that efficiency standards 

would not excessively penalize 

customers purchasing transformers built 

with primaries operating at higher-thannormal BIL levels. For example, the 

representative unit from design line 9 is 

a 300 kVA, three-phase, dry-type 

transformer with a 4160 V primary 

voltage. This primary voltage would 

normally be built with a 30 kV BIL; 

however, for a particular application 

there could be exposure to higher than 

normal voltage surges resulting from 

switchgear, and transformer specifiers 

may choose to order this unit with a 45 

kV or even a 60 kV BIL. If the 

Department established the minimum 

efficiency standard based on a 30 kV 

BIL, it could restrict the manufacturer's 

ability to manufacture a compliant 45 

kV BIL or 60 kV BIL unit. To 

accommodate this concern of 

manufacturers, the Department selected 

slightly higher than normal BIL ratings 

for each of the representative units in 

design line 9 through 13 for the 

specified primary voltages. 

Table 11.6 presents the Department's 

thirteen engineering design lines and 

the representative units selected from 

each design line for analysis. Note that 

for the liquid-immersed, mediumvoltage, single-phase distribution 

transformers, design line 1 represents 

rectangular tank units from 10 to 100 

kVA while design line 2 covers the same 

kVA range, but represents cylindrical 

tank designs. The Department analyzed 

these two common methods of 

manufacturing this type of transformer 

to capture any economic variability that 

may result from different core/coil 

construction techniques or tank costs. 

TABLE 11.6.-ENGINEERING DESIGN liNES AND REPRESENTATIVE UNITS FOR ANALYSIS 

DL Type of distribution transformer kVA range Voltage taps Secondary Engineering design line representavoltages tive unit 

1 ............. Liquid-immersed, medium-voltage, 10-100 ±2-2.5% .............. 240/120 to 600V 50kVA, 65°C, single-phase, 60Hz, 

single-phase, rectangular tank. 7200V primary, 240/120V secondary, rectangular tank 

2 ............. Liquid-immersed, medium-voltage, 10-100 ±2-2.5% .............. 120/240 to 600V 25kVA, 65°C, single-phase, 60Hz, 

single-phase, round tank. 24940GrdY/14400V primary, 1201 

240V secondary, round tank 

3 ............. Liquid-immersed, medium-voltage, 167-833 ±2-2.5% .............. 120/240 to 600 V 500kVA, 65°C, single-phase, 60Hz, 

Single-phase. 14400/24940YV primary, 2771 

480YV secondary 

4 ............. Liquid-immersed, medium-voltage, 15-500 ±2-2.5% .............. 208Y/120 to 600V 150kVA, 65°C, three-phase, 60Hz, 

three-phase. 12470Y17200V primary, 208YI 

120V secondary 

5 ............. Liquid-immersed, medium-voltage, 750-2500 ±2-2.5% .............. 208Y/120 to 1500kVA, 65°C, three-phase, 60Hz, 

three-phase. 600Y/347V. 24940GrdY 114400V primary, 

480Y/277V secondary 

6 ............. Dry-type, low-voltage, single-phase 15-333 Universal* ............ 120/240 to 600V 25kVA, 150°C, single-phase, 60Hz, 

480V primary, 120/240V secondar y , 10kV BIL 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

TABLE 11.6.-ENGINEERING DESIGN LINES AND REPRESENTATIVE UNITS FOR ANALYSIS-Continued

45391

DL Type of distribution transformer kVA range Voltage taps Secondary

voltages

Engineering design line representative unit

7 ............. Dry-type, low-voltage, three-phase .. 15-150 Universal* ............ 208Y/120 to 75kVA, 150°C, three-phase, 60Hz,

600Y/347V. 480V primary, 208Y/120V secondary, 10kV BIL

8 ............. Dry-type, low-voltage , three-phase .. 225-1000 Universal* ............ 208Y/120 to 300kVA, 150°C, three-phase, 60Hz,

600Y/347V. 480V Delta primary, 208Y/120V

secondary, 10kV BIL

9 ............. Dry-type, medium-voltage , three- 15-500 ±2-2.5% .............. 208Y/120 to 300kVA, 150°C, three-phase, 60Hz,

phase , 20-45kV BIL. 600Y/347V. 4160V primary, 480Y/277V secondary, 45kV BIL

10 ........... Dry-type, medium-voltage , three- 750-2500 ±2-2.5% .............. 208Y/120 to 1500kVA, 150°C, three-phase,

phase , 20-45kV BIL. 600Y/347V. 60Hz, 4160V primary, 480Y/277V

secondary , 45kV BIL

11 ........... Dry-type, medium-voltage , three- 15-500 ±2-2.5% .............. 208Y/120 to 300kVA, 150°C, three-phase, 60Hz,

phase, 20-45kV BIL. 600Y/347V. 12470V primary, 480Y/277V secondary, 95kV BIL

12 ........... Dry-type, medium-voltage , three- 750-2500 ±2-2.5% .............. 208Y/120 to 1500kVA, 150°C, three-phase,

phase, 60-95kV BIL. 600Y/347V. 60Hz, 12470V primary, 480Y/

277V secondary, 95kV BIL

13 ........... Dry-type, medium-voltage , three- 225-2500 ±2-2.5% .............. 208Y/120 to 2000kVA, 150°C, three-phase,

phase, 110-150kV BIL. 600Y/347V. 60Hz, 12470V primary, 480Y/

277V secondary, 125kV BIL

`Universal Taps are 2 above and 4 below 2.5%.

3. Developing the Engineering Analysis

Inputs

The Department conducted a

modified design-option approach,

where a third party creates a database of

viable transformer designs and estimates

their cost and performance

characteristics. The Department selected

the software design company OPS to

prepare this database. OPS has been

providing transformer design services

for various manufacturers in the U.S.

and abroad for more than 30 years.

The Department worked closely with

the nine manufacturers it visited in

early 2002 to develop and refine the

software inputs for the representative

units. The inputs required for the

analysis included both design-related

inputs (e.g., types of core steel,

windings, core configurations,

insulation, and spacers) and the cost of

these materials and labor. Using these

inputs, OPS created a design database

that spans the range of efficiency levels

for each of the distribution transformers

studied in the engineering analysis. This

range of efficiency levels spans from the

lowest first-cost units to the maximum,

technologically feasible efficiency level.

Information concerning the design

inputs for the representative units from

each of the engineering design lines

appears in Chapter 5 of the TSD. The

information provided includes the

minimum performance characteristics,

the core-coil combinations, primary and

secondary voltages, voltage taps, and

other design details. Chapter 5 of the

TSD also provides the material costs

used for core steel, wire and strip

windings, insulation, spacers, bushings,

tanks, core clamps, hardware, and all

the other components costed in the OPS

generated transformer designs.

These material costs are critical

inputs to the OPS design software. To be

consistent with industry practice, OPS

marks up the raw material prices

entered into the software. In other

words, the scrap factor, factory

overhead, and non-production markup

are incorporated into the cost of a

pound of core steel as it is entered into

the software design program. NEMA

commented that it would be desirable to

have manufacturers jointly agree on

markup percentages to apply to the

manufacturing data to arrive at a typical

estimated manufacturer selling price.

(NEMA, No. 7 at p. 6) In response to this

recommendation, the Department

calculated initial markup estimates

based on U.S. Industry Census Data for

1992 and 1997 and Securities and

Exchange Commission (SEC) 10-K

reports for Acme Electric Corporation,

Powell Industries, Magnetek, and

Hammond Power Solutions. These

initial markups were circulated in a

draft engineering analysis report in

December 2001 for comment.

AK Steel commented that initial scrap

factor of 10 percent was too high for

core steel and recommended that the

Department use a 2 percent scrap factor.

(AK Steel, No. 18 at p. 2) The

Department discussed this comment

with several manufacturers and with

OPS, all of whom agreed that 10 percent

was too high for core steel, but may be

correct for insulation or wire. In

recognition of the greater importance of

core steel as a contributor to the

manufacturer selling price of the

transformer, the Department decided to

use a scrap factor of 2.5 percent rather

than 10 percent for all variable materials

handled during manufacturing (e.g.,

core steel, windings, insulation).

A stakeholder commented that the

manufacturer's profit markup used in

the December 2001 draft engineering

analysis update report was too high, and

the overhead markup was too low.

(Klein, No. 17 at p. 2) The Department

confirmed this comment during its

interviews with manufacturers in early

2002. Based on input from the eight

manufacturers visited, the Department

revised its manufacturer raw-material

markups as follows:

• Scrap factor: a 2.5 percent markup.

This markup applies to variable

materials (e.g., core steel, windings,

insulation). It accounts for the handling

of material (loading into assembly or

winding equipment) and the scrap

material that cannot be used in the

production of a finished transformer

(e.g., lengths of wire too short to wind,

trimmed core steel).

• Factory overhead: a 12.5 percent

markup, applied only to direct material

costs, accounts for all the indirect costs

associated with production, indirect

materials and energy use, depreciation,

taxes, and insurance.

• Non-production: a 25 percent

markup applied to the sum of the direct

material production, the direct labor,

and the factory overhead. This markup

reflects costs such as sales and general

administrative, research and

 EE-RM/STD-00-550 COMMENT 53.1

Federal Register/Vol. 69, No. 145/Thursciay, July 29, 2004/Proposeci Rules 45391 

TABLE 11.6.-ENGINEERING DESIGN liNES AND REPRESENTATIVE UNITS FOR ANALYSiS-Continued 

DL Type of distribution transformer kVA range Voltage taps Secondary Engineering design line representavoltages tive unit 

7 ............. Dry-type, low-voltage, three-phase .. 15-150 Universal* ............ 208Y/120 to 75kVA, 150 D

C, three-phase, 60Hz, 

600Y/347V. 480V primary, 208Y/120V secondary, 10kV BIL 

8 ............. Dry-type, low-voltage, three-phase .. 225-1000 Universal* ............ 208Y/120 to 300kVA, 150 D C, three-phase, 60Hz, 

600Y/347V. 480V Delta primary, 208Y/120V 

secondary, 10kV BIL 

9 ............. Dry-type, medium-voltage, three- 15-500 ±2-2.5% .............. 208Y/120 to 300kVA, 150 D

C, three-phase, 60Hz, 

phase, 20-45kV BIL. 600Y/347V. 4160V primary, 480Y/277V secondary, 45kV BIL 

10 ........... Dry-type, medium-voltage, three- 750-2500 ±2-2.5% .............. 208Y/120 to 1500kV A, 150 D

C, three-phase, 

phase, 20-45kV BIL. 600Y/347V. 60Hz, 4160V primary, 480Y/277V 

secondary, 45kV BIL 

11 ........... Dry-type, medium-voltage, three- 15-500 ±2-2.5% .............. 208Y/120 to 300kVA, 150 D C, three-phase, 60Hz, 

phase, 20-45kV BIL. 600Y/347V. 12470V primary, 480Y/277V secondary, 95kV BIL 

12 ........... Dry-type, medium-voltage, three- 750-2500 ±2-2.5% .............. 208Y/120 to 1500kVA, 150 D C, three-phase, 

phase, 60-95kV BIL. 600Y/347V. 60Hz, 12470V primary, 480YI 

277V secondary, 95kV BIL 

13 ........... Dry-type, medium-voltage, three- 225-2500 ±2-2.5% .............. 208Y/120 to 2000kVA, 150 D

C, three-phase, 

phase, 110-150kV BIL. 600Y/347V. 60Hz, 12470V primary, 480YI 

*Universal Taps are 2 above and 4 below 2.5%. 

3. Developing the Engineering Analysis 

Inputs 

The Department conducted a 

modified design-option approach, 

where a third party creates a database of 

viable transformer designs and estimates 

their cost and performance 

characteristics. The Department selected 

the software design company OPS to 

prepare this database. OPS has been 

providing transformer design services 

for various manufacturers in the u.s. 

and abroad for more than 30 years. 

The Department worked closely with 

the nine manufacturers it visited in 

early 2002 to develop and refine the 

software inputs for the representative 

units. The inputs required for the 

analysis included both design-related 

inputs (e.g., types of core steel, 

windings, core configurations, 

insulation, and spacers) and the cost of 

these materials and labor. Using these 

inputs, OPS created a design database 

that spans the range of efficiency levels 

for each of the distribution transformers 

studied in the engineering analysis. This 

range of efficiency levels spans from the 

lowest first-cost units to the maximum, 

technologically feasible efficiency level. 

Information concerning the design 

inputs for the representative units from 

each of the engineering design lines 

appears in Chapter 5 ofthe TSD. The 

information provided includes the 

minimum performance characteristics, 

the core-coil combinations, primary and 

secondary voltages, voltage taps, and 

other design details. Chapter 5 of the 

TSD also provides the material costs 

used for core steel, wire and strip 

windings, insulation, spacers, bushings, 

tanks, core clamps, hardware, and all 

the other components costed in the OPS 

generated transformer designs. 

These material costs are critical 

inputs to the OPS design software. To be 

consistent with industry practice, OPS 

marks up the raw material prices 

entered into the software. In other 

words, the scrap factor, factory 

overhead, and non-production markup 

are incorporated into the cost of a 

pound of core steel as it is entered into 

the software design program. NEMA 

commented that it would be desirable to 

have manufacturers jointly agree on 

markup percentages to apply to the 

manufacturing data to arrive at a typical 

estimated manufacturer selling price. 

(NEMA, No.7 at p. 6) In response to this 

recommendation, the Department 

calculated initial markup estimates 

based on U.s. Industry Census Data for 

1992 and 1997 and Securities and 

Exchange Commission (SEC) 10-K 

reports for Acme Electric Corporation, 

Powell Industries, Magnetek, and 

Hammond Power Solutions. These 

initial markups were circulated in a 

draft engineering analysis report in 

December 2001 for comment. 

AK Steel commented that initial scrap 

factor of 10 percent was too high for 

core steel and recommended that the 

Department use a 2 percent scrap factor. 

(AK Steel, No. 18 at p. 2) The 

Department discussed this comment 

with several manufacturers and with 

OPS, all of whom agreed that 10 percent 

was too high for core steel, but may be 

correct for insulation or wire. In 

recognition ofthe greater importance of 

277V secondary, 125kV BIL 

core steel as a contributor to the 

manufacturer selling price of the 

transformer, the Department decided to 

use a scrap factor of 2.5 percent rather 

than 10 percent for all variable materials 

handled during manufacturing (e.g., 

core steel, windings, insulation). 

A stakeholder commented that the 

manufacturer's profit markup used in 

the December 2001 draft engineering 

analysis update report was too high, and 

the overhead markup was too low. 

(Klein, No. 17 at p. 2) The Department 

confirmed this comment during its 

interviews with manufacturers in early 

2002. Based on input from the eight 

manufacturers visited, the Department 

revised its manufacturer raw-material 

markups as follows: 

• Scrap factor: a 2.5 percent markup. 

This markup applies to variable 

materials (e.g., core steel, windings, 

insulation). It accounts for the handling 

of material (loading into assembly or 

winding equipment) and the scrap 

material that cannot be used in the 

production of a finished transformer 

(e.g., lengths of wire too short to wind, 

trimmed core steel). 

• Factory overhead: a 12.5 percent 

markup, applied only to direct material 

costs, accounts for all the indirect costs 

associated with production, indirect 

materials and energy use, depreciation, 

taxes, and insurance. 

" Non-production: a 25 percent 

markup applied to the sum of the direct 

material production, the direct labor, 

and the factory overhead. This markup 

reflects costs such as sales and general 

administrative, research and 
45392 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

development, interest payments, and

profit factor.

Chapter 5 of the TSD also discusses

the methodology followed to derive an

industry average cost of labor. The

Department calculated it initially from

SEC 10-K reports, and solicited

feedback from manufacturers during the

early 2002 site visits. The Department

started with a labor cost per hour of

$14.31, and added a series of markups

which brought the end-price of labor to

$53.46 per hour. These markups include

the burden of indirect production labor

costs (33 percent), overhead (30

percent), fringe benefits (21 percent),

assembly labor up-time (43 percent),

and non-production markup (25

percent). The assembly labor up-time

markup of 43 percent reflects a labor use

rate of 70 percent, meaning that 30

percent of the time, production staff are

not engaged in building transformers.

All of these terms are defined in Chapter

5 of the TSD.

In combination with the cost of

material and labor inputs, the OPS

software used a range of what are

known in the industry as A and B

evaluation combinations (see TOC

evaluation method in Chapter 3 of the

TSD). These A and B evaluation values

mimic hundreds of distribution

transformer purchase orders. A

represents a customer's net present

value of future losses in the transformer

core (no-load losses) and B represents a

customer's net present value of future

losses in the windings (load losses).

These values take into account a range

of factors depending on the customer.

For utilities, some of the key variables

include the avoided cost of generation,

the avoided cost of transmission and

distribution, the levelized fixed charge

rate, and the equivalent annual peak

load. For commercial and industrial

customers, some of the key variables

include the cost of capital, the energy

demand costs, the peak load on the

transformer, and the loss factor. The

Department also used A and B values in

the LCC analysis (see section II.F.2.c) to

simulate customer purchasing behavior

in the transformer market.

A and B are expressed in terms of

dollars per watt of loss. The greater the

values of A and B, the higher financial

importance a customer attaches to the

value of future transformer losses. As A

and B values increase, the watts of core

and winding losses decrease, and the

resultant transformer efficiency

increases.

For the engineering analysis, the

Department used broad ranges of A and

B evaluation values (presented in

Chapter 5 of the TSD) capturing a

comprehensive range of efficiency levels

for each design option combination of

core steel and winding material. During

the 2002 site visits, manufacturers

helped develop the range of values

used. These values cover the spectrum

of efficiencies represented in

transformer orders from customers, as

well as a low first-cost design and a

maximum technologically feasible

design. For the low first-cost design, the

A and B evaluation values are both $0/

watt, indicating that the customer does

not attach any financial value to future

losses in the core or coil of the

transformer being bought. For the

maximum technologically feasible

design, the A and B evaluation values

are higher, and were differentiated for

this analysis between the liquidimmersed and dry-type distribution

transformers.

In its December 2001 draft

engineering analysis report, the

Department had used A values for the

liquid-immersed design lines that

increased in increments of 0.25 and B

values that increased by 0.10. However,

using such fine increments of A and B

value combinations resulted in more

than 1,000 designs per design option

combination, and more than 10,000

designs per representative unit.

According to the manufacturers, these

fine increments of A and B constituted

an unnecessary level of detail for

understanding the broader relationship

between cost and efficiency. The revised

analysis, published in June 2002, used

the same range of A and B values, but

with larger increments (0.50 on A and

0.25 on B). To identify the maximum

technical efficiency potential for

selected design option combinations,

the Department applied an "extended

analysis" of A and B values, thereby

extending A values up to $16 and B

values up to $6.

During the manufacturer site visits in

early 2002, dry-type manufacturers

requested that the Department use a

different range of A and B values than

those used for the liquid-immersed

analysis. These manufacturers

recommended considering a broader

range of A and B value combinations, as

well as higher B values. For the dry-type

transformer analysis, the Department

increased A and B values incrementally

from lowest first-cost to $12/watt for A

and to $8/watt for B. More information

on the range of A and B values and the

increments used to generate the

engineering analysis design database is

presented in Chapter 5 of the TSD.

4. Energy Efficient Design Issues

Several stakeholders commented that

the Department should be aware that the

performance characteristics and

physical size of a distribution

transformer changes as the efficiency

improves. EEI commented that the two

most important changes are an increase

in available fault current and an

increase in the physical dimensions of

an equivalent kVA unit. (EEI, No. 6 at

p. 3) This point was also made by TXU

Electric and Gas. (TXU Electric and Gas,

No. 12 at p. 7) These stakeholders

expressed concern that when replacing

a transformer with a new, more efficient

unit, the customer's main electrical

disconnect may not be rated for the

increased fault current. Should this

occur, it might cause the customer to

replace equipment such as the electrical

panel in addition to the transformer to

maintain compliance with the National

Electrical Safety Code. However, EEI

cautioned that some companies may not

choose to replace the electrical panel,

thereby creating a safety hazard. (EEI,

No. 6 at p. 4) Southern Company also

highlighted the issue that a lower

impedance on a more efficient

transformer would increase available

fault current. Utilities set minimum

impedance levels to limit the available

fault current at the transformer.

(Southern Company, No. 8 at p. 6)

In order to address these concerns, the

Department held the impedance of the

designs created by the OPS software to

an appropriate minimum value during

the design phase (e.g., 1.5 percent for a

liquid-filled, 50 kVA, single-phase

transformer) to ensure that the

impedance does not become so low in

highly efficient designs that it would

result in dangerously high fault currents

in the customer's breaker.

Stakeholders also commented that if

the physical dimensions of a

transformer increase under the standard,

this increase could cause clearance and

safety problems, according to the

National Electric Safety Code. Whether

the transformer is on a pole or a pad, the

utility and/or the customer may incur

additional installation costs, beyond the

transformer installation costs. EEI noted

that this criticism would not apply to

new installations. (EEI, No. 6 at p. 4) To

accommodate this comment in the

analysis, the Department tracked the

dimensions of all the designs created by

the OPS software. For the larger, threephase, dry-type units, the height of the

cabinet was held at a common, standard

industry dimension, while the length

and width varied with the core/coil

dimension. The LCC analysis also used

this weight and dimensional data, as it

directly impacts the shipping and

installation costs.

Southern Company noted that more

efficient transformers are typically

larger and heavier. These units would

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45392 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

development, interest payments, and 

profit factor. 

Chapter 5 of the TSD also discusses 

the methodology followed to derive an 

industry average cost of labor. The 

Department calculated it initially from 

SEC 10-K reports, and solicited 

feedback from manufacturers during the 

early 2002 site visits. The Department 

started with a labor cost per hour of 

$14.31, and added a series of markups 

which brought the end-price of labor to 

$53.46 per hour. These markups include 

the burden of indirect production labor 

costs (33 percent), overhead (30 

percent)' fringe benefits (21 percent), 

assembly labor up-time (43 percent), 

and non-production markup (25 

percent). The assembly labor up-time 

markup of 43 percent reflects a labor use 

rate of 70 percent, meaning that 30 

percent of the time, production staff are 

not engaged in building transformers. 

All of these terms are defined in Chapter 

5 of the TSD. 

In combination with the cost of 

material and labor inputs, the OPS 

software used a range of what are 

known in the industry as A and B 

evaluation combinations (see TOC 

evaluation method in Chapter 3 of the 

TSD). These A and B evaluation values 

mimic hundreds of distribution 

transformer purchase orders. A 

represents a customer's net present 

value of future losses in the transformer 

core (no-load losses) and B represents a 

customer's net present value of future 

losses in the windings (load losses). 

These values take into account a range 

of factors depending on the customer. 

For utilities, some of the key variables 

include the avoided cost of generation, 

the avoided cost of transmission and 

distribution, the levelized fixed charge 

rate, and the equivalent annual peak 

load. For commercial and industrial 

customers, some of the key variables 

include the cost of capital, the energy 

demand costs, the peak load on the 

transformer, and the loss factor. The 

Department also used A and B values in 

the LCC analysis (see section H.F.2.c) to 

simulate customer purchasing behavior 

in the transformer market. 

A and B are expressed in terms of 

dollars per watt of loss. The greater the 

values of A and B, the higher financial 

importance a customer attaches to the 

value of future transformer losses. As A 

and B values increase, the watts of core 

and winding losses decrease, and the 

resultant transformer efficiency 

increases. 

For the engineering analysis, the 

Department used broad ranges of A and 

B evaluation values (presented in 

Chapter 5 of the TSD) capturing a 

comprehensive range of efficiency levels 

for each design option combination of 

core steel and winding material. During 

the 2002 site visits, manufacturers 

helped develop the range of values 

used. These values cover the spectrum 

of efficiencies represented in 

transformer orders from customers, as 

well as a low first-cost design and a 

maximum technologically feasible 

design. For the low first-cost design, the 

A and B evaluation values are both $0/ 

watt, indicating that the customer does 

not attach any financial value to future 

losses in the core or coil of the 

transformer being bought. For the 

maximum technologically feasible 

design, the A and B evaluation values 

are higher, and were differentiated for 

this analysis between the liquidimmersed and dry-type distribution 

transformers. 

In its December 2001 draft 

engineering analysis report, the 

Department had used A values for the 

liquid-immersed design lines that 

increased in increments of 0.25 and B 

values that increased by 0.10. However, 

using such fine increments of A and B 

value combinations resulted in more 

than 1,000 designs per design option 

combination, and more than 10,000 

designs per representative unit. 

According to the manufacturers, these 

fine increments of A and B constituted 

an unnecessary level of detail for 

understanding the broader relationship 

between cost and efficiency. The revised 

analysis, published in June 2002, used 

the same range of A and B values, but 

with larger increments (0.50 on A and 

0.25 on B). To identify the maximum 

technical efficiency potential for 

selected design option combinations, 

the Department applied an "extended 

analysis" of A and B values, thereby 

extending A values up to $16 and B 

values up to $6. 

During the manufacturer site visits in 

early 2002, dry-type manufacturers 

requested that the Department use a 

different range of A and B values than 

those used for the liquid-immersed 

analysis. These manufacturers 

recommended considering a broader 

range of A and B value combinations, as 

well as higher B values. For the dry-type 

transformer analysis, the Department 

increased A and B values incrementally 

from lowest first-cost to $12/watt for A 

and to $8/watt for B. More information 

on the range of A and B values and the 

increments used to generate the 

engineering analysis design database is 

presented in Chapter 5 of the TSD. 

4. Energy Efficient Design Issues 

Several stakeholders commented that 

the Department should be aware that the 

performance characteristics and 

physical size of a distribution 

transformer changes as the efficiency 

improves. EEl commented that the two 

most important changes are an increase 

in available fault current and an 

increase in the physical dimensions of 

an equivalent kVA unit. (EEl, No.6 at 

p. 3) This point was also made by TXU 

Electric and Gas. (TXU Electric and Gas, 

No. 12 at p. 7) These stakeholders 

expressed concern that when replacing 

a transformer with a new, more efficient 

unit, the customer's main electrical 

disconnect may not be rated for the 

increased fault current. Should this 

occur, it might cause the customer to 

replace equipment such as the electrical 

panel in addition to the transformer to 

maintain compliance with the National 

Electrical Safety Code. However, EEl 

cautioned that some companies may not 

choose to replace the electrical panel, 

thereby creating a safety hazard. (EEl, 

No.6 at p. 4) Southern Company also 

highlighted the issue that a lower 

impedance on a more efficient 

transformer would increase available 

fault current. Utilities set minimum 

impedance levels to limit the available 

fault current at the transformer. 

(Southern Company, No.8 at p. 6) 

In order to address these concerns, the 

Department held the impedance of the 

designs created by the OPS software to 

an appropriate minimum value during 

the design phase (e.g., 1.5 percent for a 

liquid-filled, 50 kVA, single-phase 

transformer) to ensure that the 

impedance does not become so low in 

highly efficient designs that it would 

result in dangerously high fault currents 

in the customer's breaker. 

Stakeholders also commented that if 

the physical dimensions of a 

transformer increase under the standard, 

this increase could cause clearance and 

safety problems, according to the 

National Electric Safety Code. Whether 

the transformer is on a pole or a pad, the 

utility and/ or the customer may incur 

additional installation costs, beyond the 

transformer installation costs. EEl noted 

that this criticism would not apply to 

new installations. (EEl, No.6 at p. 4) To 

accommodate this comment in the 

analysis, the Department tracked the 

dimensions of all the designs created by 

the OPS software. For the larger, threephase, dry-type units, the height ofthe 

cabinet was held at a common, standard 

industry dimension, while the length 

and width varied with the core/coil 

dimension. The LCC analysis also used 

this weight and dimensional data, as it 

directly impacts the shipping and 

installation costs. 

Southern Company noted that more 

efficient transformers are typically 

larger and heavier. These units would 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

have higher transportation costs and

may require stronger poles. (Southern

Company, No. 8 at p. 3) The OPS

software calculates the weight of each of

the transformers designed, and any

additional handling and installation

costs are included in the LCC analysis.

5. Engineering Analysis Results

The results of the engineering analysis

are presented in Chapter 5 of the TSD

and in two Microsoft Excel spreadsheets

on the Department's website. All the

designs created for each of the

representative units from the thirteen

design lines are presented. Hundreds of

design variations are developed for each

representative unit, spanning the broad

range of efficiency levels and costs.

The OPS software produces design

specification reports that include

information about the core and coil

assembly. The design report includes

details about the core, high and low

voltage windings, insulation, cooling

ducts, and labor costs, that would

enable a manufacturer to build a

transformer at a given rating. The

software also generates an electrical

analysis report that estimates the

performance of that design, including

efficiency, core and coil losses at 25

percent, 35 percent, 50 percent, 65

percent, 75 percent, 100 percent, 125

percent, and 150 percent of nameplate

load. When the database of OPS

software designs is assembled, the

output provides a clear understanding

of the relationship between cost and

efficiency because it incorporates data

on the design, the bill of materials, the

labor costs, and the efficiency.

The OPS manufacturing cost

estimates assume an ideal situation

where manufacturers do not incur

retooling or special handling costs

associated with changing materials or

core/coil dimensions. NEMA stated its

concern that the draft engineering

analyses reports presented in December

2001 and August 2002 did not capture

one-time costs and investments that will

be required to design and manufacture

design types that are outside the range

of materials, technologies, and

production methods currently used by

manufacturers. NEMA believes that

standard levels requiring materials and

technologies beyond the existing range

used by companies today will incur

significant one-time costs. The "Selling

Price" estimates provided in the

analysis must incorporate timely

recovery of these one-time costs by the

manufacturers. (NEMA, No. 19 at p. 2)

The Department appreciates this

comment because it highlights the

importance of correctly reflecting the

impact a regulation will have on the

manufacturers of transformers. The

recovery of one-time retooling costs is

part of the manufacturer impact analysis

(MIA), which will be conducted

following the ANOPR workshop. The

Department requests that reviewers, and

particularly manufacturers, comment on

the significant additional one-time costs

they would incur if efficiency standards

were introduced.

D. Energy Use and End-Use Load

Characterization

This section presents the

Department's estimation of the energy

use and end-use load characterization

for distribution transformers.

Transformer loading is a factor that is

important for determining which types

of transformer designs will deliver a

specified efficiency, and for calculating

transformer losses. Transformer losses

have two components: no-load losses

and load losses. No-load losses are

independent of the load on the

transformer, while load losses depend

approximately on the square of the

transformer loading. Because load losses

can increase dramatically with

increased loading, there is a particular

concern that during times of peak

system load, load losses can impact

system capacity costs and reliability.

The Department received extensive

comments on transformer loading due to

its substantial implications for both

transformer design and loss

calculations.

NEMA recommended that the primary

economic analyses on which a standard

is based should be done using the TP 1

load levels of 35 percent and 50 percent,

and that it may also be appropriate to

calculate national energy savings based

on a lower loading. (NEMA, No. 7 at p.

9) ACEEE commented that commercial

building distribution transformers have

been shown to have low capacity factors

(typically around 20 percent), that 16

percent is an appropriate value for lowvoltage dry-type transformers, and that

the 20-30 percent value for utility

distribution company (UDC)

transformers seemed reasonable.

(ACEEE, No. 21 at p. 1; ACEEE, No. 14

at p. 2) In contrast, TXU Electric and

Gas noted that it is not unusual to allow

peak load levels on a transformer

serving residential customers to go as

high as 130 percent of nameplate load

during the summer or 160 percent

during the winter and suggested that in

a UDC environment the loading level

number may be somewhere higher than

the NEMA recommended 50 percent.

(TXU Electric and Gas, No. 12 at p. 6)

Copper Development Association (CDA)

commented that several transformer

manufacturers recommend loading their

45393

product to at least 60-70 percent of the

nameplate rating, and that higher

loading levels are recommended in

applications where there is no need for

overload capacity. (CDA, No. 9 at p. 2)

Southern Company noted that most

large utilities have a wealth of

information concerning transformer

loading and loading practices, and that

the Department should be able to gather

needed information from utilities to

evaluate current data on loading and

typical average and peak loads on

distribution transformers. (Southern

Company, No. 8 at p. 4)

The Department developed detailed

models of the transformer loads and

based features of its models on hourly

data obtained from utility and public

sources (see Chapter 6 of the TSD). The

analysis resulted in average initial load

levels for liquid-immersed transformers

ranging from 30 percent for 25 kVA

transformers to 59 percent for 1500 kVA

transformers and average life-time load

levels of 35 percent and 70 percent,

respectively. The shipment-weighted

lifetime average loading is 52.9 percent.

These load levels are within the range

suggested in the aforementioned

comments submitted by NEMA and

TXU Electric and Gas.

For dry-type transformers, the

Department's analysis resulted in

average load levels ranging from 32

percent to 37 percent (depending on

transformer size), which are consistent

with some initial comments by NEMA

but are higher than load levels

recommended by many of the comments

on the actual loading of dry-type

transformers. Shipment-weighted

lifetime average loading is 33.6 percent

for low-voltage dry-type and 36.5

percent for medium-voltage dry-type.

The Department's estimate for lowvoltage dry-type transformers is quite

close to the NEMA recommendation,

but the estimate for medium-voltage

dry-type transformers is substantially

lower than the 50 percent loading

recommended by NEMA for economic

evaluation. This is because the estimate

of 75 percent initial peak load and the

load factors estimated from the hourly

building load data are consistent with

the lower average loading. The

Department estimated that the initial

peak loading of dry-type transformers

should be 75 percent if transformers are

sized primarily by using engineering

criteria. NEMA later commented that

the actual initial load is less than 50

percent for dry-type transformers in

commercial buildings. (NEMA, No. 26 at

p. 3) Currently, the Department

examines the low initial load case as a

sensitivity case for low-voltage dry-type

transformers. For this sensitivity case,

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register/Vol. 69, No. 145 I Thursday, July 29, 2004/Proposed Rules 45393 

have higher transportation costs and 

may require stronger poles. (Southern 

Company, No.8 at p. 3) The DPS 

software calculates the weight of each of 

the transformers designed, and any 

additional handling and installation 

costs are included in the LCC analysis. 

5. Engineering Analysis Results 

The results of the engineering analysis 

are presented in Chapter 5 ofthe TSD 

and in two Microsoft Excel spreadsheets 

on the Department's website. All the 

designs created for each of the 

representative units from the thirteen 

design lines are presented. Hundreds of 

design variations are developed for each 

representative unit, spanning the broad 

range of efficiency levels and costs. 

The DPS software produces design 

specification reports that include 

information about the core and coil 

assembly. The design report includes 

details about the core, high and low 

voltage windings, insulation, cooling 

ducts, and labor costs, that would 

enable a manufacturer to build a 

transformer at a given rating. The 

software also generates an electrical 

analysis report that estimates the 

performance of that design, including 

efficiency, core and coil losses at 25 

percent, 35 percent, 50 percent, 65 

percent, 75 percent, 100 percent, 125 

percent, and 150 percent of nameplate 

load. When the database of DPS 

software designs is assembled, the 

output provides a clear understanding 

of the relationship between cost and 

efficiency because it incorporates data 

on the design, the bill of materials, the 

labor costs, and the efficiency. 

The DPS manufacturing cost 

estimates assume an ideal situation 

where manufacturers do not incur 

retooling or special handling costs 

associated with changing materials or 

core/coil dimensions. NEMA stated its 

concern that the draft engineering 

analyses reports presented in December 

2001 and August 2002 did not capture 

one-time costs and investments that will 

be required to design and manufacture 

design types that are outside the range 

of materials, technologies, and 

production methods currently used by 

manufacturers. NEMA believes that 

standard levels requiring materials and 

technologies beyond the existing range 

used by companies today will incur 

significant one-time costs. The "Selling 

Price" estimates provided in the 

analysis must incorporate timely 

recovery of these one-time costs by the 

manufacturers. (NEMA, No. 19 at p. 2) 

The Department appreciates this 

comment because it highlights the 

importance of correctly reflecting the 

impact a regulation will have on the 

manufacturers of transformers. The 

recovery of one-time retooling costs is 

part of the manufacturer impact analysis 

(MIA), which will be conducted 

following the ANDPR workshop. The 

Department requests that reviewers, and 

particularly manufacturers, comment on 

the significant additional one-time costs 

they would incur if efficiency standards 

were introduced. 

D. Energy Use and End-Use Load 

Characterization 

This section presents the 

Department's estimation ofthe energy 

use and end-use load characterization 

for distribution transformers. 

Transformer loading is a factor that is 

important for determining which types 

of transformer designs will deliver a 

specified efficiency, and for calculating 

transformer losses. Transformer losses 

have two components: no-load losses 

and load losses. No-load losses are 

independent of the load on the 

transformer, while load losses depend 

approximately on the square of the 

transformer loading. Because load losses 

can increase dramatically with 

increased loading, there is a particular 

concern that during times of peak 

system load, load losses can impact 

system capacity costs and reliability. 

