[Federal Register Volume 69, Number 145 (Thursday, July 29, 2004)]
[Proposed Rules]
[Pages 45376-45417]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-16573]



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Part II





Department of Energy





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Office of Energy Efficiency and Renewable Energy



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10 CFR Part 430



Energy Conservation Program for Commercial and Industrial Equipment: 
Energy Conservation Standards for Distribution Transformers; Proposed 
Rule

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

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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.

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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-AB08, by any of the following methods:
     Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the instructions for submitting comments.
     E-mail: Transformer[email protected]. Include EE-
RM/STD-00-550 and/or RIN 1904-AB08 in the subject line of the message.
     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.
     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 
1E-190 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/
STD-00-550, 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: 
[email protected].
    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: [email protected].

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 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

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    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) life-cycle 
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 utility-market-based estimate to characterize 
the electricity costs to owners, which are typically utilities, of 
liquid-immersed 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

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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 liquid-immersed 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 I.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 I.1.--In-Depth Technical Analyses Conducted for the ANOPR
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            Analysis area                     Methodology                   Key inputs                Key assumptions         ANOPR section for results
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Engineering.........................  Simplify population for      (1) Material costs for       Maximum technologically      Section II.C.5; presented
                                       analysis; create design      construction; (2) Design     feasible design for liquid-  in the TSD, Chapter 5.
                                       option combinations; use     tolerances.                  immersed is amorphous
                                       design software to prepare                                core, for a dry-type is
                                       a range of efficiency                                     laser-scribed.
                                       designs.
LCC and PBP.........................  Transformer-by-transformer   (1) Cost /efficiency         (1) Liquid-immersed subject  Section II.F.4; results
                                       analysis using               relationship from            to utility industry          also presented in the TSD,
                                       representative models from   engineering analysis; (2)    economics; (2) Dry-type      Chapter 8.
                                       simplified design lines.     Baseline determination       subject to commercial/
                                                                    from purchase decision       industrial economics.
                                                                    model; (3) Electricity
                                                                    prices and tariffs.
National impact analysis............  Distribution transformer     (1) Design line-to-product   Section II.H.4; results
                                       costs and energy             class mapping; (2) 0.75      also presented in the TSD,
                                       consumption forecasted to    power scaling rule.          Chapter 10.
                                       2035; combined with LCC
                                       results and mapped to
                                       product classes (1)
                                       Average values from the
                                       LCC analysis; (2)
                                       Historical shipment
                                       shipments estimate.
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    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

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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'' (ORNL-6847) 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-AA56-4B4E-9F329B339C23F115/. 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 liquid-immersed 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 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

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discusses the methodology and structure of the LCC analysis for dry-
type 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 I.2, the Department 
presents the analyses it intends to conduct in its evaluation of 
standards for distribution transformers.

  Table I.2.--Distribution Transformers Analyses in Accordance With the
                              Process Rule
------------------------------------------------------------------------
            ANOPR                     NOPR               Final rule
------------------------------------------------------------------------
Market and technology         Revised ANOPR         Revised analyses.
 assessment.                   analyses
Screening analysis..........  Life-cycle cost sub-
                               group analysis
Engineering analysis........  Manufacturer impact
                               analysis
Energy use and end-use load   Utility impact
 characterization.             analysis
Markups for equipment price   Employment impact
 determination.                analysis
Life-cycle cost and payback   Environmental
 period analyses.              assessment
Shipments analysis..........  Regulatory impact
                               analysis
National impact analysis....
------------------------------------------------------------------------

    The analyses in Table I.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, 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 
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

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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 liquid-immersed 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 single-phase, 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 
``[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

[[Page 45382]]

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.
---------------------------------------------------------------------------

    \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 neither--the 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 ``non-distribution 
transformers, such as UPS [uninterruptible power supply] 
transformers.'' Although the proposed definition excludes 
uninterruptible power supply transformers, the portion of this 
exclusion referring to ``non-distribution 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.''
---------------------------------------------------------------------------

    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 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 non-ventilated 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 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 harmonic-mitigating 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

[[Page 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, K-9 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 K-13 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 K-factor 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 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 
16\2/3\ 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, special-impedance, 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

