[Federal Register Volume 77, Number 28 (Friday, February 10, 2012)]
[Proposed Rules]
[Pages 7282-7381]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-2642]
[[Page 7281]]
Vol. 77
Friday,
No. 28
February 10, 2012
Part III
Department of Energy
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10 CFR Part 431
Energy Conservation Program: Energy Conservation Standards for
Distribution Transformers; Proposed Rule
Federal Register / Vol. 77 , No. 28 / Friday, February 10, 2012 /
Proposed Rules
[[Page 7282]]
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DEPARTMENT OF ENERGY
10 CFR Part 431
[Docket Number EERE-2010-BT-STD-0048]
RIN 1904-AC04
Energy Conservation Program: Energy Conservation Standards for
Distribution Transformers
AGENCY: Office of Energy Efficiency and Renewable Energy, Department of
Energy.
ACTION: Notice of proposed rulemaking and public meeting.
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SUMMARY: The Energy Policy and Conservation Act of 1975 (EPCA), as
amended, prescribes energy conservation standards for various consumer
products and certain commercial and industrial equipment, including
low-voltage dry-type distribution transformers, and directs the U.S.
Department of Energy (DOE) to prescribe standards for various other
products and equipment, including other types of distribution
transformers. EPCA also requires DOE to determine whether more-
stringent, amended standards would be technologically feasible and
economically justified, and would save a significant amount of energy.
In this notice, DOE proposes amended energy conservation standards for
distribution transformers. The notice also announces a public meeting
to receive comment on these proposed standards and associated analyses
and results.
DATES: DOE will hold a public meeting on February 23, 2012, from 9 a.m.
to 1 p.m., in Washington, DC. The meeting will also be broadcast as a
Webinar. See section VII Public Participation for Webinar registration
information, participant instructions, and information about the
capabilities available to Webinar participants.
DOE will accept comments, data, and information regarding this
notice of proposed rulemaking (NOPR) before and after the public
meeting, but no later than April 10, 2012. See section VII Public
Participation for details.
ADDRESSES: The public meeting will be held at the U.S. Department of
Energy, Forrestal Building, Room 8E-089, 1000 Independence Avenue SW.,
Washington, DC 20585. To attend, please notify Ms. Brenda Edwards at
(202) 586-2945. Please note that foreign nationals visiting DOE
Headquarters are subject to advance security screening procedures. Any
foreign national wishing to participate in the meeting should advise
DOE as soon as possible by contacting Ms. Edwards to initiate the
necessary procedures. In addition, persons can attend the public
meeting via Webinar. For more information, refer to the Public
Participation section near the end of this notice.
Any comments submitted must identify the NOPR for Energy
Conservation Standards for Distribution Transformers, and provide
docket number EERE-2010-BT-STD-0048 and/or regulation identifier number
(RIN) number 1904-AC04. Comments may be submitted using any of the
following methods:
1. Federal eRulemaking Portal: www.regulations.gov. Follow the
instructions for submitting comments.
2. Email: [email protected].
Include the docket number and/or RIN in the subject line of the
message.
3. Mail: Ms. Brenda Edwards, U.S. Department of Energy, Building
Technologies Program, Mailstop EE-2J, 1000 Independence Avenue SW.,
Washington, DC 20585-0121. If possible, please submit all items on a
CD. It is not necessary to include printed copies.
4. Hand Delivery/Courier: Ms. Brenda Edwards, U.S. Department of
Energy, Building Technologies Program, 950 L'Enfant Plaza SW., Suite
600, Washington, DC 20024. Telephone: (202) 586-2945. If possible,
please submit all items on a CD, in which case it is not necessary to
include printed copies.
Written comments regarding the burden-hour estimates or other
aspects of the collection-of-information requirements contained in this
proposed rule may be submitted to Office of Energy Efficiency and
Renewable Energy through the methods listed above and by email to
[email protected].
For detailed instructions on submitting comments and additional
information on the rulemaking process, see section VII of this document
(Public Participation).
Docket: The docket is available for review at www.regulations.gov,
including Federal Register notices, framework documents, public meeting
attendee lists and transcripts, comments, and other supporting
documents/materials. A link to the docket Web page can be found at:
http://www.regulations.gov/#!docketDetail;rpp=10;po=0;D=EERE-2010-BT-
STD-0048.
FOR FURTHER INFORMATION CONTACT: James Raba, U.S. Department of Energy,
Office of Energy Efficiency and Renewable Energy, Building Technologies
Program, EE-2J, 1000 Independence Avenue SW., Washington, DC 20585-
0121. Telephone: (202) 586-8654. Email: [email protected].
Ami Grace-Tardy, U.S. Department of Energy, Office of the General
Counsel, GC-71, 1000 Independence Avenue SW., Washington, DC 20585-
0121. Telephone: (202) 586-5709. Email: [email protected].
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Summary of the Proposed Rule
A. Benefits and Costs to Consumers
B. Impact on Manufacturers
C. National Benefits
II. Introduction
A. Authority
B. Background
1. Current Standards
2. History of Standards Rulemaking for Distribution Transformers
III. General Discussion
A. Test Procedures
1. General
2. Multiple kVA Ratings
3. Dual/Multiple-Voltage Basic Impulse Level
4. Dual/Multiple-Voltage Primary Windings
5. Dual/Multiple-Voltage Secondary Windings
6. Loading
B. Technological Feasibility
1. General
2. Maximum Technologically Feasible Levels
C. Energy Savings
1. Determination of Savings
2. Significance of Savings
D. Economic Justification
1. Specific Criteria
a. Economic Impact on Manufacturers and Consumers
b. Life-Cycle Costs
c. Energy Savings
d. Lessening of Utility or Performance of Products
e. Impact of Any Lessening of Competition
f. Need for National Energy Conservation
g. Other Factors
2. Rebuttable Presumption
IV. Methodology and Discussion of Related Comments
A. Market and Technology Assessment
1. Scope of Coverage
a. Definitions
b. Underground Mining Transformer Coverage
c. Low-Voltage Dry-Type Distribution Transformers
d. Negotiating Committee Discussion of Scope
2. Equipment Classes
a. Less-Flammable Liquid-Immersed Transformers
b. Pole- and Pad-Mounted Liquid-Immersed Distribution
Transformers
c. BIL Ratings in Liquid-Immersed Distribution Transformers
3. Technology Options
a. Core Deactivation
[[Page 7283]]
b. Symmetric Core
c. Intellectual Property
B. Screening Analysis
1. Nanotechnology Composites
C. Engineering Analysis
1. Engineering Analysis Methodology
2. Representative Units
3. Design Option Combinations
4. A and B Loss Value Inputs
5. Materials Prices
6. Markups
a. Factory Overhead
b. Labor Costs
c. Shipping Costs
7. Baseline Efficiency and Efficiency Levels
8. Scaling Methodology
9. Material Availability
10. Primary Voltage Sensitivities
11. Impedance
12. Size and Weight
D. Markups Analysis
E. Energy Use Analysis
F. Life-Cycle Cost and Payback Period Analysis
1. Modeling Transformer Purchase Decision
2. Inputs Affecting Installed Cost
a. Equipment Costs
b. Installation Costs
3. Inputs Affecting Operating Costs
a. Transformer Loading
b. Load Growth Trends
c. Electricity Costs
d. Electricity Price Trends
e. Standards Compliance Date
f. Discount Rates
g. Lifetime
h. Base Case Efficiency
G. National Impact Analysis--National Energy Savings and Net
Present Value Analysis
1. Shipments
2. Efficiency Trends
3. Equipment Price Forecast
4. Discount Rate
5. Energy Used in Manufacturing Transformers
H. Customer Subgroup Analysis
I. Manufacturer Impact Analysis
1. Overview
2. Government Regulatory Impact Model
3. GRIM Key Inputs
a. Manufacturer Production Costs
b. Base-Case Shipments Forecast
c. Product and Capital Conversion Costs
d. Standards Case Shipments
e. Markup Scenarios
4. Discussion of Comments
a. Material Availability
b. Symmetric Core Technology
c. Patents Related to Amorphous Steel Production
5. Manufacturer Interviews
a. Conversion Costs and Stranded Assets
b. Shortage of Materials
c. Compliance
d. Effective Date
e. Emergency Situations
J. Employment Impact Analysis
K. Utility Impact Analysis
L. Emissions Analysis
M. Monetizing Carbon Dioxide and Other Emissions Impacts
1. Social Cost of Carbon
a. Monetizing Carbon Dioxide Emissions
b. Social Cost of Carbon Values Used in Past Regulatory Analyses
c. Current Approach and Key Assumptions
2. Valuation of Other Emissions Reductions
N. Discussion of Other Comments
1. Trial Standard Levels
2. Proposed Standards
3. Alternative Methods
4. Labeling
5. Imported Units
V. Analytical Results and Conclusions
A. Trial Standard Levels
B. Economic Justification and Energy Savings
1. Economic Impacts on Customers
a. Life-Cycle Cost and Payback Period
b. Customer Subgroup Analysis
c. Rebuttable-Presumption Payback
2. Economic Impact on Manufacturers
a. Industry Cash-Flow Analysis Results
b. Impacts on Employment
c. Impacts on Manufacturing Capacity
d. Impacts on Subgroups of Manufacturers
e. Cumulative Regulatory Burden
3. National Impact Analysis
a. Significance of Energy Savings
b. Net Present Value of Customer Costs and Benefits
c. Indirect Impacts on Employment
4. Impact on Utility or Performance of Equipment
5. Impact of Any Lessening of Competition
6. Need of the Nation to Conserve Energy
7. Summary of National Economic Impacts
8. Other Factors
C. Proposed Standards
1. Benefits and Burdens of Trial Standard Levels Considered for
Liquid-Immersed Distribution Transformers
2. Benefits and Burdens of Trial Standard Levels Considered for
Low-Voltage, Dry-Type Distribution Transformers
3. Benefits and Burdens of Trial Standard Levels Considered for
Medium-Voltage, Dry-Type Distribution Transformers
4. Summary of Benefits and Costs (Annualized) of the Proposed
Standards
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Orders 12866 and 13563
B. Review Under the Regulatory Flexibility Act
1. Description and Estimated Number of Small Entities Regulated
a. Methodology for Estimating the Number of Small Entities
b. Manufacturer Participation
c. Distribution Transformer Industry Structure and Nature of
Competition
d. Comparison Between Large and Small Entities
2. Description and Estimate of Compliance Requirements
a. Summary of Compliance Impacts
3. Duplication, Overlap, and Conflict With Other Rules and
Regulations
4. Significant Alternatives to the Proposed Rule
5. Significant Issues Raised by Public Comments
6. Steps DOE Has Taken To Minimize the Economic Impact on Small
Manufacturers
C. Review Under the Paperwork Reduction Act
D. Review Under the National Environmental Policy Act of 1969
E. Review Under Executive Order 13132
F. Review Under Executive Order 12988
G. Review Under the Unfunded Mandates Reform Act of 1995
H. Review Under the Treasury and General Government
Appropriations Act, 1999
I. Review Under Executive Order 12630
J. Review Under the Treasury and General Government
Appropriations Act, 2001
K. Review Under Executive Order 13211
L. Review Under the Information Quality Bulletin for Peer Review
VII. Public Participation
A. Attendance at the Public Meeting
B. Procedure for Submitting Prepared General Statements for
Distribution
C. Conduct of the 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
Title III, Part B of the Energy Policy and Conservation Act of 1975
(EPCA or the Act), Public Law 94-163 (42 U.S.C. 6291-6309, as
codified), established the Energy Conservation Program for ``Consumer
Products Other Than Automobiles.'' Part C of Title III of EPCA (42
U.S.C. 6311-6317) established a similar program for ``Certain
Industrial Equipment,'' including distribution transformers.\1\
Pursuant to EPCA, any new or amended energy conservation standard that
the Department of Energy (DOE) prescribes for certain equipment, such
as distribution transformers, shall be designed to achieve the maximum
improvement in energy efficiency that is technologically feasible and
economically justified. (42 U.S.C. 6295(o)(2)(A) and 6316(a)).
Furthermore, the new or amended standard must result in a significant
conservation of energy. (42 U.S.C. 6295(o)(3)(B) and 6316(a)). In
accordance with these and other statutory provisions discussed in this
notice, DOE proposes amended energy conservation standards for
distribution transformers. The proposed standards are summarized in the
following tables: Table I.1, through Table I.3 that describe the
covered equipment classes and proposed trial standard levels (TSLs),
Table I.4 that shows the mapping of TSL to energy efficiency levels
(ELs),\2\ and Table I.5 through Table I.8 which show the proposed
standard in terms of minimum electrical efficiency. These proposed
standards, if adopted, would apply to all covered distribution
transformers listed in the tables and manufactured in, or imported
into, the
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United States on or after January 1, 2016. As discussed in section
IV.C.8 of this notice, any distribution transformer with a kVA rating
falling between the kVA ratings shown in the tables shall meet a
minimum energy efficiency level calculated by a linear interpolation of
the minimum efficiency requirements of the kVA ratings immediately
above and below that rating.\3\
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\1\ For editorial reasons, upon codification in the U.S. Code,
Parts B and C were redesignated as Parts A and A-1, respectively.
\2\ A detailed description of the mapping of trial standard
level to energy efficiency levels can be found in the Technical
Support Document, chapter 10 section 10.2.2.3 pg 10-10.
\3\ kVA is an abbreviation for kilovolt-ampere, which is a
capacity metric used by industry to classify transformers. A
transformer's kVA rating represents its output power when it is
fully loaded (i.e., 100 percent).
Table I.1--Proposed Energy Conservation Standards for Liquid-Immersed Distribution Transformers (Compliance
Starting January 1, 2016)
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Phase Proposed
Equipment class Design line Type count BIL TSL
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1............................... 1, 2 and 3........ Liquid-immersed... 1 Any............. 1
2............................... 4 and 5........... Liquid-immersed... 3 Any............. 1
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Note: BIL means ``basic impulse insulation level.''
Table I.2--Proposed Energy Conservation Standards for Low-Voltage, Dry-Type Distribution Transformers
(Compliance Starting January 1, 2016)
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Phase Proposed
Equipment class Design line Type count BIL TSL
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3............................... 6................. Low-voltage, dry- 1 <=10 kV 1
type.
4............................... 7 and 8........... Low-voltage, dry- 3 <=10 kV 1
type.
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Note: BIL means ``basic impulse insulation level.''
Table I.3--Proposed Energy Conservation Standards for Medium-Voltage, Dry-Type Distribution Transformers
(Compliance Starting January 1, 2016)
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Phase Proposed
Equipment class Design line Type count BIL TSL
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5............................... 9 and 10.......... Medium-voltage, 1 25-45 kV 2
dry-type.
6............................... 9 and 10.......... Medium-voltage, 3 25-45 kV 2
dry-type.
7............................... 11 and 12......... Medium-voltage, 1 46-95 kV 2
dry-type.
8............................... 11 and 12......... Medium-voltage, 3 46-95 kV 2
dry-type.
9............................... 13A and 13B....... Medium-voltage, 1 >=96 kV 2
dry-type.
10.............................. 13A and 13B....... Medium-voltage, 3 >=96 kV 2
dry-type.
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Note: BIL means ``basic impulse insulation level,'' and measures how resistant a transformer's insulation is to
large voltage transients.
Table I.4--Trial Standard Level to Energy Efficiency Level Mapping for Proposed Energy Conservation Standard
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Proposed
Type Design line Phase count TSL Energy efficiency level
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Liquid-immersed....................... 1 1 1 1
2 1 ........... Base
3 1 ........... 1
4 3 ........... 1
5 3 ........... 1
Low-voltage, dry-type................. 6 1 1 Base
7 3 ........... 2
8 3 ........... 2
Medium-voltage, dry-type.............. 9 3 2 1
10 3 ........... 2
11 3 ........... 1
12 3 ........... 2
13A 3 ........... 1
13B 3 ........... 2
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[[Page 7285]]
Table I.5--Proposed Electrical Efficiencies for all Liquid-Immersed Distribution Transformer Equipment Classes
(Compliance Starting January 1, 2016)
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Standards by kVA and equipment class
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Equipment class 1 Equipment class 2
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kVA % kVA %
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10........................................... 98.70 15.............................. 98.65
15........................................... 98.82 30.............................. 98.83
25........................................... 98.95 45.............................. 98.92
37.5......................................... 99.05 75.............................. 99.03
50........................................... 99.11 112.5........................... 99.11
75........................................... 99.19 150............................. 99.16
100.......................................... 99.25 225............................. 99.23
167.......................................... 99.33 300............................. 99.27
250.......................................... 99.39 500............................. 99.35
333.......................................... 99.43 750............................. 99.40
500.......................................... 99.49 1000............................ 99.43
1500............................ 99.48
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Table I.6--Proposed Electrical Efficiencies for all Low-Voltage Dry-Type Distribution Transformer Equipment
Classes (Compliance Starting January 1, 2016)
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Standards by kVA and equipment class
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Equipment class 3 Equipment class 4
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kVA % kVA %
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15........................................... 97.73 15.............................. 97.44
25........................................... 98.00 30.............................. 97.95
37.5......................................... 98.20 45.............................. 98.20
50........................................... 98.31 75.............................. 98.47
75........................................... 98.50 112.5........................... 98.66
100.......................................... 98.60 150............................. 98.78
167.......................................... 98.75 225............................. 98.92
250.......................................... 98.87 300............................. 99.02
333.......................................... 98.94 500............................. 99.17
750............................. 99.27
1000............................ 99.34
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Table I.7--Proposed Electrical Efficiencies for all Medium-Voltage Dry-Type Distribution Transformer Equipment Classes (Compliance Starting January 1, 2016)
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Standards by kVA and equipment class
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Equipment class 5 Equipment class 6 Equipment class 7 Equipment class 8 Equipment class 9 Equipment class 10
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kVA % kVA % kVA % kVA % kVA % kVA %
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15.............................. 98.10 15................. 97.50 15................ 97.86 15................ 97.18 .................. ........ .................. .......
25.............................. 98.33 30................. 97.90 25................ 98.12 30................ 97.63 .................. ........ .................. .......
37.5............................ 98.49 45................. 98.10 37.5.............. 98.30 45................ 97.86 .................. ........ .................. .......
50.............................. 98.60 75................. 98.33 50................ 98.42 75................ 98.13 .................. ........ .................. .......
75.............................. 98.73 112.5.............. 98.52 75................ 98.57 112.5............. 98.36 75................ 98.53 .................. .......
100............................. 98.82 150................ 98.65 100............... 98.67 150............... 98.51 100............... 98.63 .................. .......
167............................. 98.96 225................ 98.82 167............... 98.83 225............... 98.69 167............... 98.80 225............... 98.57
250............................. 99.07 300................ 98.93 250............... 98.95 300............... 98.81 250............... 98.91 300............... 98.69
333............................. 99.14 500................ 99.09 333............... 99.03 500............... 98.99 333............... 98.99 500............... 98.89
500............................. 99.22 750................ 99.21 500............... 99.12 750............... 99.12 500............... 99.09 750............... 99.02
667............................. 99.27 1000............... 99.28 667............... 99.18 1000.............. 99.20 667............... 99.15 1000.............. 99.11
833............................. 99.31 1500............... 99.37 833............... 99.23 1500.............. 99.30 833............... 99.20 1500.............. 99.21
2000............... 99.43 2000.............. 99.36 2000.............. 99.28
2500............... 99.47 2500.............. 99.41 2500.............. 99.33
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A. Benefits and Costs to Consumers \4\
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\4\ For the purposes of this document, the ``consumers'' of
distribution transformers are referred to as ``customers.''
Customers refer to electric utilities in the case of liquid-immersed
transformers, and to utilities and building owners in the case of
dry-type transformers.
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Table I.8 presents DOE's evaluation of the economic impacts of the
proposed standards on customers of distribution transformers, as
measured by the average life-cycle cost (LCC) savings and the median
payback period (PBP). DOE measures the impacts of standards relative to
a base case that reflects likely trends in the distribution transformer
market in the absence of amended standards. The base case predominantly
consists of products at the baseline efficiency levels evaluated for
each representative unit, which correspond to the existing energy
conservation standard level of efficiency for distribution transformers
established either in DOE's 2007 rulemaking or by EPACT 2005. The
average LCC savings are positive for all but two of the design lines,
for which customers are not impacted by the proposed standards.
(Throughout this document, ``distribution transformers'' are also
referred to as simply ``transformers.'')
Table I.8--Impacts of Proposed Standards on Customers of Distribution
Transformers
------------------------------------------------------------------------
Median
Average LCC payback
Design Line savings period
(2010$) (years)
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Liquid-Immersed
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1............................................. 36 20.2
2............................................. * N/A * N/A
3............................................. 2,413 6.3
4............................................. 862 5.0
5............................................. 7,787 4.0
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Low-Voltage, Dry-Type
------------------------------------------------------------------------
6............................................. * N/A * N/A
7............................................. 1,714 4.5
8............................................. 2,476 8.4
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Medium-Voltage, Dry-Type
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9............................................. 849 2.6
10............................................ 4,791 8.8
11............................................ 1,043 10.7
12............................................ 6,934 9.0
13A........................................... 25 16.5
13B........................................... 4,709 12.5
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* No consumers are impacted by the proposed standard because no change
from the minimum efficiency standard is proposed for design lines 2
and 6.
B. Impact on Manufacturers
The industry net present value (INPV) is the sum of the discounted
cash flows to the industry from the base year through the end of the
analysis period (2011 through 2045). Using a real discount rate of 7.4
percent for liquid-immersed distribution transformers, 9 percent for
medium-voltage dry-type distribution transformers, and 11.1 percent for
low-voltage dry- type distribution transformers, DOE estimates that the
industry net present value (INPV) for manufacturers of liquid-immersed,
medium-voltage dry-type and low-voltage dry-type distribution
transformers is $625 million, $91 million, and $220 million,
respectively, in 2011$. Under the proposed standards, DOE expects that
liquid-immersed manufacturers may lose up to 6.3 percent of their INPV,
which is approximately $39.6 million; medium-voltage manufacturers may
lose up to 7.1 percent of their INPV, which is approximately $6.5
million; and low-voltage dry-type manufacturers may lose up to 7.7
percent of their INPV, which is approximately $16.8 million.
Additionally, based on DOE's interviews with the manufacturers of
distribution transformers, DOE does not expect any plant closings or
significant loss of employment.
C. National Benefits
DOE's analyses indicate that the proposed standards would save a
significant amount of energy--an estimated 1.58 quads over 30 years
(2016-2045). In addition, DOE expects the energy savings from the
proposed standards to be equivalent to the energy output from 2.40
gigawatts (GW) of generating capacity by 2045.
The cumulative national net present value (NPV) of total consumer
costs and savings of the proposed standards for distribution
transformers sold in 2016-2045, in 2010$, ranges from $2.9 billion (at
a 7-percent discount rate) to $12.2 billion (at a 3-percent discount
rate) over 30 years (2016-2045). This NPV expresses the estimated total
value of future operating cost savings minus the estimated increased
equipment costs for distribution transformers purchased in 2016-2045,
discounted to 2010.
In addition, the proposed standards would have significant
environmental benefits. The energy savings are expected to result in
cumulative greenhouse gas emission reductions of 122.1 million metric
tons (Mt) \5\ of carbon dioxide (CO2) from 2016-2045. During
this period, the proposed standards are expected to result in emissions
reductions of 99.7 thousand tons of nitrogen oxides (NOX)
and 0.819 tons of mercury (Hg).\6\
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\5\ A metric ton is equivalent to 1.1 short tons. A short ton is
equal to 2,000 pounds. Results for NOX and Hg are
presented in short tons (referred to here as simply ``tons.'')
\6\ DOE calculates emissions reductions relative to the most
recent version of the Annual Energy Outlook (AEO) Reference case
forecast. This forecast accounts for emissions reductions from in-
place regulations, including the Clean Air Interstate Rule (CAIR, 70
FR 25162 (May 12, 2005)), but not the Clean Air Mercury Rule (CAMR,
70 FR 28606 (May 18, 2005)). Subsequent regulations, including the
Cross-State Air Pollution rule issued on July 6, 2011, do not appear
in the AEO forecast at this time.
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The value of the CO2 reductions is calculated using a
range of values per metric ton of CO2 (otherwise known as
the Social Cost of Carbon, or SCC) developed by a recent interagency
process. The derivation of the SCC values is discussed in section IV.M.
DOE estimates the net present monetary value of the CO2
emissions reduction is between $0.71 and $12.5 billion, expressed in
2010$ and discounted to 2010. DOE also estimates the net present
monetary value of the NOX emissions reduction, expressed in
2010$ and discounted to 2010, is between $0.069 billion at a 7-percent
discount rate and $0.210 billion at a 3-percent discount rate.\7\
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\7\ DOE is aware of multiple agency efforts to determine the
appropriate range of values used in evaluating the potential
economic benefits of reduced Hg emissions. DOE has decided to await
further guidance regarding consistent valuation and reporting of Hg
emissions before it once again monetizes Hg in its rulemakings.
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Table I.9 summarizes the national economic costs and benefits
expected to result from today's proposed standards for distribution
transformers.
[[Page 7287]]
Table I.9--Summary of National Economic Benefits and Costs of Proposed
Distribution Transformer Energy Conservation Standards
------------------------------------------------------------------------
Present value Discount rate
Category billion 2010$ (percent)
------------------------------------------------------------------------
Benefits:
Operating Cost Savings............ 5.58 7
17.44 3
CO2 Reduction Monetized Value (at 0.71 5
$4.9/t) *........................
CO2 Reduction Monetized Value (at 4.13 3
$22.3/t) *.......................
CO2 Reduction Monetized Value (at 7.20 2.5
$36.5/t) *.......................
CO2 Reduction Monetized Value (at 12.54 3
$67.6/t) *.......................
NOX Reduction Monetized Value (at 0.069 7
$2,537/ton) *....................
0.210 3
---------------------------------
Total Benefits**.............. 9.78 7
21.7 3
Costs:
Incremental Installed Costs....... 2.67 7
5.21 3
Net Benefits:
Including CO2 and NOX............. 7.10 7
16.5 3
------------------------------------------------------------------------
* The CO2 values represent global monetized values of the SCC in 2010
under several scenarios. The values of $4.9, $22.1, and $36.3 per
metric ton (t) are the averages of SCC distributions calculated using
5%, 3%, and 2.5% discount rates, respectively. The value of $67.1/t
represents the 95th percentile of the SCC distribution calculated
using a 3% discount rate. A metric ton is equivalent to 1.1 short
tons. A short ton is equal to 2,000 pounds. Results for NOX are
presented in short tons (referred to here as simply ``tons.'')
** Total Benefits for both the 3% and 7% cases are derived using the SCC
value calculated at a 3% discount rate, and the average of the low and
high NOX values used in DOE's analysis.
The benefits and costs of today's proposed standards, for equipment
sold in 2016-2045, can also be expressed in terms of annualized values.
The annualized monetary values are the sum of: (1) The annualized
national economic value of the benefits from consumer operation of
equipment that meets the proposed standards (consisting primarily of
operating cost savings from using less energy minus increases in
equipment purchase and installation costs, which is another way of
representing consumer NPV), and (2) the annualized monetary value of
the benefits of emission reductions, including CO2 emission
reductions.\8\
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\8\ DOE used a two-step calculation process to convert the time-
series of costs and benefits into annualized values. First, DOE
calculated a present value in 2011, the year used for discounting
the NPV of total consumer costs and savings, for the time-series of
costs and benefits using discount rates of 3 and 7 percent for all
costs and benefits except for the value of CO2
reductions. For the latter, DOE used a range of discount rates, as
shown in Table I.9. From the present value, DOE then calculated the
fixed annual payment over a 30-year period, starting in 2011 that
yields the same present value. The fixed annual payment is the
annualized value. Although DOE calculated annualized values, this
does not imply that the time-series of cost and benefits from which
the annualized values were determined would be a steady stream of
payments.
---------------------------------------------------------------------------
Although combining the values of operating savings and
CO2 emission reductions provides a useful perspective, two
issues should be considered. First, the national operating savings are
domestic U.S. consumer monetary savings that occur as a result of
market transactions while the value of CO2 reductions is
based on a global value. Second, the assessments of operating cost
savings and CO2 savings are performed with different methods
that use different time frames for analysis. The national operating
cost savings is measured for the lifetime of distribution transformers
shipped in 2016-2045. The SCC values, on the other hand, reflect the
present value of some future climate-related impacts resulting from the
emission of one metric ton of carbon dioxide in each year. These
impacts continue well beyond 2100.
Estimates of annualized benefits and costs of today's proposed
standards are shown in Table I.10. (All monetary values below are
expressed in 2010$.) The results under the primary estimate are as
follows. Using a 7-percent discount rate for benefits and costs other
than CO2 reduction, for which DOE used a 3-percent discount
rate along with the SCC series corresponding to a value of $22.3/metric
ton in 2010, the cost of the standards proposed in today's proposed
standards is $302 million per year in increased equipment costs. The
benefits are $631 million per year in reduced equipment operating
costs, $244 million in CO2 reductions, and $7.78 million in
reduced NOX emissions. In this case, the net benefit amounts
to $581 million per year. Using a 3-percent discount rate for all
benefits and costs and the SCC series corresponding to a value of
$22.3/metric ton in 2010, the cost of the standards proposed in today's
rule is $308 million per year in increased equipment costs. The
benefits are $1,026 million per year in reduced operating costs, $244
million in CO2 reductions, and $12.4 million in reduced
NOX emissions. In this case, the net benefit amounts to $975
million per year.
Table I.10--Annualized Benefits and Costs of Proposed Standards for Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Monetized (million 2010$/year)
--------------------------------------------------------------
Discount rate Low net benefits High net benefits
Primary estimate * estimate * estimate *
----------------------------------------------------------------------------------------------------------------
Benefits:
[[Page 7288]]
Operating Cost Savings.... 7%............... 631................ 594................ 659.
3%............... 1,026.............. 950................ 1,075.
CO2 Reduction at $4.9/t**. 5%............... 58.6............... 58.6............... 58.6.
CO2 Reduction at $22.3/t** 3%............... 244................ 244................ 244.
CO2 Reduction at $36.5/t** 2.5%............. 389................ 389................ 389.
CO2 Reduction at $67.6/t** 3%............... 742................ 742................ 742.
NOX Reduction at $2,537/ 7%............... 7.78............... 7.78............... 7.78.
ton**.
3%............... 12.4............... 12.4............... 12.4.
---------------------------------------------------------------------------------
Total [dagger]........ 7% plus CO2 range 697 to 1380........ 660 to 1343........ 726 to 1409.
7%............... 883................ 846................ 911.
3% plus CO2 range 1097 to 1780....... 1021 to 1704....... 1146 to 1829.
3%............... 1,283.............. 1,207.............. 1,331.
Costs:
Incremental Product Costs. 7%............... 302................ 338................ 285.
3%............... 308................ 351................ 289.
Total Net Benefits:
Total [dagger]........ 7% plus CO2 range 400 to 1083........ 327 to 1010........ 445 to 1128.
7%............... 581................ 507................ 626.
3% plus CO2 range 789 to 1472........ 670 to 1353........ 857 to 1540.
3%............... 975................ 855................ 1,043.
----------------------------------------------------------------------------------------------------------------
* The Primary, Low Net Benefits, and High Net Benefits Estimates utilize forecasts of energy prices from the AEO
2011 reference case, Low Economic Growth case, and High Economic Growth case, respectively. In addition,
incremental product costs reflect no change in the Primary estimate, rising product prices in the Low Net
Benefits estimate, and declining product prices in the High Net Benefits estimate.
** The CO2 values represent global values (in 2010$) of the social cost of CO2 emissions in 2010 under several
scenarios. The values of $4.9, $22.3, and $36.5 per metric ton are the averages of SCC distributions
calculated using 5%, 3%, and 2.5% discount rates, respectively. The value of $67.6 per metric ton represents
the 95th percentile of the SCC distribution calculated using a 3% discount rate. The value for NOX (in 2010$)
is the average of the low and high values used in DOE's analysis.
Total Benefits for both the 3% and 7% cases are derived using the SCC value calculated at a 3% discount rate,
which is $22.3/metric ton in 2010 (in 2010$). In the rows labeled as ``7% plus CO2 range'' and ``3% plus CO2
range,'' the operating cost and NOX benefits are calculated using the labeled discount rate, and those values
are added to the full range of CO2 values.
DOE has tentatively concluded that the proposed standards represent
the maximum improvement in energy efficiency that is technologically
feasible and economically justified, and would result in the
significant conservation of energy. DOE further notes that equipment
achieving these proposed standard levels are already commercially
available for at least some, if not most, equipment classes covered by
today's proposal. Based on the analyses described above, DOE has
tentatively concluded that the benefits of the proposed standards to
the Nation (energy savings, positive NPV of consumer benefits, consumer
LCC savings, and emission reductions) would outweigh the burdens (loss
of INPV for manufacturers and LCC increases for some consumers).
DOE also considered more stringent energy efficiency levels as
trial standard levels, and is still considering them in this
rulemaking. However, DOE has tentatively concluded that, in some cases,
the potential burdens of the more stringent energy efficiency levels
would outweigh the projected benefits. Based on consideration of the
public comments DOE receives in response to this notice and related
information collected and analyzed during the course of this rulemaking
effort, DOE may adopt energy efficiency levels presented in this notice
that are either higher or lower than the proposed standards, or some
combination of energy efficiency level(s) that incorporate the proposed
standards in part.
II. Introduction
The following section briefly discusses the statutory authority
underlying today's proposal, as well as some of the relevant historical
background related to the establishment of energy conservation
standards for distribution transformers.
A. Authority
Title III, Part B of the Energy Policy and Conservation Act of 1975
(EPCA or the Act), Public Law 94-163 (42 U.S.C. 6291-6309, as
codified), established the Energy Conservation Program for ``Consumer
Products Other Than Automobiles.'' Part C of Title III of EPCA (42
U.S.C. 6311-6317) established a similar program for ``Certain
Industrial Equipment,'' including distribution transformers.\9\ The
Energy Policy Act of 1992 (EPACT 1992), Public Law 102-486, amended
EPCA and directed the Department to prescribe energy conservation
standards for distribution transformers. (42 U.S.C. 6317(a)) The Energy
Policy Act of 2005 (EPACT 2005), Public Law 109-25, amended EPCA to
establish energy conservation standards for low-voltage, dry-type
distribution transformers.\10\ (42 U.S.C. 6295(y)) Under 42 U.S.C.
6313(a)(6)(C)(i), DOE must review energy conservation standards for
commercial and industrial equipment and amend the standards as needed
no later than six years from the issuance of a final rule establishing
or amending a standard for a covered product. A final rule establishing
any amended standards based on such notice of
[[Page 7289]]
proposed rulemaking (NOPR) must be completed within two years of
publication of the NOPR. (42 U.S.C. 6313(a)(6)(C)(iii)(I)).
---------------------------------------------------------------------------
\9\ For editorial reasons, upon codification in the U.S. Code,
Parts B and C were redesignated as Parts A and A-1, respectively
\10\ EPACT 2005 established that the efficiency of a low-voltage
dry-type distribution transformer manufactured on or after January
1, 2007 shall be the Class I Efficiency Levels for distribution
transformers specified in Table 4-2 of the ``Guide for Determining
Energy Efficiency for Distribution Transformers'' published by the
National Electrical Manufacturers Association (NEMA TP 1-2002).
---------------------------------------------------------------------------
DOE publishes today's proposed rule pursuant to Part C of Title
III, which establishes an energy conservation program for covered
equipment that consists essentially of four parts: (1) Testing; (2)
labeling; (3) the establishment of Federal energy conservation
standards; and (4) compliance certification and enforcement procedures.
For those distribution transformers for which DOE determines that
energy conservation standards are warranted, the DOE test procedures
must be the ``Standard Test Method for Measuring the Energy Consumption
of Distribution Transformers'' prescribed by the National Electrical
Manufacturers Association (NEMA TP 2-1998), subject to review and
revision by the Secretary in accordance with certain criteria and
conditions. (42 U.S.C. 6293(b)(10), 6314(a)(2)-(3) and 6317(a)(1))
Manufacturers of covered equipment must use the prescribed DOE test
procedure as the basis for certifying to DOE that their equipment
complies with the applicable energy conservation standards adopted
under EPCA and when making representations to the public regarding the
energy use or efficiency of those types of equipment. (42 U.S.C.
6314(d)) The DOE test procedures for distribution transformers
currently appear at title 10 of the Code of Federal Regulations (CFR)
part 431, subpart K, appendix A.
DOE must follow specific statutory criteria for prescribing amended
standards for covered equipment. As indicated above, any amended
standard for covered equipment must be designed to achieve the maximum
improvement in energy efficiency that is technologically feasible and
economically justified. (42 U.S.C. 6295(o)(2)(A) and 6316(a))
Furthermore, DOE may not adopt any amended standard that would not
result in the significant conservation of energy. (42 U.S.C. 6295(o)(3)
and 6316(a)) Moreover, DOE may not prescribe a standard: (1) For
certain equipment, including distribution transformers, if no test
procedure has been established for the equipment, or (2) if DOE
determines by rule that the proposed standard is not technologically
feasible or economically justified. (42 U.S.C. 6295(o)(3)(A)-(B) and
6316(a)) In deciding whether a proposed amended standard is
economically justified, DOE must determine whether the benefits of the
standard exceed its burdens. (42 U.S.C. 6295(o)(2)(B)(i) and 6316(a))
DOE must make this determination after receiving comments on the
proposed standard, and by considering, to the greatest extent
practicable, the following seven factors:
1. The economic impact of the standard on manufacturers and
consumers of the equipment subject to the standard;
2. The savings in operating costs throughout the estimated average
life of the covered equipment in the type (or class) compared to any
increase in the price, initial charges, or maintenance expenses for the
covered products that are likely to result from the imposition of the
standard;
3. The total projected amount of energy, or as applicable, water,
savings likely to result directly from the imposition of the standard;
4. Any lessening of the utility or the performance of the covered
equipment likely to result from the imposition of the standard;
5. The impact of any lessening of competition, as determined in
writing by the Attorney General, that is likely to result from the
imposition of the standard;
6. The need for national energy and water conservation; and
7. Other factors the Secretary of Energy (Secretary) considers
relevant. (42 U.S.C. 6295(o)(2)(B)(i) and 6316(a))
EPCA, as codified, also contains what is known as an ``anti-
backsliding'' provision, which prevents the Secretary from prescribing
any amended standard that either increases the maximum allowable energy
use or decreases the minimum required energy efficiency of a covered
product. (42 U.S.C. 6295(o)(1) and 6316(a)) Also, the Secretary may not
prescribe an amended or new standard if interested persons have
established by a preponderance of the evidence that the standard is
likely to result in the unavailability in the United States of any
covered product type (or class) of performance characteristics
(including reliability), features, sizes, capacities, and volumes that
are substantially the same as those generally available in the United
States. (42 U.S.C. 6295(o)(4) and 6316(a))
Further, EPCA, as codified, establishes a rebuttable presumption
that an energy conservation standard is economically justified if the
Secretary finds that the additional cost to the consumer of purchasing
equipment complying with the energy conservation standard will be less
than three times the value of the energy savings a consumer will
receive in the first year of using the equipment. (See 42 U.S.C.
6295(o)(2)(B)(iii) and 6316(a))
Additionally, 42 U.S.C. 6295(q)(1), as applied to covered equipment
via 42 U.S.C. 6316(a), specifies requirements when promulgating a
standard for a type or class of covered equipment that has two or more
subcategories. DOE must specify a different standard level than that
which applies generally to such type or class of equipment for any
group of covered equipment that has the same function or intended use
if DOE determines that equipment within such group (A) consumes a
different kind of energy from that consumed by other covered equipment
within such type (or class); or (B) has a capacity or other
performance-related feature which other equipment within such type (or
class) does not have and such feature justifies a higher or lower
standard. (42 U.S.C. 6294(q)(1) and 6316(a)) In determining whether a
performance-related feature justifies a different standard for a group
of equipment, DOE must consider such factors as the utility to the
consumer of the feature and other factors DOE deems appropriate. Id.
Any rule prescribing such a standard must include an explanation of the
basis on which such higher or lower level was established. (42 U.S.C.
6295(q)(2) and 6316(a))
Federal energy conservation requirements generally supersede State
laws or regulations concerning energy conservation testing, labeling,
and standards. (42 U.S.C. 6297(a)-(c) and 6316(a)) DOE may, however,
grant waivers of Federal preemption for particular State laws or
regulations, in accordance with the procedures and other provisions set
forth under 42 U.S.C. 6297(d)).
DOE has also reviewed this regulation pursuant to Executive Order
(EO) 13563, issued on January 18, 2011 (76 FR 3281, Jan. 21, 2011). EO
13563 is supplemental to and explicitly reaffirms the principles,
structures, and definitions governing regulatory review established in
EO 12866. To the extent permitted by law, agencies are required by EO
13563 to: (1) Propose or adopt a regulation only upon a reasoned
determination that its benefits justify its costs (recognizing that
some benefits and costs are difficult to quantify); (2) tailor
regulations to impose the least burden on society, consistent with
obtaining regulatory objectives, taking into account, among other
things, and to the extent practicable, the costs of cumulative
regulations; (3) select, in choosing among alternative regulatory
approaches, those approaches that maximize net benefits (including
potential economic, environmental, public health and safety, and other
advantages; distributive impacts; and equity); (4) to the extent
feasible, specify
[[Page 7290]]
performance objectives, rather than specifying the behavior or manner
of compliance that regulated entities must adopt; and (5) identify and
assess available alternatives to direct regulation, including providing
economic incentives to encourage the desired behavior, such as user
fees or marketable permits, or providing information upon which choices
can be made by the public.
DOE emphasizes as well that EO 13563 requires agencies to use the
best available techniques to quantify anticipated present and future
benefits and costs as accurately as possible. In its guidance, the
Office of Information and Regulatory Affairs has emphasized that such
techniques may include identifying changing future compliance costs
that might result from technological innovation or anticipated
behavioral changes. For the reasons stated in the preamble, DOE
believes that today's notice of proposed rulemaking (NOPR) is
consistent with these principles, including the requirement that, to
the extent permitted by law, benefits justify costs and that net
benefits are maximized.
B. Background
1. Current Standards
On August 8, 2005, the Energy Policy Act of 2005 (EPACT 2005)
amended EPCA to establish energy conservation standards for low-
voltage, dry-type distribution transformers (LVDTs).\11\ (EPACT 2005,
Section 135(c); 42 U.S.C. 6295(y)) The standard levels for low-voltage
dry-type distribution transformers appear in Table II.1.
---------------------------------------------------------------------------
\11\ EPACT 2005 established that the efficiency of a low-voltage
dry-type distribution transformer manufactured on or after January
1, 2007 shall be the Class I Efficiency Levels for distribution
transformers specified in Table 4-2 of the ``Guide for Determining
Energy Efficiency for Distribution Transformers'' published by the
National Electrical Manufacturers Association (NEMA TP 1-2002).
Table II.1--Federal Energy Efficiency Standards for Low-Voltage, Dry-Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
15........................................ 97.7 15........................... 97.0
25........................................ 98.0 30........................... 97.5
37.5...................................... 98.2 45........................... 97.7
50........................................ 98.3 75........................... 98.0
75........................................ 98.5 112.5........................ 98.2
100....................................... 98.6 150.......................... 98.3
167....................................... 98.7 225.......................... 98.5
250....................................... 98.8 300.......................... 98.6
333....................................... 98.9 500.......................... 98.7
.................. 750.......................... 98.8
.................. 1000......................... 98.9
----------------------------------------------------------------------------------------------------------------
Note: Efficiencies are determined at the following reference conditions: (1) for no-load losses, at the
temperature of 20 [deg]C, and (2) for load-losses, at the temperature of 75 [deg]C and 35 percent of nameplate
load.
DOE incorporated these standards into its regulations, along with
the standards for several other types of products and equipment, in a
final rule published on October 18, 2005. 70 FR 60407, 60416--60417.
These standards appear at 10 CFR 431.196(a).
On October 12, 2007, DOE published a final rule that established
energy conservation standard for liquid-immersed distribution
transformers and medium-voltage dry-type distribution transformers,
which are shown in Table II.2 and Table II.3, respectively. 72 FR
58190, 58239-40. These standards are codified at 10 CFR 431.196(b) and
(c).
Table II.2--Energy Conservation Standards for Liquid-Immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
10........................................ 98.62 15........................... 98.36
15........................................ 98.76 30........................... 98.62
25........................................ 98.91 45........................... 98.76
37.5...................................... 99.01 75........................... 98.91
50........................................ 99.08 112.5........................ 99.01
75........................................ 99.17 150.......................... 99.08
100....................................... 99.23 225.......................... 99.17
167....................................... 99.25 300.......................... 99.23
250....................................... 99.32 500.......................... 99.25
333....................................... 99.36 750.......................... 99.32
500....................................... 99.42 1000......................... 99.36
667....................................... 99.46 1500......................... 99.42
833....................................... 99.49 2000......................... 99.46
2500......................... 99.49
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-
Procedure. 10 CFR part 431, subpart K, appendix A.
[[Page 7291]]
Table II.3--Energy Conservation Standards for Medium-Voltage, Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
BIL 20-45 kV 46-95 kV >=96 kV BIL 20-45 kV 46-95 kV >=96 kV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency Efficiency Efficiency Efficiency Efficiency Efficiency
kVA (%) (%) (%) kVA (%) (%) (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15........................................ 98.10 97.86 ............ 15........................... 97.50 97.18 ...........
25........................................ 98.33 98.12 ............ 30........................... 97.90 97.63 ...........
37.5...................................... 98.49 98.30 ............ 45........................... 98.10 97.86 ...........
50........................................ 98.60 98.42 ............ 75........................... 98.33 98.12 ...........
75........................................ 98.73 98.57 98.53 112.5........................ 98.49 98.30 ...........
100....................................... 98.82 98.67 98.63 150.......................... 98.60 98.42 ...........
167....................................... 98.96 98.83 98.80 225.......................... 98.73 98.57 98.53
250....................................... 99.07 98.95 98.91 300.......................... 98.82 98.67 98.63
333....................................... 99.14 99.03 98.99 500.......................... 98.96 98.83 98.80
500....................................... 99.22 99.12 99.09 750.......................... 99.07 98.95 98.91
667....................................... 99.27 99.18 99.15 1000......................... 99.14 99.03 98.99
833....................................... 99.31 99.23 99.20 1500......................... 99.22 99.12 99.09
........... ........... ............ 2000......................... 99.27 99.18 99.15
........... ........... ............ 2500......................... 99.31 99.23 99.20
--------------------------------------------------------------------------------------------------------------------------------------------------------
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.
2. History of Standards Rulemaking for Distribution Transformers
In a notice published on October 22, 1997 (62 FR 54809), DOE stated
that it had determined that energy conservation standards were
warranted for electric distribution transformers, relying in part on
two reports by DOE's Oak Ridge National Laboratory (ORNL). These
reports--Determination Analysis of Energy Conservation Standards for
Distribution Transformers, ORNL-6847 (1996) and Supplement to the
``Determination Analysis,'' ORNL-6847 (1997)--are available on the DOE
Web site at: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html. In 2000, DOE issued its
Framework Document for Distribution Transformer Energy Conservation
Standards Rulemaking, describing its proposed approach for developing
standards for distribution transformers, and held a public meeting to
discuss the Framework Document. The document is available on the above-
referenced DOE Web site. Stakeholders also submitted written comments
on the document, addressing a range of issues.
Subsequently, DOE issued draft reports as to certain of the key
analyses contemplated by the Framework Document.\12\ It received
comments from stakeholders on these draft reports and, on July 29,
2004, published an advance notice of proposed rulemaking (ANOPR) for
distribution transformer standards. 69 FR 45376. DOE then held a
webcast on material it had published relating to the ANOPR, followed by
a public meeting on the ANOPR on September 28, 2004. In August 2005,
DOE issued a draft of certain of the analyses on which it planned to
base the standards for liquid-immersed and medium-voltage, dry-type
distribution transformers, along with documents that supported the
draft analyses.\13\ DOE did this to enable stakeholders to review the
analyses and make recommendations as to standard levels.
---------------------------------------------------------------------------
\12\ Copies of all the draft analyses published before the ANOPR
are available on DOE's Web site: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis.html.
\13\ Copies of the four draft NOPR analyses published in August
2005 are available on DOE's Web site: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis_nopr.html.
---------------------------------------------------------------------------
On April 27, 2006, DOE published its Final Rule on Test Procedures
for Distribution Transformers. The rule: (1) Established the procedure
for sampling and testing distribution transformers so that
manufacturers can make representations as to their efficiency, as well
as establish that they comply with Federal standards; and (2) contained
enforcement provisions, outlining the procedure the Department would
follow should it initiate an enforcement action against a manufacturer.
71 FR 24972 (codified at 10 CFR 431.198).
On August 4, 2006, DOE published a NOPR in which it proposed energy
conservation standards for distribution transformers (the 2006 NOPR).
71 FR 44355. Concurrently, DOE also issued a technical support document
(TSD) that incorporated the analyses it had performed for the proposed
rule, including several spreadsheets that remain available on DOE's Web
site.\14\
---------------------------------------------------------------------------
\14\ The spreadsheets developed for this rulemaking proceeding
are available at: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis_nopr.html.
---------------------------------------------------------------------------
Some commenters asserted that DOE's proposed standards might
adversely affect replacement of distribution transformers in certain
space-constrained (e.g., vault) installations. In response, DOE issued
a notice of data availability and request for comments on this and
another issue. 72 FR 6186 (Feb. 9, 2007) (the NODA). In the NODA, DOE
sought comment on whether it should include in the LCC analysis
potential costs related to size constraints of distribution
transformers installed in vaults. DOE also outlined different
approaches as to how it might account for additional installation costs
for these space-constrained applications and requested comments on
linking energy efficiency levels for three-phase liquid-immersed units
with those of single-phase units. Finally, DOE addressed how it was
inclined to consider a final standard that is based on energy
efficiency levels derived from trial standard level (TSL) 2 and TSL 3
for three-phase units and TSLs 2, 3 and 4 for single-phase units. 72 FR
6189. Based on comments on the 2006 NOPR, and the NODA, DOE created new
TSLs to address the treatment of three-phase units and single-phase
units. In October 2007, DOE published a final rule that created the
current energy conservation standards for liquid-immersed and medium-
voltage dry-type distribution transformers. 72 FR 58190 (October 12,
[[Page 7292]]
2007) (the 2007 Final Rule) (codified at 10 CFR 431.196(b)-(c)).
The above paragraphs summarize development of the 2007 Final Rule.
The preamble to the rule included additional, detailed background
information on the history of that rulemaking. 72 FR 58194-96.
After the publication of the 2007 Final Rule, certain parties filed
petitions for review in the United States Courts of Appeals for the
Second and Ninth Circuits, challenging the rule. Several additional
parties were permitted to intervene in support of these petitions. (All
of these parties are referred to below collectively as
``petitioners.'') The petitioners alleged that, in developing its
energy conservation standards for distribution transformers, DOE did
not comply with certain applicable provisions of EPCA and of the
National Environmental Policy Act (NEPA), as amended (42 U.S.C. 4321 et
seq.) DOE and the petitioners subsequently entered into a settlement
agreement to resolve the petitions. The settlement agreement outlined
an expedited timeline for the Department to determine whether to amend
the energy conservation standards for liquid-immersed and medium-
voltage dry-type distribution transformers. Under the original
settlement agreement, DOE was required to publish by October 1, 2011,
either a determination that the standards for these distribution
transformers do not need to be amended or a NOPR that includes any new
proposed standards and that meets all applicable requirements of EPCA
and NEPA. Under an amended settlement agreement, the October 1, 2011,
deadline for a DOE determination or proposed rule was extended to
February 1, 2012. If DOE finds that amended standards are warranted,
DOE must publish a final rule containing such amended standards by
October 1, 2012.
On March 2, 2011, DOE published in the Federal Register a notice of
public meeting and availability of its preliminary TSD for the
Distribution Transformer Energy Conservation Standards Rulemaking,
wherein DOE discussed and received comments on issues such as equipment
classes of distribution transformers that DOE would analyze in
consideration of amending the energy conservation standards for
distribution transformers, the analytical framework, models and tools
it is using to evaluate potential standards, the results of its
preliminary analysis, and potential standard levels. 76 FR 11396. The
notice is available on the above-referenced DOE Web site. To expedite
the rulemaking process, DOE began at the preliminary analysis stage
because it believes that many of the same methodologies and data
sources that were used during the 2007 rulemaking rule remain valid. On
April 5, 2011, DOE held a public meeting to discuss the preliminary
TSD. Representatives of manufacturers, trade associations, electric
utilities, energy conservation organizations, Federal regulators, and
other interested parties attended this meeting. In addition, other
interested parties submitted written comments about the TSD addressing
a range of issues. These comments are discussed in the following
sections of the NOPR.
On July 29, 2011, DOE published in the Federal Register a notice of
intent to establish a subcommittee under the Energy Efficiency and
Renewable Energy Advisory Committee (ERAC), in accordance with the
Federal Advisory Committee Act and the Negotiated Rulemaking Act, to
negotiate proposed Federal standards for the energy efficiency of
medium-voltage dry-type and liquid immersed distribution transformers.
76 FR 45471. Stakeholders strongly supported a consensual rulemaking
effort. DOE believed that, in this case, a negotiated rulemaking would
result in a better informed NOPR and would minimize any potential
negative impact of the NOPR. On August 12, 2011, DOE published in the
Federal Register a similar notice of intent to negotiate proposed
Federal standards for the energy efficiency of low-voltage dry-type
distribution transformers. 76 FR 50148. The purpose of the subcommittee
was to discuss and, if possible, reach consensus on a proposed rule for
the energy efficiency of distribution transformers.
The ERAC subcommittee for medium-voltage liquid-immersed and dry-
type distribution transformers consisted of representatives of parties
having a defined stake in the outcome of the proposed standards, listed
below.
ABB Inc.
AK Steel Corporation
American Council for an Energy-Efficient Economy
American Public Power Association
Appliance Standards Awareness Project
ATI-Allegheny Ludlum
Baltimore Gas and Electric
Cooper Power Systems
Earthjustice
Edison Electric Institute
Fayetteville Public Works Commission
Federal Pacific Company
Howard Industries Inc.
LakeView Metals
Efficiency and Renewables Advisory Committee member
Metglas, Inc.
National Electrical Manufacturers Association
National Resources Defense Council
National Rural Electric Cooperative Association
Northwest Power and Conservation Council
Pacific Gas and Electric Company
Progress Energy
Prolec GE
U.S. Department of Energy
The ERAC subcommittee for medium-voltage liquid-immersed and dry-
type distribution transformers held meetings on September 15 through
16, 2011, October 12 through 13, 2011, November 8 through 9, 2011, and
November 30 through December 1, 2011; the ERAC subcommittee also held
public webinars on November 17 and December 14. During the course of
the September 15, 2011, meeting, the subcommittee agreed to its rules
of procedure, ratified its schedule of the remaining meetings, and
defined the procedural meaning of consensus. The subcommittee defined
consensus as unanimous agreement from all present subcommittee members.
Subcommittee members were allowed to abstain from voting for an
efficiency level; their votes counted neither toward nor against the
consensus.
DOE presented its draft engineering, life-cycle cost and national
impacts analysis and results. During the meetings of October 12 through
13, 2011, DOE presented its revised analysis and heard from
subcommittee members on a number of topics. During the meetings on
November 8 through 9, 2011, DOE presented its revised analysis,
including life-cycle cost sensitivities based on exclusion ZDMH and
amorphous steel as core materials. During the meetings on November 30
through December 1, 2011, DOE presented its revised analysis based on
2011 core-material prices.
At the conclusion of the final meeting, subcommittee members
presented their efficiency level recommendations. For medium-voltage
liquid-immersed distribution transformers, the advocates, represented
by the Appliance Standards Awareness Project (ASAP), recommended
efficiency level (also referred to as ``EL'') 3 for all design lines
(also referred to as ``DLs''). The National Electrical Manufacturers
Association (NEMA) and AK Steel recommended EL 1 for all DLs except for
DL 2, for which no change from the current standard was recommended.
Edison Electric Institute (EEI) and ATI Allegheny Ludlum recommended
EL1 for DLs 1, 3, and 4 and no change from the current standard or a
proposed standard of less
[[Page 7293]]
than EL 1 for DLs 2 and 5. Therefore, the subcommittee did not arrive
at consensus regarding proposed standard levels for medium-voltage
liquid-immersed distribution transformers.
For medium-voltage dry-type distribution transformers, the
subcommittee arrived at consensus and recommended a proposed standard
of EL2 for DLs 11 and 12, from which the proposed standards for DLs 9,
10, 13A, 13B would be scaled. Transcripts of the subcommittee meetings
and all data and materials presented at the subcommittee meetings are
available at the DOE Web site at: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html.
The ERAC subcommittee held meetings on September 28, 2011, October
13-14, 2011, November 9, 2011, and December 1-2, 2011, for low-voltage
distribution transformers. The ERAC subcommittee also held webinars on
November 21, 2011, and December 20, 2011. During the course of the
September 28, 2011, meeting, the subcommittee agreed to its rules of
procedure, finalized the schedule of the remaining meetings, and
defined the procedural meaning of consensus. The subcommittee defined
consensus as unanimous agreement from all present subcommittee members.
Subcommittee members were allowed to abstain from voting for an
efficiency level; their votes counted neither toward nor against the
consensus.
The ERAC subcommittee for low-voltage distribution transformers
consisted of representatives of parties having a defined stake in the
outcome of the proposed standards.
AK Steel Corporation
American Council for an Energy-Efficient Economy
Appliance Standards Awareness Project
ATI-Allegheny Ludlum
EarthJustice
Eaton Corporation
Federal Pacific Company
Lakeview Metals
Efficiency and Renewables Advisory Committee member
Metglas, Inc.
National Electrical Manufacturers Association
Natural Resources Defense Council
ONYX Power
Pacific Gas and Electric Company
Schneider Electric
U.S. Department of Energy
DOE presented its draft engineering, life-cycle cost and national
impacts analysis and results. During the meetings of October 14, 2011,
DOE presented its revised analysis and heard from subcommittee members
on various topics. During the meetings of November 9, 2011, DOE
presented its revised analysis. During the meetings of December 1,
2011, DOE presented its revised analysis based on 2011 core-material
prices.
At the conclusion of the final meeting, subcommittee members
presented their energy efficiency level recommendations. For low-
voltage dry-type distribution transformers, the advocates, represented
by ASAP, recommended EL4 for all DLs, NEMA recommended EL 2 for DLs 7
and 8, and no change from the current standard for DL 6. EEI, AK Steel
and ATI Allegheny Ludlum recommended EL 1 for DLs 7 and 8, and no
change from the current standard for DL 6. The subcommittee did not
arrive at consensus regarding a proposed standard for low-voltage dry-
type distribution transformers. Transcripts of the subcommittee
meetings and all data and materials presented at the subcommittee
meetings are available at the DOE Web site at: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html.
III. General Discussion
A. Test Procedures
Section 7(c) of the Process Rule \15\ indicates that DOE will issue
a final test procedure, if one is needed, prior to issuing a proposed
rule for energy conservation standards. DOE published its test
procedure for distribution transformers in the Federal Register as a
final rule on April 27, 2006. 71 FR 24972.
---------------------------------------------------------------------------
\15\ The Process Rule provides guidance on how DOE conducts its
energy conservation standards rulemakings, including the analytical
steps and sequencing of rulemaking stages (such as test procedures
and energy conservation standards). (10 CFR part 430, Subpart C,
Appendix A).
---------------------------------------------------------------------------
1. General
Currently, DOE requires distribution transformers to comply with
standards with their windings in the configuration that produces the
greatest losses. (10 CFR 431, Subpart K, Appendix A) During the April
5, 2011, public meeting, DOE addressed issues and solicited comments
about amending the energy conservation standards for distribution
transformers, the analytical framework and results of its preliminary
analysis, and potential energy efficiency standards. At the outset, DOE
proposed to amend the test procedure under appendix A to subpart K of
10 CFR part 431, Uniform Test Method for Measuring the Energy
Consumption of Distribution Transformers. DOE proposed to allow
compliance testing in any secondary configuration and at the lowest
basic impulse level (BIL) rating and to require compliance at the
lowest BIL at which dual or multiple voltage distribution transformers
are rated to operate.
The Northwest Power and Conservation Council (NPCC) and Northwest
Energy Efficiency Alliance (NEEA) \16\ jointly submitted comments that
the test procedure should adhere to specifications that do not make it
difficult for the most challenging designs to comply with the standard,
or else these transformer designs may be eliminated from the
marketplace. (NPCC/NEEA, No. 11 at p. 2) \17\ NPCC and NEEA further
noted that they would support a change to allow manufacturers to test
at a single voltage for models with a range of voltage taps that is
5 percent, using the middle voltage of that range. (NPCC/
NEEA, No. 11 at p. 3) Finally, NPCC and NEEA requested that DOE
explicitly explain the benefit of any changes to the test procedure,
since certain changes could make future and past ratings more difficult
to consistently compare. (NPCC/NEEA, No. 11 at p. 3)
---------------------------------------------------------------------------
\16\ The Northwest Power and Conservation Council (NPCC) and
Northwest Energy Efficiency Alliance (NEEA) submitted joint comments
and are hereinafter referred to as NPCC/NEEA.
\17\ This short-hand citation format is used throughout this
document. For example: ``(NPCC/NEEA, No. 11 at p. 2)'' refers to a
(1) a joint statement that was submitted by NPCC and NEEA and is
recorded at http://www.regulations.gov/#!home in the docket under
``Energy Conservation Standards for Distribution Transformers,''
Docket Number EERE-2010-BT-STD-0048, as comment number 11; and (2) a
passage that appears on page 2 of that statement.
---------------------------------------------------------------------------
NEMA commented that distribution transformers are rated to operate
at multiple kilovolt ampere (kVA) ratings corresponding to passive
cooling, active cooling, or a combination of both. NEMA stated that the
regulation should clarify that transformers with multiple kVA ratings
should comply at the base rating (passive cooling). (NEMA, No. 13 at
pp. 2-3)
Although DOE does not intend to eliminate features offering unique
utility from the marketplace, it wishes to gather more information on
the specific efficiency differences between winding configurations as
well as the relative frequencies of their uses. With this in mind and
considering the comments, DOE proposes to continue requiring compliance
testing in the primary and secondary winding configuration with the
highest losses, as is currently required under appendix A to subpart K
of 10 CFR part 431. DOE agrees that passive cooling is the most common
[[Page 7294]]
mode of operation for distribution transformers employed in power
distribution and clarifies that manufacturers are only required to
demonstrate compliance at kVA ratings that correspond to passive
cooling.\18\
---------------------------------------------------------------------------
\18\ Passive cooling is cooling that does not require fans,
pumps, or other energy-consuming means of increasing thermal
convection.
---------------------------------------------------------------------------
DOE requests comment and corroborating data on how often
distribution transformers are operated with their primary and secondary
windings in different configurations, and on the magnitude of the
additional losses in less efficient configurations.
2. Multiple kVA Ratings
Currently, DOE is nonspecific on which kVA rating should be used to
assess compliance in the case of distribution transformers with more
than one kVA.
ABB's recommendations on transformers with multiple kVA ratings
depended on how the transformer was cooled. For naturally-cooled
transformers, ABB recommended that they should be required to meet the
efficiency standard for every kVA rating. However, ABB suggested that
forced-cooled transformers should only have to meet the efficiency
standard at the naturally-cooled kVA rating. This is because the
forced-cooled rating, which is meant only for temporary overload
conditions, is dependent on the operation of auxiliary cooling fans
that have a lower operating life than the transformer. (ABB, No. 14 at
pp. 3-5)
DOE has received nearly unanimous feedback that transformers in
distribution applications are seldom designed to rely on active cooling
even occasionally and that the majority of designs lack active cooling
altogether. DOE wishes to clarify that manufacturers are only required
to demonstrate compliance at kVA ratings that correspond to passive
cooling.
3. Dual/Multiple-Voltage Basic Impulse Level
Currently, DOE requires distribution transformers to comply with
standards using the BIL rating of the winding configuration that
produces the greatest losses. (10 CFR 431, Subpart K, Appendix A)
Several stakeholders commented that distribution transformers with
multiple BIL ratings should comply with the efficiency based on the
highest BIL rating, as the transformer core is based on the highest BIL
rating. (Hammond (HPS), No. 3 at p. 1; NEMA, No. 13 at p. 2; and FPT,
No. 27 at p. 13) NEMA noted that for dual/multiple distribution
transformers with varying BIL levels, DOE should align its requirements
with those of the Institute of Electrical and Electronics Engineers
(IEEE) standards (C57.12.00 for liquid-filled, NEMA ST20-1992:3.3 for
low-voltage) and require testing in the ``as shipped'' condition, which
would base the efficiency on the highest BIL rating, matching IEEE and
industry practice. (NEMA, No. 13 at p. 2) Federal Pacific Transformers
(FPT) stated that medium-voltage distribution transformers with
multiple configurations should be held to the efficiency standard of
the configuration with the highest BIL rating because the distribution
transformer is required to be much larger for the higher BIL rating
and, therefore, cannot reasonably meet the energy efficiency level of
the lower BIL rating. (FPT, No. 27 at p. 13) FPT also expressed their
support for testing on the highest BIL efficiency rating for re-
connectable distribution transformers. (FPT, Pub. Mtg. Tr., No. 34 at
p. 40) \19\
---------------------------------------------------------------------------
\19\ This short-hand citation format for the public meeting
transcript is used throughout this document. For example: ``(FPT,
Pub. Mtg. Tr., No. 34 at p. 40)'' refers to a comment on the page
number of the transcript of the ``Public Meeting on Energy
Conservation Standard Preliminary Analysis for Distribution
Transformers,'' held in Washington, DC, April 5, 2011.
---------------------------------------------------------------------------
ABB commented that DOE should not change the test requirement to
allow compliance at the lowest BIL rating. According to ABB, there is
no way to ascertain which operating condition a distribution
transformer will use over its lifetime. ABB stated that DOE should
require that the efficiency be met on any operational configuration for
which the distribution transformer is designed for continuous
operation. (ABB, No. 14 at p. 2)
DOE needs to gather more information in order to be certain that
allowing compliance at any BIL rating would not result in lowered
energy savings relative to what is predicted by DOE's analysis. DOE
proposes to maintain the current requirement to comply in the
configuration that gives rise to the greatest losses.
4. Dual/Multiple-Voltage Primary Windings
Currently, DOE requires manufacturers to comply with energy
conservation standards with distribution transformer primary windings
(``primaries'') in the configuration that produces the highest losses.