The Department received extensive 

comments on transformer loading due to 

its substantial implications for both 

transformer design and loss 

calculations. 

NEMA recommended that the primary 

economic analyses on which a standard 

is based should be done using the TP 1 

load levels of 35 percent and 50 percent, 

and that it may also be appropriate to 

calculate national energy savings based 

on a lower loading. (NEMA, No.7 at p. 

9) ACEEE commented that commercial 

building distribution transformers have 

been shown to have low capacity factors 

(typically around 20 percent), that 16 

percent is an appropriate value for lowvoltage dry-type transformers, and that 

the 20-30 percent value for utility 

distribution company (UDC) 

transformers seemed reasonable. 

(ACEEE, No. 21 at p. 1; ACEEE, No. 14 

at p. 2) In contrast, TXU Electric and 

Gas noted that it is not unusual to allow 

peak load levels on a transformer 

serving residential customers to go as 

high as 130 percent of nameplate load 

during the summer or 160 percent 

during the winter and suggested that in 

a UDC environment the loading level 

number may be somewhere higher than 

the NEMA recommended 50 percent. 

(TXU Electric and Gas, No. 12 at p. 6) 

Copper Development Association (CDA) 

commented that several transformer 

manufacturers recommend loading their 

product to at least 60-70 percent of the 

nameplate rating, and that higher 

loading levels are recommended in 

applications where there is no need for 

overload capacity. (CDA, No.9 at p. 2) 

Southern Company noted that most 

large utilities have a wealth of 

information concerning transformer 

loading and loading practices, and that 

the Department should be able to gather 

needed information from utilities to 

evaluate current data on loading and 

typical average and peak loads on 

distribution transformers. (Southern 

Company, No.8 at p. 4) 

The Department developed detailed 

models of the transformer loads and 

based features of its models on hourly 

data obtained from utility and public 

sources (see Chapter 6 ofthe TSD). The 

analysis resulted in average initial load 

levels for liquid-immersed transformers 

ranging from 30 percent for 25 kVA 

transformers to 59 percent for 1500 kVA 

transformers and average life-time load 

levels of 35 percent and 70 percent, 

respectively. The shipment-weighted 

lifetime average loading is 52.9 percent. 

These load levels are within the range 

suggested in the aforementioned 

comments submitted by NEMA and 

TXU Electric and Gas. 

For dry-type transformers, the 

Department's analysis resulted in 

average load levels ranging from 32 

percent to 37 percent (depending on 

transformer size), which are consistent 

with some initial comments by NEMA 

but are higher than load levels 

recommended by many of the comments 

on the actual loading of dry-type 

transformers. Shipment-weighted 

lifetime average loading is 33.6 percent 

for low-voltage dry-type and 36.5 

percent for medium-voltage dry-type. 

The Department's estimate for lowvoltage dry-type transformers is quite 

close to the NEMA recommendation, 

but the estimate for medium-voltage 

dry-type transformers is substantially 

lower than the 50 percent loading 

recommended by NEMA for economic 

evaluation. This is because the estimate 

of 75 percent initial peak load and the 

load factors estimated from the hourly 

building load data are consistent with 

the lower average loading. The 

Department estimated that the initial 

peak loading of dry-type transformers 

should be 75 percent if transformers are 

sized primarily by using engineering 

criteria. NEMA later commented that 

the actual initial load is less than 50 

percent for dry-type transformers in 

commercial buildings. (NEMA, No. 26 at 

p. 3) Currently, the Department 

examines the low initial load case as a 

sensitivity case for low-voltage dry-type 

transformers. For this sensitivity case, 
45394 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

average loadings are about 20 percent.

The Department invites additional

comment and data regarding the

loadings of both low-voltage and

medium-voltage, dry-type transformers

and specific comments on whether the

current 75 percent average initial peak

loading used by the Department should

be lowered to 50 percent as

recommended by NEMA's more recent

comment. Comments may also address

the possibility of using 50 percent

average initial peak loads for

commercial applications and 75 percent

initial peak loads (or higher) for

industrial applications , or different

initial peak loadings for low-voltage and

medium-voltage , dry-type transformers.

The Department also received

substantial comment on specific

technical details of transformer loading.

There is a degree of coincidence

between transformer loads and either

system or building loads during the time

of peak load. Load coincidence is

measured by a peak responsibility factor

(PRF), defined as the square of the ratio

of the transformer load during the time

of the annual system or building peak,

and the annual peak load of the

transformer . The Department's analysis

estimated peak coincidence factors from

available hourly building load data

obtained from a Bonneville Power

Administration study and provided by

an electric utility stakeholder, as

described in detail in Chapter 6 of the

TSD.

On peak load coincidence, EEI

commented that transformer load

profiles often do not correlate to the

facility load profiles. (EEI, No. 28 at p.

2) Also , a stakeholder was concerned

that the Department may use

standardized loading assumptions, and

that there is no mention of diversity, or

the low likelihood that the peak load on

the transformer will coincide with the

utility peak, such as in a church. (L.G.

Spielvogel, Inc., No. 39 at p. 1) In

contrast, CDA commented that for the

commercial and industrial sector,

transformer peak times are expected to

roughly correspond with system peak

times. (CDA, No. 43 at p. 2)

The Department's analysis of peak

load coincidence is consistent with

these comments because the analysis

incorporates the range and diversity of

conditions described by the

stakeholders. Residential and certain

commercial loads were found to have

low coincidence with system peak load,

while industrial and certain commercial

loads have a high degree of coincidence.

The average PRF ranges from 31 percent

for 25 kVA, pole-mounted, liquidimmersed transformers (which serve a

large proportion of residential and small

commercial loads) to 68 percent for

1500 kVA, liquid-immersed, padmounted transformers. For dry-type

transformers, the PRF average values

range from 47 percent to 54 percent,

depending on the transformer owners

assumed for a given design line. The

data available to the Department does

not provide information that allows a

detailed analysis of dry-type transformer

peak coincidence factors with

commercial and industrial wholebuilding loads. As highlighted in

section IV.E, the Department requests

additional specific commentary and

load data regarding transformer

applications for commercial and

industrial users.

E. Markups for Equipment Price

Determination

This section explains how the

Department developed markups to the

equipment prices to derive installed

transformer prices (see TSD Chapter 7).

Supply-chain markup and installation

costs are the costs associated with

bringing a manufactured transformer

into service as an installed piece of

electrical equipment. NEMA pointed

out that determining user costs for drytype transformers is difficult because

transformers pass through a wide range

of channels before reaching the ultimate

owner. (NEMA, No. 7 at p. 6)

In the LCC analysis (see section II.F),

the Department applied the following

price markups to the manufacturing

costs of dry-type transformers:

distributor markup , contractor materials

markup, installation labor and

equipment markup and sales tax. The

Department did not apply the

distributor and contractor materials

markups to liquid-immersed

transformers but did apply the markup

on installation labor and equipment,

since utilities generally purchase their

transformers directly from

manufacturers and install the

transformers themselves. The

Department did not have sufficient data

to diversify the distribution channels

and markups beyond these two cases.

The Department requests feedback from

stakeholders on which distribution

channels are most common for the

different types of distribution

transformers.

The Department estimated these

markups for dry-type transformers

(expressed as average multipliers) from

RS Means Electrical Cost Data 2002. The

Department used RS Means data

because it is widely used in the

industry. Table 11.7 lists the average

markups used in this ANOPR;

additional detail is provided in Chapter

7 of the TSD.

TABLE 11.7.-SUPPLY-CHAIN MARKUPS

LCC analysis markups

Distributor .................................

Contractor Materials .................

Installation Labor and Equipment ......................................

Sales Tax ..................................

Average

multiplier

1.350

1.100

1.520

1.054

For dry-type transformers, the

distributor applies a markup to the

manufacturer selling price to arrive at a

distributor price, which is the price paid

by the electrical contractor. This

distributor markup reflects the cost of

distribution, including sales labor,

warehousing , overhead, and profit for

the distributor. The contractor markup

applied to the distributor price covers

contractor overhead and profit for the

sale of the transformer . Installation labor

and equipment markup accounts for the

overhead costs of labor and the wear

and tear of equipment used during the

installation process. In calculating total

installation costs, the Department used

the weight of each specific design as one

of the input variables to determine

installation cost. Shipping costs are also

added. The Department estimated

average shipping costs based on the

transformer weight using an average

unit shipping cost of $0 . 20/lb. Finally,

the Department added a sales tax to the

total cost, resulting in the total installed

cost. For liquid-immersed distribution

transformers, the total installed cost

includes the manufacturer selling price,

plus the weight specific installation

labor and equipment costs, installation

labor and equipment markup , shipping

cost, and sales tax.

Southern Company noted in its

comments that heavier, pole-mounted

transformers might also require stronger,

more expensive utility poles. (Southern

Company, No . 8 at p. 3) The Department

did not explicitly model this potential

effect due to a lack of data on the

relationship between the extra weight

that more efficient models might have

and the ability of standard utility poles

to support transformers with that extra

weight, the added costs of such poles if

they were required , and the fraction of

transformers that might be subject to

this effect. The Department requests

such data from utilities or other

stakeholders who might have it. As

highlighted in section IV.E, the

Department requests feedback from

stakeholders on markup costs to refine

supply- chain markup cost estimates.

F. Life-Cycle Cost and Payback Period

Analyses

When DOE is determining whether an

energy efficiency standard for

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45394 Federal Register / Vol. 69, No. 145/ Thursday, July 29, 2004/Proposed Rules 

average loadings are about 20 percent. 

The Department invites additional 

comment and data regarding the 

loadings of both low-voltage and 

medium-voltage, dry-type transformers 

and specific comments on whether the 

current 75 percent average initial peak 

loading used by the Department should 

be lowered to 50 percent as 

recommended by NEMA's more recent 

comment. Comments may also address 

the possibility of using 50 percent 

average initial peak loads for 

commercial applications and 75 percent 

initial peak loads (or higher) for 

industrial applications, or different 

initial peak loadings for low-voltage and 

medium-voltage, dry-type transformers. 

The Department also received 

substantial comment on specific 

technical details of transformer loading. 

There is a degree of coincidence 

between transformer loads and either 

system or building loads during the time 

of peak load. Load coincidence is 

measured by a peak responsibility factor 

(PRF), defined as the square of the ratio 

of the transformer load during the time 

of the annual system or building peak, 

and the annual peak load of the 

transformer. The Department's analysis 

estimated peak coincidence factors from 

available hourly building load data 

obtained from a Bonneville Power 

Administration study and provided by 

an electric utility stakeholder, as 

described in detail in Chapter 6 of the 

TSD. 

On peak load coincidence, EEl 

commented that transformer load 

profiles often do not correlate to the 

facility load profiles. (EEl, No. 28 at p. 

2) Also, a stakeholder was concerned 

that the Department may use 

standardized loading assumptions, and 

that there is no mention of diversity, or 

the low likelihood that the peak load on 

the transformer will coincide with the 

utility peak, such as in a church. (L.G. 

Spielvogel, Inc., No. 39 at p. 1) In 

contrast, CDA commented that for the 

commercial and industrial sector, 

transformer peak times are expected to 

roughly correspond with system peak 

times. (CDA, No. 43 at p. 2) 

The Department's analysis of peak 

load coincidence is consistent with 

these comments because the analysis 

incorporates the range and diversity of 

conditions described by the 

stakeholders. Residential and certain 

commercial loads were found to have 

low coincidence with system peak load, 

while industrial and certain commercial 

loads have a high degree of coincidence. 

The average PRF ranges from 31 percent 

for 25 kVA, pole-mounted, liquidimmersed transformers (which serve a 

large proportion of residential and small 

commercial loads) to 68 percent for 

1500 kVA, liquid-immersed, padmounted transformers. For dry-type 

transformers, the PRF average values 

range from 47 percent to 54 percent, 

depending on the transformer owners 

assumed for a given design line. The 

data available to the Department does 

not provide information that allows a 

detailed analysis of dry-type transformer 

peak coincidence factors with 

commercial and industrial wholebuilding loads. As highlighted in 

section IV.E, the Department requests 

additional specific commentary and 

load data regarding transformer 

applications for commercial and 

industrial users. 

E. Markups for Equipment Price 

Determination 

This section explains how the 

Department developed markups to the 

equipment prices to derive installed 

transformer prices (see TSD Chapter 7). 

Supply-chain markup and installation 

costs are the costs associated with 

bringing a manufactured transformer 

into service as an installed piece of 

electrical equipment. NEMA pointed 

out that determining user costs for drytype transformers is difficult because 

transformers pass through a wide range 

of channels before reaching the ultimate 

owner. (NEMA, No.7 at p. 6) 

In the LCC analysis (see section ILF), 

the Department applied the following 

price markups to the manufacturing 

costs of dry-type transformers: 

distributor markup, contractor materials 

markup, installation labor and 

equipment markup and sales tax. The 

Department did not apply the 

distributor and contractor materials 

markups to liquid-immersed 

transformers but did apply the markup 

on installation labor and equipment, 

since utilities generally purchase their 

transformers directly from 

manufacturers and install the 

transformers themselves. The 

Department did not have sufficient data 

to diversify the distribution channels 

and markups beyond these two cases. 

The Department requests feedback from 

stakeholders on which distribution 

channels are most common for the 

different types of distribution 

transformers. 

The Department estimated these 

markups for dry-type transformers 

(expressed as average multipliers) from 

RS Means Electrical Cost Data 2002. The 

Department used RS Means data 

because it is widely used in the 

industry. Table II.7lists the average 

markups used in this ANOPR; 

additional detail is provided in Chapter 

7 of the TSD. 

TABLE 11.7.-SUPPLy-CHAIN MARKUPS 

LCC analysis markups 

Distributor ................................ . 

Contractor Materials ................ . 

Installation Labor and Equipment ..................................... . 

Sales Tax ................................. . 

Average 

multiplier 

1.350 

1.100 

1.520 

1.054 

For dry-type transformers, the 

distributor applies a markup to the 

manufacturer selling price to arrive at a 

distributor price, which is the price paid 

by the electrical contractor. This 

distributor markup reflects the cost of 

distribution, including sales labor, 

warehousing, overhead, and profit for 

the distributor. The contractor markup 

applied to the distributor price covers 

contractor overhead and profit for the 

sale of the transformer. Installation labor 

and equipment markup accounts for the 

overhead costs of labor and the wear 

and tear of equipment used during the 

installation process. In calculating total 

installation costs, the Department used 

the weight of each specific design as one 

of the input variables to determine 

installation cost. Shipping costs are also 

added. The Department estimated 

average shipping costs based on the 

transformer weight using an average 

unit shipping cost of $0.20/Ib. Finally, 

the Department added a sales tax to the 

total cost, resulting in the total installed 

cost. For liquid-immersed distribution 

transformers, the total installed cost 

includes the manufacturer selling price, 

plus the weight specific installation 

labor and equipment costs, installation 

labor and equipment markup, shipping 

cost, and sales tax. 

Southern Company noted in its 

comments that heavier, pole-mounted 

transformers might also require stronger, 

more expensive utility poles. (Southern 

Company, No.8 at p. 3) The Department 

did not explicitly model this potential 

effect due to a lack of data on the 

relationship between the extra weight 

that more efficient models might have 

and the ability of standard utility poles 

to support transformers with that extra 

weight, the added costs of such poles if 

they were required, and the fraction of 

transformers that might be subject to 

this effect. The Department requests 

such data from utilities or other 

stakeholders who might have it. As 

highlighted in section IV.E, the 

Department requests feedback from 

stakeholders on markup costs to refine 

supply-chain markup cost estimates. 

F. Life-Cycle Cost and Payback Period 

Analyses 

When DOE is determining whether an 

energy efficiency standard for 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules 45395

distribution transformers is

economically justified , it takes into

consideration the economic impact of

potential standards on consumers (42

U.S.C. 6317(c) and 42 U.S.C.

6295 (o)(2)(B)). To accomplish this, the

Department calculated changes to

consumers' LCCs which are likely to

result from a candidate standard level,

as well as producing a distribution of

PBPs (see TSD Chapter 8). The effects of

standards on individual consumers

include changes in operating expenses

(usually lower) and changes in total

installed cost (usually higher). The

Department analyzed the net effect of

these changes by calculating the

changes in LCCs compared to a base

case. The LCC calculation considers

total installed cost ( equipment purchase

price plus installation cost), operating

expenses (energy and maintenance

costs), equipment lifetime , and discount

rate . The Department performed the

LCC analysis from the perspective of the

user of the distribution transformer

equipment. The PBP is an estimate of

the time required to recover the

incremental cost increase of a more

efficient transformer from the operating

cost savings.

The LCC and PBP results are

presented to facilitate stakeholder

review of the LCC analysis . Similar to

the LCC analysis, the PBP is based on

the total cost and operating expenses.

But unlike the LCC analysis, only the

first year's operating expenses are

considered in the calculation of PBP.

Because the PBP analysis does not take

into account changes in operating

expense over time or the time value of

money, it is also referred to as a

',simple" payback period.

On the broad issue of calculating LCC

savings, TXU Electric and Gas noted

that the input parameters necessary to

calculate that savings are volatile.

Variances in load characteristics such as

peak demand and load factor and

variation in energy costs which range

from 3 to 15 cents per kWh make

calculation of any energy savings

uncertain. (TXU Electric and Gas, No.

12 at p. 9)

The Department generated LCC and

PBP results as probability distributions

using a simulation based on Monte

Carlo statistical analysis methods in

which inputs to the analysis

spreadsheets consist of probability

distributions rather than single-point

values. As a result, the Monte Carlo

analysis produces a range of LCC and

PBP results. A distinct advantage of this

type of approach is that the Department

can estimate the percentage of users that

achieve particular LCC savings or attain

certain PBP values due to an efficiency

standard, in addition to the average LCC

savings or average PBP for that standard.

Because DOE conducted the analysis in

this way , it can express the

uncertainties associated with the

various input variables as probability

distributions. During the post-ANOPR

LCC sub-group analysis, the Department

intends to evaluate additional

parameters and prepare a

comprehensive assessment of the

impacts on sub-groups of users.

The Department developed

spreadsheet models in Microsoft Excel

to calculate the LCC and PBP. An addin to Microsoft Excel called Crystal Ball

(a commercially available software

program by Decisioneering ) allows for

input variables to be characterized with

probability distributions. The

spreadsheet models are available for

download from the Department's

website.

The Department performed a

sensitivity analysis of LCC model inputs

to examine which inputs have the

greatest affect on LCC results. See the

LCC Inputs, section II.F.2.

1. Approach Taken in the Life-Cycle

Cost Analysis

The LCC analysis estimates the

impact on consumers of potential

energy efficiency standards by

calculating the net cost of a transformer

under a base case of no standard and a

standards case of only standardcompliant transformers being available

in the market. The first step in

calculating the net cost of a transformer

is specifying the distribution of possible

transformer designs and the attendant

equipment and installation costs

associated with each design. The

engineering analysis provides the

manufacturer costs for each transformer

design. As explained in section II.E, the

Department estimates the final installed

cost by multiplying the manufacturer's

selling price by the appropriate

markups, then adding sales tax,

shipping costs, and installation costs.

Next, the calculation includes a

purchase-decision model that

determines which of the many designs

a customer selects. A fundamental input

to the purchase -decision model is the

proportion of transformers bought using

an evaluation of the economic impact of

losses. Section II.F.2.c on baseline and

standard design selection discusses this

fundamental input in more detail. Once

the base case and standards case designs

are selected for a customer, the

Department estimates the customer load

characteristics, which determine the

transformer no-load and load losses.

The Department created two sets of

electricity prices to estimate annual

energy expenses: a tariff-based estimate

and an hourly-based estimate. The

Department applied the tariff-based

approach to dry-type transformers,

owned primarily by commercial and

industrial customers. The Department

applied the hourly-based approach to

liquid-immersed transformers, used

primarily in utility applications. The

tariff-based approach estimates an

annual energy expense using retail

electricity prices determined from

electric utility tariffs collected in 2002.

The hourly-based approach estimates

annual energy expense using marginal

utility wholesale electricity costs from

1999 , the most recent available data

from the Federal Energy Regulatory

Commission (FERC) when the analysis

was performed. For the NOPR analysis,

the Department will use the most

current data available . For the hourlybased estimate , the Department

collected electricity production prices

that vary on an hourly basis and then

used them to model the marginal

electricity costs incurred by utilities

from hourly losses. For electricity

markets in which there is some level of

competition, the Department collected

actual wholesale hourly electricity

prices. For markets that are still fully

price-regulated , the Department

collected hourly system-load and

generation-cost data.

The Department then estimated the

final LCC value for each design and

each customer using a real discount rate

that represents the average cost of

capital for that customer. After repeating

the calculation for many customers and

many designs, the Department

calculated the distribution of net LCC

impacts of each candidate standard

level.

2. Life-Cycle Cost Inputs

For each efficiency level analyzed, the

LCC analysis requires input data for the

total installed cost of the equipment, the

operating cost, and the discount rate.

Table 11.8 summarizes the inputs and

key assumptions used to calculate the

customer economic impacts of various

energy efficiency levels. Equipment

price, installation cost, and baseline and

standard design selection affect the

installed cost of the equipment.

Transformer loading, load growth,

power factor, annual energy use and

demand, electricity costs , electricity

price trend , and maintenance costs

affect the operating cost. Discount rate

and lifetime of equipment affect the

calculation of the present value of

annual operating cost savings from a

proposed standard.

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45395 

distribution transformers is 

economically justified, it takes into 

consideration the economic impact of 

potential standards on consumers (42 

U.S.C. 6317(c) and 42 U.S.C. 

6295(0)(2)(B)). To accomplish this, the 

Department calculated changes to 

consumers' LCCs which are likely to 

result from a candidate standard level, 

as well as producing a distribution of 

PBPs (see TSD Chapter 8). The effects of 

standards on individual consumers 

include changes in operating expenses 

(usually lower) and changes in total 

installed cost (usually higher). The 

Department analyzed the net effect of 

these changes by calculating the 

changes in LCCs compared to a base 

case. The LCC calculation considers 

total installed cost (equipment purchase 

price plus installation cost), operating 

expenses (energy and maintenance 

costs), equipment lifetime, and discount 

rate. The Department performed the 

LCC analysis from the perspective of the 

user of the distribution transformer 

equipment. The PBP is an estimate of 

the time required to recover the 

incremental cost increase of a more 

efficient transformer from the operating 

cost savings. 

The LCC and PBP results are 

presented to facilitate stakeholder 

review of the LCC analysis. Similar to 

the LCC analysis, the PBP is based on 

the total cost and operating expenses. 

But unlike the LCC analysis, only the 

first year's operating expenses are 

considered in the calculation of PBP. 

Because the PBP analysis does not take 

into account changes in operating 

expense over time or the time value of 

money, it is also referred to as a 

"simple" payback period. 

On the broad issue of calculating LCC 

savings, TXU Electric and Gas noted 

that the input parameters necessary to 

calculate that savings are volatile. 

Variances in load characteristics such as 

peak demand and load factor and 

variation in energy costs which range 

from 3 to 15 cents per kWh make 

calculation of any energy savings 

uncertain. (TXU Electric and Gas, No. 

12 at p. 9) 

The Department generated LCC and 

PBP results as probability distributions 

using a simulation based on Monte 

Carlo statistical analysis methods in 

which inputs to the analysis 

spreadsheets consist of probability 

distributions rather than single-point 

values. As a result, the Monte Carlo 

analysis produces a range of LCC and 

PBP results. A distinct advantage of this 

type of approach is that the Department 

can estimate the percentage of users that 

achieve particular LCC savings or attain 

certain PBP values due to an efficiency 

standard, in addition to the average LCC 

savings or average PBP for that standard. 

Because DOE conducted the analysis in 

this way, it can express the 

uncertainties associated with the 

various input variables as probability 

distributions. During the post-ANOPR 

LCC sub-group analysis, the Department 

intends to evaluate additional 

parameters and prepare a 

comprehensive assessment of the 

impacts on sub-groups of users. The Department developed 

spreadsheet models in Microsoft Excel 

to calculate the LCC and PBP. An addin to Microsoft Excel called Crystal Ball 

(a commercially available software 

program by Decisioneering) allows for 

input variables to be characterized with 

probability distributions. The 

spreadsheet models are available for 

download from the Department's 

website. 

The Department performed a 

sensitivity analysis of LCC model inputs 

to examine which inputs have the 

greatest affect on LCC results. See the 

LCC Inputs, section I1.F.2. 

1. Approach Taken in the Life-Cycle 

Cost Analysis 

The LCC analysis estimates the 

impact on consumers of potential 

energy efficiency standards by 

calculating the net cost of a transformer 

under a base case of no standard and a 

standards case of only standardcompliant transformers being available 

in the market. The first step in 

calculating the net cost of a transformer 

is specifying the distribution of possible 

transformer designs and the attendant 

equipment and installation costs 

associated with each design. The 

engineering analysis provides the 

manufacturer costs for each transformer 

design. As explained in section II.E, the 

Department estimates the final installed 

cost by multiplying the manufacturer's 

selling price by the appropriate 

markups, then adding sales tax, 

shipping costs, and installation costs. 

Next, the calculation includes a 

purchase-decision model that 

determines which of the many designs 

a customer selects. A fundamental input 

to the purchase-decision model is the 

proportion of transformers bought using 

an evaluation of the economic impact of 

losses. Section I1.F.2.c on baseline and 

standard design selection discusses this 

fundamental input in more detail. Once 

the base case and standards case designs 

are selected for a customer, the 

Department estimates the customer load 

characteristics, which determine the 

transformer no-load and load losses. 

The Department created two sets of 

electricity prices to estimate annual 

energy expenses: a tariff-based estimate 

and an hourly-based estimate. The 

Department applied the tariff-based 

approach to dry-type transformers, 

owned primarily by commercial and 

industrial customers. The Department 

applied the hourly-based approach to 

liquid-immersed transformers, used 

primarily in utility applications. The 

tariff-based approach estimates an 

annual energy expense using retail 

electricity prices determined from 

electric utility tariffs collected in 2002. 

The hourly-based approach estimates 

annual energy expense using marginal 

utility wholesale electricity costs from 

1999, the most recent available data 

from the Federal Energy Regulatory 

Commission (FERC) when the analysis 

was performed. For the NOPR analysis, 

the Department will use the most 

current data available. For the hourlybased estimate, the Department 

collected electricity production prices 

that vary on an hourly basis and then 

used them to model the marginal 

electricity costs incurred by utilities 

from hourly losses. For electricity 

markets in which there is some level of 

competition, the Department collected 

actual wholesale hourly electricity 

prices. For markets that are still fully 

price-regulated, the Department 

collected hourly system-load and 

generation-cost data. 

The Department then estimated the 

final LCC value for each design and 

each customer using a real discount rate 

that represents the average cost of 

capital for that customer. After repeating 

the calculation for many customers and 

many designs, the Department 

calculated the distribution of net LCC 

impacts of each candidate standard 

level. 

2. Life-Cycle Cost Inputs 

For each efficiency level analyzed, the 

LCC analysis requires input data for the 

total installed cost of the equipment, the 

operating cost, and the discount rate. 

Table 11.8 summarizes the inputs and 

key assumptions used to calculate the 

customer economic impacts of various 

energy efficiency levels. Equipment 

price, installation cost, and baseline and 

standard design selection affect the 

installed cost of the equipment. 

Transformer loading, load growth, 

power factor, annual energy use and 

demand, electricity costs, electricity 

price trend, and maintenance costs 

affect the operating cost. Discount rate 

and lifetime of equipment affect the 

calculation ofthe present value of 

annual operating cost savings from a 

proposed standard. 
45396 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

TABLE 11.8.-SUMMARY OF INPUTS AND KEY ASSUMPTIONS USED IN THE LCC ANALYSIS

Input

Transformer loading ........................

Annual energy and demand ...........

Equipment price ..............................

Installation cost ...............................

Effective Date of Standard ..............

Candidate Standard Levels ............

Baseline and standard design selection.

Power Factor ...................................

Load growth ....................................

Electricity costs ...............................

Electricity price trend .. ....................

Lifetime ............................................

Maintenance cost ............................

Discount rates .................................

Description

Loading depends on customer and transformer characteristics. The average initial liquid-immersed transformer loading is 30% for 25 kVA and 59% for 1500 kVA transformers. The average initial dry-type

transformer loading is 32 % for 25 kVA and 37% for 2000 kVA transformers. The shipment-weighted lifetime average loading is 33.6% for low-voltage dry and 36.5% for medium-voltage dry. With load growth,

average installed liquid -immersed transformer loading is 35% for 25 kVA and 70% for 1500 kVA transformers with a shipment-weighted lifetime average loading of 52 . 9%. See section II.D.

Derived from a statistical hourly load simulation for use liquid-immersed transformers, and estimated from

the 1995 Commercial Building Energy Consumption Survey data for dry-type transformers using factors

derived from hourly load data. Load losses vary as the square of the load and are equal to rated load

losses at 100% loading. See section II.D.

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, manufacturer selling price plus sales tax is used. Shipping costs are included for both types of transformers. See

section II.E.

Includes a weight-specific component, derived from RS Means Electrical Cost Data 2002 and a markup to

cover installation labor, and equipment wear and tear. See section I.E.

Assumed to be 2007 for this analysis.

Five efficiency levels for each design line with the minimum equal to TP 1 and the maximum from the most

efficient designs from the engineering analysis.

The selection of baseline and standard-compliant transformers depends on customer behavior . For liquidimmersed transformers, the fraction of purchases evaluated is 50%, while for dry-type transformers, the

fraction of evaluated purchases is 10%. The average A value for evaluators is $5/watt, while the B value

depends on expected transformer load.*

Assumed to be unity.

One percent per year for liquid-immersed and 0% per year for dry-type transformers.

Derived from tariff-based and hourly-based electricity prices. Capacity costs provide extra value for reducing losses at peak. Average marginal tariff-based retail electricity price : 6.40/kWh for no-load losses and

7.40/kWh for load losses. Average marginal wholesale utility hourly-based costs: 3.80/kWh for no-load

losses and 4.50/kWh for load losses.

Obtained from Annual Energy Outlook 2003 (AEO 2003). Average real price change from 2001 to 2020 is

-9%, -6%, -12%, and 0% for the reference, high growth , low growth, and constant real price scenarios, respectively.

Distribution of lifetimes, with mean lifetime for both liquid and dry-type transformers assumed to be 32

years.

Annual maintenance cost does not vary as a function of efficiency.

Mean real discount rates range from 4 .2% for owners of pole-mounted , liquid-immersed transformers to

6.6% for dry-type transformer owners.

`The concept of using A and B evaluation combinations was introduced in section II . C.3, Developing the Engineering Analysis Inputs . Within

the context of the LCC analysis, the A factor measures the value to a transformer purchaser , in $/watt, of reducing no-load losses while the B

factor measures the value , in $/watt, of reducing load losses. The purchase decision model developed by the Department mimics the likely

choices that consumers make given the A and B values they assign to the transformer losses.

The Department performed a

sensitivity analysis of LCC model inputs

to examine which ones have the greatest

impact on LCC results. The LCC results

are most sensitive to three parameters in

the purchase decision model: fraction of

purchases evaluated, cost of electricity,

and loading estimates. The single most

sensitive input is the fraction of

purchases in which transformer losses

are evaluated during a purchase. The

input with the next most significant

impact is the cost of electricity.

Electricity price trends have an indirect

effect on the average cost of electricity

over time while the initial estimate of

electricity costs has a relatively larger

impact on LCC results. The third most

significant impact on LCC results

derives from the loading estimates.

Loading estimates are affected mostly by

transformer sizing practices and

secondarily by technical details of the

load characteristics.

The power factor estimate affects the

LCC results through its effect on load

loss estimates. Depending on the

customer profile for a given LCC

analysis, discount rates can also have a

large impact on LCC results. Other

inputs such as lifetime, maintenance

costs, and installation costs have a

relatively small impact on LCC results

when compared to inputs such as those

mentioned above.

As noted by its absence in Table II.8,

the Department chose not to include the

impact of income taxes in the LCC

analysis for this ANOPR. The

Department understands that there are

two ways in which taxes affect the net

impacts of purchasing more energy

efficient equipment compared to

baseline equipment: (1) Energy efficient

equipment typically costs more to

purchase than baseline equipment

which in turn lowers net income and

may lower company taxes; and (2)

efficient equipment typically costs less

to operate than baseline equipment

which in turn increases net income and

may increase company taxes. In general,

the Department believes that the net

impact of taxes on the LCC analysis

depends upon firm profitability and

"expense" practices (how firms expense

the purchase cost of equipment). The

Department seeks input on whether

income tax effects are significant

enough to warrant inclusion in the LCC

analysis for the NOPR. The Department

specifically requests information on

how many utilities and commercial and

industrial firms that purchase

distribution transformers have net

Federal and/or state income tax liability

and, if they do, what "expense"

practices they use to depreciate the

purchase costs.

a. Effective Date of Standard

The Department is planning to

propose that the effective date of any

new energy efficiency standard for

 EE-RM/STD-00-550 COMMENT 53.1

45396 Federal Register I Vol. 69, No. 145 I Thursday, July 29, 2004 I Proposed Rules 

TABLE 11.8.-SUMMARY OF INPUTS AND KEY ASSUMPTIONS USED IN THE LCC ANALYSIS 

Input Description 

Transformer loading ........................ Loading depends on customer and transformer characteristics. The average initial liquid·immersed trans· 

former loading is 30% for 25 kVA and 59% for 1500 kVA transformers. The average initial dry·type 

transformer loading is 32% for 25 kVA and 37% for 2000 kVA transformers. The shipment·weighted life· 

time average loading is 33.6% for low·voltage dry and 36.5% for medium·voltage dry. With load growth, 

average installed liquid·immersed transformer loading is 35% for 25 kVA and 70% for 1500 kVA trans· 

formers with a shipment·weighted lifetime average loading of 52.9%. See section II.D. 

Annual energy and demand ........... Derived from a statistical hourly load simulation for use liquid·immersed transformers, and estimated from 

the 1995 Commercial Building Energy Consumption Survey data for dry·type transformers using factors 

derived from hourly load data. Load losses vary as the square of the load and are equal to rated load 

losses at 100% loading. See section II.D. 

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, manufac· 

turer selling price plus sales tax is used. Shipping costs are included for both types of transformers. See 

section II.E. 

Installation cost ............................... Includes a weight·specific component, derived from RS Means Electrical Cost Data 2002 and a markup to 

cover installation labor, and equipment wear and tear. See section II.E. 

Effective Date of Standard .............. Assumed to be 2007 for this analysis. 

Candidate Standard Levels ............ Five efficiency levels for each design line with the minimum equal to TP 1 and the maximum from the most 

efficient designs from the engineering analysis. 

Baseline and standard design se· The selection of baseline and standard·compliant transformers depends on customer behavior. For liquid· 

lection. immersed transformers, the fraction of purchases evaluated is 50%, while for dry·type transformers, the 

fraction of evaluated purchases is 10%. The average A value for evaluators is $5/watt, while the B value 

depends on expected transformer load.' 

Power Factor ................................... Assumed to be unity. 

Load growth ...... .............................. One percent per year for liquid·immersed and 0% per year for dry·type transformers. 

Electricity costs ............................... Derived from tariff·based and hourly·based electricity prices. Capacity costs provide extra value for reduc· 

ing losses at peak. Average marginal tariff·based retail electricity price: 6.4¢/kWh for no·load losses and 

7.4¢/kWh for load losses. Average marginal wholesale utility hourly·based costs: 3.8¢/kWh for no·load 

losses and 4.5¢/kWh for load losses. 

Electricity price trend ...................... Obtained from Annual Energy Outlook 2003 (AEO 2003). Average real price change from 2001 to 2020 is 

- 9%, - 6%, -12%, and 0% for the reference, high growth, low growth, and constant real price sce· 

narios, respectively. 

Lifetime ............................................ Distribution of lifetimes, with mean lifetime for both liquid and dry·type transformers assumed to be 32 

years. 

Maintenance cost ............................ Annual maintenance cost does not vary as a function of efficiency. 

Discount rates ... .............................. Mean real discount rates range from 4.2% for owners of pole·mounted, liquid·immersed transformers to 

6.6% for dry·type transformer owners. 

*The concept of using A and B evaluation combinations was introduced in section II.C.3, Developing the Engineering Analysis Inputs. Within 

the context of the LCC analysis, the A factor measures the value to a transformer purchaser, in $/watt, of reducing no·load losses while the B 

factor measures the value, in $/watt, of reducing load losses. The purchase decision model developed by the Department mimics the likely 

choices that consumers make given the A and B values they assign to the transformer losses. 

