[Federal Register Volume 78, Number 75 (Thursday, April 18, 2013)]
[Rules and Regulations]
[Pages 23336-23436]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2013-08712]



[[Page 23335]]

Vol. 78

Thursday,

No. 75

April 18, 2013

Part II





Department of Energy





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10 CFR Part 431





 Energy Conservation Program: Energy Conservation Standards for 
Distribution Transformers; Final Rule

  Federal Register / Vol. 78 , No. 75 / Thursday, April 18, 2013 / 
Rules and Regulations  

[[Page 23336]]


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DEPARTMENT OF ENERGY

10 CFR Part 431

[Docket No. 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: Final rule.

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

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 
distribution transformers. EPCA also requires the U.S. Department of 
Energy (DOE) to determine whether more-stringent standards would be 
technologically feasible and economically justified, and would save a 
significant amount of energy. In this final rule, DOE is adopting more-
stringent energy conservation standards for distribution transformers. 
It has determined that the amended energy conservation standards for 
this equipment would result in significant conservation of energy, and 
are technologically feasible and economically justified.

DATES: The effective date of this rule is June 17, 2013. Compliance 
with the amended standards established for distribution transformers in 
this final rule is required as of January 1, 2016.

ADDRESSES: The docket for this rulemaking is available for review at 
www.regulations.gov, including Federal Register notices, framework 
documents, public meeting attendee lists and transcripts, comments, 
negotiated rulemaking, and other supporting documents/materials. 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.
    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. 
The regulations.gov Web page will contain simple instructions on how to 
access all documents, including public comments, in the docket.
    For further information on how to review the docket, contact Ms. 
Brenda Edwards at (202) 586-2945 or by email: 
[email protected].

FOR FURTHER INFORMATION CONTACT: 
James Raba, U.S. Department of Energy, Office of Energy Efficiency and 
Renewable Energy, Building Technologies Program, EE-2J, 1000 
Independence Avenue SW., Washington, DC, 20585-0121. Telephone: (202) 
586-8654. Email: [email protected].
Ami Grace-Tardy, U.S. Department of Energy, Office of the General 
Counsel, GC-71, 1000 Independence Avenue SW., Washington, DC, 20585-
0121. Telephone: (202) 586-5709. Email: [email protected].

SUPPLEMENTARY INFORMATION: 

Table of Contents

I. Summary of the Final Rule and Its Benefits
    A. Benefits and Costs to Customers
    B. Impact on Manufacturers
    C. National Benefits
    D. Conclusion
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 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 Equipment
    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 and Surface Mining Transformer Coverage
    c. Step-Up Transformers
    d. Low-Voltage Dry-Type Distribution Transformers
    e. Negotiating Committee Discussion of Scope
    2. Equipment Classes
    a. Less-Flammable Liquid-Immersed Transformers
    b. Pole-Mounted Liquid-Immersed Distribution Transformers
    c. Network and Vault Liquid-Immersed Distribution Transformers
    d. BIL Ratings in Liquid-Immersed Distribution Transformers
    e. Data Center Transformers
    f. Noise and Vibration
    g. Multivoltage Capability
    h. Consumer Utility
    3. Technology Options
    a. Core Deactivation
    b. Symmetric Core
    c. Intellectual Property
    d. Core Construction Technique
    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
    a. kVA Scaling
    b. Phase Count Scaling
    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
    i. Inputs to Payback Period Analysis
    j. Rebuttable-Presumption Payback Period
    G. National Impact Analysis--National Energy Savings and Net 
Present Value Analysis
    1. Shipments
    2. Efficiency Trends
    3. National Energy Savings
    4. Equipment Price Forecast
    5. Net Present Value of Customer Benefit
    H. Customer Subgroup Analysis
    I. Manufacturer Impact Analysis
    1. Overview
    2. Product and Capital Conversion Costs
    a. Product Conversion Costs
    b. Capital Conversion Costs
    3. Markup Scenarios
    4. Other Key GRIM Inputs
    5. Discussion of Comments
    a. Core Steel
    b. Small Manufacturers
    c. Conversion Costs
    6. Manufacturer Interviews

[[Page 23337]]

    7. Sub-Group Impact Analysis
    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. Labeling Requirements
    O. Discussion of Other Comments
    1. Supplementary Trial Standard Levels
    2. Efficiency Levels
    3. Impact of Standards on Transformer Refurbishment
    4. Alternative Means of Saving Energy
    5. Alternative Rulemaking Procedures
    6. Proposed Standards--Weighting of Benefits vs. Burdens
    a. General Comments
    b. Standards on Liquid-Immersed Distribution Transformers
    c. Standards on Low-Voltage Dry-Type Distribution Transformers
    d. Standards on Medium-Voltage Dry-Type Distribution 
Transformers
    e. Response to Comments on Standards Proposed in Notice of 
Proposed Rulemaking
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. Conclusion
    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 Today's 
Standards
VI. Procedural Issues and Regulatory Review
    A. Review Under Executive Orders 12866 and 13563
    B. Review Under the Regulatory Flexibility Act
    1. Statement of the Need for, and Objectives of, the Rule
    2. Summary of and Responses to the Significant Issues Raised by 
the Public Comments, and a Statement of Any Changes Made as a Result 
of Such Comments
    3. Description and Estimated Number of Small Entities Regulated
    a. Methodology for Estimating the Number of Small Entities
    b. Distribution Transformer Industry Structure
    c. Comparison Between Large and Small Entities
    4. Description and Estimate of Compliance Requirements
    a. Liquid-Immersed
    b. Low-Voltage Dry-Type
    c. Medium-Voltage Dry-Type
    d. Summary of Compliance Impacts
    5. Steps Taken To Minimize Impacts on Small Entities and Reasons 
Why Other Significant Alternatives to Today's Final Rule Were 
Rejected
    6. Duplication, Overlap, and Conflict With Other Rules and 
Regulations
    7. Significant Alternatives to Today's Rule
    8. Significant Issues Raised by Public Comments
    9. 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
    M. Congressional Notification
VII. Approval of the Office of the Secretary

I. Summary of the Final Rule and Its Benefits

    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 DOE prescribes for 
certain equipment, such as distribution transformers, shall be designed 
to achieve the maximum improvement in energy efficiency that DOE 
determines is technologically feasible and economically justified. (42 
U.S.C. 6295(o)(2)(A), 6316(a)) Furthermore, any new or amended standard 
must result in significant conservation of energy. (42 U.S.C. 
6295(o)(3)(B), 6316(a)) In accordance with these and other statutory 
provisions addressed in this rulemaking, DOE is adopting amended energy 
conservation standards for distribution transformers. The amended 
standards are summarized in Table I.1 through Table I.3. Table I.4 
shows the mapping of trial standard levels (TSLs) to energy efficiency 
levels (ELs),\2\ and Table I.5 through Table I.8 show the standards in 
terms of minimum electrical efficiency. These amended standards apply 
to all equipment that is listed in Table I.1 and manufactured in, or 
imported into, the United States on or after January 1, 2016. As 
discussed in section IV.C.8 of this preamble, any distribution 
transformer having a kilovolt-ampere (kVA) rating falling between the 
kVA ratings shown in the tables shall meet a minimum energy efficiency 
level calculated by a linear interpolation of the minimum efficiency 
requirements of the kVA ratings immediately above and below that 
rating.\3\
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    \1\ For editorial reasons, upon codification in the U.S. Code, 
Parts B and C were redesignated as Parts A and A-1, respectively.
    \2\ A detailed description of the mapping of trial standard 
level to energy efficiency levels can be found in the Technical 
Support Document, chapter 10 section 10.2.2.3.
    \3\ kVA, an abbreviation for kilovolt-ampere, 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).
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    For the reasons discussed in this preamble, particularly in Section 
V, DOE is adopting TSL 1 for liquid-immersed distribution transformers. 
DOE acknowledges the input of various stakeholders in support of a more 
stringent energy conservation standard for liquid-immersed distribution 
transformers. DOE notes that the potential for significant disruption 
in the steel supply market at higher efficiency levels was a key 
element in adopting TSL 1 in this rulemaking. DOE will monitor the 
steel and liquid-immersed distribution transformer markets and by no 
later than 2016, determine whether interim changes to market 
conditions, particularly the supply chain for amorphous steel, justify 
re-evaluating the efficiency standards adopted in today's rulemaking.
    Although DOE proposed TSL 1 for low-voltage dry-type distribution 
transformers, DOE is adopting in this final rule TSL 2 for such 
transformers for the reasons discussed in greater detail in Section 
IV.I.5.B. DOE acknowledges that various stakeholders

[[Page 23338]]

argued that concerns regarding small manufacturers should not be a 
barrier to adopting TSL 3 because small manufacturers have the option 
of either sourcing cores from third parties or investing in mitering 
machines. DOE will monitor the low-voltage dry-type distribution 
transformer market, and by no later than 2016, determine whether market 
conditions justify re-evaluating the efficiency standards adopted in 
today's rulemaking.

             Table I.1--Energy Conservation Standards for Liquid-Immersed Distribution Transformers
                                      [Compliance starting January 1, 2016]
----------------------------------------------------------------------------------------------------------------
                                                                           Phase
        Equipment classes             Design line            Type          count         BIL*        Adopted TSL
----------------------------------------------------------------------------------------------------------------
1...............................  1, 2 and 3........  Liquid-immersed...        1  All.............            1
2...............................  4 and 5...........  Liquid-immersed...        3  All.............            1
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* BIL means ``basic impulse insulation level'' and measures how resistant a transformer's insulation is to large
  voltage transients.


           Table I.2--Energy Conservation Standards for Low-Voltage Dry-Type Distribution Transformers
                                      [Compliance starting January 1, 2016]
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                                                                           Phase
         Equipment class              Design line            Type          count         BIL*        Adopted TSL
----------------------------------------------------------------------------------------------------------------
3...............................  6.................  Low-voltage dry-          1  <= 10 kV........            2
                                                       type.
4...............................  7 and 8...........  Low-voltage dry-          3  <= 10 kV........            2
                                                       type.
----------------------------------------------------------------------------------------------------------------
* BIL means ``basic impulse insulation level'' and measures how resistant a transformer's insulation is to large
  voltage transients.


         Table I.3--Energy Conservation Standards for Medium-Voltage Dry-Type Distribution Transformers
                                      [Compliance starting January 1, 2016]
----------------------------------------------------------------------------------------------------------------
                                                                           Phase
         Equipment class              Design line            Type          count         BIL*        Adopted TSL
----------------------------------------------------------------------------------------------------------------
5...............................  9 and 10..........  Medium-voltage dry-       1  25-45 kV........            2
                                                       type.
6...............................  9 and 10..........  Medium-voltage dry-       3  25-45 kV........            2
                                                       type.
7...............................  11 and 12.........  Medium-voltage dry-       1  46-95 kV........            2
                                                       type.
8...............................  11 and 12.........  Medium-voltage dry-       3  46-95 kV........            2
                                                       type.
9...............................  13A and 13B.......  Medium-voltage dry-       1  >=96 kV.........            2
                                                       type.
10..............................  13A and 13B.......  Medium-voltage dry-       3  >=96 kV.........            2
                                                       type.
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* 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 Distribution Transformer Energy
                                             Conservation Standards
----------------------------------------------------------------------------------------------------------------
                                                                                Energy efficiency     Efficiency
                Type                  Design line  Phase count      TSL               level              (%)
----------------------------------------------------------------------------------------------------------------
Liquid-immersed.....................            1            1            1  1 (0.4 actual)*.......        99.11
                                                2            1  ...........  Base (0.5 actual)*....        98.95
                                                3            1  ...........  1 (1.1 actual)*.......        99.49
                                                4            3  ...........  1.....................        99.16
                                                5            3  ...........  1.....................        99.48
Low-voltage dry-type................            6            1            2  Base..................        98.00
                                                7            3  ...........  3.....................        98.60
                                                8            3  ...........  2.....................        99.02
Medium-voltage dry-type.............            9            3            2  1.....................        98.93
                                               10            3  ...........  2.....................        99.37
                                               11            3  ...........  1.....................        98.81
                                               12            3  ...........  2.....................        99.30
                                              13A            3  ...........  1.....................        98.69
                                              13B            3  ...........  2.....................        99.28
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* Because of scaling, actual efficiency values unavoidably differ from nominal EL values.


      Table I.5--Electrical Efficiencies for All Liquid-Immersed Distribution Transformer Equipment Classes
                                      [Compliance starting January 1, 2016]
----------------------------------------------------------------------------------------------------------------
                       Equipment Class 1                                        Equipment Class 2
----------------------------------------------------------------------------------------------------------------
                     kVA                              %                        kVA                       %
----------------------------------------------------------------------------------------------------------------
                                      Standards by kVA and Equipment Class
----------------------------------------------------------------------------------------------------------------
10...........................................           98.70   15..............................           98.65

[[Page 23339]]

 
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   1,000...........................           99.43
667..........................................           99.52   1,500...........................           99.48
833..........................................           99.55   2,000...........................           99.51
                                               ...............  2,500...........................           99.53
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   Table I.6--Electrical Efficiencies for All Low-Voltage Dry-Type Distribution Transformer Equipment Classes
                                      [Compliance starting January 1, 2016]
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                       Equipment Class 3                                        Equipment Class 4
----------------------------------------------------------------------------------------------------------------
                      kVA                              %                       kVA                       %
----------------------------------------------------------------------------------------------------------------
                                      Standards by kVA and Equipment Class
----------------------------------------------------------------------------------------------------------------
15............................................           97.70  15..............................           97.89
25............................................           98.00  30..............................           98.23
37.5..........................................           98.20  45..............................           98.40
50............................................           98.30  75..............................           98.60
75............................................           98.50  112.5...........................           98.74
100...........................................           98.60  150.............................           98.83
167...........................................           98.70  225.............................           98.94
250...........................................           98.80  300.............................           99.02
333...........................................           98.90  500.............................           99.14
                                                ..............  750.............................           99.23
                                                ..............  1,000...........................           99.28
----------------------------------------------------------------------------------------------------------------


                                          Table I.7--Electrical Efficiencies for All Medium-Voltage Dry-Type Distribution Transformer Equipment Classes
                                                                              [Compliance starting January 1, 2016]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
            Equipment  Class 5                    Equipment  Class 6            Equipment  Class 7            Equipment  Class 8            Equipment  Class 9           Equipment  Class 10
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
               kVA                    %             kVA              %             kVA             %             kVA             %             kVA             %             kVA            %
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Standards by kVA and Equipment Class
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
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   1,000..............    99.28   667...............    99.18   1,000.............    99.20   667...............    99.15   1,000.............    99.11
833.............................    99.31   1,500..............    99.37   833...............    99.23   1,500.............    99.30   833...............    99.20   1,500.............    99.21
                                  ........  2,000..............    99.43   ..................  ........  2,000.............    99.36   ..................  ........  2,000.............    99.28
                                  ........  2,500..............    99.47   ..................  ........  2,500.............    99.41   ..................  ........  2,500.............    99.33
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 23340]]

A. Benefits and Costs to Customers \4\
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    \4\ For 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 summarizes DOE's evaluation of the economic impacts of 
today's standards on customers who purchase 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 standards for distribution transformers. (Throughout this 
document, ``distribution transformers'' are also referred to as simply 
``transformers.'')

  Table I.8--Impacts of Today's Standards on Customers of Distribution
                              Transformers
------------------------------------------------------------------------
                                                                Median
                                                Average LCC    payback
                  Design line                      savings      period
                                                   2011$        years
------------------------------------------------------------------------
                             Liquid-Immersed
------------------------------------------------------------------------
1.............................................           72         18.2
2.............................................           66          5.9
3.............................................        2,753          8.6
4.............................................          967          7.0
5.............................................        4,289          6.3
------------------------------------------------------------------------
                        Low-voltage dry-type \**\
------------------------------------------------------------------------
6.............................................      N/A \*\      N/A \*\
7.............................................        1,678          3.6
8.............................................        2,588          7.7
------------------------------------------------------------------------
                         Medium-voltage dry-type
------------------------------------------------------------------------
9.............................................          787          2.6
10............................................        4,455          8.6
11............................................          996         10.6
12............................................        6,790          8.5
13A...........................................          -27         16.1
13B...........................................        4,346         12.2
------------------------------------------------------------------------
\*\ No customers are impacted by today's standard because there is no
  change from the minimum efficiency standard for design line 6.
\**\ See section IV.A.3.d for discussion of core construction technique.

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 (2012 to 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 
INPV for manufacturers of liquid-immersed, medium-voltage dry-type, and 
low-voltage dry-type distribution transformers is $575.1 million, $68.7 
million, and $237.6 million, respectively, in 2011$. Under the 
standards of today's rule, DOE expects that manufacturers of liquid-
immersed units may lose as much as 8.4 percent of their INPV, which is 
approximately $48.2 million; medium-voltage manufacturers may lose as 
much as 4.2 percent of their INPV, which is approximately $2.9 million; 
and low-voltage manufacturers may lose as much as 4.7 percent of their 
INPV, which is approximately $11.1 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 today's standards would save a 
significant amount of energy. The lifetime savings for equipment 
purchased in the 30-year period that begins in the year of compliance 
with amended standards (2016-2045) amounts to 3.63 quads.
    The cumulative net present value (NPV) of total customer costs and 
savings of today's standards for distribution transformers, in 2011$, 
ranges from $3.4 billion (at a 7-percent discount rate) to $12.9 
billion (at a 3-percent discount rate). This NPV expresses the 
estimated total value of future operating-cost savings minus the 
estimated increased equipment costs for equipment purchased in 2016-
2045, discounted to 2012.
    In addition, today's standards would have significant environmental 
benefits. The energy savings would result in cumulative emission 
reductions of 264.7 million metric tons (Mt) \5\ of carbon dioxide 
(CO2), 223.3.thousand tons of nitrogen oxides 
(NOX), 182.9 thousand tons of sulfur dioxide 
(SO2), and 0.6 ton of mercury (Hg).\6\
---------------------------------------------------------------------------

    \5\ A metric ton is equivalent to 1.1 short tons. Results for 
NOX and Hg are presented in short tons.
    \6\ DOE calculated emissions reductions relative to the Annual 
Energy Outlook (AEO) 2011 Reference case, which incorporated 
projected effects of all emissions regulations promulgated as of 
January 31, 2011, including the Clean Air Interstate Rule (CAIR, 70 
FR 25162 (May 12, 2005)). Subsequent regulations, including the CAIR 
replacement rule, the Cross-State Air Pollution Rule (76 FR 48208 
(August 8, 2011)), do not appear in the projection.
---------------------------------------------------------------------------

    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 $0.80 billion and $13.31 billion, 
expressed in 2011$ and discounted to 2012. DOE also estimates the net 
present monetary value of the NOX emissions reduction, 
expressed in 2011$ and discounted to 2012, is $93.2 million at a 7-
percent discount rate and $234.1 million at a 3-percent discount 
rate.\7\
---------------------------------------------------------------------------

    \7\ DOE has decided to await further guidance regarding 
consistent valuation and reporting of Hg emissions before it 
monetizes Hg in its rulemakings.
---------------------------------------------------------------------------

    Table I.9 summarizes the national economic costs and benefits 
expected to result from today's standards for distribution 
transformers.

      Table I.9--Summary of National Economic Benefits and Costs of
         Distribution Transformer Energy Conservation Standards
------------------------------------------------------------------------
                                          Present value   Discount rate
                Category                 billion  2011$         %
------------------------------------------------------------------------
                                Benefits
------------------------------------------------------------------------
Operating Cost Savings.................            6.30              7

[[Page 23341]]

 
                                                  18.2               3
CO2 reduction monetized value ($4.9/t              0.80              5
 case) \*\.............................
CO2 reduction monetized value ($22.3/t             4.38              3
 case) \*\.............................
CO2 reduction monetized value ($36.5/t             7.51              2.5
 case) \*\.............................
CO2 reduction monetized value ($67.6/t            13.31              3
 case) \*\.............................
NOX reduction monetized value ($2,591/             0.09              7
 ton) \**\.............................
                                                   0.23              3
Total benefits [dagger]................           10.77              7
                                                  22.8               3
------------------------------------------------------------------------
                                  Costs
------------------------------------------------------------------------
Incremental installed costs............            2.89              7
                                                   5.22              3
------------------------------------------------------------------------
                              Net Benefits
------------------------------------------------------------------------
Including CO2 and NOX reduction                    7.88              7
 monetized value.......................
                                                  17.6               3
------------------------------------------------------------------------
\*\ The CO2 values represent global monetized values of the SCC in 2011$
  in 2011 under several scenarios. The values of $4.9, $22.3, and $36.5/
  per metric ton (t) are the averages of SCC distributions calculated
  using 5%, 3%, and 2.5% discount rates, respectively. The value of
  $67.6/t represents the 95th percentile of the SCC distribution
  calculated using a 3% discount rate. The SCC time series used by DOE
  incorporate an escalation factor.
\**\ The value represents the average of the low and high NOX values
  used in DOE's analysis.
[dagger] Total benefits for both the 3% and 7% cases are derived using
  the series corresponding to SCC value of $22.3/t.

    The benefits and costs of today's 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 customer operation of equipment 
that meets today's 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 customer 
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 2012, 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 three and seven 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.10. From the present value, DOE then calculated the 
fixed annual payment over a 30-year period (2016 through 2045) 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 is a steady stream of 
payments.
---------------------------------------------------------------------------

    Although combining the values of operating cost savings and 
CO2 emission reductions provides a useful 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, whereas the value of CO2 reductions is 
based on a global value. Second, the assessments of operating cost 
savings and CO2 savings are performed using different 
methods that employ 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 ton of carbon dioxide in each year. 
Those impacts continue well beyond 2100.
    Estimates of annualized benefits and costs of today's standards are 
shown in Table I.10. The results under the primary estimate are as 
follows. (All monetary values below are expressed in 2011$.) 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/ton in 2011), the cost of 
the standards in today's rule is $266 million per year in increased 
equipment costs, while the benefits are $581 million per year in 
reduced equipment operating costs, $237 million in CO2 
reductions, and $8.60 million in reduced NOX emissions. In 
this case, the net benefit amounts to $561 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/ton in 2011), the cost of the 
standards in today's rule is $282 million per year in increased 
equipment costs, while the benefits are $983 million per year in 
reduced operating costs, $237 million in CO2 reductions, and 
$12.67 million in reduced NOX emissions. In this case, the 
net benefit amounts to $950 million per year.

[[Page 23342]]



 Table I.10--Annualized Benefits and Costs of Amended Standards for Distribution Transformers Sold in 2016-2045
----------------------------------------------------------------------------------------------------------------
                                                                         Million 2011$/year
                                                   -------------------------------------------------------------
                                 Discount rate %                           Low net benefits    High net benefits
                                                     Primary estimate *       estimate *          estimate *
----------------------------------------------------------------------------------------------------------------
                                                    Benefits
----------------------------------------------------------------------------------------------------------------
Operating cost savings.......  7                    581                  559                  590.
                               3                    983                  930                  1003.
CO2 reduction monetized value  5                    57.7                 57.7                 57.7.
 ($4.9/t case) **.
CO2 reduction monetized value  3                    237                  237                  237.
 ($22.3/t case) **.
CO2 reduction monetized value  2.5                  377                  377                  377.
 ($36.5/t case) **.
CO2 reduction monetized value  3                    721                  721                  721.
 ($67.6/t case) **.
NOX reduction monetized value  7                    8.60                 8.60                 8.60.
 ($2,591/ton) **.
                               3                    12.67                12.67                12.67.
    Total benefits[dagger]...  7% plus CO2 range    648 to 1311          625 to 1288          656 to 1319.
                               7                    827                  805                  836.
                               3% plus CO2 range    1053 to 1716         1000 to 1663         1074 to 1737.
                               3                    1233                 1179                 1253.
----------------------------------------------------------------------------------------------------------------
                                                      Costs
----------------------------------------------------------------------------------------------------------------
Incremental equipment costs..  7                    266                  300                  257.
                               3                    282                  325                  271.
----------------------------------------------------------------------------------------------------------------
                                                  Net Benefits
----------------------------------------------------------------------------------------------------------------
Total[dagger]................  7% plus CO2 range    381 to 1044          325 to 988           400 to 1063.
                               7                    561                  504                  579.
                               3% plus CO2 range    771 to 1434          675 to 1338          803 to 1466.
                               3%                   950                  854                  982.
----------------------------------------------------------------------------------------------------------------
* This table presents the annualized costs and benefits associated with transformers shipped in 2016-2045. These
  results include benefits to customers that accrue after 2045 from equipment purchased in 2016-2045. Costs
  incurred by manufacturers, some of which may be incurred in preparation for the rule, are not directly
  included, but are indirectly included as part of incremental equipment costs. The Primary, Low Benefits, and
  High Benefits estimates utilize projections of energy prices from the AEO2012 Reference case, Low Estimate,
  and High Estimate, respectively. In addition, incremental equipment costs reflect a constant equipment price
  trend in the Primary Estimate, an increasing price trend in the Low Benefits Estimate, and a declining price
  trend in the High Benefits Estimate. The methods used to derive projected price trends are explained in
  section IV.F.2.
** The CO2 values represent global monetized values of the SCC, in 2011$, in 2011 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 $67.6/t represents the 95th percentile of the SCC
  distribution calculated using a 3% discount rate. The SCC time series used by DOE incorporate an escalation
  factor. The value for NOX (in 2011$) 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 series corresponding to SCC value of
  $22.3/t. In the rows labeled ``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.

D. Conclusion

    Based on the analyses culminating in this final rule, DOE found the 
benefits to the nation of the standards (energy savings, consumer LCC 
savings, positive NPV of customer benefit, and emission reductions) 
outweigh the burdens (loss of INPV and LCC increases for some users of 
this equipment). DOE has concluded that the standards in today's final 
rule represent the maximum improvement in energy efficiency that is 
technologically feasible and economically justified, and would result 
in significant conservation of energy.

II. Introduction

    The following section briefly discusses the statutory authority 
underlying today's final rule, as well as some of the relevant 
historical background related to the establishment of today's amended 
standards.

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 of Energy to prescribe energy 
conservation standards for those distribution transformers for which 
DOE determines such standards would be technologically feasible, 
economically justified, and would result in significant energy savings. 
(42 U.S.C. 6317(a)) The Energy Policy Act of 2005 (EPACT 2005), Public 
Law 109-58, amended EPCA to establish energy conservation standards for 
low-voltage dry-type distribution transformers.\10\ (42 U.S.C. 6295(y))
---------------------------------------------------------------------------

    \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).

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

[[Page 23343]]

    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 of Energy in accordance with certain criteria 
and conditions. (42 U.S.C. 6293(b)(10), 6314(a)(2)-(3) and 6317(a)(1)) 
Manufacturers of such 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 appear 
at title 10 of the Code of Federal Regulations (CFR) part 431, subpart 
K, appendix A.
    DOE is required to follow certain 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 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 amended standard 
is not technologically feasible or economically justified. (42 U.S.C. 
6295(o)(3) and 6316(a)) In deciding whether an 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 
customers 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 a standard is economically justified if the Secretary finds that 
the additional cost to the customer of purchasing equipment complying 
with an energy conservation standard level will be less than three 
times the value of the energy savings during the first year that the 
customer will receive as a result of the standard, as calculated under 
the applicable test procedure. 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 
under 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. 6295(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 
customer of such a 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, January 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 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

[[Page 23344]]

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 final rule is consistent with these principles, 
including the requirement that, to the extent permitted by law, 
benefits justify costs and that net benefits are maximized. Consistent 
with EO 13563, and the range of impacts analyzed in this rulemaking, 
the energy efficiency standard adopted herein by DOE achieves maximum 
net benefits.

B. Background

1. Current Standards
    On August 8, 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. See Table I.6 above for today's 
amended LVDT standards.
---------------------------------------------------------------------------

    \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 Conservation 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
                                                                1,000...........................            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% 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 standards 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). See Tables I.5 and I.7 above for today's amended liquid-immersed 
and medium-voltage dry-type (MVDT) standards.

         Table II.2--Federal 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   1,000...........................           99.36
667..........................................           99.46   1,500...........................           99.42
833..........................................           99.49   2,000...........................           99.46
                                               ...............  2,500...........................           99.49
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50% of nameplate-rated load, determined according to the DOE test-procedure.
  10 CFR part 431, subpart K, appendix A.


[[Page 23345]]


                         Table II.3--Federal Energy Conservation Standards for Medium-Voltage Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                     Single-phase                                                           Three-phase
                                  -------------------------------------------------                      -----------------------------------------------
                                                         BIL*                                                                   BIL
               kVA                -------------------------------------------------          kVA         -----------------------------------------------
                                      20-45 kV        46-95 kV         >=96 kV                               20-45 kV        46-95 kV         >=96 kV
                                  -------------------------------------------------                      -----------------------------------------------
                                    Efficiency %    Efficiency %     Efficiency %                          Efficiency %    Efficiency %    Efficiency %
--------------------------------------------------------------------------------------------------------------------------------------------------------
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   1,000...............           99.14           99.03           98.99
833..............................           99.31           99.23           99.20   1,500...............           99.22           99.12           99.09
                                   ..............  ..............  ...............  2,000...............           99.27           99.18           99.15
                                   ..............  ..............  ...............  2,500...............           99.31           99.23           99.20
--------------------------------------------------------------------------------------------------------------------------------------------------------
* BIL means ``basic impulse insulation level.''
Note: All efficiency values are at 50% 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). In 2000, DOE 
issued and took comment on 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 at: http://www.regulations.gov/#!docketDetail;dct=FR%252BPR%252BN%252BO%252BSR;rpp=10;po=0;D=EERE-
2006-STD-0099.
    On July 29, 2004, DOE published an advance notice of proposed 
rulemaking (ANOPR) for distribution transformer standards.\12\ 69 FR 
45375. In August 2005, DOE issued draft analyses on which it planned to 
base the standards for liquid-immersed and medium-voltage dry-type 
distribution transformers, along with supporting documentation.\13\
---------------------------------------------------------------------------

    \12\ The ANOPR published in July 2004 is available at: http://www.regulations.gov/#!documentDetail;D=EERE-2006-STD-0099-0069.
    \13\ These analyses are available in the docket folder at: 
http://www.regulations.gov/#!docketDetail;D=EERE-2006-STD-0099.
---------------------------------------------------------------------------

    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) outlined 
the procedure the Department of Energy 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.\14\
---------------------------------------------------------------------------

    \14\ The NOPR TSD published in August 2006 is available at: 
http://www.regulations.gov/#!documentDetail;D=EERE-2006-STD-0099-
0140.
---------------------------------------------------------------------------

    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 (February 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, and requested comments on linking 
energy efficiency levels for three-phase liquid-immersed units with 
those of 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 and incorporated increased 
installation costs for pole-mounted and vault transformers. 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, 2007) (the 2007 
Final Rule) (codified at 10 CFR 431.196(b)-(c)). 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 those 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 of Energy to determine whether 
to amend the energy conservation standards for liquid-

[[Page 23346]]

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 those 
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 agreed to publish a final rule containing such 
amended standards by October 1, 2012. Today's final rule satisfies the 
amended settlement agreement.
    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 that DOE would analyze in consideration of amending the energy 
conservation standards, 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 believed that many of the same methodologies and data 
sources that were used during the 2007 final 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. Those comments are discussed in the following 
sections of the final rule.
    On July 29, 2011, DOE published in the Federal Register a notice of 
intent to establish a subcommittee under DOE's 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 decided that a negotiated rulemaking would result in a 
better-informed 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 both 
subcommittees 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, 
listed below, having a defined stake in the outcome of the proposed 
standards and included:

 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 in 2011 on September 15 
through 16, October 12 through 13, November 8 through 9, and November 
30 through December 1; the ERAC subcommittee also held public webinars 
on November 17 and December 14. The meetings were open to the public. 
During 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; in such cases 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 excluding 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 energy efficiency 
Advocates, represented by the Appliance Standards Awareness Project 
(ASAP), recommended efficiency level (also referred to as ``EL'') 2 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 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, and 13B would be scaled. Transcripts of the all subcommittee 
meetings (for all transformer types) and all data and materials 
presented at the subcommittee meetings are available via a link under 
the DOE Web site at: http://www.regulations.gov/#!docketDetail;D=EERE-
2010-BT-STD-0048.
    The ERAC subcommittee held meetings in 2011 on September 28, 
October 13-14, November 9, and December 1-2 for low-voltage 
distribution transformers. The ERAC subcommittee also held webinars on 
November 21, 2011, and December 20, 2011. The meetings were open to the 
public. During the September 28, 2011, meeting, the subcommittee agreed 
to its

[[Page 23347]]

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 and included:

 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 meeting of October 14, 2011, 
DOE presented its revised analysis and heard from subcommittee members 
on various topics. During the meeting of November 9, 2011, DOE 
presented its revised analysis. During the meeting 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.
    DOE published a NOPR on February 10, 2012, which proposed amended 
standards for all three transformer types. 77 FR 7282. Medium-voltage 
dry-type distribution transformers were proposed at the negotiating 
committee's consensus level. Liquid-immersed distribution transformers 
were proposed at TSL 1. Low-voltage dry-type distribution transformers 
were proposed at TSL 1. In the NOPR, DOE sought comment on a number of 
issues related to the rulemaking.\15\
---------------------------------------------------------------------------

    \15\ On February 24, 2012, DOE published a technical correction 
to the NOPR, amending and adding values in certain tables in the 
NOPR. 77 FR 10997.
---------------------------------------------------------------------------

    Following publication of the NOPR, DOE received several comments 
expressing a desire to see some of the NOPR suggestions extended and 
analyzed for liquid-immersed distribution transformers. In response, 
DOE generated a supplementary NOPR analysis with three additional TSLs. 
The three TSLs presented were based on possible new equipment classes 
for pole-mounted distribution transformers, network/vault-based 
distribution transformers, and those with high basic impulse level 
(BIL) ratings. On June 4, 2012 DOE published a notice announcing the 
availability of this supplementary analysis \16\ and of a public 
meeting to be held on June 20, 2012 to present and receive feedback on 
it. DOE also generated an additional TSL in a June 18, 2012 analysis 
published on DOE's Web site.
---------------------------------------------------------------------------

    \16\ 77 FR 32916.
---------------------------------------------------------------------------

III. General Discussion

A. Test Procedures

    DOE published its test procedure for distribution transformers in 
the Federal Register as a final rule on April 27, 2006. 71 FR 24972. 
Section 7(c) of the Process Rule \17\ indicates that DOE will issue a 
final test procedure, if one is needed, prior to issuing a proposed 
rule for energy conservation standards. Under 42 U.S.C. 6314(a)(1), at 
least every seven years, DOE must evaluate whether to amend test 
procedures for each class of commercial equipment based on whether an 
amended test procedure would more accurately or fully comply with the 
requirements that test procedures be reasonably designed to produce 
test results that reflect energy efficiency, energy use, and estimated 
operating costs during a representative average use cycle, and that the 
test procedures are not unduly burdensome to conduct.\18\ Any 
determination that a test procedure amendment is not required under 
this standard must be published in the Federal Register. (42 U.S.C. 
6314(a)(1)(A)(ii))
---------------------------------------------------------------------------

    \17\ 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).
    \18\ In addition, if the test procedure determines estimated 
annual operating costs, such procedure must meet additional 
requirements at 42 U.S.C. 6314(a)(3).
---------------------------------------------------------------------------

    As detailed below, in today's notice, DOE determines that an 
amended test procedure is not necessary because the 2006 test procedure 
is reasonably designed to produce test results that reflect energy 
efficiency and energy use, and an amended test procedure that more 
precisely measures energy efficiency and energy use for every possible 
distribution transformer configuration would be unduly burdensome to 
conduct.
1. General
    Several parties commented on the test procedure for distribution 
transformers. The California Investor Owned Utilities (CA IOUs) 
commented that DOE should not modify the test procedure. (CA IOUs, No. 
189 at p. 1) Today's rule contains no test procedure amendments, but 
the rule does clarify the test procedure's application in response to 
comments. DOE may revisit the issue of test procedures in a future 
proceeding.
    NEMA commented that because of variability in process, materials, 
and testing, manufacturers must ``overdesign'' transformers in order to 
have confidence that their products will meet standards. (NEMA, No. 170 
at p. 3) DOE notes that its compliance procedures already contain 
allowances for statistical variation as a result of measurement, 
laboratory, and testing procedure variability. Manufacturers are also 
required to take certification sampling plans and tolerances into 
account when developing their certified ratings after testing a sample 
of minimum units from the production of a basic model. The represented 
efficiency equation essentially allows a manufacturer to ``represent'' 
a basic model of distribution transformer as having achieved a higher 
efficiency than calculated through testing the minimum sample for 
certification. DOE is not adopting any modifications to its 
certification or enforcement sampling procedures in this final rule, 
but it may further address them in a separate proceeding at a later 
date if it finds such practices to be overly strict or generous.
    Additionally, Schneider Electric commented that DOE's test 
procedure is inadequate or ambiguous in several areas, including test 
environment drafts, ambient method internal temperatures, test 
environment ambient temperature variation, ambient method test delays,

[[Page 23348]]

coordination of coil and ambient test methods, temperature data 
records, and application of voltage or current. (Schneider, No. 180 at 
p. 12) DOE examined the test procedure components identified by 
Schneider Electric and determined that, at this time, no change to the 
test procedure is necessary to address the issues raised. Further, the 
existing, statutorily-prescribed test procedure is an industry standard 
familiar to manufacturers. DOE continues to believe that the procedure 
is reasonably designed to produce test results that reflect energy 
efficiency and energy use without being unduly burdensome to conduct.
    Finally, DOE's present sampling plans require a minimum number of 
units be tested in order to calculate the represented efficiency of a 
basic model. (10 CFR 429.47 (a)). Prolec-GE commented that DOE's 
compliance protocols allow too small a statistical variation, 
particularly because silicon steel sees a greater variation in losses 
than does the amorphous variety. (Prolec-GE, No. 177 at p. 17) To the 
extent Prolec-GE is concerned about the variability in their 
production, DOE notes that the statistical sampling plans allow for 
manufacturers to increase the sample size, which should help better 
characterize the variability association with the production. DOE's 
existing sampling plans are a balance between manufacturing burden 
associated with testing and accurately characterizing the efficiency of 
a given basic model based on a sample of the production. While DOE is 
not adopting any changes to its existing sampling plans in today's 
final rule, DOE welcomes data showing the production variability for 
different types and efficiencies of distribution transformers to help 
better inform any changes that may be considered in a separate and 
future proceeding.
2. Multiple kVA Ratings
    The current test procedure is not specific regarding which kVA 
rating should be used to assess compliance in the case of distribution 
transformers that have more than one rating. Though less common in 
distribution transformers than in other types of transformers (e.g., 
``power'' or ``substation'' transformers), active cooling measures such 
as fans or pumps are sometimes used to aid cooling. Greater heat 
dissipation capacity means that the transformer can be safely operated 
at higher loading levels for longer periods of time. Active cooling 
components generally carry much shorter lifetimes than the transformer 
itself, however, and the failure of any cooling component would expose 
the transformer at-large to premature failure due to elevated 
temperatures. Accordingly, distribution transformers rarely contain 
such components and, when they do, rarely make use of them except in 
occasional overload situations. As a result, they play little role in 
the design of the transformer or in a transformer's ability to operate 
efficiently even when equipped.
    Apart from ratings corresponding to active cooling, transformers 
may also carry additional ratings (i.e., above the ``base rating'') 
corresponding to passive cooling and reflecting different temperature 
rises. A transformer would be rated for higher kVA if allowed to rise 
to a greater temperature and, by extension, dissipate more energy.
    DOE sought comment on whether the test procedure needs greater 
specificity with respect to multiple kVA ratings. No party argued that 
distribution transformers should comply with standards at any ratings 
corresponding to active cooling, for the reasons discussed above. Four 
manufacturers (Howard Industries, Cooper Power Systems, Prolec-GE, and 
Schneider Electric), one trade organization (NEMA), and one utility 
(Progress Energy) all commented that compliance should be based 
exclusively on a transformer's ``base'' rating, or the rating that 
corresponds to the lowest temperature rise. (Prolec-GE, No. 177 at p. 
6; Schneider, No. 180 at p. 2; PEMCO, No. 183 at p. 2; PE, No. 192 at 
p. 3; HI, No. 151 at p. 12; NEMA, No. 170 at pp. 6-7) ABB argued that 
compliance should be based on a transformer's base rating and on any 
others (if any) corresponding to passive cooling. (ABB, No. 158 at pp. 
2-4) HVOLT commented that the term ``passive cooling'' may not be 
sufficient to clarify DOE's intent because some transformers have more 
than one rating which may be achieved with passive cooling. (HVOLT, No. 
146 at p. 49)
    Though prevalent in certain types of larger transformers, active 
cooling is not a significant feature in the design or operation of 
distribution transformers. Distribution transformers are seldom 
equipped with active cooling features or designed to make use of them. 
Additionally, units which are equipped with such features are rarely 
operated using them. As a result, active cooling features bear little 
influence on transformer efficiency and are not appropriate for use in 
measuring energy efficiency. Similarly, transformers with more than one 
rating corresponding to passive cooling will experience reduced 
equipment lifetime when operated at those high ratings and are 
therefore best evaluated at their lowest, ``base'' rating. DOE 
clarifies today that manufacturers should use a transformer's base kVA 
rating to assess compliance. For distribution transformers with more 
than one kVA rating, base kVA rating means the kVA rating that 
corresponds to the lowest temperature rise that actively removes heat 
from the distribution transformer without engagement of any fans, 
pumps, or other equipment. It is the base kVA rating and the base kVA 
rating only, which manufacturers should base their certified ratings on 
and on which DOE will assess compliance. In no case should a 
distribution transformer be certified using any kVA rating 
corresponding to heat removal or enhanced convection by auxiliary 
equipment.
3. Dual/Multiple Basic Impulse Level
    Distribution transformers may be built such that different winding 
configurations carry different BIL ratings. In the past, MVDT 
transformers were placed into equipment classes by BIL rating (among 
other criteria) and the question arose of which rating (if there were 
more than one) should be used to assess compliance. Currently, DOE 
requires distribution transformers to comply with standards using the 
BIL rating of the winding configuration that produces the greatest 
losses. (10 CFR part 431, subpart K, appendix A)
    BIL rating offers additional utility in the form of increased 
resistance to large voltage transients arising, for example, from 
lightning strikes, but requires some design compromises that affect 
efficiency, primarily with respect to winding clearances. A transformer 
rated for a given BIL must be designed as such, even if the windings 
may be reconfigured such that they carry a lower rating. For this 
reason, Progress Energy, PEMCO, NEMA, Cooper Power Systems, Power 
Partners, and Howard Industries all commented that transformers with 
multiple BIL ratings should comply only at the highest BIL for which 
they are rated. (HI, No. 151 at p. 12; Power Partners, No. 155 at p. 1-
2; Cooper, No. 165 at p. 2; NEMA, No. 170 at p. 7; Prolec-GE, No. 177 
at p. 6; PEMCO, No. 183 at p. 2; PE, No. 192 at p. 3) ABB commented 
that transformers should meet the efficiency levels of all of its rated 
BILs, because there is no way to know in advance how a transformer will 
be operated over its lifetime. (ABB, No. 158 at p. 4)
    Although DOE agrees there is no way to be sure how a distribution 
transformer will be operated over its lifetime, it does not believe 
multiple BIL ratings currently present an energy conservation standards 
circumvention

[[Page 23349]]

risk. Designing transformers to higher BIL ratings adds cost and 
consumers would be unlikely to utilize them unless genuinely required 
by the application.
    DOE clarifies that transformers may be certified at any BIL for 
which they are rated, including the highest BIL ratings. This does 
nothing to change DOE's requirement that distribution transformers 
comply in the configuration that produces the greatest losses, however, 
even if that configuration itself does not carry the highest BIL 
rating. For example, a MVDT distribution transformer may have two 
winding configurations, respectively BIL rated at 60 kV and 125 kV. 
Although the distribution transformer must meet only the 125 kV 
standards, it may produce greater losses (and thus need to be 
certified) in the 60 kV configuration.
4. Dual/Multiple-Voltage Primary Windings
    Currently, DOE requires manufacturers to comply with energy 
conservation standards while the distribution transformer's primary 
windings (``primaries'') are in the configuration that produces the 
highest losses. (10 CFR part 431, subpart K, appendix A)
    DOE understands that, in contrast to the secondary windings, 
reconfigurable primaries typically exhibit a larger variation in 
efficiency between series and primary connections. Such transformers 
are often purchased with the intent of upgrading the local power grid 
to a higher operating voltage and lowered overall system losses.
    Several parties commented on the matter of primary winding 
configurations in response to the NOPR. Kentucky Association of 
Electric Cooperatives (KAEC), Cooper Power Systems, NEMA, and Progress 
Energy commented that it is least burdensome for manufacturers if they 
can report losses in the same configuration in which the transformers 
are shipped, which by Institute of Electrical and Electronics Engineers 
(IEEE) standards must be the series configuration. (KAEC, No. 149 at p. 
2; NEMA, No. 170 at p. 6; PE, No. 192 at p. 10; PE, No. 192 at p. 2; 
Prolec-GE, No. 177 at p. 5; Schneider, No. 180 at p. 2; Schneider, No. 
180 at p. 8; Cooper Power Systems, No. 222 at p. 3) Howard Industries 
and Prolec-GE commented that manufacturers should be allowed to test 
distribution transformers with their primaries in any configuration. 
(HI, No. 151 at p. 12; Prolec-GE, No. 177 at p. 5) Utilities Baltimore 
Gas and Electric and Commonwealth Edison supported testing in the 
configuration in which the transformer will ultimately be used. (BG&E, 
No. 182 at p. 2; ComEd, No. 184 at p. 2)
    ABB submitted comments and data explaining that the ratios of the 
losses of different winding positions varied considerably and, as a 
result, that there was no reliable way to predict which configuration 
would carry the lowest losses. ABB and the California IOUs supported 
maintaining the test procedure's current requirements. (ABB, No. 158 at 
p. 2; CA IOUs, No. 189 at pp. 1-2)
    DOE is concerned that the primary winding configuration can have a 
significant impact on energy consumption and that by relaxing the 
restriction of compliance in the configuration producing the highest 
losses, any forecasted energy savings may be diminished. DOE is not 
modifying any test procedure requirements in today's rule, but may 
reexamine the topic in a dedicated test procedure rulemaking in the 
future.
5. Dual/Multiple-Voltage Secondary Windings
    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. Whereas the IEEE standard \19\ requires a distribution 
transformer to be shipped with the windings in series, a manufacturer 
testing for compliance might need to disassemble the unit, reconfigure 
the windings, and reassemble the unit for shipping at added time and 
expense.
---------------------------------------------------------------------------

    \19\ IEEE C57.12.00-2010.
---------------------------------------------------------------------------

    Several parties commented on the matter of reconfigurable secondary 
windings. Cooper Power Systems, KAEC, NEMA, Progress Energy, and 
Schneider Electric supported conducting testing with windings in 
series, as is the IEEE convention and as would produce the highest 
voltage. (Cooper, No. 165 at pp. 1-2, 6 No. 222 at p. 3; HI, No. 151 at 
p. 12; KAEC, No. 149 at p. 2; NEMA, No. 170 at p. 6; PE, No. 192 at p. 
10; PE, No. 192 at p. 2; Schneider, No. 180 at p. 2; Schneider, No. 180 
at p. 8)
    Power Partners and Prolec-GE commented that testing should be 
permitted in any winding configuration at the discretion of the 
manufacturer. (Power Partners, No. 155 at p. 1; Prolec-GE, No. 177 at 
pp. 3-4)
    Additionally, ABB and the California IOUs commented that there was 
no way of knowing which position would produce the greatest losses and, 
therefore, the test procedure should remain unchanged with respect to 
winding configuration requirements. (ABB, No. 158 at p. 2; CA IOUs, No. 
189 at p. 1-2)
    DOE is concerned that secondary windings may have significantly 
different losses in various configurations and that, furthermore, there 
is no reliable way to predict in which configuration the transformer 
will be operated over the majority of its lifetime. Just as with dual/
multiple primary windings, changing the requirement of testing in the 
configuration producing the highest losses, may diminish forecasted 
energy savings. As a result, DOE is not modifying any test procedure 
requirements in today's rule, but may reexamine the topic in a 
dedicated test procedure rulemaking in the future.
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. DOE wishes to clarify that the loading 
discussed herein pertains only to that which manufacturers must use to 
test their equipment. DOE's economic analysis uses loading 
distributions that attempt to reflect the most recent understanding of 
the United States electrical grid. DOE does not believe that all (or 
the average of all) customers utilize transformers at the required test 
procedure loading values.
    Several parties commented on the appropriateness of these test 
loading values. ABB, ComEd, Cooper, EEI, Howard, KAEC, NEMA, NRECA, 
PEMCO, Prolec-GE, and Schneider all commented that the values were 
appropriate and should continue to be used. (ABB, No. 158 at p. 5; 
ComEd, No. 184 at p. 2; Cooper, No. 165 at p. 2; EEI, No. 185 at p. 4; 
HI, No. 151 at p. 12; KAEC, No. 149 at p. 3; NEMA, No. 170 at p. 12; 
NRECA, No. 172 at p. 4; PEMCO, No. 183 at p. 2; Prolec-GE, No. 177 at 
p. 7; Schneider, No. 180 at p. 3)
    Progress Energy commented that it believed the current values 
suffice for the present but that DOE should further explore the topic 
in the future. (PE, No. 192 at p. 3) BG&E commented that utilities had 
oversized transformers in the past due to lack of ability to accurately 
monitor loading and that loading will increase in the future. (BG&E, 
No. 182 at p. 3) Finally, MGLW and the Copper Development

[[Page 23350]]

Association commented that DOE should use a test procedure that 
requires measurements at several loading levels and reporting of 
efficiency as a weighted average of those. (MLGW, No. 133 at p. 2; CDA, 
No. 153 at p. 4)
    DOE understands that distribution transformers experience a range 
of loading levels when installed in the field. DOE understands that the 
majority of stakeholders, including manufacturers and utilities, 
support retention of the current testing requirements and DOE 
determined that its existing test procedure provides results that are 
representative of the performance of distribution transformers in 
normal use. Although DOE may examine the topic of potential loading 
points in a dedicated test procedure rulemaking in the future, at this 
time, DOE does not believe that the potential improvement in testing 
precision outweighs the complexity and the burden of requiring testing 
at different loadings depending on each individual transformer's 
characteristics.

