Energy Conservation Program for Commercial Equipment: Distribution Transformers Energy Conservation Standards
Federal RegisterAug 4, 2006
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DEPARTMENT OF ENERGY
Office of Energy Efficiency and Renewable Energy
10 CFR Part 431
[Docket Number: EE-RM/STD-00-550]
RIN 1904-AB08
Energy Conservation Program for Commercial Equipment: Distribution Transformers Energy Conservation Standards
AGENCY:
Office of Energy Efficiency and Renewable Energy, Department of Energy.
ACTION:
Notice of proposed rulemaking and public meeting.
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 those distribution transformers for which DOE determines that energy conservation standards would be technologically feasible and economically justified, and would result in significant energy savings. In this notice, the Department is proposing energy conservation standards for distribution transformers and is announcing a public meeting.
DATES:
The Department will hold a public meeting on Wednesday, September 27, 2006, from 9 a.m. to 4 p.m., in Washington, DC. The Department must receive requests to speak at the public meeting before 4 p.m., Wednesday, September 13, 2006. The Department must receive a signed original and an electronic copy of statements to be given at the public meeting before 4 p.m., Wednesday, September 13, 2006.
The Department will accept comments, data, and information regarding the notice of proposed rulemaking (NOPR) before and after the public meeting, but no later than October 18, 2006. See section VII, “Public Participation,” of this NOPR for details.
ADDRESSES:
The public meeting will be held at the U.S. Department of Energy, Forrestal Building, Room 1E245, 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 Regulatory Information Number (RIN) 1904-AB08, by any of the following methods:
•
Federal eRulemaking Portal:
http://www.regulations.gov.
Follow the instructions for submitting comments.
•
E-mail:
TransformerNOPRComment@ee.doe.gov.
Include docket number 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, NOPR for Distribution Transformers Energy Conservation Standards, docket number EE-RM/STD-00-550 and/or RIN 1904-AB08, 1000 Independence Avenue, SW., Washington, DC 20585-0121. Please submit one signed original paper copy.
•
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. Telephone: (202) 586-2945. Please submit one signed original paper copy.
Instructions: All submissions received must include the agency name and docket number or RIN for this rulemaking. For detailed instructions on submitting comments and additional information on the rulemaking process, see section VII of this document (Public Participation).
Docket: For access to the docket to read background documents or comments received, visit 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) 586-2945, 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 (formerly Room 1E-190 at the Forrestal Building) is no longer housing rulemaking materials.
FOR FURTHER INFORMATION CONTACT:
Antonio Bouza, Project Manager, Energy Conservation Standards for Distribution Transformers, Docket No. EE-RM/STD-00-550, U.S. Department of Energy, Energy Efficiency and Renewable Energy, Building Technologies Program, EE-2J, 1000 Independence Avenue, SW., Washington, DC 20585-0121, (202) 586-4563, e-mail:
Antonio.Bouza@ee.doe.gov.
Thomas B. DePriest, Esq., U.S. Department of Energy, Office of General Counsel, GC-72, 1000 Independence Avenue, SW., Washington, DC 20585, (202) 586-9507, e-mail:
Thomas.Depriest@hq.doe.gov.
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Summary of the Proposed Rule
II. Introduction
A. Consumer Overview
B. Authority
C. Background
1. Current Standards
2. History of Standards Rulemaking for Distribution Transformers
3. Process Improvement
III. General Discussion
A. Test Procedures
B. Technological Feasibility
1. General
2. Maximum Technologically Feasible Levels
C. Energy Savings
D. Economic Justification
1. Economic Impact on Manufacturers and Commercial Consumers
2. Life-Cycle Costs
3. Energy Savings
4. Lessening of Utility or Performance of Equipment
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
IV. Methodology and Discussion of Comments
A. Market and Technology Assessment
1. Product Classes
2. Definition of a Distribution Transformer
B. Engineering Analysis
1. Engineering Analysis Methodology
2. Engineering Analysis Inputs
3. Engineering Analysis Outputs
C. Life-Cycle Cost and Payback Period Analysis
1. Inputs Affecting Installed Cost
a. Equipment Price
b. Installation Costs
c. Baseline and Standard Design Selection
2. Inputs Affecting Operating Costs
a. Transformer Loading
b. Load Growth
c. Power Factor
d. Electricity Costs
e. Electricity Price Trends
3. Inputs Affecting Present Value of Annual Operating Cost Savings
a. Standards Implementation Date
b. Discount Rate
4. Candidate Standard Levels
5. Trial Standard Levels
6. Miscellaneous Life-Cycle Cost Issues
a. Tax Impacts
b. Cost Recovery Under Deregulation, Rate Caps
c. Other Issues
D. National Impact Analysis—National Energy Savings and Net Present Value Analysis
E. Commercial Consumer Subgroup Analysis
F. Manufacturer Impact Analysis
1. General Description
2. Industry Profile
3. Industry Cash-Flow Analysis
4. Subgroup Impact Analysis
5. Government Regulatory Impact Model Analysis
G. Employment Impact Analysis
H. Utility Impact Analysis
I. Environmental Analysis
V. Analytical Results
A. Economic Justification and Energy Savings
1. Economic Impacts on Commercial Consumers
a. Life-Cycle Cost and Payback Period
b. Rebuttable-Presumption Payback
c. Commercial Consumer Subgroup Analysis
2. Economic Impacts on Manufacturers
a. Industry Cash-Flow Analysis Results
b. Impacts on Employment
c. Impacts on Manufacturing Capacity
d. Impacts on Manufacturers that are Small Businesses
3. National Impact Analysis
a. Amount and Significance of Energy Savings
b. Energy Savings and Net Present Value
c. Impacts on Employment
4. Impact on Utility or Performance of Equipment
5. Impact of Any Lessening of Competition
6. Need of the Nation to Conserve Energy
7. Other Factors
B. Stakeholder Comments on the Selection of a Final Standard
C. Proposed Standard
1. Results for Liquid-Immersed Distribution Transformers
a. Liquid-Immersed Trial Standard Level 6
b. Liquid-Immersed Trial Standard Level 5
c. Liquid-Immersed Trial Standard Level 4
d. Liquid-Immersed Trial Standard Level 3
e. Liquid-Immersed Trial Standard Level 2
2. Results for Medium-Voltage, Dry-Type Distribution Transformers
a. Medium-Voltage, Dry-Type Trial Standard Level 6
b. Medium-Voltage, Dry-Type Trial Standard Level 5
c. Medium-Voltage, Dry-Type Trial Standard Level 4
d. Medium-Voltage, Dry-Type Trial Standard Level 3
e. Medium-Voltage, Dry-Type Trial Standard Level 2
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Order 12866
B. Review Under the Regulatory Flexibility Act/Initial Regulatory Flexibility Analysis
1. Reasons for the Proposed Rule
2. Objectives of, and Legal Basis for, the Proposed Rule
3. Description and Estimated Number of Small Entities Regulated
4. Description and Estimate of Compliance Requirements
5. Duplication, Overlap, and Conflict With Other Rules and Regulations
6. Significant Alternatives to the Rule
C. Review Under the Paperwork Reduction Act
D. Review Under the National Environmental Policy Act
E. Review under Executive Order 13132
F. Review Under Executive Order 12988
G. Review Under the Unfunded Mandates Reform Act of 1995
H. Review Under the Treasury and General Government Appropriations Act of 1999
I. Review Under Executive Order 12630
J. Review Under the Treasury and General Government Appropriations Act of 2001
K. Review Under Executive Order 13211
L. Review Under Section 32 of the Federal Energy Administration Act of 1974
M. Review Under the Information Quality Bulletin for Peer Review
VII. 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
VIII. Approval of the Office of the Secretary
I. Summary of the Proposed Rule
Pursuant to the Energy Policy and Conservation Act, as amended, the Department is proposing energy conservation standards for liquid-immersed and medium-voltage, dry-type distribution transformers. The Department believes these standards will achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified, and will result in significant energy savings. In the advance notice of proposed rulemaking (ANOPR) for distribution transformers, the Department had also conducted analysis on low-voltage, dry-type distribution transformers. 69 FR 45376 (July 29, 2004). However, the Energy Policy Act of 2005 (EPACT 2005) established energy conservation standards for low-voltage, dry-type distribution transformers. (42 U.S.C. 6295(y)) Because of these amendments, DOE removed low-voltage, dry-type distribution transformers—product class 3 (low-voltage, dry-type, single-phase) and product class 4 (low-voltage, dry-type, three-phase)—from this rulemaking. Table I.1 shows the proposed standard levels for the product classes that are still within the scope of this rulemaking.
Table I.1.—Proposed Standard Levels for Distribution Transformers
Superclasses—product classes (PC)
Proposed standard levels
Liquid-immersed
Trial Standard Level 2.
Single-phase (PC 1)
Three-phase (PC 2)
Medium-voltage, dry-type
Trial Standard Level 2.
Single-phase, 25-45 kV BIL (PC 5)
Three-phase, 25-45 kV BIL (PC 6)
Single-phase, 46-95 kV BIL (PC 7)
Three-phase, 46-95 kV BIL (PC 8)
Single-phase, ≥96 kV BIL (PC 9)
Three-phase, ≥96 kV BIL (PC 10)
Note:
PC stands for product class; kV is kilovolt; BIL is basic impulse insulation level.
Tables II.1 and II.2 show the specific efficiency levels for the various kilovolt ampere (kVA) sizes, within each product class, that reflect the Department's proposed standards.
The Department's analyses indicate that the proposed standards, trial standard level 2 (TSL2) for liquid-immersed transformers and TSL2 for medium-voltage, dry-type transformers, would save a significant amount of energy—an estimated 2.4 quads (quadrillion (10
15
) British thermal units (BTU)) of cumulative energy over 29 years (2010-2038). This amount is roughly equal to the total energy consumption of the Commonwealth of Virginia in 2001. The economic impacts on commercial consumers (
i.e.
, the average life-cycle cost (LCC) savings) are positive.
The national net present value (NPV) of TSL2 is $2.52 billion using a seven-percent discount rate and $9.43 billion using a three-percent discount rate, cumulative from 2010 to 2073 in 2004$. This is the estimated total value of future savings minus the estimated increased equipment costs, discounted
to the year 2004. Using a real corporate discount rate of 8.9 percent, the Department estimates the liquid-immersed and medium-voltage, dry-type distribution transformer industry's NPV to be $558 million in 2004$. The impact of the proposed standard on liquid-immersed transformer manufacturers' industry net present value (INPV) is expected to be between a 2.4 percent loss and a 2.0 percent increase (−$12.9 million to $10.7 million). The medium-voltage, dry-type transformer industry is estimated to lose between 10.1 percent and 13.4 percent of its NPV (−$3.3 million to −$4.3 million) as a result of the proposed standard. Based on the Department's interviews with the major manufacturers of distribution transformers, DOE expects minimal plant closings or loss of employment as a result of the proposed standards.
The proposed standards will lead to reductions in greenhouse gases, resulting in cumulative (undiscounted) emission reductions of 167.1 million tons (Mt) of carbon dioxide (CO
2
). Additionally, the standards would generate 46.4 thousand tons (kt) of nitrogen oxides (NO
X
) emissions reductions or a similar amount of NO
X
emissions allowance credits in areas where such emissions are subject to emissions caps. The Department expects the energy savings from the proposed standards to eliminate the need for approximately 11 new 400-megawatt (MW) power plants by 2038.
Therefore, the Department concludes that the benefits (energy savings, commercial consumer LCC savings, national NPV increases, and emissions reductions) to the Nation of the proposed standards outweigh their costs (loss of manufacturer NPV and commercial consumer LCC increases for some users of distribution transformers). The Department concludes that the proposed standards of TSL2 for liquid-immersed and TSL2 for medium-voltage, dry-type transformers are technologically feasible and economically justified. At present, both liquid-immersed and medium-voltage, dry-type transformers are commercially available at the TSL2 standard level.
II. Introduction
A. Consumer Overview
The Department is proposing to set energy-efficiency standard levels for distribution transformers as shown in Tables II.1 and II.2. The proposed standard would apply to liquid-immersed and medium-voltage, dry-type distribution transformers manufactured for sale in the United States, or imported to the United States, on or after January 1, 2010. In preparing these tables, the Department identified some areas where the analytical methods used to develop the efficiency values resulted in discontinuities in the table of efficiencies. Generally, larger transformers will have greater efficiency than smaller transformers, all other factors being equal. Not all efficiency ratings that result from the Department's analysis fit this pattern. The Department invites comment on all the efficiency ratings.
Table II.1.—Proposed Standard Level, TSL2, for Liquid-Immersed Distribution Transformers
Single-phase
kVA
Efficiency
(%)
Three-phase
kVA
Efficiency
(%)
10
98.40
15
98.36
15
98.56
30
98.62
25
98.73
45
98.76
37.5
98.85
75
98.91
50
98.90
112.5
99.01
75
99.04
150
99.08
100
99.10
225
99.17
167
99.21
300
99.23
250
99.26
500
99.32
333
99.31
750
99.24
500
99.38
1000
99.29
667
99.42
1500
99.36
833
99.45
2000
99.40
2500
99.44
Note:
All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972.
Table II.2.—Proposed Standard Level, TSL2, for Medium-Voltage, Dry-Type Distribution Transformers
Single-phase
BIL
kVA
20-45 kV
efficiency
(%)
46-95 kV
efficiency
(%)
≥96 kV
efficiency
(%)
Three-phase
20-45 kV
efficiency
(%)
46-95 kV
efficiency
(%)
≥96 kV
efficiency
(%)
kVA
15
98.10
97.86
15
97.50
97.19
25
98.33
98.12
30
97.90
97.63
37.5
98.49
98.30
45
98.10
97.86
50
98.60
98.42
75
98.33
98.12
75
98.73
98.57
98.53
112.5
98.49
98.30
100
98.82
98.67
98.63
150
98.60
98.42
167
98.96
98.83
98.80
225
98.73
98.57
98.53
250
99.07
98.95
98.91
300
98.82
98.67
98.63
333
99.14
99.03
98.99
500
98.96
98.83
98.80
500
99.22
99.12
99.09
750
99.07
98.95
98.91
667
99.27
99.18
99.15
1000
99.14
99.03
98.99
833
99.31
99.23
99.20
1500
99.22
99.12
99.09
2000
99.27
99.18
99.15
2500
99.31
99.23
99.20
Note:
BIL means basic impulse insulation level.
Note:
All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972.
B. Authority
Title III of EPCA sets forth a variety of provisions designed to improve energy efficiency. Part B of Title III (42 U.S.C. 6291-6309) provides for the Energy Conservation Program for Consumer Products other than Automobiles. Part C of Title III (42 U.S.C. 6311-6317) establishes a similar program for “Certain Industrial Equipment,” and includes distribution transformers, the subject of this rulemaking. The Department publishes today's NOPR pursuant to Part C of Title III, which provides for test procedures, labeling, and energy conservation standards for distribution transformers and certain other products, and authorizes DOE to require information and reports from manufacturers. The distribution transformer test procedure appears in Title 10 Code of Federal Regulations (CFR) Part 431, Subpart K, Appendix A; 71 FR 24972.
