Energy Conservation Program: Energy Conservation Standards for Distribution Transformers

Federal RegisterFeb 10, 2012

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DEPARTMENT OF ENERGY

10 CFR Part 431

[Docket Number EERE-2010-BT-STD-0048]

RIN 1904-AC04

Energy Conservation Program: Energy Conservation Standards for Distribution Transformers

AGENCY:

Office of Energy Efficiency and Renewable Energy, Department of Energy.

ACTION:

Notice of proposed rulemaking and public meeting.

SUMMARY:

The Energy Policy and Conservation Act of 1975 (EPCA), as amended, prescribes energy conservation standards for various consumer products and certain commercial and industrial equipment, including low-voltage dry-type distribution transformers, and directs the U.S. Department of Energy (DOE) to prescribe standards for various other products and equipment, including other types of distribution transformers. EPCA also requires DOE to determine whether more-stringent, amended standards would be technologically feasible and economically justified, and would save a significant amount of energy. In this notice, DOE proposes amended energy conservation standards for distribution transformers. The notice also announces a public meeting to receive comment on these proposed standards and associated analyses and results.

DATES:

DOE will hold a public meeting on February 23, 2012, from 9 a.m. to 1 p.m., in Washington, DC. The meeting will also be broadcast as a Webinar. See section VII Public Participation for Webinar registration information, participant instructions, and information about the capabilities available to Webinar participants.

DOE will accept comments, data, and information regarding this notice of proposed rulemaking (NOPR) before and after the public meeting, but no later than April 10, 2012. See section VII Public Participation for details.

ADDRESSES:

The public meeting will be held at the U.S. Department of Energy, Forrestal Building, Room 8E-089, 1000 Independence Avenue SW., Washington, DC 20585. To attend, please notify Ms. Brenda Edwards at (202) 586-2945. Please note that foreign nationals visiting DOE Headquarters are subject to advance security screening procedures. Any foreign national wishing to participate in the meeting should advise DOE as soon as possible by contacting Ms. Edwards to initiate the necessary procedures. In addition, persons can attend the public meeting via Webinar. For more information, refer to the Public Participation section near the end of this notice.

Any comments submitted must identify the NOPR for Energy Conservation Standards for Distribution Transformers, and provide docket number EERE-2010-BT-STD-0048 and/or regulation identifier number (RIN) number 1904-AC04. Comments may be submitted using any of the following methods:

Federal eRulemaking Portal:

www.regulations.gov

. Follow the instructions for submitting comments.

Email:

DistributionTransformers-2010-STD-0048@ee.doe.gov

. Include the docket number and/or RIN in the subject line of the message.

Mail:

Ms. Brenda Edwards, U.S. Department of Energy, Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue SW., Washington, DC 20585-0121. If possible, please submit all items on a CD. It is not necessary to include printed copies.

Hand Delivery/Courier:

Ms. Brenda Edwards, U.S. Department of Energy, Building Technologies Program, 950 L'Enfant Plaza SW., Suite 600, Washington, DC 20024. Telephone: (202) 586-2945. If possible, please submit all items on a CD, in which case it is not necessary to include printed copies.

Written comments regarding the burden-hour estimates or other aspects of the collection-of-information requirements contained in this proposed rule may be submitted to Office of Energy Efficiency and Renewable Energy through the methods listed above and by email to

Chad_S_Whiteman@omb.eop.gov

For detailed instructions on submitting comments and additional information on the rulemaking process, see section VII of this document (Public Participation).

Docket:

The docket is available for review at

www.regulations.gov

, including

Federal Register

notices, framework documents, public meeting attendee lists and transcripts, comments, and other supporting documents/materials. A link to the docket Web page can be found at:

http://www.regulations.gov/#!docketDetail;rpp=10;po=0;D=EERE-2010-BT-STD-0048

FOR FURTHER INFORMATION CONTACT:

James Raba, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies Program, EE-2J, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 586-8654. Email:

Jim.Raba@ee.doe.gov

Ami Grace-Tardy, U.S. Department of Energy, Office of the General Counsel, GC-71, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 586-5709. Email:

Ami.Grace-Tardy@hq.doe.gov

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Summary of the Proposed Rule

A. Benefits and Costs to Consumers

B. Impact on Manufacturers

C. National Benefits

II. Introduction

A. Authority

B. Background

1. Current Standards

2. History of Standards Rulemaking for Distribution Transformers

III. General Discussion

A. Test Procedures

1. General

2. Multiple kVA Ratings

3. Dual/Multiple-Voltage Basic Impulse Level

4. Dual/Multiple-Voltage Primary Windings

5. Dual/Multiple-Voltage Secondary Windings

6. Loading

B. Technological Feasibility

1. General

2. Maximum Technologically Feasible Levels

C. Energy Savings

1. Determination of Savings

2. Significance of Savings

D. Economic Justification

1. Specific Criteria

a. Economic Impact on Manufacturers and Consumers

b. Life-Cycle Costs

c. Energy Savings

d. Lessening of Utility or Performance of Products

e. Impact of Any Lessening of Competition

f. Need for National Energy Conservation

g. Other Factors

2. Rebuttable Presumption

IV. Methodology and Discussion of Related Comments

A. Market and Technology Assessment

1. Scope of Coverage

a. Definitions

b. Underground Mining Transformer Coverage

c. Low-Voltage Dry-Type Distribution Transformers

d. Negotiating Committee Discussion of Scope

2. Equipment Classes

a. Less-Flammable Liquid-Immersed Transformers

b. Pole- and Pad-Mounted Liquid-Immersed Distribution Transformers

c. BIL Ratings in Liquid-Immersed Distribution Transformers

3. Technology Options

a. Core Deactivation

b. Symmetric Core

c. Intellectual Property

B. Screening Analysis

1. Nanotechnology Composites

C. Engineering Analysis

1. Engineering Analysis Methodology

2. Representative Units

3. Design Option Combinations

4. A and B Loss Value Inputs

5. Materials Prices

6. Markups

a. Factory Overhead

b. Labor Costs

c. Shipping Costs

7. Baseline Efficiency and Efficiency Levels

8. Scaling Methodology

9. Material Availability

10. Primary Voltage Sensitivities

11. Impedance

12. Size and Weight

D. Markups Analysis

E. Energy Use Analysis

F. Life-Cycle Cost and Payback Period Analysis

1. Modeling Transformer Purchase Decision

2. Inputs Affecting Installed Cost

a. Equipment Costs

b. Installation Costs

3. Inputs Affecting Operating Costs

a. Transformer Loading

b. Load Growth Trends

c. Electricity Costs

d. Electricity Price Trends

e. Standards Compliance Date

f. Discount Rates

g. Lifetime

h. Base Case Efficiency

G. National Impact Analysis—National Energy Savings and Net Present Value Analysis

1. Shipments

2. Efficiency Trends

3. Equipment Price Forecast

4. Discount Rate

5. Energy Used in Manufacturing Transformers

H. Customer Subgroup Analysis

I. Manufacturer Impact Analysis

1. Overview

2. Government Regulatory Impact Model

3. GRIM Key Inputs

a. Manufacturer Production Costs

b. Base-Case Shipments Forecast

c. Product and Capital Conversion Costs

d. Standards Case Shipments

e. Markup Scenarios

4. Discussion of Comments

a. Material Availability

b. Symmetric Core Technology

c. Patents Related to Amorphous Steel Production

5. Manufacturer Interviews

a. Conversion Costs and Stranded Assets

b. Shortage of Materials

c. Compliance

d. Effective Date

e. Emergency Situations

J. Employment Impact Analysis

K. Utility Impact Analysis

L. Emissions Analysis

M. Monetizing Carbon Dioxide and Other Emissions Impacts

1. Social Cost of Carbon

a. Monetizing Carbon Dioxide Emissions

b. Social Cost of Carbon Values Used in Past Regulatory Analyses

c. Current Approach and Key Assumptions

2. Valuation of Other Emissions Reductions

N. Discussion of Other Comments

1. Trial Standard Levels

2. Proposed Standards

3. Alternative Methods

4. Labeling

5. Imported Units

V. Analytical Results and Conclusions

A. Trial Standard Levels

B. Economic Justification and Energy Savings

1. Economic Impacts on Customers

a. Life-Cycle Cost and Payback Period

b. Customer Subgroup Analysis

c. Rebuttable-Presumption Payback

2. Economic Impact on Manufacturers

a. Industry Cash-Flow Analysis Results

b. Impacts on Employment

c. Impacts on Manufacturing Capacity

d. Impacts on Subgroups of Manufacturers

e. Cumulative Regulatory Burden

3. National Impact Analysis

a. Significance of Energy Savings

b. Net Present Value of Customer Costs and Benefits

c. Indirect Impacts on Employment

4. Impact on Utility or Performance of Equipment

5. Impact of Any Lessening of Competition

6. Need of the Nation to Conserve Energy

7. Summary of National Economic Impacts

8. Other Factors

C. Proposed Standards

1. Benefits and Burdens of Trial Standard Levels Considered for Liquid-Immersed Distribution Transformers

2. Benefits and Burdens of Trial Standard Levels Considered for Low-Voltage, Dry-Type Distribution Transformers

3. Benefits and Burdens of Trial Standard Levels Considered for Medium-Voltage, Dry-Type Distribution Transformers

4. Summary of Benefits and Costs (Annualized) of the Proposed Standards

VI. Procedural Issues and Regulatory Review

A. Review Under Executive Orders 12866 and 13563

B. Review Under the Regulatory Flexibility Act

1. Description and Estimated Number of Small Entities Regulated

a. Methodology for Estimating the Number of Small Entities

b. Manufacturer Participation

c. Distribution Transformer Industry Structure and Nature of Competition

d. Comparison Between Large and Small Entities

2. Description and Estimate of Compliance Requirements

a. Summary of Compliance Impacts

3. Duplication, Overlap, and Conflict With Other Rules and Regulations

4. Significant Alternatives to the Proposed Rule

5. Significant Issues Raised by Public Comments

6. Steps DOE Has Taken To Minimize the Economic Impact on Small Manufacturers

C. Review Under the Paperwork Reduction Act

D. Review Under the National Environmental Policy Act of 1969

E. Review Under Executive Order 13132

F. Review Under Executive Order 12988

G. Review Under the Unfunded Mandates Reform Act of 1995

H. Review Under the Treasury and General Government Appropriations Act, 1999

I. Review Under Executive Order 12630

J. Review Under the Treasury and General Government Appropriations Act, 2001

K. Review Under Executive Order 13211

L. Review Under the Information Quality Bulletin for Peer Review

VII. Public Participation

A. Attendance at the Public Meeting

B. Procedure for Submitting Prepared General Statements for Distribution

C. Conduct of the Public Meeting

D. Submission of Comments

E. Issues on Which DOE Seeks Comment

VIII. Approval of the Office of the Secretary

I. Summary of the Proposed Rule

Title III, Part B of the Energy Policy and Conservation Act of 1975 (EPCA or the Act), Public Law 94-163 (42 U.S.C. 6291-6309, as codified), established the Energy Conservation Program for “Consumer Products Other Than Automobiles.” Part C of Title III of EPCA (42 U.S.C. 6311-6317) established a similar program for “Certain Industrial Equipment,” including distribution transformers.

Pursuant to EPCA, any new or amended energy conservation standard that the Department of Energy (DOE) prescribes for certain equipment, such as distribution transformers, shall be designed to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A) and 6316(a)). Furthermore, the new or amended standard must result in a significant conservation of energy. (42 U.S.C. 6295(o)(3)(B) and 6316(a)). In accordance with these and other statutory provisions discussed in this notice, DOE proposes amended energy conservation standards for distribution transformers. The proposed standards are summarized in the following tables: Table I.1, through Table I.3 that describe the covered equipment classes and proposed trial standard levels (TSLs), Table I.4 that shows the mapping of TSL to energy efficiency levels (ELs),

and Table I.5 through Table I.8 which show the proposed standard in terms of minimum electrical efficiency. These proposed standards, if adopted, would apply to all covered distribution transformers listed in the tables and manufactured in, or imported into, the

United States on or after January 1, 2016. As discussed in section IV.C.8 of this notice, any distribution transformer with a kVA rating falling between the kVA ratings shown in the tables shall meet a minimum energy efficiency level calculated by a linear interpolation of the minimum efficiency requirements of the kVA ratings immediately above and below that rating.

For editorial reasons, upon codification in the U.S. Code, Parts B and C were redesignated as Parts A and A-1, respectively.