[[Page 45384]]

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 step-down 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 three-phase transformer intended 
primarily to provide a neutral point for system-grounding 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 
non-linear 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 non-linear 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 II.2:

  Table II.1.--Normal Impedance Ranges for Liquid-Immersed Transformers
------------------------------------------------------------------------
                           kVA                            Impedance  (%)
------------------------------------------------------------------------
                        Single-Phase Transformers
------------------------------------------------------------------------
10......................................................         1.0-4.5
15......................................................         1.0-4.5
25......................................................         1.0-4.5
37.5....................................................         1.0-4.5
50......................................................         1.5-4.5
75......................................................         1.5-4.5
100.....................................................         1.5-4.5
167.....................................................         1.5-4.5
250.....................................................         1.5-6.0
333.....................................................         1.5-6.0
500.....................................................         1.5-7.0
667.....................................................         5.0-7.5
833.....................................................         5.0-7.5
---------------------------------------------------------
                        Three-Phase Transformers
------------------------------------------------------------------------
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 II.2.--Normal Impedance Ranges for Dry-Type Transformers
------------------------------------------------------------------------
                           kVA                            Impedance  (%)
------------------------------------------------------------------------
                        Single-Phase Transformers
------------------------------------------------------------------------
15......................................................         1.5-6.0
25......................................................         1.5-6.0
37.5....................................................         1.5-6.0
50......................................................         1.5-6.0
75......................................................         2.0-7.0
100.....................................................         2.0-7.0
167.....................................................         2.5-8.0
250.....................................................         3.5-8.0
333.....................................................         3.5-8.0
500.....................................................         3.5-8.0
667.....................................................         5.0-8.0
833.....................................................         5.0-8.0
---------------------------------------------------------
                        Three-Phase Transformers
------------------------------------------------------------------------
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

[[Page 45385]]

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 one-quarter 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 liquid-immersed 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, liquid-immersed units are filled with mineral oil and are 
used in outdoor installations (e.g., concrete pad or pole-mounted). The 
Department recognizes that dry-type 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 performance-related features 
that affect consumer utility, the Department is tentatively planning to 
have separate efficiency standards for liquid-immersed and dry-type 
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 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, medium-voltage 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 
liquid-immersed 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 (end-user) 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.

[[Page 45386]]



                                             Table II.3.--Proposed Distribution Transformer Product Classes
--------------------------------------------------------------------------------------------------------------------------------------------------------
              Number                    Insulation              Voltage               Phases                 BIL rating                 kVA range
--------------------------------------------------------------------------------------------------------------------------------------------------------
1................................  Liquid-Immersed.....  Medium..............  Single..............  .........................  10-833 kVA
2................................  Liquid-Immersed.....  Medium..............  Three...............  .........................  15-2500 kVA
3................................  Dry-Type............  Low.................  Single..............  .........................  15-333 kVA
4................................  Dry-Type............  Low.................  Three...............  .........................  15-1000 kVA
5................................  Dry-Type............  Medium..............  Single..............  20-45kV BIL..............  15-833 kVA
6................................  Dry-Type............  Medium..............  Three...............  20-45kV BIL..............  15-2500 kVA
7................................  Dry-Type............  Medium..............  Single..............  46-95kV BIL..............  15-833 kVA
8................................  Dry-Type............  Medium..............  Three...............  46-95kV BIL..............  15-2500 kVA
9................................  Dry-Type............  Medium..............  Single..............  >=96kV BIL...............  75-833 kVA
10...............................  Dry-Type............  Medium..............  Three...............  >=96kV BIL...............  225-2500 kVA
--------------------------------------------------------------------------------------------------------------------------------------------------------

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 
single-phase units. However, these single-phase units tend to have 
lower kVA ratings than the three-phase units, which are more than half 
of the total MVA capacity shipped of liquid-immersed 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 low-voltage, 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 dry-type MVA shipments in 2001. Medium-voltage, 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 liquid-
immersed 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 II.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            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-         Lower..................  Higher.................  Higher.
     sectional area (CSA).
    (b) Decreasing volts per turn....  Lower..................  Higher.................  Higher.
Decrease flux path length by           Lower..................  Higher.................  Lower.
 decreasing conductor CSA.
--------------------------------------