B. Technological Feasibility

1. General
    In each standards rulemaking, DOE conducts a screening analysis 
based on information it has gathered on all current technology options 
and prototype designs that could improve the efficiency of the products 
that are the subject of the rulemaking. As the first step in such 
analysis, DOE develops a list of technology options for consideration 
in consultation with manufacturers, design engineers, and other 
interested parties. DOE then determines which of these means for 
improving efficiency are technologically feasible. DOE considers 
technologies incorporated in commercially available products or in 
working prototypes to be technologically feasible. 10 CFR 430, subpart 
C, appendix A, section 4(a)(4)(i) There are distribution transformers 
available at all of the energy efficiency levels considered in today's 
final rule. Therefore, DOE believes all of the energy efficiency levels 
adopted by today's final rulemaking are technologically feasible.
    Once DOE has determined that particular technology options are 
technologically feasible, it further evaluates each of them in light of 
the following additional screening criteria: (1) Practicability to 
manufacture, install, or service; (2) adverse impacts on product 
utility or availability; and (3) adverse impacts on health or safety. 
For further details on the screening analysis for this rulemaking, see 
chapter 4 of the final rule TSD.
2. Maximum Technologically Feasible Levels
    When DOE considers an amended standard for a type or class of 
covered equipment, it must determine the maximum improvement in energy 
efficiency or maximum reduction in energy use that is technologically 
feasible for that equipment. (42 U.S.C. 6295(p)(1); 42 U.S.C. 6316(a)) 
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. The max-tech design incorporates the most 
efficient materials, such as core steels and winding materials, and 
applied design parameters that 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 those designs to establish 
max-tech levels for its LCC analysis, then scaled them to other kVA 
ratings within a given design line to establish max-tech efficiencies 
for all the distribution transformer kVA ratings. For today's rule, DOE 
determined max-tech in exactly the same manner.

C. Energy Savings

1. Determination of Savings
    For each TSL, DOE projected energy savings from the products that 
are the subject of this rulemaking purchased in the 30-year period that 
begins in the year of compliance with amended standards (2016-2045). 
The savings are measured over the entire lifetime of products purchased 
in the 30-year period.\20\ DOE quantified the energy savings 
attributable to each TSL as the difference in energy consumption 
between each standards case and the base case. The base case represents 
a projection of energy consumption in the absence of amended mandatory 
efficiency standards, and considers market forces and policies that 
affect demand for more efficient products.
---------------------------------------------------------------------------

    \20\ In the past DOE presented energy savings results for only 
the 30-year period that begins in the year of compliance. In the 
calculation of economic impacts, however, DOE considered operating 
cost savings measured over the entire lifetime of products purchased 
in the 30-year period. Because some transformers sold in 2045 will 
reach the maximum transformer lifetime of 60 years, DOE calculated 
economic impacts through 2105. DOE has chosen to modify its 
presentation of national energy savings to be consistent with the 
approach used for its national economic analysis.
---------------------------------------------------------------------------

    DOE used its national impact analysis (NIA) spreadsheet model to 
estimate energy savings from amended standards for the products that 
are the subject of this rulemaking. The NIA spreadsheet model 
calculates energy savings in site electricity, which is the energy 
directly consumed by transformers at the locations where they are used. 
DOE reports national energy savings on an annual basis in terms of the 
primary energy savings, which is the savings in the energy that is used 
to generate and transmit the site electricity. To convert site 
electricity to primary energy, DOE derived annual conversion factors 
from the model used to prepare the Energy Information Administration's 
(EIA) Annual Energy Outlook 2012 (AEO 2012). Recent data suggests that 
electricity related losses, which includes conversion from the primary 
fuel source and the transmission of electricity, is about twice that of 
site electricity use.
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 (DC 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 for a 30-year analysis period. The

[[Page 23351]]

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. Second, DOE analyzes and reports the 
impacts on different types of manufacturers, paying particular 
attention to impacts on small manufacturers. See section VI.B for 
further discussion. 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 various DOE regulations and other regulatory requirements on 
manufacturers.
    For individual customers, 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 customers in the aggregate, DOE 
also calculates the national NPV of the economic impacts on customers 
over the forecast period applicable to a particular rulemaking.
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 equipment. 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 customer discount rates. DOE assumed in its 
analysis that customers will purchase the considered equipment in 2016.
    To account for uncertainty and variability in specific inputs, such 
as equipment 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 customers 
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 customers that may be disproportionately affected by a 
national standard.
c. Energy Savings
    Although 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 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 Equipment
    In establishing classes of equipment, 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 the equipment. (42 U.S.C. 
6295(o)(2)(B)(i)(IV)) None of the TSLs presented in today's final rule 
would lessen the utility or performance of the equipment under 
consideration in the rulemaking.
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, 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 transmitted a copy of its proposed 
rule and NOPR TSD to the Attorney General with a request that the 
Department of Justice (DOJ) provide its determination on this issue. 
DOJ's response, that the proposed energy conservation standards are 
unlikely to have a significant adverse impact on competition, is 
reprinted at the end of this final rule.
f. Need for National Energy Conservation
    Certain benefits of the amended standards for distribution 
transformers 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 conducted a utility 
impact analysis, described in section IV.K 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 amended 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 today's standards, and from each 
TSL it considered, in chapter 15 of the TSD for the final rule. DOE 
also reports estimates of the economic value of emissions reductions 
resulting from the considered TSLs (see section IV.M of this final 
rule).
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 of Energy considers relevant. (42 U.S.C. 
6295(o)(2)(B)(i)(VII)) Under this provision, DOE has also considered 
the matter of electrical steel availability. This factor is discussed 
further in sections IV.C.9. and IV.I.5.a.
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 customer of a type 
of equipment 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 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 
customer, manufacturer, Nation, and environment, as required under 42 
U.S.C. 6295(o)(2)(B)(i). The results of that 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 three-year PBP analysis). The rebuttable presumption payback 
calculation is discussed in sections IV.F.3.j and V.B.1.c of this final 
rule.

IV. Methodology and Discussion of Related Comments

    DOE used two spreadsheet tools to estimate the impact of today's 
amended standards. The first spreadsheet

[[Page 23352]]

calculates LCCs and PBPs of potential new energy conservation 
standards. The second provides shipments forecasts and calculates 
impacts of potential new energy conservation standards on national NES 
and NPV. 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/product.aspx/productid/66.
    Additionally, DOE estimated the impacts of energy conservation 
standards for distribution transformers on utilities and the 
environment using a version of the Energy Information Administration's 
(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, called NEMS-
BT,\21\ is based on the AEO version with minor modifications.\22\ 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.
---------------------------------------------------------------------------

    \21\ BT stands for DOE's Building Technologies Program (http://www1.eere.energy.gov/buildings/).
    \22\ 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 equipment 
concerned, including the purpose of the equipment, 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 included scope of coverage, 
definitions, equipment classes, types of equipment sold and offered for 
sale, and technology options that could improve the energy efficiency 
of the equipment 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 final 
rule, stating what equipment will be subject to amended standards.
a. Definitions
    Today's 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, 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 24972).
    Additional detail on the definitions of each of these excluded 
transformers, which are defined at 10 CFR 431.192, can found in chapter 
3 of the TSD.
    Many stakeholders expressed support for the defined scope of 
coverage presented in the NOPR. (ABB, No. 158 at p. 5; Cooper, No. 165 
at p. 2; HI, No. 151 at p. 12; KAEC, No. 149 at p. 4; NEMA, No. 170 at 
p. 8; PEMCO, No. 183 at p. 2; Prolec-GE, No. 177 at p. 7) NRECA pointed 
out that while some of its members might purchase distribution 
transformers outside the scope of coverage so few of these types of 
transformers are made it does not warrant a change in coverage. (NRECA, 
No. 172 at p. 4-5) Progress Energy agreed, noting that while utilities 
will occasionally purchase transformers outside of this range, it is a 
very small percentage of the total number of distribution transformers 
purchased. (PE, No. 192 at p. 4) EEI was not aware of any of member 
that purchased units outside of the current defined kVA range. (EEI, 
No. 185 at p. 5) Finally, BG&E and ComEd noted that DOE has spent a 
significant amount of time developing efficiency levels for each kVA 
size and that therefore they supported the current scope. (BG&E, No. 
182 at p. 3; ComEd, No. 184 at p. 3) Power Partners was also in support 
of the current scope, but noted that if separate product classes were 
established for overhead transformers and network/vault transformers 
the kVA scope for those product classes should be aligned with the 
specific requirements for those product standards. (Power Partners, No. 
155 at p. 3)
    Several stakeholders expressed that additional kVA ranges should be 
added to the scope of coverage. Specifically, Schneider Electric 
requested that for LVDT products, the following kVA ranges would add 
value to the national impact benefits: 1kVA through 500kVA single phase 
and 3kVA through 1500kVA three phase. (Schneider, No. 180 at p. 4) 
Similarly, CDA requested an increased range, urging DOE to extend its 
kVA coverage to sizes about 2,500 kVA. (CDA, No. 153 at p. 2)
    Earthjustice expressed concern over sealed and non-ventilating 
transformers. It felt that these products represented a potential 
loophole for smaller transformers in DL7 and noted that DOE should 
revise its definition to ensure these units do not displace covered 
units. (Earthjustice, No. 195 at p. 6) Similarly, Earthjustice noted 
revisions to the definition of ``uninterruptible power supply 
transformer might be necessary'' as some manufacturers are selling 
exempt UPS units, that are otherwise not covered, for general purpose 
applications at a cost of 30-40 percent lower than covered 
transformers. (Earthjustice, No. 195 at p. 6) CDA requested that DOE 
seek legislation to expand its scope to include power transformers. 
(CDA, No. 153 at p. 2)
    Schneider Electric requested that DOE reevaluate several 
definitions in its scope of coverage. First, it asked that DOE address 
its tap ranges and the determination of covered equipment versus 
products versus exempt equipment to possibly capture further energy 
savings. Second, it requested that DOE re-evaluate special impedance 
transformers and ranges. Finally, it noted that because low voltage is 
limited to 600 volts and below, market conditions have created multiple 
voltages in the 1.2kV class of equipment, but current standards \23\ 
require this equipment to be evaluated as medium voltage or excluded 
since the secondary voltage is limited to less than 600 volts. 
(Schneider, No. 180 at p. 12) Schneider believes that these equipment 
groups and definitions require reconsideration to prevent circumvention 
of standards and capture further energy savings.
---------------------------------------------------------------------------

    \23\ See 10 CFR 431.196.
---------------------------------------------------------------------------

    DOE appreciates the comment on its scope of coverage. With respect 
to kVA, DOE's current standards are consistent with several NEMA 
publications. For liquid-immersed and medium-voltage dry-type 
transformers, both DOE coverage and that of NEMA's TP-1 standard 
extends to 833 kVA for single-phase units and 2500 kVA for three-phase 
units. For low-voltage dry-type units, both DOE coverage and that of 
NEMA's Premium specification extends to 333 kVA for single-phase units 
and

[[Page 23353]]

1000 kVA for three-phase units. DOE cites these documents as evidence 
that its kVA scope is consistent with industry understanding. DOE may 
revise its understanding in the future as the market evolves, but for 
today's rule maintains the kVA scope proposed in the NOPR.
    For sealed and nonventilating transformers, uninterruptible power 
supply transformers, special impedance transformers, and those with tap 
ranges of greater than twenty percent, DOE notes that these types of 
equipment are specifically excluded from standards under EPCA, as 
amended, 42 USC 6291 (35)(B)(ii)), as codified at 10 CFR 431.192.
    Cooper Power systems requested clarification on several points 
relating to scope of coverage. Some transformers are built with the 
ability to output at multiple voltages, any number of which may fall 
within DOE's scope of coverage. For transformers having multiple 
nominal voltage ratings that straddle the present boundaries of DOE's 
scope of coverage (i.e., a secondary voltage of 600/1200 volts), Cooper 
recommended that DOE clarify whether the entire distribution 
transformer is exempt from efficiency standards. Cooper felt it was 
unclear if both configurations would have to meet the efficiency 
standard, neither would meet the standard, or only the secondary 
voltage of 600 would have to meet the standard. (Cooper Power Systems, 
No. 222 at p. 3) Second, for three-phase transformers with wye-
connected phase windings or single-phase transformers that are rated 
for externally connecting in a wye configuration, where the phase-to-
phase voltage exceeds the present boundaries of the definition of 
distribution transformer, Cooper requested that DOE clarify that these 
units are exempt from the standard because the secondary voltage 
exceeds 600 volts. (Cooper Power Systems, No. 222 at p. 3)
    DOE clarifies that the definition of distribution transformer 
refers to a transformer having an output voltage of 600 volts or less, 
not having only an output voltage of less than 600 volts. If the 
transformer has an output of 600 volts or below and meets the other 
requirements of the definition, DOE considers it to be a distribution 
transformer within the scope of coverage and therefore subject to 
standards. This applies equally to transformers with split secondary 
windings (as in Cooper's first example) and to three-phase transformers 
where the delta connection may fall below 601 volts and the wye 
connection may not. DOE also clarifies that once it is determined that 
a transformer is subject to standards, DOE's test procedure requires 
that a transformer comply with the standard when tested in the 
configuration that produces the greatest losses, regardless of whether 
that configuration alone would have placed the transformer at-large 
within the scope of coverage under 10 CFR 431.192.
b. Underground and Surface Mining Transformer Coverage
    In the October 12, 2007, final rule on energy conservation 
standards for distributions transformers, DOE codified 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 those transformers were within its scope of coverage, it was 
not establishing energy conservation standards for underground mining 
transformers. At the time, DOE recognized that the mining transformers 
were subject to unique and extreme dimensional constraints that impact 
their efficiency and performance capabilities. Therefore, DOE 
established a separate equipment class for mining transformers and 
stated that it might 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 maintained 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.
    Several stakeholders commented on DOE's definition for mining 
transformers during the current rulemaking. Joy Global Surface Mining 
recommended that surface mining transformers be added to the exemption 
list under the following definition: ``Surface mining transformer is a 
medium-voltage dry-type distribution transformer that is built only for 
installation in a surface mine, on-board equipment for use in a surface 
mine or for equipment used for digging or drilling above ground. It 
shall have a nameplate which identifies the transformer as being for 
this use only.'' (Joy Global Surface Mining, No. 214 at p. 1) ABB and 
PEMCO agreed that ordinary (i.e., non-surface) mining transformers 
should be moved to the exclusion list in 10 CFR 431.192 (5). (ABB, No. 
158 at p. 5; PEMCO, No. 183 at p. 2) PEMCO felt strongly that 
underground mining transformers should be in the list of transformers 
excluded from the efficiency standard, pointing out that ``underground 
mining transformers require the use of much heavier cores and thus have 
an even larger reason to be excluded than some product types already 
excluded.'' (PEMCO, No. 183 at p. 2) NEMA commented that all 
underground mining transformers should be made exempt from the DOE 
energy efficiency regulation for MVDT due to the special circumstances 
they must operate under; dimensions and weight are critical for these 
products, and to reduce the weight and size these transformers are 
operated near full load, therefore, compliance with DOE regulation will 
not optimize efficiency. (NEMA, No. 170 at p. 11) Cooper Power 
suggested that DOE expand the definition of mining transformers to 
include both liquid filled and dry-type transformers, and specify that 
this only applies to transformers used inside the mine itself; Cooper 
supports the exclusion of these transformers from efficiency standards. 
(Cooper, No. 165 at p. 2) ABB asserted that the definition of mining 
transformers should be expanded to include transformers used for 
digging or tunneling. Furthermore, ABB asserted that such equipment 
should be moved to the exclusion list in 10 CFR 431.192 (5). (ABB, No. 
158 at p. 6)
    DOE has learned from comments received throughout the rulemaking 
that mining transformers are subject to several 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 today's rule, DOE will again set no 
standards for underground mining transformers but expands this 
treatment to include surface mining transformers. Moreover, as 
commenters point out, surface mining transformers are used to operate 
specialized machinery which carries space constraints of its own. 
Furthermore, mining transformers in

[[Page 23354]]

general perform a role that may differ from general power distribution 
in many regards, including lifetime, loading, and often the need to 
supply power at several voltages simultaneously. As DOE had intended 
its prior determination regarding mining transformers to apply to all 
mining activities, for today's rule, DOE will again set no standards 
for underground mining transformers but clarify that this determination 
also applies to surface mining transformers. Thus, DOE has amended the 
definition of ``mining transformer'' to include surface mining 
transformers.
    In view of the above, DOE recognizes a potential means to 
circumvent energy efficiency standards requirements for distribution 
transformers. Therefore, DOE continues to leave both underground and 
surface mining transformers off of the list of distribution 
transformers that are not covered under 10 CFR 431.192, but instead 
reserve a separate equipment class for mining transformers. DOE may set 
standards in the future if it believes that underground or surface 
mining transformers are being purchased as a way to circumvent energy 
conservation standards for distribution transformers otherwise covered 
under 10 CFR 431.192.
c. Step-Up Transformers
    In the 2012 NOPR, DOE proposed to continue to not set standards for 
step-up transformers, as these transformers are not ordinarily 
considered to be performing a power distribution function. However, DOE 
was aware that step-up transformers may be able to be used in place of 
step-down transformers (i.e., by operating them backwards) and may 
represent a potential means to circumvent any energy efficiency 
requirements as standards increase. In the NOPR, DOE requested comment 
regarding this issue.
    Many stakeholders expressed support for adding step-up transformers 
to the scope of coverage. Howard Industries commented that there is no 
practical reason for excluding these transformers, and that DOE should 
require step-up transformers to meet the same efficiency as step-down, 
as long as either the output or input voltage is 600 volts or less. 
They expressed concern that eliminating these transformers would 
present a potential loophole. (HI, No. 151 at p. 12) Prolec-GE agreed, 
noting that to eliminate this loophole, step-up transformers should at 
least indicate their purpose on their nameplates. (Prolec-GE, No. 146 
at pp. 55-56) However, Earthjustice commented that simply requiring 
nameplates for these transformers would be unlikely to deter some users 
from installing step-up transformers in place of covered transformers. 
They expressed their concern that DOE had not addressed potential 
loopholes that had been identified in the rulemaking. (Earthjustice, 
No, 195 at pp. 5-6) Advocates agreed with comments made during 
negotiations arguing that step-up transformers should be covered by new 
standards due to similarities to distribution transformer that could 
easily lead to substitution and circumvention. (Advocates, No. 186 pp. 
5-6) Finally, Berman Economics commented that because step-up 
transformers had not been included in the 2007 final rule, leaving them 
uncovered may lead to unintended circumvention. (Berman Economics, No. 
221 at p. 7)
    Other stakeholders expressed their support for DOE's decision to 
not separately define and set standards for step-up transformers. 
(Cooper, No. 165 at p. 2; NEMA, No. 170 at p. 8; BG&E, No. 182 at p. 3) 
APPA and EEI agreed, pointing out that while in emergency conditions 
one can occasionally see a step-up transformer used as a step-down 
transformer, these situations are rare and overall do not result in 
significant transformer efficiency loss. (APPA, No. 191 at p. 6; EEI, 
No. 185 at p. 5-6) Progress Energy commented similarly, noting that 
they do not purchase step-up transformers for use as step-down 
transformers. (PE, No. 192 at p. 4) ABB and Prolec-GE agreed with the 
decision to not set separate standards for step-up transformers but 
requested that these transformers be identified on their nameplate 
uniformly across the industry. (ABB, No. 158 at p. 6; Prolec-GE, No. 
177 at p. 7) PEMCO commented that no action was necessary as the 
product class falls outside the current definition of a distribution 
transformer. (PEMCO, No. 183 at p. 2) Schneider Electric sought 
clarification given the existing definition in section 431.192 and 
noted that the current standards do not exclude step-up LVDT 
transformers as written. (Schneider, No. 180 at p. 4)
    For today's rule, DOE continues to consider step-up transformers as 
equipment that is not covered, because they do not perform a function 
traditionally viewed as power distribution. Transformer coverage is not 
determined simply based on whether the transformer is stepping voltage 
up or down. DOE clarifies that liquid-immersed step-up transformers 
usually fall outside of the rulemaking scope of coverage because of 
limits on input and output voltage, and not because they are excluded 
per se. Liquid-immersed and medium-voltage dry-type transformers tend 
to fall within DOE's scope of coverage only if stepping down voltage 
because the input voltage upper limit (34.5 kV) is much greater than 
the output voltage limit (600 V). No such distinction exists for LVDT 
transformers, which are covered for input and output voltages of 600 V 
or below, regardless of whether stepping voltage up or down. 
Nonetheless, because of the circumvention risk, DOE will monitor the 
use of step-up transformers and consider establishing standards for 
them, if warranted.
d. 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 has an input 
voltage of 600 V or less; is air-cooled; and 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 affect LVDT standards. 
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.
e. 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 because of certain features 
that may affect consumer utility. (ABB, Pub. Mtg. Tr., No. 89 at p. 
245) In the NOPR, DOE reprinted definitions for these terms, which were 
proposed at various points by committee members. 77 FR 7301. DOE sought 
comment in its NOPR about whether it would be appropriate to establish 
separate equipment classes for any of the following types and, if so, 
how such classes might be defined such that it was not financially 
advantageous for customers to purchase transformers in either class for 
general use. Please see IV.A.2.c for further discussion of DOE's 
equipment classes in today's final rule.
2. Equipment Classes
    DOE divides covered equipment into classes by: (a) The type of 
energy used; (b) the capacity; and/or (c) any performance-related 
features that affect

[[Page 23355]]

consumer utility or efficiency. (42 U.S.C. 6295(q)) Different energy 
conservation standards may apply to different equipment classes (ECs). 
For the preliminary and NOPR analyses, DOE analyzed the same 10 ECs as 
were used in the previous distribution transformers energy conservation 
standards rulemaking.\24\ These 10 equipment classes subdivided 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 2007 final rule. In today's rulemaking, however, DOE has 
decided to address all three types of distribution transformers and is 
establishing new standards for all three types of distribution 
transformers, including low-voltage dry-type distribution transformers. 
Table IV.1 presents the ten equipment classes proposed in the NOPR and 
finalized in this rulemaking and provides the associated kVA range 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
5............................  Dry-type.......  Medium.........  Single.........         20-45kV      15-833 kVA
6............................  Dry-type.......  Medium.........  Three..........         20-45kV     15-2500 kVA
7............................  Dry-type.......  Medium.........  Single.........         46-95kV      15-833 kVA
8............................  Dry-type.......  Medium.........  Three..........         46-95kV     15-2500 kVA
9............................  Dry-type.......  Medium.........  Single.........         >= 96kV      75-833 kVA
10...........................  Dry-type.......  Medium.........  Three..........         >= 96kV   225-2,500 kVA
----------------------------------------------------------------------------------------------------------------

a. Less-Flammable Liquid-Immersed Transformers
    During the previous rulemaking, 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 standards 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).
    DOE revisited the issue in this rulemaking 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. 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.
b. Pole-Mounted Liquid-Immersed Distribution Transformers
    During negotiations and in response to the NOPR, several parties 
raised the question of whether pole-mounted, pad-mounted, and possibly 
other types of

[[Page 23356]]

liquid-immersed transformers should be considered in separate equipment 
classes. For example, pole-mounted distribution transformers may carry 
differential incremental cost characteristics and face different size 
and weight constraints than transformers mounted on the ground. They 
may also have different features, and experience different loading 
conditions than some other transformer types. These type of questions 
led DOE to request comment in the NOPR on whether pole-mounted 
distribution transformers warranted consideration in a separate 
equipment classes. A number of parties responded. In response to 
suggestions in these comments, DOE gave more detailed consideration to 
separating pole-mounted distribution transformers in a supplementary 
NOPR analysis, announced in a June 4, 2012, Notice of Public Meeting 
and Data Availability. 77 FR 32916.
    APPA, ASAP, BG&E, ComEd, Howard, Progress Energy, Pepco, and Power 
Partners all supported separation of pole-mounted transformers into 
separate equipment classes for the above-mentioned reasons. Size and 
weight was the most commonly-cited reason. (APPA, No. 191 at p. 7, No. 
237 at p. 3; ASAP, No. 146 at pp. 69-70; BG&E, No. 146 at p. 69, No. 
182 at p. 4; ComEd, No. 184 at p. 8, No. 227 at p. 2; HI, No. 151 at p. 
4, No. 226 at p. 1; PE, No. 192 at p. 5, Pepco, No. 146 at p. 68, No. 
145 at pp. 2-3; Power Partners, No. 155 at p. 2)
    ABB, NEMA, Berman Economics, Cooper, EEI, AK Steel, and KAEC stated 
that the increase in standards did not warrant separate treatment of 
pole-mounted transformers, stating that separation adds complexity to 
the regulation and does not allow manufacturers of both pole-mounted 
and other types of liquid-immersed distribution transformers to 
standardize manufacturing and design practices across product lines. 
(ABB, No. 158 at p. 6; Berman Economics, No. 150 at p. 19, No. 221 at 
p. 4; Cooper, No. 165 at p. 3; EEI, No. 229 at p. 2; AK Steel, No. 230 
at p. 3; KAEC, No. 149 at p. 4; NEMA, No. 170 at p. 12)
    The Advocates, NEMA, and Prolec-GE commented that separation may be 
warranted but only if DOE opted for higher standards than were proposed 
in the NOPR. (Advocates, No. 158 at p. 13; Prolec-GE, No. 177 at p. 3; 
NEMA, No. 170 at p. 14)
    NEMA further noted that the matter was complicated and that there 
were advantages to both approaches. (NEMA, No. 225 at p. 4) Finally, 
EEI and NRECA commented that DOE should explore the matter but in the 
next rulemaking for distribution transformers. (EEI, No. 185 at p. 7; 
NRECA, No. 172 at p. 7) NRECA supported the concept of separation, but 
this support was qualified by concerns that DOE might raise the 
efficiency levels. (NRECA, No. 172 at pp. 5-6)
    Based on the array of views on this issue and the potential energy 
and cost savings to weigh, DOE conducted further analysis of this of 
liquid-immersed transformers issue and presented the findings of its 
supplementary analysis at a public meeting on June 20, 2012. 77 FR 
32916 (June 4, 2012). In today's rule, DOE has chosen not to separate 
pad and pole-mounted transformers. DOE's concerns about steel 
competitiveness and availability were not resolved through comments in 
response to both the NOPR and the supplemental analysis. Moreover, the 
comments did not demonstrate that establishing standards for 
transformers separated by those on pads and those on poles was superior 
to the approach taken in the proposed rule. Therefore, DOE chose not to 
finalize separate standards for pad-mounted transformers in today's 
final rule. However, DOE appreciates the concerns about allowing 
manufacturers to standardize manufacturing and design practices across 
product lines. DOE may consider establishing separate equipment classes 
for pole-mounted distribution transformers in the future, but at 
present believes the equipment class structure proposed in the NOPR to 
be justified for today's final rule.
c. Network and Vault Liquid-Immersed Distribution Transformers
    During negotiations, several parties raised the question of whether 
network, vault, and possibly other types of liquid-immersed 
transformers should be considered in separate equipment classes. In the 
2012 NOPR, DOE considered separating these types of transformers and 
sought comment from manufacturers on this matter.
    In response to the NOPR, many stakeholders commented on separation 
of network and vault transformers into new equipment classes. Several 
stakeholders expressed support for separate equipment classes for 
network and vault transformers, noting that they agreed with the 
definition put forth by the negotiations working group. (ABB, No. 158 
at p. 6; Adams Electrical Coop, No. 163 at p. 2; APPA, No. 191 at p. 6; 
BG&E, No. 182 at p. 3; BG&E, No. 223 at p. 2; CFCU, No. 190 at p. 1; 
ConEd, No. 184 at p. 4; EEI, No. 229 at p. 2; KAEC, No. 149 at p. 4; 
NEMA, No. 146 at p. 67; NEMA, No. 170 at p. 11; NRECA, No. 172 at p. 5; 
NRECA, No. 228 at pp. 2-3; Power Partners, No. 155 at p. 2) 
Stakeholders felt that this separate equipment class should have 
efficiency standards that are unchanged from the levels that have been 
in effect since January 1, 2010, set in the 2007 final rule. (Cooper, 
No. 165 at p. 3; Cooper Power Systems, No. 222 at p. 4; EEI, No. 185 at 
p. 3; NEMA, No. 170 at p. 8; PE, No. 192 at p. 5; Prolec-GE, No. 177 at 
pp. 7, 12; PE, No. 192 at p. 8)
    Many manufacturers noted that network/vault transformers should be 
separated based on the tight size and space restrictions placed on 
them. (NEMA, No. 225 at p. 3; Prolec-GE, No. 146 at p. 15; ABB, No. 158 
at p. 9) In many cases, manufacturers stated that higher efficiency 
transformers cannot fit into existing vaults and still maintain 
required safety and maintenance clearance. (NEMA, No. 170 at p. 3) 
Stakeholders argued that any increase in size due to increased 
efficiency standards would eliminate any economic benefit from higher 
efficiency due to the extremely high costs of modifying existing vault 
or other underground infrastructure in urban areas. (Adams Electric 
Coop, No. 163 at p. 2; BG&E, No. 223 at pp. 2-3; ConEd, No. 184 at p. 
4; NRECA, No. 172 at p. 3; Pepco, No. 145 at p. 23; ABB, No. 158 at p. 
9; Howard Industries, No. 226 at pp. 1-2; APPA, No. 191 at p. 4; Pepco, 
No. 145 at p. 3; ConEd, No. 236 at pp. 1-2) Others pointed out that 
expansion of vaults and manholes in city environments is sometimes even 
physically impossible due to space constraints. (ConEd, No. 184 at p. 
4) Howard Industries noted that often American National Standards 
Institute (ANSI) standards govern the sizes of these types of 
transformers based on established maximum dimensional constraints due 
to vault sizing. (HI, No. 151 at p. 3) Prolec-GE commented that the 
application of these transformers not only requires them to be compact, 
but also built to a much higher level of ruggedness and durability. 
(Prolec-GE, No. 238 at pp. 1-2)
    Con Edison, who is the largest user of network- and vault-based 
distribution transformers in the United States, pointed out that while 
it agrees with separation of network-based transformers, modifications 
were needed to the definition presented in Appendix 1-A to include 
transformers purchased by Con Edison, who is the largest user of 
network- and vault-based distribution transformers in the United 
States. (ConEd, No. 236 at p. 2)
    Other stakeholders noted that while network and vault transformers 
could experience dimensional problems at higher efficiencies, these 
problems are

[[Page 23357]]

diminished at lower levels. Berman Economics notes that ``the de 
minimis increase in efficiency proposed by DOE in this NOPR do not 
appear to warrant any such special treatment.'' (Berman Economics, No. 
150 at p. 21) ASAP agreed, noting that if the final rule efficiency 
levels stayed as modest as those in the NOPR then separation was not 
necessary. (ASAP, No. 146 at pp. 66-67)
    Multiple stakeholders expressed hesitation about separating vault 
transformers. Berman Economics recommended that DOE consider a separate 
class for network transformers only, as the additional electronics and 
protections required of a networked transformer likely would make it an 
uneconomic substitute for a non-networked transformer, an argument that 
could not be made for vault transformers. (Berman Economics, No. 221 at 
p. 5) Furthermore, Advocates pointed out that vault transformers may be 
a compliance loophole/risk and, at minimum, nameplate marking that 
reads ``For installation in a vault only,'' should be required for this 
equipment. (Advocates, No. 235 at p. 4) Others noted that the idea of 
vault transformers being used as substitutes for pad-mounted 
transformers is ``fraught with over-simplifications and faulty 
assumptions.'' (APPA, No. 237 at pp. 2-3) They believed that 
substitution would not occur if DOE defined and carved out network and 
vault transformers per the IEEE definitions. (APPA, No. 237 at pp. 2-3) 
It was also pointed out that utilities pay as much as two times as much 
for a vault transformer as for pad-mounted units of similar capacity. 
(EEI, No. 229 at p. 5)
    DOE appreciates the attention and depth of thought given by 
stakeholders to this nuanced rulemaking issue. At this time, DOE 
believes that establishing a new equipment class for network and vault 
based transformers is unnecessary. It is DOE's understanding that there 
is no technical barrier that prevents network and vault based 
transformers from achieving the same levels of efficiency as other 
liquid-immersed distribution transformers. However, DOE does understand 
that there are additional costs, besides those to the physical 
transformer, which may be incurred when a replacement transformer is 
significantly larger than the original transformer and does not allow 
for the necessary space and maintenance clearances. Rather than 
establishing a new equipment class, DOE has considered the costs for 
such vault replacements in the NIA. Please see section X. Therefore, as 
stated, DOE is not establishing a new equipment class for these 
transformer types, but may consider doing so in a future rulemaking.
d. 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) Other parties 
responded in response to the NOPR with suggestions about how to address 
BIL ratings in liquid-immersed distribution transformers. NEMA pointed 
out that as BIL increases, a greater volume of core material is needed, 
adding both expense and no-load losses. (NEMA, No. 170 at p. 4) Cooper 
agreed with separation by BIL, pointing out that ``standards by BIL 
level will help differentiate transformers that require more insulation 
and that are less efficient by nature.'' (Cooper, No. 165 at p. 3) 
Howard Industries opined that it felt 200 kV BIL and higher 
transformers should have their own category whose efficiency levels 
were capped at those set in the 2007 Final Rule. It noted that high BIL 
ratings require additional insulation to meet American National 
Standards Institute (ANSI) requirements and such additional insulation 
limits the achievable efficiency for these transformers. (HI, No. 151 
at p. 12) Berman Economics supported separation, and commented that DOE 
could split at 200 kV if these transformers would not be cheaper than 
150 BIL transformers at the newly set standard. (Berman Economics, No. 
221 at p. 6) BG&E does not purchase 200 kV BIL transformers but 
supported maintaining the current 2007 Final Rule efficiency levels for 
these transformers due to construction and weight limitations. (BG&E, 
No. 223 at p. 2)
    Several stakeholders felt that separate standards should be set for 
all transformers with a BIL of 150 kV or higher. (NRECA, No. 228 at p. 
3; Advocates No. 235 at pp. 4-5; EEI, No. 229 at pp. 5-6; APPA, No. 237 
at p. 3) Stakeholders who supported a split at 150 kV felt that all 
transformers with BILs above this level should not have increasing 
standards in this rule; the standards should remain at efficiency 
levels set in the 2007 final rule. (NEMA, No. 225 at p. 3-4; Howard 
Industries, No. 226 at p. 2) Prolec-GE pointed out that a class of only 
200 kV and above is of extremely limited volume and provides no 
benefit, stating that there is a significant step up in cost for higher 
efficiencies at 150 kV BIL. (Prolec-GE, No. 238 at p. 2) ``To prevent 
substitution of higher BIL rated transformers as a means of 
circumventing the efficiency standard, Cooper recommends using coil 
voltage as a defining criterion for the 150 kV BIL class. Transformers 
having an insulation system designed to withstand 150 kV BIL and either 
a line-to-ground or line-to-neutral voltage that is 19 kV (e.g. 
34500GY/19920 or 19920 Delta) or greater would be required to qualify 
as a true 150 kV BIL distribution transformer.'' (Cooper Power Systems, 
No. 222 at pp. 3-4)
    NEMA and KAEC recommended that the efficiency levels proposed in 
the NOPR be set for liquid-immersed transformers at 95 kV BIL and below 
only, while all other BILs remain at the current standard. (NEMA, No. 
170 at p. 10; KAEC, No. 149 at p. 5) Prolec-GE agreed that the liquid-
immersed transformers should be separated at 95 kV BIL and below and 
above 95 kV. It also suggested that DOE add more design lines for these 
equipment classes, as it did not believe the scaling was accurate. 
(Prolec-GE, No. 177 at p. 8) Power Partners commented that there should 
be several BIL divisions for liquid-immersed distribution transformers 
and suggested that DOE have equipment classes for the following: 7200/
12470Y 95BIL, 14400/2490Y 125BIL, 19920/34500Y 150BIL, and 34500 200 
BIL. (Power Partners, No. 155 at p. 3)
    Several stakeholders supported the concept of exploring how BIL 
affects efficiency but felt that it was not a significant enough issue 
to delay publication of this rule. They proposed that DOE investigate 
this concept in the next rulemaking. (PE, No. 192 at p. 6; NRECA, No. 
172 at p. 6; EEI, No. 185 at p. 8; ComEd, No. 184 at p. 10; BG&E, No. 
182 at p. 5; APPA, No. 191 at p. 7) Similarly, ABB commented that at 
the current proposed levels, ABB does not recommend moving to a 
separate BIL range for liquid-immersed transformers. If efficiency 
levels were to increase, ABB would support a change, but did not feel 
it is warranted with the proposed levels. (ABB, No. 158 at p. 7) HVOLT 
agreed that at proposed levels, separating by BIL was likely not 
needed, and pointed out that efficiency impacts of varied BIL were 
smaller in liquid-immersed transformers than in dry-type transformers. 
(HVOLT, No. 146 at p. 73)
    DOE appreciates all of the input regarding separating standards for 
different BIL ratings of liquid-immersed distribution transformers. 
Similar to network- and vault-based transformers, DOE may give strong 
consideration to establishing equipment classes by BIL rating when 
considering increased

[[Page 23358]]

future standards, but does not perceive a strong technological need for 
such separation at the efficiency levels under consideration in today's 
rule and does not, therefore, establish separate equipment classes for 
liquid-immersed distribution transformers by BIL rating.
e. Data Center Transformers
    During negotiations, participants noted that data center 
transformers may experience disproportionate difficulty in achieving 
higher efficiencies due to certain features that may affect consumer 
utility. In the NOPR, DOE proposed the definition below for data center 
transformers and sought comment both on the definition itself, and 
whether to separate data center transformers into their own equipment 
class. It noted that separation, the equipment classes must be defined 
such that it would not be financially advantageous for consumers to 
purchase data center transformers for general use.
    i. 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 energizing 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--
    1. during energizing of the transformer without external devices 
attached to the transformer that can reduce inrush current;
    2. the transformer shall be energized at zero +/- 3 degrees voltage 
crossing of a phase. Five consecutive energizing 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;
    3. 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
    4. 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 as a Nationally Recognized Testing Laboratory (NRTL), 
under the Occupational Safety and Health Administration, U.S. 
Department of Labor, for a K-factor rating greater than K-4, as defined 
in Underwriters Laboratories (UL) Standard 1561: 2011 Fourth Edition, 
Dry-Type General Purpose and Power Transformers;
    2. temperature rise less than 130[deg]C with class 220 \25\ 
insulation or temperature rise less than 110[deg]C with class 200 \26\ 
insulation;
---------------------------------------------------------------------------

    \25\ International Electrotechnical Commission Standard 60085 
Electrical Insulation--Thermal Evaluation and Designation, 3rd 
edition, 2004, page 11 table 1.
    \26\ International Electrotechnical Commission Standard 60085 
Electrical Insulation--Thermal Evaluation and Designation, 3rd 
edition, 2004, page 11 table 1.
---------------------------------------------------------------------------