The Department performed a 

sensitivity analysis of Lee model inputs 

to examine which ones have the greatest 

impact on Lee results. The Lee results 

are most sensitive to three parameters in 

the purchase decision model: fraction of 

purchases evaluated, cost of electricity, 

and loading estimates. The single most 

sensitive input is the fraction of 

purchases in which transformer losses 

are evaluated during a purchase. The 

input with the next most significant 

impact is the cost of electricity. 

Electricity price trends have an indirect 

effect on the average cost of electricity 

over time while the initial estimate of 

electricity costs has a relatively larger 

impact on Lee results. The third most 

significant impact on Lee results 

derives from the loading estimates. 

Loading estimates are affected mostly by 

transformer sizing practices and 

secondarily by technical details of the 

load characteristics. 

The power factor estimate affects the 

Lee results through its effect on load 

loss estimates. Depending on the 

customer profile for a given Lee 

analysis, discount rates can also have a 

large impact on Lee results. Other 

inputs such as lifetime, maintenance 

costs, and installation costs have a 

relatively small impact on Lee results 

when compared to inputs such as those 

mentioned above. 

As noted by its absence in Table II.S, 

the Department chose not to include the 

impact of income taxes in the Lee 

analysis for this ANOPR. The 

Department understands that there are 

two ways in which taxes affect the net 

impacts of purchasing more energy 

efficient equipment compared to 

baseline equipment: (1) Energy efficient 

equipment typically costs more to 

purchase than baseline equipment 

which in turn lowers net income and 

may lower company taxes; and (2) 

efficient equipment typically costs less 

to operate than baseline equipment 

which in turn increases net income and 

may increase company taxes. In general, 

the Department believes that the net 

impact oftaxes on the Lee analysis 

depends upon firm profitability and 

"expense" practices (how firms expense 

the purchase cost of equipment). The 

Department seeks input on whether 

income tax effects are significant 

enough to warrant inclusion in the Lee 

analysis for the NOPR. The Department 

specifically requests information on 

how many utilities and commercial and 

industrial firms that purchase 

distribution transformers have net 

Federal and/or state income tax liability 

and, ifthey do, what "expense" 

practices they use to depreciate the 

purchase costs. 

a. Effective Date of Standard 

The Department is planning to 

propose that the effective date of any 

new energy efficiency standard for 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules 45397

distribution transformers be three years

after the final rule is published. The

Department has been conducting

analysis supporting this ANOPR since

the framework document workshop in

2000. Early on, the Department assumed

that the final rule would be issued in

2004 and that the new standard would

take effect in 2007 and used these dates

in the LCC and national impacts

analyses. The Department recognizes

that these dates are now unlikely to be

achieved. Adjusting the effective date by

a year or two will have relatively small

impacts on the analysis LCC and

national impacts results presented in

this ANOPR. For the NOPR analysis, the

Department will adjust these dates to

accurately reflect the probable rule

schedule at that time. The Department

calculated the LCC for customers as if

each new distribution transformer

purchase occurs in the year the standard

takes effect. The Department based the

cost of the equipment on that year.

b. Candidate Standard Levels

The Department must first select

efficiency levels to examine before it

can conduct an analysis of the impact of

candidate standard levels (CSL). NEMA

suggested four efficiency levels: (1) A

low-cost baseline design (lowest

installed cost that meets all safety and

performance requirements); (2) TP 1

level; (3) the maximum efficiency

design (the highest efficiency products

capable of being manufactured,

irrespective of cost), or an alternative

that is a fixed percentage improvement

of the difference between TP 1 and 100

percent efficiency-in this case, about a

25-30 percent improvement over TP 1;

and (4) an efficiency level halfway

between TP 1 and maximum efficiency.

(NEMA, No. 7 at pp. 7-8)

The American Council for an Energy

Efficient Economy (ACEEE)

recommended analysis of five efficiency

levels: (1) The Department's proposed

baseline (the least efficient transformer

available on the market); (2) NEMA TP

1; (3) an efficiency level based on an

approximately 7-year simple payback;

(4) an efficiency level based on an

approximately 12-year simple payback

(which approximates the minimum lifecycle cost point for a 30-year product

life with a 7-percent real discount rate);

and (5) the maximum technologically

feasible efficiency level. (ACEEE, No. 14

at p. 2)

Since the LCC analysis produces

payback as an output, PBPs could not be

used directly as an input for a particular

candidate standard level. The

Department's LCC model is flexible, and

adjusting inputs and assumptions will

produce different LCC outputs,

including PBPs. Stakeholders are

invited to use the spreadsheet models

(posted on DOE's website) to explore

how changing the inputs results in

different payback outputs. The PBP

results produced as part of the ANOPR

include values similar to those

requested by stakeholders but the

Department did not conduct an explicit

analysis exploring sets of inputs that

produced specific PBP outputs.

The Department started with these

NEMA and ACEEE comments and then

examined distribution transformer cost/

efficiency relationships from the

engineering analysis and found that TP

1 efficiency levels could be obtained

with relatively small cost increases over

the lowest cost designs for all design

lines. Therefore, the Department

decided that evaluating a CSL between

the lowest cost designs and the TP 1

efficiency level was not warranted,

resulting in TP 1 as the minimum CSL.

For each design line, the Department set

the maximum CSL among the most

efficient transformers in that

engineering design line. The

Department created three other CSLs

between the minimum and maximum

efficiency levels, approximately equally

proportioned so as to capture cost and

benefit impacts at a total of five roughly

equally spaced standard levels, unique

to each design line. The Department

believes that analyzing this distribution

of five CSLs for each of the 13

engineering design lines will provide

sufficient information for considering a

broad and meaningful range of

efficiency ratings. The lowest candidate

standard level is NEMA's TP 1, and the

highest has losses that are 10 percent

greater than the most efficient design

identified in the engineering analysis.

Table 11.9 lists the candidate standard

levels, expressed in terms of efficiency,

and in terms relative to NEMA TP 1

efficiency levels.

TABLE 11.9.-CANDIDATE STANDARD LEVELS EVALUATED FOR EACH DESIGN LINE

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5

Design line TP 1+ Efficiency TP 1+ Efficiency TP 1+ Efficiency TP 1+ Efficiency TP 1+ Efficiency

(%) (%) (%) (%) (%) (%) (%) (%) (%) (%)

DL 1 .................................... 0.00 98. 90 0.20 99. 10 0.40 99.30 0.50 99 .40 0.68 99.58

DL 2 .................................... 0.00 98.70 0.20 98.90 0.40 99.10 0.60 99.30 0.77 99.47

DL 3 .................................... 0.00 99.30 0.10 99.40 0.30 99.60 0.40 99.70 0.45 99.75

DL 4 .................................... 0.00 98 . 90 0.20 99. 10 0.40 99 . 30 0.50 99 .40 0.66 99.56

DL 5 .................................... 0.00 99 . 30 0.10 99.40 0.20 99 . 50 0.30 99 .60 0.36 99.66

DL 6 .................................... 0.00 98.00 0.20 98.20 0.40 98.40 0.70 98.70 0.79 98.79

DL 7 .................................... 0.00 98 . 00 0.30 98.30 0.60 98 . 60 0.90 98 .90 1.09 99.09

DL 8 .................................... 0.00 98 . 60 0.20 98.80 0.40 99.00 0.60 99 .20 0.67 99.27

DL 9 .................................... 0.00 98 . 60 0.20 98.80 0.40 99 . 00 0.60 99.20 0.71 99.31

DL 10 .................................. 0.00 99.10 0.10 99.20 0.20 99.30 0.30 99.40 0.34 99.44

DL 11 .................................. 0.00 98.50 0.20 98.70 0.40 98. 90 0.50 99 .00 0.60 99.10

DL 12 .................................. 0.00 99.00 0.10 99.10 0.30 99.30 0.40 99.40 0.45 99.45

DL 13 .................................. 0.00 99.00 0.10 99.10 0.30 99.30 0.40 99.40 0.45 99.45

c. Baseline and Standard Design

Selection

A key factor in estimating the

economic impact of a proposed standard

is the selection of transformer designs in

the base case and standards case

scenarios. The key issue is the degree to

which transformer purchasers will buy

transformers that have a minimum LCC

for their application without the

promulgation of a standard, compared

to purchasing behavior with an

efficiency standard in place.

The Department received many

comments on design selection and

purchase behavior and developed a

purchase decision model that tries to

incorporate many of the stated concerns.

The engineering analysis provides cost

and efficiency characteristics for

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register IVoI. 69, No. 145 I Thursday, July 29, 2004 I Proposed Rules 45397 

distribution transformers be three years 

after the final rule is published. The 

Department has been conducting 

analysis supporting this ANOPR since 

the framework document workshop in 

2000. Early on, the Department assumed 

that the final rule would be issued in 

2004 and that the new standard would 

take effect in 2007 and used these dates 

in the LCC and national impacts 

analyses. The Department recognizes 

that these dates are now unlikely to be 

achieved. Adjusting the effective date by 

a year or two will have relatively small 

impacts on the analysis LCC and 

national impacts results presented in 

this ANOPR. For the NOPR analysis, the 

Department will adjust these dates to 

accurately reflect the probable rule 

schedule at that time. The Department 

calculated the LCC for customers as if 

each new distribution transformer 

purchase occurs in the year the standard 

takes effect. The Department based the 

cost ofthe equipment on that year. 

b. Candidate Standard Levels 

The Department must first select 

efficiency levels to examine before it 

can conduct an analysis ofthe impact of 

candidate standard levels (CSL). NEMA 

suggested four efficiency levels: (1) A 

low-cost baseline design (lowest 

installed cost that meets all safety and 

performance requirements); (2) TP 1 

level; (3) the maximum efficiency 

design (the highest efficiency products 

capable of being manufactured, 

irrespective of cost), or an alternative 

that is a fixed percentage improvement 

ofthe difference between TP 1 and 100 

percent efficiency-in this case, about a 

25-30 percent improvement over TP 1; 

and (4) an efficiency level halfway 

between TP 1 and maximum efficiency. 

(NEMA, No.7 at pp. 7-8) 

The American Council for an Energy 

Efficient Economy (ACEEE) 

recommended analysis of five efficiency 

levels: (1) The Department's proposed 

baseline (the least efficient transformer 

available on the market); (2) NEMA TP 

1; (3) an efficiency level based on an 

approximately 7-year simple payback; 

(4) an efficiency level based on an 

approximately 12-year simple payback 

(which approximates the minimum lifecycle cost point for a 30-year product 

life with a 7-percent real discount rate); 

and (5) the maximum technologically 

feasible efficiency level. (ACEEE, No. 14 

at p. 2) 

Since the LCC analysis produces 

payback as an output, PEPs could not be 

used directly as an input for a particular 

candidate standard level. The 

Department's LCC model is flexible, and 

adjusting inputs and assumptions will 

produce different LCC outputs, 

including PEPs. Stakeholders are 

invited to use the spreadsheet models 

(posted on DOE's website) to explore 

how changing the inputs results in 

different payback outputs. The PEP 

results produced as part of the ANOPR 

include values similar to those 

requested by stakeholders but the 

Department did not conduct an explicit 

analysis exploring sets of inputs that 

produced specific PEP outputs. 

The Department started with these 

NEMA and ACEEE comments and then 

examined distribution transformer cost/ 

efficiency relationships from the 

engineering analysis and found that TP 

1 efficiency levels could be obtained 

with relatively small cost increases over 

the lowest cost designs for all design 

lines. Therefore, the Department 

decided that evaluating a CSL between 

the lowest cost designs and the TP 1 

efficiency level was not warranted, 

resulting in TP 1 as the minimum CSL. 

For each design line, the Department set 

the maximum CSL among the most 

efficient transformers in that 

engineering design line. The 

Department created three other CSLs 

between the minimum and maximum 

efficiency levels, approximately equally 

proportioned so as to capture cost and 

benefit impacts at a total of five roughly 

equally spaced standard levels, unique 

to each design line. The Department 

believes that analyzing this distribution 

of five CSLs for each of the 13 

engineering design lines will provide 

sufficient information for considering a 

broad and meaningful range of 

efficiency ratings. The lowest candidate 

standard level is NEMA's TP 1, and the 

highest has losses that are 10 percent 

greater than the most efficient design 

identified in the engineering analysis. 

Table II.glists the candidate standard 

levels, expressed in terms of efficiency, 

and in terms relative to NEMA TP 1 

efficiency levels. 

TABLE Il.g.-CANDIDATE STANDARD LEVELS EVALUATED FOR EACH DESIGN liNE 

DeSign line TP1+ 

(%) 

DL 1 .................................... 0.00 

DL 2 .................................... 0.00 

DL 3 .................................... 0.00 

DL 4 .................................... 0.00 

DL 5 .................................... 0.00 

DL 6 .................................... 0.00 

DL 7 .................................... 0.00 

DL 8 .................................... 0.00 

DL 9 .................................... 0.00 

DL 10 .................................. 0.00 

DL 11 .................................. 0.00 

DL 12 .................................. 0.00 

DL 13 .................................. 0.00 

c. Baseline and Standard Design 

Selection 

CSL 1 

Efficiency TP 1+ 

(%) (%) 

98.90 0.20 

98.70 0.20 

99.30 0.10 

98.90 0.20 

99.30 0.10 

98.00 0.20 

98.00 0.30 

98.60 0.20 

98.60 0.20 

99.10 0.10 

98.50 0.20 

99.00 0.10 

99.00 0.10 

CSL 2 CSL 3 

Efficiency TP 1+ Efficiency 

(%) (%) (%) 

99.10 0.40 99.30 

98.90 0.40 99.10 

99.40 0.30 99.60 

99.10 0.40 99.30 

99.40 0.20 99.50 

98.20 0.40 98.40 

98.30 0.60 98.60 

98.80 0.40 99.00 

98.80 0.40 99.00 

99.20 0.20 99.30 

98.70 0.40 98.90 

99.10 0.30 99.30 

99.10 0.30 99.30 

A key factor in estimating the 

economic impact of a proposed standard 

is the selection of transformer designs in 

the base case and standards case 

scenarios. The key issue is the degree to 

which transformer purchasers will buy 

transformers that have a minimum LCC 

for their application without the 

promulgation of a standard, compared 

to purchasing behavior with an 

efficiency standard in place. 

CSL4 CSL 5 

TP1+ Efficiency TP1+ Efficiency 

(%) (%) (%) (%) 

0.50 99.40 0.68 99.58 

0.60 99.30 0.77 99.47 

0.40 99.70 0.45 99.75 

0.50 99.40 0.66 99.56 

0.30 99.60 0.36 99.66 

0.70 98.70 0.79 98.79 

0.90 98.90 1.09 99.09 

0.60 99.20 0.67 99.27 

0.60 99.20 0.71 99.31 

0.30 99.40 0.34 99.44 

0.50 99.00 0.60 99.10 

0.40 99.40 0.45 99.45 

0.40 99.40 0.45 99.45 

The Department received many 

comments on design selection and 

purchase behavior and developed a 

purchase decision model that tries to 

incorporate many of the stated concerns. 

The engineering analysis provides cost 

and efficiency characteristics for 
45398 Federal Register / Vol. 69, No. 145 / Thursday, July 29, 2004 / Proposed Rules

between 150 and 300 designs for each

design option combination in each of

the 13 engineering design lines. The

purchase decision model in the LCC

analysis selects which of the hundreds

of designs are likely to be selected by

transformer purchasers.

Southern Company commented that

54 percent of the distribution

transformer line items that it buys and

75 percent by volume of the 300 line

items bought currently meet the TP 1

efficiency standard. It concluded that

the "assumption that the baseline model

would be the `typically sold, low

efficiency' model in the marketplace"

may not be a valid assumption.

(Southern Company, No . 8 at p. 2)

NEMA had commented earlier in the

rulemaking that the baseline models

used for the representative ratings

analyses should be the transformers

currently being sold when the life-cycle

cost or total owning cost is not

considered by the purchaser. (NEMA,

No. 7 at p. 6 ) NRDC and EEI argued that

because of electricity restructuring,

utilities are moving away from TOC

evaluation of transformer purchases.

(NRDC , No. 5 at p . 3; EEI, No. 24 at p.

2) EEI noted that for UDCs, competitive

retail markets are eliminating their

ability to gain any economic return for

installing high-efficiency transformers.

(EEI, No. 24 at p. 3) Under such

conditions, utility companies would

tend to buy those transformers that have

the lowest installed cost. HVOLT agreed

for slightly different reasons, noting that

because of the generation glut that

occurred in 2001-2002 , the 2003 A and

B values have dropped to $0/watt in

many parts of the country (see section

II.C.3). (HVOLT, No. 42 at p. 1)

On the other hand, METGLAS

Solutions disagreed that an

overwhelming fraction of purchasers

give little or no weight to losses in their

evaluations. It argued that it is not true

that only a small segment of the country

has large A and B factors , especially

when one takes a global perspective. For

example , in Japan the A factor is close

to $10 and in many European countries

it is close to $8. (METGLAS Solutions,

No. 16 at p . 2) And in a later comment,

NEMA provided some quantitative

detail on the fraction of higher

efficiency transformers currently bought

by noting that the market share of

liquid-filled transformers satisfying TP 1

has gone from nearly 100 percent a few

years ago to about 50 percent today.

(NEMA, No. 26 at p. 4)

The Department, in its purchasedecision model for liquid-immersed

transformers, assumed that 50 percent of

transformer purchases are based on an

evaluation process using A and B

values. These A and B values are

characterized as distributions with a

mean of $5/watt for the A factor. A

majority of purchases either have low A

factors or are not evaluated, yet a large

fraction (approximately 25 percent)

have A factors larger than $5/watt. The

Department does not currently model

trends in the number of evaluators, but

instead estimates that transformer

evaluation behavior will be the same in

the future as it is currently . The details

of the transformer design selection are

provided in the TSD, Chapter 8. As

highlighted later in section IV.E, the

Department requests input from

interested parties on the purchasedecision model and transformerevaluation-behavior for liquid-immersed

transformers. Additional information on

the fraction of evaluated purchases for

different categories of transformers,

specific trends or forecasts of evaluation

behavior, and the average A factor

values for such evaluations will be

particularly valuable for the LCC

analysis.

Evaluation is less common for drytype transformers than it is for liquidimmersed transformers. EEI

recommended that for dry-type

transformers, DOE use the nonevaluation scenario (0 percent

conducting evaluation). (EEI, No. 28 at

p. 2) HVOLT agreed that many

commercial and industrial customers

make purchases, based on lowest first

cost, but it found a significant

percentage that will support a 3-5 year

payback and would go as high as $1.50/

watt for no-load losses (A) and as high

as $0.35/watt for load losses (B).

(HVOLT, No. 42 at p. 1) NEMA

commented that for low-voltage, drytype transformers, the market is

commercial buildings. Commercial

building owners are interested in the

lowest first cost and typically their

tenants pay the electric bills, leading to

a low use of high efficiency transformers

results, while about 25 percent of

medium-voltage, dry-type transformers

meet the TP 1 standard. (NEMA, No. 26

at pp. 2-3)

The Department, in its purchasedecision model for dry-type

transformers, assumed that 10 percent of

transformer purchases are based on an

evaluation process using A and B

values. To give an example of how this

drives purchasing behavior, the

Department's current customer-designselection model estimates that the

average baseline efficiency for 75 kVA,

low-voltage , three-phase , dry-type

transformers on the market is 96.4

percent at 35 percent loading compared

to the TP 1 standard level of 98.0

percent. As highlighted in section IV.E,

the Department requests input from

interested parties on the customerdesign-selection model and transformerevaluation-behavior for dry-type

transformers. Specific issues include the

actual efficiency of the low first-cost

designs currently on the market. The

efficiency of the low first- cost designs

has a large impact on overall energy

savings estimates. Additional issues

include whether the fraction of

evaluators for low-voltage , dry-type

transformers should be lowered to 0

percent as recommended by EEI, and

raised to 25 percent for medium-voltage,

dry-type transformers as implied by

NEMA's comment. The average A-factor

value is also a significant issue, and

additional comments are invited on

whether the Department should use an

A-factor different from the current

assumptions.

d. Power Factor

The power factor is the real power

divided by the apparent power. Real

power is the time average of the

instantaneous product of voltage and

current. Apparent power is the product

of the root mean square voltage and the

root mean square current. When

specifying transformer efficiency,

specifications such as NEMA's TP 1-

2002 assume a power factor of 1.0.

Thus, in the absence of any specific data

or guidance on the appropriate power

factor, the Department used a power

factor of 1.0 in calculating the efficiency

levels for its engineering analysis and

used a power factor of 1.0 when it

analyzed candidate standard levels for

this ANOPR.

However, in real-world installations,

the loads experienced by distribution

transformers are likely to have power

factors of less than 1.0. The National

Rural Electric Cooperative Association

(NRECA) commented that setting the

power factor to the value of 1.0 is

probably not adequate for most

transformers since they service loads

with less than a unity power factor.

(NRECA, No. 40 at p. 4 ) Because the

LCC analysis models transformers

installed and operated in the field, DOE

created a spreadsheet with an adjustable

power factor, thereby enabling the LCC

to run at power factors lower than 1.0.

The Department requests specific

stakeholder comment on the power

factor of 1.0 assumption.

e. Load Growth

The LCC projects the operating costs

for transformer operation many years

into the future. This requires an

estimate of how the load on individual

transformers will change over time, i.e.,

the load growth. On this issue, CDA

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45398 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

between 150 and 300 designs for each 

design option combination in each of 

the 13 engineering design lines. The 

purchase decision model in the LCC 

analysis selects which of the hundreds 

of designs are likely to be selected by 

transformer purchasers. 

Southern Company commented that 

54 percent of the distribution 

transformer line items that it buys and 

75 percent by volume of the 300 line 

items bought currently meet the TP 1 

efficiency standard. It concluded that 

the "assumption that the baseline model 

would be the 'typically sold, low 

efficiency' model in the marketplace" 

may not be a valid assumption. 

(Southern Company, No.8 at p. 2) 

NEMA had commented earlier in the 

rulemaking that the baseline models 

used for the representative ratings 

analyses should be the transformers 

currently being sold when the life-cycle 

cost or total owning cost is not 

considered by the purchaser. (NEMA, 

No.7 at p. 6) NRDC and EEl argued that 

because of electricity restructuring, 

utilities are moving away from TOC 

evaluation of transformer purchases. 

(NRDC, No.5 at p. 3; EEl, No. 24 at p. 

2) EEl noted that for UDCs, competitive 

retail markets are eliminating their 

ability to gain any economic return for 

installing high-efficiency transformers. 

(EEl, No. 24 at p. 3) Under such 

conditions, utility companies would 

tend to buy those transformers that have 

the lowest installed cost. HVOL T agreed 

for slightly different reasons, noting that 

because of the generation glut that 

occurred in 2001-2002, the 2003 A and 

B values have dropped to $O/watt in 

many parts of the country (see section 

II.C.3). (HVOLT, No. 42 at p. 1) 

On the other hand, METGLAS 

Solutions disagreed that an 

overwhelming fraction of purchasers 

give little or no weight to losses in their 

evaluations. It argued that it is not true 

that only a small segment of the country 

has large A and B factors, especially 

when one takes a global perspective. For 

example, in Japan the A factor is close 

to $10 and in many European countries 

it is close to $8. (METGLAS Solutions, 

No. 16 at p. 2) And in a later comment, 

NEMA provided some quantitative 

detail on the fraction of higher 

efficiency transformers currently bought 

by noting that the market share of 

liquid-filled transformers satisfying TP 1 

has gone from nearly 100 percent a few 

years ago to about 50 percent today. 

(NEMA, No. 26 at p. 4) 

The Department, in its purchasedecision model for liquid-immersed 

transformers, assumed that 50 percent of 

transformer purchases are based on an 

evaluation process using A and B 

values. These A and B values are 

characterized as distributions with a 

mean of $5/watt for the A factor. A 

majority of purchases either have low A 

factors or are not evaluated, yet a large 

fraction (approximately 25 percent) 

have A factors larger than $5/watt. The 

Department does not currently model 

trends in the number of evaluators, but 

instead estimates that transformer 

evaluation behavior will be the same in 

the future as it is currently. The details 

ofthe transformer design selection are 

provided in the TSD, Chapter 8. As 

highlighted later in section IV.E, the 

Department requests input from 

interested parties on the purchasedecision model and transformerevaluation-behavior for liquid-immersed 

transformers. Additional information on 

the fraction of evaluated purchases for 

different categories of transformers, 

specific trends or forecasts of evaluation 

behavior, and the average A factor 

values for such evaluations will be 

particularly valuable for the LCC 

analysis. 

Evaluation is less common for drytype transformers than it is for liquidimmersed transformers. EEl 

recommended that for dry-type 

transformers, DOE use the nonevaluation scenario (0 percent 

conducting evaluation). (EEl, No. 28 at 

p. 2) HVOLT agreed that many 

commercial and industrial customers 

make purchases, based on lowest first 

cost, but it found a significant 

percentage that will support a 3-5 year 

payback and would go as high as $1.50/ 

watt for no-load losses (A) and as high 

as $0.35/watt for load losses (B). 

(HVOLT, No. 42 at p. 1) NEMA 

commented that for low-voltage, drytype transformers, the market is 

commercial buildings. Commercial 

building owners are interested in the 

lowest first cost and typically their 

tenants pay the electric bills, leading to 

a low use of high efficiency transformers 

results, while about 25 percent of 

medium-voltage, dry-type transformers 

meet the TP 1 standard. (NEMA, No. 26 

at pp. 2-3) 

The Department, in its purchasedecision model for dry-type 

transformers, assumed that 10 percent of 

transformer purchases are based on an 

evaluation process using A and B 

values. To give an example of how this 

drives purchasing behavior, the 

Department's current customer-designselection model estimates that the 

average baseline efficiency for 75 kVA, 

low-voltage, three-phase, dry-type 

transformers on the market is 96.4 

percent at 35 percent loading compared 

to the TP 1 standard level of 98.0 

percent. As highlighted in section IV.E, 

the Department requests input from 

interested parties on the customerdesign-selection model and transformerevaluation-behavior for dry-type 

transformers. Specific issues include the 

actual efficiency of the low first-cost 

designs currently on the market. The 

efficiency ofthe low first-cost designs 

has a large impact on overall energy 

savings estimates. Additional issues 

include whether the fraction of 

evaluators for low-voltage, dry-type 

transformers should be lowered to 0 

percent as recommended by EEl, and 

raised to 25 percent for medium-voltage, 

dry-type transformers as implied by 

NEMA's comment. The average A-factor 

value is also a significant issue, and 

additional comments are invited on 

whether the Department should use an 

A-factor different from the current 

assumptions. 

d. Power Factor 

The power factor is the real power 

divided by the apparent power. Real 

power is the time average of the 

instantaneous product of voltage and 

current. Apparent power is the product 

of the root mean square voltage and the 

root mean square current. When 

specifying transformer efficiency, 

specifications such as NEMA's TP 1-

2002 assume a power factor of 1.0. 

Thus, in the absence of any specific data 

or guidance on the appropriate power 

factor, the Department used a power 

factor of 1.0 in calculating the efficiency 

levels for its engineering analysis and 

used a power factor of 1.0 when it 

analyzed candidate standard levels for 

this ANOPR. 

However, in real-world installations, 

the loads experienced by distribution 

transformers are likely to have power 

factors of less than 1.0. The National 

Rural Electric Cooperative Association 

(NRECA) commented that setting the 

power factor to the value of 1.0 is 

probably not adequate for most 

transformers since they service loads 

with less than a unity power factor. 

(NRECA, No. 40 at p. 4) Because the 

LCC analysis models transformers 

installed and operated in the field, DOE 

created a spreadsheet with an adjustable 

power factor, thereby enabling the LCC 

to run at power factors lower than 1.0. 

The Department requests specific 

stakeholder comment on the power 

factor of 1.0 assumption. 

e. Load Growth 

The LCC projects the operating costs 

for transformer operation many years 

into the future. This requires an 

estimate of how the load on individual 

transformers will change over time, i.e., 

the load growth. On this issue, CDA 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

observed that a transformer 's initial

loading is almost certain to increase

over its typically long service life of

approximately 40 years. CDA also stated

that since transformers tend to stay in

place for decades once installed, what

appears to be light loading in a new

subdivision may become dramatically

higher over time. CDA believes that

more research is needed and the

Department should be cautious in

assuming that low load factors are

typical across the spectrum of the

residential market. (CDA, No. 9 at pp. 4-

5) NEMA stated that the Department's

assumption that the loads on

transformers grow by 1 percent per year

is incorrect. It agreed that the overall

growth in transformer loads is 1-2

percent per year , but stated that for

medium-voltage, dry-type transformers,

this growth is met by the purchase of

additional transformers, not by

increased load on existing transformers.

It suggested that the load growth per

transformer should be zero percent.

(NEMA, No. 26 at p. 3) NRECA

commented that while the Department's

transformer load growth model has 0

percent, 1 percent, or 2 percent per year

input selections available, this may not

be adequate to represent load growth on

rural electric transformers. (NRECA, No.

40 at p. 4) HVOLT commented that

transformer loads start out with nearly

the same load that they will see for their

expected life since residential

transformers are assigned to a group of

homes that are usually built within a

couple of years of each other . Heating/

cooling, water heating , laundry, and

cooking are the big loads that begin as

soon as the service is installed and there

is little subsequent residential load

growth. However , commercial and

industrial transformers , i.e. mediumvoltage dry-type, are sized to satisfy

their intended loads, and new load

expansion results in installation of a

new transformer . (HVOLT, No. 42 at p.

1) CDA noted that it is reasonable to

expect residential transformer loading to

increase over time as people add

appliances and air conditioning to

existing dwellings. Also , CDA found

many instances where loads increased

in commercial structures due to the

addition of electrical loads to existing

buildings. (CDA, No. 43 at p. 2) The

Department received stakeholder

guidance during the October 17, 2002,

webcast that a zero -percent load growth

was the preferable default for dry-type

distribution transformers.

For liquid-immersed transformers, the

Department used as the default scenario

a 1-percent-per-year load growth, i.e., a

medium rate , as identified in ORNL6847 , Determination Analysis of Energy

Conservation Standards for Distribution

Transformers. For dry-type

transformers, the Department applied a

zero-percent load growth. The

Department applied the load growth

factor to each transformer beginning in

2007, the expected effective date of the

standard. For exploration of the LCC

sensitivity to variations in load growth,

the Department included the ability to

examine scenarios with 0-percent, 1-

percent, and 2-percent load growth. As

highlighted in section IV.E, the

Department seeks comments from

stakeholders on the issue of load

growth.

f. Electricity Costs

The Department needs estimates of

electricity prices and costs to place a

value on transformer losses for

inclusion in the LCC calculation.

Stakeholders had a series of suggestions

regarding the electricity prices and costs

that the Department should use in its

LCC analysis. NEMA stated that for

utility applications, the Department

should use average utility electricity

costs as the basic electricity price. It

urged DOE to seek input from utilities

on their current rates. (NEMA, No. 26 at

pp. 2-3) NEMA suggested that for

commercial and industrial applications,

DOE should use average electricity

prices. (NEMA, No. 7 at p. 11) NEMA

also commented that since deregulation,

electricity rates for all customers have

decreased. In addition , NEMA noted

that many large industrial customers

have negotiated rates that merely keep

them as customers, with little or no

utility profit. Utilities have done this to

maintain load factors and the industrial

rate in this case is near their cost.

Therefore , DOE should seek input from

public- and investor-owned utilities on

rates. (NEMA, No . 26 at p. 3)

NRDC urged DOE to look carefully at

recent energy price trends and to

include in the range of its analysis the

levels of upward variation in price that

occurred in California during 2001.

(NRDC, No . 5 at p. 5, No. 25 at p. 2, No.

27 at pp. 2-3) CDA commented that a

heavily loaded transformer that was

designed to minimize mainly no-load

losses will have significantly greater

load losses than no -load losses during

peak times. It is also at these peak times

that cost per kWh is highest and the

economic justification is greatest to

address load losses. (CDA, No. 9 at p. 3)

CDA also urged the Department to

consider the effect of minimization of

the load loss of transformers on peakhour utility demands. CDA also

commented that there is a large

variation in electricity costs among

45399

utilities, with some utilities charging

relatively high electricity prices for

industrial customers. (CDA, No . 43 at p.

2) HVOLT commented that NEMA used

$0.065 /kWh which continues to be close

to reality. (HVOLT, No. 42 at p. 1)

NRECA commented that marginal

electricity prices are not necessarily

something that a distribution

cooperative can determine accurately, at

least not on an hour-by-hour basis,

because most electricity purchases by

cooperatives are not made based upon

hourly differentiated rates. (NRECA, No.

40 at p. 3)

Since the liquid-immersed

transformer market is dominated by

utilities, the Department used marginal

wholesale electricity prices to reflect

peak impacts for the liquid-immersed

design lines (see TSD Chapter 8). For

utilities, marginal wholesale electricity

prices are the prices experienced for the

last kWh of electricity produced. A

utility's marginal price can be higher or

lower than its average price , depending

on the relationships between capacity,

generation, transmission, and

distribution costs. The general structure

of the hourly marginal cost equation

divides the costs of the electricity into

capacity components and energy cost

components. The capacity components

include generation capacity,

transmission capacity , and distribution

capacity. Capacity components also

include a reserve margin needed to

assure system reliability. Energy cost

components include a marginal cost of

supply that varies by hour, factors that

account for losses, and cost recovery of

associated marginal expenses. The

Department applied this specific

equation to the calculation of the

marginal wholesale cost of supply of

electricity to cover transformer losses.

The Department used published FERC

Form 714 data and California,

Pennsylvania and New York electricity

market data for the year 1999 to

determine these costs.

Since the dry-type transformer market

is dominated by commercial and

industrial customers, the Department's

calculation of monthly customer

incremental retail electricity costs from

transformer losses used a representative

set of actual utility tariff formulas from

the year 2002 . Utility tariffs include

fixed charges, energy (per kWh) charges,

and demand (per kW) charges. Utilities

typically group the rates for the different

charges by blocks defined by levels of

energy use and demand. The tariff

formulas contain a series of blocks and

several parameters per block which

define the charges in that block of use.

The LCC spreadsheet for dry-type

transformers contains a customer bill

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45399 

observed that a transformer's initial 

loading is almost certain to increase 

over its typically long service life of 

approximately 40 years. CDA also stated 

that since transformers tend to stay in 

place for decades once installed, what 

appears to be light loading in a new 

subdivision may become dramatically 

higher over time. CDA believes that 

more research is needed and the 

Department should be cautious in 

assuming that low load factors are 

typical across the spectrum ofthe 

residential market. (CDA, No.9 at pp. 4-

5) NEMA stated that the Department's 

assumption that the loads on 

transformers grow by 1 percent per year 

is incorrect. It agreed that the overall 

growth in transformer loads is 1-2 

percent per year, but stated that for 

medium-voltage, dry-type transformers, 

this growth is met by the purchase of 

additional transformers, not by 

increased load on existing transformers. 

It suggested that the load growth per 

transformer should be zero percent. 

(NEMA, No. 26 at p. 3) NRECA 

commented that while the Department's 

transformer load growth model has 0 

percent, 1 percent, or 2 percent per year 

input selections available, this may not 

be adequate to represent load growth on 

rural electric transformers. (NRECA, No. 

40 at p. 4) HVOL T commented that 

transformer loads start out with nearly 

the same load that they will see for their 

expected life since residential 

transformers are assigned to a group of 

homes that are usually built within a 

couple of years of each other. Heating/ 

cooling, water heating, laundry, and 

cooking are the big loads that begin as 

soon as the service is installed and there 

is little subsequent residential load 

growth. However, commercial and 

industrial transformers, i.e. mediumvoltage dry-type, are sized to satisfy 

their intended loads, and new load 

expansion results in installation of a 

new transformer. (HVOLT, No. 42 at p. 

1) CDA noted that it is reasonable to 

expect residential transformer loading to 

increase over time as people add 

appliances and air conditioning to 

existing dwellings. Also, CDA found 

many instances where loads increased 

in commercial structures due to the 

addition of electrical loads to existing 

buildings. (CDA, No. 43 at p. 2) The 

Department received stakeholder 

guidance during the October 17, 2002, 

webcast that a zero-percent load growth 

was the preferable default for dry-type 

distribution transformers. 

For liquid-immersed transformers, the 

Department used as the default scenario 

a I-percent-per-year load growth, i.e., a 

medium rate, as identified in ORNL6847, Determination Analysis of Energy 

Conservation Standards for Distribution 

Transformers. For dry-type 

transformers, the Department applied a 

zero-percent load growth. The 

Department applied the load growth 

factor to each transformer beginning in 

2007, the expected effective date ofthe 

standard. For exploration of the LCC 

sensitivity to variations in load growth, 

the Department included the ability to 

examine scenarios with O-percent, 1-

percent, and 2-percent load growth. As 

highlighted in section IV.E, the 

Department seeks comments from 

stakeholders on the issue of load 

growth. 

f. Electricity Costs 

The Department needs estimates of 

electricity prices and costs to place a 

value on transformer losses for 

inclusion in the LCC calculation. 