[[Page 45387]]

 
                                             To decrease load losses
----------------------------------------------------------------------------------------------------------------
Use lower-loss conductor material....  No change..............  Lower..................  Higher.
Decrease current density by            Higher.................  Lower..................  Higher.
 increasing conductor CSA.
Decrease current path length by:.....                                                    .......................
    (a) Decreasing core CSA..........  Higher.................  Lower..................  Lower.
    (b) Increasing volts per turn....  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; high-temperature 
superconductors; amorphous core material in stacked core configuration; 
carbon composite materials for heat removal; high-temperature 
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 ``off-the-
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.

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 reverse-engineering or cost-assessment approach, which involves a 
``bottoms-up'' 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

[[Page 45388]]

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 efficiency-level 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 efficiency-level 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[reg] / 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    The Department published revised, draft liquid-immersed engineering 
analysis results on June 5, 2002, as an 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[deg]C rather 
than the expected 65[deg]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[deg]C 
ambient and 65[deg]C temperature rise; however, when the design 
specification report was created, a 30[deg]C ambient temperature had 
been mistakenly entered, which forced the reported temperature rise to 
be 55[deg]C. Thus, the design was created with a 65[deg]C rise, but 
inadvertently reported as 55[deg]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 grain-
oriented steel produced in a laser-scribed 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

[[Page 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 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 dry-type distribution transformers, 
single- and 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 sub-divisions 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 of the 
product classes are sub-divided 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 dry-type, 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 II.5.--Mapping of Proposed Product Classes to Engineering Design
                                  Lines
------------------------------------------------------------------------
 Distribution transformer product
              class                 kVA range   Engineering design lines
------------------------------------------------------------------------
1. Liquid-immersed, medium-        10-833      DL 1: 10-100 kVA,
 voltage, single-phase.                         Rectangular
                                               DL 2: 10-100 kVA, Round
                                               DL 3: 167-833 kVA
2. Liquid-immersed, medium-        15-2500     DL 4: 15-500 kVA
 voltage, three-phase.
                                               DL 5: 750-2500 kVA
3. Dry-type, low-voltage, single-  15-333      DL 6: 15-333 kVA
 phase.
4. Dry-type, low-voltage, three    15-1000     DL 7: 15-150 kVA
 phase.
                                               DL 8: 225-1000 kVA
5. Dry-type, medium-voltage,       15-833      (DL 9/3: 15-167 kVA)*
 single-phase, 20-45 kV BIL.
                                               (DL 10/3: 250-833 kVA)*
6. Dry-type, medium-voltage,       15-2500     DL 9: 15-500 kVA
 three-phase, 20-45 kV BIL.
                                               DL 10: 750-2500 kVA
7. Dry-type, medium-voltage,       15-833      (DL 11/3: 15-167 kVA)*
 single-phase, 46-95 kV BIL.
                                               (DL 12/3: 250-833 kVA)*
8. Dry-type, medium-voltage,       15-2500     DL 11: 15-500 kVA
 three-phase, 46-95 kV BIL.
                                               DL 12: 750-2500 kVA
9. Dry-type, medium-voltage,       75-833      (DL 13/3: 75-833 kVA)*
 single-phase, >=96 kV BIL.
10. Dry-type, medium-voltage,      225-2500    DL 13: 225-2500 kVA
 three-phase, >=96 kV BIL.
------------------------------------------------------------------------
*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, low-voltage, 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,

[[Page 45390]]