    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.
    Several stakeholders responded to the request for comment on data 
center transformers. HVOLT agreed with the idea of creating a separate 
equipment class for data center transformers, but noted that ``the 
concept of the inrush current held to four times rating is not 
accurate.'' (HVOLT, No. 146 at p. 65) NEMA and KAEC supported the 
establishment of a separate equipment class for data center 
transformers as well as the definition developed by the working group 
and recommended that the efficiency levels for this new class remain at 
EL0, which is equivalent to the levels of NEMA's standard TP-1 2002. 
(NEMA, No. 170, at p. 9; KAEC, No. 149 at p. 4 NEMA, No. 170 at p. 5) 
ABB agreed, noting that it supported the definition developed by the 
working group and a separate equipment class for LVDT data center 
transformers. (ABB, No. 158 at p. 6) Cooper Power supported the 
definition, and recommended that the efficiency level for these 
transformers remain at the baseline. (Cooper, no. 165 at p. 3) NRECA 
noted that few of its members serve data centers and that it does not 
have any data on load factors and peak responsibility factors for data 
centers, but pointed to Uptime Institute and Lawrence Berkeley National 
Laboratories as sources that may have such data available. (NRECA, No. 
172 at p. 5) Howard Industries commented that this proposal would not 
directly affect it or its products and until further information is 
given it could give no response on whether or, so had not there is a 
necessity for establishing a separate equipment class at this time. 
(HI, No. 151 at p. 3) Finally, Cooper power suggested that, if a 
separate definition for data center transformers is adopted, a 75 
percent load level should be used in the test procedure. (Cooper, No. 
165 at p. 3)
    DOE appreciates the comments received about data center 
transformers. In today's rule, DOE is not establishing separate 
equipment classes for data center transformers for several reasons. 
First, after reviewing the proposed definition with technical experts, 
DOE has come to believe that not all of the listed clauses in the 
definition are directly related to efficiency as it would pertain to 
the specific operating environment of a data center. For example, the 
requirement for copper windings would seem generally to aid efficiency 
rather than hinder it. Second, DOE believes that there may be risk of 
circumvention of standards and that a transformer may be built to 
satisfy the data center definition without significant added expense. 
Third, DOE understands that operators of data centers are generally 
themselves interested in equipment with high efficiencies because they 
often face large electricity costs. If that were true, they may be 
purchasing at or above today's standard and be unaffected by the rule. 
Finally, DOE understands that the most significant technical 
requirement of data center transformers to be related to inrush 
current. In the worst possible case, DOE understands that operators of 
data center transformers can (and perhaps already do) take measures to 
limit inrush current external to the transformer. For these reasons, 
DOE is not establishing a separate equipment class for data center 
transformers in today's rule.
f. Noise and Vibration
    Progress Energy recommended to DOE that ``any change in efficiency 
requirements fully investigates the impact of higher sound levels and/
or vibration.'' (PE No, 92 at p. 10) Progress Energy noted that higher 
sound or vibration levels or both will be of significant concern where 
users are nearby. (PE, No. 192 at p. 10) Southern California Edison 
reported that it had experienced ferroresonance issues with amorphous 
core transformers in the past. Further, it expressed ferroresonance 
concerns about lower loss designs with M2 core steel. (Southern 
California Edison, No. 239 at p. 1) However, neither EEI nor APPA were 
aware of vibration or acoustic noise issues associated with higher 
efficiency transformers but conceded that, if there were to be 
ferroresonance issues with higher efficiency transformers, it could 
impact customer satisfaction, especially in residential areas. (EEI, 
No. 185 at p. 19; APPA, No. 191 at p. 13-14) Cooper Power Systems

[[Page 23359]]

commented that it did not expect that the new standards as proposed 
will have any negative effect on performance or increase vibration or 
acoustic noise. (Cooper, No. 165 at p. 6)
    DOE understands that, in certain applications, noise, and 
vibration, or harshness (NVH) could be especially problematic. However, 
based on comments, DOE does not believe that NVH concerns would be 
significant under the efficiency levels proposed and it does not 
propose to establish equipment classes using NVH as criteria for 
today's rule. DOE notes that several manufacturers offer technologies 
that reduce NVH in cases where it may be of unusual concern.
g. Multivoltage Capability
    As discussed in section IIII.A, many distribution transformers have 
primary and secondary windings that may be reconfigured to accommodate 
multiple voltages. In some configurations, the transformer may operate 
less efficiently.
    NEMA commented that DOE should exclude from further consideration 
transformers with multiple primary windings, because they are 
disadvantaged in meeting higher efficiencies. (NEMA, No. 225 at p. 6) 
On the other hand, Prolec-GE commented that dual voltage distribution 
transformers should be included and treated the same as high BIL units, 
and expressed concern about 7200 X 14400 volt transformers where it 
could be less expensive for a user to purchase the dual voltage unit 
than to purchase a 14400 volt single voltage unit. Further, Prolec-GE 
believes that this issue is limited to simpler dual voltage ratings 
where the ratio of the two primary voltages is exactly 2:1, and that 
this potential loophole was not intended under the proposed 
regulations. (Prolec-GE, No. 238 at p. 2)
    For the reason outlined in view of this Prolec-GE comment, DOE is 
not establishing equipment classes by multivoltage capability in 
today's final rule. Nevertheless, DOE may consider doing so in future 
rulemakings, or consider modification of the test procedure as 
discussed in III.A.4, Dual/Multiple-Voltage Primary Windings.
h. Consumer Utility
    A primary consideration in establishment of equipment classes is 
whether or not the equipment under consideration offers differential 
utility to the consumer. DOE sought comment on the establishment of a 
number of equipment classes, including pole-mounted, data-center, 
network/vault-based, and high BIL distribution transformers to explore 
whether stakeholders believed equipment utility could be affected. ABB 
commented that the levels proposed in the NOPR were unlikely to reduce 
equipment performance or utility. (ABB, No. 158 at p. 10)
    Although most stakeholder discussion of space-constrained 
applications centered around network/vault-based distribution 
transformers, Howard Industries mentioned another compact application--
``ranchrunners''--and requested a separate equipment class for such 
units (HI, No. 151 at p. 5) Based on the limited data submitted, DOE 
does not understand ranchrunners to be used in applications where even 
minimal size increases would necessarily trigger great cost increases. 
Furthermore, DOE does not believe large size or weight increases are 
likely at the standard levels under consideration. DOE may consider 
further consideration of the impact of increased size and weight in 
future rulemakings, but is not establishing separate equipment classes 
for ranchrunners in today's final rule.
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 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 final rule 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-         Lower....................  Higher..................  Higher.
     sectional 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)
    In response to the NOPR, HYDRO-Quebec offered more information on 
their iron-based amorphous alloy ribbon. It noted that it has two 
technologies to produce this amorphous

[[Page 23360]]

ribbon: (1) A continuous in-line annealing of an amorphous ribbon 
moving forward at several meters per second and giving a curved shape 
to the ribbon that remains flexible afterwards and can easily be wound 
into a toroidal core with excellent soft magnetic properties, and (2) a 
new kernel topology for an electrical distribution transformer 
compromising a magnetic core made by rolling up the flexible annealed 
amorphous metal ribbon around the coil. (HQ, No. 125 at p. 1) Hydro-
Quebec explains that production of this rolled-up-core transformer 
technology is automated, and the automated continuous production 
process makes the product cost competitive with foreign production. 
``As for Hydro-Quebec's flexible ribbon, the annealing technology is 
compatible with implementation of compact, high-throughput, automated, 
and continuous production processes directly at the casting plant and 
would thereby benefit from the same advantages pertaining to amorphous 
steels.'' (HQ, No. 125 at p. 2)
    DOE understands that Hydro-Quebec and others worldwide are 
conducting research on cost-effective manufacture of amorphous core 
transformers, and believes that such efforts may ultimately save energy 
and economically benefit consumers. At the present, however, DOE does 
not understand such technology to necessarily enable achievement of 
higher efficiency levels. Furthermore, DOE did not attempt to model 
such technology in its engineering analysis because it could not obtain 
data on what such technology costs when applied at commercial scales.
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 
there is an optimal number.
    In response to the NOPR, Progress Energy noted that the response 
time of core deactivation systems might impair power quality by 
increasing the transformer impedance during the initial cycles of motor 
starting events. (PE, No. 171 at p. 1) 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 NOPR, Progress Energy Carolinas, Inc. commented 
that core deactivation is not a proven technology and would subject 
utility customers to lower reliability.
    DOE 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 leg. In a symmetric core, however, no leg is 
magnetically distinguishable from the other two.
    One manufacturer of symmetric core transformers cited several 
advantages to its 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 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

[[Page 23361]]

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            lb      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.
    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 was not able to 
obtain or produce sufficient data to modify its analysis of symmetric 
cores after the preliminary analysis. For this reason, DOE did not 
consider symmetric core designs as part of the NOPR analysis.
    In response to the NOPR, several manufacturers expressed support 
for excluding symmetric core designs from DOE's analysis. ComEd, EEI, 
Progress Energy, NRECA, and APPA all commented that they were pleased 
to see symmetric core designs excluded from the NOPR analysis. (ComEd, 
No. 184 at p. 11; EEI, No. 185 at p. 9; APPA, No. 191 at p. 9; PE, No. 
192 at p. 7; NRECA, No. 172 at p. 7) BG&E recommended that symmetric 
core designs not be included in the final rule based on previous 
comments that highlighted significant issues with the proposed designs. 
(BG&E, No. 182 at p. 5) Cooper Power pointed out that symmetric core 
designs have not proven themselves in the market place, and therefore 
should be excluded in terms of their technological feasibility. 
(Cooper, No. 165 at p. 4) Similarly, Prolec-GE saw many issues with the 
use of symmetric core in medium-voltage liquid-filled transformers, and 
did not believe that this technology offered benefits. (Prolec-GE, No. 
177 at p. 10)
    ABB and NEMA both observed that any information regarding symmetric 
core technology for distribution transformers is currently considered 
strategic and proprietary and cannot be entered into the public record 
at this time. (ABB, No. 158 at p. 7) NEMA argued further that while it 
is important for DOE to understand the potential of emerging 
technologies, such technologies should not be introduced into the 
regulation until they have proven themselves in the marketplace; 
symmetric core designs are currently of low penetration in the industry 
and have not been proven to offer potential for efficiency improvement. 
(NEMA, No. 170 at p. 11)
    Howard Industries commented that symmetric core technology is not 
appropriate for the majority of the U.S. distribution transformer 
market, noting that this style of design results in much deeper tanks 
and larger pads as well as a new winding configuration. It also pointed 
out that symmetric core designs are patented by Hexaformer AB, in 
Sweden, and manufacturing this technology requires a license from 
Hexaformer. Overall, they feel that the cost to adapt to this 
technology would be large, impractical, and time consuming. (HI, No. 
151 at p. 12) Progress Energy Carolinas, Inc. concurred with Howard 
Industries that the winding configuration for symmetric core designs 
would be problematic. They pointed out that the delta tertiary winding 
needed will be subject to thermal failure, and increase the losses of 
the transformer. Furthermore, they pointed out that the presence of a 
delta tertiary winding on a wye-wye three-phase distribution 
transformer will provide a source for zero-sequence currents to ground 
faults on the source distribution system, resulting in backfeed and, 
consequently, a potentially hazardous situation. (PE, No. 171 at p. 1)
    Finally, Schneider Electric asserted that the efficiency levels 
proposed in the NOPR are not high enough to lead manufacturers to 
evaluate symmetric core technology. It commented that, to fully explore 
these and other technologies, the implementation time and efficiency 
levels must be increased. It was Schneider Electric's opinion that 
further, increasing the levels in small increments and only giving four 
years to transition does not allow for proper research and development 
to be completed to properly comment on any new technology. (Schneider, 
No. 180 at p. 5)
    In response to the NOPR, DOE did not receive any data that would 
force reconsideration of the symmetric core analysis conducted during 
the preliminary analysis. Stakeholders

[[Page 23362]]

expressed support for the exclusion of this technology from the NOPR 
analysis. For all of the above reasons, DOE does not consider symmetric 
core designs as part of the final rule analysis.
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 enables 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.
    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 in 
future rulemakings.
d. Core Construction Technique
    DOE examines a number of core construction techniques in its 
engineering analysis, including butt-lapping, full mitering, step-lap 
mitering, and distributed gap wound construction. Particularly in the 
low-voltage dry-type market, where some smaller manufacturers may not 
own large mitering machines, core construction methodology is of 
concern. In the NOPR, DOE did not examine butt-lapped core construction 
as a design option for design line 7 for steel grades above M6 and, as 
a result, found only butt-lapped designs are feasible through EL 2. 
Since the NOPR, however, DOE has reassessed the assumption that butt-
lapping is not possible beyond EL 2. For design lines 6 and 8, the 
topic of butt-lapping is less consequential. All of DOE's design line 6 
analysis is centered around butt-lapping,\27\ while the use of mitering 
for larger LVDT units (represented by design line 8) is prevalent in 
both the market and DOE's analysis.
---------------------------------------------------------------------------

    \27\ Except for the amorphous design options, because DOE 
eliminates consideration of amorphous cores in butt-lapped and other 
stacked configurations in its screening analysis.
---------------------------------------------------------------------------

    DOE received several comments on core construction method as it 
relates to design line 7. During the negotiated rulemaking, ASAP 
commented that DOE should further explore whether butt-lapping was 
possible beyond EL 2. (ASAP, No. 146 at p. 135, pp. 25-26) HVOLT, a 
power and distribution transformer consulting company, commented that 
butt-lapping could probably get very close to EL 3, but not be the most 
cost competitive choice at that level. (HVOLT, No. 146 at p. 135) ASAP 
also commented that DOE should explore more design options in the 
interest of creating a smoother curve, and that butt-lapped options 
should be among them. (ASAP, No. 146 at pp. 24-25)
    In response to the NOPR, ASAP, two manufacturers of LVDTs, and 
California Investor-Owned Utilities urged DOE to reconsider the 
technological assumptions (including butt-lapping capabilities at 
higher TSLs) behind its TSL 1 proposal. ASAP stated that it believed a 
more careful consideration of the record and a more thorough 
investigation of the impacts on small, domestic manufacturers would 
lead DOE to TSL 3, noting that many manufacturers supported at least 
TSL 2 during the negotiated rulemaking and believed that TSL 2 could be 
attained using butt-lapping. (ASAP, No. 186 at pp. 3, 7-8) Eaton 
generally recommended that DOE standardize efficiency levels to EL 3 
(i.e., NEMA Premium[supreg]), stating that such efficiency levels are 
realistic using current technology and are very close to the standards 
DOE proposed in the NOPR. (Eaton, No. 157 at p. 2) The California IOUs 
commented that DOE should revise its analysis to reflect that core 
construction techniques are currently used to produce efficiencies 
higher than TSL 1 for both small and large manufacturers. (CA IOUs, No. 
189 at p. 2) The group of utilities also stated that NEMA lists 11 
manufacturers committed to delivering LVDTs at NEMA Premium[supreg] 
efficiency levels, including both large and small manufacturers. (CA 
IOUs, No. 189 at p. 2) Schneider Electric reiterated its support of 
efficiency levels higher than those proposed in the NOPR. (Schneider, 
No. 180 at p. 1)
    DOE understands that the ability to produce transformers using a 
variety of construction techniques is important to preserving design 
flexibility. After receiving the above-referenced comments on the NOPR, 
DOE consulted with technical design experts and learned that butt-
lapping is technologically feasible for DL 7 through EL 3. DOE revises 
its understanding of the limits of butt-lapped core construction in 
today's rule to extend through EL 3 in DL 7.

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 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

[[Page 23363]]

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.
1. Nanotechnology Composites
    DOE is aware that materials science research is being conducted 
into the use of nanoscale engineering to improve certain properties of 
materials used in transformers. Nanotechnology is the manipulation of 
matter on an atomic and molecular scale. Such materials have small-
scale structures created through novel manufacturing techniques that 
may give rise to improved properties (e.g., higher resistivity in 
steel) not natively present in the bulk material. At present, DOE has 
not learned of any such materials that meet DOE's criteria of being 
practicable to manufacture and does not consider nanotechnology 
composites in its engineering analysis.
    Many stakeholders were supportive of DOE's decision to exclude 
nanotechnology from their analysis in the NOPR. Howard Industries and 
Cooper Power both expressed that nanotechnology is not a proven 
technology in the field of distribution transformers; nanotechnology is 
still in the research phase and further development would be required 
prior to being viable in the distribution transformer field. (HI, No. 
151 at p. 12; Cooper, No. 165 at p. 4) Prolec-GE agreed, pointing out 
that this technology is ``still in its infancy and there is not enough 
public information to make a practicable analysis if benefits exist.'' 
(Prolec-GE, No. 177 at p. 11) While NRECA, EEI and APPA all expressed 
interest in the development of advanced technologies that could result 
in more efficient transformers, they agree with the above stakeholders 
that this technology is not currently available for distribution 
transformers. (NRECA, No. 172 at p. 7; APPA, no. 191 at p. 9; EEI, No. 
185 at p. 9; BG&E, No. 182 at p. 5) ComEd and Progress Energy noted 
that, due to lack of availability, nanotechnology composites should not 
be included in DOE's final rule. (ComEd, No. 184 at p. 11; PE, No. 192 
at p. 7)
    Stakeholders also noted that information on nanotechnology is not 
currently readily available. ABB pointed out that any information 
regarding the application and design of nanotechnology in distribution 
transformers is considered strategic and proprietary and that these 
composites are not currently commercially available in the distribution 
transformer market. (ABB, No. 158 at p. 7) NEMA agreed, stating, ``this 
technology is in its infancy. Information regarding an individual 
manufacturer's application of this technology is considered strategic 
and proprietary and cannot be divulged in the public record at this 
time.'' (NEMA, No. 170 at p. 11)
    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. Therefore, DOE does not 
consider nanotechnology composites in the today's 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 (``max-tech'') 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

[[Page 23364]]

assessment based on a detailed bill of materials derived from 
transformer teardowns.
    DOE's analysis for this 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 2007 final rule 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-type 
distribution transformers) 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 in order 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 distribution transformers (three 
different BIL levels).
    After developing its DLs, DOE then selected one representative unit 
from each DL for study, 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 on 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 a 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 
to the other, unanalyzed, kVA ratings within that same engineering 
design line.
    PEMCO commented that DOE generated too many designs, and that many 
were impractical or unlikely to sell. (PEMCO, No. 183 at p. 1) EMS 
Consulting made an opposite remark, that DOE's chosen methodology omits 
many possible solutions. (EMS, No. 178 at p. 5) Finally, NEMA commented 
that the ``steepness'' of some of DOE's curves were lower than was 
shown by some manufacturers, ABB in particular. (NEMA, No. 170 at p. 4, 
p. 3) In other words, NEMA questioned whether cost might rise more 
quickly with efficiency than DOE's analysis suggested. Conversely, ATI 
Allegheny commented that DOE did excellent work on the engineering 
analysis. (ATI, No. 181 at p. 1)
    DOE acknowledges both that it may not have analyzed every possible 
design and that, conversely, some designs would be unlikely to be 
considered by many purchasers, but notes that the goal of the 
engineering analysis is to both explore the limits of design 
possibility and establish a cost/efficiency behavior. The Life-Cycle 
Cost and Payback Period Analysis, in turn, examines which of the 
designs would be cost-effective for individual purchasers. It would not 
be practical to attempt to analyze every possible physical design. 
Regarding NEMA's comments, DOE is always seeking constructive feedback 
to aid in the accuracy of its engineering analysis, but cautions that 
comparisons between designs must be made carefully in order to be sure 
that they remain valid across a wide variety of market forces and 
construction techniques. A manufacturer's cost of producing higher-
efficiency units in today's market may be different than the cost of 
meeting those same efficiencies after establishment of energy 
conservation standards, which may lead to production at higher volumes.
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 
unit typical of those used in high volume applications.
    In view of comments received from stakeholders throughout the 
analysis period, 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 
allows DOE's analysis to better reflect the behavior of high kVA, high 
BIL medium-voltage dry-type units and is shown in Table IV.5. 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.

[[Page 23365]]

DOE also notes that as a part of the negotiations process, DOE worked 
directly with multiple interested parties to develop a new scaling 
methodology for the NOPR that addresses some of the interested party 
concerns regarding scaling.

 Table IV.5--Engineering Design Lines (DLs) and Representative Units for
                              NOPR Analysis
------------------------------------------------------------------------
                          Type of                    Representative unit
   EC *        DL       distribution    kVA range   for this engineering
                        transformer                      design line
------------------------------------------------------------------------
1........  1........  Liquid-               10-167  50 kVA, 65 [deg]C,
                       immersed,                     single-phase, 60Hz,
                       single-phase,                 14400V primary, 240/
                       rectangular                   120V secondary,
                       tank.                         rectangular tank,
                                                     95kV BIL.
           2........  Liquid-               10-167  25 kVA, 65 [deg]C,
                       immersed,                     single-phase, 60Hz,
                       single-phase,                 14400V primary, 120/
                       round tank.                   240V secondary,
                                                     round tank, 125 kV
                                                     BIL.
           3........  Liquid-              250-833  500 kVA, 65 [deg]C,
                       immersed,                     single-phase, 60Hz,
                       single-phase.                 14400V primary,
                                                     277V secondary,
                                                     150kV BIL.
2........  4........  Liquid-               15-500  150 kVA, 65 [deg]C,
                       immersed,                     three-phase, 60Hz,
                       three-phase.                  12470Y/7200V
                                                     primary, 208Y/120V
                                                     secondary, 95kV
                                                     BIL.
           5........  Liquid-             750-2500  1500 kVA, 65 [deg]C,
                       immersed,                     three-phase, 60Hz,
                       three-phase.                  24940GrdY/14400V
                                                     primary, 480Y/277V
                                                     secondary, 125 kV
                                                     BIL.
3........  6........  Dry-type, low-        15-333  25 kVA, 150 [deg]C,
                       voltage,                      single-phase, 60Hz,
                       single-phase.                 480V primary, 120/
                                                     240V secondary,
                                                     10kV BIL.
4........  7........  Dry-type, low-        15-150  75 kVA, 150 [deg]C,
                       voltage, three-               three-phase, 60Hz,
                       phase.                        480V primary, 208Y/
                                                     120V secondary,
                                                     10kV BIL.
           8........  Dry-type, low-      225-1000  300 kVA, 150 [deg]C,
                       voltage, three-               three-phase, 60Hz,
                       phase.                        480V Delta primary,
                                                     208Y/120V
                                                     secondary, 10kV
                                                     BIL.
6........  9........  Dry-type,             15-500  300 kVA, 150 [deg]C,
                       medium-                       three-phase, 60Hz,
                       voltage, three-               4160V Delta
                       phase, 20-45kV                primary, 480Y/277V
                       BIL.                          secondary, 45kV
                                                     BIL.
           10.......  Dry-type,           750-2500  1500 kVA, 150
                       medium-                       [deg]C, three-
                       voltage, three-               phase, 60Hz, 4160V
                       phase, 20-45kV                primary, 480Y/277V
                       BIL.                          secondary, 45kV
                                                     BIL.
8........  11.......  Dry-type,             15-500  300 kVA, 150 [deg]C,
                       medium-                       three-phase, 60Hz,
                       voltage, three-               12470V primary,
                       phase, 46-95kV                480Y/277V
                       BIL.                          secondary, 95kV
                                                     BIL.
           12.......  Dry-type,           750-2500  1500 kVA, 150
                       medium-                       [deg]C, three-
                       voltage, three-               phase, 60Hz, 12470V
                       phase, 46-95kV                primary, 480Y/277V
                       BIL.                          secondary, 95kV
                                                     BIL.
10.......  13A......  Dry-type,             75-833  300 kVA, 150 [deg]C,
                       medium-                       three-phase, 60Hz,
                       voltage, three-               24940V primary,
                       phase, 96-                    480Y/277V
                       150kV BIL.                    secondary, 125kV
                                                     BIL.
           13B......  Dry-type,           225-2500  2000 kVA, 150
                       medium-                       [deg]C, three-
                       voltage, three-               phase, 60Hz, 24940V
                       phase, 96-                    primary, 480Y/277V
                       150kV BIL.                    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 \28\ combinations. For the 
engineering analysis, DOE reused many of the design option combinations 
that were analyzed in the 2007 final rule for distribution 
transformers. 72 FR 58190 (October 12, 2007).
---------------------------------------------------------------------------

    \28\ 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 2007 final rule 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.
    DOE incorporated these supplementary designs into the reference 
case (i.e., DOE's default set of assumptions without any sensitivity 
analysis) for the NOPR analysis. Additionally, DOE aimed to consider 
the most popular design option combinations, and the design option 
combinations that yield the greatest improvements in efficiency. While 
DOE was unable to consider all potential design option combinations, it 
did consider multiple designs for each representative unit and 
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

[[Page 23366]]

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 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 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 to be consistent with designs 
submitted by manufacturers.\29\ 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. The design remains that way for today's final rule.
---------------------------------------------------------------------------

    \29\ During the negotiations process, DOE's subcontractor, 
Navigant Consulting, Inc. (Navigant), participated in a 
bidirectional exchange of engineering data with industry 
representatives in an effort to validate the OPS designs generated 
for the engineering analysis.
---------------------------------------------------------------------------

    In response to the NOPR, Eaton noted that this rule provides many 
design options, and allows for the use of various designs and different 
grades of steel, but encouraged DOE to standardize the efficiency 
levels to NEMA Premium[supreg] (i.e., EL 3). (Eaton, No. 157 at p. 2) 
Although Schneider supported the LVDT efficiency levels proposed by DOE 
in the NOPR, the company stated in its NOPR comments that it still 
supports efficiency levels higher than those proposed in the NOPR (as 
evidenced by discussions during the negotiated rulemaking meetings.) 
(Schneider, No. 180 at p. 1)
    ASAP commented that it perceived there to be a ``gap'' in the DL 7 
data, and that DOE should seek to fill that gap by exploring other 
design option combinations corresponding to butt-lapped core 
construction. (ASAP, No. 146 at p. 24-25, 135) In response, DOE first 
generated analysis for two additional design option combinations: An M4 
core with aluminum windings and an M3 core with copper windings. DOE 
includes both sets of results in its final rule engineering analysis. 
In general, DOE notes that preservation of a number of design options 
was a strong consideration in selection of the final standard. Second, 
given these two new design lines discussed above, DOE revisited the 
question of whether DL 7 for LVDTs was achievable by manufacturers with 
butt lapping techniques in order to avoid purchasing mitering 
equipment. Specifically, DOE consulted with technical design experts, 
and they confirmed butt-lapping was technically feasible through EL 3. 
In addition, as detailed in section IV.A.3, DOE received public comment 
supporting this conclusion and did not receive public comments directly 
refuting this conclusion. (See, e.g., ASAP, No. 186 at pp. 3, 7-8; 
Eaton, No. 157 at p. 2; CA IOUs, No. 189 at p. 2)
    Consequently, DOE modified the LVDT standard proposed from TSL 1 to 
TSL 2 in today's final rule.
    DL 7 analysis illustrating the possibility of constructing butt-
lapped cores at EL3 led DOE to reconsider the impacts to small 
manufacturers. DOE originally assumed that a small manufacturer without 
the equipment needed to construct mitered cores would have to either 
invest in such equipment at considerable expense, source cores from a 
third party, or exit that market. As explained in Section IV.I.1, DOE 
calculates the net present value of the industry (``INPV'') in 
attempting to quantify impacts to manufacturers under different 
scenarios. During the NOPR, DOE calculated LVDT INPV to be between $200 
million and $235 million (in 2011$). In today's final rule, that figure 
rises to $227 million to $249 million (in 2011$).
    In addition, as described in the NOPR and as DOE confirmed for the 
final rule, DOE understands that the majority of the LVDT market volume 
is currently imported, much of it from large, well-capitalized 
manufacturers in Mexico. Furthermore, many small businesses operating 
inside the United States cater to niches outside of DOE's scope of 
coverage, and would not be directly affected by the rule. Finally, DOE 
spoke with several small domestic manufacturers and learned that some 
are already able to miter cores, and would make the decision to butt-
lap or miter at EL3 based on economics and without facing large capital 
investment decisions. More detail can be found in Section IV.I.5.b.
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.
    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 from the NOPR to generate 
the range of designs for the final rule 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

[[Page 23367]]

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 2007 final rule 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.
    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 reviewed its materials prices during interviews 
with manufacturers and industry experts and revised its materials 
prices for copper and aluminum conductors. 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, two 
well-known commodities benchmarks. 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. Materials price cases for the 
final rule are identical to those of the NOPR. 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.
    Several stakeholders commented on the material prices used in the 
NOPR. ABB, NRECA, and NEMA all noted that the material costs appeared 
to be too low, both for 2010 and 2011. (ABB, No. 158 at pp. 7-8; NEMA, 
No. 170 at p. 11; NRECA, No. 146 at p. 159) Similarly, Prolec-GE 
pointed out that, as the economy recovers, demand for these materials 
will increase, as will their prices. They agreed that DOE's material 
price projections were too low. (Prolec-GE, No. 177 at p. 11) ATI 
specifically noted that DOE's price for M3 steel was too low in the 
2011 price scenario, and commented that this price is a very important 
one in the analysis. (ATI, No. 146 at pp. 74-75) Progress Energy 
concurred, noting that the price of silicon core steel in DOE's 
analysis was lower than actual prices, and recommended that DOE revise 
all their material prices. (PE, No. 192 at p. 7) Cooper and HI agreed 
with these stakeholders that DOE's material prices were too low, 
specifically pointing out that surcharges need to be included to more 
accurately reflect real world prices. (Cooper, No. 165 at p. 4; HI, No. 
151 at p. 12)
    APPA did not disagree with DOE's material prices, but pointed out 
that if DOE choose to update them, they should update wholesale 
electric prices to the most recent year available as well. (APPA, No. 
191 at p. 9) BG&E and ComEd agreed, pointing out ``base costs, for both 
material and wholesale energy, should reflect from the most recent 
published data for the most recent year.'' (BG&E No. 182 at p. 5; 
ComEd, No. 184 at p. 11) ASAP commented that DOE should re-optimize its 
engineering analysis with respect to the new pricing to find the most 
accurate results. (ASAP, No. 146 at p. 153)
    DOE notes that because it analyzes such a large breadth of designs, 
its engineering analysis is less sensitive to changes in materials 
prices than it otherwise would be. DOE performed a sensitivity analysis 
during the preliminary analysis phase of the rulemaking in order to 
understand the magnitude of the effect of a change in material prices 
and found it to be very small. The differential pricing between the 
designs, upon which the LCC, NIA, and other economics results are 
based, are even less sensitive. DOE believes its conclusions would not 
vary between either case.
    DOE appreciates the above-listed feedback from commenters, however, 
for today's rule, DOE continues to use the 2010 and 2011 materials 
prices that were first included in the NOPR as reference case 
scenarios, which is the most recent and accurate information available 
to DOE. 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.
    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.
6. Markups
    DOE derived the manufacturer's selling price for each design in the

[[Page 23368]]

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 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.
    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.
    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.
    For today's rule, 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 out-sourced.
    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 the per-pound cost of butt-lapped units 
built to the same specifications. (ONYX, Pub. Mtg. Tr., No. 30 at p. 
43) In view of the manufacturer comments, DOE understands 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 
than for medium-voltage transformers, necessitating 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.
    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 the Northwest Energy Efficiency 
Alliance (NEEA) and Northwest Power and Conservation Council (NPCC) 
suggested, noting that the impact of these incremental costs are often 
very minor for large, expensive transformer designs. (NEEA, No. 11 at 
p. 7) Following discussion with Federal Pacific and 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.
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 2007 final rule, 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

[[Page 23369]]

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. DOE 
derived the $0.22 per pound by relying on the shipping costs developed 
in its 2007 final rule, 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.
    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 2007 final rule 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.
    Based on comments received and DOE's additional research into the 
treatment of shipping costs through manufacturer interviews, DOE 
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. This practice 
was retained for the final rule.
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 2007 final rule 
for medium-voltage transformers or by EPACT 2005 for low-voltage 
transformers. 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.
    For today's rule, 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 2007 final rule 
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[supreg] 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.
    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
a. kVA Scaling
    For today's rule, 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 the 2007 final rule on distribution transformers.
    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 final rule 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.

[[Page 23370]]

    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 is smoother and offers a more robust 
scaling behavior over the covered kVA range.
    DOE received a number of comments on the matter of scaling across 
kVA ranges. Cooper Power Systems supported the use of the .75 exponent, 
though noted that it may not hold for higher kVA values. (Cooper, No. 
165 at p. 4) MGLW commented that for single-phase pad-mounted 
distribution transformers the exponent may approach .75, but that it 
was not accurate for single-phase pole-mounted distribution 
transformers, whose curve would be of polynomial form. (MLGW, No. 127 
at p. 1) PEMCO proposed to use a curve in logarithmic space, which 
would create an even more complex behavior in linear coordinates. 
(PEMCO, No. 183 at p. 2) Progress Energy commented that DOE should 
avoid scaling altogether, and instead use data from vendors. (PE, No. 
192 at p. 6) ABB, APPA, BG&E, EEI, Howard, NEMA, NRECA, Power Partners, 
Prolec-GE, Commonwealth Edison, and Schneider all commented that DOE's 
general approach was sound, but that the accuracy of the procedure may 
be improved with more data-validated modeling. (ABB, No. 158 at p. 7; 
APPA, No. 191 at pp. 7-8; APPA, No. 237 at p. 3; BG&E, No. 182 at p. 5; 
EEI, No. 185 at p. 9; HI, No. 151 at p. 12; NEMA, No. 170 at p. 10; 
NRECA, No. 172 at p. 6; Power Partners, No. 155 at p. 3; Prolec-GE, No. 
146 at pp. 82-83; Prolec-GE, No. 177 at p. 10; ComEd, No. 184 at p. 10; 
Schneider, No. 180 at p. 5)
    In the case of equipment class 1, which addresses single-phase 
liquid-immersed distribution transformers, some stakeholders expressed 
confusion on the scaling. Because this equipment class contains three 
design lines and because DOE is deriving a standard using a straight 
line in logarithmic space, it is possible that the three ELs, one from 
each design line) may not fall exactly in-line. In that case, as 
occurred for equipment class one with TSL 1, DOE best fit a straight 
line through three points. APPA, EEI, Berman Economics, NRECA, Pepco, 
and the Advocates both commented that because DOE did not propose a 
standard that aligned with each of these ELs, the economic results were 
not exact. (APPA, No. 191 at p. 3; Berman Economics, No. 150 at p. 2; 
NRECA, No. 2; Pepco, No. 145 at pp. 1-2; Advocates, No. 186 at pp. 9-
10) DOE thanks the commenters for making that clear, and has revised 
its presentation of final rule economic results accordingly.
    For today's rule, DOE finds the NOPR methodology well-supported by 
a large number of stakeholders and continues to employ it. DOE believes 
transformers are approximately well-modeled as power-law devices. In 
other words, attributes of the devices should grow in proportion to the 
size raised to a constant power. The ideal, mathematically derived 
value of that exponent is .75, but in practice transformers may not be 
constructed ideally and other effects may drive the exponent above or 
below .75. DOE believes allowing the exponent to float from .75 where 
justified may help to account for certain size-dependent effects not 
always well captured by the theoretical .75 result.
b. Phase Count Scaling
    In the 2007 final rule, DOE covered both single- and three-phase 
transformers and harmonized standards across phases. More specifically, 
DOE set standards such that a single-phase transformer of a certain 
type (e.g., liquid immersed) and kVA rating (e.g., 100) would be 
required to meet the same standard as would a three-phase transformer 
of the same type and three times the kVA rating (in this example, 300 
kVA liquid immersed). In certain cases, DOE believes there is sound 
technological basis for doing so. For example, three-phase liquid-
immersed distribution transformers mounted on poles are frequently 
constructed using three single-phase cores inside of a single housing. 
Although miscellaneous losses may vary slightly (e.g., bus losses) 
across three- and single-phase pole-mounted units, one would expect the 
core-and-coil efficiencies to be identical for a similar construction 
choices such as steel grade, winding grade, core geometry, etc.
    In many other cases, however, there may not be a strong technical 
basis for strongly coupling single- and three-phase standards. Several 
parties commented on the matter in response to the NOPR.
    Howard Industries and Power Partners both supported linking single- 
and three-phase standards, as was done in the 2007 final rule. (HI, No. 
151 at p. 12; Power Partners, No. 155 at p. 3) ABB, APPA, Cooper, NEMA, 
Progress Energy, Prolec-GE, and Schneider, however, argued that 
construction differences resulted in there being no logical reason to 
link the two standards, and that any standards should be derived from 
independent analysis of each. (ABB, No. 158 at p. 7; APPA, No. 191 at 
p. 7; Cooper, No. 165 at p. 3; NEMA, No. 170 at p. 10; NEMA, No. 170 at 
p. 3; PE, No. 192 at p. 6; Prolec-GE, No. 146 at p. 85; Prolec-GE, No. 
177 at p. 9; Schneider, No. 180 at p. 5)
    In today's rule, DOE follows the convention of the NOPR and does 
not impose the constraint that single- and three-phase efficiencies 
must be linked. DOE notes, however, that standards were harmonized 
across phase counts in the case of single-phase MVDT equipment classes, 
where market volume is minimal and direct analysis of such units a 
lower priority.
9. Material Availability
    Throughout this rulemaking, DOE received several comments 
expressing concern over the availability of materials, including core 
steel and conductors, needed to build energy efficient distribution 
transformers. These issues pertain to a global scarcity of materials as 
well as issues of materials access for small manufacturers.
    DOE is aware that many core steels, including amorphous steels, 
have constraints on their supply and presents an analysis of global 
steel supply in TSD 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 engineering analysis, DOE only considered transformer 
designs with impedances within the normal impedance ranges specified in 
Table 1 and Table 2 of 10 CFR 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.
    Several stakeholders expressed concern over efficiency standards 
that could potentially cause changes in impedance. Progress Energy, 
BG&E, NEMA and ComEd all commented that the increased efficiency levels 
in the 2010 standards resulted in changes in impedance values. (PE, No. 
192 at p. 11;

[[Page 23371]]

BG&E, No. 182 at p.10; ComEd, No. 184 at p. 15; NEMA, No. 170 at pp. 
18-19) ``Manufacturers are already having challenges with transformer 
designs that meet the efficiencies required in the Final Rule dated 
October 12, 2007, the minimum impedance requirement of 5.3% and weight 
limit of 3,600 lbs * * * for select ComEd designs * * * only one of 
five suppliers from which ComEd is currently purchasing can meet the 
efficiency, impedance and weight requirements.'' (ComEd, No. 184 at p. 
15) Howard Industries concurred that changes in efficiency standards 
may also change impedance, commenting that for SPS type designs higher 
efficiency levels typically bring lower impedance which leads to short 
circuit let-through current. (HI, No. 151 at p. 12) BG&E also noted 
that if higher efficiency standards drive impedance ranges outside of 
the IEEE required range, utilities will be forced to change out a whole 
block of transformers, even if only one is directly affected, to ensure 
matching impedances and a safe, reliable installation. (BG&E, No. 182 
at p. 10) NRECA and APPA second this point, noting that transformers 
must meet IEEE standards concerning impedance values while 
simultaneously meeting or exceeding the DOE minimum efficiency 
standards. (NRECA, No. 172 at p. 11; APPA, No. 191 at p. 14) Schneider 
Electric pointed out that changes in impedance levels impact the 
voltage drop of the system and potential increased impedance due to 
higher efficiency designs could impact overall energy conservation; the 
impact in line losses from the increased impedance could offset any 
benefits obtained in the transformer. (Schneider, No. 180 at p. 11) ABB 
expressed concern that the X/R ratio could rise with increasing 
standards which could result in higher losses in the distribution 
system as a whole. It is ABB's opinion that if there is an applicable 
industry standard for a specific transformer then the X cannot be 
adjusted as easily and will result in an increased X/R. (ABB, No. 158 
at p. 10) Furthermore, it noted that as efficiency increases, 
resistance decreases, causing a higher X/R ratio. They commented that 
if there is no applicable industry standard on a specific transformer 
for impedance values, the X could be offset to correlate with the 
change in R, however, this would lead to an increase in the percent 
[voltage] regulation \30\ and higher losses in the transformer. If 
there is an industry standard, the X cannot be adjusted as easily and 
will result in an increased X/R. (ABB, No. 158 at p. 10) ConEd also 
pointed out that higher efficiencies may lead to higher inrush 
currents, which may require installation of more robust and costly 
distribution components to be installed which would increase costs. 
(ConEd, No. 236 at p. 4)
---------------------------------------------------------------------------

    \30\ In other words, how well a transformer maintains output 
voltage as load increases.
---------------------------------------------------------------------------

    On the other hand, various stakeholders claimed that there was no 
direct relationship between impedance and efficiency levels. EEI 
commented that they would be concerned if higher standards would make 
it more difficult for manufacturers to meet the necessary requirements 
for impedance, inrush current and X/R ratio, but noted that they are 
not currently aware of any existing direct relationship. (EEI, No. 185 
at p. 20) Prolec-GE agreed, noting that they did not see any issues 
with inrush, X/R ratios, or impedance at the levels proposed in the 
NOPR. (Prolec-GE, No. 177 at p. 16)
    For today's rule, DOE continued to consider only designs within the 
normal impedance ranges used in the preliminary analysis. DOE believes 
that this demonstrates the possibility of manufacturing a variety of 
impedances at efficiencies well in excess of those adopted in today's 
rule. 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 accounts for the cost considerations of 
higher and lower impedance tolerances. Furthermore, DOE believes the 
standards under consideration in the NOPR to be of modest enough 
increase to minimize serious concern with respect to impedance and X/R 
ratio.
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.
    For today's 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.
    Nonetheless, DOE notes that the majority of its designs are within 
weight constraints suggested by stakeholders. 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.
    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.
    Based on comments from interested parties, for the NOPR DOE added a 
new distribution channel to represent the direct sale of transformers 
to utilities, which account for approximately 80 percent of liquid-
immersed transformer shipments. Howard Industries and Prolec-GE agreed 
with DOE's estimate that 80 percent of transformers are sold by 
manufacturers to utilities. (HI, No. 151 at p. 8; Prolec-GE, No. 177 at 
p. 13) For the final rule, DOE retained this distribution channel.
    DOE developed average distributor and contractor markups by 
examining the installation and contractor cost estimates provided by RS 
Means

[[Page 23372]]

Electrical Cost Data 2011.\31\ DOE developed separate markups for 
baseline equipment (baseline markups) and for the incremental cost of 
more-efficient equipment (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.
---------------------------------------------------------------------------

    \31\ RSMeans Electrical Cost Data 2011; 2010; J.H. Chiang, C. 
Babbitt.
---------------------------------------------------------------------------

    Chapter 6 of the final rule TSD provides additional detail on the 
markups analysis.

E. Energy Use Analysis

    The energy use analysis produced energy use estimates and end-use 
load shapes for distribution transformers. The energy use estimates 
enable evaluation of energy savings from the operation of distribution 
transformer equipment at various efficiency levels, while the end-use 
load characterization allows evaluation of the impact on monthly and 
peak demand for electricity.
    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.
    Transformer loading is an important factor in determining which 
types of transformer designs will deliver a specified efficiency, and 
for calculating transformer losses. For the NOPR, DOE estimated a range 
of loading for different types of transformers based on analysis done 
for the 2007 final rule. During the negotiations the load distributions 
were presented and found to be reasonable by the parties. In addition, 
data submitted by Moon Lake Electric during the negotiations were used 
to validate the load models for single-phase liquid-immersed 
distribution transformers.
    For the NOPR, higher-capacity three-phase liquid-immersed and 
medium-voltage dry-type transformers were loaded at 20 to 66 percent, 
and smaller capacity single-phase medium-voltage liquid-immersed 
transformers were loaded at 20 to 60 percent. Low-voltage dry-type 
transformers were loaded at 3 to 45 (mean of 25) percent.
    Cooper stated that the average loading used for liquid-filled 
transformers was underestimated, and historical utility evaluation 
factors suggest 50 percent loading for single-phase liquid-immersed 
transformers and closer to 60 percent for three-phase liquid-immersed 
transformers. (Cooper, No. 165 at p. 5) EEI stated that higher capacity 
three-phase distribution transformers are likely to be serving large 
industrial facilities with higher loading factors. (EEI, No. 185 at p. 
14) Utilities stakeholders responded with a wide range of average 
loading values that they have on their distribution transformers: ComEd 
stated that its aggregated load factors range from approximately 40 to 
70 percent depending on the customer class. (ComEd, No. 184 at p. 2) 
MLGW stated that its average aggregated load factor was approximately 
17 percent across its distribution system. (MLGW, No. 133 at p. 1) 
PEPCO agreed that the average aggregate load factors presented in the 
NOPR were a good compromise and that they should not be changed. 
(PEMCO, No.183 at p. 2)
    As previously mentioned, DOE was able to validate its load models 
for single-phase liquid-immersed transformers using submitted data, so 
it retained the loading used in the NOPR for the final rule. For three-
phase liquid-immersed transformers, DOE believes that the comment from 
Cooper does not provide an adequate basis for changing the loading 
range that was viewed as reasonable by the parties to the negotiation 
and the loading values provided by utilities comport with DOE's 
estimated loadings.
    Dry-type distribution 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.\32\ 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) \33\ were 
used to estimate the amount of floor space of buildings that might use 
the type of transformer covered by the rulemaking. The statistical 
weights assigned to the building sample were rescaled to reflect this 
additional floor space. Only the weighting of large buildings were 
rescaled.
---------------------------------------------------------------------------

    \32\ 1992 Commercial Building Energy Consumption and 
Expenditures Survey (CBECS); 1995; U.S. Department of Energy--Energy 
Information Administration; http://www.eia.doe.gov/emeu/cbecs/microdat.html.
    \33\ Manufacturing Energy Consumption Survey (MECS); 2006 U.S. 
Department of Energy--Energy Information Administration; http://www.eia.gov/emeu/mecs/contents.html.

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

[[Page 23373]]

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.\34\ The LCC is the total customer expense 
over the life of a type of equipment, 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 equipment. 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 type of equipment 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.
---------------------------------------------------------------------------

    \34\ 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.
---------------------------------------------------------------------------

    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 market for equipment that exceeds 
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.16 
below summarizes the major inputs to the LCC and PBP analysis, and 
whether those inputs were revised for the final rule.
    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. Therefore, while some atypical situations 
may not be captured in the analysis, DOE believes the analysis captures 
an adequate range of situations in which transformers operate.