EPCA contains criteria for prescribing new or amended energy conservation standards. The Department must prescribe standards only for those distribution transformers for which DOE: (1) Has determined that standards would be technologically feasible and economically justified and would result in significant energy savings, and (2) has prescribed test procedures. (42 U.S.C. 6317(a)) Moreover, as indicated above, the Department analyzed whether today's proposed standards for distribution transformers will achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified. (See 42 U.S.C. 6295(o)(2)(A), 6316(a), and 6317(a) and (c)) In addition, DOE will decide whether today's proposed standard is economically justified, after receiving comments on the proposed standard, by determining whether the benefits of the standard exceed its costs. The Department will make this determination by considering, to the greatest extent practicable, the following seven factors which are set forth in 42 U.S.C. 6295(o)(2)(B)(i):
(1) The economic impact of the standard on manufacturers and consumers of the products subject to the standard;
(2) The savings in operating costs throughout the estimated average life of products in the type (or class) compared to any increase in the price, initial charges, or maintenance expenses for the covered products that are likely to result from the imposition of the standard;
(3) The total projected amount of energy savings likely to result directly from the imposition of the standard;
(4) Any lessening of the utility or the performance of the 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.
In developing energy conservation standards for distribution transformers, DOE is also applying certain other provisions of 42 U.S.C. 6295. First, the Department will not prescribe a standard for the product if interested persons have established by a preponderance of the evidence that the standard is likely to result in the unavailability in the United States of any type (or class) of this product with performance characteristics, features, sizes, capacities, and volume that are substantially the same as those generally available in the United States. (See 42 U.S.C. 6295(o)(4))
Second, DOE is applying 42 U.S.C. 6295(o)(2)(B)(iii), which establishes a rebuttable presumption that a standard is economically justified if the Secretary finds that “the additional cost to the consumer of purchasing a product complying with an energy conservation standard level will be less than three times the value of the energy * * * savings during the first year that the consumer will receive as a result of the standard, as calculated under the applicable test procedure * * *” The rebuttable-presumption test is an alternative path to establishing economic justification.
Third, in setting standards for a type or class of equipment that has two or more subcategories, DOE will specify a different standard level than that which applies generally to such type or class of equipment for any group of products “which have the same function or intended use, if * * * products within such group—(A) consume a different kind of energy from that consumed by other covered products within such type (or class); or (B) have a capacity or other performance-related feature which other products within such type (or class) do not have and such feature justifies a higher or lower standard” than applies or will apply to the other products. (See 42 U.S.C. 6295(q)(1)) In determining whether a performance-related feature justifies such a different standard for a group of products, the Department considers such factors as the utility to the consumer of such a feature and other factors DOE deems appropriate. Any rule prescribing such a standard will include an explanation of the basis on which DOE established such higher or lower level. (See 42 U.S.C. 6295(q)(2))
Federal energy efficiency requirements for equipment covered by 42 U.S.C. 6317 generally supersede State laws or regulations concerning energy conservation testing, labeling, and standards. (42 U.S.C. 6297(a)-(c) and 42 U.S.C. 6316(a)) The Department can, however, grant waivers of preemption for particular State laws or regulations, in accordance with the procedures and other provisions of section 327(d) of the Act. (42 U.S.C. 6297(d) and 42 U.S.C. 6316(a))
C. Background
1. Current Standards
Presently, there are no national energy conservation standards for the liquid-immersed and medium-voltage, dry-type distribution transformers covered by this rulemaking. However, on August 8, 2005, EPACT 2005 established energy conservation standards for low-voltage, dry-type distribution transformers that
will take effect on January 1, 2007. (42 U.S.C. 6295(y))
2. History of Standards Rulemaking for Distribution Transformers
On October 22, 1997, the Secretary of Energy published a notice stating that the Department “has determined, based on the best information currently available, that energy conservation standards for electric distribution transformers are technologically feasible, economically justified and would result in significant energy savings.” 62 FR 54809.
The Secretary's determination was based, in part, on analyses conducted by the Department'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 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 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.
1
In its supplemental assessment, ORNL-6925, the ORNL research team used a more accurate analytical model and better transformer market and loading data developed following the publication of ORNL-6847. Downloadable versions of both ORNL reports are available on the DOE Web site at:
http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html
1
Note:
NEMA later updated TP 1 in 2002 (NEMA TP 1-2002), in which it increased some of the efficiency levels. The latest version of TP 1 is available at the NEMA Web site:
http://www.nema.org/stds/tp1.cfm#download.
As a result of its positive determination, the Department developed the
Framework Document for Distribution Transformer Energy Conservation Standards Rulemaking
in 2000, describing the procedural and analytic approaches the Department anticipated using to evaluate the establishment of energy conservation standards for distribution transformers.
2
This document is also available on the aforementioned DOE Web site. On November 1, 2000, the Department held a public meeting 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 meeting. The major issues discussed were: Definition of covered transformer products, definition of product classes, possible proprietary (patent) issues regarding amorphous material, ties between efficiency improvements and installation costs, baseline and possible higher efficiency levels, base case trends (i.e., trends absent regulation), transformer costs versus transformer prices, appropriate LCC subgroups, 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.
2
The Department published a notice of availability of the Framework Document in the
Federal Register
. 65 FR 59761 (October 6, 2000). The Framework Document itself is available on the DOE Web site:
http://www.eere.energy.gov/buildings/appliance_standards/commercial/pdfs/trans_framework.pdf.
Stakeholder comments submitted during the Framework Document comment period elaborated on 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 national energy savings (NES) and NPV analyses, the analysis of the effects of a potential standard on employment, the manufacturer impact analysis (MIA), and the timing of the analyses.
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 three 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) obtain information and comments on production costs and manufacturing processes presented in the draft engineering analysis update report, and (3) provide to manufacturers an opportunity, early in the rulemaking process, to express specific concerns to the Department.
Seeking early and frequent consultation with stakeholders, the Department posted draft reports on its website as it prepared for the publication of the ANOPR. The reports included draft screening analysis findings, and draft engineering analysis and LCC analysis reports on 50 kVA single-phase, liquid-immersed, pad-mounted transformers and 300 kVA three-phase, medium-voltage, dry-type transformers. The Department also held a live, online Web cast on October 17, 2002, giving an overview of the LCC analysis and a tutorial on the use of the LCC spreadsheet. The Department received comments from stakeholders on all the draft publications, which helped improve the quality of the analysis included in the ANOPR published on July 29, 2004. 69 FR 45376.
In the ANOPR, the Department invited stakeholders to comment on the following key issues: Definition and coverage, product classes, engineering analysis inputs, design option combinations, the 0.75 scaling rule, modeling of transformer load profiles, distribution chain markups, discount rate selection and use, baseline determination through purchase evaluation formulae, electricity prices, load growth over time, life-cycle cost subgroups, and utility deregulation impacts.
In preparation for the September 28, 2004, ANOPR public meeting, the Department held a Web cast on August 10, 2004, to acquaint stakeholders with the analytical tools (spreadsheets) and other material published the previous month. During the ANOPR comment period, which ended on November 9, 2004, stakeholders submitted comments on the 13 issues listed above, as well as on other issues. These comments are discussed in section IV of this NOPR.
On August 5, 2005, the Department posted on its Web site several draft NOPR analyses for early public review, including draft technical support document (TSD) chapters on the engineering analysis, the energy use and end-use load characterization, the markups for equipment price determination, the LCC and payback period analyses, the shipments analysis, the national impact analysis, and the MIA. The Department also posted draft NOPR spreadsheets for the engineering
analysis, LCC analysis, national impact analysis, and MIA on its Web site.
On August 8, 2005, President Bush signed into law EPACT 2005, Public Law 109-58. Section 135(c)(4) of this Act establishes minimum efficiency levels for low-voltage, dry-type transformers manufactured, or imported into the U.S., on or after January 1, 2007. (42 U.S.C. 6295(y)) The levels are those appearing in Table 4-2 of NEMA TP 1-2002,
Guide for Determining Energy Efficiency for Distribution Transformers.
The Department incorporated this standard along with efficiency standards for several other products and equipment in a
Federal Register
Notice. 70 FR 60407 (October 18, 2005). Because EPACT 2005 established standards for low-voltage, dry-type distribution transformers, the Department is no longer considering standards for the single- and three-phase, low-voltage dry-type distribution transformers in this rulemaking.
In conjunction with this NOPR, the Department also published on its website the complete TSD and several spreadsheets. The TSD contains technical documentation of each analysis conducted under this rulemaking, providing specific information on the methodology and results. The spreadsheets, discussed in the relevant TSD chapters, represent the analytical tools and results that support today's proposed rule. The engineering analysis spreadsheets represent the Department's design database, providing the cost-efficiency relationships for the 10 specific distribution transformer units analyzed—five liquid-immersed and five medium-voltage, dry-type units. The LCC spreadsheet calculates the LCC and payback periods at six standard levels for these representative units. The national impact analysis spreadsheet tool calculates impacts of efficiency standards on distribution transformer shipments, as well as the NES and NPV of the standard levels considered. The MIA spreadsheet evaluates the financial impact of standards on distribution transformer manufacturers. All of these spreadsheet tools are posted on the Department's Web site, along with the complete NOPR TSD, at
http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis_nopr.html.
3. Process Improvement
The “Process Rule,”
Procedures, Interpretations and Policies for Consideration of New or Revised Energy Conservation Standards for Consumer Products,
Title 10 CFR Part 430, Subpart C, Appendix A, applies to the development of energy-efficiency standards for consumer products. While distribution transformers are considered a commercial product, the Department decided to apply some of the provisions of the “Process Rule” to this rulemaking.
In today's notice, the Department describes the framework and methodologies for developing the proposed standards. The framework and methodologies reflect improvements made, and steps taken, in accordance with the Process Rule, including DOE's use of economic models and analytical tools. Since the rulemaking process is dynamic, if timely new data, models, or tools that enhance the development of standards become available, the Department will incorporate them into the rulemaking.
III. General Discussion
A. Test Procedures
Section 7(b) of the Process Rule requires that the Department propose necessary modifications to the test procedure for a product before issuing a NOPR concerning efficiency standards for that product. Section 7(c) of the Process Rule states that DOE will issue a final, modified test procedure prior to issuing a proposed rule for energy conservation standards. The test procedure for distribution transformers was published as a final rule on April 27, 2006. 71 FR 24972.
B. Technological Feasibility
1. General
The Department considers design options technologically feasible if they are in use by the respective industry or if research has progressed to the development of a working prototype. The Process Rule sets forth a definition of technological feasibility as follows: “Technologies incorporated in commercially available products or in working prototypes will be considered technologically feasible.” 10 CFR Part 430, Subpart C, Appendix A, section 4(a)(4)(i).
In each standards rulemaking, the Department conducts a screening analysis, which is based on information gathered regarding existing technology options and prototype designs. In consultation with manufacturers, design engineers, and other stakeholders, the Department develops a list of design options for consideration in the rulemaking. Once the Department has determined that a particular design option is technologically feasible, it then further evaluates each design option in light of the other three criteria in the Process Rule. 10 CFR Part 430, Subpart C, Appendix A, section 4(a)(3) and (4). The three additional criteria are: (a) Practicability to manufacture, install, or service, (b) adverse impacts on product utility or availability, or (c) health or safety concerns that cannot be resolved. 10 CFR Part 430, Subpart C, Appendix A, section 4(a). All design options that pass these screening criteria are candidates for further assessment.
As discussed in the ANOPR for this rulemaking, the Department is not considering the following design options because they do not meet one or more of the 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. 69 FR 45387. For the NOPR, there were no changes to the list of technology options screened out of the ANOPR analysis. Discussion of the application of the screening analysis criteria to the design options appears in Chapter 4 of the TSD.
The Department believes that all of the efficiency levels evaluated in today's notice are technologically feasible. The technologies incorporated in the transformer design database have all been used (or are being used) in commercially available products or working prototypes. The designs all incorporate core steel and conductor types that are commercially available in today's transformer materials supply market. Any one manufacturer may not be using all the materials considered by the Department for a given model analyzed, but these materials could be purchased from multiple suppliers today if design changes warranted it.
In addition, to prepare transformer designs for evaluation, DOE used transformer design software that is also used by manufacturers in the U.S. and abroad. The Department evaluated the transformer design software by comparing the software's designs against six transformers it purchased, tested, and disassembled. For these units, the software accurately predicted the performance and manufacturer selling prices when using the same material cost, labor cost, and manufacturer markup assumptions that were used in the engineering analysis for the NOPR (see TSD Chapter 5, section 5.7).
For liquid-immersed distribution transformers, the designs prepared by the software were all wound-core designs. The least efficient design used M6 core steel and the most efficient used amorphous material. All designs
contained in the Department's design database could be built today. For medium-voltage, dry-type transformers, DOE used commercially available core steels, ranging from M6 through domain-refined 9-mil (0.009 inch) high permeability, grain-oriented steel (H-O DR). Core-construction techniques included butt-lap, mitered, and cruciform construction. The conductors and insulation types used were all conventional, and are commercially available in distribution transformers today. Thus, the Department believes that all the efficiency levels discussed in today's proposed rule are technologically feasible.
2. Maximum Technologically Feasible Levels
In developing today's proposed standards, the Department followed the provisions of 42 U.S.C. 6295(p)(2), which states that, when the Department proposes to adopt, or to decline to adopt, an amended or new standard for each type (or class) of covered product, “the Secretary shall determine the maximum improvement in energy efficiency or maximum reduction in energy use that is technologically feasible.” The Department determined the maximum technologically feasible (“max-tech”) efficiency level in the engineering analysis (see TSD Chapter 5) using the most efficient materials not screened out and applying design parameters that drove the transformer design software to create designs at the highest efficiencies achievable. The Department then used these highest-efficiency designs to establish the max-tech level for the LCC analysis (see TSD Chapter 8). In the national impact analysis (see TSD Chapter 10), the Department then scaled these max-tech efficiencies to the other kVA ratings within a given design line, establishing max-tech efficiencies at all the distribution transformer kVA ratings. Tables III.1 and III.2 provide the complete list of max-tech efficiency levels considered for all kVA ratings within each product class.
Table III.1.—Max-Tech Levels for Liquid-Immersed Distribution Transformers
Single-phase
kVA
Efficiency
(%)
Three-phase
kVA
Efficiency
(%)
10
99.32
15
99.31
15
99.39
30
99.42
25
99.46
45
99.47
37.5
99.51
75
99.54
50
99.59
112.5
99.58
75
99.59
150
99.61
100
99.62
225
99.65
167
99.66
300
99.67
250
99.70
500
99.71
333
99.72
750
99.66
500
99.75
1000
99.68
667
99.77
1500
99.71
833
99.78
2000
99.73
2500
99.74
Note:
All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972.
Table III.2.—Max.-Tech Levels for Medium-Voltage, Dry-Type Distribution Transformers
Single-phase
BIL
kVA
20-45 kV
efficiency
(%)
46-95 kV
efficiency
(%)
≥96 kV
(%)
Three-phase
kVA
20-45 kV
efficiency
(%)
46-95 kV
efficiency
(%)
≥96 kV
efficiency
(%)
15
99.05
98.54
15
98.75
98.08
25
99.17
98.71
30
98.95
98.38
37.5
99.25
98.84
45
99.05
98.54
50
99.30
98.92
75
99.17
98.71
75
99.37
99.02
99.22
112.5
99.25
98.84
100
99.41
99.09
99.28
150
99.30
98.92
167
99.48
99.20
99.36
225
99.37
99.02
99.22
250
99.42
99.42
99.42
300
99.41
99.09
99.28
333
99.46
99.46
99.46
500
99.48
99.20
99.36
500
99.51
99.51
99.52
750
99.42
99.42
99.42
667
99.54
99.54
99.55
1000
99.46
99.46
99.46
833
99.57
99.57
99.57
1500
99.51
99.51
99.52
2000
99.54
99.54
99.55
2500
99.57
99.57
99.57
Note:
BIL means basic impulse insulation level.