A detailed description of the mapping of trial standard level to energy efficiency levels can be found in the Technical Support Document, chapter 10 section 10.2.2.3 pg 10-10.

kVA is an abbreviation for kilovolt-ampere, which is a capacity metric used by industry to classify transformers. A transformer's kVA rating represents its output power when it is fully loaded (

i.e.,

100 percent).

Table I.1—Proposed Energy Conservation Standards for Liquid-Immersed Distribution Transformers (Compliance Starting January 1, 2016)

Equipment class

Design line

Type

Phase count

BIL

Proposed TSL

1, 2 and 3

Liquid-immersed

Any

4 and 5

Liquid-immersed

Any

Note:

BIL means “basic impulse insulation level.”

Table I.2—Proposed Energy Conservation Standards for Low-Voltage, Dry-Type Distribution Transformers (Compliance Starting January 1, 2016)

Equipment class

Design line

Type

Phase count

BIL

Proposed TSL

Low-voltage, dry-type

≤10 kV

7 and 8

Low-voltage, dry-type

≤10 kV

Note:

BIL means “basic impulse insulation level.”

Table I.3—Proposed Energy Conservation Standards for Medium-Voltage, Dry-Type Distribution Transformers (Compliance Starting January 1, 2016)

Equipment class

Design line

Type

Phase count

BIL

Proposed TSL

9 and 10

Medium-voltage, dry-type

25-45 kV

9 and 10

Medium-voltage, dry-type

25-45 kV

11 and 12

Medium-voltage, dry-type

46-95 kV

11 and 12

Medium-voltage, dry-type

46-95 kV

13A and 13B

Medium-voltage, dry-type

≥96 kV

13A and 13B

Medium-voltage, dry-type

≥96 kV

Note:

BIL means “basic impulse insulation level,” and measures how resistant a transformer's insulation is to large voltage transients.

Table I.4—Trial Standard Level to Energy Efficiency Level Mapping for Proposed Energy Conservation Standard

Type

Design line

Phase count

Proposed TSL

Energy efficiency level

Liquid-immersed

Base

Low-voltage, dry-type

Base

Medium-voltage, dry-type

13A

13B

Table I.5—Proposed Electrical Efficiencies for all Liquid-Immersed Distribution Transformer Equipment Classes (Compliance Starting January 1, 2016)

Standards by kVA and equipment class

Equipment class 1

kVA

Equipment class 2

kVA

98.70

98.65

98.82

98.83

98.95

98.92

37.5

99.05

99.03

99.11

112.5

99.11

99.19

150

99.16

100

99.25

225

99.23

167

99.33

300

99.27

250

99.39

500

99.35

333

99.43

750

99.40

500

99.49

1000

99.43

1500

99.48

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

Standards by kVA and equipment class

Equipment class 3

kVA

Equipment class 4

kVA

97.73

97.44

98.00

97.95

37.5

98.20

98.31

98.47

98.50

112.5

98.66

100

98.60

150

98.78

167

98.75

225

98.92

250

98.87

300

99.02

333

98.94

500

99.17

750

99.27

1000

99.34

Table I.7—Proposed Electrical Efficiencies for all Medium-Voltage Dry-Type Distribution Transformer Equipment Classes (Compliance Starting January 1, 2016)

Standards by kVA and equipment class

Equipment class 5

kVA

Equipment class 6

kVA

Equipment class 7

kVA

Equipment class 8

kVA

Equipment class 9

kVA

Equipment class 10

kVA

98.10

97.50

97.86

97.18

98.33

97.90

98.12

97.63

37.5

98.49

98.10

37.5

98.30

97.86

98.60

98.33

98.42

98.13

98.73

112.5

98.52

98.57

112.5

98.36

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

A. Benefits and Costs to Consumers

For the purposes of this document, the “consumers” of distribution transformers are referred to as “customers.” Customers refer to electric utilities in the case of liquid-immersed transformers, and to utilities and building owners in the case of dry-type transformers.

Table I.8 presents DOE's evaluation of the economic impacts of the proposed standards on customers of distribution transformers, as measured by the average life-cycle cost (LCC) savings and the median payback period (PBP). DOE measures the impacts of standards relative to a base case that reflects likely trends in the distribution transformer market in the absence of amended standards. The base case predominantly consists of products at the baseline efficiency levels evaluated for each representative unit, which correspond to the existing energy conservation standard level of efficiency for distribution transformers established either in DOE's 2007 rulemaking or by EPACT 2005. The average LCC savings are positive for all but two of the design lines, for which customers are not impacted by the proposed standards. (Throughout this document, “distribution transformers” are also referred to as simply “transformers.”)

Table I.8—Impacts of Proposed Standards on Customers of Distribution Transformers

Design Line

Average LCC savings (2010$)

Median payback period (years)

Liquid-Immersed

20.2

* N/A

2,413

6.3

862

5.0

7,787

4.0

Low-Voltage, Dry-Type

* N/A

1,714

4.5

2,476

8.4

Medium-Voltage, Dry-Type

849

2.6

4,791

8.8

1,043

10.7

6,934

9.0

13A

16.5

13B

4,709

12.5

* No consumers are impacted by the proposed standard because no change from the minimum efficiency standard is proposed for design lines 2 and 6.

B. Impact on Manufacturers

The industry net present value (INPV) is the sum of the discounted cash flows to the industry from the base year through the end of the analysis period (2011 through 2045). Using a real discount rate of 7.4 percent for liquid-immersed distribution transformers, 9 percent for medium-voltage dry-type distribution transformers, and 11.1 percent for low-voltage dry- type distribution transformers, DOE estimates that the industry net present value (INPV) for manufacturers of liquid-immersed, medium-voltage dry-type and low-voltage dry-type distribution transformers is $625 million, $91 million, and $220 million, respectively, in 2011$. Under the proposed standards, DOE expects that liquid-immersed manufacturers may lose up to 6.3 percent of their INPV, which is approximately $39.6 million; medium-voltage manufacturers may lose up to 7.1 percent of their INPV, which is approximately $6.5 million; and low-voltage dry-type manufacturers may lose up to 7.7 percent of their INPV, which is approximately $16.8 million. Additionally, based on DOE's interviews with the manufacturers of distribution transformers, DOE does not expect any plant closings or significant loss of employment.

C. National Benefits

DOE's analyses indicate that the proposed standards would save a significant amount of energy—an estimated 1.58 quads over 30 years (2016-2045). In addition, DOE expects the energy savings from the proposed standards to be equivalent to the energy output from 2.40 gigawatts (GW) of generating capacity by 2045.

The cumulative national net present value (NPV) of total consumer costs and savings of the proposed standards for distribution transformers sold in 2016-2045, in 2010$, ranges from $2.9 billion (at a 7-percent discount rate) to $12.2 billion (at a 3-percent discount rate) over 30 years (2016-2045). This NPV expresses the estimated total value of future operating cost savings minus the estimated increased equipment costs for distribution transformers purchased in 2016-2045, discounted to 2010.

In addition, the proposed standards would have significant environmental benefits. The energy savings are expected to result in cumulative greenhouse gas emission reductions of 122.1 million metric tons (Mt)

of carbon dioxide (CO

) from 2016-2045. During this period, the proposed standards are expected to result in emissions reductions of 99.7 thousand tons of nitrogen oxides (NO

) and 0.819 tons of mercury (Hg).

A metric ton is equivalent to 1.1 short tons. A short ton is equal to 2,000 pounds. Results for NO

and Hg are presented in short tons (referred to here as simply “tons.”)

DOE calculates emissions reductions relative to the most recent version of the Annual Energy Outlook (AEO) Reference case forecast. This forecast accounts for emissions reductions from in-place regulations, including the Clean Air Interstate Rule (CAIR, 70 FR 25162 (May 12, 2005)), but not the Clean Air Mercury Rule (CAMR, 70 FR 28606 (May 18, 2005)). Subsequent regulations, including the Cross-State Air Pollution rule issued on July 6, 2011, do not appear in the AEO forecast at this time.

The value of the CO

reductions is calculated using a range of values per metric ton of CO

(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 CO

emissions reduction is between $0.71 and $12.5 billion, expressed in 2010$ and discounted to 2010. DOE also estimates the net present monetary value of the NO

emissions reduction, expressed in 2010$ and discounted to 2010, is between $0.069 billion at a 7-percent discount rate and $0.210 billion at a 3-percent discount rate.

DOE is aware of multiple agency efforts to determine the appropriate range of values used in evaluating the potential economic benefits of reduced Hg emissions. DOE has decided to await further guidance regarding consistent valuation and reporting of Hg emissions before it once again monetizes Hg in its rulemakings.

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

Table I.9—Summary of National Economic Benefits and Costs of Proposed Distribution Transformer Energy Conservation Standards

Category

Present value

billion 2010$

Discount rate

(percent)

Benefits:

Operating Cost Savings

5.58

17.44

Reduction Monetized Value (at $4.9/t) *

0.71

Reduction Monetized Value (at $22.3/t) *

4.13

Reduction Monetized Value (at $36.5/t) *

7.20

2.5

Reduction Monetized Value (at $67.6/t) *

12.54

Reduction Monetized Value (at $2,537/ton) *

0.069

0.210

Total Benefits**

9.78

21.7

Costs:

Incremental Installed Costs

2.67

5.21

Net Benefits:

Including CO

and NO

7.10

16.5

* The CO

values represent global monetized values of the SCC in 2010 under several scenarios. The values of $4.9, $22.1, and $36.3 per metric ton (t) are the averages of SCC distributions calculated using 5%, 3%, and 2.5% discount rates, respectively. The value of $67.1/t represents the 95th percentile of the SCC distribution calculated using a 3% discount rate. A metric ton is equivalent to 1.1 short tons. A short ton is equal to 2,000 pounds. Results for NO

are presented in short tons (referred to here as simply “tons.”)

** Total Benefits for both the 3% and 7% cases are derived using the SCC value calculated at a 3% discount rate, and the average of the low and high NO

values used in DOE's analysis.

The benefits and costs of today's proposed standards, for equipment sold in 2016-2045, can also be expressed in terms of annualized values. The annualized monetary values are the sum of: (1) The annualized national economic value of the benefits from consumer operation of equipment that meets the proposed standards (consisting primarily of operating cost savings from using less energy minus increases in equipment purchase and installation costs, which is another way of representing consumer NPV), and (2) the annualized monetary value of the benefits of emission reductions, including CO

emission reductions.

DOE used a two-step calculation process to convert the time-series of costs and benefits into annualized values. First, DOE calculated a present value in 2011, the year used for discounting the NPV of total consumer costs and savings, for the time-series of costs and benefits using discount rates of 3 and 7 percent for all costs and benefits except for the value of CO

reductions. For the latter, DOE used a range of discount rates, as shown in Table I.9. From the present value, DOE then calculated the fixed annual payment over a 30-year period, starting in 2011 that yields the same present value. The fixed annual payment is the annualized value. Although DOE calculated annualized values, this does not imply that the time-series of cost and benefits from which the annualized values were determined would be a steady stream of payments.

Although combining the values of operating savings and CO

emission reductions provides a useful perspective, two issues should be considered. First, the national operating savings are domestic U.S. consumer monetary savings that occur as a result of market transactions while the value of CO

reductions is based on a global value. Second, the assessments of operating cost savings and CO

savings are performed with different methods that use different time frames for analysis. The national operating cost savings is measured for the lifetime of distribution transformers shipped in 2016-2045. The SCC values, on the other hand, reflect the present value of some future climate-related impacts resulting from the emission of one metric ton of carbon dioxide in each year. These impacts continue well beyond 2100.

Estimates of annualized benefits and costs of today's proposed standards are shown in Table I.10. (All monetary values below are expressed in 2010$.) The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO

reduction, for which DOE used a 3-percent discount rate along with the SCC series corresponding to a value of $22.3/metric ton in 2010, the cost of the standards proposed in today's proposed standards is $302 million per year in increased equipment costs. The benefits are $631 million per year in reduced equipment operating costs, $244 million in CO

reductions, and $7.78 million in reduced NO

emissions. In this case, the net benefit amounts to $581 million per year. Using a 3-percent discount rate for all benefits and costs and the SCC series corresponding to a value of $22.3/metric ton in 2010, the cost of the standards proposed in today's rule is $308 million per year in increased equipment costs. The benefits are $1,026 million per year in reduced operating costs, $244 million in CO

reductions, and $12.4 million in reduced NO

emissions. In this case, the net benefit amounts to $975 million per year.