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, pad-mounted transformer because liquid-filled, 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 three-phase, 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, three-phase, liquid-
immersed transformer was selected instead of the NEMA-recommended 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 II.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, dry-type 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 >=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 low-voltage, dry-type 
units.
    Once DOE became aware of the importance of BIL ratings for medium-
voltage, 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-than-normal 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 II.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, medium-voltage, 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 II.6.--Engineering Design Lines and Representative Units for Analysis
----------------------------------------------------------------------------------------------------------------
                                                                                             Engineering design
      DL         Type of distribution    kVA range      Voltage taps        Secondary       line representative
                      transformer                                            voltages               unit
----------------------------------------------------------------------------------------------------------------
1.............  Liquid-immersed,             10-100  2-     240/120 to 600V..  50kVA, 65[deg]C,
                 medium-voltage,                      2.5%.                                 single-phase, 60Hz,
                 single-phase,                                                              7200V primary, 240/
                 rectangular tank.                                                          120V secondary,
                                                                                            rectangular tank
2.............  Liquid-immersed,             10-100  2-     120/240 to 600V..  25kVA, 65[deg]C,
                 medium-voltage,                      2.5%.                                 single-phase, 60Hz,
                 single-phase, round                                                        24940GrdY/14400V
                 tank.                                                                      primary, 120/240V
                                                                                            secondary, round
                                                                                            tank
3.............  Liquid-immersed,            167-833  2-     120/240 to 600 V.  500kVA, 65[deg]C,
                 medium-voltage,                      2.5%.                                 single-phase, 60Hz,
                 single-phase.                                                              14400/24940YV
                                                                                            primary, 277/480YV
                                                                                            secondary
4.............  Liquid-immersed,             15-500  2-     208Y/120 to 600V.  150kVA, 65[deg]C,
                 medium-voltage, three-               2.5%.                                 three-phase, 60Hz,
                 phase.                                                                     12470Y/7200V
                                                                                            primary, 208Y/120V
                                                                                            secondary
5.............  Liquid-immersed,           750-2500  2-     208Y/120 to 600Y/  1500kVA, 65[deg]C,
                 medium-voltage, three-               2.5%.              347V.              three-phase, 60Hz,
                 phase.                                                                     24940GrdY/14400V
                                                                                            primary, 480Y/277V
                                                                                            secondary
6.............  Dry-type, low-voltage,       15-333  Universal*.......  120/240 to 600V..  25kVA, 150[deg]C,
                 single-phase.                                                              single-phase, 60Hz,
                                                                                            480V primary, 120/
                                                                                            240V secondary, 10kV
                                                                                            BIL

[[Page 45391]]

 
7.............  Dry-type, low-voltage,       15-150  Universal*.......  208Y/120 to 600Y/  75kVA, 150[deg]C,
                 three-phase.                                            347V.              three-phase, 60Hz,
                                                                                            480V primary, 208Y/
                                                                                            120V secondary, 10kV
                                                                                            BIL
8.............  Dry-type, low-voltage,     225-1000  Universal*.......  208Y/120 to 600Y/  300kVA, 150[deg]C,
                 three-phase.                                            347V.              three-phase, 60Hz,
                                                                                            480V Delta primary,
                                                                                            208Y/120V secondary,
                                                                                            10kV BIL
9.............  Dry-type, medium-            15-500  2-     208Y/120 to 600Y/  300kVA, 150[deg]C,
                 voltage, three-phase,                2.5%.              347V.              three-phase, 60Hz,
                 20-45kV BIL.                                                               4160V primary, 480Y/
                                                                                            277V secondary, 45kV
                                                                                            BIL
10............  Dry-type, medium-          750-2500  2-     208Y/120 to 600Y/  1500kVA, 150[deg]C,
                 voltage, three-phase,                2.5%.              347V.              three-phase, 60Hz,
                 20-45kV BIL.                                                               4160V primary, 480Y/
                                                                                            277V secondary, 45kV
                                                                                            BIL
11............  Dry-type, medium-            15-500  2-     208Y/120 to 600Y/  300kVA, 150[deg]C,
                 voltage, three-phase,                2.5%.              347V.              three-phase, 60Hz,
                 20-45kV BIL.                                                               12470V primary, 480Y/
                                                                                            277V secondary, 95kV
                                                                                            BIL
12............  Dry-type, medium-          750-2500  2-     208Y/120 to 600Y/  1500kVA, 150[deg]C,
                 voltage, three-phase,                2.5%.              347V.              three-phase, 60Hz,
                 60-95kV BIL.                                                               12470V primary, 480Y/
                                                                                            277V secondary, 95kV
                                                                                            BIL
13............  Dry-type, medium-          225-2500  2-     208Y/120 to 600Y/  2000kVA, 150[deg]C,
                 voltage, three-phase,                2.5%.              347V.              three-phase, 60Hz,
                 110-150kV BIL.                                                             12470V primary, 480Y/
                                                                                            277V secondary,
                                                                                            125kV BIL
----------------------------------------------------------------------------------------------------------------
*Universal Taps are 2 above and 4 below 2.5%.