(10 CFR 431, Subpart K, Appendix A)
Where DOE invited additional comments about the test procedures,
Howard Industries added that, under the presumption that DOE would
allow compliance testing in any of the secondary configurations
(``secondaries''), DOE should insert the word ``primary'' into the
testing requirements [at section 5.0, Determining the Efficiency Value
of the Transformer, under appendix A to subpart K of 10 CFR part 431],
and require the manufacturer to ``determine the basic model's
efficiency at the `primary' voltage at which the highest losses occur
or at each `primary' voltage at which the distribution transformer is
rated to operate.'' Howard Industries noted that, for multiple-voltage
distribution transformers, this insertion would clarify that
distribution transformer efficiency is determined by the primary
voltage and that the low-voltage or secondary winding configuration
that is used would be at the manufacturer's discretion. (HI, No. 23 at
p. 2)
HVOLT commented that distribution transformers with dual or
multiple-voltage primary windings should be allowed to comply while the
primaries are connected in series. HVOLT explained that utilities
purchase these transformers to upgrade a distribution circuit to higher
voltages within a few years of purchase and that these transformers
will spend more than 90 percent of their lives with the primary
windings connected in series. (HVOLT, No. 33 at p. 2)
DOE understands that, in contrast to the secondary windings,
reconfigurable primaries typically exhibit a larger variation in
efficiency between series and primary connections. As the above
commenters have pointed out, however, such transformers are often
purchased with the intent of upgrading the local power grid to a higher
operating voltage with lowered overall system losses. In that sense,
transformers with reconfigurable primaries can be seen as a stepping
stone toward greater overall energy savings, even if those savings do
not occur within the transformer itself.
DOE conducted several sensitivity analyses to examine the effects
of a reconfigurable primary winding on efficiency and found that the
difference between the efficiency of the secondary and the efficiency
of the primary was more significant than in the case of configurable
secondary windings.
DOE wishes to obtain more information on both the difference in
losses between different winding configurations as well as the
different configurations' relative frequency of operation in practice.
DOE requests comment on this proposal to continue to mandate compliance
in the highest-loss configuration and data illustrating the
[[Page 7295]]
efficiency differences between primary winding configurations.
5. Dual/Multiple-Voltage Secondary Windings
Currently, DOE requires transformers to comply with their secondary
windings in the configuration that produces the greatest losses. (10
CFR 431, Subpart K, Appendix A)
Interested parties commented that DOE should not change the current
test requirement to permit compliance testing in any secondary
configuration at the lowest BIL rating for transformers with dual/
multiple-voltage secondary windings, and that these transformers should
comply with an energy efficiency level using the combination of
connections that produces the highest losses. (HPS, No. 3 at p.1; NPCC/
NEEA, No. 11 at p. 3; and ABB, No. 14 at p. 2) ABB also noted that
there is no way to determine the connection on which a unit will be
operated over its lifetime.
Schneider Electric (SE) commented that NEMA ST20-1992: 3.3 [Dry-
Type Transformers for General Applications, NEMA ST 20-1992(R1997)]
requires that ``low-voltage [transformers] be shipped with the
connections done for the highest voltage'' and requested that ``all
compliance testing be done in the configuration requirement of ST-20.''
(SE., No. 18 at p. 5) Similarly, NEMA commented that ``DOE should align
its requirements with those of IEEE standards (C57.12.00 for liquid-
filled, NEMA ST 20-1992: 3.3 for low-voltage), requiring testing in the
'as shipped' condition.'' (NEMA, No. 13 at p. 2) Further, NEMA noted
that industry practice is to ship these units in the series connection.
Similarly, FPT asserted that, ``for units with multiple (series-
parallel) low-voltage ratings, the efficiency standard should be based
on the highest voltage (series) connection, which matches the IEEE
standard and industry practice.'' (FPT, No. 27 at p. 11)
Several interested parties expressed support for DOE's proposal to
allow compliance testing in any secondary configuration at the lowest
voltage rating. (Power Partners, Inc. (PP), Pub. Mtg. Tr., No. 34 at p.
40; HVOLT, No. 33 at p. 2; HI, No. 23 at p.2; and PP, No. 19 at p. 2)
HVOLT noted that about 99 percent of dual/multiple-voltage single-
phase, pole-type transformers are used in the series connection, and
the work to otherwise reconnect to the secondary is burdensome. (HVOLT,
No. 33 at p.2) Similarly, HI pointed out that very few transformers are
ever reconnected for parallel operation and that testing requirements
in a parallel configuration can be burdensome. (HI, No. 23 at p. 2)
Furthermore, HVOLT commented that a distribution transformer that
is designed for a dual voltage rating does not have an even multiple
quantity of series connections compared to parallel connection designs.
This means that there are already unused windings that will be in the
parallel connection. Because the testing procedure requires that they
be tested on the lowest BIL connections, these types of distribution
transformers effectively have a higher efficiency requirement. HVOLT
believes dual voltage distribution transformers are being unduly
burdened by the test procedure. (HVOLT, Pub. Mtg. Tr., No. 34 at pp.
38-39)
HI recommended that DOE adjust the efficiency value by 0.1 for
dual/multiple-voltage liquid-immersed distribution transformers with
windings having a ratio other than 2:1, due to the complexity of the
winding for these distribution transformers. HI noted that a similar
approach was taken by the Canadian Standards Associations Standards.
(HI, No. 23 at p. 2)
DOE understands that some distribution transformers may be shipped
with reconfigurable secondary windings, and that certain configurations
may have different efficiencies. Currently, DOE requires distribution
transformers to be tested in the configuration that exhibits the
highest losses, which is usually with the secondary windings in
parallel. Whereas the IEEE Standard \20\ requires a distribution
transformer to be shipped with the windings in series, a manufacturer
testing for compliance could need to test the distribution transformer
for energy efficiency, disassemble the unit, reconfigure the windings,
and reassemble the unit for shipping at added time and expense.
Nonetheless, DOE would need to obtain more specific information on the
potential net energy losses associated with permitting distribution
transformers to be tested in any secondary winding configuration and
proposes to maintain the current requirement of compliance in the
configuration that produces the greatest losses.
---------------------------------------------------------------------------
\20\ IEEE C57.12.00.
---------------------------------------------------------------------------
DOE requests comment on secondary winding configurations, and on
the magnitude of the additional losses associated with the less
efficient configurations as well as the relative frequencies of
operation in each winding configuration.
6. Loading
Currently, DOE requires that both liquid-immersed and medium-
voltage, dry-type distribution transformers comply with standards at 50
percent loading and that low-voltage, dry-type distribution
transformers comply at 35 percent loading.
Warner Power (WP) commented that a single 35 percent test load for
low-voltage dry-type distribution transformers (LVDTs) does not
adequately reflect known service conditions at widely varying, and
often low, average loads. It cited several studies indicating a lower
average load factor and a shrinking load factor and recommended LVDTs
be certified at 15 percent and 35 percent loading. (WP, No. 30 at pp.
1-2) In addition, Warner Power suggested that a weighted curve between
10 percent and 80 percent load factors would be better than a single 35
percent load factor. It recommended using published data to more
accurately reflect real load conditions, accounting for daily, weekly,
and seasonal variations. For LVDT transformers, it pointed out that the
load profile should characterize the typical use in different types of
buildings. (WP, No. 30 at p.5) NPCC and NEEA opined that, with better
loading data for distribution transformers, they would support testing
at multiple loading points, such as 15, 35, 50 and 70 percent, with a
weighted-average calculation that is unique to each class. They noted,
however, that such data is likely not available. (NPCC/NEEA, No. 11 at
pp. 2-3)
HVOLT commented that the test procedure-required load values for
all three categories of distribution transformers appeared reasonable
for the foreseeable future. Otherwise, with electric vehicles and plug-
in hybrids entering the market, HVOLT opined that root-mean-square
loading will increase in the long-term but may take decades to have an
effect. (HVOLT, No. 33 at p. 1) NPCC and NEEA announced that they are
collecting additional field data to inform the appropriateness of the
test procedure loading points. (NPCC/NEEA, No. 11 at p. 2)
NEMA, ABB, and Schneider Electric (SE) all commented that DOE
should not modify its test procedures by considering weighted-average
loadings for core deactivation efficiency standards. (NEMA, No. 13 at
p. 2; ABB, No. 14 at pp. 2-3; and SE., Pub. Mtg. Tr., No. 34 at p. 57)
ABB further clarified that this approach would be inaccurate because
the true load varies by every distinct installation. Instead, it
asserted that the current load factors are more appropriate because
they reflect the aggregate impact on the national grid. (ABB, No. 14 at
pp. 2-3)
[[Page 7296]]
NPCC and NEEA recommended that DOE attempt to gather data on actual
core deactivation designs and control algorithms before it changes the
test procedure. Additionally, NPCC and NEEA suggested that DOE gather
data on the performance of distribution transformers under various load
conditions. If this data is unavailable or inconclusive, they suggested
that DOE not change the test procedure at this time but rather ensure
that core deactivation technology is examined in the next rulemaking
for distribution transformers. (NPCC/NEEA, No. 11 at p. 3)
Warner Power (WP) indicated its intent to submit data concerning
modified test procedures which would better capture core deactivation
technologies. (WP, Pub. Mtg. Tr., No. 34 at p. 42)
DOE is proposing to maintain the use of a single, discrete loading
point for distribution transformers because the use of weighted-average
loadings would represent a fairly significant change in the test
procedure, possibly causing some units that meet energy conservation
standards to no longer do so. In the future, DOE may consider modifying
this approach. DOE welcomes relevant data in conjunction with comments
on typical distribution transformer loading profiles.
B. Technological Feasibility
1. General
There are distribution transformers available at all of the energy
efficiency levels considered in today's notice of proposed rulemaking.
Therefore, DOE believes all of the energy efficiency levels adopted by
today's notice of proposed rulemaking are technologically feasible.
2. Maximum Technologically Feasible Levels
When DOE proposes to adopt, or decline to adopt, an amended or new
standard for a type of covered product, section 325(o)(2) of EPCA, 42
U.S.C. 6295(o)(2), requires that DOE determine the maximum improvement
in energy efficiency or maximum reduction in energy use that is
technologically feasible. While developing the energy conservation
standards for liquid-immersed and medium-voltage, dry-type distribution
transformers that were codified under 10 CFR 431.196, DOE determined
the maximum technologically feasible (``max-tech'') energy efficiency
level through its engineering analysis using the most efficient
materials, such as core steels and winding materials, and applied
design parameters that drove distribution transformer software to
create designs at the highest efficiencies achievable at the time. 71
FR 44362 (August 4, 2006) and 72 FR 58196 (October 12, 2007). DOE used
these designs to establish max-tech levels for its LCC analysis and
scaled them to other kVA ratings within a given design line, thereby
establishing max-tech efficiencies for all the distribution transformer
kVA ratings.
C. Energy Savings
1. Determination of Savings
Section 325(o)(2)(A) of EPCA, 42 U.S.C. 6295(o)(2)(A), requires
that any new or amended standard must be chosen so as to achieve the
maximum improvement in energy efficiency that is technologically
feasible and economically justified. In determining whether economic
justification exists, key factors include the total projected amount of
energy savings likely to result directly from the standard and the
savings in operating costs throughout the estimated average life of the
covered equipment. To understand the national economic impact of
potential efficiency regulations for distribution transformers, DOE
conducted a national impact analysis (NIA) using a spreadsheet model to
estimate future national energy savings (NES) from amended energy
conservation standards.\21\ For each TSL, DOE forecasted energy savings
beginning in 2016, the year that manufacturers would be required to
comply with amended standards, and ending in 2045. DOE quantified the
energy savings for each TSL as the difference in energy consumption
between the ``standards case'' and the ``base case.'' The base case
represents the forecast of energy consumption in the absence of amended
mandatory efficiency standards, and takes into consideration market
demand for more-efficient equipment.
---------------------------------------------------------------------------
\21\ The NIA spreadsheet model is described in section IV.G of
this notice.
---------------------------------------------------------------------------
The NIA spreadsheet model calculates the electricity savings in
``site energy'' expressed in kilowatt-hours (kWh). Site energy is the
energy directly consumed by distribution transformer products at the
locations where they are used. DOE reports national energy savings on
an annual basis in terms of the aggregated source (primary) energy
savings, which is the savings in the energy that is used to generate
and transmit the site energy. (See TSD chapter 10.) To convert site
energy to source energy, DOE derived annual conversion factors from the
model used to prepare the Energy Information Administration's (EIA)
Annual Energy Outlook 2011 (AEO2011).
2. Significance of Savings
As noted above, 42 U.S.C. 6295(o)(3)(B) prevents DOE from adopting
a standard for covered equipment if such a standard would not result in
``significant'' energy savings. While EPCA does not define the term
``significant,'' the U.S. Court of Appeals for the District of
Columbia, in Natural Resources Defense Council v. Herrington, 768 F.2d
1355, 1373 (D.C. Cir. 1985), indicated that Congress intended
``significant'' energy savings in this context to be savings that were
not ``genuinely trivial.'' The energy savings for all of the TSLs
considered in this rulemaking are non-trivial and, therefore, DOE
considers them ``significant'' within the meaning of EPCA section
325(o).
D. Economic Justification
1. Specific Criteria
As noted previously, EPCA requires DOE to evaluate seven factors to
determine whether a potential energy conservation standard is
economically justified. (42 U.S.C. 6295(o)(2)(B)(i)) The following
sections describe how DOE has addressed each of the seven factors in
this rulemaking.
a. Economic Impact on Manufacturers and Consumers
In determining the impacts of an amended standard on manufacturers,
DOE first determines the quantitative impacts using an annual cash-flow
approach. This includes both a short-term assessment, based on the cost
and capital requirements during the period between the issuance of a
regulation and when entities must comply with the regulation, and a
long-term assessment over a 30-year analysis period. The industry-wide
impacts analyzed include INPV (which values the industry on the basis
of expected future cash flows), cash flows by year, changes in revenue
and income, and other measures of impact, as appropriate. Second, DOE
analyzes and reports the impacts on different types of manufacturers,
paying particular attention to impacts on small manufacturers. Third,
DOE considers the impact of standards on domestic manufacturer
employment and manufacturing capacity, as well as the potential for
standards to result in plant closures and loss of capital investment.
Finally, DOE takes into account cumulative impacts of different DOE
regulations and other regulatory requirements on manufacturers.
[[Page 7297]]
For individual consumers, measures of economic impact include the
changes in LCC and the PBP associated with new or amended standards.
The LCC, which is separately specified in EPCA as one of the seven
factors to be considered in determining the economic justification for
a new or amended standard (42 U.S.C. 6295(o)(2)(B)(i)(II)), is
discussed in the following section. For consumers in the aggregate, DOE
also calculates the national net present value of the economic impacts
on consumers over the forecast period used in a particular rulemaking.
Federal Pacific suggested that DOE establish reference efficiencies
by rating, as defined by NEMA Premium, for those users who want
efficiencies higher than current minimum efficiencies. However, they
did not want these reference efficiencies to become the new minimum
efficiency mandates. (FPT, No. 27 at p. 2)
The National Rural Electric Cooperative Association (NRECA)
recommended that DOE not raise the efficiency standards for the liquid-
filled distribution transformers, since many rural utilities with low
distribution transformer loads cannot economically justify the current
energy efficiency level. (NRECA, No. 31 and 36 at p. 1)
DOE appreciates the comments and considers impacts to consumers,
manufacturers, and utilities in TSD chapters 8, 12, and 14,
respectively. DOE welcomes comment on these analyses and on any subset
of consumers, manufacturers, or utilities that could be
disproportionately affected.
b. Life-Cycle Costs
The LCC is the sum of the purchase price of a type of equipment
(including its installation) and the operating expense (including
energy and maintenance and repair expenditures) discounted over the
lifetime of the product. The LCC savings for the considered energy
efficiency levels are calculated relative to a base case that reflects
likely trends in the absence of amended standards. The LCC analysis
requires a variety of inputs, such as equipment prices, equipment
energy consumption, energy prices, maintenance and repair costs,
equipment lifetime, and consumer discount rates. DOE assumed in its
analysis that consumers will purchase the considered equipment in 2016.
To account for uncertainty and variability in specific inputs, such
as product lifetime and discount rate, DOE uses a distribution of
values with probabilities attached to each value. A distinct advantage
of this approach is that DOE can identify the percentage of consumers
estimated to receive LCC savings or experience an LCC increase, in
addition to the average LCC savings associated with a particular
standard level. In addition to identifying ranges of impacts, DOE
evaluates the LCC impacts of potential standards on identifiable
subgroups of consumers that may be disproportionately affected by a
national standard.
c. Energy Savings
While significant conservation of energy is a separate statutory
requirement for imposing an energy conservation standard, EPCA requires
DOE, in determining the economic justification of a standard, to
consider the total projected energy savings that are expected to result
directly from the standard. (42 U.S.C. 6295(o)(2)(B)(i)(III)) DOE uses
the NIA spreadsheet results in its consideration of total projected
energy savings.
d. Lessening of Utility or Performance of Products
In establishing classes of products, and in evaluating design
options and the impact of potential standard levels, DOE sought to
develop standards for distribution transformers that would not lessen
the utility or performance of these products. (42 U.S.C.
6295(o)(2)(B)(i)(IV)) None of the TSLs presented in today's NOPR would
substantially reduce the utility or performance of the equipment under
consideration in the rulemaking.
DOE requests comment on the possibility of reduced equipment
performance or utility resulting from today's proposed standards,
particularly the risk of reducing the ability to perform periodic
maintenance and the risk of increasing vibration and acoustic noise.
e. Impact of Any Lessening of Competition
EPCA directs DOE to consider any lessening of competition that is
likely to result from standards. It also directs the Attorney General
of the United States (Attorney General) to determine the impact, if
any, of any lessening of competition likely to result from a proposed
standard and to transmit such determination to the Secretary within 60
days of the publication of a proposed rule, together with an analysis
of the nature and extent of the impact. (42 U.S.C. 6295(o)(2)(B)(i)(V)
and (B)(ii)) DOE will transmit a copy of today's proposed rule to the
Attorney General with a request that the Department of Justice (DOJ)
provide its determination on this issue. DOE will address the Attorney
General's determination in the final rule.
f. Need for National Energy Conservation
Certain benefits of the proposed standards are likely to be
reflected in improvements to the security and reliability of the
Nation's energy system. Reductions in the demand for electricity may
also result in reduced costs for maintaining the reliability of the
Nation's electricity system. DOE conducts a utility impact analysis to
estimate how standards may affect the Nation's needed power generation
capacity. (See 42 U.S.C. 6295(o)(2)(B)(i)(VI))
Energy savings from the proposed standards are also likely to
result in environmental benefits in the form of reduced emissions of
air pollutants and greenhouse gases associated with energy production.
DOE reports the environmental effects from the proposed standards, and
from each TSL it considered, in the environmental assessment contained
in chapter 15 in the NOPR TSD. DOE also reports estimates of the
economic value of emissions reductions resulting from the considered
TSLs.
g. Other Factors
EPCA allows the Secretary of Energy, in determining whether a
standard is economically justified, to consider any other factors that
the Secretary considers relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) In
developing the proposals of this notice, DOE has also considered the
matter of electrical steel availability. This factor is discussed
further in section V.B.8.
2. Rebuttable Presumption
As set forth in 42 U.S.C. 6295(o)(2)(B)(iii), EPCA creates a
rebuttable presumption that an energy conservation standard is
economically justified if the additional cost to the consumer of a
product that meets the standard is less than three times the value of
the first-year of energy savings resulting from the standard, as
calculated under the applicable DOE test procedure. DOE's LCC and
payback period (PBP) analyses generate values used to calculate the PBP
for consumers of potential amended energy conservation standards. These
analyses include, but are not limited to, the three-year PBP
contemplated under the rebuttable presumption test. However, DOE
routinely conducts an economic analysis that considers the full range
of impacts to the consumer, manufacturer, Nation, and environment, as
required under 42 U.S.C. 6295(o)(2)(B)(i). The
[[Page 7298]]
results of this analysis serve as the basis for DOE to definitively
evaluate the economic justification for a potential standard level
(thereby supporting or rebutting the results of any preliminary
determination of economic justification). The rebuttable presumption
payback calculation is discussed in section V.B.1.c of this NOPR and
chapter 8 of the NOPR TSD.
IV. Methodology and Discussion of Related Comments
DOE used two spreadsheet tools to estimate the impact of today's
proposed standards. The first spreadsheet calculates LCCs and PBPs of
potential new energy conservation standards. The second provides
shipments forecasts and calculates national energy savings and net
present value impacts of potential new energy conservation standards.
DOE also assessed manufacturer impacts, largely through use of the
Government Regulatory Impact Model (GRIM). The two spreadsheets are
available online at the rulemaking Web site: http://www1.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html.
Additionally, DOE estimated the impacts of energy conservation
standards for distribution transformers on utilities and the
environment. DOE used a version of EIA's National Energy Modeling
System (NEMS) for the utility and environmental analyses. The NEMS
model simulates the energy sector of the U.S. economy. EIA uses NEMS to
prepare its Annual Energy Outlook (AEO), a widely known energy forecast
for the United States. The version of NEMS used for appliance standards
analysis is called NEMS-BT \22\ and is based on the AEO version with
minor modifications.\23\ The NEMS-BT offers a sophisticated picture of
the effect of standards because it accounts for the interactions
between the various energy supply and demand sectors and the economy as
a whole.
---------------------------------------------------------------------------
\22\ BT stands for DOE's Building Technologies Program.
\23\ The EIA allows the use of the name ``NEMS'' to describe
only an AEO version of the model without any modification to code or
data. Because the present analysis entails some minor code
modifications and runs the model under various policy scenarios that
deviate from AEO assumptions, the name ``NEMS-BT'' refers to the
model as used here. For more information on NEMS, refer to The
National Energy Modeling System: An Overview, DOE/EIA-0581 (98)
(Feb.1998), available at: http://tonto.eia.doe.gov/FTPROOT/forecasting/058198.pdf.
---------------------------------------------------------------------------
A. Market and Technology Assessment
For the market and technology assessment, DOE develops information
that provides an overall picture of the market for the products
concerned, including the purpose of the products, the industry
structure, and market characteristics. This activity includes both
quantitative and qualitative assessments, based primarily on publicly
available information. The subjects addressed in the market and
technology assessment for this rulemaking include scope of coverage,
definitions, equipment classes, types of products sold and offered for
sale, and technology options that could improve the energy efficiency
of the products under examination. Chapter 3 of the TSD contains
additional discussion of the market and technology assessment.
1. Scope of Coverage
This section addresses the scope of coverage for today's proposal,
stating which products would be subject to amended standards. The
numerous comments DOE received on the scope of today's proposal are
also summarized and addressed in this section.
a. Definitions
Today's proposed standards rulemaking concerns distribution
transformers, which include three categories: liquid-immersed, low-
voltage dry-type (LVDT) and medium-voltage dry-type (MVDT). The
definition of a distribution transformer was presented in EPACT 2005
and then further refined by DOE when it was codified into 10 CFR
431.192 by the April 27, 2006 final rule for distribution transformer
test procedures (71 FR 24995) as follows:
Distribution transformer means a transformer that--
(1) Has an input voltage of 34.5 kV or less;
(2) Has an output voltage of 600 V or less;
(3) Is rated for operation at a frequency of 60 Hz; and
(4) Has a capacity of 10 kVA to 2500 kVA for liquid-immersed units
and 15 kVA to 2500 kVA for dry-type units; but
(5) The term ``distribution transformer'' does not include a
transformer that is an--
(i) Autotransformer;
(ii) Drive (isolation) transformer;
(iii) Grounding transformer;
(iv) Machine-tool (control) transformer;
(v) Non-ventilated transformer;
(vi) Rectifier transformer;
(vii) Regulating transformer;
(viii) Sealed transformer;
(ix) Special-impedance transformer;
(x) Testing transformer;
(xi) Transformer with tap range of 20 percent or more;
(xii) Uninterruptible power supply transformer; or
(xiii) Welding transformer.
Additional detail on the definitions of each of these excluded
transformers can found in TSD chapter 3.
DOE received multiple comments seeking clarification on various
terms used in the definition of a distribution transformer. NEMA
requested that DOE amend the definitions of two transformer types
explicitly excluded from the distribution transformer definition,
namely ``rectifier transformer'' and ``testing transformer.'' NEMA
suggested that both definitions should require the nameplates of such
transformers to identify the transformers as being for such uses only.
(NEMA, No. 13 at p. 10) Furthermore, NEMA recommended that transformers
used inside underground tunneling equipment should be added to the
definition for underground mining distribution transformers because
this equipment is specialized and requires a compact transformer.
(NEMA, No. 13 at p. 10) FPT agreed with NEMA and recommended that DOE
amend the definition of ``underground mining transformer'' with the
following sentence: ``The term `mining' may also be understood to mean
underground tunneling or digging.'' FPT added that the term ``mining''
should be clarified to encompass any underground operation involving
the removal of material underground, such as digging or tunneling,
which have the same restrictions with the size of distribution
transformers, but might not be considered to be mining applications.
(FPT, No. 27 at pp. 10-11) Finally, PP commented that DOE should
clarify the definitions of input and output voltage to reflect the
three-phase system voltages and not the line to ground voltage, which
is typically the input voltage for single-phase transformers. (PP, No.
1 at p. 1)
DOE agrees that these additions to the definitions of ``rectifier
transformer'' and ``testing transformer'' are helpful in aiding the
consumer to distinguish rectifier and testing transformers and
therefore proposes to amend its definitions correspondingly.
Additionally, DOE believes that transformers used for the removal of
material underground are subject to similar space constraints as
traditional mining transformers and therefore their ability to meet
higher efficiency standards are similarly restricted. However, DOE
wishes to learn more about the nature of those applications in order to
define the units precisely. Consequently, DOE proposes to maintain the
current definition of ``mining transformer'' unless it is able to
determine that the expansion, as
[[Page 7299]]
suggested by NEMA and FPT, is warranted and able to be implemented with
sufficient specificity. DOE requests comment on that proposal and any
information useful in understanding how transformers used in certain
underground applications differ and could be defined precisely.
Finally, DOE also wishes to remove any ambiguity in the terms ``input
voltage'' and ``output voltage'' and requests comment on where that
ambiguity lies.
Multiple interested parties submitted comments regarding the kVA
ratings that are currently included in the scope of coverage. PP
commented that DOE should consider removing single-phase liquid-
immersed distribution transformers rated above 250 kVA with a low-
voltage rating of 600V from the scope of the regulation. They contended
that these transformers constitute a very low volume of shipments (481
units in 2009) and MVA capacity shipped (201 MVA in 2009) and therefore
the overall national energy savings would not be significant. (PP, No.
19 at pp. 1-3; Pub. Mtg. Tr., No. 34 at p. 34) PP added that the impact
of increased weight and dimensions is greater in these sizes where
maximum tank size and weight constraints are critical. Moreover, PP
proposed that DOE should consider 500 kVA the upper limit of kVA
ratings covered and shift the lower limit from 10 to 5 kVA. (PP, Pub.
Mtg. Tr., No. 34 at pp. 46, 73-74; PP, No. 19 at pp. 1-2) Similarly,
NPCC and NEEA urged DOE to decide whether to include single-phase
liquid-immersed distribution transformers down to 5 kVA in the scope of
coverage. (NPCC/NEEA, No. 11 at p. 9)
BBF and Associates suggested that DOE investigate increasing the
scope of the rulemaking to include transformers from 2500 kVA to 20
MVA. (BBF, Pub. Mtg. Tr., No. 34 at p. 279) CDA recommended that DOE
include transformers up to 30,000 kVA (30 MVA) in its scope, including
sub-station transformers. It noted that these units are within the
distribution system, and are substantial in unit shipment volumes.
(CDA, No. 17 at pp. 1-2, 4)
DOE understands that larger (250-833 kVA) single-phase, liquid-
immersed units are currently covered and is not proposing to exclude
them from consideration for this rulemaking. Because these ratings were
covered by the previous rulemaking for distribution transformers, DOE
is statutorily prohibited from backsliding and excluding such products
from regulation at this time. (See 42 U.S.C. 6295(o)(1)6316(a))
However, DOE notes that it is accounting for the added life-cycle costs
of larger and heavier transformers and discusses its methodology for
this in chapter 6 of the TSD. Additionally, DOE determined during the
previous standards rulemaking that 5 kVA transformers were below the
kVA limit ``commonly understood to be distribution transformers.'' 69
FR 45381. DOE proposes to maintain that stance for this rulemaking as
these units are generally too small to be employed in power
distribution and collectively consume extremely little power.
Similarly, units larger than 2.5 MVA (DOE's current upper limit) are
usually considered substation transformers, which DOE is not proposing
to cover. DOE invites comment on its proposal to maintain the current
scope of coverage.
Interested parties also solicited clarification from DOE on
transformers that are used in a variety of applications. FPT requested
that DOE clarify whether existing efficiency standards apply to
transformers used in aircraft, trains/locomotives, offshore drilling
platforms, mobile substations, ships, and other similar applications.
(FPT, No. 27 at p. 2) Furthermore, FPT recommended that DOE investigate
whether transformers being used in wind farms or solar energy
applications should be exempted since these designs should be optimized
at higher loading levels than the test procedure loading points of 35
percent (low-voltage dry-type) and 50 percent (liquid-immersed and
medium-voltage dry-type). (FPT, No. 27 at p. 2) Lastly, CDA commented
that DOE should expand the scope of the rulemaking to include step-up
transformers of kVA sizes that are currently included in the scope,
such as transformers used in wind farms. (CDA, No. 17 at pp. 2-3)
EPACT 2005 defined the term ``distribution transformer,'' 42 U.S.C.
6291(35)(B)(ii), to mean a transformer that (i) has an input voltage of
34.5 kilovolts or less; (ii) has an output voltage of 600 volts or
less; and (iii) is rated for operation at a frequency of 60 Hertz. The
definition goes on to generally exclude certain specialized-application
distribution transformers. At this time, DOE is not proposing to cover
distribution transformers used in mobile applications because they do
not represent traditional power distribution. For example, aircraft and
marine transformers frequently operate at 400 Hz, and mobile substation
transformers often fall outside the currently defined voltage and kVA
ranges. Furthermore, transformers used in mobile applications could be
unduly impacted by any increases in size and weight required to reach
higher efficiencies. DOE requests comment on the topic of transformers
used in mobile applications and any data helpful in considering whether
standards are warranted. DOE also requests comment on the likelihood of
this exclusion serving as a loophole in the face of increasing
standards.
DOE does not propose to exclude transformers used in renewable
energy applications simply because of the potential difference in
loading that they may experience. DOE currently understands that the
users who buy transformers for those applications tend to value losses
highly and that such transformers would have little trouble meeting
standards. Furthermore, DOE notes that its choices for the test
procedure loading points do not imply that it intends to exclusively
cover transformers with precisely those loading values. Rather, DOE
accounts for consumers purchasing transformers optimized for loading
values other than the test procedure value in its LCC analysis.
DOE proposes to continue to not set standards for step-up
transformers, because they are not ordinarily considered to be
performing a power distribution function. However, DOE is aware that
step-up transformers may be able to be used in place of step-down
transformers and may represent a potential loophole as standards
increase. DOE requests comment on its proposal to continue not to set
standards for step-up transformers.
Finally, DOE received an inquiry with regards to how it plans to
deal with core deactivation technology. Specifically, Schneider
Electric wanted to know if DOE would change the definition of
transformers to include banks of transformers. (SE., Pub. Mtg. Tr., No.
34 at p. 57) Core-deactivation technology employs a system of smaller
transformers to replace a single, larger transformer. For example,
using this technology, three transformers sized at 25 kVA and operated
in parallel could replace a single 75 kVA transformer. The smaller
transformers that compose the system can then be activated and
deactivated using core deactivation technology based on the loading
demand. At present, DOE is not proposing to set efficiency standards
for banks of transformers, but notes that each constituent transformer
would be subject to an efficiency standard if, on its own, it meets the
definition of a distribution transformer.
b. Underground Mining Transformer Coverage
In the October 12, 2007, final rule on energy conservation
standards for distributions transformers, DOE codified
[[Page 7300]]
into 10 CFR 431.192 the definition of an ``underground mining
distribution transformer'' as follows:
Underground mining distribution transformer means a medium-voltage
dry-type distribution transformer that is built only for installation
in an underground mine or inside equipment for use in an underground
mine, and that has a nameplate which identifies the transformer as
being for this use only. 72 FR 58239.
In that same final rule, DOE also clarified that although it
believed these transformers were within its scope of coverage, it was
not establishing any energy conservation standards for underground
mining transformers. At the time, DOE recognized that these
transformers were subject to unique and extreme dimensional constraints
which impact their efficiency and performance capabilities. Therefore,
DOE established a separate equipment class for mining transformers and
stated that it may consider energy conservation standards for such
transformers at a later date. Although DOE did not establish energy
conservation standards for such transformers, it also did not add
underground mining transformers to the list of excluded transformers in
the definition of a distribution transformer. DOE retained that it had
the authority to cover such equipment if, during a later analysis, it
found technologically feasible and economically justified energy
conservation standard levels. 72 FR 58197.
In response to the March 2, 2011 preliminary analysis, NEMA
recommended that underground mining distribution transformers,
including transformers used inside underground tunneling equipment,
should be included on the exemption list to clarify that the standards
shall not apply to them. (NEMA, No. 13 at p. 10) NPCC and NEEA
commented that DOE should remove any confusion about the coverage of
underground mining transformers either by setting standards for these
units or adding them to the list of excluded transformers. (NPCC/NEEA,
No. 11 at p. 9)
FPT urged DOE to exclude mining transformers from minimum
efficiency levels because it would result in undue economic hardship
for the mining industry and unrealistic design constraints on mining
equipment that use such transformers. FPT pointed out that mining
transformers make up a small portion of the market and that the total
amount of energy they consume is very small compared to the national
energy consumption rate. FPT also noted that a mining transformer is
more specialized in its design and application than many of the
transformers excluded from the definition of distribution transformers
under 10 CFR 431.192. (FPT, No. 27 at pp. 8-10)
In view of the above, DOE understands that underground mining
transformers are subject to a number of constraints that are not
usually concerns for transformers used in general power distribution.
Because space is critical in mines, an underground mining transformer
may be at a considerable disadvantage in meeting an efficiency
standard. Underground mining transformers are further disadvantaged by
the fact that they must supply power at several output voltages
simultaneously. For this rulemaking, DOE again proposes not to set
standards for underground mining transformers, but recognizes the
possibility of a loophole. Therefore, DOE continues to leave
underground mining transformers off of the list of exempt distribution
transformers and reserve a separate equipment class for mining
transformers. DOE may set standards in the future if it believes that
underground mining transformers are being purchased as a way to
circumvent energy conservation standards.
c. Low-Voltage Dry-Type Distribution Transformers
10 CFR 431.192 defines the term ``low-voltage dry-type distribution
transformer'' to be a distribution transformer that:
(1) Has an input voltage of 600 volts or less;
(2) Is air-cooled; and
(3) Does not use oil as a coolant.
Because EPACT 2005 prescribed standards for LVDTs, which DOE
incorporated into its regulations at 70 FR 60407 (October 18, 2005)
(codified at 10 CFR 431.196(a)), LVDTs were not included in the 2007
standards rulemaking. As a result, the settlement agreement following
the publication of the 2007 final rule does not impact LVDT standards.
Two interested parties, EEI and SE., requested clarification on
whether LVDT distribution transformers would be included in this
rulemaking. (EEI, Public Mtg. Tr., No. 34 at p. 56, 27; SE., No. 7 at
p. 1) In particular, SE questioned whether Congress would be involved
in amending standards for LVDTs. (SE., No. 7 at p. 1) Further, SE
expressed concern that there does not appear to be a timeline for the
LVDT distribution transformer rulemaking and that one is needed in
order to plan potential capital expenditures for any new efficiency
levels. (SE., Pub. Mtg. Tr., No. 34 at p. 19)
SE requested that DOE analyze LVDTs in a separate rulemaking from
liquid-immersed distribution transformers and MVDTs. It noted that the
law defines them separately and that LVDT distribution transformers are
used in applications that are different from those of MVDT distribution
transformers. SE further noted that LVDT distribution transformers may
warrant an expanded scope of coverage and encouraged DOE to reassess
the range of kVAs covered, product definitions, exemptions, and loading
points. (SE., No. 18 at p. 1) FPT suggested that DOE evaluate LVDT
distribution transformers at a later date because this product category
is not part of the court order. (FPT, No. 27 at p. 1) Rather, FPT
believed that DOE should establish non-mandatory efficiencies for LVDT
distribution transformers so that consumers who wish to purchase higher
efficiency units can have a point of reference. (FPT, No. 27 at pp. 1-
2)
CDA observed that the current efficiency levels for LVDT
distribution transformers are at NEMA TP-1 levels and that the 2010
MVDT and liquid-immersed distribution transformer efficiency levels
were set at approximately TSL 4. 72 FR 58239-40 (CDA, No. 17 at p. 3).
CDA believed that it is appropriate for DOE to evaluate and adjust the
minimum efficiency standards for LVDT distribution transformers,
wherever cost-effective, to levels that are comparable to the 2010
levels for other [MVDT and liquid-immersed] distribution transformers.
(CDA, No. 17 at p. 3) Earthjustice commented that DOE must revisit
standards for LVDT distribution transformers as part of EPCA's
requirement that standards be reevaluated not later than six years
after issuance. Earthjustice noted that, on October 18, 2005, DOE
codified the efficiency standards for LVDT distribution transformers
that were set forth in EPACT 2005 (70 FR 60407) and that DOE must now
publish, by October 18, 2011, either a new proposed standard or a
determination that amended standards are not warranted. (Earthjustice,
No. 20 at pp. 1-2) In joint comments, the Appliance Standards Awareness
Project (ASAP), American Council for an Energy Efficient Economy
(ACEEE), and Natural Resources Defense Council (NRDC) agreed with
Earthjustice that DOE is obligated under EPCA to review the efficiency
standards for liquid-immersed and MVDT distribution transformers and
amend the efficiency standards for LVDT distribution transformers if
justified. (ASAP/ACEEE/
[[Page 7301]]
NRDC, No. 28 at p. 5) HVOLT also believed that DOE should consider LVDT
distribution transformers at this time. (HVOLT, No. 33 at p. 2) EEI
believed that LVDT distribution transformers could be included in the
rulemaking, since they are covered products under the statute and are
now under a DOE regulatory purview. (EEI, Pub. Mtg. Tr., No. 34 at pp.
21, 27)
Without regard to whether DOE may have a statutory obligation to
review standards for LVDTs, DOE has analyzed all three transformer
types and is proposing standards for each in this rulemaking.
Schneider Electric suggested expanding coverage to include sealed
units within the range of Design Lines 6 and 7: single-phase 15 and 25
kVA and three-phase 15 kVA distribution transformers. Further, it
suggested that an additional three-phase 15 kVA design line, which
would include SCOTT-T and OPEN DELTA designs, be created to meet the
definition of sealed transformers. (SE., No. 7 at p. 2) DOE is not
making this change because the EPACT 2005 definition of a distribution
transformer and the definition currently codified at 10 CFR 431.192
both explicitly prohibit the inclusion of such transformers.
d. Negotiating Committee Discussion of Scope
Negotiation participants noted that both network/vault transformers
and ``data center'' transformers may experience disproportionate
difficulty in achieving higher efficiencies due to certain features
that may affect consumer utility. (ABB, Pub. Mtg. Tr., No. 89 at p.
245) The definitions below had been proposed at various points by
committee members and DOE seeks comment on both whether it would be
appropriate to establish separate equipment classes for any of the
following types and, if so, on how such classes might be defined such
that it was not financially advantageous for consumers to purchase
transformers in either class for general use.
i. A ``network transformer'' is one--
(i) Designed for use in a vault,
(ii) Designed for occasional submerged operation in water,
(iii) Designed to feed a system of variable capacity system of
interconnected secondaries, and
(iv) Built per the requirements of IEEE C57.12.40-(year)
ii. A ``vault-type'' transformer is one--
(i) Designed for use in a vault,
(ii) Designed for occasional submerged operation in water, and
(iii) Built per the requirements of IEEE C57.12.23-(year) or IEEE
C57.12.24-(year), respectively.
iii. Data center transformer means a three-phase low-voltage dry-
type distribution transformer that--
(i) Is designed for use in a data center distribution system and
has a nameplate identifying the transformer as being for this use only;
(ii) Has a maximum peak energization current (or in-rush current)
less than or equal to four times its rated full load current multiplied
by the square root of 2, as measured under the following conditions--
(iii) During energization of the transformer without external
devices attached to the transformer that can reduce inrush current;
(iv) The transformer shall be energized at zero +/- 3 degrees
voltage crossing of A phase. Five consecutive energization tests shall
be performed with peak inrush current magnitudes of all phases recorded
in every test. The maximum peak inrush current recorded in any test
shall be used;
(v) The previously energized and then de-energized transformer
shall be energized from a source having available short circuit current
not less than 20 times the rated full load current of the winding
connected to the source; and
(vi) The source voltage shall not be less than 5 percent of the
rated voltage of the winding energized; and
(vii) Is manufactured with at least two of the following other
attributes:
1. Listed by NRTL for a K-factor rating, as defined in UL standard
1561: 2011 Fourth Edition, greater than K-4;
2. Temperature rise less than 130[deg]C with class 220 insulation
or temperature rise less than 110[deg]C with class 200 insulation;
3. A secondary winding arrangement that is not delta or wye (star);
4. Copper primary and secondary windings;
5. An electrostatic shield; or
6. Multiple outputs at the same voltage a minimum of 15[deg] apart,
which when summed together equal the transformer's input kVA capacity.
2. Equipment Classes
DOE divides covered equipment into classes by: (a) the type of
energy used; (b) the capacity; or (c) any performance-related features
that affect consumer utility or efficiency. (42 U.S.C. 6295(q))
Different energy conservation standards may apply to different
equipment classes (ECs). For the preliminary analysis and for today's
NOPR, DOE analyzed the same ten ECs as were used in the previous
distribution transformers energy conservation standards rulemaking.\24\
These ten equipment classes divided up the population of distribution
transformers by:
---------------------------------------------------------------------------
\24\ See chapter 5 of the TSD for further discussion of
equipment classes.
---------------------------------------------------------------------------
(a) Type of transformer insulation--liquid-immersed or dry-type,
(b) Number of phases--single or three,
(c) Voltage class--low or medium (for dry-type units only), and
(d) Basic impulse insulation level (for medium-voltage, dry-type
units only).
On August 8, 2005, the President signed into law EPACT 2005, which
contained a provision establishing energy conservation standards for
two of DOE's equipment classes--EC3 (low-voltage, single-phase, dry-
type) and EC4 (low-voltage, three-phase, dry-type). With standards
thereby established for low-voltage, dry-type distribution
transformers, DOE no longer considered these two equipment classes for
standards during the previous rulemaking. Since the current rulemaking
is considering new standards for distribution transformers, DOE has
preliminarily decided to also revisit low-voltage, dry-type
distribution transformers to determine if higher efficiency standards
are justified. Table IV.1 presents the ten equipment classes within the
scope of this rulemaking analysis and provides the kVA range associated
with each.
Table IV.1--Distribution Transformer Equipment Classes
--------------------------------------------------------------------------------------------------------------------------------------------------------
EC Insulation Voltage Phase BIL Rating kVA Range
--------------------------------------------------------------------------------------------------------------------------------------------------------
1................................ Liquid-Immersed..... Medium.............. Single.............. ......................... 10-833 kVA
2................................ Liquid-Immersed..... Medium.............. Three............... ......................... 15-2500 kVA
3................................ Dry-Type............ Low................. Single.............. ......................... 15-333 kVA
4................................ Dry-Type............ Low................. Three............... ......................... 15-1000 kVA
[[Page 7302]]
5................................ Dry-Type............ Medium.............. Single.............. 20-45kV BIL 15-833 kVA
6................................ Dry-Type............ Medium.............. Three............... 20-45kV BIL 15-2500 kVA
7................................ Dry-Type............ Medium.............. Single.............. 46-95kV BIL 15-833 kVA
8................................ Dry-Type............ Medium.............. Three............... 46-95kV BIL 15-2500 kVA
9................................ Dry-Type............ Medium.............. Single.............. >= 96kV BIL 75-833 kVA
10............................... Dry-Type............ Medium.............. Three............... >= 96kV BIL 225-2500 kVA
--------------------------------------------------------------------------------------------------------------------------------------------------------
ABB commented that the currently defined equipment classes do not
cover the product scope as defined in 10 CFR part 431.192, which
defines medium-voltage as between 601 V and 34.5 kV. Therefore, it
recommended changing the equipment classes analyzed, or at least
revising the definition in the CFR. (ABB, No. 14 at p. 9)
DOE is uncertain of how its current equipment classes are
inconsistent with its published definition of ``medium-voltage dry-
type'' and requests further comment on the issue.
a. Less-Flammable Liquid-Immersed Transformers
In the August 2006 standards NOPR, DOE solicited comments about how
it should treat distribution transformers filled with an insulating
fluid of higher flash point than that of traditional mineral oil. 71 FR
44369 (August 4, 2006). Known as ``less-flammable, liquid-immersed''
(LFLI) transformers, these units are marketed to some applications
where a fire would be especially costly and traditionally served by the
dry-type market, such as indoor applications.
During preliminary interviews with manufacturers, DOE was informed
that LFLI transformers might offer the same utility as dry-type
transformers since they were unlikely to catch fire. Manufacturers also
stated that LFLI transformers could have a minor efficiency
disadvantage relative to traditional liquid-immersed transformers
because their more viscous insulating fluid requires more internal
ducting to properly circulate.
In the October 2007 final rule, DOE determined that LFLI
transformers should be considered in the same equipment class as
traditional liquid-immersed transformers. DOE concluded that the design
of a transformer (i.e., dry-type or liquid-immersed) was a performance-
related feature that affects the energy efficiency of the equipment
and, therefore, dry-type and liquid-immersed should be analyzed
separately. Furthermore, DOE found that LFLI transformers could meet
the same efficiency levels as traditional liquid-immersed units. As a
result, DOE did not separately analyze LFLI transformers, but relied on
the analysis for the mineral oil liquid-immersed transformers. 72 FR
58202 (October 12, 2007).
For the preliminary analysis, DOE revisited the issue in light of
additional research on LFLI transformers and conversations with
manufacturers and industry experts. DOE first considered whether LFLI
transformers offered the same utility as dry-type equipment, and came
to the same conclusion as in the last rulemaking. While LFLI
transformers can be used in some applications that historically use
dry-type units, there are applications that cannot tolerate a leak or
fire. In these applications, customers assign higher utility to a dry-
type transformer. Since LFLI transformers can achieve higher
efficiencies than comparable dry-type units, combining LFLIs and dry-
types into one equipment class may result in standard levels that dry-
type units are unable to meet. Therefore, DOE decided not to analyze
LFLI transformers in the same equipment classes as dry-type
distribution transformers.
Similarly, DOE revisited the issue of whether or not LFLI
transformers should be analyzed separately from traditional liquid-
immersed units. DOE concluded, once again, that LFLI transformers could
achieve any efficiency level that mineral oil units could achieve.
Although their insulating fluids are slightly more viscous, this
disadvantage has little efficiency impact, and diminishes as efficiency
increases and heat dissipation requirements decline. Furthermore, at
least one manufacturer suggested that LFLI transformers might be
capable of higher efficiencies than mineral oil units because their
higher temperature tolerance may allow the unit to be downsized and run
hotter than mineral oil units. Additionally, HVOLT agreed with DOE that
high temperature liquid-filled transformer insulation systems have a
similar space factor to mineral oil systems and should thus have
similar losses. (HVOLT, No. 33 at p. 2) For these reasons, DOE believes
that LFLI transformers would not be disproportionately affected by
standards set in the liquid-immersed equipment classes. Therefore, DOE
did not consider LFLI in a separate equipment class for the NOPR
analysis.
b. Pole- and Pad-Mounted Liquid-Immersed Distribution Transformers
During negotiations, several parties raised the question of whether
pole-mounted, pad-mounted, and possibly other types of liquid-immersed
transformers should be considered in separate equipment classes. (ABB,
Pub. Mtg. Tr., No. 89 at p. 230) DOE acknowledges that as standards
rise, transformer types which previously had similar incremental costs
may start to diverge and requests comment on whether and why separate
equipment classes are warranted for pole-mounted, pad-mounted, and
other types of liquid-immersed distribution transformers.
c. BIL Ratings in Liquid-Immersed Distribution Transformers
During negotiations, several parties raised the question of whether
liquid-immersed distribution transformers should have standards set
according to BIL rating, as do medium-voltage, dry-type distribution
transformers. (ABB, Pub. Mtg. Tr., No. 89 at p. 218) DOE acknowledges
that as standards rise, BIL ratings which previously had similar
incremental costs may start to diverge and requests comment on whether
and why separate equipment classes are warranted for liquid-immersed
transformers of different BIL ratings. DOE requests particular comment
on how many BIL bins are appropriate to cover the range and where the
specific boundaries of those bins should lie.
3. Technology Options
The technology assessment provides information about existing
technology options to construct more energy-efficient distribution
transformers. There are two main types of losses in transformers: no-
load (core) losses and load (winding) losses. Measures taken to reduce
one type of loss typically increase the other type of losses. Some
examples of technology options to improve efficiency include: (1)
Higher-grade electrical core steels, (2) different
[[Page 7303]]
conductor types and materials, and (3) adjustments to core and coil
configurations.
In consultation with interested parties, DOE identified several
technology options and designs for consideration. These technology
options are presented in Table IV.2. Further detail on these technology
options can be found in chapter 3 of the preliminary TSD.
Table IV.2--Options and Impacts of Increasing Transformer Efficiency
----------------------------------------------------------------------------------------------------------------
No-load losses Load losses Cost impact
----------------------------------------------------------------------------------------------------------------
To decrease no-load losses
----------------------------------------------------------------------------------------------------------------
Use lower-loss core materials...... Lower................. No change *........... Higher.
Decrease flux density by:
Increasing core cross-sectional Lower................. Higher................ Higher.
area (CSA).
Decreasing volts per turn...... Lower................. Higher................ Higher.
Decrease flux path length by Lower................. Higher................ Lower.
decreasing conductor CSA.
Use 120[deg] symmetry in three- Lower................. No change............. TBD.
phase cores **.
----------------------------------------------------------------------------------------------------------------
To decrease load losses
----------------------------------------------------------------------------------------------------------------
Use lower-loss conductor material.. No change............. Lower................. Higher.
Decrease current density by Higher................ Lower................. Higher.
increasing conductor CSA.
Decrease current path length by:
Decreasing core CSA............ Higher................ Lower................. Lower.
Increasing volts per turn...... Higher................ Lower................. Lower.
----------------------------------------------------------------------------------------------------------------
* Amorphous core materials would result in higher load losses because flux density drops, requiring a larger
core volume.
** Sometimes referred to as a ``hexa-transformer'' design.
HYDRO-Quebec (IREQ) notified DOE that a new iron-based amorphous
alloy ribbon for distribution transformers was developed that has
enhanced magnetic properties while remaining ductile after annealing.
Further, IREQ noted that a distribution transformer assembly using this
technology has been developed. (IREQ, No. 10 at pp. 1-2)
DOE was not able to analyze the described material in the NOPR
phase of the rulemaking, but intends to explore it further in the final
rule. Two of the challenges facing amorphous steel include availability
of the raw material and core manufacturing capacity. DOE seeks comment
and analysis about amorphous steels that offer greater raw material
availability and greater capacity to manufacture amorphous core steel.
a. Core Deactivation
As noted previously, core deactivation technology employs the
concept that a system of smaller transformers can replace a single,
larger transformer. For example, three 25 kVA transformers operating in
parallel could replace a single 75 kVA transformer.
DOE understands that winding losses are proportionally smaller at
lower load factors, but for any given current, a smaller transformer
will experience greater winding losses than a larger transformer. As a
result, those losses may be more than offset by the smaller
transformer's reduced core losses. As loading increases, winding losses
become proportionally larger and eventually outweigh the power saved by
using the smaller core. At that point, the control unit (which consumes
little power itself) switches on an additional transformer, which
reduces winding losses at the cost of additional core losses. The
control unit knows how efficient each combination of transformers is
for any given loading, and is constantly monitoring the unit's power
output so that it will use the optimal number of cores. In theory,
there is no limit to the number of transformers that may operate in
parallel in this sort of system, but cost considerations would imply an
optimal number.
DOE spoke with a company that is developing a core deactivation
technology. Noting that many dry-type transformers are operated at very
low loadings a large percentage of the time (e.g., a building at
night), the company seeks to reduce core losses by replacing a single,
traditional transformer with two or more smaller units that could be
activated and deactivated in response to load demands. In response to
load demand changes, a special unit controls the transformers and
activates and/or deactivates them in real-time.
Although core deactivation technology has some potential to save
energy over a real-world loading cycle, those savings might not be
represented in the current DOE test procedure. Presently, the test
procedure specifies a single loading point of 50 percent for liquid-
immersed and MVDT transformers, and 35 percent for LVDT. The real gain
in efficiency for core deactivation technology comes at loading points
below the root mean square (RMS) loading specified in the test
procedure, where some transformers in the system could be deactivated.
At loadings where all transformers are activated, which may be the case
at the test procedure loading, the combined core and coil losses of the
system of transformers could exceed those of a single, larger
transformer. This would result in a lower efficiency for the system of
transformers compared to the single, larger transformer.
In response to the preliminary analysis, NEMA commented that core
deactivation technology is unrelated to the design of a transformer,
but rather is related to the system of which it is a part. Therefore,
NEMA commented, it is outside the scope of this rulemaking, because all
transformers must comply with DOE regulations. (NEMA, No. 13 at p. 3)
ABB agreed that core deactivation technology is not related to the
design of a transformer, but rather related to the design of the system
in which the transformer is deployed. ABB noted that core deactivation
technology input voltage source is disconnected from the transformer
terminals, similar to a switchgear component and, as such, is not an
integral element of the distribution transformer any more than a
disconnect switch or circuit breaker. ABB commented that DOE does not
consider other systems for energy efficiency, but if it is to look at
core deactivation technology, perhaps it should also consider
technologies that maintain the load power factor closer to unity. (ABB,
No. 14 at pp. 3, 6)
[[Page 7304]]
Howard Industries (HI) commented that core deactivation technology
does not currently exist for liquid-immersed transformers, and has not
been evaluated for feasibility. In its opinion, core deactivation
technology could cause several issues, such as flicker problems and in-
rush current/surge protection. Additionally, HI believed that there are
patent issues for this technology. For these reasons, HI recommended
that DOE not consider core deactivation technology for liquid-immersed
transformers. (HI, No. 23 at pp. 4, 11) Edison Electric Institute (EEI)
agreed that core deactivation should not be considered for liquid-
immersed transformers, which face significant load diversity because
multiple buildings and/or homes can be served by a single transformer.
EEI commented that, due to this load diversity, it is highly unlikely
that core deactivation would provide energy savings for liquid-immersed
transformers. (EEI, No. 29 at pp. 4-5)
HVOLT commented that core deactivation is not feasible. Based on
HVOLT calculations, core deactivation only achieves fewer losses than a
single, full-sized unit when loaded below 15 percent. Core deactivation
also requires considerations for impedance, regulation, switching
devices, and transformer reliability, making the technology
unattractive for efficiency regulations. (HVOLT, No. 33 at pp. 2-3)
Furthermore, HVOLT performed loading analyses of core deactivation
technology and found that the only loading point where it beats
traditional transformers was at zero percent. (HVOLT, Pub. Mtg. Tr.,
No. 34 at p. 60) However, Warner Power indicated that HVOLT's analysis
was based on assumed numbers rather than actual designs and stated that
core deactivation technology is more efficient than HVOLT's analysis
indicated. (WP, Pub. Mtg. Tr., No. 34 at p. 62) Warner Power also
commented that the 0.75 scaling factor did not accurately capture the
efficiency of the smaller component transformers in a core deactivation
system and asserted that it would prefer to see a linear scaling factor
(WP, No. 30 at pp. 6-7, 11). Furthermore, Warner Power pointed out that
core deactivation technology is better suited for many small loads than
for large, discrete loads. The multiple, smaller loads create a smooth
load profile throughout the day without sudden large demands. (WP, No.
30 at p. 7) Warner Power also commented that, for core deactivation
technology, it is important to note that the secondary and tertiary
component transformers do not typically power on at 33 percent and 66
percent load. Rather, the switching point is where the system operates
with the lowest total losses and is specific to the transformer design.
(WP, No. 30 at p. 7) Finally, Warner Power stated that core
deactivation technology allows a transformer to achieve higher
efficiency at low loading values. WP hypothesized that average power
consumption will go down in buildings and transformer core losses will
start to become more significant, thus making core deactivation
technology more desirable. (WP, Pub. Mtg. Tr., No. 34 at p. 42)
NRECA and the NRECA Transmission & Distribution Engineering
Committee (T&DEC) commented that core deactivation technology would be
extremely difficult to successfully implement from an economical
viewpoint. (NRECA/T&DEC, No. 31 and 36 at p. 2) Southern Company (SC)
agreed and noted that core deactivation technology does not seem
practical or cost-effective because it would use more materials than a
single transformer, which would increase the weight and cost of the
unit. SC further noted that the increased weight could be problematic
for pole-mounted transformers. (SC, No. 22 at p. 3)
FPT commented that DOE should not consider core deactivation in the
efficiency standard rulemaking at this time because it is only
advantageous in certain situations with low loading requirements, and
thus only represents a small portion of the market. (FPT, No. 27 at p.
3) Rather, FPT suggested that DOE encourage users to de-energize the
LVDT from the primary switch/breaker. FPT also noted that the
technology would face challenges with medium-voltage transformers, such
as pre-strikes, re-strikes, ferroresonance, and reducing the life of
the primary circuit sectionalizing device. (FPT, No. 27 at p. 3)
Berman Economics was interested to know if DOE would also be
looking at the potential differences in stress and wear on the
transformer as one is activating and deactivating the core deactivation
transformer. (BE, Pub. Mtg. Tr, No. 34 at p. 62)
DOE appreciates all of the comments from interested parties
regarding core deactivation technology. DOE understands that core
deactivation technology is most easily implemented in LVDT distribution
transformer designs. Implementing core deactivation technology in
medium-voltage distribution transformers is possible, but poses
difficulties for switching the primary and secondary connections. For
the NOPR, DOE has not fully quantified these difficulties because it
did not directly analyze core deactivation technology, although DOE
believes it may be possible to evaluate the technology using its
existing transformer designs. DOE also acknowledges that operating a
core deactivation bank of transformers instead of a single unit may
save energy and lower LCC for certain consumers. At present, however,
DOE is adopting the position that each of the constituent transformers
must comply with the energy conservation standards under the scope of
the rulemaking.
b. Symmetric Core
DOE understands that several companies worldwide are commercially
producing three-phase transformers with symmetric cores--those in which
each leg of the transformer is identically connected to the other two.
The symmetric core uses a continuously wound core with 120-degree
radial symmetry, resulting in a triangularly shaped core when viewed
from above. In a traditional core, the center leg is magnetically
distinguishable from the other two because it has a shorter average
flux path to each. In a symmetric core, however, no leg is magnetically
distinguishable from the other two.
One manufacturer of symmetric core transformers cited several
advantages to the symmetric core design. These include reduced weight,
volume, no-load losses, noise, vibration, stray magnetic fields, inrush
current, and power in the third harmonic. Thus far, DOE has seen
limited cost and efficiency data for only a few symmetric core units
from testing done by manufacturers. DOE has not seen any designs for
symmetric core units modeled in a software program.
DOE understands that, because of zero-sequence fluxes associated
with wye-wye connected transformers, symmetric core designs are best
suited to delta-delta or delta-wye connections. While traditional cores
can circumvent the problem of zero-sequence fluxes by introducing a
fourth or fifth unwound leg, core symmetry makes extra legs inherently
impractical. Another way to mitigate zero-sequence fluxes comes in the
form of a tertiary winding, which is delta-connected and has no
external connections. This winding is dormant when the transformer's
load is balanced across its phases. Although symmetric core designs
may, in theory, be made tolerant of zero-sequence fluxes by employing
this method, this would come at extra cost and complexity.
Using this tertiary winding, DOE believes that symmetric core
designs can service nearly all distribution
[[Page 7305]]
transformer applications in the United States. Most dry-type
transformers have a delta connection and would not require a tertiary
winding. Similarly, most liquid-immersed transformers serving the
industrial sector have a delta connection. These market segments could
use the symmetric core design without any modification for a tertiary
winding. However, in the United States most utility-operated
distribution transformers are wye-wye connected. These transformers
would require the tertiary winding in a symmetric core design.
DOE understands that symmetric core designs are more challenging to
manufacture and require specialized equipment that is currently
uncommon in the industry. However, DOE did not find a reasonable basis
to screen this technology option out of the analysis, and is aware of
at least one manufacturer producing dry-type symmetric core designs
commercially in the United States.
For the preliminary analysis, DOE lacked the data necessary to
perform a thorough engineering analysis of symmetric core designs. To
generate a cost-efficiency relationship for symmetric core design
transformers, DOE made several assumptions. DOE adjusted its
traditional core design models to simulate the cost and efficiency of a
comparable symmetric core design. To do this, DOE reduced core losses
and core weight while increasing labor costs to approximate the
symmetric core designs. These adjustments were based on data received
from manufacturers, published literature, and through conversations
with manufacturers. Table IV.3 indicates the range of potential
adjustments for each variable that DOE considered and the mean value
used in the analysis.
Table IV.3--Symmetric Core Design Adjustments
----------------------------------------------------------------------------------------------------------------
[Percentage changes]
-----------------------------------------------
Range Core losses Core weight
(W) (lbs) Labor hours
----------------------------------------------------------------------------------------------------------------
Minimum......................................................... -0.0 -12.0 +10.0
Mean............................................................ -15.5 -17.5 +55.0
Maximum......................................................... -25.0 -25.0 +100.0
----------------------------------------------------------------------------------------------------------------
DOE applied the adjustments to each of the traditional three-phase
transformer designs to develop a cost-efficiency relationship for
symmetric core technology. DOE did not model a tertiary winding for the
wye-wye connected liquid-immersed design lines (DLs). Based on its
research, DOE believes that the losses associated with the tertiary
winding may offset the benefits of the symmetric core design and that
the tertiary winding will add cost to the design. Therefore, DOE
modeled symmetric core designs for the three-phase, liquid-immersed
design lines without a tertiary winding to examine the impact of
symmetric core technology on the subgroup of applications that do not
require the tertiary winding.
NPCC and NEEA jointly commented that DOE should revise its
assumptions about costs and limitations of symmetric core designs in
accordance with information provided by manufacturers of these
technologies. (NPCC/NEEA, No. 11 at p. 2) Furthermore, NPCC and NEEA
noted that DOE should revise its analysis for symmetric core designs to
account for labor costs that mirror those of conventional core designs.
NPCC and NEEA recommended that DOE request additional data from
manufacturers that are producing this technology. (NPCC/NEEA, No. 11 at
pp. 4, 6)
Hex Tec (HEX) commented that DOE should consider a symmetric core
design using amorphous core steel in its evaluation. (HEX, No. 35 at p.
1) It noted that there are several variations of the symmetric core
design being made around the world and that licenses are available.
Furthermore, it commented that amorphous metal suppliers are emerging
in India and China, concluding that there are no barriers to adopting
symmetric core technology with an amorphous core. (HEX, No. 35 at p. 1)
Hex Tec pointed out that amorphous units up to 3 MVA in size have been
produced using Evans distributed gap core construction, but are labor
intensive and difficult to produce, and concluded that amorphous
designs are easier to make using a symmetric core. (HEX, No. 35 at p.
1) Finally, Hex Tec submitted a letter written by the Vice President of
Research & Development at Metglas that indicates that symmetric core
units using amorphous steel of 15 to 100 kVA demonstrated core losses
of 0.13 Watts/lb at an induction of 1.2 T. The letter also noted that
audible sound levels were low. (HEX, No. 35 at p. 14)
Hammond (HPS) commented that its analytical and prototype work
indicated that symmetric core designs do not experience a core loss
advantage but do have higher manufacturing costs. (HPS, No. 3 at p. 2)
However, Hex Tec commented that it builds symmetric cores with labor
costs and material savings that are comparable to those incurred by
conventional construction. (HEX, Pub. Mtg. Tr., No. 34 at p. 25) Hex
Tec noted that the equipment to produce symmetric wound cores is
significantly less expensive than flat stack steel equipment and that
the labor production times are lower. (HEX, Pub. Mtg. Tr., No. 34 at p.
52) Hex Tec added that labor requirements, both TAC time and process
times, are lower for symmetric core designs than for conventional
designs. (HEX, No. 35 at p. 2)
Hex Tec submitted data showing that the weight of three-phase, 75
kVA LVDT symmetric core designs ranged from 390 to 600 pounds between
98.6 and 99.2 percent efficiency. These weights are lower than the
weights of comparably efficient designs using conventional cores. (HEX,
No. 35 at p. 7) Hex Tec also submitted data comparing the efficiency,
dimensions, core and coil material content, and cost of several
conventional designs for three-phase, 75 kVA LVDT units to those of
otherwise identical symmetric core designs. (HEX, No. 35 at p. 8) Hex
Tec noted it took the same amount of labor time as a major
conventional-design manufacturer to produce a three-phase 75 kVA LVDT
rated at CSL3,\25\ and that it was able to do so with lower material
costs. (HEX, Pub. Mtg. Tr., No. 34 at p. 110) Hex Tec also submitted
data showing comparisons between the weight, losses, and costs of
conventional core designs and symmetric core designs at 1000
[[Page 7306]]
kVA and 2000 kVA for MVDTs. (HEX, No. 35 at pp. 9-10)
---------------------------------------------------------------------------
\25\ ``Candidate Standard Levels'' (CSLs) are analogous to the
Efficiency Levels (ELs) DOE utilizes together in the NOPR to create
Trial Standard Levels (TSLs). This particular commenter refers to
CSL3 from the 2007 rulemaking, not the present one.
---------------------------------------------------------------------------
Warner Power pointed out that recent improvements in the
manufacturing process for symmetric core designs, leveraged by
increasing volumes, will bring labor costs down to approximately 10
percent below labor costs for conventional cores. (WP, No. 30 at p. 3)
Warner Power commented that symmetric cores use a wound core with no
scrap and approximately 15 percent lower weight than that of
conventional cores. (WP, No. 30 at p. 3) Warner felt that DOE's
symmetric core analysis contained some significant errors that would
generate the wrong output, and that the manufacturing cost estimates
for symmetric cores were overstated. (WP, No. 30 at p. 9; WP Pub. Mtg.