Table I.10—Annualized Benefits and Costs of Proposed Standards for Distribution Transformers

Discount rate

Monetized (million 2010$/year)

Primary estimate *

Low net

benefits estimate *

High net benefits estimate *

Benefits:

Operating Cost Savings

631

594

659.

1,026

950

1,075.

Reduction at $4.9/t**

58.6

58.6.

Reduction at $22.3/t**

244

244.

Reduction at $36.5/t**

2.5%

389

389.

Reduction at $67.6/t**

742

742.

Reduction at $2,537/ton**

7.78

7.78.

12.4

12.4.

Total †

7% plus CO

range

697 to 1380

660 to 1343

726 to 1409.

883

846

911.

3% plus CO

range

1097 to 1780

1021 to 1704

1146 to 1829.

1,283

1,207

1,331.

Costs:

Incremental Product Costs

302

338

285.

308

351

289.

Total Net Benefits:

Total †

7% plus CO

range

400 to 1083

327 to 1010

445 to 1128.

581

507

626.

3% plus CO

range

789 to 1472

670 to 1353

857 to 1540.

975

855

1,043.

* The Primary, Low Net Benefits, and High Net Benefits Estimates utilize forecasts of energy prices from the

AEO 2011

reference case, Low Economic Growth case, and High Economic Growth case, respectively. In addition, incremental product costs reflect no change in the Primary estimate, rising product prices in the Low Net Benefits estimate, and declining product prices in the High Net Benefits estimate.

** The CO

values represent global values (in 2010$) of the social cost of CO

emissions in 2010 under several scenarios. The values of $4.9, $22.3, and $36.5 per metric ton are the averages of SCC distributions calculated using 5%, 3%, and 2.5% discount rates, respectively. The value of $67.6 per metric ton represents the 95th percentile of the SCC distribution calculated using a 3% discount rate. The value for NOX (in 2010$) is the average of the low and high values used in DOE's analysis.

Total Benefits for both the 3% and 7% cases are derived using the SCC value calculated at a 3% discount rate, which is $22.3/metric ton in 2010 (in 2010$). In the rows labeled as “7% plus CO

range” and “3% plus CO

range,” the operating cost and NO

benefits are calculated using the labeled discount rate, and those values are added to the full range of CO

values.

DOE has tentatively concluded that the proposed standards represent the maximum improvement in energy efficiency that is technologically feasible and economically justified, and would result in the significant conservation of energy. DOE further notes that equipment achieving these proposed standard levels are already commercially available for at least some, if not most, equipment classes covered by today's proposal. Based on the analyses described above, DOE has tentatively concluded that the benefits of the proposed standards to the Nation (energy savings, positive NPV of consumer benefits, consumer LCC savings, and emission reductions) would outweigh the burdens (loss of INPV for manufacturers and LCC increases for some consumers).

DOE also considered more stringent energy efficiency levels as trial standard levels, and is still considering them in this rulemaking. However, DOE has tentatively concluded that, in some cases, the potential burdens of the more stringent energy efficiency levels would outweigh the projected benefits. Based on consideration of the public comments DOE receives in response to this notice and related information collected and analyzed during the course of this rulemaking effort, DOE may adopt energy efficiency levels presented in this notice that are either higher or lower than the proposed standards, or some combination of energy efficiency level(s) that incorporate the proposed standards in part.

II. Introduction

The following section briefly discusses the statutory authority underlying today's proposal, as well as some of the relevant historical background related to the establishment of energy conservation standards for distribution transformers.

A. Authority

The Energy Policy Act of 1992 (EPACT 1992), Public Law 102-486, amended EPCA and directed the Department to prescribe energy conservation standards for distribution transformers. (42 U.S.C. 6317(a)) The Energy Policy Act of 2005 (EPACT 2005), Public Law 109-25, amended EPCA to establish energy conservation standards for low-voltage, dry-type distribution transformers.

(42 U.S.C. 6295(y)) Under 42 U.S.C. 6313(a)(6)(C)(i), DOE must review energy conservation standards for commercial and industrial equipment and amend the standards as needed no later than six years from the issuance of a final rule establishing or amending a standard for a covered product. A final rule establishing any amended standards based on such notice of

proposed rulemaking (NOPR) must be completed within two years of publication of the NOPR. (42 U.S.C. 6313(a)(6)(C)(iii)(I)).

For editorial reasons, upon codification in the U.S. Code, Parts B and C were redesignated as Parts A and A-1, respectively

EPACT 2005 established that the efficiency of a low-voltage dry-type distribution transformer manufactured on or after January 1, 2007 shall be the Class I Efficiency Levels for distribution transformers specified in Table 4-2 of the “Guide for Determining Energy Efficiency for Distribution Transformers” published by the National Electrical Manufacturers Association (NEMA TP 1-2002).

DOE publishes today's proposed rule pursuant to Part C of Title III, which establishes an energy conservation program for covered equipment that consists essentially of four parts: (1) Testing; (2) labeling; (3) the establishment of Federal energy conservation standards; and (4) compliance certification and enforcement procedures. For those distribution transformers for which DOE determines that energy conservation standards are warranted, the DOE test procedures must be the “Standard Test Method for Measuring the Energy Consumption of Distribution Transformers” prescribed by the National Electrical Manufacturers Association (NEMA TP 2-1998), subject to review and revision by the Secretary in accordance with certain criteria and conditions. (42 U.S.C. 6293(b)(10), 6314(a)(2)-(3) and 6317(a)(1)) Manufacturers of covered equipment must use the prescribed DOE test procedure as the basis for certifying to DOE that their equipment complies with the applicable energy conservation standards adopted under EPCA and when making representations to the public regarding the energy use or efficiency of those types of equipment. (42 U.S.C. 6314(d)) The DOE test procedures for distribution transformers currently appear at title 10 of the Code of Federal Regulations (CFR) part 431, subpart K, appendix A.

DOE must follow specific statutory criteria for prescribing amended standards for covered equipment. As indicated above, any amended standard for covered equipment must be designed to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A) and 6316(a)) Furthermore, DOE may not adopt any amended standard that would not result in the significant conservation of energy. (42 U.S.C. 6295(o)(3) and 6316(a)) Moreover, DOE may not prescribe a standard: (1) For certain equipment, including distribution transformers, if no test procedure has been established for the equipment, or (2) if DOE determines by rule that the proposed standard is not technologically feasible or economically justified. (42 U.S.C. 6295(o)(3)(A)-(B) and 6316(a)) In deciding whether a proposed amended standard is economically justified, DOE must determine whether the benefits of the standard exceed its burdens. (42 U.S.C. 6295(o)(2)(B)(i) and 6316(a)) DOE must make this determination after receiving comments on the proposed standard, and by considering, to the greatest extent practicable, the following seven factors:

1. The economic impact of the standard on manufacturers and consumers of the equipment subject to the standard;

2. The savings in operating costs throughout the estimated average life of the covered equipment in the type (or class) compared to any increase in the price, initial charges, or maintenance expenses for the covered products that are likely to result from the imposition of the standard;

3. The total projected amount of energy, or as applicable, water, savings likely to result directly from the imposition of the standard;

4. Any lessening of the utility or the performance of the covered equipment likely to result from the imposition of the standard;

5. The impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from the imposition of the standard;

6. The need for national energy and water conservation; and

7. Other factors the Secretary of Energy (Secretary) considers relevant. (42 U.S.C. 6295(o)(2)(B)(i) and 6316(a))

EPCA, as codified, also contains what is known as an “anti-backsliding” provision, which prevents the Secretary from prescribing any amended standard that either increases the maximum allowable energy use or decreases the minimum required energy efficiency of a covered product. (42 U.S.C. 6295(o)(1) and 6316(a)) Also, the Secretary may not prescribe an amended or new standard if interested persons have established by a preponderance of the evidence that the standard is likely to result in the unavailability in the United States of any covered product type (or class) of performance characteristics (including reliability), features, sizes, capacities, and volumes that are substantially the same as those generally available in the United States. (42 U.S.C. 6295(o)(4) and 6316(a))

Further, EPCA, as codified, establishes a rebuttable presumption that an energy conservation standard is economically justified if the Secretary finds that the additional cost to the consumer of purchasing equipment complying with the energy conservation standard will be less than three times the value of the energy savings a consumer will receive in the first year of using the equipment. (See 42 U.S.C. 6295(o)(2)(B)(iii) and 6316(a))

Additionally, 42 U.S.C. 6295(q)(1), as applied to covered equipment via 42 U.S.C. 6316(a), specifies requirements when promulgating a standard for a type or class of covered equipment that has two or more subcategories. DOE must specify a different standard level than that which applies generally to such type or class of equipment for any group of covered equipment that has the same function or intended use if DOE determines that equipment within such group (A) consumes a different kind of energy from that consumed by other covered equipment within such type (or class); or (B) has a capacity or other performance-related feature which other equipment within such type (or class) does not have and such feature justifies a higher or lower standard. (42 U.S.C. 6294(q)(1) and 6316(a)) In determining whether a performance-related feature justifies a different standard for a group of equipment, DOE must consider such factors as the utility to the consumer of the feature and other factors DOE deems appropriate.

Id.

Any rule prescribing such a standard must include an explanation of the basis on which such higher or lower level was established. (42 U.S.C. 6295(q)(2) and 6316(a))

Federal energy conservation requirements generally supersede State laws or regulations concerning energy conservation testing, labeling, and standards. (42 U.S.C. 6297(a)-(c) and 6316(a)) DOE may, however, grant waivers of Federal preemption for particular State laws or regulations, in accordance with the procedures and other provisions set forth under 42 U.S.C. 6297(d)).

DOE has also reviewed this regulation pursuant to Executive Order (EO) 13563, issued on January 18, 2011 (76 FR 3281, Jan. 21, 2011). EO 13563 is supplemental to and explicitly reaffirms the principles, structures, and definitions governing regulatory review established in EO 12866. To the extent permitted by law, agencies are required by EO 13563 to: (1) Propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits and costs are difficult to quantify); (2) tailor regulations to impose the least burden on society, consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations; (3) select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity); (4) to the extent feasible, specify

performance objectives, rather than specifying the behavior or manner of compliance that regulated entities must adopt; and (5) identify and assess available alternatives to direct regulation, including providing economic incentives to encourage the desired behavior, such as user fees or marketable permits, or providing information upon which choices can be made by the public.

DOE emphasizes as well that EO 13563 requires agencies to use the best available techniques to quantify anticipated present and future benefits and costs as accurately as possible. In its guidance, the Office of Information and Regulatory Affairs has emphasized that such techniques may include identifying changing future compliance costs that might result from technological innovation or anticipated behavioral changes. For the reasons stated in the preamble, DOE believes that today's notice of proposed rulemaking (NOPR) is consistent with these principles, including the requirement that, to the extent permitted by law, benefits justify costs and that net benefits are maximized.

B. Background

1. Current Standards

On August 8, 2005, the Energy Policy Act of 2005 (EPACT 2005) amended EPCA to establish energy conservation standards for low-voltage, dry-type distribution transformers (LVDTs).

(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.

Table II.1—Federal Energy Efficiency Standards for Low-Voltage, Dry-Type Distribution Transformers

Single-phase

kVA

Efficiency (%)

Three-phase

kVA

Efficiency (%)

97.7

97.0

98.0

97.5

37.5

98.2

97.7

98.3

98.0

98.5

112.5

98.2

100

98.6

150

98.3

167

98.7

225

98.5

250

98.8

300

98.6

333

98.9

500

98.7

750

98.8

1000

98.9

Note:

Efficiencies are determined at the following reference conditions: (1) for no-load losses, at the temperature of 20 °C, and (2) for load-losses, at the temperature of 75 °C and 35 percent of nameplate load.

DOE incorporated these standards into its regulations, along with the standards for several other types of products and equipment, in a final rule published on October 18, 2005. 70 FR 60407, 60416—60417. These standards appear at 10 CFR 431.196(a).

On October 12, 2007, DOE published a final rule that established energy conservation standard for liquid-immersed distribution transformers and medium-voltage dry-type distribution transformers, which are shown in Table II.2 and Table II.3, respectively. 72 FR 58190, 58239-40. These standards are codified at 10 CFR 431.196(b) and (c).