s3. 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

[[Page 45392]]

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 liquid-immersed 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, three-phase, 
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

[[Page 45393]]

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 low-
voltage 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 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 low-voltage 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,

[[Page 45394]]

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, liquid-immersed transformers (which serve a large 
proportion of residential and small commercial loads) to 68 percent for 
1500 kVA, liquid-immersed, pad-mounted 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 whole-building 
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 dry-type 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 II.7 lists the average markups used in this ANOPR; 
additional detail is provided in Chapter 7 of the TSD.

                    Table II.7.--Supply-Chain Markups
------------------------------------------------------------------------
                                                               Average
                    LCC analysis markups                      multiplier
------------------------------------------------------------------------
Distributor................................................        1.350
Contractor Materials.......................................        1.100
Installation Labor and Equipment...........................        1.520
Sales Tax..................................................        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

[[Page 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 add-in 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 standard-compliant 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 hourly-based 
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 II.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.

[[Page 45396]]



   Table II.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
                                     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.
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,
                                     manufacturer 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        The selection of baseline and
 selection.                          standard-compliant transformers
                                     depends on customer behavior. For
                                     liquid-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
                                     reducing losses at peak. Average
                                     marginal tariff-based retail
                                     electricity price: 6.4[cent]/kWh
                                     for no-load losses and 7.4[cent]/
                                     kWh for load losses. Average
                                     marginal wholesale utility hourly-
                                     based costs: 3.8[cent]/kWh for no-
                                     load losses and 4.5[cent]/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 scenarios,
                                     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 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

[[Page 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 
life-cycle 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 II.9 lists the candidate 
standard levels, expressed in terms of efficiency, and in terms 
relative to NEMA TP 1 efficiency levels.

                                          Table II.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

[[Page 45398]]

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 purchase-decision 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 purchase-
decision model and transformer-evaluation-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 dry-type transformers than it is for 
liquid-immersed transformers. EEI recommended that for dry-type 
transformers, DOE use the non-evaluation 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, dry-type 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 purchase-decision 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-design-selection 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 customer-
design-selection model and transformer-evaluation-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

[[Page 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 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. medium-voltage 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 ORNL-6847, 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 peak-hour 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 $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

[[Page 45400]]

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 II.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 II.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.

[[Page 45401]]



               Table II.10.--Weighted Average Discount Rates by Design Line and Ownership Category
----------------------------------------------------------------------------------------------------------------
      Mean real discount rate                              Transformer ownership category
----------------------------------------------------------------------------------------------------------------
                         Weighted     Property    Industrial   Commercial   Investor-     Publicly    Government
                         average       owners     companies    companies      owned        owned       offices
     Design line         discount  ---------------------------------------  utilities    utilities  ------------
                           rate                                           --------------------------
                       (percent)       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 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 
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.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 II.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       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
----------------------------------------------------------------------------------------------------------------


[[Page 45402]]

    Table II.12 presents the summary of the LCC 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 LCC 
analysis was 98.59 percent and the average manufacturer's selling price 
was $950.

              Table II.12.--Summary of LCC & PBP Results for the Design Line 2 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       98.70       98.90       99.10       99.30       99.47
Transformers having LCC Savings >= $0 (%)...........       99.7        66.7        26.8        13.7         2.8
Mean LCC Savings ($)................................       99          62         -76        -216        -492
Mean Payback (Years)................................        5.8        21.7        30.3        29.7        40.7
----------------------------------------------------------------------------------------------------------------

    Table II.13 presents the summary of the LCC 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 LCC 
analysis was 99.33 percent and the average manufacturer's selling price 
was $4,599.