Tr., No. 34 at p. 111)
Power Partners commented that DOE should not set a standard based
on symmetric core designs because they are not common in the industry
and could place an unreasonable burden on smaller manufacturers who
would be unable to invest in the equipment necessary for the
technology. (PP, No. 19 at p. 2) NEMA agreed, commenting that symmetric
core is in its infancy and has low penetration in the industry and
should not be introduced into the regulation until it has been proven
in the marketplace. (NEMA, No. 13 at p. 3) FPT commented that symmetric
core technology should not be used as the basis for increasing
efficiency levels and noted that, while the technology may be
advantageous in some areas, it may present problems with larger
transformers. (FPT, No. 27 at pp. 3-4, 13) Warner Power disagreed and
stated that symmetric core designs and core deactivation technology
should be included in the scope of DOE's analysis, recommending several
symmetric core and core deactivation design option combinations. (WP,
No. 30 at p. 9)
NEEA reiterated that symmetric core manufacturers have stated that
there should not be any patent concerns for the technology, since it is
not yet patented. (NEEA, No. 11 at p. 4; NEEA, Pub. Mtg. Tr., No. 34 at
p. 261) Howard Industries disagreed and commented that DOE should not
consider symmetric core technology because it is patented by Hexaformer
AB of Sweden, which would result in increased licensing costs. (HI, No.
23 at pp. 3-4, 6-7, 11) Furthermore, HI noted that no manufacturers in
North America currently produce the design for liquid-immersed units.
(HI, No. 23 at pp. 3-4, 6-7, 11) HI also pointed out that Hexaformer AB
does not produce units higher than 200 kVA and 24 kV, whereas most
utilities require larger kVA sizes and 35 kV. (HI, No. 23 at pp. 3-4,
6-7, 11) Finally, Howard commented that all efficiency improvements for
symmetric core liquid-immersed designs are theoretical at this point.
(HI, No. 23 at pp. 3-4, 6-7, 11)
Southern Company commented that symmetric core technology is not
feasible for utility applications because they require wye-wye
connections, while symmetric cores have a delta connection. SC noted
that, while a tertiary winding may enable the symmetric core design to
be connected in the system, SC has had trouble in the past with
tertiary windings and has discontinued purchasing transformers that use
them. (SC, No. 22 at p. 2) Howard Industries and HVOLT also noted that
most utility transformers are wye-wye connected and would need a delta
tertiary winding to use symmetric core technology, which would drive
down efficiency while increasing costs. (HI, No. 23 at pp. 3-4, 6-7,
11; HVOLT, Pub. Mtg. Tr., No. 34 at p. 50; HVOLT, Pub. Mtg. Tr., No. 34
at p. 50)
DOE attempts to consider all designs that are technologically
feasible and practicable to manufacture and believes that symmetric
core designs can meet these criteria. However, DOE has not been able to
obtain or produce sufficient data to modify its analysis of symmetric
cores since the preliminary analysis. Therefore, although not screened
out, DOE has not considered symmetric core designs for its NOPR
analyses. DOE welcomes comment and submission of engineering data that
would be useful in analyzing symmetric core designs in the final rule.
c. Intellectual Property
In setting standards, DOE seeks to analyze the efficiency
potentials of commercially available technologies and working
prototypes as well as the availability of those technologies to the
market at-large. If certain market participants own intellectual
property that enable them to reach efficiencies that other participants
practically cannot, amended standards may reduce the competitiveness of
the market.
In the case of distribution transformers, stakeholders have raised
potential intellectual property concerns surrounding both symmetric
core technology and amorphous metals in particular. DOE currently
understands that symmetric core technology itself is not proprietary,
but that one of the more commonly employed methods of production is the
property of the Swedish company Hexaformer AB. However, Hexaformer AB's
method is not the only one capable of producing symmetric cores.
Moreover, Hexaformer AB and other companies owning intellectual
property related to the manufacture of symmetric core designs have
demonstrated an eagerness to license such technology to others that are
using it to build symmetric core transformers commercially today.
Warner Power commented that the well-known symmetric core design
(Hexaformers) is subject to worldwide patents for the core winding and
assembly process, but multiple licenses have been authorized and the IP
owner has indicated it will entertain additional licenses. The basic
design concept is not patented, and several other manufacturers make
symmetric cores, so patents should not be a limiting factor. (WP, No.
30 at pp. 3-4)
EEI noted that, if certain higher-efficiency designs are covered by
patents, then the number of manufacturers may decrease, which would
increase transformer prices. It recommended that DOE discuss any
relevant patents and indicate whether they will be in place after 2016.
(EEI, No. 29 at p. 10)
DOE understands that symmetric core technology may ultimately offer
a lower-cost path to higher efficiency, at least in certain
applications, and that few symmetric cores are produced in the United
States. However, DOE notes again that it has been unable to secure data
that are sufficiently robust for use as the basis for an energy
conservation standard, but encourages interested parties to submit data
that would assist in DOE's analysis of symmetric core technology.
B. Screening Analysis
DOE uses the following four screening criteria to determine which
design options are suitable for further consideration in a standards
rulemaking:
1. Technological feasibility. Technologies incorporated in
commercial products or in working prototypes will be considered to be
technologically feasible.
2. Practicability to manufacture, install, and service. If mass
production of a technology in commercial products and reliable
installation and servicing of the technology could be achieved on the
scale necessary to serve the relevant market at the time of the
effective date of the standards, then that technology will be
considered practicable to manufacture, install, and service.
3. Impacts on product utility to consumers. If a technology is
determined to have significant adverse impact on the utility of the
product to significant subgroups of consumers, or
[[Page 7307]]
result in the unavailability of any covered product type with
performance characteristics (including reliability), features, sizes,
capacities, and volumes that are substantially the same as products
generally available in the United States at the time, it will not be
considered further.
4. Safety of technologies. If it is determined that a technology
will have significant adverse impacts on health or safety, it will not
be considered further. (10 CFR part 430, subpart C, appendix A)
In the preliminary analysis, DOE identified the technologies for
improving distribution transformer efficiency that were under
consideration. DOE developed this initial list of design options from
the technologies identified in the technology assessment. Then DOE
reviewed the list to determine if the design options are practicable to
manufacture, install, and service; would adversely affect equipment
utility or equipment availability; or would have adverse impacts on
health and safety. In the engineering analysis, DOE only considered
those design options that satisfied the four screening criteria. The
design options that DOE did not consider because they were screened out
are summarized in Table IV.4.
Table IV.4--Design Options Screened Out of the Analysis
------------------------------------------------------------------------
Design option excluded Eliminating screening criteria
------------------------------------------------------------------------
Silver as a Conductor Material......... Practicability to manufacture,
install, and service.
High-Temperature Superconductors....... Technological feasibility;
Practicability to manufacture,
install, and service.
Amorphous Core Material in Stacked Core Technological feasibility;
Configuration. Practicability to manufacture,
install, and service.
Carbon Composite Materials for Heat Technological feasibility.
Removal.
High-Temperature Insulating Material... Technological feasibility.
Solid-State (Power Electronics) Technological feasibility;
Technology. Practicability to manufacture,
install, and service.
Nanotechnology Composites.............. Technological feasibility.
------------------------------------------------------------------------
Chapter 4 of the TSD discusses each of these screened-out design
options in more detail. The chapter also includes a list of emerging
technologies that could impact future distribution transformer
manufacturing costs.
Multiple interested parties commented that they agreed with the
technology options screened out of the analysis by DOE. (EEI, No. 29 at
p. 5; HI, No. 23 at p. 5; NPCC/NEEA, No. 11 at p. 3) Metglas concurred
that using amorphous metals in a stack core configuration is
technically infeasible. (Metglas, Pub. Mtg. Tr., No. 34 at p. 66)
Howard Industries also recommended that DOE screen out symmetric core
designs and core deactivation technology from their analysis based on
proprietary concerns. (HI, No. 23 at p. 5)
DOE appreciates the feedback and remains interested in advances
that would allow a currently screened technology to be considered as a
design option. As for symmetric core designs, DOE has not screened this
technology out because it is aware that manufacturers around the world
are building and selling such transformers. However, without additional
information regarding the technology, DOE has been unable to fully
evaluate this as a design option.
1. Nanotechnology Composites
DOE understands that the nanotechnology field is actively
researching ways to produce bulk material with desirable features on a
molecular scale. Some of these materials may have high resistivity,
high permeability, or other properties that make them attractive for
use in electrical transformers. DOE knows of no current commercial
efforts to employ these materials in distribution transformers and no
prototype designs using this technology, but welcomes comment on such
technology and its implications for the future of the industry.
NEMA and ABB Transformers both commented that, because
nanotechnology composite technology is not commercially available in
the U.S., manufacturers cannot discuss it publicly. (NEMA, No. 13 at p.
4; ABB, No. 14 at p. 7) Howard Industries, Inc. was unaware of any
nanotechnology composite technology for distribution transformers. (HI,
No. 23 at p. 4)
DOE appreciates confirmatory feedback, and does not propose to
consider nanotechnology composites in the current rulemaking.
C. Engineering Analysis
The engineering analysis develops cost-efficiency relationships for
the equipment that are the subject of a rulemaking by estimating
manufacturer costs of achieving increased efficiency levels. DOE uses
manufacturing costs to determine retail prices for use in the LCC
analysis and MIA. In general, the engineering analysis estimates the
efficiency improvement potential of individual design options or
combinations of design options that pass the four criteria in the
screening analysis. The engineering analysis also determines the
maximum technologically feasible energy efficiency level.
DOE must consider those distribution transformers that are designed
to achieve the maximum improvement in energy efficiency that the
Secretary of Energy determines to be technologically feasible and
economically justified. (42 U.S.C. 6295(o)(2)(A)) Therefore, an
important role of the engineering analysis is to identify the maximum
technologically feasible efficiency level. The maximum technologically
feasible level is one that can be reached by adding efficiency
improvements and/or design options, both commercially feasible and in
prototypes, to the baseline units. DOE believes that the design options
comprising the maximum technologically feasible level must have been
physically demonstrated in a prototype form to be considered
technologically feasible.
In general, DOE can use three methodologies to generate the
manufacturing costs needed for the engineering analysis. These methods
are:
(1) The design-option approach--reporting the incremental costs of
adding design options to a baseline model;
(2) The efficiency-level approach--reporting relative costs of
achieving improvements in energy efficiency; and
(3) The reverse engineering or cost assessment approach--involving
a ``bottom up'' manufacturing cost assessment based on a detailed bill
of
[[Page 7308]]
materials derived from transformer teardowns.
DOE's analysis for the distribution transformers rulemaking is
based on the design-option approach, in which design software is used
to assess the cost-efficiency relationship between various design
option combinations. This is the same approach that was taken in the
previous rulemaking for distribution transformers.
1. Engineering Analysis Methodology
When developing its engineering analysis for distribution
transformers, DOE divided the covered equipment into equipment classes.
As discussed, distribution transformers are classified by insulation
type (liquid-immersed or dry-type), number of phases (single or three),
primary voltage (low-voltage or medium-voltage for dry-types) and basic
impulse insulation level (BIL) rating (for dry-types). Using these
transformer design characteristics, DOE developed ten equipment
classes. Within each of these equipment classes, DOE further classified
distribution transformers by their kilovolt-ampere (kVA) rating. These
kVA ratings are essentially size categories, indicating the power
handling capacity of the transformers. For DOE's rulemaking there are
over 100 kVA ratings across all ten equipment classes.
DOE recognized that it would be impractical to conduct a detailed
engineering analysis on all kVA ratings, so it sought to develop an
approach that simplified the analysis while retaining reasonable levels
of accuracy. DOE consulted with industry representatives and
transformer design engineers to develop an understanding of the
construction principles for distribution transformers. It found that
many of the units share similar designs and construction methods. Thus,
DOE simplified the analysis by creating engineering design lines (DLs),
which group kVA ratings based on similar principles of design and
construction. The DLs subdivide the equipment classes, to improve the
accuracy of the engineering analysis. These DLs differentiate the
transformers by insulation type (liquid-immersed or dry-type), number
of phases (single or three), and primary insulation levels for medium-
voltage, dry-type (three different BIL levels).
After developing its DLs, DOE then selected one representative unit
from each DL for study in the engineering analysis, greatly reducing
the number of units for direct analysis. For each representative unit,
DOE generated hundreds of unique designs by contracting with Optimized
Program Services, Inc. (OPS), a software company specializing in
transformer design since 1969. The OPS software used three primary
inputs that it received from DOE, (1) a design option combination,
which included core steel grade, primary and secondary conductor
material, and core configuration; (2) a loss valuation combination; and
(3) material prices. For each representative unit, DOE examined
anywhere from 8 to 16 design option combinations and for each design
option combination, the OPS software generated 518 designs based off of
unique loss valuation combinations. These loss valuation combinations
are known in industry as A and B evaluation combinations and represent
a customer's present value of future losses in a transformer core and
winding, respectively. For each design option combination and A and B
combination, the OPS software generated an optimized transformer design
based on the material prices that were also part of the inputs.
Consequently, DOE obtained thousands of transformer designs for each
representative unit. The performance of these designs ranged in
efficiency from a baseline level, equivalent to the current
distribution transformer energy conservation standards, to a
theoretical max-tech efficiency level.
After generating each design, DOE used the outputs of the OPS
software to help create a manufacturer selling price (MSP). The
material cost outputs of the OPS software, along with labor estimates
were marked up for scrap factors, factory overhead, shipping, and non-
production costs to generate an MSP for each design. Thus, DOE obtained
a cost versus efficiency relationship for each representative unit.
Finally, after DOE had generated the MSPs versus efficiency
relationship for each representative unit, it extrapolated the results
the other, unanalyzed, kVA ratings within that same engineering design
line.
2. Representative Units
For the preliminary analysis, DOE analyzed 13 DLs that cover the
range of equipment classes within the distribution transformer market.
Within each DL, DOE selected a representative unit to analyze in the
engineering analysis. A representative unit is meant to be an idealized
distribution transformer typical of those used in high volume
applications. Table IV.5 outlines the design lines and representative
units selected for each equipment class.
Table IV.5--Engineering Design Lines and Representative Units for Analysis
----------------------------------------------------------------------------------------------------------------
Representative unit for this
EC * DL Type of distribution transformer kVA Range engineering design line
----------------------------------------------------------------------------------------------------------------
1.............. 1.............. Liquid-immersed, single-phase, 10-167 50 kVA, 65 [deg]C, single-phase,
rectangular tank. 60Hz, 14400V primary, 240/120V
secondary, rectangular tank.
2.............. Liquid-immersed, single-phase, 10-167 25 kVA, 65 [deg]C, single-phase,
round tank. 60Hz, 14400V primary, 120/240V
secondary, round tank.
3.............. Liquid-immersed, single-phase... 250-833 500 kVA, 65 [deg]C, single-phase,
60Hz, 14400V primary, 277V
secondary.
----------------------------------------------------------------------------------------------------------------
2.............. 4.............. Liquid-immersed, three-phase.... 15-500 150 kVA, 65 [deg]C, three-phase,
60Hz, 12470Y/7200V primary, 208Y/
120V secondary.
5.............. Liquid-immersed, three-phase.... 750-2500 1500 kVA, 65 [deg]C, three-phase,
60Hz, 24940GrdY/14400V primary,
480Y/277V secondary.
----------------------------------------------------------------------------------------------------------------
3.............. 6.............. Dry-type, low-voltage, single- 15-333 25 kVA, 150 [deg]C, single-phase,
phase. 60Hz, 480V primary, 120/240V
secondary, 10kV BIL.
----------------------------------------------------------------------------------------------------------------
4.............. 7.............. Dry-type, low-voltage, three- 15-150 75 kVA, 150 [deg]C, three-phase,
phase. 60Hz, 480V primary, 208Y/120V
secondary, 10kV BIL.
8.............. Dry-type, low-voltage, three- 225-1000 300 kVA, 150 [deg]C, three-phase,
phase. 60Hz, 480V Delta primary, 208Y/
120V secondary, 10kV BIL.
----------------------------------------------------------------------------------------------------------------
[[Page 7309]]
6.............. 9.............. Dry-type, medium-voltage, three- 15-500 300 kVA, 150 [deg]C, three-phase,
phase, 20-45kV BIL. 60Hz, 4160V Delta primary, 480Y/
277V secondary, 45kV BIL.
10............. Dry-type, medium-voltage, three- 750-2500 1500 kVA, 150 [deg]C, three-
phase, 20-45kV BIL. phase, 60Hz, 4160V primary, 480Y/
277V secondary, 45kV BIL.
----------------------------------------------------------------------------------------------------------------
8.............. 11............. Dry-type, medium-voltage, three- 15-500 300 kVA, 150 [deg]C, three-phase,
phase, 46-95kV BIL. 60Hz, 12470V primary, 480Y/277V
secondary, 95kV BIL.
12............. Dry-type, medium-voltage, three- 750-2500 1500 kVA, 150 [deg]C, three-
phase, 46-95kV BIL. phase, 60Hz, 12470V primary,
480Y/277V secondary, 95kV BIL.
----------------------------------------------------------------------------------------------------------------
10............. 13............. Dry-type, medium-voltage, three- 225-2500 2000 kVA, 150 [deg]C, three-
phase, 96-150kV BIL. phase, 60Hz, 12470V primary,
480Y/277V secondary, 125kV BIL.
----------------------------------------------------------------------------------------------------------------
* EC = Equipment Class
ABB commented that the definition of design lines for equipment
class 4 leaves an uncovered kVA range from 150 kVA to 225 kVA, and
recommended that DOE extend the scope of DL 8 to be 150-1000 kVA. (ABB,
No. 14 at p. 12) In view of the ABB comment, DOE would like to clarify
that DL 7 covers kVA ratings up through 150 kVA, and that DL 8 covers
kVA ratings beginning with 225 kVA. DOE does not specify any ratings in
between 150 and 225 kVA because it is not aware of any standard ratings
between these two ratings. Furthermore, 10 CFR 431.196(a) states that
low-voltage dry-type distribution transformers with kVA ratings not
appearing in the table [of designated kVA ratings and efficiencies]
shall have their minimum efficiency level determined by linear
interpolation of the kVA and efficiency values immediately above and
below that kVA rating. Therefore, DOE has not altered the design lines
for low-voltage dry-type transformers.
Additionally, ABB had several recommendations for DOE regarding
representative units. First, ABB commented that DOE correctly noted in
the 2007 rulemaking that BIL does not impact efficiency for liquid-
immersed transformers as significantly as it impacts MVDT units.
However, since DOE does not separate out the liquid-immersed efficiency
levels by BIL and performs its analysis on the 15 kV voltage class, it
understates the energy savings for units with a higher BIL and makes it
more difficult for these units to meet the efficiency standard. ABB
recommended that DOE analyze representative units for liquid-immersed
design lines in the 200 kV BIL class, such as a 34500 V (200 BIL) unit.
(ABB, No. 14 at pp. 7-8) For the liquid-immersed design lines, ABB
recommended that DOE consider a 150 kVA (200 BIL) single-phase
representative unit and a 30 kVA (200 BIL) three-phase representative
unit to better represent the range of BILs covered and to provide for
more accurate scaling. (ABB, No. 14 at p. 11) To improve the scaling
within the LVDT equipment classes, ABB also recommended that DOE
consider a 100 kVA (10 BIL) single-phase representative unit and a 25
kVA (10 BIL) three-phase unit. (ABB, No. 14 at p. 12) For DL13, ABB
recommended that DOE consider a representative unit in the 200 kV BIL
class, such as 34500 V (200 BIL). For EC 10, ABB recommended that DOE
consider a representative unit at 200 kV BIL in order to analyze a unit
at the upper limit of the BIL rating for the equipment class. (ABB, No.
14 at p. 10)
ABB also disagreed with the assumption that single-phase MVDT units
have one-third the losses of three-phase MVDT units and commented that
DOE should directly analyze single-phase MVDT units. It further noted
that this assumption was not made for liquid-immersed or LVDT units.
(ABB, No. 14 at pp. 5, 10) ABB suggested that DOE analyze several
single-phase MVDT representative units including the following: 50 kVA
(45 BIL), 300 kVA (45 BIL), 50 kVA (95 BIL), and 300 kVA (95 BIL). ABB
also recommended that DOE analyze 150 kVA (200 BIL) and 500 kVA (200
BIL) units if DOE does not change the definition of EC 9, or 50 kVA
(200 BIL) and 300 kVA (200 BIL) if it does change the definition of EC
9 to align with 10 CFR part 431.192. (ABB, No. 14 at p. 10) To provide
for better scaling, ABB recommended that DOE consider the following
representative units for three-phase MVDT: 30 kVA (45 BIL), and 30 kVA
(95 BIL). ABB also recommended that DOE analyze 500 kVA (200 BIL) units
if it does not change the definition of EC10, or 30 kVA (200 BIL) and
300 kVA (200 BIL) units if it does change the definition of EC9 to
align with 10 CFR 431.192. (ABB, No. 14 at p. 10)
NEMA commented that it found the representative unit for DL 5, DL
13, and the units for the single-phase liquid-immersed design lines all
to be satisfactory. (NEMA, No. 13 at p. 4) However, NEMA stated that
DOE should consider at least one representative unit for each of the
three equipment classes for single-phase medium-voltage dry-type
transformers. (NEMA, No. 13 at p. 5) NEMA also suggested an additional
representative unit for each of the three LVDT design lines. (NEMA, No.
13 at p. 5) For DL1, NEMA commented that DOE should examine an
additional representative unit of 167 kVA, 65 degrees Celsius, single-
phase, 60 Hz, 14400V primary, 240/120 secondary, rectangular tank.
(NEMA, No. 13 at p. 4) For DL2, NEMA felt that DOE should examine an
additional representative unit of 100 kVA, 65 degrees Celsius, single-
phase, 60 Hz, 14400V primary, 120/240 secondary, round tank. (NEMA, No.
13 at p. 5)
Howard Industries also recommended several representative units for
DOE to consider. Howard noted that it is not optimum to require the
same efficiency for the entire range of BIL ratings for liquid-immersed
distribution transformers. It suggested that DOE examine representative
units with higher BIL ratings for the single-phase liquid-immersed
design lines, such as 19920 V (150 kV BIL), as well as for dual primary
voltage ratings, such as 7200 x 19920 V primary voltages. (HI, No. 23
at p. 5) Also, Howard Industries recommended that DOE consider a
representative unit for DL5 with a 150 kV BIL and a dual voltage
primary, such as 12470GRDY/7200 x 24500GRDY/19920. (HI, No. 23 p. 5)
Further, it commented that large three-phase liquid-immersed
transformers with low-voltage ratings, such as 208Y/120, should be
examined because these
[[Page 7310]]
designs are difficult to manufacture even under the present efficiency
standards. (HI, No. 23 at p. 5) Finally, Howard Industries noted that
DOE may need to consider additional representative units in order to
perform accurate scaling for pole type transformers. It recommended
that DOE consider kVA ranges of 10-50 kVA, 75-167 kVA, and 250-833 kVA
for accurate scaling of pole-mount units. (HI, No. 23 at p. 8)
Power Partners noted that it could not determine the BIL rating for
design line 1. (PP, Pub. Mtg. Tr., No. 34 at p. 71) Howard Industries
and Power Partners both supported using 125 BIL 14400 volt designs for
design lines 1-3. (PP, Pub. Mtg. Tr., No. 34 at p. 72; HI, Pub. Mtg.
Tr., No. 34 at p. 72) NRECA and T&DEC commented that the 14.4 kV
primary voltage selected for DOE's analysis of design lines 1 through 3
is appropriate in that it represents a large portion of the market.
However, they commented that DOE should explain how other voltages
above and below this level would be impacted. (NRECA/T&DEC, No. 31 and
36 at p. 3) In DL 3, PP suggested analyzing the smallest and largest
transformers in addition to the midpoint. (PP, Pub. Mtg. Tr., No. 34 at
p. 136) Power Partners would support the use of 14400 volt 125 BIL coil
voltage as the means of analysis for all liquid-filled design lines.
(PP, Pub. Mtg. Tr., No. 34 at p. 83) PP would also support 14400 volts
in the design lines for single-phase liquid-immersed transformers. (PP,
Pub. Mtg. Tr., No. 34 at p. 71) It commented that DOE should increase
the voltage of its liquid-immersed representative units to 34500GY/
19920 (150 BIL) or, at a minimum, consider 14400/24940Y (125 BIL).
Power Partners noted that it is more difficult to meet the efficiency
standards at these higher voltages, and suggested detailed
specifications for revision to the representative units for DL2 and
DL3. (PP, No. 19 at pp. 2-3)
In regards to the representative unit for DL13, FPT commented that
dry-type transformers with primaries rated for 125 kV BIL are more
commonly rated at 24900V and 150 kV BIL units typically have 34500 volt
primaries. (FPT, No. 27 at p. 14) Hex Tec stated that, for DL 13,
``MVDT three-phase units, 2000 kVA 12470, 480/277 with a 95 kV BIL is
the workhorse of that market.'' (HEX, Pub. Mtg. Tr., No. 34 at p. 81)
For 96-150 kV BIL, FPT believed that 24900 or 24940 volts would be more
appropriate for the primary voltage of the representative unit in DL13.
(FPT, Pub. Mtg. Tr., No. 34 at p. 81) Hammond commented that the
representative unit for DL13 should have a primary of 24940 V Delta for
the 125 kV BIL. (HPS, No. 3 at p. 3)
Schneider Electric (SE) suggested adding another design line for
low-voltage three-phase units at 15 kVA. SE felt that this would be
beneficial to the national impact analysis because that design line is
readily available in the marketplace. (SE, Pub. Mtg. Tr., No. 34 at p.
83) SE also commented that DOE should analyze two representative units
for each of the three existing LVDT design lines. It recommended that
DOE split the analyzed kVA ranges into two ranges and analyze a
representative unit in each. (SE, No. 18 at p. 7)
Central Moloney commented that the 25 kVA pole unit is shown as
240/120 but that the standard is 120/240. (CM, Pub. Mtg. Tr., No. 34 at
p. 72)
Overall, NPCC and NEEA commented that the representative units
selected should accurately represent products that are being sold in
the marketplace, and recommended that DOE adjust its analysis based on
feedback from manufacturers. (NPCC/NEEA, No. 11 at p. 5)
In view of the above comments, DOE slightly modified its
representative units for the NOPR analysis. For the NOPR, DOE analyzed
the same 13 representative units as in the preliminary analysis, but
also added a design line, and therefore representative unit, by
splitting the former design line 13 into two new design lines, 13A and
13B. This new representative unit is shown in Table IV.6. The
representative units selected by DOE were chosen because they comprise
high volume segments of the market for their respective design lines
and also provide, in DOE's view, a reasonable basis for scaling to the
unanalyzed kVA ratings. DOE chooses certain designs to analyze as
representative of a particular design line or design lines because it
is impractical to analyze all possible designs in the scope of coverage
for this rulemaking. DOE will consider extending its direct analysis
further to substantiate the efficiency standard proposed for the final
rule and will publish sensitivity results to help assess the accuracy
of its analysis in the areas not directly analyzed. DOE also notes that
as a part of the negotiations process, DOE has worked directly with
multiple interested parties to develop a new scaling methodology for
the NOPR that addresses some of the aforementioned interested party
concerns regarding scaling.
Table IV.6--Engineering Design Lines (DLs) and Representative Units for Analysis
----------------------------------------------------------------------------------------------------------------
Representative unit for
EC * DL Type of distribution kVA Range this engineering design
transformer line
----------------------------------------------------------------------------------------------------------------
1................... 1.................. Liquid-immersed, single- 10-167 50 kVA, 65 [deg]C, single-
phase, rectangular tank. phase, 60Hz, 14400V
primary, 240/120V
secondary, rectangular
tank, 95kV BIL.
2.................. Liquid-immersed, single- 10-167 25 kVA, 65 [deg]C, single-
phase, round tank. phase, 60Hz, 14400V
primary, 120/240V
secondary, round tank, 125
kV BIL.
3.................. Liquid-immersed, single- 250-833 500 kVA, 65 [deg]C, single-
phase. phase, 60Hz, 14400V
primary, 277V secondary,
150kV BIL.
2................... 4.................. Liquid-immersed, three- 15-500 150 kVA, 65 [deg]C, three-
phase. phase, 60Hz, 12470Y/7200V
primary, 208Y/120V
secondary, 95kV BIL.
5.................. Liquid-immersed, three- 750-2500 1500 kVA, 65 [deg]C, three-
phase. phase, 60Hz, 24940GrdY/
14400V primary, 480Y/277V
secondary, 125 kV BIL.
3................... 6.................. Dry-type, low-voltage, 15-333 25 kVA, 150 [deg]C, single-
single-phase. phase, 60Hz, 480V primary,
120/240V secondary, 10kV
BIL.
4................... 7.................. Dry-type, low-voltage, 15-150 75 kVA, 150 [deg]C, three-
three-phase. phase, 60Hz, 480V primary,
208Y/120V secondary, 10kV
BIL.
8.................. Dry-type, low-voltage, 225-1000 300 kVA, 150 [deg]C, three-
three-phase. phase, 60Hz, 480V Delta
primary, 208Y/120V
secondary, 10kV BIL.
6................... 9.................. Dry-type, medium-voltage, 15-500 300 kVA, 150 [deg]C, three-
three-phase, 20-45kV BIL. phase, 60Hz, 4160V Delta
primary, 480Y/277V
secondary, 45kV BIL.
[[Page 7311]]
10................. Dry-type, medium-voltage, 750-2500 1500 kVA, 150 [deg]C, three-
three-phase, 20-45kV BIL. phase, 60Hz, 4160V
primary, 480Y/277V
secondary, 45kV BIL.
8................... 11................. Dry-type, medium-voltage, 15-500 300 kVA, 150 [deg]C, three-
three-phase, 46-95kV BIL. phase, 60Hz, 12470V
primary, 480Y/277V
secondary, 95kV BIL.
12................. Dry-type, medium-voltage, 750-2500 1500 kVA, 150 [deg]C, three-
three-phase, 46-95kV BIL. phase, 60Hz, 12470V
primary, 480Y/277V
secondary, 95kV BIL.
10.................. 13A................ Dry-type, medium-voltage, 75-833 300 kVA, 150 [deg]C, three-
three-phase, 96-150kV BIL. phase, 60Hz, 24940V
primary, 480Y/277V
secondary, 125kV BIL.
13B................ Dry-type, medium-voltage, 225-2500 2000 kVA, 150 [deg]C, three-
three-phase, 96-150kV BIL. phase, 60Hz, 24940V
primary, 480Y/277V
secondary, 125kV BIL.
----------------------------------------------------------------------------------------------------------------
* EC means equipment class (see Chapter 3 of the TSD). DOE did not select any representative units from the
single-phase, medium-voltage equipment classes (EC5, EC7 and EC9), but calculated the analytical results for
EC5, EC7, and EC9 based on the results for their three-phase counterparts.
3. Design Option Combinations
There are many different combinations of design options that could
be considered for each representative unit DOE analyzes. While DOE
cannot consider all the possible combinations of design options, DOE
attempts to select design option combinations that are common in the
industry while also spanning the range of possible efficiencies for a
given DL. For each design option combination chosen, DOE evaluates 518
designs based on different A and B factor \26\ combinations. For the
engineering analysis, DOE reused many of the design option combinations
that were analyzed in the previous rulemaking for distribution
transformers.
---------------------------------------------------------------------------
\26\ A and B factors correspond to loss valuation and are used
by DOE to generate distribution transformers with a broad range of
performance and design characteristics.
---------------------------------------------------------------------------
For the preliminary analysis, DOE considered a design option
combination that uses an amorphous steel core for each of the dry-type
design lines, whereas DOE's previous rulemaking did not consider
amorphous steel designs for the dry-type design lines. Instead, DOE had
considered H-0 domain refined (H-0 DR) steel as the maximum-
technologically feasible design. However, DOE is aware that amorphous
steel designs are now used in dry-type distribution transformers.
Therefore, DOE considered amorphous steel designs for each of the dry-
type transformer design lines in the preliminary analysis.
During preliminary interviews with manufacturers, DOE received
comment that it should consider additional design option combinations
using aluminum for the primary conductor rather than copper. While
manufacturers commented that copper is still used for the primary
conductor in many distribution transformers, they noted that aluminum
has become relatively more common. This is due to the relative prices
of copper and aluminum. In recent years, copper has become even more
expensive compared to aluminum.
DOE also noted that certain design lines were lacking a design to
bridge the efficiency values between the lowest efficiency amorphous
designs and the next highest efficiency designs. In an effort to close
that gap for the preliminary analysis, DOE evaluated ZDMH and M2 core
steel as the highest efficiency designs below amorphous for the liquid-
immersed design lines. Similarly, DOE evaluated H-0 DR and M3 core
steel as the highest efficiency designs below amorphous for dry-type
design lines.
The joint comments submitted by NPCC and NEEA as well as those
submitted by ASAP, ACEEE, and NRDC indicated that DOE should include
these supplementary designs in the reference case analysis for the
NOPR. (NPCC/NEEA, No. 11 at pp. 5-6; ASAP/ACEEE/NRDC, No. 28 at p. 3)
NPCC and NEEA added that DOE should consider all potential design
options in its analyses to ensure that all the cost-effective means of
reaching higher efficiencies have been considered. (NPCC/NEEA, No. 11
at p. 4) For example, several stakeholders recommended that DOE examine
wound core designs for its analysis of dry-type distribution
transformers. (NPCC/NEEA, No. 11 at pp. 2, 4-5; EMS, Pub. Mtg. Tr., No.
34 at p. 86; PG&E, Pub. Mtg. Tr., No. 34 at p. 87; ASAP, Pub. Mtg. Tr.,
No. 34 at p. 88) Joint comments from ASAP, ACEEE, and NRDC and PG&E and
SCE noted that DOE should consider wound core designs for its low-
voltage dry-type design lines, where high sales volume could better
justify the additional equipment and tooling costs of switching to
wound core production. (ASAP/ACEEE/NRDC, No. 28 at p. 3; PG&E/SCE, No.
32 at p. 1; PG&E, Pub. Mtg. Tr., No. 34 at p. 261) Lastly, HVOLT noted
that wound cores in kVA sizes beyond 300 kVA will tend to buzz, but Hex
Tec clarified that the wound cores used in symmetric core designs above
300 kVA do not induce any additional audible sound. (HVOLT, Pub. Mtg.
Tr., No. 34 at p. 51; Hex Tec, Pub. Mtg. Tr., No. 34 at p. 51)
DOE clarifies that although it was not done so in the preliminary
analysis, DOE has incorporated its supplementary designs into the
reference case for the NOPR analysis. Additionally, DOE aims to
consider the most popular design option combinations, and the design
option combinations that yield the greatest improvements in efficiency.
While DOE is unable to consider all potential design option
combinations, it does consider multiple designs for each representative
unit and has considered additional design options in its NOPR analysis
based on stakeholder comments.
As for wound core designs, DOE did consider analyzing them for all
of its dry-type representative units that are 300 kVA or less in the
NOPR. However, based on limited availability in the United States, DOE
did not believe that it was feasible to include these designs in their
final engineering results. For similar availability reasons, DOE chose
to exclude its wound core ZDMH and M3 designs from its low-voltage dry-
type analysis. Based on how uncommon these designs are in the current
market, DOE believes that it would be unrealistic to include them in
engineering curves without major adjustments.
DOE did not consider wound core designs for DLs 10, 12, and 13B
because they are 1500 kVA and larger. DOE understands that conventional
wound core designs in these large kVA ratings will emit an audible
``buzzing'' noise, and will experience an efficiency penalty that grows
with kVA rating such
[[Page 7312]]
that stacked core is more attractive. DOE notes, however, that it does
consider a wound core amorphous design in each of the dry-type design
lines.
DOE also received interested party feedback indicating that DOE
should consider step-lap miter designs for its dry-type design lines.
(NPCC/NEEA, No. 11 at p. 4; Metglas, Pub. Mtg. Tr., No. 34 at p. 91) In
the preliminary analysis, DOE had only analyzed fully-mitered designs
for the dry-type design lines, but stakeholders noted that step-lap
miter designs could potentially yield greater efficiencies than the
fully-mitered designs. However, during the negotiations process,
interested parties clarified that step-lap mitering may not be cost-
effective in the smaller dry-type designs because the smaller average
steel piece size gives rise to a larger destruction factor, and larger
losses, than would be predicted by modeling. (ONYX, Pub. Mtg. Tr., No.
30 at p. 43) Stakeholders agreed that it would not be appropriate to
consider step-lap mitering for design line 6, a 25 kVA unit, to reflect
its scarcity or absence from the market. Therefore, in the NOPR DOE
analyzed step-lap miter designs for each of the dry-type design lines
except design line 6.
In the preliminary analysis, DOE considered several premium grade
core steels. It examined H0-DR, ZDMH, and SA1 amorphous core steels in
its designs, as well as the standard M-grade steels. DOE requested
comment on whether there were other premium grade core steels that
should be considered in the analysis. ABB commented that ZDMH, H0-DR,
and SA1 amorphous steels cover all the high performance core steel
grades that are currently commercially available. (ABB, No. 14 at p.
13) Therefore, DOE continued to analyze them for the NOPR and did not
consider any additional premium core steels.
DOE did opt to add two design option combinations that incorporate
M-grade steels that have become popular choices at the current standard
levels. For all medium-voltage, dry-type design lines (9-13B), DOE
added a design option combination of an M4 step-lap mitered core with
aluminum primary and secondary windings. For design line 8, DOE added a
design option combination of an M6 fully mitered core with aluminum
primary and secondary windings. DOE understands both combinations to be
prevalent baseline options in the present transformer market.
For the NOPR analysis, DOE also made the decision to remove certain
high flux density designs from DL7 in order to be consistent with
designs submitted by manufacturers.\27\ There is a variety of reasons
that manufacturers would choose to limit flux density (e.g., vibration,
noise). Further detail on this change can be found in chapter 5 of the
TSD.
---------------------------------------------------------------------------
\27\ During the negotiations process, DOE's subcontractor,
Navigant Consulting, Inc. (Navigant), participated in a
bidirectional exchange of engineering data in an effort to validate
the OPS designs generated for the engineering analysis.
---------------------------------------------------------------------------
4. A and B Loss Value Inputs
As discussed, one of the primary inputs to the OPS software is an A
and B combination for customer loss evaluation. In the preliminary
analysis, DOE generated each transformer design in the engineering
analysis based upon an optimized lowest total owning cost evaluation
for a given combination of A and B values. Again, the A and B values
represent the present value of future core and coil losses,
respectively and DOE generated designs for over 500 different A and B
value combinations for each of the design option combinations
considered in the analysis.
In response to the preliminary analysis, Berman Economics commented
that designing a transformer to total owning cost based on A and B
factors will result in a higher first cost transformer than a design
that aims to minimize first cost for a given efficiency level. (BE, No.
16 at p. 6) Additionally, Berman Economics noted that many utilities
and customers do not specify an A and B value when ordering
transformers, and will just ask for the lowest first cost design. (BE,
Pub. Mtg. Tr., No. 34 at p. 123)
DOE notes that the designs created in the engineering analysis span
a range of costs and efficiencies for each design option combination
considered in the analysis. This range of costs and efficiencies is
determined by the range of A and B factors used to generate the
designs. Although DOE does not generate a design for every possible A
and B combination, because there are infinite variations, DOE believes
that its 500-plus combinations have created a sufficiently broad design
space. By using so many A and B factors, DOE is confident that it
produces the lowest first cost design for a given efficiency level and
also the lowest total owning cost design. Furthermore, although all
distribution transformer customers do not purchase based on total
owning cost, the A and B combination is still a useful tool that allows
DOE to generate a large number of designs across a broad range of
efficiencies and costs for a particular design line. Finally, OPS noted
at the public meeting that its design software requires A and B values
as inputs. (OPS, Pub. Mtg. Tr., No. 34 at p. 123) For all of these
reasons, DOE continued to use A and B factors in the NOPR to generate
the range of designs for the engineering analysis.
5. Materials Prices
In distribution transformers, the primary materials costs come from
electrical steel used for the core and the aluminum or copper conductor
used for the primary and secondary winding. As these are commodities
whose prices frequently fluctuate throughout a year and over time, DOE
attempted to account for these fluctuations by examining prices over
multiple years. For the preliminary analysis, DOE conducted the
engineering analysis analyzing materials price information over a five-
year time period from 2006-2010, all in constant 2010$. Whereas DOE
used a five-year average price in the previous rulemaking for
distribution transformers, for the preliminary analysis in this
rulemaking, DOE selected one year from its five-year time frame as its
reference case, namely 2010. Additionally, DOE considered high and low
materials price sensitivities from that same five-year time frame, 2008
and 2006 respectively.
DOE decided to use current (2010) materials prices in its analysis
for the preliminary analysis because of feedback from manufacturers
during interviews. Manufacturers noted the difficulty in choosing a
price that accurately projects future materials prices due to the
recent variability in these prices. Manufacturers also commented that
the previous five years had seen steep increases in materials prices
through 2008, after which prices declined as a result of the global
economic recession. Further detail on these factors can be found in
appendix 3A. Due to the variability in materials prices over this five-
year timeframe, manufacturers did not believe a five-year average price
would be the best indicator, and recommended using the current
materials prices.
To estimate its materials prices, DOE spoke with manufacturers,
suppliers, and industry experts to determine the prices paid for each
raw material used in a distribution transformer in each of the five
years between 2006 and 2010. While prices fluctuate during the year and
can vary from manufacturer to manufacturer depending on a number of
variables, such as the purchase quantity, DOE attempted to develop an
average materials price for the year based on the price a medium to
large manufacturer would pay.
[[Page 7313]]
In general, stakeholders agreed with DOE's approach for analyzing
materials prices in the preliminary analysis. Power Partners and EEI
agreed with DOE's approach of using 2010 materials prices in the
reference case and examining alternate years' materials prices as
sensitivities. (PP, Pub. Mtg. Tr., No. 34 at p. 100; EEI, Pub. Mtg.
Tr., No. 34 at p. 100) Howard Industries noted that 2010 prices are
reasonable for the reference case as long as DOE uses the 2010 prices
with any additional design runs. (HI, No. 23 at p. 6) Similarly, ABB
agreed with DOE's approach to use a single reference year, such as
2010, for the materials prices, and noted that materials prices are
reaching an all-time high in 2011. (ABB, No. 14 at p. 14) Finally,
Power Partners commented that DOE did a reasonable job grouping the
various wire sizes into ranges. (PP, Pub. Mtg. Tr., No. 34 at p. 118)
Conversely, Southern Company and FPT commented that DOE's approach
for generating reference case materials prices could be improved.
Southern Company noted that 2010 materials prices may be lower than
future materials prices once the economy improves and there is a
limited availability of supplies coupled with increased demand. (SC,
No. 22 at p. 4) FPT also commented that DOE should consider whether
there will be an adequate supply of higher grade core steels at the
price points identified in the analysis, noting that smaller
manufacturers are likely not able to purchase materials at the same
price points as larger manufacturers and may have to pay more,
especially if there is an increase in demand resulting from amended
standards. (FPT, No. 27 at p. 2)
With the onset of the negotiations, DOE was presented with an
opportunity to implement a 2011 materials price case based on data it
had gathered before and during the negotiation proceedings. Relative to
the 2010 case, the 2011 prices were lower for all steels, particularly
M2 and lower grade steels.
For the NOPR, DOE continued to use the 2010 materials prices as a
reference case scenario, but added a second, 2011 price case. DOE
presents both cases as recent examples of how the steel market
fluctuates and uses both to derive economic results. It also considered
high and low price scenarios based on the 2008 and 2006 materials
prices, respectively, but adjusted the prices in each of these years to
consider greater diversity in materials prices. For the high price
scenario, DOE increased the 2008 prices by 25 percent, and for the low
price scenario, DOE decreased the 2006 prices by 25 percent as
additional sensitivity analyses. DOE believes that these price
sensitivities accurately account for any pricing discrepancies
experienced by smaller or larger manufacturers, and adequately consider
potential price fluctuations.
NPCC and NEEA jointly commented that DOE should forecast future
materials prices based on spot commodities future prices. (NPCC/NEEA,
No. 11 at pp. 6-7) Similarly, FPT commented that 2010 materials prices
may not be a good indication of future steel prices, which will likely
increase. (FPT, No. 27 at p. 12) On the other hand, Berman Economics
commented that the pricing of core steels over the past few years has
declined, even though standard levels have shifted the market to higher
core steel grades. As a result, Berman Economics stated that core steel
production could be expected to expand in light of new energy
conservation standards without any significant impacts on the materials
prices. (BE, No. 16 at p. 10)
For the engineering analysis, DOE did not attempt to forecast
future materials prices. DOE continued to use the 2010 materials price
in the reference case scenario, added a 2011 reference scenario, and
also considered high and low sensitivities to account for any potential
fluctuations in materials prices. The LCC and NIA consider a scenario,
however, in which transformer prices increase in the future based on
increasing materials prices, among other variables. Further detail on
this scenario can be found in chapter 8 of the TSD.
Several stakeholders commented that the average materials prices
DOE calculated for the 2006-2010 timeframe, particularly for year 2010,
were not accurate. NEMA recommended that DOE gather additional
information from manufacturers on this topic. (NEMA, No. 13 at p. 6)
FPT commented that DOE's price of $2.38 per pound for amorphous steel
appeared to be low, and questioned whether the price had been verified
with suppliers of amorphous material. Joint comments submitted by ASAP,
ACEEE, and NRDC stated that DOE's materials prices were too high
compared to market prices in 2010. (ASAP/ACEEE/NRDC, No. 28 at p. 2)
HVOLT commented that DOE's prices for copper and aluminum were
understated, noting that current copper prices are around $6.50.
(HVOLT, No. 33 at p. 1; HVOLT, Pub. Mtg. Tr., No. 34 at p. 117) Power
Partners commented that the prices for aluminum wire were too high and
that prices for copper wire were too low, suggesting that DOE derive
its conductor prices by adding a processing cost to the COMEX or London
Metal Exchange (LME) indices. (PP, Pub. Mtg. Tr., No. 34 at pp. 100,
118; PP, No. 19 at p. 3) To this point, Hex Tec added that the
fabrication cost varies by wire size. (HEX, Pub. Mtg. Tr., No. 34 at p.
118)
For the NOPR, DOE reviewed its materials prices during interviews
with manufacturers and industry experts and revised its materials
prices for copper and aluminum conductors. As suggested by Power
Partners, DOE derived these prices by adding a processing cost
increment to the underlying index price. DOE determined the current
2011 index price from the LME and COMEX. These indices only had current
2011 values available, so DOE used the producer price index for copper
and aluminum to convert the 2011 index price into prices for the time
period of 2006-2010. DOE then applied a unique processing cost adder to
the index price for each of its conductor groupings. To derive the
adder price, DOE compared the difference in the LME index price to the
2011 price paid by manufacturers, and applied this difference to the
index price in each year. DOE inquired with many manufacturers, both
large and small, to derive these prices. Further detail can be found in
chapter 5 of the TSD.
DOE reviewed core steel prices with manufacturers and industry
experts and found them to be accurate within the range of prices paid
by manufacturers in 2010. However, based on feedback in negotiations,
DOE adjusted steel prices for M4 grade steels and lower grade steels.
As for FPT's concern regarding prefabricated amorphous cores,
estimated at $2.38 per pound in 2010, DOE notes that this price was
derived from speaking with several North American suppliers of
prefabricated amorphous cores, and aligns with marked-up price
estimates for raw amorphous ribbon. Therefore, so DOE continued to use
this price estimate in the NOPR for the 2010 price scenario.
6. Markups
DOE derived the manufacturer's selling price for each design in the
engineering analysis by considering the full range of production costs
and non-production costs. The full production cost is a combination of
direct labor, direct materials, and overhead. The overhead contributing
to full production cost includes indirect labor, indirect material,
maintenance, depreciation, taxes, and insurance related to company
assets. Non-production cost includes the cost of selling, general and
administrative items (market research, advertising, sales
representatives, and
[[Page 7314]]
logistics), research and development (R&D), interest payments, warranty
and risk provisions, shipping, and profit factor. Because profit factor
is included in the non-production cost, the sum of production and non-
production costs is an estimate of the manufacturer's selling price.
DOE utilized various markups to arrive at the total cost for each
component of the distribution transformer. These markups are outlined
in greater detail in chapter 5 of the TSD.
NPCC and NEEA jointly commented that DOE should vet the non-
production markup with manufacturers to ensure that it is accurate.
(NPCC/NEEA, No. 11 at p. 6) Berman Economics added that manufacturers
do not price their units in the same way that DOE did in its analysis;
rather, they look at their costs and the market and generate a
competitive price accordingly. Therefore, Berman Economics suggested
that DOE only look at the material and labor costs and refrain from
including the other markups. (BE, Pub. Mtg. Tr., No. 34 at p. 96)
DOE interviewed manufacturers of distribution transformers and
related products to learn about markups, among other topics, and
observed a number of very different practices. In absence of a
consensus, DOE attempted to adapt manufacturer feedback to inform its
current modeling methodology while acknowledging that it may not
reflect the exact methodology of many manufacturers. DOE feels that it
is necessary to model markups, however, since there are costs other
than material and labor that affect final manufacturer selling price.
The following sections describe various facets of DOE's markups for
distribution transformers.
a. Factory Overhead
DOE uses a factory overhead markup to account for all indirect
costs associated with production, indirect materials and energy use
(e.g., annealing furnaces), taxes, and insurance. In the preliminary
analysis, DOE derived the cost for factory overhead by applying a 12.5
percent markup to direct material production costs.
Several stakeholders commented that factory overhead is more
commonly estimated as a markup on labor costs, not material costs.
(NPCC/NEEA, No. 11 at pp. 2, 6; ASAP/ACEEE/NRDC, No. 28 at p. 2; PP,
Pub. Mtg. Tr., No. 34 at p. 102; HEX, Pub. Mtg. Tr., No. 34 at p. 103)
ABB commented that factory overhead should not be tied to direct
material costs, but rather to the design option being produced and the
volume being produced, using a fixed quantity for factory overhead
based on the design option. (ABB, No. 14 at pp. 14-15)
DOE appreciates the comments and considered other approaches for
calculating factory overhead for the NOPR. However, DOE was unable to
determine an alternate methodology that could accurately estimate
factory overhead costs. In the absence of further information for how
to calculate factory overhead based on labor costs or design options,
DOE continued to use its approach based on the material production
costs. DOE notes that factory overhead costs are not applied to the
material production cost component, but are simply estimated based on
the production costs.
In the preliminary analysis, DOE applied the same factory overhead
markup to its prefabricated amorphous cores as it did to its other
design options where the manufacturer was assumed to produce the core.
Since the factory overhead markup accounts for indirect production
costs that are not easily tied to a particular design, it was applied
consistently across all design types. DOE did not find that there was
sufficient substantiation to conclude that manufacturers would apply a
reduced overhead markup for a design with a prefabricated core.
Hammond Power Systems and Howard Industries agreed with DOE's
decision to apply the same factory overhead to prefabricated amorphous
cores. (HPS, No. 3 at p. 4; HI, No. 23 at p. 6) On the other hand, NPCC
and NEEA jointly commented that factory overhead should not be applied
to prefabricated cores because the markup would already be included in
the selling price of the prefabricated core. (NPCC/NEEA, No. 11 at p.
7) ABB, however, noted that even though manufacturers may outsource
various components of the transformer manufacturing, such as
enclosures, cores, or coils, DOE should assume a vertical manufacturing
process in which the manufacturer produces all components in-house.
(ABB, No. 14 at pp. 14-15) NEMA commented that DOE should gather
additional data from individual manufacturers on the topic of factory
overhead. (NEMA, No. 13 at p. 6)
For the NOPR analysis, DOE continued to apply the same factory
overhead markup to prefabricated amorphous cores as to other cores
built in-house. This approach is consistent with the suggestion of the
manufacturers, and DOE notes that factory overhead for a given design
applies to many items aside from the core production. Furthermore,
since DOE already accounts for decreased labor hours in its designs
using prefabricated amorphous cores, but also considers an increased
core price based on a prefabricated core rather than the raw amorphous
material, it already accounts for the tradeoffs associated with
developing the core in-house versus outsourced.
During negotiations, DOE learned from both manufacturers of
transformers and manufacturers of transformer cores that mitering and,
to a greater extent, step-lap mitering, result in a per-pound cost of
finished cores higher than butt-lapped units built to the same
specifications. (ONYX, Pub. Mtg. Tr., No. 30 at p. 43) This helps to
account for the fact that butt-lapping is common at baseline
efficiencies in today's low-voltage market.
In response, DOE opted to increase mitering costs for both low- and
medium-voltage dry-type designs. In the medium-voltage case, DOE
incorporated a processing cost of 10 cents per core pound for step-lap
mitering. In the low-voltage case, DOE incorporated a processing cost
of 10 cents per core pound for ordinary mitering and 20 cents per core
pound for step-lap mitering. DOE used different per pound adders for
step-lap mitering for medium-voltage and low-voltage units because the
base case design option for each is different. For low-voltage units,
DOE modeled butt-lapped designs at the baseline efficiency level
whereas ordinary mitering was modeled at the baseline for medium-
voltage. Therefore, using a step-lap mitered core represents a more
significant change in technology for low-voltage dry-type transformers
and thus the higher markup.
b. Labor Costs
In the preliminary analysis, DOE accounted for additional labor and
material costs for large (>=1500 kVA), dry-type designs using amorphous
metal. The additional labor costs accounted for special handling
considerations, since the amorphous material is very thin and can be
difficult to work with in such a large core. They also accounted for
extra bracing that is necessary for large, wound core, dry-type designs
in order to prevent short circuit problems.
NPCC, NEEA, and NEMA commented that DOE should consult individual
manufacturers to gather information about the additional costs DOE
associates with large amorphous designs. (NPCC/NEEA, No. 11 at p. 6;
NEMA, No. 13 at p. 6) NPCC and NEEA added that DOE should consider a
range of assumed incremental costs starting at zero when analyzing
amorphous core designs. (NPCC/NEEA, No. 11 at p. 7)
[[Page 7315]]
Several manufacturers also commented on the issue of additional
costs for large amorphous designs. Howard Industries commented that
these designs face similar cost increases as those that DOE identified
for large dry-type designs using an amorphous core. It noted that
typically these liquid-immersed designs require an additional 10 hours
of handling, added cost for the epoxy and catalyst used in sealing the
amorphous cores, and additional bracing depending on the weight of the
core/coil assembly. Howard Industries estimated this cost as an extra
$100 to $200 for additional materials and hardware. (HI, No. 23 at p.
6)
ABB commented that if DOE accounts for additional labor and
material costs for large amorphous designs, then it should apply the
same logic to all design options, and also noted that large liquid-
immersed amorphous designs would have the same costs as the dry-type
designs. ABB noted that large wound cores would have more labor and
hardware compared to small wound cores, and that stacked cores will
have more labor than wound cores. Finally, ABB noted that stacked M2
would require more labor than stacked M6 steel. (ABB, No. 14 at p. 15)
Power Partners commented that DOE needed to add in additional assembly
time for liquid-immersed transformers using amorphous cores. (PP, Pub.
Mtg. Tr., No. 34 at p. 102) Finally, Hex Tec noted that certain core
construction methods (e.g., symmetric core designs) make the handling
of amorphous material much easier, which can eliminate the need for
extra handling. (HEX, Pub. Mtg. Tr., No. 34 at p. 103)
During negotiations, Federal Pacific commented that it believed DOE
was underestimating labor hours for core assembly for all low- and
medium-voltage dry-type design lines.
In response to interested party feedback, DOE applied an
incremental increase in core assembly time to amorphous designs in the
liquid-immersed design line 5 (1500 kVA). This additional core assembly
time of 10 hours is consistent with DOE's treatment of amorphous
designs in large, dry-type design lines. However, DOE did not account
for additional hardware costs for bracing in the liquid-immersed
designs using amorphous cores. This is because DOE already accounts for
bracing costs for all of its liquid-immersed designs, which use wound
cores, in its analysis. DOE determined that it adequately accounted for
these bracing costs in the smaller kVA sizes using amorphous designs,
and thus only made the change to the large (>=1500 kVA) design lines.
DOE did not model varying incremental cost increases starting with zero
for large amorphous designs, as NEEA and NPCC suggested, noting that
the impact of these incremental costs are oftentimes very minor for
large, expensive transformer designs. In response to Federal Pacific's
comment and data from other manufacturers of medium- and low-voltage
transformers, DOE explored its estimates of labor hours and increased
those relating to core assembly for design lines 6-13B. Details on the
specific values of the adjustments can be found in chapter 5 of the
TSD.
Finally, in response to ABB's comment that DOE should apply
different labor and material costs to each design option in the
analysis, DOE notes that it already does account for costs differently
based on the design options used. Labor requirements are, for example,
determined in part based on the grade of core steel, the core weight,
and the number of turns in the winding. Similarly, material costs are
determined specific to each material input based on each design's
specifications.
c. Shipping Costs
During its interviews with manufacturers in the preliminary
analysis, DOE was informed that manufacturers often pay shipping
(freight) costs to the customer. Manufacturers indicated that they
absorb the cost of shipping the units to the customer and that they
include these costs in their total cost structure when calculating
profit markups. As such, manufacturers apply a profit markup to their
shipping costs just like any other cost of their production process.
Manufacturers indicated that these costs typically amount to anywhere
from four to eight percent of revenue.
In the previous rulemaking for distribution transformers, DOE
accounted for shipping costs exclusively in the LCC analysis. These
costs were paid by the customer, and thus did not include a markup from
the manufacturer based on its profit factor. In the preliminary
analysis, DOE included shipping costs in the manufacturer's cost
structure, which is then marked up by a profit factor. These shipping
costs account for delivering the units to the customer, who may then
bear additional shipping costs to deliver the units to the final end-
use location. As such, DOE accounts for the first leg of shipping costs
in the engineering analysis and then any subsequent shipping costs in
the LCC analysis. The shipping cost was estimated to be $0.22 per pound
of the transformer's total weight and typically amounts to four to
eight percent of the total MSP. DOE derived the $0.22 per pound by
relying on the shipping costs developed in its previous rulemaking on
distribution transformers, when DOE collected a sample of shipping
quotations for transporting transformers. In that rulemaking, DOE
estimated shipping costs as $0.20 per pound based on an average
shipping distance of 1,000 miles. For the preliminary analysis, DOE
updated the cost to $0.22 per pound based on the price index for
freight shipping between 2007 and 2010. Additional detail on these
shipping costs can be found in chapter 5 and chapter 8 of the TSD.
DOE received several comments about the methodology for deriving
shipping costs. NEMA commented that DOE should gather additional
information from manufacturers. (NEMA, No. 13 at p. 6) Federal Pacific
commented that weight increases as transformers become more efficient,
and noted that shipping costs would thus increase if standards were
amended. (FPT, No. 27 at pp. 4-5) Several stakeholders commented that
DOE should consider the cost of fuel in its shipping cost calculation,
particularly since it has increased in recent years. (NRECA/T&DEC, No.
31 and 36 at p. 3; EEI, Pub. Mtg. Tr., No. 34 at p. 95; EEI, No. 29 at
p. 5) NPCC and NEEA jointly commented that shipping costs will increase
with time as diesel fuel prices rise. (NPCC/NEEA, No. 11 at p. 7)
For the NOPR, DOE revised its shipping cost estimate to account for
the rising cost of diesel fuel. DOE adjusted its previous shipping cost
of $0.20 (in 2006 dollars) from the previous rulemaking to a 2011 cost
based on the producer price index for No. 2 diesel fuel. This yielded a
shipping cost of $0.28 per pound. DOE also retained its shipping cost
calculation based on the weight of the transformer to differentiate the
shipping costs between lighter and heavier, typically more efficient,
designs.
In the preliminary analysis, DOE applied a non-production markup to
all cost components, including shipping costs, to derive the MSP. DOE
based this cost treatment on the assumption that manufacturers would
mark up the shipping costs when calculating their final selling price.
The resulting shipping costs were, as stated, approximately four to
eight percent of total MSP.
During the public meeting, ASAP asked if DOE had found market data
that indicated that shipping costs should be included in the sale
price. (ASAP, Pub. Mtg. Tr., No. 34 at p. 102) HPS
[[Page 7316]]
commented that DOE's assumption that shipping costs are typically four
to eight percent of MSP is accurate, but noted that it does not
typically mark up shipping costs. (HPS, No. 3 at p. 5) ABB commented
that shipping costs are recognized as an expense to manufacturers, but
that they do not impact the profit markup of the manufacturer because
transformers must be priced based on the market. Rather, shipping costs
reduce the profit of the sale. Additionally, ABB noted that shipping
costs are typically only two to four percent of total transformer
costs. (ABB, No. 14 at p. 15) Similarly, Federal Pacific commented that
manufacturers bear the cost of shipping, but they do not mark up the
shipping cost in their profit markup or other markups. (FPT, No. 27 at
p. 17) Conversely, Howard Industries agreed with DOE's approach in
which markups were applied to the cost of shipping. Howard Industries
added that it agreed that shipping costs are typically four to eight
percent of revenues. (HI, No. 23 at p. 6)
Based on the comments received and DOE's additional research into
the treatment of shipping costs through manufacturer interviews, DOE
has preliminarily decided to retain the shipping costs in its
calculation of MSP, but not to apply any markups to the shipping cost
component. Therefore, shipping costs were added separately into the MSP
calculation, but not included in the cost basis for the non-production
markup. The resulting shipping costs were still in line with the
estimate of four to eight percent of MSP for all the dry-type design
lines. For the liquid-immersed design lines, the shipping costs ranged
from six to twelve percent of MSP and averaged about nine percent of
MSP.
7. Baseline Efficiency and Efficiency Levels
DOE analyzed designs over a range of efficiency values for each
representative unit. Within the efficiency range, DOE developed designs
that approximate a continuous function of efficiency. However, DOE only
analyzes incremental impacts of increased efficiency by comparing
discrete efficiency benchmarks to a baseline efficiency level. The
baseline efficiency level evaluated for each representative unit is the
existing energy conservation standard level of efficiency for
distribution transformers established either in DOE's previous
rulemaking or by EPACT 2005. The incrementally higher efficiency
benchmarks are referred to as ``efficiency levels'' (ELs) and, along
with MSP values, characterize the cost-efficiency relationship above
the baseline. These ELs are ultimately used by DOE if it decides to
amend the existing energy conservation standards.
For the NOPR, DOE considered several criteria when setting ELs.
First, DOE harmonized the efficiency values across single-phase
transformers and the per-phase kVA equivalent three-phase transformers.
For example, a 50 kVA single-phase transformer would have the same
efficiency requirement as a 150 kVA three-phase transformer. This
approach is consistent with DOE's methodology from the previous
rulemaking and from the preliminary analysis of this rulemaking.
Therefore, DOE selected equivalent ELs for several of the
representative units that have equivalent per-phase kVA ratings.
Second, DOE selected equally spaced ELs by dividing the entire
efficiency range into five to seven evenly spaced increments. The
number of increments depended on the size of the efficiency range. This
allowed DOE to examine impacts based on an appropriate resolution of
efficiency for each representative unit.
Finally, DOE adjusted the position of some of the equally spaced
ELs and examined additional ELs. These minor adjustments to the equally
spaced ELs allowed DOE to consider important efficiency values based on
the results of the software designs. For example, DOE adjusted some ELs
slightly up or down in efficiency to consider the maximum efficiency
potential of non-amorphous design options. Other ELs were added to
consider important benchmark efficiencies, such as the NEMA Premium
efficiency levels for LVDT distribution transformers. Last, DOE
considered additional ELs to characterize the maximum-technologically
feasible design for representative units where the harmonized per-phase
efficiency value would have been unachievable for one of the
representative units.
EEI requested that DOE provide summary tables of the ELs and the
proposed TSLs to highlight any differences between the two. (EEI, Pub.
Mtg. Tr., No. 34 at p. 125) Furthermore, EEI pointed out that CSL 0 is
TSL 3 or 4 from the last rulemaking and is more efficient than a 2005
or 2007 unit. (EEI, Pub. Mtg. Tr., No. 34 at p. 113)
NEMA recommended that the TSLs from the previous rulemaking be
visually overlaid with the ELs from this rulemaking to allow easier
comparisons between the recent standards and the current rulemaking.
(NEMA, No. 13 at pp. 6-7)
Schneider Electric commented that it would like to see the label
``CSL 0'' removed from the analysis and instead replaced with exactly
what those levels were and where it was mandated, i.e., in EISA 2007.
(SE., Pub. Mtg. Tr., No. 34 at p. 119)
DOE has found that multiple sets of efficiency levels and candidate
standard levels have confused stakeholders in the past, and prefers to
limit this document's discussion to those ELs at hand. EEI is correct
to point out that the previous rule's standard is the current rule's
baseline. DOE is statutorily prohibited from decreasing efficiency
standards, and so any discussion of future standards necessarily begins
with what is in effect at the time.
Berman Economics noted that high-cost designs that are above the
minimum first cost amount for a given EL should not be considered in
DOE's analysis because they do not represent the cost required to
comply with the standard. It felt that, by including these designs, DOE
artificially increases the cost estimate from the Monte Carlo analysis.
(BE, No. 16 at pp. 6-7)
Although DOE's current test procedure specifies a load value at
which to test transformers, DOE recognizes that different consumers see
real-world loadings that may be higher or lower. In those cases,
consumers may choose a transformer offering a lower LCC even when faced
with a higher first cost. If DOE's cost/efficiency design cloud were
redrawn to reflect loadings other than those specified in the test
procedure, different designs would migrate to the optimum frontier of
the cloud. Additionally, although DOE's engineering analysis reflects a
range of transformers costs for a given EL, the LCC analysis only
selects transformer designs near the lowest cost point.
8. Scaling Methodology
For the preliminary analysis, DOE performed a detailed analysis on
each representative unit and then extrapolated the results of its
analysis from the unit studied to the other kVA ratings within that
same engineering design line. DOE performed this extrapolation to
develop inputs to the national impacts analysis. The technique it used
to extrapolate the findings of the representative unit to the other kVA
ratings within a design line is referred to as ``the 0.75 scaling
rule.'' This rule states that, for similarly designed transformers,
costs of construction and losses scale with the ratio of their kVA
ratings raised to the 0.75 power. The relationship is valid where the
optimum efficiency loading points of the two transformers being scaled
are the same. DOE used the same methodology to scale its findings
during
[[Page 7317]]
the previous rulemaking on distribution transformers.