Table II.2—Energy Conservation Standards for Liquid-Immersed Distribution Transformers

Single-phase

kVA

Efficiency (%)

Three-phase

kVA

Efficiency (%)

98.62

98.36

98.76

98.62

98.91

98.76

37.5

99.01

98.91

99.08

112.5

99.01

99.17

150

99.08

100

99.23

225

99.17

167

99.25

300

99.23

250

99.32

500

99.25

333

99.36

750

99.32

500

99.42

1000

99.36

667

99.46

1500

99.42

833

99.49

2000

99.46

2500

99.49

Note:

All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-Procedure. 10 CFR part 431, subpart K, appendix A.

Table II.3—Energy Conservation Standards for Medium-Voltage, Dry-Type Distribution Transformers

Single-phase

BIL

kVA

20-45 kV

Efficiency (%)

46-95 kV

Efficiency (%)

≥96 kV

Efficiency (%)

Three-phase

BIL

kVA

20-45 kV

Efficiency (%)

46-95 kV

Efficiency (%)

≥96 kV

Efficiency (%)

98.10

97.86

97.50

97.18

98.33

98.12

97.90

97.63

37.5

98.49

98.30

98.10

97.86

98.60

98.42

98.33

98.12

98.73

98.57

98.53

112.5

98.49

98.30

100

98.82

98.67

98.63

150

98.60

98.42

167

98.96

98.83

98.80

225

98.73

98.57

98.53

250

99.07

98.95

98.91

300

98.82

98.67

98.63

333

99.14

99.03

98.99

500

98.96

98.83

98.80

500

99.22

99.12

99.09

750

99.07

98.95

98.91

667

99.27

99.18

99.15

1000

99.14

99.03

98.99

833

99.31

99.23

99.20

1500

99.22

99.12

99.09

2000

99.27

99.18

99.15

2500

99.31

99.23

99.20

Note:

BIL means “basic impulse insulation level.”

Note:

All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR part 431, subpart K, appendix A.

2. History of Standards Rulemaking for Distribution Transformers

In a notice published on October 22, 1997 (62 FR 54809), DOE stated that it had determined that energy conservation standards were warranted for electric distribution transformers, relying in part on two reports by DOE's Oak Ridge National Laboratory (ORNL). These reports—

Determination Analysis of Energy Conservation Standards for Distribution Transformers,

ORNL-6847 (1996) and

Supplement to the “Determination Analysis,”

ORNL-6847 (1997)—are available on the DOE Web site at:

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html.

In 2000, DOE issued its Framework Document for Distribution Transformer Energy Conservation Standards Rulemaking, describing its proposed approach for developing standards for distribution transformers, and held a public meeting to discuss the Framework Document. The document is available on the above-referenced DOE Web site. Stakeholders also submitted written comments on the document, addressing a range of issues.

Subsequently, DOE issued draft reports as to certain of the key analyses contemplated by the Framework Document.

It received comments from stakeholders on these draft reports and, on July 29, 2004, published an advance notice of proposed rulemaking (ANOPR) for distribution transformer standards. 69 FR 45376. DOE then held a webcast on material it had published relating to the ANOPR, followed by a public meeting on the ANOPR on September 28, 2004. In August 2005, DOE issued a draft of certain of the analyses on which it planned to base the standards for liquid-immersed and medium-voltage, dry-type distribution transformers, along with documents that supported the draft analyses.

DOE did this to enable stakeholders to review the analyses and make recommendations as to standard levels.

Copies of all the draft analyses published before the ANOPR are available on DOE's Web site:

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis.html

Copies of the four draft NOPR analyses published in August 2005 are available on DOE's Web site:

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis_nopr.html

On April 27, 2006, DOE published its Final Rule on Test Procedures for Distribution Transformers. The rule: (1) Established the procedure for sampling and testing distribution transformers so that manufacturers can make representations as to their efficiency, as well as establish that they comply with Federal standards; and (2) contained enforcement provisions, outlining the procedure the Department would follow should it initiate an enforcement action against a manufacturer. 71 FR 24972 (codified at 10 CFR 431.198).

On August 4, 2006, DOE published a NOPR in which it proposed energy conservation standards for distribution transformers (the 2006 NOPR). 71 FR 44355. Concurrently, DOE also issued a technical support document (TSD) that incorporated the analyses it had performed for the proposed rule, including several spreadsheets that remain available on DOE's Web site.

The spreadsheets developed for this rulemaking proceeding are available at:

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis_nopr.html

Some commenters asserted that DOE's proposed standards might adversely affect replacement of distribution transformers in certain space-constrained (

e.g.,

vault) installations. In response, DOE issued a notice of data availability and request for comments on this and another issue. 72 FR 6186 (Feb. 9, 2007) (the NODA). In the NODA, DOE sought comment on whether it should include in the LCC analysis potential costs related to size constraints of distribution transformers installed in vaults. DOE also outlined different approaches as to how it might account for additional installation costs for these space-constrained applications and requested comments on linking energy efficiency levels for three-phase liquid-immersed units with those of single-phase units. Finally, DOE addressed how it was inclined to consider a final standard that is based on energy efficiency levels derived from trial standard level (TSL) 2 and TSL 3 for three-phase units and TSLs 2, 3 and 4 for single-phase units. 72 FR 6189. Based on comments on the 2006 NOPR, and the NODA, DOE created new TSLs to address the treatment of three-phase units and single-phase units. In October 2007, DOE published a final rule that created the current energy conservation standards for liquid-immersed and medium-voltage dry-type distribution transformers. 72 FR 58190 (October 12,

2007) (the 2007 Final Rule) (codified at 10 CFR 431.196(b)-(c)).

The above paragraphs summarize development of the 2007 Final Rule. The preamble to the rule included additional, detailed background information on the history of that rulemaking. 72 FR 58194-96.

After the publication of the 2007 Final Rule, certain parties filed petitions for review in the United States Courts of Appeals for the Second and Ninth Circuits, challenging the rule. Several additional parties were permitted to intervene in support of these petitions. (All of these parties are referred to below collectively as “petitioners.”) The petitioners alleged that, in developing its energy conservation standards for distribution transformers, DOE did not comply with certain applicable provisions of EPCA and of the National Environmental Policy Act (NEPA), as amended (42 U.S.C. 4321

et seq.

) DOE and the petitioners subsequently entered into a settlement agreement to resolve the petitions. The settlement agreement outlined an expedited timeline for the Department to determine whether to amend the energy conservation standards for liquid-immersed and medium-voltage dry-type distribution transformers. Under the original settlement agreement, DOE was required to publish by October 1, 2011, either a determination that the standards for these distribution transformers do not need to be amended or a NOPR that includes any new proposed standards and that meets all applicable requirements of EPCA and NEPA. Under an amended settlement agreement, the October 1, 2011, deadline for a DOE determination or proposed rule was extended to February 1, 2012. If DOE finds that amended standards are warranted, DOE must publish a final rule containing such amended standards by October 1, 2012.

On March 2, 2011, DOE published in the

Federal Register

a notice of public meeting and availability of its preliminary TSD for the Distribution Transformer Energy Conservation Standards Rulemaking, wherein DOE discussed and received comments on issues such as equipment classes of distribution transformers that DOE would analyze in consideration of amending the energy conservation standards for distribution transformers, the analytical framework, models and tools it is using to evaluate potential standards, the results of its preliminary analysis, and potential standard levels. 76 FR 11396. The notice is available on the above-referenced DOE Web site. To expedite the rulemaking process, DOE began at the preliminary analysis stage because it believes that many of the same methodologies and data sources that were used during the 2007 rulemaking rule remain valid. On April 5, 2011, DOE held a public meeting to discuss the preliminary TSD. Representatives of manufacturers, trade associations, electric utilities, energy conservation organizations, Federal regulators, and other interested parties attended this meeting. In addition, other interested parties submitted written comments about the TSD addressing a range of issues. These comments are discussed in the following sections of the NOPR.

On July 29, 2011, DOE published in the

Federal Register

a notice of intent to establish a subcommittee under the Energy Efficiency and Renewable Energy Advisory Committee (ERAC), in accordance with the Federal Advisory Committee Act and the Negotiated Rulemaking Act, to negotiate proposed Federal standards for the energy efficiency of medium-voltage dry-type and liquid immersed distribution transformers. 76 FR 45471. Stakeholders strongly supported a consensual rulemaking effort. DOE believed that, in this case, a negotiated rulemaking would result in a better informed NOPR and would minimize any potential negative impact of the NOPR. On August 12, 2011, DOE published in the

Federal Register

a similar notice of intent to negotiate proposed Federal standards for the energy efficiency of low-voltage dry-type distribution transformers. 76 FR 50148. The purpose of the subcommittee was to discuss and, if possible, reach consensus on a proposed rule for the energy efficiency of distribution transformers.

The ERAC subcommittee for medium-voltage liquid-immersed and dry-type distribution transformers consisted of representatives of parties having a defined stake in the outcome of the proposed standards, listed below.

• ABB Inc.

• AK Steel Corporation

• American Council for an Energy-Efficient Economy

• American Public Power Association

• Appliance Standards Awareness Project

• ATI-Allegheny Ludlum

• Baltimore Gas and Electric

• Cooper Power Systems

• Earthjustice

• Edison Electric Institute

• Fayetteville Public Works Commission

• Federal Pacific Company

• Howard Industries Inc.

• LakeView Metals

• Efficiency and Renewables Advisory Committee member

• Metglas, Inc.

• National Electrical Manufacturers Association

• National Resources Defense Council

• National Rural Electric Cooperative Association

• Northwest Power and Conservation Council

• Pacific Gas and Electric Company

• Progress Energy

• Prolec GE

• U.S. Department of Energy

The ERAC subcommittee for medium-voltage liquid-immersed and dry-type distribution transformers held meetings on September 15 through 16, 2011, October 12 through 13, 2011, November 8 through 9, 2011, and November 30 through December 1, 2011; the ERAC subcommittee also held public webinars on November 17 and December 14. During the course of the September 15, 2011, meeting, the subcommittee agreed to its rules of procedure, ratified its schedule of the remaining meetings, and defined the procedural meaning of consensus. The subcommittee defined consensus as unanimous agreement from all present subcommittee members. Subcommittee members were allowed to abstain from voting for an efficiency level; their votes counted neither toward nor against the consensus.

DOE presented its draft engineering, life-cycle cost and national impacts analysis and results. During the meetings of October 12 through 13, 2011, DOE presented its revised analysis and heard from subcommittee members on a number of topics. During the meetings on November 8 through 9, 2011, DOE presented its revised analysis, including life-cycle cost sensitivities based on exclusion ZDMH and amorphous steel as core materials. During the meetings on November 30 through December 1, 2011, DOE presented its revised analysis based on 2011 core-material prices.

At the conclusion of the final meeting, subcommittee members presented their efficiency level recommendations. For medium-voltage liquid-immersed distribution transformers, the advocates, represented by the Appliance Standards Awareness Project (ASAP), recommended efficiency level (also referred to as “EL”) 3 for all design lines (also referred to as “DLs”). The National Electrical Manufacturers Association (NEMA) and AK Steel recommended EL 1 for all DLs except for DL 2, for which no change from the current standard was recommended. Edison Electric Institute (EEI) and ATI Allegheny Ludlum recommended EL1 for DLs 1, 3, and 4 and no change from the current standard or a proposed standard of less

than EL 1 for DLs 2 and 5. Therefore, the subcommittee did not arrive at consensus regarding proposed standard levels for medium-voltage liquid-immersed distribution transformers.

For medium-voltage dry-type distribution transformers, the subcommittee arrived at consensus and recommended a proposed standard of EL2 for DLs 11 and 12, from which the proposed standards for DLs 9, 10, 13A, 13B would be scaled. Transcripts of the subcommittee meetings and all data and materials presented at the subcommittee meetings are available at the DOE Web site at:

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html

The ERAC subcommittee held meetings on September 28, 2011, October 13-14, 2011, November 9, 2011, and December 1-2, 2011, for low-voltage distribution transformers. The ERAC subcommittee also held webinars on November 21, 2011, and December 20, 2011. During the course of the September 28, 2011, meeting, the subcommittee agreed to its rules of procedure, finalized the schedule of the remaining meetings, and defined the procedural meaning of consensus. The subcommittee defined consensus as unanimous agreement from all present subcommittee members. Subcommittee members were allowed to abstain from voting for an efficiency level; their votes counted neither toward nor against the consensus.

The ERAC subcommittee for low-voltage distribution transformers consisted of representatives of parties having a defined stake in the outcome of the proposed standards.