Note:
All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972.
C. Energy Savings
One of the criteria that govern the Department's adoption of standards for distribution transformers is that the standard must result in “significant” energy savings. (42 U.S.C. 6317(a)) While the term “significant” is not defined by EPCA, a U.S. Court of Appeals, in
Natural Resources Defense Council
v.
Herrington
, 768 F.2d 1355, 1373 (D.C. Cir. 1985), indicated that Congress intended “significant” energy savings in a similar context in Section 325 of the Act to be savings that were not “genuinely trivial.” The energy savings for all of the trial standard levels considered in this rulemaking are nontrivial, and therefore the Department considers them “significant” as required by 42 U.S.C. 6317.
D. Economic Justification
As noted earlier, EPCA provides seven factors to be evaluated in determining whether an energy conservation standard for distribution transformers is economically justified. The following discusses how the Department has addressed each of those seven factors thus far in this rulemaking. (42 U.S.C. 6295(o)(2)(B)(i))
1. Economic Impact on Manufacturers and Commercial Consumers
The Process Rule established procedures, interpretations, and policies to guide the Department in the consideration of new or revised appliance efficiency standards. The provisions of the rule have direct bearing on the implementation of the MIA. First, the Department used an annual-cash-flow approach in determining the quantitative impacts of a new or amended standard on manufacturers. This included both a short-term assessment based on the cost and capital requirements during the period between the announcement of a regulation and the time when the regulation comes into effect, and a long-term assessment. Impacts analyzed include industry NPV, cash flows by year, changes in revenue and income, and other measures of impact, as appropriate. Second, the Department analyzed and reported the impacts on different types of manufacturers, with particular attention to impacts on small manufacturers. Third, the Department considered the impact of standards on domestic manufacturer employment, manufacturing capacity, plant closures, and loss of capital investment. Finally, the Department took into account cumulative impacts of different DOE regulations on manufacturers.
For commercial consumers, measures of economic impact are the changes in installed (first) cost and annual operating costs. To assess the impact on first cost, the Department considered the percent increase in the consumer equipment cost before installation. To assess the impact on life-cycle costs, which include both consumer equipment costs and annual operating costs, the Department conducted an LCC analysis of the equipment at each candidate standard level (CSL) (
see
below).
2. Life-Cycle Costs
The LCC is the sum of the purchase price, including the installation, and the operating expense—including operating energy consumption, maintenance, and repair expenditures—discounted over the lifetime of the equipment. To determine the purchase price including installation, DOE estimated the markups that are added to the manufacturer selling price by distributors and contractors, and estimated installation costs from an analysis of transformer installation cost estimates for a wide range of weights and sizes. The Department assumed that maintenance and repair costs are not dependent on transformer efficiency. In estimating operating energy costs, DOE used the full range of commercial consumer marginal energy prices, which are the energy prices that correspond to incremental changes in energy use.
For each distribution transformer representative unit, the Department calculated both LCC and LCC savings from a base-case scenario for six candidate standard efficiency levels. The six candidate standard levels were chosen to correspond to the following:
• NEMA TP 1-2002;
•
1/3
of efficiency difference between TP 1 and minimum LCC;
•
2/3
of efficiency difference between TP 1 and minimum LCC;
• Minimum LCC;
• Maximum energy savings with no change in LCC; and
• Maximum technologically feasible.
In order to calculate the appropriate efficiency levels for kVA ratings that were not analyzed (
i.e.
, all the kVA ratings other than the ten representative units), the Department applied a scaling rule to extrapolate the findings on the ten representative units to these other ratings. For information on the scaling rule,
see
section IV.B.1 and TSD Chapter 5, section 5.2.2.
The Department presents the calculated LCC savings as a distribution, with a mean value and range. The Department used a distribution of consumer real discount rates for the calculations, with mean values ranging from 3.3 to 7.5 percent, specific to the cost of capital faced by purchasers of the representative units. Chapter 8 of the TSD contains the details of the LCC calculations. The LCC is one of the factors DOE considers in determining the economic justification for a new or amended standard. (
See
42 U.S.C. 6295(o)(2)(B)(i)(II))
3. Energy Savings
While significant conservation of energy is a separate statutory requirement for imposing an energy conservation standard, in determining the economic justification of a standard, the Department considers the total projected energy savings that are expected to result directly from the standard. (See 42 U.S.C. 6295(o)(2)(B)(i)(III)) The Department used the NES spreadsheet results in its consideration of total projected savings. The savings figures are discussed in section V.A.3 of this notice.
4. Lessening of Utility or Performance of Equipment
In establishing classes of products, and in evaluating design options and the impact of potential standard levels, the Department avoided having new standards for distribution transformers that lessen the utility or performance of the equipment under consideration in this rulemaking. None of the proposed trial standard levels reduces the utility or performance of distribution transformers. (See 42 U.S.C. 6295(o)(2)(B)(i)(IV)) The Department's engineering options do not change the utility and performance of distribution transformers. The impact of any increase in transformer weight associated with efficiency improvements is captured by the economic analysis. Specifically, installation costs for pole-mounted transformers include estimates of stronger pole and pole change-out costs that may be incurred with heavier, more efficient transformers.
5. Impact of Any Lessening of Competition
The Department considers any lessening of competition that is likely to result from standards. Accordingly, DOE has written to the Attorney General to request that the Attorney General transmit to the Secretary, not later than 60 days after the publication of this proposed rule, a written determination of the impact, if any, of any lessening of competition likely to result from the proposed standard, together with an analysis of the nature and extent of such
impact. (See 42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii))
6. Need of the Nation To Conserve Energy
The non-monetary benefits of the proposed standard are likely to be reflected in improvements to the security and reduced reliability costs of the Nation's energy system—namely, reductions in the overall demand for energy will result in reduced costs for maintaining reliability of the Nation's electricity system. The Department conducts a utility impact analysis to show the reduction in installed generation capacity requirements. Reduced power demand (including peak power demand) generally reduces the costs of maintaining the security and reliability of the energy system.
The Department has determined that today's proposed standard should result in reductions in greenhouse gas emissions. The Department quantified a range of primary energy conversion factors and estimated the emissions reductions associated with the generation displaced by energy-efficiency standards. The environmental effects from each trial standard level for this equipment are reported in the TSD environmental assessment. (See 42 U.S.C. 6295(o)(2)(B)(i)(VI))
7. Other Factors
The Secretary of Energy, in determining whether a standard is economically justified, considers any other factors that the Secretary deems to be relevant. (See 42 U.S.C. 6295(o)(2)(B)(i)(VII)) For today's proposed standard, the Secretary took into consideration a factor relating to several comments received at the ANOPR public meeting, during the comment period following the meeting, and in the MIA interviews. Stakeholders expressed concern about the increasing cost of raw materials for building transformers, the volatility of material prices, and the cumulative effect of material price increases on the transformer industry (see section IV.B.2, Engineering Analysis Inputs). The Department conducted supplementary engineering and LCC analyses using first-quarter 2005 material prices and considered the impacts on LCC savings and payback periods when evaluating the appropriate standard levels for liquid-immersed and medium-voltage, dry-type distribution transformers. The results of the engineering and LCC analyses for the first-quarter 2005 material pricing analysis are in TSD Appendix 5C.
IV. Methodology and Discussion of Comments
A. Market and Technology Assessment
1. 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, or (b) capacity, or other performance-related features, such as those that affect both consumer utility and efficiency. Different energy-efficiency standards may apply to different product classes. As discussed in the ANOPR, the Department received some guidance from stakeholders on establishing appropriate product classes for the population of distribution transformers. 69 FR 45385. Originally, the Department created 10 product classes, dividing up the population of distribution transformers by:
• Type of transformer insulation—liquid-immersed or dry-type;
• Number of phases—single or three;
• Voltage class—low or medium (for dry-type units only); and
• Basic impulse insulation level (for medium-voltage, dry-type units only).
EPACT 2005 includes provisions establishing energy conservation standards for two of the Department's product classes (PC3, low-voltage, single-phase, dry-type and PC4, low-voltage, three-phase, dry-type). (42 U.S.C. 6295(y)) With standards thereby established for low-voltage, dry-type distribution transformers, the Department is no longer considering these two product classes for standards. Table IV.1 presents the eight product classes that remain within the scope of this rulemaking.
Table IV.1.—Distribution Transformer Product Classes for the NOPR
PC No.*
Insulation
Voltage
Phase
BIL rating
kVA range
PC1
Liquid-Immersed
Single
10-833 kVA.
PC2
Liquid-Immersed
Three
15-2500 kVA.
PC5
Dry-Type
Medium
Single
20-45 kV BIL
15-833 kVA.
PC6
Dry-Type
Medium
Three
20-45 kV BIL
15-2500 kVA.
PC7
Dry-Type
Medium
Single
46-95 kV BIL
15-833 kVA.
PC8
Dry-Type
Medium
Three
46-95 kV BIL
15-2500 kVA.
PC9
Dry-Type
Medium
Single
≥96 kV BIL
75-833 kVA.
PC10
Dry-Type
Medium
Three
≥96 kV BIL
225-2500 kVA.
*
Note:
Although the PC3 and PC4 product classes are no longer included in this rulemaking, for consistency with prior material published under this rulemaking, the Department has not renumbered the liquid-immersed and medium-voltage, dry-type product classes that remain.
DOE received no comments that requested modifications to the Department's product classes as proposed in the ANOPR. However, Howard Industries commented that it supported the independent categorization of liquid-immersed and dry-type transformers. It pointed out that the applications and type of customers for these two types of transformers can vary widely. (Howard, No. 70 at p. 2) The Department agrees with this comment and continues to treat liquid-immersed and dry-type transformers separately in its analysis.
Concerning the use of three basic impulse insulation level (BIL) groupings for medium-voltage, dry-type transformers, Federal Pacific Transformer (FPT) noted that BIL levels do affect cost and efficiency, and agreed that DOE should conduct its analysis by BIL grouping. It commented that the efficiency levels should be modeled according to the BIL levels as much as possible. (FPT, No. 64 at p. 3) NEMA commented that it was willing to change the BIL groupings in TP 1-2002 from two to three, so TP 1 would have the same BIL groupings for medium-voltage, dry-type transformers as the Department's proposal. (NEMA, No. 60 at p. 2) The Alliance to Save Energy (ASE) commented that the Department's refinement of BIL classifications over TP 1 is justified and should result in more appropriate efficiency levels. (ASE, No. 52 at p. 2 and No. 75 at p. 2) Finally, the Oregon Department of Energy (ODOE) commented that it supports the refinements that created three BIL groupings for these transformers. (ODOE, No. 66 at p. 2) The Department did not receive any comments critical of the three BIL
groupings for medium-voltage, dry-type transformers, and therefore continues to use these same BIL groupings in today's proposed rule.
Howard Industries and ASE commented on whether DOE should regulate the efficiency of liquid-immersed transformers. Howard commented that, for liquid-immersed transformers—especially for the utility, municipal, and co-operative segments—energy-efficiency standards should be voluntary because these transformer customers are already considering life-cycle costs in their purchasing decisions. (Howard, No. 70 at p. 4) Howard commented that it feels a voluntary program would be better for the whole utility market than a mandatory standard. Howard believes a mandatory program would contribute to standardization of liquid-immersed transformer designs, and encourage manufacturers to move to countries with lower labor costs. Howard suggested that the ballast and electric motor industries are two examples of products where mandatory standards were implemented and domestic manufacturing declined. (Howard, No. 70 at p. 2) ASE agreed with the Department's decision that liquid-immersed transformers fall within the scope of the standard. (ASE, No. 75 at p. 2) Under 42 U.S.C. 6317, the Department is charged in this rulemaking with determining whether standards for distribution transformers are technologically feasible and economically justified and would result in significant energy savings. Based on the Department's analysis and information available to date, standards for liquid-immersed transformers appear to be technologically feasible and economically justified, and would result in significant energy savings. The Department considered a voluntary program, NEMA TP-1 in its Determination Analysis, but concluded that the “efficiency levels would capture the most cost effective energy savings but may not capture substantial energy savings that appear to be economically justified and technologically feasible.” 62 FR 54816. In addition, the Department considered the impact of voluntary programs in its regulatory impact analysis (see the report in the TSD “Regulatory Impact Analysis for Electrical Distribution Transformers”), and found that a voluntary program would not result in standards that achieve the maximum efficiency level that is technologically feasible and economically justified. Thus, in accordance with 42 U.S.C. 6317, the Department intends to continue to consider liquid-immersed distribution transformers for energy efficiency standards. To gain a better understanding of the concern raised by Howard Industries about minimum efficiency standards leading to design standardization, the Department requests that other stakeholders comment on this issue.
2. Definition of a Distribution Transformer
The Department received several comments from stakeholders on the definition of a distribution transformer. The Department has established the definition (and scope of this rulemaking) in its final rule on the test procedure for distribution transformers. 10 CFR Part 431, Subpart K; 71 FR 24972.
EPCA directed DOE to develop standards for those “distribution transformers” for which energy conservation standards would be technologically feasible and economically justified, and would result in significant energy savings, but did not specify a definition for a distribution transformer. (42 U.S.C. 6317(a)) Thus, the Department began developing a definition in the determination analysis, and refined that definition through the test procedure rulemaking and this rulemaking. This process was obviated to a substantial extent by the enactment of EPACT 2005, which amended EPCA to, among other things, include a definition of a distribution transformer. (42 U.S.C. 6291(35)) The existing statutory definition establishes the scope of coverage for this rulemaking.
Before the passage of EPACT 2005, stakeholders had submitted comments on the definition of a distribution transformer presented in the ANOPR. These comments are summarized here with discussion on whether or not the new EPCA definition of a distribution transformer, promulgated in EPACT 2005, addresses the issues raised by the stakeholders. For more detail on the definition of a distribution transformer, please see the test procedure final rule notice. 71 FR 24972.
PEMCO and Southern Company commented on exclusions for dimensionally or physically constrained transformers. PEMCO noted that an exclusion for replacement or retrofit transformers is needed because they must have exactly the same physical dimensions as the ones they are replacing. (PEMCO, No. 57 at p. 1) Southern Company agreed, noting that in retrofit installations, size and weight are a factor. Southern commented that, as transformer efficiency increases, the units become larger and obstructions and required minimum clearances are more difficult to achieve. Southern noted that this is true for both liquid-immersed, pad-mounted units and dry-type transformers installed in buildings. It concluded that the increased size is likely to cause both delivery and installation problems in many locations. (Southern, No. 71 at p. 2) At the ANOPR public meeting, Ameren commented that the Department should consider the impact of different size/configurations resulting from increased efficiency on the speed and ease of emergency replacement transformers. (Public Meeting Transcript, No. 56.12 at pp. 255-256) The Department accounted for generally applicable dimensional and physical constraints on transformer installation through the inclusion of size- and weight-dependent installation costs in its LCC model. These costs include potential pole change-out costs for large overhead transformers, and the size- and weight-dependent labor and equipment costs associated with installing larger transformers. The costs estimated by the Department do not include the costs of rehabilitating confined spaces that may have to be modified for the installation of larger transformers. This issue is similar to the situation that arises when utilities and contractors need to increase transformer size due to load growth. One method of modeling such costs would be to include a space-occupancy cost to the cost of transformer operation. The Department invites comment on whether space-occupancy costs should be included in transformer cost estimates and which methods are appropriate for estimating such costs.