In response to the preliminary analysis, DOE received multiple
comments regarding the 0.75 scaling rule. HVOLT expressed its support
for the use of the 0.75 scaling rule. (HVOLT, Pub. Mtg. Tr., No. 34 at
p. 139) Several other stakeholders stated that they believed the 0.75
scaling rule is accurate over small kVA ranges, but can break down near
the limits of the scaling range. (HPS, No. 3 at p.4; NPCC/NEEA, No. 11
at pp. 7-8; NEMA, No. 13 at pp. 4, 6; SE., No. 18 at p.7; HI, No. 23 at
p. 7; FPT, Pub. Mtg. Tr., No. 34 at p. 137) NPCC, NEEA and NEMA
recommended that DOE consider analyzing additional design lines and
representative units to maintain the integrity of the scaling. (NPCC/
NEEA, No. 11 at pp. 7-8; NEMA, No. 13 at pp. 4-6) FPT also suggested
introducing additional designs to the analysis, noting that it has
found it difficult to meet the efficiency levels on the lower-end kVAs
for the dry-types. (FPT, Pub. Mtg. Tr., No. 34 at p. 136) Schneider
Electric recommended that DOE expand its kVA ranges within the design
lines and overlay the design lines to allow for multiple evaluation
points within the scaling rule. (SE., No. 18 at p. 7) Howard Industries
believed that DOE should adjust the 0.75 scaling factor to account for
more efficient and costlier materials needed to stay within the size
and weight constraints of customers' demands. (HI, No. 23 at p. 7)
EEI commented that the 0.75 scaling rule may not be accurate for
scaling outside a single standard deviation of kVA size. EEI
recommended that DOE work with manufacturers to create new formulas for
scaling beyond a single standard deviation. (EEI, No. 29 at p. 6)
Warner Power stated that the 0.75 scaling rule is less accurate for
higher scaling ratios where transformer designs change significantly,
but felt that the rule was accurate for scaling where the ratio of kVAs
was between 0.8 and 1.2. (WP, No. 30 at pp. 7, 11)
ABB noted that the 0.75 scaling rule is accurate within about a
half order of magnitude when all other parameters are constant. ABB
also stated that in their experience the 0.75 coefficient increases as
the kVA decreases and approaches 1.0 as an upper limit. ABB added that
the same is true as the BIL increases. (ABB, No. 14 at pp. 10, 13)
Hammond agreed that the 0.75 scaling rule can be problematic for
smaller kVAs of higher voltage and BIL ratings. (HPS, No. 3 at p. 4)
Metglas explained that the scaling rule assumes one has the same
percentage insulation in the cross-section of the conductor in the
transformers while, in reality, as the transformers get smaller, more
insulation is needed to maintain the same BIL. FPT believed that the
0.75 scaling rule was less accurate for lower kVA ratings (below 500
kVA), in part because small kVA sizes require very small wires that are
dramatically more expensive than larger wires in larger kVA sizes. FPT
also claimed that current standards are more difficult to meet at the
lower kVA sizes. (FPT, No. 27 at pp. 14-17)
PP expressed frustration that the design work involved
extrapolating from a 500 kVA model to a 833 kVA model and believed that
the extrapolations did not hold true. (PP, Pub. Mtg. Tr., No. 34 at p.
135)
Because it is not practical to directly analyze every combination
of design options and kVAs under the rulemaking's scope of coverage,
DOE selected a smaller number of units it believed to be representative
of the larger scope. Many of the current design lines use
representative units retained from the 2007 rulemaking with minor
modifications. To generate efficiency values for kVA values not
directly analyzed, DOE employed a scaling methodology based on physical
principles (overviewed in Appendix 5B) and widely used by industry in
various forms. DOE's scaling methodology is an approximation and, as
with any approximation, can suffer in accuracy as it is extended
further from its reference value.
Several of the comments on this topic suggest that DOE could
improve the accuracy of its scaling by limiting the range over which it
is applied. To that end, DOE has added a design line (13A to address
the case of high BIL, small kVA medium-voltage dry-type units while
redesignating the former 13 ``13B''.) DOE will seek to corroborate
scaling results with direct analysis in other areas that fall outside
of the scaling ranges put forth by commenters for the final rule.
Additionally, DOE modified the way it splices extrapolations from
each representative unit to cover equipment classes at large.
Previously, DOE extrapolated curves from individual data points and
blended them near the boundaries to set standards. Currently, DOE fits
a single curve through all available data points in a space and
believes that the resulting curve will both be smoother and offer a
more robust scaling behavior over the covered kVA range.
Finally, although the laws of physics applied to an ideal
transformer yield a scaling exponent of 0.75, DOE recognizes that real-
world engineering considerations may produce a behavior better modeled
using a different exponent. A number of commenters suggested that the
smaller transformers in particular had difficulty meeting standards,
which seems to imply that the overall shape of the efficiency curve
should come from a lower overall exponent. This would tend to project
lower efficiencies at lower kVAs and higher efficiencies at higher
kVAs. DOE seeks to further understand how kVA rating and other factors
combine to affect transformer efficiency, and seeks comment to that
end.
Negotiating parties agreed that deriving results for the ``high''
and ``low'' BIL MVDT equipment classes, namely, 5,6,9, and 10, was the
most appropriate way to correctly establish relative standards such
that the various efficiencies were logical with respect to each other.
(ASAP, Pub. Mtg. Tr., No. (docket number
unavailable) at p. 175) Parties agreed that standards should be set by
adding 10 percent in losses to equipment classes 7 and 8 to derive
standards for equipment classes 9 and 10 and subtracting 10 percent in
losses from classes 7 and 8 to derive standards for classes 5 and 6.
DOE's own analysis suggests that this method of scaling is reasonable
and proposes using it to derive standards as it does it today's notice.
Furthermore, several parties noted that liquid-immersed
transformers experienced smaller, but not insignificant, performance
benefits or penalties as a function of BIL and noted that standards for
liquid-immersed units could be tweaked in the same manner as those from
MVDT units. Doing so would permit capture of increased energy savings
at the more-efficient BILs while still permitting manufacture of the
higher BIL transformers at reasonable expense.
DOE requests comment on scaling across both BIL and kVA ratings as
it applies to both dry-type and liquid-immersed transformers and on
specific ways for DOE to establish a sound methodology for deriving BIL
adjustment factors in the liquid-immersed case. DOE also requests
comment on how standards are best harmonized across phase counts for
all types of transformers and how standards for single-phase
transformers may be scaled to produce those of three-phase transformers
and vice-versa.
9. Material Availability
DOE received several comments expressing concern over the
availability of materials, including core steel and conductors, needed
to build energy efficient distribution transformers.
[[Page 7318]]
These issues pertain to a global scarcity of materials as well as
issues of materials access for small manufacturers.
NPCC, NEEA, Schneider Electric, and the joint comments from ASAP,
ACEEE and NRDC all indicated that DOE should revise its selling prices
to make sure they are in line with market prices. They commented that
DOE's selling prices were too high compared to the prices supplied by
manufacturers at the public meeting. (NPCC/NEEA, No. 11 at p. 2 and pp.
6-7; SE., No. 18 at p. 8; ASAP/ACEEE/NRDC, No. 28 at pp. 1-2) The ASAP,
ACEEE and NRDC joint comments further specified that commenters at the
meeting noted that the price of a small purchase quantity going through
a distributor was still 40-60% lower than DOE's price estimates. They
added that, if DOE is unable to determine how to adjust its cost
inputs, it should apply an adjustment factor to the final selling price
to bring it in line with current market prices. If DOE cannot determine
prices for LVDT, the joint commenters recommended that DOE apply the
adjustment factor from the liquid-immersed analysis to the dry-type
analysis. (ASAP/ACEEE/NRDC, No. 28 at pp. 1-2)
Conversely, HVolt, Inc. commented that DOE's finished transformer
prices are too low and that several manufacturers have generated
selling prices (using current materials prices and low markups) that
are 2.5-4 times higher than DOE's prices at CSL 6. (HVOLT, No. 33 at p.
1)
Manufacturers often accuse DOE or over-representing manufacturer
selling prices, while parties interested in increasing energy
efficiency accuse it of under-representing these prices. DOE is
interested in tailoring its analysis to align more closely with the
market and believes the best way for parties to demonstrate falsely
high or low prices is to submit actual purchase or bid records for
designs close to DOE's representative units. If needed, such records
could be submitted under the terms of a non-disclosure agreement.
Finally, DOE notes that it is the incremental, and not absolute, cost
of added efficiency that dominates the cost-effectiveness calculations
that it performs. Consequently, errors in the absolute prices will have
a smaller effect on the rule outcome than errors in the cost of
marginal efficiency. DOE requests further comment on manufacturer
selling price and any accompanying data that can help substantiate such
comment.
Southern Company commented that DOE should consider the limited
supply of amorphous steel when evaluating amended standard levels. It
added that there is not enough amorphous steel to meet the demand of
the entire transformer industry, and noted that prices for amorphous
steel could increase substantially if it was the sole core material
used in distribution transformer designs. (SC, No. 22 at p. 1)
DOE is aware that many core steels, including amorphous steels,
have constraints on their supply and presents an analysis of global
steel supply in Appendix 3-A.
10. Primary Voltage Sensitivities
DOE understands that primary voltage and the accompanying BIL may
increasingly affect efficiency of liquid-immersed transformers as
standards rise. DOE may conduct primary voltage sensitivity analysis in
order to better quantify the effects of BIL and primary voltage on
efficiency, and may use such information to consider establishing
equipment classes by BIL rating for liquid-immersed distribution
transformers.
11. Impedance
In the preliminary analysis, DOE only considered transformer
designs with impedances within the normal impedance ranges specified in
Table 1 and Table 2 of 10 CFR part 431.192. These impedances represent
the typical range of impedance that is used for a given liquid-immersed
or dry-type transformer based on its kVA rating and whether it is
single-phase or three-phase.
Commonwealth Edison (ComEd) commented that its single-phase
overhead transformer specification only allows impedances between 5.3
and 6.2 percent for 250, 333, and 500 kVA transformers. Furthermore,
ComEd commented that manufacturers are already having difficulty
creating designs with the minimum impedance requirement of 5.3 percent
based on the current standard level. (ComEd, No. 24 at p. 3) Similarly,
Central Moloney commented that it also has limitations on the impedance
of the transformers, which get harder to meet at larger sizes. (Central
Moloney, Pub. Mtg. Tr., No. 34 at p. 78)
For the NOPR, DOE continued to consider designs within the normal
impedance ranges used in the preliminary analysis. While certain
applications may have specifications that are more stringent than these
normal impedance ranges, DOE believes that the majority of applications
are able to tolerate impedances within these ranges. Since DOE
considers a wide array of designs within the normal impedance ranges,
it adequately considers the cost considerations of higher and lower
impedance tolerances.
DOE requests comment on impedance values and on any related
parameters (e.g., inrush current, X/R ratio) that may be used in
evaluation of distribution transformers. DOE requests particular
comment on how any of those parameters may be affected by energy
conservation standards of today's proposed levels or higher.
12. Size and Weight
In the preliminary analysis, DOE did not constrain the weight of
its designs. DOE accounted for the full weight of each design generated
by the optimization software based on its materials and hardware.
Similarly, DOE let several dimensional measurements of its designs vary
based on the optimal core/coil dimensions plus space factors. However,
DOE did hold certain tank and enclosure dimensions constant for its
design lines. Most notably, DOE fixed the height dimension on all of
its rectangular tank transformers. For each design that had variable
dimensions, DOE accounted for the additional cost of installing the
unit, where applicable.
Several interested parties expressed concerns about the size and
weight of the designs used in DOE's analysis. Power Partners commented
that single-phase liquid-immersed units above 500 kVA are very
difficult to design for the current standard level when accounting for
the weight and size constraints that users specify. (PP, Pub. Mtg. Tr.,
No. 34 at p. 46) Power Partners and Howard Industries commented that
this issue is particularly a concern for pole-mounted transformers, and
noted that many customers put large (500 kVA single-phase) units on
poles. (PP, Pub. Mtg. Tr., No. 34 at p. 75; HI, Pub. Mtg. Tr., No. 34
at p. 77) Pepco Holdings, Inc. (PHI) stated that the largest
transformer that it will hang on a pole is 333 kVA, but noted that it,
too, has concerns about weight and size. (PHI, Pub. Mtg. Tr., No. 34 at
p. 77)
Many stakeholders noted that size and weight limitations exist for
certain customer specifications. Power Partners, Central Moloney (CM),
and PHI all commented that restrictions exist for size and weight, and
stated that DOE should account for maximum weight and dimensional
limits. (PP, Pub. Mtg. Tr., No. 34 at p. 73; CM, Pub. Mtg. Tr., No. 34
at p. 77; PHI, Pub. Mtg. Tr., No. 34 at p. 74) PHI noted that these
restrictions are especially important for pole-mount, subway,
subsurface, and network transformers. (PHI, No. 26 and 37 at p. 1)
Power Partners commented that over 80 percent of new transformers
manufactured are for replacement, and
[[Page 7319]]
noted that replacement pole-mount transformers need to fit into the
existing pole space. As such, Power Partners suggested a maximum weight
of 650 pounds for the representative unit in DL2 (25 kVA single-phase)
and a maximum weight of 3,600 pounds for the representative unit in DL3
(500 kVA single-phase). (PP, No. 19 at p. 3) Conversely, PG&E commented
that the large transformers in its service area are typically pad-
mounted and noted that weight is not a big concern. (PG&E, Pub. Mtg.
Tr., No. 34 at p. 74)
For the NOPR engineering analysis, DOE did not restrict its designs
based on a limit for size or weight beyond the fixed height
measurements it was already considering for the rectangular tank sizes.
DOE understands that larger transformers may require additional
installation costs such as a new pole change-out or vault expansion. To
the extent that it had data on these additional costs, DOE accounted
for them in its LCC analysis, as described in section IV.F. However,
DOE did not choose to limit its design specifications based on a
specific size or weight constraint.
During negotiation meetings, several parties noted that
transformers in underground vaults could face staggering cost increases
if obligated to comply with unmodified standards. (ABB, Pub. Mtg. Tr.,
No. 89 at p. 245) The parties proposed to create a separate equipment
class for such units and began discussing how such a class might be
defined in terms of physical features and such that it would not
represent a standards loophole. DOE requests comment on the possibility
of establishing a separate equipment class for vault transformers and
how such a class could be defined.
Nonetheless, DOE notes that the majority of its designs are within
the weight constraints suggested by Power Partners. In design line 2,
over 95 percent of DOE's designs are below 650 pounds. In design line
3, over 62 percent of DOE's designs are below 3,600 pounds, and when
only the designs with the lowest first cost are considered, nearly 74
percent of the designs are less than 3,600 pounds. The majority of the
designs that exceed 3,600 pounds are at the maximum efficiency levels
using an amorphous core steel.
During negotiations, Federal Pacific and HVOLT commented that
substation-style designs common to the medium-voltage, dry-type market
are larger than the designs that DOE had previously modeled and would
exhibit bus and lead losses reflecting their longer buses and leads.
(HVOLT, Pub. Mtg. Tr., No. 91 at p. 290)
DOE worked with manufacturers to explore the magnitude of the
effect of longer buses and leads and found it to be small relative to
the gap between efficiency levels. Nonetheless, DOE made small upward
adjustments to bus and lead losses of all medium-voltage, dry-type
design lines. Details on the specific values of the adjustments made
can be found in Chapter 5 of the TSD.
D. Markups Analysis
The markups analysis develops appropriate markups in the
distribution chain to convert the estimates of manufacturer selling
price derived in the engineering analysis to customer prices. In the
preliminary analysis, DOE determined the distribution channels for
distribution transformers, their shares of the market, and the markups
associated with the main parties in the distribution chain,
distributors, contractors and electric utilities.
Several stakeholders commented that DOE's analysis failed to
include the distribution channel that delivers liquid-immersed
transformers directly from manufacturers to large utilities. (NEEA, No.
11 at p. 2, Joint Comments PG&E and SCE, No. 32 at p. 2, and EMS,
Public Meeting Transcript, No. 34 at p. 145) EMS Consulting commented
that when large utilities purchase directly from manufacturers, the
commission of the manufacturer's representative is included in the
price of the transformer and should not be added in separately. (EMS,
Public Meeting Transcript, No. 34 at p. 145) PG&E and SCE noted that
because utilities often pay much less for transformers purchased in
bulk, the selling prices DOE presented in the preliminary analysis are
too high. (Joint Comments PG&E and SCE, No. 32 at p. 2) For the NOPR,
DOE added a new distribution channel to represent the direct sale of
transformers to independently owned utilities, which account for
approximately 80 percent of liquid-immersed transformer shipments. This
sales channel removes a distributor markup, which had included the
commission of the manufacturer's representative in the preliminary
analysis. The inclusion of this channel reduces the overall markup for
liquid-immersed transformers.
EEI stated that a distribution channel from manufacturers to
distributors to multi-site commercial and/or industrial customers
(i.e., large purchasers) may represent 10 percent to 25 percent of dry-
type transformer sales. (EEI, No. 29 at p. 6) DOE did not find data
that would allow it to include the channel mentioned by EEI as a
separate distribution channel.
In the preliminary analysis, DOE developed average distributor and
contractor markups by examining the installation and contractor cost
estimates provided by RS Means Electrical Cost Data 2011. DOE developed
separate markups for baseline products (baseline markups) and for the
incremental cost of more-efficient products (incremental markups).
Incremental markups are coefficients that relate the change in the
installation cost due to the increase equipment weight of some higher-
efficiency models.
FPT agreed with the distributor markups that DOE developed for
liquid-immersed transformers. (FPT, No. 27 at p. 17) HPS agreed that a
15-percent markup is appropriate for distributor markup. (HPS, No. 3 at
p. 6) ABB and NEMA, on the other hand, recommended that DOE consult
with a sample of major distributors to obtain a better understanding of
internal markups. (ABB, No. 14 at p. 18; NEMA, No. 13 at p. 8) DOE was
not able to conduct a representative survey of transformer distributors
within the context of the current rulemaking. Given the supportive
comments from FPT and HPS, DOE retained the markup used in the
preliminary analysis for the NOPR for liquid-immersed and low-voltage
dry-type transformers. However, based on input received from
manufacturers during the negotiated rulemaking process, DOE revised the
distributor and contractor markups that affect the retail price for
medium-voltage dry-type transformers to 1.26 and 1.16, respectively.
HVOLT suggested that DOE's estimated contractor labor and materials
markup that affects the installation costs of 1.43 is too high. (HVOLT,
Public Meeting Transcript, No. 34 at p. 149) DOE used RS Means
Electrical Cost Data 2010 to estimate a contractor labor and materials
markup of 1.43. This markup is justified as it includes: (1) Direct
labor required for installation, including unloading, uncrating,
hauling within 200 feet of the loading dock, setting in place,
connecting to the distribution network, and testing; and (2) equipment
rentals necessary for completion of the installation such as a
forklift, and/or hoist.
Chapter 6 of the NOPR TSD provides additional detail on the markups
analysis.
E. Energy Use Analysis
The energy use and end-use load characterization analysis (chapter
6) produced energy use estimates and end-
[[Page 7320]]
use load shapes for distribution transformers. The energy use estimates
enabled evaluation of energy savings from the operation of distribution
transformer equipment at various efficiency levels, while the end-use
load characterization allowed evaluation of the impact on monthly and
peak demand for electricity from the operation of transformers.
The energy used by distribution transformers is characterized by
two types of losses. The first are no-load losses, which are also known
as core losses. No-load losses are roughly constant and exist whenever
the transformer is energized (i.e., connected to live power lines). The
second are load losses, which are also known as resistance or I\2\R
losses. Load losses vary with the square of the load being served by
the transformer.
Because the application of distribution transformers varies
significantly by type of transformer (liquid-immersed or dry-type) and
ownership (electric utilities own approximately 95 percent of liquid-
immersed transformers, commercial/industrial entities use mainly dry-
type), DOE performed two separate end-use load analyses to evaluate
distribution transformer efficiency. The analysis for liquid-immersed
transformers assumes that these are owned by utilities and uses hourly
load and price data to estimate the energy, peak demand, and cost
impacts of improved efficiency. For dry-type transformers, the analysis
assumes that these are owned by commercial and industrial customers, so
the energy and cost savings estimates are based on monthly building-
level demand and energy consumption data and marginal electricity
prices. In both cases, the energy and cost savings are estimated for
individual transformers and aggregated to the national level using
weights derived from either utility or commercial/industrial building
data.
For utilities, the cost of serving the next increment of load
varies as a function of the current load on the system. To correctly
estimate the cost impacts of improved transformer efficiency, it is
therefore important to capture the correlation between electric system
loads and operating costs and between individual transformer loads and
system loads. For this reason, DOE estimated hourly loads on individual
liquid-immersed transformers using a statistical model that simulates
two relationships: (1) The relationship between system load and system
marginal price; and (2) the relationship between the transformer load
and system load. Both are estimated at a regional level.
DOE received a number of comments on its preliminary analysis for
liquid-immersed transformers.
Regarding the price-load correlation incorporated into the end-use
load characterization, EEI suggested that DOE obtain data for 2009/2010
to develop a more complete picture of the savings associated with
reducing core and coil losses in liquid-filled transformers. (EEI, No.
29 at p. 6) Because changes to the functional form of the price-load
correlation are small compared to the variability in the model,
updating the data will not affect the resulting price-load correlation.
Thus, DOE continued to use 2008 Federal Energy Regulatory Commission
(FERC) Form714 lambda data and market prices for the NOPR analysis.
EEI also suggested that DOE use tariffs to determine the prices
paid for base load electricity generation, because reducing the
constant core losses will not save electricity at marginal rates. (EEI,
No. 29 at p. 8) NRECA stated that most NRECA members make wholesale
purchases at tariff rates that reflect installed, existing resources,
with only a small increment based on hourly, market-based purchases.
(NRECA, No. 31 and 36 at p. 4) They concluded that DOE's approach
overemphasized rates for purchases made on the hourly market.
The energy savings from more efficient distribution transformers
are a small decrement to the total energy consumption. The hourly price
reflects the cost of serving a small, marginal change in load, and is
therefore the appropriate method to use to estimate the costs savings
associated with energy savings. This is true for both coil losses and
winding losses, and is independent of how the transformer owner pays
for the bulk of their power purchases. DOE produced a detailed
comparison of tariff-based marginal prices and hourly marginal prices
for peaking end-uses as part of the Commercial Unitary Air Conditioner
& Heat Pump rulemaking.\28\ This analysis confirmed that, on an annual
average basis, both methods lead to similar cost estimates.
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\28\ See http://www1.eere.energy.gov/buildings/appliance_standards/commercial/ac_hp.html.
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Regarding hourly load data, NEMA recommended that DOE consult with
utilities, building owners, and other end-users to obtain any available
field data. (NEMA, No. 13 at p. 8) DOE consulted with a variety of
industry contacts but was unable to find any source of metered hourly
load for transformers. Data submitted by subcommittee member K. Winder
of Moon Lake Electric during the negotiations were used to validate the
load models for single-phase liquid-immersed transformers. For the
final rule, if stakeholders are able to provide, or assist in providing
such data, DOE will use it to validate and modify the transformer load
models as needed.
Dry-type transformers are primarily installed on buildings and
owned by the building owner/operator. Commercial and industrial (C&I)
utility customers are typically billed monthly, with the bill based on
both electricity consumption and demand. Hence, the value of improved
transformer efficiency depends on both the load impacts on the
customer's electricity consumption and demand and the customer's
marginal prices.
The customer sample of dry-type distribution transformer owners was
taken from the EIA Commercial Buildings Energy Consumption Survey
(CBECS) databases. Survey data for the years 1992 and 1995 were used,
as these are the only years for which monthly customer electricity
consumption (kWh) and peak demand (kW) are provided. To account for
changes in the distribution of building floor space by building type
and size, the weights defined in the 1992 and 1995 building samples
were rescaled to reflect the distribution in the most recent 2003 CBECS
survey. CBECS covers primarily commercial buildings, but a significant
fraction of transformers are shipped to industrial building owners. To
account for this in the sample, data from the 2006 Manufacturing Energy
Consumption Survey (MECS) were used to estimate the amount of floor
space of buildings that might use the type of transformer covered by
the rulemaking. The weights assigned to the building sample were
rescaled to reflect this additional floor space. Only the weights of
large buildings were rescaled.
Regarding DOE's energy use characterization, EEI stated that DOE
should use EIA's 2006 MECS to develop baseline electricity consumption
and demand for industrial facilities. (EEI, No. 29 at p. 8) Using CBECS
data as a proxy, they said, may lead to incorrect analysis on
transformers for the industrial facilities being modeled. (EEI, No. 29
at p. 8) The MECS survey data does not contain any building-level
information on energy consumption, and contains no information
whatsoever on electricity demand. Thus, DOE retained use of CBECS data
for the NOPR analysis.
Transformer loading is an important factor in determining which
types of transformer designs will deliver a specified efficiency, and
for calculating transformer losses. In the preliminary
[[Page 7321]]
analysis, DOE assumed non-residential load factors of 35 percent, 40
percent, and 25 percent for medium-voltage single-phase, medium-voltage
three-phase, and low-voltage transformers respectively. Several
stakeholders commented on the load factors DOE used to characterize
commercial and industrial loads. EEI suggested that DOE use Electric
Power Research Institute (EPRI) and/or utility load factor studies to
develop separate commercial and industrial load factors to use in its
analysis. (EEI, No. 29 at p. 7) suggested that load factors for large
commercial buildings have been trending upward because of the increased
numbers of data centers. (HEX, Public Meeting Transcript, No. 34 at p.
192) EEI suggested that, based on EPRI data, DOE use higher load
factors (50-55 percent for commercial buildings and 70-80 percent for
industrial buildings). (EEI, Public Meeting Transcript, No. 34 at p.
168) ABB stated that DOE's current assumptions about average load
factors are sufficiently accurate. (ABB, No. 14 at p. 18) FPT stated
commercial and industrial users tend to load their transformers to a
lower percent of nameplate than utilities would load residential
liquid-filled transformers because of the greater risk and impact of an
outage of a transformer in a commercial or industrial installation.
(FTP, No. 27 at p. 19)
Several subcommittee members commented that in rural areas the
number of customers per transformer is likely to be significantly lower
than in urban or suburban areas, which in turn results in lower RMS
loads. (APPA and NRECA, Public Meeting Transcript, No. 91 at p. 201) To
account for this effect, DOE performed an analysis to determine an
average population density in the territory served by each of the
utilities represented in the LCC simulation. For each utility, EIA Form
861 data were used to generate a list of counties served by the
utility. Census data were used to determine the average housing unit
density in each county. An average over counties was then used to
assign the utility to a low density, average density or high density
category, with the cutoff for low density set at 32 households per
square mile. For those utilities serving primarily low density areas
the median of the RMS load distribution is reduced from 35 percent to
25 percent.
For the NOPR, DOE modified its analysis of dry-type transformer
loading to: (1) model commercial and industrial building installations
separately; and (2) reflect how transformers are used in the field.
Higher-capacity medium-voltage transformers are loaded at 40 percent
and smaller capacity transformers medium-voltage are loaded at 35
percent. Low-voltage transformers are loaded at 25 percent.
DOE received a number of comments that apply to both the hourly and
monthly load models.
Regarding load (coil) losses, EEI suggested that DOE use diversity
factors to account for the fact that significantly less than 100
percent of load losses are correlated with peak demands for a building
or distribution system. Using this method, they said, would prevent
overestimating cost savings. (EEI, No. 29 at p. 8) DOE already employs
diversity factors to account for the fact that load (coil) losses often
do not correlate with system or building peak loads.
Several stakeholders questioned whether DOE's analysis of
responsibility factor accounts for the diversity of loads that
transformers serve. NRECA, for instance, commented that diversity among
a transformer's loads must be considered to set the responsibility
factor for an individual transformer, if multiple customers are served
through a transformer. (NRECA, No. 31 and 36 at p. 4) EEI also
expressed concern that DOE's analysis of responsibility factor excluded
diversity of loads. (EEI, No. 29 at p. 7) CDA recommended that DOE's
analysis of responsibility factor consider the effect of load (winding)
losses that likely occur simultaneously with system peaks. (CDA, No. 17
at p. 3)
The statistical model that DOE uses to estimate the responsibility
factor for each individual transformer accounts for the diversity of
loads. The responsibility factor model is applied to the load (winding)
losses. The model accounts for the effect of diversity of individual
transformer loads with respect to the peak of the aggregate load of the
system that contains the transformer. Winding losses are included in
the analysis.
Several stakeholders commented on DOE's use of a power factor of 1
in its end-use load characterization. PG&E and SCE stated that DOE
should consider a power factor less than unity. (Joint Comments PG&E
and SCE, No. 32 at p. 1) EEI suggested that DOE use a power factor
other than 1 to account for decreased transformer efficiency from
increased harmonic parasitic loads. (EEI, Public Meeting Transcript,
No. 34 at p. 156)
In DOE's analysis, transformer loss estimates are calculated
relative to the peak load on the transformer. The ratio of the peak
load on a transformer to the transformer capacity is modeled by a
distribution. There are two additional parameters that can affect the
overall scale of transformer loading relative to its rated capacity.
One is the power factor, and the other is a modeling parameter that
adjusts the ratio of the RMS load relative to the square of the
transformer peak load. Neither of these factors is known with great
accuracy. The LCC spreadsheet allows the user to adjust the power
factor. Adjusting the power factor from one to 0.95 may scale the
energy losses up slightly, but as all transformer designs are affected
equally, there should be no significant impact on the selection of
designs that meet the candidate standard level. In the absence of
additional field data on both RMS loads and power factors in different
transformer installations, DOE does not believe that these small
adjustments can significantly improve the accuracy of the LCC
calculations.
NEEA commented on the calculation of load losses, recommending that
DOE use hourly marginal line losses rather than annual average line
losses to adjust distribution transformer loads to system generation
loads. It stated that using hourly marginal line losses would more
accurately reflect the value of load losses. (NEEA, No. 11 at p. 10)
DOE found no data supporting the use of hourly marginal line losses
rather than average annual line losses in calculating load losses.
Thus, it continued to use average annual line losses for the NOPR
analysis.
F. Life-Cycle Cost and Payback Period Analysis
DOE conducts LCC and PBP analyses to evaluate the economic impacts
on individual customers of potential energy conservation standards for
distribution transformers. The LCC is the total customer expense over
the life of a product, consisting of purchase and installation costs
plus operating costs (expenses for energy use, maintenance and repair).
To compute the operating costs, DOE discounts future operating costs to
the time of purchase and sums them over the lifetime of the product.
The PBP is the estimated amount of time (in years) it takes customers
to recover the increased purchase cost (including installation) of a
more efficient product through lower operating costs. DOE calculates
the PBP by dividing the change in purchase cost (normally higher) due
to a more stringent standard by the change in average annual operating
cost (normally lower) that results from the standard.
For any given efficiency level, DOE measures the PBP and the change
in LCC relative to an estimate of the base-case efficiency levels. The
base-case estimate reflects the market in the absence of amended energy
conservation standards, including the
[[Page 7322]]
market for products that exceed the current energy conservation
standards.
Equipment price, installation cost, and baseline and standard
affect the installed cost of the equipment. Transformer loading, load
growth, power factor, annual energy use and demand, electricity costs,
electricity price trends, and maintenance costs affect the operating
cost. The compliance date of the standard, the discount rate, and the
lifetime of equipment affect the calculation of the present value of
annual operating cost savings from a proposed standard. Table IV.1
summarizes all the major inputs to the LCC and PBP analysis, and
whether those inputs were revised for the proposed rule.
Commenting on the preliminary analysis, SC stated that because the
assumptions DOE uses in its LCC and PBP analyses are not always correct
and not specific to an individual utility or user, the conclusions are
most likely inaccurate for some utilities. (SC, No. 22 at p. 4) DOE
calculated the LCC and PBP for a representative sample (a distribution)
of individual transformers. In this manner, DOE's analysis explicitly
recognized that there is both variability and uncertainty in its
inputs. DOE used Monte Carlo simulations to model the distributions of
inputs. The Monte Carlo process statistically captures input
variability and distribution without testing all possible input
combinations. Some atypical situations may not be captured in the
analysis, but DOE believes the analysis captures an adequate range of
situations in which transformers operate.
Table IV.1--Key Inputs for the LCC and PBP Analyses
------------------------------------------------------------------------
Preliminary analysis Changes for proposed
Inputs description rule
------------------------------------------------------------------------
Affecting Installed Costs:
Equipment price......... Derived by Added a case for
multiplying liquid-immersed
manufacturer transformers that
selling price (from are sold directly
the engineering to utilities.
analysis) by
distributor markup
and contractor
markup plus sales
tax for dry-type
transformers. For
liquid-immersed
transformers, DOE
used manufacturer
selling price plus
small distributor
markup plus sales
tax. Shipping costs
were included for
both types of
transformers.
Installation cost....... Includes a weight- Updated the
specific component, installation
derived from RS factors to use RS
Means Electrical Means Electrical
Cost Data 2010 and Cost Data 2011.
a markup to cover Improved the
installation labor, modeling of pole
pole replacement replacements for
costs for design design line 2.
line 2 and
equipment wear and
tear.
Baseline and standard The selection of Adjusted the percent
design selection. baseline and of evaluators to:
standard-compliant 10% for liquid-
transformers immersed
depended on transformers, and
customer behavior. 2% for low-voltage
For liquid-immersed dry-type and 2% for
transformers, the medium-voltage dry-
fraction of type transformers.
purchases evaluated
was 75%, while for
dry-type
transformers, the
fraction of
evaluated purchases
was 50% for small
capacity medium-
voltage and 80% for
large-capacity
medium-voltage.
Affecting Operating Costs:
Transformer loading..... Loading depended on Adjusted loading as
customer and a function of
transformer transformer
characteristics. capacity and
utility customer
density.
Load growth............. 0.5% per year for No change.
liquid-immersed and
0% per year for dry-
type transformers.
Power factor............ Assumed to be unity. No change.
Annual energy use and Derived from a No change.
demand. statistical hourly
load simulation for
liquid-immersed
transformers, and
estimated from the
1992 and 1995
Commercial Building
Energy Consumption
Survey data for dry-
type transformers
using factors
derived from hourly
load data. Load
losses varied as
the square of the
load and were equal
to rated load
losses at 100%
loading.
Electricity costs....... Derived from tariff- No change.
based and hourly
based electricity
prices. Capacity
costs provided
extra value for
reducing losses at
peak.
Electricity price trend. Obtained from Annual Updated to Annual
Energy Outlook 2010 Energy Outlook 2011
(AEO2010). (AEO 2011).
Maintenance cost........ Annual maintenance No change.
cost did not vary
as a function of
efficiency.
Compliance date......... Assumed to be 2016.. No change.
Discount rates.......... Mean real discount The mean real
rates ranged from discount rates were
4.0% for owners of adjusted to 3.7%
pole-mounted, for owners of
liquid-immersed liquid-immersed
transformers to transformers and
5.1% for dry-type 4.6% for dry-type
transformer owners. transformers.
Lifetime................ Distribution of No change.
lifetimes, with
mean lifetime for
both liquid and dry-
type transformers
assumed to be 32
years.
------------------------------------------------------------------------
[[Page 7323]]
The following sections contain brief discussions of comments on the
inputs and key assumptions of DOE's LCC analysis and explain how DOE
took these comments into consideration.
1. Modeling Transformer Purchase Decision
The LCC spreadsheet uses a purchase-decision model that specifies
which of the hundreds of designs in the engineering database are likely
to be selected by transformer purchasers to meet a given efficiency
level. The engineering analysis yielded a cost-efficiency relationship
in the form of manufacturer selling prices, no-load losses, and load
losses for a wide range of realistic transformer designs. This set of
data provides the LCC model with a distribution of transformer design
choices.
DOE used an approach that focuses on the selection criteria
customers are known to use when purchasing transformers. Those criteria
include first costs, as well as what is known in the transformer
industry as total owning cost (TOC). The TOC method combines first
costs with the cost of losses. Purchasers of distribution transformers,
especially in the utility sector, have long used the TOC method to
determine which transformers to purchase. DOE refers to purchasers who
use the TOC method as evaluators.
The utility industry developed TOC evaluation as an easy-to-use
tool to reflect the unique financial environment faced by each
transformer purchaser. To express variation in such factors as the cost
of electric energy, and capacity and financing costs, the utility
industry developed a range of evaluation factors, called A and B
values, to use in their calculations. A and B are the equivalent first
costs of the no-load and load losses (in $/watt), respectively.
In the preliminary analysis, DOE assumed that 75 percent of liquid-
immersed transformers are purchased using TOC evaluation. DOE assumed
that 25 percent of low-voltage dry-type transformers are purchased
using TOC evaluation. For medium-voltage dry-type transformers, DOE
assumed that 50 percent of smaller capacity units are purchased with
TOC evaluation and that 85 percent of larger capacity units are
purchased using TOC evaluation.
Several stakeholders commented on DOE's estimate of the share of
purchasers who make purchase decisions based on TOC. FPT said that DOE
significantly overstated the percentage of evaluators for dry-type
distribution transformers. They estimated there are 0 percent to 1
percent evaluators for low-voltage dry-type, about 10 percent for
medium-voltage dry-type, and about 20 percent for high-capacity dry-
type distribution transformers. (FPT, No. 27 at p. 4) ABB agreed that
DOE overestimated the number of evaluators. They estimated that
evaluators represent less than 1 percent for low-voltage dry-type and
small medium-voltage dry-type, and less than 5 percent for large
medium-voltage dry-type. (ABB, No. 14 at p. 19) Other stakeholders
agreed that DOE's estimates of evaluators are too high. (EEI, No. 29 at
p. 8; ASAP, Public Meeting Transcript, No. 34 at p. 197) NEMA commented
that the percent of evaluators seems high for some product lines, and
recommended that DOE obtain information from individual manufacturers
and end-users, or examine shipments data to determine evaluators.
(NEMA, No. 13 at p. 8) ASAP et al. recommended that the DOE survey
enough users and suppliers to develop a better estimate of the
percentage of units purchased in 2010 that had significantly higher
efficiency than the minimum standard. (Joint Comments ASAP, ACEEE and
NRDC, No. 28 at p. 4)
Conducting a representative survey of users or manufacturers is not
possible within the scope of the present rulemaking. For the NOPR
analysis, DOE revised the evaluation rates, based on the available data
and stakeholder comments. DOE revised its evaluation rates as follows:
10 percent for liquid-immersed, 2 percent for low-voltage, and 2
percent for medium-voltage dry-type transformers. The transformer
selection approach is discussed in detail in chapter 8 of the NOPR TSD.
FPT stated that only utilities really evaluate based on A and B
factors, so another method needs to be used to analyze other types of
customers. FPT recommended that DOE base its analysis of industrial and
commercial customers on PBP criteria. (FPT, No. 27 at p. 5) DOE
effectively bases its analysis on PBP; the results are converted to
equivalent A and B factors so that the same model structure can be used
in all the spreadsheets.
HI stated that fewer customers will evaluate their purchases when
DOE mandates higher efficiency levels, which would result in purchase
of transformers with less than optimum efficiency for their
application. (HI, No. 23 at p. 9) DOE acknowledges that evaluation
rates may vary depending on the standard for a given design line.
Because DOE has no basis for estimating this phenomenon, however, it
used the same evaluation rates for each of the considered CSLs.
2. Inputs Affecting Installed Cost
a. Equipment Costs
In the LCC and PBP analysis, the equipment costs faced by
distribution transformer purchasers are derived from the MSPs estimated
in the engineering analysis and the overall markups estimated in the
markups analysis.
Several stakeholders recommended that DOE lower its estimate of
transformer selling prices. Based on its Internet review of selling
prices, Metglas said the prices DOE generated are too high. (MET,
Public Meeting Transcript, No. 34 at p. 97) PG&E and SCE suggested that
DOE calibrate its prices against market data and exclude the cost of
any additional features from the price estimates. (Joint Comments PG&E
and SCE, No. 32 at p. 2) ASAP, ACEEE and NRDC agreed that DOE's
estimated selling prices are too high, and recommended that DOE adjust
its estimates based on market research, and then apply an adjustment
factor to bring final transformer selling prices in line with observed
prices. (Joint Comments ASAP, ACEEE and NRDC, No. 28 at pp. 1-2)
For the NOPR analysis, DOE reviewed bid documents on the Internet
after the current standards took effect in 2010 and found a wide range
of prices. DOE also received confidential data from NEEA on utility
transformer purchases that showed a wide range of prices. The data did
not clearly indicate that DOE's estimated customer prices are too high.
DOE notes that the inclusion of a new distribution channel for liquid
results in a lower average markup and thus lower average customer price
for these products.
EEI stated that DOE should consider transformer pricing data from
2006 onward, because that period reflects the increasing global demand
for distribution transformers as well as the increase in commodity
costs for key transformer components. EEI asserted that transformer
prices have not declined, but rather increased, compared to the rate of
inflation. (EEI, No. 29 at pp. 2-4)
To forecast a price trend for the NOPR, DOE derived an inflation-
adjusted index of the PPI for electric power and specialty transformer
manufacturing over 1967-2010. These data show a long-term decline from
1975 to 2003, and then a steep increase since then. DOE believes that
there is considerable uncertainty as to whether the recent trend has
peaked, and would be followed by a return to the previous long-term
declining trend, or whether the recent trend represents the beginning
of a long-term rising trend
[[Page 7324]]
due to global demand for distribution transformers and rising commodity
costs for key transformer components. Given the uncertainty, DOE has
chosen to use constant prices (2010 levels) for both its LCC and PBP
analysis and the NIA. For the NIA, DOE also analyzed the sensitivity of
results to alternative transformer price forecasts. DOE developed one
forecast in which prices decline after 2010, and one in which prices
rise. Appendix 10-C of the NOPR TSD describes the historic data and the
derivation of the default and alternative price forecasts.
DOE requests comments on the most appropriate trend to use for real
transformer prices, both in the short run (to 2016) and the long run
(2016-2045).
b. Installation Costs
Higher efficiency distribution transformers tend to be larger and
heavier than less efficient designs. In the preliminary analysis, DOE
included the increased cost of installing larger, heavier transformers
as a component of the first cost of more efficient transformers. DOE
presented the installation cost model and solicited comment from
stakeholders.
Commenting on the preliminary analysis, several stakeholders stated
that DOE should revise its assumption that 25 percent of pole-mounted
liquid-immersed transformers greater than 1,000 pounds will require an
additional $2,000 cost for pole change-out. (Joint Comments PG&E and
SCE, No. 32 at p. 2; Joint Comments ASAP, ACEEE and NRDC, No. 28 at p.
2-3; NEEA, No. 11 at p. 8) The above comments reflect a
misunderstanding of DOE's preliminary analysis. The 25 percent referred
to in the comments was the maximum pole change-out fraction in the
algorithm DOE used to estimate when change-outs would be required when
the weight of the transformer exceeds 1,000 pounds.
EEI noted that several of its members expressed concern that more
efficient liquid-immersed transformers would have much higher weights,
which would increase costs in terms of installation and pole structural
integrity for retrofits of existing pole-mounted transformers. (EEI,
No. 29 at p. 2) APPA commented that DOE must adequately account for the
costs of pole replacements due to larger transformers. (APPA, No. 21 at
p. 2) SC stated that pole change-outs may be necessary when
transformers are replaced because larger diameter poles will be needed
to support transformer weight increases, and that larger diameter poles
may be required with new transformer installations. (SC, No. 22 at p.
3) ComEd commented that for pole-mounted transformers, an increase in
transformer weight may generate an increase in the required pole class
to sustain the load. (ComEd, No. 24 at p. 1) PP agreed that additional
transformer weight could make pole-mounting difficult. (PP, No. 19 at
p. 1) NRECA and T&DEC stated that the added cost of replacing utility
poles is especially burdensome for rural electric cooperatives. (Joint
Comments NRECA and T&DEC, No. 31 and 36 at pp. 1-2)
Other stakeholders stated that standards that result in heavier
transformers would not necessarily require pole change-outs. ASAP et
al. stated that increased weight due to higher efficiency will not
require pole change-outs. They noted that the primary determining
factor in selecting pole size is the horizontal load, not the vertical
load, which is affected by the transformer weight. (Joint Comments
ASAP, ACEEE and NRDC, No. 28 at p. 2-3) PG&E and SCE stated that
replacement of the pole (or pad) is more a function of transformer
upsizing than of increased size due to efficiency improvement, adding
that when replacing in-kind utility transformers, the rate of pole
change-out due to increased size and weight of higher-efficiency
improvements is very low. They also noted that for new construction,
pole change-out is unnecessary because there is no existing pole to
change out. (Joint Comments PG&E and SCE, No. 32 at p. 2)
In general, as transformers are redesigned to reach higher
efficiency, the weight and size also increase. The degree of weight
increase depends on how the design is modified to improve efficiency.
For pole-mounted transformers, represented by design line (DL) 2, the
increased weight may lead to situations where the pole needs to be
replaced to support the additional weight of the transformer. This in
turn leads to an increase in the installation cost. To account for this
effect in the analysis, three steps are needed:
The first step is to determine whether the pole needs to be
changed. This depends on the weight of the transformer in the base case
compared to the weight of the transformer under a proposed efficiency
level, and on assumptions about the load-bearing capacity of the pole.
In the LCC calculation, it is assumed that a pole change-out will only
be necessary if the weight increase is larger than 15 percent and
greater than 150 lbs of the weight of the baseline unit. Utility poles
are primarily made of wood. Both ANSI and NESC provide guidelines on
how to estimate the strength of a pole based on the tree species, pole
circumference and other factors. Natural variability in wood growth
leads to a high degree of variability in strength values across a given
pole class. Thus, NESC also provides guidelines on reliability, which
result in an acceptable probability that a given pole will exceed the
minimal required design strength. Because poles are sized to cope with
large wind stresses and potential accumulation of snow and ice, this
results in ``over-sizing'' of the pole relative to the load by a factor
of two to four. Because of this ``over-sizing'' DOE limited the total
fraction of pole replacements to 25 percent of the total population.
The second step is to determine the cost of a pole change-out.
Specific examples of pole change-out costs were submitted by the sub-
committee. These examples were consistent with data taken from the
RSMeans Building Construction Cost database. Based on this information,
a triangular distribution was used to estimate pole change-out costs,
with a lower limit at $2,025 and an upper limit at $5,999. Utility
poles have a finite life-time, so that pole change-out due to increased
transformer weight should be counted as an early replacement of the
pole; i.e. it is not correct to attribute the full cost of pole
replacement to the transformer purchase. Equivalently, if a pole is
changed out when a transformer is replaced, it will have a longer
lifetime relative to the pole it replaces, which offsets some of the
cost of the pole installation. To account for this affect, pole
installation costs are multiplied by a factor n/pole-lifetime, which
approximately represents the value of the additional years of life. The
parameter n is chosen from a flat distribution between 1 and the pole
lifetime, which is assumed to be 30 years.\29\
---------------------------------------------------------------------------
\29\ As the LCC represents the costs associated with purchase of
a single transformer, to account for multiple transformers mounted
on a single pole, the pole cost should also be divided by a factor
representing the average number of transformers per pole. No data is
currently available on the fraction of poles that have more than one
transformer, so this factor is not included.
---------------------------------------------------------------------------
PHI noted that if a pole-mount transformer exceeds 900 pounds, they
are required to have two crews for the replacement, a heavy-duty rigger
and traffic control crew, adding to the expense of the installation.
(PHI, No. 26 at p. 1) DOE's analysis accounts for increase in
installation labor costs as transformer weight increases and is
described in detail in chapter 6 of the NOPR TSD.
Regarding pad-mounted transformers, ComEd commented that new
standards
[[Page 7325]]
could require that the pads for some pad-mounted transformers receive
foundation upgrades to accommodate the increased size and weight, which
might require that generators be deployed to maintain customer services
during the upgrade. (ComEd, No. 24 at p. 3) APPA also stated that DOE
must adequately account for the costs of pad mount replacements due to
larger transformers. (APPA, No. 21 at p. 2) HI noted that symmetric
core technology could affect installation practices because the core
design has a triangular footprint that requires a much deeper pad to
accommodate the deeper tanks. (HI, No. 23 at p. 3) At present, DOE's
model does not include any additional costs that may be required for
pad-mounted transformers at higher efficiency levels. DOE requests data
on the weight and size thresholds that might be expected to trigger pad
mount upgrades and on approximate costs of a typical upgrade.
DOE received comments on the affect that that symmetric core
technology would have on installation costs. NRECA described
theoretical evaluation that indicates weight and labor costs would
increase for symmetric core technology. (NRECA, No. 31 and 36 at p. 3)
The engineering analysis estimated the weight of transformers that
utilize symmetric core technology. As mentioned above, the LCC and PBP
analysis accounts for increase in installation labor costs as
transformer weight increases.
EEI noted that several of its members expressed concern that more
efficient transformers will be larger in size (height, width, and
depth), which will have an impact for all retrofit situations,
especially in underground vaults, which in many urban areas cannot be
physically expanded, or can only be expanded at a great cost in terms
of materials, labor, and street closures. (EEI, No. 29 at p. 2) Because
vault-installed transformers account for a small fraction of
transformer installations, and mainly affect urban utilities that have
underground distribution systems, DOE chose to analyze these
transformers as part of the customer subgroup analysis. This analysis,
and the approach DOE used to account for installing larger-volume
transformers, is described in section IV.H.
3. Inputs Affecting Operating Costs
a. Transformer Loading
DOE's assumptions about loading of different types of transformers
are described in section IV.E. DOE generally estimated the loading on
larger transformers is greater than the loading on smaller
transformers.
b. Load Growth Trends
The LCC takes into account the projected operating costs for
distribution transformers many years into the future. This projection
requires an estimate of how the electrical load on transformers will
change over time. In the preliminary analysis, for dry-type
transformers, DOE assumed no load growth, while for liquid-immersed
transformers DOE used as the default scenario a one-percent-per-year
load growth. It applied the load growth factor to each transformer
beginning in 2016. To explore the LCC sensitivity to variations in load
growth, DOE included in the model the ability to examine scenarios with
zero percent, one percent, and two percent load growth.
DOE did not receive comments regarding its load growth assumptions,
and it retained the assumptions described above for the NOPR analysis.
c. Electricity Costs
DOE needed estimates of electricity prices and costs to place a
value on transformer losses for the LCC calculation. As discussed in
section IV.E, DOE created two sets of electricity prices to estimate
annual energy expenses for its analysis: 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. IV.E
also presents the comments received on this topic and DOE's response.
DOE received a few comments regarding electricity cost estimation.
Electricity cost estimates are discussed in detail in chapter 7 of the
NOPR TSD.
d. Electricity Price Trends
For the relative change in electricity prices in future years, DOE
relied on price forecasts from the Energy Information Administration
(EIA) Annual Energy Outlook (AEO). For the preliminary analysis, DOE
used price forecasts from AEO 2011.
PG&E and SCE considered DOE's forecasted electricity prices in the
preliminary analysis to be low. They recommended that DOE revisit their
electric price forecast to ensure it accurately reflects historical
trends and potential future global scenarios that may drive electricity
prices higher than otherwise anticipated. (Joint Comments PG&E and SCE,
No. 32 at p. 2) For the proposed rule, DOE updated the price forecast
to AEO 2011 and examined the sensitivity of analysis results to changes
in electricity price trends. Appendix 8-D of the NOPR TSD provides a
sensitivity analysis for equipment of each product group with the
largest market shares, for liquid-immersed transformers design lines 1
and 5 are examined, for low-voltage dry-type transformers design line 7
is examined, and for medium-voltage dry-type transformers design line
12. These analysis shows that the effect of changes in electricity
price trends, compared to changes in other analysis inputs, is
relatively small. DOE evaluated a variety of potential sensitivities,
and the robustness of analysis results with respect to the full range
of sensitivities, in weighing the potential benefits and burdens of the
proposed rule.
e. Standards Compliance Date
DOE calculated customer impacts as if each new distribution
transformer purchase occurs in the year manufacturers must comply with
the standard. For the preliminary analysis, this was assumed to be
January 1, 2016.
Several stakeholders commented on the compliance date for new
efficiency standards for distribution transformers. Howard Industries
stated that the feasibility of the proposed date depends on the
magnitude of changes in the new rulemaking and the supply chain
limitations that will occur once the economy recovers. They estimated
that they will need until the January 1, 2016, date to comply with new
efficiency levels for liquid-immersed distribution transformers. (HI,
No. 23 at p. 1) EEI agreed that the compliance date for any new
standards should be no sooner than January 1, 2016. (EEI, No. 29 at p.
4) Schneider Electric commented that the previous standard for low-
voltage dry-type transformers was implemented within 16 months because
many manufacturers already were producing enough compliant transformers
that it was a stock product. It noted that circumstances are not the
same for the new standard levels, and a longer period should be allowed
for compliance. (SE., No. 18 at p. 5) (NEEA agreed with the current
compliance date, but said that if the final rule is not stringent, DOE
should consider an earlier date and/or should examine the interaction
between stringency of standards with the number of models already in
production. (NEEA, No. 11 at p. 10)
As discussed in section II.A, if DOE finds that amended standards
for distribution transformers are warranted, DOE must publish a final
rule containing such amended standards by October 1, 2012. The
statutorily-required compliance date of January 1, 2016, provides
manufacturers with over three years to prepare for manufacturing
[[Page 7326]]
distribution transformers to the new standards.
f. Discount Rates
The discount rate is the rate at which future expenditures are
discounted to estimate their present value. DOE employs a two-step
approach in calculating discount rates for analyzing customer economic
impacts. The first step is to assume that the actual customer cost of
capital approximates the appropriate customer discount rate. The second
step is to use the use the capital asset pricing model (CAPM) to
calculate the equity capital component of the customer discount rate.
For the preliminary analysis, DOE estimated a statistical distribution
of commercial customer discount rates that varied by transformer type
by calculating the cost of capital for the different types of
transformer owners.
Commenting on the preliminary analysis, EEI stated that small
businesses and entities under financial duress likely would face
significantly higher effective discount rates. (EEI, No. 29 at p. 8)
The intent of the LCC analysis is to estimate the economic impacts of
higher-efficiency transformers over a representative range of customer
situations. While the discount rates used may not be applicable for all
customers, DOE believes that they reflect the financial situation of
the majority of transformer customers.
More detail regarding DOE's estimates of commercial customer
discount rates is provided in chapter 8 of the NOPR TSD.
g. Lifetime
DOE defined distribution transformer life as the age at which the
transformer retires from service. For the preliminary analysis, DOE
assumed, based on a report by Oak Ridge National Laboratory,\30\ that
the average life of distribution transformers is 32 years. This
lifetime assumption includes a constant failure rate of 0.5 percent/
year due to lightning and other random failures unrelated to
transformer age and an additional corrosive failure rate of 0.5
percent/year starting at year 15.
---------------------------------------------------------------------------
\30\ Barnes. Determination Analysis of Energy Conservation
Standards for Distribution Transformers. ORNL-6847. 1996.
---------------------------------------------------------------------------
Commenting on this assumption, HVOLT and PHI suggested that DOE use
a lifetime of 30 years. (HVOLT, Public Meeting Transcript, No. 34 at p.
126; PHI, Public Meeting Transcript, No. 34 at p. 210) DOE did not
receive any additional data that provide a basis for changing its 32-
year assumption on distributor lifetime, so it retained the approach
used in the preliminary analysis for the NOPR analysis.
h. Base Case Efficiency
To determine an appropriate base case against which to compare
various candidate standard levels, DOE used the purchase-decision model
described in section IV.F.1. For the base case, initially transformer
purchasers are allowed to choose among the entire range of transformers
at each design line.
During the negotiation process, ERAC subcommittee members noted
that currently there are no transformers using ZDMH as a core material
sold in the U.S. market. (ABB, Public Meeting Transcript, No. 91 at p.
276) Therefore, DOE screened out designs using this material in the
base case selection. For higher efficiency levels, the LCC analysis
samples from all design options identified in the engineering analysis.
Subcommittee members provided data on market share as a function of
efficiency. For some design lines, the lower boundary of the price-
efficiency curve produced in the engineering analysis is quite flat, so
that the choice algorithm in the LCC analysis showed units being
selected in the base case with efficiencies substantially higher than
the current DOE minimum standard. DOE modified its approach so that the
fraction of units selected in the base case at different efficiency
levels is consistent with the provided market share data.
G. National Impact Analysis--National Energy Savings and Net Present
Value Analysis
DOE's NIA assessed the national energy savings (NES) and the
national NPV of total customer costs and savings that would be expected
to result from amended standards at specific efficiency levels.
(``Customer'' refers to purchasers of the product being regulated.)
To make the analysis more accessible and transparent to all
interested parties, DOE used an MS Excel spreadsheet model to calculate
the energy savings and the national customer costs and savings from
each TSL. DOE understands that MS Excel is the most widely used
spreadsheet calculation tool in the United States and there is general
familiarity with its basic features. Thus, DOE's use of MS Excel as the
basis for the spreadsheet models provides interested parties with
access to the models within a familiar context. In addition, the TSD
and other documentation that DOE provides during the rulemaking help
explain the models and how to use them, and interested parties can
review DOE's analyses by changing various input quantities within the
spreadsheet.
DOE used the NIA spreadsheet to calculate the NES and NPV, based on
the annual energy consumption and total installed cost data from the
energy use characterization and the LCC analysis. DOE forecasted the
energy savings, energy cost savings, product costs, and NPV of customer
benefits for each product class for products sold from 2016 through
2045. The forecasts provided annual and cumulative values for all four
output parameters. In addition, DOE analyzed scenarios that used inputs
from the AEO 2011 Low Economic Growth and High Economic Growth cases.
These cases have higher and lower energy price trends compared to the
Reference case. NIA results based on these cases are presented in
appendix 10-B of the NOPR TSD.
DOE evaluated the impacts of amended standards for distribution
transformers by comparing base-case projections with standards-case
projections. The base-case projections characterize energy use and
customer costs for each product class in the absence of amended energy
conservation standards. DOE compared these projections with projections
characterizing the market for each product class if DOE were to adopt
amended standards at specific energy efficiency levels (i.e., the
standards cases) for that class.
The tables below summarize all the major NOPR inputs to the
shipments analysis and the NIA, and whether those inputs were revised
for the proposed rule.
Table IV.2--Inputs for the Shipments Analysis
------------------------------------------------------------------------
Preliminary analysis Changes for proposed
Input description rule
------------------------------------------------------------------------
Shipments data.............. Third-party expert No change.
(HVOLT) for 2009.
[[Page 7327]]
Shipments forecast.......... 2016-2045: Based on Updated to AEO 2011.
AEO 2010.
Dry-type/liquid-immersed Based on EIA's Updated to AEO 2011.
market shares. electricity sales
data and AEO2010.
Regular replacement market.. Based on a survival No change.
function
constructed from a
Weibull
distribution
function normalized
to produce a 32-
year mean lifetime.
Source: ORNL 6804/
R1, The Feasibility
of Replacing or
Upgrading Utility
Distribution
Transformers During
Routine
Maintenance, page D-
1.
Elasticities, liquid- For liquid-immersed No change.
immersed. transformers:.
Low: 0.00..
Medium: -
0.04.
High: -0.20
Elasticities, dry-type...... For dry-type No change.
transformers:.
Low: 0.00..
Medium: -
0.02.
High: -0.20
------------------------------------------------------------------------
Table IV.3--Inputs for the National Impact Analysis
------------------------------------------------------------------------
Preliminary analysis Changes for
Input description proposed rule
------------------------------------------------------------------------
Shipments..................... Annual shipments from No change.
shipments model.
Compliance date of standard... January 1, 2016....... No change.
Base case efficiencies........ Constant efficiency No change.
through 2044. Equal
to weighted-average
efficiency in 2016.
Standards case efficiencies... Constant efficiency at No change.
the specified
standard level from
2016 to 2044.
Annual energy consumption per Average rated No change.
unit. transformer losses
are obtained from the
LCC analysis, and are
then scaled for
different size
categories, weighted
by size market share,
and adjusted for
transformer loading
(also obtained from
the LCC analysis).
Total installed cost per unit. Weighted-average No change.
values as a function
of efficiency level
(from LCC analysis).
Electricity expense per unit.. Energy and capacity No change.
savings for the two
types of transformer
losses are each
multiplied by the
corresponding average
marginal costs for
capacity and energy,
respectively, for the
two types of losses
(marginal costs are
from the LCC
analysis).
Escalation of electricity AEO 2010 forecasts (to Updated the
prices. 2035) and escalation of
extrapolation for electricity
2044 and beyond. prices forecast
using AEO 2011.
Electricity site-to-source A time series Updated
conversion. conversion factor; conversion
includes electric factors from
generation, NEMS.
transmission, and
distribution losses.
Conversion varies
yearly and is
generated by DOE/
EIA's National Energy
Modeling System
(NEMS) program.
Discount rates................ 3% and 7% real........ No change.
Present year.................. Equipment and No change.
operating costs are
discounted to the
year of equipment
price data, 2010.
------------------------------------------------------------------------
1. Shipments
DOE constructed a simplified forecast of transformer shipments for
the base case by assuming that long-term growth in transformer
shipments will be driven by long-term growth in electricity
consumption. The detailed dynamics of transformer shipments is highly
complex. This complexity can be seen in the fluctuations in the total
quantity of transformers manufactured as expressed by the U.S.
Department of Commerce, Bureau of Economic Analysis (BEA), transformer
quantity index. DOE examined the possibility of modeling the
fluctuations in transformers shipped using a bottom-up model where the
shipments are triggered by retirements and new capacity additions, but
found that there were not sufficient data to calibrate model parameters
within an acceptable margin of error. Hence, DOE developed the
transformer shipments forecast assuming that annual transformer
shipments growth is equal to forecasted growth in electricity
consumption as given by the AEO 2011 forecast up to the year 2035. For
the years from 2036 to 2045, DOE extrapolated the AEO 2011 forecast
with the growth rate of electricity consumption from 2025 to 2035. The
model starts with an estimate of the overall growth in transformer
capacity and then estimates shipments for particular design lines and
transformer sizes using estimates of the recent market shares for
different design and size categories. Chapter 9 provides a detailed
description of how DOE conducted its shipments forecasts.
EEI suggested that the shipment projections are overly optimistic
and should be closer to a flat line of growth. (EEI, No. 29 at p. 9)
The historical shipments data based on the BEA's quantity index data
for power and distribution transformers show a
[[Page 7328]]
relatively flat trend between the late 1970s and 2007. The data show a
sharp increase in 2008, a higher-than-average level in 2009, and a
steep plunge in 2010. This recent trend apparently reflects purchasers
stocking up on transformers in advance of the standards that took
effect in 2010. Given this unusual market situation, DOE believes that
holding future shipments at the 2010 level would be unrealistic. For
the NOPR, DOE's base case forecast shows shipments gradually returning
to the level of 2008 by the end of the forecast period.
Commenting on the preliminary analysis, NEMA noted that in some
markets, liquid-immersed and medium-voltage dry-type transformers
compete against one another, and for some applications, liquid-immersed
units have additional costs for liquid containment or fire protection.
NEMA encouraged DOE to consider whether higher prices for liquid-
immersed units due to standards might cause users to shift to dry-type
transformers. (NEMA, No. 13 at p. 7) ABB said that they have not
observed a shift in market share between equipment classes as a result
of current regulations, but they asked that any new regulation be
analyzed as to its potential impact in shifting demand between
equipment classes. (ABB, No. 14 at p. 19)
In principle, the appropriate way to address the probability that a
customer switches to a different product class in response to an
increase in the price of a specific product is to estimate the cross-
price elasticity of demand between competing classes. To estimate this
elasticity, DOE would need historical data on the shipments and price
of the liquid-immersed and medium-voltage dry-type transformers. The
shipments data at that level of disaggregation is available only for
two years (2001 and 2009), which is not sufficient to support the
estimation of cross-price elasticity of liquid-immersed distribution
transformers. Thus, for the NOPR DOE did not estimate potential
switching from liquid-immersed to dry-type transformers. DOE requests
data that would allow it to estimate such switching for the final rule.
Some stakeholders expressed concern that higher prices due to new
standards will increase refurbishing of transformers, which would
reduce purchase and shipments of new transformers. (EEI, Public Meeting
Transcript, No. 34 at p. 249; NEEA, No. 11 at p. 9; HI, No. 23 at p.
13) NEMA commented that the analysis should consider the replace versus
refurbish decision for each considered standard level. (NEMA, No. 13 at
pp. 7, 9) ABB commented that it has not observed increased refurbishing
with the current regulation since January 1, 2010, but it believes new
regulations may well increase the use of rebuilt transformers. (ABB,
No. 14 at p. 19) NRECA said that some of its members are already making
greater efforts to maintain and refurbish older units rather than
purchase costlier new, more efficient units. (NRECA, No. 31 and 36 at
p. 4)
To capture the customer response to transformer price increase, DOE
estimated the customer price elasticity of demand. Although the general
trend of transformer purchases is determined by increases in
generation, utilities conceivably exercise some discretion in how much
transformer capacity to buy--the amount of ``over-capacity'' to
purchase. The ratio of transformer capacity to load varies according to
economic considerations, namely the price of transformers, and the
income generated by each unit of capacity purchased (essentially the
price of electricity). When transformer costs are low, utilities may
increase their investment in capacity in order to economically meet
future increases in demand, and they will be more likely to do so when
returns, indicated by electricity prices, are high. Any decrease in
sales induced by an increase in the price of distribution transformers
is due to a decrease in this ratio. In DOE's estimation of the purchase
price elasticity, it used a logit function to characterize the
utilities' response to the price of a unit capacity of transformer. The
functional form captures what can be called an average price elasticity
of demand with a term to capture the estimation error, which accounts
for all other effects. Technically, the price elasticity should
therefore account for any decrease in the shipments due to a decision
on the customer's part to refurbish transformers as opposed to
purchasing a new unit. DOE's approach is described in chapter 9 of the
NOPR TSD.