           Table IV.6--Key Inputs for the LCC and PBP Analysis
------------------------------------------------------------------------
                                                         Changes for the
            Inputs                 NOPR description        final rule
------------------------------------------------------------------------
                        Affecting Installed Costs
------------------------------------------------------------------------
Equipment price...............  Derived by multiplying  No change.
                                 manufacturer selling
                                 price (from the
                                 engineering analysis)
                                 by distributor markup
                                 and contractor markup
                                 plus sales tax for
                                 dry-type
                                 transformers. For
                                 liquid-immersed
                                 transformers, DOE
                                 used manufacturer
                                 selling price plus
                                 small distributor
                                 markup plus sales
                                 tax. Shipping costs
                                 were included for
                                 both types of
                                 transformers.
Installation cost.............  Includes a weight-      Added pole
                                 specific component      replacement
                                 derived from RS Means   cost for design
                                 Electrical Cost Data    line 3.
                                 2011 and a markup to
                                 cover installation
                                 labor, pole
                                 replacement costs for
                                 design line 2 and
                                 equipment wear and
                                 tear.
Baseline and standard design    The selection of        No change.
 selection.                      baseline and standard-
                                 compliant
                                 transformers depends
                                 on customer behavior.
                                 The fraction of
                                 purchases evaluated
                                 was 10% for liquid-
                                 immersed
                                 transformers, 2% for
                                 low-voltage dry-type
                                 and 2% for medium-
                                 voltage dry-type
                                 transformers.
------------------------------------------------------------------------
                        Affecting Operating Costs
------------------------------------------------------------------------
Transformer loading...........  Modeled loading as a    No change.
                                 function of
                                 transformer 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 demand..  Derived from a          No change.
                                 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 AEO
                                 Energy Outlook 2011     2012. Price
                                 (AEO2011).              trends for
                                                         liquid-immersed
                                                         transformers
                                                         are based on a
                                                         mix of
                                                         generating fuel
                                                         prices.
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      No change.
                                 rates ranged from
                                 3.7% for owners of
                                 liquid-immersed
                                 transformers to 4.6%
                                 for dry-type
                                 transformer owners.
Lifetime......................  Distribution of         No change.
                                 lifetimes, with mean
                                 lifetime for both
                                 liquid and dry-type
                                 transformers assumed
                                 to be 32 years.
------------------------------------------------------------------------


[[Page 23374]]

    The following sections contain brief discussions of comments on the 
inputs and key assumptions of DOE's LCC and PBP 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.
    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.
    DOE used evaluation rates as follows: 10 percent of liquid-immersed 
transformers were evaluated, 2 percent of low-voltage dry-type 
transformers were evaluated, and 2 percent of medium-voltage dry-type 
transformers were evaluated. The transformer selection approach is 
discussed in detail in chapter 8 of the final rule TSD.
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.
    To forecast a price trend for the NOPR, DOE derived an inflation-
adjusted index of the PPI for electric power and specialty transformer 
manufacturing from 1967 to 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 due to global demand for distribution 
transformers and rising commodity costs for key transformer components. 
Given the uncertainty, DOE chose 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 did not receive comments on the most appropriate trend to use 
for real transformer prices, and it retained the approach used for the 
NOPR for today's final rule.
b. Installation Costs
    Higher efficiency distribution transformers tend to be larger and 
heavier than less efficient designs. The degree of weight increase 
depends on how the design is modified to improve efficiency. In the 
NOPR analysis, DOE estimated the increased cost of installing larger, 
heavier transformers based on estimates of labor cost by transformer 
capacity from Electrical Cost Data 2011 Book by RSMeans.\35\ DOE 
retained the same approach for the final rule. DOE's analysis of 
increase in installation labor costs as transformer weight increases is 
described in detail in chapter 6 of the final rule TSD.
---------------------------------------------------------------------------

    \35\ J.H. Chiang, C. Babbitt ; RSMeans Electrical Cost Data 
2011; 2010.
---------------------------------------------------------------------------

    For pole-mounted transformers, represented by design lines (DL) 2 
and 3, 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 existing transformer 
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 NOPR analysis, it was assumed that a pole change-out will only 
be necessary if the weight increase is larger than 15 percent of the 
weight of the baseline unit, which DOE used to represent the existing 
transformer, and more than 150 pounds heavier for a design line 2 
transformer, and 1,418 pounds heavier for a design line 3 transformer. 
While EEI stated that it may take less than a 1,418 pound increase for 
a design line 3 distribution transformer to require a pole change out 
(EEI, No. 229 at p. 2), neither EEI nor its members provided comments 
to support a different value. Therefore, DOE believes there is not a 
compelling reason to change from the approach used in the NOPR. Utility 
poles are primarily made of wood. Both ANSI \36\ and the National 
Electrical Safety Code (NESC) \37\ 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. Accounting for this ``over-sizing,'' DOE estimated that 
the total fraction of pole replacements would not exceed 25 percent of 
the total population. Chapter 6 of the final rule TSD explains the 
approach used to arrive at this figure.
---------------------------------------------------------------------------

    \36\ American National Standards Institute (ANSI), Wood Poles--
Specifications and Dimension, ANSI O5.1.2008, 2008.
    \37\ Institute of Electrical and Electronics Engineers (IEEE), 
2012 National Electrical Safety Code (NESC), IEEE C2-2012, 2012.
---------------------------------------------------------------------------

    HI commented that there very likely will be a sizeable number of 
situations where a new pole may be required, but it noted that DOE's 
assumption that up to 25 percent of the total pole-mounted transformer 
population may require pole replacements is probably a reasonable 
figure. (HI, No. 151 at p. 8) EEI, APPA and NRECA suggested that the 
pole change-out fraction be increased to as high as 50 percent to 75 
percent of units located in cities with populations of at least 25,000. 
(EEI, No. 185 at p. 14; NRECA, No. 172 at p. 10; APPA, No. 191 at p. 
12) EEI, NRECA, and APPA did not provide evidence or rationale to 
support their suggestion of a higher change-out fraction for urban 
utilities in their comments. Therefore, DOE believes there is not a 
compelling reason to change from the approach used in the NOPR.
    The second step is to determine the cost of a pole change-out. In 
the NOPR phase, specific examples of pole change-out costs were 
submitted by the sub-committee. These examples were consistent with 
data taken from the

[[Page 23375]]

RSMeans Building Construction Cost database.\38\ Based on this 
information, for design line 2 with a capacity of 25 kVA, 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. For design line 3 with a 
capacity of 500 kVA, DOE used a similar distribution with a lower limit 
of $5,877 and an upper limit of $13,274 for pole replacement, and a 
distribution with a lower limit of $5,877 and an upper limit of $16,899 
for multi-pole (platform) replacement. These costs are in addition to 
the weight-based installation cost described above.
---------------------------------------------------------------------------

    \38\ J.H. Chiang, C. Babbitt; RSMeans Electrical Cost Data 2011; 
2010.
---------------------------------------------------------------------------

    Utility poles have a finite lifetime so, in some cases, 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 
effect, 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.\39\
---------------------------------------------------------------------------

    \39\ 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.
---------------------------------------------------------------------------

    DOE received a number of comments on pole replacement costs. Westar 
stated that it costs them approximately $2,330 to replace an existing 
pole with a 50-foot Class 1 pole for a 100 kVA distribution 
transformer, which might be the new norm for residential areas. It 
added that whenever they replace a pole they would lose NESC 
grandfathering for that structure and have to redo everything on the 
pole to bring it up to the current NESC code, instead of merely 
switching out the transformer. This results in additional labor. 
(Westar, No. 169 at p. 2) BG&E commented that DOE's methodology may not 
reflect the true costs of pole change-outs, as pole replacement costs 
quoted by industry experts are either estimates or they reflect actual 
costs from previous years. In BG&E's experience, actual costs tend to 
exceed the estimates by a significant amount (20 to 60 percent). In 
2011, its average pole replacement cost was $7,100, which includes the 
cost of the new pole along with any replacement material used during 
the installation. (BG&E, No. 223 at p. 2) ComEd also stated that DOE 
may have underestimated the cost of pole change-outs. At ComEd, the 
average pole replacement cost is in the range of $4,000-$5,000, which 
includes the cost of the new pole along with any replacement material 
and labor. (ComEd, No. 184 at p. 13) Progress Energy stated that it 
realized average pole replacement costs of $2,200 during 2011, but it 
noted that during the negotiated meetings, utilities reported pole 
replacement costs upwards of $12,000. Progress Energy recommended that 
DOE continue to use the pole replacement costs that they have been 
using so that the final rule will not be delayed. (Progress Energy, No. 
192 at p. 9) EEI suggested that DOE increase the pole change-out cost 
estimates to a range of values (or a weighted average) provided by EEI 
member companies. (EEI, No. 185 at p. 14)
    The information that DOE received regarding average pole 
replacement costs was of limited use because most of the utilities did 
not provide their average pole replacement costs for the transformer 
capacities used in the analysis. However, DOE notes that the pole 
replacement costs mentioned in the above comments fall within the range 
of costs that DOE used for its pole-mounted design lines (design lines 
2 and 3). DOE recognizes that there may be some cases where the pole 
replacement cost may be outside this range, but these would account for 
a very small fraction of situations.
    Westar stated that when mounting a bank of three[hyphen]phase 
transformers on a pole, if the weight increased beyond 2,000 pounds per 
position (which wouldn't be out of the realm of possibility for a 
transformer using amorphous core steel), they would need to use a 
500kVA pad mount. (Westar, No. 169 at p. 2) DOE recognizes that in some 
situations pole replacement may not be an acceptable option to 
utilities when replacing transformers. DOE believes that the range of 
installation costs that it used for pole replacement, in combination 
with the weight-based installation costs, captures the cost of 
situations where a pad mount would be needed.
    Westar commented that a new design for a pad-mounted transformer 
could require larger fiberglass pads than they currently use, or they 
would have to start pouring a concrete pad for each pad mount. (Westar, 
No. 169 at p. 3) DOE believes that the installation costs it used for 
pad-mounted transformers, which range from $2,169 for design line 1 (at 
50 kVA) to $8,554 for design line 5 (at 1500 kVA), encompass the 
situation described by Westar.
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 that the loading 
of larger capacity distribution transformers is greater than the 
loading on smaller capacity transformers.
b. Load Growth Trends
    The LCC analysis 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 NOPR 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 final rule 
analysis.
c. Electricity Costs
    DOE used estimates of electricity prices and costs to place a value 
on transformer losses. For the NOPR, DOE performed two types of 
analyses. One investigated the nature of hourly transformer loads, 
their correlation with the overall utility system load, and their 
correlation with hourly electricity costs and prices. Another estimated 
the impacts of transformer loads and resultant losses on monthly 
electricity usage, demand, and electricity bills. DOE used the hourly 
analysis for liquid-immersed transformers, which are owned 
predominantly by utilities that pay costs that vary by the hour. DOE 
used the monthly analysis for dry-type transformers, which typically 
are owned by commercial and industrial establishments that receive 
monthly electricity bills.
    For the hourly price analysis, DOE used marginal costs of 
electricity, which are the costs to utilities for the last kilowatt-
hour of electricity produced. The general structure of the hourly 
marginal cost equation divides the costs

[[Page 23376]]

of electricity to utilities into capacity components and energy cost 
components, which are respectively applied as marginal demand and 
energy charges for the purpose of determining the value of transformer 
electrical losses. For each component, DOE estimated the economic value 
for both no-load losses and load losses.
    Commenting on DOE's hourly price analysis, NRECA stated that 
marginal energy prices recover the system generation capacity costs, 
and demand charges are not needed to collect capacity charges. (NRECA, 
No. 156 at pp. 4-5) It added that use of demand charges introduces bias 
towards improved cost-effectiveness of more efficient transformers. 
(NRECA, No. 156 at p. 7)
    DOE disagrees with NRECA's position that demand charges are not 
needed to collect capacity charges. DOE agrees that marginal energy 
prices in a single price-clearing auction can provide for recovery of 
some amount of generation capacity cost, but it is unlikely that an 
energy-only market (one that relies only on market incentives for 
investment) would provide for full recovery of system generation 
capacity costs.\40\ Even with the addition of revenues from an 
ancillary services market, recovery would likely still fall below the 
full amount of generation capacity cost for a new generator. Indeed, 
recent market evaluation reports by the Midwest Independent System 
Operator (ISO) and California ISO (CAISO) demonstrate that energy and 
ancillary service market prices in those markets are far below the 
levels that would be necessary to fully compensate a new generation 
owner for their generation capacity cost.\41\ PJM (a regional 
transmission operator in the eastern U.S.) addresses the gap between 
the full going-forward costs \42\ and the revenues from energy and 
ancillary services markets through the addition of a separate capacity 
market.\43\ Most other regions use similar capacity markets or require 
load serving entities (LSEs) to contract for specified amounts of 
capacity. Examples of operating regions that use capacity markets or 
require acquisition of specified levels of capacity include CAISO,\44\ 
MISO,\45\ and ISO New England.\46\ NRECA acknowledges the existence of 
capacity markets, but implies that the capacity payments can be ignored 
because their purpose is to reduce price volatility. (NRECA, No. 156 at 
p. 5) DOE disagrees with this position because ISOs have stated that 
the capacity markets and contracts are needed to maintain system 
reliability, not just mitigate price volatility.\47\
---------------------------------------------------------------------------

    \40\ On an ``Energy Only'' Electricity Market Design For 
Resource Adequacy, 2005; William W. Hogan; http://www.ferc.gov/EventCalendar/files/20060207132019-hogan_energy_only_092305.pdf.
    \41\ CAISO 2011 Market Issues and Performance Report, pp. 45-48, 
http://www.caiso.com/Documents/2011AnnualReport-MarketIssues-Performance.pdf. MISO 2010 State of the Market Report Executive 
Summary, Executive Summary, p. viii, https://www.midwestiso.org/Library/Repository/Report/IMM/2010%20State%20of%20the%20Market%20Report.pdf.
    \42\ The term ``going forward costs'' includes, but is not 
limited to, all costs associated with fuel transportation and fuel 
supply, administrative and general, and operation and maintenance on 
a power plant.http://law.onecle.com/california/utilities/390.html.
    \43\ A Review of Generation Compensation and Cost Elements in 
the PJM Markets, 2009, p. 30, http://www.pjm.com/~/media/committees-
groups/committees/mrc/20100120/20100120-item-02-review-of-
generation-costs-and-compensation.ashx.
    \44\ CAISO 2011, p. 181, http://www.caiso.com/Documents/2011AnnualReport-MarketIssues-Performance.pdf.
    \45\ MISO 2010, p. viii; https://www.midwestiso.org/Library/Repository/Report/IMM/2010%20State%20of%20the%20Market%20Report.pdf.
    \46\ ISO New England 2010 Annual Markets Report, p. 33, http://www.iso-ne.com/markets/mkt_anlys_rpts/annl_mkt_rpts/2010/amr10_final_060311.pdf.
    \47\ ISO New England 2010, p. 33, http://www.iso-ne.com/markets/mkt_anlys_rpts/annl_mkt_rpts/2010/amr10_final_060311.pdf. PJM 
2009, p. 29, http://www.pjm.com/~/media/committees-groups/
committees/mrc/20100120/20100120-item-02-review-of-generation-costs-
and-compensation.ashx. CAISO 2011, p. 181, http://www.caiso.com/Documents/2011AnnualReport-MarketIssues-Performance.pdf. NYISO 2010, 
p. 156; http://www.nyiso.com/public/markets_operations/documents/studies_reports/index.jsp.
---------------------------------------------------------------------------

    Whether an area has a capacity market or capacity requirements, a 
reduction in electricity demand due to more efficient transformers 
would lower the amount of capacity purchases required by LSEs, which 
would lower capacity procurement costs. DOE's application of demand 
charges captures these lower procurement costs.
    DOE acknowledges that not all electricity markets have structured 
capacity markets or capacity requirements. The Electric Reliability 
Council of Texas (ERCOT), an energy-only market without set 
requirements for generation capacity procurement, is premised on the 
energy market and the ancillary service markets being able to provide 
sufficient revenues to attract new market entrants as needed. The 
expectation is that as reserve margins decline, market prices would 
increase to provide the needed revenues for new investment. In the 
long-term, absent the cessation of demand growth, one would expect 
market revenues to equal the full cost of a new market entrant.\48\ 
Given past market behavior, however, the market revenues will likely be 
relatively low over many hours and extremely high during a limited 
number of price spike hours. Accurate modeling and forecasting of price 
spikes is an extremely difficult task. For the ERCOT region, DOE 
believes that its capacity cost approach is an appropriate proxy to 
capture the high price spikes that can occur in energy-only markets.
---------------------------------------------------------------------------

    \48\ If an energy-only market is functioning properly, it must 
be able to provide sufficient revenues to incent new market entrants 
over the long term. Failure to incent sufficient generation to 
provide adequate reliability would likely force a market redesign or 
the introduction of new LSE obligations such as resource adequacy 
requirements.
---------------------------------------------------------------------------

    Many publicly owned utilities (POU) are not required to participate 
in capacity markets or mandated to attain specified amounts of 
generation capacity. Capacity attainment is at the sole discretion of 
those POU's governing bodies, but DOE expects that POUs would continue 
to build or contract with sufficient capacity to provide reliable 
service to their customers. As this capacity procurement will impose a 
cost that is incremental to the utility's system marginal energy cost, 
the use of capacity costs is also appropriate for evaluation of 
transformer economics for these utilities.
    Although DOE believes it is appropriate to include demand charges, 
for the final rule, DOE reviewed its capacity cost methodology and 
found that the demand charges used in the NOPR analysis were too high. 
In the NOPR, demand charges were based on the full fixed cost of new 
generation. For the final rule, the revised demand charges are based on 
the full cost of new generation net of the revenues that the generator 
could earn from the hourly energy market. This quantification of 
capacity costs net of market revenues is consistent with the design of 
the nation's capacity markets, including PJM RPM Capacity Market \49\ 
and the ISO-NE Forward Capacity Market.\50\ In addition, this method is 
used to develop marginal costs for the evaluation of distributed 
resources, energy efficiency, and demand response programs in regions 
without organized capacity markets, such as California.\51\ The 
modifications for the final rule significantly reduce the capacity cost 
used in the LCC analysis. The approach is described further in chapter 
8 of the final rule TSD.
---------------------------------------------------------------------------

    \49\ PJM 2009, Executive Summary p. 6.
    \50\ ISO-NE 2010, p. 33; http://www.iso-ne.com/markets/mkt_anlys_rpts/annl_mkt_rpts/2010/amr10_final_060311.pdf.
    \51\ See http://docs.cpuc.ca.gov/efile/PD/162141.pdf.
---------------------------------------------------------------------------

    In the NOPR, to value the capacity costs, DOE used advanced coal 
technology to reflect generation capacity

[[Page 23377]]

costs for no-load loss generation. NRECA stated that substituting the 
capacity cost of a combustion turbine/combined-cycle plant for the 
avoided cost of a new coal-fired plant appears to reduce the savings 
and cost-effectiveness of the more-efficient transformer designs. 
(NRECA, No. 156 at p. 9) DOE agrees with NRECA's criticism of the 
approach used for the NOPR. For the final rule DOE assumed that 
capacity costs for no-load loss generation depend on the type of 
generation that is built, and that these losses are served by base load 
capacity. DOE estimated the capacity cost by assuming that marginal 
capacity is added in the proportions 40 percent coal, 40 percent 
natural gas combined-cycle, and 20 percent wind. These proportions are 
based on the capacity mix estimated in the AEO 2011 projection.
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 final rule analysis, DOE 
used price forecasts from AEO 2012.
    In the NOPR, to project the relative change in electricity prices 
for liquid-immersed transformers, DOE used the average electricity 
prices from AEO 2011. NRECA stated that gas-fired combustion turbines 
and combined cycle units are being used to service base loads today, as 
well as meeting peak demand (NRECA, No. 156 at p. 9), and EEI asserted 
that natural gas is the marginal fuel ``a lot'' of the time (EEI, No. 
0051-0030 at p. 108). DOE agrees with both of these statements. For the 
final rule, DOE assumed that future production cost of electricity for 
utilities, the primary owners of liquid-immersed transformers, would be 
influenced by the price of fuel for generation (i.e., coal and natural 
gas). To estimate the relative change in the price to produce 
electricity in future years in today's rule, DOE applied separate price 
trends to both no-load and load losses. DOE used the sales weighted 
price trend of both natural gas and coal to estimate the relative price 
change for no-load losses; and natural gas only to estimate the 
relative price change for load losses. These trends are based on the 
AEO 2012 projections and are described in greater detail in chapter 8 
of the TSD.
    Appendix 8-D of this final rule TSD provides a sensitivity analysis 
for equipment of a sub-set of representative design lines. These 
analysis shows that the effect of changes in electricity price trends, 
compared to changes in other analysis inputs, is relatively small.
e. Standards Compliance Date
    DOE calculated customer impacts as if each new distribution 
transformer purchase occurs in the year that manufacturers must comply 
with the standard. As discussed in section II.A, if DOE finds that 
amended standards for distribution transformers are warranted, DOE 
agreed to publish a final rule containing such amended standards by 
October 1, 2012. The compliance date of January 1, 2016, provides 
manufacturers with over three years to prepare for the amended 
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 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.
    More detail regarding DOE's estimates of commercial customer 
discount rates is provided in chapter 8 of the final rule TSD.
g. Lifetime
    DOE defined distribution transformer life as the age at which the 
transformer retires from service. For the NOPR analysis, DOE estimated, 
based on a report by Oak Ridge National Laboratory,\52\ that the 
average life of distribution transformers is 32 years. This lifetime 
estimate 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. DOE did not receive any comments on transformer lifetime and 
it retained the NOPR approach for the final rule.
---------------------------------------------------------------------------

    \52\ Barnes. Determination Analysis of Energy Conservation 
Standards for Distribution Transformers. ORNL-6847. 1996.
---------------------------------------------------------------------------

h. Base Case Efficiency
    To determine an appropriate base case against which to compare 
various potential 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. Transformers are chosen based on either lowest 
first cost, or if the purchaser is an evaluator, on lowest Total Owning 
Cost (TOC). During the negotiations (see section II.B.2) manufacturers 
and utilities stated that ZDMH is not currently used in North America, 
so designs using ZDMH as a core steel were excluded from the base case.
i. Inputs to Payback Period Analysis
    The payback period is the amount of time it takes the consumer to 
recover the additional installed cost of more efficient products, 
compared to baseline products, through energy cost savings. Payback 
periods are expressed in years. Payback periods that exceed the life of 
the product mean that the increased total installed cost is not 
recovered in reduced operating expenses.
    The inputs to the PBP calculation are the total installed cost of 
the product to the customer for each efficiency level and the average 
annual operating expenditures for each efficiency level. The PBP 
calculation uses the same inputs as the LCC analysis, except that 
discount rates are not needed.
j. Rebuttable-Presumption Payback Period
    As noted above, EPCA, as amended, establishes a rebuttable 
presumption that a standard is economically justified if the Secretary 
finds that the additional cost to the consumer of purchasing a product 
complying with an energy conservation standard level will be less than 
three times the value of the energy (and, as applicable, water) savings 
during the first year that the consumer will receive as a result of the 
standard, as calculated under the test procedure in place for that 
standard. (42 U.S.C. 6295(o)(2)(B)(iii)) For each considered efficiency 
level, DOE determines the value of the first year's energy savings by 
calculating the quantity of those savings in accordance with the 
applicable DOE test procedure, and multiplying that amount by the 
average energy price forecast for the year in which compliance with the 
amended standards would be required.

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

[[Page 23378]]

levels. (``Customer'' refers to purchasers of the equipment 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.\53\ 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, equipment costs, 
and NPV of customer benefits for each product class for equipment 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 2012 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 final rule TSD.
---------------------------------------------------------------------------

    \53\ 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 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 equipment class in the absence of amended 
energy conservation standards. DOE compared these projections with 
projections characterizing the market for each equipment class if DOE 
were to adopt amended standards at specific energy efficiency levels 
(i.e., the standards cases) for that class.
    Table IV.27 and Table IV.38 summarize all the major NOPR inputs to 
the shipments analysis and the NIA, and whether those inputs were 
revised for the final rule.

                                  Table IV.7--Inputs for the Shipments Analysis
----------------------------------------------------------------------------------------------------------------
                 Input                         NOPR description                  Changes for final rule
----------------------------------------------------------------------------------------------------------------
Shipments data........................  Third-party expert (HVOLT) for  No change.
                                         2009.
Shipments forecast....................  2016-2045: Based on AEO 2011..  Updated to AEO 2012.
Dry-type/liquid-immersed market shares  Based on EIA's electricity      Updated to AEO 2012.
                                         sales data and AEO2011.
Regular replacement market............  Based on a survival function    No change.
                                         constructed from a Weibull
                                         distribution function
                                         normalized to produce a 32-
                                         year mean lifetime *.
Elasticities, liquid-immersed.........  For liquid-immersed             No change.
                                         transformers.
                                         Low: 0.00............
                                         Medium: -0.04........
                                         High: -0.20..........
Elasticities, dry-type................  For dry-type transformers.....  No change.
                                         Low: 0.00............
                                         Medium: -0.02........
                                         High: -0.20..........
----------------------------------------------------------------------------------------------------------------
* Source: ORNL 6804/R1, The Feasibility of Replacing or Upgrading Utility Distribution Transformers During
  Routine Maintenance, page D-1.


                               Table IV.8--Inputs for the National Impact Analysis
----------------------------------------------------------------------------------------------------------------
                 Input                         NOPR description                Changes for the final rule
----------------------------------------------------------------------------------------------------------------
Shipments.............................  Annual shipments from           No change.
                                         shipments model.
Compliance date of standard...........  January 1, 2016...............  No change.
Equipment Classes.....................  Separate ECs for single- and    No change
                                         three-phase liquid-immersed
                                         distribution transformers.
Base case efficiencies................  Constant efficiency through     No change.
                                         2044. Equal to weighted-
                                         average efficiency in 2016.
Standards case efficiencies...........  Constant efficiency at the      No change.
                                         specified standard level from
                                         2016 to 2044.
Annual energy consumption per unit....  Average rated transformer       No change.
                                         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 values as a    No change.
                                         function of efficiency level
                                         (from LCC analysis).
Electricity expense per unit..........  Energy and capacity savings     No change.
                                         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 prices......  AEO 2011 forecasts (to 2035)    Updated to AEO 2012.
                                         and extrapolation for 2044
                                         and beyond.
Electricity site-to-source conversion.  A time series conversion        No change
                                         factor; includes electric
                                         generation, transmission, and
                                         distribution losses.
Discount rates........................  3% and 7% real................  No change.
Present year..........................  2010..........................  2012.
----------------------------------------------------------------------------------------------------------------


[[Page 23379]]

1. Shipments
    DOE projected 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 projection by assuming 
that annual transformer shipments growth is equal to growth in 
electricity consumption as given by the AEO 2012 forecast through 2035. 
For the years from 2036 to 2045, DOE extrapolated the AEO 2012 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 of the final rule TSD 
provides a detailed description of how DOE projected shipments for each 
of the equipment classes in today's final rule.
    DOE recognizes that increase in transformer prices due to standards 
may cause changes in purchase of new transformers. Although the general 
trend of utility 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. In addition, some utilities may choose to refurbish 
transformers rather than purchase a new transformer if the price of the 
latter increases significantly.
    To capture the customer response to transformer price increase, DOE 
estimated the customer price elasticity of demand. 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. Although DOE was not able to 
explicitly model the replace versus refurbish decision due to lack of 
necessary data, the price elasticity should 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 final rule TSD. Comments on the issue of 
replacing versus refurbishing are discussed in section IV.O.3 of this 
preamble.
2. Efficiency Trends
    DOE did not include any base case efficiency trend in its shipments 
and national energy savings models. AEO forecasts show no long term 
trend in transmission and distribution losses, which are indicative of 
transformer efficiency. DOE estimates that the probability of an 
increasing efficiency trend and the probability of a decreasing 
efficiency trend are approximately equal, and therefore assumed no 
trend in base case or standards case efficiency.
3. National Energy Savings
    For each year in the forecast period, DOE calculates the national 
energy savings for each standard level by multiplying the stock of 
products affected by the energy conservation standards by the per-unit 
annual energy savings. Cumulative energy savings are the sum of the NES 
for each year.
    To estimate national energy savings, DOE uses a multiplicative 
factor to convert site energy consumption into primary energy 
consumption (the energy required to convert and deliver the site 
energy). This conversion factor accounts for the energy used at power 
plants to generate electricity and losses in transmission and 
distribution. The conversion factor varies over time because of 
projected changes in the power plant types projected to provide 
electricity to the country. The factors that DOE developed are marginal 
values, which represent the response of the system to an incremental 
decrease in consumption associated with standards. For today's rule, 
DOE used annual conversion factors based on the version of NEMS that 
corresponds to AEO 2012, which provides energy forecasts through 2035. 
For 2036-2047, DOE used conversion factors that remain constant at the 
2035 values.
    Section 1802 of EPACT 2005 directed DOE to contract a study with 
the National Academy of Science (NAS) to examine whether the goals of 
energy efficiency standards are best served by measuring energy 
consumed, and efficiency improvements, at the actual point of use or 
through the use of the full-fuel-cycle, beginning at the source of 
energy production. (Pub. L. 109-58 (August 8, 2005)). NAS appointed a 
committee on ``Point-of-Use and Full-Fuel-Cycle Measurement Approaches 
to Energy Efficiency Standards'' to conduct the study, which was 
completed in May 2009. The NAS committee defined full-fuel-cycle energy 
consumption as including, in addition to site energy use: Energy 
consumed in the extraction, processing, and transport of primary fuels 
such as coal, oil, and natural gas; energy losses in thermal combustion 
in power generation plants; and energy losses in transmission and 
distribution to homes and commercial buildings.
    In evaluating the merits of using point-of-use and full-fuel-cycle 
(FFC) measures, the NAS committee noted that DOE uses what the 
committee referred to as ``extended site'' energy consumption to assess 
the impact of energy use on the economy, energy security, and 
environmental quality. The extended site measure of energy consumption 
includes the energy consumed during the generation, transmission, and 
distribution of electricity but, unlike the full-fuel-cycle measure, 
does not include the energy consumed in extracting, processing, and 
transporting primary fuels. A majority of the NAS committee concluded 
that extended site energy consumption understates the total energy 
consumed to make an appliance operational at the site. As a result, the 
NAS committee recommended that DOE consider shifting its analytical 
approach over time to use a full-fuel-cycle measure of energy 
consumption when assessing national and environmental impacts, 
especially with respect to the calculation of greenhouse gas (GHG) 
emissions. For those appliances that use multiple fuels, the NAS 
committee indicated that measuring full-fuel-cycle energy consumption 
would provide a more complete picture of energy consumed and permit 
comparisons across many different appliances, as well as an improved 
assessment of impacts.
    In response to the NAS committee recommendations, on August 18, 
2011, DOE announced its intention to use full-fuel-cycle measures of 
energy use and greenhouse gas and other emissions in the national 
impact analyses and emissions analyses included in future energy 
conservation standards rulemakings. 76 FR 51282 While DOE stated in 
that notice that it intended to use the Greenhouse Gases, Regulated 
Emissions, and Energy Use in Transportation (GREET) model to conduct 
the analysis, it also said it would review alternative methods,

[[Page 23380]]

including the use of NEMS. After evaluating both models and the 
approaches discussed in the August 18, 2011 notice, DOE has determined 
NEMS is a more appropriate tool for this specific use. Therefore, DOE 
intends to use the NEMS model, rather than the GREET model, to conduct 
future FFC analyses. 77 FR 49701 (Aug. 17, 2012). DOE did not 
incorporate FFC measures into today's final rule because it did not 
want to introduce a new method in the final phase of a rulemaking. 
Rather, in today's rule, DOE continues to use its standard measures of 
energy use and greenhouse gas and other emissions in the national 
impact analyses and emissions analyses.
4. 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 
final rule TSD.
5. Net Present Value of Customer Benefit
    The inputs for determining the net present value (NPV) of the total 
costs and benefits experienced by consumers of considered appliances 
are: (1) Total annual installed cost; (2) total annual savings in 
operating costs; and (3) a discount factor. DOE calculates net savings 
each year as the difference between the base case and each standards 
case in total savings in operating costs and total increases in 
installed costs. DOE calculates operating cost savings over the life of 
each product shipped during the forecast period.
    In calculating the NPV, DOE multiplies the net savings in future 
years by a discount factor to determine their present value. DOE 
estimates the NPV using both a 3-percent and a 7-percent real discount 
rate, in accordance with guidance provided by the Office of Management 
and Budget (OMB) to Federal agencies on the development of regulatory 
analysis.\54\ 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.
---------------------------------------------------------------------------

    \54\ 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.
---------------------------------------------------------------------------

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.
    A number of parties expressed specific concerns about size and 
space constraints for network/vault transformers. (BG&E, No. 182 at p. 
6; ComEd, No. 184 at p. 11; Pepco, No. 145 at pp. 2-3; PE, No. 192 at 
p. 8; Prolec-GE, No. 177 at p. 12)
    For today's final rule, DOE evaluated purchasers of vault-installed 
transformers (mainly utilities concentrated in urban areas), 
represented by design lines 4 and 5, as a customer subgroup, and 
examined the impact of standards on these groups using the methodology 
of the LCC and PBP analysis. 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 $26 per 
transformer cubic foot.\55\ For today's notice, these costs were 
adjusted to 2011$ using the chained price index for non-residential 
construction for power and communications to $1,886 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.
---------------------------------------------------------------------------

    \55\ 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 final rule 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 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 TSD.
2. Product and Capital Conversion Costs
    New and 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 into two major groups: (1) Product 
conversion costs and (2) capital conversion costs. DOE's estimates of 
the product and capital conversion costs for distribution transformers 
can be found in section V.B.2.a of today's final rule and in chapter 12 
of the TSD.
a. Product 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. DOE based its estimates of the product conversion costs that 
would be required to meet each TSL on information obtained from 
manufacturer interviews, the engineering analysis, and the NIA 
shipments analysis. For the distribution transformer industry, a large 
portion of product conversion costs will be related to the production 
of amorphous cores, which would require the development of new designs, 
materials management, and safety measures. Procurement of such 
technical expertise may be particularly difficult for manufacturers

[[Page 23381]]

without experience using amorphous steel.
b. Capital Conversion Costs
    Capital conversion costs are investments in property, plant, and 
equipment necessary to adapt or change existing production facilities 
such that new equipment designs can be fabricated and assembled. 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 for each steel type, as well as the 
most likely core construction techniques, to model the additional 
equipment the industry would need to meet the efficiencies embodied by 
each TSL.
3. Markup Scenarios
    In the NOPR 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. While DOE has modified several inputs to the GRIM 
for today's final rule, it continues to analyze these two markup 
scenarios for the final rule. For a complete discussion, see the NOPR 
or chapter 12 of the TSD.
4. Other Key GRIM Inputs
    Key inputs to the GRIM characterize the distribution transformer 
industry cost structure, investments, shipments, and markups. For 
today's final rule, DOE made several updates to the GRIM to reflect 
changes in these inputs since publication of the NOPR. Specifically, 
DOE incorporated changes made in the engineering analysis and NIA, 
including updates to the MPCs, shipment forecasts, and shipment 
efficiency distributions. In addition, DOE made minor changes to its 
conversion cost methodology in response to comments as described below. 
These updated inputs affected the values calculated for the conversion 
costs and markups described above, as well as the INPV results 
presented in section V.B.2.
5. Discussion of Comments
    The following section discusses a number of comments DOE received 
on the February 2012 NOPR MIA methodology. DOE has grouped the comments 
into the following topics: Core steel, small manufacturers, conversion 
costs, and benefits versus burdens.
a. Core Steel
    The issue of core steel is critical to this rulemaking. This 
section discusses comments related to steel price projections, steel 
mix and competition between suppliers, and steel supply and production 
capacity. Most of these issues are highly interconnected.
    Steel Prices. Several stakeholders commented on the steel prices 
used by DOE. Prolec-GE believes that the steel supply assessment in 
appendix 3A of the TSD was too optimistic about supply and price in a 
post-recession global environment and that any analysis for higher than 
current level efficiencies should evaluate a much higher range of 
material price variance that what DOE used in the NOPR. (Prolec-GE, No. 
52 at p. 13) APPA notes that the analysis in appendix 3A of the TSD 
provides good information about prices from 2006 to 2010, but it does 
not include information about the significant increase in prices 
compared to 2002-2003 levels.
    Northeast Energy Efficiency Partnerships argued that, when faced 
with competition, conventional high-grade electrical steel prices could 
come down and compete effectively with the more efficient amorphous 
materials. (NEEP, No. 193 at p. 3) Earthjustice expressed similar 
sentiments, stating that the analysis conducted by DOE on DL1 presents 
an unrealistic picture of the LCC impacts of meeting TSLs 2 and 3 with 
conventional steels in that design line because competitive pressure 
from amorphous metal will likely reduce the price for grain-oriented 
electrical steels and, therefore, improve the LCC savings for 
consumers. (Earthjustice, No. 195 at p. 1-3)
    DOE recognizes that steel prices have proven highly volatile in the 
past and could continue to fluctuate in the future for a variety of 
reasons, including macroeconomic factors, competition among steel 
suppliers, trade policy and raw material prices. With respect to 
Earthjustice's comment, while DOE agrees that the LCC is highly 
sensitive to relative steel price assumptions at certain TSLs, DOE 
notes that a decline in silicon transformer prices would be unlikely to 
materially change the slope of the silicon steel transformer cost 
curve. Therefore, the incremental costs (and LCC savings) would not 
change significantly. To NEEP's comment, DOE agrees that competition 
between silicon steel suppliers, the incumbent amorphous metal 
suppliers and new market entrants will impact future prices. However, 
DOE does not believe it is possible to predict the relative movements 
in these prices. Throughout the negotiation process, stakeholders have 
argued for different price points for different steels under different 
scenarios. The eventual relative prices of steels in the out years will 
be in part subject to the aforementioned market forces, the direction 
and magnitude of which cannot be known at this time. For these reasons, 
DOE performed a sensitivity analysis that included a wide range of 
potential core steel prices to evaluate their impact on LCC savings as 
discussed in section V.B.3.
    Diversity of Steel Mix and Competition. Most stakeholders stated a 
preference for a market in which traditional and amorphous steel could 
effectively compete, but there was disagreement over which efficiency 
level would strike that balance, particularly for liquid-immersed 
distribution transformers. The various steel types that are available 
on the market for distribution transformers are listed in Table 5.10 in 
chapter 5 of the TSD. Stakeholders generally sought a standard that 
would allow manufacturers to use a diversity of electrical steels that 
are cost-competitive and economically feasible. This issue is critical 
to stakeholders for several reasons, including what some worried would 
be a lack of amorphous steel supply, a transition to a market that 
currently has only one global supplier with significant capacity, as 
well as forced conversion costs associated with the manufacturing of 
amorphous steel cores.
    Both APPA and Adams Electric Cooperative (AEC) commented that it is 
important that DOE preserve the competitive market by allowing both 
grain-oriented steel and amorphous core transformers to be price 
competitive. APPA and AEC are concerned about the availability and 
price of the core materials if only one product is competitively viable 
because this will affect jobs for traditional steel

[[Page 23382]]

manufacturers and also small transformer manufacturers that may not be 
able to afford or have the expertise to convert their plants to 
accommodate amorphous core construction. (APPA, No. 191 at p. 5; AEC, 
No. 163 at p. 3) Wisconsin Electric also stated that it is important to 
have a mix of suppliers available to keep the price of amorphous steel 
in check and to mitigate the risk of unforeseen situations, such as 
natural disasters. (Wisconsin Electric, No. 168 at p. 2)
    Some stakeholders, in particular ACEEE, ASAP, NRDC, and Northwest 
Power and Conservation Council (NPCC), asserted that competition can 
still be maintained at efficiency levels higher than those proposed in 
the NOPR. These stakeholders believe that TSL 1 favors silicon steel 
and will, therefore, raise the price for silicon steel while relegating 
amorphous steel to niche status, relative to a higher TSL. They noted 
that industry sources and press accounts confirm that electrical steel 
is a very high profit margin product and the lack of strong competition 
for M3 in the current market appears to be contributing to very high M3 
prices. (Advocates, No. 186 at p. 10) Therefore, the Advocates argued 
that a modified TSL 4 (EL2 for all design lines) for liquid-immersed 
transformers could be met using either amorphous metal or silicon 
steel, thereby increasing competition. ASAP had suggested during the 
NOPR public meeting that moving into a market where there would be 
three domestically based competitors would be a better competitive 
outcome than the status quo of two competitors who have the lion's 
share of the market. (ASAP, No. 146 at p. 38) In response to the 
supplementary analysis of June 20, 2012, the Advocates suggested the 
adoption of TSL C, which they believed would provide for robust 
competition among core material suppliers. (Advocates, No. 235 at p. 1) 
They also noted that TSL D, which consists of EL 2 for pad-mounted 
transformers and EL 1 for pole-mounted transformers, would favor the 
continued use of grain oriented electrical steel for the majority of 
the market and allow silicon steel and amorphous metal to reach rough 
cost parity for pad-mounted transformers. (Advocates, No. 235 at p. 4) 
ACEEE, ASAP, NRDC, and NPCC further cited some transformer 
manufacturers as saying TSL 4 or 3.5 (EL 2 or EL 1.5) for liquid-
immersed transformers would lead to robust competition because a market 
currently served by two steel suppliers (AK Steel and ATI Allegheny 
Ludlum) would then be served by three since the amorphous metal 
supplier (Metglas) could compete. (Advocates, No. 186 at p. 10-11) 
Additional amorphous metal suppliers may also enter the market because 
barriers to entry into amorphous metal transformer production are, 
according to Metglas, quite limited. (Metglas, No. 102 at p. 2) Also, 
based on the results of an analysis conducted by an industry expert for 
ASAP, the Advocates believe that it would be very unlikely that TSL 4 
standards from the NOPR for liquid-immersed transformers would result 
in amorphous metal market share exceeding 20 percent in the near- and 
medium-term due to the current dominant position of silicon steel, 
inertia in utility decision making, and the ability of steel makers to 
lower prices to protect against market share erosion. Furthermore, 
increases in the standards for LVDT and MVDT transformers, which have 
markets where amorphous metal does not compete and is not expected to 
compete at the levels proposed by DOE, will increase silicon steel 
tonnage. In the longer term, silicon steel manufacturers can make 
strategic investment decisions that will enable them to compete, such 
as increasing production of High B steel or entering amorphous metal 
production. (Advocates, No. 186 at pp. 12-13) Berman Economics also 
argued that competition between traditional and amorphous steel is 
still possible with higher standards for liquid-immersed transformers 
because, according to shipments data from ABB, TSL 4 has the greatest 
diversity of core materials. (Berman Economics, No. 221 at p. 7)
    On the other hand, many stakeholders believe that competition among 
steel suppliers will not be possible at levels higher than those 
proposed in the NOPR. At the NOPR public meeting, ATI stated that the 
proposed standards maintain a competitive balance between alternative 
materials and grain-oriented electrical steel, which has adequate 
supply from annual global production levels exceeding two million 
metric tons and price competition from several producers. (ATI, No. 146 
at p. 18) ATI believes that higher standards will result in cost-
effective design options limited to amorphous metal cores for liquid-
immersed transformers. Such a situation would cost U.S. jobs, increase 
the risk of supply shortages and disruptions, and create a non-
competitive market for new liquid-immersed designs which ATI expects 
will eliminate any projected LCC savings. (ATI, No. 54 at p. 2) 
Furthermore, ATI stated that even TSL 1 may have adverse impacts on 
competition because the efficiency levels assigned to design lines 2 
and 5 in TSL 1 were set well above the crossover point for competition 
between multiple core materials and therefore the implementation of TSL 
1 would curtail the availability of multiple options for core material 
choices for liquid-immersed transformers. ATI did not support any of 
the new TSLs proposed in DOE's supplementary analysis, which were 
higher than TSL 1 and which would, according to ATI, have significant 
impacts on the competitiveness of grain-oriented electrical steel and 
result in nearly complete conversion of the liquid-immersed market to 
amorphous cores. (ATI Allegheny, No. 218 at p. 1) Instead, ATI proposed 
an alternative TSL which consists of what it believes are more accurate 
crossover points for the liquid-immersed design lines: EL 1.3 for DL 1, 
EL 0 for DL2, EL 0.7 for DL 3, EL 1 for DL 4, and EL 0.7 for DL 5. (ATI 
Allegheny, No. 218 at p. 1)
    Cooper Power stated that the currently proposed efficiency levels 
are at the maximum levels that allow use of both silicon and amorphous 
core steels. Higher efficiency levels will tip the market in favor of 
amorphous materials that are not available in the quantities needed and 
do not have the desired diversity of suppliers to maintain a healthy 
market. (Cooper Power, No. 165 at p. 4) Cooper Power had found through 
one of its analyses that the crossover point at which transformer price 
is equivalent between M3 and amorphous was at EL 0.5 for all design 
lines 1, 3, 4, and 5 and EL 0.25 for DL2. According to Cooper Power, 
the best choice for raising the efficiency levels and keeping both M3 
core steel and amorphous core steel competitive with one another would 
be to choose EL 0.5. (Cooper Power Systems, No. 222 at p. 2) During the 
NOPR public meeting, Cooper Power commented that, past EL 1, it is no 
longer a level playing field between amorphous and silicon core steel. 
(Cooper Power, No. 146, at p. 49-50) HVOLT also commented that the 
crossover point between M3 and amorphous is at EL 1, and it's a hard 
move to amorphous past that level. (HVOLT, No. 146 at p. 51) The United 
Auto Workers (UAW) is concerned that requiring efficiency levels beyond 
TSL-1 for liquid-immersed transformers would impose unwarranted 
conversion costs on transformer producers, force the use of amorphous 
metals that are not available in adequate supply, and create 
significant anticompetitive market power for the producer of amorphous 
metal electrical steel. (UAW, No. 194 at