• AK Steel Corporation

• American Council for an Energy-Efficient Economy

• Appliance Standards Awareness Project

• ATI-Allegheny Ludlum

• EarthJustice

• Eaton Corporation

• Federal Pacific Company

• Lakeview Metals

• Efficiency and Renewables Advisory Committee member

• Metglas, Inc.

• National Electrical Manufacturers Association

• Natural Resources Defense Council

• ONYX Power

• Pacific Gas and Electric Company

• Schneider Electric

• U.S. Department of Energy

DOE presented its draft engineering, life-cycle cost and national impacts analysis and results. During the meetings of October 14, 2011, DOE presented its revised analysis and heard from subcommittee members on various topics. During the meetings of November 9, 2011, DOE presented its revised analysis. During the meetings of December 1, 2011, DOE presented its revised analysis based on 2011 core-material prices.

At the conclusion of the final meeting, subcommittee members presented their energy efficiency level recommendations. For low-voltage dry-type distribution transformers, the advocates, represented by ASAP, recommended EL4 for all DLs, NEMA recommended EL 2 for DLs 7 and 8, and no change from the current standard for DL 6. EEI, AK Steel and ATI Allegheny Ludlum recommended EL 1 for DLs 7 and 8, and no change from the current standard for DL 6. The subcommittee did not arrive at consensus regarding a proposed standard for low-voltage dry-type distribution transformers. Transcripts of the subcommittee meetings and all data and materials presented at the subcommittee meetings are available at the DOE Web site at:

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html

III. General Discussion

A. Test Procedures

Section 7(c) of the Process Rule

indicates that DOE will issue a final test procedure, if one is needed, prior to issuing a proposed rule for energy conservation standards. DOE published its test procedure for distribution transformers in the

Federal Register

as a final rule on April 27, 2006. 71 FR 24972.

The Process Rule provides guidance on how DOE conducts its energy conservation standards rulemakings, including the analytical steps and sequencing of rulemaking stages (such as test procedures and energy conservation standards). (10 CFR part 430, Subpart C, Appendix A).

1. General

Currently, DOE requires distribution transformers to comply with standards with their windings in the configuration that produces the greatest losses. (10 CFR 431, Subpart K, Appendix A) During the April 5, 2011, public meeting, DOE addressed issues and solicited comments about amending the energy conservation standards for distribution transformers, the analytical framework and results of its preliminary analysis, and potential energy efficiency standards. At the outset, DOE proposed to amend the test procedure under appendix A to subpart K of 10 CFR part 431, Uniform Test Method for Measuring the Energy Consumption of Distribution Transformers. DOE proposed to allow compliance testing in any secondary configuration and at the lowest basic impulse level (BIL) rating and to require compliance at the lowest BIL at which dual or multiple voltage distribution transformers are rated to operate.

The Northwest Power and Conservation Council (NPCC) and Northwest Energy Efficiency Alliance (NEEA)

jointly submitted comments that the test procedure should adhere to specifications that do not make it difficult for the most challenging designs to comply with the standard, or else these transformer designs may be eliminated from the marketplace. (NPCC/NEEA, No. 11 at p. 2)

NPCC and NEEA further noted that they would support a change to allow manufacturers to test at a single voltage for models with a range of voltage taps that is ± 5 percent, using the middle voltage of that range. (NPCC/NEEA, No. 11 at p. 3) Finally, NPCC and NEEA requested that DOE explicitly explain the benefit of any changes to the test procedure, since certain changes could make future and past ratings more difficult to consistently compare. (NPCC/NEEA, No. 11 at p. 3)

The Northwest Power and Conservation Council (NPCC) and Northwest Energy Efficiency Alliance (NEEA) submitted joint comments and are hereinafter referred to as NPCC/NEEA.

This short-hand citation format is used throughout this document. For example: “(NPCC/NEEA, No. 11 at p. 2)” refers to a (1) a joint statement that was submitted by NPCC and NEEA and is recorded at

http://www.regulations.gov/#!home

in the docket under “Energy Conservation Standards for Distribution Transformers,” Docket Number EERE-2010-BT-STD-0048, as comment number 11; and (2) a passage that appears on page 2 of that statement.

NEMA commented that distribution transformers are rated to operate at multiple kilovolt ampere (kVA) ratings corresponding to passive cooling, active cooling, or a combination of both. NEMA stated that the regulation should clarify that transformers with multiple kVA ratings should comply at the base rating (passive cooling). (NEMA, No. 13 at pp. 2-3)

Although DOE does not intend to eliminate features offering unique utility from the marketplace, it wishes to gather more information on the specific efficiency differences between winding configurations as well as the relative frequencies of their uses. With this in mind and considering the comments, DOE proposes to continue requiring compliance testing in the primary and secondary winding configuration with the highest losses, as is currently required under appendix A to subpart K of 10 CFR part 431. DOE agrees that passive cooling is the most common

mode of operation for distribution transformers employed in power distribution and clarifies that manufacturers are only required to demonstrate compliance at kVA ratings that correspond to passive cooling.

Passive cooling is cooling that does not require fans, pumps, or other energy-consuming means of increasing thermal convection.

DOE requests comment and corroborating data on how often distribution transformers are operated with their primary and secondary windings in different configurations, and on the magnitude of the additional losses in less efficient configurations.

2. Multiple kVA Ratings

Currently, DOE is nonspecific on which kVA rating should be used to assess compliance in the case of distribution transformers with more than one kVA.

ABB's recommendations on transformers with multiple kVA ratings depended on how the transformer was cooled. For naturally-cooled transformers, ABB recommended that they should be required to meet the efficiency standard for every kVA rating. However, ABB suggested that forced-cooled transformers should only have to meet the efficiency standard at the naturally-cooled kVA rating. This is because the forced-cooled rating, which is meant only for temporary overload conditions, is dependent on the operation of auxiliary cooling fans that have a lower operating life than the transformer. (ABB, No. 14 at pp. 3-5)

DOE has received nearly unanimous feedback that transformers in distribution applications are seldom designed to rely on active cooling even occasionally and that the majority of designs lack active cooling altogether. DOE wishes to clarify that manufacturers are only required to demonstrate compliance at kVA ratings that correspond to passive cooling.

3. Dual/Multiple-Voltage Basic Impulse Level

Currently, DOE requires distribution transformers to comply with standards using the BIL rating of the winding configuration that produces the greatest losses. (10 CFR 431, Subpart K, Appendix A)

Several stakeholders commented that distribution transformers with multiple BIL ratings should comply with the efficiency based on the highest BIL rating, as the transformer core is based on the highest BIL rating. (Hammond (HPS), No. 3 at p. 1; NEMA, No. 13 at p. 2; and FPT, No. 27 at p. 13) NEMA noted that for dual/multiple distribution transformers with varying BIL levels, DOE should align its requirements with those of the Institute of Electrical and Electronics Engineers (IEEE) standards (C57.12.00 for liquid-filled, NEMA ST20-1992:3.3 for low-voltage) and require testing in the “as shipped” condition, which would base the efficiency on the highest BIL rating, matching IEEE and industry practice. (NEMA, No. 13 at p. 2) Federal Pacific Transformers (FPT) stated that medium-voltage distribution transformers with multiple configurations should be held to the efficiency standard of the configuration with the highest BIL rating because the distribution transformer is required to be much larger for the higher BIL rating and, therefore, cannot reasonably meet the energy efficiency level of the lower BIL rating. (FPT, No. 27 at p. 13) FPT also expressed their support for testing on the highest BIL efficiency rating for re-connectable distribution transformers. (FPT, Pub. Mtg. Tr., No. 34 at p. 40)

This short-hand citation format for the public meeting transcript is used throughout this document. For example: “(FPT, Pub. Mtg. Tr., No. 34 at p. 40)” refers to a comment on the page number of the transcript of the “Public Meeting on Energy Conservation Standard Preliminary Analysis for Distribution Transformers,” held in Washington, DC, April 5, 2011.

ABB commented that DOE should not change the test requirement to allow compliance at the lowest BIL rating. According to ABB, there is no way to ascertain which operating condition a distribution transformer will use over its lifetime. ABB stated that DOE should require that the efficiency be met on any operational configuration for which the distribution transformer is designed for continuous operation. (ABB, No. 14 at p. 2)

DOE needs to gather more information in order to be certain that allowing compliance at any BIL rating would not result in lowered energy savings relative to what is predicted by DOE's analysis. DOE proposes to maintain the current requirement to comply in the configuration that gives rise to the greatest losses.

4. Dual/Multiple-Voltage Primary Windings

Currently, DOE requires manufacturers to comply with energy conservation standards with distribution transformer primary windings (“primaries”) in the configuration that produces the highest losses. (10 CFR 431, Subpart K, Appendix A)

Where DOE invited additional comments about the test procedures, Howard Industries added that, under the presumption that DOE would allow compliance testing in any of the secondary configurations (“secondaries”), DOE should insert the word “primary” into the testing requirements [at section 5.0, Determining the Efficiency Value of the Transformer, under appendix A to subpart K of 10 CFR part 431], and require the manufacturer to “determine the basic model's efficiency at the `primary' voltage at which the highest losses occur or at each `primary' voltage at which the distribution transformer is rated to operate.” Howard Industries noted that, for multiple-voltage distribution transformers, this insertion would clarify that distribution transformer efficiency is determined by the primary voltage and that the low-voltage or secondary winding configuration that is used would be at the manufacturer's discretion. (HI, No. 23 at p. 2)

HVOLT commented that distribution transformers with dual or multiple-voltage primary windings should be allowed to comply while the primaries are connected in series. HVOLT explained that utilities purchase these transformers to upgrade a distribution circuit to higher voltages within a few years of purchase and that these transformers will spend more than 90 percent of their lives with the primary windings connected in series. (HVOLT, No. 33 at p. 2)

DOE understands that, in contrast to the secondary windings, reconfigurable primaries typically exhibit a larger variation in efficiency between series and primary connections. As the above commenters have pointed out, however, such transformers are often purchased with the intent of upgrading the local power grid to a higher operating voltage with lowered overall system losses. In that sense, transformers with reconfigurable primaries can be seen as a stepping stone toward greater overall energy savings, even if those savings do not occur within the transformer itself.

DOE conducted several sensitivity analyses to examine the effects of a reconfigurable primary winding on efficiency and found that the difference between the efficiency of the secondary and the efficiency of the primary was more significant than in the case of configurable secondary windings.

DOE wishes to obtain more information on both the difference in losses between different winding configurations as well as the different configurations' relative frequency of operation in practice. DOE requests comment on this proposal to continue to mandate compliance in the highest-loss configuration and data illustrating the

efficiency differences between primary winding configurations.

5. Dual/Multiple-Voltage Secondary Windings

Currently, DOE requires transformers to comply with their secondary windings in the configuration that produces the greatest losses. (10 CFR 431, Subpart K, Appendix A)

Interested parties commented that DOE should not change the current test requirement to permit compliance testing in any secondary configuration at the lowest BIL rating for transformers with dual/multiple-voltage secondary windings, and that these transformers should comply with an energy efficiency level using the combination of connections that produces the highest losses. (HPS, No. 3 at p.1; NPCC/NEEA, No. 11 at p. 3; and ABB, No. 14 at p. 2) ABB also noted that there is no way to determine the connection on which a unit will be operated over its lifetime.