Stakeholders had a series of suggestions 

regarding the electricity prices and costs 

that the Department should use in its 

LCC analysis. NEMA stated that for 

utility applications, the Department 

should use average utility electricity 

costs as the basic electricity price. It 

urged DOE to seek input from utilities 

on their current rates. (NEMA, No. 26 at 

pp. 2-3) NEMA suggested that for 

commercial and industrial applications, 

DOE should use average electricity 

prices. (NEMA, No.7 at p. 11) NEMA 

also commented that since deregulation, 

electricity rates for all customers have 

decreased. In addition, NEMA noted 

that many large industrial customers 

have negotiated rates that merely keep 

them as customers, with little or no 

utility profit. Utilities have done this to 

maintain load factors and the industrial 

rate in this case is near their cost. 

Therefore, DOE should seek input from 

public- and investor-owned utilities on 

rates. (NEMA, No. 26 at p. 3) 

NRDC urged DOE to look carefully at 

recent energy price trends and to 

include in the range ofits analysis the 

levels of upward variation in price that 

occurred in California during 2001. 

(NRDC, No.5 at p. 5, No. 25 at p. 2, No. 

27 at pp. 2-3) CDA commented that a 

heavily loaded transformer that was 

designed to minimize mainly no-load 

losses will have significantly greater 

load losses than no-load losses during 

peak times. It is also at these peak times 

that cost per kWh is highest and the 

economic justification is greatest to 

address load losses. (CDA, No.9 at p. 3) 

CDA also urged the Department to 

consider the effect of minimization of 

the load loss of transformers on peakhour utility demands. CDA also 

commented that there is a large 

variation in electricity costs among 

utilities, with some utilities charging 

relatively high electricity prices for 

industrial customers. (CDA, No. 43 at p. 

2) HVOLT commented that NEMA used 

$O.065/kWh which continues to be close 

to reality. (HVOLT, No. 42 at p. 1) 

NRECA commented that marginal 

electricity prices are not necessarily 

something that a distribution 

cooperative can determine accurately, at 

least not on an hour-by-hour basis, 

because most electricity purchases by 

cooperatives are not made based upon 

hourly differentiated rates. (NRECA, No. 

40 at p. 3) 

Since the liquid-immersed 

transformer market is dominated by 

utilities, the Department used marginal 

wholesale electricity prices to reflect 

peak impacts for the liquid-immersed 

design lines (see TSD Chapter 8). For 

utilities, marginal wholesale electricity 

prices are the prices experienced for the 

last kWh of electricity produced. A 

utility's marginal price can be higher or 

lower than its average price, depending 

on the relationships between capacity, 

generation, transmission, and 

distribution costs. The general structure 

of the hourly marginal cost equation 

divides the costs of the electricity into 

capacity components and energy cost 

components. The capacity components 

include generation capacity, 

transmission capacity, and distribution 

capacity. Capacity components also 

include a reserve margin needed to 

assure system reliability. Energy cost 

components include a marginal cost of 

supply that varies by hour, factors that 

account for losses, and cost recovery of 

associated marginal expenses. The 

Department applied this specific 

equation to the calculation of the 

marginal wholesale cost of supply of 

electricity to cover transformer losses. 

The Department used published FERC 

Form 714 data and California, 

Pennsylvania and New York electricity 

market data for the year 1999 to 

determine these costs. 

Since the dry-type transformer market 

is dominated by commercial and 

industrial customers, the Department's 

calculation of monthly customer 

incremental retail electricity costs from 

transformer losses used a representative 

set of actual utility tariff formulas from 

the year 2002. Utility tariffs include 

fixed charges, energy (per kWh) charges, 

and demand (per kW) charges. Utilities 

typically group the rates for the different 

charges by blocks defined by levels of 

energy use and demand. The tariff 

formulas contain a series of blocks and 

several parameters per block which 

define the charges in that block of use. 

The LCC spreadsheet for dry-type 

transformers contains a customer bill 
45400 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

calculator that calculates customer bills

based on information collected from a

representative set of utility tariffs,

seasonal charges, tariff blocks, and the

fixed, energy, and demand charges in

each block. The Department collected

218 published utility tariffs from 90

utilities to provide the data for the bill

calculator.

As highlighted in section IV.E, the

Department seeks input from

stakeholders regarding the appropriate

energy costs to use in this rulemaking.

g. Electricity Price Trends

NRDC commented that all three of the

proposed electricity price trend

scenarios explore real electricity price

increases relative to 2001 prices. (NRDC,

No. 27 at p. 2) CDA commented that

there are growing indications that

electricity prices will not be declining

in future years as demand catches up

with, and perhaps exceeds, available

generation and transmission capacity.

(CDA, No. 43 at p. 2)

For the relative change in electricity

prices for future years, the Department

used the price trends from three AEO

2003 forecast scenarios and a constant

real price scenario. LCC spreadsheet

users have the choice of four scenarios:

AEO 2003 low growth scenario, AEO

2003 reference scenario, AEO 2003 high

growth scenario, and constant real price

scenario. To reflect the uncertainty in

forecasts of economic growth, the AEO

2003 forecasts use high and low

economic growth cases along with the

reference case to project the possible

energy markets. The high economic

growth case incorporates higher

population, labor force, and

productivity growth rates than the

reference case. Investment, disposable

income, and industrial production are

higher and economic output is projected

to increase by 3.5 percent per year

between 2001 and 2025. The low

economic growth case assumes lower

population, labor force, and

productivity gains, with resulting higher

prices and interest rates and lower

industrial output growth. In the low

economic growth case, economic output

is expected to increase by 2.5 percent

per year over the forecast horizon. The

ANOPR uses the trend from the

reference scenario, 3.0 percent, as its

default "medium" scenario.

h. Equipment Lifetime

The Department defined distribution

transformer service life as the age at

which the transformer retires from

service. NEMA suggested that the

Department use a transformer lifetime of

30 years for the LCC analysis. (NEMA,

No. 7 at pp. 10-11) NEMA later

suggested that DOE should investigate

the actual lifetime of dry-type

distribution transformers which it felt

could be closer to 20 years, rather than

the 32 years assumed in the

Department's analysis. (NEMA, No. 26

at p. 3) CDA commented that it is not

uncommon to find transformers 50-plus

years old still in service. (CDA, No. 43

at p. 3)

The Department assumed, based on

ORNL-6847, Determination Analysis of

Energy Conservation Standards for

Distribution Transformers, that the

average life of distribution transformers

is 32 years. After preparing an in-depth

review of average lifetimes during the

Determination Analysis, ORNL found it

to be 32 years. The Department still

believes this is an accurate

representation of the average lifetime of

a distribution transformer. This lifetime

assumption includes a constant failure

rate of 0.5 percent/year due to lightning

and other random failures unrelated to

transformer age and an additional

corrosive failure rate of 0.5 percent/year

at year 15 and beyond. The Department

adjusted the retirement distribution to

maintain an average life of 32 years for

both liquid-immersed and dry-type

transformers.

i. Maintenance Costs

The Department assumed that the cost

for general maintenance of distribution

transformers will not change with

increased efficiency. In practice, there is

little scheduled maintenance for

distribution transformers. The

maintenance that does occur normally

consists of brief annual checks for dust

buildup, vermin infestation, and

accident or lightning damage.

j. Discount Rates

The discount rate is the rate at which

future expenditures are discounted to

estimate their present value.

Stakeholders expressed concern over

the appropriate discount rate to use in

the LCC analysis. NEMA stated that 8

percent should be the minimum

discount rate considered and that a

discount range of 15-20 percent

adjusted for inflation (real) would more

closely reflect opportunity costs for

business. (NEMA, No. 7 at p. 11) NEMA

also suggested that the Department use

a high hurdle rate of 35 percent for the

LCC analysis. (NEMA, No. 26 at p. 2)

Mr. John Ainscough also noted that DOE

should consider the opportunity cost of

capital that may be diverted from other

areas to pay for more expensive

transformers. (J. Ainscough, No. 15 at p.

1) NRDC stated that the 35 percent

discount rate is unjustified, pointing out

that this discount rate is evidence of the

type of market failure that standards are

supposed to address. (NRDC, No. 27 at

p. 3) NRDC stated that an 8 percent

discount rate is too high. NRDC noted

that it has demonstrated in previous

appliance rulemakings that market rates

of return on investment are in the range

of 5-5.5 percent real, at best. (NRDC,

No. 5 at p. 4) NRDC stated that these are

the highest rates that are defensible and

recommended that the distribution of

rates used for the analysis center around

2-3 percent real to reflect reduced

societal risk resulting from energy

efficiency standards. NRDC also stated

that it agrees with the Department that

the actual cost of capital represents the

appropriate discount rate for the LCC

analysis. (NRDC, No. 25 at p. 2 and No.

27 at p. 2) Cooper Power Systems

commented that the discount rate

selection method should be similar to

that used by DOE to determine the

present value of improved efficiency in

other energy savings projects such as for

refrigerators and motor efficiency.

(Cooper Power Systems, No. 34 at p. 2)

Lacking stakeholder consensus, the

Department used the classic economic

definition that discount rates are equal

to the cost of capital. The cost of capital

is a combination of debt interest rates

and the cost of equity capital to the

affected firms and industries. For each

design line, the Department divided

ownership into classes of potential

customers. Table 11.10 shows the classes

of owners and their percentages by

design line. The Department determined

from the Damodaran online investment

survey (http://pages.stern.nyu.edu/

adamodar/) that each class of potential

owners has a distribution of discount

rates. The discount rate distribution for

each design line analyzed in the LCC

analysis is a weighted sample that

combines estimated ownership

percentages based on the 2001 shipment

estimates and their respective discount

rates. Table II.10 also shows the mean

real discount rates by ownership

category used by DOE in the analysis. In

addition, Table 11.10 shows the resultant

weighted average discount rates for each

design line. A more detailed description

of the data sources is provided in

Chapter 8 of the TSD. As highlighted in

section IV.E, the Department seeks input

from stakeholders on the

appropriateness of these discount rates.

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45400 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

calculator that calculates customer bills 

based on information collected from a 

representative set of utility tariffs, 

seasonal charges, tariff blocks, and the 

fixed, energy, and demand charges in 

each block. The Department collected 

218 published utility tariffs from 90 

utilities to provide the data for the bill 

calculator. 

As highlighted in section IV.E, the 

Department seeks input from 

stakeholders regarding the appropriate 

energy costs to use in this rulemaking. 

g. Electricity Price Trends 

NRDC commented that all three of the 

proposed electricity price trend 

scenarios explore real electricity price 

increases relative to 2001 prices. (NRDC, 

No. 27 at p. 2) CDA commented that 

there are growing indications that 

electricity prices will not be declining 

in future years as demand catches up 

with, and perhaps exceeds, available 

generation and transmission capacity. 

(CDA, No. 43 at p. 2) 

For the relative change in electricity 

prices for future years, the Department 

used the price trends from three AEO 

2003 forecast scenarios and a constant 

real price scenario. LCC spreadsheet 

users have the choice of four scenarios: 

AEO 2003 low growth scenario, AEO 

2003 reference scenario, AEO 2003 high 

growth scenario, and constant real price 

scenario. To reflect the uncertainty in 

forecasts of economic growth, the AEO 

2003 forecasts use high and low 

economic growth cases along with the 

reference case to project the possible 

energy markets. The high economic 

growth case incorporates higher 

population, labor force, and 

productivity growth rates than the 

reference case. Investment, disposable 

income, and industrial production are 

higher and economic output is projected 

to increase by 3.5 percent per year 

between 2001 and 2025. The low 

economic growth case assumes lower 

population, labor force, and 

productivity gains, with resulting higher 

prices and interest rates and lower 

industrial output growth. In the low 

economic growth case, economic output 

is expected to increase by 2.5 percent 

per year over the forecast horizon. The 

ANOPR uses the trend from the 

reference scenario, 3.0 percent, as its 

default "medium" scenario. 

h. Equipment Lifetime 

The Department defined distribution 

transformer service life as the age at 

which the transformer retires from 

service. NEMA suggested that the 

Department use a transformer lifetime of 

30 years for the LCC analysis. (NEMA, 

No.7 at pp. 10-11) NEMA later 

suggested that DOE should investigate 

the actual lifetime of dry-type 

distribution transformers which it felt 

could be closer to 20 years, rather than 

the 32 years assumed in the 

Department's analysis. (NEMA, No. 26 

at p. 3) CDA commented that it is not 

uncommon to find transformers 50-plus 

years old still in service. (CDA, No. 43 

at p. 3) 

The Department assumed, based on 

ORNL-6847, Determination Analysis of 

Energy Conservation Standards for 

Distribution Transformers, that the 

average life of distribution transformers 

is 32 years. After preparing an in-depth 

review of average lifetimes during the 

Determination Analysis, ORNL found it 

to be 32 years. The Department still 

believes this is an accurate 

representation of the average lifetime of 

a distribution transformer. This lifetime 

assumption includes a constant failure 

rate of 0.5 percent/year due to lightning 

and other random failures unrelated to 

transformer age and an additional 

corrosive failure rate of 0.5 percent/year 

at year 15 and beyond. The Department 

adjusted the retirement distribution to 

maintain an average life of 32 years for 

both liquid-immersed and dry-type 

transformers. 

i. Maintenance Costs 

The Department assumed that the cost 

for general maintenance of distribution 

transformers will not change with 

increased efficiency. In practice, there is 

little scheduled maintenance for 

distribution transformers. The 

maintenance that does occur normally 

consists of brief annual checks for dust 

buildup, vermin infestation, and 

accident or lightning damage. 

j. Discount Rates 

The discount rate is the rate at which 

future expenditures are discounted to 

estimate their present value. 

Stakeholders expressed concern over 

the appropriate discount rate to use in 

the LCC analysis. NEMA stated that 8 

percent should be the minimum 

discount rate considered and that a 

discount range of 15-20 percent 

adjusted for inflation (real) would more 

closely reflect opportunity costs for 

business. (NEMA, No.7 at p. 11) NEMA 

also suggested that the Department use 

a high hurdle rate of 35 percent for the 

LCC analysis. (NEMA, No. 26 at p. 2) 

Mr. John Ainscough also noted that DOE 

should consider the opportunity cost of 

capital that may be diverted from other 

areas to pay for more expensive 

transformers. (J. Ainscough, No. 15 at p. 

1) NRDC stated that the 35 percent 

discount rate is unjustified, pointing out 

that this discount rate is evidence ofthe 

type of market failure that standards are 

supposed to address. (NRDC, No. 27 at 

p. 3) NRDC stated that an 8 percent 

discount rate is too high. NRDC noted 

that it has demonstrated in previous 

appliance rulemakings that market rates 

ofreturn on investment are in the range 

of 5-5.5 percent real, at best. (NRDC, 

No.5 at p. 4) NRDC stated that these are 

the highest rates that are defensible and 

recommended that the distribution of 

rates used for the analysis center around 

2-3 percent real to reflect reduced 

societal risk resulting from energy 

efficiency standards. NRDC also stated 

that it agrees with the Department that 

the actual cost of capital represents the 

appropriate discount rate for the LCC 

analysis. (NRDC, No. 25 at p. 2 and No. 

27 at p. 2) Cooper Power Systems 

commented that the discount rate 

selection method should be similar to 

that used by DOE to determine the 

present value of improved efficiency in 

other energy savings projects such as for 

refrigerators and motor efficiency. 

(Cooper Power Systems, No. 34 at p. 2) 

Lacking stakeholder consensus, the 

Department used the classic economic 

definition that discount rates are equal 

to the cost of capital. The cost of capital 

is a combination of debt interest rates 

and the cost of equity capital to the 

affected firms and industries. For each 

design line, the Department divided 

ownership into classes of potential 

customers. Table 11.10 shows the classes 

of owners and their percentages by 

design line. The Department determined 

from the Damodaran online investment 

survey (http://pages.stern.nyu.edu/ 

adamodarl) that each class of potential 

owners has a distribution of discount 

rates. The discount rate distribution for 

each design line analyzed in the LCC 

analysis is a weighted sample that 

combines estimated ownership 

percentages based on the 2001 shipment 

estimates and their respective discount 

rates. Table n.l0 also shows the mean 

real discount rates by ownership 

category used by DOE in the analysis. In 

addition, Table 11.10 shows the resultant 

weighted average discount rates for each 

design line. A more detailed description 

of the data sources is provided in 

Chapter 8 of the TSD. As highlighted in 

section IV.E, the Department seeks input 

from stakeholders on the 

appropriateness ofthese discount rates. 
Federal Register / Vol. 69, No. 145 / Thursday, July 29, 2004 / Proposed Rules

TABLE 11.10.-WEIGHTED AVERAGE DISCOUNT RATES BY DESIGN LINE AND OWNERSHIP CATEGORY

45401

Mean real discount rate Transformer ownership category

Weighted aver- Property Industrial Commercial Investor-owned Publicly owned Government

Design

li

age discount rate

t

owners companies companies utilities utilities offices

ne (percen )

4.35% 7.55% 7.46% 4.16% 4.31% 3.33%

Estimated ownership (%)

1 ........ 4.24 0.4 0.5 0.9 72.0 26.0 0.2

2........ 4.24 0.4 0.5 0.9 72.0 26.0 0.2

3 ........ 4.40 2.1 2.4 4.5 80.0 10.0 1.0

4........ 4.24 0.4 0.5 0.9 72.0 26.0 0.2

5........ 5.38 9.5 9.5 27.0 35.0 15.0 4.0

6........ 6.56 19.0 19.0 54.0 0.0 0.0 7.9

7........ 6.56 19.0 19.0 54.0 0.0 0.0 7.9

8........ 6.56 19.0 19.0 54.0 0.0 0.0 7.9

9........ 6.56 19.0 19.0 54.0 0.0 0.0 7.9

10...... 6.56 19.0 19.0 54.0 0.0 0.0 7.9

11 ...... 6.56 19.0 19.0 54.0 0.0 0.0 7.9

12...... 6.56 19.0 19.0 54.0 0.0 0.0 7.9

13...... 6.56 19.0 19.0 54.0 0.0 0.0 7.9

3. Payback Period

A more energy efficient device will

usually cost more to buy than a device

of standard energy efficiency. But the

more efficient device will usually cost

less to operate due to the reductions in

operating costs (i.e., lower energy bills).

The PBP is the time (usually expressed

in years) it takes to recover the

additional installed cost of the efficient

device through energy cost savings.

Payback analysis is a common

technique used to evaluate investment

decisions. Because the LCC analysis

uses distributions of inputs to represent

individual transformer purchases,

results such as PBPs are given in the

form of distributions.

The data inputs to the payback

calculation are the purchase expense,

otherwise known as the total installed

consumer cost or "first cost," and the

annual operating costs for each selected

design. The inputs to the purchase

expense are the equipment price and the

installation cost with appropriate

markups. The inputs to the operating

costs are the annual energy

consumption and the electricity price.

The payback calculation uses the same

inputs as the LCC analysis but since this

is a "simple" payback, the operating

cost is for the year the standard takes

effect, assumed here to be 2007.

4. Life-Cycle Cost and Payback Period

Results

The following 13 tables (Table II.11

through Table 11.23) present the findings

from the Department's LCC analysis. For

each evaluated design line and each

candidate standard level, the

Department presents the minimum

efficiency candidate standard level, the

percent of transformers that experience

positive (or zero ) LCC savings when

subject to the standard level, the mean

LCC savings, and the mean PBP. The

Department presents these findings to

facilitate stakeholder review of the LCC

analysis. The Department has not

selected any specific standard level for

any design line. Graphical illustrations

that provide a more comprehensive

report of the LCC findings are available

in Chapter 8 of the TSD. For each LCC

analysis, candidate standard level 1 is

equivalent to the efficiency level of

NEMA TP 1-2002.

In the paragraph preceding each of the

following 13 tables, the Department

provides the average efficiency and the

average manufacturer's selling price of

the baseline transformers selected

during the LCC analysis for each design

line's representative unit. This average

efficiency is the mean of the efficiencies

of all the transformers selected under

the baseline scenario. The Department

selected a range of transformer designs

according to customer A and B

evaluation combinations in the baseline

and candidate standard level scenarios.

Some units selected have high

efficiencies while others have low

efficiencies. For three of the thirteen

design lines (1, 3, and 5), the average

efficiency of the baseline transformers is

higher than the minimum efficiency

selected for candidate standard level 1.

While such a relationship might seem

inappropriate, the Department notes

that a direct comparison between the

baseline average efficiency and the

efficiency level chosen for any

candidate standard is not meaningful.

That is because the former value is an

average efficiency of those transformers

selected under baseline conditions

while the latter value is the minimum

efficiency for the selection of

transformer designs meeting a candidate

standard level.

Table 11.11 presents the summary of

the LCC and PBP analyses for the

representative unit from design line 1, a

50 kVA, liquid-immersed, single-phase,

pad-mounted transformer. For this unit,

the average efficiency of the baseline

transformers selected during the LCC

analysis was 98.91 percent and the

average manufacturer's selling price was

$1,580.

TABLE 11.11.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 1 REPRESENTATIVE UNIT

Candidate standard level

1 2 3 4 5

Minimum Efficiency (%) ..................................................................................... 98.90 99.10 99.30 99.40

Transformers having LCC Savings ? $0 (%) .................................................... 99.5 86.3 41.4 35.8

Mean LCC Savings ($) ...................................................................................... 134 158 -13 - 64

Mean Payback (Years) ...................................................................................... 6.3 14.5 25.1 23.3

99.58

13.1

-359

32.5

 EE-RM/STD-00-550 COMMENT 53.1

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45401 

TABLE 11.10.-WEIGHTED AVERAGE DISCOUNT RATES BY DESIGN LINE AND OWNERSHIP CATEGORY 

Mean real discount rate 

Weighted aver- Property 

Design age discount rate owners 

line (percent) 

4.35% 

1 ........ 4.24 0.4 

2 ........ 4.24 0.4 

3 ........ 4.40 2.1 

4 ........ 4.24 0.4 

5 ........ 5.38 9.5 

6 ........ 6.56 19.0 

7 ........ 6.56 19.0 

8 ........ 6.56 19.0 

9 ........ 6.56 19.0 

10 ...... 6.56 19.0 

11 ...... 6.56 19.0 

12 ...... 6.56 19.0 

13 ...... 6.56 19.0 

3. Payback Period 

A more energy efficient device will 

usually cost more to buy than a device 

of standard energy efficiency. But the 

more efficient device will usually cost 

less to operate due to the reductions in 

operating costs (i.e., lower energy bills). 

The PBP is the time (usually expressed 

in years) it takes to recover the 

additional installed cost of the efficient 

device through energy cost savings. 

Payback analysis is a common 

technique used to evaluate investment 

decisions. Because the LCC analysis 

uses distributions of inputs to represent 

individual transformer purchases, 

results such as PBPs are given in the 

form of distributions. 

The data inputs to the payback 

calculation are the purchase expense, 

otherwise known as the total installed 

consumer cost or "first cost," and the 

annual operating costs for each selected 

design. The inputs to the purchase 

expense are the equipment price and the 

installation cost with appropriate 

markups. The inputs to the operating 

costs are the annual energy 

consumption and the electricity price. 

The payback calculation uses the same 

inputs as the LCC analysis but since this 

is a "simple" payback, the operating 

cost is for the year the standard takes 

effect, assumed here to be 2007. 

Transformer ownership category 

Industrial Commercial Investor-owned Publicly owned Govemment 

companies companies utilities utilities offices 

7.55% 7.46% 4.16% 4.31% 3.33% 

Estimated ownership (%) 

0.5 0.9 

0.5 0.9 

2.4 4.5 

0.5 0.9 

9.5 27.0 

19.0 54.0 

19.0 54.0 

19.0 54.0 

19.0 54.0 

19.0 54.0 

19.0 54.0 

19.0 54.0 

19.0 54.0 

4. Life-Cycle Cost and Payback Period 

Results 

The following 13 tables (Table IU1 

through Table II.23) present the findings 

from the Department's LCC analysis. For 

each evaluated design line and each 

candidate standard level, the 

Department presents the minimum 

efficiency candidate standard level, the 

percent of transformers that experience 

positive (or zero) LCC savings when 

subject to the standard level, the mean 

LCC savings, and the mean PBP. The 

Department presents these findings to 

facilitate stakeholder review of the LCC 

analysis. The Department has not 

selected any specific standard level for 

any design line. Graphical illustrations 

that provide a more comprehensive 

report of the LCC findings are available 

in Chapter 8 of the TSD. For each LCC 

analysis, candidate standard level 1 is 

equivalent to the efficiency level of 

NEMA TP 1-2002. 

In the paragraph preceding each of the 

following 13 tables, the Department 

provides the average efficiency and the 

average manufacturer's selling price of 

the baseline transformers selected 

during the LCC analysis for each design 

line's representative unit. This average 

efficiency is the mean of the efficiencies 

of all the transformers selected under 

the baseline scenario. The Department 

72.0 26.0 0.2 

72.0 26.0 0.2 

80.0 10.0 1.0 

72.0 26.0 0.2 

35.0 15.0 4.0 

0.0 0.0 7.9 

0.0 0.0 7.9 

0.0 0.0 7.9 

0.0 0.0 7.9 

0.0 0.0 7.9 

0.0 0.0 7.9 

0.0 0.0 7.9 

0.0 0.0 7.9 

selected a range of transformer designs 

according to customer A and B 

evaluation combinations in the baseline 

and candidate standard level scenarios. 

Some units selected have high 

efficiencies while others have low 

efficiencies. For three of the thirteen 

design lines (1, 3, and 5), the average 

efficiency of the baseline transformers is 

higher than the minimum efficiency 

selected for candidate standard level 1. 

While such a relationship might seem 

inappropriate, the Department notes 

that a direct comparison between the 

baseline average efficiency and the 

efficiency level chosen for any 

candidate standard is not meaningful. 

That is because the former value is an 

average efficiency of those transformers 

selected under baseline conditions 

while the latter value is the minimum 

efficiency for the selection of 

transformer designs meeting a candidate 

standard level. 

Table II.ll presents the summary of 

the LCC and PBP analyses for the 

representative unit from design line 1, a 

50 kVA, liquid-immersed, single-phase, 

pad-mounted transformer. For this unit, 

the average efficiency of the baseline 

transformers selected during the LCC 

analysis was 98.91 percent and the 

average manufacturer's selling price was 

$1,580. 

TABLE 11.11.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 1 REPRESENTATIVE UNIT 

Candidate standard level 

2 3 4 5 

Minimum Efficiency (%) .................................................................................... . 98.90 99.10 99.30 99.40 99.58 

Transformers having LCC Savings;::: $0 (%) ................................................... . 99.5 86.3 41.4 35.8 13.1 

Mean LCC Savings ($) ..................................................................................... . 134 158 -13 -64 -359 

Mean Payback (Years) ..................................................................................... . 6.3 14.5 25.1 23.3 32.5 
45402 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

Table 11.12 presents the summary of pole-mounted transformer. For this unit, average manufacturer's selling price was

the LCC and PBP analyses for the the average efficiency of the baseline $950.

representative unit from design line 2, a transformers selected during the LCC

25 kVA, liquid-immersed, single-phase, analysis was 98.59 percent and the

TABLE 11.12.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 2 REPRESENTATIVE UNIT

Candidate standard level

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings ? $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

1

98.70

99.7

99

5.8

2

98.90

66.7

62

21.7

3

99.10

26.8

- 76

30.3

4

99.30

13.7

-216

29.7

5

99.47

2.8

-492

40.7

Table 11.13 presents the summary of distribution transformer. For this unit, average manufacturer's selling price was

the LCC and PBP analyses for the the average efficiency of the baseline $4,599.

representative unit from design line 3, a transformers selected during the LCC

500 kVA, liquid-immersed, single-phase analysis was 99.33 percent and the

TABLE 11 . 13.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 3 REPRESENTATIVE UNIT

Candidate standard level

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings > $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

1

99.30

96.5

884

8.2

2

99.40

97.5

1,606

8.3

3

99.60

70.3

1,168

16.9

4

99.70

68.9

1,838

18.1

5

99.75

52.1

1,292

23.6

Table 11.14 presents the summary of distribution transformer. For this unit, average manufacturer's selling price was

the LCC and PBP analyses for the the average efficiency of the baseline $3,577.

representative unit from design line 4, a transformers selected during the LCC

150 kVA, liquid-immersed, three-phase analysis was 98.86 percent and the

TABLE 11.14.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 4 REPRESENTATIVE UNIT

Candidate standard level

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings >_ $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

1

98.90

97.5

574

7.7

2

99.10

90.9

733

12.1

3

99.30

73.7

491

16.5

4

99.40

75.9

585

16.2

5

99.56

50.8

301

24.7

Table 11.15 presents the summary of distribution transformer. For this unit, average manufacturer's selling price was

the LCC and PBP analyses for the the average efficiency of the baseline $11,088.

representative unit from design line 5, a transformers selected during the LCC

1500 kVA, liquid-immersed, three-phase analysis was 99.35 percent and the

TABLE 11.15.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 5 REPRESENTATIVE UNIT

Candidate standard level

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings ? $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

1

99.30

97.8

4,174

6.2

2

99.40

97.2

6,617

6.7

3

99.50

80.2

7,451

13.4

4

99.60

78.5

7,268

13.4

5

99.66

64.4

6,838

17.7

Table 11.16 presents the summary of phase transformer. For this unit, the average manufacturer's selling price was

the LCC and PBP analyses for the average efficiency of the baseline $864.

representative unit from design line 6, a transformers selected during the LCC

25 kVA, low-voltage, dry-type, single- analysis was 95.36 percent and the

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45402 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

Table II.12 presents the summary of 

the Lee and PBP analyses for the 

representative unit from design line 2, a 

25 kVA, liquid-immersed, single-phase, 

pole-mounted transformer. For this unit, 

the average efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.59 percent and the 

average manufacturer's selling price was 

$950. 

TABLE 11.12.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN LINE 2 REPRESENTATIVE UNIT 

Minimum Efficiency (%) .................................................................................... . 98.70 

Transformers having LCC Savings <: $0 (%) .................................................. .. 99.7 

Mean LCC Savings ($) .................................................................................... .. 99 

Mean Payback (Years) .................................................................................... .. 5.8 

Table II.13 presents the summary of 

the Lee and PBP analyses for the 

representative unit from design line 3, a 

500 kVA, liquid-immersed, single-phase 

distribution transformer. For this unit, 

the average efficiency of the baseline 

transformers selected during the Lee 

analysis was 99.33 percent and the 

Candidate standard level 

2 3 4 5 

98.90 99.10 99.30 99.47 

66.7 26.8 13.7 2.8 

62 -76 -216 -492 

21.7 30.3 29.7 40.7 

average manufacturer's selling price was 

$4,599. 

TABLE 11.13.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN LINE 3 REPRESENTATIVE UNIT 

Minimum Efficiency (%) .................................................................................... . 99.30 

Transformers having LCC Savings <: $0 (%) .................................................. .. 96.5 

Mean LCC Savings ($) .................................................................................... .. 884 

Mean Payback (Years) .................................................................................... .. 8.2 

Table II.14 presents the summary of 

the Lee and PBP analyses for the 

representative unit from design line 4, a 

150 kVA, liquid-immersed, three-phase 

distribution transformer. For this unit, 

the average efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.86 percent and the 

Candidate standard level 

2 3 4 5 

99.40 99.60 99.70 99.75 

97.5 70.3 68.9 52.1 

1,606 1,168 1,838 1,292 

8.3 16.9 18.1 23.6 

average manufacturer's selling price was 

$3,577. 

TABLE 11.14.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN LINE 4 REPRESENTATIVE UNIT 

Minimum Efficiency (%) .................................................................................... . 98.90 

Transformers having LCC Savings <: $0 (%) .................................................. .. 97.5 

Mean LCC Savings ($) .................................................................................... .. 574 

Mean Payback (Years) .................................................................................... .. 7.7 

Table II.15 presents the summary of 

the Lee and PBP analyses for the 

representative unit from design line 5, a 

1500 kVA, liquid-immersed, three-phase 

distribution transformer. For this unit, 

the average efficiency of the baseline 

transformers selected during the Lee 

analysis was 99.35 percent and the 

Candidate standard level 

2 3 4 5 

99.10 99.30 99.40 99.56 

90.9 73.7 75.9 50.8 

733 491 585 301 

12.1 16.5 16.2 24.7 

average manufacturer's selling price was 

$11,088. 

TABLE 11.15.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN LINE 5 REPRESENTATIVE UNIT 

Minimum Efficiency (%) ................................................................................... .. 99.30 

Transformers having LCC Savings <: $0 (%) .................................................. .. 97.8 

Mean LCC Savings ($) .................................................................................... .. 4,174 

Mean Payback (Years) ..................................................................................... . 6.2 

Table II.16 presents the summary of 

the Lee and PBP analyses for the 

representative unit from design line 6, a 

25 kVA, low-voltage, dry-type, singlephase transformer. For this unit, the 

average efficiency of the baseline 

transformers selected during the Lee 

analysis was 95.36 percent and the 

Candidate standard level 

2 3 4 5 

99.40 99.50 99.60 99.66 

97.2 80.2 78.5 64.4 

6,617 7,451 7,268 6,838 

6.7 13.4 13.4 17.7 

average manufacturer's selling price was 

$864. 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

TABLE 11.16.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 6 REPRESENTATIVE UNIT

Candidate standard level

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings >_ $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

1

98.00

99.3

1,777

1.7

2

98.20

99.1

1,865

2.6

3

98.40

99.1

1,948

2.6

4

98.70

94.1

1,906

5.6

45403

5

98.79

92.8

1,867

6.7

Table 11.17 presents the summary of phase transformer. For this unit, the average manufacturer's selling price was

the LCC and PBP analyses for the average efficiency of the baseline $1,808.

representative unit from design line 7, a transformers selected during the LCC

75 kVA, low-voltage, dry-type, three- analysis was 96.43 percent and the

TABLE 11.17.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 7 REPRESENTATIVE UNIT

Candidate standard level

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings ? $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

1

98.00

100.0

3,156

0.6

2

98.30

99.0

3,588

2.6

3

98.60

98.4

3,927

3.5

4

98.90

88.8

3,910

7.1

5

99.09

77.5

3,799

10.8

Table 11.18 presents the summary of phase transformer. For this unit, the average manufacturer's selling price was

the LCC and PBP analyses for the average efficiency of the baseline $4,735.

representative unit from design line 8, a transformers selected during the LCC

300 kVA, low-voltage, dry-type, three- analysis was 97.79 percent and the

TABLE 11.18.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 8 REPRESENTATIVE UNIT

Candidate standard level

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings ? $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

1

98.60

99.8

6,761

1.0

2

98.80

97.8

7,035

2.9

3

99.00

96.6

7,899

4.5

4

99.20

92.1

8,941

6.5

5

99.27

89.4

8,712

7.4

Table 11.19 presents the summary of three-phase transformer with a 45 kV percent and the average manufacturer's

the LCC and PBP analyses for the BIL. For this unit, the average efficiency selling price was $6,084.

representative unit from design line 9, a of the baseline transformers selected

300 kVA, medium-voltage, dry-type, during the LCC analysis was 97.90

TABLE 11.19.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 9 REPRESENTATIVE UNIT

Candidate standard level

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings >_ $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

1

98.60

95.8

6,465

4.8

2

98.80

93.4

7,550

6.1

3

99.00

95.2

8,536

5.7

4

99.20

84.6

8,942

8.9

5

99.31

70.0

7,838

13.1

Table 11.20 presents the summary of three-phase transformer with a 45 kV percent and the average manufacturer's

the LCC and PBP analyses for the BIL. For this unit, the average efficiency selling price was $22,473.

representative unit from design line 10, of the baseline transformers selected

a 1500 kVA, medium-voltage, dry-type, during the LCC analysis was 98.63

 EE-RM/STD-00-550 COMMENT 53.1

Federal Register/Vol. 69, No. 14S/Thursday, July 29, 2004/Proposed Rules 45403 

TABLE 11.16.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN liNE 6 REPRESENTATIVE UNIT 

Minimum Efficiency (%) .................................................................................... . 98.00 

Transformers having LCC Savings ~ $0 (%) ................................................... . 99.3 

Mean LCC Savings ($) .................................................................................... .. 1,777 

Mean Payback (Years) ..................................................................................... . 1.7 

Table II.17 presents the summary of 

the Lee and PEP analyses for the 

representative unit from design line 7, a 

75 kVA, low-voltage, dry-type, threephase transformer. For this unit, the 

average efficiency of the baseline 

transformers selected during the Lee 

analysis was 96.43 percent and the 

Candidate standard level 

2 3 4 5 

98.20 98.40 98.70 98.79 

99.1 99.1 94.1 92.8 

1,865 1,948 1,906 1,867 

2.6 2.6 5.6 6.7 

average manufacturer's selling price was 

$1,808. 