Howard and FPT expressed concern about distribution transformers designed for use in specific environments. Howard recommended that underground and subway-style transformers be excluded from the standards. Howard noted that these transformers are often being retrofitted into existing concrete vaults and, in most cases, the whole concrete structure would need to be replaced if DOE mandated a more efficient unit. (Howard, No. 70 at p. 3) FPT recommended that the Department consider exempting mining transformers designed for installation inside equipment with severe space limitations, due to their radically different loss characteristics. FPT noted that efficiency standards could cause problems in applications where these transformers would not fit. (Public Meeting Transcript, No. 56.12 at pp. 54-56; FPT, No. 64 at p. 2) ODOE
commented that it had no objection to the Department excluding specialty transformers for the mining industry, provided that the exclusion can be written so as not to inadvertently create a loophole for other end uses. (ODOE, No. 66 at p. 2) As amended, EPCA does not exclude these types of dimensionally constrained transformers from its definition of distribution transformer. Furthermore, although 42 U.S.C. 6291(35)(B)(iii) authorizes DOE to exclude additional types of distribution transformers, DOE does not have a sufficient basis for excluding dimensionally constrained transformers under this provision. While these transformers apparently are designed for special applications, in line with 42 U.S.C. 6291(35)(B)(iii)(I), DOE lacks specific information on the other two criteria, namely, whether these transformers would be likely to be used in general purpose applications, and whether significant energy savings would result from applying standards to them. Stakeholders have submitted neither data on the energy savings potential of standards for these transformers, nor information as to the likelihood they could be used in general purpose applications. Therefore, the Department is not proposing to exclude any of the transformers discussed in this paragraph under section 321(35)(B)(iii) of EPCA. (42 U.S.C. 6291(35)(B)(iii))
On the issue of harmonic mitigating and harmonic tolerating transformers, most of the comments proposed eliminating the exemption for these types of distribution transformers. At the ANOPR public meeting, both the American Council for an Energy Efficient Economy (ACEEE) and NEMA commented that they supported the elimination of the exemption for harmonic mitigating and harmonic tolerating (or K-rated) transformers. (Public Meeting Transcript, No. 56.12 at p. 27 and p. 35) In written comments, ACEEE, Harmonics Limited, NEMA, and ODOE all recommended eliminating the exemption for harmonic mitigating and harmonic tolerating (or K-rated) transformers. (ACEEE, No. 50 at p. 2 and No. 76 at p. 4; Harmonics Limited, No. 59 at p. 1; NEMA, No. 48 at p. 3 and No. 60 at p. 2; ODOE, No. 66 at p. 2) PEMCO commented that it agrees with including K-factor transformers as covered equipment to stop the current practice of using that exemption to avoid efficiency requirements. (PEMCO, No. 57 at p. 2)
EMS International Consulting (EMSIC) provided a different viewpoint on harmonic tolerating transformers (or K-factor designs); it commented that it believes K-factor and harmonic mitigating transformers (up to a certain level of K-factor) should be subject to standards. (EMSIC, No. 73 at p. 3) FPT went further, proposing a more detailed treatment of K-factor designs. FPT recognizes that some parties are specifying K-factor transformers as a means of getting around State standards requiring TP 1, and that this would probably happen more if DOE exempts K-factor transformers broadly. Therefore, FPT recommended that: (1) Transformers rated up to 300 kVA and having a K-factor of K-13 or less be required to comply with the efficiency standards, and (2) transformers above 300 kVA and having a K-factor of K-4 or less be required to comply with the efficiency standards. (FPT, No. 64 at p. 2)
The definition of a distribution transformer in EPACT 2005 does not contain an explicit exemption for harmonic mitigating or harmonic tolerating (K-rated) transformers. Furthermore, DOE does not have a sufficient basis for excluding them under 42 U.S.C. 6291(35)(B)(iii). While these transformers apparently are designed for special applications, in line with 42 U.S.C. 6291(35)(B)(iii)(I), DOE lacks specific information on the other two criteria, namely, whether these transformers would be likely to be used in general purpose applications, and whether significant energy savings would result from applying standards to them. Therefore, the Department is not proposing to exclude any of the transformers discussed in this paragraph under section 321(35)(B)(iii) of EPCA. 42 U.S.C. 6291(35)(B)(iii).
On the issue of non-ventilated transformers, the Department received a comment from NEMA indicating that it agrees with the Department's exclusion of non-ventilated transformers because of the inherent core losses in such designs. (NEMA, No. 60 at p. 1) This exclusion is now required by EPCA, because EPACT 2005 included an exemption for sealed and non-ventilated transformers.
On the issue of refurbished transformers, the Department received comments representing different viewpoints. Georgia Power commented that DOE's documentation is not clear on the reuse of transformers that have been removed from service for refurbishment. It indicated that it saves approximately 11.5 percent of its total transformer budget by refurbishing and reusing transformers. Georgia Power concluded that, if the Department requires these units to be regulated, it will have a significant financial impact on utilities. (Georgia Power, No. 78 at p. 3)
Manufacturers, on the other hand, appear to be concerned that the increased cost of new, standards-compliant transformers would cause some customers to either purchase rebuilt transformers or refurbish existing ones they own. ERMCO is concerned that if these products are not subject to standards, it may be possible for an end user to avoid the standard by always rewinding failed units. ERMCO stated that there are several independent and utility-owned repair shops that refurbish: Some make minor repairs, others rewind coils. (ERMCO, No. 58 at p. 2) Howard commented that when the final rule is established, it is absolutely essential that it apply to new transformers, used transformers, and repaired transformers. (Howard, No. 70 at p. 3) HVOLT recommended that the Department require any rebuilt transformer that has a winding replaced to meet the new standard, stating that this is necessary to remove a major loophole and would ultimately result in improved energy efficiency for the country. (HVOLT, No. 65 at p. 3 and Public Meeting Transcript, No. 56.12 at p. 59) EMSIC commented that it believes that all refurbished (“repaired”) units should be subject to the new standards to close a potential loophole. (EMSIC, No. 73 at p. 3) ODOE agreed that re-wound transformers should be required to meet the new standards. ODOE also commented that some organizations in the Pacific Northwest have been involved in promotion of high-quality rewinding practices. Through these programs, it has become evident that high-quality work in this area can produce a product that meets the same performance specifications as a new product, while poor-quality work can seriously degrade performance. (ODOE, No. 66 at p. 2)
EPACT 2005's definition of a distribution transformer does not mention refurbished or repaired transformers, and therefore no guidance on treatment of these transformers is provided by the statute. Furthermore, the Department's regulatory authority with respect to refurbished equipment is not clearly delineated. EPCA, as amended by EPACT 2005, seems to require that only newly manufactured distribution transformers meet Federal efficiency requirements. (42 U.S.C. 6302, 6316(a) and 6317(a)(1)) Thus, DOE believes it lacks authority to require used and repaired transformers to comply with energy conservation standards. The same may be true for rebuilt transformers, although DOE's authority is an issue. Generally, EPCA provides that products, when
“manufactured,” are subject to efficiency standards. (42 U.S.C. 6302 and 6316) It is arguable, but by no means clear, that rebuilt transformers (i.e., those with one or more coils re-wound) could be considered to be “manufactured” again when they are rebuilt, and therefore be classified as new distribution transformers subject to standards. If, however, rebuilt products cannot be classified as newly manufactured, DOE would be subject to the same lack of authority to regulate them as applies to other used and repaired products. In addition, the Department does not have authority to regulate the efficiency of distribution transformers re-wound by their owners (i.e., ownership of the transformer is not transferred or sold to another party), despite the suggestion of some commenters that DOE do so. EPCA provides authority to regulate only products that are sold, imported, or otherwise placed in commerce. (42 U.S.C. 6291, 6311, and 6317(f)(1))
Throughout the history of its appliance and commercial equipment energy conservation standards program, DOE has not sought to regulate used units that have been reconditioned or rebuilt, or that have undergone major repairs. For transformers, regulating this part of the market, including the enforcement of efficiency requirements, would be a complex and burdensome task. By and large, the Department believes EPCA indicates a Congressional intent that DOE focus on the market for new products, and believes this is where the most energy savings can be achieved. For distribution transformers in particular, the Department understands that, at present, rebuilt transformers are only a small part of the market.
For all of these reasons, the Department is proposing not to include energy conservation standards for used, repaired, and rebuilt distribution transformers in this rulemaking. Nevertheless, the Department recognizes the concerns raised by commenters about possible substitution of rebuilt transformers for new transformers. If conditions change—for example, if rebuilt transformers become a larger segment of the transformer market—DOE will reconsider its decision not to subject them to energy conservation requirements. The Department invites comment on this decision.
On the issue of excluding special impedance transformers, the Department received one comment from Howard. In response to the ANOPR table of normal impedance ranges, Howard provided a slightly revised table of “normal” impedance ranges that it believes are more in line with the American National Standards Institute (ANSI) standards with which most utility systems comply. (Howard, No. 70 at p. 3) Howard's table contains slightly narrower bands of “normal” impedance ranges, which would result in fewer transformers being subject to standards and more transformers being classified as exempt. The Department is concerned that some transformers designed for electricity distribution could be manufactured with impedances outside normal ranges so that they would not be subject to otherwise applicable efficiency standards. Such transformers could have a competitive advantage over standards-compliant distribution transformers. If this occurred, it would subvert the standards. The Department also notes that, in NEMA's revised test procedure document, NEMA TP 2-2005, the tables of normal impedance ranges for both liquid-immersed and dry-type transformers are exactly the same as those published by the Department. Thus, in the test procedure final rule notice, the Department retained its tables of “normal” impedance ranges. 71 FR 24972.
B. Engineering Analysis
The purpose of the engineering analysis was to evaluate a range of transformer efficiency levels and associated manufacturing selling prices. The engineering analysis considered technologies and design option combinations that were not screened out by the four criteria in the screening analysis. In the LCC analysis, the Department used the manufacturer selling price-efficiency relationships developed in the engineering analysis when it considered the consumer costs of moving to higher efficiency levels.
For the distribution transformers engineering analysis, the Department learned that manufacturers in both the liquid-immersed and medium-voltage, dry-type sectors commonly use software to design a distribution transformer to fill a customer's order. This software-design approach follows from the actual dynamics in the transformer market, where customers often specify certain performance characteristics and requirements. Manufacturers then compete for the contract based on the customized designs they generate using their software, which takes into account the customer's requirements and current material costs.
Consistent with this approach, 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 cost components. The software creates transformer designs and cost and performance characteristics associated with those designs that, when compiled, characterize the relationship between cost and efficiency. The Department selected software developed by an independent company, Optimized Program Service (OPS), not associated with any single manufacturer or manufacturer's association. The engineering analysis design runs span a broad range of efficiencies from lowest first cost to maximum technologically feasible. The data used in the engineering analysis is discussed in Chapter 5 of the TSD.
1. Engineering Analysis Methodology
There exist certain fundamental relationships between the kVA ratings of transformers and their physical size and performance. Termed the “0.75 scaling rule,” these size-versus-performance relationships arise from equations describing how a transformer's cost and efficiency change with kVA rating. The Department used the 0.75 scaling rule to reduce the number of units that needed to be analyzed for establishing minimum efficiency standards for distribution transformers as a whole. The findings on those units analyzed were later scaled to other kVA ratings using the 0.75 scaling rule. To maintain the accuracy of the 0.75 scaling rule, DOE established engineering “design lines.” Each design line consists of distribution transformers that have a full range of kVA ratings and that have similar construction and engineering principles. Some design lines consist of an entire product class, but none spans more than a product class. The Department then selected one representative unit from each of these design lines for analysis. The 0.75 scaling rule was a critical underlying factor in the engineering analysis, since it enabled DOE to reduce the number of units analyzed to 10. Discussion on use of the 0.75 scaling rule can be found in TSD Chapter 5, section 5.2.2. Technical detail on the derivation of the 0.75 scaling rule can be found in TSD Appendix 5B.
In the ANOPR, the Department solicited comments on the use of the 0.75 scaling rule. 69 FR 45416. ASE and ODOE wrote that they support the use of the 0.75 scaling rule, and believe it is the correct and necessary approach to simplify the analysis. (ASE, No. 52 at p. 3 and No. 75 at p. 3; ODOE, No. 66 at p. 4) HVOLT commented at the ANOPR public meeting that the 0.75 scaling rule was used to develop the NEMA TP 1
tables, and there have been no major complaints about it. (Public Meeting Transcript, No. 56.12 at p. 92) PEMCO commented that it routinely uses the 0.75 scaling rule in its business operations, and that the rule works for scaling component costs for consistent construction practice and within reasonable size differences. PEMCO cautioned, however, that the higher the voltage class of the windings and the closer to the lower end of a kVA product range, the greater the error from the 0.75 scaling rule. (PEMCO, No. 57 at p. 1) The Department appreciates this comment from PEMCO, as it had created the engineering design lines to minimize error, particularly with respect to the medium-voltage, dry-type BIL groupings. In addition to the three BIL groupings, the Department also subdivided some of the product classes into two or more engineering design lines, so the kVA rating of the representative unit would not be scaled more than an order of magnitude up or down in any one design line. It took both of these steps to minimize any error from scaling, and to provide a more robust analytic foundation for the proposed standards. Based on these comments and the cautionary note from PEMCO, the Department will continue to apply the 0.75 scaling rule to extrapolate findings to those kVA ratings not specifically analyzed within each of the design lines.
Another critical issue on which stakeholders commented pertained to the use of OPS software in the development of the Department's database of transformer designs. HVOLT commented that the Department's percentage cost increases for the 25 kVA pole-type transformer were not large enough. It believes that the percentage cost difference between the standard levels considered should be greater. (HVOLT, No. 65 at p. 2) The Department appreciates this comment, and looked carefully at all the OPS software inputs and results, and discussed these with individual manufacturers during site visits in 2005. The Department recognizes that the manufacturer selling prices in the ANOPR base case for the 25 kVA unit were too high, and that the percentage increase from a larger base price would be smaller for the same absolute dollar cost increase. Following revisions to the engineering analysis for the 25 kVA liquid-immersed, pole-type transformer, the baseline unit manufacturer selling price decreased from around $800 to approximately $500 and, as a result, the percentage change in manufacturer selling prices between efficiency values has increased.
FPT expressed concern that the manufacturer selling prices for dry-type transformers may rise more rapidly than is represented in the engineering analysis. FPT is concerned that this may skew the decision-making process regarding what efficiency levels are cost-justified. (FPT, No. 64 at p. 2) Similarly, Howard commented that it believes the inputs and outputs of the OPS program are inaccurate, since it found the outputs of the software to be different from its own calculations. Howard expressed concern at the number of compromises, generalizations, and assumptions that could dilute the effectiveness of the results. (Howard, No. 70 at p. 3) NEMA commented that, because LCC results seem to justify standards higher than TP 1, the OPS design software may not be accurately modeling real-world units. (NEMA, No. 48 at p. 2) NEMA also commented that it had tested an actual unit that had a similar technical specification to an OPS design, and found different results than were reported by the Department. NEMA noted that the designs in the Department's database were not built and tested, and therefore are not representative of real transformers. (Public Meeting Transcript, No. 56.12 at p. 35) In a written submission, NEMA provided further detail on this comparison, and again questioned the real-world predictive capabilities of the software used. (NEMA, No. 60 at p. 3)
In response to these comments, the Department reviewed and refined the inputs to the OPS software in consultation with transformer manufacturers, OPS, and the Department's technical experts. It is important to recognize that there are many inputs to both the engineering and the LCC analytical models. For both analytical models, the Department updated its data and cost estimates for the NOPR analysis. These refinements changed the resulting designs and associated manufacturer selling price-efficiency relationships discussed in section IV.B of today's notice and Chapter 5 of the TSD.