Schneider Electric (SE) commented that NEMA ST20-1992: 3.3 [Dry-Type Transformers for General Applications, NEMA ST 20-1992(R1997)] requires that “low-voltage [transformers] be shipped with the connections done for the highest voltage” and requested that “all compliance testing be done in the configuration requirement of ST-20.” (SE., No. 18 at p. 5) Similarly, NEMA commented that “DOE should align its requirements with those of IEEE standards (C57.12.00 for liquid-filled, NEMA ST 20-1992: 3.3 for low-voltage), requiring testing in the 'as shipped' condition.” (NEMA, No. 13 at p. 2) Further, NEMA noted that industry practice is to ship these units in the series connection. Similarly, FPT asserted that, “for units with multiple (series-parallel) low-voltage ratings, the efficiency standard should be based on the highest voltage (series) connection, which matches the IEEE standard and industry practice.” (FPT, No. 27 at p. 11)

Several interested parties expressed support for DOE's proposal to allow compliance testing in any secondary configuration at the lowest voltage rating. (Power Partners, Inc. (PP), Pub. Mtg. Tr., No. 34 at p. 40; HVOLT, No. 33 at p. 2; HI, No. 23 at p.2; and PP, No. 19 at p. 2) HVOLT noted that about 99 percent of dual/multiple-voltage single-phase, pole-type transformers are used in the series connection, and the work to otherwise reconnect to the secondary is burdensome. (HVOLT, No. 33 at p.2) Similarly, HI pointed out that very few transformers are ever reconnected for parallel operation and that testing requirements in a parallel configuration can be burdensome. (HI, No. 23 at p. 2)

Furthermore, HVOLT commented that a distribution transformer that is designed for a dual voltage rating does not have an even multiple quantity of series connections compared to parallel connection designs. This means that there are already unused windings that will be in the parallel connection. Because the testing procedure requires that they be tested on the lowest BIL connections, these types of distribution transformers effectively have a higher efficiency requirement. HVOLT believes dual voltage distribution transformers are being unduly burdened by the test procedure. (HVOLT, Pub. Mtg. Tr., No. 34 at pp. 38-39)

HI recommended that DOE adjust the efficiency value by 0.1 for dual/multiple-voltage liquid-immersed distribution transformers with windings having a ratio other than 2:1, due to the complexity of the winding for these distribution transformers. HI noted that a similar approach was taken by the Canadian Standards Associations Standards. (HI, No. 23 at p. 2)

DOE understands that some distribution transformers may be shipped with reconfigurable secondary windings, and that certain configurations may have different efficiencies. Currently, DOE requires distribution transformers to be tested in the configuration that exhibits the highest losses, which is usually with the secondary windings in parallel. Whereas the IEEE Standard

requires a distribution transformer to be shipped with the windings in series, a manufacturer testing for compliance could need to test the distribution transformer for energy efficiency, disassemble the unit, reconfigure the windings, and reassemble the unit for shipping at added time and expense. Nonetheless, DOE would need to obtain more specific information on the potential net energy losses associated with permitting distribution transformers to be tested in any secondary winding configuration and proposes to maintain the current requirement of compliance in the configuration that produces the greatest losses.

IEEE C57.12.00.

DOE requests comment on secondary winding configurations, and on the magnitude of the additional losses associated with the less efficient configurations as well as the relative frequencies of operation in each winding configuration.

6. Loading

Currently, DOE requires that both liquid-immersed and medium-voltage, dry-type distribution transformers comply with standards at 50 percent loading and that low-voltage, dry-type distribution transformers comply at 35 percent loading.

Warner Power (WP) commented that a single 35 percent test load for low-voltage dry-type distribution transformers (LVDTs) does not adequately reflect known service conditions at widely varying, and often low, average loads. It cited several studies indicating a lower average load factor and a shrinking load factor and recommended LVDTs be certified at 15 percent and 35 percent loading. (WP, No. 30 at pp. 1-2) In addition, Warner Power suggested that a weighted curve between 10 percent and 80 percent load factors would be better than a single 35 percent load factor. It recommended using published data to more accurately reflect real load conditions, accounting for daily, weekly, and seasonal variations. For LVDT transformers, it pointed out that the load profile should characterize the typical use in different types of buildings. (WP, No. 30 at p.5) NPCC and NEEA opined that, with better loading data for distribution transformers, they would support testing at multiple loading points, such as 15, 35, 50 and 70 percent, with a weighted-average calculation that is unique to each class. They noted, however, that such data is likely not available. (NPCC/NEEA, No. 11 at pp. 2-3)

HVOLT commented that the test procedure-required load values for all three categories of distribution transformers appeared reasonable for the foreseeable future. Otherwise, with electric vehicles and plug-in hybrids entering the market, HVOLT opined that root-mean-square loading will increase in the long-term but may take decades to have an effect. (HVOLT, No. 33 at p. 1) NPCC and NEEA announced that they are collecting additional field data to inform the appropriateness of the test procedure loading points. (NPCC/NEEA, No. 11 at p. 2)

NEMA, ABB, and Schneider Electric (SE) all commented that DOE should not modify its test procedures by considering weighted-average loadings for core deactivation efficiency standards. (NEMA, No. 13 at p. 2; ABB, No. 14 at pp. 2-3; and SE., Pub. Mtg. Tr., No. 34 at p. 57) ABB further clarified that this approach would be inaccurate because the true load varies by every distinct installation. Instead, it asserted that the current load factors are more appropriate because they reflect the aggregate impact on the national grid. (ABB, No. 14 at pp. 2-3)

NPCC and NEEA recommended that DOE attempt to gather data on actual core deactivation designs and control algorithms before it changes the test procedure. Additionally, NPCC and NEEA suggested that DOE gather data on the performance of distribution transformers under various load conditions. If this data is unavailable or inconclusive, they suggested that DOE not change the test procedure at this time but rather ensure that core deactivation technology is examined in the next rulemaking for distribution transformers. (NPCC/NEEA, No. 11 at p. 3)

Warner Power (WP) indicated its intent to submit data concerning modified test procedures which would better capture core deactivation technologies. (WP, Pub. Mtg. Tr., No. 34 at p. 42)

DOE is proposing to maintain the use of a single, discrete loading point for distribution transformers because the use of weighted-average loadings would represent a fairly significant change in the test procedure, possibly causing some units that meet energy conservation standards to no longer do so. In the future, DOE may consider modifying this approach. DOE welcomes relevant data in conjunction with comments on typical distribution transformer loading profiles.

B. Technological Feasibility

1. General

There are distribution transformers available at all of the energy efficiency levels considered in today's notice of proposed rulemaking. Therefore, DOE believes all of the energy efficiency levels adopted by today's notice of proposed rulemaking are technologically feasible.

2. Maximum Technologically Feasible Levels

When DOE proposes to adopt, or decline to adopt, an amended or new standard for a type of covered product, section 325(o)(2) of EPCA, 42 U.S.C. 6295(o)(2), requires that DOE determine the maximum improvement in energy efficiency or maximum reduction in energy use that is technologically feasible. While developing the energy conservation standards for liquid-immersed and medium-voltage, dry-type distribution transformers that were codified under 10 CFR 431.196, DOE determined the maximum technologically feasible (“max-tech”) energy efficiency level through its engineering analysis using the most efficient materials, such as core steels and winding materials, and applied design parameters that drove distribution transformer software to create designs at the highest efficiencies achievable at the time. 71 FR 44362 (August 4, 2006) and 72 FR 58196 (October 12, 2007). DOE used these designs to establish max-tech levels for its LCC analysis and scaled them to other kVA ratings within a given design line, thereby establishing max-tech efficiencies for all the distribution transformer kVA ratings.

C. Energy Savings

1. Determination of Savings

Section 325(o)(2)(A) of EPCA, 42 U.S.C. 6295(o)(2)(A), requires that any new or amended standard must be chosen so as to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified. In determining whether economic justification exists, key factors include the total projected amount of energy savings likely to result directly from the standard and the savings in operating costs throughout the estimated average life of the covered equipment. To understand the national economic impact of potential efficiency regulations for distribution transformers, DOE conducted a national impact analysis (NIA) using a spreadsheet model to estimate future national energy savings (NES) from amended energy conservation standards.

For each TSL, DOE forecasted energy savings beginning in 2016, the year that manufacturers would be required to comply with amended standards, and ending in 2045. DOE quantified the energy savings for each TSL as the difference in energy consumption between the “standards case” and the “base case.” The base case represents the forecast of energy consumption in the absence of amended mandatory efficiency standards, and takes into consideration market demand for more-efficient equipment.

The NIA spreadsheet model is described in section IV.G of this notice.

The NIA spreadsheet model calculates the electricity savings in “site energy” expressed in kilowatt-hours (kWh). Site energy is the energy directly consumed by distribution transformer products at the locations where they are used. DOE reports national energy savings on an annual basis in terms of the aggregated source (primary) energy savings, which is the savings in the energy that is used to generate and transmit the site energy. (See TSD chapter 10.) To convert site energy to source energy, DOE derived annual conversion factors from the model used to prepare the Energy Information Administration's (EIA)

Annual Energy Outlook 2011 (AEO2011).

2. Significance of Savings

As noted above, 42 U.S.C. 6295(o)(3)(B) prevents DOE from adopting a standard for covered equipment if such a standard would not result in “significant” energy savings. While EPCA does not define the term “significant,” the U.S. Court of Appeals for the District of Columbia, in

Natural Resources Defense Council

Herrington,

768 F.2d 1355, 1373 (D.C. Cir. 1985), indicated that Congress intended “significant” energy savings in this context to be savings that were not “genuinely trivial.” The energy savings for all of the TSLs considered in this rulemaking are non-trivial and, therefore, DOE considers them “significant” within the meaning of EPCA section 325(o).

D. Economic Justification

1. Specific Criteria

As noted previously, EPCA requires DOE to evaluate seven factors to determine whether a potential energy conservation standard is economically justified. (42 U.S.C. 6295(o)(2)(B)(i)) The following sections describe how DOE has addressed each of the seven factors in this rulemaking.

a. Economic Impact on Manufacturers and Consumers

In determining the impacts of an amended standard on manufacturers, DOE first determines the quantitative impacts using an annual cash-flow approach. This includes both a short-term assessment, based on the cost and capital requirements during the period between the issuance of a regulation and when entities must comply with the regulation, and a long-term assessment over a 30-year analysis period. The industry-wide impacts analyzed include INPV (which values the industry on the basis of expected future cash flows), cash flows by year, changes in revenue and income, and other measures of impact, as appropriate. Second, DOE analyzes and reports the impacts on different types of manufacturers, paying particular attention to impacts on small manufacturers. Third, DOE considers the impact of standards on domestic manufacturer employment and manufacturing capacity, as well as the potential for standards to result in plant closures and loss of capital investment. Finally, DOE takes into account cumulative impacts of different DOE regulations and other regulatory requirements on manufacturers.

For individual consumers, measures of economic impact include the changes in LCC and the PBP associated with new or amended standards. The LCC, which is separately specified in EPCA as one of the seven factors to be considered in determining the economic justification for a new or amended standard (42 U.S.C. 6295(o)(2)(B)(i)(II)), is discussed in the following section. For consumers in the aggregate, DOE also calculates the national net present value of the economic impacts on consumers over the forecast period used in a particular rulemaking.

Federal Pacific suggested that DOE establish reference efficiencies by rating, as defined by NEMA Premium, for those users who want efficiencies higher than current minimum efficiencies. However, they did not want these reference efficiencies to become the new minimum efficiency mandates. (FPT, No. 27 at p. 2)

The National Rural Electric Cooperative Association (NRECA) recommended that DOE not raise the efficiency standards for the liquid-filled distribution transformers, since many rural utilities with low distribution transformer loads cannot economically justify the current energy efficiency level. (NRECA, No. 31 and 36 at p. 1)

DOE appreciates the comments and considers impacts to consumers, manufacturers, and utilities in TSD chapters 8, 12, and 14, respectively. DOE welcomes comment on these analyses and on any subset of consumers, manufacturers, or utilities that could be disproportionately affected.

b. Life-Cycle Costs

The LCC is the sum of the purchase price of a type of equipment (including its installation) and the operating expense (including energy and maintenance and repair expenditures) discounted over the lifetime of the product. The LCC savings for the considered energy efficiency levels are calculated relative to a base case that reflects likely trends in the absence of amended standards. The LCC analysis requires a variety of inputs, such as equipment prices, equipment energy consumption, energy prices, maintenance and repair costs, equipment lifetime, and consumer discount rates. DOE assumed in its analysis that consumers will purchase the considered equipment in 2016.

To account for uncertainty and variability in specific inputs, such as product lifetime and discount rate, DOE uses a distribution of values with probabilities attached to each value. A distinct advantage of this approach is that DOE can identify the percentage of consumers estimated to receive LCC savings or experience an LCC increase, in addition to the average LCC savings associated with a particular standard level. In addition to identifying ranges of impacts, DOE evaluates the LCC impacts of potential standards on identifiable subgroups of consumers that may be disproportionately affected by a national standard.

c. Energy Savings

While significant conservation of energy is a separate statutory requirement for imposing an energy conservation standard, EPCA requires DOE, in determining the economic justification of a standard, to consider the total projected energy savings that are expected to result directly from the standard. (42 U.S.C. 6295(o)(2)(B)(i)(III)) DOE uses the NIA spreadsheet results in its consideration of total projected energy savings.

d. Lessening of Utility or Performance of Products

In establishing classes of products, and in evaluating design options and the impact of potential standard levels, DOE sought to develop standards for distribution transformers that would not lessen the utility or performance of these products. (42 U.S.C. 6295(o)(2)(B)(i)(IV)) None of the TSLs presented in today's NOPR would substantially reduce the utility or performance of the equipment under consideration in the rulemaking.