TABLE 11.17.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN liNE 7 REPRESENTATIVE UNIT 

Minimum Efficiency (%) .................................................................................... . 98.00 

Transformers having LCC Savings ~ $0 (%) .................................................. .. 100.0 

Mean LCC Savings ($) .................................................................................... .. 3,156 

Mean Payback (Years) ..................................................................................... . 0.6 

Table 1l.18 presents the summary of 

the Lee and PEP analyses for the 

representative unit from design line 8, a 

300 kV A, low-voltage, dry-type, threephase transformer. For this unit, the 

average efficiency of the baseline 

transformers selected during the Lee 

analysis was 97.79 percent and the 

Candidate standard level 

2 3 4 5 

98.30 98.60 98.90 99.09 

99.0 98.4 88.8 77.5 

3,588 3,927 3,910 3,799 

2.6 3.5 7.1 10.8 

average manufacturer's selling price was 

$4,735. 

TABLE 11.18.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN liNE 8 REPRESENTATIVE UNIT 

Minimum Efficiency (%) .................................................................................... . 98.60 

Transformers having LCC Savings ~ $0 (%) .................................................. .. 99.8 

Mean LCC Savings ($) ..................................................................................... . 6,761 

Mean Payback (Years) ..................................................................................... . 1.0 

Table II.19 presents the summary of 

the Lee and PEP analyses for the 

representative unit from design line 9, a 

300 kVA, medium-voltage, dry-type, 

three-phase transformer with a 45 kV 

ElL. For this unit, the average efficiency 

of the baseline transformers selected 

during the Lee analysis was 97.90 

Candidate standard level 

2 3 4 5 

98.80 99.00 99.20 99.27 

97.8 96.6 92.1 89.4 

7,035 7,899 8,941 8,712 

2.9 4.5 6.5 7.4 

percent and the average manufacturer's 

selling price was $6,084. 

TABLE 11.19.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN liNE 9 REPRESENTATIVE UNIT 

Minimum Efficiency (%) .................................................................................... . 98.60 

Transformers having LCC Savings ~ $0 (%) .................................................. .. 95.8 

Mean LCC Savings ($) .................................................................................... .. 6,465 

Mean Payback (Years) .................................................................................... .. 4.8 

Table II.20 presents the summary of 

the Lee and PEP analyses for the 

representative unit from design line 10, 

a 1500 kVA, medium-voltage, dry-type, 

three-phase transformer with a 45 kV 

ElL. For this unit, the average efficiency 

of the baseline transformers selected 

during the Lee analysis was 98.63 

Candidate standard level 

2 3 4 5 

98.80 99.00 99.20 99.31 

93.4 95.2 84.6 70.0 

7,550 8,536 8,942 7,838 

6.1 5.7 8.9 13.1 

percent and the average manufacturer's 

selling price was $22,473. 
45404 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

TABLE 11.20.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 10 REPRESENTATIVE UNIT

Candidate standard level

2

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings >_ $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

Table 11.21 presents the summary of

the LCC and PBP analyses for the

representative unit from design line 11,

a 300 kVA, medium-voltage, dry-type,

99.10

89.9

14,458

8.5

99.20

90.5

16,130

8.5

3

99.30

90.0

18,050

8.9

4

99.40

72.1

15,594

13.9

5

99.44

64.5

13,704

15.6

three-phase transformer with a 95 kV

BIL. For this unit, the average efficiency

of the baseline transformers selected

during the LCC analysis was 97.77

TABLE 11.21.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 11 REPRESENTATIVE UNIT

Candidate standard level

2

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings ? $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years ) ......................................................................................

Table 11.22 presents the summary of

the LCC and PBP analyses for the

representative unit from design line 12,

a 1500 kVA, medium-voltage, dry-type,

98.50

96.4

4,473

5.8

three-phase transformer with a 95 kV

BIL. For this unit, the average efficiency

of the baseline transformers selected

during the LCC analysis was 98.67

TABLE 11.22.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 12 REPRESENTATIVE UNIT

Candidate standard level

2

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings >_ $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

Table 11.23 presents the summary of

the LCC and PBP analyses for the

representative unit from design line 13,

a 2000 kVA, medium-voltage , dry-type,

99.00

91.5

8,369

8.0

percent and the average manufacturer's

selling price was $10,142.

98.70

94.9

5,350

6.7

3

98.90

87.4

5,734

9.3

4

99.00

75.6

5,136

12.5

5

99.10

68.0

4,666

14.3

percent and the average manufacturer's

selling price was $26,542.

99.10

85.8

12,318

9.6

3

99.30

84.6

15,390

10.7

4

99.40

71.0

14,365

14.2

5

99.45

59.6

11,341

17.1

three-phase transformer with a 125 kV

BIL. For this unit, the average efficiency

of the baseline transformers selected

during the LCC analysis was 98.73

percent and the average manufacturer's

selling price was $37,082.

TABLE 11.23.-SUMMARY OF LCC & PBP RESULTS FOR THE DESIGN LINE 13 REPRESENTATIVE UNIT

Candidate standard level

2

Minimum Efficiency (%) .....................................................................................

Transformers having LCC Savings ? $0 (%) ....................................................

Mean LCC Savings ($) ......................................................................................

Mean Payback (Years) ......................................................................................

G. Shipments Analysis

This section presents the

Department's shipments analysis, which

is a key input into the national impact

analysis (section II.H). Additional detail

on the shipments analysis can be found

in Chapter 9 of the TSD.

99.00

92.0

11,691

6.7

1. Shipments Model

The shipments model combines the

shipments estimates for 2001,

transformer quantity indices from the

U.S. Bureau of Economic Analysis

(BEA), electricity market shares from

DOE's Energy Information

Administration (EIA), and equipment

99.10

90.6

16,119

8.5

3

99.30

76.9

16,685

12.7

4

99.40

77.6

19,706

12.7

5

99.45

44.9

7,593

20.3

price estimates from the LCC to project

transformer shipments. The shipments

model produces both a backcast (an

estimate backwards in time) and a

forecast of total shipments. The

shipments forecast and a retirement

function are used to calculate in-service

transformer age distribution, and

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

45404 Federal Register I Vol. 69, No. 145 I Thursday, July 29, 2004/Proposed Rules 

TABLE 11.20.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN LINE 10 REPRESENTATIVE UNIT 

Candidate standard level 

2 3 4 5 

Minimum Efficiency (%) .................................................................................... . 99.10 99.20 99.30 99.40 99.44 

Transformers having LCC Savings ~ $0 (%) .................................................. .. 89.9 90.5 90.0 72.1 64.5 

Mean LCC Savings ($) .................................................................................... .. 14,458 16,130 18,050 15,594 13,704 

Mean Payback (Years) .................................................................................... .. 8.5 

Table II.21 presents the summary of 

the LCC and PBP analyses for the 

representative unit from design line 11, 

a 300 kVA, medium-voltage, dry-type, 

three-phase transformer with a 95 kV 

BIL. For this unit, the average efficiency 

of the baseline transformers selected 

during the LCC analysis was 97.77 

8.5 8.9 13.9 15.6 

percent and the average manufacturer's 

selling price was $10,142. 

TABLE 11.21.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN LINE 11 REPRESENTATIVE UNIT 

Minimum Efficiency (%) .................................................................................... . 98.50 

Transformers having LCC Savings ~ $0 (%) .................................................. .. 96.4 

Mean LCC Savings ($) .................................................................................... .. 4,473 

Mean Payback (Years) .................................................................................... .. 5.8 

Table 11.22 presents the summary of 

the LCC and PBP analyses for the 

representative unit from design line 12, 

a 1500 kVA, medium-voltage, dry-type, 

three-phase transformer with a 95 kV 

BlL. For this unit, the average efficiency 

of the baseline transformers selected 

during the LCC analysis was 98.67 

Candidate standard level 

2 3 4 5 

98.70 98.90 99.00 99.10 

94.9 87.4 75.6 68.0 

5,350 5,734 5,136 4,666 

6.7 9.3 12.5 14.3 

percent and the average manufacturer's 

selling price was $26,542. 

TABLE 11.22.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN LINE 12 REPRESENTATIVE UNIT 

Candidate standard level 

2 3 4 5 

Minimum Efficiency (%) ................................................................................... .. 99.00 99.10 99.30 99.40 99.45 

Transformers having LCC Savings ~ $0 (%) .................................................. .. 91.5 85.8 84.6 71.0 59.6 

Mean LCC Savings ($) .................................................................................... .. 8,369 12,318 15,390 14,365 11,341 

Mean Payback (Years) ..................................................................................... . 8.0 

Table II.23 presents the summary of 

the LCC and PBP analyses for the 

representative unit from design line 13, 

a 2000 kVA, medium-voltage, dry-type, 

three-phase transformer with a 125 kV 

BlL. For this unit, the average efficiency 

of the baseline transformers selected 

during the LCC analysis was 98.73 

9.6 10.7 14.2 17.1 

percent and the average manufacturer's 

selling price was $37,082. 

TABLE 11.23.-SUMMARY OF Lee & PBP RESULTS FOR THE DESIGN LINE 13 REPRESENTATIVE UNIT 

Minimum Efficiency (%) .................................................................................... . 99.00 

Transformers having LCC Savings ~ $0 (%) .................................................. .. 92.0 

Mean LCC Savings ($) .................................................................................... .. 11,691 

Mean Payback (Years) ..................................................................................... . 6.7 

C. Shipments Analysis 

This section presents the 

Department's shipments analysis, which 

is a key input into the national impact 

analysis (section II.H). Additional detail 

on the shipments analysis can be found 

in Chapter 9 of the TSD. 

1. Shipments Model 

The shipments model combines the 

shipments estimates for 2001, 

transformer quantity indices from the 

U.S. Bureau of Economic Analysis 

(BEA), electricity market shares from 

DOE's Energy Information 

Administration (ElA), and equipment 

Candidate standard level 

2 3 4 5 

99.10 99.30 99.40 99.45 

90.6 76.9 77.6 44.9 

16,119 16,685 19,706 7,593 

8.5 12.7 12.7 20.3 

price estimates from the Lec to project 

transformer shipments. The shipments 

model produces both a backcast (an 

estimate backwards in time) and a 

forecast oftotal shipments. The 

shipments forecast and a retirement 

function are used to calculate in-service 

transformer age distribution, and 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

estimate the proportion of transformers

in-service impacted by candidate

standard levels and transformer

retirements. The Department determines

the number of transformers

manufactured to satisfy new electrical

capacity by subtracting transformer

retirements from total shipments.

Distribution transformer shipment

estimates are also used as an input to

the MIA. That analysis, which DOE will

undertake after the ANOPR is

published, will estimate the impacts of

potential efficiency standards on

manufacturers. The Department will

report the findings of the MIA in the

NOPR.

The Department considered several

approaches to developing an estimate of

the shipments of distribution

transformers in 2001. Manufacturers

consider annual shipment information

extremely sensitive, and several

manufacturers who met with the

Department in early 2002 indicated they

would not be able to provide this data,

even under a confidentiality agreement

with one of the Department's

contractors. Furthermore, the

Department recognizes that there are

more than 100 manufacturers supplying

distribution transformers to the U.S.

market. It would be difficult to prepare

an estimate on a company-by-company

basis.

To resolve this impasse for this

specific data gap, the Department

contracted a third-party, HVOLT, only

to prepare a shipments estimate. This

contractor developed an estimate of

distribution transformer shipments in

45405

2001 by constructing a market

participation matrix incorporating

manufacturers and their product lines.

HVOLT then populated this matrix

based on its knowledge of the industry

and a limited number of confidential

interviews with key manufacturers and

users. These estimates were rolled-up

and then given to the Department as

national aggregate shipment totals for

each of the 115 kVA ratings (see Tables

9.3.2 through 9.3.4 in TSD Chapter 9).

Table 11.24 presents the shipment

estimates in both units shipped and

megavolt-amperes (MVA) shipped, and

the approximate value of these

shipments, showing that the

distribution transformer industry totaled

about $1.6 billion dollars in 2001 (2001

dollars).

TABLE 11.24.-NATIONAL DISTRIBUTION TRANSFORMER SHIPMENT ESTIMATES FOR 2001

Distribution transformer product class Units shipped MVA capacity

shipped

Shipment

value

($million)

1. Liquid-immersed , medium-voltage , single-phase .......................................................................... 977,388 36,633 698.8

2. Liquid-immersed , medium-voltage , three-phase ........................................................................... 79,367 42,887 540.4

3. Dry-type, low-voltage, single-phase .............................................................................................. 23,324 983 17.8

4. Dry-type, low-voltage, three-phase ............................................................................................... 290,818 21,909 235.0

5. Dry-type, medium-voltage, single-phase, 20-45 kV BIL ............................................................... 119 18 0.5

6. Dry-type, medium-voltage, three-phase , 20-45 kV BIL ................................................................ 650 776 13.5

7. Dry-type, medium-voltage, single-phase, 46-95 kV BIL ............................................................... 121 22 0.6

8. Dry-type, medium-voltage, three-phase , 46-95 kV BIL ................................................................ 2,371 3,913 68.1

9. Dry-type, medium-voltage, single-phase , >-96 kV BIL ................................................................... 20 4 0.1

10. Dry-type, medium-voltage, three-phase , >-96 kV BIL .................................................................. 187 367 6.4

Total ............................................................................................................................................ 1,374,366 107,512 1,581.2

The Department used the forecasts of

shipments for the base case and the

standards case to provide an estimate of

the annual sales and number of

transformers in-service in any given

year during the forecast period. The

estimate includes the age distribution of

transformers for each transformer type

(classified according to product classes).

The Department used annual

transformer sales to calculate equipment

costs for the NPV and the age

distribution of the transformers inservice to calculate the energy use for

the NES. The Department chose an

accounting model method to prepare

shipment scenarios for the base case and

the candidate standard level cases. The

model keeps track of the aging and

replacement of transformer capacity

given a projection of future transformer

sales growth.

Shipments are organized into two

categories: replacements and new

capacity. Replacements occur when old

transformers break down, corrode, are

struck by lightning, or otherwise need to

be replaced. New capacity purchases

occur due to increases in electricity use

that may be driven by increasing

population, increasing commercial and

industrial activity, or growth in

electricity distribution systems. The

model starts with an estimate of the

national growth in cumulative

transformer capacity to estimate total

shipments. The model then divides the

total shipments into liquid-immersed

and dry-type transformers using their

respective market shares estimated from

electricity consumption data. The

liquid-immersed and dry-type

transformers are further divided into

their respective product classes using

estimates of the relative market share for

different design and size categories.

Seven modeling steps are performed as

follows:

• In the data collection step, the

Department acquires and processes

information on transformer shipments.

• The construction of an aggregate

shipments backcast uses shipments and

electricity consumption data to provide

an estimate of historical total annual

capacity shipped.

• The construction of an aggregate

shipments forecast applies a shipments

growth rate to provide a base case

annual-shipments estimate for the

future.

• The liquid-immersed and dry-type

market share estimate divides the total

capacity shipped into liquid-immersed

and dry-type transformers.

• The modeling of the purchase price

elasticity provides an estimate of how

higher purchase prices due to a

candidate standard level can impact the

future capacity shipped.

• The accounting of transformer sales

and quantity in-service uses the

shipments estimates and a retirement

function to derive an annual age

distribution of transformers in-service.

• A final consistency check confirms

that the estimates of the shipments

model are consistent with available data

on utility transformer purchases and

replacements.

The following section describes the

inputs to the shipments model at

different stages of the calculation. The

Department welcomes suggestions from

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45405 

estimate the proportion of transformers 

in-service impacted by candidate 

standard levels and transformer 

retirements. The Department determines 

the number of transformers 

manufactured to satisfy new electrical 

capacity by subtracting transformer 

retirements from total shipments. 

Distribution transformer shipment 

estimates are also used as an input to 

the MIA. That analysis, which DOE will 

undertake after the ANOPR is 

published, will estimate the impacts of 

potential efficiency standards on 

manufacturers. The Department will 

report the findings of the MIA in the 

NOPR. 

The Department considered several 

approaches to developing an estimate of 

the shipments of distribution 

transformers in 2001. Manufacturers 

consider annual shipment information 

extremely sensitive, and several 

manufacturers who met with the 

Department in early 2002 indicated they 

would not be able to provide this data, 

even under a confidentiality agreement 

with one of the Department's 

contractors. Furthermore, the 

Department recognizes that there are 

more than 100 manufacturers supplying 

distribution transformers to the U.S. 

market. It would be difficult to prepare 

an estimate on a company-by-company 

basis. 

To resolve this impasse for this 

specific data gap, the Department 

contracted a third-party, HVOLT, only 

to prepare a shipments estimate. This 

contractor developed an estimate of 

distribution transformer shipments in 

2001 by constructing a market 

participation matrix incorporating 

manufacturers and their product lines. 

HVOL T then populated this matrix 

based on its knowledge of the industry 

and a limited number of confidential 

interviews with key manufacturers and 

users. These estimates were rolled-up 

and then given to the Department as 

national aggregate shipment totals for 

each of the 115 kVA ratings (see Tables 

9.3.2 through 9.3.4 in TSD Chapter 9). 

Table II.24 presents the shipment 

estimates in both units shipped and 

megavolt-amperes (MV A) shipped, and 

the approximate value of these 

shipments, showing that the 

distribution transformer industry totaled 

about $1.6 billion dollars in 2001 (2001 

dollars). 

TABLE 11.24.-NATIONAL DISTRIBUTION TRANSFORMER SHIPMENT ESTIMATES FOR 2001 

Distribution transformer product class 

1. Liquid-immersed, medium-voltage, single-phase ........................................................................ .. 

2. Liquid-immersed, medium-voltage, three-phase .......................................................................... . 

3. Dry-type, low-voltage, single-phase ............................................................................................. . 

4. Dry-type, low-voltage, three-phase .............................................................................................. . 

5. Dry-type, medium-voltage, single-phase, 20-45 kV BIL .............................................................. . 

6. Dry-type, medium-voltage, three-phase, 20-45 kV BIL .............................................................. .. 

7. Dry-type, medium-voltage, single-phase, 46-95 kV BIL .............................................................. . 

8. Dry-type, medium-voltage, three-phase, 46-95 kV BIL .............................................................. .. 

9. Dry-type, medium-voltage, single-phase, 296 kV BIL .................................................................. . 

10. Dry-type, medium-voltage, three-phase, 296 kV BIL ................................................................ .. 

Total ........................................................................................................................................... . 

The Department used the forecasts of 

shipments for the base case and the 

standards case to provide an estimate of 

the annual sales and number of 

transformers in-service in any given 

year during the forecast period. The 

estimate includes the age distribution of 

transformers for each transformer type 

(classified according to product classes). 

The Department used annual 

transformer sales to calculate equipment 

costs for the NPV and the age 

distribution of the transformers inservice to calculate the energy use for 

the NES. The Department chose an 

accounting model method to prepare 

shipment scenarios for the base case and 

the candidate standard level cases. The 

model keeps track of the aging and 

replacement of transformer capacity 

given a projection of future transformer 

sales growth. 

Shipments are organized into two 

categories: replacements and new 

capacity. Replacements occur when old 

transformers break down, corrode, are 

struck by lightning, or otherwise need to 

be replaced. New capacity purchases 

occur due to increases in electricity use 

that may be driven by increasing 

population, increasing commercial and 

industrial activity, or growth in 

electricity distribution systems. The 

model starts with an estimate of the 

national growth in cumulative 

transformer capacity to estimate total 

shipments. The model then divides the 

total shipments into liquid-immersed 

and dry-type transformers using their 

respective market shares estimated from 

electricity consumption data. The 

liquid-immersed and dry-type 

transformers are further divided into 

their respective product classes using 

estimates of the relative market share for 

different design and size categories. 

Seven modeling steps are performed as 

follows: 

• In the data collection step, the 

Department acquires and processes 

information on transformer shipments. 

.. The construction of an aggregate 

shipments backcast uses shipments and 

electricity consumption data to provide 

an estimate of historical total annual 

capacity shipped. 

MV A capacity Shipment 

Units shipped value shipped ($million) 

977,388 36,633 698.8 

79,367 42,887 540.4 

23,324 983 17.8 

290,818 21,909 235.0 

119 18 0.5 

650 776 13.5 

121 22 0.6 

2,371 3,913 68.1 

20 4 0.1 

187 367 6.4 

1,374,366 107,512 1,581.2 

• The construction of an aggregate 

shipments forecast applies a shipments 

growth rate to provide a base case 

annual-shipments estimate for the 

future. 

• The liquid-immersed and dry-type 

market share estimate divides the total 

capacity shipped into liquid-immersed 

and dry-type transformers. 

• The modeling of the purchase price 

elasticity provides an estimate of how 

higher purchase prices due to a 

candidate standard level can impact the 

future capacity shipped. 

• The accounting of transformer sales 

and quantity in-service uses the 

shipments estimates and a retirement 

function to derive an annual age 

distribution of transformers in-service. 

.. A final consistency check confirms 

that the estimates of the shipments 

model are consistent with available data 

on utility transformer purchases and 

replacements. 

The following section describes the 

inputs to the shipments model at 

different stages of the calculation. The 

Department welcomes suggestions from 
45406 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

stakeholders for improving the data

inputs to the model.

2. Shipments Model Inputs

The shipments model inputs

correspond closely to the steps of the

shipments calculation described in the

previous section. Some inputs come

from outside the shipments estimates of the age distribution of

calculations, while other inputs for later transformers in-service.

stages of the calculation are Table 11.25 presents a summary of

intermediate results calculated from these shipments model inputs. Chapter

earlier inputs. The final outputs of the 9 of the TSD contains a detailed

shipments calculation are the annual description of all the shipments model

shipments estimates and the annual inputs.

TABLE 11.25.-SUMMARY OF SHIPMENTS MODEL INPUTS

Input

Shipments data ..................................................................

Shipments backcast ...........................................................

Shipments forecast ............................................................

Dry-type/liquid-immersed market shares ...........................

Regular replacement market ..............................................

Elasticities . .........................................................................

The Department determined the price

elasticities for liquid-immersed

transformers by calibrating a model

employing a standard econometric logit

equation, fit to FERC Form No. 1 data.

The fit resulted in a price elasticity of

- 0.04, which the Department used as

the "medium" scenario . For a "high"

sensitivity to price change scenario,

DOE used an elasticity of - 0.20. The

Description

Third party expert (HVOLT) for the year 2001.

For years 1977-2000: Used BEA's manufacturing data for distribution transformers.

Source: http://www. bea.doc .gov/bea/pn/ndn03O4 . zip. For years 1950-1976: Based

on EIA's electricity sales data. Source : http://www.eia .doe.gov/emeu/aer/txt/

stb0805.xIs.

Years 2002-2035: Based on AEO 2003.

Based on EIA's electricity sales data and AEO 2003.

Based on a survival function constructed from a Weibull distribution function normalized to produce a 32-year mean lifetime. Source : ORNL 6804/R1, The Feasibility

of Replacing or Upgrading Utility Distribution Transformers During Routine Maintenance, page D-1.

For liquid-immersed transformers:

® Low: 0.00

® Medium: -0.04

• High: -0.20

For dry-type transformers:

® 0.00

"low" scenario used zero elasticity or

no impact in purchase decisions from a

price change.

Total shipments depend on

assumptions regarding the lifetime of a

distribution transformer and the growth

in new electricity demand. For

consistency with the LCC, the

Department used the same 32-year

average lifetime.

3. Shipments Model Results

The main output of the shipments

model is the total capacity of

distribution transformers shipped in

each year from 2007 through 2035. Total

shipments for all CSLs for liquidimmersed and dry-type distribution

transformers are shown in Table 11.26.

TABLE 11.26.-CUMULATIVE TRANSFORMER SHIPMENTS BETWEEN 2007-2035 BY CANDIDATE STANDARD LEVEL

Distribution transformers

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

Dry-type ............................................................................................................................

The biggest factor that influences the

size of the potential standards-induced

change in shipments is the actual

equipment price increase due to

standards. The Department assumed

price impacts only for liquid-immersed

transformers. If price increases are large,

the shipments volume decreases almost

proportionally to the price increase, but

because the price elasticity of liquidimmersed transformers is less than one,

price increases result in increased gross

sales dollar volume to the transformer

manufacturer. The Department will

examine the net financial impact of

these opposing effects in more detail in

the MIA.

Transformer capacity shipments in billion k

Base

case

3.06

1.23

CSL 1

3.06

1.23

A

CSL 5

3.01

1.23

H. National Impact Analysis

This section presents the

methodology and structure the

Department used to implement the

national impact analysis. This analysis

assessed future NES from candidate

transformer standards as well as the

national economic impacts using the

NPV metric. Additional detail is found

in Chapter 10 of the TSD.

The NES is the cumulative

incremental energy savings from a

transformer efficiency standard relative

to a base case of no national standard

over a forecast period that ends in the

year 2035. The Department calculated

the NES for each candidate standard

level in units of quadrillion (quads) Btus

(British thermal units) for standards

assumed to be implemented in the year

2007. The NES calculation started with

transformer shipments and quantity inservice from the shipments model. The

Department calculated total energy use

by transformers in-service using

estimates of transformer losses from the

LCC analysis, for each year for both a

base case and a candidate standards

case.

Over time, in the standards case, more

efficient transformers gradually replace

less efficient ones. Thus, the energy per

unit capacity used by transformers inservice gradually decreases in the

CSL 2

3.05

1.23

CSL 3

3.04

1.23

CSL 4

3.03

1.23

 EE-RM/STD-00-550 COMMENT 53.1

45406 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

stakeholders for improving the data 

inputs to the model. 

2. Shipments Model Inputs 

The shipments model inputs 

correspond closely to the steps of the 

shipments calculation described in the 

previous section. Some inputs come 

from outside the shipments 

calculations, while other inputs for later 

stages of the calculation are 

intermediate results calculated from 

earlier inputs. The final outputs of the 

shipments calculation are the annual 

shipments estimates and the annual 

estimates of the age distribution of 

transformers in-service. 

Table II.25 presents a summary of 

these shipments model inputs. Chapter 

9 of the TSD contains a detailed 

description of all the shipments model 

inputs. 

TABLE 11.25.-SUMMARY OF SHIPMENTS MODEL INPUTS 

Input Description 

Shipments data .................................................................. Third party expert (HVOL T) for the year 2001. 

Shipments backcast ........................................................... For years 1977-2000: Used BEA's manufacturing data for distribution transformers. 

Source: http://www.bea.doc.gov/bea/pn/ndn0304.zip. For years 1950-1976: Based 

on EIA's electricity sales data. Source: http://www.eia.doe.gov/emeu/aer/txt/ 

stb0805.xls. 

Shipments forecast ............................................................ Years 2002-2035: Based on AEO 2003. 

Dry-type/liquid-immersed market shares ........................... Based on EIA's electricity sales data and AEO 2003. 

Regular replacement market .............................................. Based on a survival function constructed from a Wei bull distribution function normalized to produce a 32-year mean lifetime. Source: ORNL 6804/R1, The Feasibility 

of Replacing or Upgrading Utility Distribution Transformers During Routine Maintenance, page D-1. 

Elasticities ......... ................................................................. For liquid-immersed transformers: 

The Department determined the price 

elasticities for liquid-immersed 

transformers by calibrating a model 

employing a standard econometric logit 

equation, fit to FERC Form No.1 data. 

The fit resulted in a price elasticity of 

0.04, which the Department used as 

the "medium" scenario. For a "high" 

sensitivity to price change scenario, 

DOE used an elasticity of - 0.20. The 

• Low: 0.00 

• Medium: - 0.04 

• High: - 0.20 

For dry-type transformers: 

• 0.00 

"low" scenario used zero elasticity or 

no impact in purchase decisions from a 

price change. 

Total shipments depend on 

assumptions regarding the lifetime of a 

distribution transformer and the growth 

in new electricity demand. For 

consistency with the LCC, the 

Department used the same 32-year 

average lifetime. 

3. Shipments Model Results 

The main output of the shipments 

model is the total capacity of 

distribution transformers shipped in 

each year from 2007 through 2035. Total 

shipments for all CSLs for liquidimmersed and dry-type distribution 

transformers are shown in Table II.26. 

TABLE II.26.-CUMULATIVE TRANSFORMER SHIPMENTS BETWEEN 2007-2035 BY CANDIDATE STANDARD LEVEL 

Transformer capacity shipments in billion kVA 

Distribution transformers Base 

case 

Liquid-immersed ............................................................................................................. .. 3.06 

Dry-type ........................................................................................................................... . 1.23 

The biggest factor that influences the 

size of the potential standards-induced 

change in shipments is the actual 

equipment price increase due to 

standards. The Department assumed 

price impacts only for liquid-immersed 

transformers. If price increases are large, 

the shipments volume decreases almost 

proportionally to the price increase, but 

because the price elasticity of liquidimmersed transformers is less than one, 

price increases result in increased gross 

sales dollar volume to the transformer 

manufacturer. The Department will 

examine the net financial impact of 

these opposing effects in more detail in 

the MIA. 

H. National Impact Analysis 

This section presents the 

methodology and structure the 

Department used to implement the 

national impact analysis. This analysis 

assessed future NES from candidate 

transformer standards as well as the 

national economic impacts using the 

NPV metric. Additional detail is found 

in Chapter 10 of the TSD. 

The NES is the cumulative 

incremental energy savings from a 

transformer efficiency standard relative 

to a base case of no national standard 

over a forecast period that ends in the 

year 2035. The Department calculated 

the NES for each candidate standard 

CSL1 CSL 2 CSL 3 CSL 4 CSL 5 

3.06 3.05 3.04 3.03 3.01 

1.23 1.23 1.23 1.23 1.23 

level in units of quadrillion (quads) Btus 

(British thermal units) for standards 

assumed to be implemented in the year 

2007. The NES calculation started with 

transformer shipments and quantity inservice from the shipments model. The 

Department calculated total energy use 

by transformers in-service using 

estimates of transformer losses from the 

Lec analysis, for each year for both a 

base case and a candidate standards 

case. 

Over time, in the standards case, more 

efficient transformers gradually replace 

less efficient ones. Thus, the energy per 

unit capacity used by transformers inservice gradually decreases in the 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

standards case relative to the base case.

The Department converted the site

energy used by the transformers into the

amount of energy consumed at the

source of electricity generation (the

source energy) with a site-to-source

conversion factor. The site-to-source

factor accounts for transmission,

distribution, and generation losses. For

each year analyzed, the difference in

source energy use between the base case

and standard scenario is the annual

energy savings. The Department

summed the undiscounted annual

energy savings from 2007 through 2035

to calculate the total NES for the

forecast period. The NES analysis which

will accompany the NOPR will include

both undiscounted and discounted

values for future energy savings to

account for their timing.

The NPV is the net present value of

the incremental economic impacts of a

candidate standard levels. The

Department calculated the NPV in a way

that is similar to the NES, except that

incremental costs are estimated instead

of energy, and the net costs are

discounted rather than calculated as an

undiscounted sum. Like the NES, the

NPV calculation started with

transformer shipments and quantity inservice from the shipments model.

Using estimates of transformer installed

costs, losses, and electricity costs from

the LCC analysis, the Department

calculated the national expenditures for

installed transformer purchases and the

corresponding operating costs of the

transformers in-service for each year for

both a base case and standards case.

Over time, in the standards case,

transformers that are both more

expensive and more efficient gradually

replace less efficient transformers. Thus,

the operating cost per unit capacity used

by the transformers in-service gradually

decreases in the standards case relative

to the base case, while the equipment

costs increase. The Department

discounted purchases and expenses and

operating costs for transformers using a

national average discount factor as

described in Chapter 10 of the TSD. The

Department calculated the NPV impact

of transformers that will be bought

between 2007 and 2035.

To make the analysis more accessible

to all stakeholders, the Department

prepared a national impact spreadsheet

model (available on the Department's

website) in Microsoft Excel to execute

the calculations outlined above. The

spreadsheet calculates capacity and

operating cost savings associated with

each of the candidate standard levels.

The NES analysis considers cumulative

energy savings through the year 2035,

while the NPV considers capacity and

operating cost savings through the year

2070 3 for transformers bought on or

before 2035. By taking the difference

between the base case and candidate

standard levels, summing, and

discounting the annual results, the

spreadsheet calculates an NPV for each

candidate standard level relative to the

base case.

1. Method

Both calculations start by using the

estimate of shipments and quantity inservice that resulted from the shipments

model (section II.G) and then proceed

with the NES and NPV calculations. Key

inputs from the LCC analysis are the

average rated losses for both no-load

and load losses, and the equipment cost

of transformers, including installation.

The losses and the equipment costs then

go through a transformer size and

product class adjustment that converts

the data from representative design lines

to average product class information.

Additional inputs regarding average and

peak losses-including root mean

square (RMS) loading, peak loading, and

peak responsibility factor-allow a

calculation of losses from rated losses at

rated loading. At this point, the

information flow for the NES and NPV

calculation splits into two paths.

On one path, the NES calculation

sums the actual losses and the affected

45407

in-service transformers, and takes the

difference between the base case and

standards scenarios to calculate site

energy savings. The conversion of site

energy savings to energy savings at the

source (i.e., at the power plant), is

calculated by the National Energy

Modeling System (NEMS). The sum of

annual energy savings for the forecast

period through 2035 then provides the

final NES number.

On the other path, the NPV

calculation brings in marginal price

inputs from the LCC analysis for both

energy costs and capacity costs and for

both load losses and no-load losses. The

marginal prices, when combined with

the actual peak and average losses,

provide an estimate of the operating

cost. Meanwhile, the equipment

installed cost multiplied by the annual

shipments provides an estimate of the

total annual equipment costs. The

Department then takes three differences

to calculate the net impact of the

candidate standard levels. The first

difference is between the candidate

standard level scenario equipment costs

and the base case equipment costs to get

the net equipment cost increase from a

candidate standard level. The second

difference is between the base case

operating cost and the candidate

standard level operating cost to get the

net operating cost savings from a

candidate standard level. And the third

difference is between the net operating

cost savings and the net equipment cost

increase to get the net savings (or

expense) for each year. The net savings

(or expense) is then discounted and

summed to the year 2070 for

transformers bought on or before 2035 to

provide the NPV impact of a candidate

standard level.

Table II.27 summarizes the inputs

used to calculate the NES and NPV of

the various candidate standard levels. A

more detailed discussion of the inputs

follows the table.

TABLE 11.27.-SUMMARY OF NES AND NPV INPUTS

Input

Shipments ..........................................................................

Effective Date of Standard .................................................

Base Case Efficiencies ......................................................

Standards Case Efficiencies (2007-2035) ........................

Annual Energy Consumption per Unit ...............................

Total Installed Cost per Unit ..............................................

Description

Annual shipments from shipments model (see details in section II.G.

Assumed here to be 2007.

Constant efficiency through 2035 . Equal to weighted-average efficiency in 2007.

Constant efficiency at the specified standard level from 2007-2035.

Average rated transformer losses are obtained from the LCC analysis, which are

then scaled for different size categories, weighted by size market share , adjusted

for transformer loading (also obtained from the LCC analysis).

Weighted-average values as a function of efficiency level (from LCC analysis).

3 The year 2070 is the rounded sum of 2035 plus

32 years, the average lifetime of distribution

transformers.

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45407 

standards case relative to the base case. 

The Department converted the site 

energy used by the transformers into the 

amount of energy consumed at the 

source of electricity generation (the 

source energy) with a site-to-source 

conversion factor. The site-to-source 

factor accounts for transmission, 

distribution, and generation losses. For 

each year analyzed, the difference in 

source energy use between the base case 

and standard scenario is the annual 

energy savings. The Department 

summed the undiscounted annual 

energy savings from 2007 through 2035 

to calculate the total NES for the 

forecast period. The NES analysis which 

will accompany the NOPR will include 

both undiscounted and discounted 

values for future energy savings to 

account for their timing. 

The NPV is the net present value of 

the incremental economic impacts of a 

candidate standard levels. The 

Department calculated the NPV in a way 

that is similar to the NES, except that 

incremental costs are estimated instead 

of energy, and the net costs are 

discounted rather than calculated as an 

undiscounted sum. Like the NES, the 

NPV calculation started with 

transformer shipments and quantity inservice from the shipments model. 