[[Page 23383]]

p. 2) EEI is very concerned about the availability of steels if DOE 
decides to increase any efficiency levels above those proposed in the 
NOPR because, as DOE's life-cycle analyses have shown, the ``tipping'' 
point where many domestic steelmakers are not competitive is usually at 
levels that are equal to or less than TSL 1 for liquid-immersed 
transformers. Domestic steelmakers agreed, explaining that the 
anticompetitive ramifications of a decision to promulgate a standard 
greater than TSL 1 for the liquid-immersed market would not be 
economically justified. According to AK Steel and ATI, since amorphous 
metal is currently competitive but may not be in sufficient supply, and 
non-amorphous manufacturers may not be able to compete with amorphous 
metal on a first-cost basis beyond TSL 1, any decision by DOE to 
promulgate a standard greater than TSL 1 would transfer significant 
market power, including potential price increases, to the maker of 
amorphous metal. (AK Steel and ATI, No. 188 at p. 2-3) AK Steel also 
commented that DOE should finalize a standard equivalent to TSL 1 from 
the NOPR rather than adopt the new TSLs A through D proposed in the 
supplementary analysis because it believes that the new TSLs, which are 
more stringent, would have significant anticompetitive effects that 
will harm both electric utilities and the public through increased 
prices. (AK Steel, No. 230 at p. 12-13) NEMA supports the currently 
proposed efficiency levels because higher levels will tip the scale in 
favor of amorphous materials that are not available in the quantities 
needed and do not have the desired diversity of suppliers to maintain a 
healthy market. (NEMA, No. 170 at p. 14) In response to the 
supplementary analysis, NEMA argued that the new TSLs (with the 
exception of TSL A if DL 2 remains at EL 0) would all result in steel 
supply shortages or a bias in favor of amorphous. (NEMA, No. 225 at p. 
4) AEC believes that DOE appropriately balanced high transformer 
efficiency with a viable competitive market in the NOPR. (AEC, No. 163 
at p. 3) NRECA agreed, stating that DOE has achieved the correct 
balance of high transformer efficiency while maintaining a viable 
competitive market, because any efficiency level above those 
recommended in the NOPR will greatly impact competition and, therefore, 
affect jobs for steel manufacturers and small transformer manufacturers 
that may not have the resources to convert their plants to accommodate 
amorphous core construction. (NRECA, No. 228 at p. 4) Likewise, the 
United Steelworkers Union (USW) supports the currently proposed 
efficiency levels because they allow end-users to choose between 
competing technologies rather than relying on a single option. (USW, 
No. 148 at p. 2)
    DOE recognizes the importance of maintaining a competitive market 
for transformer steel supply in which traditional steel and amorphous 
steel suppliers can both participate. This was a critical consideration 
in DOE's assessment of the rule's impact on competition. As with the 
discussion on future prices, the precise ``crossover point'' is 
variable depending on a number of factors, including firm pricing 
strategies, global demand and supply, trade policy, market entry, and 
economies of scale among producers and consumers of the core steel. The 
magnitudes of these potential influences on the cross-over point cannot 
be precisely known in advance.
    DOE attempted to survey manufacturers about the mix of core steel 
used currently for transformers meeting various efficiency levels and 
also queried the industry about their expectations for core steel mix 
at those efficiencies should the next DOE standard require them. 
However, beyond those presentations made publicly by various 
manufacturers during the negotiations--which demonstrated conflicting 
views on the ``crossover point''--DOE could not gather sufficient data 
to calculate manufacturer expectations of the crossover point at 
various TSLs. While several stakeholders have pointed to the ``tipping 
point'' shown by the LCC's steel selection analysis as evidence that 
the market will transition to amorphous entirely for some design lines, 
DOE repeats here that not every possible design was analyzed and that 
the LCC tool is highly sensitive to price assumptions which have been 
shown to be extremely variable over time and among suppliers. Balancing 
all of the evidence in this docket, DOE believes that the levels 
established by today's final rule will maintain a choice of steel mix 
for the industry. As discussed in the weighing of benefits and burdens 
section (section IV.I.5.d), DOE remains concerned about the potential 
for significant disruption in the steel supply market at levels higher 
than those established by today's rule.
    As for the conversion costs that may be required should some 
manufacturers decide to begin making, or to increase production of, 
amorphous core transformers, DOE accounts for them in the GRIM 
analysis.
    Supply and Capacity. The ability of core steel producers to 
increase supply if necessary is another related key issue discussed by 
stakeholders. Some stakeholders were concerned that suppliers may not 
have the capacity to produce certain steels in quantities great enough 
to meet demand at higher efficiency levels, while other stakeholders 
believed that suppliers will be fully capable of expanding capacity as 
needed.
    Several stakeholders expressed concerns about utilities being 
unable to serve customers due to steel supply constraints in the 
distribution chain. EEI stated that its members do not want to repeat 
the situation they faced in 2006-2008 when there were transformer 
shortages and utilities were told that there would be delays of months 
or even years before certain transformers would be available. (EEI, No. 
185 at p. 10) APPA noted that the threat of transformer rationing may 
return in an improved economy and hamper the ability of utilities to 
meet their obligation to serve customers. (APPA, No. 191 at p. 10) 
Likewise, Consolidated Edison believes that the possible requirement to 
use higher grade core steels in order to achieve higher efficiencies 
may result in supply scarcity, increased costs, and tough competition 
for these materials after recovery from the global recession. (ConEd, 
No. 236 at p. 4) Commonwealth Edison Company is very concerned about 
the availability of a quality steel supply for the transformer 
manufacturing industry and that a limited supply of transformers will 
have a significant negative effect on the company's ability to provide 
safe and reliable electric service to its customers. (ComEd, No. 184 at 
p. 11) Howard Industries is also concerned about the limited 
availability of critical core materials such as M2 and amorphous, which 
could pose a large risk to the transformer and utility industries and 
may become a particularly troublesome issue if the economy and housing 
markets return to more normal levels. (Howard Industries, No. 226 at p. 
2) In addition, the USW stated that the number of transformer producers 
with the equipment to build reliable transformers with amorphous ribbon 
cores is relatively small. Therefore, a sudden transition to amorphous 
ribbon would result in a fragile supply chain for distribution 
transformers, potentially leading to large cost increases and supply 
shortages that would place the security of the U.S. electrical 
transmission grid at risk. (USW, No. 148 at p. 2) ATI stated during the 
NOPR

[[Page 23384]]

public meeting that a scenario in which grain-oriented electrical steel 
is not available as a core material option could result in a long-term 
situation where no domestic companies would produce the strategically 
important material for transformers that are the critical link in the 
U.S. electrical grid. (ATI, No. 146 at p. 19)
    Some stakeholders also emphasized the importance of being able to 
use M3 steel, which is more readily available than other more efficient 
steels. Prolec-GE noted that silicon steel grades above M3 have 
significant supply limitations and predicted no change in that 
situation for the foreseeable future. Therefore, Prolec-GE continues to 
see the need for a balanced approach to higher efficiencies such that 
M3 silicon steel and amorphous metal can compete for a share of the 
liquid-immersed market, which would allow manufacturers to have a 
sufficient supply of these materials to serve customer requirements. 
(Prolec-GE, No. 52 at pp. 11-12) Progress Energy also stated that M2 
core steel is in short supply because it is only a small part of a 
silicon core steel producer's output and M3 and M4 grades of core steel 
should be required for 85 percent or more of any required efficiency 
level so that utilities will not face shortage situations that would 
have negative impacts on grid reliability. (Progress Energy, No. 192 at 
pp. 7-8) Likewise, Power Partners voiced concern about the U.S. supply 
of core steel should DOE adopt an efficiency that requires the use of 
grades better than M3. Power Partners stated that the current domestic 
capacity for M2 will not support 100 percent of all liquid-immersed 
transformers and, therefore, recommended that DOE only consider 
efficiency levels that can be attained with M3 core steel with no loss 
evaluation. The grades better than M3 should be employed when the 
utility loss evaluation justifies its use. (Power Partners, No. 155 at 
pp. 3-4) Southern California Edison has stated that greater market 
demand for M2 core steel may create supply shortages and result in high 
steel prices. (Southern California Edison, No. 239 at p. 1) According 
to Central Moloney, M2 and higher grades of steel are premium products 
within the steel manufacturing process which comprise no more than 15 
percent of overall steel production. Central Moloney is concerned that 
the marketplace will not be able to support the demand of these premium 
products if efficiency levels are increased. (Central Moloney, No. 224 
at pp. 1-2)
    Stakeholders have also expressed several concerns regarding the 
availability of steels supplied by foreign vendors, especially 
amorphous steel. Both Commonwealth Edison Company and Baltimore Gas and 
Electric Company stated that the overseas procurement of steel could 
result in specification issues and that there could be a negative 
impact on the U.S. electric grid if DOE sets a standard that requires 
the use of a specific core steel that is not readily available in the 
domestic market and which does not have a proven track record. (ComEd, 
No. 184 at p. 12 and BG&E, No. 182 at p. 7) Power Partners has stated 
that grades of grain-oriented electrical steel better than M2 for wound 
core applications are only available from international sources and 
supply capacity is very limited. (Power Partners, No. 155 at pp. 3-4) 
In addition, Progress Energy is concerned that amorphous and 
mechanically scribed core steel will not be available in sufficient 
quantities because domestic transformer vendors rely on basically one 
amorphous core steel provider. This supplier may not have the capacity 
to provide enough amorphous material to meet demand from all U.S. 
transformer manufacturers as well as overseas business if the 
efficiency levels are increased beyond EL 1 for liquid-immersed 
distribution transformers. (Progress Energy, No. 192 at pp. 7-8) ABB 
has indicated that amorphous steel is a sole source product for the 
U.S., and, as demand increases for it, there could be a tight global 
supply as well as upward price pressure. (ABB, No. 158 at p. 8) ABB has 
also expressed concerns about mechanically scribed steel. This type of 
steel has only four global suppliers, and its availability may be 
subject to international trade restrictions. (ABB, No. 158 at p. 8) 
According to Cooper Power Systems, ZDMH is in large part unavailable in 
the U.S. and should therefore represent only a small fixed percentage 
of overall usage. (Cooper Power Systems, No. 222 at p. 2)
    However, some stakeholders are more confident that the supply of 
higher efficiency steels would increase to meet demand due to higher 
standards. ACEEE, ASAP, NRDC, and NPCC believe that it is highly 
unlikely that amorphous production will not expand in response to 
higher standards because: (1) The U.S. producer of amorphous metal has 
demonstrated its ability to add capacity over the past several years as 
producers of high-value electricity (e.g., wind producers) have favored 
amorphous metal products, and (2) other manufacturers are exploring 
amorphous production and there are no legal barriers to entry for new 
competitors. (Advocates, No. 186 at p. 11) The Advocates also noted 
that one of the largest global suppliers of silicon steel for 
transformers, POSCO (formerly Pohang Iron and Steel Company), is 
entering the amorphous metal market. The company approved a plan for 
commercializing amorphous metal production in 2010 and will soon begin 
production and marketing of amorphous metal with plans to produce up to 
1 kiloton (kt) in 2012, 5 kt in 2013, and 10 kt in 2014. (Advocates, 
No. 235 at p. 3) Schneider Electric stated that, with the exception of 
amorphous, there are sufficient suppliers worldwide (Europe and Asia) 
who have either increased capacity or who have near term plans to 
increase capacity to meet the growing demand for high-grade steels. The 
company feels it is better to allow global market conditions to dictate 
business plans rather than the DOE because manufacturing and freight 
costs play a lesser role than supply and demand in determining the 
final price for high-grade steels, whether domestic or foreign, as long 
as there are sufficient suppliers worldwide. (Schneider, No. 180 at p. 
6) In addition, Hydro-Quebec has stated that the equipment for making 
amorphous steels is mainly used to serve the distribution transformer 
market, which allows amorphous steel to be less influenced by other 
non-transformer markets that may impact steel price and availability. 
Amorphous steel production lines are also much smaller than silicon 
steel lines, thereby allowing amorphous steel makers to add production 
capacity by small increments with relatively low capital expenditures 
and in a relatively short time frame. Hydro-Quebec therefore believes 
that amorphous steel production can be tightly connected with 
increasing demand. (Hydro-Quebec, No. 125 at p. 2) Metglas, has also 
stated that an increase in capacity to even 100 percent of 2016 demand 
would only require an approximately $200M investment in amorphous metal 
casting capacity and an even smaller total industry investment by core/
transformer makers in amorphous metal transformer manufacturing 
capacity. Metglas further stated that it has a technology transfer 
program to assist any U.S. transformer maker in quickly progressing 
into production of amorphous metal-based transformers. (Metglas, No. 
102 at p. 2) Berman Economics supports Metglas' position, arguing that 
Metglas has demonstrated its willingness and capability to increase 
capacity as a result of the 2007 Final Rule and should be expected to 
do so again, particularly considering the

[[Page 23385]]

financial resources available to Metglas from its parent, Hitachi. 
Moreover, since there are no patent restrictions on amorphous steel, 
there is nothing to prevent silicon steel from diversifying to include 
an amorphous line should it choose to do so. (Berman Economics, No. 150 
at p. 10) Berman Economics also believes that DOE improperly assumes 
that increased use of amorphous will reduce silicon steel production in 
an effort to ensure that silicon steel production does not suffer 
profit losses as amorphous becomes more competitive. Additionally, 
Earthjustice claimed that DOE did not rationally analyze the potential 
impacts associated with steel production capacity constraints because, 
according to the NOPR, adopting TSLs 2 or 3 for liquid-immersed 
transformers would lead to shortages of amorphous metal such that 
grain-oriented electrical steel cores would have to be used in non-
cost-effective applications, but in the TSD, those TSLs would split the 
market between amorphous and grain-oriented steels and DOE expects 
minimal core steel capacity issues at TSLs that do not force the entire 
market into amorphous steel usage. (Earthjustice, No. 195 at pp. 1-2)
    DOE is aware that there is currently only one global supplier of 
amorphous steel with any significant capacity and that the parent 
company is foreign-owned (although a substantial share of its 
production takes place domestically through its U.S. subsidiary). At 
the same time, a few other steel producers have announced plans to 
begin, or have recently begun, very limited production of amorphous 
metal. DOE is also aware that there are only a few suppliers for 
mechanically scribed steel and that some of these suppliers are also 
foreign-owned. Given the lack of suppliers of domain-refined (e.g., H0, 
ZDMH) and amorphous steels, DOE agrees that the amended energy 
conservation standards should provide manufacturers with the option to 
cost-effectively use grain-oriented silicon steels, which have fewer 
supply constraints. This would help ensure that utilities have access 
to transformers, particularly in the event of stronger economic growth 
(a driver of transformer demand) or a natural disaster, both concerns 
raised by commenters. Furthermore, DOE understands that M2 cannot be 
produced at the quantities equivalent to current M3 yields due to the 
nature of the silicon steel production process. Given these facts, DOE 
concluded that a standard that could not be achieved by M3 would not be 
economically justified. On the other hand, DOE also acknowledges that 
the current amorphous supplier may be able to expand capacity to meet 
additional demand and a few other companies have begun the initial 
stages of developing capacity. The eventual steel quality and 
production capacity of these emerging amorphous sources are unknown at 
this time. Therefore, DOE has been careful in selecting a TSL that 
would allow manufacturers to use not only amorphous and mechanically 
scribed steel,that is currently produced in limited quantities, but 
also grain-oriented steels.
    DOE believes that the Earthjustice comment that DOE did not 
rationally analyze the potential impacts associated with steel 
production capacity constraints actually refers to two related but 
separate issues in the NOPR and NOPR TSD. In the TSD, DOE explains that 
the availability of total core steel would not be an issue until TSL 4 
because both conventional and amorphous steels would be available to 
use until that point. In the NOPR, DOE explains that the availability 
of amorphous steel may be an issue at TSLs 2 and 3, and that 
manufacturers may need to use other types of steels, such as M3, which 
are not the lowest cost options. These statements are not contradictory 
because, although amorphous steel capacity may not be able to expand to 
meet all demand at TSLs 2 and 3, that does not imply that total core 
steel capacity would be insufficient because manufacturers still have 
the option of using M3 or M2 or other steels at these levels.
b. Small Manufacturers
    An important area of discussion among stakeholders is the impact of 
energy efficiency standards on small manufacturers. At the NOPR public 
meeting, ASAP had suggested that DOE should do additional work to 
better document and understand the scale of the impacts on small 
manufacturers. (ASAP, No. 146 at p. 170)
    Some stakeholders expressed concern that standards higher than 
those proposed in the NOPR would have a significant negative impact on 
small manufacturers. NEMA is very concerned with the possibility that 
higher efficiency standards will negatively impact small manufacturing 
facilities and may drive some small companies, in particular LVDT 
transformer manufacturers, out of business. (NEMA, No. 170 at pp. 4, 8) 
In addition, at least one small NEMA manufacturer of liquid-immersed 
distribution transformers has reported that it cannot stay in business 
at levels higher than EL1. (NEMA, No. 170 at p. 6) APPA is also 
concerned about small manufacturer impacts resulting from the use of 
amorphous steel, stating that small transformer manufacturers that may 
not be able to afford or have the expertise to convert their plants to 
accommodate amorphous core construction may be forced to go out of 
business. (APPA, No. 191 at p. 5) HVOLT commented that producing 
stacked core products with mitering would take millions of dollars and 
small manufacturers in some states cannot afford that investment, and 
may be forced to go out of business. (HVOLT, No. 146 at pp. 50-51) 
Furthermore, at higher efficiency levels, even if small manufacturers 
can continue to use butt-lapping, they may not be able to sell their 
transformers at a price where material costs are recovered. (HVOLT, No. 
146 at p. 151)
    However, other stakeholders have suggested that small manufacturer 
effects have been overemphasized in DOE's analysis. ACEEE, ASAP, NRDC, 
and NPCC disagreed with DOE's small business analysis, claiming that it 
overstates impacts on small business manufacturers of LVDT 
transformers. The NOPR record and an investigation by the Advocates 
indicate that the vast majority of covered transformers are 
manufactured by a handful of large manufacturers with all of their 
major production facilities in Mexico. Since small, domestic 
manufacturers cannot compete on price with Mexican production 
facilities, domestic manufacturers focus on specialty transformers 
which are generally outside the scope of the regulation or on high-
efficiency offerings. (Advocates, No. 186 at pp. 5-6) Furthermore, even 
if DOE finds that there are a significant number of small manufacturers 
with U.S. production facilities making covered LVDT transformers, the 
Advocates suggest that DOE should still adopt TSL 3 because any small 
manufacturer with long term viability in the distribution transformer 
market can build compliant transformers. DOE's record indicates that 
the least-cost option for building LVDT transformers at TSL 3 entails 
step-lap mitering and some small manufacturers already have mitering 
equipment. The Advocates commented that for companies that currently 
lack mitering machines, industry experts have testified that a step lap 
mitering machine costs between $0.5 million and $1 million, which is a 
small investment that should be well within reach for viable 
manufacturing companies, even if they are small. The Advocates also 
indicate that DOE may have placed too much emphasis on

[[Page 23386]]

small business impacts in its decision-making criteria. Companies also 
have the option of sourcing their cores from third party suppliers, who 
can obtain better materials prices than all but the largest transformer 
makers, regardless of the efficiency levels chosen. In fact, they cite 
to the NOPR to support the notion that market pressures are already 
likely to be pushing small transformer manufacturers to purchase 
sourced cores regardless of the efficiency levels adopted. (Advocates, 
No. 186 at p. 6) Furthermore, although small manufacturers may not get 
the same treatment from steel suppliers as large manufacturers do, 
small manufacturers will face this disadvantage regardless of the 
standard level chosen. (Advocates, No. 186 at p. 5)
    Similar sentiments were expressed by California Investor Owned 
Utilities (CA IOUs). According to the CA IOUs, although DOE repeatedly 
emphasizes the concern that small manufacturers may be 
disproportionately impacted by higher standard levels and leans on this 
concern as justification for selecting TSL 1 for low-voltage dry-type 
transformers, there are actually very few small manufacturers in this 
market and those small manufacturers that do exist primarily focus on 
design lines that are exempted from coverage. The CA IOUs commented 
that some small manufacturers that do produce covered transformers are 
focusing on high efficiency NEMA Premium[supreg] transformers, 
indicating that smaller manufacturers are already capable of producing 
higher efficiency transformers. Furthermore, small manufacturers could 
source their cores, and many are currently doing so today, which 
offsets any need to upgrade core construction equipment. (CA IOUs, No. 
189 at pp. 2-3)
    Also, Earthjustice has commented that DOE has arbitrarily relied on 
impacts on small manufacturers in rejecting stronger standards for low-
voltage dry-type (LVDT) units despite there being few, if any, small 
manufacturers of this equipment who are likely to be impacted. DOE has 
not explained why sourcing cores is not an acceptable option for any 
small manufacturer and, given the evidence in the TSD that sourcing 
cores is a more profitable approach for small manufacturers of LVDTs, 
DOE's reliance on the adverse financial impacts to small manufacturers 
associated with producing such cores in-house in rejecting stronger 
LVDT standards is unreasonable. (Earthjustice, No. 195 at pp. 3-5)
    NEEP has suggested that DOE should not sacrifice large national 
benefits to provide ill-defined benefits for a small number of 
manufacturers. Even if some domestic small manufacturers may be 
affected by the new standards, DOE should do a more comprehensive 
analysis of how much the standards would impact those small 
manufacturers. The investments needed to meet new standards may be 
affordable for companies which have covered transformers as a 
significant part of their business, and companies that have covered 
transformers as a small portion of their business may choose to exit 
this part of the market or source their cores. (NEEP, No. 193 at pp. 4-
5)
    DOE understands that small companies face additional challenges 
from an increase in standards because they are more likely to have 
lower production volumes, fewer engineering resources, a lack of 
purchasing power for high performance steels, and less access to 
capital.
    For liquid-immersed distribution transformers, DOE does not believe 
that small manufacturers will face significant capital conversion costs 
at TSL 1 because they can continue to produce silicon steel cores using 
M3 or better grades rather than invest in amorphous technology should 
they make that business decision. Alternatively, they could source 
their cores, a common industry practice.
    For the LVDT market, DOE conducted further analysis based on 
comments received on the NOPR to reevaluate the impact of higher 
standards on small manufacturers. Although there may not be many small 
LVDT manufacturers that produce covered equipment in the U.S. and small 
manufacturers may hold only a low percentage of market share, the 
Department of Energy does consider impacts on small manufacturers to be 
a significant factor in determining an appropriate standard level. As 
discussed in the engineering analysis, because commenters suggested 
that EL3, the efficiency level selected at TSL 2 for DL7 (equivalent to 
NEMA Premium[supreg]), could be achieved with a butt-lap design, DOE 
further investigated the efficiency limits of butt-lapping potential. 
The primary reason that DOE proposed TSL 1 over TSL 2 in the NOPR was 
because it did not appear that TSL 2 could be met using butt-lapping 
technology, which would have caused undue hardship on small 
manufacturers that utilize this technology. However, in response to 
comments from the NOPR, DOE analyzed additional design option 
combinations using butt-lapping technology for DL 7 in its engineering 
analysis and determined that EL 3 can still be achieved without the 
need for mitering by using higher grade steels. While these would 
likely not be the designs of choice for high-volume manufacturers 
because the capital cost of a mitering machine has a much lower per 
unit cost given their larger volumes, this option may allow low-volume 
players, such as small manufacturers, to avoid investing in mitering 
machines or sourcing their cores due to financial constraints. However, 
at TSL 3 and higher, manufacturers may not be able to continue using 
butt-lapping technology with steels that are readily available.
    Although sourced cores may be the most cost-effective strategy in 
the near term, some manufacturers indicated during interviews that 
production of cores is an important part of the value chain and that 
they could ill-afford to cede it to third parties. On the other hand, 
some manufacturers indicated they are able to successfully compete 
because of their sourcing strategies, not in spite of them, because 
they can meet a variety of customer needs more quickly and cheaply than 
would otherwise be possible. Particularly because most small U.S. LVDT 
manufacturers are heavily involved in the transformer market not 
otherwise covered by statute, which constitutes roughly 50 percent of 
all LVDT sales, DOE believes that sourcing DOE-covered mitered cores 
represents a viable strategic alternative for small LVDT manufacturers, 
given that it is a common industry business strategy for low volume 
product lines.
    In conclusion, DOE believes that TSL 2, the level established by 
today's standards, affords small LVDT transformer manufacturers with 
several strategic paths to compliance: (1) Investing in mitering 
capability, (2) continuing to use low-capital butt-lap core designs 
with higher grade steels, (3) sourcing cores from third-party core 
manufacturers, or (4) focus on the exempt portion of the market.
c. Conversion Costs
    Berman Economics questioned DOE's methodology for calculating 
conversion costs, which was described in section IV.I.3.c of the NOPR. 
Berman argued that DOE provided unreasonable estimates of conversion 
costs because DOE based estimates on an arbitrary percent of total R&D 
expenditures across all equipment regulated by DOE. Therefore, the 
conversion cost estimates are not relevant to the proposed regulatory 
action. (Berman Economics, No. 150 at pp. 14-15)
    In response, the percentages that DOE used to determine product 
conversion costs for liquid-immersed transformer

[[Page 23387]]

manufacturers were based solely on information relevant to the 
distribution transformer industry, not for all equipment regulated by 
DOE. DOE's estimates for product conversion expenses for liquid-
immersed distribution transformer manufacturers would be based upon the 
extent to which the industry would need to convert to amorphous 
technology. This methodology is similar to the one used for the 2007 
final rule but modified to reflect feedback from manufacturers during 
interviews and to consider the technology required to meet the 
efficiency levels from the current rulemaking.
    Berman Economics also commented that DOE's estimates of stranded 
assets were illogical for production, financial, and corporate strategy 
reasons. From a production perspective, there is likely to be a net 
increase in demand for silicon steel at EL 2 for liquid-immersed 
transformers so assets such as annealing ovens would not be stranded. 
Berman Economics stated most annealing ovens are very old and have 
already been depreciated, and manufacturing investment may be expensed 
in the year purchased according to current tax laws, so the cost of all 
recently purchased annealing ovens has already been recovered. From a 
strategic perspective, if a manufacturer chooses not to offer an 
amorphous line of products, DOE should not put itself in a position to 
favor that manufacturer's strategy over another. Furthermore, Berman 
Economics stated that DOE based stranded assets on an arbitrary percent 
of new capital conversion costs which may have been a holdover from the 
decision on microwave ovens. (Berman Economics, No. 150 at pp. 15-16)
    DOE agrees that the calculations in the NOPR for stranded assets 
were incorrectly derived in the GRIM and has revised the model for the 
final rule. For the final rule, stranded assets in the standards case 
are derived from the share of the industry's net property, plant and 
equipment (PPE) that is estimated to no longer be useful due to energy 
conservation standards. The change has no substantial effect on the 
overall results. See TSD chapter 12 for more details.
    Berman Economics also stated that DOE has overestimated capital 
conversion costs because the Department assumed a 100 percent front-
load in investment prior to the 2016 effective date rather than a 
least-cost method of financing, such as a long-term loan. (Berman 
Economics, No. 150 at p. 16)
    Accounting for investments in the time frame between the effective 
date of today's rule and the rule compliance date is the accepted 
methodology vetted during the preliminary analysis and the standard 
model used for DOE rulemakings. This methodology also considers the 
possibility that some manufacturers, such as small manufacturers, may 
have difficulty obtaining loans.
    In addition, Berman Economics argued that an increased market 
demand for amorphous steel relative to silicon steel may reduce 
investment expenditures rather than increase them because the annealing 
oven for an amorphous steel core costs substantially less than the 
annealing oven for a silicon steel core. Some transformer manufacturers 
may also be able to source cores, which, Berman Economics stated, DOE 
incorrectly considered an undesirable market activity. Berman Economics 
noted that an outsourcing opportunity allows manufacturers to 
specialize, use cash for other strategic purposes, and pursue multiple 
objectives. (Berman Economics, No. 150 at pp. 16-17)
    DOE takes into account conversion costs associated with a given 
TSL. While the cost of a single annealing oven for an amorphous steel 
core may be less than the cost of a single annealing oven for a silicon 
steel core, other factors, particularly throughput levels, associated 
tooling, and the R&D expenses allocated to the development of new 
designs and production processes, also drive conversion costs 
calculations.
    With respect to core sourcing, as with the above discussion related 
to the LVDT market, DOE notes that it is not making any judgment on the 
value of one business strategy versus another. Whether sourcing cores 
is a viable option for any given manufacturer is a decision for each 
manufacturer in the context of its unique environment. However, during 
interviews, some manufacturers indicated that production of cores is an 
important part of the value chain and doubted their long-term viability 
should they outsource that function.
    Finally, Berman Economics has noted that the logic explained by DOE 
that more stringent levels of efficiency are associated with larger 
adverse industry impacts does not hold true in the GRIM, which 
indicates that the model contains a multiplicity of unknown logic 
errors and its results must be viewed as spurious. (Berman Economics, 
No. 150 at p. 18)
    Although higher efficiency levels are often correlated with greater 
adverse industry impacts, certain offsetting factors based on DOE's 
markup assumptions may result in deviations from this pattern. For 
example, in the preservation of gross margin percentage scenario, DOE 
applied a single uniform ``gross margin percentage'' markup across all 
efficiency levels so that, as production costs increase with 
efficiency, the absolute dollar markup increases as well. Therefore, 
the highest efficiency levels do not result in the highest drop in INPV 
because manufacturers are able to compensate for higher conversion 
costs by charging higher prices.
6. Manufacturer Interviews
    DOE interviewed manufacturers representing approximately 65 percent 
of liquid-immersed distribution transformer sales, 75 percent of 
medium-voltage dry-type transformer sales, and 50 percent of low-
voltage dry-type transformer sales. These interviews were in addition 
to those DOE conducted as part of the engineering analysis. DOE 
outlined the key issues for the rulemaking for manufacturers in the 
NOPR. 77 FR 7282 (February 10, 2012). DOE considered the information 
received during these interviews in the development of the NOPR and 
this final rule.
7. Sub-Group Impact Analysis
    DOE identified small manufacturers as a subgroup in the MIA. DOE 
describes the impacts on small manufacturers in section VI.B. below.

J. Employment Impact Analysis

    Employment impacts include direct and indirect impacts. Direct 
employment impacts are any changes in the number of employees of 
manufacturers of the equipment 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 equipment; and (4) 
the effects of those three factors throughout the economy. DOE's 
employment impact analysis addresses these impacts. No public comments 
were received on this analysis.

[[Page 23388]]

    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.\56\ 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.
---------------------------------------------------------------------------

    \56\ 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 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 forecasting 
model, and understands the uncertainties involved in projecting 
employment impacts, especially changes in the later years of the 
analysis. Because ImSET does not incorporate price changes, the 
employment effects predicted by ImSET may over-estimate actual job 
impacts over the long run. For the final rule, DOE used ImSET only to 
estimate short-term employment impacts.
    For more details on the employment impact analysis, see chapter 13 
of the final rule 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. To calculate this, DOE first obtained the energy 
savings inputs associated with efficiency improvements to the 
considered products from the NIA. Then, DOE used that data in 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. Finally, DOE calculates the 
utility impact analysis by comparing the results at each TSL to the 
latest AEO Reference case. For the final rule, the estimated impacts 
for the considered standards are the differences between values derived 
from NEMS-BT and the values in the AEO 2012 reference case.
    Chapter 14 of the final rule TSD describes the utility impact 
analysis. No public comments were received on this analysis.

L. Emissions Analysis

    In the emissions analysis, DOE estimated the reduction in power 
sector emissions of CO2, SO2, 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 transformers 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 AEO 2012, which generally 
represents current legislation and environmental regulations, including 
recent government actions, for which implementing regulations were 
available as of December 31, 2011.
    SO2 emissions from affected electric generating units 
(EGUs) are subject to nationwide and regional emissions cap and trading 
programs. 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 were also limited under the Clean Air Interstate Rule 
(CAIR), which created an allowance-based trading program that operates 
along with the Title IV program. 70 FR 25162 (May 12, 2005) CAIR was 
remanded to the U.S. Environmental Protection Agency (EPA) by the U.S. 
Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in 
2008, but it remained in effect. On July 6, 2011 EPA issued a 
replacement for CAIR, the Cross-State Air Pollution Rule (CSAPR). 76 FR 
48208 (August 8, 2011). The version of NEMS-BT used for today's rule 
assumes the implementation of CSAPR.\57\
---------------------------------------------------------------------------

    \57\ On December 30, 2011, the D.C. Circuit stayed the new rules 
while a panel of judges reviews them, and told EPA to continue 
administering CAIR. See EME Homer City Generation, LP v. EPA, Order, 
No. 11-1302, Slip Op. at *2 (D.C. Cir. Dec. 30, 2011). On August 21, 
2012, the D.C. Circuit vacated CSAPR. See EME Homer City Generation, 
LP v. EPA, No. 11-1302, 2012 WL 3570721 at *24 (D.C. Cir. Aug. 21, 
2012). The court ordered EPA to continue administering CAIR. AEO 
2012 had been finalized prior to both these decisions, however. DOE 
understands that CAIR and CSAPR are similar with respect to their 
effect on emissions impacts of energy efficiency standards.
---------------------------------------------------------------------------

    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. 
In past rulemakings, DOE recognized that there was uncertainty about 
the effects of efficiency standards on SO2 emissions covered 
by the existing cap-and-trade system, but it concluded that no 
reductions in power sector emissions would occur for SO2 as 
a result of standards.
    Beginning in 2015, however, SO2 emissions will fall as a 
result of the Mercury and Air Toxics Standards (MATS) for power plants, 
which were announced by EPA on December 21, 2011. 77 FR 9304 (Feb. 16, 
2012). In the final MATS rule, EPA established a standard for hydrogen 
chloride as a surrogate for acid gas hazardous air pollutants (HAP), 
and also established a standard for SO2 (a non-HAP acid gas) 
as an alternative equivalent surrogate

[[Page 23389]]

standard for acid gas HAP. The same controls are used to reduce HAP and 
non-HAP acid gas; thus, SO2 emissions will be reduced as a 
result of the control technologies installed on coal-fired power plants 
to comply with the MATS requirements for acid gas. AEO 2012 assumes 
that, in order to continue operating, coal plants must have either flue 
gas desulfurization or dry sorbent injection systems installed by 2015. 
Both technologies, which are used to reduce acid gas emissions, also 
reduce SO2 emissions. Under the MATS, NEMS shows a reduction 
in SO2 emissions when electricity demand decreases (e.g., as 
a result of energy efficiency standards). Emissions will be far below 
the cap that would be established by CSAPR, so it is unlikely that 
excess SO2 emissions allowances resulting from the lower 
electricity demand would be needed or used to permit offsetting 
increases in SO2 emissions by any regulated EGU. Therefore, 
DOE believes that efficiency standards will reduce SO2 
emissions in 2015 and beyond.
    Under CSAPR, there is a cap on NOX emissions in 28 
eastern States and the District of Columbia. Energy conservation 
standards are expected to have little effect on NOX 
emissions in those States covered by CSAPR because excess 
NOX emissions allowances resulting from the lower 
electricity demand could be used to permit offsetting increases in 
NOX emissions. However, standards would be expected to 
reduce NOX emissions in the States not affected by the caps, 
so DOE estimated NOX emissions reductions from the standards 
considered in today's rule for these States.
    The MATS limit mercury emissions from power plants, but they do not 
include emissions caps and, as such, DOE's energy conservation 
standards would likely reduce Hg emissions. For this rulemaking, DOE 
estimated mercury emissions reductions using the NEMS-BT based on AEO 
2012, which incorporates the MATS.
    Chapter 15 of the final rule TSD provides further information on 
the emissions analysis.

M. Monetizing Carbon Dioxide and Other Emissions Impacts

    As part of the development of this rule, DOE considered the 
estimated monetary benefits from the reduced emissions of 
CO2 and NOX that are expected to result from each 
of the considered TSLs. 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 equipment shipped in 
the forecast period for each TSL. This section summarizes the basis for 
the monetary values used for CO2 and NOX 
emissions and presents the values considered in this rulemaking.
    For CO2, DOE is relying on a set of values for the 
social cost of carbon (SCC) that was developed by a government 
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 final rule 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 dioxide 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 \58\ 
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.
---------------------------------------------------------------------------

    \58\ 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 rulemaking, and DOE 
does not attempt to answer that question here.

[[Page 23390]]

    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 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.\59\ 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.
---------------------------------------------------------------------------

    \59\ 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 2011-2015 at 
3-90 (Oct. 2008) (Available at: http://www.nhtsa.gov/fuel-economy).
---------------------------------------------------------------------------

    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.\60\ 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).
---------------------------------------------------------------------------

    \60\ 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).
---------------------------------------------------------------------------

    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.\61\ 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.
---------------------------------------------------------------------------

    \61\ The models are described in appendix 15-A of the final rule 
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 four 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 over time, as depicted in Table IV.9. 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,\62\ although preference is given to consideration of 
the global benefits of reducing CO2 emissions.
---------------------------------------------------------------------------

    \62\ It is recognized that this calculation for domestic values 
is approximate, provisional, and highly speculative.

[[Page 23391]]



                                    Table IV.9--Social Cost of CO2, 2010-2050
                                        [in 2007 dollars per metric ton]
----------------------------------------------------------------------------------------------------------------
                                                                           Discount Rate
                                                 ---------------------------------------------------------------
                                                        5%              3%             2.5%             3%
                      Year                       ---------------------------------------------------------------
                                                                                                       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
----------------------------------------------------------------------------------------------------------------

    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 2011$ using the GDP 
price deflator. For each of the four cases specified, the values used 
for emissions in 2011 were $4.9, $22.3, $36.5, and $67.6 per metric ton 
avoided (values expressed in 2011$).\63\ 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 
final rule TSD, appropriately escalated to 2011$. 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 each SCC value.
---------------------------------------------------------------------------

    \63\ 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
    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 rule using a range of dollar per ton values 
cited by OMB.\64\ These values, which range from $370 per ton to $3,800 
per ton of NOX from stationary sources, measured in 2001$ 
(equivalent to a range of $450 to $4,623 per ton in 2011$), are based 
on estimates of the mortality-based benefits of NOX 
reductions from stationary sources made by EPA. In accordance with OMB 
guidance, DOE conducted two calculations of the monetary benefits 
derived using each of the above values for NOX, one using a 
discount rate of 3 percent and the other using a discount rate of 7 
percent.\65\
---------------------------------------------------------------------------

    \64\ 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 Page 64.
    \65\ OMB, Circular A-4: Regulatory Analysis (Sept. 17, 2003).
---------------------------------------------------------------------------

    Commenting on the NOPR, APPA stated that DOE has significantly 
overstated the environmental benefits from NOX reduction 
attributed to the efficiency levels in the proposed rule. APPA 
suggested that DOE use emissions allowance prices from EPA's Clean Air 
Interstate Rule and the NOX Budget Trading Program, which 
averaged $15.89 per ton in 2011. (APPA, No. 191 at p. 2)
    In response, DOE disagrees with APPA's claim that ``[t]hese 
emissions markets and their subsequent prices were designed to monetize 
the environmental cost of polluting in its entirety.'' Emissions 
allowance prices in any given market are a function of several factors, 
including the stringency of the regulations and the costs of complying 
with regulations, as well as the initial allocation of allowances. The 
prices do not reflect the potential damages caused by emissions that 
still take place. There is extensive literature on valuation of 
benefits of reducing air pollutants, including valuation of reduced 
NOX emissions from electricity generation.\66\ The values 
that DOE has used are consistent with the estimates in the literature.
---------------------------------------------------------------------------

    \66\ See e.g., Burtraw, Dallas, Karen Palmer, Ranjit Bharvirkar, 
and Anthony Paul (2001). Cost-Effective Reduction of NOX 
Emissions from Electricity Generation. Discussion Paper 00-55REV. 
Resources for the Future, Washington, DC.
---------------------------------------------------------------------------

    DOE has decided to await further guidance regarding consistent 
valuation and reporting of Hg emissions before it monetizes Hg in its 
rulemakings.

N. Labeling Requirements

    In the NOPR, DOE responded to comments regarding the classification 
and labeling of rectifier and testing transformers. In response to 
these comments, DOE acknowledged that the proposed additions to the 
definitions helped to clarify ``rectifier'' and ``testing 
transformers'' and proposed to amend the definitions accordingly.

[[Page 23392]]

    Cooper Power expressed support for the plan DOE set forth in the 
NOPR to clarify rectifier and testing transformers. (Cooper, No. 165 at 
p. 2) Howard Industries also expressed support, noting that while they 
do not manufacture rectifier or testing transformers, they find DOE's 
nameplate request to ``indicate that they are for such purposes 
exclusively'' to be acceptable. (HI, No. 151 at p. 12) Earthjustice 
commented that the addition of labeling requirements for rectifier and 
testing transformers can help prevent misapplication of these exempt 
products, but they feel additional changes, such as requiring any print 
or electronic marketing for such units to indicate their use 
specifically, may also be necessary to ensure enforcement. 
(Earthjustice, No. 195 at p. 5; Earthjustice No. 146 at p. 44) However, 
Progress Energy commented that rectifier and testing transformers are 
already very specialized and usually more expensive than distribution 
transformers; therefore, there is a very low chance of a utility 
attempting to replace a distribution transformer with one of these 
transformers. (PE, No. 192 at p. 4) APPA concurred, noting that they 
were unaware of rectifier or testing transformers being used as a 
loophole. (APPA, No. 191 at p. 6) Similarly, HVOLT pointed out that the 
physical differences between rectifier and distribution transformers 
would be fairly obvious without a nameplate marking. Furthermore, they 
feel that adding the word ``rectifier'' to the nameplate would only add 
more congestion. (HVOLT, No. 146 at p. 46)
    In response to the NOPR, many stakeholders expressed their support 
for clearly identifying transformers excluded from DOE standards 
through a standardized labeling system. ABB recommended that the text 
``DOE Excluded: Transformer type'' be included on the nameplate for all 
of the excluded type transformers, and suggested that this labeling 
requirement be added to CFR part 429. (ABB, No. 158 at p. 5) ABB also 
noted that they agree with the proposal to not set standards for step-
up transformers, and that all step-up transformers be identified on the 
nameplate with uniform language. (ABB, No. 158 at p. 6) NEMA agreed 
with ABB, stating that ``labeling should be applied in a consistent 
manner for all designated non-regulated distribution transformers'' and 
suggested the following language be used: ``This ----------Transformer 
is NOT intended for use as a Distribution Transformer per 10 CFR 
431.192'' (NEMA, No. 170 at p. 7) Prolec-GE and PEMCO expressed similar 
ideas, both commenting that all excluded transformers should be 
identified by type and indicate that they are excluded from standards. 
(PEMCO, No. 183 at p. 2; Prolec-GE, No. 177 at p. 7) Schneider 
concurred, stating ``all non-regulated transformers should require 
labeling--not just rectifier and testing transformers.'' (Schneider, 
No. 180 at p.3)
    Prolec-GE encouraged DOE to establish labeling requirements or 
guidelines for covered products for use in the United States. They 
believed that, at present, without specifications for labeling 
products, those charged with certification, compliance and enforcement 
would have difficulty identifying which products were to meet which 
standards a difficult time with inconsistent labeling. (Prolec-GE, No. 
177 at pp. 16-17) Schneider Electric also expressed that regulated 
products should have labeling rules with the following language ``DOE 
10 CFR PART 431 COMPLIANT.'' Schneider would also like DOE 
certification regulations (10 CFR part 429) expanded to include non-
regulated products. (Schneider, No. 180 at p. 3)
    GE commented that refurbished units should be labeled as such and 
have the original manufacturer's nameplate removed. (GE, No. 146 at p. 
114)
    DOE had initially considered amending the definitions of 
``rectifier transformer'' and ``testing transformer'' to include a 
labeling requirement. Commenters, however, have pointed out that a 
number of transformer types would benefit from a clear set of labeling 
requirements, which could aid manufacturers, consumers, and DOE itself 
in determining whether a given sample is covered or determined by the 
manufacturer as meeting the standards. Given the breadth of the issue, 
DOE makes no changes to labeling requirements in today's rule, but may 
address the matter of distribution transformer labeling in a future 
rulemaking. DOE appreciates the comments and feedback regarding 
labeling supplied by the stakeholders. Issues regarding labeling, 
compliance, and enforcement may, however, be considered in a different 
proceeding.