DOE requests comment on the possibility of reduced equipment performance or utility resulting from today's proposed standards, particularly the risk of reducing the ability to perform periodic maintenance and the risk of increasing vibration and acoustic noise.

e. Impact of Any Lessening of Competition

EPCA directs DOE to consider any lessening of competition that is likely to result from standards. It also directs the Attorney General of the United States (Attorney General) to determine the impact, if any, of any lessening of competition likely to result from a proposed standard and to transmit such determination to the Secretary within 60 days of the publication of a proposed rule, together with an analysis of the nature and extent of the impact. (42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii)) DOE will transmit a copy of today's proposed rule to the Attorney General with a request that the Department of Justice (DOJ) provide its determination on this issue. DOE will address the Attorney General's determination in the final rule.

f. Need for National Energy Conservation

Certain benefits of the proposed standards are likely to be reflected in improvements to the security and reliability of the Nation's energy system. Reductions in the demand for electricity may also result in reduced costs for maintaining the reliability of the Nation's electricity system. DOE conducts a utility impact analysis to estimate how standards may affect the Nation's needed power generation capacity. (See 42 U.S.C. 6295(o)(2)(B)(i)(VI))

Energy savings from the proposed standards are also likely to result in environmental benefits in the form of reduced emissions of air pollutants and greenhouse gases associated with energy production. DOE reports the environmental effects from the proposed standards, and from each TSL it considered, in the environmental assessment contained in chapter 15 in the NOPR TSD. DOE also reports estimates of the economic value of emissions reductions resulting from the considered TSLs.

g. Other Factors

EPCA allows the Secretary of Energy, in determining whether a standard is economically justified, to consider any other factors that the Secretary considers relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) In developing the proposals of this notice, DOE has also considered the matter of electrical steel availability. This factor is discussed further in section V.B.8.

2. Rebuttable Presumption

As set forth in 42 U.S.C. 6295(o)(2)(B)(iii), EPCA creates a rebuttable presumption that an energy conservation standard is economically justified if the additional cost to the consumer of a product that meets the standard is less than three times the value of the first-year of energy savings resulting from the standard, as calculated under the applicable DOE test procedure. DOE's LCC and payback period (PBP) analyses generate values used to calculate the PBP for consumers of potential amended energy conservation standards. These analyses include, but are not limited to, the three-year PBP contemplated under the rebuttable presumption test. However, DOE routinely conducts an economic analysis that considers the full range of impacts to the consumer, manufacturer, Nation, and environment, as required under 42 U.S.C. 6295(o)(2)(B)(i). The

results of this analysis serve as the basis for DOE to definitively evaluate the economic justification for a potential standard level (thereby supporting or rebutting the results of any preliminary determination of economic justification). The rebuttable presumption payback calculation is discussed in section V.B.1.c of this NOPR and chapter 8 of the NOPR TSD.

IV. Methodology and Discussion of Related Comments

DOE used two spreadsheet tools to estimate the impact of today's proposed standards. The first spreadsheet calculates LCCs and PBPs of potential new energy conservation standards. The second provides shipments forecasts and calculates national energy savings and net present value impacts of potential new energy conservation standards. DOE also assessed manufacturer impacts, largely through use of the Government Regulatory Impact Model (GRIM). The two spreadsheets are available online at the rulemaking Web site:

http://www1.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html

Additionally, DOE estimated the impacts of energy conservation standards for distribution transformers on utilities and the environment. DOE used a version of EIA's National Energy Modeling System (NEMS) for the utility and environmental analyses. The NEMS model simulates the energy sector of the U.S. economy. EIA uses NEMS to prepare its

Annual Energy Outlook (AEO),

a widely known energy forecast for the United States. The version of NEMS used for appliance standards analysis is called NEMS-BT

and is based on the

AEO

version with minor modifications.

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.

BT stands for DOE's Building Technologies Program.

The EIA allows the use of the name “NEMS” to describe only an AEO version of the model without any modification to code or data. Because the present analysis entails some minor code modifications and runs the model under various policy scenarios that deviate from AEO assumptions, the name “NEMS-BT” refers to the model as used here. For more information on NEMS, refer to The National Energy Modeling System: An Overview, DOE/EIA-0581 (98) (Feb.1998), available at:

http://tonto.eia.doe.gov/FTPROOT/forecasting/058198.pdf.

A. Market and Technology Assessment

For the market and technology assessment, DOE develops information that provides an overall picture of the market for the products concerned, including the purpose of the products, the industry structure, and market characteristics. This activity includes both quantitative and qualitative assessments, based primarily on publicly available information. The subjects addressed in the market and technology assessment for this rulemaking include scope of coverage, definitions, equipment classes, types of products sold and offered for sale, and technology options that could improve the energy efficiency of the products under examination. Chapter 3 of the TSD contains additional discussion of the market and technology assessment.

1. Scope of Coverage

This section addresses the scope of coverage for today's proposal, stating which products would be subject to amended standards. The numerous comments DOE received on the scope of today's proposal are also summarized and addressed in this section.

a. Definitions

Today's proposed standards rulemaking concerns distribution transformers, which include three categories: liquid-immersed, low-voltage dry-type (LVDT) and medium-voltage dry-type (MVDT). The definition of a distribution transformer was presented in EPACT 2005 and then further refined by DOE when it was codified into 10 CFR 431.192 by the April 27, 2006 final rule for distribution transformer test procedures (71 FR 24995) as follows:

Distribution transformer

means a transformer that—

(1) Has an input voltage of 34.5 kV or less;

(2) Has an output voltage of 600 V or less;

(3) Is rated for operation at a frequency of 60 Hz; and

(4) Has a capacity of 10 kVA to 2500 kVA for liquid-immersed units and 15 kVA to 2500 kVA for dry-type units; but

(5) The term “distribution transformer” does not include a transformer that is an—

(i) Autotransformer;

(ii) Drive (isolation) transformer;

(iii) Grounding transformer;

(iv) Machine-tool (control) transformer;

(v) Non-ventilated transformer;

(vi) Rectifier transformer;

(vii) Regulating transformer;

(viii) Sealed transformer;

(ix) Special-impedance transformer;

(x) Testing transformer;

(xi) Transformer with tap range of 20 percent or more;

(xii) Uninterruptible power supply transformer; or

(xiii) Welding transformer.

Additional detail on the definitions of each of these excluded transformers can found in TSD chapter 3.

DOE received multiple comments seeking clarification on various terms used in the definition of a distribution transformer. NEMA requested that DOE amend the definitions of two transformer types explicitly excluded from the distribution transformer definition, namely “rectifier transformer” and “testing transformer.” NEMA suggested that both definitions should require the nameplates of such transformers to identify the transformers as being for such uses only. (NEMA, No. 13 at p. 10) Furthermore, NEMA recommended that transformers used inside underground tunneling equipment should be added to the definition for underground mining distribution transformers because this equipment is specialized and requires a compact transformer. (NEMA, No. 13 at p. 10) FPT agreed with NEMA and recommended that DOE amend the definition of “underground mining transformer” with the following sentence: “The term `mining' may also be understood to mean underground tunneling or digging.” FPT added that the term “mining” should be clarified to encompass any underground operation involving the removal of material underground, such as digging or tunneling, which have the same restrictions with the size of distribution transformers, but might not be considered to be mining applications. (FPT, No. 27 at pp. 10-11) Finally, PP commented that DOE should clarify the definitions of input and output voltage to reflect the three-phase system voltages and not the line to ground voltage, which is typically the input voltage for single-phase transformers. (PP, No. 1 at p. 1)

DOE agrees that these additions to the definitions of “rectifier transformer” and “testing transformer” are helpful in aiding the consumer to distinguish rectifier and testing transformers and therefore proposes to amend its definitions correspondingly. Additionally, DOE believes that transformers used for the removal of material underground are subject to similar space constraints as traditional mining transformers and therefore their ability to meet higher efficiency standards are similarly restricted. However, DOE wishes to learn more about the nature of those applications in order to define the units precisely. Consequently, DOE proposes to maintain the current definition of “mining transformer” unless it is able to determine that the expansion, as

suggested by NEMA and FPT, is warranted and able to be implemented with sufficient specificity. DOE requests comment on that proposal and any information useful in understanding how transformers used in certain underground applications differ and could be defined precisely. Finally, DOE also wishes to remove any ambiguity in the terms “input voltage” and “output voltage” and requests comment on where that ambiguity lies.

Multiple interested parties submitted comments regarding the kVA ratings that are currently included in the scope of coverage. PP commented that DOE should consider removing single-phase liquid-immersed distribution transformers rated above 250 kVA with a low-voltage rating of 600V from the scope of the regulation. They contended that these transformers constitute a very low volume of shipments (481 units in 2009) and MVA capacity shipped (201 MVA in 2009) and therefore the overall national energy savings would not be significant. (PP, No. 19 at pp. 1-3; Pub. Mtg. Tr., No. 34 at p. 34) PP added that the impact of increased weight and dimensions is greater in these sizes where maximum tank size and weight constraints are critical. Moreover, PP proposed that DOE should consider 500 kVA the upper limit of kVA ratings covered and shift the lower limit from 10 to 5 kVA. (PP, Pub. Mtg. Tr., No. 34 at pp. 46, 73-74; PP, No. 19 at pp. 1-2) Similarly, NPCC and NEEA urged DOE to decide whether to include single-phase liquid-immersed distribution transformers down to 5 kVA in the scope of coverage. (NPCC/NEEA, No. 11 at p. 9)

BBF and Associates suggested that DOE investigate increasing the scope of the rulemaking to include transformers from 2500 kVA to 20 MVA. (BBF, Pub. Mtg. Tr., No. 34 at p. 279) CDA recommended that DOE include transformers up to 30,000 kVA (30 MVA) in its scope, including sub-station transformers. It noted that these units are within the distribution system, and are substantial in unit shipment volumes. (CDA, No. 17 at pp. 1-2, 4)

DOE understands that larger (250-833 kVA) single-phase, liquid-immersed units are currently covered and is not proposing to exclude them from consideration for this rulemaking. Because these ratings were covered by the previous rulemaking for distribution transformers, DOE is statutorily prohibited from backsliding and excluding such products from regulation at this time. (See 42 U.S.C. 6295(o)(1)6316(a)) However, DOE notes that it is accounting for the added life-cycle costs of larger and heavier transformers and discusses its methodology for this in chapter 6 of the TSD. Additionally, DOE determined during the previous standards rulemaking that 5 kVA transformers were below the kVA limit “commonly understood to be distribution transformers.” 69 FR 45381. DOE proposes to maintain that stance for this rulemaking as these units are generally too small to be employed in power distribution and collectively consume extremely little power. Similarly, units larger than 2.5 MVA (DOE's current upper limit) are usually considered substation transformers, which DOE is not proposing to cover. DOE invites comment on its proposal to maintain the current scope of coverage.

Interested parties also solicited clarification from DOE on transformers that are used in a variety of applications. FPT requested that DOE clarify whether existing efficiency standards apply to transformers used in aircraft, trains/locomotives, offshore drilling platforms, mobile substations, ships, and other similar applications. (FPT, No. 27 at p. 2) Furthermore, FPT recommended that DOE investigate whether transformers being used in wind farms or solar energy applications should be exempted since these designs should be optimized at higher loading levels than the test procedure loading points of 35 percent (low-voltage dry-type) and 50 percent (liquid-immersed and medium-voltage dry-type). (FPT, No. 27 at p. 2) Lastly, CDA commented that DOE should expand the scope of the rulemaking to include step-up transformers of kVA sizes that are currently included in the scope, such as transformers used in wind farms. (CDA, No. 17 at pp. 2-3)

EPACT 2005 defined the term “distribution transformer,” 42 U.S.C. 6291(35)(B)(ii), to mean a transformer that (i) has an input voltage of 34.5 kilovolts or less; (ii) has an output voltage of 600 volts or less; and (iii) is rated for operation at a frequency of 60 Hertz. The definition goes on to generally exclude certain specialized-application distribution transformers. At this time, DOE is not proposing to cover distribution transformers used in mobile applications because they do not represent traditional power distribution. For example, aircraft and marine transformers frequently operate at 400 Hz, and mobile substation transformers often fall outside the currently defined voltage and kVA ranges. Furthermore, transformers used in mobile applications could be unduly impacted by any increases in size and weight required to reach higher efficiencies. DOE requests comment on the topic of transformers used in mobile applications and any data helpful in considering whether standards are warranted. DOE also requests comment on the likelihood of this exclusion serving as a loophole in the face of increasing standards.

