```

[Federal Register Volume 77, Number 28 (Friday, February 10, 2012)]
[Proposed Rules]
[Pages 7282-7381]
From the Federal Register Online via the Government Printing 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.

-----------------------------------------------------------------------

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: DistributionTransformers-2010-STD-0048@ee.doe.gov. 
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 
Chad_S_Whiteman@omb.eop.gov.
    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: Jim.Raba@ee.doe.gov.
    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: Ami.Grace-Tardy@hq.doe.gov.

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

[[Page 7284]]

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\
---------------------------------------------------------------------------

    \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)
----------------------------------------------------------------------------------------------------------------
                                                                           Phase                       Proposed
         Equipment class              Design line            Type          count          BIL            TSL
----------------------------------------------------------------------------------------------------------------
1...............................  1, 2 and 3........  Liquid-immersed...        1  Any.............            1
2...............................  4 and 5...........  Liquid-immersed...        3  Any.............           1
----------------------------------------------------------------------------------------------------------------
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)
----------------------------------------------------------------------------------------------------------------
                                                                           Phase                       Proposed
         Equipment class              Design line            Type          count          BIL            TSL
----------------------------------------------------------------------------------------------------------------
3...............................  6.................  Low-voltage, dry-         1  =96 kV                     2
                                                       dry-type.
10..............................  13A and 13B.......  Medium-voltage,           3  >=96 kV                    2
                                                       dry-type.
----------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
                                                                    Proposed
                 Type                   Design line  Phase count      TSL           Energy efficiency level
----------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------

[[Page 7285]]

 Table I.5--Proposed Electrical Efficiencies for all Liquid-Immersed Distribution Transformer Equipment Classes
                                      (Compliance Starting January 1, 2016)
----------------------------------------------------------------------------------------------------------------
                                      Standards by kVA and equipment class
-----------------------------------------------------------------------------------------------------------------
                       Equipment class 1                                        Equipment class 2
----------------------------------------------------------------------------------------------------------------
                     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
----------------------------------------------------------------------------------------------------------------

   Table I.6--Proposed Electrical Efficiencies for all Low-Voltage Dry-Type Distribution Transformer Equipment
                                  Classes (Compliance Starting January 1, 2016)
----------------------------------------------------------------------------------------------------------------
                                      Standards 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
----------------------------------------------------------------------------------------------------------------

                  Table I.7--Proposed Electrical Efficiencies for all Medium-Voltage Dry-Type Distribution Transformer Equipment Classes (Compliance Starting January 1, 2016)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Standards by kVA and equipment class
-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
             Equipment class 5                    Equipment class 6              Equipment class 7             Equipment class 8             Equipment class 9            Equipment class 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
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 7286]]

A. Benefits and Costs to Consumers \4\
---------------------------------------------------------------------------

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

    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)
------------------------------------------------------------------------
                             Liquid-Immersed
------------------------------------------------------------------------
1.............................................           36         20.2
2.............................................        * N/A        * N/A
3.............................................        2,413          6.3
4.............................................          862          5.0
5.............................................        7,787          4.0
------------------------------------------------------------------------
                          Low-Voltage, Dry-Type
------------------------------------------------------------------------
6.............................................        * N/A        * N/A
7.............................................        1,714          4.5
8.............................................        2,476          8.4
------------------------------------------------------------------------
                        Medium-Voltage, Dry-Type
------------------------------------------------------------------------
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
------------------------------------------------------------------------
* 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\
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

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

    \28\ See http://www1.eere.energy.gov/buildings/appliance_standards/commercial/ac_hp.html.
---------------------------------------------------------------------------

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

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]]

Brenda.Edwards@ee.doe.gov. 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
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