O. Discussion of Other Comments

    Comments DOE received in response to the NOPR analysis on the 
soundness and validity of the methodologies and data DOE used are 
discussed in previous parts of section IV. Other stakeholder comments 
in response to the NOPR addressed specific issues associated with 
amended standards for transformers. DOE addresses these other comments 
below.
1. Supplementary Trial Standard Levels
    DOE created TSLs that each consist of specific efficiency levels 
for a set of design lines. For the NOPR, 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.
    For liquid-immersed distribution transformers, joint comments 
submitted by ASAP, ACEEE, NRDC and NPCC recommended that DOE modify TSL 
4 to represent their collective final position from the Negotiated 
Rulemaking, which advocated including EL 2 for all liquid-immersed 
distribution transformer design lines. (In the NOPR, DOE misstated and 
analyzed the Advocates collective final position from the Negotiated 
Rulemaking as EL3 for all liquid-immersed distribution transformer 
design lines.). They also recommended that DOE examine a TSL 3.5 level, 
which would correspond to EL 1.5 across the board. (ASAP, ACEEE, NRDC, 
NPCC, No. 186 at p. 9)
    In response to these comments DOE considered four new TSLs, labeled 
A, B, C and D, to explore possible energy savings below EL 2. TSL C, 
consisting of EL 2 for all liquid-immersed distribution transformer 
design lines, correctly represents the collective final position of 
ASAP, ACEEE, NRDC, and NPCC in the negotiations. DOE presented these 
new TSLs to stakeholders at a public meeting on June 20, 2012.
    Several parties stated that these new TSLs, while being 
technologically feasible, would present issues due to increased 
transformer size and weight. NRECA, Howard Industries, and NEMA stated 
that this issue would increase the frequency of pole replacement by 
utilities. (NRECA, No. 228 at p. 2; HI, No. 218 at p.1; NEMA, No. 225 
at p. 6) Central Maloney commented that their designs at the new TSLs 
exceeded customer weight specifications for their single-phase, pole-
mounted distribution transformers at various kVA capacities. (CM, No. 
224 at p.3) Others stated that the economic benefits of TSLs B through 
D could only be realized with core steels other than M3 (NEMA, No. 225 
at pp. 4, 5; ATI No. 218 at p. 1), which could transfer significant 
market power to producers of SA1 core steel (AK, No. 230 at p. 4) and 
lead to unintended anti-competitive results. (ATI, No. 218 at p. 1; AK, 
No. 230 at p. 5)
    DOE concluded that all of these new TSLs would result in similar 
burdens as

[[Page 23393]]

the TSLs 2, and 3 that were analyzed in the NOPR. As discussed further 
in section 5.C.1 of this final rule, all of these TSLs would face 
issues regarding the type of steel used in liquid-immersed 
transformers. DOE is concerned that the current supplier of amorphous 
steel, 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 might be needed by transformer manufacturers before 
2015. Although the industry can manufacture liquid-immersed 
distribution transformers at TSL 3 from M3 or lower grade steels, the 
positive LCC and national impacts results are based on lowest first-
cost designs, which include amorphous steel for all the design lines 
analyzed. 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. Given that the recommended TSLs face similar issues as TSL 3, 
DOE did not incorporate them into the final rule.
2. Efficiency Levels
    ASAP, ACEEE, NRDC and NPCC stated that DOE has not evaluated the 
potential impacts of the proposed standards for liquid-immersed 
distribution transformers since the proposed standard levels are not 
the same as the levels in TSL 1 for equipment class 1. They said that 
DOE's final standard must be based on analysis and results for the 
actual efficiency levels established by the final rule. (ASAP, ACEEE, 
NRDC, NPCC, No. 186 at p. 9) Similarly, NEEP stated that the proposed 
TSL 1 for liquid-immersed distribution transformers did not have all 
the corresponding ELs for the various design lines. It noted that DOE 
proposed 98.95 percent for design line 2, which does not correspond to 
any EL. (NEEP, No. 193 at p. 2)
    In response to these comments, for this final rule, DOE analyzed 
the actual efficiency ratings proposed in the NOPR for equipment class 
1 (single-phase liquid-immersed transformers) at TSL 1. These 
efficiencies are 99.11 percent for design line 1, 98.95 percent for 
design line 2, and 99.49 percent for design line 3. These efficiencies 
correspond to EL 0.4 for design line 1, EL 0.5 for design line 2, and 
EL 1.1 for design line 3.
    The TSLs that DOE used for the final rule are presented in section 
V.A of this preamble. DOE notes that, for the final rule, it has 
slightly modified the definition of TSL 2 for low-voltage dry-type 
distribution transformers from the NOPR definition. Where previously DL 
6 had been at EL 3 in TSL 2, in today's rule DL 6 is held at the 
baseline because DOE did not find positive economic benefits to the 
consumer above that level. Small, single-phase transformers tend to be 
lightly-loaded and have a more difficult time than their larger, three-
phase counterparts recovering increases in first cost. DOE believes 
this change provides increased customer benefits with TSL 2.
3. Impact of Standards on Transformer Refurbishment
    A number of parties expressed concern that amended standards on 
transformers would induce use of rebuilt or refurbished distribution 
transformers rather than the more expensive new transformers. (HI, 
No.151 at pp. 9, 12; Cooper, No. 165 at p. 5; Prolec-GE, No. 177 at p. 
14; ComEd, No. 184 at p. 13; Westar, No. 169 at p. 3) Several parties 
stated that the higher the initial cost increase due to energy 
efficiency standards, the higher the likelihood that utilities will use 
more recycled equipment. (EEI, No. 185 at p. 17; APPA, No. 191 at p. 
12; Progress Energy, No. 192 at p. 9) BG&E stated that if new 
transformer requirements significantly increase costs, it may consider 
purchasing refurbished designs to address the size and weight problems 
of transformers meeting the standard. (BG&E, No. 182 at p. 9) Fort 
Collins Utilities commented that it would be purchasing fewer new 
transformers and re-winding more of its existing transformer units. 
(CFCU, No. 190 at p. 3)
    Some parties specifically stated that setting standards for liquid-
immersed distribution transformers greater than TSL 1 would increase 
the use of less-efficient, refurbished transformers, and this would 
reduce the energy savings from such standards. (NEMA, No. 170 at p. 3; 
USW, No. 188 at pp. 4, 18-19) AEC and NRECA stated that if DOE raises 
standards above the levels proposed in the NOPR, it is likely that 
costs will increase dramatically, increasing the likelihood that more 
existing transformers will be recycled via refurbishment, rewinding, or 
rebuilding. (AEC, No. 163 at p. 3; NRECA, No. 172 at p. 3)
    Several parties stated that rebuilt or refurbished transformers 
would be less efficient than new transformers and, therefore, the 
energy saving goals of standards would be undermined. (HI, No. 151 at 
pp. 9, 12; Cooper, No. 165 at p. 5; Prolec-GE, No. 177 at p. 14) AEC 
and NRECA stated that, in some cases, the efficiency of transformers 
may actually increase as a result of refurbishment or rewinding, but 
the efficiency of the refurbished transformer will most likely not meet 
the proposed efficiency levels. (AEC, No. 163 at p. 3; NRECA, No. 172 
at p. 3) HI requested that DOE seek authority over the refurbished/
repair industry to minimize use of lower-efficiency transformers. (HI, 
No. 151 at p. 11)
    DOE acknowledges that a significant increase in the cost of new 
transformers could encourage growth in the use of refurbished 
transformers by some utilities, and that refurbished transformers 
likely would be less efficient than new transformers meeting today's 
standards. Although DOE was not able to explicitly model the likely 
extent of refurbishing at each considered TSL, it did include in its 
shipments analysis a price elasticity parameter that captures the 
response of the market to higher costs in a general way (see chapter 9 
of the final rule TSD). Furthermore, DOE believes that the costs of new 
transformers meeting today's standards, which are approximately 3.0 
percent (design line 2) and 13.1 percent (design line 3) higher than 
today's typical single-phase liquid-immersed distribution transformers, 
and approximately 6.9 percent (design line 4) and 12.6 percent (design 
line 5) higher than today's typical three-phase liquid-immersed 
transformers, would not be so high as to induce a significant level of 
refurbishing instead of replacement.
    Earthjustice asserted that ``the statute leaves room for DOE to 
regulate the efficiency of rebuilt transformers'' and that ``it is 
reasonable for DOE to determine that rewound transformers are `new 
covered products' subject to energy conservation standards if the title 
of the rewound transformer is then transferred to an end-user.'' 
(Earthjustice No. 195 at p. 6) Other commenters reached opposite 
conclusions regarding whether DOE has the authority to regulate 
refurbished or rewound transformers. AEC agreed with statements made by 
DOE's Office of the General Counsel during negotiations that existing 
and recycled transformers are not ``covered'' equipment and would not 
have to meet the proposed energy efficiency standards for new products 
that are ``covered.'' (AEC No. 163 at p. 3)
    DOE has analyzed this issue for many years. For instance, in its 
August 4, 2006, NOPR, DOE summarized its legal authority to regulate 
new, used and refurbished transformers and sought public comment on the 
issue. 71 FR 44356, 44366-67. In that notice, DOE noted that for the 
entire history of its appliance and commercial equipment energy 
conservation standards program, DOE has not sought to regulate used

[[Page 23394]]

units that have been reconditioned or rebuilt, or that have undergone 
major repairs. DOE stated that given there is no legislative history to 
ascertain Congressional intent and the potential ambiguity of the 
statutory language, this conclusion was based on detailed analysis and 
interpretation of numerous statutory provisions in the EPCA, namely 42 
U.S.C. 6302, 6316(a) and 6317(a)(1). Importantly, DOE analyzed the 
meaning of a ``newly covered product'' and whether a refurbished 
transformer could nonetheless fall under this definition. (42 USC sec. 
6302) The most reasonable interpretation of the statutory definition is 
that Congress intended that this provision apply to newly manufactured 
products and equipment the title of which has not passed for the first 
time to a consumer of the product. This conclusion was reiterated in 
the October 12, 2007 final rule. (72 FR 58203) And this remains DOE's 
position today. The issue was raised during the negotiations, and 
again, DOE emphasized that refurbished transformers were not 
``covered'' equipment as defined by EPCA. (DOE No. 95 at p. 95) Despite 
DOE's lack of legal authority, DOE has continued to evaluate the degree 
to which utilities may purchase a refurbished product rather than a new 
transformer, as discussed above.
4. Alternative Means of Saving Energy
    Rockwood Electric commented that a more effective means of saving 
energy than requiring energy conservation in the distribution 
transformers themselves would be to require that power distribution 
occur at higher voltages and thereby reduce resistive losses. (Rockwood 
Electric, No. 167 at p. 1) CFCU advocated that DOE seek more cost-
effective means of finding efficiency in electric distribution systems 
than by increasing efficiency standards for distribution transformers. 
(CFCU, No. 190 at p. 2) DOE has no plans to address distribution 
voltage ratings in the present rulemaking, and does not consider the 
possibility to fall within its scope of coverage.
5. Alternative Rulemaking Procedures
    Prior to publication of the NOPR, DOE held a series of negotiating 
sessions to discuss standards for all three types of distribution 
transformer under the Negotiated Rulemaking Act. The negotiating 
parties succeeded in arriving at a consensus standard for medium-
voltage dry-type transformers, which is adopted in today's rule. Such 
adoption was supported by a broad spectrum of parties as discussed 
previously (Advocates, 4/10/12 comment at p. 2) Several parties 
commented on the negotiated rulemaking process.
    Despite praising the consensus agreement on the medium-voltage-dry-
type units, the Advocates commented that overall the process ``produced 
virtually no benefits.'' (Advocates, No. 186 at p. 14) In contrast, 
NEMA commented that the process was extremely valuable and resulted in 
a better analysis. (NEMA, No. 170 at p. 2) Eaton remarked that the 
negotiation process improved the resulting proposal for LVDT 
distribution transformers and was a more efficient vehicle for 
considering stakeholder input. (Eaton, No. 157 at p. 2) Progress Energy 
recommended that the spirit of the negotiating committee be retained 
indefinitely through formation of a task force of stakeholders that 
could advise DOE in the future. (PE, No. 192 at p. 2)
    DOE appreciates feedback on the negotiation process and will 
consider its use in appropriate future rulemakings. Currently, DOE has 
no plans to form a task force on distribution transformer standards.
6. Proposed Standards--Weighting of Benefits vs. Burdens
    DOE received many comments that supported or criticized the 
Department's weighing of the benefits and burdens in its selection of 
the proposed levels, particularly for liquid-immersed and low-voltage 
dry type transformers. The first section below presents general 
comments on all of the transformer superclasses, and the following 
sections present comments specifically on each of the superclasses. The 
final section presents a response to the comments by DOE.
a. General Comments
    Many stakeholders expressed their support for the standards 
proposed by DOE. (AK, No. 146 at p. 143; ATI, No. 146 at p. 7; ATI, No. 
181 at p. 1-2; CDA, No. 153 at p. 1; ComEd, No. 184 at p. 1; Cooper, 
No. 165 at p. 1; DE, No. 179 at p. 1; JEC, No. 173 at p. 2; KAEC, No. 
126 at p. 1-2; KAEC, No. 149 at p. 7; NEMA, No. 146 at p. 146; NRECA, 
No. 146 at p. 158; PECO, No. 196 at p. 1; UAW, No. 194 at p. 1; USW, 
No. 148 at p. 1; Adams Electrical Coop, No. 13) Others pointed out that 
these levels are well-balanced, allowing cold rolled grain-oriented 
steel (CRGO)/amorphous competition, energy savings, and benefits to 
consumers without unduly harming manufacturers. (ATI, No. 146 at p. 9; 
Cooper, No. 143 at p. 1; Cooper, No. 146 at p. 13-14; (FedPac, No. 132 
at p. 1 and pp. 3-4; HVOLT, No. 144 at p. 1 and pp. 10-11; NEMA, No. 
146 at p. 12-13; Prolec-GE, No. 146 at p. 14-15; Schneider, No. 180 at 
p. 1; USW, No. 148 at p. 1) Other parties agreed, noting that a higher 
standard would cause a transition to amorphous steel, and urged DOE not 
to move to higher standard levels, as the proposed standards are the 
highest justified levels. (USW, No. 148 at p. 2; Weststar, No. 169 at 
p. 1 and p. 4; Adams Electrical Coop, No. 163 at p. 1; APPA, No. 191 at 
p. 2; Steelmakers, No. 188 at p. 2; PECO, No. 196 at p. 1; NEMA, No. 
170 at p. 2; MTEMC, No. 210 at p. 1; EEI, No. 185 at p. 2; BG&E, No. 
182 at p. 2; BSE, No. 152 at p. 1) ATI agreed, noting that the NOPR 
efficiency levels are the proper levels to ensure M3 and amorphous 
metals are cost competitive with each other. (ATI No. 181 at p. 2) KAEC 
commented that increased standards could pose a threat to small 
manufacturers. (KAEC, No. 126 at p. 2) BSE commented that an increase 
in standards would increase the capital expense of the transformer, 
which will in turn have a negative impact on rates that consumers are 
charged for their electricity with very minimal gains in efficiency. 
(BSE, No. 152 at p. 1) NEMA noted that there are no utility problems at 
the current proposed levels. (NEMA, No. 170 at p. 13) Steelmakers 
commented that DOE's proposal for liquid-immersed transformers 
correctly states that the standards it is proposing will not lessen the 
utility or performance of distribution transformers, while noting that 
increasing standards would negatively impact utility. (Steelmakers, No. 
188 at pp. 15-16) AEC and NRECA both noted that under any revised 
analysis, DOE should not consider increasing the proposed efficiency 
levels, as the evidence has shown that there would be many negative 
impacts on domestic steelmakers, domestic transformer manufacturers, 
electric utilities, and end-use customers. (AEC, No. 163 at p. 1; 
NRECA, No. 172 at pp. 2, 6) NRECA supported the proposed efficiency 
levels in the NOPR as they minimize the concerns associated with size 
and weight issues. (NRECA, No. 172 at p. 8) APPA members recommend that 
the proposed efficiency levels should be viewed as the maximum 
achievable levels. (APPA, No. 191 at p. 2)
    Other parties believe that DOE should choose more stringent 
efficiency levels. ASAP, ACEEE, NRDC and NPCC stated that a more 
thorough consideration of the record and completion of critical missing 
or incomplete analyses will lead DOE to the conclusion that higher 
standards are justified for both low-voltage dry-type and medium-
voltage liquid-immersed transformers. They stated that higher standards 
than those

[[Page 23395]]

proposed would yield shorter paybacks for consumers and much larger 
environmental and energy system benefits. The Advocates noted that 
other major countries, including China and India, make use of amorphous 
core transformers to a greater degree than does the United States. 
(Advocates, No. 186 at pp. 2-3) Metglas requested that DOE revise the 
proposed regulation because it deprives consumers of billions of 
dollars in potential energy savings and millions of tons of harmful 
pollution reductions by favoring older, less efficient transformer 
designs over innovative U.S.-made energy-efficient technologies. 
(Metglas, No. 102 at p. 3)
    EMS Consulting commented that DOE's rationale for setting lower 
standards to minimize impact on the distribution transformer industry 
will cost the country significant potential energy savings and 
recommended higher standards for both liquid-immersed and low-voltage 
dry-type transformers. Based on EMS' calculations, a standard set 
between EL 1.5 and EL 2 for liquid-immersed transformers would allow 
the nation to gain additional energy savings while increasing demand 
for grain-oriented steels and creating a new market for amorphous 
steel. The market for grain-oriented steels will also expand as a 
result of higher standards for low-voltage dry-type transformers, which 
may be able to achieve EL 3 with M4/M5 material and butt-lap cores or 
EL 4 with step-lap mitering, and the investment required by industry to 
meet EL 4 is well-justified considering benefits to end users. (EMS, 
No. 178 at p. 8)
    Some stakeholders commented that the proposed standards were too 
high and were not economically justified. (WE, No. 168 at p. 1,3; Sioux 
Valley Energy, No. 159 at p. 1; Polk-Burnett Electric Cooperative, No. 
175 at p. 1; PJE, No. 202 at p. 1; MEC, No. 161 at p. 1; East Miss. 
EPA, No. 166 at p. 1; Central Electric Power Coop, No. 176 at p. 1) 
Specifically, stakeholders noted that the proposed standards would 
cause hardships to electricity consumers. (KEC, No. 164 at p. 1; BEC, 
No. 204 at p. 1; BEC, No. 205 at p. 1; CHELCO, No. 203 at p. 1) East 
Central Energy agreed, noting that the proposed standards achieve 
little to no benefit and would cost extra for manufacturers. (East 
Central Energy, No. 160 at p. 1) BEC pointed out that the cost savings 
were overstated in the NOPR. (BEC, No. 205 at p. 1) Westar Energy 
commented that they were hesitant to support even an increase to EL1 
for liquid-immersed units. (Westar, No. 169 at p. 1) CCED noted that 
the standards proposed in the NOPR were without merit and the existing 
2010 standards should be maintained instead. (CCED, No. 174 at p. 3)
    Some stakeholders expressed opinions about how steel availability 
should factor into the standards that DOE chooses. Progress Energy 
urged DOE not to set a standard that would result in the use of 
specific steels that have questionable supply availability, noting that 
M3 and M4 grades of core steel should be required for 85 percent or 
more of any required efficiency level. (PE, No. 192 at p. 7-8) 
Earthjustice felt that DOE failed to rationally analyze the potential 
impacts associated with steel production capacity constraints while 
deciding on standard levels. (Earthjustice, No. 195 at p. 1) The 
Advocates noted that in the long term, amorphous steel is likely to 
predominate in the transformer market due to higher efficiency. They 
commented that countries such as China and India are fostering a 
transition to highly efficient transformers and more amorphous steel is 
used in these countries than in the United States. (Advocates, No. 186 
at pp. 13-14)
b. Standards on Liquid-Immersed Distribution Transformers
    The Advocates felt that DOE emphasized the worst-case scenario for 
manufacturer impacts when rejecting TSL 2 and TSL 3 for liquid-immersed 
transformers. (Advocates, No. 186 at p. 12) They noted that at TSL 4 
for liquid-immersed transformers, potential costs to manufacturers are 
still far less than potential benefits to consumers. (Advocates, No. 
186 at p. 11) The Advocates stated that DOE estimates that TSL 4 could 
result in a potential loss of industry value of 12 percent under the 
``maintenance of profits'' scenario, a potential impact well within the 
norm of DOE estimates for other standards rulemakings. (Advocates, No. 
186 at p. 3) The Advocates stated that a standard in the range of TSL 
3.5 to TSL 4 would promote robust competition between silicon steel and 
amorphous metal, maximizing benefits for consumers and producing much 
larger energy savings for the Nation. They stated that TSL 4 or 3.5 can 
be met even if amorphous metal supplies do not increase. They added 
that if DOE feels that more time would provide greater confidence that 
supply of amorphous steel could increase to help meet market needs 
triggered by a TSL 3.5 or TSL 4 standard, they would not object to 
moving the effective date of today's rule a year or two further into 
the future. (Advocates, No. 186 at pp. 9-11)
    At the NOPR public meeting, ASAP commented that the standard levels 
proposed for liquid-immersed transformers are far below the point that 
would maximize consumer benefits because DOE put an inordinate amount 
of weight on manufacturer impacts to the detriment of consumer 
benefits. (ASAP, No. 146 at p. 27) They also commented that DOE placed 
significant weight on steel manufacturer impacts but did not conduct a 
more detailed analysis on those impacts, in particular one which 
includes employment at each TSL for steel manufacturers. (ASAP, No. 146 
at p. 143) ASAP recommended that DOE select EL 2 for liquid-immersed 
units. (ASAP, No. 146 at p. 18)
    Berman Economics stated that DOE's rationale for choosing TSL 1 for 
liquid-immersed transformers, that a higher standard would require an 
unacceptable increase in cost to industry, suggests that DOE prefers 
that consumers pay more money than to require additional investment on 
the part of manufacturers. (Berman Economics, No. 150 at p. 2-3) Berman 
Economics also argues that DOE's rejection of EL 2 for liquid-immersed 
transformers is an indication that DOE is focused on avoiding 
competition for silicon steel even at the cost of energy and consumer 
savings and environmental preservation. (Berman Economics, No. 150 at 
p. 4) EMS recommended a level between EL 1.5 and EL 2.0. (EMS, No. 178 
at p. 7)
    Several stakeholders felt that DOE relied on impacts on small 
manufacturers too heavily, and noted that small manufacturers can build 
up to TSL 3. (Earthjustice, No. 195 at p. 2; Advocates, No. 186 at p. 
11; NEEP, No. 193 at p. 1; ASAP, No. 146 at pp. 26-27; CA IOUs, No. 189 
at p. 3)
    Some stakeholders stated that setting higher standards may result 
in reduced benefits to consumers. EEI stated that utilities are 
concerned that if standards are set so high that transformer 
manufacturers need to use steels with possible supply constraints, 
there may be negative impacts on the electrical grid, which would have 
a negative impact on consumers. (EEI, No. 185 at p. 13)
    EEI stated that several members expressed concern that the more 
efficient transformers will be larger in size (height, width, and 
depth), which will have an impact for all retrofit situations, and they 
would have much larger weights, which would increase costs in terms of 
installation and pole structural integrity for retrofits of existing 
pole-mounted transformers. (EEI, No. 185 at p. 11) A number of electric 
utilities made similar comments. (BG&E, No. 182 at p. 6;

[[Page 23396]]

ComEd, No. 184 at p. 11; EMEPA, No. 166 at p. 1; PECO, No. 196 at p. 1; 
Pepco, No. 145 at p. 3; WE, No. 168 at p. 3; Westar, No. 169 at p. 2) 
Howard Industries also stated that the increased size and weight will 
sometimes be a constraint and result in increased costs. (HI, No. 151 
at p. 7)
    A number of parties expressed specific concerns about size and 
space constraints for network/vault transformers. (BG&E, No. 182 at p. 
6; ComEd, No. 184 at p. 11; Pepco, No. 145 at pp. 2-3; PE, No. 192 at 
p. 8; Prolec-GE, No. 177 at p. 12) These concerns lead several parties 
to recommend a separate equipment class for network/vault transformers. 
(DOE addresses this issue in section IV.A.2.) EEI and several electric 
utilities stated that efficiency standards for network/vault 
transformers should be the same as the efficiency levels that have been 
in effect since January 1, 2010. (EEI, No. 185 at p. 3; Pepco, No. 145 
at p. 2; PE, No. 192 at p. 8; Prolec-GE, No. 177 at p. 12)
    Northern Wasco supported the DOE proposal for liquid-immersed units 
and believed anything beyond would not be cost-effective. (NWC, No. 147 
at p. 1) UAW agreed, noting that any level above TSL 1 would not be 
economically justified. (UAW, No. 194 at p. 2) ATI stated that 
efficiency levels in excess of the NOPR proposal would create a non-
competitive market for new medium-voltage liquid-type designs that 
would eliminate projected LCC savings. (ATI, No. 54 at p. 2) 
Steelmakers commented that promulgating energy conservation standards 
greater than TSL 1 for liquid-immersed transformers would transfer 
significant competitive power to the sole maker of amorphous metal. 
(Steelmakers, No. 188 at pp. 9-10)
    After the supplementary analysis was presented, which included the 
new TSLs described in section IV.O.1, a handful of stakeholders 
recommended that DOE adopt one of the TSLs presented in the 
supplementary analysis. The Advocates recommended that DOE adopt TSL C, 
following the supplementary rulemaking process, to increase energy 
savings relative to the levels proposed in the NOPR and increase life 
cycle cost savings. (Advocates, No. 235 at p. 2) They added that if DOE 
wants to foster a more gradual market growth for amorphous metal, TSL D 
would achieve such an outcome by lowering the standard for pole type 
transformers, but would still approach the national savings of TSL C. 
(Advocates, No. 235 at p. 1) Berman Economics agreed that TSL C or D 
should be selected as they provide the best balance. (Berman Economics, 
No. 221 at p. 1) NEMA stated that TSL A was the only level presented in 
the supplementary rulemaking that met the three principles that they 
applied during the rulemaking process to select levels, but suggested 
that the level be moved to EL 0 for design line 2. (NEMA, No. 225 at p. 
4) Prolec-GE expressed their support for TSL A as well, believing that 
these efficiency levels provide additional energy savings while 
preserving manufacturers' ability to use both silicon and amorphous 
steel to meet the demand of the market. In the absence of TSL A, they 
recommended TSL 2 as the maximum possible alternative, which they noted 
would result in higher cost and heavier and larger pole units. (Prolec-
GE, No. 238 at p. 3)
c. Standards on Low-Voltage Dry-Type Distribution Transformers
    The Advocates stated that for LVDT transformers, DOE rejected TSL 3 
despite its own economic analysis showing greater net consumer savings, 
and mean paybacks of five to twelve years, well within a transformer's 
typical 30-year lifespan. (Advocates, No. 186 at p. 3) They stated that 
a more thorough investigation of impacts on domestic small 
manufacturers and a better balancing of public benefits and 
manufacturer impacts will lead DOE to adopt TSL 3, the maximum level 
which yields net present value benefits for consumers and can 
incontrovertibly be achieved using silicon steel cores. They said that 
if DOE rejects TSL 3, the agency should at least adopt TSL 2, which 
represents the NEMA Premium[supreg] level (30 percent reduction in 
losses) for all transformers. They added that DOE overestimated the 
savings from the proposed standards (i.e., TSL 1). (Advocates, No. 186 
at pp. 3-4) However, they recommend that if TSL 3 is not adopted, TSL 2 
should be chosen, as a number of manufacturers are already committed to 
manufacturing at NEMA Premium[supreg]. (Advocates, No. 186 at p. 7-8) 
ASAP commented that DOE should select EL 4 for DL7 and DL8. (ASAP, No. 
146 at p. 19) EMS stated that low-voltage dry-type standards should be 
set at TSL 2 or TSL 3. (EMS, No. 178 at p. 7)
    CA IOUs stated that TSL 3 is the highest achievable efficiency 
level at which low-voltage dry-type distribution transformers can be 
constructed using grain-oriented steel, and they recommend that DOE 
consider adopting standards at this level. They noted that while DOE 
expresses concern that small manufacturers are disproportionately 
impacted by standards for low-voltage dry-type transformers, DOE's 
analysis shows that there are actually very few small manufacturers in 
this market, and that those small manufacturers that do exist in the 
market primarily focus on design lines that are exempted from coverage. 
(CA IOUs, No. 189 at pp. 2-3)
    Schneider Electric and FedPac both expressed support for the low-
voltage dry type proposed standards in the NOPR. (FedPac, No. 132 at p. 
2; Schneider, No. 180 at p. 1) FedPac noted that the proposed standards 
may be slightly high for 3-phase above 150 kVA and may put small 
manufacturers at risk due to potentially large capital investments 
necessary to remain in business at these levels. (FedPac, No. 132 at 
pp. 2-3)
    Some stakeholders demonstrated support for NEMA Premium[supreg] 
levels for low-voltage dry-type transformers. Eaton noted that NEMA 
Premium[supreg] represents an opportunity to produce efficiency gains 
and encourage new technologies and recommended adopting NEMA 
Premium[supreg] for DL7 and DL8. (Eaton, No. 157 at p. 2) NEEP pointed 
out that industry parties suggested higher efficiency on the record 
during negotiations, including NEMA Premium[supreg]. (NEEP, No. 193 at 
p. 5)
    NEMA recommended that DOE select ELs 0, 2 and 2 for DLs 6, 7 and 8, 
respectively. NEMA noted that NEMA Premium[supreg] was still in 
development. (NEMA, No. 170 at p. 5) NEMA expressed concern that high 
efficiency standards for LVDT transformers would hurt small U.S. 
manufacturers. (NEMA, No. 170 at p. 5)
d. Standards on Medium-Voltage Dry-Type Distribution Transformers
    The Advocates expressed support for the proposed standards for 
medium-voltage dry-type (MVDT) transformers. (The Advocates, No. 186 at 
p. 2) FedPac noted that the DOE was correct in its NOPR decision to not 
increase standards for single-phase MVDTs. (FedPac, No. 132 at p. 2)
    NEMA made specific recommendations for medium-voltage, dry type 
transformers. First, it recommended for DL13 that the efficiency level 
allow for 10 percent more loss that DL12, as these are high BIL 
transformers. Second, it noted that for single-phase transformers the 
single-phase efficiency should be less than the three-phase efficiency 
by a maximum of 30 percent higher losses and should not exceed 2010 
standard. (NEMA, No. 170 at p. 4)
    NEMA stated that for medium-voltage dry-type transformers used in 
high-rise buildings, it recommended different treatment because of size 
and weight

[[Page 23397]]

limitations (elevator capacity) in existing installations. It stated 
that manufacturers are confident that the sizes and weights of the 
high-rise MVDT transformer in compliance with the current standards can 
continue to be used without significant problems, but going to any 
higher efficiency levels for high-rise MVDT transformers will adversely 
impact the continued installation and replacement of this type of 
transformer. (NEMA, No. 170 at p. 4) BG&E and ComEd also stated that 
designs that increase the size and weight of dry-type transformers 
could prohibit replacement of existing units used in high-rise 
buildings. (BG&E, No. 182 at p. 6; ComEd, No. 184 at p. 11)
e. Response to Comments on Standards Proposed in Notice of Proposed 
Rulemaking
    DOE acknowledges the comments described above and has taken them 
into account in developing today's final rule. 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. In section V.C, DOE explains why it has 
adopted the standards established by this final rule, and it addresses 
the issues raised in the preceding comments. DOE agrees with many of 
the concerns associated with higher efficiency transformers, and these 
considerations contributed to the selection of today's standards. In 
particular, DOE believes that the increase in medium-voltage dry-type 
distribution transformer size and weight for the efficiency levels in 
today's final rule, which were unanimously agreed to by the negotiation 
committee, will not adversely impact the continued installation and 
replacement of these transformers.

V. Analytical Results and Conclusions

A. Trial Standard Levels

    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. The mapping of TSLs to corresponding 
efficiency levels for each design line is described in detail in 
chapter 10, section 10.2.2.3 of the final rule TSD. The baseline in the 
tables is equal to the current energy conservation standards.
    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 EL 3 for design line 7, EL 2 for design line 8 and no 
efficiency increase for design line 6; 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 based on the 
subcommittee consensus detailed in section II.B.2, above, 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 technologically feasible level (max tech).

                        Table V.1--Efficiency Values of the Trial Standard Levels for Liquid-Immersed Transformers by Design Line
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          TSL
                   Design line                      Baseline  ------------------------------------------------------------------------------------------
                                                                    1            2            3            4            5            6            7
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                  Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1...............................................        99.08        99.11        99.16        99.16        99.22        99.25        99.31        99.50
2...............................................        98.91        98.95        99.00        99.00        99.07        99.11        99.18        99.41
3...............................................        99.42        99.49        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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                 TSL
                         Design line                             Baseline  -----------------------------------------------------------------------------
                                                                                 1            2            3            4            5            6
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                        Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
6............................................................        98.00        98.00        98.00        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
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 23398]]


  Table V.3--Efficiency Values of the Trial Standard Levels for Medium-Voltage Dry-Type Transformers by Design
                                                      Line
----------------------------------------------------------------------------------------------------------------
                                                                               TSL
            Design line               Baseline  ----------------------------------------------------------------
                                                      1            2            3            4            5
----------------------------------------------------------------------------------------------------------------
                                                                       Percent
                                   -----------------------------------------------------------------------------
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        99.84        99.45
13B...............................        99.15        99.19        99.28        99.28        99.28        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, 
higher-efficiency equipment would affect customers in two ways: (1) 
Annual operating expense would decrease, and (2) purchase price would 
increase. Section IV.F.2 of this preamble 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 
base-case equals or exceeds 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 (%)........................................         99.11         99.16         99.16         99.22         99.25         99.31         99.50
Transformers with Net LCC Cost (%) *..................         37.3          44.2          44.2           7.0           7.0          11.2          42.6
Transformers with Net LCC Benefit (%) *...............         62.5          55.6          55.6          92.9          92.9          88.8          57.4
Transformers with No Change in LCC (%) *..............          0.2           0.2           0.2           0.2           0.2           0.0           0.0
Mean LCC Savings ($)..................................         83           153           153           696           696           618           365
Median PBP (Years)....................................         17.7          24.7          24.7          10.8          10.8          13.7          24.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.
** The results are the same for these TSLs because in both cases customers are expected to purchase the least cost transformer designs that meet the EL.
  The least cost transformer designs are the same for TSLs 4 and 5.


                           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 (%)........................................         98.95         99.00         99.00         99.07         99.11         99.18         99.41
Transformers with Net LCC Cost (%) *..................         41.5          18.2          18.2          11.4          13.1          17.8          67.2
Transformers with Net LCC Benefit (%) *...............         55.2          81.8          81.8          88.6          86.9          82.2          32.8
Transformers with No Change in LCC (%) *..............          3.4           0.0           0.0           0.0           0.0           0.0           0.0
Mean LCC Savings ($)..................................         66           278           278           343           330           311          -579
Median PBP (Years)....................................          5.9           9.9           9.9          11.1          13.0          15.5          31.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


[[Page 23399]]


                           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 (%)........................................         99.49         99.48         99.51         99.57         99.54         99.61         99.73
Transformers with Net LCC Cost (%) *..................         14.5          13.9          12.0           4.0           5.3           4.0          29.9
Transformers with Net LCC Benefit (%) *...............         84.2          84.8          86.9          95.9          94.7          96.0          70.1
Transformers with No Change in LCC (%) *..............          1.3           1.3           1.2           0.0           0.0           0.0           0.0
Mean LCC Savings ($)..................................       2709          2407          3526          5527          5037          6942          4491
Median PBP (Years)....................................          8.5           8.3           5.8           6.5           6.4           7.2          19.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


                           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         99.19         99.22         99.25         99.50
Transformers with Net LCC Cost (%) *..................          6.6           6.6           6.6           7.6           2.5           2.5           5.9
Transformers with Net LCC Benefit (%) *...............         92.8          92.8          92.8          91.8          96.9          96.9          94.1
Transformers with No Change in LCC (%) *..............          0.6           0.6           0.6           0.6           0.6           0.6           0.0
Mean LCC Savings ($)..................................        977           977           977          1212          3603          3603          4349
Median PBP (Years)....................................          7.0           7.0           7.0           9.1           5.6           5.6          10.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


                           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 (%) *..................         30.5          30.5          19.9           9.8          14.8           9.1          41.9
Transformers with Net LCC Benefit (%) *...............         69.1          69.1          80.0          90.2          85.2          91.0          58.1
Transformers with No Change in LCC (%) *..............          0.4           0.4           0.1           0.0           0.0           0.0           0.0
Mean LCC Savings ($)..................................       3668          3668          6852         10382          8616         12014          4619
Median PBP (Years)....................................          6.5           6.5           6.5           9.1           8.5          11.4          22.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
*Rounding may cause some items to not total 100 percent.


                           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         98.00         98.93         99.17         99.17         99.44
Transformers with Net LCC Cost (%) *...............................          0.0           0.0          16.5          37.8          37.8          96.6
Transformers with Net LCC Benefit (%) *............................          0.0           0.0          83.5          62.2          62.2           3.4
Transformers with No Change in LCC (%) *...........................        100.0         100.0           0.0           0.0           0.0           0.0
Mean LCC Savings ($)...............................................          0             0           325           148           148          -992
Median PBP (Years).................................................          0.0           0.0          12.4          15.7          15.7          31.7
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


                          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 Increase in LCC (%) *........................          1.5           1.3           1.7           3.3           3.3          45.6

[[Page 23400]]

 
Transformers with Net LCC Savings (%) *............................         98.4          98.7          98.3          96.7          96.7          54.4
Transformers with No Impact on LCC (%) *...........................          0.1           0.1           0.0           0.0           0.0           0.0
Mean LCC Savings ($)...............................................       1526          1678          1838          2280          2280           212
Median PBP (Years).................................................          3.9           3.6           4.1           6.3           6.3          16.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
*Rounding may cause some items to not total 100 percent.


      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                 4.7           4.7          13.3           9.0          79.3          79.3
 Increase in LCC (%) *......
Transformers with Net LCC            95.3          95.3          86.7          91.0          20.7          20.7
 Savings (%) *..............
Transformers with No Impact           0.0           0.0           0.0           0.0           0.0           0.0
 on LCC (%) *...............
Mean LCC Savings ($)........       2588          2588          2724          4261         -2938         -2938
Median PBP (Years)..........          7.7           7.7          11.3          10.1          22.5          22.5
----------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


      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 (%)           3.6           3.6           5.9           5.9          57.4
 *........................................
Transformers with Net LCC Savings (%) *...         83.2          83.2          94.1          94.1          42.6
Transformers with No Impact on LCC (%) *..         13.3          13.3           0.0           0.0           0.0
Mean LCC Savings ($)......................        787           787          1514          1514          -299
Median PBP (Years)........................          2.6           2.6           6.1           6.1          18.5
----------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


      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          17.9          17.9          17.9          88.8
 *........................................
Transformers with Net LCC Savings (%) *...         98.8          82.1          82.1          82.1          11.2
Transformers with No Impact on LCC (%) *..          0.5           0.0           0.0           0.0           0.0
Mean LCC Savings ($)......................       4604          4455          4455          4455        -14727
Median PBP (Years)........................          1.1           8.6           8.6           8.6          27.5
----------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


      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 (%)          21.9          21.9          25.9          25.9          82.7
 *........................................
Transformers with Net LCC Savings (%) *...         78.1          78.1          74.1          74.1          17.4
Transformers with No Impact on LCC (%) *..          0.0           0.0           0.0           0.0           0.0
Mean LCC Savings ($)......................        996           996          1849          1849         -4166
Median PBP (Years)........................         10.6          10.6          13.6          13.6          24.1
----------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


[[Page 23401]]


      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 (%)           7.1           7.6          17.1          17.1          85.4
 *........................................
Transformers with Net LCC Savings (%) *...         92.9          92.4          82.9          82.9          14.6
Transformers with No Impact on LCC (%) *..          0.0           0.0           0.0           0.0           0.0
Mean LCC Savings ($)......................       4537          6790          8594          8594        -14496
Median PBP (Years)........................          6.0           8.5          12.3          12.3          24.7
----------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


     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         98.84         99.04         99.45
Transformers with Net Increase in LCC (%)          54.2          54.2          45.5          66.3          98.5
 *........................................
Transformers with Net LCC Savings (%) *...         45.8          45.8          54.5          33.7           1.5
Transformers with No Impact on LCC (%) *..          0.0           0.0           0.0           0.0           0.0
Mean LCC Savings ($)......................        -27           -27           311         -1019        -12053
Median PBP (Years)........................         16.1          16.1          16.2          20            35.3
----------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.


     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         99.28         99.28         99.52
Transformers with Net Increase in LCC (%)          30.5          27.3          27.3          27.3          70.4
 *........................................
Transformers with Net LCC Savings (%) *...         69.3          72.7          72.7          72.7          29.6
Transformers with No Impact on LCC (%) *..          0.2           0.0           0.0           0.0           0.0
Mean LCC Savings ($)......................       2494          4346          4346          4346         -6823
Median PBP (Years)........................          4.5          12.2          12.2          12.2          20.6
----------------------------------------------------------------------------------------------------------------
* Rounding may cause some items to not total 100 percent.

b. Customer Subgroup Analysis
    In the customer subgroup analysis, DOE estimated the LCC impacts of 
the distribution transformer TSLs on purchasers of vault-installed 
transformers (primarily urban utilities). DOE included only the three-
phase liquid-immersed design lines in this analysis, since those types 
account for the vast majority of vault-installed transformers. Table 
V.18 shows the mean LCC savings at each TSL for this customer subgroup.
    Chapter 11 of the final rule TSD explains DOE's method for 
conducting the customer subgroup analysis and presents the detailed 
results of that analysis.

                 Table V.18--Comparison of Mean Life-Cycle Cost Savings for Liquid-Immersed Transformers Purchased by Consumer Subgroup
                                                                         [2011$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                  Trial standard level
                         Design line                          ------------------------------------------------------------------------------------------
                                                                    1            2            3            4            5            6            7
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Medium Vault Replacement Subgroup
--------------------------------------------------------------------------------------------------------------------------------------------------------
4............................................................        -1236        -1236        -1236        -3078         -759         -759         -377
5............................................................         2387         2387        -6183        -4421        -6156        -2905         4619
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      All Customers
--------------------------------------------------------------------------------------------------------------------------------------------------------
4............................................................          977          977          977         1212         3603         3603         4349
5............................................................         3668         3668         6852        10382         8616        12014         4619
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 23402]]

c. Rebuttable Presumption Payback
    As discussed in section IV.F.3.j, EPCA establishes a rebuttable 
presumption that an energy conservation standard is economically 
justified if the increased purchase cost for equipment 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. 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 and Table V.21 show the 
rebuttable-presumption PBPs for the considered TSLs. The rebuttable 
presumption is fulfilled in those cases where the PBP is three years or 
less. However, DOE routinely conducts an economic analysis that 
considers the full range of impacts to the customer, manufacturer, 
Nation, and environment, as required under 42 U.S.C. 6295(o)(2)(B)(i). 
The results of that 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 three-year PBP 
analysis). Section V.C addresses how DOE considered the range of 
impacts to select today's standard.

