[Federal Register: July 29, 2004 (Volume 69, Number 145)]
[Proposed Rules]
[Page 45375-45417]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr29jy04-30]
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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
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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: TransformerANOPR Comment@ee.doe.gov. 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:
Ronald.Lewis@ee.doe.gov.
Thomas B. DePriest, Esq., U.S. Department of Energy, Office of
General Counsel, Forrestal Building, Mail Station GC-72, 1000
Independence Avenue, SW., Washington, DC, 20585, (202) 586-9507. E-
mail: Thomas.DePriest@hq.doe.gov.
SUPPLEMENTARY INFORMATION:
I. Introduction
A. Purpose of the ANOPR
B. Summary of the Analysis
1. Engineering Analysis
2. Life-Cycle Cost and Payback Period Analyses
3. National Impact Analysis
C. Authority
D. Background
1. History of Standards Rulemaking for Distribution Transformers
2. Process Improvement
3. Test Procedure
II. Distribution Transformer Analyses
A. Market and Technology Assessment
1. Definition of a Distribution Transformer
a. Changes to, and Retention of, Provisions in the Framework
Document Definition
b. Exclusions Discussed in the Test Procedure Reopening Notice
c. Additional Exclusions Drawn from NEMA 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
[[Page 45379]]
conservation standards. That report was based on information from
annual sales data, average load data, and surveys of existing and
potential transformer efficiencies obtained from several organizations.
In September 1997, ORNL published a second report entitled
Supplement to the ``Determination Analysis'' (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
[[Page 45380]]
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
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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
[[Page 45381]]
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: Brenda.Edwards-Jones@ee.doe.gov.
Persons requesting to speak should briefly describe the nature of
their interest in this rulemaking and provide a telephone number for
contact. The Department requests persons selected to be heard to submit
an advance copy of their statements at least two weeks before the
public meeting. At its discretion, DOE may permit any person who cannot
supply an advance copy of his or her statement to participate, if that
person has made advance alternative arrangements with the Building
Technologies Program. The request to give an oral presentation should
ask for such alternative arrangements.
C. Conduct of Public Meeting
The Department will designate a DOE official to preside at the
public meeting and may also use a professional facilitator to aid
discussion. The meeting will not be a judicial or evidentiary-type
public hearing, but DOE will conduct it in accordance with 5 U.S.C. 553
and section 336 of EPCA. (42 U.S.C. 6306) A court reporter will be
present to record the transcript of the proceedings. The Department
reserves the right to schedule the order of presentations and to
establish the procedures governing the conduct of the public meeting.
After the public meeting, interested parties may submit further
comments on the proceedings as well as on any aspect of the rulemaking
until the end of the comment period.
The public meeting will be conducted in an informal, conference
style. The Department will present summaries of comments received
before the public meeting, allow time for presentations by
participants, and encourage all interested parties to share their views
on issues affecting this rulemaking. Each participant will be allowed
to make a prepared general statement (within time limits determined by
DOE) before the discussion of specific topics. The Department will
permit other participants to comment briefly on any general statements.
At the end of all prepared statements on a topic, DOE will permit
participants to clarify their statements briefly and comment on
statements made by others. Participants should be prepared to answer
questions by DOE and by other participants concerning these issues.
Department representatives may also ask questions of participants
concerning other matters relevant to the public meeting. The official
conducting the public meeting will accept additional comments or
questions from those attending, as time permits. The presiding official
will announce any further procedural rules or modification of the above
procedures that may be needed for the proper conduct of the public
meeting.
The Department will make the entire record of this proposed
rulemaking, including the transcript from the public meeting, available
for inspection at the U.S. Department of Energy, Forrestal Building,
Room 1J-018 (Resource Room of the Building Technologies Program), 1000
Independence Avenue, SW., Washington, DC, (202) 586-9127, between 9
a.m. and 4 p.m., Monday through Friday, except Federal holidays. Any
person may buy a copy of the transcript from the transcribing reporter.
D. Submission of Comments
The Department will accept comments, data, and information
regarding all aspects of this ANOPR before or after the public meeting,
but no later than the date provided at the beginning of this advance
notice of proposed rulemaking. Please submit comments, data, and
information electronically. Send them to the following E-mail address:
Transformer ANOPRComment@ee.doe.gov. Submit electronic comments in
WordPerfect, Microsoft Word, PDF, or text (ASCII) file format and avoid
the use of special characters or any form of encryption. Comments in
electronic format should be identified by the docket number 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