              Table II.13.--Summary of LCC & PBP Results for the Design Line 3 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       99.30       99.40       99.60       99.70       99.75
Transformers having LCC Savings >= $0 (%)...........       96.5        97.5        70.3        68.9        52.1
Mean LCC Savings ($)................................      884       1,606       1,168       1,838       1,292
Mean Payback (Years)................................        8.2         8.3        16.9        18.1        23.6
----------------------------------------------------------------------------------------------------------------

    Table II.14 presents the summary of the LCC 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 LCC 
analysis was 98.86 percent and the average manufacturer's selling price 
was $3,577.

              Table II.14.--Summary of LCC & PBP Results for the Design Line 4 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       98.90       99.10       99.30       99.40       99.56
Transformers having LCC Savings >= $0 (%)...........       97.5        90.9        73.7        75.9        50.8
Mean LCC Savings ($)................................      574         733         491         585         301
Mean Payback (Years)................................        7.7        12.1        16.5        16.2        24.7
----------------------------------------------------------------------------------------------------------------

    Table II.15 presents the summary of the LCC 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 LCC 
analysis was 99.35 percent and the average manufacturer's selling price 
was $11,088.

              Table II.15.--Summary of LCC & PBP Results for the Design Line 5 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       99.30       99.40       99.50       99.60       99.66
Transformers having LCC Savings >= $0 (%)...........       97.8        97.2        80.2        78.5        64.4
Mean LCC Savings ($)................................    4,174       6,617       7,451       7,268       6,838
Mean Payback (Years)................................        6.2         6.7        13.4        13.4        17.7
----------------------------------------------------------------------------------------------------------------

    Table II.16 presents the summary of the LCC and PBP analyses for 
the representative unit from design line 6, a 25 kVA, low-voltage, dry-
type, single-phase transformer. For this unit, the average efficiency 
of the baseline transformers selected during the LCC analysis was 95.36 
percent and the average manufacturer's selling price was $864.

[[Page 45403]]



              Table II.16.--Summary of LCC & PBP Results for the Design Line 6 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       98.00       98.20       98.40       98.70       98.79
Transformers having LCC Savings >= $0 (%)...........       99.3        99.1        99.1        94.1        92.8
Mean LCC Savings ($)................................    1,777       1,865       1,948       1,906       1,867
Mean Payback (Years)................................        1.7         2.6         2.6         5.6         6.7
----------------------------------------------------------------------------------------------------------------

    Table II.17 presents the summary of the LCC and PBP analyses for 
the representative unit from design line 7, a 75 kVA, low-voltage, dry-
type, three-phase transformer. For this unit, the average efficiency of 
the baseline transformers selected during the LCC analysis was 96.43 
percent and the average manufacturer's selling price was $1,808.

              Table II.17.--Summary of LCC & PBP Results for the Design Line 7 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       98.00       98.30       98.60       98.90       99.09
Transformers having LCC Savings >= $0 (%)...........      100.0        99.0        98.4        88.8        77.5
Mean LCC Savings ($)................................    3,156       3,588       3,927       3,910       3,799
Mean Payback (Years)................................        0.6         2.6         3.5         7.1        10.8
----------------------------------------------------------------------------------------------------------------

    Table II.18 presents the summary of the LCC and PBP analyses for 
the representative unit from design line 8, a 300 kVA, low-voltage, 
dry-type, three-phase transformer. For this unit, the average 
efficiency of the baseline transformers selected during the LCC 
analysis was 97.79 percent and the average manufacturer's selling price 
was $4,735.

              Table II.18.--Summary of LCC & PBP Results for the Design Line 8 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       98.60       98.80       99.00       99.20       99.27
Transformers having LCC Savings >= $0 (%)...........       99.8        97.8        96.6        92.1        89.4
Mean LCC Savings ($)................................    6,761       7,035       7,899       8,941       8,712
Mean Payback (Years)................................        1.0         2.9         4.5         6.5         7.4
----------------------------------------------------------------------------------------------------------------

    Table II.19 presents the summary of the LCC and PBP analyses for 
the representative unit from design line 9, a 300 kVA, medium-voltage, 
dry-type, three-phase transformer with a 45 kV BIL. For this unit, the 
average efficiency of the baseline transformers selected during the LCC 
analysis was 97.90 percent and the average manufacturer's selling price 
was $6,084.