During the negotiated rulemaking, DOE heard from many stakeholders
that there is a growing potential for utilities to repair failed
transformers and return them to service for less than the cost of a
purchasing a new transformer. Some manufacturers commented that if the
cost of a new transformer increased by 20 percent utilities may
refurbish rather than purchase new equipment to replace failed
equipment. (ABB, Public Meeting Transcript, No. 95 at p. 100) DOE
received a market potential study from AK Steel stating that the
replacement market could represent up to 80 percent of the liquid-
immersed market over the next 15 years and that utilities purchasing
replacement equipment would consider refurbishing failed units instead
of purchasing new equipment. (AK, Public Meeting Transcript, No. 95 at
p. 101) DOE received comment from committee members that a small number
of municipal utilities were already purchasing refurbished equipment as
part of their normal day-to-day operations. (APPA, Public Meeting
Transcript, No. 95 at p. 169) On the other hand, PG&E stated that the
risks involved with using refurbished equipment (e.g., shorter
lifetimes, shorter warrantee, inconsistent equipment quality) give this
option limited appeal to larger investor-owned utilities. (PG&E, Public
Meeting Transcript, No. 95 at p. 172) DOE acknowledges that uncertainty
exists regarding the issue of refurbishing vs. replacement. However, it
did not receive data that provided a reasonable basis for changing the
analysis used for the NOPR. DOE intends to further investigate this
issue for the final rule. Toward that end, DOE request further
information that would allow it to quantify the likely extent of
refurbishment at different potential standard levels.
2. Efficiency Trends
DOE did not include any base case efficiency trends in its
shipments and national energy savings models. AEO forecasts show no
long term trend in transmission and distribution losses. DOE estimates
that the probability of an increasing efficiency trend and the
probability of a decreasing efficiency trend are approximately equal,
and therefore used a zero trend in base case efficiency. DOE seeks
further comment on its decision to use frozen efficiencies for the
analysis period. Specifically, DOE would like comments on additional
sources of data on trends in efficiency improvement.
3. Equipment Price Forecast
As noted in section IV.F.2, DOE assumed no change in transformer
prices over the 2016-2045 period. In addition, DOE conducted
sensitivity analysis using alternative price trends. Based on PPI data
for electric power and specialty transformer manufacturing, DOE
developed one forecast in which prices decline after 2010, and one in
which prices rise. These price trends, and the NPV results from the
associated sensitivity cases, are described in Appendix 10-C of the
NOPR TSD.
4. Discount Rate
In calculating the NPV, DOE multiplies the net savings in future
[[Page 7329]]
years by a discount factor to determine their present value. For
today's NOPR, DOE estimated the NPV of appliance consumer benefits
using both a 3-percent and a 7-percent real discount rate. DOE uses
these discount rates in accordance with guidance provided by the Office
of Management and Budget (OMB) to Federal agencies on the development
of regulatory analysis.\31\ The discount rates for the determination of
NPV are in contrast to the discount rates used in the LCC analysis,
which are designed to reflect a consumer's perspective. The 7-percent
real value is an estimate of the average before-tax rate of return to
private capital in the U.S. economy. The 3-percent real value
represents the ``social rate of time preference,'' which is the rate at
which society discounts future consumption flows to their present
value.
---------------------------------------------------------------------------
\31\ OMB Circular A-4 (Sept. 17, 2003), section E, ``Identifying
and Measuring Benefits and Costs. Available at: www.whitehouse.gov/omb/memoranda/m03-21.html.
---------------------------------------------------------------------------
5. Energy Used in Manufacturing Transformers
FPT stated that DOE should account for the additional energy needed
to produce more efficient transformers, such as energy use associated
with working with higher-grade core steels. (FPT, No. 27 at p. 4) HI
and SC made similar comments. (HI, No. 23 at p. 7; SC, No. 22 at p. 3)
In response, DOE notes that EPCA directs DOE to consider the total
projected amount of energy, or as applicable, water, savings likely to
result directly from the imposition of the standard when determining
whether a standard is economically justified. (42 U.S.C.
6295(o)(2)(B)(i)(III)) DOE interprets this to include energy used in
the generation, transmission, and distribution of fuels used by
appliances or equipment. In addition, DOE is evaluating the full-fuel-
cycle measure, which includes the energy consumed in extracting,
processing, and transporting primary fuels. DOE's current accounting of
primary energy savings and the full-fuel-cycle measure are directly
linked to the energy used by appliances or equipment. DOE believes that
energy used in manufacturing of appliances or equipment falls outside
the boundaries of ``directly'' as intended by EPCA. Thus, DOE did not
consider such energy use in the NIA.
H. Customer Subgroup Analysis
In analyzing the potential impacts of new or amended standards, DOE
evaluates impacts on identifiable groups (i.e., subgroups) of customers
that may be disproportionately affected by a national standard. For
this rulemaking, DOE identified purchasers of vault-installed
transformers (mainly utilities concentrated in urban areas) as
subgroups that could be disproportionately affected, and examined the
impact of proposed standards on these groups using the methodology of
the LCC and PBP analysis.
Kentucky Association of Electric Cooperatives, Inc. (KAEC) stated
that rural electric cooperatives should be analyzed as a customer
subgroup in the LCC subgroup analysis because they will face
disproportionate costs for any amended efficiency standards. KAEC
stated that rural electric cooperatives typically are loaded at only 25
percent, not the 50 percent loading assumed in the test procedure.
(KAEC, No. 4 at p. 2) DOE's estimate of average root mean square (RMS)
loading for a 50 kVA pad-mounted transformer for the national sample is
approximately 35 percent. For rural electric cooperatives DOE used the
estimate provided by KAEC to lower the average loading for rural
customers, as described in section IV.E of this document.
Several interested parties commented that it is important for DOE
to take into consideration the problem that may arise in installing
larger transformers in space-constrained situations. HI commented that
DOE needs to do more analysis on the size constraints for submersible
and vault type transformers. (HI, No. 23 at p. 13) ComEd stated that
for street and building vaults, larger transformers potentially could
cause severe problems during replacement because of equipment openings,
operating clearances, and the loading capacity of floors and elevators.
It stated that: (1) Existing building vaults typically have only a few
inches of clearance; and (2) larger transformers may not be able to be
maneuvered through building hallways or may exceed the weight
limitations of building elevators and floors. It added that although a
slightly larger transformer would not create a space issue for street/
sidewalk vaults, a larger transformer may violate certain company
operating clearances inside the vault, and possibly be deemed a safety
issue. (ComEd, No. 24 at p. 2) PHI noted that the existing manholes
provided for subsurface, subway, and network transformers would have to
be enlarged to install a larger unit, which requires time and
additional costs. (PHI, No. 26 and 37 at p. 1)
For the NOPR, DOE evaluated vault-installed transformers
represented by design lines 4 and 5 as a customer subgroup. DOE
examined the impacts of larger transformer volume with regard to costs
for vault enlargement. DOE assumed that if the volume of a unit in a
standard case is larger than the median volume of transformer designs
for the particular design line, a vault modification would be
warranted. To estimate the cost, DOE compared the difference in volume
between the unit selected in the base case against the unit selected in
the standard case, and applied fixed and variable costs. In the 2007
final rule, DOE estimated the fixed cost as $1,740 per transformer and
the variable cost as $26 per transformer cubic foot.\32\ For today's
notice, these costs were adjusted to 2010$ using the chained price
index for non-residential construction for power and communications to
$1854 per transformer and $28 per transformer cubic foot. DOE
considered instances where it may be extremely difficult to modify
existing vaults by adding a very high vault replacement cost option to
the LCC spreadsheet. Under this option, the fixed cost is $30,000 and
the variable cost is $733 per transformer cubic foot.
---------------------------------------------------------------------------
\32\ See section 7.3.5 of the 2007 final rule TSD, available at
http://www1.eere.energy.gov/buildings/appliance_standards/commercial/pdfs/transformer_fr_tsd/chapter7.pdf).
---------------------------------------------------------------------------
The customer subgroup analysis is discussed in detail in chapter 11
of the NOPR TSD.
I. Manufacturer Impact Analysis
1. Overview
DOE performed a manufacturer impact analysis (MIA) to estimate the
financial impact of amended energy conservation standards on
manufacturers of distribution transformers and to calculate the impact
of such standards on employment and manufacturing capacity. The MIA has
both quantitative and qualitative aspects. The quantitative part of the
MIA primarily relies on the Government Regulatory Impact Model (GRIM),
an industry cash-flow model with inputs specific to this rulemaking.
The key GRIM inputs are data on the industry cost structure, product
costs, shipments, and assumptions about markups and conversion
expenditures. The key output is the industry net present value (INPV).
Different sets of shipment and markup assumptions (scenarios) will
produce different results. The qualitative part of the MIA addresses
factors such as product characteristics, impacts on particular sub-
groups of firms, and important market and product trends. The complete
MIA is outlined in Chapter 12 of the NOPR TSD.
[[Page 7330]]
DOE conducted the MIA for this rulemaking in three phases. In Phase
1 of the MIA, DOE prepared a profile of the distribution transformer
industry, which includes a top-down cost analysis of manufacturers used
to derive preliminary financial inputs for the GRIM (e.g., sales
general and administration (SG&A) expenses; R&D expenses; and tax
rates). DOE used public sources of information, including company
Securities and Exchange Commission (SEC) 10-K filings, Moody's company
data reports, corporate annual reports, the U.S. Census Bureau's
Economic Census, and Hoover's reports.
In Phase 2 of the MIA, DOE prepared an industry cash-flow analysis
to quantify the impacts of a new energy conservation standard. In
general, more stringent energy conservation standards can affect
manufacturer cash flow in three distinct ways: (1) Create a need for
increased investment, (2) raise production costs per unit, and (3)
alter revenue due to higher per-unit prices and possible changes in
sales volumes.
In Phase 3 of the MIA, DOE conducted structured, detailed
interviews with a representative cross-section of manufacturers. During
these interviews, DOE discussed engineering, manufacturing,
procurement, and financial topics to validate assumptions used in the
GRIM and to identify key issues or concerns. See section IV.I.4 for a
description of the key issues manufacturers raised during the
interviews.
Additionally, in Phase 3, DOE evaluates sub-groups of manufacturers
that may be disproportionately impacted by standards or that may not be
accurately represented by the average cost assumptions use to develop
the industry cash-flow analysis. For example, small manufacturers,
niche players, or manufacturers with cost structures that largely
differ from the industry average could be more negatively affected.
For the MIA, DOE grouped the cash flow results for design lines
made by the same sets of manufacturers serving the same markets in
order to assess the impacts of amended energy conservation standards
with more granularity. DOE separately analyzed the industries of three
transformer ``superclasses''--liquid-immersed, medium-voltage dry-type,
and low-voltage dry-type--based on differences in the tooling and
equipment, product designs, customer types, and characteristics of the
markets in which they operate. The Department considered small
manufacturers as a separate subgroup because they may be
disproportionately affected by standards. DOE applied the small
business size standards published by the Small Business Administration
(SBA) to determine whether a company is considered a small business 65
FR 30836, 30848 (May 15, 2000), as amended at 65 FR 53533, 53544 (Sept.
5, 2000) and codified at 13 CFR part 121. To be categorized as a small
business under NAICS 335311(``Power, Distribution and Specialty
Transformer Manufacturing''), a distribution transformer manufacturer
and its affiliates may employ a maximum of 750 employees. The 750-
employee threshold includes all employees in a business's parent
company and any other subsidiaries. Based upon this classification, DOE
identified at least 31 small distribution transformer manufacturers
that qualify as small businesses. The distribution transformer small
manufacturer sub-group is discussed in Chapter 12 of the TSD and in
section VI.B.1 of today's notice.
2. Government Regulatory Impact Model
DOE uses the GRIM to quantify the standards-induced changes in cash
flow that result in a higher or lower industry value. The GRIM analysis
uses a standard, annual cash-flow analysis that incorporates products
costs, markups, shipments, and industry financial information as
inputs, and models changes in costs, investments, and manufacturer
margins that would result from new and amended energy conservation
standards. The GRIM spreadsheet uses the inputs to arrive at a series
of annual cash flows, beginning with the base year of the analysis,
2011, and continuing to 2045. DOE calculates INPVs by summing the
stream of annual discounted cash flows during this period, using a
discount rate of 7.4 percent for liquid immersed transformers, 9
percent for medium-voltage dry-type transformers, and 11.1 percent for
low-voltage dry-type transformers. The difference in INPV between the
base case and a standards case represents the financial impact of the
amended standard on manufacturers. DOE's discount rate estimate was
derived from industry financials and then modified according to
feedback during manufacturer interviews.
DOE typically presents its estimates of industry impacts by groups
of the major equipment types served by the same manufacturers. For the
distribution transformer industry, DOE presents its estimates of
industry impacts for each superclass. The GRIM results are shown in
section V.B.2.a. Additional details about the GRIM can be found in
Chapter 12 of the TSD.
3. GRIM Key Inputs
a. Manufacturer Production Costs
Manufacturing a higher-efficiency product is typically more
expensive than manufacturing a baseline product. The changes in the
MPCs of the analyzed products can affect the revenues, gross margins,
and cash flow of the industry, making these product cost data key GRIM
inputs for DOE's analysis.
During the engineering analysis, DOE used transformer design
software to create a database of designs spanning a broad range of
efficiencies for each of the representative units. This design software
generated a bill of materials. The software also provided information
pertaining to the labor necessary to construct the transformer,
including the number of turns in the windings and core dimensions,
including stack height, which enabled DOE to estimate per unit labor
costs. The Department then applied markups to allow for scrap,
handling, factory overhead, and non-production costs to estimate the
manufacturer selling price.
These designs and their MSPs are subsequently inputted into the LCC
customer choice model. For each CSL and within each design line, the
LCC model uses a Monte Carlo analysis and criteria described in section
F to select a subset of all the potential designs options (and
associated MSPs). This subset is meant to represent those designs that
would actually be shipped in the market under various standard levels.
DOE inputted into the GRIM the weighted average cost of the designs
selected by the LCC model and scaled those MPCs to other selected
capacities in each design line's KVA range.
b. Base-Case Shipments Forecast
The GRIM estimates manufacturer revenues based on total unit
shipment forecasts and the distribution of these values by capacity and
design line. Changes in sales volumes and product mix over time can
significantly affect manufacturer finances. For this analysis, the GRIM
uses the NIA's annual shipment forecasts from 2011 to 2045, the end of
the analysis period. See Chapter 9 of the TSD for additional details.
c. Product and Capital Conversion Costs
Amended energy conservation standards will cause manufacturers to
incur conversion costs to bring their production facilities and product
designs into compliance. For the MIA, DOE classified these conversion
costs
[[Page 7331]]
into two major groups: (1) Product conversion costs and (2) capital
conversion costs. Product conversion costs are investments in research,
development, testing, marketing, and other non-capitalized costs
necessary to make product designs comply with the new or amended energy
conservation standard. Capital conversion costs are investments in
property, plant, and equipment necessary to adapt or change existing
production facilities such that new product designs can be fabricated
and assembled.
Several manufacturers commented on the capital and product
conversion costs that would be necessary to meet particular efficiency
levels. Power Partners stated that any new standards would require
additional retooling and investment (Power Partners, Public Meeting
Transcript, No. 19 at p. 1). Howard Industries commented that DOE
should consider the full impact of capital investments for higher
efficiency designs, such as symmetric core designs, which would require
large capital investments and patent fees, and amorphous core designs,
which would require large capital investments for additional floor
space, laminators, cutters, stackers, encapsulation equipment, and
annealing ovens. (Howard Industries, Public Meeting Transcript, No. 23
at p. 10-11) Additionally, Federal Pacific indicated that manufacturers
who do not currently have the experience and resources needed to
manufacture amorphous cores themselves will have to spend a significant
amount of money in certifying amorphous core transformers to the IEEE
C57 short circuit requirements if DOE efficiency levels necessitate the
use of amorphous steel in core production. (Federal Pacific, Public
Meeting Transcript, No. 27 at p. 3)
DOE recognizes manufacturers would incur conversion costs to modify
their plants and equipment to produce higher efficiency distribution
transformers. DOE explicitly considers these expenditures it in its
GRIM analysis; the following describes the department's methodology for
estimating potential conversion costs for each TSL.
For capital conversion costs, DOE prepared bottom-up estimates of
the costs required to meet standards at each TSL for each design line.
To do this, DOE used equipment cost estimates provided by manufacturers
and equipment suppliers, an understanding of typical manufacturing
processes developed during interviews and in consultation with subject
matter experts, and the properties associated with different core and
winding materials. Major drivers of capital conversion costs include
changes in core steel type (and thickness), core weight, core stack
height, and core construction techniques, all of which are
interdependent and can vary by efficiency level. DOE uses estimates of
the core steel quantities needed by steel type for each TSL, and then
most likely core construction techniques, to model the additional
equipment the industry would need to meet the efficiencies embodied by
each TSL.
For the liquid-immersed sector, conversion costs are entirely
driven at each TSL by the need of the industry to expand capacity for
amorphous production. Based on interviews with manufacturers and
equipment suppliers, DOE assumed an amorphous production line with
1,200 tons of annual capacity would cost $950,000. This figure includes
costs associated with an annealing oven, core cutting machine, lacing
tables and other miscellaneous equipment. As the increasing stringency
of the TSLs drive amorphous adoption, conversion costs increase.
For the low-voltage and medium-voltage dry-type market, DOE took
two approaches to estimate capital conversion costs. First, DOE used an
industry feedback approach. The Department interviewed manufacturers
and industry experts about the capital conversion costs for design
lines at increasing efficiency levels, aggregated the conversion cost
feedback, and market-shared weighted the feedback to determine likely
industry capital conversion costs. For the second approach, DOE
performed a bottoms-up analysis of conversion costs based on core steel
selections forecasted by the LCC and production equipment costs (a more
detailed description of the analysis can be found in chapter 12 of the
TSD). The two approaches yielded results with similar orders of
magnitude. For those levels that do not require amorphous wound cores,
the capital costs are largely driven by the need to modify existing or
purchase new core cutting machines and associated equipment and
tooling. This need arises as increasingly stringent TSLs require
thinner steels, heavier cores, and mitered core construction
techniques, all of which slow throughput and reduce existing capacity.
At those TSLs where amorphous cores become the dominant steel of
choice, DOE used the same amorphous core production line output and
cost assumptions as discussed above for the liquid immersed market.
As it relates to product conversion costs, DOE understands the
production of amorphous cores requires unique expertise and equipment.
For manufacturers without experience with amorphous steel, a standard
necessitating the use of the material would require the development or
the procurement of the technical expertise necessary to produce cores.
Because amorphous steel is extremely thin and brittle after annealing,
materials management, safety measures, and design considerations that
are not associated with non-amorphous steels would need to be
implemented.
For the liquid immersed distribution transformers, because of the
industry's relative inexperience with amorphous technology, DOE
estimated product conversion costs would equal two times annual
industry R&D expenses for those TSLs where a majority of the market
would be expected to transition to amorphous material. These one-time
expenditures account for the design, engineering, prototyping, and
other R&D efforts the industry would have to undertake to move to a
predominately amorphous market. At TSL 1, the only TSL which did not
show a clear move to amorphous technology, DOE estimated product
conversion costs of one times industry annual R&D.
In the low-voltage and medium-voltage dry-type market, DOE
aggregated estimates of product conversion costs from manufacturers
that were gathered during interviews and scaled those estimates to
represent the market share of those not interviewed. Again, for those
levels that indicated a clear shift to amorphous (or, in the case of
LVDT, potentially wound cores), DOE assumed one-time product conversion
costs equal to two times annual industry R&D expenses.
In conclusion, both capital and product conversion costs are key
inputs to the GRIM and directly impact the change in INPV that results
from new standards. DOE assumed that all conversion-related investments
occur between the year of publication of the final rule \33\ and the
year by which manufacturers must comply with the standard (2016). DOE's
estimates of conversion costs can be found in section V.B.2.a of
today's notice and a detailed description of the estimation methodology
can be found in TSD chapter 12.
---------------------------------------------------------------------------
\33\ I.e., 2012.
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d. Standards Case Shipments
As discussed in section F, DOE modeled standard case shipments
based on what units the LCC customer choice model selected at each
efficiency level. DOE's shipments analysis includes an elasticity
factor based on the potential
[[Page 7332]]
for transformer purchasers to elect to refurbish rather than replace
failed transformers as the purchase price increases. The shipments
analysis is discussed in more detail in chapter 9 of the TSD.
e. Markup Scenarios
As discussed above, manufacturer selling prices include direct
manufacturing production costs (i.e., labor, material, and overhead
estimated in DOE's MPCs) and all non-production costs (i.e., SG&A, R&D,
and interest), along with profit. To calculate the MSPs in the GRIM,
DOE applied markups to the MPCs estimated in the engineering analysis
and selected in the LCC for each design line and efficiency level.
Modifying these markups in the standards case yields different sets of
impacts on manufacturers. For the MIA, DOE modeled two standards-case
markup scenarios to represent the uncertainty regarding the potential
impacts on prices and profitability for manufacturers following the
implementation of amended energy conservation standards: (1) A
preservation of gross margin percentage markup scenario, and (2) a
preservation of operating profit markup scenario. These scenarios lead
to different markups values, which, when applied to the inputted MPCs,
result in varying revenue and cash flow impacts.
Under the preservation of gross margin percentage scenario, DOE
applied a single uniform ``gross margin percentage'' markup across all
efficiency levels. As production costs increase with efficiency, this
scenario implies that the absolute dollar markup will increase as well.
Based on publicly available financial information for manufacturers of
distribution transformers and comments from manufacturer interviews,
DOE assumed the non-production cost markup--which includes SG&A
expenses; R&D expenses; interest; and profit--to be 1.25 for
distribution transformers. Because this markup scenario assumes that
manufacturers would be able to maintain their gross margin percentage
markups as production costs increase in response to an energy
conservation standard, it represents a high bound to industry
profitability under an energy conservation standard.
In the preservation of operating profit scenario, DOE adjusted the
manufacturer markups in the GRIM at each TSL to yield approximately the
same earnings before interest and taxes in the standards case in the
year after the compliance date of the amended standards as in the base
case. Under this scenario, as the cost of production and the cost of
sales go up, DOE assumes manufacturers are generally required to reduce
their markups to a level that maintains base case operating profit in
absolute dollars. Therefore, operating margin in percentage terms is
reduced between the base case and standards case. This markup scenario
represents a low bound to industry profitability under an energy
conservation standard.
4. Discussion of Comments
During the April 2011 public meeting, interested parties commented
on the assumptions and results of the preliminary TSD. Oral and written
comments discussed several topics, including conversion costs, material
availability, amorphous steel, and symmetric core technology. DOE
addresses these comments below.
a. Material Availability
Manufacturers noted that the availability of raw materials is
particularly a concern at higher efficiency levels, where transformer
designs would be based upon a very limited selection of steel types.
Hammond stated that the supply of high grade steels, such as domain-
refined steels, would not be sufficient to meet demand if the
efficiency standard forces all designs to use that type of steel.
Hammond also stated that shortages could occur if levels are pushed
anywhere beyond the current level. (Hammond, Public Meeting Transcript,
No. 3 at p. 4 and 6) According to EEI, scarcity of raw materials would
be especially problematic if standards are raised beyond CSL 2 for most
design lines. Also, EEI noted that if the efficiency levels selected
are so high that they can only be met with one or two design options,
manufacturers would be faced with limited choices in suppliers and
higher costs, and customers would be faced with limited choices in
designs and with higher prices. (EEI, Public Meeting Transcript, No. 29
at p. 1 and 4) Furthermore, as noted by KAEC, the transformer industry
may not be able to respond to demand under emergency situations if
increased efficiency levels reduce the number of options available for
core steels and those steels are in limited supply or subject to long
lead times. (KAEC, Public Meeting Transcript, No. 4 at p. 3) Southern
Company also noted that an improved economy would increase demand for
transformers and exacerbate the shortage of core steels necessary to
build higher efficiency transformers. (Southern Company, Public Meeting
Transcript, No. 22 at p. 1) Many manufacturers expressed concerns about
the limited availability of raw materials, especially higher efficiency
electrical steels. Power Partners commented that: (1) There is a
limited global supply of core steels in grades better than M3, (2) the
domestic supply of M2 steel is not enough to support 100 percent of all
liquid-immersed transformer production, and (3) grades of grain
oriented electrical steel better than M2 (e.g., ZDMH) is in limited
supply and only available from a foreign supplier. (Power Partners,
Public Meeting Transcript, No. 19 at p. 4) Howard Industries also
commented on the limited availability of ZDMH and M2 steel, stating
that ZDMH steel is only produced in Japan and that production of M2
steel by AK Steel and Allegheny Ludlum (the two primary suppliers of
M2) is unlikely to increase. (Howard Industries, Public Meeting
Transcript, No. 23 at p. 10-11)
The use and availability of amorphous steel, in particular, is a
major concern in the distribution transformer industry. DOE understands
that amorphous steel is currently produced by only two companies in the
world (Metglas and AT&M), both of which are foreign-owned and one of
which only supplies the Chinese market. Southern Company argued that a
standard level that requires the use of amorphous steel could cause
domestic suppliers of grain-oriented steel to go out of business or
force them to lay off employees. (Southern Company, Public Meeting
Transcript, No. 22 at p. 1) Also, Howard Industries commented that,
because production in China is not exported, amorphous steel will
likely need to be supplied by U.S. manufacturers. (Howard Industries,
Public Meeting Transcript, No. 23 at p. 10-11) However, Metglas stated
that AT&M (the Chinese amorphous supplier) has announced aggressive
expansion in its plants and is expected to export at some point in the
future. (Metglas, Public Meeting Transcript, No. 34 at p. 259)
Nevertheless, due to the limited current supply of amorphous steel,
Federal Pacific suggested that DOE should consider whether the
increased demand for amorphous steel from any proposed standard levels
could be met by the compliance date. (Federal Pacific, Public Meeting
Transcript, No. 27 at p. 2-3)
Manufacturers suggested several analyses which DOE should consider
performing in order to determine core steel availability. ABB
recommended that DOE should project the consumption of all grades of
core steels for each efficiency level in the analysis so that the
industry can assess the underlying impact on supply. (ABB, Public
Meeting Transcript, No. 14 at p.
[[Page 7333]]
17) Schneider Electric recommended that DOE should work with the steel
industry to gain insights into core steel availability. (Schneider,
Public Meeting Transcript, No. 18 at p. 9) NEMA recommended that DOE
should discuss core steel supply with large and small manufacturers,
and that DOE should also forecast the supply and cost of steel at each
CSL and TSL considered in the analysis. (NEMA, Public Meeting
Transcript, No. 13 at p. 7-8) Also, Berman Economics commented that the
shape of the material supply curve is more relevant than the current
quantity of supply. Once demand increases, the market would respond by
supplying more steel, according to Berman Economics. (Berman Economics,
Public Meeting Transcript, No. 34 at p. 260)
DOE agrees with comments that standards could shift the mix and
quantities of core steels demanded by transformer manufacturers and
could alter the market dynamics among core steel and transformer
manufacturers. Therefore, DOE interviewed many players in the core
steel supply chain. DOE investigated core steel availability with large
and small distribution transformers manufacturers, core manufacturers,
and steel suppliers. DOE discussed several topics during these
interviews, including market capacity for each type of core steel,
prospects for expansion, barriers to obtaining those steels, and
impacts on competition.
Based on its engineering analysis, DOE recognizes that some high
efficiency steels are substantially more cost-effective at higher TSLs
than lower-grade or traditional steels. Furthermore, the most stringent
TSLs can only be met with certain core steels, typically amorphous,
depending on the design line. Based on its interviews and market
research, DOE understands these steels are currently produced in
limited quantities by a small handful of suppliers, some of which do
not produce steels domestically.
To better understand the impact of standards on materials
availability, DOE conducted an extensive analysis of the core steel
market, as discussed in TSD appendix 3A.
To evaluate the impacts of standards on the core steel market and
transformer manufacturers, DOE first estimated the core steel
consumption of transformer manufacturers in 2016 (the first year of
required compliance with the proposed standard) in the base case and
the standards cases. To do this, DOE had to evaluate the designs
selected by the LCC customer choice model at each EL for each design
line. This model estimated the distribution of designs that would be
selected at any given standard level. Key parameters of this sample of
selected designs, such as the distribution of core steel types and
average core weights by steel type, were critical inputs into the steel
demand analysis. DOE found the average core weight of the designs
selected for each design line's representative unit at each efficiency
level.
Next, the Department used the .75 scaling rule to extrapolate these
average core weights to those units forecast to be shipped within a
design line but not at the KVA range of the representative unit that is
directly analyzed in the engineering and LCC analyses. For example, DOE
extrapolated the core weight of the 50 kVA representative unit for DL1
to a 100 kVA unit in DL1. This implicitly assumes that the distribution
of core steel types used in transformers remains constant within the
kVA range represented by each design line. Although the calculation of
core weights for units at the extremes of a kVA range may benefit from
an adjusted scaling rule or intermediate design lines, time constraints
have limited the extent of the analysis. However, for the most part,
the .75 scaling rule is a suitable method for scaling across kVAs.
Using the shipments analysis, which projected kVA demand by design
line and capacity, DOE calculated total core steel demand from
transformers covered by this rule. While DOE recognizes the core steel
market is global in scope, its projections include only core steel used
in distribution transformers covered by this rulemaking for use in the
U.S. [In response to Southern Company's comment regarding additional
demand that may come from an improved economy, DOE notes that the
shipment analysis is based on the EIA forecast of economic growth
throughout the analysis period, and thus accounts for higher-the-
current rates of economic growth.]
In reference to the comments summarized above, based on industry
research and the core steel analysis, DOE agrees with Power Partners
that domestic steel suppliers do not currently have the capacity to
supply the entire distribution transformer market with M2, nor does DOE
believe domestic suppliers could cost-effectively produce enough M2 to
do so because the nature of silicon steel production limits M2 output
to one pound for every four pounds of M3. Due to this manufacturing
constraint, if M3 was not able to be used due to standards, steel
manufacturers would be unlikely to produce M2 at levels potentially
demanded by standards, which could create a tipping point at which the
market must move to amorphous by default.
With respect to amorphous demand and capacity, at this time, DOE
understands there is only one credible supplier to the U.S. market of
high-grade amorphous core steel. (Although there is one notable Chinese
supplier with substantial capacity, DOE understands the company has no
history of exporting the material and serves only China's rapidly
growing domestic market at this time. Despite Metglas' comment above
that this supplier is expected to export soon, several manufacturers
expressed skepticism at that possibility in interviews and also noted
the quality of the steel was poor. At this time, DOE has little reason
to believe the company will commence exporting substantial amounts of
high quality amorphous steel in the near future.) Based on publically
available information, DOE estimates the domestic supplier of amorphous
metal has a global capacity of approximately 100,000 metrics tons per
year, 40 percent of which is U.S. based. DOE estimates less than 10,000
tons are currently used for covered US transformers. Notably, the
company has substantially ramped up capacity in a relatively short
time, growing from a 30,000-tons-per-year level in 2005 and lending
credence to the notion that its supply can escalate quickly. The
amorphous supplier is a subsidiary of a large conglomerate and has
commented that it has the financial resources to expand.
While DOE believes the company could substantially grow capacity
beyond its current levels in time for a 2016 compliance date, there
still exists a significant risk of supply constraints, given the
magnitude of the surge in amorphous demand that could potentially be
compelled by TSL 2 and above. It is worth noting that this is a global
market (indeed, as discussed, DOE estimates less than 10 percent of all
amorphous core from this supplier is used in U.S. transformers).
Therefore, even if the company could increase capacity substantially,
it is unlikely, according to most projections, that demand would remain
flat in markets receiving the other 90 percent of this supplier's
business.
Beyond potential capacity constraints, DOE is also concerned about
the competitive impact--among both steel manufacturers and distribution
transformer manufacturers--of a standard that threatened to shift most
of the market to amorphous steel. In highly competitive markets,
standard economic theory dictates that higher prices would encourage
additional suppliers and
[[Page 7334]]
production to come online, bringing prices back to a long-run
equilibrium. In the very long run, that may be true here. However, the
highly sophisticated nature of amorphous ribbon production, which is
based on extensive know-how gained over years of production and high
fixed costs, creates barriers to entry that, while not legal (i.e.,
patents) in nature, suggest there is a significant risk that there will
be no alternative sources of supply by the compliance date or even in
the few years beyond it. Therefore, DOE is concerned about the lack of
alternative amorphous suppliers and the virtual monopoly supplier that
would likely exist in the short term at higher TSLs, particularly given
the engineering constraints on the economic production of M2 and very
limited supply of ZDMH.
b. Symmetric Core Technology
Several stakeholders commented on the costs that may be associated
with the implementation of symmetric core technology. Howard Industries
stated that symmetric core designs would require large capital
investments and patent fees. (Howard Industries, Public Meeting
Transcript, No. 23 at p. 10-11) Conversely, NEEA stated that capital
investments for the technology are low according to symmetric core
manufacturers (NEEA, Public Meeting Transcript, No. 11 at p. 4).
Furthermore, HVOLT argued that, although there may be specific patents
with different kinds of construction, patents fundamentally related to
core configurations should have expired by now given that symmetric
core technology was patented in the 1930s. (HVOLT, Public Meeting
Transcript, No. 34 at p. 49)
Symmetric core manufacturers commented on the benefits of symmetric
core technology. Hex Tec noted that the equipment used to produce
symmetric wound cores is significantly less expensive than flat stacked
steel equipment for the same size and the labor production times are
lower. (Hex Tec, Public Meeting Transcript, No. 34 at p. 52)
Furthermore, according to Hex Tec, intellectual property should not be
a concern because there are a number of symmetric core designs
available and therefore plenty of variance in design. (Hex Tec, Public
Meeting Transcript, No. 34 at p. 49) Hex Tec has also submitted a
letter from the Vice President of Research & Development at Metglas
which indicates that Hex Tec's core winding machine for amorphous
symmetric core designs can be easily scaled for commercialization. (Hex
Tec, Public Meeting Transcript, No. 35 at p. 11-14)
DOE did not explicitly analyze symmetric core as a design option
for consideration in the engineering. Therefore, symmetric core
construction was not considered in the MIA.
c. Patents Related to Amorphous Steel Production
Some manufacturers were concerned about patents on amorphous steel
production. ASAP has questioned whether or not there are any patent
issues that exist for amorphous manufacturers entering the market.
(ASAP, Public Meeting Transcript, No. 34 at p. 262) However, according
to Metglas, the basic amorphous patent expired in 1999, so barriers to
entry are based more on know-how than on patents. (Metglas, Public
Meeting Transcript, No. 34 at p. 262)
Because there are no more patents that create a barrier to entry in
the production of amorphous steel, DOE did not consider patents in its
analysis of amorphous steel production capacity. However, DOE did
consider the technical barriers that exist and accounted for the
engineering and R&D investment necessary to begin production.
5. Manufacturer Interviews
DOE interviewed manufacturers representing approximately 65 percent
of liquid-immersed transformer sales, 75 percent of medium-voltage dry-
type transformer sales, and 30 percent of low-voltage dry-type
transformer sales. These interviews were in addition to those DOE
conducted as part of the engineering analysis. The information gathered
during these interviews enabled DOE to tailor the GRIM to reflect the
unique financial characteristics of the distribution transformer
industry. All interviews provided information that DOE used to evaluate
the impacts of potential new and amended energy conservation standards
on manufacturer cash flows, manufacturing capacities, and employment
levels.
During the manufacturer interviews, DOE asked manufacturers to
describe their major concerns about this rulemaking. The following
sections describe the most significant issues identified by
manufacturers. DOE also includes additional concerns in chapter 12 of
the NOPR TSD.
a. Conversion Costs and Stranded Assets
For manufacturers of distribution transformers, liquid-immersed,
medium-voltage dry-type, and low-voltage dry-type, conversion costs and
stranded assets are a major concern. All manufacturers stated that
efficiency levels that require the use of amorphous steel would sharply
increase conversion costs. Due to the thickness and brittleness of
amorphous steel, unique production processes and new material handling
processes must be applied. Manufacturers noted that they would need to
make extensive capital investments in amorphous core production
equipment, including core cutting machines, annealing ovens, and lacing
tables.
Dry-type manufacturers also stated that a standard that moves the
industry to wound cores would also greatly increase conversions costs.
Since the vast majority of LVDT and MVDT manufacturers produce stacked
cores, a move to wound cores would lead to extensive stranded assets.
In some cases, manufacturers may consider purchasing prefabricated
cores rather than modifying their facilities to produce wound cores due
to the extensive conversion costs.
Additionally, dry-type manufactures stated that a revised standard
that does not require amorphous steel or wound core designs could still
lead to capital conversion costs. As the standard increases,
manufacturers are likely to use higher grade steels for core
production. Because high grade steels tend to be thinner, additional
Georg machines, core assembly lines and workstations, custom miter
cutters, and panel boards may be needed in order to maintain existing
throughput levels.
Some manufacturers mentioned that stranded assets may also be an
issue when equipment needs to be retired and/or replaced if it cannot
be repurposed for higher efficiency designs. DOE accounted for stranded
assets in the GRIM.
b. Shortage of Materials
The availability of higher efficiency grain-oriented electrical
steels is a key issue for all manufacturers of distribution
transformers. Manufacturers stated that there is currently a limited
supply of M4, M3, M2, ZDMH, H-0 DR, and SA1 amorphous steels on the
market and manufacturers expressed concern that higher standards may
increase both demand and prices. Of these steels, M4 and M3 steels are
currently the most widely produced, with suppliers such as AK Steel,
Allegheny Ludlum, ThyssenKrupp, Nippon, JFE, Wuhan, Novolipetsk, Posco,
ArcelorMittal, Orb, Baosteel, Stalproduct, Angang, and Arcelor/Hunan.
However, as the grade of grain-oriented electrical steel improves, its
availability decreases. M2 is a higher grade than M3 but it is produced
by fewer suppliers, such as
[[Page 7335]]
AK Steel, Allegheny Ludlum, ThyssenKrupp, Nippon, and JFE. The
availability of deep domain-refined steel such as ZDMH, H-0 DR, and SA1
amorphous is even more limited. H-0 DR is only produced by Nippon, JFE,
AK Steel, Posco, and Baosteel, and ZDMH is only produced by Nippon.
Amorphous steel is only produced by Hitachi (MetGlas) and AT&M, but
AT&M only supplies the Chinese market. If efficiency levels are set so
high that only amorphous can be used, then domestic manufacturers may
be subject to monopolistic pricing from suppliers.
Manufacturers further stated that, in addition to being in limited
supply, higher efficiency steels are also: (1) More expensive, (2)
subject to tariffs when imported from a foreign supplier, (3) subject
to long lead times for both domestic and international suppliers, and
(4) difficult to obtain for manufacturers that do not have contracts in
place with suppliers. Furthermore, due in part to the major capital
investment required to build a steel plant, barriers to entry are high
and capacity cannot be easily increased. Transformer manufacturers feel
that all these factors contribute to the limited availability of higher
efficiency steel.
c. Compliance
Some manufacturers emphasized the importance of compliance and
enforcement. According to manufacturers, insufficient enforcement could
result in an unfair competitive advantage for some companies who opt
not to comply. Manufacturers were particularly concerned about
importers of foreign manufactured products. One specific issue is the
scope of coverage for low-voltage dry-type transformers, which is
currently the scope recommended by NEMA in the 2006 TP1 rulemaking. The
market for products inside of scope and the market for products outside
of scope are approximately equal in terms of revenue. As a result, if
standards increase for products that are in-scope, manufacturers are
concerned there would be an increase in demand for products that are
out-of-scope and are not be subject to the same compliance burdens.
Some of these out-of-scope products are highly inefficient, so if they
become more widely used, the energy savings resulting from more
efficient in-scope transformers may be significantly offset by the
additional energy needed to run less efficient out-of-scope
transformers.
d. Effective Date
Manufacturers expressed concerns about the amount of time being
provided for the implementation of a possible new standard.
Manufacturers indicated that more time is needed to meet a new
standard, especially if the standard requires a very high efficiency
level. In order to avoid stranding too many assets and materials,
sufficient time must be given to manufacturers for the purchase and use
of new equipment, development of new designs if needed, and
transitioning of customers to new product offerings. Also, some
manufacturers stated that standards for low-voltage dry-type
transformers, which were not included in the previous 2007 rulemaking,
should be on an extended timeline.
e. Emergency Situations
Liquid-immersed transformer manufacturers stated that the ability
to obtain waivers during emergency situations is an important issue for
them. For example, when a natural disaster occurs, there may be a sharp
increase in demand for transformers and manufacturers may not be able
to meet DOE's efficiency requirements under these circumstances due to
limitations of high efficiency steel availability. In order to
adequately supply areas facing such emergency situations, manufacturers
requested the ability to obtain waivers so that they can produce
transformers as quickly as possible.
Because the TSLs proposed in today's rulemaking can be met using
traditional steels, DOE does not anticipate that steel availability
during emergency situations will affect manufacturer compliance with
the proposed TSLs.
J. Employment Impact Analysis
DOE considers employment impacts in the domestic economy as one
factor in selecting a proposed standard. Employment impacts include
direct and indirect impacts. Direct employment impacts are any changes
in the number of employees of manufacturers of the products subject to
standards, their suppliers, and related service firms. The MIA
addresses those impacts. Indirect employment impacts are changes in
national employment that occur due to the shift in expenditures and
capital investment caused by the purchase and operation of more
efficient appliances. Indirect employment impacts from standards
consist of the jobs created or eliminated in the national economy,
other than in the manufacturing sector being regulated, due to: (1)
Reduced spending by end users on energy; (2) reduced spending on new
energy supply by the utility industry; (3) increased consumer spending
on the purchase of new products; and (4) the effects of those three
factors throughout the economy.
One method for assessing the possible effects on the demand for
labor of such shifts in economic activity is to compare sector
employment statistics developed by the Labor Department's Bureau of
Labor Statistics (BLS). BLS regularly publishes its estimates of the
number of jobs per million dollars of economic activity in different
sectors of the economy, as well as the jobs created elsewhere in the
economy by this same economic activity. Data from BLS indicate that
expenditures in the utility sector generally create fewer jobs (both
directly and indirectly) than expenditures in other sectors of the
economy.\34\ There are many reasons for these differences, including
wage differences and the fact that the utility sector is more capital-
intensive and less labor-intensive than other sectors. Energy
conservation standards have the effect of reducing consumer utility
bills. Because reduced consumer expenditures for energy likely lead to
increased expenditures in other sectors of the economy, the general
effect of efficiency standards is to shift economic activity from a
less labor-intensive sector (i.e., the utility sector) to more labor-
intensive sectors (e.g., the retail and service sectors). Thus, based
on the BLS data alone, DOE believes net national employment may
increase because of shifts in economic activity resulting from amended
standards for transformers.
---------------------------------------------------------------------------
\34\ See Bureau of Economic Analysis, Regional Multipliers: A
User Handbook for the Regional Input-Output Modeling System (RIMS
II). Washington, DC. U.S. Department of Commerce, 1992.
---------------------------------------------------------------------------
For the standard levels considered in today's direct final rule,
DOE estimated indirect national employment impacts using an input/
output model of the U.S. economy called Impact of Sector Energy
Technologies version 3.1.1 (ImSET). ImSET is a special-purpose version
of the ``U.S. Benchmark National Input-Output'' (I-O) model, which was
designed to estimate the national employment and income effects of
energy-saving technologies. The ImSET software includes a computer-
based I-O model having structural coefficients that characterize
economic flows among the 187 sectors. ImSET's national economic I-O
structure is based on a 2002 U.S. benchmark table, specially aggregated
to the 187 sectors most relevant to industrial, commercial, and
residential building energy use. DOE notes that ImSET is not a general
equilibrium
[[Page 7336]]
forecasting model. Given the relatively small change to expenditures
due to energy conservation standards and the resulting small changes to
employment, however, DOE believes that the size of any forecast error
caused by using ImSET will be small.
For more details on the employment impact analysis, see chapter 13
of the NOPR TSD.
K. Utility Impact Analysis
The utility impact analysis estimates several important effects on
the utility industry that would result from the adoption of new or
amended standards. For this analysis, DOE used the NEMS-BT model to
generate forecasts of electricity consumption, electricity generation
by plant type, and electric generating capacity by plant type, that
would result from each TSL. DOE obtained the energy savings inputs
associated with efficiency improvements to considered products from the
NIA. DOE conducts the utility impact analysis as a scenario that
departs from the latest AEO 2011 reference case. In other words, the
estimated impacts of a proposed standard are the differences between
values forecasted by NEMS-BT and the values in the AEO 2011 reference
case.
As part of the utility impact analysis, DOE used NEMS-BT to assess
the impacts on electricity prices of the reduced need for new electric
power plants and infrastructure projected to result from the considered
standards. In NEMS-BT, changes in power generation infrastructure
affect utility revenue requirements, which in turn affect electricity
prices. DOE estimated the change in electricity prices projected to
result over time from each TSL.
Chapter 14 of the NOPR TSD describes the utility impact analysis.
L. Emissions Analysis
In the emissions analysis, DOE estimated the reduction in power
sector emissions of CO2, NOX, and Hg from amended
energy conservation standards for distribution transformers. DOE used
the NEMS-BT computer model, which is run similarly to the AEO NEMS,
except that distribution transformer energy use is reduced by the
amount of energy saved (by fuel type) due to each TSL. The inputs of
national energy savings come from the NIA spreadsheet model, while the
output is the forecasted physical emissions. The net benefit of each
TSL is the difference between the forecasted emissions estimated by
NEMS-BT at each TSL and the AEO Reference Case. NEMS-BT tracks
CO2 emissions using a detailed module that provides results
with broad coverage of all sectors and inclusion of interactive
effects. For today's rule, DOE used the version of NEMS-BT based on
AEO2011, which incorporated projected effects of all emissions
regulations promulgated as of January 31, 2011.
SO2 emissions from affected electric generating units
(EGUs) are subject to nationwide and regional emissions cap and trading
programs, and DOE has determined that these programs create uncertainty
about the impact of energy conservation standards on SO2
emissions. Title IV of the Clean Air Act sets an annual emissions cap
on SO2 for affected EGUs in the 48 contiguous States and the
District of Columbia (DC). SO2 emissions from 28 eastern
States and DC are also limited under the Clean Air Interstate Rule
(CAIR, 70 Fed. Reg. 25162 (May 12, 2005)), which created an allowance-
based trading program that would gradually replaced the Title IV
program in those States and DC. Although CAIR was remanded to EPA by
the U.S. Court of Appeals for the District of Columbia Circuit (DC
Circuit), see North Carolina v. EPA, 550 F.3d 1176 (DC Cir. 2008), it
remained in effect temporarily, consistent with the DC Circuit's
earlier opinion in North Carolina v. EPA, 531 F.3d 896 (DC Cir. 2008).
On July 6, 2011 EPA issued a replacement for CAIR, the Cross-State Air
Pollution Rule. 76 FR 48208 (August 8, 2011). (See http://www.epa.gov/crossstaterule/). On December 30, 2011, however, the DC Circuit stayed
the new rules while a panel of judges reviews them, and told EPA to
continue enforcing CAIR (see EME Homer City Generation v. EPA, No. 11-
1302, Order at *2 (DC Cir. Dec. 30, 2011)). The AEO 2011 NEMS-BT used
for today's NOPR assumes the implementation of CAIR.
The attainment of emissions caps typically is flexible among EGUs
and is enforced through the use of emissions allowances and tradable
permits. Under existing EPA regulations, any excess SO2
emissions allowances resulting from the lower electricity demand caused
by the imposition of an efficiency standard could be used to permit
offsetting increases in SO2 emissions by any regulated EGU.
However, if the standard resulted in a permanent increase in the
quantity of unused emissions allowances, there would be an overall
reduction in SO2 emissions from the standards. While there
remains some uncertainty about the ultimate effects of efficiency
standards on SO2 emissions covered by the existing cap-and-
trade system, the NEMS-BT modeling system that DOE uses to forecast
emissions reductions currently indicates that no physical reductions in
power sector emissions would occur for SO2.
As discussed above, the AEO 2011 NEMS used for today's NOPR assumes
the implementation of CAIR, which established a cap on NOX
emissions in 28 eastern States and the District of Columbia. With CAIR
in effect, the energy conservation standards for distribution
transformers are expected to have little or no physical effect on
NOX emissions in those States covered by CAIR, for the same
reasons that they may have little effect on SO2 emissions.
However, the standards would be expected to reduce NOX
emissions in the 22 States not affected by CAIR. For these 22 States,
DOE used NEMS-BT to estimate NOX emissions reductions from
the standards considered in today's NOPR.
On December 21, 2011, EPA announced national emissions standards
for hazardous air pollutants (NESHAPs) for mercury and certain other
pollutants emitted from coal and oil-fired EGUs. (See http://epa.gov/mats/pdfs/20111216MATSfinal.pdf.) The NESHAPs do not include a trading
program and, as such, DOE's energy conservation standards would likely
reduce Hg emissions. For the emissions analysis for this rulemaking,
DOE estimated mercury emissions reductions using NEMS-BT based on
AEO2011, which does not incorporate the NESHAPs. DOE expects that
future versions of the NEMS-BT model will reflect the implementation of
the NESHAPs.
FPT requested that the DOE perform an emissions analysis for the
additional energy required to process higher-grade materials for more
efficient core steels. (FPT, No. 27 at p. 4) HI maintained that higher-
efficiency transformers will weigh more, which will result in higher
air emissions from extra oven energy for annealing and extra energy use
for processing raw materials. (HI, No. 23 at p. 12) As discussed in
section IV.G.5, DOE did not include the energy used to manufacture
transformers in its analysis because EPCA directs DOE to consider the
total projected amount of energy savings likely to result directly from
the imposition of the standard and DOE interprets this to only include
energy used in the generation, transmission, and distribution of fuels
used by appliances or equipment. DOE did not include the emissions
associated with such energy use for the same reason.
M. Monetizing Carbon Dioxide and Other Emissions Impacts
As part of the development of this proposed rule, DOE considered
the estimated monetary benefits likely to
[[Page 7337]]
result from the reduced emissions of CO2 and NOX
that are expected to result from each of the considered TSLs. In order
to make this calculation similar to the calculation of the NPV of
customer benefit, DOE considered the reduced emissions expected to
result over the lifetime of products shipped in the forecast period for
each TSL. This section summarizes the basis for the monetary values
used for each of these emissions and presents the values considered in
this rulemaking.
For today's NOPR, DOE is relying on a set of values for the social
cost of carbon (SCC) that was developed by an interagency process. A
summary of the basis for those values is provided below, and a more
detailed description of the methodologies used is provided as an
appendix to chapter 16 of the NOPR TSD.
1. Social Cost of Carbon
Under section 1(b)(6) of Executive Order 12866, 58 FR 51735 (Oct.
4, 1993), agencies must, to the extent permitted by law, ``assess both
the costs and the benefits of the intended regulation and, recognizing
that some costs and benefits are difficult to quantify, propose or
adopt a regulation only upon a reasoned determination that the benefits
of the intended regulation justify its costs.'' The purpose of the SCC
estimates presented here is to allow agencies to incorporate the
monetized social benefits of reducing CO2 emissions into
cost-benefit analyses of regulatory actions that have small, or
``marginal,'' impacts on cumulative global emissions. The estimates are
presented with an acknowledgement of the many uncertainties involved
and with a clear understanding that they should be updated over time to
reflect increasing knowledge of the science and economics of climate
impacts.
As part of the interagency process that developed the SCC
estimates, technical experts from numerous agencies met on a regular
basis to consider public comments, explore the technical literature in
relevant fields, and discuss key model inputs and assumptions. The main
objective of this process was to develop a range of SCC values using a
defensible set of input assumptions grounded in the existing scientific
and economic literatures. In this way, key uncertainties and model
differences transparently and consistently inform the range of SCC
estimates used in the rulemaking process.
a. Monetizing Carbon Dioxide Emissions
The SCC is an estimate of the monetized damages associated with an
incremental increase in carbon emissions in a given year. It is
intended to include (but is not limited to) changes in net agricultural
productivity, human health, property damages from increased flood risk,
and the value of ecosystem services. Estimates of the SCC are provided
in dollars per metric ton of carbon dioxide.
When attempting to assess the incremental economic impacts of
carbon dioxide emissions, the analyst faces a number of serious
challenges. A recent report from the National Research Council\35\
points out that any assessment will suffer from uncertainty,
speculation, and lack of information about (1) future emissions of
greenhouse gases, (2) the effects of past and future emissions on the
climate system, (3) the impact of changes in climate on the physical
and biological environment, and (4) the translation of these
environmental impacts into economic damages. As a result, any effort to
quantify and monetize the harms associated with climate change will
raise serious questions of science, economics, and ethics and should be
viewed as provisional.
---------------------------------------------------------------------------
\35\ National Research Council. ``Hidden Costs of Energy:
Unpriced Consequences of Energy Production and Use.'' National
Academies Press: Washington, DC 2009.
---------------------------------------------------------------------------
Despite the serious limits of both quantification and monetization,
SCC estimates can be useful in estimating the social benefits of
reducing carbon dioxide emissions. Consistent with the directive quoted
above, the purpose of the SCC estimates presented here is to make it
possible for agencies to incorporate the social benefits from reducing
carbon dioxide emissions into cost-benefit analyses of regulatory
actions that have small, or ``marginal,'' impacts on cumulative global
emissions. Most Federal regulatory actions can be expected to have
marginal impacts on global emissions.
For such policies, the agency can estimate the benefits from
reduced (or costs from increased) emissions in any future year by
multiplying the change in emissions in that year by the SCC value
appropriate for that year. The net present value of the benefits can
then be calculated by multiplying each of these future benefits by an
appropriate discount factor and summing across all affected years. This
approach assumes that the marginal damages from increased emissions are
constant for small departures from the baseline emissions path, an
approximation that is reasonable for policies that have effects on
emissions that are small relative to cumulative global carbon dioxide
emissions. For policies that have a large (non-marginal) impact on
global cumulative emissions, there is a separate question of whether
the SCC is an appropriate tool for calculating the benefits of reduced
emissions. This concern is not applicable to this notice, and DOE does
not attempt to answer that question here.
At the time of the preparation of this notice, the most recent
interagency estimates of the potential global benefits resulting from
reduced CO2 emissions in 2010, expressed in 2010$, were
$4.9, $22.3, $36.5, and $67.6 per metric ton avoided. For emissions
reductions that occur in later years, these values grow in real terms
over time. Additionally, the interagency group determined that a range
of values from 7 percent to 23 percent should be used to adjust the
global SCC to calculate domestic effects,\36\ although preference is
given to consideration of the global benefits of reducing
CO2 emissions.
---------------------------------------------------------------------------
\36\ It is recognized that this calculation for domestic values
is approximate, provisional, and highly speculative. There is no a
priori reason why domestic benefits should be a constant fraction of
net global damages over time.
---------------------------------------------------------------------------
It is important to emphasize that the interagency process is
committed to updating these estimates as the science and economic
understanding of climate change and its impacts on society improves
over time. Specifically, the interagency group has set a preliminary
goal of revisiting the SCC values within 2 years or at such time as
substantially updated models become available, and to continue to
support research in this area. In the meantime, the interagency group
will continue to explore the issues raised by this analysis and
consider public comments as part of the ongoing interagency process.
b. Social Cost of Carbon Values Used in Past Regulatory Analyses
To date, economic analyses for Federal regulations have used a wide
range of values to estimate the benefits associated with reducing
carbon dioxide emissions. In the model year 2011 CAFE final rule, the
Department of Transportation (DOT) used both a ``domestic'' SCC value
of $2 per metric ton of CO2 and a ``global'' SCC value of
$33 per metric ton of CO2 for 2007 emission reductions (in
2007$), increasing both values at 2.4 percent per year. It also
included a sensitivity analysis at $80 per metric ton of
CO2. See Average Fuel Economy Standards Passenger Cars and
Light Trucks Model Year 2011, 74 FR 14196 (March 30, 2009) (Final
Rule); Final Environmental Impact Statement Corporate Average Fuel
Economy Standards, Passenger Cars and Light Trucks, Model Years
[[Page 7338]]
2011-2015 at 3-90 (Oct. 2008) (Available at: http://www.nhtsa.gov/fuel-economy). A domestic SCC value is meant to reflect the value of damages
in the United States resulting from a unit change in carbon dioxide
emissions, while a global SCC value is meant to reflect the value of
damages worldwide.
A 2008 regulation proposed by DOT assumed a domestic SCC value of
$7 per metric ton of CO2 (in 2006$, with a range of $0 to
$14 for sensitivity analysis) for 2011 emission reductions, also
increasing at 2.4 percent per year. See Average Fuel Economy Standards,
Passenger Cars and Light Trucks, Model Years 2011-2015, 73 FR 24352
(May 2, 2008) (Proposed Rule); Draft Environmental Impact Statement
Corporate Average Fuel Economy Standards, Passenger Cars and Light
Trucks, Model Years 2011-2015 at 3-58 (June 2008) (Available at: http://www.nhtsa.gov/fuel-economy). A regulation for packaged terminal air
conditioners and packaged terminal heat pumps finalized by DOE in
October of 2008 used a domestic SCC range of $0 to $20 per metric ton
CO2 for 2007 emission reductions (in 2007$). 73 FR 58772,
58814 (Oct. 7, 2008). In addition, EPA's 2008 Advance Notice of
Proposed Rulemaking on Regulating Greenhouse Gas Emissions Under the
Clean Air Act identified what it described as ``very preliminary'' SCC
estimates subject to revision. 73 FR 44354 (July 30, 2008). EPA's
global mean values were $68 and $40 per metric ton CO2 for
discount rates of approximately 2 percent and 3 percent, respectively
(in 2006$ for 2007 emissions).
In 2009, an interagency process was initiated to offer a
preliminary assessment of how best to quantify the benefits from
reducing carbon dioxide emissions. To ensure consistency in how
benefits are evaluated across agencies, the Administration sought to
develop a transparent and defensible method, specifically designed for
the rulemaking process, to quantify avoided climate change damages from
reduced CO2 emissions. The interagency group did not
undertake any original analysis. Instead, it combined SCC estimates
from the existing literature to use as interim values until a more
comprehensive analysis could be conducted. The outcome of the
preliminary assessment by the interagency group was a set of five
interim values: Global SCC estimates for 2007 (in 2006$) of $55, $33,
$19, $10, and $5 per ton of CO2. These interim values
represent the first sustained interagency effort within the U.S.
government to develop an SCC for use in regulatory analysis. The
results of this preliminary effort were presented in several proposed
and final rules and were offered for public comment in connection with
proposed rules, including the joint EPA-DOT fuel economy and
CO2 tailpipe emission proposed rules.
c. Current Approach and Key Assumptions
Since the release of the interim values, the interagency group
reconvened on a regular basis to generate improved SCC estimates, which
were considered for this proposed rule. Specifically, the group
considered public comments and further explored the technical
literature in relevant fields. The interagency group relied on three
integrated assessment models (IAMs) commonly used to estimate the SCC:
The FUND, DICE, and PAGE models.\37\ These models are frequently cited
in the peer-reviewed literature and were used in the last assessment of
the Intergovernmental Panel on Climate Change. Each model was given
equal weight in the SCC values that were developed.
---------------------------------------------------------------------------
\37\ The models are described in appendix 15-A of the NOPR TSD.
---------------------------------------------------------------------------
Each model takes a slightly different approach to model how changes
in emissions result in changes in economic damages. A key objective of
the interagency process was to enable a consistent exploration of the
three models while respecting the different approaches to quantifying
damages taken by the key modelers in the field. An extensive review of
the literature was conducted to select three sets of input parameters
for these models: Climate sensitivity, socio-economic and emissions
trajectories, and discount rates. A probability distribution for
climate sensitivity was specified as an input into all three models. In
addition, the interagency group used a range of scenarios for the
socio-economic parameters and a range of values for the discount rate.
All other model features were left unchanged, relying on the model
developers' best estimates and judgments.
The interagency group selected four SCC values for use in
regulatory analyses. Three values are based on the average SCC from
three integrated assessment models, at discount rates of 2.5 percent, 3
percent, and 5 percent. The fourth value, which represents the 95th
percentile SCC estimate across all three models at a 3-percent discount
rate, is included to represent higher-than-expected impacts from
temperature change further out in the tails of the SCC distribution.
For emissions (or emission reductions) that occur in later years, these
values grow in real terms over time, as depicted in Table IV.7.
Table IV.7--Social Cost of CO2, 2010-2050
[In 2007 dollars per metric ton]
----------------------------------------------------------------------------------------------------------------
Discount rate (%)
----------------------------------------------------------------------------------
3
Year -------------------------------------------
5 3 2.5 95th
Average Average Average Percentile
---------------------------------------------------------------------------------------- ------------------------------
2010................................ 4.7 21.4 35.1 64.9
2015................................ 5.7 23.8 38.4 72.8
2020................................ 6.8 26.3 41.7 80.7
2025................................ 8.2 29.6 45.9 90.4
2030................................ 9.7 32.8 50.0 100.0
2035................................ 11.2 36.0 54.2 109.7
2040................................ 12.7 39.2 58.4 119.3
2045................................ 14.2 42.1 61.7 127.8
2050................................ 15.7 44.9 65.0 136.2
----------------------------------------------------------------------------------------------------------------
[[Page 7339]]
It is important to recognize that a number of key uncertainties
remain, and that current SCC estimates should be treated as provisional
and revisable since they will evolve with improved scientific and
economic understanding. The interagency group also recognizes that the
existing models are imperfect and incomplete. The National Research
Council report mentioned above points out that there is tension between
the goal of producing quantified estimates of the economic damages from
an incremental metric ton of carbon and the limits of existing efforts
to model these effects. There are a number of concerns and problems
that should be addressed by the research community, including research
programs housed in many of the agencies participating in the
interagency process to estimate the SCC.
DOE recognizes the uncertainties embedded in the estimates of the
SCC used for cost-benefit analyses. As such, DOE and others in the U.S.
Government intend to periodically review and reconsider those estimates
to reflect increasing knowledge of the science and economics of climate
impacts, as well as improvements in modeling. In this context,
statements recognizing the limitations of the analysis and calling for
further research take on exceptional significance.
In summary, in considering the potential global benefits resulting
from reduced CO2 emissions, DOE used the most recent values
identified by the interagency process, adjusted to 2010$ using the GDP
price deflator. For each of the four cases specified, the values used
for emissions in 2010 were $4.9, $22.3, $36.5, and $67.6 per metric ton
avoided (values expressed in 2010$).\38\ To monetize the CO2
emissions reductions expected to result from amended standards for
distribution transformers, DOE used the values identified in Table A1
of the ``Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866,'' which is reprinted in appendix 16-A of the
NOPR TSD, appropriately escalated to 2010$. To calculate a present
value of the stream of monetary values, DOE discounted the values in
each of the four cases using the specific discount rate that had been
used to obtain the SCC values in each case.
---------------------------------------------------------------------------
\38\ Table A1 presents SCC values through 2050. For DOE's
calculation, it derived values after 2050 using the 3-percent per
year escalation rate used by the interagency group.
---------------------------------------------------------------------------
2. Valuation of Other Emissions Reductions
DOE investigated the potential monetary benefit of reduced
NOX emissions from the TSLs it considered. As noted above,
new or amended energy conservation standards would reduce
NOX emissions in those 22 States that are not affected by
the CAIR. DOE estimated the monetized value of NOX emissions
reductions resulting from each of the TSLs considered for today's NOPR
based on environmental damage estimates found in the relevant
scientific literature. Available estimates suggest a very wide range of
monetary values, ranging from $370 per ton to $3,800 per ton of
NOX from stationary sources, measured in 2001$ (equivalent
to a range of $450 to $4,623 per ton in 2010$).\39\ In accordance with
OMB guidance, DOE conducted two calculations of the monetary benefits
derived using each of the economic values used for NOX, one
using a real discount rate of 3 percent and the other using a real
discount rate of 7 percent. \40\
---------------------------------------------------------------------------
\39\ For additional information, refer to U.S. Office of
Management and Budget, Office of Information and Regulatory Affairs,
2006 Report to Congress on the Costs and Benefits of Federal
Regulations and Unfunded Mandates on State, Local, and Tribal
Entities, Washington, DC
\40\ OMB, Circular A-4: Regulatory Analysis (Sept. 17, 2003).
---------------------------------------------------------------------------
DOE is aware of multiple agency efforts to determine the
appropriate range of values used in evaluating the potential economic
benefits of reduced Hg emissions. DOE has decided to await further
guidance regarding consistent valuation and reporting of Hg emissions
before it once again monetizes Hg in its rulemakings.
N. Discussion of Other Comments
Comments DOE received in response to the preliminary analysis on
the soundness and validity of the methodologies and data DOE used are
discussed in section IV. Other stakeholder comments in response to the
preliminary analysis addressed the burdens and benefits associated with
new energy conservation standards. DOE addresses these other
stakeholder comments below.
1. Trial Standard Levels
Current standards maintain ``harmonized'' standards across phases,
which means that a single-phase transformer must meet the same
efficiency standard of its three-phase analog of three times the kVA.
DOE is aware of the potential for misapplied standards to shift market
demand to segments with relatively less stringent coverage and
implanted phase harmonization to guard against incentivizing
replacement of three-phase transformers with three smaller single-phase
units.
HVOLT asserted that the previous 2007 rulemaking misstated the
potential of three-phase distribution transformers early on in the
rulemaking. Furthermore, HVOLT commented that, as a result, the final
selected TSL for three-phase distribution transformers was low compared
to the TSL selected for single-phase transformers. HVOLT believes that
this has caused a misperception to the public that three-phase
transformers received a less-stringent standard, when it is in fact of
equal stringency to the standard for single-phase transformers. HVOLT
requested that this point be clarified in the NOPR. (HVOLT, No. 33 at
p. 2)
Relative to single-phase designs, DOE understands three-phase
transformers to have an efficiency disadvantage related to harmonics
and zero-sequence fluxes. That disadvantage happens to be of such a
size that efficiency will be similar, all else constant, for
transformers with the same power per phase. For example, a 75 kVA
three-phase unit should have efficiency similar to that of a 25 kVA
single-phase unit designed to similar specifications. During the 2007
rulemaking, DOE created additional TSLs to ``harmonize'' efficiency
across phase counts in responses to stakeholder comment that standards
should be set thus.
For the NOPR, DOE relaxed the phase harmonization constraint on
single-phase efficiency, particularly for LVDT and MVDT equipment
classes. DOE believes that market shift will not occur unless standards
are dramatically disproportionate.
DOE acknowledges that acceptance of this ``constant efficiency per
phase'' principle is not universal and seeks comment on where and why
this principle may or may not apply.
Hammond Power Solutions and Howard Industries expressed agreement
with DOE's method to develop TSLs. (HPS, No. 3 at p. 5; HI, No. 23 at
p. 7) However, ASAP commented that it would like to see the TSL at the
minimum LCC point as well as the maximum level that is cost-effective,
which typically would fall above the LCC. (ASAP, Pub. Mtg. Tr., No. 34
at p. 127) Furthermore, ASAP encouraged DOE to consider a TSL that
retained a variety of core materials as an option, and to include a
wide range of TSLs for consideration. (ASAP, Pub. Mtg. Tr., No. 34 at
p. 128) ABB commented that DOE should develop a structured methodology
that evaluates and ranks
[[Page 7340]]
each CSL and TSL based on technological feasibility, economic
justification, and maximum improvement in energy efficiency. (ABB, No.