The Department appreciates and thanks NEMA and its members for taking the time to locate and test a transformer that was similar to the one published. The Department found two critical problems with the comparison made. First, the design NEMA reviewed was not one DOE used in the ANOPR engineering analysis, but rather a draft design produced for comment two years before the ANOPR, in August 2002. Based on stakeholder feedback on that draft design, DOE modified the inputs to the OPS software when generating the ANOPR engineering database; thus, that design was not included. Second, the two designs NEMA compared, while having the same kVA rating, were not similar transformers. The OPS design and the unit NEMA tested had different BIL ratings and would be grouped in different product classes; therefore, different testing results would be expected.
Concerning the comments on the accuracy of the OPS software, the Department recognizes that differences between the Department's engineering analysis results and those of manufacturers can be caused by a number of factors, including different material prices, labor estimates, modeling parameters (e.g., impedance range, inductance), markups, and the consideration of different non-active transformer components (e.g., gauges, tanks). The Department discussed its inputs both in the ANOPR and during the manufacturer site visits, and revised them as necessary to be the best approximation of real-world practices. In the process of verifying the OPS software, DOE found that, under similar input conditions and modeling parameters, the cost and performance estimates in the Department's database are consistent with real-world transformer designs. This was verified both by comparing designs during manufacturer interviews in May 2005 and through a tear-down analysis of six transformers. The Department purchased six 75 kVA three-phase, low-voltage, dry-type transformers, and had the units tested, disassembled, and analyzed. It then used the OPS software to model the physical designs and generate an electrical analysis report. The OPS software accurately predicted the actual performance of the six transformers. In addition, using the 2000-2004 average material prices, the Department calculated the manufacturer selling prices for each of these six units using the same method as it used for the engineering analysis. The Department found that the cost-efficiency relationship (slope) for these six units tracked the cost-efficiency relationship developed for the NOPR analysis. A description of this tear-down analysis and its results can be found in TSD Chapter 5, section 5.7.
In addition to consulting with manufacturers and conducting a tear-down analysis, the Department arranged for a third-party transformer design engineer to prepare transformer designs based on the same inputs as those used by OPS. The transformer design engineer looked at three of the representative units published in this NOPR, and prepared designs at a low-
first-cost, TP 1, and high-efficiency point. The Department then compared these designs to the OPS output for those same kVA ratings on an efficiency and manufacturer's selling price basis. It found that the transformer engineer's designs tracked the cost and efficiency improvements of the OPS designs. This work is discussed in Chapter 5 of the TSD.
The Department is confident of the accuracy of the OPS software, given the above-mentioned: (1) Comparison of engineering results with manufacturers during interviews; (2) tear-down analysis; (3) comparison of OPS designs with those of a third-party design engineer; and (4) discussions with manufacturers who use the OPS software and consulting services.
The Department received a few comments from stakeholders concerning the design lines and the representative units selected from those design lines. ACEEE commented that additional design lines may be necessary to better represent all transformers and better identify the lowest life-cycle cost points. ACEEE recommended looking at single-phase, liquid-immersed distribution transformers between 50 kVA and 500 kVA and three-phase units below 150 kVA. (ACEEE, No. 76 at p. 1 and Public Meeting Transcript, No. 56.12 at p. 27) In response to this comment, the Department reviewed its design lines and selection of representative units for the NOPR. Concerning an additional representative unit between 50 kVA and 500 kVA, the Department does not believe one is required. The 50 kVA (and 25 kVA pole-mounted) unit scales up to a maximum of 167 kVA—including the 75 kVA, 100 kVA, and 167 kVA rated units. The 500 kVA unit scales down to only two ratings, 250 kVA and 333 kVA. Use of the 0.75 scaling rule within these ranges is reasonable and accurate. Concerning an additional representative unit in the three-phase, liquid-immersed product class below 150 kVA, the Department also does not believe such an addition is necessary or would substantially improve the analysis. The 150 kVA unit is scaled down to 15 kVA, which is the maximum range over which the Department applies the 0.75 scaling rule in its analysis (one order of magnitude). The Department believes the 0.75 scaling rule is reasonable and accurate at this range. Additionally, creating an additional design line and analyzing a representative unit at kVA ratings below 150 kVA for three-phase, liquid-immersed transformers would not significantly improve the analysis. The shipments of three-phase, liquid-immersed transformers below 150 kVA represent just 1.6 percent of all three-phase, liquid-immersed units shipped, and a fraction of a percent of the liquid-immersed product classes. Therefore, the Department did not add any new representative units to the NOPR engineering analysis.
The Department received one comment concerning the treatment of medium-voltage, less-flammable, liquid-immersed transformers in the engineering analysis. Cooper Industries recommended that the Department consider combining these units as design option combinations in product classes 5 through 10 (the medium-voltage, dry-type product classes). Cooper Industries noted that less-flammable, liquid-immersed transformers are used in the same applications as dry-type transformers and are recognized for this application in the National Electrical Code. (Cooper, No. 62 at p. 2) As discussed in the ANOPR, the Department considers liquid-immersed and dry-type transformers as separate product classes. 69 FR 45385. It based this decision on input from several manufacturers during site visits in 2002, a review of industry standards—including those published by the Institute of Electrical and Electronics Engineers, Inc. (IEEE), the NEMA TP 1-2002 voluntary standard, and four comments received from stakeholders on the distribution transformer Framework Document. (Howard, No. 4 at p. 2; NEMA, No. 7 at p. 5; TXU Electric and Gas, No. 12 at p. 5; ACEEE, No. 14 at p. 2) All of these stakeholders advised the Department to treat liquid-immersed and dry-type distribution transformers separately when establishing standards.
Countering the separate treatment of liquid-immersed and dry-type transformers, Cooper asked that less-flammable, liquid-immersed units (a special type of liquid-immersed transformer) be evaluated for standards along with medium-voltage, dry-type units, because they can be used in the same applications. The Department appreciates this comment. However, energy efficiency standards are prescribed on the basis of differences in features that affect energy use. (42 U.S.C. 6295(q)) An example of these different features is the cooling mechanism for a transformer coil, whether it is air-cooled or liquid-cooled. Standards are therefore not classified or organized on the basis of whether they can service the same application. That said, customer applications are taken into consideration for the Department's economic analysis when a standard is developed and proposed (see the LCC analysis, TSD Chapter 8). Thus, due to the fact that the efficiency standard is applied on the basis of product class, not application, the Department did not incorporate less-flammable, liquid-immersed units into the medium-voltage dry-type analysis. The Department invites comment on this issue and on the recommendation from Cooper.
2. Engineering Analysis Inputs
One of the critical issues identified by many stakeholders commenting on the ANOPR analysis was whether DOE used prices that were representative of current material prices. Georgia Power commented that future transformer pricing may be affected by the decreasing number of suppliers of transformer materials—such as mineral oil and core steel—and that those still in business are already operating at full capacity. At present there are only two domestic suppliers of core steel: AK Steel and Allegheny Ludlum Steel Corporation (see TSD Appendix 3A). Georgia Power noted that higher-efficiency transformers will require more of these materials, which may result in material shortages. It is concerned that this situation could have a major impact on future transformer pricing and availability. (Georgia Power, No. 78 at pp. 1-2) HVOLT submitted a similar comment, and mentioned specifically that material prices have risen dramatically in step with higher energy prices. HVOLT noted that virtually all material suppliers now impose surcharges on top of their base material prices to yield the net selling price. HVOLT recommended the Department conduct a more detailed analysis of material prices. (HVOLT, No. 65 at pp. 2-3)
HVOLT and Edison Electric Institute (EEI) commented that material prices at the time of the ANOPR public meeting (September 2004) had increased relative to the material prices the Department used for its ANOPR analysis (2001 prices). (Public Meeting Transcript, No. 56.12 at p. 77; EEI, No. 63 at p. 3) The Southern Company commented that there have been substantial price increases in many of the materials used to build transformers, including copper and steel, and suggested that these increases make high-efficiency transformers less cost-effective. Southern recommended that recent raw material price increases and reasonable projections of future prices be included in the updated cost study produced for the NOPR. (Southern, No. 71 at p. 3) The National Rural Electric Cooperative Association (NRECA) commented that it supports and concurs with EEI's comments on the dramatic increase in
the prices of steel and copper in the last two years. (NRECA, No. 74 at p. 2) In line with these statements, ERMCO commented that the 2004 material prices presented at the ANOPR public meeting looked reasonable, although prices for mineral oil and wire (both aluminum and copper) had increased substantially in the last month. ERMCO recognized that material prices are volatile, and again emphasized the cost increase for mineral oil. (ERMCO, No. 58 at p. 2)
In response to these comments and concerns about the increases in material prices (many of which were also provided to the Department verbally during the 2005 manufacturer site visits), the Department conducted two material pricing scenarios for the NOPR, covering core steel, conductors, insulation, and other key material inputs (see TSD Chapter 5, section 5.4). One, the reference case scenario, uses a five-year average of prices for these materials for the years 2000 through 2004. This scenario averages some of the material price volatility in the market, including low and high material price points that occurred during that time period. The second scenario is a “current” material price analysis, using material prices from the first quarter of 2005. This scenario provides a snapshot in time of material prices that were of concern to the stakeholders who submitted comments to the Department. When establishing a standard that will apply to all distribution transformers manufactured after a date several years in the future (here, January 1, 2010), the Department believes a material price that incorporates average pricing over a time period is a better basis for establishing the standard than using the material prices that manufacturers typically pay in any one year. Thus, DOE used the reference case (five-year average of material prices) as the basis for the standards proposed today. The engineering analysis results based on the material price reference case can be found in TSD Chapter 5. The Department also calculated engineering analysis and LCC analysis results based on the current (first quarter 2005) material price scenario; these are provided in TSD Appendix 5C.
In addition, the Department worked to gain a better understanding of the electrical core steel market, which is the main cost driver behind the construction of distribution transformers. It conducted interviews with both domestic core steel providers, two national steel wholesalers, and two manufacturers of equipment that processes core steel. The Department also reviewed publicly available information on the steel market in general, including trends, pressures, and constraints, such as input substitution opportunities and the supply-demand effects of Chinese economic growth. The findings of the Department's study of the electrical core steel market can be found in TSD Appendix 3A. The Department used the information from this research to improve its understanding of the core steel market and to verify the comments received from stakeholders concerning the recent trend toward increases in material prices, specifically electrical core steel.
During the ANOPR public meeting, ERMCO recommended that the Department consider the impacts of tariffs on the availability (and cost) of speciality steels. (Public Meeting Transcript, No. 56.12 at pp. 243-244) The Department did consider the import duty on raw (un-worked) Japanese core steel, specifically mechanically scribed, deep-domain refined, core steel (ZDMH). For discussion on the treatment of ZDMH core steel in this analysis, see TSD Chapter 5.
The Department also received a comment on the labor inputs used in the engineering analysis. FPT commented that the labor calculations in the ANOPR analysis for cutting and stacking core steel were incorrect. It stated that the labor rates should not be based on hours/inch, because of the different thicknesses of core steel. Stacking thinner laminations of steels takes longer because more pieces of material must be handled for each inch of core stack. (FPT, No. 64 at pp. 1-2) The Department agrees with this comment and modified the methods used in the engineering analysis for calculating the labor costs. The revised method and stacking rates DOE used for the various grades of steel are described in TSD Chapter 5.
3. Engineering Analysis Outputs
DOE received two comments on the energy losses associated with auxiliary devices. During the ANOPR workshop, Ameren commented that the Department should include the impact of losses from accessories in its calculation and determination of national energy savings. (Public Meeting Transcript, No. 56.12 at p. 254) ERMCO also commented on this subject, requesting that an allowance be made for protective devices for transformers (e.g., circuit breakers), which are sometimes specified by utility companies. In its comment, ERMCO suggested two possible approaches: (1) Have a separate table of efficiency ratings for transformers with protective devices, or (2) do not include any losses due to protective devices in the measurement of efficiency of the transformer. (ERMCO, No. 58 at p. 1) The Department notes that the measurement and representation of the efficiency of regulated transformers is prescribed in the test procedures for distribution transformers. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972. As published, the test procedure directs manufacturers to provide an efficiency representation for a regulated unit that does not include losses from protective devices. The efficiency standard proposed today only governs the performance of the basic transformer; it would not apply to the protective devices and would not seek to regulate the efficiency of these devices. The test procedure directs manufacturers to either calculate and deduct losses from these protective devices, or to by-pass the protective devices in the load-loss test set-up configuration.
HVOLT, NEMA, and ODOE commented on manufacturer selling prices. HVOLT commented during the ANOPR workshop that the actual selling prices of liquid-immersed units are lower than was reported in DOE's analysis. (Public Meeting Transcript, No. 56.12 at p. 78) HVOLT also later stated that the price for a low-first-cost 25 kVA single-phase, pole-mount transformer was on the order of $400, while the Department's analysis reported $800. (Public Meeting Transcript, No. 56.12 at p. 96) NEMA recommended that the Department contact individual manufacturers and discuss the pricing of their lowest-first-cost transformers to calibrate the engineering analysis. (NEMA, No. 48 at p. 2 and Public Meeting Transcript, No. 56.12 at p. 35) ODOE echoed the comment from NEMA, recommending that the Department check the pricing of transformers sold by manufacturers. (ODOE, No. 66 at p. 3) Following NEMA's and ODOE's recommendations, the Department spoke to individual manufacturers (both NEMA members and non-NEMA members) about material pricing, manufacturers' selling prices, OPS software inputs, and other equipment costs (
e.g.
, tanks, bushings, busbar). The adjustments DOE made following these conversations resulted in a reduction in manufacturer selling prices for some design lines. For example, the low-first-cost design for the 25kVA single-phase, pole-mount transformer went from approximately $800 per unit to around $500 per unit using the five-year, average-material-price scenario.
DOE received two comments about the feasibility of manufacturing the most
efficient designs produced in the engineering analysis. Cooper conducted a design analysis of the 50 kVA pad-mount, the 150 kVA three-phase, and the 1500 kVA three-phase, liquid-immersed units. It found that it was not possible to meet the ANOPR candidate standard level 5 (CSL5) efficiency level. Furthermore, it found that, as the design reaches ANOPR CSL3, the cost to produce the transformer generally increases exponentially. Because of this, Cooper believes that the OPS software does not account for realistic material performance characteristics or realize the cost or productivity impact of these design changes with regard to the manufacturing of a product. (Cooper, No. 62 at p. 1) NRECA also questioned the validity of the highest efficiency levels (ANOPR CSL4 and CSL5). It recommended that the Department verify whether transformers with these efficiencies actually exist or are merely theoretical designs on paper. (NRECA, No. 74 at p. 2)
As discussed in section IV.B.1, the Department took several steps to verify the OPS software and the predictive capability of the software to design transformers. The Department is confident in the accuracy of the OPS software, given the: (1) Comparison of engineering results with manufacturers during interviews; (2) tear-down analysis; (3) comparison of OPS designs with those of a third-party design engineer; and (4) discussions with manufacturers who use the OPS software and consulting services. In response to Cooper's and NRECA's comments on the maximum technologically feasible designs, the Department notes that the design option combinations that achieved the highest efficiencies in a given representative unit used non-traditional materials, such as amorphous material and laser-scribed, high-permeability, grain-oriented electrical steel. The core destruction factors, packing factors, and other real-world adjustments for production floor manufacturing are inputs that OPS has refined over decades in consultation with its clients, some of which have manufactured amorphous material and laser-scribed steel. If the core material, winding, and construction are all built to the design report specification, these are feasible designs. Details of the engineering analysis can be found in TSD Chapter 5 and Appendices 5A, 5B, and 5C.