              Table II.19.--Summary of LCC & PBP Results for the Design Line 9 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       98.60       98.80       99.00       99.20       99.31
Transformers having LCC Savings >= $0 (%)...........       95.8        93.4        95.2        84.6        70.0
Mean LCC Savings ($)................................    6,465       7,550       8,536       8,942       7,838
Mean Payback (Years)................................        4.8         6.1         5.7         8.9        13.1
----------------------------------------------------------------------------------------------------------------

    Table II.20 presents the summary of the LCC and PBP analyses for 
the representative unit from design line 10, a 1500 kVA, medium-
voltage, dry-type, three-phase transformer with a 45 kV BIL. For this 
unit, the average efficiency of the baseline transformers selected 
during the LCC analysis was 98.63 percent and the average 
manufacturer's selling price was $22,473.

[[Page 45404]]



              Table II.20.--Summary of LCC & PBP Results for the Design Line 10 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           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         8.5         8.9        13.9        15.6
----------------------------------------------------------------------------------------------------------------

    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 percent and the average manufacturer's selling price 
was $10,142.

              Table II.21.--Summary of LCC & PBP Results for the Design Line 11 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       98.50       98.70       98.90       99.00       99.10
Transformers having LCC Savings >= $0 (%)...........       96.4        94.9        87.4        75.6        68.0
Mean LCC Savings ($)................................    4,473       5,350       5,734       5,136       4,666
Mean Payback (Years)................................        5.8         6.7         9.3        12.5        14.3
----------------------------------------------------------------------------------------------------------------

    Table II.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 BIL. For this 
unit, the average efficiency of the baseline transformers selected 
during the LCC analysis was 98.67 percent and the average 
manufacturer's selling price was $26,542.

              Table II.22.--Summary of LCC & PBP Results for the Design Line 12 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           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         9.6        10.7        14.2        17.1
----------------------------------------------------------------------------------------------------------------

    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 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 II.23.--Summary of LCC & PBP Results for the Design Line 13 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                       Candidate standard level
                                                     -----------------------------------------------------------
                                                           1           2           3           4           5
----------------------------------------------------------------------------------------------------------------
Minimum Efficiency (%)..............................       99.00       99.10       99.30       99.40       99.45
Transformers having LCC Savings >= $0 (%)...........       92.0        90.6        76.9        77.6        44.9
Mean LCC Savings ($)................................   11,691      16,119      16,685      19,706       7,593
Mean Payback (Years)................................        6.7         8.5        12.7        12.7        20.3
----------------------------------------------------------------------------------------------------------------

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.
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 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

[[Page 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. 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 II.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 II.24.--National Distribution Transformer Shipment Estimates for
                                  2001
------------------------------------------------------------------------
                                                              Shipment
   Distribution transformer         Units     MVA capacity      value
         product class             shipped       shipped     ($million)
------------------------------------------------------------------------
1. Liquid-immersed, medium-          977,388        36,633         698.8
 voltage, single-phase........
2. Liquid-immersed, medium-           79,367        42,887         540.4
 voltage, three-phase.........
3. Dry-type, low-voltage,             23,324           983          17.8
 single-phase.................
4. Dry-type, low-voltage,            290,818        21,909         235.0
 three-phase..................
5. Dry-type, medium-voltage,             119            18           0.5
 single-phase, 20-45 kV BIL...
6. Dry-type, medium-voltage,             650           776          13.5
 three-phase, 20-45 kV BIL....
7. Dry-type, medium-voltage,             121            22           0.6
 single-phase, 46-95 kV BIL...
8. Dry-type, medium-voltage,           2,371         3,913          68.1
 three-phase, 46-95 kV BIL....
9. Dry-type, medium-voltage,              20             4           0.1
 single-phase, >=96 kV BIL....
10. Dry-type, medium-voltage,            187           367           6.4
 three-phase, >=96 kV BIL.....
                               ---------------
    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 in-service 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

[[Page 45406]]