14 at pp. 16, 19-20) ABB added that DOE should recognize the risk of
inadvertently shifting demand between kVA within the same equipment
class, between single-phase and three-phase units within the same
product group (e.g. MVDT or LVDT), between product groups (e.g.,
between liquid-immersed and MVDT), and between new product offerings
and refurbished transformers. (ABB, No. 14 at pp. 16, 19-20) Edison
Electrical Institute requested that DOE provide detailed tables
explaining how the CSL numbers in the preliminary analysis relate to
the TSL numbers in the NOPR. (EEI, No. 29 at p. 6)
DOE constructs TSLs from efficiency levels (ELs), the NOPR analog
of the Preliminary Analysis' CSLs, using several economic factors
(e.g., maximum LCC) and technological factors (e.g., maximum LCC where
a variety of core materials are available) factors. DOE did not choose
a TSL corresponding to minimized LCC savings above the maximum, but
does have a TSL corresponding to the CSL above maximum LCC savings that
offers increased efficiency. DOE does not use CSLs from the Preliminary
Analysis to construct TSLs, but does outline in section V.A the ELs
packaged into each TSL. Finally, DOE is concerned about the possibility
of inadvertently shifting demand between equipment.
2. Proposed Standards
NRECA and T&DEC cautioned that raising efficiency standards for
medium-voltage dry-type transformers would limit a customer's purchase
choices and increase costs both for utilities and their customers. They
stated that higher efficiency standards would not be economically
justified for rural electric cooperatives. (NRECA/T&DEC, No. 31 and No.
36 at pp. 1-2) FPT stated its opposition to new efficiency standards
that would limit the choices available to customers to achieve the
optimum transformer design for each circumstance. (FPT, No. 27 at p. 1)
PHI recommended that DOE not raise efficiency standards for liquid-
immersed distribution transformers because they cannot withstand
additional increases in weight or dimensions. (PHI, Nos. 26 and 37 at
p. 1) FPT commented that, if the efficiency levels for medium-voltage
dry-type transformers are increased, the PBP for the cost increase to
meet the higher mandated efficiency should be no longer than 3 to 5
years. (FPT, No. 27 at p. 18)
DOE appreciates comment on appropriate standard levels and
acknowledges that maintaining availability of equipment offering unique
consumer utility is important. DOE believes, however, that it has made
an effort to quantify the costs of more efficient equipment to a
variety of consumers as well as the costs of additional size and
weight.
The Kentucky Association of Electric Cooperatives, Inc. (KAEC)
commented that the current minimum efficiency standards for liquid-
immersed distribution transformers already represent the maximum energy
efficiency that is economically justified, and any higher efficiency
level will come at a high cost. (KAEC, No. 4 at pp. 1-2) Power Partners
commented that increases to the current minimum efficiency standards
are not justified based on the increased costs to manufacturers,
customers, and ultimately, consumers. (PP, No. 19 at p. 1) FPT noted
that it is not in favor of increasing efficiency standards for dry-type
distribution transformers because higher efficiency levels will take
away customer choices for the most optimum transformer design. (FPT,
No. 27 at pp. 1, 18) Additionally, FPT commented that, because most
MVDTs are custom built, they should not be subject to standards. (FPT,
No. 27 at pp. 1, 18) Furthermore, HVOLT noted that any standard level
should not require a specific design, including materials,
configurations and manufacturing methods. HVOLT believes that the 2007
rule reached the limits for many of these considerations, and once the
inputs are corrected, the analysis will indicate this result. (HVOLT,
No. 33 at p. 3)
Berman Economics suggested that DOE set the efficiency standard at
the highest level justified, which appeared to be CSL 4 in the
preliminary analysis or CSL 2 at a minimum after adjusting for
overpricing. BE suggested that change itself affects manufacturers more
than the amount of change because any change in efficiency standards
requires manufacturers to re-optimize designs to ensure compliance.
(BE, No. 16 at p. 2) Joint comments submitted by ASAP, ACEEE and NRDC
noted that DOE's analysis shows that amorphous steel is cost-effective
and commented that DOE should propose standards that utilize amorphous
steel technology for a portion of the market. They believed that DOE
should identify the portion of the market that would be the least
disrupted by standards set at an amorphous level, such as small, pad-
mounted liquid-immersed transformers (DL1 and DL4). It is their
understanding that most of the manufacturers operating in the DL1 and
DL4 markets already have amorphous capabilities, and very few smaller
manufacturers operate in this market segment. (ASAP/ACEEE/NRDC, No. 28
at pp. 4-5) Alternatively, Power Partners commented that DOE should not
set a standard level that requires a core steel above the M3 grade.
(PP, No. 19 at p. 4)
DOE conducted several analyses in order to meet its obligation to
evaluate the economic justifiability of a proposed standard, notable
among them the LCC and PBP Analysis and the NIA. Summaries of those
analyses are present in this notice, with more detailed descriptions of
the methodology in the TSD. In proposing or setting standards, DOE
considers a variety of criteria, including the availability of
materials needed to reach a given efficiency. In the case of core
steel, DOE has conducted a supply analysis (presented in appendix 3A of
the NOPR TSD) examining the ability of the market to supply steel at
different efficiency levels and requests comment on the methodology and
results of this analysis. The barriers to entry and the potential for
limited supply of amorphous steel, and the potential for significant
price in the near future, are important qualitative factors that DOE is
considering.
The Copper Development Association (CDA) and Pacific Gas & Electric
(PG&E) commented that DOE should set standards levels at the highest
efficiency that is technologically feasible and economically justified.
(CDA, No. 17 at p. 1; PG&E, Pub. Mtg. Tr., No. 34 at pp. 24-25) The
American Public Power Association (APPA) noted that the October 2007
final rule for distribution transformers achieved the highest
efficiency levels that are economically justified and expressed concern
that when efficiency levels gravitate to the highest levels achievable,
the cost benefit analysis breaks down as peripheral costs rise. Pole
replacements and pad mount replacements-due to larger distribution
transformers-also add costs that might not be adequately captured in
the DOE analysis. (APPA, No. 21 at p. 2)
HVOLT opined that this rulemaking is a reassessment of the previous
distribution transformers rulemaking but with new economic parameters.
It asserted that national standards should be doable with known
technology, not require an invention, and not put a lot of
manufacturers out of business. (HVOLT, Pub. Mtg. Tr., No. 34 at p. 116)
NRECA and the Transmission & Distribution Engineering Committee
[[Page 7341]]
(T&DEC) together recommended that DOE not raise the efficiency
standards for liquid-filled distribution transformers, because the
current levels already represent the economically justified maximum
efficiency. Both added that many users in rural areas with low
transformer loads cannot economically justify the current level.
(NRECA/T&DEC, Nos. 31 and 36 at p. 1) Additionally, the added weight
and increased dimensions of the higher efficiency distribution
transformers would require pole replacement for many cooperatives and
other utilities. NRECA/T&DEC opined that when higher efficiency levels
are mandated, the result could be less production, less-competitive
materials, questionable availability, and reduced competition. (NRECA/
T&DEC, Nos. 31 and 36 at p. 3)
FPT noted that if DOE sets higher efficiency standards, it should
coordinate with the EPA to reinstitute the Energy Star program for
distribution transformers so that manufacturers can use the label to
market their products. (FPT, No. 27 at p. 4) FPT also commented that
higher efficiency levels based on a specified loading of 35 percent or
50 percent could result in greater losses for applications that operate
at higher load factors. FPT provided an example of a NEMA Premium
transformer versus a TP1 transformer with an 80-degree temperature
rise, indicating that the TP1 transformer with the lower temperature
rise could have a greater efficiency at loadings above 50 percent.
(FPT, No. 27 at pp. 5-7)
The Kentucky Association of Electric Cooperatives (KAEC) believed
that liquid-immersed single-phase standards are adequate and achieve
maximum efficiency while being economically justifiable. It believed
the biggest efficiency gains have already been made. In addition, KAEC
expressed concern that, as a small manufacturer, it would need higher
capital investment to meet any increase in efficiency standards, and
that its energy savings would be less and payback periods longer
because it and other rural electric cooperatives serve fewer customers.
(KAEC, Pub. Mtg. Tr., No. 34 at pp. 22-23)
As stated previously, DOE seeks to set the highest energy
conservation standards that are technologically feasible, economically
justified, and that will result in significant energy savings and
appreciates any analysis that would assist DOE in evaluating the
appropriate standard using these parameters.
3. Alternative Methods
Mr. Kenneth Harden (HK), a design engineer, offered to DOE a copy
of his thesis, which evaluated the impact of federal regulations and
operational conditions on the efficiency of low-voltage dry-type
distribution transformers, and provided recommendations to optimize
future rulemakings certifying the energy efficiency of low-voltage dry-
type distribution transformers. It also recommended the specification
of low-voltage dry-type distribution transformers and the design of
transformers for industrial power networks. (HK, No. 12 at p. 1)
DOE appreciates Mr. Harden's submission and would welcome a meeting
to discuss some of the thoughts he has put forth on the rulemaking
process in general and on distribution transformers in particular.
4. Labeling
Both NEMA and FPT recommended that DOE establish a uniform approach
for how to mark a distribution transformer nameplate to indicate
compliance with the applicable energy conservation standard in 10 CFR
431.196. (FPT, No. 27 at p. 20; NEMA, No. 13 at p. 9) NEMA proposed the
following: ``DOE 10 CFR PART 431 COMPLIANT.'' (NEMA, No. 13 at p. 9)
DOE appreciates the comments regarding labeling and will take it
under consideration as it continues to explore appropriate requirements
for certification, compliance, enforcement and how labeling may fit
into those processes. Certification requirements for distribution
transformers can be found in 10 CFR 429.47.
5. Imported Units
NEMA commented that, although covered non-compliant products that
are imported for export must be marked as such, U.S. Customs and Border
Protection will likely have difficulty determining which products are
covered, and whether a covered product is compliant, other than those
marked for export. (NEMA, No. 13 at p. 9)
DOE notes that it is the responsibility of the importer, and not
United States Customs, to establish compliance just as any manufacturer
would. DOE welcomes further comment and evidence that can suggest
imported transformers are failing to meet standards.
V. Analytical Results and Conclusions
A. Trial Standard Levels
DOE analyzed the benefits and burdens of the TSLs developed for
today's proposed rule. DOE examined seven TSLs for liquid-immersed
distribution transformers, six TSLs for low-voltage, dry-type
distribution transformers, and five TSLs for medium-voltage dry-type
distribution transformers. Table V.1 through Table V.3 present the TSLs
analyzed and the corresponding efficiency level for the representative
unit in each transformer design line. For other capacities in each
design line, the corresponding efficiencies for each TSL are given in
appendix 8-B in the NOPR TSD. The baseline in the tables is equal to
the current energy conservation standard.
For liquid-immersed distribution transformers, the efficiency
levels in each TSL can be characterized as follows: TSL 1 represents an
increase in efficiency where a diversity of electrical steels are cost-
competitive and economically feasible for all design lines; TSL 2
represents EL1 for all design lines; TSL 3 represents the maximum
efficiency level achievable with M3 core steel; TSL 4 represents the
maximum NPV with 7 percent discounting; TSL 5 represents EL 3 for all
design lines; TSL 6 represents the maximum source energy savings with
positive NPV with 7 percent discounting; and TSL 7 represents the
maximum technologically feasible level (max tech).
For low-voltage, dry-type distribution transformers, the efficiency
levels in each TSL can be characterized as follows: TSL 1 represents
the maximum efficiency level achievable with M6 core steel; TSL 2
represents NEMA premium levels; TSL 3 represents the maximum EL
achievable using butt-lap miter core manufacturing for single-phase
distribution transformers, and full miter core manufacturing for three-
phase distribution transformers; TSL 4 represents the maximum NPV with
7 percent discounting; TSL 5 represents the maximum source energy
savings with positive NPV with 7 percent discounting; and TSL 6
represents the maximum technologically feasible level (max tech).
For medium-voltage, dry-type distribution transformers, the
efficiency levels in each TSL can be characterized as follows: TSL 1
represents EL1 for all design lines; TSL 2 represents an increase in
efficiency where a diversity of electrical steels are cost-competitive
and economically feasible for all design lines; TSL 3 represents the
maximum NPV with 7 percent discounting; TSL 4 represents the maximum
source energy savings with positive NPV with 7 percent discounting; and
TSL 5 represents the maximum
[[Page 7342]]
technologically feasible level (max tech).
Table V.1--Efficiency Values of the Trial Standard Levels for Liquid-Immersed Transformers by Design Line
[In percent]
--------------------------------------------------------------------------------------------------------------------------------------------------------
TSL
Design line Baseline ----------------------------------------------------------------------------
1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
1............................................................... 99.08 99.16 99.16 99.16 99.22 99.25 99.31 99.50
2............................................................... 98.91 98.91 99.00 99.00 99.07 99.11 99.18 99.41
3............................................................... 99.42 99.48 99.48 99.51 99.57 99.54 99.61 99.73
4............................................................... 99.08 99.16 99.16 99.16 99.22 99.25 99.31 99.60
5............................................................... 99.42 99.48 99.48 99.51 99.57 99.54 99.61 99.69
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.2--Efficiency Values of the Trial Standard Levels for Low-Voltage Dry-Type Transformers by Design Line
[In percent]
----------------------------------------------------------------------------------------------------------------
TSL
Design line Baseline -----------------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
6.................................. 98.00 98.00 98.60 98.80 99.17 99.17 99.44
7.................................. 98.00 98.47 98.60 98.80 99.17 99.17 99.44
8.................................. 98.60 99.02 99.02 99.25 99.44 99.58 99.58
----------------------------------------------------------------------------------------------------------------
Table V.3--Efficiency Values of the Trial Standard Levels for Medium-Voltage Dry-Type Transformers by Design
Line
[In percent]
----------------------------------------------------------------------------------------------------------------
TSL
Design line Baseline ------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
9............................................. 98.82 98.93 98.93 99.04 99.04 99.55
10............................................ 99.22 99.29 99.37 99.37 99.37 99.63
11............................................ 98.67 98.81 98.81 99.13 99.13 99.50
12............................................ 99.12 99.21 99.30 99.46 99.46 99.63
13A........................................... 98.63 98.69 98.69 99.04 99.04 99.45
13B........................................... 99.15 99.19 99.28 99.45 99.45 99.52
----------------------------------------------------------------------------------------------------------------
B. Economic Justification and Energy Savings
1. Economic Impacts on Customers
a. Life-Cycle Cost and Payback Period
To evaluate the net economic impact of standards on transformer
customers, DOE conducted LCC and PBP analyses for each TSL. In general,
a higher-efficiency product would affect customers in two ways: (1)
Annual operating expense would decrease; and (2) purchase price would
increase. Section III.F.2 of this notice discusses the inputs DOE used
for calculating the LCC and PBP. The LCC and PBP results are calculated
from transformer cost and efficiency data that are modeled in the
engineering analysis (section IV.C). During the negotiated rulemaking,
DOE presented separate transformer cost data based on 2010 and 2011
material prices to the committee members. DOE conducted its LCC and PBP
analysis utilizing both the 2010 and 2011 material price cost data. The
average results of these two analyses are presented here.
For each design line, the key outputs of the LCC analysis are a
mean LCC savings and a median PBP relative to the base case, as well as
the fraction of customers for which the LCC will decrease (net
benefit), increase (net cost), or exhibit no change (no impact)
relative to the base-case product forecast. No impacts occur when the
product efficiencies of the base-case forecast already equal or exceed
the efficiency at a given TSL. Table V.4 through Table V.17 show the
key results for each transformer design line.
Table V.4--Summary Life-Cycle Cost and Payback Period Results for Design Line 1 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------------------------------------------
1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)........................................ 99.16 99.16 99.16 99.22 99.25 99.31 99.50
Transformers with Net LCC Cost (%).................... 57.9 57.9 57.9 4.8 4.8 8.0 55.4
[[Page 7343]]
Transformers with Net LCC Benefit (%)................. 41.8 41.8 41.8 95.0 95.0 92.0 44.6
Transformers with No Change in LCC (%)................ 0.2 0.2 0.2 0.2 0.2 0.0 0.0
Mean LCC Savings ($).................................. 36 36 36 641 641 532 50
Median PBP (Years).................................... 20.2 20.2 20.2 7.9 7.9 10.0 19.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.5--Summary Life-Cycle Cost and Payback Period Results for Design Line 2 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------------------------------------------
1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)........................................ 98.91 99.00 99.00 99.07 99.11 99.18 99.41
Transformers with Net LCC Cost (%).................... 0.0 14.2 14.2 9.8 11.2 15.8 80.2
Transformers with Net LCC Benefit (%)................. 0.0 85.8 85.8 90.2 88.8 84.3 19.8
Transformers with No Change in LCC (%)................ 100.0 0.0 0.0 0.0 0.0 0.0 0.0
Mean LCC Savings ($).................................. 0 309 309 338 300 250 -736
Median PBP (Years).................................... 0.0 6.9 6.9 8.0 9.5 11.5 24.3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.6--Summary Life-Cycle Cost and Payback Period Results for Design Line 3 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------------------------------------------
1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)........................................ 99.48 99.48 99.51 99.57 99.54 99.61 99.73
Transformers with Net LCC Cost (%).................... 15.7 15.7 11.2 4.0 5.3 3.9 25.1
Transformers with Net LCC Benefit (%)................. 83.0 83.0 87.7 96.0 94.6 96.1 74.9
Transformers with No Change in LCC (%)................ 1.4 1.4 1.2 0.0 0.0 0.0 0.0
Mean LCC Savings ($).................................. 2,413 2,413 3,831 5,591 5,245 6,531 4,135
Median PBP (Years).................................... 6.3 6.3 4.0 4.7 4.6 5.2 13.3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.7--Summary Life-Cycle Cost and Payback Period Results for Design Line 4 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------------------------------------------
1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)........................................ 99.16 99.16 99.16 99.22 99.25 99.31 99.60
Transformers with Net LCC Cost (%).................... 6.0 6.0 6.0 1.9 1.9 1.9 31.1
Transformers with Net LCC Benefit (%)................. 93.5 93.5 93.5 97.5 97.5 97.6 63.9
Transformers with No Change in LCC (%)................ 0.6 0.6 0.6 0.6 0.6 0.6 0.0
Mean LCC Savings ($).................................. 862 862 862 3,356 3,356 3,362 1,274
Median PBP (Years).................................... 5.0 5.0 5.0 4.1 4.1 4.1 14.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.8--Summary Life-Cycle Cost and Payback Period Results for Design Line 5 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------------------------------------------
1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)........................................ 99.48 99.48 99.51 99.57 99.54 99.61 99.69
Transformers with Net LCC Cost (%).................... 19.1 19.1 13.2 7.8 10.4 7.9 39.9
Transformers with Net LCC Benefit (%)................. 80.6 80.6 86.8 92.2 89.6 92.1 60.1
[[Page 7344]]
Transformers with No Change in LCC (%)................ 0.4 0.4 0.1 0.0 0.0 0.0 0.0
Mean LCC Savings ($).................................. 7,787 7,787 10,288 12,513 11,395 12,746 3,626
Median PBP (Years).................................... 4.0 4.0 4.2 6.3 5.7 8.3 16.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.9--Summary Life-Cycle Cost and Payback Period Results for Design Line 6 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).............. 98.00 98.60 98.93 99.17 99.17 99.44
Transformers with Net 0.0 71.5 17.6 36.2 36.2 93.4
Increase in LCC (%)........
Transformers with Net LCC 0.0 28.5 82.4 63.8 63.8 6.6
Savings (%)................
Transformers with No Impact 100.0 0.0 0.0 0.0 0.0 0.0
on LCC (%).................
Mean LCC Savings ($)........ 0 -125 335 187 187 -881
Median PBP (Years).......... 0.0 24.7 13.0 16.3 16.3 32.4
----------------------------------------------------------------------------------------------------------------
Table V.10--Summary Life-Cycle Cost and Payback Period Results for Design Line 7 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).............. 98.47 98.60 98.80 99.17 99.17 99.44
Transformers with Net 1.8 1.8 2.0 3.7 3.7 46.4
Increase in LCC (%)........
Transformers with Net LCC 98.2 98.2 98.0 96.3 96.3 53.6
Savings (%)................
Transformers with No Impact 0.0 0.0 0.0 0.0 0.0 0.0
on LCC (%).................
Mean LCC Savings ($)........ 1,714 1,714 1,793 2,270 2,270 270
Median PBP (Years).......... 4.5 4.5 4.7 6.9 6.9 18.1
----------------------------------------------------------------------------------------------------------------
Table V.11--Summary Life-Cycle Cost and Payback Period Results for Design Line 8 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).............. 99.02 99.02 99.25 99.44 99.58 99.58
Transformers with Net 5.2 5.2 15.3 10.5 78.5 78.5
Increase in LCC (%)........
Transformers with Net LCC 94.8 94.8 84.7 89.5 21.5 21.5
Savings (%)................
Transformers with No Impact 0.0 0.0 0.0 0.0 0.0 0.0
on LCC (%).................
Mean LCC Savings ($)........ 2,476 2,476 2,625 4,145 -2,812 -2,812
Median PBP (Years).......... 8.4 8.4 12.3 11.0 24.5 24.5
----------------------------------------------------------------------------------------------------------------
Table V.12--Summary Life-Cycle Cost and Payback Period Results for Design Line 9 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
---------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Efficiency (%)............................ 98.93 98.93 99.04 99.04 99.55
Transformers with Net Increase in LCC (%). 3.4 3.4 5.7 5.7 53.4
Transformers with Net LCC Savings (%)..... 83.4 83.4 94.3 94.3 46.6
Transformers with No Impact on LCC (%).... 13.3 13.3 0.0 0.0 0.0
Mean LCC Savings ($)...................... 849 849 1,659 1,659 237
Median PBP (Years)........................ 2.6 2.6 6.2 6.2 19.1
----------------------------------------------------------------------------------------------------------------
Table V.13--Summary Life-Cycle Cost and Payback Period Results for Design Line 10 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
---------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Efficiency (%)............................ 99.29 99.37 99.37 99.37 99.63
Transformers with Net Increase in LCC (%). 0.7 16.7 16.7 16.7 84.8
[[Page 7345]]
Transformers with Net LCC Savings (%)..... 98.8 83.3 83.3 83.3 15.2
Transformers with No Impact on LCC (%).... 0.5 0.0 0.0 0.0 0.0
Mean LCC Savings ($)...................... 4,509 4,791 4,791 4,791 -12,756
Median PBP (Years)........................ 1.1 8.8 8.8 8.8 28.4
----------------------------------------------------------------------------------------------------------------
Table V.14--Summary Life-Cycle Cost and Payback Period Results for Design Line 11 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
---------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Efficiency (%)............................ 98.81 98.81 99.13 99.13 99.50
Transformers with Net Increase in LCC (%). 20.6 20.6 25.7 25.7 76.1
Transformers with Net LCC Savings (%)..... 79.4 79.4 74.3 74.3 23.9
Transformers with No Impact on LCC (%).... 0.0 0.0 0.0 0.0 0.0
Mean LCC Savings ($)...................... 1,043 1,043 2,000 2,000 -3160
Median PBP (Years)........................ 10.7 10.7 14.1 14.1 24.5
----------------------------------------------------------------------------------------------------------------
Table V.15--Summary Life-Cycle Cost and Payback Period Results for Design Line 12 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
---------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Efficiency (%)............................ 99.21 99.30 99.46 99.46 99.63
Transformers with Net Increase in LCC (%). 6.7 7.8 18.1 18.1 81.1
Transformers with Net LCC Savings (%)..... 93.3 92.2 81.9 81.9 18.9
Transformers with No Impact on LCC (%).... 0.0 0.0 0.0 0.0 0.0
Mean LCC Savings ($)...................... 4,518 6,934 8,860 8,860 -12,420
Median PBP (Years)........................ 6.3 9.0 13.0 13.0 25.9
----------------------------------------------------------------------------------------------------------------
Table V.16--Summary Life-Cycle Cost and Payback Period Results for Design Line 13A Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
---------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Efficiency (%)............................ 98.69 98.69 99.04 99.04 99.45
Transformers with Net Increase in LCC (%). 52.2 52.2 64.4 64.4 97.1
Transformers with Net LCC Savings (%)..... 47.8 47.8 35.6 35.6 2.9
Transformers with No Impact on LCC (%).... 0.0 0.0 0.0 0.0 0.0
Mean LCC Savings ($)...................... 25 25 -846 -846 -11,077
Median PBP (Years)........................ 16.5 16.5 21.7 21.7 37.1
----------------------------------------------------------------------------------------------------------------
Table V.17--Summary Life-Cycle Cost and Payback Period Results for Design Line 13B Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
---------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Efficiency (%)............................ 99.19 99.28 99.45 99.45 99.52
Transformers with Net Increase in LCC (%). 28.5 26.3 52.7 52.7 67.2
Transformers with Net LCC Savings (%)..... 71.3 73.7 47.3 47.3 32.8
Transformers with No Impact on LCC (%).... 0.2 0.0 0.0 0.0 0.0
Mean LCC Savings ($)...................... 2,733 4,709 384 384 -5,407
Median PBP (Years)........................ 4.6 12.5 19.3 19.3 21.9
----------------------------------------------------------------------------------------------------------------
b. Customer Subgroup Analysis
DOE estimated customer subgroup impacts by determining the LCC
impacts of the distribution transformer TSLs on purchasers of vault-
installed transformers (primarily urban utilities). DOE included only
the liquid-immersed design lines in this analysis, since those types
account for more than ninety percent of the transformers purchased by
electric utilities. Table V.18 shows the mean LCC savings at each TSL
for this customer subgroup.
Chapter 11 of the NOPR TSD explains DOE's method for conducting the
customer subgroup analysis and
[[Page 7346]]
presents the detailed results of that analysis.
Table V.18--Comparison of Mean Life-Cycle Cost Savings for Liquid-Immersed Transformers Purchased by Consumer Subgroups
[2010$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Design line ------------------------------------------------------------------------------------------
1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Medium Vault Replacement Subgroup
--------------------------------------------------------------------------------------------------------------------------------------------------------
4............................................................ -422 -422 -422 106 106 113 -2,358
5............................................................ 1,062 1,062 3,203 4,689 3,854 4,270 -5,996
--------------------------------------------------------------------------------------------------------------------------------------------------------
All Customers
--------------------------------------------------------------------------------------------------------------------------------------------------------
4............................................................ 862 862 862 3,356 3,356 3,362 1,274
5............................................................ 7,787 7,787 10,288 12,513 11,395 12,746 3626
--------------------------------------------------------------------------------------------------------------------------------------------------------
c. Rebuttable-Presumption Payback
As discussed above, EPCA establishes a rebuttable presumption that
an energy conservation standard is economically justified if the
increased purchase cost for a product that meets the standard is less
than three times the value of the first-year energy savings resulting
from the standard. (42 U.S.C. 6295(o)(2)(B)(iii), 6316(a)) DOE
calculated a rebuttable-presumption PBP for each TSL to determine
whether DOE could presume that a standard at that level is economically
justified. Table V.19 shows the rebuttable-presumption PBPs for the
considered TSLs. Because only a single, average value is necessary for
establishing the rebuttable-presumption PBP, DOE used discrete values
rather than distributions for its input values. As required by EPCA,
DOE based the calculations on the assumptions in the DOE test procedure
for distribution transformers. (42 U.S.C. 6295(o)(2)(B)(iii), 6316(a))
As a result, DOE calculated a single rebuttable-presumption payback
value, and not a distribution of PBPs, for each TSL.
Table V.19--Rebuttable-Presumption Payback Periods (years) for Liquid-Immersed Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rated Trial standard level
Design line capacity ------------------------------------------------------------------------------------------
(kVA) 1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
1............................................... 50 17.1 17.1 17.1 8.3 8.3 10.2 16.3
2............................................... 25 0.0 9.5 9.5 9.9 11.0 12.5 21.3
3............................................... 500 5.8 5.8 4.5 4.9 4.9 5.2 11.9
4............................................... 150 4.7 4.7 4.7 3.9 3.9 4.0 13.5
5............................................... 1500 4.3 4.3 4.2 5.9 5.5 7.5 15.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.20--Rebuttable-Presumption Payback Periods (years) for Low-Voltage Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rated Trial standard level
Design line capacity -----------------------------------------------------------------------------
(kVA) 1 2 3 4 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
6............................................................ 25 0.0 15.9 13.0 15.0 15.0 26.5
7............................................................ 75 4.2 4.2 4.4 6.4 6.4 14.9
8............................................................ 300 6.8 6.8 10.4 9.7 20.2 20.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.21--Rebuttable-Presumption Payback Periods (Years) for Medium-Voltage Dry-Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Rated Trial standard level
Design line capacity ----------------------------------------------------------------
(kVA) 1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
9................................. 300 1.9 1.9 4.6 4.6 15.5
10................................ 1,500 1.9 5.7 5.7 5.7 21.8
11................................ 300 9.5 9.5 13.0 13.0 18.8
12................................ 1,500 5.5 7.44 12.0 12.0 20.3
13A............................... 300 11.9 11.9 22.2 22.2 28.9
13B............................... 2,000 5.2 11.1 19.1 19.1 19.4
----------------------------------------------------------------------------------------------------------------
[[Page 7347]]
DOE believes that the rebuttable-presumption PBP criterion (i.e., a
limited PBP) is not sufficient for determining economic justification.
Therefore, DOE has considered a full range of impacts, including those
to customers, manufacturers, the Nation, and the environment. Section
V.C provides a complete discussion of how DOE considered the range of
impacts to select its proposed standards.
2. Economic Impact on Manufacturers
DOE performed a MIA to estimate the impact of amended energy
conservation standards on manufacturers of distribution transformers.
The section below describes the expected impacts on manufacturers at
each TSL. Chapter 12 of the TSD explains the analysis in further
detail.
a. Industry Cash-Flow Analysis Results
The tables below depict the financial impacts (represented by
changes in INPV) of amended energy standards on manufacturers as well
as the conversion costs that DOE estimates manufacturers would incur at
each TSL. The effect of amended standards on INPV was analyzed
separately for each type of distribution transformer manufacturer:
Liquid-immersed, medium-voltage dry-type, and low-voltage dry-type. To
evaluate the range of cash flow impacts on the distribution transformer
industry, DOE modeled two different scenarios using different
assumptions for markups that correspond to the range of anticipated
market responses to new and amended standards. A full description of
these scenarios and their results can be found in chapter 12 of the
NOPR TSD.
To assess the lower end of the range of potential impacts, DOE
modeled the preservation of operating profit markup scenario, which
assumes that manufacturers would be able to earn the same operating
margin in absolute dollars in the standards case as in the base case.
To assess the higher end of the range of potential impacts, DOE modeled
a preservation of gross margin percentage markup scenario in which a
uniform ``gross margin percentage'' markup is applied across all
efficiency levels. In this scenario, DOE assumed that a manufacturer's
absolute dollar markup would increase as production costs increase in
the standards case.
The set of results below shows two tables of INPV impacts for each
of the three types of distribution transformer manufacturers: The first
table reflects the lower bound of impacts and the second represents the
upper bound.
In the discussion that follows the tables, DOE also discusses the
difference in cash flow between the base case and the standards case in
the year before the compliance date for new and amended energy
conservation standards. This figure represents how large the required
conversion costs are relative to the cash flow generated by the
industry in the absence of new and amended energy conservation
standards.
Table V.22--Manufacturer Impact Analysis for Liquid-Immersed Distribution Transformers--Preservation of Operating Profit Markup Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Units Base case ----------------------------------------------------------------------------
1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV................................... 2011$ M................ 625.1 585.5 532.1 523.8 461.0 451.2 427.5 297.9
Change in INPV......................... 2011$ M................ ......... (39.6) (92.9) (101.2) (164.0) (173.8) (197.6) (327.2)
%...................... ......... (6.3) (14.9) (16.2) (26.2) (27.8) (31.6) (52.3)
Capital Conversion Costs............... 2011$ M................ ......... 26.3 64.9 67.6 98.5 100.4 105.6 128.2
Product Conversion Costs............... 2011$ M................ ......... 27.6 46.8 57.5 93.7 93.7 93.7 93.7
Total Conversion Costs................. 2011$ M................ ......... 53.9 111.7 125.1 192.1 194.1 199.3 221.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
\*\ Note: Parentheses indicate negative values.
Table V.23--Manufacturer Impact Analysis for Liquid-Immersed Distribution Transformers--Preservation of Gross Margin Percentage Markup
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Units Base case ----------------------------------------------------------------------------
1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV................................... 2011$ M................ 625.1 614.7 583.4 577.5 551.6 537.1 547.6 673.0
Change in INPV......................... 2011$ M................ ......... (10.4) (41.7) (47.6) (73.5) (88.0) (77.5) 48.0
%...................... ......... (1.7) (6.7) (7.6) (11.8) (14.1) (12.4) 7.7
Capital Conversion Costs............... 2011$ M................ ......... 26.3 64.9 67.6 98.5 100.4 105.6 128.2
Product Conversion Costs............... 2011$ M................ ......... 27.6 46.8 57.5 93.7 93.7 93.7 93.7
Total Conversion Costs................. 2011$ M................ ......... 53.9 111.7 125.1 192.1 194.1 199.3 221.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
At TSL 1, DOE estimates impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$39.6 million to
-$10.4 million, corresponding to a change in INPV of -6.3 percent to -
1.7 percent. At this proposed level, industry free cash flow is
estimated to decrease by approximately 60.1 percent to $15.8 million,
compared to the base-case value of $39.5 million in the year before the
compliance date (2015).
While TSL 1 can be met with traditional steels, including M3, in
all design lines, amorphous core transformers will be incrementally
more competitive on a first cost basis, likely inducing some or many
manufacturers to gradually build amorphous steel transformer production
capacity. Because the production process for amorphous cores is
entirely separate from that of silicon steel cores, large investments
in new capital, including new core cutting equipment and annealing
ovens will be required. Additionally, a great deal of testing,
prototyping, design and manufacturing engineering resources will be
required because most manufacturers have relatively little experience,
if any, with amorphous steel transformers. These capital and production
conversion expenses lead to a reduction in cash flow in the years
preceding the standard. In the lower-bound scenario, DOE assumes
manufacturers can only maintain annual operating profit in the
[[Page 7348]]
standards case. Therefore, these conversion investments, and
manufacturers' higher working capital needs associated with more
expensive transformers, drain cash flow and lead to a greater reduction
in INPV, when compared to the upper-bound scenario. In the upper bound
scenario, DOE assumes manufacturers will be able to fully mark up and
pass the higher product costs, leading to higher operating income. This
higher operating income is essentially offset on a cash flow basis by
the conversion costs and the increase in working capital requirements,
leading to a negligible change in INPV at TSL1 in the upper-bound
scenario.
At TSL 2, DOE estimates impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$92.9 million to
-$41.7 million, corresponding to a change in INPV of -14.9 percent to -
6.7 percent. At this proposed level, industry free cash flow is
estimated to decrease by approximately 122.7 percent to -$9 million,
compared to the base-case value of $39.5 million in the year before the
compliance date (2015).
TSL 2 requires the same efficiency levels as TSL 1, except for DL
2, which is increased from baseline to EL1. EL1, as opposed to the
baseline efficiency, could induce manufacturers to build more amorphous
capacity, when compared to TSL 1, because amorphous transformers become
incremental more cost competitive. Because DL2 represents the largest
share of core steel usage of all design lines, this has a significant
impact on investments. There are more severe impacts on industry in the
lower-bound profitability scenario when these greater one-time cash
outlays are coupled with slight margin pressure. In the high-
profitability scenario, manufacturers are able to maintain gross
margins, mitigating the adverse cash flow impacts of the increased
investment in working capital (associated with more expensive
transformers).
At TSL 3, DOE estimates impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$101.2 million to
-$47.6 million, corresponding to a change in INPV of -16.2 percent to -
7.6 percent. At this proposed level, industry free cash flow is
estimated to decrease by approximately 135.2 percent to -$13.9 million,
compared to the base-case value of $39.5 million in the year before the
compliance date (2015).
TSL 3 results are similar to TSL 2 results because the efficiency
levels are the same except for DL3 and DL5, which each increase to EL 2
under TSL 3. The increase in stringency makes more amorphous core
transformers slightly more cost competitive in these DLs, likely
increasing amorphous transformer capacity needs, all other things being
equal, and driving more investment to meet the standards.
At TSL 4, DOE estimates impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$164 million to -
$73.5 million, corresponding to a change in INPV of -26.2 percent to -
11.8 percent. At this proposed level, industry free cash flow is
estimated to decrease by approximately 202 percent to -$40.3 million,
compared to the base-case value of $39.5 million in the year before the
compliance date (2015).
During interviews, manufacturers expressed differing views on
whether the efficiency levels embodied in TSL 4 would shift the market
away from silicon steels entirely. Because DL3 and DL5 must meet EL4 at
this TSL, DOE expects the majority of the market would shift to
amorphous core transformers at TSL 4 and above. Even assuming a
sufficient supply of amorphous steel were available, TSL 4 and above
would require a dramatic build up in amorphous core transformer
production capacity. DOE believes this wholesale transition away from
silicon steels could seriously disrupt the market, drive small
businesses to either source their cores or exit the market, and lead
even large businesses to consider moving production offshore or exiting
the market altogether. The negative impacts are driven by the large
conversion costs associated with new amorphous production lines and
stranded assets of manufacturers' existing silicon steel transformer
production capacity. If the higher first costs at TSL 4 drive more
utilities to refurbish rather than replace failed transformers, a
scenario many manufacturers predicted at the efficiency levels and
prices embodied in TSL 4, reduced transformer sales could cause further
declines in INPV.
At TSL 5, DOE estimates impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$173.8 million to
-$88 million, or a change in INPV of -27.8 percent to -14.1 percent. At
this proposed level, industry free cash flow is estimated to decrease
by approximately 230.8 percent to -$51.7 million, compared to the base-
case value of $39.5 million in the year before the compliance date
(2015).
TSL5 would likely shift the entire market to amorphous core
transformers, leading to even greater investment needs than TSL4,
driving the adverse impacts discussed above.
At TSL 6, DOE estimates impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$197.6 million to
-$77.5 million, corresponding to a change in INPV of -31.6 percent to -
12.4 percent. At this proposed level, industry free cash flow is
estimated to decrease by approximately 241.5 percent to -$55.9 million,
compared to the base-case value of $39.5 million in the year before the
compliance date (2015).
The impacts at TSL 6 are similar to those DOE expects at TSL 5,
except that slightly more amorphous core production capacity will be
needed because TSL 6-compliant transformers will have somewhat heavier
cores and thus require more amorphous steel. This leads to slightly
greater capital expenditures at TSL 6 compared to TSL 5.
At TSL 7, DOE estimates impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$327.2 million to
$48 million, corresponding to a change in INPV of -52.3 percent to 7.7
percent. At this proposed level, industry free cash flow is estimated
to decrease by approximately 267.2 percent to -$66 million, compared to
the base-case value of $39.5 million in the year before the compliance
date (2015).
The impacts at TSL 7 are similar to those DOE expects at TSL 6,
except that slightly more amorphous core production capacity will be
needed because TSL 6-compliant transformers will have somewhat heavier
cores and thus require more amorphous steel. This leads to slightly
greater capital expenditures at TSL 7 compared to TSL 6, incrementally
reducing industry value.
[[Page 7349]]
Table V.24--Manufacturer Impact Analysis Low-voltage Dry-Type Distribution Transformers--Preservation of Operating Profit Markup Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Units Base case -----------------------------------------------------------------
1 2 3 4 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV......................................... 2011$M...................... 219.5 202.7 199.9 192.8 173.4 164.2 136.4
Change in INPV............................... 2011$M...................... ......... (16.8) (19.6) (26.7) (46.1) (55.3) (83.1)
%........................... ......... (7.7) (8.9) (12.2) (21.0) (25.2) (37.9)
Capital Conversion Costs..................... 2011$M...................... ......... 5.1 7.4 11.4 23.8 23.8 23.8
Product Conversion Costs..................... 2011$M...................... ......... 2.9 3.8 5.0 8.0 8.0 8.0
Total Conversion Costs....................... 2011$M...................... ......... 8.0 11.1 16.4 31.8 31.8 31.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Note: Parentheses indicate negative values.
Table V.25--Manufacturer Impact Analysis Low-voltage Dry-Type Distribution Transformers--Preservation of Gross Margin Percentage Markup Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial Standard Level
Units Base Case -----------------------------------------------------------------
1 2 3 4 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV......................................... 2011$M...................... 219.5 236.4 234.6 239.6 250.4 263.4 321.5
Change in INPV............................... 2011$M...................... ......... 16.9 15.0 20.1 30.9 43.9 101.9
%........................... ......... 7.7 6.8 9.1 14.1 20.0 46.4
Capital Conversion Costs..................... 2011$M...................... ......... 5.1 7.4 11.4 23.8 23.8 23.8
Product Conversion Costs..................... 2011$M...................... ......... 2.9 3.8 5.0 8.0 8.0 8.0
Total Conversion Costs....................... 2011$M...................... ......... 8.0 11.1 16.4 31.8 31.8 31.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Note: Parentheses indicate negative values.
At TSL 1, DOE estimates impacts on INPV for low-voltage dry-type
distribution transformer manufacturers to range from -$16.8 million to
$16.9 million, corresponding to a change in INPV of -7.7 percent to 7.7
percent. At this proposed level, industry free cash flow is estimated
to decrease by approximately 26.1 percent to $10.2 million, compared to
the base-case value of $13.8 million in the year before the compliance
date (2015).
TSL 1 provides many design paths for manufacturers to comply. DOE's
engineering analysis indicates manufacturers can continue to use the
low-capital butt-lap core designs, meaning investment in mitering or
wound core capability is not necessary. Manufacturers can use higher-
quality grain oriented steels in butt-lap designs to meet TSL1, source
some or all cores, or invest in modified mitering capability.
At TSL 2, DOE estimates impacts on INPV for low-voltage dry-type
distribution transformer manufacturers to range from -$19.6 million to
$15 million, corresponding to a change in INPV of -8.9 percent to 6.8
percent. At this proposed level, industry free cash flow is estimated
to decrease by approximately 37.4 percent to $8.6 million, compared to
the base-case value of $13.8 million in the year before the compliance
date (2015).
TSL2 differs from TSL1 in that DL6 and DL7 must meet EL3, up from
baseline for DL 6 and EL2 for DL 7, which will likely require advanced
core construction techniques, including mitering or wound core designs.
Much of the incremental investment needed at TSL2 is due to the
increase from EL2 to EL3 in DL7, which represents more than three-
quarters of the market by core weight in this superclass. This increase
in stringency for DL7 drives the need for investment in mitering
capacity. All major manufacturers already have mitering capability but
moving the high-volume DL7 from butt-lap to mitered cores would slow
throughput and require additional capacity. A range of options are
still available at TSL2 as manufacturers could use higher grade steels,
mitering, or wound cores. Additionally, at TSL2, manufacturers will
still be able to use M6, which is common in the current market. Some
manufacturers, however, usually small manufacturers, indicated during
interviews they would begin to source a greater share of their cores
rather than make investments in mitering machines or wound core
production lines.
At TSL 3, DOE estimates impacts on INPV for low-voltage dry-type
distribution transformer manufacturers to range from -$26.7 million to
$20.1 million, corresponding to a change in INPV of -12.2 percent to
9.1 percent. At this proposed level, industry free cash flow is
estimated to decrease by approximately 53.9 percent to $6.4 million,
compared to the base-case value of $13.8 million in the year before the
compliance date (2015).
TSL3 represents EL4 for DL6, DL7, and DL8. DOE's engineering
analysis shows that manufacturers will be able to meet EL4 using M4 or
better steels. M4, however, is a thinner steel than is currently
employed, which, in combination with larger cores, will dramatically
slow production throughput, requiring the industry to expand capacity
to maintain current shipments. This is the reason for the increase in
conversion costs. In the lower-bound profitability scenario, when DOE
assumes the industry cannot fully pass on incremental costs, these
investments and the higher working capital needs drain cash flow and
lead to the negative impacts shown in the preservation of operating
profit scenario. In the high-profitability scenario, impacts are
slightly positive because DOE assumes manufacturers are able to fully
recoup their conversion expenditures through higher operating cash
flow.
At TSL 4, DOE estimates impacts on INPV for low-voltage dry-type
distribution transformer manufacturers to range from -$46.1 million to
$30.9 million, corresponding to a change in INPV of -21 percent to 14.1
percent. At this proposed level, industry free cash flow is estimated
to decrease by approximately 102.1 percent to -$0.3 million, compared
to the base-case value of $13.8 million in the year before the
compliance date (2015).
TSL 4 and higher would create significant challenges for the
industry
[[Page 7350]]
and likely disrupt the marketplace. DOE's conversion costs at TSL 4
assume the industry will entirely convert to amorphous wound core
technology to meet the efficiency standards. Few manufacturers of
distribution transformers in this superclass have any experience with
amorphous steel or wound core technology and would face a steep
learning curve. This is reflected in the large conversion costs and
adverse impacts on INPV in the Preservation of Operating Profit
scenario. Most manufacturers DOE interviewed expected many low-volume
manufacturers to exit the DOE-covered market altogether if amorphous
steel was required to meet the standard. As such, DOE believes TSL 4
could lead to greater consolidation than the industry would experience
at lower TSLs.
At TSL 5, DOE estimates impacts on INPV for low-voltage dry-type
distribution transformer manufacturers to range from -$55.3 million to
$43.9 million, corresponding to a change in INPV of -25.2 percent to 20
percent. At this proposed level, industry free cash flow is estimated
to decrease by approximately 122.6 percent to -$3.1 million, compared
to the base-case value of $13.8 million in the year before the
compliance date (2015).
The impacts at TSL 5 are similar to those DOE expects at TSL 4,
except that slightly more amorphous core production capacity will be
needed because TSL 5-compliant transformers will have somewhat heavier
cores and thus require more amorphous steel. This leads to slightly
greater capital expenditures at TSL 5 compared to TSL 4.
At TSL 6, DOE estimates impacts on INPV for low-voltage dry-type
distribution transformer manufacturers to range from -$83.1 million to
$101.9 million, corresponding to a change in INPV of -37.9 percent to
46.4 percent. At this proposed level, industry free cash flow is
estimated to decrease by approximately 125.7 percent to -$3.5 million,
compared to the base-case value of $13.8 million in the year before the
compliance date (2015).
The impacts at TSL 6 are similar to those DOE expects at TSL 5,
except that slightly more amorphous core production capacity will be
needed because TSL 6-compliant transformers will have somewhat heavier
cores and thus require more amorphous steel. This leads to slightly
greater capital expenditures at TSL 6 compared to TSL 5.
Table V.26--Manufacturer Impact Analysis Medium-voltage Dry-Type Distribution Transformers--Preservation of
Operating Profit Markup Scenario
----------------------------------------------------------------------------------------------------------------
Trial standard level
Units Base case ------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
INPV.......................... 2011$M 91.0 87.1 84.5 79.7 77.1 71.0
Change in INPV................ 2011$ M ......... (3.8) (6.5) (11.3) (13.9) (20.0)
% ......... (4.2) (7.1) (12.4) (15.3) (21.9)
Capital Conversion Costs...... 2011$M ......... 2.6 4.0 7.5 10.9 11.1
Product Conversion Costs...... 2011$M ......... 1.0 3.0 4.7 4.7 8.0
Total Conversion Costs........ 2011$M ......... 3.6 7.0 12.2 15.6 19.1
----------------------------------------------------------------------------------------------------------------
Note: Parentheses indicate negative values.
Table V.27--Manufacturer Impact Analysis Medium-voltage Dry-Type Distribution Transformers--Preservation of
Gross Margin Percentage Markup Scenario
----------------------------------------------------------------------------------------------------------------
Trial standard level
Units Base case ------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
INPV.......................... 2011$M 91.0 89.1 90.0 95.1 92.5 114.1
Change in INPV................ 2011$M ......... (1.9) (0.9) 4.1 1.5 23.1
% ......... (2.0) (1.0) 4.5 1.7 25.4
Capital Conversion Costs...... 2011$M ......... 2.6 4.0 7.5 10.9 11.1
Product Conversion Costs...... 2011$M ......... 1.0 3.0 4.7 4.7 8.0
Total Conversion Costs........ 2011$M ......... 3.6 7.0 12.2 15.6 19.1
----------------------------------------------------------------------------------------------------------------
Note: Parentheses indicate negative values.
At TSL 1, DOE estimates impacts on INPV for medium-voltage dry-type
distribution transformer manufacturers to range from -$3.8 million to -
$1.9 million, corresponding to a change in INPV of -4.2 percent to -2.0
percent. At this proposed level, industry free cash flow is estimated
to decrease by approximately 28.1 percent to $4.1 million, compared to
the base-case value of $5.7 million in the year before the compliance
date (2015).
TSL 1 represents EL1 for all MVDT DLs. At TSL 1, manufacturers have
a variety of steels available to them, including M4, the most common
steel in the superclass, in DL12, the largest DL by core steel usage.
Additionally, the vast majority of the market already uses step-lap
mitering technology. Therefore, DOE anticipates only moderate
conversion costs for the industry, mainly associated with slower
throughput due to larger cores. Some manufacturers may need to slightly
expand capacity to maintain throughput and/or modify equipment to
manufacturer with greater precision and tighter tolerances. In general,
however, conversion expenditures should be relatively minor compared
INPV. For this reason, TSL 1 yields relatively minor adverse changes to
INPV in the standards case.
At TSL 2, DOE estimates impacts on INPV for medium-voltage dry-type
distribution transformer manufacturers to range from -$6.5 million to -
$0.9 million, corresponding to a change in INPV of -7.1 percent to -1.0
percent. At this proposed level, industry free cash flow is estimated
to decrease by approximately 52.1 percent to $2.7 million, compared to
the base-case value of $5.7 million in the year before the compliance
date (2015).
Compared to TSL 1, TSL 2 requires EL2, rather than EL1, in DLs 10,
12, and
[[Page 7351]]
13B. Because M4 (as well as the commonly used H1) can still be employed
to meet these levels, DOE expects similar results at TSL 2 as at TSL 1.
Slightly greater conversion costs will be required as the compliant
transformers will have heavier cores, all other things being equal,
meaning additionally capacity may be necessary depending on each
manufacturer's current capacity utilization rate. As with TSL 1, TSL 2
will not require significant changes to most manufacturers production
processes because the thickness of the steels will not change
significantly, if at all.
At TSL 3, DOE estimates impacts on INPV for medium-voltage dry-type
distribution transformer manufacturers to range from -$11.3 million to
$4.1 million, corresponding to a change in INPV of -12.4 percent to 4.5
percent. At this proposed level, industry free cash flow is estimated
to decrease by approximately 90.1 to $0.6 million, compared to the
base-case value of $5.7 million in the year before the compliance date
(2015).
At TSL 4, DOE estimates impacts on INPV for medium-voltage dry-type
distribution transformer manufacturers to range from -$13.9 million to
$1.5 million, corresponding to a change in INPV of -15.3 percent to 1.7
percent. At this proposed level, industry free cash flow is estimated
to decrease by approximately -117.2 percent to -$1.0 million, compared
to the base-case value of $5.7 million in the year before the
compliance date (2015).
TSL 3 and TSL 4 require EL2 for DL9 and DL10, but EL4 for DL11
through DL13B, which hold the majority of the volume. Several
manufacturers were concerned TSL 3 would require some of the high
volume design lines to use either H1, HO, or transition entirely to
amorphous wound cores. Without a cost effective M-grade steel option,
the industry could face severe disruption. Even assuming a sufficient
supply of Hi-B steel, a major concern of some manufacturers because it
is used and generally priced for power transformer markets, relatively
large expenditures would be required in R&D and engineering as most
manufacturers would have to move production to steel, with which they
have little experience. DOE estimates total conversion costs would more
than double at TSL 3, relative to TSL 2. If, based on the movement of
steel prices, EL4 can be met cost competitively only through the use of
amorphous steel or an exotic design with little or no current place in
scale manufacturing, manufacturers would face significant challenges
that DOE believes would lead to consolidation and likely cause many
low-volume manufacturers to exit the product line or source their
cores.
At TSL 5, DOE estimates impacts on INPV for medium-voltage dry-type
distribution transformer manufacturers to range from -$20 million to
$23.1 million, corresponding to a change in INPV of -21.9 percent to
25.4 percent. At this proposed level, industry free cash flow is
estimated to decrease by approximately 152.8 percent to -$3.0 million,
compared to the base-case value of $5.7 million in the year before the
compliance date (2015).
TSL 5 represents max-tech and yields results similar to but more
severe than TSL 4 results. The entire market must convert to amorphous
wound cores at TSL 5. Because the industry has no experience with wound
core technology, and little, if any, experience with amorphous steel,
this transition would represent a tremendous challenge for industry.
Interviews suggest most manufacturers would exit the market altogether
or source their cores rather than make the investments in plant and
equipment and R&D required to meet these levels.
b. Impacts on Employment
Liquid Immersed. Based on interviews and industry research, DOE
estimates that there are roughly 5,000 employees associated with DOE-
covered liquid immersed distribution transformer production and some
three-quarters of these workers are located domestically. DOE does not
expect large changes in domestic employment to occur due to today's
proposed standard. Manufacturers generally agreed that amorphous
production is more labor-intensive and would require greater labor
expenditures than traditional steel core production. So long as
domestic plants are not relocated outside the country, DOE expects
moderate increases in domestic employment at TSL1 and TSL2. There could
be a small drop in employment at small, domestic manufacturing firms if
small manufacturers began sourcing cores. This employment would
presumably transfer to the core makers, some of whom are domestic and
some of whom are foreign. There is a risk that energy conservation
standards that largely require the use of amorphous steel could cause
even large manufacturers who are currently producing transformers in
the U.S. to evaluate offshore options. Faced with the prospect of
wholesale changes to their production process, large investments and
stranded assets, some manufacturers expect to strongly consider
shifting production offshore at TSL 3, due to the increased labor
expenses associated with the production processes required to make
amorphous steel cores. In summary, at TSLs 1 and 2, DOE does not expect
significant impacts on employment, but at TSL 3 or greater, which would
require more investment, the impact is very uncertain.
Low-Voltage Dry-Type. Based on interviews with manufacturers, DOE
estimates that there are approximately 2,200 employees associated with
DOE-covered LVDT production. Approximately 75 percent of these
employees are located outside of the U.S. Typically, high volume units
are made in Mexico, taking advantage of lower labor rates, while custom
designs are made closer to the manufacturer's customer base or R&D
centers. DOE does not expect large changes in domestic employment to
occur due to a standard. Most production already occurs outside the
U.S., and, by and large, manufacturers agreed that most design changes
necessary to meet higher energy conservation standards would increase
labor expenditures, not decrease it. If, however, small manufacturers
began sourcing cores instead of manufacturing them in-house, there
could be a small drop in employment at these firms. This employment
would presumably transfer to the core makers, some of whom are domestic
and some of whom are foreign. In summary, DOE does not expect
significant changes to domestic LVDT industry employment levels as a
result of the proposed standards. Higher TSLs may lead to small
declines in domestic employment as more firms will be challenged with
what amounts to clean-sheet redesigns. Facing the prospect of
greenfield investments, these manufacturers may elect to make those
investments in lower-labor cost countries.
Medium-Voltage Dry-Type. Based on interviews with manufacturers,
DOE estimates that there are approximately 1,850 employees associated
with DOE-covered MVDT production. Approximately 75 percent of these
employees are located domestically. With the exception of TSLs that
require amorphous cores, manufacturers agreed that most design changes
necessary to meet higher energy conservation standards would increase
labor expenditures, not decrease them, but current production equipment
would not be stranded, mitigating any incentive to move production
offshore. Corroborating this, the largest manufacturer and domestic
employer in this market has indicated that the standard, as proposed in
this rule, will not cause their company to reconsider
[[Page 7352]]
production location. As such, DOE does not expect significant changes
to domestic MVDT industry employment levels as a result of the standard
proposed in this rule. For TSLs that would require amorphous cores, DOE
does anticipate significant changes to domestic MVDT industry
employment levels.
c. Impacts on Manufacturing Capacity
Based on manufacturer interviews, DOE believes that there is
significant excess capacity in the distribution transformer market.
Shipments in the industry are well down from their peak in 2007,
according to manufacturers. Therefore, DOE does not believe there would
be any production capacity constraints at TSLs that do not require
dramatic transitions to amorphous cores. For those TSLs that require
amorphous cores in significant volumes, DOE believes there is potential
for capacity constraints in the near term due to limitations on core
steel availability. However, for the levels proposed in this rule, DOE
does not foresee any capacity constraints.
d. Impacts on Subgroups of Manufacturers
Small manufacturers, niche equipment manufacturers, and
manufacturers exhibiting a cost structure substantially different from
the industry average could be affected disproportionately. As discussed
in section V.B.2.a, using average cost assumptions to develop an
industry cash-flow estimate is inadequate to assess differential
impacts among manufacturer subgroups. DOE considered four subgroups in
the MIA: Liquid-immersed, dry-type medium-voltage, dry-type low-
voltage, and small manufacturers. For a discussion of the impacts on
the first three groups, see section IV.I.1. For a discussion of the
impacts on the small manufacturer subgroup, see the Regulatory
Flexibility Analysis in section VI.B and chapter 12 of the NOPR TSD.
e. Cumulative Regulatory Burden
While any one regulation may not impose a significant burden on
manufacturers, the combined effects of recent or impending regulations
may have serious consequences for some manufacturers, groups of
manufacturers, or an entire industry. Assessing the impact of a single
regulation may overlook this cumulative regulatory burden. In addition
to energy conservation standards, other regulations can significantly
affect manufacturers' financial operations. Multiple regulations
affecting the same manufacturer can strain profits and lead companies
to abandon product lines or markets with lower expected future returns
than competing products. For these reasons, DOE conducts an analysis of
cumulative regulatory burden as part of its rulemakings pertaining to
appliance efficiency. During previous stages of this rulemaking DOE
identified a number of requirements in addition to amended energy
conservation standards for distribution transformers. The following
section briefly addresses comments DOE received with respect to
cumulative regulatory burden and summarizes other key related concerns
that manufacturers raised during interviews.
Many interested parties have expressed concerns about the recent
implementation of previous standards for distribution transformers. For
low-voltage dry-type distribution transformers, the Energy Policy Act
of 2005 required compliance with NEMA TP-1 standards by the beginning
of 2007. For liquid-immersed and medium-voltage dry-type transformers,
DOE's 2007 energy conservation standards rulemaking required compliance
by the beginning of 2010. Power Partners has stated that the last set
of energy conservation standards for distribution transformers went
into effect very recently and required large capital investments and
retooling. Therefore, any new standards which would require additional
retooling and investment would create a cumulative burden for
manufacturers. (PP, No. 19 at p. 1) EEI also commented that DOE
standards were increased less than 14 months ago, with effective dates
of January 1, 2007 for low-voltage dry-type distribution transformers
and January 1, 2010 for medium-voltage dry-type and liquid-immersed
designs. (EEI, Pub. Mtg. Tr., No. 34 at p. 28)
Other factors that manufacturers stated may contribute to
cumulative regulatory burden are foreign regulations and Underwriters
Laboratories listing compliance requirements. Manufacturers that export
their products to places such as Canada, China, Mexico, or the Middle
East need to comply with foreign as well as domestic regulations. The
Canadian government regulates efficiency of dry-type transformers
through its Canadian Standards Association (CSA) standard C802.2-00
(effective January 1, 2005). China regulates transformer efficiency
through its China Compulsory Certification (CCC) program (effective May
1, 2002), which requires manufacturers of various products including
transformers to obtain the CCC Mark before exporting to or selling in
the Chinese market. In Mexico, liquid-immersed units are regulated
through NOM-002-SEDE-2010.
DOE discusses these and other requirements, and includes the full
details of the cumulative regulatory burden analysis, in Chapter 12 of
the NOPR TSD.
3. National Impact Analysis
a. Significance of Energy Savings
To estimate the energy savings through 2045 attributable to
potential standards for distribution transformers, DOE compared the
energy consumption of those products under the base case to their
energy consumption under each TSL. Table V.28 presents the forecasted
NES for each considered TSL. The savings were calculated using the
approach described in section IV.G.
Table V.28--Cumulative National Energy Savings for Distribution Transformer Trial Standard Levels in 2016-2045
----------------------------------------------------------------------------------------------------------------
Trial Standard Level
------------------------------------------------------------------
1 2 3 4 5 6 7
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed
----------------------------------------------------------------------------------------------------------------
Cumulative Source Savings 2045 (Quads)....... 0.36 0.74 0.82 1.44 1.42 1.70 2.70
----------------------------------------------------------------------------------------------------------------
Low-Voltage Dry-Type
----------------------------------------------------------------------------------------------------------------
Cumulative Source Savings 2045 (Quads)....... 1.09 1.12 1.29 1.86 1.90 2.08
----------------------------------------------------------------------------------------------------------------
[[Page 7353]]
Medium-Voltage Dry-Type
----------------------------------------------------------------------------------------------------------------
Cumulative Source Savings 2045 (Quads)....... 0.06 0.13 0.23 0.23 0.37
----------------------------------------------------------------------------------------------------------------
Chapter 10 of the NOPR TSD provides additional details on the NES
values reported and also presents tables that show the magnitude of the
energy savings discounted at rates of 3 percent and 7 percent.
Discounted energy savings represent a policy perspective in which
energy savings realized farther in the future are less significant than
energy savings realized in the nearer term.
b. Net Present Value of Customer Costs and Benefits
DOE estimated the cumulative NPV to the Nation of the total costs
and savings for customers that would result from the TSLs considered
for distribution transformers. In accordance with the OMB's guidelines
on regulatory analysis,\41\ DOE calculated NPV using both a 7-percent
and a 3-percent real discount rate. The 7-percent rate is an estimate
of the average before-tax rate of return on private capital in the U.S.
economy, and reflects the returns on real estate and small business
capital as well as corporate capital. DOE used this discount rate to
approximate the opportunity cost of capital in the private sector,
because recent OMB analysis has found the average rate of return on
capital to be near this rate. DOE used the 3-percent rate to capture
the potential effects of standards on private consumption (e.g.,
through higher prices for products and reduced purchases of energy).
This rate represents the rate at which society discounts future
consumption flows to their present value. This rate can be approximated
by the real rate of return on long-term government debt (i.e., yield on
United States Treasury notes minus annual rate of change in the
Consumer Price Index), which has averaged about 3 percent on a pre-tax
basis for the past 30 years.
---------------------------------------------------------------------------
\41\ OMB Circular A-4, section E (Sept. 17, 2003). Available at:
http://www.whitehouse.gov/omb/circulars_a004_a-4. (Last accessed
March 18, 2011.)
---------------------------------------------------------------------------
Table V.29 shows the customer NPV results for each TSL DOE
considered for distribution transformers, using both a 7-percent and a
3-percent discount rate. In each case, the impacts cover the lifetime
of products purchased in 2016-2045. See chapter 10 of the NOPR TSD for
more detailed NPV results.
Table V.29--Cumulative Net Present Value of Consumer Benefits for Distribution Transformers Trial Standard Levels for Units Sold in 2016-2045
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial Standard Level
Discount -------------------------------------------------------------------------------------------------
rate (%) 1 2 3 4 5 6 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Liquid-Immersed.........................................................................................................................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Present Value (billion 2010$)........ 3 3.66 7.39 8.24 14.21 13.48 13.17 -1.11
--------------------------------------------------------------------------------------------------------------------------------------------------------
7 0.75 1.51 1.73 2.96 2.65 1.76 -8.25
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low-Voltage Dry-Type
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Present Value (billion 2010$)........ 3 7.81 7.79 8.51 11.16 9.37 2.69
--------------------------------------------------------------------------------------------------------------------------------------------------------
7 2.03 1.97 2.03 2.36 1.37 -2.41
--------------------------------------------------------------------------------------------------------------------------------------------------------
Medium-Voltage Dry-Type
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Present Value (billion 2010$)........ 3 0.42 0.67 0.90 0.90 -0.38
7 0.10 0.13 0.06 0.06 -0.84
--------------------------------------------------------------------------------------------------------------------------------------------------------
The results shown here reflect the default product price trend,
which uses constant prices. DOE conducted an NPV sensitivity analysis
using alternative price trends. DOE developed one forecast in which
prices decline after 2010, and one in which prices rise. The NPV
results from the associated sensitivity cases are described in appendix
10-C of the NOPR TSD.
c. Indirect Impacts on Employment
As discussed above, DOE expects energy conservation standards for
distribution transformers to reduce energy costs for equipment owners,
and
[[Page 7354]]
the resulting net savings to be redirected to other forms of economic
activity. Those shifts in spending and economic activity could affect
the demand for labor. As described in section IV.J, DOE used an input/
output model of the U.S. economy to estimate indirect employment
impacts of the TSLs that DOE considered in this rulemaking. DOE
understands that there are uncertainties involved in projecting
employment impacts, especially changes in the later years of the
analysis. Therefore, DOE generated results for near-term timeframes
(2015-2020), where these uncertainties are reduced.
The results suggest that today's proposed standards are likely to
have negligible impact on the net demand for labor in the economy. The
net change in jobs is so small that it would be imperceptible in
national labor statistics and might be offset by other, unanticipated
effects on employment. Chapter 13 of the NOPR TSD presents more
detailed results.
4. Impact on Utility or Performance of Equipment
DOE believes that the standards it is proposing today will not
lessen the utility or performance of distribution transformers.
5. Impact of Any Lessening of Competition
DOE has also considered any lessening of competition that is likely
to result from new and amended standards. The Attorney General
determines the impact, if any, of any lessening of competition likely
to result from a proposed standard, and transmits such determination to
the Secretary, together with an analysis of the nature and extent of
such impact. (42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii))
To assist the Attorney General in making such a determination, DOE
has provided DOJ with copies of this notice and the TSD for review. DOE
will consider DOJ's comments on the proposed rule in preparing the
final rule, and DOE will publish and respond to DOJ's comments in that
document.
6. Need of the Nation to Conserve Energy
Enhanced energy efficiency, where economically justified, improves
the Nation's energy security, strengthens the economy, and reduces the
environmental impacts or costs of energy production. Reduced
electricity demand due to energy conservation standards is also likely
to reduce the cost of maintaining the reliability of the electricity
system, particularly during peak-load periods. As a measure of the
expected energy conservation out to 2045, Table V.30 presents the
estimated energy savings in terms of equivalent generating capacity for
the TSLs that DOE considered in this rulemaking.