Using estimates of transformer installed 

costs, losses, and electricity costs from 

the LCC analysis, the Department 

calculated the national expenditures for 

installed transformer purchases and the 

corresponding operating costs of the 

transformers in-service for each year for 

both a base case and standards case. Over time, in the standards case, 

transformers that are both more 

expensive and more efficient gradually 

replace less efficient transformers. Thus, 

the operating cost per unit capacity used 

by the transformers in-service gradually 

decreases in the standards case relative 

to the base case, while the equipment 

costs increase. The Department 

discounted purchases and expenses and 

operating costs for transformers using a 

national average discount factor as 

described in Chapter 10 of the TSD. The 

Department calculated the NPV impact 

of transformers that will be bought 

between 2007 and 2035. 

To make the analysis more accessible 

to all stakeholders, the Department 

prepared a national impact spreadsheet 

model (available on the Department's 

website) in Microsoft Excel to execute 

the calculations outlined above. The 

spreadsheet calculates capacity and 

operating cost savings associated with 

each of the candidate standard levels. 

The NES analysis considers cumulative 

energy savings through the year 2035, 

while the NPV considers capacity and 

operating cost savings through the year 

2070 3 for transformers bought on or 

before 2035. By taking the difference 

between the base case and candidate 

standard levels, summing, and 

discounting the annual results, the 

spreadsheet calculates an NPV for each 

candidate standard level relative to the 

base case. 

1. Method 

Both calculations start by using the 

estimate of shipments and quantity inservice that resulted from the shipments 

model (section II.G) and then proceed 

with the NES and NPV calculations. Key 

inputs from the LCC analysis are the 

average rated losses for both no-load 

and load losses, and the equipment cost 

oftransformers, including installation. 

The losses and the equipment costs then 

go through a transformer size and 

product class adjustment that converts 

the data from representative design lines 

to average product class information. 

Additional inputs regarding average and 

peak losses-including root mean 

square (RMS) loading, peak loading, and 

peak responsibility factor-allow a 

calculation of losses from rated losses at 

rated loading. At this point, the 

information flow for the NES and NPV 

calculation splits into two paths. 

On one path, the NES calculation 

sums the actual losses and the affected 

in-service transformers, and takes the 

difference between the base case and 

standards scenarios to calculate site 

energy savings. The conversion of site 

energy savings to energy savings at the 

source (i.e., at the power plant), is 

calculated by the National Energy 

Modeling System (NEMS). The sum of 

annual energy savings for the forecast 

period through 2035 then provides the 

final NES number. 

On the other path, the NPV 

calculation brings in marginal price 

inputs from the LCC analysis for both 

energy costs and capacity costs and for 

both load losses and no-load losses. The 

marginal prices, when combined with 

the actual peak and average losses, 

provide an estimate of the operating 

cost. Meanwhile, the equipment 

installed cost multiplied by the annual 

shipments provides an estimate of the 

total annual equipment costs. The 

Department then takes three differences 

to calculate the net impact of the 

candidate standard levels. The first 

difference is between the candidate 

standard level scenario equipment costs 

and the base case equipment costs to get 

the net equipment cost increase from a 

candidate standard level. The second 

difference is between the base case 

operating cost and the candidate 

standard level operating cost to get the 

net operating cost savings from a 

candidate standard level. And the third 

difference is between the net operating 

cost savings and the net equipment cost 

increase to get the net savings (or 

expense) for each year. The net savings 

(or expense) is then discounted and 

summed to the year 2070 for 

transformers bought on or before 2035 to 

provide the NPV impact of a candidate 

standard level. 

Table II.27 summarizes the inputs 

used to calculate the NES and NPV of 

the various candidate standard levels. A 

more detailed discussion of the inputs 

follows the table. 

TABLE 11.27.-SUMMARY OF NES AND NPV INPUTS 

Input Description 

Shipments .......................................................................... Annual shipments from shipments model (see details in section II.G. 

Effective Date of Standard ................................................. Assumed here to be 2007. 

Base Case Efficiencies ...................................................... Constant efficiency through 2035. Equal to weighted-average efficiency in 2007. 

Standards Case Efficiencies (2007-2035) ........................ Constant efficiency at the specified standard level from 2007-2035. 

Annual Energy Consumption per Unit ............................... Average rated transformer losses are obtained from the LCC analysis, which are 

then scaled for different size categories, weighted by size market share, adjusted 

for transformer loading (also obtained from the LCC analysis). 

Total Installed Cost per Unit .............................................. Weighted-average values as a function of efficiency level (from LCC analysis). 

3 The year 2070 is the rounded sum of 2035 plus 

32 years, the average lifetime of distribution 

transformers. 
45408 Federal Register / Vol. 69, No. 145 / Thursday, July 29, 2004 / Proposed Rules

TABLE 11.27.-SUMMARY OF NES AND NPV INPUTS-Continued

Input

Electricity Expense per Unit ...............................................

Escalation of Electricity Prices ...........................................

Electricity Site-to-Source Conversion ................................

Discount Rates ...................................................................

Analysis Year .....................................................................

The Department provides detailed

descriptions of the NES and NPV

models below. It provides a descriptive

overview of how the Department

performed each model's calculations,

and follows with a summary of the

inputs. Chapter 10 of the TSD contains

full technical descriptions of these

models and their inputs, processes (with

equations, when appropriate), and

outputs. After the model descriptions,

the Department presents the summary

results of the national impacts

calculations.

2. National Energy Savings

The Department developed a method

to calculate national energy savings

resulting from different candidate

distribution transformer efficiency

standards-the NES. Positive NES

values correspond to net energy savings,

that is, a decrease in energy

consumption with standards in

comparison to the energy consumption

in a base case.

The Department received a comment

from TXU Electric and Gas that energy

savings must be tempered with a more

comprehensive look at the effects of

producing more efficient transformers.

TXU Electric and Gas stated that to

increase the distribution transformer

efficiency there might be a 50 percent

increase in production of higher quality

core steel and a 30 percent increase in

the use of transformer oil in each unit.

These products require energy to

produce or refine. The production of the

core steel is environmentally "dirty."

The costs associated with increased

energy usage and the environmental

impacts of production of higher

efficiency transformers should be

considered in the cost effectiveness of

the improved efficiency. (TXU Electric

and Gas, No. 12 at p. 8)

In evaluating and establishing energy

efficiency standards, the Department

does not presently consider the wide

range of externalities associated with

the production of higher efficiency

products or equipment-in this case,

Description

Both energy and capacity savings for the two types of transformer losses are multiplied by the average marginal costs for both capacity and energy for the two types

of losses (marginal costs are from the LCC analysis).

AEO 2003 forecasts (to 2025) and extrapolation for 2035 and beyond (see LCC discussion, section II.F).

A time series conversion factor; includes electric generation , transmission , and distribution losses. Conversion varies yearly and is generated by DOE/EIA's National

Energy Modeling System program.

3% and 7% real.

Future expenses are discounted to the year of equipment price data, 2001.

distribution transformers. The

difficulties and uncertainties associated

with analyzing those externalities

would substantially increase the

complexity of standards rulemakings

and potentially lessen the reliability of

their ultimate outcomes. Therefore, in

calculating increased costs associated

with standards, DOE's current

methodology is limited to using the

transformer manufacturers' estimated

costs of producing more efficient

transformers.

a. National Energy Savings Overview

The Department calculated the

cumulative incremental energy savings

in units of quadrillion Btus (quads) from

candidate transformer efficiency

standards relative to a base case of no

standard over a forecast period that

spans the first standards years from

2007 to 2035.

NEMA submitted a comment

addressing how the Department should

characterize the baseline condition

against which energy savings for various

candidate standard levels are calculated.

In particular, NEMA commented that in

principle, the NES analysis should use

the same inputs as the LCC analysis.

NEMA considered market penetration of

more efficient transformers without

regulations to be a key aspect of the NES

and noted that multiple base case

scenarios may be needed. (NEMA, No.

7 at p. 12) Consistent with NEMA's

comment, the Department used a range

of purchaser valuations given to

transformer no-load and load losses,

expressed as A and B distributions, to

represent customer choice scenarios as

noted in section II.F.2.c.

The shipments model provides the

estimate for the affected in-service

transformers. The key to the NES

calculation is in measuring the

difference in energy per unit capacity

between the standards case and the base

case, given the input from the LCC and

including the site-to-source conversion

factor that translates site energy into

energy consumed at the power plant.

The next section summarizes the inputs

necessary for the NES calculation. The

Department welcomes suggestions from

stakeholders for possible data

enhancements in the NES inputs.

b. National Energy Savings Inputs

The NES model inputs fall into three

broad categories: (1) Those that help

convert the data from the LCC into data

for the product classes and transformer

size distributions used in the NES; (2)

those that help calculate the unit energy

consumption; and (3) site-to-source

factors that enable the calculation of

source energy consumption from site

energy use.

The size scaling of losses and costs

adjusts LCC representative design line

data so it can represent the size

distribution of transformers that are in

a particular product class. The mapping

of LCC design line data to product

classes (Table 11.5) provides the proper

inter-design line averaging or

adjustments for representation of the

product classes.

The RMS loading is a key factor in

estimating actual load losses given the

load losses at rated load for a

transformer. Load growth over the

lifetime of the transformer can change

the average RMS loading experienced by

affected transformers. The effective date

of the standard impacts the definition of

the affected transformers. The unit

energy consumption is the energy per

unit capacity of an affected transformer

and depends on all of the first four

inputs.

The electricity site-to-source

conversion provides the estimate of

energy consumption at the generation

station given the energy use at the site

of the transformer. Finally, the affected

transformers are those in-service

transformers that may have different

characteristics as a result of a candidate

standard level.

The Department received comments

from stakeholders on the loading level

appropriate for measuring national

energy savings. In particular, NEMA

commented that it would be appropriate

 EE-RM/STD-00-550 COMMENT 53.1

#53. 

45408 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

TABLE 11.27.-SUMMARY OF NES AND NPV INPUTs-Continued 

Input Description 

Electricity Expense per Unit ............................................... Both energy and capacity savings for the two types of transformer losses are multiplied by the average marginal costs for both capacity and energy for the two types 

of losses (marginal costs are from the LCC analysis). 

Escalation of Electricity Prices ........................................... AEO 2003 forecasts (to 2025) and extrapolation for 2035 and beyond (see LCC discussion, section II.F). 

Electricity Site-to-Source Conversion . ............................... A time series conversion factor; includes electric generation, transmission, and distribution losses. Conversion varies yearly and is generated by DOE/EIA's National 

Energy Modeling System program. 

Discount Rates .................................... ............................... 3% and 7% real. 

Analysis Year ..................................................................... Future expenses are discounted to the year of equipment price data, 2001. 

The Department provides detailed 

descriptions of the NES and NPV 

models below. It provides a descriptive 

overview of how the Department 

performed each model's calculations, 

and follows with a summary of the 

inputs. Chapter 10 of the TSD contains 

full technical descriptions of these 

models and their inputs, processes (with 

equations, when appropriate), and 

outputs. After the model descriptions, 

the Department presents the summary 

results of the national impacts 

calculations. 

2. National Energy Savings 

The Department developed a method 

to calculate national energy savings 

resulting from different candidate 

distribution transformer efficiency 

standards-the NES. Positive NES 

values correspond to net energy savings, 

that is, a decrease in energy 

consumption with standards in 

comparison to the energy consumption 

in a base case. 

The Department received a comment 

from TXU Electric and Gas that energy 

savings must be tempered with a more 

comprehensive look at the effects of 

producing more efficient transformers. 

TXU Electric and Gas stated that to 

increase the distribution transformer 

efficiency there might be a 50 percent 

increase in production of higher quality 

core steel and a 30 percent increase in 

the use of transformer oil in each unit. 

These products require energy to 

produce or refine. The production of the 

core steel is environmentally "dirty." 

The costs associated with increased 

energy usage and the environmental 

impacts of production of higher 

efficiency transformers should be 

considered in the cost effectiveness of 

the improved efficiency. (TXU Electric 

and Gas, No. 12 at p. 8) 

In evaluating and establishing energy 

efficiency standards, the Department 

does not presently consider the wide 

range of externalities associated with 

the production of higher efficiency 

products or equipment-in this case, 

distribution transformers. The 

difficulties and uncertainties associated 

with analyzing those externalities 

would substantially increase the 

complexity of standards rulemakings 

and potentially lessen the reliability of 

their ultimate outcomes. Therefore, in 

calculating increased costs associated 

with standards, DOE's current 

methodology is limited to using the 

transformer manufacturers' estimated 

costs of producing more efficient 

transformers. 

a. National Energy Savings Overview 

The Department calculated the 

cumulative incremental energy savings 

in units of quadrillion Btus (quads) from 

candidate transformer efficiency 

standards relative to a base case of no 

standard over a forecast period that 

spans the first standards years from 

2007 to 2035. 

NEMA submitted a comment 

addressing how the Department should 

characterize the baseline condition 

against which energy savings for various 

candidate standard levels are calculated. 

In particular, NEMA commented that in 

principle, the NES analysis should use 

the same inputs as the LCC analysis. 

NEMA considered market penetration of 

more efficient transformers without 

regulations to be a key aspect of the NES 

and noted that multiple base case 

scenarios may be needed. (NEMA, No. 

7 at p. 12) Consistent with NEMA's 

comment, the Department used a range 

of purchaser valuations given to 

transformer no-load and load losses, 

expressed as A and B distributions, to 

represent customer choice scenarios as 

noted in section II.F.2.c. 

The shipments model provides the 

estimate for the affected in-service 

transformers. The key to the NES 

calculation is in measuring the 

difference in energy per unit capacity 

between the standards case and the base 

case, given the input from the LCC and 

including the site-to-source conversion 

factor that translates site energy into 

energy consumed at the power plant. 

The next section summarizes the inputs 

necessary for the NES calculation. The 

Department welcomes suggestions from 

stakeholders for possible data 

enhancements in the NES inputs. 

b. National Energy Savings Inputs 

The NES model inputs fall into three 

broad categories: (1) Those that help 

convert the data from the LCC into data 

for the product classes and transformer 

size distributions used in the NES; (2) 

those that help calculate the unit energy 

consumption; and (3) site-to-source 

factors that enable the calculation of 

source energy consumption from site 

energy use. The size scaling of losses and costs 

adjusts LCC representative design line 

data so it can represent the size 

distribution of transformers that are in 

a particular product class. The mapping 

of LCC design line data to product 

classes (Table 11.5) provides the proper 

inter-design line averaging or 

adjustments for representation of the 

product classes. 

The RMS loading is a key factor in 

estimating actual load losses given the 

load losses at rated load for a 

transformer. Load growth over the 

lifetime of the transformer can change 

the average RMS loading experienced by 

affected transformers. The effective date 

of the standard impacts the definition of 

the affected transformers. The unit 

energy consumption is the energy per 

unit capacity of an affected transformer 

and depends on all of the first four 

inputs. 

The electricity site-to-source 

conversion provides the estimate of 

energy consumption at the generation 

station given the energy use at the site 

of the transformer. Finally, the affected 

transformers are those in-service 

transformers that may have different 

characteristics as a result of a candidate 

standard level. 

The Department received comments 

from stakeholders on the loading level 

appropriate for measuring national 

energy savings. In particular, NEMA 

commented that it would be appropriate 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

to do sensitivity analysis comparisons at

different loading levels, but that the

primary economic analyses on which a

standard is based should be done using

the TP 1 load levels of 35 percent and

50 percent. NEMA noted that it may

also be appropriate to calculate national

energy savings based on lower loading.

NEMA stated that it does not think it is

prudent to base standards on lower load

levels. NEMA went on to say that many

large transformers are used to supply

power for continuous, 24-hour

industrial processes that have high load

factors. Examples of these applications

are chemical companies, oil refineries,

steel mills, grain refineries, and copper

and aluminum manufacturers. NEMA

stated that any analysis that establishes

standards based on lower load factors

will unduly penalize these industries,

and not result in actual maximum

energy savings. (NEMA, No. 7 at p. 10)

Howard Industries, Inc. noted that

since utilities will be forced to adopt the

DOE rule, they will likely drop the TOC

approach of evaluating distribution

transformers with the result that often

they may end up buying less efficient

transformers. However, in other cases,

to meet the threshold efficiency of the

rule, utilities may have to pay more for

their transformers even though they are

not economically justified, and therefore

45409

the DOE rule will not be good for the

environment because more energy will

be needed to supply these increased

losses. Howard Industries argued that

these points should be taken into

consideration when the DOE makes its

new NES analysis. (Howard Industries,

No. 4 at p. 2)

The Department has taken these

comments into consideration in the NES

calculations, which use loading, costs,

and losses as inputs from the LCC

analysis. (TSD Chapter 8)

Table 11.28 summarizes the various

inputs and sources of the distribution

transformer NES calculations.

TABLE 11.28.-SUMMARY OF INPUTS FOR NES CALCULATIONS

Input

Size scaling of losses and costs .. ......................................

Mapping of design lines to product classes ......................

Root mean square loading . ................................................

Annual Load growth . ..........................................................

Effective date of standard ..................................................

Unit energy consumption ...................................................

Site-to-source electricity conversion ..................................

Affected transformers .........................................................

To determine product class

characteristics from design line

estimates, the Department first scaled

characteristics by transformer capacity

to determine per kVA characteristics.

Then the Department calculated

shipment-weighted averages of per kVA

characteristics of the appropriate design

lines to get the per kVA characteristics

of the product classes. The Department's

contractor provided the capacity

shipped for each design line (and each

product class), the LCC analysis

provided the economic results for each

design, and the 0.75 Scaling Rule

provided the re-scaled cost and loss

estimates for each size category

represented with a given design line.

For no-load losses, no more adjustment

is needed; but for load losses, the losses

at rated load need to be converted to

losses at actual loading. The RMS

loading is a key factor in estimating load

losses at actual loading. Thus, the load

losses are particularly sensitive to the

RMS loading.

3. Net Present Value Calculation

The Department takes into

consideration the national financial

impact from the imposition of new

energy efficiency standards, which is

expressed as the national NPV. The

output of the shipments model is

Description

The "0.75 rule" applied to the losses and costs from the LCC analysis.

Table 11.5 shows the mapping of the 13 engineering design lines to the 10 product

classes.

From the LCC analysis.

1 % for the liquid -immersed and 0% for the dry-type transformers.

Three years after publication of the Final Rule.

Based on losses and RMS loading and the load growth.

A time series conversion factor; includes electric generation , transmission, and distribution losses. Conversion varies yearly and is generated by the NEMS program.

From the shipments model.

combined with energy savings and

financial data from the LCC to calculate

an annual stream of costs and benefits

resulting from candidate distribution

transformer energy efficiency standards.

This time series is discounted to 2001

and summed, resulting in the national

NPV. The Department selected 2001 as

the NPV analysis year, for consistency

with the year of equipment price data

used in the analysis. A different NPV

analysis year may be used in the NOPR.

a. Net Present Value Overview

The NPV is the present value of the

incremental economic impacts of a

candidate standard level.

Mathematically, NPV is the present

value in a time series of costs and

savings occurring in the future. The

Department calculated net savings each

year as the difference between total

operating cost savings (both energy and

electricity system capacity) and

increases in total installed costs

(including equipment price and

installation cost). Electricity system

capacity costs include generation,

transmission and distribution. Savings

were calculated over the life of the

equipment, which takes into account

the differences in yearly energy rates.

The Department calculated the NPV as

the difference between the present value

of operating cost savings and the present

value of increased total installed costs.

It discounted purchases and expenses

and operating costs for transformers

using national average discount factors,

which the Department calculated from

the discount rate and the number of

years between 2001 (the year to which

DOE discounted the sum) and the year

in which the costs and savings occur.

An NPV greater than zero indicates net

savings (i.e., the energy efficiency

standard reduces customer expenditures

in the standards case relative to the base

case). An NPV less than zero indicates

that the energy efficiency standard

creates net costs to consumers.

The following section outlines the

inputs specific to the NPV calculation.

The Department welcomes suggestions

from stakeholders for improving these.

b. Net Present Value Inputs

The NPV model inputs include cost

inputs, selected inputs that are

important for detailing electricity

capacity costs, and several of the inputs

used for the NES calculation. This

section presents those inputs that have

not yet been described as part of the

shipments and NES models. Table 11.29

summarizes these inputs.

 EE-RM/STD-00-550 COMMENT 53.1

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45409 

to do sensitivity analysis comparisons at 

different loading levels, but that the 

primary economic analyses on which a 

standard is based should be done using 

the TP 1 load levels of 35 percent and 

50 percent. NEMA noted that it may 

also be appropriate to calculate national 

energy savings based on lower loading. 

NEMA stated that it does not think it is 

prudent to base standards on lower load 

levels. NEMA went on to say that many 

large transformers are used to supply 

power for continuous, 24-hour 

industrial processes that have high load 

factors. Examples of these applications 

are chemical companies, oil refineries, 

steel mills, grain refineries, and copper 

and aluminum manufacturers. NEMA 

stated that any analysis that establishes 

standards based on lower load factors 

will unduly penalize these industries, 

and not result in actual maximum 

energy savings. (NEMA, No.7 at p. 10) 

Howard Industries, Inc. noted that 

since utilities will be forced to adopt the 

DOE rule, they will likely drop the TOC 

approach of evaluating distribution 

transformers with the result that often 

they may end up buying less efficient 

transformers. However, in other cases, 

to meet the threshold efficiency of the 

rule, utilities may have to pay more for 

their transformers even though they are 

not economically justified, and therefore 

the DOE rule will not be good for the 

environment because more energy will 

be needed to supply these increased 

losses. Howard Industries argued that 

these points should be taken into 

consideration when the DOE makes its 

new NES analysis. (Howard Industries, 

No.4 at p. 2) 

The Department has taken these 

comments into consideration in the NES 

calculations, which use loading, costs, 

and losses as inputs from the LCC 

analysis. (TSD Chapter 8) 

Table II.28 summarizes the various 

inputs and sources of the distribution 

transformer NES calculations. 

TABLE 11.28.-SUMMARY OF INPUTS FOR NES CALCULATIONS 

Input Description 

Size scaling of losses and costs ........................................ The "0.75 rule" applied to the losses and costs from the LCC analysis. 

Mapping of design lines to product classes ...................... Table 11.5 shows the mapping of the 13 engineering design lines to the 10 product 

classes. 

Root mean square loading .................. ............................... From the LCC analysis. 

Annual Load growth ............................ ............................... 1 % for the liquid-immersed and 0% for the dry-type transformers. 

Effective date of standard ................... ............................... Three years after publication of the Final Rule. 

Unit energy consumption .................... ............................... Based on losses and RMS loading and the load growth. 

Site-to-source electricity conversion .................................. A time series conversion factor; includes electric generation, transmission, and distribution losses. Conversion varies yearly and is generated by the NEMS program. 

Affected transformers .......................... ............................... From the shipments model. 

To determine product class 

characteristics from design line 

estimates, the Department first scaled 

characteristics by transformer capacity 

to determine per kVA characteristics. 

Then the Department calculated 

shipment-weighted averages of per kVA 

characteristics of the appropriate design 

lines to get the per kVA characteristics 

of the product classes. The Department's 

contractor provided the capacity 

shipped for each design line (and each 

product class), the LCC analysis 

provided the economic results for each 

design, and the 0.75 Scaling Rule 

provided the re-scaled cost and loss 

estimates for each size category 

represented with a given design line. 

For no-load losses, no more adjustment 

is needed; but for load losses, the losses 

at rated load need to be converted to 

losses at actual loading. The RMS 

loading is a key factor in estimating load 

losses at actual loading. Thus, the load 

losses are particularly sensitive to the 

RMS loading. 

3. Net Present Value Calculation 

The Department takes into 

consideration the national financial 

impact from the imposition of new 

energy efficiency standards, which is 

expressed as the national NPV. The 

output of the shipments model is 

combined with energy savings and 

financial data from the LCC to calculate 

an annual stream of costs and benefits 

resulting from candidate distribution 

transformer energy efficiency standards. 

This time series is discounted to 2001 

and summed, resulting in the national 

NPV. The Department selected 2001 as 

the NPV analysis year, for consistency 

with the year of equipment price data 

used in the analysis. A different NPV 

analysis year may be used in the NOPR. 

a. Net Present Value Overview 

The NPV is the present value of the 

incremental economic impacts of a 

candidate standard level. 

Mathematically, NPV is the present 

value in a time series of costs and 

savings occurring in the future. The 

Department calculated net savings each 

year as the difference between total 

operating cost savings (both energy and 

electricity system capacity) and 

increases in total installed costs 

(including equipment price and 

installation cost). Electricity system 

capacity costs include generation, 

transmission and distribution. Savings 

were calculated over the life of the 

equipment, which takes into account 

the differences in yearly energy rates. 

The Department calculated the NPV as 

the difference between the present value 

of operating cost savings and the present 

value of increased total installed costs. 

It discounted purchases and expenses 

and operating costs for transformers 

using national average discount factors, 

which the Department calculated from 

the discount rate and the number of 

years between 2001 (the year to which 

DOE discounted the sum) and the year 

in which the costs and savings occur. 

An NPV greater than zero indicates net 

savings (i.e., the energy efficiency 

standard reduces customer expenditures 

in the standards case relative to the base 

case). An NPV less than zero indicates 

that the energy efficiency standard 

creates net costs to consumers. 

The following section outlines the 

inputs specific to the NPV calculation. 

The Department welcomes suggestions 

from stakeholders for improving these. 

b. Net Present Value Inputs 

The NPV model inputs include cost 

inputs, selected inputs that are 

important for detailing electricity 

capacity costs, and several of the inputs 

used for the NES calculation. This 

section presents those inputs that have 

not yet been described as part of the 

shipments and NES models. Table II.29 

summarizes these inputs. 
45410 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

TABLE 11.29.-SUMMARY OF INPUTS FOR NPV CALCULATIONS

Input

First cost (installed) ............................................................

Operating cost ....................................................................

Peak responsibility factor (PRF) ........................................

Initial peak load ..................................................................

Electricity price forecast scalar ..........................................

Marginal electricity costs ....................................................

Discount rates ....................................................................

The Department received several

comments from stakeholders on the

appropriate discount rate to use in the

NPV calculation. Cooper Power Systems

noted that another concern is the

uncertainty regarding the appropriate

interest rate to select for the present

value evaluations. If the rate is skewed

too high, lower efficiency units will be

evaluated more favorably and vice

versa. Cooper stated that a value as high

as 35 percent cannot be justified today.

Cooper stated that they would like to

see how the interest rates are to be

chosen. (Cooper Power Systems, No. 34

at p. 1)

NEMA commented that a discount

rate representative of real world

commercial and industrial business

choices should be used. NEMA believes

that the 8 percent real as suggested at

the Department's framework document

workshop is the minimum rate that

should be considered. NEMA believes

more appropriate discount rates would

be in the range of 15 to 20 percent real.

(NEMA, No. 7 at p. 11)

Description

All of the initial costs that are incurred with the installation of a transformer.

Annual cost of operating a transformer including both energy and capacity costs for

supplying no-load and load losses.

The square of the ratio of the transformer load during peak divided by the annual

peak transformer load. PRF is used to calculate the load loss peak coincidence

factor for system capacity cost and demand cost estimates.

The peak load of the transformer at the time of installation.

The ratio that scales the forecasted increase or decrease in electricity price over the

period from 2001 to 2070.

The cost for the last kWh of electricity purchased.

The time value of money used by the Department to estimate the present value of a

future monetary cost or benefit, 3% and 7% real.

The Department estimated national

impacts with both a 3 percent and a 7

percent real discount rate in accordance

with the Office of Management and

Budget's (OMB) guidelines contained in

Circular A-4, Regulatory Analysis,

September 17, 2003 (see Chapter 10 of

the TSD).

4. National Energy Savings and Net

Present Value Results

The following seven tables (Tables

11.30 through 11.36) present the findings

from the Department's national impacts

analysis. For each evaluated product

class and each candidate standard level,

the Department presents the NES in

quads and the NPV in billions of

dollars. Table 11.30 provides a summary

of the total analysis, grouping together

all the liquid-immersed product classes

and all the dry-type product classes.

Tables 11.31 and 11.34 provide NPV

results for liquid-immersed and drytype product classes respectively using

a 3 percent real discount rate. Tables

11.32 and 11.35 provide NPV results for

the same product classes, using the 7

percent real discount rate. The

Department presents all these findings

to facilitate stakeholder review of the

national impact analysis. The

Department has not selected any

specific standard level for any product

class. A more comprehensive report of

the national impact analysis findings is

provided in Chapter 10 of the TSD.

a. National Energy Savings and Net

Present Value From Candidate Standard

Levels

Preliminary NES and NPV results

from the NES spreadsheet model for

CSL 1 through CSL 5 are shown in Table

11.30, Tables 11.31 through 11.33 present

NPV and NES results for liquidimmersed transformers by product class.

Tables 11.34 through 11.36 present NPV

and NES results for dry-type

transformers by product class. The NPV

results are reported using both a 3

percent and a 7 percent real discount

rate. The NES is reported in quads,

representing a quadrillion (1015) Btus of

avoided primary energy consumption at

the power plant.

TABLE 11.30.-SUMMARY OF CUMULATIVE NES AND NPV IMPACTS BETWEEN 2007-2035

Distribution transformers Analysis

Candidate standard level

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5

Liquid-immmersed ............................................. NES (quads) .....................................................

NPV (billion 2001$, 3%) ...................................

NPV (billion 2001 $, 7%) ...................................

Dry-type ... .......................................................... NES (quads) .....................................................

NPV (billion 2001 $, 3%) ...................................

NPV (billion 2001 $, 7%) ...................................

1.88 3.02 5.20 6.98 7.87

6.50 8.32 6.45 5.16 -0.71

1.67 1.51 -1.21 -3.18 -7.37

4.98 5.75 6.71 7.46 8.18

32.83 37.24 41.95 43.80 44.45

10.09 11.27 12.39 12.26 11.41

TABLE 11.31.-NET PRESENT VALUE BETWEEN 2007-2035: LIQUID-IMMERSED PRODUCT CLASSES, 3% REAL DISCOUNT

RATE

Product class

CSL 1

Net present value ($ billions)

CSL 2 CSL 3 CSL 4 CSL 5

1. Liquid-immersed , medium-voltage , single-phase . ............................................................. 3.05 3.21 0.60 -1.05

2. Liquid-immersed , medium-voltage, three-phase ............................................................... 3.45 5.11 5.86 6.21

Total ................................................................................................................................ 6.50 8.32 6.45 5.16

-6.87

6.17

-0.71

 EE-RM/STD-00-550 COMMENT 53.1

#53. 

45410 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

TABLE 11.29.-SUMMARY OF INPUTS FOR NPV CALCULATIONS 

Input Description 

First cost (installed) ............................................................ All of the initial costs that are incurred with the installation of a transformer. 

Operating cost ... ................................................................. Annual cost of operating a transformer including both energy and capacity costs for 

supplying no-load and load losses. 

Peak responsibility factor (PRF) ........................................ The square of the ratio of the transformer load during peak divided by the annual 

peak transformer load. PRF is used to calculate the load loss peak coincidence 

factor for system capacity cost and demand cost estimates. 

Initial peak load . ................................................................. The peak load of the transformer at the time of installation. 

Electricity price forecast scalar .......................................... The ratio that scales the forecasted increase or decrease in electricity price over the 

period from 2001 to 2070. 

Marginal electricity costs .................................................... The cost for the last kWh of electricity purchased. 

Discount rates ... ................................................................. The time value of money used by the Department to estimate the present value of a 

The Department received several 

comments from stakeholders on the 

appropriate discount rate to use in the 

NPV calculation. Cooper Power Systems 

noted that another concern is the 

uncertainty regarding the appropriate 

interest rate to select for the present 

value evaluations. If the rate is skewed 

too high, lower efficiency units will be 

evaluated more favorably and vice 

versa. Cooper stated that a value as high 

as 35 percent cannot be justified today. 

Cooper stated that they would like to 

see how the interest rates are to be 

chosen. (Cooper Power Systems, No. 34 

at p. 1) 

future monetary cost or benefit, 3% and 7% real. 

The Department estimated national 

impacts with both a 3 percent and a 7 

percent real discount rate in accordance 

with the Office of Management and 

Budget's (OMB) guidelines contained in 

Circular A-4, Regulatory Analysis, 

September 17,2003 (see Chapter 10 of 

the TSD). 

4. National Energy Savings and Net 

percent real discount rate. The 

Department presents all these findings 

to facilitate stakeholder review of the 

national impact analysis. The 

Department has not selected any 

specific standard level for any product 

class. A more comprehensive report of 

the national impact analysis findings is 

provided in Chapter 10 of the TSD. 

Present Value Results a. National Energy Savings and Net 

The following seven tables (Tables Present Value From Candidate Standard 

II.30 through II.36) present the findings Levels 

from the Department's national impacts Preliminary NES and NPV results 

analysis. For each evaluated product from the NES spreadsheet model for 

class and each candidate standard level, CSL 1 through CSL 5 are shown in Table 

the Department presents the NES in II.30. Tables II.31 through II.33 present 

NEMA commented that a discount quads and the NPV in billions of NPV and NES results for liquidrate representative of real world dollars. Table II.30 provides a summary immersed transformers by product class. 

commercial and industrial business of the total analysis, grouping together Tables II.34 through II.36 present NPV 

choices should be used. NEMA believes all the liquid-immersed product classes and NES results for dry-type 

that the 8 percent real as suggested at and all the dry-type product classes. transformers by product class. The NPV 

the Department's framework document Tables II.31 and II.34 provide NPV results are reported using both a 3 

workshop is the minimum rate that results for liquid-immersed and dry- percent and a 7 percent real discount 

should be considered. NEMA believes type product classes respectively using rate. The NES is reported in quads, 

more appropriate discount rates would a 3 percent real discount rate. Tables representing a quadrillion (1015) Btus of 

be in the range of 15 to 20 percent real. II.32 and II.35 provide NPV results for avoided primary energy consumption at 

(NEMA, No.7 at p. 11) the same product classes, using the 7 the power plant. 

TABLE 11.30.-SUMMARY OF CUMULATIVE NES AND NPV IMPACTS BETWEEN 2007-2035 

Candidate standard level 

Distribution transformers Analysis 

CSL 1 CSL 2 CSL3 CSL 4 CSL 5 

Liquid-immmersed ............................................ . NES (quads) ..................................................... 1.88 3.02 5.20 6.98 7.87 

NPV (billion 2001$, 3%) ................................... 6.50 8.32 6.45 5.16 -0.71 

NPV (billion 2001$, 7%) ................................... 1.67 1.51 -1.21 -3.18 -7.37 

Dry-type ............................................................ . NES (quads) ..................................................... 4.98 5.75 6.71 7.46 8.18 

NPV (billion 2001$, 3%) ................................... 32.83 37.24 41.95 43.80 44.45 

NPV (billion 2001$, 7%) ................................... 10.09 11.27 12.39 12.26 11.41 

TABLE 11.31.-NET PRESENT VALUE BETWEEN 2007-2035: liQUID-IMMERSED PRODUCT CLASSES, 3% REAL DISCOUNT 

RATE 

Net present value ($ billions) 

Product class 

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5 

1. Liquid-immersed, medium-voltage, single-phase ............................................................. . 3.05 3.21 0.60 -1.05 -6.87 

2. Liquid-immersed, medium-voltage, three-phase .............................................................. . 3.45 5.11 5.86 6.21 6.17 

Total ............................................................................................................................... . 6.50 8.32 6.45 5.16 -0.71 
a

Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

Cumulative primary energy savings

TABLE 11.32.-NET PRESENT VALUE BETWEEN 2007-2035: LIQUID-IMMERSED PRODUCT CLASSES, 7% REAL DISCOUNT

RATE

Product class

1. Liquid-immersed , medium-voltage, single-phase ..............................................................

2. Liquid-immersed , medium-voltage , three-phase ...............................................................

Total ................................................................................................................................

45411

TABLE 11.33.-NATIONAL ENERGY SAVINGS BETWEEN 2007-2035: LIQUID-IMMERSED PRODUCT CLASSES

Product class

1. Liquid-immersed , medium-voltage , single-phase . .......................................................................

2. Liquid-immersed, medium-voltage , three-phase .........................................................................

Total ..........................................................................................................................................

uads)

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5

0.97 1. 53 2.70 4.10 4.43

0.92 1.48 2.51 2.87 3.44

1 .88 3.02 5.20 6.98 7.87

TABLE 11.34.-NET PRESENT VALUE BETWEEN 2007-2035: DRY-TYPE PRODUCT CLASSES, 3% REAL DISCOUNT RATE

Product class

3. Dry-type, low-voltage, single-phase ........................................................................

4. Dry-type, low-voltage, three-phase ..........................................................................

5. Dry-type, medium-voltage , single -phase, 20-45 kV BIL .........................................

6. Dry-type, medium-voltage , three-phase, 20-45 kV BIL ..........................................

7. Dry-type, medium-voltage , single-phase, 46-95 kV BIL .........................................

8. Dry-type, medium-voltage, three-phase, 46-95 kV BIL ..........................................

9. Dry-type, medium-voltage , single-phase , >96 kV BIL .............................................

10. Dry-type, medium-voltage , three-phase , ?96 kV BIL ............................................

Total ......................................................................................................................