C. Life-Cycle Cost and Payback Period Analysis
This section describes the LCC and payback period (PBP) analysis and the spreadsheet model DOE used for analyzing the economic impacts on customers. Details of the spreadsheet model, and of all the inputs to the LCC and PBP analysis, are in TSD Chapter 8. The Department conducted the LCC and PBP analysis using a spreadsheet model developed in Microsoft (MS) Excel for Windows 95 or above. When combined with Crystal Ball (a commercially available software program), the LCC and PBP model generates a Monte Carlo simulation to perform the analysis by incorporating uncertainty and variability considerations. While the Department included an annual maintenance cost as part of the LCC and PBP calculation, it assumed that maintenance and repair costs are independent of transformer efficiency.
The LCC is the total customer cost over the life of the equipment, including purchase expense and operating costs (including energy expenditures and maintenance). To compute the LCC, the Department summed the installed price of a transformer and the discounted annual future operating costs over the lifetime of the equipment. The PBP is the change in purchase expense due to an increased efficiency standard divided by the change in first-year operating cost that results from the standard. The Department expresses PBP in years. The data inputs to the PBP 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 transformer purchase expense were the equipment price and the installation cost, with appropriate markups. The inputs to the operating costs were the annual energy consumption and the electricity price. The PBP calculation uses the same inputs as the LCC analysis but, since it is a simple payback, the operating cost is for the year the standard takes effect, assumed to be 2010.
For each efficiency level analyzed, the LCC analysis required input data for the total installed cost of the equipment, the operating cost, and the discount rate. Table IV.2 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 trends, and maintenance costs affect the operating cost. The effective date of the standard, the discount rate, and the lifetime of equipment affect the calculation of the present value of annual operating cost savings from a proposed standard. Table IV.2 shows how the Department modified these inputs and key assumptions for the NOPR, relative to the ANOPR.
Table IV.2.—Summary of Inputs and Key Assumptions Used in the LCC and PBP Analyses
Inputs
ANOPR description
Changes for NOPR
Equipment price
Derived by multiplying manufacturer selling price (from the engineering analysis) by distributor markup and contractor markup plus sales tax for dry-type transformers. For liquid-immersed transformers, DOE used manufacturer selling price plus sales tax. Shipping costs were included for both types of transformers
Reduced distributor markup for dry-type added small distributor markup for liquid-immersed.
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
Added a pole replacement component to design line 2.
Baseline and standard design selection
The selection of baseline and standard-compliant transformers depended on customer behavior. For liquid-immersed transformers, the fraction of purchases evaluated was 50%, while for dry-type transformers, the fraction of evaluated purchases was 10%. The average A value for evaluators was $5/watt, while the B value depended on expected transformer load
Increased liquid-immersed transformer evaluation percentage to 75%. Divided dry-types into (1) small-capacity medium-voltage and (2) large-capacity medium-voltage, with evaluation percentages of 50% and 80%, respectively.
Affecting Operating Costs
Transformer loading
Loading depended on customer and transformer characteristics. The average initial liquid-immersed transformer loading was 30% for 25 dry-type kVA and 59% for 1500 kVA transformers. The average initial dry-type transformer loading was 32% for 25 kVA and 37% for 2000 kVA transformers. The shipment-weighted lifetime average loading was 33.6% for low-voltage, dry and 36.5% for medium-voltage, dry. With load growth, average installed liquid-immersed transformer loading was 35% for 25 kVA and 70% for 1500 kVA transformers with a shipment-weighted lifetime average loading of 52.9%
Increased average peak loading for medium-voltage, dry-type transformers from 75% to 85%.
Load growth
1% per year for liquid-immersed and 0% per year for dry-type transformers
No change.
Power factor
Assumed to be unity
No change.
Annual energy use and demand
Derived from a statistical hourly use and demand load simulation for 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 varied as the square of the load and were equal to rated load losses at 100% loading
No change.
Electricity costs
Derived from tariff-based and hourly based electricity prices. Capacity costs provided extra value for reducing losses at peak. Average marginal tariff-based retail electricity price: 6.4¢/kWh for no-load losses and 7.4¢/kWh for load losses. Average marginal wholesale utility hourly based costs: 3.8¢/kWh for no-load losses and 4.5¢/kWh for load losses
Updated tariff-based electricity prices with 2004 tariff data. Adjusted hourly based electricity prices for inflation.
Electricity price trend
Obtained from
Annual Energy Outlook 2003
(
AEO2003
)
Updated to
AEO2005
.†
Maintenance cost
Annual maintenance cost did not vary cost as a function of efficiency
No change.
Affecting Present Value of Annual Operating Cost Savings
Effective date
Assumed to be 2007
Assumed to be 2010.
Discount rates
Mean real discount rates ranged from 4.2% for owners of pole-mounted, liquid-immersed transformers to 6.6% for dry-type transformer owners
No change.
Lifetime
Distribution of lifetimes, with mean lifetime for both liquid and dry-type transformers assumed to be 32 years
No change.
Candidate Standard Levels
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
Six efficiency levels with the minimum equal to TP 1 and the maximum from the most efficient designs from the engineering analysis. Intermediate efficiency levels for each design line selected using a redefined set of LCC criteria (see section III.D.1.b).
* The concept of using A and B loss evaluation combinations is discussed in TSD chapter 3, Total Owning Cost Evaluation. 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 is aware of
AEO2006,
and the electricity price forecast does not differ significantly from
AEO2005.
The following sections contain brief discussions of the methods underlying each of these inputs and key assumptions in the LCC analysis. Where appropriate, the Department also summarizes stakeholder comments on these inputs and key assumptions and explains how it took these comments into consideration.
1. Inputs Affecting Installed Cost
a. Equipment Price
The equipment price of a transformer reflects the application of supply-chain markups, and the addition of sales tax and shipping costs, to the manufacturer's selling price. The markup is the percentage increase in price as the transformer passes through the distribution channel. Commercial and industrial customers most often purchase dry-type transformers from electrical contractors who purchase the transformers through distributors, whereas many liquid-immersed transformers are purchased by utilities directly from manufacturers and installed directly by utility staff. Therefore, DOE's markups for liquid-immersed transformers are smaller than those for dry-type transformers. In addition to the supply-chain markups, DOE's equipment prices include shipping costs and sales tax for both types of transformers. The Department did not have sufficient data to diversify the distribution channels and markups beyond these two general categories. Details of the installed cost inputs can be found in TSD Chapter 7.
In the ANOPR analysis, the Department assumed that all liquid-immersed transformers were purchased directly from manufacturers by utilities. NEMA commented that distribution channels are more complex than DOE assumed in the ANOPR analysis. It noted that some liquid-immersed units may go through distributors and some dry-type units may be sold directly from the manufacturer. NEMA also indicated that small transformers are more likely to go through distributors and large transformers are more likely to be sold
directly. (NEMA, No. 48 at p. 2) NRECA commented that most, if not all, cooperative utilities purchase liquid-immersed transformers through distributors. (Public Meeting Transcript, No. 56.12 at p. 120) In response to NEMA's comment, the Department discussed distribution channels and markup practices with utility technical staff to obtain additional input for the NOPR analysis. Based on this input, the Department adjusted the distributor markup to 7 percent for liquid-immersed transformers and 15 percent for dry-type transformers. These distributor markup values compare with 0 percent and 35 percent, respectively, for the liquid-immersed and dry-type distributor markups for the more simplified distribution channels that the Department assumed for the ANOPR analysis.
b. Installation Costs
Higher-efficiency distribution transformers tend to be larger and heavier than less efficient designs. The Department therefore included the increased cost of installing larger, heavier transformers as a component of the first cost of efficient transformers. In the ANOPR, the Department presented the installation cost model and solicited comment from stakeholders. For details of the installation cost calculations, see TSD section 7.3.1.
EEI provided substantial comments regarding the installation cost implications of more-efficient transformers that are physically larger and heavier than less-efficient transformers. It asserted that transformer size and weight may require physical modification to pole structure or mounting pads, and that, in severe replacement applications, increased transformer size may require building and structural modifications. (EEI, No. 63 at pp. 4-5) NRECA expressed similar concerns that the size and weight of more energy-efficient transformers may dramatically affect installation cost. (NRECA, No. 74 at p. 2) Tampa Electric Company (TEC) commented that transformer efficiency standards must take into account physical dimension constraints to ensure compatibility with older units that will need to be replaced. (TEC, No. 77 at p. 1) Georgia Power Company commented that, as a result of the expected increase in physical size and weight of higher efficiency transformers, installation costs will be increased in several ways. First, it estimates that pole replacements will be required for 80 percent of the transformer replacement installations that have joint use applications (
e.g.
, telephone line, cable television) on the pole. Second, in addition to the pole replacements at existing locations, Georgia Power projects that numerous larger diameter and taller poles will be required at new transformer installations. Third, it asserts that an increase in the size and weight of pole-mounted and pad-mounted transformers will significantly increase utility costs, and that this impact will be proportional to the percent increase in transformer size and weight resulting from the higher efficiency requirements. (Georgia Power, No. 78 at pp. 2-3) Ameren also commented that it believes the Department should consider the economic impact of transformer weight increases, such as the necessity for using stronger poles, resulting from efficiency improvements. (Public Meeting Transcript, No. 56.12 at pp. 253-254)
Howard commented that higher efficiency transformers will be larger, resulting in increased shipping costs as well as handling problems for the installers. (Howard, No. 70 at p. 3) Comments from EEI included information from utility members of EEI, the American Public Power Association (APPA), and NRECA, who reported that in many cases increased transformer size and weight can affect the cost of new pole-mounted transformer installations; costs vary from utility to utility and depend on the size and weight increase. (EEI, No. 63 at pp. 20-62) Southern Company asserted that increases in installation costs from the weight increases of more-efficient transformers are not adequately covered in the ANOPR analysis. (Southern, No. 71 at p. 2) National Grid (NGrid) commented that high-efficiency transformers present utilities with logistical and financial challenges, but they have found that the benefits outweigh the costs when analyzed using a life-cycle cost analysis method employed in the industry. (NGrid, No. 80 at p. 1)
While the Department's ANOPR included weight- and size-dependent installation costs associated with the increased shipping, handling, labor, and equipment costs of installing larger and heavier transformers, the ANOPR did not include the costs of stronger poles or pole replacement. In response to stakeholder comments on pole-replacement costs, for the NOPR analysis the Department added a pole-replacement-cost function to the installation cost equation for design line 2, which covers pole-mounted transformers. This analysis assumed that a pole change-out cost of $2,000 occurs for up to 25 percent of pole-mounted transformers when the weight of the transformer exceeds 1,000 pounds. Because not all transformer installations require a change-out of existing equipment even in the most extreme case, the Department assumed a maximum change-out fraction. The Department selected 25 percent as the maximum change-out fraction estimate based on stakeholder input. (EEI No. 63 at p. 25)
c. Baseline and Standard Design Selection
A major factor in estimating the economic impact of a proposed standard is the selection of transformer designs in the base case and standards case scenarios. A key issue in the selection process is the degree to which transformer purchasers take into consideration the cost of transformer losses (A and B factors) when choosing a transformer—both before and after the implementation of a standard. The purchase-decision model in the LCC spreadsheet selects which of the hundreds of designs in the engineering database are likely to be selected by transformer purchasers. The LCC transformer selection process is discussed in detail in TSD Chapter 8, section 8.2.
The Department received three types of comments on the design selection and purchase behavior modeled in the LCC spreadsheets: (1) Applicability of values used, (2) actual values that stakeholders have observed in the market, and (3) percent of customers who use the evaluation formulae. Concerning the applicability of values used, NRECA questioned whether the B factors relative to the A factors used in the LCC spreadsheet accurately represent the A and B factors for rural cooperatives. (NRECA, No. 74 at pp. 2-3) Ameren asserted that the A and B values used by the Department for the ANOPR analysis were not representative of Midwestern electric utilities. (Public Meeting Transcript, No. 56.12 at p. 113) NEMA said that both manufacturers and utilities indicated at the public meeting that the A and B values assumed by the Department to characterize the base case were higher than those in current use, leading to a DOE base case that may reflect higher transformer efficiencies than marketplace reality. (NEMA, No. 60 at p. 2) ODOE also commented that the method the Department used to characterize the base case may result in higher average efficiencies than are actually found in the current market. ODOE believes that the value of losses is seldom a significant factor in purchase decisions for transformers. (ODOE, No. 66 at p. 5)
Regarding the actual values observed in the market, HVOLT commented that, for the 80 percent of electric utilities that currently evaluate losses when purchasing a liquid-immersed transformer, the A factor is between $2.00 and $2.50 and the B factor is approximately $0.75. HVOLT noted that these evaluation formulae are higher than the A factor ($1.57) and B factor ($0.57) used to develop the TP 1 standard. (Public Meeting Transcript, No. 56.12 at p. 107) AK Steel Corporation observed that some transformer customers evaluate with an A value of between $1.50 and $2.00. (Public Meeting Transcript, No. 56.12 at p. 109)
Relating to the percent of customers who use the evaluation formulae, BBF & Associates (BBF&A) said its market study in the early 1990s indicated that 90 percent or more of transformers were evaluated using A and B factors in the traditional approach. It pointed out that a subsequent survey in 2001-2002 showed that less than 50 percent were evaluated. (Public Meeting Transcript, No. 56.12 at p. 110) In the context of a discussion on liquid-immersed transformers, HVOLT said that around 80 percent of the market evaluates losses today. (Public Meeting Transcript, No. 56.12 at p. 107) For dry-type transformers, HVOLT suggested that there is probably less purchase evaluation than the Department assumed in the analysis, but that an estimate of 10 percent evaluators is probably accurate. (Public Meeting Transcript, No. 56.12 at p. 156) ACEEE stated that the efficiency of liquid-immersed transformers is dropping as utilities move away from evaluation of purchase decisions, due to regulatory uncertainty caused by restructuring of the electric utility industry. (ACEEE, No. 76 at pp. 1-2) Similarly, the Copper Development Association (CDA) observed that at the ANOPR public meeting, stakeholders commented that 62 percent of the smaller-kVA distribution transformers sold in 2002 were lowest-cost versions and several utility personnel indicated that A and B evaluation values were zero. CDA commented that it believes these statements illustrate that many transformers currently being purchased are lowest-first-cost, low-efficiency units. (CDA, No. 69 at p. 4)
The Department responded to these stakeholder comments regarding A and B values and the percent evaluators by using new data provided by stakeholders, and newly collected data from the Internet, to adjust the distributions and parameters it used to model purchase decisions (see TSD Chapter 8, section 8.3.1). It used data provided by NRECA and data collected from the Internet to revise its estimate of the mean A value to $3.85/watt compared to the value of $5/watt used in the ANOPR analysis. This addresses the stakeholder concerns that the A values used in the ANOPR analysis may have been high. With regard to the actual values, the Department characterized transformer loss evaluation with a distribution of A values that includes the lower range of values—$1.50/watt to $2.50/watt—mentioned by AK Steel. However, the data collected by the Department were inconsistent with HVOLT's assertion that 80 percent of electric utilities use an A factor between $2.00 and $2.50.