Table V.30--Expected Energy Savings out to 2045 Represented as Equivalent Generating Capacity Under Distribution
Transformer Trial Standard Levels
----------------------------------------------------------------------------------------------------------------
Trial standard level
----------------------------------------------------------------------------
1 2 3 4 5 6 7
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed (GW)............... 0.610 1.23 1.33 2.24 2.21 2.53 3.73
Low-Voltage Dry-Type (GW).......... 1.62 1.66 1.90 2.70 2.75 2.92 --
Medium-Voltage Dry-Type (GW)....... 0.091 0.174 0.332 0.332 0.510 -- --
Total.......................... 2.33 3.06 3.56 5.28 5.47 5.46 3.73
----------------------------------------------------------------------------------------------------------------
Energy savings from standards for distribution transformers could
also produce environmental benefits in the form of reduced emissions of
air pollutants and greenhouse gases associated with electricity
production. Table V.31 provides DOE's estimate of cumulative
CO2, NOX, and Hg emissions reductions projected
to result from the TSLs considered in this rulemaking. DOE reports
annual CO2, NOX, and Hg emissions reductions for
each TSL in chapter 15 of the NOPR TSD.
As discussed in section IV.M, DOE did not report SO2
emissions reductions from power plants because, due to SO2
emissions caps, there is uncertainty about the effect of energy
conservation standards on the overall level of SO2 emissions
in the United States. DOE also did not include NOX emissions
reduction from power plants in States subject to CAIR because an energy
conservation standard would not affect the overall level of
NOX emissions in those States due to the emissions caps
mandated by CAIR.
Table V.31--Summary of Emissions Reduction Estimated for Distribution Transformer Trial Standard Levels
(cumulative in 2016-2045)
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------------------------------------------
1 2 3 4 5 6 7
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons).......... 31.2 62.7 67.7 113 112 128 186
NOX (thousand tons)................ 25.5 51.2 55.3 92.7 91.5 104 152
Hg (tons).......................... 0.209 0.420 0.454 0.762 0.751 0.857 1.25
----------------------------------------------------------------------------------------------------------------
Low-Voltage Dry-Type
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons).......... 82.1 83.9 96.0 137 139 148 --
NOX (thousand tons)................ 67.0 68.6 78.4 112 114 121 --
Hg (tons).......................... 0.551 0.564 0.645 0.918 0.934 0.992 --
----------------------------------------------------------------------------------------------------------------
Medium-Voltage Dry-Type
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons).......... 4.62 8.80 16.8 16.8 25.7 -- --
NOX (thousand tons)................ 3.77 7.19 13.7 13.7 21.0 -- --
[[Page 7355]]
Hg (tons).......................... 0.031 0.059 0.113 0.113 0.173 -- --
----------------------------------------------------------------------------------------------------------------
As part of the analysis for this proposed rule, DOE estimated
monetary benefits likely to result from the reduced emissions of
CO2 and NOX that DOE estimated for each of the
TSLs considered. As discussed in section IV.M, DOE used values for the
SCC developed by an interagency process. The four values for
CO2 emissions reductions resulting from that process
(expressed in 2010$) are $4.9/metric ton (the average value from a
distribution that uses a 5-percent discount rate), $22.3/metric ton
(the average value from a distribution that uses a 3-percent discount
rate), $36.5/metric ton (the average value from a distribution that
uses a 2.5-percent discount rate), and $67.6/metric ton (the 95th-
percentile value from a distribution that uses a 3-percent discount
rate). These values correspond to the value of emission reductions in
2010; the values for later years are higher due to increasing damages
as the magnitude of climate change increases.
Table V.32 presents the global value of CO2 emissions
reductions at each TSL. For each of the four cases, DOE calculated a
present value of the stream of annual values using the same discount
rate as was used in the studies upon which the dollar-per-ton values
are based. DOE calculated domestic values as a range from 7 percent to
23 percent of the global values, and these results are presented in
chapter 16 of the NOPR TSD.
Table V.32--Estimates of Global Present Value of CO2 Emissions Reduction Under Distribution Transformer Trial
Standard Levels
[Million 2010$]
----------------------------------------------------------------------------------------------------------------
5% discount rate, 3% discount rate, 2.5% discount 3% discount rate,
TSL average * average * rate, average * 95th percentile *
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed
----------------------------------------------------------------------------------------------------------------
1............................... 173 1003 1747 3051
2............................... 350 2026 3528 6160
3............................... 382 2219 3866 6746
4............................... 655 3831 6681 11643
5............................... 646 3779 6591 11486
6............................... 752 4414 7705 13414
7............................... 1140 6754 11811 20523
----------------------------------------------------------------------------------------------------------------
Low-Voltage Dry-Type
----------------------------------------------------------------------------------------------------------------
1............................... 481 2820 4921 8570
2............................... 492 2884 5032 8764
3............................... 562 3297 5753 10020
4............................... 800 4693 8190 14264
5............................... 814 4776 8336 14517
6............................... 866 5076 8858 15427
----------------------------------------------------------------------------------------------------------------
Medium-Voltage Dry-Type
----------------------------------------------------------------------------------------------------------------
1............................... 27 159 277 483
2............................... 52 302 528 919
3............................... 98 576 1006 1751
4............................... 98 576 1006 1751
5............................... 151 884 1543 2688
----------------------------------------------------------------------------------------------------------------
DOE is well aware that scientific and economic knowledge about the
contribution of CO2 and other GHG emissions to changes in
the future global climate and the potential resulting damages to the
world economy continues to evolve rapidly. Thus, any value placed on
reducing CO2 emissions in this rulemaking is subject to
change. DOE, together with other Federal agencies, will continue to
review various methodologies for estimating the monetary value of
reductions in CO2 and other GHG emissions. This ongoing
review will consider the comments on this subject that are part of the
public record for this and other rulemakings, as well as other
methodological assumptions and issues. However, consistent with DOE's
legal obligations, and taking into account the uncertainty involved
with this particular issue, DOE has included in this NOPR the most
recent values and analyses resulting from the ongoing interagency
review process.
DOE also estimated a range for the cumulative monetary value of the
economic benefits associated with NOX emissions reductions
anticipated to result from amended standards for refrigeration
products. The low and high dollar-per-ton values that DOE used are
discussed in section IV.M. Table V.33 presents the cumulative present
values
[[Page 7356]]
for each TSL calculated using 7-percent and 3-percent discount rates.
Table V.33--Estimates of Present Value of NOX Emissions Reduction Under
Distribution Transformer Trial Standard Levels
------------------------------------------------------------------------
Million 2010$
-------------------------------------------------------------------------
TSL 3% discount rate 7% discount rate
------------------------------------------------------------------------
Liquid-Immersed
------------------------------------------------------------------------
1............................... 9 to 94........... 3 to 32
2............................... 19 to 191......... 6 to 64
3............................... 20 to 208......... 7 to 69
4............................... 35 to 356......... 11 to 117
5............................... 34 to 351......... 11 to 115
6............................... 40 to 408......... 13 to 132
7............................... 60 to 616......... 19 to 194
------------------------------------------------------------------------
Low-Voltage Dry-Type
------------------------------------------------------------------------
1............................... 25 to 261......... 8 to 85
2............................... 26 to 267......... 8 to 87
3............................... 30 to 305......... 10 to 99
4............................... 42 to 434......... 14 to 141
5............................... 43 to 442......... 14 to 143
6............................... 46 to 470......... 15 to 152
------------------------------------------------------------------------
Medium-Voltage Dry-Type
------------------------------------------------------------------------
1............................... 1 to 15........... 0 to 5
2............................... 3 to 28........... 1 to 9
3............................... 5 to 53........... 2 to 17
4............................... 5 to 53........... 2 to 17
5............................... 8 to 82........... 3 to 27
------------------------------------------------------------------------
7. Summary of National Economic Impacts
The NPV of the monetized benefits associated with emissions
reductions can be viewed as a complement to the NPV of the customer
savings calculated for each TSL considered in this rulemaking. Table
V.34 through Table V.36 present the NPV values that result from adding
the estimates of the potential economic benefits resulting from reduced
CO2 and NOX emissions in each of four valuation
scenarios to the NPV of customer savings calculated for each TSL
considered in this rulemaking, at both a seven-percent and three-
percent discount rate. The CO2 values used in the columns of
each table correspond to the four scenarios for the valuation of
CO2 emission reductions presented in section IV.M.
Table V.34--Liquid-Immersed Distribution Transformers: Net Present Value of Customer Savings Combined With Net
Present Value of Monetized Benefits From CO2 and NOX Emissions Reductions
[Billion 2010$]
----------------------------------------------------------------------------------------------------------------
Consumer NPV at 3% discount rate added with:
-------------------------------------------------------------------------------
SCC Value of $4.9/ SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
TSL metric ton CO2* metric ton CO2* metric ton CO2* metric ton CO2*
and Low Value for and Medium Value and Medium Value and High Value for
NOX** for NOX** for NOX** NOX**
----------------------------------------------------------------------------------------------------------------
1............................... 3.8 4.7 5.5 6.8
2............................... 7.8 9.5 11.0 13.7
3............................... 8.6 10.6 12.2 15.2
4............................... 14.9 18.2 21.1 26.2
5............................... 14.2 17.5 20.3 25.3
6............................... 14.0 17.8 21.1 27.0
7............................... 0.1 6.0 11.0 20.0
----------------------------------------------------------------------------------------------------------------
Consumer NPV at 7% Discount Rate added with:
-------------------------------------------------------------------------------
SCC Value of $4.9/ SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
TSL metric ton CO2* metric ton CO2* metric ton CO2* metric ton CO2*
and Low Value for and Medium Value and Medium Value and High Value for
NOX** for NOX** for NOX** NOX**
----------------------------------------------------------------------------------------------------------------
1............................... 0.9 1.8 2.5 3.8
2............................... 1.9 3.6 5.1 7.7
3............................... 2.1 4.0 5.6 8.5
4............................... 3.6 6.9 9.7 14.7
5............................... 3.3 6.5 9.3 14.3
6............................... 2.5 6.2 9.5 15.3
7............................... -7.1 -1.4 3.7 12.5
----------------------------------------------------------------------------------------------------------------
* These label values represent the global SCC in 2010, in 2010$. The present values have been calculated with
scenario-consistent discount rates.
** Low Value corresponds to $450 per ton of NOX emissions. Medium Value corresponds to $2,537 per ton of NOX
emissions. High Value corresponds to $4,623 per ton of NOX emissions.
[[Page 7357]]
Table V.35--Low-Voltage Dry-Type Distribution Transformers: Net Present Value of Customer Savings Combined With
Net Present Value of Monetized Benefits From CO2 and NOX Emissions Reductions
[Billion 2010$]
----------------------------------------------------------------------------------------------------------------
Consumer NPV at 3% Discount Rate added with:
-------------------------------------------------------------------------------
SCC Value of $4.9/ SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
TSL metric ton CO2* metric ton CO2* metric ton CO2* metric ton CO2*
and Low Value for and Medium Value and Medium Value and High Value for
NOX** for NOX** for NOX** NOX**
----------------------------------------------------------------------------------------------------------------
1............................... 8.3 10.8 12.9 16.6
2............................... 8.3 10.8 13.0 16.8
3............................... 9.1 12.0 14.4 18.8
4............................... 12.0 16.1 19.6 25.9
5............................... 10.2 14.4 17.9 24.3
6............................... 3.6 8.0 11.8 18.6
----------------------------------------------------------------------------------------------------------------
Consumer NPV at 7% Discount Rate added with:
-------------------------------------------------------------------------------
SCC Value of $4.9/ SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
TSL metric ton CO2* metric ton CO2* metric ton CO2* metric ton CO2*
and Low Value for and Medium Value and Medium Value and High Value for
NOX** for NOX** for NOX** NOX**
----------------------------------------------------------------------------------------------------------------
1............................... 2.5 4.9 7.0 10.7
2............................... 2.5 4.9 7.1 10.8
3............................... 2.6 5.4 7.8 12.1
4............................... 3.2 7.1 10.6 16.8
5............................... 2.2 6.2 9.8 16.0
6............................... -1.5 2.7 6.5 13.2
----------------------------------------------------------------------------------------------------------------
Table V.36--Medium-Voltage Dry-Type Distribution Transformers: Net Present Value of Customer Savings Combined
With Net Present Value of Monetized Benefits From CO2 and NOX Emissions Reductions
[Billion 2010$]
----------------------------------------------------------------------------------------------------------------
Consumer NPV at 3% Discount Rate added with:
-------------------------------------------------------------------------------
SCC Value of $4.9/ SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
TSL metric ton CO2* metric ton CO2* metric ton CO2* metric ton CO2*
and Low Value for and Medium Value and Medium Value and High Value for
NOX** for NOX** for NOX** NOX**
----------------------------------------------------------------------------------------------------------------
1............................... 0.5 0.6 0.7 0.9
2............................... 0.7 1.0 1.2 1.6
3............................... 1.0 1.5 1.9 2.7
4............................... 1.0 1.5 1.9 2.7
5............................... -0.2 0.6 1.2 2.4
----------------------------------------------------------------------------------------------------------------
Consumer NPV at 7% Discount Rate added with:
-------------------------------------------------------------------------------
SCC Value of $4.9/ SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
TSL metric ton CO2* metric ton CO2* metric ton CO2* metric ton CO2*
and Low Value for and Medium Value and Medium Value and High Value for
NOX** for NOX** for NOX** NOX**
----------------------------------------------------------------------------------------------------------------
1............................... 0.1 0.3 0.4 0.6
2............................... 0.2 0.4 0.7 1.1
3............................... 0.2 0.6 1.1 1.8
4............................... 0.2 0.6 1.1 1.8
5............................... -0.7 0.1 0.7 1.9
----------------------------------------------------------------------------------------------------------------
Although adding the value of customer savings to the values of
emission reductions provides a valuable perspective, two issues should
be considered. First, the national operating cost savings are domestic
U.S. customer monetary savings that occur as a result of market
transactions, while the value of CO2 reductions is based on
a global value. Second, the assessments of operating cost savings and
the SCC are performed with different methods that use quite different
time frames for analysis. The national operating cost savings is
measured for the lifetime of products shipped in 2016-2045. The SCC
values, on the other hand, reflect the present value of future climate-
related impacts resulting from the emission of one metric ton of
CO2 in each year. These impacts continue well beyond 2100.
8. Other Factors
The Secretary of Energy, in determining whether a standard is
economically justified, may consider any other factors that the
Secretary deems to be relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VI))
[[Page 7358]]
Electrical steel is a critical consideration in the design and
manufacture of distribution transformers, amounting for more than 60
percent of the distribution transformers mass in some designs. Rapid
changes in the supply or pricing of certain grades can seriously hinder
manufacturers' abilities to meet the market demand and, as a result,
this rulemaking has given an uncommon level of attention to effects of
electrical steel supply and availability.
The most important point to note is that several energy efficiency
levels in each design line are reachable only by using amorphous steel,
which is available in the United States from a single supplier that
does not have enough present capacity to supply the industry at all-
amorphous standard levels. Several more energy efficiency levels are
reachable with the top grades of conventional electrical steels
(``grain-oriented'') but result in distribution transformers that are
unlikely to be cost-competitive with the often more-efficient amorphous
units. As stated above, switching to amorphous steel is not practicable
as there are availability concerns with amorphous steel.
Distribution transformers are also highly customized products;
manufacturers routinely build only one or a handful of units of a
particular design and require flexibility with respect to construction
materials in order to do this competitively. Setting a standard that
either technologically or economically required amorphous material
would both eliminate a large amount of design flexibility and expose
the industry to enormous risk with respect to supply and pricing of
core steel. For both reasons, DOE considered electrical steel
availability to be a major factor in determining which TSLs were
economically justified.
C. Proposed Standards
When considering proposed standards, the new or amended energy
conservation standard that DOE adopts for any type (or class) of
covered product shall be designed to achieve the maximum improvement in
energy efficiency that the Secretary determines is technologically
feasible and economically justified. (42 U.S.C. 6295(o)(2)(A)) In
determining whether a standard is economically justified, the Secretary
must determine whether the benefits of the standard exceed its burdens
to the greatest extent practicable, in light of the seven statutory
factors discussed previously. (42 U.S.C. 6295(o)(2)(B)(i)) The new or
amended standard must also ``result in significant conservation of
energy.'' (42 U.S.C. 6295(o)(3)(B))
For today's NOPR, DOE considered the impacts of standards at each
TSL, beginning with the maximum technologically feasible level, to
determine whether that level was economically justified. Where the max-
tech level was not justified, DOE then considered the next most
efficient level and undertook the same evaluation until it reached the
highest efficiency level that is both technologically feasible and
economically justified and saves a significant amount of energy.
To aid the reader in understanding the benefits and/or burdens of
each TSL, tables in this section summarize the quantitative analytical
results for each TSL, based on the assumptions and methodology
discussed herein. The efficiency levels contained in each TSL are
described in section V.A. In addition to the quantitative results
presented in the tables, DOE also considers other burdens and benefits
that affect economic justification. These include the impacts on
identifiable subgroups of customers who may be disproportionately
affected by a national standard, and impacts on employment. Section
V.B.1 presents the estimated impacts of each TSL for these subgroups.
DOE discusses the impacts on employment in transformer manufacturing in
section V.B.2.b, and discusses the indirect employment impacts in
section V.B.3.c.
1. Benefits and Burdens of Trial Standard Levels Considered for Liquid-
Immersed Distribution Transformers
Table V.37 and Table V.38 summarize the quantitative impacts
estimated for each TSL for liquid-immersed distribution transformers.
Table V.37--Summary of Analytical Results for Liquid-Immersed Distribution Transformers: National Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
National Energy Savings 0.36............ 0.74............ 0.82............ 1.44............ 1.42........... 1.70........... 2.70
(quads).
--------------------------------------------------------------------------------------------------------------------------------------------------------
NPV of Consumer Benefits (2010$ billion)
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% discount rate............. 3.66............ 7.39............ 8.24............ 14.21........... 13.48.......... 13.17.......... -1.11
7% discount rate............. 0.75............ 1.51............ 1.73............ 2.96............ 2.65........... 1.76........... -8.25
==============================
Cumulative Emissions
Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (million metric tons).... 31.2............ 62.7............ 67.7............ 113............. 112............ 128............ 186
NOX (thousand tons).......... 25.5............ 51.2............ 55.3............ 92.7............ 91.5........... 104............ 152
Hg (tons).................... 0.209........... 0.420........... 0.454........... 0.762........... 0.751.......... 0.857.......... 1.25
--------------------------------------------------------------------------------------------------------------------------------------------------------
Value of Emissions Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (2010$ million)*......... 173 to 3051..... 350 to 6,160.... 382 to 6,746.... 655 to 11,643... 646 to 11,486.. 752 to 13,414.. 1140 to 20,523
NOX--3% discount rate (2010$ 9 to 94......... 19 to 191....... 20 to 208....... 35 to 356....... 34 to 351...... 40 to 408...... 60 to 616
million).
[[Page 7359]]
NOX--7% discount rate (2010$ 3 to 32......... 6 to 64......... 7 to 69......... 11 to 117....... 11 to 115...... 13 to 132...... 19 to 194
million).
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Range of the economic value of CO2 reductions is based on estimates of the global benefit of reduced CO2 emissions.
Table V.38--Summary of Analytical Results for Liquid-Immersed Distribution Transformers: Manufacturer and Consumer Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Manufacturer Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Industry NPV (2011$ million). 586 to 615...... 532 to 583...... 524 to 578...... 461 to 552...... 451 to 537..... 428 to 548..... 298 to 673
Industry NPV (% change)...... (6.3) to (1.7).. (14.9) to (6.7). (16.2) to (7.6). (26.2) to (11.8) (27.8) to (31.6) to (52.3) to 7.7
(14.1). (12.4).
--------------------------------------------------------------------------------------------------------------------------------------------------------
Consumer Mean LCC Savings (2010$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 1................ 36.............. 36.............. 36.............. 641............. 641............ 532............ 50
Design line 2................ 0............... 309............. 309............. 338............. 300............ 250............ -736
Design line 3................ 2413............ 2413............ 3831............ 5591............ 5245........... 6531........... 4135
Design line 4................ 862............. 862............. 862............. 3356............ 3356........... 3362........... 1274
Design line 5................ 7787............ 7787............ 10288........... 12513........... 11395.......... 12746.......... 3626
--------------------------------------------------------------------------------------------------------------------------------------------------------
Consumer Median PBP (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 1................ 20.2............ 20.2............ 20.2............ 7.9............. 7.9............ 10.0........... 19.2
Design line 2................ 0.0............. 6.9............. 6.9............. 8.0............. 9.5............ 11.5........... 24.3
Design line 3................ 6.3............. 6.3............. 4.0............. 4.7............. 4.6............ 5.2............ 13.3
Design line 4................ 5.0............. 5.0............. 5.0............. 4.1............. 4.1............ 4.1............ 14.6
Design line 5................ 4.0............. 4.0............. 4.2............. 6.3............. 5.7............ 8.3............ 16.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Distribution of Consumer LCC Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 1
Net Cost (%)............. 57.9............ 57.9............ 57.9............ 4.8............. 4.8............ 8.0............ 55.4
Net Benefit (%).......... 41.8............ 41.8............ 41.8............ 95.0............ 95.0........... 92.0........... 44.6
No Impact (%)............ 0.2............. 0.2............. 0.2............. 0.2............. 0.2............ 0.0............ 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 2
Net Cost (%)............. 0.0............. 14.2............ 14.2............ 9.8............. 11.2........... 15.8........... 80.2
Net Benefit (%).......... 0.0............. 85.8............ 85.8............ 90.2............ 88.8........... 84.3........... 19.8
No Impact (%)............ 100.0........... 0.0............. 0.0............. 0.0............. 0.0............ 0.0............ 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 3
Net Cost (%)............. 15.7............ 15.7............ 11.2............ 4.0............. 5.3............ 3.9............ 25.1
Net Benefit (%).......... 83.0............ 83.0............ 87.7............ 96.0............ 94.6........... 96.1........... 74.9
No Impact (%)............ 1.4............. 1.4............. 1.2............. 0.0............. 0.0............ 0.0............ 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 4
Net Cost (%)............. 6.0............. 6.0............. 6.0............. 1.9............. 1.9............ 1.9............ 31.1
Net Benefit (%).......... 93.5............ 93.5............ 93.5............ 97.5............ 97.5........... 97.6........... 63.9
No Impact (%)............ 0.6............. 0.6............. 0.6............. 0.6............. 0.6............ 0.6............ 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 5
Net Cost (%)............. 19.1............ 19.1............ 13.2............ 7.8............. 10.4........... 7.9............ 39.9
[[Page 7360]]
Net Benefit (%).......... 80.6............ 80.6............ 86.8............ 92.2............ 89.6........... 92.1........... 60.1
No Impact (%)............ 0.4............. 0.4............. 0.1............. 0.0............. 0.0............ 0.0............ 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
First, DOE considered TSL 7, the most efficient level (max tech),
which would save an estimated total of 2.70 quads of energy through
2045, an amount DOE considers significant. TSL 7 has an estimated NPV
of customer benefit of -$8.25 billion using a 7 percent discount rate,
and -$1.11 billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 7 are 186 million metric
tons of CO2, 152 thousand tons of NOX, and 1.25
tons of Hg. The estimated monetary value of the CO2
emissions reductions at TSL 7 ranges from $1,140 million to $20,523
million.
At TSL 7, the average LCC impact ranges from -$736 for design line
2 to $4,135 for design line 3. The median PBP ranges from 24.3 years
for design line 2 to 13.3 years for design line 3. The share of
customers experiencing a net LCC benefit ranges from 19.8 percent for
design line 2 to 74.9 percent for design line 3.
At TSL 7, the projected change in INPV ranges from a decrease of
$327 million to an increase of $48 million. If the decrease of $327
million were to occur, TSL 7 could result in a net loss of 52.3 percent
in INPV to manufacturers of liquid-immersed distribution transformers.
At TSL 7, there is a risk of very large negative impacts on
manufacturers due to the substantial capital and engineering costs they
would incur and the market disruption associated with the likely
transition to a market entirely served by amorphous steel.
Additionally, if manufacturers' concerns about their customers
rebuilding rather than replacing transformers at the price points
projected for TSL 7 are realized, new transformer sales would suffer
and make it even more difficult to recoup investments in amorphous
transformer production capacity. Additionally, if manufacturers'
concerns about their customers rebuilding rather than replacing
transformers at the price points projected for TSL 7 are realized, new
transformer sales would suffer and make it even more difficult to
recoup investments in amorphous transformer production capacity. DOE
also has concerns about the competitive impact of TSL 7 on the
electrical steel industry, as only one proven supplier of amorphous
ribbon currently serves the U.S. market.
The Secretary tentatively concludes that, at TSL 7 for liquid-
immersed distribution transformers, the benefits of energy savings,
positive average customer LCC savings, emission reductions, and the
estimated monetary value of the emissions reductions would be
outweighed by the potential multi-billion dollar negative net economic
cost, the economic burden on customers as indicated by large PBPs,
significant increases in installed cost, and the large percentage of
customers who would experience LCC increases, the capital and
engineering costs that could result in a large reduction in INPV for
manufacturers, and the risk that manufacturers may not be able to
obtain the quantities of amorphous steel required to meet standards at
TSL 7. Consequently, DOE has tentatively concluded that TSL 7 is not
economically justified.
Next, DOE considered TSL 6, which would save an estimated total of
1.70 quads of energy through 2045, an amount DOE considers significant.
TSL 6 has an estimated NPV of customer benefit of $1.76 billion using a
7 percent discount rate, and $13.17 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 6 are 128 million metric
tons of CO2, 104 thousand tons of NOX, and 0.857
tons of Hg. The estimated monetary value of the CO2
emissions reductions at TSL 6 ranges from $752 million to $13,414
million.
At TSL 6, the average LCC impact ranges from $250 for design line 2
to $12,746 for design line 5. The median PBP ranges from 11.5 years for
design line 2 to 4.1 years for design line 4. The share of customers
experiencing a net LCC benefit ranges from 84.3 percent for design line
2 to 97.6 percent for design line 4.
At TSL 6, the projected change in INPV ranges from a decrease of
$198 million to a decrease of $78 million. If the decrease of $198
million were to occur, TSL 6 could result in a net loss of 31.6 percent
in INPV to manufacturers of liquid-immersed distribution transformers.
At TSL 6, DOE recognizes the risk of very large negative impacts on
manufacturers due to the large capital and engineering costs and the
market disruption associated with the likely transition to a market
entirely served by amorphous steel. Additionally, if manufacturers'
concerns about their customers rebuilding rather than replacing their
transformers at the price points projected for TSL 6 are realized, new
transformer sales would suffer and make it even more difficult to
recoup investments in amorphous transformer production capacity.
The energy savings under TSL 6 are achievable only by using
amorphous steel, which is currently available from a single supplier
that has annual production capacity of approximately 100,000 tons, the
vast majority of which serves global demand. Thus, current availability
is far below the amount that would be required to meet the U.S. liquid-
immersed transformer market demand of approximately 250,000 tons.
Electrical steel is a critical consideration in the manufacture of
distribution transformers, accounting for more than 60 percent of the
transformer's mass in some designs. DOE is concerned that the current
supplier, together with others that might enter the market, would not
be able to increase production of amorphous steel rapidly enough to
supply the amounts that would be needed by transformer manufacturers
before 2015. Therefore, setting a standard that requires amorphous
material would expose the industry to enormous risk with respect to
core steel supply. DOE also has concerns about the competitive impact
of TSL 6 on the electrical steel industry. TSL 6 could jeopardize the
ability of silicon steels to compete with amorphous metal, which risks
upsetting competitive balance among steel suppliers and between them
and their customers.
The Secretary tentatively concludes that, at TSL 6 for liquid-
immersed distribution transformers, the benefits of energy savings,
positive NPV of customer benefit, positive average customer LCC
savings, emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the capital
and
[[Page 7361]]
engineering costs that could result in a large reduction in INPV for
manufacturers, and the risk that manufacturers may not be able to
obtain the quantities of amorphous steel required to meet standards at
TSL 6. Consequently, DOE has tentatively concluded that TSL 6 is not
economically justified.
Next, DOE considered TSL 5, which would save an estimated total of
1.42 quads of energy through 2045, an amount DOE considers significant.
TSL 5 has an estimated NPV of customer benefit of $2.65 billion using a
7 percent discount rate, and $13.48 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 5 are 112 million metric
tons of CO2, 104 thousand tons of NOX, and 0.751
tons of Hg. The estimated monetary value of the CO2
emissions reductions at TSL 5 ranges from $646 million to $11,486
million.
At TSL 5, the average LCC impact ranges from $300 for design line 2
to $11,395 for design line 5. The median PBP ranges from 9.5 years for
design line 2 to 4.1 years for design line 4. The share of customers
experiencing a net LCC benefit ranges from 88.8 percent for design line
2 to 97.5 percent for design line 4.
At TSL 5, the projected change in INPV ranges from a decrease of
$174 million to a decrease of $88 million. If the decrease of $174
million were to occur, TSL 5 could result in a net loss of 27.8 percent
in INPV to manufacturers of liquid-immersed distribution transformers.
At TSL 5, DOE recognizes the risk of very large negative impacts on
manufacturers due to the large capital and engineering costs they would
incur and the market disruption associated with the likely transition
to a market almost entirely served by amorphous steel. Additionally, if
manufacturers' concerns about their customers rebuilding rather than
replacing transformers at the price points projected for TSL 5 are
realized, new transformer sales would suffer and make it even more
difficult to recoup investments in amorphous transformer production
capacity.
The energy savings under TSL 5 are achievable only by using
amorphous steel, which is currently available from a single supplier
that has annual production capacity of 100,000 tons, far below the
amount that would be required to meet the U.S. liquid-immersed
transformer market demand of approximately 250,000 tons. DOE is
concerned that the current supplier, together with others that might
enter the market, would not be able to increase production of amorphous
steel rapidly enough to supply the amounts that would be needed by
transformer manufacturers before 2015. Therefore, setting a standard
that requires amorphous material would expose the industry to enormous
risk with respect to core steel supply. As with higher TSLs, DOE also
has concerns about the competitive impact of TSL 5 on the electrical
steel manufacturing industry. TSL 5 could jeopardize the ability of
silicon steels to compete with amorphous metal, which risks upsetting
competitive balance among steel suppliers and between them and their
customers.
The Secretary tentatively concludes that, at TSL 5 for liquid-
immersed distribution transformers, the benefits of energy savings,
positive NPV of customer benefit, positive average customer LCC
savings, emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the capital
and engineering costs that could result in a large reduction in INPV
for manufacturers, and the risk that manufacturers may not be able to
obtain the quantities of amorphous steel required to meet standards at
TSL 5. Consequently, DOE has concluded that TSL 5 is not economically
justified.
Next, DOE considered TSL 4, which would save an estimated total of
1.44 quads of energy through 2045, an amount DOE considers significant.
TSL 4 has an estimated NPV of customer benefit of $2.96 billion using a
7 percent discount rate, and $14.21 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 4 are 113 million metric
tons of CO2, 92.7 thousand tons of NOX, and 0.762
tons of Hg. The estimated monetary value of the CO2
emissions reductions at TSL 4 ranges from $655 million to $11,643
million.
At TSL 4, the average LCC impact ranges from $338 for design line 2
to $12,513 for design line 5. The median PBP ranges from 8.0 years for
design line 2 to 4.1 years for design line 4. The share of customers
experiencing a net LCC benefit ranges from 90.2 percent for design line
2 to 97.5 percent for design line 4.
At TSL 4, the projected change in INPV ranges from a decrease of
$164 million to a decrease of $74 million. If the decrease of $164
million were to occur, TSL 4 could result in a net loss of 26.2 percent
in INPV to manufacturers of liquid-immersed distribution transformers.
At TSL 4, DOE recognizes the risk of large negative impacts on
manufacturers due to the substantial capital and engineering costs they
would incur. Additionally, if manufacturers' concerns about their
customers rebuilding rather than replacing transformers at the price
points projected for TSL 4 are realized, new transformer sales would
suffer and make it even more difficult to recoup investments in
amorphous transformer production capacity.
DOE is also concerned that TSL 4, like the higher TSLs, will
require amorphous steel to be competitive in many applications and at
least a few design lines. As stated previously, the available supply of
amorphous steel is well below the amount that would likely be required
to meet the U.S. liquid-immersed transformer market demand. DOE is
concerned that the current supplier, together with others that might
enter the market, would not be able to increase production of amorphous
steel rapidly enough to supply the amounts that would be needed by
transformer manufacturers before 2015. Therefore, setting a standard
that requires amorphous material would expose the industry to enormous
risk with respect to core steel supply.
In addition, depending on how steel prices react to a standard, DOE
believes TSL 4 could threaten the viability of a place in the market
for conventional steel. Therefore, as with higher TSLs, DOE has
concerns about the competitive impact of TSL 4 on the electrical steel
manufacturing industry.
The Secretary tentatively concludes that, at TSL 4 for liquid-
immersed distribution transformers, the benefits of energy savings,
positive NPV of customer benefit, positive average customer LCC
savings, emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the capital
and engineering costs that could result in a large reduction in INPV
for manufacturers, and the risk that manufacturers may not be able to
obtain the quantities of amorphous steel required to meet standards at
TSL 4. Consequently, DOE has tentatively concluded that TSL 4 is not
economically justified.
Next, DOE considered TSL 3, which would save an estimated total of
0.82 quads of energy through 2045, an amount DOE considers significant.
TSL 3 has an estimated NPV of customer benefit of $1.73 billion using a
7 percent discount rate, and $8.24 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 3 are 67.7 million
metric tons of CO2, 55.3 thousand tons of NOX,
and 0.454 tons of Hg. The estimated monetary value of the
CO2 emissions reductions at TSL 3 ranges from $382 million
to $6,746 million.
[[Page 7362]]
At TSL 3, the average LCC impact ranges from $36 for design line 1
to $10,288 for design line 5. The median PBP ranges from 20.2 years for
design line 1 to 4.0 years for design line 3. The share of customers
experiencing a net LCC benefit ranges from 41.8 percent for design line
1 to 93.5 percent for design line 4.
At TSL 3, the projected change in INPV ranges from a decrease of
$101 million to a decrease of $48 million. If the decrease of $101
million were to occur, TSL 3 could result in a net loss of 16.2 percent
in INPV to manufacturers. At TSL 3, DOE recognizes the risk of large
negative impacts on manufacturers due to the large capital and
engineering costs they would incur.
Although the industry can manufacture liquid-immersed transformers
at TSL 3 from M3 or lower grade steels, the positive LCC and national
impacts results described above are based on lowest first-cost designs,
which include amorphous steel for all the design lines analyzed. As is
the case with higher TSLs, DOE is concerned that the current supplier,
together with others that might enter the market, would not be able to
increase production of amorphous steel rapidly enough to supply the
amounts that would be needed by transformer manufacturers before 2015.
If manufacturers were to meet standards at TSL 3 using M3 or lower
grade steels, DOE's analysis shows that the LCC impacts are
negative.\42\
---------------------------------------------------------------------------
\42\ DOE conducted a sensitivity analysis where LCC results are
presented for liquid-immersed transformers without amorphous steel;
see in appendix 8-C in the NOPR TSD.
---------------------------------------------------------------------------
The Secretary tentatively concludes that, at TSL 3 for liquid-
immersed distribution transformers, the benefits of energy savings,
positive NPV of customer benefit, positive average customer LCC
savings, emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the capital
and engineering costs that could result in a large reduction in INPV
for manufacturers, and the risk that manufacturers may not be able to
obtain the quantities of amorphous steel required to meet standards at
TSL 3 in a cost-effective manner. Consequently, DOE has tentatively
concluded that TSL 3 is not economically justified.
Next, DOE considered TSL 2, which would save an estimated total of
0.74 quads of energy through 2045, an amount DOE considers significant.
TSL 2 has an estimated NPV of customer benefit of $1.51 billion using a
7 percent discount rate, and $7.39 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 2 are 62.7 million
metric tons of CO2, 51.2 thousand tons of NOX,
and 0.42 tons of Hg. The estimated monetary value of the CO2
emissions reductions at TSL 2 ranges from $350 million to $6,160
million.
At TSL 2, the average LCC impact ranges from $0 for design line 2
to $7,787 for design line 5. The median PBP ranges from 20.2 years for
design line 1 to 4.0 years for design line 5. The share of customers
experiencing a net LCC benefit ranges from 41.8 percent for design line
1 to 93.5 percent for design line 4.
At TSL 2, the projected change in INPV ranges from a decrease of
$93 million to a decrease of $42 million. If the decrease of $93
million were to occur, TSL 2 could result in a net loss of 14.9 percent
in INPV to manufacturers of liquid-immersed distribution transformers.
At TSL 2, DOE recognizes the risk of negative impacts on manufacturers
due to the significant capital and engineering costs they would incur.
Although the industry can manufacture liquid-immersed transformers
at TSL 2 from M3 or lower grade steels, the positive LCC and national
impacts results described above are based on lowest first-cost designs,
which include amorphous steel for design line 2. This design line
represents approximately 44 percent of all liquid-immersed transformer
shipments by MVA. Amorphous steel is available from a single supplier
whose annual production capacity is below the amount that would be
required to meet the demand for design line 2 under TSL 2. DOE is
concerned that the current supplier, together with others that might
enter the market, would not be able to increase production of amorphous
steel rapidly enough to supply the amounts that would be needed by
transformer manufacturers before 2015. If manufacturers were to meet
standards at TSL 2 using M3 or lower grade steels, DOE's analysis shows
that the LCC impacts would be negative.
The Secretary tentatively concludes that, at TSL 2 for liquid-
immersed distribution transformers, the benefits of energy savings,
positive NPV of customer benefit, positive average customer LCC
savings, emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the capital
and engineering costs that could result in a reduction in INPV for
manufacturers, and the risk that manufacturers may not be able to
obtain the quantities of amorphous steel required to meet standards at
TSL 2 in a cost-effective manner. Consequently, DOE has tentatively
concluded that TSL 2 is not economically justified.
Next, DOE considered TSL 1, which would save an estimated total of
0.36 quads of energy through 2045, an amount DOE considers significant.
TSL 1 has an estimated NPV of customer benefit of $0.75 billion using a
7 percent discount rate, and $3.66 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 1 are 31.2 million
metric tons of CO2, 25.5 thousand tons of NOX,
and 0.209 tons of Hg. The estimated monetary value of the
CO2 emissions reductions at TSL 1 ranges from $173 million
to $3,051 million.
At TSL 1, the average LCC impact ranges from $0 for design line 2
to $7,787 for design line 5. The median PBP ranges from 20.2 years for
design line 1 to 4.0 years for design line 5. The share of customers
experiencing a net LCC benefit ranges from 41.8 percent for design line
1 to 93.5 percent for design line 4.
At TSL 1, the projected change in INPV ranges from a decrease of
$40 million to a decrease of $10 million. If the decrease of $40
million were to occur, TSL 1 could result in a net loss of 6.3 percent
in INPV to manufacturers of liquid-immersed distribution transformers.
The energy savings under TSL 1 are achievable without using
amorphous steel. Therefore, the aforementioned risks that manufacturers
may not be able to obtain the quantities of amorphous steel required to
meet standards, or that manufacturers may be exposed to increased
material prices due to the concentration of core material to a single
supplier are not present under TSL 1.
After considering the analysis and weighing the benefits and the
burdens, DOE has tentatively concluded that at TSL 1 for liquid-
immersed distribution transformers, the benefits of energy savings,
positive NPV of customer benefit, positive average customer LCC
savings, emission reductions, and the estimated monetary value of the
emissions reductions would outweigh the potential reduction in INPV for
manufacturers. The Secretary of Energy has concluded that TSL 1 would
save a significant amount of energy and is technologically feasible and
economically justified. In addition, during the negotiated rulemaking,
NEMA and AK Steel recommended TSL 1. For the above considerations, DOE
today proposes to adopt the energy conservation standards for liquid-
[[Page 7363]]
immersed distribution transformers at TSL 1. Table V.39 presents the
proposed energy conservation standards for liquid-immersed distribution
transformers.
Table V.39--Proposed Energy Conservation Standards for Liquid-Immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Electrical efficiency by kVA and equipment class
-----------------------------------------------------------------------------------------------------------------
Equipment class 1 Equipment class 2
----------------------------------------------------------------------------------------------------------------
kVA Percent kVA Percent
----------------------------------------------------------------------------------------------------------------
10........................................ 98.70 15........................... 98.65
15........................................ 98.82 30........................... 98.83
25........................................ 98.95 45........................... 98.92
37.5...................................... 99.05 75........................... 99.03
50........................................ 99.11 112.5........................ 99.11
75........................................ 99.19 150.......................... 99.16
100....................................... 99.25 225.......................... 99.23
167....................................... 99.33 300.......................... 99.27
250....................................... 99.39 500.......................... 99.35
333....................................... 99.43 750.......................... 99.40
500....................................... 99.49 1000......................... 99.43
.................. 1500......................... 99.48
----------------------------------------------------------------------------------------------------------------
2. Benefits and Burdens of Trial Standard Levels Considered for Low-
Voltage, Dry-Type Distribution Transformers
Table V.40 and Table V.41 summarize the quantitative impacts
estimated for each TSL for low-voltage, dry-type distribution
transformers.
Table V.40--Summary of Analytical Results for Low-Voltage, Dry-Type Distribution Transformers: National Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
National Energy Savings (quads) 1.09............... 1.12.............. 1.29.............. 1.86.............. 1.90.............. 2.08
--------------------------------------------------------------------------------------------------------------------------------------------------------
NPV of Consumer Benefits (2010$ billion)
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% discount rate............... 7.81............... 7.79.............. 8.51.............. 11.16............. 9.37.............. 2.69
7% discount rate............... 2.03............... 1.97.............. 2.03.............. 2.36.............. 1.37.............. -2.41
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cumulative Emissions Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)...... 82.1............... 83.9.............. 96.0.............. 137............... 139............... 148
NOX (thousand tons)............ 67.0............... 68.6.............. 78.4.............. 112............... 114............... 121
Hg (tons)...................... 0.551.............. 0.564............. 0.645............. 0.918............. 0.934............. 0.992
--------------------------------------------------------------------------------------------------------------------------------------------------------
Value of Emissions Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (2010$ million)*........... 481 to 8570........ 492 to 8764....... 562 to 10020...... 800 to 14264...... 814 to 14517...... 866 to 15427
NOX--3% discount rate (2010$ 25 to 261.......... 26 to 267......... 30 to 305......... 42 to 434......... 43 to 442......... 46 to 470
million).
NOX--7% discount rate (2010$ 8 to 85............ 8 to 87........... 10 to 99.......... 14 to 141......... 14 to 143......... 15 to 152
million).
--------------------------------------------------------------------------------------------------------------------------------------------------------
\*\ Range of the economic value of CO2 reductions is based on estimates of the global benefit of reduced CO2 emissions.
Table V.41--Summary of Analytical Results for Low-Voltage, Dry-Type Distribution Transformers: Manufacturer and Consumer Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Manufacturer Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Industry NPV (2011$ million)... 203 to 236......... 200 to 235........ 193 to 240........ 173 to 250........ 164 to 263........ 136 to 322
Industry NPV (% change)........ (7.7) to 7.7....... (8.9) to 6.8...... (12.2) to 9.1..... (21.0) to 14.1.... (25.2) to 20.0.... (37.9) to 46.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Consumer Mean LCC Savings (2010$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 6.................. 0.................. -125.............. 335............... 187............... 187............... -881
Design line 7.................. 1714............... 1714.............. 1793.............. 2270.............. 2270.............. 270
[[Page 7364]]
Design line 8.................. 2476............... 2476.............. 2625.............. 4145.............. -2812............. -2812
--------------------------------------------------------------------------------------------------------------------------------------------------------
Consumer Median PBP (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 6.................. 0.0................ 24.7.............. 13.0.............. 16.3.............. 16.3.............. 32.4
Design line 7.................. 4.5................ 4.5............... 4.7............... 6.9............... 6.9............... 18.1
Design line 8.................. 8.4................ 8.4............... 12.3.............. 11.0.............. 24.5.............. 24.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Distribution of Consumer LCC Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 6
Net Cost (%)............... 0.0................ 71.5.............. 17.6.............. 36.2.............. 36.2.............. 93.4
Net Benefit (%)............ 0.0................ 28.5.............. 82.4.............. 63.8.............. 63.8.............. 6.6
No Impact (%).............. 100.0.............. 0.0............... 0.0............... 0.0............... 0.0............... 0.0
Design line 7
Net Cost (%)............... 1.8................ 1.8............... 2.0............... 3.7............... 3.7............... 46.4
Net Benefit (%)............ 98.2............... 98.2.............. 98.0.............. 96.3.............. 96.3.............. 53.6
No Impact (%).............. 0.0................ 0.0............... 0.0............... 0.0............... 0.0............... 0.0
Design line 8
Net Cost (%)............... 5.2................ 5.2............... 15.3.............. 10.5.............. 78.5.............. 78.5
Net Benefit (%)............ 94.8............... 94.8.............. 84.7.............. 89.5.............. 21.5.............. 21.5
No Impact (%).............. 0.0................ 0.0............... 0.0............... 0.0............... 0.0............... 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
First, DOE considered TSL 6, the most efficient level (max tech),
which would save an estimated total of 2.08 quads of energy through
2045, an amount DOE considers significant. TSL 6 has an estimated NPV
of customer benefit of -$2.41 billion using a 7 percent discount rate,
and $2.69 billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 6 are 148 million metric
tons of CO2, 121 thousand tons of NOX, and 0.992
tons of Hg. The estimated monetary value of the CO2
emissions reductions at TSL 6 ranges from $866 million to $15,427
million.
At TSL 6, the average LCC impact ranges from -$2,812 for design
line 8 to $270 for design line 7. The median PBP ranges from 32.4 years
for design line 6 to 18.1 years for design line 7. The share of
customers experiencing a net LCC benefit ranges from 6.6 percent for
design line 6 to 53.6 percent for design line 7.
At TSL 6, the projected change in INPV ranges from a decrease of
$83 million to an increase of $102 million. If the decrease of $83
million occurs, TSL 6 could result in a net loss of 37.9 percent in
INPV to manufacturers of low-voltage dry-type distribution
transformers. At TSL 6, DOE recognizes the risk of very large negative
impacts on the industry. TSL 6 would require manufacturers to scrap
nearly all production assets and create transformer designs with which
most, if not all, have no experience. DOE is concerned, in particular,
about large impacts on small businesses, which may not be able to
procure sufficient volume of amorphous steel at competitive prices, if
at all.
The Secretary tentatively concludes that, at TSL 6 for low-voltage
dry-type distribution transformers, the benefits of energy savings,
emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the economic
burden on customers (as indicated by negative average LCC savings,
large PBPs, and the large percentage of customers who would experience
LCC increases at design line 6 and design line 8), the potential for
very large negative impacts on the manufacturers, and the potential
burden on small manufacturers. Consequently, DOE has tentatively
concluded that TSL 6 is not economically justified.
Next, DOE considered TSL 5, which would save an estimated total of
1.90 quads of energy through 2045, an amount DOE considers significant.
TSL 5 has an estimated NPV of customer benefit of $1.37 billion using a
7 percent discount rate, and $9.37 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 5 are 139 million metric
tons of CO2, 114 thousand tons of NOX, and 0.934
tons of Hg. The estimated monetary value of the CO2
emissions reductions at TSL 5 ranges from $814 million to $14,517
million.
At TSL 5, the average LCC impact ranges from -$2,812 for design
line 8 to $2,270 for design line 7. The median PBP ranges from 24.5
years for design line 8 to 6.9 years for design line 7. The share of
customers experiencing a net LCC benefit ranges from 21.5 percent for
design line 8 to 96.3 percent for design line 7.
At TSL 5, the projected change in INPV ranges from a decrease of
$55 million to an increase of $44 million. If the decrease of $55
million occurs, TSL 5 could result in a net loss of 25.2 percent in
INPV to manufacturers of low-voltage dry-type distribution
transformers. At TSL 5, DOE recognizes the risk of very large negative
impacts on the industry. TSL 5 would require manufacturers to scrap
nearly all production assets and create transformer designs with which
most, if not all, have no experience. DOE is concerned, in particular,
about large impacts on small businesses, which may not be able to
procure sufficient volume of amorphous steel at competitive prices, if
at all.
The Secretary tentatively concludes that, at TSL 5 for low-voltage
dry-type distribution transformers, the benefits of energy savings,
emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the economic
burden on customers at design line 8 (as indicated by negative average
LCC savings, large PBPs, and the large percentage of customers who
would experience LCC increases), the potential for very large negative
impacts on the manufacturers, and the potential burden on small
manufacturers. Consequently, DOE has tentatively concluded that TSL 5
is not economically justified.
Next, DOE considered TSL 4, which would save an estimated total of
1.86 quads of energy through 2045, an amount DOE considers significant.
TSL 4 has an estimated NPV of customer
[[Page 7365]]
benefit of $2.36 billion using a 7 percent discount rate, and $11.16
billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 4 are 137 million metric
tons of CO2, 112 thousand tons of NOX, and 0.918
tons of Hg. The estimated monetary value of the CO2
emissions reductions at TSL 4 ranges from $800 million to $14,264
million.
At TSL 4, the average LCC impact ranges from $187 for design line 6
to $4,145 for design line 8. The median PBP ranges from 16.3 years for
design line 6 to 6.9 years for design line 7. The share of customers
experiencing a net LCC benefit ranges from 63.8 percent for design line
6 to 96.3 percent for design line 7.
At TSL 4, the projected change in INPV ranges from a decrease of
$46 million to an increase of $31 million. If the decrease of $46
million occurs, TSL 4 could result in a net loss of 21 percent in INPV
to manufacturers of low-voltage dry-type distribution transformers. At
TSL 4, DOE recognizes the risk of very large negative impacts on the
industry. As with the higher TSLs, TSL 4 would require manufacturers to
scrap nearly all production assets and create transformer designs with
which most, if not all, have no experience. DOE is concerned, in
particular, about large impacts on small businesses, which may not be
able to procure sufficient volume of amorphous steel at competitive
prices, if at all.
The Secretary tentatively concludes that, at TSL 4 for low-voltage
dry-type distribution transformers, the benefits of energy savings,
positive NPV of customer benefit, positive average LCC savings,
emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the
potential for very large negative impacts on the manufacturers, and the
potential burden on small manufacturers. Consequently, DOE has
tentatively concluded that TSL 4 is not economically justified.
Next, DOE considered TSL 3, which would save an estimated total of
1.29 quads of energy through 2045, an amount DOE considers significant.
TSL 3 has an estimated NPV of customer benefit of $2.03 billion using a
7 percent discount rate, and $8.51 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 3 are 96.0 million
metric tons of CO2, 78.4 thousand tons of NOX,
and 0.645 tons of Hg. The estimated monetary value of the
CO2 emissions reductions at TSL 3 ranges from $562 million
to $10,020 million.
At TSL 3, the average LCC impact ranges from $335 for design line 6
to $2,625 for design line 8. The median PBP ranges from 13.0 years for
design line 6 to 4.7 years for design line 7. The share of customers
experiencing a net LCC benefit ranges from 82.4 percent for design line
6 to 98.0 percent for design line 7.
At TSL 3, the projected change in INPV ranges from a decrease of
$27 million to an increase of $20 million. If the decrease of $27
million occurs, TSL 3 could result in a net loss of 12.2 percent in
INPV to manufacturers of low-voltage dry-type distribution
transformers. At TSL 3, DOE recognizes the risk of negative impacts on
the industry, particularly the small manufacturers. While TSL 3 could
likely be met with M4 steel, DOE's analysis shows that this design
option is at the edge of its technical feasibility at the efficiency
levels comprised by TSL 3. Although these levels could be met with M3
or better steels, DOE is concerned that a significant number of small
manufacturers would be unable to acquire these steels in sufficient
supply and quality to compete. Additionally, TSL 3 requires significant
investment in advanced core construction equipment such are step-lap
mitering machines or wound core production lines, as butt lap designs,
even with high-grade designs, are unlikely to comply. Given their more
limited engineering resources and capital, small businesses may find it
difficult to make these designs at competitive prices and may have to
exit the market. At the same time, however, those small manufacturers
may be able to source their cores--and many are doing so to a
significant extent currently--which could mitigate impacts.
The Secretary tentatively concludes that, at TSL 3 for low-voltage
dry-type distribution transformers, the benefits of energy savings,
positive NPV of customer benefit, positive average LCC savings,
emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the risk of
negative impacts on the industry, particularly the small manufacturers.
Consequently, DOE has tentatively concluded that TSL 3 is not
economically justified.
Next, DOE considered TSL 2, which would save an estimated total of
1.12 quads of energy through 2045, an amount DOE considers significant.
TSL 2 has an estimated NPV of customer benefit of $1.97 billion using a
7 percent discount rate, and $7.79 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 2 are 83.9 million
metric tons of CO2, 68.6 thousand tons of NOX,
and 0.564 tons of Hg. The estimated monetary value of the
CO2 emissions reductions at TSL 2 ranges from $492 million
to $8,764 million.
At TSL 2, the average LCC impact ranges from -$125 for design line
6 to $2,476 for design line 8. The median PBP ranges from 24.7 years
for design line 6 to 4.5 years for design line 7. The share of
customers experiencing a net LCC benefit ranges from 28.5 percent for
design line 6 to 98.2 percent for design line 7.
At TSL 2, the projected change in INPV ranges from a decrease of
$20 million to an increase of $15 million. If the decrease of $20
million occurs, TSL 2 could result in a net loss of 8.9 percent in INPV
to manufacturers of low-voltage dry-type distribution transformers. At
TSL 2, DOE recognizes the risk of negative impacts on the industry,
particularly small manufacturers. TSL 2 would likely require mitering
or wound core technology, which many small businesses do not have in-
house. Given their more limited engineering resources and capital,
small businesses may find it difficult to make these designs at
competitive prices and may have to exit the market. At the same time,
however, those small manufacturers may be able to source their cores--
and many are doing so to a significant extent currently--which could
mitigate impacts.
The Secretary tentatively concludes that, at TSL 2 for low-voltage
dry-type distribution transformers, the benefits of energy savings,
positive NPV of customer benefit, positive average LCC savings,
emission reductions, and the estimated monetary value of the
CO2 emissions reductions would be outweighed by the risk of
negative impacts on the industry, particularly regarding the
uncertainty over how small businesses would be impacted. Consequently,
DOE has tentatively concluded that TSL 2 is not economically justified.
Next, DOE considered TSL 1, which would save an estimated total of
1.09 quads of energy through 2045, an amount DOE considers significant.
TSL 1 has an estimated NPV of customer benefit of $2.03 billion using a
7 percent discount rate, and $7.81 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 1 are 82.1 million
metric tons of CO2, 67.0 thousand tons of NOX,
and 0.551 tons of Hg. The estimated monetary value of the
CO2 emissions reductions at TSL 1 ranges from $481 million
to $8,570 million.
At TSL 1, the average LCC impact ranges from $1,714 for design line
7 to $2,476 for design line 8. The median PBP ranges from 8.4 years for
design line 8 to 4.5 years for design line 7. The
[[Page 7366]]
share of customers experiencing a net LCC benefit ranges from 94.8
percent for design line 8 to 98.2 percent for design line 7.
At TSL 1, the projected change in INPV ranges from a decrease of
$17 million to an increase of $17 million. If the decrease of $17
million occurs, TSL 1 could result in a net loss of 7.7 percent in INPV
to manufacturers of low-voltage dry-type distribution transformers. At
TSL 1, DOE recognizes the risk of small negative impacts on the
industry if manufacturers are not able to recoup their investment
costs. At this level, small manufacturers can still use butt-lap
construction and steels with which they generally have experience.
After considering the analysis and weighing the benefits and the
burdens, DOE has tentatively concluded that at TSL 1 for low-voltage,
dry-type distribution transformers, the benefits of energy savings, NPV
of customer benefit, positive customer LCC impacts, emissions
reductions and the estimated monetary value of the emissions reductions
would outweigh the risk of small negative impacts on the manufacturers.
In particular, the Secretary has concluded that TSL 1 would save a
significant amount of energy and is technologically feasible and
economically justified. NEMA also recommended TSL 1 for low-voltage,
dry-type distribution transformers during the negotiated rulemaking.
For the reasons given above, DOE today proposes to adopt the energy
conservation standards for low-voltage dry-type distribution
transformers at TSL 1. Table V.42 presents the proposed energy
conservation standards for low-voltage, dry-type distribution
transformers.
Table V.42--Proposed Energy Conservation Standards for Low-Voltage, Dry-Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Electrical efficiency by kVA and equipment class
-----------------------------------------------------------------------------------------------------------------
Equipment class 3 Equipment class 4
----------------------------------------------------------------------------------------------------------------
kVA % kVA %
----------------------------------------------------------------------------------------------------------------
15........................................ 97.73 15........................... 97.44
25........................................ 98.00 30........................... 97.95
37.5...................................... 98.20 45........................... 98.20
50........................................ 98.31 75........................... 98.47
75........................................ 98.50 112.5........................ 98.66
100....................................... 98.60 150.......................... 98.78
167....................................... 98.75 225.......................... 98.92
250....................................... 98.87 300.......................... 99.02
333....................................... 98.94 500.......................... 99.17
750.......................... 99.27
1000......................... 99.34
----------------------------------------------------------------------------------------------------------------
3. Benefits and Burdens of Trial Standard Levels Considered for Medium-
Voltage, Dry-Type Distribution Transformers
Table V.43 and Table V.44 summarize the quantitative impacts
estimated for each TSL for medium-voltage, dry-type distribution
transformers.
Table V.43--Summary of Analytical Results for Medium-Voltage, Dry-Type Distribution Transformers: National Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
National Energy Savings (quads)... 0.06.................. 0.13.................. 0.23.................. 0.23................. 0.37
--------------------------------------------------------------------------------------------------------------------------------------------------------
NPV of Consumer Benefits (2010$ billion)
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% discount rate.................. 0.42.................. 0.67.................. 0.90.................. 0.90................. -0.38
7% discount rate.................. 0.10.................. 0.13.................. 0.06.................. 0.06................. -0.84
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cumulative Emissions Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)......... 4.62.................. 8.80.................. 16.8.................. 16.8................. 25.7
NOX (thousand tons)............... 3.77.................. 7.19.................. 13.7.................. 13.7................. 21.0
Hg (tons)......................... 0.031................. 0.059................. 0.113................. 0.113................ 0.173
--------------------------------------------------------------------------------------------------------------------------------------------------------
Value of Emissions Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (2010$ million)*.............. 27 to 483............. 52 to 919............. 98 to 1751............ 98 to 1751........... 151 to 2688
NOX--3% discount rate (2010$ 1 to 15............... 3 to 28............... 5 to 53............... 5 to 53.............. 8 to 82
million).
NOX--7% discount rate (2010$ 0 to 5................ 1 to 9................ 2 to 17............... 2 to 17.............. 3 to 27
million).
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Range of the economic value of CO2 reductions is based on estimates of the global benefit of reduced CO2 emissions.
[[Page 7367]]
Table V.44--Summary of Analytical Results for Medium-Voltage, Dry-Type Distribution Transformers: Manufacturer and Consumer Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Manufacturer Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Industry NPV (2011$ million)...... 87 to 89.............. 85 to 90.............. 80 to 95.............. 77 to 93............. 71 to 114
Industry NPV (% change)........... (4.2) to (2.0)........ (7.1) to (1.0)........ (12.4) to 4.5......... (15.3) to 1.7........ (21.9) to 25.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Consumer Mean LCC Savings (2010$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 9..................... 849................... 1659.................. 1659.................. 1659................. 237
Design line 10.................... 4509.................. 4791.................. 4791.................. 4791................. -12756
Design line 11.................... 1043.................. 202................... 2000.................. 2000................. -3160
Design line 12.................... 4518.................. 6332.................. 8860.................. 8860................. -12420
Design line 13A................... 25.................... 447................... -846.................. -846................. -11077
Design line 13B................... 2734.................. -961.................. 384................... 384.................. -5403
--------------------------------------------------------------------------------------------------------------------------------------------------------
Consumer Median PBP (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 9..................... 2.6................... 6.2................... 6.2................... 6.2.................. 19.1
Design line 10.................... 1.1................... 8.8................... 8.8................... 8.8.................. 28.4
Design line 11.................... 10.7.................. 17.6.................. 14.1.................. 14.1................. 24.5
Design line 12.................... 6.3................... 13.5.................. 13.0.................. 13.0................. 25.9
Design line 13A................... 16.5.................. 16.6.................. 21.7.................. 21.7................. 37.1
Design line 13B................... 4.6................... 20.4.................. 19.3.................. 19.3................. 21.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Distribution of Consumer LCC Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 9
Net Cost (%).................. 3.4................... 5.7................... 5.7................... 5.7.................. 53.4
Net Benefit (%)............... 83.4.................. 94.3.................. 94.3.................. 94.3................. 46.6
No Impact (%)................. 13.3.................. 0.0................... 0.0................... 0.0.................. 0.0
Design line 10
Net Cost (%).................. 0.7................... 16.7.................. 16.7.................. 16.7................. 84.8
Net Benefit (%)............... 98.8.................. 83.3.................. 83.3.................. 83.3................. 15.2
No Impact (%)................. 0.5................... 0.0................... 0.0................... 0.0.................. 0.0
Design line 11
Net Cost (%).................. 20.6.................. 49.5.................. 25.7.................. 25.7................. 76.1
Net Benefit (%)............... 79.4.................. 50.5.................. 74.3.................. 74.3................. 23.9
No Impact (%)................. 0.0................... 0.0................... 0.0................... 0.0.................. 0.0
Design line 12
Net Cost (%).................. 6.7................... 23.5.................. 18.1.................. 18.1................. 81.1
Net Benefit (%)............... 93.3.................. 76.5.................. 81.9.................. 81.9................. 18.9
No Impact (%)................. 0.0................... 0.0................... 0.0................... 0.0.................. 0.0
Design line 13A
Net Cost (%).................. 52.2.................. 42.3.................. 64.4.................. 64.4................. 97.1
Net Benefit (%)............... 47.8.................. 57.7.................. 35.6.................. 35.6................. 2.9
No Impact (%)................. 0.0................... 0.0................... 0.0................... 0.0.................. 0.0
Design line 13B
Net Cost (%).................. 28.5.................. 59.6.................. 52.7.................. 52.7................. 67.2
Net Benefit (%)............... 71.3.................. 40.4.................. 47.3.................. 47.3................. 32.8
No Impact (%)................. 0.2................... 0.0................... 0.0................... 0.0.................. 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
First, DOE considered TSL 5, the most efficient level (max tech),
which would save an estimated total of 0.37 quads of energy through
2045, an amount DOE considers significant. TSL 5 has an estimated NPV
of customer benefit of -$0.84 billion using a 7 percent discount rate,
and -$0.38 billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 5 are 25.7 million
metric tons of CO2, 21.0 thousand tons of NOX,
and 0.173 tons of Hg. The estimated monetary value of the
CO2 emissions reductions at TSL 5 ranges from $151 million
to $2,688 million.
At TSL 5, the average LCC impact ranges from -$12,756 for design
line 10 to -$237 for design line 9. The median PBP ranges from 37.1
years for design line 13A to 19.1 years for design line 9. The share of
customers experiencing a net LCC benefit ranges from 2.9 percent for
design line 13A to 46.6 percent for design line 9.
At TSL 5, the projected change in INPV ranges from a decrease of
$20 million to an increase of $23 million. If the decrease of $20
million occurs, TSL 5 could result in a net loss of 21.9 percent in
INPV to manufacturers of medium-voltage dry-type distribution
transformers. At TSL 5, DOE recognizes the risk of very large negative
impacts on industry because they would likely be forced to move to
amorphous technology, with which there is no experience in this market.
The Secretary tentatively concludes that, at TSL 5 for medium-
voltage dry-type distribution transformers, the benefits of energy
savings, emission reductions, and the estimated monetary value of the
emissions reductions would be outweighed by the negative NPV of
customer benefit, the economic burden on customers (as indicated by
negative average LCC savings, large PBPs, and the large percentage of
customers who would experience LCC increases), and
[[Page 7368]]
the risk of very large negative impacts on the manufacturers.
Consequently, DOE has tentatively concluded that TSL 5 is not
economically justified.
Next, DOE considered TSL 4, which would save an estimated total of
0.23 quads of energy through 2045, an amount DOE considers significant.
TSL 4 has an estimated NPV of customer benefit of $0.06 billion using a
7 percent discount rate, and $0.90 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 4 are 16.8 million
metric tons of CO2, 13.7 thousand tons of NOX,
and 0.113 tons of Hg. The estimated monetary value of the
CO2 emissions reductions at TSL 4 ranges from $98 million to
$1,751 million.
At TSL 4, the average LCC impact ranges from -$846 for design line
13A to $8,860 for design line 12. The median PBP ranges from 21.7 years
for design line 13A to 6.2 years for design line 9. The share of
customers experiencing a net LCC benefit ranges from 35.6 percent for
design line 13A to 94.3 percent for design line 9.
At TSL 4, the projected change in INPV ranges from a decrease of
$14 million to an increase of $2 million. If the decrease of $14
million occurs, TSL 4 could result in a net loss of 15.3 percent in
INPV to manufacturers of medium-voltage dry-type distribution
transformers. At TSL 4, DOE recognizes the risk of very large negative
impacts on most manufacturers in the industry who have little
experience with the steels that would be required. Small businesses, in
particular, with limited engineering resources, may not be able to
convert their lines to employ thinner steels and may be disadvantaged
with respect to access to key materials, including Hi-B steels.
The Secretary tentatively concludes that, at TSL 4 for medium-
voltage dry-type distribution transformers, the benefits of energy
savings, positive NPV of customer benefit, positive impacts on
consumers (as indicated by positive average LCC savings, favorable
PBPs, and the large percentage of customers who would experience LCC
benefits), emission reductions, and the estimated monetary value of the
emissions reductions would be outweighed by the risk of very large
negative impacts on the manufacturers, particularly small businesses.
Consequently, DOE has tentatively concluded that TSL 4 is not
economically justified.
Next, DOE considered TSL 3, which would save an estimated total of
0.23 quads of energy through 2045, an amount DOE considers significant.
TSL 3 has an estimated NPV of customer benefit of $0.06 billion using a
7 percent discount rate, and $0.90 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 3 are 16.8 million
metric tons of CO2, 13.7 thousand tons of NOX,
and 0.113 tons of Hg. The estimated monetary value of the
CO2 emissions reductions at TSL 3 ranges from $98 million to
$1,751 million.