                        Table V.19--Rebuttable-Presumption Payback Periods (years) for Liquid-Immersed Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                  Trial standard level
             Design line                 Rated capacity kVA   ------------------------------------------------------------------------------------------
                                                                    1            2            3            4            5            6            7
--------------------------------------------------------------------------------------------------------------------------------------------------------
1...................................  50.....................         17.5         17.7         17.7         12.5         12.5         14.9         20.0
2...................................  25.....................         22.5         20.7         20.7         16.5         17.1         18.3         34.2
3...................................  500....................          9.1          9.0          9.0          7.6          8.0          7.5         16.9
4...................................  150....................          8.1          8.1          8.1          5.5          5.5          5.5         17.5
5...................................  1500...................         13.1         13.1          8.4          8.5          8.7         10.0         19.9
--------------------------------------------------------------------------------------------------------------------------------------------------------


                      Table V.20--Rebuttable-Presumption Payback Periods (years) for Low-Voltage Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                        Trial standard level
                Design line                        Rated capacity kVA      -----------------------------------------------------------------------------
                                                                                 1            2            3            4            5            6
--------------------------------------------------------------------------------------------------------------------------------------------------------
6..........................................  25...........................          0.0          0.0         12.5         14.5         14.5         25.7
7..........................................  75...........................          3.8          3.5          4.0          6.1          6.1         14.1
8..........................................  300..........................          6.5          6.5         10.0          9.3         19.4         19.4
--------------------------------------------------------------------------------------------------------------------------------------------------------


Table V.21--Rebuttable-Presumption Payback Periods (years) for Medium-Voltage Dry-Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
                                                                       Trial standard level
         Design line            Rated capacity  ----------------------------------------------------------------
                                      kVA             1            2            3            4            5
----------------------------------------------------------------------------------------------------------------
9............................  300.............          1.8          1.8          4.2          4.2         14.1
10...........................  1500............          1.3          5.5          5.5          5.5         19.9
11...........................  300.............         10.0         10.0         12.7         12.7         18.3
12...........................  1500............          5.9          7.3         11.5         11.5         19.7
13A..........................  300.............         12.7         12.7         12.5         21.4         27.9
13B..........................  2000............          5.7         10.4         10.4         10.4         18.7
----------------------------------------------------------------------------------------------------------------

2. Economic Impact on Manufacturers
    For the MIA in the February 2012 NOPR, DOE used changes in INPV to 
compare the direct financial impacts of different TSLs on manufacturers 
(77 FR 7282, February 10, 2012). DOE used the GRIM to compare the INPV 
of the base case (no new or amended energy conservation standards) to 
that of each TSL. The INPV is the sum of all net cash flows discounted 
by the industry's cost of capital (discount rate) to the base year. The 
difference in INPV between the base case and the standards case is an 
estimate of the economic impacts that implementing that standard level 
would have on the distribution transformer industry. For today's final 
rule, DOE continues to use the methodology presented in the NOPR at 77 
FR 7282 (February 10, 2012).
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. These assumptions 
correspond to the bounds of a range of market responses that DOE 
anticipates could occur in the standards case (i.e., where new and 
amended energy conservation standards apply). Each of the two scenarios 
results in a

[[Page 23403]]

unique set of cash flows and corresponding industry values at each TSL. 
The February 2012 NOPR discusses each of these scenarios in full, and 
they are also presented in chapter 12 of the TSD.
    The MIA results for liquid-immersed distribution transformers are 
as follows:

        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      575.1      526.9      465.9      461.7      389.0      382.1      358.4      181.6
Change in INPV.......................................    2011$ M  .........     (48.2)    (109.3)    (113.4)    (186.1)    (193.0)    (216.7)    (393.5)
                                                               %  .........      (8.4)     (19.0)     (19.7)     (32.4)     (33.6)     (37.7)     (68.4)
Capital Conversion Costs.............................    2011$ M  .........       25.3       57.8       60.6       92.8       96.2      101.5      124.5
Product Conversion Costs.............................    2011$ M  .........       24.2       65.2       65.7       96.1       96.1       96.1       96.1
Total Conversion Costs...............................    2011$ M  .........       49.4      123.0      126.3      188.9      192.3      197.7      220.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
*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      575.1      551.6      508.1      506.2      477.8      473.8      486.6      575.6
Change in INPV.......................................    2011$ M  .........     (23.5)     (67.0)     (68.9)     (97.3)    (101.4)     (88.5)        0.5
                                                               %  .........      (4.1)     (11.7)     (12.0)     (16.9)     (17.6)     (15.4)        0.1
Capital Conversion Costs.............................    2011$ M  .........       25.3       57.8       60.6       92.8       96.2      101.5      124.5
Product Conversion Costs.............................    2011$ M  .........       24.2       65.2       65.7       96.1       96.1       96.1       96.1
Total Conversion Costs...............................    2011$ M  .........       49.4      123.0      126.3      188.9      192.3      197.7      220.6
--------------------------------------------------------------------------------------------------------------------------------------------------------

    At TSL 1, DOE estimates impacts on INPV for liquid-immersed 
distribution transformer manufacturers to range from -$48.2 million to 
-$23.5 million, corresponding to a change in INPV of -8.4 percent to -
4.1 percent. At this level, industry free cash flow is estimated to 
decrease by approximately 54.4 percent to $16.4 million, compared to 
the base-case value of $36.0 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. According to manufacturer 
interviews, this would likely induce some 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 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 markup and pass on the higher product costs, leading 
to higher operating income. This higher operating income essentially 
offsets 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 -$109.3 million to 
-$67.0 million, corresponding to a change in INPV of -19.0 percent to -
11.7 percent. At this level, industry free cash flow is estimated to 
decrease by approximately 133.7 percent to -$12.1 million, compared to 
the base-case value of $36.0 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 core transformers 
become incrementally 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 -$113.4 million to 
-$68.9 million, corresponding to a change in INPV of -19.7 percent to -
12.0 percent. At this level, industry free cash flow is estimated to 
decrease by approximately 137.6 percent to -$13.6 million, compared to 
the base-case value of $36.0 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 amorphous

[[Page 23404]]

core transformers slightly more cost competitive in these DLs, 
according to the engineering analysis, which would likely increase 
amorphous core transformer capacity needs--all other things being 
equal--and drive more investment to meet the standards.
    At TSL 4, DOE estimates impacts on INPV for liquid-immersed 
distribution transformer manufacturers to range from -$186.1 million to 
-$97.3 million, corresponding to a change in INPV of -32.4 percent to -
16.9 percent. At this level, industry free cash flow is estimated to 
decrease by approximately 206.6 percent to -$38.4 million, compared to 
the base-case value of $36.0 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 again driven by the 
large conversion costs associated with new amorphous steel production 
lines. 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 -$193.0 million to 
-$101.4 million, or a change in INPV of -33.6 percent to -17.6 percent. 
At this level, industry free cash flow is estimated to decrease by 
approximately 210.8 percent to -$39.9 million, compared to the base-
case value of $36.0 million in the year before the compliance date 
(2015).
    TSL 5 would likely shift the entire market to amorphous core 
transformers, leading to even greater investment needs than TSL 4, and 
further driving the adverse impacts discussed above.
    At TSL 6, DOE estimates impacts on INPV for liquid-immersed 
distribution transformer manufacturers to range from -$216.7 million to 
-$88.5 million, corresponding to a change in INPV of -37.7 percent to -
15.4 percent. At this level, industry free cash flow is estimated to 
decrease by approximately 217.5 percent to -$42.3 million, compared to 
the base-case value of $36.0 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 -$393.5 million to 
$0.5 million, corresponding to a change in INPV of -68.4 percent to 0.1 
percent. At this level, industry free cash flow is estimated to 
decrease by approximately 246.2 percent to -$52.7 million, compared to 
the base-case value of $36.0 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 7-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.
    The MIA results for low-voltage dry-type distribution transformers 
are as follows:

        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      237.6      229.6      226.5      219.0      198.7      190.8      159.0
Change in INPV..................................................    2011 $M  .........      (8.0)     (11.1)     (18.6)     (38.9)     (46.8)     (78.6)
                                                                          %  .........      (3.4)      (4.7)      (7.8)     (16.4)     (19.7)     (33.1)
Capital Conversion Costs........................................    2011 $M  .........        4.5        5.3       12.0       28.5       30.7       45.6
Product Conversion Costs........................................    2011 $M  .........        2.9        3.6        5.0        8.0        8.0        8.0
Total Conversion Costs..........................................    2011 $M  .........        7.4        9.0       17.0       36.5       38.7       53.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
* 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      237.6      252.4      249.4      265.7      279.9      298.6      356.6
Change in INPV.......................................    2011 $M  .........       14.8       11.8       28.1       42.3       61.0      118.9
                                                               %  .........        6.2        5.0       11.8       17.8       25.7       50.1
Capital Conversion Costs.............................    2011 $M  .........        4.5        5.3       12.0       28.5       30.7       45.6
Product Conversion Costs.............................    2011 $M  .........        2.9        3.6        5.0        8.0        8.0        8.0
Total Conversion Costs...............................    2011 $M  .........        7.4        9.0       17.0       36.5       38.7       53.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Note: Parentheses indicate negative values.


[[Page 23405]]

    At TSL 1, DOE estimates impacts on INPV for low-voltage dry-type 
distribution transformer manufacturers to range from -$8.0 million to 
$14.8 million, corresponding to a change in INPV of -3.4 percent to 6.2 
percent. At this level, industry free cash flow is estimated to 
decrease by approximately 5.0 percent to $14.5 million, compared to the 
base-case value of $15.2 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 (if they 
do not already have it).
    At TSL 2, DOE estimates impacts on INPV for low-voltage dry-type 
distribution transformer manufacturers to range from -$11.1 million to 
$11.8 million, corresponding to a change in INPV of -4.7 percent to 5.0 
percent. At this level, industry free cash flow is estimated to 
decrease by approximately 9.1 percent to $13.8 million, compared to the 
base-case value of $15.2 million in the year before the compliance date 
(2015).
    TSL 2 differs from TSL1 in that DL7 must meet EL3, up from EL2. 
Comments received from the NOPR and consultations with technical 
experts suggest that butt-lap technology can still be used to achieve 
EL 3 for DL 7. However, DOE expects the high volume manufacturers which 
supply most of the market to employ mitered cores at this efficiency 
level. Therefore, the increase in conversion costs for DL 7, which 
represents more than three-quarters of the market by core weight in 
this superclass, is primarily driven by the need to purchase additional 
core cutting equipment to accommodate the production of larger, mitered 
cores. Furthermore, manufacturers also indicated that there would be a 
reduced burden at TSL 2 relative to TSL 1 because they would be able to 
standardize the use of NEMA Premium[supreg] (with the exception of DL 
6).
    At TSL 3, DOE estimates impacts on INPV for low-voltage dry-type 
distribution transformer manufacturers to range from -$18.6 to $28.1 
million, corresponding to a change in INPV of -7.8 percent to 11.8 
percent. At this level, industry free cash flow is estimated to 
decrease by approximately 31.9 percent to $10.4 million, compared to 
the base-case value of $15.2 million in the year before the compliance 
date (2015).
    TSL3 represents EL4 for DL6, DL7, and DL8. Although manufacturers 
may be able to meet EL4 using M4 steel, comments and interviews suggest 
uncertainty about the ability of M4 to meet EL 4 for all design lines. 
Manufacturers may be forced to use higher-grade and thinner steels like 
M3, H1, and H0. However, these thinner steels, in combination with 
larger cores, will dramatically slow production throughput and 
therefore require 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 -$38.9 million to 
$42.3 million, corresponding to a change in INPV of -16.4 percent to 
17.8 percent. At this level, industry free cash flow is estimated to 
decrease by approximately 87.2 percent to $1.9 million, compared to the 
base-case value of $15.2 million in the year before the compliance date 
(2015).
    TSL 4 and higher would create significant challenges for the 
industry 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 -$46.8 million to 
$61.0 million, corresponding to a change in INPV of -19.7 percent to 
25.7 percent. At this level, industry free cash flow is estimated to 
decrease by approximately 93.9 percent to $0.9 million, compared to the 
base-case value of $15.2 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 -$78.6 million to 
$118.9 million, corresponding to a change in INPV of -33.1 percent to 
50.1 percent. At this level, industry free cash flow is estimated to 
decrease by approximately 138 percent to -$5.8 million, compared to the 
base-case value of $15.2 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.
    The MIA results for medium-voltage dry-type distribution 
transformers are as follows:

[[Page 23406]]



      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         68.7         67.3         65.7         57.9         58.0         34.5
Change in INPV...............................................      2011 $M  ...........        (1.4)        (2.9)       (10.7)       (10.7)       (34.1)
                                                                         %  ...........        (2.0)        (4.2)       (15.6)       (15.5)       (49.7)
Capital Conversion Costs.....................................      2011 $M  ...........          0.2          0.5          3.9          3.9         13.9
Product Conversion Costs.....................................      2011 $M  ...........          2.0          2.0          3.7          3.7          8.2
Total Conversion Costs.......................................      2011 $M  ...........          2.2          2.6          7.7          7.7         22.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
* 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         68.7         69.3         71.7         74.4         74.3         81.5
Change in INPV...............................................      2011 $M  ...........          0.7          3.0          5.7          5.6         12.9
                                                                         %  ...........          1.0          4.4          8.3          8.2         18.7
Capital Conversion Costs.....................................      2011 $M  ...........          0.2          0.5          3.9          3.9         13.9
Product Conversion Costs.....................................      2011 $M  ...........          2.0          2.0          3.7          3.7          8.2
Total Conversion Costs.......................................      2011 $M  ...........          2.2          2.6          7.7          7.7         22.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Note: Parentheses indicate negative values.

    At TSL 1, DOE estimates impacts on INPV for medium-voltage dry-type 
distribution transformer manufacturers to range from -$1.4 million to 
$0.7 million, corresponding to a change in INPV of -2.0 percent to 1.0 
percent. At this level, industry free cash flow is estimated to 
decrease by approximately 2.3 percent to $4.3 million, compared to the 
base-case value of $4.4 million in the year before the compliance date 
(2015).
    TSL 1 represents EL1 for all MVDT design lines. For DL12, the 
largest design line by core steel usage, manufacturers have a variety 
of steels available to them, including M4, the most common steel in the 
superclass. 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 to 
INPV. For this reason, TSL 1 yields relatively minor adverse changes to 
INPV in the standards case.
    At TSL 2 (the consensus recommendation from the negotiating 
committee), DOE estimates impacts on INPV for medium-voltage dry-type 
distribution transformer manufacturers to range from -$2.9 million to 
$3.0 million, corresponding to a change in INPV of -4.2 percent to 4.4 
percent. At this level, industry free cash flow is estimated to 
decrease by approximately 6.0 percent to $4.2 million, compared to the 
base-case value of $4.4 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 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 additional 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 -$10.7 million to 
$5.7 million, corresponding to a change in INPV of -15.6 percent to 8.3 
percent. At this level, industry free cash flow is estimated to 
decrease by approximately 53.4 to $2.1 million, compared to the base-
case value of $4.4 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-$10.7 million to 
$5.6 million, corresponding to a change in INPV of -15.5 percent to 8.2 
percent. At this level, industry free cash flow is estimated to 
decrease by approximately -53.4 percent to $2.1 million, compared to 
the base-case value of $4.4 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 H1 or H0, or transition entirely to 
amorphous wound cores (with which the industry has experience). Without 
a cost effective M-grade steel option, the industry could face severe 
disruption. Even assuming a sufficient supply of Hi-B steel, which is 
generally used and priced for the power transformer market, 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

[[Page 23407]]

would face significant challenges that DOE believes would lead to 
consolidation and likely cause many low-volume manufacturers to exit 
the product line.
    At TSL 5, DOE estimates impacts on INPV for medium-voltage dry-type 
distribution transformer manufacturers to range from -$34.1 million to 
$12.9 million, corresponding to a change in INPV of -49.7 percent to 
18.7 percent. At this level, industry free cash flow is estimated to 
decrease by approximately 189.1 percent to -$3.9 million, compared to 
the base-case value of $4.4 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 engineering analysis shows that 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 rather altogether or source their 
cores rather than make the investments in plant, equipment, and the R&D 
required to meet such levels.
b. Impacts on Employment
    Liquid-Immersed. Based on interviews with manufacturers and other 
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 standard. Manufacturers generally agreed that 
amorphous core steel production is more labor-intensive and would 
require greater labor expenditures than tradition 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 higher 
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 today's 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 them. 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 today's 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 green 
field investments, these manufacturers may elect to make those 
investments in lower-labor cost countries.\67\
---------------------------------------------------------------------------

    \67\ A green field investment is a form of foreign direct 
investment where a parent company starts a new venture in a foreign 
country by constructing new operational facilities from the ground 
up.
---------------------------------------------------------------------------

    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 standards would increase labor expenditures, 
not decrease them, but current production equipment would not be 
stranded, mitigating the incentive to move production offshore. 
Corroborating this, the largest manufacturer and domestic employer in 
this market has indicated that the standard in this final rule, will 
not cause their company to reconsider production location. As such, DOE 
does not expect significant changes to domestic MVDT industry 
employment levels as a result of the standard in today's final 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 in today's 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. Therefore, 
using average cost assumptions to develop an industry cash-flow 
estimate is inadequate to assess differential impacts among 
manufacturer subgroups. DOE considered small manufacturers as a 
subgroup in the MIA. 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 final rule 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

[[Page 23408]]

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 Department did not receive comments regarding cumulative regulatory 
burden issues for the NOPR. DOE addresses the full details of the 
cumulative regulatory burden analysis in chapter 12 of the final rule 
TSD.
3. National Impact Analysis
a. Significance of Energy Savings
    For each TSL, DOE projected energy savings for transformers 
purchased in the 30-year period that begins in the year of compliance 
with amended standards (2016-2045). The savings are measured over the 
entire lifetime of products purchased in the 30-year period, which in 
the case of transformers extends through 2105. DOE quantified the 
energy savings attributable to each TSL as the difference in energy 
consumption between each standards case and the base case. Table V.28 
presents the estimated energy savings for each considered TSL. The 
approach used is further described in section IV.G.\68\
---------------------------------------------------------------------------

    \68\ Chapter 10 of the TSD 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.

              Table V.28--Cumulative National Energy Savings for Distribution Transformer Trial Standard Levels for Units Sold in 2016-2045
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                  Trial standard level
                                                              ------------------------------------------------------------------------------------------
                                                                    1            2            3            4            5            6            7
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                         quads
                                                              ------------------------------------------------------------------------------------------
Liquid-immersed..............................................         0.92         1.56         1.76         3.31         3.30         4.09         7.01
Low-voltage dry-type.........................................         2.28         2.43         3.05         4.39         4.48         4.94  ...........
Medium-voltage dry-type......................................         0.15         0.29         0.53         0.53         0.84  ...........  ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For this rulemaking, DOE undertook a sensitivity analysis using 
nine rather than 30 years of product shipments. The choice of a nine-
year period is a proxy for the timeline in EPCA for the review of the 
energy conservation standard established in this final rule and 
potential revision of and compliance with a new standard for 
distribution transformers.\69\ This timeframe may not be statistically 
relevant with regard to the product lifetime, product manufacturing 
cycles or other factors specific to distribution transformers. Thus, 
this information is presented for informational purposes only and is 
not indicative of any change in DOE's analytical methodology. The NES 
results based on a nine-year analytical period are presented in Table 
V.29. The impacts are counted over the lifetime of products purchased 
in 2016-2024.
---------------------------------------------------------------------------

    \69\ EPCA requires DOE to review its standards at least once 
every 6 years, and requires, for certain products, a 3 year period 
after any new standard is promulgated before compliance is required, 
except that in no case may any new standards be required within 6 
years of the compliance date of the previous standards. While adding 
a 6-year review to the 3-year compliance period adds up to 9 years, 
DOE notes that it may undertake reviews at any time within the 6 
year period and that the 3-year compliance date may yield to the 6-
year backstop. A 9-year analysis period may not be appropriate given 
the variability that occurs in the timing of standards reviews and 
the fact that for some products, the compliance period is 5 years 
rather than 3 years.

              Table V.29--Cumulative National Energy Savings for Distribution Transformer Trial Standard Levels for Units Sold in 2016-2024
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                  Trial standard level
                                                              ------------------------------------------------------------------------------------------
                                                                    1            2            3            4            5            6            7
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                         quads
                                                              ------------------------------------------------------------------------------------------
Liquid-immersed..............................................         0.25         0.42         0.47         0.90         0.90         1.12         1.93
Low-voltage dry-type.........................................         0.63         0.67         0.85         1.22         1.24         1.38  ...........
Medium-voltage dry-type......................................         0.04         0.08         0.15         0.15         0.23  ...........  ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------

b. Net Present Value of Customer Costs and Benefits
    DOE estimated the cumulative NPV of the total costs and savings for 
customers that would result from the TSLs considered for distribution 
transformers. In accordance with OMB's guidelines on regulatory 
analysis,\70\ DOE calculated the 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. This discount rate approximates 
the opportunity cost of capital in the private sector (OMB analysis has 
found the average rate of return on capital to be near this rate). The 
three-percent rate reflects 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

[[Page 23409]]

their present value. It can be approximated by the real rate of return 
on long-term government debt (i.e., yield on United States Treasury 
notes), which has averaged about 3 percent for the past 30 years.
---------------------------------------------------------------------------

    \70\ OMB Circular A-4, section E (Sept. 17, 2003). Available at: 
http://www.whitehouse.gov/omb/circulars_a004_a-4.
---------------------------------------------------------------------------

    Table V.30 shows the customer NPV results for each TSL considered. 
In each case, the impacts cover the lifetime of equipment purchased in 
2016-2045.

           Table V.30--Net Present Value of Customer 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                  ...........                                        billion 2011$
                                                              ------------------------------------------------------------------------------------------
Liquid-immersed.................................            3         3.12         4.82         5.62        10.78        10.19        10.27        -8.50
                                                            7         0.58         0.69         0.91         1.92         1.60         0.74       -12.97
Low-voltage dry-type............................            3         8.38         9.04        10.38        13.65        11.80         5.17  ...........
                                                            7         2.45         2.67         2.82         3.34         2.22        -1.92  ...........
Medium-voltage dry-type.........................            3         0.49         0.79         1.12         1.12        -0.20  ...........  ...........
                                                            7         0.13         0.17         0.12         0.12        -0.89  ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The results shown in the table reflect the default equipment 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 final rule TSD.
    The NPV results based on the aforementioned nine-year analytical 
period are presented in Table V.31. The impacts are counted over the 
lifetime of equipment purchased in 2016-2024. As mentioned previously, 
this information is presented for informational purposes only and is 
not indicative of any change in DOE's analytical methodology or 
decision criteria.

           Table V.31--Net Present Value of Customer Benefits for Distribution Transformers Trial Standard Levels for Units Sold in 2016-2024
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                  Trial standard level
                                                    Discount  ------------------------------------------------------------------------------------------
                                                     rate %         1            2            3            4            5            6            7
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                  ...........                                        billion 2011$
                                                              ------------------------------------------------------------------------------------------
Liquid-Immersed.................................            3         1.09         1.67         1.95         3.77         3.55         3.55        -3.49
                                                            7         0.26         0.31         0.41         0.88         0.73         0.29        -6.56
Low-voltage dry-type............................            3         3.02         3.26         3.73         4.88         4.19         1.70  ...........
                                                            7         1.19         1.30         1.37         1.60         1.04        -1.04  ...........
Medium-voltage dry-type.........................            3         0.18         0.28         0.39         0.39        -0.11  ...........  ...........
                                                            7         0.07         0.08         0.05         0.05        -0.46  ...........  ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------

c. Indirect Impacts on Employment
    DOE expects energy conservation standards for distribution 
transformers to reduce energy costs for equipment owners, and 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 time frames 
(2016-2020), where these uncertainties are reduced.
    The results suggest that today's 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 final rule TSD presents detailed results.
4. Impact on Utility or Performance of Equipment
    DOE believes that the standards in today's rule 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 of Energy, 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 the Department of Justice (DOJ) with copies of this notice 
and the TSD for review. DOE considered DOJ's comments on the proposed 
rule in preparing the final rule.
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

[[Page 23410]]

peak-load periods. As a measure of this reduced demand, chapter 14 in 
the final rule TSD presents the estimated reduction in generating 
capacity in 2045 for the TSLs that DOE considered in this rulemaking.
    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.32 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 final rule TSD.

                         Table V.32--Cumulative Emissions Reduction Estimated for Distribution Transformer Trial Standard Levels
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                       Trial standard level
                                         ---------------------------------------------------------------------------------------------------------------
                                                 1               2               3               4               5               6               7
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Liquid-Immersed
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)...............            82.2           143.1           156.5           274.6           273.4           321.8           501.8
NOX (thousand tons).....................            69.3           120.6           131.8           231.1           230.1           270.8           421.9
SO2 (thousand tons).....................            52.0            90.0            98.4           173.0           172.4           203.2           318.0
Hg (tons)...............................             0.2             0.3             0.3             0.6             0.6             0.7             1.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Low-Voltage Dry-Type
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)...............           151.3           161.6           203.0           292.8           297.6           319.3  ..............
NOX (thousand tons).....................           127.6           136.4           171.3           247.0           251.0           269.3  ..............
SO2 (thousand tons).....................           110.1           117.6           147.8           213.2           216.7           232.4  ..............
Hg (tons)...............................             0.4             0.4             0.5             0.8             0.8             0.8  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Medium-Voltage Dry-Type
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)...............            11.2            20.9            40.7            40.7            61.3  ..............  ..............
NOX (thousand tons).....................            9.34            17.7            34.2            34.2            51.5  ..............  ..............
SO2 (thousand tons).....................            7.06           13.29           25.65           25.65           38.69  ..............  ..............
Hg (tons)...............................            0.02            0.04            0.10            0.10            0.14  ..............  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As part of the analysis for this 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 sets of SCC values resulting from that 
process (expressed in 2011$) are represented by $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 2011; the values for later years are higher due 
to increasing damages as the projected magnitude of climate change 
increases.
    Table V.33 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 final rule TSD.

  Table V.33--Estimates of Global Present Value of CO2 Emissions Reduction Under Distribution Transformer Trial
                                                 Standard Levels
----------------------------------------------------------------------------------------------------------------
                                                                                            2.5%     3% discount
                                                              5% discount  3% discount    discount    rate, 95th
                             TSL                                 rate,        rate,        rate,      percentile
                                                              average \*\  average \*\  average \*\      \*\
----------------------------------------------------------------------------------------------------------------
                                                  Million 2011$
----------------------------------------------------------------------------------------------------------------
                                                 Liquid-Immersed
----------------------------------------------------------------------------------------------------------------
1...........................................................          259        1,390        2,377        4,230
2...........................................................          454        2,428        4,151        7,390
3...........................................................          494        2,649        4,530        8,060
4...........................................................          855        4,609        7,891       14,024
5...........................................................          851        4,588        7,855       13,960
6...........................................................          991        5,366        9,195       16,325
7...........................................................        1,515        8,266       14,190       25,144
----------------------------------------------------------------------------------------------------------------

[[Page 23411]]

 
                                              Low-Voltage Dry-Type
----------------------------------------------------------------------------------------------------------------
1...........................................................          450        2,470        4,245        7,512
2...........................................................          480        2,637        4,532        8,020
3...........................................................          603        3,313        5,694       10,075
4...........................................................          870        4,779        8,214       14,535
5...........................................................          884        4,857        8,348       14,771
6...........................................................          949        5,211        8,956       15,847
----------------------------------------------------------------------------------------------------------------
                                             Medium-Voltage Dry-Type
----------------------------------------------------------------------------------------------------------------
1...........................................................           35          188          321          571
2...........................................................           65          350          599        1,065
3...........................................................          126          680        1,164        2,067
4...........................................................          126          680        1,164        2,067
5...........................................................          190        1,024        1,755        3,117
----------------------------------------------------------------------------------------------------------------

    DOE is well aware that scientific and economic knowledge about the 
contribution of CO2 and other greenhouse gas (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 final rule 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 distribution 
transformers. The low and high dollar-per-ton values that DOE used are 
discussed in section IV.M. Table V.34 presents the cumulative present 
values for each TSL calculated using seven-percent and three-percent 
discount rates.

 Table V.34--Estimates of Present Value of NOX Emissions Reduction Under
             Distribution Transformer Trial Standard Levels
------------------------------------------------------------------------
         TSL              3% discount rate          7% discount rate
------------------------------------------------------------------------
                              Million 2011$
------------------------------------------------------------------------
                             Liquid-Immersed
------------------------------------------------------------------------
1...................  13 to 138...............  6 to 57
2...................  24 to 242...............  10 to 100
3...................  26 to 263...............  11 to 109
4...................  44 to 454...............  18 to 185
5...................  44 to 452...............  18 to 184
6...................  51 to 525...............  21 to 211
7...................  78 to 799...............  31 to 314
------------------------------------------------------------------------
                          Low-Voltage Dry-Type
------------------------------------------------------------------------
1...................  23 to 238...............  9 to 92
2...................  25 to 254...............  10 to 99
3...................  31 to 319...............  12 to 124
4...................  45 to 460...............  17 to 179
5...................  45 to 468...............  18 to 182
6...................  49 to 502...............  19 to 195
------------------------------------------------------------------------
                         Medium-Voltage Dry-Type
------------------------------------------------------------------------
1...................  2 to 18.................  1 to 7
2...................  3 to 34.................  1 to 14
3...................  6 to 67.................  3 to 27
4...................  6 to 67.................  3 to 27
5...................  10 to 100...............  4 to 41
------------------------------------------------------------------------

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.35 through Table V.37 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 sets of SCC values discussed above.

[[Page 23412]]



 Table V.35--Liquid-Immersed Distribution Transformers: Net Present Value of Customer Savings Combined With Net
                    Present Value of Monetized Benefits From CO2 and NOX Emissions Reductions
----------------------------------------------------------------------------------------------------------------
                                                   Customer NPV at 3% Discount Rate added with:
                                 -------------------------------------------------------------------------------
               TSL                SCC Value of $4.9/  SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
                                    t CO2 * and Low   t CO2 * and Medium  t CO2 * and Medium   t CO2 * and High
                                   Value for NOX **    Value for NOX **    Value for NOX **    Value for NOX **
----------------------------------------------------------------------------------------------------------------
                                                  Billion 2011$
----------------------------------------------------------------------------------------------------------------
1...............................                 3.4                 4.6                 5.6                 7.5
2...............................                 5.3                 7.4                 9.1                12.5
3...............................                 6.1                 8.4                10.3                13.9
4...............................                11.7                15.6                18.9                25.3
5...............................                11.1                15.0                18.3                24.6
6...............................                11.3                15.9                19.8                27.1
7...............................                -6.9                 0.2                 6.1                17.4
----------------------------------------------------------------------------------------------------------------


 
                                                   Customer NPV at 7% Discount Rate added with:
                                 -------------------------------------------------------------------------------
               TSL                SCC Value of $4.9/  SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
                                    t CO2 * and Low   t CO2 * and Medium  t CO2 * and Medium   t CO2 * and High
                                   Value for NOX **    Value for NOX **    Value for NOX **    Value for NOX **
----------------------------------------------------------------------------------------------------------------
                                                  Billion 2011$
----------------------------------------------------------------------------------------------------------------
1...............................                 0.8                 2.0                 3.0                 4.9
2...............................                 1.2                 3.2                 4.9                 8.2
3...............................                 1.4                 3.6                 5.5                 9.1
4...............................                 2.8                 6.6                 9.9                16.1
5...............................                 2.5                 6.3                 9.6                15.7
6...............................                 1.8                 6.2                10.1                17.3
7...............................               -11.4                -4.5                 1.4                12.5
----------------------------------------------------------------------------------------------------------------
* These label values represent the global SCC in 2011, in 2011$. 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.


 Table V.36--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
----------------------------------------------------------------------------------------------------------------
                                                   Customer NPV at 3% Discount Rate added with:
                                 -------------------------------------------------------------------------------
               TSL                SCC Value of $4.9/  SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
                                    t CO2 * and Low   t CO2 * and Medium  t CO2 * and Medium   t CO2 * and High
                                   Value for NOX **    Value for NOX **    Value for NOX **    Value for NOX **
----------------------------------------------------------------------------------------------------------------
                                                  Billion 2011$
----------------------------------------------------------------------------------------------------------------
1...............................                 8.8                11.0                12.8                16.1
2...............................                 9.5                11.8                13.7                17.3
3...............................                11.0                13.9                16.3                20.8
4...............................                14.6                18.7                22.1                28.6
5...............................                12.7                16.9                20.4                27.0
6...............................                 6.2                10.7                14.4                21.5
----------------------------------------------------------------------------------------------------------------


 
                                                   Customer NPV at 7% Discount Rate added with:
                                 -------------------------------------------------------------------------------
               TSL                SCC Value of $4.9/  SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
                                    t CO2 * and Low   t CO2 * and Medium  t CO2 * and Medium   t CO2 * and High
                                   Value for NOX **    Value for NOX **    Value for NOX **    Value for NOX **
----------------------------------------------------------------------------------------------------------------
                                                  Billion 2011$
----------------------------------------------------------------------------------------------------------------
1...............................                 2.9                 5.0                 6.7                10.0
2...............................                 3.2                 5.4                 7.3                10.8
3...............................                 3.4                 6.2                 8.6                13.0
4...............................                 4.2                 8.2                11.7                18.1
5...............................                 3.1                 7.2                10.7                17.2
6...............................                -1.0                 3.4                 7.1                14.1
----------------------------------------------------------------------------------------------------------------
* These label values represent the global SCC in 2011, in 2011$. The present values have been calculated with
  scenario-consistent discount rates.

[[Page 23413]]

 
** 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.


  Table V.37--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
----------------------------------------------------------------------------------------------------------------
                                                   Customer NPV at 3% Discount Rate added with:
                                 -------------------------------------------------------------------------------
               TSL                SCC Value of $4.9/  SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
                                    t CO2 * and Low   t CO2 * and Medium  t CO2 * and Medium   t CO2 * and High
                                   Value for NOX **    Value for NOX **    Value for NOX **    Value for NOX **
----------------------------------------------------------------------------------------------------------------
          Billion 2011$
----------------------------------------------------------------------------------------------------------------
1...............................                 0.5                 0.7                 0.8                 1.1
2...............................                 0.9                 1.2                 1.4                 1.9
3...............................                 1.3                 1.8                 2.3                 3.3
4...............................                 1.3                 1.8                 2.3                 3.3
5...............................                 0.0                 0.9                 1.6                 3.0
----------------------------------------------------------------------------------------------------------------


 
                                                   Customer NPV at 7% Discount Rate added with:
                                 -------------------------------------------------------------------------------
               TSL                SCC Value of $4.9/  SCC Value of $22.3/ SCC Value of $36.5/ SCC Value of $67.6/
                                    t CO2 * and Low   t CO2 * and Medium  t CO2 * and Medium   t CO2 * and High
                                   Value for NOX **    Value for NOX **    Value for NOX **    Value for NOX **
----------------------------------------------------------------------------------------------------------------
                                                  Billion 2011$
----------------------------------------------------------------------------------------------------------------
1...............................                 0.2                 0.3                 0.5                 0.7
2...............................                 0.2                 0.5                 0.8                 1.2
3...............................                 0.2                 0.8                 1.3                 2.2
4...............................                 0.2                 0.8                 1.3                 2.2
5...............................                -0.7                 0.2                 0.9                 2.3
----------------------------------------------------------------------------------------------------------------
* These label values represent the global SCC in 2011, in 2011$. 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.

    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)(VII))
    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 extensively examined the effects of electrical 
steel supply and availability.
    DOE's most important conclusion from this examination is that 
several energy efficiency levels in each design line are attainable 
only by using amorphous steel, which is currently produced by only one 
supplier in any significant volume and that supplier at present does 
not have enough capacity to supply the industry at all-amorphous 
standard levels. Several more energy efficiency levels are reachable 
with the top grades of conventional (grain-oriented) electrical steels, 
but this would 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 to remain competitive. 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 
significant factor in determining which TSLs were economically 
justified.

C. Conclusion

    When considering proposed standards, the new or amended energy 
conservation standard that DOE adopts for any type (or class) of 
covered equipment shall be designed to achieve the maximum improvement 
in energy efficiency that the Secretary of Energy 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

[[Page 23414]]

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 rulemaking, DOE considered the impacts of standards at 
each TSL, beginning with the max-tech 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 technologically feasible, 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 the considered 
subgroup. 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.38 and Table V.39 summarize the quantitative impacts 
estimated for each TSL for liquid-immersed distribution transformers.

                        Table V.38--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 quads  0.92............  1.56............  1.76............  3.31............  3.30...........  4.09...........  7.01
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         NPV of Consumer Benefits 2011$ billion
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% discount rate.............  3.12............  4.82............  5.62............  10.78...........  10.19..........  10.27..........  -8.50
7% discount rate.............  0.58............  0.69............  0.91............  1.92............  1.60...........  0.74...........  -12.97
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Cumulative Emissions Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....  82.2............  143.1...........  156.5...........  274.6...........  273.4..........  321.8..........  501.8
NOX (thousand tons)..........  69.3............  120.6...........  131.8...........  231.1...........  230.1..........  270.8..........  421.9
SO2 (thousand tons)..........  52.0............  90.0............  98.4............  173.0...........  172.4..........  203.2..........  318.0
Hg (tons)....................  0.2.............  0.3.............  0.3.............  0.6.............  0.6............  0.7............  1.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Value of Emissions Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 2011$ million*...........  259 to 4230.....  454 to 7390.....  494 to 8060.....  855 to 14024....  851 to 13960...  991 to 16325...  1515 to 25144
NOX - 3% discount rate 2011$   13 to 138.......  24 to 242.......  26 to 263.......  44 to 454.......  44 to 452......  51 to 525......  78 to 799
 million.
NOX - 7% discount rate 2011$   6 to 57.........  10 to 100.......  11 to 109.......  18 to 185.......  18 to 184......  21 to 211......  31 to 314
 million.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Range of the economic value of CO2 reductions is based on estimates of the global benefit of reduced CO2 emissions.


               Table V.39--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...  527 to 552......  466 to 508......  462 to 506......  389 to 478......  382 to 474.....  358 to 487.....  181 to 576
Industry NPV % change........  (8.4) to (4.1)..  (19.0) to (11.7)  (19.7) to (12.0)  (32.4) to (16.9)  (33.6) to        (37.7) to        (68.4) to 0.1
                                                                                                        (17.6).          (15.4).
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Consumer Mean LCC Savings 2011$
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 1................  83..............  153.............  153.............  696.............  696............  618............  365
Design line 2................  66..............  278.............  278.............  343.............  330............  311............  -579
Design line 3................  2709............  2407............  3526............  5527............  5037...........  6942...........  4491
Design line 4................  977.............  977.............  977.............  1212............  3603...........  3603...........  4349
Design line 5................  3668............  3668............  6852............  10382...........  8616...........  12014..........  4619
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 23415]]

 
                                                                Consumer Median PBP years
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 1................  17.7............  24.7............  24.7............  10.8............  10.8...........  13.7...........  24.6
Design line 2................  5.9.............  9.9.............  9.9.............  11.1............  13.0...........  15.5...........  31.6
Design line 3................  8.5.............  8.3.............  5.8.............  6.5.............  6.4............  7.2............  19.1
Design line 4................  7.0.............  7.0.............  7.0.............  9.1.............  5.6............  5.6............  10.2
Design line 5................  6.5.............  6.5.............  6.5.............  9.1.............  8.5............  11.4...........  22.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Distribution of Consumer LCC Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Design line 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cost %...................  37.3............  44.2............  44.2............  7.0.............  7.0............  11.2...........  42.6
Net Benefit %................  62.5............  55.6............  55.6............  92.9............  92.9...........  88.8...........  57.4
No Impact %..................  0.2.............  0.2.............  0.2.............  0.2.............  0.2............  0.0............  0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Design line 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cost %...................  41.5............  18.2............  18.2............  11.4............  13.1...........  17.8...........  67.2
Net Benefit %................  55.2............  81.8............  81.8............  88.6............  86.9...........  82.2...........  32.8
No Impact %..................  3.4.............  0.0.............  0.0.............  0.0.............  0.0............  0.0............  0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Design line 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cost (%).................  14.5............  13.9............  12.0............  4.0.............  5.3............  4.0............  29.9
Net Benefit (%)..............  84.2............  84.8............  86.9............  95.9............  94.7...........  96.0...........  70.1
No Impact (%)................  1.3.............  1.3.............  1.2.............  0.0.............  0.0............  0.0............  0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Design line 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cost (%).................  6.6.............  6.6.............  6.6.............  7.6.............  2.5............  2.5............  5.9
Net Benefit (%)..............  92.8............  92.8............  92.8............  91.8............  96.9...........  96.9...........  94.1
No Impact (%)................  0.6.............  0.6.............  0.6.............  0.6.............  0.6............  0.6............  0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Design line 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cost (%).................  30.5............  30.5............  19.9............  9.8.............  14.8...........  9.1............  41.9
Net Benefit (%)..............  69.1............  69.1............  80.0............  90.2............  85.2...........  91.0...........  58.1
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 7.01 quads of energy, an amount 
DOE considers significant. TSL 7 has an estimated NPV of customer 
benefit of -$12.97 billion using a 7 percent discount rate, and -$8.50 
billion using a 3 percent discount rate.
    The cumulative emissions reductions at TSL 7 are 501.0 million 
metric tons of CO2, 421.9 thousand tons of NOX, 
318.0 thousand tons of SO2, and 1.1 tons of Hg. The 
estimated monetary value of the CO2 emissions reductions at 
TSL 7 ranges from $1,515 million to $25,144 million.
    At TSL 7, the average LCC impact ranges from -$579 for design line 
2 to $4,619 for design line 5. The median PBP ranges from 31.6 years 
for design line 2 to 10.2 years for design line 4. The share of 
customers experiencing a net LCC benefit ranges from 32.8 percent for 
design line 2 to 70.1 percent for design line 3.
    At TSL 7, the projected change in INPV ranges from a decrease of 
$394 million to an increase of $0.5 million. If the decrease of $394 
million were to occur, TSL 7 could result in a net loss of 68.4 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. 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.
    In view of the foregoing, DOE concludes that, at TSL 7 for liquid-
immersed distribution transformers, the benefits of energy savings, 
positive average customer LCC savings, generating capacity reductions, 
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 concluded that TSL 7 is 
not economically justified.

[[Page 23416]]

    Next, DOE considered TSL 6, which would save an estimated total of 
4.09 quads of energy, an amount DOE considers significant. TSL 6 has an 
estimated NPV of customer benefit of $0.74 billion using a 7 percent 
discount rate, and $10.27 billion using a 3 percent discount rate.
    The cumulative emissions reductions at TSL 6 are 321.8 million 
metric tons of CO2, 270.8 thousand tons of NOX, 
203.2 thousand tons of SO2, and 0.7 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 6 
ranges from $991 million to $16,325 million.
    At TSL 6, the average LCC impact ranges from $311 for design line 2 
to $12,014 for design line 5. The median PBP ranges from 5.6 years for 
design line 4 to 15.5 years for design line 2. The share of customers 
experiencing a net LCC benefit ranges from 82.2 percent for design line 
2 to 96.9 percent for design line 4.
    At TSL 6, the projected change in INPV ranges from a decrease of 
$217 million to a decrease of $89 million. If the decrease of $217 
million were to occur, TSL 6 could result in a net loss of 37.7 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 only one supplier currently produces in any 
significant volume (annual production capacity of approximately 100,000 
tons, the vast majority of which serves global demand). Thus, the 
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.
    In view of the foregoing, DOE 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, generating capacity reductions, 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 6. Consequently, DOE 
has concluded that TSL 6 is not economically justified.
    Next, DOE considered TSL 5, which would save an estimated total of 
3.30 quads of energy, an amount DOE considers significant. TSL 5 has an 
estimated NPV of customer benefit of $1.60 billion using a 7 percent 
discount rate, and $10.19 billion using a 3 percent discount rate.
    The cumulative emissions reductions at TSL 5 are 273.4 million 
metric tons of CO2, 230.1 thousand tons of NOX, 
172.4 thousand tons of SO2, and 0.6 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 5 
ranges from $851 million to $13,960 million.
    At TSL 5, the average LCC impact ranges from $330 for design line 2 
to$8,616 for design line 5. The median PBP ranges from 5.6 years for 
design line 4 to 13.0 years for design line 2. The share of customers 
experiencing a net LCC benefit ranges from 85.2 percent for design line 
5 to 96.9 percent for design line 4.
    At TSL 5, the projected change in INPV ranges from a decrease of 
$193 million to a decrease of $101 million. If the decrease of $193 
million were to occur, TSL 5 could result in a net loss of 33.6 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 core transformer 
production capacity.
    Similar to TSL 6 as described above, the energy savings under TSL 5 
are achievable only by using amorphous steel, which is currently 
available from only one supplier with significant volume and that 
supplier's production capacity of 100,000 tons is far below what would 
be required to meet market demand for electrical steel. 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. 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.
    In view of the foregoing, DOE 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, generating capacity reductions, 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 
3.31 quads of energy, an amount DOE considers significant. TSL 4 has an 
estimated NPV of customer benefit of $1.92 billion using a 7 percent 
discount rate, and $10.78 billion using a 3 percent discount rate.
    The cumulative emissions reductions at TSL 4 are 274.6 million 
metric tons of CO2, 231.1 thousand tons of NOX, 
173.0 thousand tons of SO2, and 0.6 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 4

[[Page 23417]]

ranges from $855 million to $14,024 million.
    At TSL 4, the average LCC impact ranges from $343 for design line 2 
to $10,382 for design line 5. The median PBP ranges from 11.1 years for 
design line 2 to 6.5 years for design line 3. The share of customers 
experiencing a net LCC benefit ranges from 88.6 percent for design line 
2 to 95.9 percent for design line 4.
    At TSL 4, the projected change in INPV ranges from a decrease of 
$186 million to a decrease of $97 million. If the decrease of $186 
million were to occur, TSL 4 could result in a net loss of 32.4 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 core 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 distribution 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.
    In view of the foregoing, DOE 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, generating capacity reductions, 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 concluded that TSL 4 is not economically justified.
    Next, DOE considered TSL 3, which would save an estimated total of 
1.76 quads of energy, an amount DOE considers significant. TSL 3 has an 
estimated NPV of customer benefit of $0.91 billion using a 7 percent 
discount rate, and $6.62 billion using a 3 percent discount rate.
    The cumulative emissions reductions at TSL 3 are 156.5 million 
metric tons of CO2, 131.8 thousand tons of NOX, 
98.4 thousand tons of SO2, and 0.3 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 3 
ranges from $494 million to $8,060 million.
    At TSL 3, the average LCC impact ranges from $153 for design line 1 
to $6,852 for design line 5. The median PBP ranges from 24.7 years for 
design line 1 to 5.8 years for design line 3. The share of customers 
experiencing a net LCC benefit ranges from 55.6 percent for design line 
1 to 92.8 percent for design line 4.
    At TSL 3, the projected change in INPV ranges from a decrease of 
$113 million to a decrease of $69 million. If the decrease of $113 
million were to occur, TSL 3 could result in a net loss of 19.7 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 distribution 
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.\71\
---------------------------------------------------------------------------

    \71\ DOE conducted a sensitivity analysis where LCC results are 
presented for liquid-immersed transformers without amorphous steel; 
see appendix 8-C in the final rule TSD.
---------------------------------------------------------------------------

    In view of the foregoing, DOE 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, generating capacity reductions, 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 concluded that TSL 3 is not economically 
justified.
    Next, DOE considered TSL 2, which would save an estimated total of 
1.56 quads of energy, an amount DOE considers significant. TSL 2 has an 
estimated NPV of customer benefit of $0.69 billion using a 7-percent 
discount rate, and $4.82 billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 2 are 143.1 million 
metric tons of CO2, 120.6 thousand tons of NOX, 
90.0 thousand tons of SO2, and 0.3 ton of Hg. The estimated 
monetary value of the CO2 emissions reduction at TSL 2 
ranges from $454 million to $7,390 million.
    At TSL 2, the average LCC impact ranges from $153 for design line 1 
to $3,668 for design line 5. The median PBP ranges from 24.7 years for 
design line 1 to 6.5 years for design line 5. The share of customers 
experiencing a net LCC benefit ranges from 55.6 percent for design line 
1 to 92.8 percent for design line 4.
    At TSL 2, the projected change in INPV ranges from a decrease of 
$110 million to a decrease of $67 million. If the decrease of $110 
million were to occur, TSL 2 could result in a net loss of 19 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 currently available in significant 
volume from one supplier whose annual

[[Page 23418]]

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.
    In view of the foregoing, DOE 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, generating capacity reductions, 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 concluded that TSL 2 is not economically 
justified.
    Next, DOE considered TSL 1, which would save an estimated total of 
0.92 quad of energy, an amount DOE considers significant. TSL 1 has an 
estimated NPV of customer benefit of $0.58 billion using a 7-percent 
discount rate, and $3.12 billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 1 are 82.2 million 
metric tons of CO2, 69.3 thousand tons of NOX, 
52.0 thousand tons of SO2, and 0.2 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 1 
ranges from $259 million to $4,230 million.
    At TSL 1, the average LCC impact ranges from $83 for design line 2 
to $3,668 for design line 5. The median PBP ranges from 17.7 years for 
design line 1 to 5.9 years for design line 2. The share of customers 
experiencing a net LCC benefit ranges from 55.2 percent for design line 
2 to 92.8 percent for design line 4.
    At TSL 1, the projected change in INPV ranges from a decrease of 
$48 million to a decrease of $24 million. If the decrease of $48 
million were to occur, TSL 1 could result in a net loss of 8.4 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 are not present under TSL 1.
    After considering the analysis and weighing the benefits and the 
burdens, DOE has 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, generating 
capacity reductions, emission reductions, and the estimated monetary 
value of the emissions reductions would outweigh the potential 
reduction in INPV for manufacturers.
    In view of the foregoing, DOE has concluded that TSL 1 would save a 
significant amount of energy and is technologically feasible and 
economically justified. For the above considerations, DOE today adopts 
the energy conservation standards for liquid-immersed distribution 
transformers at TSL 1. Table V.40 presents the energy conservation 
standards for liquid-immersed distribution transformers.