With respect to the percentage of evaluators, the Department obtained new data from NEMA regarding the percentage of transformers sold that are consistent with the voluntary TP 1 standard. The Department therefore adjusted the percentage of evaluators in its customer choice model to be consistent with the new data provided by NEMA. The Department believes that this method provides the most precise and detailed estimate of the percentage of evaluators that is consistent with actual market data.
The Department received several comments noting that shipments of TP 1-compliant transformers have recently increased, and noting the potential impact of States adopting TP 1 as their transformer standard. NEMA stated that its members' shipments of TP 1-compliant transformers increased in 2002 and 2003 compared to 2001 for all transformers considered in the scope of this rulemaking. (NEMA, No. 48 at p. 3) An EEI survey of nine of its members showed that an average of approximately 65 percent of liquid-immersed transformers purchased are already compliant with NEMA TP 1. (EEI, No. 63 at pp. 7-19) NGrid now purchases energy-efficient, liquid-immersed transformers that meet or exceed NEMA's TP 1 standard throughout its service territory in Massachusetts, Rhode Island, New Hampshire, and New York. This is true despite the fact that only Massachusetts requires TP 1-compliant, liquid-immersed transformers. (NGrid, No. 80 at p. 1) Georgia Power expressed doubt that the Department can accurately account for the number of transformers that are already purchased with NEMA TP 1 efficiencies. (Georgia Power, No. 78 at pp. 1-2)
The Appliance Standards Awareness Project (ASAP) and Northwest Power and Conservation Council (NPCC) commented that the base case should reflect the impact of State-established transformer standards. (Public Meeting Transcript, No. 56.12 at p. 248, Public Meeting Transcript, No. 56.12 at pp. 180-181) ODOE commented that the Department needs to pay careful attention to those States that have TP 1 as an existing standard because, by the time the DOE standard is published, States mandating TP 1 could represent a quarter to a third of transformer shipments. (Public Meeting Transcript, No. 56.12 at p. 185) NEMA said that, of those States that have adopted TP 1, most have done it for low-voltage, dry-type distribution transformers, so the other product classes would not be affected. (Public Meeting Transcript, No. 56.12 at p. 182)
In response to these comments, the Department obtained from NEMA new, detailed data regarding TP 1 compliance of shipped transformers. The Department adjusted the parameters of the customer choice model such that the base case TP 1 compliance in the LCC is consistent with the most recent NEMA data available to the Department.
Southern Company and ODOE requested that the Department provide the efficiency rating for the base case. (Public Meeting Transcript, No. 56.12 at p. 215 and p. 217) ACEEE agreed, noting that this information would enable further independent analysis of the cost and savings data. (ACEEE, No. 50 at p. 2 and No. 76 at p. 3) The Department complied with this request and reported the base case efficiencies for the ANOPR analysis in Supplemental Appendix 8E of the ANOPR TSD. These values have been updated for the NOPR analysis, and can be found in Appendix 8E of the TSD.
2. Inputs Affecting Operating Costs
a. Transformer Loading
Transformer loading is an important factor in 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 increase exponentially with loading, there is a particular concern that, during times of peak system load, load losses can impact system capacity costs and reliability. Details of the transformer loading models are presented in TSD Chapter 6.
For the ANOPR analysis, the Department estimated the loading characteristics of transformers by
analyzing the statistics of available load data, and by assuming a distribution of initial annual peak loadings. ASE commented that the Department's analysis of load profiles is largely consistent with data provided by other stakeholders. It also recognized that the Department used publicly available data for utility loads, and commented that the average loadings for liquid-immersed transformers were reasonable. (ASE, No. 52 at p. 3 and No. 75 at p. 3) ODOE agreed with the transformer loads estimated by the Department based on ODOE's examination of loading studies conducted in the Pacific Northwest, which produced lower loading levels than expected by many analysts. (ODOE, No. 66 at p. 4)
HVOLT estimated that the average loading for dry-type, medium-voltage units is about 50 percent, with a daytime average of 60 percent and a nighttime average of 35 percent. (Public Meeting Transcript, No. 56.12 at pp. 131-132) HVOLT estimated that loading for liquid-immersed transformers is about 50 percent, but noted that loads in the residential sector can increase so much that loading can exceed the transformer nameplate rating. (Public Meeting Transcript, No. 56.12 at p. 131 and p. 133) In a written comment, HVOLT endorsed using loading assumptions identical to those for NEMA TP 1. HVOLT is not familiar with any publicly released loading studies that would alter the root mean square (RMS)-equivalent load of 50 percent load for medium-voltage transformers. (HVOLT, No. 65 at p. 3) EEI estimated that, according to three surveyed members, average loading levels range from 30 percent to 58 percent. A survey of eight members yielded a range of high-loading levels from 45 to 100 percent, and a range of low-loading levels from 35 to 75 percent. (EEI, No. 63 at pp. 7-19) TEC said that it strives to load transformers higher than the 50 percent level assumed by DOE, and recommended that the Department give consideration to efficiency ratings at higher loading levels. (TEC, No. 77 at p. 1)
The Department concluded that the ANOPR statistical loading analysis was largely consistent with stakeholder comments, with slight adjustments necessary for the loading levels of medium-voltage, dry-type transformers (see TSD Chapter 6, section 6.3.3.3). The Department increased the loading on medium-voltage, dry-type transformers in response to the comments by HVOLT, to be consistent with the relative difference in loading levels used by NEMA TP 1 between low-voltage and medium-voltage dry-type transformers.
On the issue of peak load coincidence, the Department received two comments. ASE agreed with the Department's peak load coincidence analysis for the ANOPR. (ASE, No. 52 at p. 3 and No. 75 at p. 3) The CDA commented that peak coil losses may have a high coincidence factor with system peaks. (CDA, No. 51 at pp. 3-4) The Department concluded that the statistical model used for peak loading in the ANOPR analysis was consistent with stakeholder comments and did not change peak loading statistics for the NOPR analysis.
b. Load Growth
The LCC takes into account the projected operating costs for distribution transformers many years into the future. This projection requires an estimate of how, if at all, the electrical load on transformers will change over time. For dry-type transformers, the Department assumed no load growth. For liquid-immersed transformers, the Department used as the default scenario a one-percent-per-year load growth. It applied the load growth factor to each transformer beginning in 2010, the expected effective date of the standard. To explore the LCC sensitivity to variations in load growth, the Department included in the model the ability to examine scenarios with zero-percent, one-percent, and two-percent load growth. Load growth is discussed in detail in TSD Chapter 8, section 8.3.6.
The Department received a range of comments on its load growth projections. CDA commented that loading on all transformers increases with time. It stated that, for liquid-immersed transformers, residential consumption per household has increased; for dry-types, commercial and industrial loads grow over time through more energy-intensive use of floor space and plant expansion. (CDA, No. 51 at pp. 1-2) ODOE stated that DOE should select a growth rate of zero, with sensitivity analysis at one-percent growth. (ODOE, No. 66 at p. 6) NEMA agreed with the Department's load growth estimates of zero percent for dry-type and one percent for liquid-immersed transformers. However, to the extent that building owners may defer transformer upgrades because of high unit costs, it noted that there may be some load growth on older, less efficient units. (NEMA, No. 48 at p. 2)
HVOLT commented that, in commercial and industrial complexes, new transformers are added to handle additional loads when there is an expansion, and there is not much information to suggest a substantial load growth on those transformers. (Public Meeting Transcript, No. 56.12 at p. 40) HVOLT also stated that one-percent load growth for liquid-immersed transformers seems too high. (Public Meeting Transcript, No. 56.12 at p. 138) HVOLT also said that there is not much load growth in residential applications, since transformers are installed in a community with a cluster of homes, they come online quickly, and after that, there are few factors producing load growth for the rest of the transformer's life. (Public Meeting Transcript, No. 56.12 at p. 39)
The Department retained its estimate of zero-percent load growth for dry-type transformers and one-percent load growth for liquid-immersed transformers. While some stakeholders disagreed with the Department's estimate of load growth for liquid-immersed transformers, data showing both growth in per-customer electrical loads over time and increasing transformer sizes purchased by utilities support the Department's approach (see TSD Chapter 8).
Regarding another aspect of the issue of load growth over time, EEI stated its concern that, because of load growth, higher efficiency transformers optimized to the loading point prescribed by the test procedure may have higher coil losses after being in service for several years. That is, EEI is concerned that the “balance point” between higher coil losses and lower core losses may not be reached until late in the operating life of a transformer. (EEI, No. 63 at pp. 3-4) Both the ANOPR and NOPR load analyses were responsive to this comment. The Department's estimate of losses tracked losses based on estimates of actual loads rather than test procedure loads. Both near-term and long-term losses were included in LCC estimates, with a weighting determined by the customer discount rate (see TSD Chapter 8).
c. Power Factor
The power factor is real power divided by apparent power. Real power is the time average of the instantaneous product of voltage and current. Apparent power is the product of the RMS voltage and the RMS current. For the ANOPR, the Department used a power factor of 1.0. A detailed discussion of the power factor can be found in TSD Chapter 8, section 8.3.12.
The Department received two comments on power factor. Southern Company commented that the power factor should be less than 1.0. (Public Meeting Transcript, No. 56.12 at p. 164) NEMA, on the other hand, stated that a
power factor assumption of 1.0 is appropriate. (NEMA, No. 60 at p. 2)
While the Department agrees with Southern Company that actual power factors are less than 1.0, they are very close to 1.0, and the Department agrees with NEMA that use of a power factor of 1.0 is appropriate for the analysis of the efficiency standard. Using a power factor less than 1.0 would slightly increase the estimated losses for transformers, but would complicate the Department's analysis and affect all components of the Department's analysis where losses are estimated. The Department determined that the disadvantages of complicating the analysis by using an estimated distribution of slightly lower power factors outweighed the slight increase in analytical accuracy that could result.
d. Electricity Costs
The Department needed estimates of electricity prices and costs to place a value on transformer losses for the LCC calculation. As noted earlier, the Department created two sets of electricity prices to estimate annual energy expenses for its ANOPR: An hourly based estimate of wholesale electricity costs for the liquid-immersed transformer market, and a tariff-based estimate for the dry-type transformer market (see TSD Chapter 8).
Southern Company questioned whether wholesale electricity prices are the correct prices for liquid-immersed transformers, and suggested that the Department consider the availability of very inexpensive electricity generating capacity in some regions. (Public Meeting Transcript, No. 56.12 at p. 125 and pp. 237-238) The Department's analysis for both the ANOPR and the NOPR estimated the marginal, or incremental, wholesale cost of electricity. The Department agrees with Southern Company that inexpensive electricity generating capacity exists in many regions of the country. The Department modeled a national distribution of generation capacity costs by estimating the marginal capacity cost of new generation as a function of the type of plant serving the capacity and the utility cost of capital which the Department obtained from a representative national sample of utilities (see TSD Chapter 8).
e. Electricity Price Trends
For the relative change in electricity prices in future years, DOE relied on price forecasts from the EIA's
Annual Energy Outlook (AEO)
. For its ANOPR, the Department used price forecasts from the
AEO2003
, the most recent price forecasts available at the time. The application of electricity price trends in the NOPR analysis is discussed in detail in TSD Chapter 8, section 8.3.7.
ODOE and HVOLT commented that the price forecasts used by the Department were too low. (ODOE, No. 66 at p. 4; Public Meeting Transcript, No. 56.12 at p. 38) Some stakeholders stated that more volatility should be added to the forecasts. The Natural Resources Defense Council (NRDC) commented that DOE should consider a scenario where electricity prices increase unexpectedly. (Public Meeting Transcript, No. 56.12 at p. 45) The NPCC stated that the Department assumed a monotonic wholesale electricity market and should model forecasted prices with some volatility. (Public Meeting Transcript, No. 56.12 at p. 124) ODOE and ACEEE suggested that the price trends should be updated with the most recent
AEO
forecasts; ACEEE added that DOE should include a high electricity price scenario in the analysis. (ODOE, No. 66 at p. 4; ACEEE, No. 76 at p. 3) Counter to the above stakeholders, CDA and AK Steel thought the Department's price forecasts were reasonable. CDA commented that the Department was correct to assume a moderate rate of energy cost increases, although it also believes a higher rate could be justified given recent experience. (CDA, No. 51 at p. 3) AK Steel added that EIA's long-term electricity price forecasts are good. (Public Meeting Transcript, No. 56.12 at p. 128)
For the NOPR, the Department updated its price forecasts with trends from the
AEO2005
as recommended by stakeholders, and addressed other stakeholder concerns through use of sensitivity analysis. The Department believes that price forecasts from the
AEO
are the most reliable and credible estimates of future electricity prices. As compared to
AEO2003
, the price trends from
AEO2005
actually show slightly lower forecasted prices. During the writing of this notice, the EIA published
AEO2006
, but since the electricity price forecast did not differ significantly from
AEO2005
, the Department did not update its analysis results using
AEO2006
. The Department addresses stakeholder concerns regarding the possibility of higher electricity prices through the sensitivity section of the LCC analysis (see TSD Chapter 8). This analysis estimates LCC results under conditions where electricity prices are 15 percent higher than the Department's medium scenario. However, as in the ANOPR analysis, the Department retained the medium
AEO
forecast as the electricity price trend that is most credible and authoritative with respect to the analysis of the future economic impacts of efficiency standards.
3. Inputs Affecting Present Value of Annual Operating Cost Savings
a. Standards Implementation Date
The Department proposes that the new energy-efficiency standard for distribution transformers apply to all units manufactured three years or more after publication of the final rule. For the NOPR analysis, the Department assumed a 2007 final rule publication; hence a 2010 implementation or compliance date. The Department calculated the LCC for customers as if each new distribution transformer purchase occurs in the year manufacturers must comply with the standard.
Several comments called for acceleration of the rulemaking schedule. ACEEE said the NOPR should be published by July 2005 and the final rule six months later. (ACEEE, No. 76 at p. 4) The National Association of Regulatory Utility Commissioners (NARUC) urged DOE to establish a new standard for distribution transformers as soon as possible. (NARUC, No. 68 at pp. 2-5) NRDC asked DOE to make a commitment to a schedule, with appropriate milestones, that will allow a final rule to be issued no later than January 29, 2006. (NRDC, No. 61 at p. 3) ASE urged the Department to maintain an 18-month schedule to complete the rulemaking. (ASE, No. 52 at p. 1 and No. 75 at p. 1)
The Department understands that the rulemaking schedule impacts the date by which manufacturers of distribution transformers must comply with any new energy-efficiency standard. It is committed to completing the rulemaking in a timely fashion and expects to publish a final rule by September 2007.
b. Discount Rate
The discount rate is the rate at which future expenditures are discounted to estimate their present value. It is the factor that determines the relative weight of first costs and operating costs in the LCC calculation. Consumers experience discount rates in their day-to-day lives either as interest rates on loans or as rates of return on investments. Another characterization of the discount rate is the “time value of money.” The value of a dollar today is one plus the discount rate times the value of a dollar a year from now. The Department estimated consumer discount rates by calculating the consumer cost of capital (see TSD Chapter 8).