At TSL 3, the average LCC impact ranges from -$846 for design line
13A to $8,860 for design line 12. The median PBP ranges from 21.7 years
for design line 13A to 6.2 years for design line 9. The share of
customers experiencing a net LCC benefit ranges from 35.6 percent for
design line 13A to 94.3 percent for design line 9.
At TSL 3, the projected change in INPV ranges from a decrease of
$11 million to an increase of $4 million. If the decrease of $11
million occurs, TSL 3 could result in a net loss of 12.4 percent in
INPV to manufacturers of medium-voltage dry-type transformers. At TSL
3, DOE recognizes the risk of large negative impacts on most
manufacturers in the industry who have little experience with the
steels that would be required. As with TSL 4, small businesses, in
particular, with limited engineering resources, may not be able to
convert their lines to employ thinner steels and may be disadvantaged
with respect to access to key materials, including Hi-B steels.
The Secretary tentatively concludes that, at TSL 3 for medium-
voltage dry-type distribution transformers, the benefits of energy
savings, positive NPV of customer benefit, positive impacts on
consumers (as indicated by positive average LCC savings, favorable
PBPs, and the large percentage of customers who would experience LCC
benefits), emission reductions, and the estimated monetary value of the
emissions reductions would be outweighed by the risk of large negative
impacts on the manufacturers, particularly small businesses.
Consequently, DOE has tentatively concluded that TSL 3 is not
economically justified.
Next, DOE considered TSL 2, which would save an estimated total of
0.13 quads of energy through 2045, an amount DOE considers significant.
TSL 2 has an estimated NPV of customer benefit of $0.10 billion using a
7 percent discount rate, and $0.42 billion using a 3 percent discount
rate.
The cumulative emissions reductions at TSL 2 are 8.80 million
metric tons of CO2, 7.19 thousand tons of NOX,
and 0.059 tons of Hg. The estimated monetary value of the
CO2 emissions reductions at TSL 2 ranges from $52 million to
$919 million.
At TSL 2, the average LCC impact ranges from -$961 for design line
13B to $6,332 for design line 12. The median PBP ranges from 20.4 years
for design line 13B to 6.2 years for design line 9. The share of
customers experiencing a net LCC benefit ranges from 40.4 percent for
design line 13B to 94.3 percent for design line 9.
At TSL 2, the projected change in INPV ranges from a decrease of $7
million to a decrease of $1 million. If the decrease of $7 million
occurs, TSL 2 could result in a net loss of 7.1 percent in INPV to
manufacturers of medium-voltage dry-type distribution transformers. At
TSL 2, DOE recognizes the risk of small negative impacts if
manufacturers are unable to recoup investments made to meet the
standard.
After considering the analysis and weighing the benefits and the
burdens, DOE has tentatively concluded that at TSL 2 for medium-
voltage, dry-type distribution transformers, the benefits of energy
savings, positive NPV of customer benefit, positive impacts on
consumers (as indicated by positive average LCC savings for five of the
six design lines, favorable PBPs, and the large percentage of customers
who would experience LCC benefits), emission reductions, and the
estimated monetary value of the emissions reductions would outweigh the
risk of small negative impacts if manufacturers are unable to recoup
investments made to meet the standard. In particular, the Secretary of
Energy has concluded that TSL 2 would save a significant amount of
energy and is technologically feasible and economically justified. In
addition, DOE notes that TSL 2 corresponds to the standards that were
agreed to by the ERAC subcommittee, as described in section II.B.2.
Based on the above considerations, DOE today proposes to adopt the
energy conservation standards for medium-voltage, dry-type distribution
transformers at TSL 2. Table V.45 presents the proposed energy
conservation standards for medium-voltage, dry-type distribution
transformers.
[[Page 7369]]
Table V.45--Proposed Energy Conservation Standards for Medium-Voltage, Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Electrical efficiency by kVA and equipment class
---------------------------------------------------------------------------------------------------------------------------------------------------------
Equipment class 5 Equipment class 6 Equipment class 7 Equipment class 8 Equipment class Equipment class
--------------------------------------------------------------------------------------------------------------------- 9 10
-----------------------------------
kVA % kVA % kVA % kVA % kVA % kVA %
--------------------------------------------------------------------------------------------------------------------------------------------------------
15................................................ 98.10 15 97.50 15 97.86 15 97.18 ....... ....... ....... .......
25................................................ 98.33 30 97.90 25 98.12 30 97.63 ....... ....... ....... .......
37.5.............................................. 98.49 45 98.10 37.5 98.30 45 97.86 ....... ....... ....... .......
50................................................ 98.60 75 98.33 50 98.42 75 98.13 ....... ....... ....... .......
75................................................ 98.73 112.5 98.52 75 98.57 112.5 98.36 75 98.53 ....... .......
100............................................... 98.82 150 98.65 100 98.67 150 98.51 100 98.63 ....... .......
167............................................... 98.96 225 98.82 167 98.83 225 98.69 167 98.80 225 98.57
250............................................... 99.07 300 98.93 250 98.95 300 98.81 250 98.91 300 98.69
333............................................... 99.14 500 99.09 333 99.03 500 98.99 333 98.99 500 98.89
500............................................... 99.22 750 99.21 500 99.12 750 99.12 500 99.09 750 99.02
667............................................... 99.27 1000 99.28 667 99.18 1000 99.20 667 99.15 1000 99.11
833............................................... 99.31 1500 99.37 833 99.23 1500 99.30 833 99.20 1500 99.21
2000 99.43 ........ ....... 2000 99.36 ....... ....... 2000 99.28
2500 99.47 ........ ....... 2500 99.41 ....... ....... 2500 99.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
4. Summary of Benefits and Costs (Annualized) of the Proposed Standards
The benefits and costs of today's proposed standards can also be
expressed in terms of annualized values. The annualized monetary values
are the sum of (1) the annualized national economic value of the
benefits from operating products that meet the proposed standards
(consisting primarily of operating cost savings from using less energy,
minus increases in equipment purchase costs, which is another way of
representing customer NPV), and (2) the monetary value of the benefits
of emission reductions, including CO2 emission
reductions.\43\ The value of the CO2 reductions is
calculated using a range of values per metric ton of CO2
developed by a recent interagency process.
---------------------------------------------------------------------------
\43\ DOE used a two-step calculation process to convert the
time-series of costs and benefits into annualized values. First, DOE
calculated a present value in 2011, the year used for discounting
the NPV of total consumer costs and savings, for the time-series of
costs and benefits using discount rates of 3 and 7 percent for all
costs and benefits except for the value of CO2
reductions. For the latter, DOE used a range of discount rates, as
shown in Table V.46. From the present value, DOE then calculated the
fixed annual payment over a 30-year period, starting in 2011 that
yields the same present value. The fixed annual payment is the
annualized value. Although DOE calculated annualized values, this
does not imply that the time-series of cost and benefits from which
the annualized values were determined would be a steady stream of
payments.
---------------------------------------------------------------------------
Although combining the values of operating savings and
CO2 reductions provides a useful perspective, two issues
should be considered. First, the national operating savings are
domestic U.S. customer monetary savings that occur as a result of
market transactions while the value of CO2 reductions is
based on a global value. Second, the assessments of operating cost
savings and SCC are performed with different methods that use different
time frames for analysis. The national operating cost savings is
measured for the lifetime of products shipped in 2016-2045. The SCC
values, on the other hand, reflect the present value of future climate-
related impacts resulting from the emission of one metric ton of
CO2 in each year. These impacts continue well beyond 2100.
Table V.46 shows the annualized values for the proposed standards
for distribution transformers. The results for the primary estimate are
as follows. Using a 7-percent discount rate for benefits and costs
other than CO2 reductions, for which DOE used a 3-percent
discount rate along with the SCC series corresponding to a value of
$22.3/metric ton in 2010, the cost of the standards proposed in today's
rule is $302 million per year in increased product costs, while the
annualized benefits are $631 million in reduced product operating
costs, $244 million in CO2 reductions, and $7.78 million in
reduced NOX emissions. In this case, the net benefit amounts
to $581 million per year. Using a 3-percent discount rate for all
benefits and costs and the SCC series corresponding to a value of
$22.3/metric ton in 2010, the cost of the standards proposed in today's
rule is $308 million per year in increased product costs, while the
annualized benefits are $1,026 million in reduced operating costs, $244
million in CO2 reductions, and $12.4 million in reduced
NOX emissions. In this case, the net benefit amounts to $975
million per year.
Table V.46--Annualized Benefits and Costs of Proposed Standards for Distribution Transformers Sold in 2016-2045
----------------------------------------------------------------------------------------------------------------
Monetized (million 2010$/year)
------------------------------------------------------------
Discount rate Low net benefits High net benefits
Primary estimate* estimate* estimate*
----------------------------------------------------------------------------------------------------------------
Benefits
Operating Cost Savings..... 7%................ 631................ 594............... 659
3%................ 1,026.............. 950............... 1,075
CO2 Reduction at $4.9/t**.. 5%................ 58.6............... 58.6.............. 58.6
[[Page 7370]]
CO2 Reduction at $22.3/t**. 3%................ 244................ 244............... 244
CO2 Reduction at $36.5/t**. 2.5%.............. 389................ 389............... 389
CO2 Reduction at $67.6/t**. 3%................ 742................ 742............... 742
NOX Reduction at $2,537/ 7%................ 7.78............... 7.78.............. 7.78
ton**.
3%................ 12.4............... 12.4.............. 12.4
Total [dagger]............. 7% plus CO2 range. 697 to 1380........ 660 to 1343....... 726 to 1409
7%................ 883................ 846............... 911
3% plus CO2 range. 1097 to 1780....... 1021 to 1704...... 1146 to 1829
3%................ 1,283.............. 1,207............. 1,331
Costs
Incremental Product Costs.. 7%................ 302................ 338............... 285
3%................ 308................ 351............... 289
Total Net Benefits
Total [dagger]............. 7% plus CO2 range. 400 to 1083........ 327 to 1010....... 445 to 1128
7%................ 581................ 507............... 626
3% plus CO2 range. 789 to 1472........ 670 to 1353....... 857 to 1540
3%................ 975................ 855............... 1,043
----------------------------------------------------------------------------------------------------------------
* The Primary, Low Net Benefits, and High Net Benefits Estimates utilize forecasts of energy prices from the AEO
2011 reference case, Low Economic Growth case, and High Economic Growth case, respectively. In addition,
incremental product costs reflect no change in the Primary estimate, rising product prices in the Low Net
Benefits estimate, and declining product prices in the High Net Benefits estimate.
** The CO2 values represent global values (in 2010$) of the social cost of CO2 emissions in 2010 under several
scenarios. The values of $4.9, $22.3, and $36.5 per metric ton are the averages of SCC distributions
calculated using 5%, 3%, and 2.5% discount rates, respectively. The value of $67.6 per metric ton represents
the 95th percentile of the SCC distribution calculated using a 3% discount rate. The value for NOX (in 2010$)
is the average of the low and high values used in DOE's analysis.
[dagger] Total Benefits for both the 3% and 7% cases are derived using the SCC value calculated at a 3% discount
rate, which is $22.3/metric ton in 2010 (in 2010$). In the rows labeled as ``7% plus CO2 range'' and ``3% plus
NOX range,'' the operating cost and NOX benefits are calculated using the labeled discount rate, and those
values are added to the full range of CO2 values.
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Orders 12866 and 13563
Section 1(b)(1) of Executive Order 12866, ``Regulatory Planning and
Review,'' 58 FR 51735 (Oct 4, 1993), requires each agency to identify
the problem that it intends to address, including, where applicable,
the failures of private markets or public institutions that warrant new
agency action, as well as to assess the significance of that problem.
The problems that today's proposed standards address are as follows:
(1) There is a lack of consumer information and/or information
processing capability about energy efficiency opportunities in the
commercial equipment market.
(2) There is asymmetric information (one party to a transaction has
more and better information than the other) and/or high transactions
costs (costs of gathering information and effecting exchanges of goods
and services).
(3) There are external benefits resulting from improved energy
efficiency of distribution transformers that are not captured by the
users of such equipment. These benefits include externalities related
to environmental protection and energy security that are not reflected
in energy prices, such as reduced emissions of greenhouse gases.
The specific market failure that the energy conservation standard
addresses for distribution transformers is that a substantial portion
of distribution transformer purchasers are not evaluating the cost of
transformer losses when they make distribution transformer purchase
decisions. Therefore, distribution transformers are being purchased
that do not provide the minimum LCC service to equipment owners.
For distribution transformers, the Institute of Electronic and
Electrical Engineers Inc. (IEEE) has documented voluntary guidelines
for the economic evaluation of distribution transformer losses, IEEE
PC57.12.33/D8. These guidelines document economic evaluation methods
for distribution transformers that are common practice in the utility
industry. But while economic evaluation of transformer losses is
common, it is not a universal practice. DOE collected information
during the course of the previous energy conservation standard
rulemaking to estimate the extent to which distribution transformer
purchases are evaluated. Data received from the National Electrical
Manufacturers Association indicated that these guidelines or similar
criteria are applied to approximately 75 percent of liquid-immersed
transformer purchases, 50 percent of small capacity medium-voltage dry-
type transformer purchases, and 80 percent of large capacity medium-
voltage dry-type transformer purchases. Therefore, 25 percent, 50
percent, and 20 percent of distribution transformer purchases do not
have economic evaluation of transformer losses. These are the portions
of the distribution transformer market in which there is market
failure. Today's proposed energy conservation standards would eliminate
from the market those distribution transformers designs that are
purchased on a purely minimum first cost basis, but which would not
likely be purchased by equipment buyers when the economic value of
equipment losses are properly evaluated.
In addition, DOE has determined that today's regulatory action is
an ``economically significant regulatory action'' under section 3(f)(1)
of Executive Order 12866. Accordingly, section 6(a)(3) of the Executive
Order requires that DOE prepare a regulatory impact analysis (RIA) on
today's proposed rule and that the Office of Information and Regulatory
Affairs (OIRA) in the Office of Management and
[[Page 7371]]
Budget (OMB) review this rule. DOE presented to OIRA for review the
draft rule and other documents prepared for this rulemaking, including
the RIA, and has included these documents in the rulemaking record. The
assessments prepared pursuant to Executive Order 12866 can be found in
the technical support document for this rulemaking.
DOE has also reviewed this regulation pursuant to Executive Order
13563. 76 FR 3281 (Jan. 21, 2011). EO 13563 is supplemental to and
explicitly reaffirms the principles, structures, and definitions
governing regulatory review established in Executive Order 12866. To
the extent permitted by law, agencies are required by Executive Order
13563 to: (1) Propose or adopt a regulation only upon a reasoned
determination that its benefits justify its costs (recognizing that
some benefits and costs are difficult to quantify); (2) tailor
regulations to impose the least burden on society, consistent with
obtaining regulatory objectives, taking into account, among other
things, and to the extent practicable, the costs of cumulative
regulations; (3) select, in choosing among alternative regulatory
approaches, those approaches that maximize net benefits (including
potential economic, environmental, public health and safety, and other
advantages; distributive impacts; and equity); (4) to the extent
feasible, specify performance objectives, rather than specifying the
behavior or manner of compliance that regulated entities must adopt;
and (5) identify and assess available alternatives to direct
regulation, including providing economic incentives to encourage the
desired behavior, such as user fees or marketable permits, or providing
information upon which choices can be made by the public.
DOE emphasizes as well that Executive Order 13563 requires agencies
to use the best available techniques to quantify anticipated present
and future benefits and costs as accurately as possible. In its
guidance, the Office of Information and Regulatory Affairs has
emphasized that such techniques may include identifying changing future
compliance costs that might result from technological innovation or
anticipated behavioral changes. For the reasons stated in the preamble,
DOE believes that today's NOPR is consistent with these principles.
B. Review Under the Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires
preparation of an initial regulatory flexibility analysis (IRFA) for
any rule that by law must be proposed for public comment, unless the
agency certifies that the rule, if promulgated, will not have a
significant economic impact on a substantial number of small entities.
As required by Executive Order 13272, ``Proper Consideration of Small
Entities in Agency Rulemaking,'' 67 FR 53461 (Aug. 16, 2002), DOE
published procedures and policies on February 19, 2003, to ensure that
the potential impacts of its rules on small entities are properly
considered during the rulemaking process. 68 FR 7990. DOE has made its
procedures and policies available on the Office of the General
Counsel's Web site (www.gc.doe.gov).
Based on the number of small distribution transformer manufacturers
and the potential scope of the impact, DOE could not certify that the
proposed standards would not have a significant impact on a significant
number of small businesses in the distribution transformer industry.
Therefore, DOE has prepared an IRFA for this rulemaking, a copy of
which DOE will transmit to the Chief Counsel for Advocacy of the SBA
for review under 5 U.S.C 605(b). As presented and discussed below, the
IFRA describes potential impacts on small transformer manufacturers
associated with capital and product conversion costs and discusses
alternatives that could minimize these impacts.
A statement of the objectives of, and reasons and legal basis for,
the proposed rule are set forth elsewhere in the preamble and not
repeated here.
1. Description and Estimated Number of Small Entities Regulated
a. Methodology for Estimating the Number of Small Entities
For manufacturers of distribution transformers, the Small Business
Administration (SBA) has set a size threshold, which defines those
entities classified as ``small businesses'' for the purposes of the
statute. DOE used the SBA's small business size standards to determine
whether any small entities would be subject to the requirements of the
rule. 65 FR 30836, 30850 (May 15, 2000), as amended at 65 FR 53533,
53545 (Sept. 5, 2000) and codified at 13 CFR part 121. The size
standards are listed by North American Industry Classification System
(NAICS) code and industry description and are available at http://www.sba.gov/content/table-small-business-size-standards. Distribution
transformer manufacturing is classified under NAICS 335311, ``Power,
Distribution and Specialty Transformer Manufacturing.'' The SBA sets a
threshold of 750 employees or less for an entity to be considered as a
small business for this category.
To estimate the number of companies that could be small business
manufacturers of products covered by this rulemaking, DOE conducted a
market survey using available public information to identify potential
small manufacturers. DOE's research involved industry trade association
membership directories (including NEMA), information from previous
rulemakings, UL qualification directories, individual company Web
sites, and market research tools (e.g., Hoover's reports) to create a
list of companies that potentially manufacture distribution
transformers covered by this rulemaking. DOE also asked stakeholders
and industry representatives if they were aware of any other small
manufacturers during manufacturer interviews and at previous DOE public
meetings. As necessary, DOE contacted companies on its list to
determine whether they met the SBA's definition of a small business
manufacturer. DOE screened out companies that do not offer products
covered by this rulemaking, do not meet the definition of a ``small
business,'' or are foreign owned and operated.
DOE initially identified at least 63 potential manufacturers of
distribution transformers sold in the U.S. DOE reviewed publicly
available information on these potential manufacturers and contacted
many to determine whether they qualified as small businesses. Based on
these efforts, DOE estimates there are 10 liquid immersed small
business manufacturers, 14 LVDT small business manufacturers, and 17
small business manufacturers of MVDT. Some small businesses compete in
more than one of these markets.
b. Manufacturer Participation
Of the LVDT manufacturers, DOE was able to reach and discuss
potential standards with eight of the 14 small business manufacturers.
Of the MVDT manufacturers, DOE was able to reach and discuss potential
standards with five of the 17 small business manufacturers. Of the
liquid-immersed small business manufacturers, DOE was able to reach and
discuss potential standards with three of the 10 small business
manufacturers. DOE also obtained information about small business
impacts while interviewing large manufacturers.
[[Page 7372]]
c. Distribution Transformer Industry Structure and Nature of
Competition
Liquid Immersed
Six major manufacturers supply more than 80 percent of the market
for liquid-immersed transformers. None of the major manufacturers of
distribution transformers covered in this rulemaking are considered to
be small businesses. The vast majority of shipments are manufactured
domestically. Electric utilities compose the customer base and
typically buy on first-cost. Many small manufacturers position
themselves towards the higher end of the market or in particular
product niches, such as network transformers or harmonic mitigating
transformers, but, in general, competition is based on price after a
given unit's specs are prescribed by a customer.
Low-Voltage Dry-Type
Four major manufacturers supply more than 80 percent of the market
for low-voltage dry-type transformers. None of the major LVDT
manufacturers of distribution transformers covered in this rulemaking
are small businesses. The customer base rarely purchases on efficiency
and is very first-cost conscious, which, in turn, places a premium on
economies of scale in manufacturing. DOE estimates approximately 80
percent of the market is served by imports, mostly from Canada and
Mexico. Many of the small businesses that compete in the low-voltage
dry-type market produce specialized transformers that are exempted from
standards. Roughly 50 percent of the market by revenue is exempted from
DOE standards. This market is much more fragmented than the one serving
DOE-covered LVDT transformers.
In the DOE-covered LVDT market, low-volume manufacturers typically
do not compete directly with large manufacturers using business models
similar to those of their bigger rivals because scale disadvantages in
purchasing and production are usually too great a barrier in this
portion of the market. The exceptions to this rule are those companies
that also compete in the medium-voltage market and, to some extent, are
able to leverage that experience and production economies. More
typically, low-volume manufacturers have focused their operations on
one or two parts of the value chain--rather than all of it--and trained
their sights on market segments outside of the high-volume baseline
efficiency market.
In terms of operations, some small firms focus on the engineering
and design of transformers and source the production of the cores or
even the whole transformer, while other small firms focus on just
production and rebrand for companies that offer broader solutions
through their own sales and distribution networks.
In terms of market focus, many small firms simply compete entirely
in the DOE-exempted markets. DOE did not attempt to contact companies
operating entirely in this very fragmented market. Of those that do
compete in the DOE-covered market, a few small businesses reported a
focus on the high-end of the market, often selling NEMA Premium or
better transformers as retrofit opportunities. Others focus on
particular applications or other niches, like data centers, and become
well-versed in the unique needs of a particular customer base.
Medium-Voltage Dry-Type
The medium-voltage dry-type transformer market is relatively
consolidated with one large company holding a substantial share of the
market. Electric utilities and industrial users make up most of the
customer base and typically buy on first-cost or features other than
efficiency. DOE estimates that at least 75 percent of production occurs
domestically. Several manufacturers also compete in the power
transformer market. Like the LVDT industry, most small business
manufacturers often produce transformers exempted from DOE standards.
DOE estimates 10 percent of the market is exempt from standards.
d. Comparison Between Large and Small Entities
Small distribution transformer manufacturers differ from large
manufacturers in several ways that affect the extent to which they
would be impacted by the proposed standards. Characteristics of small
manufacturers include: lower production volumes, fewer engineering
resources, less technical expertise, lack of purchasing power for high
performance steels, and less access to capital.
Lower production volumes lie at the heart of most small business
disadvantages, particularly for a small manufacturer that is vertically
integrated. A lower-volume manufacturer's conversion costs would need
to be spread over fewer units than a larger competitor. Thus, unless
the small business can differentiate its product in some way that earns
a price premium, the small business is a `price taker' and experiences
a reduction in profit per unit relative to the large manufacturer.
Therefore, because much of the same equipment would need to be
purchased by both large and small manufacturers in order to produce
transformers (in-house) at higher TSLs, undifferentiated small
manufacturers would face a greater variable cost penalty because they
must depreciate the one-time conversion expenditures over fewer units.
Smaller companies are also more likely to have more limited
engineering resources and they often operate with lower levels of
design and manufacturing sophistication. Smaller companies typically
also have less experience and expertise in working with more advanced
technologies, such as amorphous core construction in the liquid
immersed market or step-lap mitering in the dry-type markets. Standards
that required these technologies could strain the engineering resources
of these small manufacturers if they chose to maintain a vertically
integrated business model.
Small distribution transformer manufacturers can also be at a
disadvantage due to their lack of purchasing power for high performance
materials. If more expensive steels are needed to meet standards and
steel cost grows as a percentage of the overall product cost, small
manufacturers who pay higher per pound prices would be
disproportionately impacted.
Lastly, small manufacturers typically have less access to capital,
which may be needed by some to cover the conversion costs associated
with new technologies.
2. Description and Estimate of Compliance Requirements
Liquid Immersed. Based on interviews with manufacturers in the
liquid-immersed market, DOE does not believe small manufacturers will
face significant capital conversion costs at the levels proposed in
today's rulemaking. DOE expects small manufacturers of liquid-immersed
distribution transformers to continue to produce silicon steel cores,
rather than invest in amorphous technology. While silicon steel designs
capable of achieving TSL 1 would get larger, and thus reduce
throughput, most manufacturers said the industry in general has
substantial excess capacity due to the recent economic downturn.
Therefore, DOE believes TSL 1 would not require the typical small
manufacturer to invest in additional capital equipment. However, small
manufacturers may incur some engineering and product design costs
associated with re-optimizing their production processes around new
baseline products. DOE estimates TSL 1
[[Page 7373]]
would require industry production development costs of only one-half of
one year's annual industry R&D expenses, as the levels do not require
any changes in technology or steel types. Because these costs are
relatively fixed per manufacturer, these one-time costs impact smaller
manufacturers disproportionately compared to larger manufacturers. The
table below illustrates this effect by comparing the conversion costs
to a typical small company's and a typical large manufacturer's annual
R&D expenses.
Table VI.1--Estimated Product Conversion Costs as a Percentage of Annual
R&D Expense
------------------------------------------------------------------------
Product conversion
Product conversion cost as a
cost percentage of
annual R&D expense
------------------------------------------------------------------------
Typical Large Manufacturer...... $1.4 M 20
Typical Small Manufacturer...... $1.4 M 222
------------------------------------------------------------------------
While the costs disproportionately impact small manufactures, the
standard levels, as stated above, do not require small manufacturers to
invest in entirely different production processes nor do they require
steels or core construction techniques with which these manufacturers
are not familiar. A range of design options would still be available.
Low-Voltage Dry-Type. For the low-voltage dry-type market, at TSL
1, the level proposed in today's notice, DOE estimates, capital
conversion costs of $0.75 million and product conversion costs of $0.2
million for a typical small and large manufacturer, based on
manufacturer interviews. Because of the largely fixed nature of these
one-time conversion expenditures that distribution transformer
manufacturers would incur as a result of standards, small manufacturers
who choose to invest to maintain in-house production will likely be
disproportionately impacted compared to large manufacturers. As Table
VI.2 indicates, small manufacturers face a greater relative hurdle in
complying with standards should they opt to continue to maintain core
production in-house.
Table VI.2--Estimated Capital and Product Conversion Costs as a Percentage of Annual Capital Expenditures and
R&D Expense
----------------------------------------------------------------------------------------------------------------
Capital conversion cost
as a percentage of Product conversion cost Total conversion cost
annual capital as a percentage of as a percentage of
expenditures annual R&D expense annual EBIT
----------------------------------------------------------------------------------------------------------------
Large Manufacturer................... 40 11 17
Small Manufacturer................... 152 49 77
----------------------------------------------------------------------------------------------------------------
As demonstrated in the table above, the investments required to
meet TSL 1, disproportionately impact small businesses. However, DOE's
capital conversion costs estimates in the table above assume that small
businesses are currently producing their cores in-house and will choose
to do so in the future, rather than source them from third-party core
manufactures who often have significant cost advantages through bulk
steel purchasing power and greater production efficiencies due to
higher volumes. As such, many small businesses DOE interviewed already
source a large percentage of their cores and many indicated they
expected such a strategy would be the low-cost option under higher
standards.
Compared to higher TSLs, TSL 1 provides many more design paths for
small manufacturers to comply. DOE's engineering analysis indicates
manufacturers can continue to use the low-capital butt-lap core
designs, meaning investment in mitering capability is not necessary to
comply. Manufacturers can use higher-quality grain oriented steels in
butt-lap designs to meet these proposed efficiency levels, source some
or all cores, or invest in mitering capability. DOE notes that roughly
half of the small business LVDT manufacturers DOE interviewed already
have mitering capability. For all of the reasons discussed, DOE
believes the capital expenditures it assumed for small businesses are
likely conservative and that small businesses have a variety of
technical and strategic paths to continue to compete in the market at
TSL 1.
Medium-Voltage Dry-Type. Based on its engineering analysis and
interviews, DOE expects relatively minor capital expenditures for the
industry to meet TSL 2. DOE understands that the market is already
standardized on step-lap mitering, so manufacturers will not need to
make major investments for more advanced core construction.
Furthermore, TSL 2 does not require a change to much thinner steels
such as M3 or HO. The industry can use M4 and H1, thicker steels with
which it has much more experience and which are easier to employ in the
stacked-core production process that dominates the medium-voltage
market. However, some investment will be required to maintain capacity
as some manufacturers will likely migrate to more M4 and H1 steel from
the slightly thicker M5, which is also common. Additionally, design
options at TSL 2 typically have larger cores, also slowing throughput.
Therefore, some manufacturers may need to invest in additional
production equipment. Alternatively, depending on each company's
availability capacity, manufacturers could employ addition production
shifts, rather than invest in additional capacity.
For the medium-voltage dry-type market, at TSL 2, the level
proposed in today's notice, DOE estimates capital conversion costs of
$1.0 million and product conversion costs of $0.2 million for a typical
small and large manufacturer that would need to expand mitering
capacity to meet TSL 2. Table VI.3 illustrates the relative impacts on
small and large manufacturers.
[[Page 7374]]
Table VI.3--Estimated Capital and Product Conversion Costs as a Percentage of Annual Capital Expenditures and
R&D Expense
----------------------------------------------------------------------------------------------------------------
Capital conversion cost
as a percentage of Product conversion cost Total conversion cost
annual capital as a percentage of as a percentage of
expenditures annual R&D expense annual EBIT
----------------------------------------------------------------------------------------------------------------
Large Manufacturer................... 43 7 14
Small Manufacturer................... 327 65 124
----------------------------------------------------------------------------------------------------------------
a. Summary of Compliance Impacts
The compliance impacts on small businesses are discussed above for
low-voltage dry-type, medium-voltage dry-type, and liquid-filled
distribution transformer manufacturers. Although the conversion costs
required can be considered substantial for all companies, the impacts
could be relatively greater for a typical small manufacturer because of
much lower production volumes and the relatively fixed nature of the
R&D and capital investments required.
DOE seeks comment on the potential impacts of amended standards on
small distribution transformer manufacturers.
3. Duplication, Overlap, and Conflict With Other Rules and Regulations
DOE is not aware of any rules or regulations that duplicate,
overlap, or conflict with the rule being considered today.
4. Significant Alternatives to the Proposed Rule
The discussion above analyzes impacts on small businesses that
would result from the other TSLs DOE considered. Though TSLs lower than
the proposed TSLs are expected to reduce the impacts on small entities,
DOE is required by EPCA to establish standards that achieve the maximum
improvement in energy efficiency that are technically feasible and
economically justified, and result in a significant conservation of
energy. Therefore, DOE rejected the lower TSLs.
In addition to the other TSLs being considered, the NOPR TSD
includes a regulatory impact analysis in chapter 17. For distribution
transformers, this report discusses the following policy alternatives:
(1) Consumer rebates, (2) consumer tax credits, and (3) manufacturer
tax credits. DOE does not intend to consider these alternatives further
because they either are not feasible to implement or are not expected
to result in energy savings as large as those that would be achieved by
the standard levels under consideration.
DOE continues to seek input from businesses that would be affected
by this rulemaking and will consider comments received in the
development of any final rule.
5. Significant Issues Raised by Public Comments
DOE's MIA suggests that, while TSL1, TSL1, and TSL 2 presents
greater difficulties for small businesses than lower levels in the
liquid-immersed, LVDT, and MVDT superclasses, respectively, the impacts
at higher TSLs would be greater. DOE expects that small businesses will
generally be able to profitably compete at the TSL proposed in today's
rulemaking. DOE's MIA is based on its interviews of both small and
large manufacturers, and consideration of small business impacts
explicitly enters into DOE's choice of the TSLs proposed in this NOPR.
DOE also notes that today's proposed standards can be met with a
variety of materials, including multiple core steels and both copper
and aluminum windings. Because the proposed TSLs can be met with a
variety of materials, DOE does not expect that material availability
issues will be a problem for the industry that results from this
rulemaking.
ACEEE submitted a comment stating that small, medium-voltage dry-
type manufacturers would not be forced out of business at higher
standard levels because they could either install the necessary
mitering equipment or purchase finished cores. (ACEEE, No. 127 at p. 9)
DOE recognizes both of these possibilities. While DOE agrees that
standard levels higher than TSL2 would not necessarily drivel small
businesses from the market, there is much more uncertainty about
whether traditional M-grade steels can be used at higher TSLs, which
could disproportionately jeopardize many small manufacturers who have
limited access to domain refined steels.
6. Steps DOE Has Taken to Minimize the Economic Impact on Small
Manufacturers
In consideration of the benefits and burdens of standards,
including the burdens posed to small manufacturers, DOE concluded TSL1
is the highest level that can be justified for liquid immersed and low-
voltage dry-type transformers and TSL2 is the highest level that can be
justified for medium-voltage, dry-type transformers. As explained in
part 6 of the IRFA, ``Significant Alternatives to the Rule,'' DOE
explicitly considered the impacts on small manufacturers of liquid
immersed and dry-type transformers in selecting the TSLs proposed in
today's rulemaking, rather than selecting a higher trial standard
level. It is DOE's belief that levels at TSL3 or higher would place
excessive burdens on small manufacturers of medium-voltage, dry-type
transformers, as would TSL 2 or higher for liquid immersed and low-
voltage dry-type transformers. Such burdens would include large product
redesign costs and also operational problems associated with the
extremely thin laminations of core steel that would be needed to meet
these levels and advanced core construction equipment and tooling. For
low-voltage dry-type specifically, TSL2 essentially eliminates butt-lap
core designs and will therefore put more burden on small manufacturers
than would TSL1. However, the differential impact on small businesses
(versus large businesses) is expected to be lower in moving to TSL1
than in moving from TSL2 to TSL3 because of the likely need to employ
step lap mitering or wound core designs. Similarly, for medium voltage
dry-type, the steels and construction techniques likely to be used at
TSL 2 are already commonplace in the market, whereas TSL 3 would likely
trigger a more dramatic shift to thinner and more exotic steels, to
which many small businesses have limited access. Lastly, DOE is
confident that TSL1 for the liquid immersed market would not require
small manufacturers to invest in amorphous technology, which could put
them at a significant disadvantage.
Section VI.B above discusses how small business impacts entered
into DOE's selection of today's proposed standards for distribution
transformers. DOE made its decision regarding standards by beginning
with the highest level considered and successively eliminating TSLs
until it found a TSL
[[Page 7375]]
that is both technologically feasible and economically justified,
taking into account other EPCA criteria. Because DOE believes that the
TSLs proposed are economically justified (including consideration of
small business impacts), the reduced impact on small businesses that
would have been realized in moving down to lower efficiency levels was
not considered in DOE's decision (but the reduced impact on small
businesses that is realized in moving down to TSL2 from TSL3 (in the
case of medium-voltage dry-type) and TSL2 to TSL1 (in the case of
liquid immersed and low-voltage dry-type) was explicitly considered in
the weighing of benefits and burdens).
C. Review Under the Paperwork Reduction Act
Manufacturers of distribution transformers must certify to DOE that
their products comply with any applicable energy conservation
standards. In certifying compliance, manufacturers must test their
products according to the DOE test procedures for distribution
transformers, including any amendments adopted for those test
procedures. DOE has established regulations for the certification and
recordkeeping requirements for all covered consumer products and
commercial equipment, including distribution transformers. (76 FR 12422
(March 7, 2011). The collection-of-information requirement for the
certification and recordkeeping is subject to review and approval by
OMB under the Paperwork Reduction Act (PRA). This requirement has been
approved by OMB under OMB control number 1910-1400. Public reporting
burden for the certification is estimated to average 20 hours per
response, including the time for reviewing instructions, searching
existing data sources, gathering and maintaining the data needed, and
completing and reviewing the collection of information.
Notwithstanding any other provision of the law, no person is
required to respond to, nor shall any person be subject to a penalty
for failure to comply with, a collection of information subject to the
requirements of the PRA, unless that collection of information displays
a currently valid OMB Control Number.
D. Review Under the National Environmental Policy Act of 1969
Pursuant to the National Environmental Policy Act (NEPA) of 1969,
as amended (42 U.S.C. 4321 et seq.), DOE has determined that the
proposed rule fits within the category of actions included in
Categorical Exclusion (CX) B5.1 and otherwise meets the requirements
for application of a CX. (See 10 CFR 1021.410(b) and Appendix B to
Subpart D) The proposed rule fits within this category of actions
because it is a rulemaking that establishes energy conservation
standards for consumer products or industrial equipment, and for which
none of the exceptions identified in CX B5.1(b) apply. Therefore, DOE
has made a CX determination for this rulemaking, and DOE does not need
to prepare an Environmental Assessment or Environmental Impact
Statement for this proposed rule. DOE's CX determination for this
proposed rule is available at http://cxnepa.energy.gov.
E. Review Under Executive Order 13132
Executive Order 13132, ``Federalism,'' 64 FR 43255 (Aug. 10, 1999)
imposes certain requirements on Federal agencies formulating and
implementing policies or regulations that preempt State law or that
have Federalism implications. The Executive Order requires agencies to
examine the constitutional and statutory authority supporting any
action that would limit the policymaking discretion of the States and
to carefully assess the necessity for such actions. The Executive Order
also requires agencies to have an accountable process to ensure
meaningful and timely input by State and local officials in the
development of regulatory policies that have Federalism implications.
On March 14, 2000, DOE published a statement of policy describing the
intergovernmental consultation process it will follow in the
development of such regulations. 65 FR 13735. EPCA governs and
prescribes Federal preemption of State regulations as to energy
conservation for the products that are the subject of today's proposed
rule. States can petition DOE for exemption from such preemption to the
extent, and based on criteria, set forth in EPCA. (42 U.S.C. 6297) No
further action is required by Executive Order 13132.
F. Review Under Executive Order 12988
With respect to the review of existing regulations and the
promulgation of new regulations, section 3(a) of Executive Order 12988,
``Civil Justice Reform,'' imposes on Federal agencies the general duty
to adhere to the following requirements: (1) Eliminate drafting errors
and ambiguity; (2) write regulations to minimize litigation; and (3)
provide a clear legal standard for affected conduct rather than a
general standard and promote simplification and burden reduction. 61 FR
4729 (Feb. 7, 1996). Section 3(b) of Executive Order 12988 specifically
requires that Executive agencies make every reasonable effort to ensure
that the regulation: (1) Clearly specifies the preemptive effect, if
any; (2) clearly specifies any effect on existing Federal law or
regulation; (3) provides a clear legal standard for affected conduct
while promoting simplification and burden reduction; (4) specifies the
retroactive effect, if any; (5) adequately defines key terms; and (6)
addresses other important issues affecting clarity and general
draftsmanship under any guidelines issued by the Attorney General.
Section 3(c) of Executive Order 12988 requires Executive agencies to
review regulations in light of applicable standards in section 3(a) and
section 3(b) to determine whether they are met or it is unreasonable to
meet one or more of them. DOE has completed the required review and
determined that, to the extent permitted by law, this proposed rule
meets the relevant standards of Executive Order 12988.
G. Review Under the Unfunded Mandates Reform Act of 1995
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA)
requires each Federal agency to assess the effects of Federal
regulatory actions on State, local, and Tribal governments and the
private sector. Public Law 104-4, sec. 201 (codified at 2 U.S.C. 1531).
For a proposed regulatory action likely to result in a rule that may
cause the expenditure by State, local, and Tribal governments, in the
aggregate, or by the private sector of $100 million or more in any one
year (adjusted annually for inflation), section 202 of UMRA requires a
Federal agency to publish a written statement that estimates the
resulting costs, benefits, and other effects on the national economy.
(2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal agency to
develop an effective process to permit timely input by elected officers
of State, local, and Tribal governments on a proposed ``significant
intergovernmental mandate,'' and requires an agency plan for giving
notice and opportunity for timely input to potentially affected small
governments before establishing any requirements that might
significantly or uniquely affect small governments. On March 18, 1997,
DOE published a statement of policy on its process for
intergovernmental consultation under UMRA. 62 FR 12820. DOE's policy
statement is also available at www.gc.doe.gov.
Although today's proposed rule does not contain a Federal
intergovernmental mandate, it may require expenditures of $100 million
or more on the private
[[Page 7376]]
sector. Specifically, the proposed rule will likely result in a final
rule that could require expenditures of $100 million or more. Such
expenditures may include: (1) Investment in R&D and in capital
expenditures by distribution transformer manufacturers in the years
between the final rule and the compliance date for the new standards,
and (2) incremental additional expenditures by consumers to purchase
higher-efficiency distribution transformers, starting at the compliance
date for the applicable standard.
Section 202 of UMRA authorizes a Federal agency to respond to the
content requirements of UMRA in any other statement or analysis that
accompanies the proposed rule. (2 U.S.C. 1532(c)) The content
requirements of section 202(b) of UMRA relevant to a private sector
mandate substantially overlap the economic analysis requirements that
apply under section 325(o) of EPCA and Executive Order 12866. The
SUPPLEMENTARY INFORMATION section of this NOPR and the ``Regulatory
Impact Analysis'' chapter of the TSD for this proposed rule respond to
those requirements.
Under section 205 of UMRA, the Department is obligated to identify
and consider a reasonable number of regulatory alternatives before
promulgating a rule for which a written statement under section 202 is
required. 2 U.S.C. 1535(a). DOE is required to select from those
alternatives the most cost-effective and least burdensome alternative
that achieves the objectives of the proposed rule unless DOE publishes
an explanation for doing otherwise, or the selection of such an
alternative is inconsistent with law. As required by 42 U.S.C. 6295(d),
(f), and (o), 6313(e), and 6316(a), today's proposed rule would
establish energy conservation standards for distribution transformers
that are designed to achieve the maximum improvement in energy
efficiency that DOE has determined to be both technologically feasible
and economically justified. A full discussion of the alternatives
considered by DOE is presented in the ``Regulatory Impact Analysis''
section of the TSD for today's proposed rule.
H. Review Under the Treasury and General Government Appropriations Act,
1999
Section 654 of the Treasury and General Government Appropriations
Act, 1999 (Pub. L. 105-277) requires Federal agencies to issue a Family
Policymaking Assessment for any rule that may affect family well-being.
This rule would not have any impact on the autonomy or integrity of the
family as an institution. Accordingly, DOE has concluded that it is not
necessary to prepare a Family Policymaking Assessment.
I. Review Under Executive Order 12630
DOE has determined that under Executive Order 12630, ``Governmental
Actions and Interference with Constitutionally Protected Property
Rights'' 53 FR 8859 (March 18, 1988), this regulation would not result
in any takings that might require compensation under the Fifth
Amendment to the U.S. Constitution.
J. Review Under the Treasury and General Government Appropriations Act,
2001
Section 515 of the Treasury and General Government Appropriations
Act, 2001 (44 U.S.C. 3516, note) provides for Federal agencies to
review most disseminations of information to the public under
guidelines established by each agency pursuant to general guidelines
issued by OMB. OMB's guidelines were published at 67 FR 8452 (February
22, 2002), and DOE's guidelines were published at 67 FR 62446 (October
7, 2002). DOE has reviewed today's NOPR under the OMB and DOE
guidelines and has concluded that it is consistent with applicable
policies in those guidelines.
K. Review Under Executive Order 13211
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 28355
(May 22, 2001)), requires Federal agencies to prepare and submit to
OIRA at OMB, a Statement of Energy Effects for any proposed significant
energy action. A ``significant energy action'' is defined as any action
by an agency that promulgates or is expected to lead to promulgation of
a final rule, and that: (1) Is a significant regulatory action under
Executive Order 12866, or any successor order; and (2) is likely to
have a significant adverse effect on the supply, distribution, or use
of energy, or (3) is designated by the Administrator of OIRA as a
significant energy action. For any proposed significant energy action,
the agency must give a detailed statement of any adverse effects on
energy supply, distribution, or use should the proposal be implemented,
and of reasonable alternatives to the action and their expected
benefits on energy supply, distribution, and use.
DOE has tentatively concluded that today's regulatory action, which
sets forth proposed energy conservation standards for distribution
transformers, is not a significant energy action because the proposed
standards are not likely to have a significant adverse effect on the
supply, distribution, or use of energy, nor has it been designated as
such by the Administrator at OIRA. Accordingly, DOE has not prepared a
Statement of Energy Effects on the proposed rule.
L. Review Under the Information Quality Bulletin for Peer Review
On December 16, 2004, OMB, in consultation with the Office of
Science and Technology Policy (OSTP), issued its Final Information
Quality Bulletin for Peer Review (the Bulletin). 70 FR 2664 (January
14, 2005). The Bulletin establishes that certain scientific information
shall be peer reviewed by qualified specialists before it is
disseminated by the Federal Government, including influential
scientific information related to agency regulatory actions. The
purpose of the bulletin is to enhance the quality and credibility of
the Government's scientific information. Under the Bulletin, the energy
conservation standards rulemaking analyses are ``influential scientific
information,'' which the Bulletin defines as scientific information the
agency reasonably can determine will have, or does have, a clear and
substantial impact on important public policies or private sector
decisions. 70 FR 2667.
In response to OMB's Bulletin, DOE conducted formal in-progress
peer reviews of the energy conservation standards development process
and analyses and has prepared a Peer Review Report pertaining to the
energy conservation standards rulemaking analyses. Generation of this
report involved a rigorous, formal, and documented evaluation using
objective criteria and qualified and independent reviewers to make a
judgment as to the technical/scientific/business merit, the actual or
anticipated results, and the productivity and management effectiveness
of programs and/or projects. The ``Energy Conservation Standards
Rulemaking Peer Review Report'' dated February 2007 has been
disseminated and is available at the following Web site:
www1.eere.energy.gov/buildings/appliance_standards/peer_review.html.
VII. Public Participation
A. Attendance at the Public Meeting
The time, date, and location of the public meeting are listed in
the DATES and ADDRESSES sections at the beginning of this notice. If
you plan to attend the public meeting, please notify Ms. Brenda Edwards
at (202) 586-2945 or
[[Page 7377]]
[email protected]. As explained in the ADDRESSES section,
foreign nationals visiting DOE Headquarters are subject to advance
security screening procedures. Please also note that anyone that wishes
to bring a laptop computer into the Forrestal Building will be required
to obtain a property pass. Otherwise, visitors should avoid bringing
laptops, or allow an extra 45 minutes.
In addition, you can attend the public meeting via webinar. Webinar
registration information, participant instructions, and information
about the capabilities available to webinar participants will be
published on DOE's Web site at: http://www1.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html.
Participants are responsible for ensuring their systems are compatible
with the webinar software.
All documents in the docket are listed in the www.regulations.gov
index. However, not all documents listed in the index may be publicly
available, such as information that is exempt from public disclosure.
The regulations.gov web page will contain simple instructions on how to
access all documents, including public comments, in the docket. See
section B for further information on how to submit comments through
www.regulations.gov.
B. Procedure for Submitting Prepared General Statements for
Distribution
Any person who has plans to present a prepared general statement
may request that copies of his or her statement be made available at
the public meeting. Such persons may submit requests, along with an
advance electronic copy of their statement in PDF (preferred),
Microsoft Word or Excel, WordPerfect, or text (ASCII) file format, to
the appropriate address shown in the ADDRESSES section at the beginning
of this notice. The request and advance copy of statements must be
received at least one week before the public meeting and may be
emailed, hand-delivered, or sent by mail. DOE prefers to receive
requests and advance copies via email. Please include a telephone
number to enable DOE staff to make follow-up contact, if needed.
C. Conduct of the Public Meeting
DOE will designate a DOE official to preside at the public meeting
and may also use a professional facilitator to aid discussion. The
meeting will not be a judicial or evidentiary-type public hearing, but
DOE will conduct it in accordance with section 336 of EPCA (42 U.S.C.
6306). A court reporter will be present to record the proceedings and
prepare a transcript. DOE reserves the right to schedule the order of
presentations and to establish the procedures governing the conduct of
the public meeting. After the public meeting, interested parties may
submit further comments on the proceedings as well as on any aspect of
the rulemaking until the end of the comment period.
The public meeting will be conducted in an informal, conference
style. DOE will present summaries of comments received before the
public meeting, allow time for prepared general statements by
participants, and encourage all interested parties to share their views
on issues affecting this rulemaking. Each participant will be allowed
to make a general statement (within time limits determined by DOE),
before the discussion of specific topics. DOE will allow, as time
permits, other participants to comment briefly on any general
statements.
At the end of all prepared statements on a topic, DOE will permit
participants to clarify their statements briefly and comment on
statements made by others. Participants should be prepared to answer
questions by DOE and by other participants concerning these issues. DOE
representatives may also ask questions of participants concerning other
matters relevant to this rulemaking. The official conducting the public
meeting will accept additional comments or questions from those
attending, as time permits. The presiding official will announce any
further procedural rules or modification of the above procedures that
may be needed for the proper conduct of the public meeting.
A transcript of the public meeting will be included in the docket,
which can be viewed as described in the Docket section at the beginning
of this notice. In addition, any person may buy a copy of the
transcript from the transcribing reporter.
D. Submission of Comments
DOE will accept comments, data, and information regarding this
proposed rule before or after the public meeting, but no later than the
date provided in the DATES section at the beginning of this proposed
rule. Interested parties may submit comments, data, and other
information using any of the methods described in the ADDRESSES section
at the beginning of this notice.
Submitting comments via regulations.gov. The regulations.gov web
page will require you to provide your name and contact information.
Your contact information will be viewable to DOE Building Technologies
staff only. Your contact information will not be publicly viewable
except for your first and last names, organization name (if any), and
submitter representative name (if any). If your comment is not
processed properly because of technical difficulties, DOE will use this
information to contact you. If DOE cannot read your comment due to
technical difficulties and cannot contact you for clarification, DOE
may not be able to consider your comment.
However, your contact information will be publicly viewable if you
include it in the comment itself or in any documents attached to your
comment. Any information that you do not want to be publicly viewable
should not be included in your comment, nor in any document attached to
your comment. Persons viewing comments will see only first and last
names, organization names, correspondence containing comments, and any
documents submitted with the comments.
Do not submit to regulations.gov information for which disclosure
is restricted by statute, such as trade secrets and commercial or
financial information (hereinafter referred to as Confidential Business
Information (CBI)). Comments submitted through regulations.gov cannot
be claimed as CBI. Comments received through the Web site will waive
any CBI claims for the information submitted. For information on
submitting CBI, see the Confidential Business Information section
below.
DOE processes submissions made through regulations.gov before
posting. Normally, comments will be posted within a few days of being
submitted. However, if large volumes of comments are being processed
simultaneously, your comment may not be viewable for up to several
weeks. Please keep the comment tracking number that regulations.gov
provides after you have successfully uploaded your comment.
Submitting comments via email, hand delivery/courier, or mail.
Comments and documents submitted via email, hand delivery, or mail also
will be posted to regulations.gov. If you do not want your personal
contact information to be publicly viewable, do not include it in your
comment or any accompanying documents. Instead, provide your contact
information in a cover letter. Include your first and last names, email
address, telephone number, and optional mailing address. The cover
letter will not be publicly viewable as long as it does not include any
comments.
Include contact information each time you submit comments, data,
documents,
[[Page 7378]]
and other information to DOE. If you submit via mail or hand delivery/
courier, please provide all items on a CD, if feasible. It is not
necessary to submit printed copies. No facsimiles (faxes) will be
accepted.
Comments, data, and other information submitted to DOE
electronically should be provided in PDF (preferred), Microsoft Word or
Excel, WordPerfect, or text (ASCII) file format. Provide documents that
are not secured, that are written in English, and that are free of any
defects or viruses. Documents should not contain special characters or
any form of encryption and, if possible, they should carry the
electronic signature of the author.
Campaign form letters. Please submit campaign form letters by the
originating organization in batches of between 50 to 500 form letters
per PDF or as one form letter with a list of supporters' names compiled
into one or more PDFs. This reduces comment processing and posting
time.
Confidential Business Information. According to 10 CFR 1004.11, any
person submitting information that he or she believes to be
confidential and exempt by law from public disclosure should submit via
email, postal mail, or hand delivery/courier two well-marked copies:
one copy of the document marked confidential including all the
information believed to be confidential, and one copy of the document
marked non-confidential with the information believed to be
confidential deleted. Submit these documents via email or on a CD, if
feasible. DOE will make its own determination about the confidential
status of the information and treat it according to its determination.
Factors of interest to DOE when evaluating requests to treat
submitted information as confidential include: (1) A description of the
items; (2) whether and why such items are customarily treated as
confidential within the industry; (3) whether the information is
generally known by or available from other sources; (4) whether the
information has previously been made available to others without
obligation concerning its confidentiality; (5) an explanation of the
competitive injury to the submitting person which would result from
public disclosure; (6) when such information might lose its
confidential character due to the passage of time; and (7) why
disclosure of the information would be contrary to the public interest.
It is DOE's policy that all comments may be included in the public
docket, without change and as received, including any personal
information provided in the comments (except information deemed to be
exempt from public disclosure).
E. Issues on Which DOE Seeks Comment
Although DOE welcomes comments on any aspect of this proposal, DOE
is particularly interested in receiving comments and views of
interested parties concerning the following issues:
1. DOE requests comment on primary and secondary winding
configurations, on how testing should be required, on efficiency
differences related to different winding configurations, and on how
frequently transformers are operated in various winding configurations.
2. DOE requests comment on its proposal to require transformers
with multiple nameplate kVA ratings to comply only at those ratings
corresponding to passive cooling.
3. DOE requests comment on its proposal to maintain the requirement
that transformers comply with standards for the BIL rating of the
configuration that produces the highest losses.
4. DOE requests comment on its proposal to maintain the current
test loading value requirements for all types of distribution
transformers.
5. DOE requests comment on its proposal to require rectifier and
testing transformers to indicate on their nameplates that they are for
such purposes exclusively.
6. DOE requests comment on its proposal to maintain the definition
of mining transformer but also requests information useful in precisely
expanding the definition to encompass any activity that entails the
removal of material underground, such as digging or tunneling.
7. DOE requests comment on its proposal to maintain the current kVA
scope of coverage.
8. DOE requests comment on its proposal to continue not to set
standards for step-up transformers.
9. DOE requests comment on the negotiating committee's proposal to
establish a separate equipment class for network/vault transformers and
on how such transformers might be defined.
10. DOE requests comment on the negotiating committee's proposal to
establish a separate equipment class for data center transformers and
on how such transformers might be defined.
11. DOE seeks comment on the operating characteristics for data
center transformers. Specifically DOE seeks comment on appropriate load
factors, and peak responsibility factors of data center transformers.
12. DOE requests comment on whether separate equipment classes are
warranted for pole-mounted, pad-mounted, or other types of liquid-
immersed transformers.
13. DOE requests comment on setting standards by BIL rating for
liquid-immersed distribution transformers as it currently does for
medium-voltage, dry-type units.
14. DOE requests comment on how best to scale across phase counts
for each transformer type and how standards for either single- or
three-phase transformers may be derived from the other type.
15. DOE requests comment on its proposal to scale standards to
unanalyzed kVA ratings by fitting a straight line in logarithmic space
to selected efficiency levels (ELs) with the understanding that the
resulting line may not have a slope equal to 0.75.
16. DOE seeks comment on symmetric core designs.
17. DOE seeks comment on nanotechnology composites and their
potential for use in distribution transformers.
18. DOE requests comment on its materials prices for both 2010 and
2011 cases.
19. DOE requests comment on the current and future availabilities
of high-grade steels, particularly amorphous and mechanically-scribed
steel in the United States.
20. DOE requests comment on particular applications in which
transformer size and weight are likely to be a constraint and any data
that may be used to characterize the problem.
21. DOE requests comment on its steel supply availability analysis,
presented in appendix 3A of the TSD.
22. DOE seeks comment on its proposed additional distribution
channel for liquid-immersed transformers that estimates that
approximately 80 percent of transformers are sold by manufacturers
directly to utilities.
23. DOE seeks comment on any additional sources of distribution
transformer load data that could be used to validate the Energy Use and
End-Use Load Characterization analysis. DOE is specifically interested
in additional load data for higher capacity three phase distribution
transformers.
24. DOE seeks comment on its pole replacement methodology that is
used estimate increased installation costs resulting from increased
transformer weight due the proposed standard. The pole replacement
methodology is presented in chapter 6, section 6.3.1 of the TSD.
25. DOE seeks comment on recent changes to utility distribution
transformer purchase practices that would lead to the purchase of a
[[Page 7379]]
refurbished, specifically re-wound, distribution transformer over the
purchase of new distribution transformer.
26. DOE seeks comment on the equipment lifetimes of refurbished,
specifically re-wound distribution transformers and how it compares to
that of a new distribution transformer.
27. DOE seeks comment on recent changes in distribution transformer
sizing practices. In particular, DOE would like comments on any
additional sources of data regarding trends in market share across
equipment classes for either liquid-immersed or dry-type transformers
that should be considered in the analysis.
28. DOE requests comment on the possibility of reduced equipment
utility or performance resulting from today's proposed standards,
particularly the risk of reducing the ability to perform periodic
maintenance and the risk of increasing vibration and acoustic noise.
29. DOE requests comment and corroborating data on how often
distribution transformers are operated with their primary and secondary
windings in different configurations, and on the magnitude of the
additional losses in less efficient configurations.
30. DOE requests comment on impedance values and on any related
parameters (e.g., inrush current, X/R ratio) that may be used in
evaluation of distribution transformers. DOE requests particular
comment on how any of those parameters may be affected by energy
conservation standards of today's proposed levels or higher.
Approval of the Office of the Secretary
The Secretary of Energy has approved publication of today's
proposed rule.
List of Subjects in 10 CFR Part 431
Administrative practice and procedure, Confidential business
information, Energy conservation, Household appliances, Imports,
Intergovernmental relations, Reporting and recordkeeping requirements,
and Small businesses.
Issued in Washington, DC, on January 31, 2012.
Henry Kelly,
Acting Assistant Secretary of Energy, Energy Efficiency and Renewable
Energy.
For the reasons set forth in the preamble, DOE proposes to amend
part 431 of chapter II, of title 10 of the Code of Federal Regulations,
to read as set forth below:
PART 431--ENERGY EFFICIENCY PROGRAM FOR CERTAIN COMMERCIAL AND
INDUSTRIAL EQUIPMENT
1. The authority citation for part 431 continues to read as
follows:
Authority: 42 U.S.C. 6291-6317.
2. Revise Sec. 431.196 to read as follows:
Sec. 431.196 Energy conservation standards and their effective dates.
(a) Low-Voltage Dry-Type Distribution Transformers. (1) The
efficiency of a low-voltage dry-type distribution transformer
manufactured on or after January 1, 2007, but before January 1, 2016,
shall be no less than that required for their kVA rating in the table
below. Low-voltage dry-type distribution transformers with kVA ratings
not appearing in the table shall have their minimum efficiency level
determined by linear interpolation of the kVA and efficiency values
immediately above and below that kVA rating.
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA % kVA %
----------------------------------------------------------------------------------------------------------------
15........................................ 97.7 15........................... 97.0
25........................................ 98.0 30........................... 97.5
37.5...................................... 98.2 45........................... 97.7
50........................................ 98.3 75........................... 98.0
75........................................ 98.5 112.5........................ 98.2
100....................................... 98.6 150.......................... 98.3
167....................................... 98.7 225.......................... 98.5
250....................................... 98.8 300.......................... 98.6
333....................................... 98.9 500.......................... 98.7
750.......................... 98.8
1000......................... 98.9
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test-
Procedure. 10 CFR part 431, Subpart K, Appendix A.
(2) The efficiency of a low-voltage dry-type distribution
transformer manufactured on or after January 1, 2016, shall be no less
than that required for their kVA rating in the table below. Low-voltage
dry-type distribution transformers with kVA ratings not appearing in
the table shall have their minimum efficiency level determined by
linear interpolation of the kVA and efficiency values immediately above
and below that kVA rating.
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA % kVA %
----------------------------------------------------------------------------------------------------------------
15........................................ 97.73 15........................... 97.44
25........................................ 98.00 30........................... 97.95
37.5...................................... 98.20 45........................... 98.20
50........................................ 98.31 75........................... 98.47
75........................................ 98.50 112.5........................ 98.66
100....................................... 98.60 150.......................... 98.78
167....................................... 98.75 225.......................... 98.92
250....................................... 98.87 300.......................... 99.02
333....................................... 98.94 500.......................... 99.17
750.......................... 99.27
[[Page 7380]]
1000......................... 99.34
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test-
Procedure. 10 CFR part 431, Subpart K, Appendix A.
(b) Liquid-Immersed Distribution Transformers. (1) The efficiency
of a liquid-immersed distribution transformer manufactured on or after
January 1, 2010, but before January 1, 2016, shall be no less than that
required for their kVA rating in the table below. Liquid-immersed
distribution transformers with kVA ratings not appearing in the table
shall have their minimum efficiency level determined by linear
interpolation of the kVA and efficiency values immediately above and
below that kVA rating.
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA % kVA %
----------------------------------------------------------------------------------------------------------------
10........................................ 98.70 15........................... 98.65
15........................................ 98.82 30........................... 98.83
25........................................ 98.95 45........................... 98.92
37.5...................................... 99.05 75........................... 99.03
50........................................ 99.11 112.5........................ 99.11
75........................................ 99.19 150.......................... 99.16
100....................................... 99.25 225.......................... 99.23
167....................................... 99.33 300.......................... 99.27
250....................................... 99.39 500.......................... 99.35
333....................................... 99.43 750.......................... 99.40
500....................................... 99.49 1000......................... 99.43
.................. 1500......................... 99.48
----------------------------------------------------------------------------------------------------------------
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.
(2) The efficiency of a liquid-immersed distribution transformer
manufactured on or after January 1, 2016, shall be no less than that
required for their kVA rating in the table below. Liquid-immersed
distribution transformers with kVA ratings not appearing in the table
shall have their minimum efficiency level determined by linear
interpolation of the kVA and efficiency values immediately above and
below that kVA rating.
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
10........................................ 98.62 15........................... 98.36
15........................................ 98.76 30........................... 98.62
25........................................ 98.91 45........................... 98.76
37.5...................................... 99.01 75........................... 98.91
50........................................ 99.08 112.5........................ 99.01
75........................................ 99.17 150.......................... 99.08
100....................................... 99.23 225.......................... 99.17
167....................................... 99.25 300.......................... 99.23
250....................................... 99.32 500.......................... 99.25
333....................................... 99.36 750.......................... 99.32
500....................................... 99.42 1000......................... 99.36
667....................................... 99.46 1500......................... 99.42
833....................................... 99.49 2000......................... 99.46
.................. 2500......................... 99.49
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-
Procedure. 10 CFR part 431, Subpart K, Appendix A.
(c) Medium-Voltage Dry-Type Distribution Transformers. (1) The
efficiency of a medium- voltage dry-type distribution transformer
manufactured on or after January 1, 2010, but before January 1, 2016,
shall be no less than that required for their kVA and BIL rating in the
table below. Medium-voltage dry-type distribution transformers with kVA
ratings not appearing in the table shall have their minimum efficiency
level determined by linear interpolation of the kVA and efficiency
values immediately above and below that kVA rating.
[[Page 7381]]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-Phase Three-Phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
BIL* 20-45 kV 46-95 kV >=96 kV BIL* 20-45 kV 46-95 kV >=96 kV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency Efficiency Efficiency Efficiency Efficiency Efficiency
kVA (%) (%) (%) kVA (%) (%) (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15..................................... 98.10 97.86 .............. 15....................... 97.50 97.18 ............
25..................................... 98.33 98.12 .............. 30....................... 97.90 97.63 ............
37.5................................... 98.49 98.30 .............. 45....................... 98.10 97.86 ............
50..................................... 98.60 98.42 .............. 75....................... 98.33 98.13 ............
75..................................... 98.73 98.57 98.53 112.5.................... 98.52 98.36 ............
100.................................... 98.82 98.67 98.63 150...................... 98.65 98.51 ............
167.................................... 98.96 98.83 98.80 225...................... 98.82 98.69 98.57
250.................................... 99.07 98.95 98.91 300...................... 98.93 98.81 98.69
333.................................... 99.14 99.03 98.99 500...................... 99.09 98.99 98.89
500.................................... 99.22 99.12 99.09 750...................... 99.21 99.12 99.02
667.................................... 99.27 99.18 99.15 1000..................... 99.28 99.20 99.11
833.................................... 99.31 99.23 99.20 1500..................... 99.37 99.30 99.21
............ ............ .............. 2000..................... 99.43 99.36 99.28
............ ............ .............. 2500..................... 99.47 99.41 99.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
* BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR part 431, Subpart K,
Appendix A.
(2) The efficiency of a medium- voltage dry-type distribution
transformer manufactured on or after January 1, 2016, shall be no less
than that required for their kVA and BIL rating in the table below.
Medium-voltage dry-type distribution transformers with kVA ratings not
appearing in the table shall have their minimum efficiency level
determined by linear interpolation of the kVA and efficiency values
immediately above and below that kVA rating.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-Phase Three-Phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
BIL* 20-45 kV 46-95 kV >=96 kV BIL* 20-45 kV 46-95 kV >=96 kV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency Efficiency Efficiency Efficiency Efficiency
kVA (%) (%) Efficiency (%) kVA (%) (%) (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15..................................... 98.10 97.86 .............. 15....................... 97.50 97.18 ............
25..................................... 98.33 98.12 .............. 30....................... 97.90 97.63 ............
37.5................................... 98.49 98.30 .............. 45....................... 98.10 97.86 ............
50..................................... 98.60 98.42 .............. 75....................... 98.33 98.12 ............
75..................................... 98.73 98.57 98.53 112.5.................... 98.49 98.30 ............
100.................................... 98.82 98.67 98.63 150...................... 98.60 98.42 ............
167.................................... 98.96 98.83 98.80 225...................... 98.73 98.57 98.53
250.................................... 99.07 98.95 98.91 300...................... 98.82 98.67 98.63
333.................................... 99.14 99.03 98.99 500...................... 98.96 98.83 98.80
500.................................... 99.22 99.12 99.09 750...................... 99.07 98.95 98.91
667.................................... 99.27 99.18 99.15 1000..................... 99.14 99.03 98.99
833.................................... 99.31 99.23 99.20 1500..................... 99.22 99.12 99.09
............ ............ .............. 2000..................... 99.27 99.18 99.15
............ ............ .............. 2500..................... 99.31 99.23 99.20
--------------------------------------------------------------------------------------------------------------------------------------------------------
* BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR part 431, Subpart K,
Appendix A.
(d) Underground Mining Distribution Transformers. [Reserved]
[FR Doc. 2012-2642 Filed 2-9-12; 8:45 am]
BILLING CODE 6450-01-P