Net present value ($ billions)

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5

2.36 2.55 2.61 2.67 2.70

29.14 32.99 37.07 38.85 39.68

0.0073 0.0084 0.0099 0.0102 0.0098

0.32 0.36 0.42 0.42 0.40

0.0055 0.0070 0.0087 0.0087 0.0084

0.93 1.24 1.71 1.73 1.63

0.0008 0.0012 0.0013 0.0016 0.0012

0.09 0.13 0.14 0.17 0.12

32.83 37.24 41.95 43.80 44.45

TABLE 11.35.-NET PRESENT VALUE BETWEEN 2007-2035: DRY-TYPE PRODUCT CLASSES, 7% REAL DISCOUNT RATE

Product class

3. Dry-type, low-voltage, single-phase ........................................................................

4. Dry-type, low-voltage, three-phase ..........................................................................

5. Dry-type, medium-voltage, single-phase, 20-45 kV BIL .........................................

6. Dry-type, medium-voltage, three-phase, 20-45 kV BIL ..........................................

7. Dry-type, medium-voltage, single-phase, 46-95 kV BIL .........................................

8. Dry-type, medium-voltage, three-phase , 46-95 kV BIL ..........................................

9. Dry-type, medium-voltage, single-phase, >96 kV BIL .............................................

10. Dry-type, medium-voltage, three-phase , ?96 kV BIL ............................................

Total ......................................................................................................................

Net present value ($ billions)

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5

0.71 0.75 0.77 0.75 0.74

9.03 10.07 11.07 11.04 10.37

0.0021 0.0023 0.0027 0.0025 0.0021

0.08 0.09 0.11 0.09 0.07

0.0019 0.0023 0.0025 0.0021 0.0019

0.25 0.32 0.41 0.34 0.24

0.0002 0.0003 0.0003 0.0003 0.0001

0.02 0.03 0.03 0.04 0.01

10.09 11.27 12.39 12.26 11.41

Net present value ($ billions)

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5

0.80 0.34 -1.88 -3.77 -7.22

0.87 1.17 0.68 0.59 -0.15

1.67 1.51 -1.21 -3.18 -7.37

TABLE 11.36.-CUMULATIVE PRIMARY ENERGY SAVINGS BETWEEN 2007-2035: DRY-TYPE PRODUCT CLASSES

Product class

3. Dry-type, low-voltage, single-phase ........................................................................

4. Dry-type, low-voltage, three-phase ..........................................................................

5. Dry-type, medium-voltage, single-phase, 20-45 kV BIL .........................................

6. Dry-type, medium-voltage, three-phase, 20-45 kV BIL ..........................................

7. Dry-type, medium-voltage, single-phase, 46-95 kV BIL .........................................

8. Dry-type, medium-voltage, three-phase, 46-95 kV BIL ..........................................

9. Dry-type, medium-voltage, single-phase, ?96 kV BIL .............................................

10. Dry-type, medium-voltage, three-phase, >96 kV BIL ............................................

Total ......................................................................................................................

Cumulative primary energy savings (qua s)

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5

0.35 0.39 0.39 0.43 0.44

4.39 5.07 5.87 6.53 7.20

0.0012 0.0014 0.0017 0.0020 0.0021

0.05 0.06 0.08 0.09 0.09

0.0010 0.0012 0.0017 0.0019 0.00221

0.17 0.21 0.33 0.38 0.41

0.0001 0.0002 0.0003 0.0003 0.0004

0.02 0.02 0.03 0.04 0.04

4.98 5.75 6.71 7.46 8.18

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45411 

TABLE 11.32.-NET PRESENT VALUE BETWEEN 2007-2035: liQUID-IMMERSED PRODUCT CLASSES, 7% REAL DISCOUNT 

RATE 

Net present value ($ billions) 

Product class 

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5 

1. Liquid-immersed, medium-voltage, single-phase ............................................................ .. 0.80 0.34 -1.88 -3.77 -7.22 

2. Liquid-immersed, medium-voltage, three-phase .............................................................. . 0.87 1.17 0.68 0.59 -0.15 

Total ............................................................................................................................... . 1.67 1.51 -1.21 -3.18 -7.37 

TABLE 11.33.-NATIONAL ENERGY SAVINGS BETWEEN 2007-2035: liQUID-IMMERSED PRODUCT CLASSES 

Cumulative primary energy savings (quads) 

Product class 

CSL1 CSL 2 CSL3 CSL 4 CSL 5 

1. Liquid-immersed, medium-voltage, single-phase ....................................................................... . 0.97 1.53 2.70 4.10 4.43 

2. Liquid-immersed, medium-voltage, three-phase ........................................................................ . 0.92 1.48 2.51 2.87 3.44 

Total ........................................................................................................................................ .. 1.88 3.02 5.20 6.98 7.87 

TABLE 11.34.-NET PRESENT VALUE BETWEEN 2007-2035: DRY-TYPE PRODUCT CLASSES, 3% REAL DISCOUNT RATE 

Net present value ($ billions) 

Product class 

CSL 1 CSL 2 CSL 3 CSL 4 CSL 5 

3. Dry-type, low-voltage, single-phase ....................................................................... . 2.36 2.55 2.61 2.67 2.70 

4. Dry-type, low-voltage, three-phase ......................................................................... . 29.14 32.99 37.07 38.85 39.68 

5. Dry-type, medium-voltage, single-phase, 20-45 kV BIL ........................................ . 0.0073 0.0084 0.0099 0.0102 0.0098 

6. Dry-type, medium-voltage, three-phase, 20-45 kV BIL ........................................ .. 0.32 0.36 0.42 0.42 0.40 

7. Dry-type, medium-voltage, single-phase, 46-95 kV BIL ....................................... .. 0.0055 0.0070 0.0087 0.0087 0.0084 

8. Dry-type, medium-voltage, three-phase, 46-95 kV BIL ........................................ .. 0.93 1.24 1.71 1.73 1.63 

9. Dry-type, medium-voltage, single-phase, ~96 kV BIL ............................................ . 0.0008 0.0012 0.0013 0.0016 0.0012 

10. Dry-type, medium-voltage, three-phase, ~96 kV BIL ........................................... . 0.09 0.13 0.14 0.17 0.12 

Total .................................................................................................................... .. 32.83 37.24 41.95 43.80 44.45 

TABLE 11.35.-NET PRESENT VALUE BETWEEN 2007-2035: DRY-TYPE PRODUCT CLASSES, 7% REAL DISCOUNT RATE 

Net present value ($ billions) 

Product class 

CSL 1 CSL 2 CSL 3 CSL4 CSL 5 

3. Dry-type, low-voltage, single-phase ....................................................................... . 0.71 0.75 0.77 0.75 0.74 

4. Dry-type, low-voltage, three-phase ......................................................................... . 9.03 10.07 11.07 11.04 10.37 

5. Dry-type, medium-voltage, single-phase, 20-45 kV BIL ........................................ . 0.0021 0.0023 0.0027 0.0025 0.0021 

6. Dry-type, medium-voltage, three-phase, 20-45 kV BIL ......................................... . 0.08 0.09 0.11 0.09 0.07 

7. Dry-type, medium-voltage, single-phase, 46-95 kV BIL ........................................ . 0.0019 0.0023 0.0025 0.0021 0.0019 

8. Dry-type, medium-voltage, three-phase, 46-95 kV BIL ......................................... . 0.25 0.32 0.41 0.34 0.24 

9. Dry-type, medium-voltage, single-phase, ~96 kV BIL ........................................... .. 0.0002 0.0003 0.0003 0.0003 0.0001 

10. Dry-type, medium-voltage, three-phase, ~96 kV BIL ........................................... . 0.02 0.03 0.03 0.04 0.01 

Total ..................................................................................................................... . 10.09 11.27 12.39 12.26 11.41 

TABLE 11.36.-CUMULATIVE PRIMARY ENERGY SAVINGS BETWEEN 2007-2035: DRY-TYPE PRODUCT CLASSES 

Cumulative primary energy savings (quads) 

Product class 

CSL 1 CSL2 CSL 3 CSL 4 CSL 5 

3. Dry-type, low-voltage, single-phase ....................................................................... . 0.35 0.39 0.39 0.43 0.44 

4. Dry-type, low-voltage, three-phase ......................................................................... . 4.39 5.07 5.87 6.53 7.20 

5. Dry-type, medium-voltage, single-phase, 20-45 kV BIL ....................................... .. 0.0012 0.0014 0.0017 0.0020 0.0021 

6. Dry-type, medium-voltage, three-phase, 20-45 kV BIL ......................................... . 0.05 0.06 0.08 0.09 0.09 

7. Dry-type, medium-voltage, single-phase, 46-95 kV BIL ....................................... .. 0.0010 0.0012 0.0017 0.0019 0.00221 

8. Dry-type, medium-voltage, three-phase, 46-95 kV BIL ......................................... . 0.17 0.21 0.33 0.38 0.41 

9. Dry-type, medium-voltage, single-phase, ~96 kV BIL ........................................... .. 0.0001 0.0002 0.0003 0.0003 0.0004 

10. Dry-type, medium-voltage, three-phase, ~96 kV BIL .......................................... .. 0.02 0.02 0.03 0.04 0.04 

Total ..................................................................................................................... . 4.98 5.75 6.71 7.46 8.18 
45412 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

I. Life-Cycle Cost Sub-Group Analysis

The LCC sub-group analysis evaluates

impacts on identifiable groups of

customers, such as customers of

different business types, who may be

disproportionately affected by any

national energy efficiency standard

level. The Department intends to

analyze the LCC and PBPs for those

customers that fall into those

identifiable groups.

Also, the Department plans to

examine variations in energy prices and

variations in energy use that might

affect the NPV of a standard to customer

sub-populations. To the extent possible,

the Department will get estimates of the

variability of each input parameter and

consider this variability in its

calculation of customer impacts.

Variations in energy use for a particular

equipment type depend on factors such

as climate and type of business.

The Department will determine the

effect on customer sub-groups using the

LCC spreadsheet model. The

spreadsheet model used for the LCC

analysis can be used with different data

inputs. The standard LCC analysis

includes various customer types that

use distribution transformers. The

Department can analyze the LCC for any

sub-group, such as rural electric

cooperatives, by using the LCC

spreadsheet model and sampling only

that sub-group. Details of this model are

explained in section II.F, describing the

LCC and PBP analyses. The Department

will be especially sensitive to purchase

price increases ("first cost" increases) to

avoid negative impacts on identifiable

population groups such as small

businesses (i.e., those with low annual

revenues), which may not be able to

afford a significant increase in the price

of distribution transformers.

J. Manufacturer Impact Analysis

The Process Rule, 10 CFR Part 430,

Subpart C, Appendix A, provides

guidance for conducting a manufacturer

impact analysis, and the Department

intends to apply this methodology to its

evaluation of standards for distribution

transformers. The Process Rule gives

guidelines for the consideration of

financial impacts, as well as a wide

range of quantitative and qualitative

industry impacts that might occur

following the adoption of a standard.

For example, a particular standard level,

if adopted by DOE, could require

changes to distribution transformer

manufacturing practices. The

Department intends to identify and

understand these impacts through

interviews with manufacturers and

other stakeholders during the NOPR

stage of its analysis.

1. Sources of Information for the

Manufacturer Impact Analysis

Many of the analyses described above,

including manufacturing costs and

shipment forecasts, provide important

information applicable to the

manufacturer impact analysis. The

Department's contractor will review and

supplement this information through

interviews with manufacturers. This

interview process plays a key role in the

manufacturer impact analysis because it

allows interested parties to privately

express their views on important issues.

To preserve confidentiality, the

Department's contractor aggregates these

perspectives across manufacturers,

creating a combined opinion or estimate

for the Department. This process

enables the Department to incorporate

sensitive information from

manufacturers in the rulemaking

process, without specifying precisely

which manufacturer provided a certain

set of data.

The Department conducts interviews

with manufacturers to gain insight into

the range of potential impacts of

standards. Information is solicited

specifically on the potential impacts of

efficiency levels on sales, direct

employment, capital assets, and

industrial competitiveness. The

Department prefers an interactive

interview process because it helps

clarify responses and identify additional

issues. Before the interviews, the

Department will circulate a draft

document showing the estimates of the

financial parameters based on publicly

available information. The Department

will solicit comments and suggestions

on these estimates during the

interviews.

The Department's contractor will ask

interview participants to notify it, either

in writing or orally, of any confidential

materials. The Department will consider

all relevant information in its decisionmaking process. However, DOE will not

make confidential information available

in the public record. The Department

also will ask participants to identify all

information that they wish to have

included in the public record and

whether they want it to be presented

with or without attribution.

The Department's contractors will

collate the completed interview

questionnaires and prepare a summary

of the major issues.

2. Industry Cash Flow Analysis

The industry cash flow analysis relies

primarily on the Government Regulatory

Impact Model (GRIM). The Department

uses GRIM to analyze the financial

impacts of more stringent energy

efficiency standards on the industry.

The GRIM analysis uses a number of

factors to determine annual cash flows

from a new standard: Annual expected

revenues; manufacturer costs (including

cost of goods, capital depreciation,

research and development, selling, and

general administrative costs); taxes; and

conversion expenditures. The

Department compares the results against

base case projections that involve no

new standards. The financial impact of

new standards is the difference between

the two sets of discounted annual cash

flows. Other performance metrics, such

as return on invested capital, also are

available from GRIM.

3. Manufacturer Sub-Group Analysis

Industry cost estimates are not

adequate to assess differential impacts

among sub-groups of manufacturers.

Small and niche manufacturers, or

manufacturers exhibiting a cost

structure that differs largely from the

industry average could experience a

greater negative impact. The Department

typically uses the results of the industry

characterization to group manufacturers

exhibiting similar characteristics.

During the manufacturer interview

process, the Department's contractor

will discuss the potential sub-groups

and sub-group members that DOE has

identified for the analysis. The

contractor will encourage the

manufacturers to recommend subgroups or characteristics that are

appropriate for the manufacturer subgroup analysis.

4. Competitive Impacts Assessment

The Department also takes into

consideration whether a new standard is

likely to reduce industry competition

and the Attorney General determines

the impacts, if any, of any reduced

competition. The Department's

contractors will make a determined

effort to gather firm-specific financial

information and impacts. The

competitive analysis will focus on

assessing the impacts to smaller, yet

significant, manufacturers. The

Department will base the assessment on

manufacturing cost data and on

information collected from interviews

with manufacturers, which will focus

on gathering information to help assess

asymmetrical cost increases to some

manufacturers, increased proportions of

fixed costs that could potentially

increase business risks, and potential

barriers to market entry (e.g., proprietary

technologies).

 EE-RM/STD-00-550 COMMENT 53.1

#53. 

45412 Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 

I. Life-Cycle Cost Sub-Group Analysis 

The LCC sub-group analysis evaluates 

impacts on identifiable groups of 

customers, such as customers of 

different business types, who may be 

disproportionately affected by any 

national energy efficiency standard 

level. The Department intends to 

analyze the LCC and PBPs for those 

customers that fall into those 

identifiable groups. 

Also, the Department plans to 

examine variations in energy prices and 

variations in energy use that might 

affect the NPV of a standard to customer 

sub-populations. To the extent possible, 

the Department will get estimates of the 

variability of each input parameter and 

consider this variability in its 

calculation of customer impacts. 

Variations in energy use for a particular 

equipment type depend on factors such 

as climate and type of business. 

The Department will determine the 

effect on customer sub-groups using the 

LCC spreadsheet model. The 

spreadsheet model used for the Lec 

analysis can be used with different data 

inputs. The standard LCC analysis 

includes various customer types that 

use distribution transformers. The 

Department can analyze the Lec for any 

sub-group, such as rural electric 

cooperatives, by using the LCC 

spreadsheet model and sampling only 

that sub-group. Details of this model are 

explained in section II.F, describing the 

Lee and PBP analyses. The Department 

will be especially sensitive to purchase 

price increases ("first cost" increases) to 

avoid negative impacts on identifiable 

population groups such as small 

businesses (i.e., those with low annual 

revenues), which may not be able to 

afford a significant increase in the price 

of distribution transformers. 

f. Manufacturer Impact Analysis 

The Process Rule, 10 CFR Part 430, 

Subpart C, Appendix A, provides 

guidance for conducting a manufacturer 

impact analysis, and the Department 

intends to apply this methodology to its 

evaluation of standards for distribution 

transformers. The Process Rule gives 

guidelines for the consideration of 

financial impacts, as well as a wide 

range of quantitative and qualitative 

industry impacts that might occur 

following the adoption of a standard. 

For example, a particular standard level, 

if adopted by DOE, could require 

changes to distribution transformer 

manufacturing practices. The 

Department intends to identify and 

understand these impacts through 

interviews with manufacturers and 

other stakeholders during the NOPR 

stage of its analysis. 

1. Sources of Information for the 

Manufacturer Impact Analysis 

Many of the analyses described above, 

including manufacturing costs and 

shipment forecasts, provide important 

information applicable to the 

manufacturer impact analysis. The 

Department's contractor will review and 

supplement this information through 

interviews with manufacturers. This 

interview process plays a key role in the 

manufacturer impact analysis because it 

allows interested parties to privately 

express their views on important issues. 

To preserve confidentiality, the 

Department's contractor aggregates these 

perspectives across manufacturers, 

creating a combined opinion or estimate 

for the Department. This process 

enables the Department to incorporate 

sensitive information from 

manufacturers in the rulemaking 

process, without specifying precisely 

which manufacturer provided a certain 

set of data. 

The Department conducts interviews 

with manufacturers to gain insight into 

the range of potential impacts of 

standards. Information is solicited 

specifically on the potential impacts of 

efficiency levels on sales, direct 

employment, capital assets, and 

industrial competitiveness. The 

Department prefers an interactive 

interview process because it helps 

clarify responses and identify additional 

issues. Before the interviews, the 

Department will circulate a draft 

document showing the estimates of the 

financial parameters based on publicly 

available information. The Department 

will solicit comments and suggestions 

on these estimates during the 

interviews. 

The Department's contractor will ask 

interview participants to notify it, either 

in writing or orally, of any confidential 

materials. The Department will consider 

all relevant information in its decisionmaking process. However, DOE will not 

make confidential information available 

in the public record. The Department 

also will ask participants to identify all 

information that they wish to have 

included in the public record and 

whether they want it to be presented 

with or without attribution. 

The Department's contractors will 

collate the completed interview 

questionnaires and prepare a summary 

ofthe major issues. 

2. Industry Cash Flow Analysis 

The industry cash flow analysis relies 

primarily on the Government Regulatory 

Impact Model (GRIM). The Department 

uses GRIM to analyze the financial 

impacts of more stringent energy 

efficiency standards on the industry. 

The GRIM analysis uses a number of 

factors to determine annual cash flows 

from a new standard: Annual expected 

revenues; manufacturer costs (including 

cost of goods, capital depreciation, 

research and development, selling, and 

general administrative costs); taxes; and 

conversion expenditures. The 

Department compares the results against 

base case projections that involve no 

new standards. The financial impact of 

new standards is the difference between 

the two sets of discounted annual cash 

flows. Other performance metrics, such 

as return on invested capital, also are 

available from GRIM. 

3. Manufacturer Sub-Group Analysis 

Industry cost estimates are not 

adequate to assess differential impacts 

among sub-groups of manufacturers. 

Small and niche manufacturers, or 

manufacturers exhibiting a cost 

structure that differs largely from the 

industry average could experience a 

greater negative impact. The Department 

typically uses the results of the industry 

characterization to group manufacturers 

exhibiting similar characteristics. 

During the manufacturer interview 

process, the Department's contractor 

will discuss the potential sub-groups 

and sub-group members that DOE has 

identified for the analysis. The 

contractor will encourage the 

manufacturers to recommend subgroups or characteristics that are 

appropriate for the manufacturer subgroup analysis. 

4. Competitive Impacts Assessment 

The Department also takes into 

consideration whether a new standard is 

likely to reduce industry competition 

and the Attorney General determines 

the impacts, if any, of any reduced 

competition. The Department's 

contractors will make a determined 

effort to gather firm-specific financial 

information and impacts. The 

competitive analysis will focus on 

assessing the impacts to smaller, yet 

significant, manufacturers. The 

Department will base the assessment on 

manufacturing cost data and on 

information collected from interviews 

with manufacturers, which will focus 

on gathering information to help assess 

asymmetrical cost increases to some 

manufacturers, increased proportions of 

fixed costs that could potentially 

increase business risks, and potential 

barriers to market entry (e.g., proprietary 

technologies). 
Federal Register / Vol. 69, No. 145 / Thursday, July 29, 2004 / Proposed Rules

5. Cumulative Regulatory Burden

The Department will recognize and

seek to mitigate the overlapping effects

on manufacturers of new or revised DOE

standards and other regulatory actions

affecting the same products. DOE will

analyze and consider the impact on

manufacturers of multiple productspecific regulatory actions. These factors

will be considered in setting rulemaking

priorities, assessing manufacturers

impacts of a particular standard, and

establishing the effective date for a new

or revised standard. In particular, DOE

will seek to propose effective dates for

new or revised standards that are

appropriately coordinated with other

regulatory actions to mitigate any

cumulative burden.

K. Utility Impact Analysis

The Department intends to determine

whether a proposed standard will

achieve the maximum improvement in

energy efficiency or the maximum

reduction in energy use that is

technologically feasible and

economically justified. To determine

whether economic justification exists,

the Department will review comments

on the proposal and determine that the

benefits of the proposed standard

exceed its burdens to the greatest extent

practicable, weighing several factors. (42

U.S.C. 6295 (o)(2)(B)) To estimate the

effects of proposed distribution

transformer standard levels on the

electric utility industry, the Department

intends to use a variant of EIA's NEMS.4

EIA used NEMS to produce its Annual

Energy Outlook (AEO). The Department

will use a variant known as NEMS-BT

to provide key inputs to the analysis, as

well as some exogenous calculations.

The utility impact analysis is a

comparison between model results for

the base case and policy cases in which

proposed standards are in place. The

analysis will consist of forecasted

differences between the base case and

standards cases for electricity

generation, installed capacity, sales, and

prices.

The use of NEMS for the utility

impact analysis offers several

"For more information on NEMS, please refer to

the U.S. Department of Energy, Energy Information

Administration documentation. A useful summary

is National Energy Modeling System: An Overview

2000, DOE/EIA-0581(2000), March, 2000. The

Department/EIA approves use of the name NEMS to

describe only an official version of the model

without any modification to code or data. Because

this analysis entails some minor code modifications

and the model is run under various policy scenarios

that are variations of DOE/EIA assumptions, in this

analysis the Department refers to it by the name

NEMS-BT (BT is DOE's Building Technologies

Program, under whose aegis this work is

performed).

advantages. As the official DOE energy

forecasting model, it relies upon a set of

assumptions that are transparent and

have received wide exposure and

commentary. NEMS allows an estimate

of the interactions between the various

energy supply and demand sectors and

the economy as a whole. The utility

impact analysis will determine the

changes in installed capacity and

generation by fuel type produced by

each candidate standard level, as well as

changes in electricity sales to the

commercial sector.

The Department will conduct the

utility impact analysis as a variant of

AEO 2003, with the same basic set of

assumptions applied. For example, the

operating characteristics (energy

conversion efficiency, emissions rates,

etc.) of future electricity generating

plants are as specified in the AEO 2003

reference case, as are the prospects for

natural gas supply.

The Department will also explore

deviations from some of the reference

case assumptions to represent

alternative futures. Two alternative

scenarios use the high- and loweconomic-growth cases of AEO 2003

(the reference case corresponds to

medium growth). The high-economicgrowth case assumes higher projected

growth rates for population, labor force,

and labor productivity, resulting in

lower predicted inflation and interest

rates relative to the reference case. The

opposite is true for the low-growth case.

While the Department varies supplyside growth determinants in these cases,

AEO 2003 assumes the same reference

case energy prices for all three economic

growth cases. Different economic

growth scenarios will affect the rate of

growth of electricity demand.

The Department will generate

transformer load shapes for use in

NEMS using LCC and NES results. The

Department will then use NEMS to

predict growth in demand to build up

a projection of the total electric system

load growth for each region. The

Department will use the projection to

predict the necessary additions to

capacity. The Department will

implement the accounting of efficiency

standards in NEMS-BT by

decrementing the appropriate reference

case load shape. The Department will

determine the size of the decrement

using data for the per-unit energy

savings developed in the LCC and PBP

analyses and the shipments forecast

developed for the NES analysis.

Since the AEO 2003 version of NEMS

forecasts only to the year 2025, the

Department must extrapolate results to

2035. The Department will use EIA's

approach for forecasting fuel prices for

45413

the Federal Energy Management

Program (FEMP) for Federal sector

energy prices. FEMP uses these prices to

estimate life-cycle costs of Federal

equipment procurements. For petroleum

products, the Department will

determine regional price forecasts to

2035 from the average growth rate for

world oil prices over the years 2010 to

2025 used in combination with refinery

and distribution markups from the year

2025. Similarly, the Department will

derive natural gas prices to 2035 from

an average growth rate figure in

combination with regional prices from

the year 2025.

L. Employment Impact Analysis

DOE's Process Rule, 10 CFR Part 430,

Subpart C, Appendix A, provides

guidance for consideration of the impact

of candidate standard levels on

employment, both direct and indirect.

The Process Rule states a general

presumption against any proposed

standard level that would cause

significant plant closures or losses of

domestic employment, unless

specifically identified expected benefits

of the standard would outweigh the

adverse effects.

The Department estimates the impacts

of standards on employment for

equipment manufacturers, relevant

service industries, energy suppliers, and

the economy in general. Both indirect

and direct employment impacts are

covered. Direct employment impacts

would result if standards led to a change

in the number of employees at

manufacturing plants and related

supply and service firms. Direct impact

estimates are covered in the

manufacturer impact analysis.

Indirect impacts are impacts on the

national economy other than in the

manufacturing sector being regulated.

Indirect impacts may result both from

expenditures shifting among goods

(substitution effect) and changes in

income which lead to a change in

overall expenditure levels (income

effect). The Department defines indirect

employment impacts from standards as

net jobs eliminated or created in the

general economy as a result of increased

spending driven by the increased price

of equipment and reduced expenditures

on energy.

The Department expects new

distribution transformer standards to

increase the total installed cost of

equipment (customer purchase price

plus sales tax, and installation). It

expects the new standards to decrease

energy consumption, and thus

expenditures on energy. Over time, the

increased total installed cost is paid

back through energy savings. The

 EE-RM/STD-00-550 COMMENT 53.1

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Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45413 

5. Cumulative Regulatory Burden 

The Department will recognize and 

seek to mitigate the overlapping effects 

on manufacturers of new or revised DOE 

standards and other regulatory actions 

affecting the same products. DOE will 

analyze and consider the impact on 

manufacturers of multiple productspecific regulatory actions. These factors 

will be considered in setting rulemaking 

priorities, assessing manufacturers 

impacts of a particular standard, and 

establishing the effective date for a new 

or revised standard. In particular, DOE 

will seek to propose effective dates for 

new or revised standards that are 

appropriately coordinated with other 

regulatory actions to mitigate any 

cumulative burden. 

K. Utility Impact Analysis 

The Department intends to determine 

whether a proposed standard will 

achieve the maximum improvement in 

energy efficiency or the maximum 

reduction in energy use that is 

technologically feasible and 

economically justified. To determine 

whether economic justification exists, 

the Department will review comments 

on the proposal and determine that the 

benefits of the proposed standard 

exceed its burdens to the greatest extent 

practicable, weighing several factors. (42 

U.S.C. 6295 (0)(2)(B)) To estimate the 

effects of proposed distribution 

transformer standard levels on the 

electric utility industry, the Department 

intends to use a variant ofEIA's NEMS.4 

EIA used NEMS to produce its Annual 

Energy Outlook (AEO). The Department 

will use a variant known as NEMS-BT 

to provide key inputs to the analysis, as 

well as some exogenous calculations. 

The utility impact analysis is a 

comparison between model results for 

the base case and policy cases in which 

proposed standards are in place. The 

analysis will consist of forecasted 

differences between the base case and 

standards cases for electricity 

generation, installed capacity, sales, and 

prices. 

The use of NEMS for the utility 

impact analysis offers several 

4 For more information on NEMS, please refer to 

the u.s. Department of Energy, Energy Information 

Administration documentation. A useful summary 

is National Energy Modeling System: An Overview 

2000, DOE/ErA-0581(2000), March, 2000. The 

Department/EIA approves use of the name NEMS to 

describe only an official version of the model 

without any modification to code or data. Because 

this analysis entails some minor code modifications 

and the model is run under various policy scenarios 

that are variations of DOE/ErA assumptions, in this 

analysis the Department refers to it by the name 

NEMS-BT (BT is DOE's Building Technologies 

Program, under whose aegis this work is 

performed). 

advantages. As the official DOE energy 

forecasting model, it relies upon a set of 

assumptions that are transparent and 

have received wide exposure and 

commentary. NEMS allows an estimate 

of the interactions between the various 

energy supply and demand sectors and 

the economy as a whole. The utility 

impact analysis will determine the 

changes in installed capacity and 

generation by fuel type produced by 

each candidate standard level, as well as 

changes in electricity sales to the 

commercial sector. 

The Department will conduct the 

utility impact analysis as a variant of 

AEO 2003, with the same basic set of 

assumptions applied. For example, the 

operating characteristics (energy 

conversion efficiency, emissions rates, 

etc.) of future electricity generating 

plants are as specified in the AEO 2003 

reference case, as are the prospects for 

natural gas supply. 

The Department will also explore 

deviations from some of the reference 

case assumptions to represent 

alternative futures. Two alternative 

scenarios use the high- and loweconomic-growth cases of AEO 2003 

(the reference case corresponds to 

medium growth). The high-economicgrowth case assumes higher projected 

growth rates for population, labor force, 

and labor productivity, resulting in 

lower predicted inflation and interest 

rates relative to the reference case. The 

opposite is true for the low-growth case. 

While the Department varies supplyside growth determinants in these cases, 

AEO 2003 assumes the same reference 

case energy prices for all three economic 

growth cases. Different economic 

growth scenarios will affect the rate of 

growth of electricity demand. 

The Department will generate 

transformer load shapes for use in 

NEMS using LCC and NES results. The 

Department will then use NEMS to 

predict growth in demand to build up 

a projection of the total electric system 

load growth for each region. The 

Department will use the projection to 

predict the necessary additions to 

capacity. The Department will 

implement the accounting of efficiency 

standards in NEMS-BT by 

decrementing the appropriate reference 

case load shape. The Department will 

determine the size of the decrement 

using data for the per-unit energy 

savings developed in the LCC and PBP 

analyses and the shipments forecast 

developed for the NES analysis. 

Since the AEO 2003 version of NEMS 

forecasts only to the year 2025, the 

Department must extrapolate results to 

2035. The Department will use ElA's 

approach for forecasting fuel prices for 

the Federal Energy Management 

Program (FEMP) for Federal sector 

energy prices. FEMP uses these prices to 

estimate life-cycle costs of Federal 

equipment procurements. For petroleum 

products, the Department will 

determine regional price forecasts to 

2035 from the average growth rate for 

world oil prices over the years 2010 to 

2025 used in combination with refinery 

and distribution markups from the year 

2025. Similarly, the Department will 

derive natural gas prices to 2035 from 

an average growth rate figure in 

combination with regional prices from 

the year 2025. 

L. Employment Impact Analysis 

DOE's Process Rule, 10 CFR Part 430, 

Subpart C, Appendix A, provides 

guidance for consideration of the impact 

of candidate standard levels on 

employment, both direct and indirect. 

The Process Rule states a general 

presumption against any proposed 

standard level that would cause 

significant plant closures or losses of 

domestic employment, unless 

specifically identified expected benefits 

of the standard would outweigh the 

adverse effects. 

The Department estimates the impacts 

of standards on employment for 

equipment manufacturers, relevant 

service industries, energy suppliers, and 

the economy in general. Both indirect 

and direct employment impacts are 

covered. Direct employment impacts 

would result if standards led to a change 

in the number of employees at 

manufacturing plants and related 

supply and service firms. Direct impact 

estimates are covered in the 

manufacturer impact analysis. 

Indirect impacts are impacts on the 

national economy other than in the 

manufacturing sector being regulated. 

Indirect impacts may result both from 

expenditures shifting among goods 

(substitution effect) and changes in 

income which lead to a change in 

overall expenditure levels (income 

effect). The Department defines indirect 

employment impacts from standards as 

net jobs eliminated or created in the 

general economy as a result of increased 

spending driven by the increased price 

of equipment and reduced expenditures 

on energy. 

The Department expects new 

distribution transformer standards to 

increase the total installed cost of 

equipment (customer purchase price 

plus sales tax, and installation). It 

expects the new standards to decrease 

energy consumption, and thus 

expenditures on energy. Over time, the 

increased total installed cost is paid 

back through energy savings. The 
45414 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

savings in energy expenditures may be

spent on new commercial investment

and other items. Using an input/output

model of the U.S. economy, this

analysis seeks to estimate the effects on

different sectors and the net impact on

jobs. The Department will estimate

national impacts for major sectors of the

U.S. economy in the NOPR. Public and

commercially available data sources and

software will be used to estimate

employment impacts. The Department

will make all methods and

documentation available for review.

For recent energy efficiency standards

rulemakings, the Department has used

the Impact of Building Energy Efficiency

Programs (IMBUILD) spreadsheet model

to analyze indirect employment

impacts. The Department's Building

Technologies Program office developed

IMBUILD, which is a special purpose

version of the Impact Analysis for

Planning (IMPLAN) national inputoutput model. IMPLAN specifically

estimates the employment and income

effects of building energy technologies.

The IMBUILD model is an economic

analysis system that focuses on those

sectors most relevant to buildings and

characterizes the interconnections

among 35 sectors as national inputoutput matrices using data from the

Bureau of Labor Statistics. The

IMBUILD output includes employment,

industry output, and wage income.

Changes in expenditures due to

commercial and industrial equipment

standards can be introduced to

IMBUILD as perturbations to existing

economic flows and the resulting net

national impact on jobs by sector can be

estimated.

Although the Department intends to

use IMBUILD for its analysis of

employment impacts, it welcomes any

input on tools and factors to be

considered.

M. Environmental Assessment

As with the utility impact analysis,

the Department will assess the impacts

of proposed distribution transformer

standard levels on certain

environmental indicators using NEMSBT to provide key inputs to the analysis,

as well as some exogenous calculations.

The environmental assessment produces

results in a manner similar to those

provided in AEO 2003.

The intent of the environmental

assessment is to provide emissions

results estimates, and to fulfill

requirements to properly quantify and

consider the environmental effects of all

new Federal rules. The environmental

assessment that will be produced by

NEMS-BT considers only two

pollutants, sulfur dioxide (SO2) and

nitrogen oxides (NOx), and one other

emission, carbon. The only form of

carbon the NEMS-BT model tracks is

carbon dioxide (CO2), so the carbon

discussed in this analysis is only in the

form of CO2. For each of the trial

standard levels, DOE will calculate total

undiscounted and discounted emissions

using NEMS-BT and will use external

analysis as needed.

The Department will conduct the

environmental assessment as an

incremental policy impact (i.e., a

transformer standard) of the AEO 2003

forecast, with the same basic set of

assumptions applied. For example, the

emissions characteristics of an

electricity generating plant will be

exactly those used in AEO 2003. Also,

forecasts conducted with NEMS-BT

take into consideration the supply-side

and demand-side effects on the electric

utility industry. Thus, the Department's

analysis will take into account any

factors impacting the type of electricity

generation and, in turn, the type and

amount of utility-industry-generated airborne emissions.

The NEMS-BT model tracks carbon

emissions with a specialized carbon

emissions estimation subroutine,

producing reasonably accurate results

due to the broad coverage of all sectors

and inclusion of interactive effects. Past

experience with carbon results from

NEMS suggests that emissions estimates

are somewhat lower than emissions

based on simple average factors. One of

the reasons for this divergence is that

NEMS tends to predict that conservation

displaces generating capacity in future

years. On the whole, NEMS-BT

provides carbon emissions results of

reasonable accuracy, at a level

consistent with other Federal published

results.

NEMS-BT also reports SO2 and NOx

which the Department has reported in

past analyses. The Clean Air Act

Amendments of 1990 set an SO2

emissions cap on all power generation.

The attainment of this target, however,

is flexible among generators through the

use of emissions allowances and

tradeable permits. NEMS includes a

module for SO2 allowance trading and

delivers a forecast of SO2 allowance

prices. Accurate simulation of SO2

trading implies that physical emissions

effects will be zero, as long as emissions

are at the ceiling. This fact has caused

considerable confusion in the past.