Discount rates depend on who is borrowing and at what scale. Thus, the discount rates in the LCC analysis are different than those in the national impact analysis. This section discusses consumer discount rates that the Department used in the LCC analysis.
With respect to consumer discount rates in the ANOPR, stakeholders expressed a diversity of views regarding which discount rates are appropriate for the LCC analysis. ASE and ODOE commented that the Department should use a three-percent real discount rate, similar to the discount rate used by the California Energy Commission (CEC) in recent State-level energy efficiency analyses. (ASE, No. 75 at p. 3; ODOE, No. 66 at p. 5) NRDC said that the Department's use of discount rates exceeding 5.5 percent real conflicts with the explicit instructions in
NRDC
v.
Herrington
, because of the court's instruction to consider payback times of less than nine years as economically justified. (NRDC, No. 61 at p. 6) ACEEE commented that the Department's choice of discount rates for utilities was appropriate. (ACEEE, No. 76 at p. 3) HVOLT recommended that the Department set efficiency standards on a three-to five-year consumer investment return, to represent commercial customer preferences. (HVOLT, No. 65 at p. 3)
The Department examined each of these comments to see if any would lead to a more accurate description of consumer economic impacts. In examining the three-percent discount rate recommended by ASE and ODOE, the Department found that the CEC, in its rulemaking, estimated the consumer cost of capital using a method similar to that of the Department. However, the CEC analyzed a different class of consumers and used less detailed data. Therefore, the Department considers its discount rates to be more accurate for the distribution transformer energy-efficiency analysis than the discount rates estimated by the CEC for other products. The Department retained the consumer discount rates that it used in the ANOPR analysis, as shown in Table IV.3. The consumer discount rates shown in the table are based on a detailed analysis of risk-adjusted cost of capital for consumers, as described in TSD Chapter 8.
Table IV.3.—Weighted-Average Discount Rates by Design Line and Ownership Category
Transformer ownership category
Property
owners
Industrial
companies
Commercial
companies
Investor-owned utilities
Publicly owned utilities
Government
offices
Mean real discount rate
4.35%
7.55%
7.46%
4.16%
4.31%
3.33%
Design line
Weighted average discount rate (%)
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
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
4. Candidate Standard Levels
To conduct the LCC analysis, the Department first selected CSLs. Based on its examination of the CSLs, the Department then selected trial standard levels (TSLs). From those TSLs, it developed today's proposed standards. Cooper Power Industries commented that DOE should use a consistent method for all product classes to determine CSLs. (Cooper, No. 62 at p. 3) ASAP stated that DOE should examine a CSL with the maximum efficiency that maintains a positive economic impact for each product class. (Public Meeting Transcript, No. 56.12 at p. 218) ACEEE recommended that the Department examine TP 1 plus 0.2 percent, 0.3 percent, and 0.4 percent efficiency improvements for all design lines. It encouraged the Department to carefully examine the cost and other economic inputs, since the lowest life-cycle cost point, when compared to TP 1, varies significantly among design lines. (ACEEE, No. 76 at p. 1) ACEEE said that DOE should regroup the CSLs so that CSL 1 is TP 1, CSL 3 is the minimum life-cycle cost point, and CSLs 2 and 4 are slightly above and below the minimum LCC. (ACEEE, No. 50 at p. 1 and No. 76 at p. 2) ACEEE suggested that DOE realign the CSLs so that they have approximately equivalent economic performance. (Public Meeting Transcript, No. 56.12 at p. 26) EEI and NRECA recommended that DOE investigate CSLs that have rated efficiencies below TP 1, since many transformers in the current market have efficiencies below TP 1. (EEI, No. 63 at p. 2; NRECA, No. 74 at p. 2 ) Howard stated that it is appropriate to round candidate standard efficiency levels to one decimal place. (Howard, No. 70 at p. 3)
For the NOPR analysis, the Department complied with most of the stakeholder recommendations regarding standard levels. As requested by Cooper, DOE developed a consistent method for selecting standard levels for each design line. In response to the request by ASAP, the Department defined a standard level that represented the maximum energy savings with approximately no change in LCC. In response to ACEEE, the Department defined CSL 4 as the efficiency level with minimum LCC for each design line, and realigned CSLs 4 and 5 to have equivalent economic performance for each design line. The Department did not comply with EEI's and NRECA's requests to examine standard levels lower than TP 1 because—as described in this NOPR—the Department has found that efficiencies higher than or equal to TP 1 are economically
justifiable, and thus the Department is obligated to pick a standard level that has efficiencies greater than or equal to TP 1. If the Department had reason to believe that any TP 1 levels were not economically justifiable for a standard, it would have examined efficiency levels below TP 1.
Table IV.4 lists the CSLs evaluated for each design line, expressed in terms of efficiency, and in terms relative to NEMA TP 1 efficiency levels.
Table IV.4.—Candidate Standard Levels Evaluated for Each Design Line
Design line
CSL
1
TP 1
TP 1+
%
Effic'y
%
2
1/3
of diff. between TP 1 and min LCC
TP 1+
%
Effic'y
%
3
2/3
of diff. between TP 1 and min LCC
TP 1+
%
Effic'y
%
4
Min LCC
TP 1+
%
Effic'y
%
5
Max energy savings with no change in LCC
TP 1+
%
Effic'y
%
6
Max energy savings
TP 1+
%
Effic'y
%
1
0.0
98.9
0.14
99.04
0.29
99.19
0.43
99.33
0.59
99.49
0.69
99.59
2
0.0
98.7
0.03
98.73
0.06
98.76
0.09
98.79
0.26
98.96
0.76
99.46
3
0.0
99.3
0.08
99.38
0.16
99.46
0.24
99.54
0.44
99.74
0.45
99.75
4
0.0
98.9
0.18
99.08
0.36
99.26
0.55
99.45
0.68
99.58
0.71
99.61
5
0.0
99.3
0.06
99.36
0.12
99.42
0.17
99.47
0.41
99.71
0.41
99.71
9
0.0
98.6
0.22
98.82
0.44
99.04
0.66
99.26
0.81
99.41
0.81
99.41
10
0.0
99.1
0.12
99.22
0.23
99.33
0.35
99.45
0.41
99.51
0.41
99.51
11
0.0
98.5
0.17
98.67
0.34
98.84
0.51
99.01
0.59
99.09
0.59
99.09
12
0.0
99.0
0.12
99.12
0.23
99.23
0.35
99.35
0.40
99.40
0.40
99.40
13
0.0
99.0
0.15
99.15
0.30
99.30
0.45
99.45
0.55
99.55
0.55
99.55
5. Trial Standard Levels
The TSLs are the efficiency levels considered by the Department for the proposed standard. They are based on the CSLs selected for the LCC analysis. However, because of special considerations concerning manufacturer impacts and design lines (DLs) within the same product class, some efficiency levels for DL1 and DL4 are drawn from the same CSL. See TSD Chapter 10 for a more detailed explanation. Table IV.5 shows the mapping from the design line CSLs to the TSLs. In the LCC and LCC subgroups chapters of the TSD (Chapters 8 and 11), the Department reports results in terms of CSLs. In subsequent analyses (e.g., shipments in Chapter 9, national impacts in Chapter 10, MIA in Chapter 12) and in this NOPR, the Department reports all results in terms of TSLs, mapping the LCC results according to Table IV.5.
Table IV.5.—Mapping of the Candidate Standard Levels to Trial Standard Levels
DL1
DL2
DL3
DL4
DL5
DL9
DL10
DL11
DL12
DL13
TSL1
CSL1
CSL1
CSL1
CSL1
CSL1
CSL1
CSL1
CSL1
CSL1
CSL1
TSL2
CSL1
CSL2
CSL2
CSL2
CSL2
CSL2
CSL2
CSL2
CSL2
CSL2
TSL3
CSL1
CSL3
CSL3
CSL3
CSL3
CSL3
CSL3
CSL3
CSL3
CSL3
TSL4
CSL2
CSL4
CSL4
CSL3
CSL4
CSL4
CSL4
CSL4
CSL4
CSL4
TSL5
CSL3
CSL5
CSL5
CSL5
CSL5
CSL5
CSL5
CSL5
CSL5
CSL5
TSL6
CSL6
CSL6
CSL6
CSL6
CSL6
CSL6
CSL6
CSL6
CSL6
CSL6
Georgia Power asked whether the efficiency values shown in Table II.d of the ANOPR apply only to the representative transformer for each design line, or if that efficiency is applicable to all of the kVA sizes represented by that design line. It noted that the latter would be too restrictive. (Georgia Power, No. 78 at pp. 3-4) The ANOPR document did not provide efficiency levels for all kVA ratings in a product class or design line. For the NOPR, the Department provides a complete specification of the efficiency levels for all kVA ratings. Tables II.1 and II.2 of this NOPR express the efficiency ratings for all specific kVA ratings covered by today's proposed standard. This additional information also responds to a comment by ACEEE. ACEEE asked that the Department provide efficiency values for all the kVA ratings in between the representative units analyzed. (ACEEE, No. 50 at p. 2) The Department provides this information in TSD Chapter 8.
6. Miscellaneous Life-Cycle Cost Issues
In response to the ANOPR analysis, DOE examined several additional issues relating to the LCC. These issues are grouped for organizational clarity and completeness, and are discussed below.
a. Tax Impacts
The Department did not include the impact of income taxes in the LCC analysis for the ANOPR. The Department understands that there are two ways in which taxes affect the net impacts attributed to purchasing equipment that is more energy-efficient than baseline equipment: (1) Energy-efficient equipment typically costs more to purchase than baseline equipment, which lowers net income and may lower company taxes; and (2) more-efficient equipment typically costs less to operate than baseline equipment, which increases net income and may increase company taxes.
In general, the Department believes that the net impact of taxes on the LCC analysis depends on firm profitability and expense practices (i.e., how firms expense the purchase cost of equipment). In the ANOPR, the Department sought input on whether commercial income tax effects are significant enough to warrant inclusion in the LCC analysis. 69 FR 45396. ACEEE commented that income tax should not be included in the analysis, because it would significantly complicate the analysis, and it has found that many businesses do not pay income taxes due to the many credits and deductions that are available in the current tax code. (ACEEE, No. 76 at p. 4) ODOE stated that it believes the number of corporations actually paying income taxes has declined to the point
where the overall impact of including income tax effects should be negligible. (ODOE, No. 66 at p. 6) Southern Company questioned how many firms do not pay income taxes. (Public Meeting Transcript, No. 56.12 at p. 164) NPCC stated that the analysis should be based on after-income-tax data, but also noted that businesses do not necessarily pay income tax. (Public Meeting Transcript, No. 56.12 at p. 158)
The Department agrees with ACEEE that the inclusion of income tax effects would significantly complicate the analysis. In analyzing the available options for including income tax effects, the Department could not find an estimation method where—with the existing data gaps—sufficient accuracy could be obtained to justify the increased analytical complexity. The Department therefore did not include an estimate of income tax impacts in the LCC analysis.
b. Cost Recovery Under Deregulation, Rate Caps
During the ANOPR review, stakeholders expressed mixed concerns regarding the potential impact of distribution transformer efficiency standards under utility deregulation. Southern Company commented that the impact on electric utilities of increasing the cost of transformers will vary depending on the regulatory scheme for the different utilities. It recommended that the Department include this issue in the analysis, especially for the utilities that are under rate cap legislation. (Public Meeting Transcript, No. 56.12 at p. 187) ODOE stated that there is a small likelihood of future electricity market deregulation and recommended that the Department ignore deregulation for the NOPR analysis. (ODOE, No. 66 at p. 5)
For the ANOPR, stakeholders stated many reasons why consumers may not be able to recover the added investment cost of higher efficiency distribution transformers. EEI expressed concern that political and economic risks related to deregulation will force utilities to make uneconomic (non-recoverable) incremental investments in efficient transformers. EEI requested that DOE include the effect of reduced utility earnings in the LCC analysis. (EEI, No. 63 at p. 4) ACEEE noted that utility representatives pointed out that some utilities currently have caps on their rates, which limit their ability to recover additional transformer costs. ACEEE expects that regulators would be supportive of cost recovery for reasonable transformer cost increases. (ACEEE, No. 76 at p. 3) NRDC commented that many utilities believe they cannot recover the additional costs associated with more-efficient transformers, but this will not be a problem because utility regulation throughout the country allows the distribution utility to achieve a regulated rate of return on all reasonable and prudent investment. NRDC noted that some utilities may find today's investments in high-efficiency transformers to be economically troublesome because they are subject to rate caps, but these rate caps all expire before the transformer efficiency standard would go into effect. New rate cases would then result in a new rate structure consistent with the standards-compliant transformer investments. (NRDC, No. 61 at pp. 7-8) ASE looked into the issue of rate caps and found that about 41 percent of electricity sales are in States with restructured electricity rate regulations, with about 27 percent of sales subject to rate caps, but that these caps expire steadily from 2005 to 2010. (ASE, No. 52 at p. 4) Georgia Power also asserted that utility companies cannot raise their prices to make up for the expected rise in transformer prices that will result from higher efficiency requirements without proceeding through the regulatory process. It stated, therefore, that DOE needs to weigh the financial burden this rulemaking may place on electric utilities before issuing a final rule. (Georgia Power, No. 78 at p. 4) NEMA also expressed concern that the entity paying the additional capital cost for a more energy-efficient transformer would frequently not be the beneficiary of the resultant energy cost savings. (NEMA, No. 48 at p. 1)
The concern expressed by stakeholders regarding the potential lack of cost recovery for distribution transformer investments is a classic example of “split incentives” for efficiency investments. A split incentive occurs when the entity that makes an investment is different from the entity that will receive the economic benefits of the investment. Split incentives prevent economically viable investments because, without receiving the benefits of an investment, the investor loses motivation to make investments that otherwise might have good returns. If the Department were to model split incentives in the LCC analysis, it would need to divide ownership of first costs and operating cost savings for a fraction of the transformers in the analysis. If the cost of capital were the same for the owner of the transformer and the owner of the operating cost savings, then the average LCC savings result would actually remain the same, although the spread of LCC savings in the LCC distribution results would increase. Some owners would only incur costs, while others would only receive benefits.
The Department decided not to explicitly model split incentives in the LCC analysis for the NOPR. Such modeling would have little impact on the total net LCC savings for the Nation. While the cost and the benefits would be divided between two different owners in the split incentive case, the sum would produce the same approximate net LCC savings as a model that does not include split incentives. The Department does, however, report the increase in first cost and the decrease in operating cost savings for each design line and efficiency level in TSD Chapter 8. Stakeholders can therefore evaluate the impact of standards under a split-incentive scenario where the increased transformer cost and the operating cost savings are owned by different entities.
c. Other Issues
HVOLT commented that DOE should consider incremental price compared to incremental benefit instead of total price to total benefit, where the increments are taken by comparing the results of one standard level to the results of the next highest standard level under consideration. (Public Meeting Transcript, No. 56.12 at p. 262) ACEEE stated that incremental analysis is not necessary. (Public Meeting Transcript, No. 56.12 at p. 158) The Department does not use incremental analysis in the evaluation of standards because of legal interpretations of the methodology it is required to follow. As described in section V.C of this NOPR, the Department followed its normal approach in selecting a proposed energy conservation standard for distribution transformers. It started by comparing the maximum technologically feasible level with the base case, and determined whether that level was economically justified. If it found the maximum technologically feasible level to be unjustified, the Departme
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