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 II.25.--Summary of Shipments Model Inputs
------------------------------------------------------------------------
               Input                             Description
------------------------------------------------------------------------
 Shipments data...................  Third party expert (HVOLT) 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     Based on EIA's electricity sales
 shares.                             data and AEO 2003.
Regular replacement market........  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.
Elasticities......................  For liquid-immersed transformers:
                                     Low: 0.00
                                     Medium: -0.04
                                     High: -0.20
                                    For dry-type transformers:
                                     0.00
------------------------------------------------------------------------

    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'' 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 liquid-immersed 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    CSL 1    CSL 2    CSL 3    CSL 4    CSL 5
----------------------------------------------------------------------------------------------------------------
Liquid-immersed...........................................     3.06     3.06     3.05     3.04     3.03     3.01
Dry-type..................................................     1.23     1.23     1.23     1.23     1.23     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 liquid-immersed 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 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 in-service 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 in-service gradually decreases in the

[[Page 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 in-service 
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.
---------------------------------------------------------------------------

    \3\ The year 2070 is the rounded sum of 2035 plus 32 years, the 
average lifetime of distribution transformers.
---------------------------------------------------------------------------

1. Method
    Both calculations start by using the estimate of shipments and 
quantity in-service 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 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 II.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-  Constant efficiency at the
 2035).                              specified standard level from 2007-
                                     2035.
 Annual Energy Consumption per       Average rated transformer losses
 Unit.                               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).

[[Page 45408]]

 
 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          A time series conversion factor;
 Conversion.                         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 II.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

[[Page 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 II.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  Table II.5 shows the mapping of the
 classes.                            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          A time series conversion factor;
 conversion.                         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.

[[Page 45410]]



          Table II.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 future monetary cost or
                                     benefit, 3% and 7% real.
------------------------------------------------------------------------

    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)
    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 II.30 through II.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 II.30 provides a summary of the total analysis, grouping 
together all the liquid-immersed product classes and all the dry-type 
product classes. Tables II.31 and II.34 provide NPV results for liquid-
immersed and dry-type product classes respectively using a 3 percent 
real discount rate. Tables II.32 and II.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 II.30. Tables II.31 through 
II.33 present NPV and NES results for liquid-immersed transformers by 
product class. Tables II.34 through II.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 (10\15\) Btus of 
avoided primary energy consumption at the power plant.

                    Table II.30.--Summary of Cumulative NES and NPV Impacts Between 2007-2035
----------------------------------------------------------------------------------------------------------------
                                                                               Candidate standard level
      Distribution transformers                  Analysis           --------------------------------------------
                                                                      CSL 1    CSL 2    CSL 3    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 II.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
----------------------------------------------------------------------------------------------------------------


[[Page 45411]]


    Table II.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 II.33.--National Energy Savings Between 2007-2035: Liquid-Immersed Product Classes
----------------------------------------------------------------------------------------------------------------
                                                                      Cumulative primary energy savings (quads)
                           Product class                            --------------------------------------------
                                                                      CSL 1    CSL 2    CSL 3    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 II.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 II.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      CSL 4      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 II.36.--Cumulative Primary Energy Savings Between 2007-2035: Dry-Type Product Classes
----------------------------------------------------------------------------------------------------------------
                                                                 Cumulative primary energy savings (quads)
                      Product class                       ------------------------------------------------------
                                                             CSL 1      CSL 2      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
----------------------------------------------------------------------------------------------------------------


[[Page 45412]]

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 decision-
making 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 sub-groups or characteristics that are 
appropriate for the manufacturer sub-group 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).

[[Page 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 product-specific 
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.
---------------------------------------------------------------------------

    \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/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).
---------------------------------------------------------------------------

    The use of NEMS for the utility impact analysis offers several 
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 low-economic-growth cases of 
AEO 2003 (the reference case corresponds to medium growth). The high-
economic-growth 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 supply-side 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 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

[[Page 45414]]

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 input-output 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 input-output 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 NEMS-BT 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 air-borne 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

[[Page 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 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 hand-deliver 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 e-mail to: [email protected].
    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 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 [email protected]. 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 EE-RM/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

[[Page 45416]]

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 II.A 
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 medium-voltage, 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 
liquid-immersed 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 first-cost 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 low-voltage, 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 liquid-immersed 
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

[[Page 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 II.I 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. 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