             Table V.40--Energy Conservation Standards for Liquid-Immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
                                Electrical Efficiency 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
667.......................................              99.52   1500.........................              99.48
833.......................................              99.55   2000.........................              99.51
                                                                2500.........................              99.53
----------------------------------------------------------------------------------------------------------------

2. Benefits and Burdens of Trial Standard Levels Considered for Low-
Voltage Dry-Type Distribution Transformers
    Table V.41 and Table V.42 summarize the quantitative impacts 
estimated for each TSL for low-voltage dry-type distribution 
transformers.

[[Page 23419]]



                     Table V.41--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)  2.28...............  2.43..............  3.05..............  4.39..............  4.48..............  4.94
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                        NPV of Customer Benefits (2011$ billion)
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% discount rate...............  8.38...............  9.04..............  10.38.............  13.65.............  11.80.............  5.17
7% discount rate...............  2.45...............  2.67..............  2.82..............  3.34..............  2.22..............  -1.92
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Cumulative Emissions Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)......  151.3..............  161.6.............  203.0.............  292.8.............  297.6.............  319.3
NOX (thousand tons)............  127.6..............  136.4.............  171.3.............  247.0.............  251.0.............  269.3
SO2 (thousand tons)............  110.1..............  117.6.............  147.8.............  213.2.............  216.7.............  232.4
Hg (tons)......................  0.4................  0.4...............  0.5...............  0.8...............  0.8...............  0.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                      Value of Emissions Reduction (2011$ million)
--------------------------------------------------------------------------------------------------------------------------------------------------------
CO2\*\.........................  450 to 7512........  480 to 8020.......  603 to 10075......  870 to 14535......  884 to 14771......  949 to 15847
NOX-3% discount rate...........  23 to 238..........  25 to 254.........  31 to 319.........  45 to 460.........  45 to 468.........  49 to 502
NOX-7% discount rate...........  9 to 92............  10 to 99..........  12 to 124.........  17 to 179.........  18 to 182.........  19 to 195
--------------------------------------------------------------------------------------------------------------------------------------------------------
\*\ Range of the economic value of CO2 reductions is based on estimates of the global benefit of reduced CO2 emissions.


             Table V.42--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)...  230 to 252.........  227 to 249........  219 to 266........  199 to 280........  191 to 299........  159 to 357
Industry NPV (% change)........  (3.4) to 6.2.......  (4.7) to 5.0......  (7.8) to 11.8.....  (16.4) to 17.8....  (19.7) to 25.7....  (33.1) to 50.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Consumer Mean LCC Savings (2011$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 6..................  0..................  0.................  325...............  148...............  148...............  -992
Design line 7..................  1526...............  1678..............  1838..............  2280..............  2280..............  212
Design line 8..................  2588...............  2588..............  2724..............  4261..............  -2938.............  -2938
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Consumer Median PBP (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line 6..................  0.0................  0.0...............  12.4..............  15.7..............  15.7..............  31.7
Design line 7..................  3.9................  3.6...............  4.1...............  6.3...............  6.3...............  16.8
Design line 8..................  7.7................  7.7...............  11.3..............  10.1..............  22.5..............  22.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Distribution of Consumer LCC Impacts
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Design line 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cost (%)...................  0.0................  0.0...............  16.5..............  37.8..............  37.8..............  96.6
Net Benefit (%)................  0.0................  0.0...............  83.5..............  62.2..............  62.2..............  3.4
No Impact (%)..................  100.0..............  100.0.............  0.0...............  0.0...............  0.0...............  0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Design line 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cost (%)...................  1.5................  1.3...............  1.7...............  3.3...............  3.3...............  45.6
Net Benefit (%)................  98.4...............  98.7..............  98.3..............  96.7..............  96.7..............  54.4
No Impact (%)..................  0.1................  0.1...............  0.0...............  0.0...............  0.0...............  0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Design line 8
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cost (%)...................  4.7................  4.7...............  13.3..............  9.0...............  79.3..............  79.3
Net Benefit (%)................  95.3...............  95.3..............  86.7..............  91.0..............  20.7..............  20.7
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 4.94 quads of energy, an amount 
DOE considers significant. TSL 6 has an estimated NPV of customer 
benefit of -$1.92 billion using a 7-percent discount rate, and $5.17 
billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 6 are 319.3 million 
metric tons of CO2, 269.3 thousand tons of NOX, 
232.4 thousand tons of SO2, and 0.8 ton of Hg. The estimated 
monetary value of

[[Page 23420]]

the CO2 emissions reductions at TSL 6 ranges from $949 
million to $15,847 million.
    At TSL 6, the average LCC impact ranges from -$2,938 for design 
line 8 to $212 for design line 7. The median PBP ranges from 31.7 years 
for design line 6 to 16.8 years for design line 7. The share of 
customers experiencing a net LCC benefit ranges from 3.4 percent for 
design line 6 to 54.4 percent for design line 7.
    At TSL 6, the projected change in INPV ranges from a decrease of 
$79 million to an increase of $119 million. If the decrease of $79 
million occurs, TSL 6 could result in a net loss of 33.1 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.
    In view of the foregoing, DOE concludes that, at TSL 6 for low-
voltage dry-type distribution transformers, the benefits of energy 
savings, generating capacity reductions, 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 concluded that TSL 6 is not economically 
justified.
    Next, DOE considered TSL 5, which would save an estimated total of 
4.48 quads of energy, an amount DOE considers significant. TSL 5 has an 
estimated NPV of customer benefit of $2.22 billion using a 7 percent 
discount rate, and $11.80 billion using a 3 percent discount rate.
    The cumulative emissions reductions at TSL 5 are 297.6 million 
metric tons of CO2, 251.0 thousand tons of NOX, 
216.7 thousand tons of SO2, and 0.8 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 5 
ranges from $884 million to $14,771 million.
    At TSL 5, the average LCC impact ranges from -$2,938 for design 
line 8 to $2,280 for design line 7. The median PBP ranges from 22.5 
years for design line 8 to 6.3 years for design line 7. The share of 
customers experiencing a net LCC benefit ranges from 20.7 percent for 
design line 8 to 96.7 percent for design line 7.
    At TSL 5, the projected change in INPV ranges from a decrease of 
$47 million to an increase of $61 million. If the decrease of $47 
million occurs, TSL 5 could result in a net loss of 19.7 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.
    In view of the foregoing, DOE concludes that, at TSL 5 for low-
voltage dry-type distribution transformers, the benefits of energy 
savings, generating capacity reductions, 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 
concluded that TSL 5 is not economically justified.
    Next, DOE considered TSL 4, which would save an estimated total of 
4.39 quads of energy, an amount DOE considers significant. TSL 4 has an 
estimated NPV of customer benefit of $3.34 billion using a 7-percent 
discount rate, and $13.65 billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 4 are 292.8 million 
metric tons of CO2, 247.0 thousand tons of NOX, 
213.2 thousand tons of SO2, and 0.8 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 4 
ranges from $870 million to $14,535 million.
    At TSL 4, the average LCC impact ranges from $148 for design line 6 
to $4,261 for design line 8. The median PBP ranges from 15.7 years for 
design line 6 to 6.3 years for design line 7. The share of customers 
experiencing a net LCC benefit ranges from 62.2 percent for design line 
6 to 96.7 percent for design line 7.
    At TSL 4, the projected change in INPV ranges from a decrease of 
$39 million to an increase of $42 million. If the decrease of $39 
million occurs, TSL 4 could result in a net loss of 16.4 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.
    Additionally, TSL 4 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.
    In view of the forgoing, DOE 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, generating capacity reductions, 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 concluded that TSL 4 is not economically 
justified.
    Next, DOE considered TSL 3, which would save an estimated total of 
3.05 quads of energy, an amount DOE considers significant. TSL 3 has an 
estimated NPV of customer benefit of $2.82 billion using a 7-percent 
discount rate, and $10.38 billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 3 are 203.0 million 
metric tons of CO2, 171.3 thousand tons of NOX, 
147.8 thousand tons of SO2, and 0.5 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 3 
ranges from $603 million to $10,075 million.
    At TSL 3, the average LCC impact ranges from $325 for design line 6 
to $2,724 for design line 8. The median PBP ranges from 12.4 years for 
design line 6 to 4.1 years for design line 7. The

[[Page 23421]]

share of customers experiencing a net LCC benefit ranges from 83.5 
percent for design line 6 to 98.3 percent for design line 7.
    At TSL 3, the projected change in INPV ranges from a decrease of 
$19 million to an increase of $28 million. If the decrease of $19 
million occurs, TSL 3 could result in a net loss of 7.8 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.
    In view of the foregoing, DOE 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, generating capacity reductions, 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 concluded 
that TSL 3 is not economically justified.
    Next, DOE considered TSL 2, which would save an estimated total of 
2.43 quads of energy, an amount DOE considers significant. TSL 2 has an 
estimated NPV of customer benefit of $2.67 billion using a 7-percent 
discount rate, and $9.04 billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 2 are 161.6 million 
metric tons of CO2, 136.4 thousand tons of NOX, 
117.6 thousand tons of SO2, and 0.4 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 2 
ranges from $480 million to $8,020 million.
    At TSL 2, the average LCC impact ranges from $0 for design line 6 
to $2,588 for design line 8. The median PBP ranges from 7.7 years for 
design line 8 to 0 years for design line 6. The share of customers 
experiencing a net LCC benefit ranges from 0 percent for design line 6 
to 98.7 percent for design line 7.
    At TSL 2, the projected change in INPV ranges from a decrease of 
$11 million to an increase of $12 million. If the decrease of $11 
million occurs, TSL 2 could result in a net loss of 4.7 percent in INPV 
to manufacturers of low-voltage dry-type distribution transformers. At 
TSL 2, manufacturers have the option of continuing to produce 
transformers using butt-lap technology, investing in mitering 
equipment, or sourcing their cores. Furthermore, since TSL 2 represents 
EL 3 for DL 7 and EL 2 for DL 8 (and baseline for DL 6), manufacturers 
may benefit from being able to standardize to NEMA Premium[supreg] 
levels for low-voltage dry-type distribution transformers.
    After considering the analysis and weighing the benefits and the 
burdens, DOE has concluded that at TSL 2 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, DOE has concluded that TSL 2 would save a significant 
amount of energy and is technologically feasible and economically 
justified. For the reasons given above, DOE today adopts the energy 
conservation standards for low-voltage dry-type distribution 
transformers at TSL 2. Table V.43 presents the energy conservation 
standards for low-voltage dry-type distribution transformers.

          Table V.43--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...................................                    97.70                       15                    97.89
25...................................                    98.00                       30                    98.23
37.5.................................                    98.20                       45                    98.40
50...................................                    98.30                       75                    98.60
75...................................                    98.50                    112.5                    98.74
100..................................                    98.60                      150                    98.83
167..................................                    98.70                      225                    98.94
250..................................                    98.80                      300                    99.02
333..................................                    98.90                      500                    99.14
                                                                                    750                    99.23
                                                                                   1000                    99.28
----------------------------------------------------------------------------------------------------------------

3. Benefits and Burdens of Trial Standard Levels Considered for Medium-
Voltage Dry-Type Distribution Transformers
    Table V.44 and Table V.45 summarize the quantitative impacts 
estimated for each TSL for medium-voltage dry-type distribution 
transformers.

[[Page 23422]]



    Table V.44--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)................         0.15         0.29         0.53         0.53         0.84
----------------------------------------------------------------------------------------------------------------
                                    NPV of Consumer Benefits (2011$ billion)
----------------------------------------------------------------------------------------------------------------
3% discount rate...............................         0.49         0.79         1.12         1.12        -0.20
7% discount rate...............................         0.13         0.17         0.12         0.12        -0.89
----------------------------------------------------------------------------------------------------------------
                                         Cumulative Emissions Reduction
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)......................         11.2         20.9         40.7         40.7         61.3
NOX (thousand tons)............................         9.34         17.7         34.2         34.2         51.5
SO2 (thousand tons)............................          7.1         13.3         25.7         25.7         38.7
Hg (tons)......................................         0.02         0.04         0.10         0.10         0.14
----------------------------------------------------------------------------------------------------------------
                                  Value of Emissions Reduction (2011$ million)
----------------------------------------------------------------------------------------------------------------
CO2 *..........................................    35 to 571   65 to 1065  126 to 2067  126 to 2067  190 to 3117
NOX-3% discount rate...........................      2 to 18      3 to 34      6 to 67      6 to 67    10 to 100
NOX-7% discount rate...........................       1 to 7      1 to 14      3 to 27      3 to 27      4 to 41
----------------------------------------------------------------------------------------------------------------
* Range of the economic value of CO2 reductions is based on estimates of the global benefit of reduced CO2
  emissions.


  Table V.45--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)...................     67 to 69     66 to 72     58 to 74     58 to 74     35 to 82
Industry NPV (% change)........................     (2.0) to     (4.2) to    (15.6) to    (15.5) to    (49.7) to
                                                         1.0          4.4          8.3          8.2         18.7
----------------------------------------------------------------------------------------------------------------
                                        Consumer Mean LCC Savings (2011$)
----------------------------------------------------------------------------------------------------------------
Design line 9..................................          787          787         1514         1514         -299
Design line 10.................................         4604         4455         4455         4455       -14727
Design line 11.................................          996          996         1849         1849        -4166
Design line 12.................................         4537         6790         8594         8594       -14496
Design line 13A................................          -27          -27          311        -1019       -12053
Design line 13B................................         2494         4346         4346         4346        -6823
----------------------------------------------------------------------------------------------------------------
                                           Consumer Median PBP (years)
----------------------------------------------------------------------------------------------------------------
Design line 9..................................          2.6          2.6          6.1          6.1         18.5
Design line 10.................................          1.1          8.6          8.6          8.6         27.5
Design line 11.................................         10.6         10.6         13.6         13.6         24.1
Design line 12.................................          6.0          8.5         12.3         12.3         24.7
Design line 13A................................         16.1         16.1         16.2           20         35.3
Design line 13B................................          4.5         12.2         12.2         12.2         20.6
----------------------------------------------------------------------------------------------------------------
                                      Distribution of Consumer LCC Impacts
----------------------------------------------------------------------------------------------------------------
                                                  Design line 9
----------------------------------------------------------------------------------------------------------------
Net Cost (%)...................................          3.6          3.6          5.9          5.9         57.4
Net Benefit (%)................................         83.2         83.2         94.1         94.1         42.6
No Impact (%)..................................         13.3         13.3          0.0          0.0          0.0
----------------------------------------------------------------------------------------------------------------
                                                 Design line 10
----------------------------------------------------------------------------------------------------------------
Net Cost (%)...................................          3.6          3.6          5.9          5.9         57.4
Net Benefit (%)................................         83.2         83.2         94.1         94.1         42.6
No Impact (%)..................................         13.3         13.3          0.0          0.0          0.0
----------------------------------------------------------------------------------------------------------------
                                                 Design line 11
----------------------------------------------------------------------------------------------------------------
Net Cost (%)...................................         21.9         21.9         25.9         25.9         82.7
Net Benefit (%)................................         78.1         78.1         74.1         74.1         17.4
No Impact (%)..................................          0.0          0.0          0.0          0.0          0.0
----------------------------------------------------------------------------------------------------------------

[[Page 23423]]

 
                                                 Design line 12
----------------------------------------------------------------------------------------------------------------
Net Cost (%)...................................          7.1          7.6         17.1         17.1         85.4
Net Benefit (%)................................         92.9         92.4         82.9         82.9         14.6
No Impact (%)..................................          0.0          0.0          0.0          0.0          0.0
----------------------------------------------------------------------------------------------------------------
                                                 Design line 13A
----------------------------------------------------------------------------------------------------------------
Net Cost (%)...................................         54.2         54.2         45.5         66.3         98.5
Net Benefit (%)................................         45.8         45.8         54.5         33.7          1.5
No Impact (%)..................................          0.0          0.0          0.0          0.0          0.0
----------------------------------------------------------------------------------------------------------------
                                                 Design line 13B
----------------------------------------------------------------------------------------------------------------
Net Cost (%)...................................         30.5         27.3         27.3         27.3         70.4
Net Benefit (%)................................         69.3         72.7         72.7         72.7         29.6
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 0.84 quad of energy, an amount 
DOE considers significant. TSL 5 has an estimated NPV of customer 
benefit of -$0.89 billion using a 7-percent discount rate, and -$0.20 
billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 5 are 61.3 million 
metric tons of CO2, 51.5 thousand tons of NOX, 
38.7 thousand tons of SO2, and 0.14 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 5 
ranges from $190 million to $3,117 million.
    At TSL 5, the average LCC impact ranges from -$14,727 for design 
line 10 to -299 for design line 9. The median PBP ranges from 35.3 
years for design line 13A to 18.5 years for design line 9. The share of 
customers experiencing a net LCC benefit ranges from 1.5 percent for 
design line 13A to 42.6 percent for design line 9.
    At TSL 5, the projected change in INPV ranges from a decrease of 
$34 million to an increase of $13 million. If the decrease of $34 
million occurs, TSL 5 could result in a net loss of 49.7 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 core steel technology, with which there is no experience in 
this market.\72\
---------------------------------------------------------------------------

    \72\ See section IV.I.5.a for further detail.
---------------------------------------------------------------------------

    In view of the foregoing, DOE concludes that, at TSL 5 for medium-
voltage dry-type distribution transformers, the benefits of energy 
savings, generating capacity reductions, 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 the risk of very large negative impacts on the 
manufacturers. Consequently, DOE has concluded that TSL 5 is not 
economically justified.
    Next, DOE considered TSL 4, which would save an estimated total of 
0.53 quad of energy, an amount DOE considers significant. TSL 4 has an 
estimated NPV of customer benefit of $0.12 billion using a 7-percent 
discount rate, and $1.12 billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 4 are 40.7 million 
metric tons of CO2, 34.2 thousand tons of NOX, 
25.7 thousand tons of SO2, and 0.1 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 4 
ranges from $126 million to $2,067 million.
    At TSL 4, the average LCC impact ranges from -$1019 for design line 
13A to $8,594 for design line 12. The median PBP ranges from 20.0 years 
for design line 13B to 6.1 years for design line 9. The share of 
customers experiencing a net LCC benefit ranges from 33.7 percent for 
design line 13A to 94.1 percent for design line 9.
    At TSL 4, the projected change in INPV ranges from a decrease of 
$11 million to an increase of $6 million. If the decrease of $11 
million occurs, TSL 4 could result in a net loss of 15.5 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.
    In view of the foregoing, DOE 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 concluded that TSL 4 is not economically 
justified.
    Next, DOE considered TSL 3, which would save an estimated total of 
0.53 quad of energy, an amount DOE considers significant. TSL 3 has an 
estimated NPV of customer benefit of $0.12 billion using a 7-percent 
discount rate, and $1.12 billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 3 are 40.7 million 
metric tons of CO2, 34.2 thousand tons of NOX, 
25.7 thousand tons of SO2, and 0.1 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 3 
ranges from $126 million to $2,067 million.
    At TSL 3, the average LCC impact ranges from $311 for design line 
13A to $8594 for design line 12. The median

[[Page 23424]]

PBP ranges from 16.2 years for design line 13A to 6.1 years for design 
line 9. The share of customers experiencing a net LCC benefit ranges 
from 54.5 percent for design line 13A to 94.1 percent for design line 
9.
    At TSL 3, the projected change in INPV ranges from a decrease of 
$11 million to an increase of $6 million. If the decrease of $11 
million occurs, TSL 3 could result in a net loss of 15.6 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.
    In view of the foregoing, DOE 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 concluded that TSL 3 is not economically 
justified.
    Next, DOE considered TSL 2, which would save an estimated total of 
0.29 quads of energy, an amount DOE considers significant. TSL 2 has an 
estimated NPV of customer benefit of $0.17 billion using a 7-percent 
discount rate, and $0.79 billion using a 3-percent discount rate.
    The cumulative emissions reductions at TSL 2 are 20.9 million 
metric tons of CO2, 17.7 thousand tons of NOX, 
13.3 thousand tons of SO2, and 0.04 ton of Hg. The estimated 
monetary value of the CO2 emissions reductions at TSL 2 
ranges from $65 million to $1,065 million.
    At TSL 2, the average LCC impact ranges from $-27 for design line 
13A to $6,790 for design line 12. The median PBP ranges from 16.1 years 
for design line 13A to 2.6 years for design line 9. The share of 
customers experiencing a net LCC benefit ranges from 45.8 percent for 
design line 13A to 92.4 percent for design line 12.
    At TSL 2, the projected change in INPV ranges from a decrease of $3 
million to an increase of $3 million. If the decrease of $3 million 
occurs, TSL 2 could result in a net loss of 4.2 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 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, DOE 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 DOE Efficiency and Renewables Advisory Committee (ERAC) 
subcommittee, as described in section II.B.2. Based on the above 
considerations, DOE today adopts the energy conservation standards for 
medium-voltage dry-type distribution transformers at TSL 2. Table V.46 
presents the energy conservation standards for medium-voltage dry-type 
distribution transformers.

[[Page 23425]]



                             Table V.46--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 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 23426]]

4. Summary of Benefits and Costs (Annualized) of Today's Standards
    The benefits and costs of today's 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 today's 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.\73\ The value 
of the CO2 reductions is calculated using a range of values 
per metric ton of CO2 developed by a recent interagency 
process.
---------------------------------------------------------------------------

    \73\ 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 2012, 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.47. From the present value, DOE then calculated the 
fixed annual payment over a 30-year period 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.47 shows the annualized values for today's 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 reduction, for which DOE used a 3-percent discount 
rate along with the SCC series corresponding to a value of $22.3/ton in 
2011), the cost of the standards in today's rule is $266 million per 
year in increased equipment costs, while the benefits are $581 million 
per year in reduced equipment operating costs, $237 million in 
CO2 reductions, and $8.60 million in reduced NOX 
emissions. In this case, the net benefit amounts to $561 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/ton in 2011), the cost 
of the standards in today's rule is $282 million per year in increased 
equipment costs, while the benefits are $983 million per year in 
reduced operating costs, $237 million in CO2 reductions, and 
$12.67 million in reduced NOX emissions. In this case, the 
net benefit amounts to $950 million per year.

     Table V.47--Annualized Benefits and Costs of Standards for Distribution Transformers Sold in 2016-2045
----------------------------------------------------------------------------------------------------------------
                                                                          Million 2011$/year
                                                     -----------------------------------------------------------
                                    Discount rate %                        Low net benefits    High net benefits
                                                      Primary estimate *      estimate *          estimate *
----------------------------------------------------------------------------------------------------------------
                                  ..................
----------------------------------------------------------------------------------------------------------------
Benefits
Operating cost savings..........  7%................  581...............  559...............  590.
                                  3%................  983...............  930...............  1003.
CO2 reduction monetized value     5%................  57.7..............  57.7..............  57.7.
 ($4.9/t case)**.
CO2 reduction monetized value     3%................  237...............  237...............  237.
 ($22.3/t case)**.
CO2 reduction monetized value     2.5%..............  377...............  377...............  377.
 ($36.5/t case)**.
CO2 reduction monetized value     3%................  721...............  721...............  721.
 ($67.6/t case)**.
NOX reduction monetized value     7%................  8.60..............  8.60..............  8.60.
 ($2,591/ton)**.
                                  3%................  12.67.............  12.67.............  12.67.
    Total benefits[dagger]......  7% plus CO2 range.  648 to 1311.......  625 to 1288.......  656 to 1319.
                                  7%................  827...............  805...............  836.
                                  3% plus CO2 range.  1053 to 1716......  1000 to 1663......  1074 to 1737.
                                  3%................  1233..............  1179..............  1253.
Costs
Incremental equipment costs.....  7%................  266...............  300...............  257.
                                  3%................  282...............  325...............  271.
Net Benefits
    Total [dagger]..............  7% plus CO2 range.  381 to 1044.......  325 to 988........  400 to 1063.
                                  7%................  561...............  504...............  579.
                                  3% plus CO2 range.  771 to 1434.......  675 to 1338.......  803 to 1466.
                                  3%................  950...............  854...............  982.
----------------------------------------------------------------------------------------------------------------
* The Primary, Low Net Benefits, and High Net Benefits Estimates utilize forecasts of energy prices from the AEO
  2012 reference case, Low Economic Growth case, and High Economic Growth case, respectively. In addition,
  incremental product costs reflect no change in the Primary estimate, rising product prices in the Low Net
  Benefits estimate, and declining product prices in the High Net Benefits estimate.
** The CO2 values represent global monetized values of the SCC, in 2011$, in 2011 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 $67.6/t represents the 95th percentile of the SCC
  distribution calculated using a 3% discount rate. The SCC time series used by DOE incorporate an escalation
  factor. The value for NOX (in 2011$) 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 series corresponding to SCC value of
  $22.3/t. In the rows labeled ``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.


[[Page 23427]]

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 addressed by today's standards 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 some 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. Consequently, distribution transformers are being purchased 
that do not provide the minimum LCC to the 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 NEMA indicated that these 
guidelines or similar criteria are applied to approximately 75 percent 
of liquid-immersed distribution 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 such 
purchases in these segments do not employ economic evaluation of 
transformer losses. These are the portions of the distribution 
transformer market in which there is market failure. Today's 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 rule and that the Office of Information and Regulatory Affairs 
(OIRA) in the Office of Management and 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, 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 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 final rule 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. 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, and a final 
regulatory flexibility analysis (FRFA) for any such rule that an agency 
adopts as a final rule, 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 (August 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 (http://energy.gov/gc/office-general-counsel). DOE reviewed the February 2012 NOPR and today's final 
rule under the provisions of the Regulatory Flexibility Act and the 
procedures and policies published on February 19, 2003.
    As presented and discussed in the following sections, the FRFA 
describes potential impacts on small manufacturers associated with the 
required product and capital conversion costs at each TSL and discusses 
alternatives that could minimize these impacts. Chapter 12 of the TSD 
contains

[[Page 23428]]

more information about the impact of this rulemaking on manufacturers.
1. Statement of the Need for, and Objectives of, the Rule
    The reasons why DOE is establishing the standards in today's final 
rule and the objectives of these standards are provided elsewhere in 
the preamble and not repeated here.
2. Summary of and Responses to the Significant Issues Raised by the 
Public Comments, and a Statement of Any Changes Made as a Result of 
Such Comments
    This FRFA incorporates the IRFA and public comments received on the 
IRFA and the economic impacts of the rule. DOE provides responses to 
these comments in the discussion below on the compliance impacts of the 
rule and elsewhere in the preamble. DOE modified the standards adopted 
in today's final rule in response to comments received, including those 
from small businesses, as described in the preamble.
3. 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, 30848 (May 15, 2000), as amended at 65 FR 53533, 
53544 (Sept. 5, 2000) and codified at 13 CFR part 121. The size 
standards are listed by NAICS code and industry description and are 
available at http://www.sba.gov/sites/default/files/files/Size_Standards_Table.pdf. 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.
    In the February 2012 NOPR, DOE identified approximately 10 liquid-
immersed distribution transformer manufacturers, 14 LVDT manufacturers, 
and 17 MVDT manufacturers of covered equipment that can be considered 
small businesses. 77 FR 7282 (February 10, 2012). Of the liquid-
immersed distribution transformer small business manufacturers, DOE was 
able to reach and discuss potential standards with six of the 10 small 
business manufacturers. Of the LVDT manufacturers, DOE was able to 
contact and discuss potential standards with seven 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. DOE also obtained information about small 
business impacts while interviewing large manufacturers.
b. Distribution Transformer Industry Structure
    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 specifications 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 manufacturers 
of LVDT 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 not covered 
under standards. Roughly 50 percent of the market by revenue is not 
covered under 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 focus their operations on one or 
two parts of the value chain--rather than all of it--and focus 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 compete entirely in 
distribution transformer markets that are not covered by statute. DOE 
did not attempt to contact companies operating solely 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[supreg] (equivalent to EL3, EL3, and EL2 for 
DL6, DL7 and DL8, respectively) or better transformers as retrofit 
opportunities. Others focus on particular applications or 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 in the MVDT industry often produce transformers not 
covered under DOE standards. DOE estimates that 10 percent of the 
market is not covered under standards.
c. 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 are the root cause of most small business

[[Page 23429]]

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.
    Last, small manufacturers typically have less access to capital, 
which may be needed by some to cover the conversion costs associated 
with new technologies.
4. Description and Estimate of Compliance Requirements
a. 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 established 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 equipment. DOE estimates TSL 1 would require industry product 
conversion costs of only one-half of one year's annual industry R&D 
expenses. Because these one-time costs are relatively fixed per 
manufacturer, they impact smaller manufacturers disproportionately 
(compared to larger manufacturers). The table below illustrates this 
effect:

Table VI.1--Estimated Product Conversion Costs as a Percentage of Annual
                               R&D Expense
------------------------------------------------------------------------
                                                               Product
                                                              conversion
                                                  Product     cost as a
                                                 conversion   percentage
                                                    cost      of annual
                                                             R&D expense
------------------------------------------------------------------------
Typical Large Manufacturer....................      $1.34 M           20
Typical Small Manufacturer....................       1.34 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.
    b. Low-Voltage Dry-Type.
    Small manufacturers have several options available to them at TSL2 
based on individual economic determinations. They may choose to: (1) 
Source their cores, (2) fabricate cores with butt-lapping technology 
and higher-grade steel, (3) buy a mitering machine (enabling them to 
build mitered cores with lower-grade steel than would be otherwise 
required), or (4) exit a product line.
    Compared to higher TSLs, TSL 2 provides many more design paths for 
small manufacturers to comply. DOE's engineering analysis indicates 
that the efficiency level represented by TSL 2 for DL7 (the high-volume 
line) could be met without mitering through the use of butt-lapping 
higher-grade steels. It is uncertain whether small manufacturers would 
elect to butt-lap with higher grade steel rather than source their 
cores or invest in mitering equipment, but each option remains a viable 
path to compliance. With respect to the other paths to compliance, DOE 
notes that roughly half of the small business LVDT manufacturers DOE 
interviewed already have mitering capability. DOE estimates half of all 
cores in small business DL7 transformers are currently sourced, 
according to transformer and core manufacturer interviews, as third-
party core manufacturers already often have significant variable cost 
advantages through bulk steel purchasing power and greater production 
efficiencies due to higher volumes.
    Each business' ultimate decision on how it will ultimately comply 
depends on its production volumes, the relative steel prices it faces, 
its position in the value chain, and whether it currently has mitering 
technology in-house, among other factors. Because a small business may 
ultimately make the business decision to build mitered cores at TSL 2, 
DOE estimates the cost of such a strategy to conservatively bound the 
compliance impact. Below DOE compares the relative impact on a small 
business of the scenario in which a small manufacturer elects to 
purchase a new mitering machine (rather than continue to butt-lap with 
higher grade steel or source its core production). Based on interviews 
with small businesses and core manufacturers, DOE believes this to be a 
conservative assessment of compliance costs, as many small businesses 
currently source a large share of their cores. DOE estimates capital 
conversion costs of $0.75 million and product conversion costs of $0.2 
million, based on manufacturer and equipment supplier interviews, would 
be incurred if small businesses without mitering equipment chose to 
invest in it. 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 in in-house mitering capability will likely be 
disproportionately impacted (compared to large manufacturers). Based on 
information gathered in interviews, DOE estimates that three small 
manufacturers would invest in mitering equipment as result of this 
rule. 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.

[[Page 23430]]



  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...................                       37                       10                       15
Small Manufacturer...................                      137                       44                       70
----------------------------------------------------------------------------------------------------------------

    For more than half of the small businesses DOE interviewed, it is 
already standard practice to source a large percentage of their DOE-
covered cores on an ongoing basis or quickly do so when steel prices 
merit such a strategy. Furthermore, small businesses are currently more 
likely to source cores for NEMA Premium[supreg] units than standard 
units. Many small businesses indicated that they expect the continuance 
of this strategy would be the low-cost option under higher standards. 
Therefore, the impacts in the table are not representative of the 
strategy DOE expects to be employed by many small manufacturers, but 
only those choosing to invest in mitering equipment.
    For all of the reasons discussed, DOE believes the capital 
expenditures it estimated above 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 2.
c. 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 H0. 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 
towards more M4 and H1 steel and away 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 additional 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 low capital and product 
conversion costs that are relatively fixed for both small and large 
manufacturers. Similar to the low-voltage dry-type market, small 
manufacturers will likely be disproportionately impacted compared to 
large manufacturers due to the fixed nature of the conversion 
expenditures. Table VI.3 illustrates the relative impacts on small and 
large manufacturers.

  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...................                        3                        9                        8
Small Manufacturer...................                       40                      117                       98
----------------------------------------------------------------------------------------------------------------

d. 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 both large and small 
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.
5. Steps Taken to Minimize Impacts on Small Entities and Reasons Why 
Other Significant Alternatives to Today's Final Rule Were Rejected
    DOE modified the standards established in today's final rule from 
those proposed in the February 2012 NOPR as discussed previously and 
based on comments and additional test data received from interested 
parties.
    The previous discussion also analyzes impacts on small businesses 
that would result from the other TSLs DOE considered. Though TSLs lower 
than the adopted TSL 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. Thus, DOE rejected the lower TSLs.
    In addition to the other TSLs being considered, the TSD includes a 
regulatory impact analysis (chapter 17) that discusses the following 
policy alternatives: (1) No standard, (2) consumer rebates, (3) 
consumer tax credits, (4) manufacturer tax credits, and (5) early 
replacement. DOE does not intend to consider these alternatives further 
because they are either not feasible to implement, or not expected to 
result in energy savings as large as those that would be achieved by 
the standard levels under consideration. Thus, DOE rejected these 
alternatives and is adopting the standards set forth in this 
rulemaking.
6. 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 finalized today.

[[Page 23431]]

7. Significant Alternatives to Today's Rule
    The discussion above analyzes impacts on small businesses that 
would result from the other TSLs DOE considered. Though TSLs lower than 
the selected 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 TSD includes a 
regulatory impact analysis (chapter 17) that 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.
8. Significant Issues Raised by Public Comments
    DOE's MIA suggests that, while TSL1, TSL1, and TSL 2 present 
greater difficulties for small businesses than lower levels in the 
liquid-immersed, LVDT, and MVDT classes, respectively, the impacts at 
higher TSLs would be greater. DOE expects that small businesses will 
generally be able to profitably compete at the TSL selected 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 selected in this final 
rule.
    DOE also notes that today's standards can be met with a variety of 
materials, including multiple core steels and both copper and aluminum 
windings. Because today's 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.
9. 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 that 
TSL1 is the highest level that can be justified for liquid-immersed and 
medium-voltage dry-type transformers and TSL2 is the highest level that 
can be justified for low-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 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 medium-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 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 distribution transformer market would not require 
small manufacturers to invest in amorphous steel technology, which 
could put them at a significant disadvantage.
    Section VI.B discusses how small business impacts entered into 
DOE's selection of today's 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 
that is both technologically feasible and economically justified, 
taking into account other EPCA criteria. Because DOE believes that the 
TSLs selected are economically justified (including consideration of 
small business impacts), the reduced impact on small businesses that 
would have been realized in moving 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 low-voltage dry-type) and to TSL1 
from TSL2 (in the case of liquid-immersed) 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 equipment complies with any applicable energy conservation 
standards. In certifying compliance, manufacturers must test their 
equipment 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, 
DOE has determined that the 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 part 1021, App. B, 
B5.1(b); 1021.410(b) and Appendix B, B(1)-(5). The rule fits within the 
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 rule. DOE's CX determination for this rule is 
available at http://cxnepa.energy.gov/ or link directly to http://energy.gov/nepa/downloads/cx-007852-categorical-exclusion-determination.

E. Review Under Executive Order 13132

    Executive Order 13132, ``Federalism.'' 64 FR 43255 (Aug. 10, 1999) 
imposes certain requirements on Federal

[[Page 23432]]

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 
final 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 final 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. Pub. L. 104-4, sec. 201 (codified at 2 U.S.C. 1531). 
For an amended 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 ``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 http://energy.gov/gc/office-general-counsel.
    DOE has concluded that this final rule would likely require 
expenditures of $100 million or more by the private sector. Such 
expenditures may include: (1) investment in research and development 
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 final 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 the final rule and the 
``Regulatory Impact Analysis'' section of the TSD for this final 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 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 
(o), 6316(a), and 6317(a)(1), today's final 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'' chapter of the TSD for 
today's final 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, under Executive Order 12630, ``Governmental 
Actions and Interference with Constitutionally Protected Property 
Rights'' 53 FR 8859 (March 18, 1988), that 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

[[Page 23433]]

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 final rule 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 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 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 concluded that today's regulatory action, which sets forth 
energy conservation standards for distribution transformers, is not a 
significant energy action because the amended 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 for the final 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.

M. Congressional Notification

    As required by 5 U.S.C. 801, DOE will report to Congress on the 
promulgation of this rule prior to its effective date. The report will 
state that it has been determined that the rule is a ``major rule'' as 
defined by 5 U.S.C. 804(2).

VII. Approval of the Office of the Secretary

    The Secretary of Energy has approved publication of today's final 
rule.

List of Subjects in 10 CFR Part 431

    Administrative practice and procedure, Confidential business 
information, Energy conservation, Reporting and recordkeeping 
requirements.

    Issued in Washington, DC, on April 9, 2013.
David Danielson,
Assistant Secretary of Energy, Energy Efficiency and Renewable Energy.

    For the reasons set forth in the preamble, DOE amends 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

0
1. The authority citation for part 431 continues to read as follows:

    Authority: 42 U.S.C. 6291-6317.

0
2. Section 431.192 is amended by:
0
a. Removing the definition of ``underground mining distribution 
transformer'' and
0
b. Adding in alphabetical order, the definition for ``mining 
distribution transformer'' to read as follows:


Sec.  431.192  Definitions.

* * * * *
    Mining distribution transformer means a medium-voltage dry-type 
distribution transformer that is built only for installation in an 
underground mine or surface mine, inside equipment for use in an 
underground mine or surface mine, on-board equipment for use in an 
underground mine or surface mine, or for equipment used for digging, 
drilling, or tunneling underground or above ground, and that has a 
nameplate which identifies the transformer as being for this use only.
* * * * *

0
3. Section 431.196 is revised 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 the applicable 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

[[Page 23434]]

 
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
  Method for Measuring the Energy Consumption of Distribution Transformers under Appendix A to Subpart K of 10
  CFR part 431.

    (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                        Efficiency (%)                 kVA                Efficiency (%)
----------------------------------------------------------------------------------------------------------------
15...........................................           97.70   15..............................           97.89
25...........................................           98.00   30..............................           98.23
37.5.........................................           98.20   45..............................           98.40
50...........................................           98.30   75..............................           98.60
75...........................................           98.50   112.5...........................           98.74
100..........................................           98.60   150.............................           98.83
167..........................................           98.70   225.............................           98.94
250..........................................           98.80   300.............................           99.02
333..........................................           98.90   500.............................           99.14
                                                                750.............................           99.23
                                                                1000............................           99.28
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test
  Method for Measuring the Energy Consumption of Distribution Transformers under Appendix A to Subpart K of 10
  CFR part 431.

    (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                        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, Appendix A to Subpart K of 10 CFR part 431.


[[Page 23435]]

    (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...........................................           98.70   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
667..........................................           99.52   1500............................           99.48
833..........................................           99.55   2000............................           99.51
                                                                2500............................           99.53
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test
  Method for Measuring the Energy Consumption of Distribution Transformers under Appendix A to Subpart K of 10
  CFR part 431.

    (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.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                   Single-phase                                                                  Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         BIL*                                                                   BIL
                                  -------------------------------------------------                      -----------------------------------------------
               kVA                    20-45 kV        46-95 kV         >=96 kV               kVA             20-45 kV        46-95 kV         >=96 kV
                                  -------------------------------------------------                      -----------------------------------------------
                                   Efficiency (%)  Efficiency (%)   Efficiency (%)                        Efficiency (%)  Efficiency (%)  Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 Method for Measuring the Energy Consumption
  of Distribution Transformers under Appendix A to Subpart K of 10 CFR part 431.

    (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.

[[Page 23436]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                   Single-phase                                                                  Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         BIL*                                                                   BIL
                                  -------------------------------------------------                      -----------------------------------------------
               kVA                    20-45 kV        46-95 kV         >=96 kV               kVA             20-45 kV        46-95 kV         >=96 kV
                                  -------------------------------------------------                      -----------------------------------------------
                                   Efficiency (%)  Efficiency (%)   Efficiency (%)                        Efficiency (%)  Efficiency (%)  Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 Method for Measuring the Energy Consumption
  of Distribution Transformers under Appendix A to Subpart K of 10 CFR part 431.

    (d) Mining Distribution Transformers. [Reserved]

Appendix

    Note: The following letter from the Department of Justice will 
not appear in the Code of Federal Regulations.

U.S. Department of Justice
Antitrust Division
Joseph F. Wayland
Acting Assistant Attorney General
RFK Main Justice Building
950 Pennsylvania Ave., NW
Washington, D.C. 20530-0001
(202)514-2401/(202)616-2645 (Fax)

September 24, 2012

Eric J. Fygi
Deputy General Counsel
Department of Energy
Washington, DC 20585

Dear Deputy General Counsel Fygi:

    I am responding to your August 16, 2012 letter seeking the views 
of the Attorney General about the potential impact on competition of 
proposed energy conservation standards for certain types of 
distribution transformers, namely medium-voltage, dry-type and 
liquid-immersed distribution transformers, as well as low-voltage, 
dry-type distribution transformers. Your request was submitted under 
Section 325(o)(2)(B)(i)(V) of the Energy Policy and Conservation 
Act, as amended (ECPA), 42 U.S.C. 6295(o)(2)(B)(i)(V), which 
requires the Attorney General to make a determination of the impact 
of any lessening of competition that is likely to result from the 
imposition of proposed energy conservation standards. The Attorney 
General's responsibility for responding to requests from other 
departments about the effect of a program on competition has been 
delegated to the Assistant Attorney General for the Antitrust 
Division in 28 CFR Sec.  0.40(g).
    In conducting its analysis the Antitrust Division examines 
whether a proposed standard may lessen competition, for example, by 
substantially limiting consumer choice, by placing certain 
manufacturers at an unjustified competitive disadvantage, or by 
inducing avoidable inefficiencies in production or distribution of 
particular products. A lessening of competition could result in 
higher prices to manufacturers and consumers, and perhaps thwart the 
intent of the revised standards by inducing substitution to less 
efficient products.
    We have reviewed the proposed standards contained in the Notice 
of Proposed Rulemaking (77 Fed. Reg. 7282, February 10, 2012) 
(NOPR). We have also reviewed supplementary information submitted to 
the Attorney General by the Department of Energy. The NOPR proposed 
Trial Standard Level 2 for medium-voltage, dry-type distribution 
transformers, which was arrived at through a consensus agreement 
among a diverse array of stakeholders as part of a negotiated 
rulemaking, and Trial Standard Level 1 for medium-voltage, liquid-
immersed and low-voltage, dry-type distribution transformers, after 
no consensus was reached as part of a negotiated rulemaking. Our 
review has focused on the standards DOE has proposed adopting. We 
have not determined the impact on competition of more stringent 
standards than those proposed in the NOPR.
    Based on this review, our conclusion is that the proposed energy 
conservation standards for medium-voltage, dry-type and liquid-
immersed distribution transformers, as well as low-voltage, dry-type 
distribution transformers, are unlikely to have a significant 
adverse impact on competition. In reaching our conclusion, we note 
that the proposed energy standards for medium-voltage, dry-type 
distribution transformers were arrived at through a consensus 
agreement among a diverse array of stakeholders.

Sincerely,

Joseph F. Wayland

[FR Doc. 2013-08712 Filed 4-17-13; 8:45 am]
BILLING CODE 6450-01-P