However, there is an SO2 benefit from

conservation in the form of a lower

allowance. price as a result of additional

allowances from this rule, and, if large

enough to be calculable by NEMS-BT,

the Department will report it. NEMS

also has an algorithm for estimating

NOx emissions from power generation.

Two recent regulatory actions proposed

by the EPA regarding regulations and

guidelines for best available retrofit

technology determinations and the

reduction of interstate transport of fine

particulate matter and ozone are tending

towards further NOx reductions and

likely to an eventual emissions cap on

nation-wide NOx. 69 FR 25184 (May 5,

2004) and 69 FR 32684 (June 10, 2004).

As with SO2 emissions, a cap on NOx

emissions will likely result in no

physical emissions effects from

equipment efficiency standards.

The reporting of the results for the

environmental assessment are similar to

a complete NEMS run as published in

the AEO 2003. These results include

power sector emissions for SO2, NOx,

and carbon, and SO2 prices in five-year

forecasted increments extrapolated to

the year 2035. The outcome of the

analysis for each candidate standard

level is reported as a deviation from the

AEO 2003 reference (base) case.

N. Regulatory Impact Analysis

The Department will prepare a draft

regulatory impact analysis in

compliance with Executive Order

12866, "Regulatory Planning and

Review," which will be subject to

review by the Office of Management and

Budget's Office of Information and

Regulatory Affairs (OIRA). 58 FR 51735.

As part of the regulatory impact

analysis, the Department will identify

and seek to mitigate the overlapping

effects on manufacturers of new or

revised DOE standards and other

regulatory actions affecting the same

equipment. Through manufacturer

interviews and literature searches, the

Department will compile information on

burdens from existing and impending

regulations affecting distribution

transformers. The Department also seeks

input from stakeholders regarding

regulations that it should consider.

The NOPR will include a complete

quantitative analysis of alternatives to

the proposed conservation standards.

The Department plans to use the NES

spreadsheet model (as discussed in

section II.H on the national impact

analysis) to calculate the NES and NPV

corresponding to specified alternatives

to the proposed conservation standards.

III. Proposed Standards Scenarios

The Process Rule, 10 CFR Part 430,

Subpart C, Appendix A, gives guidance

to the Department to specify candidate

standards levels in the ANOPR, but not

to propose a particular standard. The

Department intends to review the public

input received during the comment

period following the ANOPR public

 EE-RM/STD-00-550 COMMENT 53.1

45414 Federal Register/Vol. 69, No. 145/Thursciay, July 29, 2004/Proposeci Rules 

savings in energy expenditures may be 

spent on new commercial investment 

and other items. Using an input/output 

model ofthe U.S. economy, this 

analysis seeks to estimate the effects on 

different sectors and the net impact on 

jobs. The Department will estimate 

national impacts for major sectors of the 

U.S. economy in the NOPR. Public and 

commercially available data sources and 

software will be used to estimate 

employment impacts. The Department 

will make all methods and 

documentation available for review. 

For recent energy efficiency standards 

rulemakings, the Department has used 

the Impact of Building Energy Efficiency 

Programs (IMBUILD) spreadsheet model 

to analyze indirect employment 

impacts. The Department's Building 

Technologies Program office developed 

IMBUILD, which is a special purpose 

version of the Impact Analysis for 

Planning (IMPLAN) national inputoutput model. IMPLAN specifically 

estimates the employment and income 

effects of building energy technologies. 

The IMBUILD model is an economic 

analysis system that focuses on those 

sectors most relevant to buildings and 

characterizes the interconnections 

among 35 sectors as national inputoutput matrices using data from the 

Bureau of Labor Statistics. The 

IMBUILD output includes employment, 

industry output, and wage income. 

Changes in expenditures due to 

commercial and industrial equipment 

standards can be introduced to 

IMBUILD as perturbations to existing 

economic flows and the resulting net 

national impact on jobs by sector can be 

estimated. 

Although the Department intends to 

use IMBUILD for its analysis of 

employment impacts, it welcomes any 

input on tools and factors to be 

considered. 

M. Environmental Assessment 

As with the utility impact analysis, 

the Department will assess the impacts 

of proposed distribution transformer 

standard levels on certain 

environmental indicators using NEMSBT to provide key inputs to the analysis, 

as well as some exogenous calculations. 

The environmental assessment produces 

results in a manner similar to those 

provided in AEO 2003. 

The intent of the environmental 

assessment is to provide emissions 

results estimates, and to fulfill 

requirements to properly quantify and 

consider the environmental effects of all 

new Federal rules. The environmental 

assessment that will be produced by 

NEMS-BT considers only two 

pollutants, sulfur dioxide (S02) and 

nitrogen oxides (NOx), and one other 

emission, carbon. The only form of 

carbon the NEMS-BT model tracks is 

carbon dioxide (C02), so the carbon 

discussed in this analysis is only in the 

form of CO2. For each of the trial 

standard levels, DOE will calculate total 

undiscounted and discounted emissions 

using NEMS-BT and will use external 

analysis as needed. 

The Department will conduct the 

environmental assessment as an 

incremental policy impact (i.e., a 

transformer standard) of the AEO 2003 

forecast, with the same basic set of 

assumptions applied. For example, the 

emissions characteristics of an 

electricity generating plant will be 

exactly those used in AEO 2003. Also, 

forecasts conducted with NEMS-BT 

take into consideration the supply-side 

and demand-side effects on the electric 

utility industry. Thus, the Department's 

analysis will take into account any 

factors impacting the type of electricity 

generation and, in turn, the type and 

amount of utility-industry-generated airborne emissions. 

The NEMS-BT model tracks carbon 

emissions with a specialized carbon 

emissions estimation subroutine, 

producing reasonably accurate results 

due to the broad coverage of all sectors 

and inclusion of interactive effects. Past 

experience with carbon results from 

NEMS suggests that emissions estimates 

are somewhat lower than emissions 

based on simple average factors. One of 

the reasons for this divergence is that 

NEMS tends to predict that conservation 

displaces generating capacity in future 

years. On the whole, NEMS-BT 

provides carbon emissions results of 

reasonable accuracy, at a level 

consistent with other Federal published 

results. 

NEMS-BT also reports S02 and NOx 

which the Department has reported in 

past analyses. The Clean Air Act 

Amendments of 1990 set an S02 

emissions cap on all power generation. 

The attainment of this target, however, 

is flexible among generators through the 

use of emissions allowances and 

tradeable permits. NEMS includes a 

module for S02 allowance trading and 

delivers a forecast of S02 allowance 

prices. Accurate simulation of S02 

trading implies that physical emissions 

effects will be zero, as long as emissions 

are at the ceiling. This fact has caused 

considerable confusion in the past. 

However, there is an S02 benefit from 

conservation in the form of a lower 

allowance price as a result of additional 

allowances from this rule, and, if large 

enough to be calculable by NEMS-BT, 

the Department will report it. NEMS 

also has an algorithm for estimating 

NOx emissions from power generation. 

Two recent regulatory actions proposed 

by the EPA regarding regulations and 

guidelines for best available retrofit 

technology determinations and the 

reduction of interstate transport of fine 

particulate matter and ozone are tending 

towards further NOx reductions and 

likely to an eventual emissions cap on 

nation-wide NOx . 69 FR 25184 (May 5, 

2004) and 69 FR 32684 (June 10, 2004). 

As with S02 emissions, a cap on NOx 

emissions will likely result in no 

physical emissions effects from 

equipment efficiency standards. 

The reporting of the results for the 

environmental assessment are similar to 

a complete NEMS run as published in 

the AEO 2003. These results include 

power sector emissions for S02, NOx, 

and carbon, and S02 prices in five-year 

forecasted increments extrapolated to 

the year 2035. The outcome of the 

analysis for each candidate standard 

level is reported as a deviation from the 

AEO 2003 reference (base) case. 

N. Regulatory Impact Analysis 

The Department will prepare a draft 

regulatory impact analysis in 

compliance with Executive Order 

12866, "Regulatory Planning and 

Review," which will be subject to 

review by the Office of Management and 

Budget's Office of Information and 

Regulatory Affairs (OIRA). 58 FR 51735. 

As part of the regulatory impact 

analysis, the Department will identify 

and seek to mitigate the overlapping 

effects on manufacturers of new or 

revised DOE standards and other 

regulatory actions affecting the same 

equipment. Through manufacturer 

interviews and literature searches, the 

Department will compile information on 

burdens from existing and impending 

regulations affecting distribution 

transformers. The Department also seeks 

input from stakeholders regarding 

regulations that it should consider. 

The NOPR will include a complete 

quantitative analysis of alternatives to 

the proposed conservation standards. 

The Department plans to use the NES 

spreadsheet model (as discussed in 

section ILH on the national impact 

analysis) to calculate the NES and NPV 

corresponding to specified alternatives 

to the proposed conservation standards. 

III. Proposed Standards Scenarios 

The Process Rule, 10 CFR Part 430, 

Subpart C, Appendix A, gives guidance 

to the Department to specify candidate 

standards levels in the ANOPR, but not 

to propose a particular standard. The 

Department intends to review the public 

input received during the comment 

period following the ANOPR public 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

meeting and update the analyses

appropriately for each product class

before issuing the NOPR.

The Department seeks comments on

whether standards that meet alternative

scenarios would provide energy savings

to the Nation comparable to the savings

that would be obtained by the highest

standards that are technologically

feasible and economically justified,

effective in 2007, or the final date to be

determined in the NOPR analysis. The

Department may consider standards that

meet the following alternative scenarios,

for example:

0 A moderate increase in the

efficiency level at an earlier effective

date, for example, an effective date two

years after the publication of the Final

Rule.

0 A larger increase in efficiency level

at a later effective date.

0 A two-phase approach combining

the two scenarios, for example, a

moderate increase in efficiency level for

some product classes effective at an

earlier date and an even higher

efficiency level effective at a later date.

IV. Public Participation

A. Attendance at Public Meeting

The time and date of the public

meeting are listed in the DATES section

at the beginning of this notice of

proposed rulemaking. Anyone who

wants to attend the public meeting must

notify Ms. Brenda Edwards-Jones at

(202) 586-2945. Foreign nationals

visiting DOE Headquarters are subject to

advance security screening procedures,

requiring a 30-day advance notice. A

foreign national who wishes to

participate in the meeting must tell DOE

of this fact as soon as possible by

contacting Ms. Brenda Edwards-Jones to

initiate the necessary procedures.

B. Procedure for Submitting Requests To

Speak

Any person who has an interest in

today's notice, or who is a

representative of a group or class of

persons that has an interest in these

issues, may request an opportunity to

make an oral presentation. Please handdeliver requests to speak, along with a

computer diskette or CD in WordPerfect,

Microsoft Word, PDF, or text (ASCII) file

format to the address shown at the

beginning of this advance notice of

proposed rulemaking between the hours

of 9 a.m. and 4 p.m., Monday through

Friday, except Federal holidays.

Requests may also be sent by mail or email to: Brenda.Edwardsjones@ee.doe.gov.

Persons requesting to speak should

briefly describe the nature of their

interest in this rulemaking and provide

a telephone number for contact. The

Department requests persons selected to

be heard to submit an advance copy of

their statements at least two weeks

before the public meeting. At its

discretion, DOE may permit any person

who cannot supply an advance copy of

his or her statement to participate, if

that person has made advance

alternative arrangements with the

Building Technologies Program. The

request to give an oral presentation

should ask for such alternative

arrangements.

C. Conduct of Public Meeting

The Department will designate a DOE

official to preside at the public meeting

and may also use a professional

facilitator to aid discussion. The

meeting will not be a judicial or

evidentiary-type public hearing, but

DOE will conduct it in accordance with

5 U.S.C. 553 and section 336 of EPCA.

(42 U.S.C. 6306) A court reporter will be

present to record the transcript of the

proceedings. The Department reserves

the right to schedule the order of

presentations and to establish the

procedures governing the conduct of the

public meeting. After the public

meeting, interested parties may submit

further comments on the proceedings as

well as on any aspect of the rulemaking

until the end of the comment period.

The public meeting will be conducted

in an informal, conference style. The

Department will present summaries of

comments received before the public

meeting, allow time for presentations by

participants, and encourage all

interested parties to share their views on

issues affecting this rulemaking. Each

participant will be allowed to make a

prepared general statement (within time

limits determined by DOE) before the

discussion of specific topics. The

Department will permit other

participants to comment briefly on any

general statements.

At the end of all prepared statements

on a topic, DOE will permit participants

to clarify their statements briefly and

comment on statements made by others.

Participants should be prepared to

answer questions by DOE and by other

participants concerning these issues.

Department representatives may also

ask questions of participants concerning

other matters relevant to the public

meeting. The official conducting the

public meeting will accept additional

comments or questions from those

attending, as time permits. The

presiding official will announce any

further procedural rules or modification

of the above procedures that may be

45415

needed for the proper conduct of the

public meeting.

The Department will make the entire

record of this proposed rulemaking,

including the transcript from the public

meeting, available for inspection at the

U.S. Department of Energy, Forrestal

Building, Room 1J-018 (Resource Room

of the Building Technologies Program),

1000 Independence Avenue, SW.,

Washington, DC, (202) 586-9127,

between 9 a.m. and 4 p.m., Monday

through Friday, except Federal holidays.

Any person may buy a copy of the

transcript from the transcribing reporter.

D. Submission of Comments

The Department will accept

comments, data, and information

regarding all aspects of this ANOPR

before or after the public meeting, but

no later than the date provided at the

beginning of this advance notice of

proposed rulemaking. Please submit

comments, data, and information

electronically. Send them to the

following E-mail address: Transformer

ANOPRComment@ee.doe.gov. Submit

electronic comments in WordPerfect,

Microsoft Word, PDF, or text (ASCII) file

format and avoid the use of special

characters or any form of encryption.

Comments in electronic format should

be identified by the docket number EERM/STD-00-550, and wherever

possible carry the electronic signature of

the author. Absent an electronic

signature, comments submitted

electronically must be followed and

authenticated by submitting the signed

original paper document. No

telefacsimiles (faxes) will be accepted.

Pursuant to 10 CFR 1004.11, any

person submitting information that he

or she believes to be confidential and

exempt by law from public disclosure

should submit two copies: one copy of

the document including all the

information believed to be confidential,

and one copy of the document with the

information believed to be confidential

deleted. The Department of Energy will

make its own determination about the

confidential status of the information

and treat it according to its

determination.

Factors of interest to the Department

when evaluating requests to treat

submitted information as confidential

include: (1) A description of the items;

(2) whether and why such items are

customarily treated as confidential

within the industry; (3) whether the

information is generally known by, or

available from, other sources; (4)

whether the information has previously

been made available to others without

obligation concerning its

confidentiality; (5) an explanation of the

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register/Vol. 69, No. 145/Thursday, July 29, 2004/Proposed Rules 45415 

meeting and update the analyses 

appropriately for each product class 

before issuing the NOPR. 

The Department seeks comments on 

whether standards that meet alternative 

scenarios would provide energy savings 

to the Nation comparable to the savings 

that would be obtained by the highest 

standards that are technologically 

feasible and economically justified, 

effective in 2007, or the final date to be 

determined in the NOPR analysis. The 

Department may consider standards that 

meet the following alternative scenarios, 

for example: 

" A moderate increase in the 

efficiency level at an earlier effective 

date, for example, an effective date two 

years after the publication of the Final 

Rule. 

" A larger increase in efficiency level 

at a later effective date. 

• A two-phase approach combining 

the two scenarios, for example, a 

moderate increase in efficiency level for 

some product classes effective at an 

earlier date and an even higher 

efficiency level effective at a later date. 

IV. Public Participation 

A. Attendance at Public Meeting 

The time and date of the public 

meeting are listed in the DATES section 

at the beginning of this notice of 

proposed rulemaking. Anyone who 

wants to attend the public meeting must 

notify Ms. Brenda Edwards-Jones at 

(202) 586-2945. Foreign nationals 

visiting DOE Headquarters are subject to 

advance security screening procedures, 

requiring a 3D-day advance notice. A 

foreign national who wishes to 

participate in the meeting must tell DOE 

of this fact as soon as possible by 

contacting Ms. Brenda Edwards-Jones to 

initiate the necessary procedures. 

B. Procedure for Submitting Requests To 

Speak 

Any person who has an interest in 

today's notice, or who is a 

representative of a group or class of 

persons that has an interest in these 

issues, may request an opportunity to 

make an oral presentation. Please handdeliver requests to speak, along with a 

computer diskette or CD in WordPerfect, 

Microsoft Word, PDF, or text (ASCII) file 

format to the address shown at the 

beginning of this advance notice of 

proposed rule making between the hours 

of 9 a.m. and 4 p.m., Monday through 

Friday, except Federal holidays. 

Requests may also be sent by mail or email to: Brenda.EdwardsJones@ee.doe.gov. 

Persons requesting to speak should 

briefly describe the nature of their 

interest in this rulemaking and provide 

a telephone number for contact. The 

Department requests persons selected to 

be heard to submit an advance copy of 

their statements at least two weeks 

before the public meeting. At its 

discretion, DOE may permit any person 

who cannot supply an advance copy of 

his or her statement to participate, if 

that person has made advance 

alternative arrangements with the 

Building Technologies Program. The 

request to give an oral presentation 

should ask for such alternative 

arrangements. 

C. Conduct of Public Meeting 

The Department will designate a DOE 

official to preside at the public meeting 

and may also use a professional 

facilitator to aid discussion. The 

meeting will not be a judicial or 

evidentiary-type public hearing, but 

DOE will conduct it in accordance with 

5 U.S.C. 553 and section 336 ofEPCA. 

(42 U.S.C. 6306) A court reporter will be 

present to record the transcript of the 

proceedings. The Department reserves 

the right to schedule the order of 

presentations and to establish the 

procedures governing the conduct of the 

public meeting. After the public 

meeting, interested parties may submit 

further comments on the proceedings as 

well as on any aspect of the rulemaking 

until the end of the comment period. 

The public meeting will be conducted 

in an informal, conference style. The 

Department will present summaries of 

comments received before the public 

meeting, allow time for presentations by 

participants, and encourage all 

interested parties to share their views on 

issues affecting this rulemaking. Each 

participant will be allowed to make a 

prepared general statement (within time 

limits determined by DOE) before the 

discussion of specific topics. The 

Department will permit other 

participants to comment briefly on any 

general statements. 

At the end of all prepared statements 

on a topic, DOE will permit participants 

to clarify their statements briefly and 

comment on statements made by others. 

Participants should be prepared to 

answer questions by DOE and by other 

participants concerning these issues. 

Department representatives may also 

ask questions of participants concerning 

other matters relevant to the public 

meeting. The official conducting the 

public meeting will accept additional 

comments or questions from those 

attending, as time permits. The 

presiding official will announce any 

further procedural rules or modification 

of the above procedures that may be 

needed for the proper conduct of the 

public meeting. 

The Department will make the entire 

record of this proposed rulemaking, 

including the transcript from the public 

meeting, available for inspection at the 

U.S. Department of Energy, Forrestal 

Building, Room IJ-018 (Resource Room 

of the Building Technologies Program), 

1000 Independence Avenue, SW., 

Washington, DC, (202) 586-9127, 

between 9 a.m. and 4 p.m., Monday 

through Friday, except Federal holidays. 

Any person may buy a copy of the 

transcript from the transcribing reporter. 

D. Submission of Comments 

The Department will accept 

comments, data, and information 

regarding all aspects of this ANOPR 

before or after the public meeting, but 

no later than the date provided at the 

beginning of this advance notice of 

proposed rulemaking. Please submit 

comments, data, and information 

electronically. Send them to the 

following E-mail address: Transformer 

ANOPRComment@ee.doe.gov. Submit 

electronic comments in WordPerfect, 

Microsoft Word, PDF, or text (ASCII) file 

format and avoid the use of special 

characters or any form of encryption. 

Comments in electronic format should 

be identified by the docket number EERM/STD-00-550, and wherever 

possible carry the electronic signature of 

the author. Absent an electronic 

signature, comments submitted 

electronically must be followed and 

authenticated by submitting the signed 

original paper document. No 

telefacsimiles (faxes) will be accepted. 

Pursuant to 10 CFR 1004.11, any 

person submitting information that he 

or she believes to be confidential and 

exempt by law from public disclosure 

should submit two copies: one copy of 

the document including all the 

information believed to be confidential, 

and one copy of the document with the 

information believed to be confidential 

deleted. The Department of Energy will 

make its own determination about the 

confidential status of the information 

and treat it according to its 

determination. 

Factors of interest to the Department 

when evaluating requests to treat 

submitted information as confidential 

include: (1) A description ofthe items; 

(2) whether and why such items are 

customarily treated as confidential 

within the industry; (3) whether the 

information is generally known by, or 

available from, other sources; (4) 

whether the information has previously 

been made available to others without 

obligation concerning its 

confidentiality; (5) an explanation of the 
45416 Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

competitive injury to the submitting

person which would result from public

disclosure; (6) when such information

might lose its confidential character due

to the passage of time; and (7) why

disclosure of the information would be

contrary to the public interest.

E. Issues on Which DOE Seeks Comment

The Department is interested in

receiving comments on all aspects of

this ANOPR. DOE especially invites

comments or data to improve the

Departments' analysis, including data or

information that will respond to the

following questions or concerns that

were addressed in this ANOPR:

1. Definition and Coverage

The Department seeks to clarify

coverage under this proposed activity.

This ANOPR proposes a definition that

more closely parallels NEMA's TP 1,

outlining a broad scope of coverage and

then identifying exemptions. The

Department invites stakeholders to

comment on the new distribution

transformer definition, including the

revised scope, the exemptions list, and

the exemptions list definitions (see

section ILA for details).

2. Product Classes

The Department proposes product

classes that are in keeping with those in

NEMA's TP 1-2002 document,

specifically by breaking down the

population of distribution transformers

by type of insulation (liquid-immersed

or dry-type), number of phases (single or

three), voltage (low or medium), and BIL

rating (for medium-voltage dry-types).

The Department is proposing a greater

degree of specificity by BIL rating than

that provided in NEMA's TP 1-2002

document. The Department requests

feedback from stakeholders on its BIL

classification system for mediumvoltage, dry-type transformers (see

section II.A for details).

3. Engineering Analysis Inputs

In Chapter 5 of the TSD, the

Department presents all the costs of

material used as design inputs to the

modeling software. The Department

asks that stakeholders, particularly

manufacturers, review the material

prices and comment on whether they

represent reasonable input costs for the

engineering analysis.

4. Design Option Combinations

For each representative unit analyzed,

the Department selected several

methods of construction, by varying

core steels and winding material. These

combinations represent the most

common types of transformers made, as

well as the lowest first-cost and the

maximum technologically feasible

design. The complete breakdown of the

design option combinations is presented

in Chapter 5 of the TSD. The

Department requests that stakeholders

review these design option

combinations and comment on whether

they are the best ones to use for a given

representative unit. Also, the

Department requests comments on the

screening analysis, regarding both

technologies and materials that were

included and those screened out from

further consideration. (See section II.B

for details.)

5. The 0.75 Scaling Rule

The Department applied a 0.75 power

law scaling rule to two key components

of the transformer efficiency analysis:

(a) In simplifying the engineering

analysis by taking 115 different kVA

ratings and turning them into 13

engineering design lines with 13

representative units, the Department

committed to using the 0.75 scaling rule

to scale losses from the representative

unit to other kVA ratings within a

design line. The Department requests

comments on this practice, discussed in

section II.C.2 and outlined in Chapter 5

of the TSD.

(b) To simplify the economic analysis,

the Department extrapolated economic

costs and benefits for a particular design

line to each of the kVA ratings using the

0.75 rule. Not all economic costs and

benefits of transformer efficiency scale

according to the 0.75 rule, although the

rule may be a reasonable approximation

for ranges of kVA ratings. The

Department requests comment on the

desirability of having a simple scaling

for transformer efficiency economics

versus using more detailed scaling

methods that may result in a more

complicated relationship between kVA

rating and efficiency level.

6. Modeling of Transformer Load

Profiles

Lacking sufficient empirical

transformer loading data, the

Department developed models of

transformer loads specific to each type

of transformer. The Department requests

comments on the methods it employed

as well as sources of specific loading

data that it could use in the NOPR

analyses. (See section II.F for details.)

7. Distribution Chain Markups

The Department used cost data from

RS Means combined with manufacturer

price estimates and U.S. economic

census data to estimate markups and

installation costs for transformers from

the factory door through completed

installation. The Department requests

stakeholder feedback on markup factors,

methods, and data used by the

Department. (See section II.E for

details.)

8. Discount Rate Selection and Use

The Department used a weighted

average cost of capital as the discount

rate for the LCC and the OMB-mandated

discounted rates for the NPV

calculation. The Department requests

stakeholder feedback on the

appropriateness of these discount rates.

(See sections II.F and II.H for details.)

9. Baseline Determination Through

Purchase Evaluation Formulae

The Department characterized current

market conditions for both liquidimmersed and dry-type transformers

using a distribution of load and no-load

loss values, and assumed percentages of

customers that evaluate their

transformer purchases by considering

the value of load and no-load losses.

The Department invites further

comment on the purchase decision

model and transformer evaluation

behavior for both liquid-immersed and

dry-type transformers, especially:

e Actual A and B values used in the

current market,

® Actual efficiency of the low firstcost designs currently on the market

since the efficiency of the low first-cost

designs has a large impact on overall

energy savings estimates,

® Applicability of the approach to

characterize both medium- and lowvoltage, dry-type transformer market

behavior, and

The stability over time of the

transformer market, especially the

percent of evaluators and levels of A

and B values.

(See section II.F for details.)

10. Electricity Prices

The Department requests stakeholder

feedback on the two methods it used for

this rulemaking to determine the cost of

electricity consumed by transformers.

For dry-type transformers used

predominately by commercial and

industrial firms, the Department

calculated estimated bills based on a

sample of electricity tariffs. For liquidimmersed transformers, the Department

used market and FERC Form 714 data to

estimate the marginal cost of electricity

to utilities. (See section II.F for details.)

11. Load Growth Over Time

Since the Department lacks specific

information on transformer load growth

over time, it assumed for its default

ANOPR scenario a 1-percent annual

growth rate for liquid-immersed

 EE-RM/STD-00-550 COMMENT 53.1

45416 Federal Register IVoI. 69, No. 145 I Thursday, July 29, 2004 I Proposed Rules 

competitive injury to the submitting 

person which would result from public 

disclosure; (6) when such information 

might lose its confidential character due 

to the passage of time; and (7) why 

disclosure of the information would be 

contrary to the public interest. 

E. Issues on Which DOE Seeks Comment 

The Department is interested in 

receiving comments on all aspects of 

this ANOPR. DOE especially invites 

comments or data to improve the 

Departments' analysis, including data or 

information that will respond to the 

following questions or concerns that 

were addressed in this ANOPR: 

1. Definition and Coverage 

The Department seeks to clarify 

coverage under this proposed activity. 

This ANOPR proposes a definition that 

more closely parallels NEMA's TP 1, 

outlining a broad scope of coverage and 

then identifying exemptions. The 

Department invites stakeholders to 

comment on the new distribution 

transformer definition, including the 

revised scope, the exemptions list, and 

the exemptions list definitions (see 

section ILA for details). 

2. Product Classes 

The Department proposes product 

classes that are in keeping with those in 

NEMA's TP 1-2002 document, 

specifically by breaking down the 

population of distribution transformers 

by type of insulation (liquid-immersed 

or dry-type), number of phases (single or 

three), voltage (low or medium), and ElL 

rating (for medium-voltage dry-types). 

The Department is proposing a greater 

degree of specificity by ElL rating than 

that provided in NEMA's TP 1-2002 

document. The Department requests 

feedback from stakeholders on its ElL 

classification system for mediumvoltage, dry-type transformers (see 

section ILA for details). 

3. Engineering Analysis Inputs 

In Chapter 5 ofthe TSD, the 

Department presents all the costs of 

material used as design inputs to the 

modeling software. The Department 

asks that stakeholders, particularly 

manufacturers, review the material 

prices and comment on whether they 

represent reasonable input costs for the 

engineering analysis. 

4. Design Option Combinations 

For each representative unit analyzed, 

the Department selected several 

methods of construction, by varying 

core steels and winding material. These 

combinations represent the most 

common types of transformers made, as 

well as the lowest first-cost and the 

maximum technologically feasible 

design. The complete breakdown of the 

design option combinations is presented 

in Chapter 5 of the TSD. The 

Department requests that stakeholders 

review these design option 

combinations and comment on whether 

they are the best ones to use for a given 

representative unit. Also, the 

Department requests comments on the 

screening analysis, regarding both 

technologies and materials that were 

included and those screened out from 

further consideration. (See section n.B 

for details.) 

5. The 0.75 Scaling Rule 

The Department applied a 0.75 power 

law scaling rule to two key components 

ofthe transformer efficiency analysis: 

(a) In simplifying the engineering 

analysis by taking 115 different kVA 

ratings and turning them into 13 

engineering design lines with 13 

representative units, the Department 

committed to using the 0.75 scaling rule 

to scale losses from the representative 

unit to other kVA ratings within a 

design line. The Department requests 

comments on this practice, discussed in 

section II.C.2 and outlined in Chapter 5 

of the TSD. 

(b) To simplify the economic analysis, 

the Department extrapolated economic 

costs and benefits for a particular design 

line to each ofthe kV A ratings using the 

0.75 rule. Not all economic costs and 

benefits of transformer efficiency scale 

according to the 0.75 rule, although the 

rule may be a reasonable approximation 

for ranges of kV A ratings. The 

Department requests comment on the 

desirability of having a simple scaling 

for transformer efficiency economics 

versus using more detailed scaling 

methods that may result in a more 

complicated relationship between kVA 

rating and efficiency level. 

6. Modeling of Transformer Load 

Profiles 

Lacking sufficient empirical 

transformer loading data, the 

Department developed models of 

transformer loads specific to each type 

of transformer. The Department requests 

comments on the methods it employed 

as well as sources of specific loading 

data that it could use in the NOPR 

analyses. (See section n.F for details.) 

7. Distribution Chain Markups 

The Department used cost data from 

RS Means combined with manufacturer 

price estimates and U.S. economic 

census data to estimate markups and 

installation costs for transformers from 

the factory door through completed 

installation. The Department requests 

stakeholder feedback on markup factors, 

methods, and data used by the 

Department. (See section ILE for 

details.) 

8. Discount Rate Selection and Use 

The Department used a weighted 

average cost of capital as the discount 

rate for the LCC and the OMB-mandated 

discounted rates for the NPV 

calculation. The Department requests 

stakeholder feedback on the 

appropriateness of these discount rates. 

(See sections n.F and n.H for details.) 

9. Baseline Determination Through 

Purchase Evaluation Formulae 

The Department characterized current 

market conditions for both liquidimmersed and dry-type transformers 

using a distribution of load and no-load 

loss values, and assumed percentages of 

customers that evaluate their 

transformer purchases by considering 

the value of load and no-load losses. 

The Department invites further 

comment on the purchase decision 

model and transformer evaluation 

behavior for both liquid-immersed and 

dry-type transformers, especially: 

• Actual A and B values used in the 

current market, • Actual efficiency of the low firstcost designs currently on the market 

since the efficiency ofthe low first-cost 

designs has a large impact on overall 

energy savings estimates, 

• Applicability of the approach to 

characterize both medium- and lowvoltage, dry-type transformer market 

behavior, and 

• The stability over time of the 

transformer market, especially the 

percent of evaluators and levels of A 

and B values. 

(See section II.F for details.) 

10. Electricity Prices 

The Department requests stakeholder 

feedback on the two methods it used for 

this rulemaking to determine the cost of 

electricity consumed by transformers. 

For dry-type transformers used 

predominately by commercial and 

industrial firms, the Department 

calculated estimated bills based on a 

sample of electricity tariffs. For liquidimmersed transformers, the Department 

used market and FERC Form 714 data to 

estimate the marginal cost of electricity 

to utilities. (See section ILF for details.) 

11. Load Growth Over Time 

Since the Department lacks specific 

information on transformer load growth 

over time, it assumed for its default 

ANOPR scenario a I-percent annual 

growth rate for liquid-immersed 
Federal Register /Vol. 69, No. 145 /Thursday, July 29, 2004 /Proposed Rules

transformers and zero-percent load

growth for dry-type transformers. The

Department requests stakeholders

comments on these assumptions. (See

section II.F for details.)

12. Life-Cycle Cost Sub-Groups

The Department has identified

various categories of utilities, such as

municipal utilities and rural electric

cooperatives, as possible sub-groups for

which to conduct a separate LCC

analysis. The Department seeks

stakeholder feedback regarding the most

appropriate sub-groups to include in the

NOPR analysis. (See section 11.1 for

details.)

13. Utility Deregulation Impacts

The Department is aware of ongoing

wholesale and retail deregulation

activities in the electric utility industry,

but is uncertain how this deregulation

will affect transformer purchase

decisions in the long term. The

Department requests comments from

stakeholders with specific information

regarding the impact of deregulation.

Utility deregulation will likely have the

most significant impacts on LCC results,

through changes in electricity prices.

LCC Details are found in TSD Chapter

8.

V. Regulatory Review and Procedural

Requirements

This advance notice of proposed

rulemaking was submitted for review to

OIRA in the Office of Management and

Budget under Executive Order 12866,

"Regulatory Planning and Review." 58

FR 51735. If DOE later proposes energy

conservation standards for certain

distribution transformers, the

rulemaking would likely constitute a

significant regulatory action, and DOE

would prepare and submit to OIRA for

review the assessment of costs and

benefits required by section 6(a)(3) of

45417

the Executive Order. In addition,

various other analyses and procedures

may apply to such future rulemaking

action, including those required by the

National Environmental Policy Act, 42

U.S.C. 4321 et seq.; the Unfunded

Mandates Act of 1995, Pub. L. 104-4;

the Paperwork Reduction Act, 44 U.S.C.

3501 et seq.; the Regulatory Flexibility

Act, 5 U.S.C. 601 et seq.; and certain

Executive Orders.

VI. Approval of the Office of the

Secretary

The Secretary of Energy has approved

publication of today's Advance Notice

of Proposed Rulemaking.

Issued in Washington, DC, on July 13,

2004.

David K. Garman,

Assistant Secretary, Energy Efficiency and

Renewable Energy.

[FR Doc. 04-16573 Filed 7-28-04; 8:45 am]

BILLING CODE 6450-01-P

 EE-RM/STD-00-550 COMMENT 53.1

#53.1 

Federal Register I Vol. 69, No. 145 I Thursday, July 29, 2004 I Proposed Rules 45417 

transformers and zero-percent load 

growth for dry-type transformers. The 

Department requests stakeholders 

comments on these assumptions. (See 

section II.F for details.) 

12. Life-Cycle Cost Sub-Groups 

The Department has identified 

various categories of utilities, such as 

municipal utilities and rural electric 

cooperatives, as possible sub-groups for 

which to conduct a separate LCC 

analysis. The Department seeks 

stakeholder feedback regarding the most 

appropriate sub-groups to include in the 

NOPR analysis. (See section ILl for 

details.) 

13. Utility Deregulation Impacts 

The Department is aware of ongoing 

wholesale and retail deregulation 

activities in the electric utility industry, 

but is uncertain how this deregulation 

will affect transformer purchase 

decisions in the long term. The 

Department requests comments from 

stakeholders with specific information 

regarding the impact of deregulation. 

Utility deregulation will likely have the 

most significant impacts on LCC results, 

through changes in electricity prices. 

LCC Details are found in TSD Chapter 

8. 

V. Regulatory Review and Procedural 

Requirements 

This advance notice of proposed 

rulemaking was submitted for review to 

OIRA in the Office of Management and 

Budget under Executive Order 12866, 

"Regulatory Planning and Review." 58 

FR 51735. If DOE later proposes energy 

conservation standards for certain 

distribution transformers, the 

rulemaking would likely constitute a 

significant regulatory action, and DOE 

would prepare and submit to OIRA for 

review the assessment of costs and 

benefits required by section 6(a)(3) of 

the Executive Order. In addition, 

various other analyses and procedures 

may apply to such future rulemaking 

action, including those required by the 

National Environmental Policy Act, 42 

U.S.C. 4321 et seq.; the Unfunded 

Mandates Act of 1995, Pub. 1. 104-4; 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq.; the Regulatory Flexibility 

Act, 5 U.S.C. 601 et seq.; and certain 

Executive Orders. 

VI. Approval ofthe Office ofthe 

Secretary 

The Secretary of Energy has approved 

publication of to day's Advance Notice 

of Proposed Rulemaking. 

Issued in Washington, DC, on July 13, 

2004. 

David K. Garman, 

Assistant Secretary, Energy Efficiency and 

Renewable Energy. 

[FR Doc. 04-16573 Filed 7-28-04; 8:45 am] 

BILLING CODE 6450-{)1-P