DOE does not propose to exclude transformers used in renewable energy applications simply because of the potential difference in loading that they may experience. DOE currently understands that the users who buy transformers for those applications tend to value losses highly and that such transformers would have little trouble meeting standards. Furthermore, DOE notes that its choices for the test procedure loading points do not imply that it intends to exclusively cover transformers with precisely those loading values. Rather, DOE accounts for consumers purchasing transformers optimized for loading values other than the test procedure value in its LCC analysis.

DOE proposes to continue to not set standards for step-up transformers, because they are not ordinarily considered to be performing a power distribution function. However, DOE is aware that step-up transformers may be able to be used in place of step-down transformers and may represent a potential loophole as standards increase. DOE requests comment on its proposal to continue not to set standards for step-up transformers.

Finally, DOE received an inquiry with regards to how it plans to deal with core deactivation technology. Specifically, Schneider Electric wanted to know if DOE would change the definition of transformers to include banks of transformers. (SE., Pub. Mtg. Tr., No. 34 at p. 57) Core-deactivation technology employs a system of smaller transformers to replace a single, larger transformer. For example, using this technology, three transformers sized at 25 kVA and operated in parallel could replace a single 75 kVA transformer. The smaller transformers that compose the system can then be activated and deactivated using core deactivation technology based on the loading demand. At present, DOE is not proposing to set efficiency standards for banks of transformers, but notes that each constituent transformer would be subject to an efficiency standard if, on its own, it meets the definition of a distribution transformer.

b. Underground Mining Transformer Coverage

In the October 12, 2007, final rule on energy conservation standards for distributions transformers, DOE codified

into 10 CFR 431.192 the definition of an “underground mining distribution transformer” as follows:

Underground mining distribution transformer

means a medium-voltage dry-type distribution transformer that is built only for installation in an underground mine or inside equipment for use in an underground mine, and that has a nameplate which identifies the transformer as being for this use only. 72 FR 58239.

In that same final rule, DOE also clarified that although it believed these transformers were within its scope of coverage, it was not establishing any energy conservation standards for underground mining transformers. At the time, DOE recognized that these transformers were subject to unique and extreme dimensional constraints which impact their efficiency and performance capabilities. Therefore, DOE established a separate equipment class for mining transformers and stated that it may consider energy conservation standards for such transformers at a later date. Although DOE did not establish energy conservation standards for such transformers, it also did not add underground mining transformers to the list of excluded transformers in the definition of a distribution transformer. DOE retained that it had the authority to cover such equipment if, during a later analysis, it found technologically feasible and economically justified energy conservation standard levels. 72 FR 58197.

In response to the March 2, 2011 preliminary analysis, NEMA recommended that underground mining distribution transformers, including transformers used inside underground tunneling equipment, should be included on the exemption list to clarify that the standards shall not apply to them. (NEMA, No. 13 at p. 10) NPCC and NEEA commented that DOE should remove any confusion about the coverage of underground mining transformers either by setting standards for these units or adding them to the list of excluded transformers. (NPCC/NEEA, No. 11 at p. 9)

FPT urged DOE to exclude mining transformers from minimum efficiency levels because it would result in undue economic hardship for the mining industry and unrealistic design constraints on mining equipment that use such transformers. FPT pointed out that mining transformers make up a small portion of the market and that the total amount of energy they consume is very small compared to the national energy consumption rate. FPT also noted that a mining transformer is more specialized in its design and application than many of the transformers excluded from the definition of distribution transformers under 10 CFR 431.192. (FPT, No. 27 at pp. 8-10)

In view of the above, DOE understands that underground mining transformers are subject to a number of constraints that are not usually concerns for transformers used in general power distribution. Because space is critical in mines, an underground mining transformer may be at a considerable disadvantage in meeting an efficiency standard. Underground mining transformers are further disadvantaged by the fact that they must supply power at several output voltages simultaneously. For this rulemaking, DOE again proposes not to set standards for underground mining transformers, but recognizes the possibility of a loophole. Therefore, DOE continues to leave underground mining transformers off of the list of exempt distribution transformers and reserve a separate equipment class for mining transformers. DOE may set standards in the future if it believes that underground mining transformers are being purchased as a way to circumvent energy conservation standards.

c. Low-Voltage Dry-Type Distribution Transformers

10 CFR 431.192 defines the term “low-voltage dry-type distribution transformer” to be a distribution transformer that:

(1) Has an input voltage of 600 volts or less;

(2) Is air-cooled; and

(3) Does not use oil as a coolant.

Because EPACT 2005 prescribed standards for LVDTs, which DOE incorporated into its regulations at 70 FR 60407 (October 18, 2005) (codified at 10 CFR 431.196(a)), LVDTs were not included in the 2007 standards rulemaking. As a result, the settlement agreement following the publication of the 2007 final rule does not impact LVDT standards.

Two interested parties, EEI and SE., requested clarification on whether LVDT distribution transformers would be included in this rulemaking. (EEI, Public Mtg. Tr., No. 34 at p. 56, 27; SE., No. 7 at p. 1) In particular, SE questioned whether Congress would be involved in amending standards for LVDTs. (SE., No. 7 at p. 1) Further, SE expressed concern that there does not appear to be a timeline for the LVDT distribution transformer rulemaking and that one is needed in order to plan potential capital expenditures for any new efficiency levels. (SE., Pub. Mtg. Tr., No. 34 at p. 19)

SE requested that DOE analyze LVDTs in a separate rulemaking from liquid-immersed distribution transformers and MVDTs. It noted that the law defines them separately and that LVDT distribution transformers are used in applications that are different from those of MVDT distribution transformers. SE further noted that LVDT distribution transformers may warrant an expanded scope of coverage and encouraged DOE to reassess the range of kVAs covered, product definitions, exemptions, and loading points. (SE., No. 18 at p. 1) FPT suggested that DOE evaluate LVDT distribution transformers at a later date because this product category is not part of the court order. (FPT, No. 27 at p. 1) Rather, FPT believed that DOE should establish non-mandatory efficiencies for LVDT distribution transformers so that consumers who wish to purchase higher efficiency units can have a point of reference. (FPT, No. 27 at pp. 1-2)

CDA observed that the current efficiency levels for LVDT distribution transformers are at NEMA TP-1 levels and that the 2010 MVDT and liquid-immersed distribution transformer efficiency levels were set at approximately TSL 4. 72 FR 58239-40 (CDA, No. 17 at p. 3). CDA believed that it is appropriate for DOE to evaluate and adjust the minimum efficiency standards for LVDT distribution transformers, wherever cost-effective, to levels that are comparable to the 2010 levels for other [MVDT and liquid-immersed] distribution transformers. (CDA, No. 17 at p. 3) Earthjustice commented that DOE must revisit standards for LVDT distribution transformers as part of EPCA's requirement that standards be reevaluated not later than six years after issuance. Earthjustice noted that, on October 18, 2005, DOE codified the efficiency standards for LVDT distribution transformers that were set forth in EPACT 2005 (70 FR 60407) and that DOE must now publish, by October 18, 2011, either a new proposed standard or a determination that amended standards are not warranted. (Earthjustice, No. 20 at pp. 1-2) In joint comments, the Appliance Standards Awareness Project (ASAP), American Council for an Energy Efficient Economy (ACEEE), and Natural Resources Defense Council (NRDC) agreed with Earthjustice that DOE is obligated under EPCA to review the efficiency standards for liquid-immersed and MVDT distribution transformers and amend the efficiency standards for LVDT distribution transformers if justified. (ASAP/ACEEE/

NRDC, No. 28 at p. 5) HVOLT also believed that DOE should consider LVDT distribution transformers at this time. (HVOLT, No. 33 at p. 2) EEI believed that LVDT distribution transformers could be included in the rulemaking, since they are covered products under the statute and are now under a DOE regulatory purview. (EEI, Pub. Mtg. Tr., No. 34 at pp. 21, 27)

Without regard to whether DOE may have a statutory obligation to review standards for LVDTs, DOE has analyzed all three transformer types and is proposing standards for each in this rulemaking.

Schneider Electric suggested expanding coverage to include sealed units within the range of Design Lines 6 and 7: single-phase 15 and 25 kVA and three-phase 15 kVA distribution transformers. Further, it suggested that an additional three-phase 15 kVA design line, which would include SCOTT-T and OPEN DELTA designs, be created to meet the definition of sealed transformers. (SE., No. 7 at p. 2) DOE is not making this change because the EPACT 2005 definition of a distribution transformer and the definition currently codified at 10 CFR 431.192 both explicitly prohibit the inclusion of such transformers.

d. Negotiating Committee Discussion of Scope

Negotiation participants noted that both network/vault transformers and “data center” transformers may experience disproportionate difficulty in achieving higher efficiencies due to certain features that may affect consumer utility. (ABB, Pub. Mtg. Tr., No. 89 at p. 245) The definitions below had been proposed at various points by committee members and DOE seeks comment on both whether it would be appropriate to establish separate equipment classes for any of the following types and, if so, on how such classes might be defined such that it was not financially advantageous for consumers to purchase transformers in either class for general use.

i. A “network transformer” is one—

(i) Designed for use in a vault,

(ii) Designed for occasional submerged operation in water,

(iii) Designed to feed a system of variable capacity system of interconnected secondaries, and

(iv) Built per the requirements of IEEE C57.12.40-(year)

ii. A “vault-type” transformer is one—

(i) Designed for use in a vault,

(ii) Designed for occasional submerged operation in water, and

(iii) Built per the requirements of IEEE C57.12.23-(year) or IEEE C57.12.24-(year), respectively.

iii. Data center transformer means a three-phase low-voltage dry-type distribution transformer that—

(i) Is designed for use in a data center distribution system and has a nameplate identifying the transformer as being for this use only;

(ii) Has a maximum peak energization current (or in-rush current) less than or equal to four times its rated full load current multiplied by the square root of 2, as measured under the following conditions—

(iii) During energization of the transformer without external devices attached to the transformer that can reduce inrush current;

(iv) The transformer shall be energized at zero +/− 3 degrees voltage crossing of A phase. Five consecutive energization tests shall be performed with peak inrush current magnitudes of all phases recorded in every test. The maximum peak inrush current recorded in any test shall be used;

(v) The previously energized and then de-energized transformer shall be energized from a source having available short circuit current not less than 20 times the rated full load current of the winding connected to the source; and

(vi) The source voltage shall not be less than 5 percent of the rated voltage of the winding energized; and

(vii) Is manufactured with at least two of the following other attributes:

1. Listed by NRTL for a K-factor rating, as defined in UL standard 1561: 2011 Fourth Edition, greater than K-4;

2. Temperature rise less than 130°C with class 220 insulation or temperature rise less than 110°C with class 200 insulation;

3. A secondary winding arrangement that is not delta or wye (star);

4. Copper primary and secondary windings;

5. An electrostatic shield; or

6. Multiple outputs at the same voltage a minimum of 15° apart, which when summed together equal the transformer's input kVA capacity.

2. Equipment Classes

DOE divides covered equipment into classes by: (a) the type of energy used; (b) the capacity; or (c) any performance-related features that affect consumer utility or efficiency. (42 U.S.C. 6295(q)) Different energy conservation standards may apply to different equipment classes (ECs). For the preliminary analysis and for today's NOPR, DOE analyzed the same ten ECs as were used in the previous distribution transformers energy conservation standards rulemaking.

These ten equipment classes divided up the population of distribution transformers by:

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,

(d) Basic impulse insulation level (for medium-voltage, dry-type units only).

On August 8, 2005, the President signed into law EPACT 2005, which contained a provision establishing energy conservation standards for two of DOE's equipment classes—EC3 (low-voltage, single-phase, dry-type) and EC4 (low-voltage, three-phase, dry-type). With standards thereby established for low-voltage, dry-type distribution transformers, DOE no longer considered these two equipment classes for standards during the previous rulemaking. Since the current rulemaking is considering new standards for distribution transformers, DOE has preliminarily decided to also revisit low-voltage, dry-type distribution transformers to determine if higher efficiency standards are justified. Table IV.1 presents the ten equipment classes within the scope of this rulemaking analysis and provides the kVA range associated with each.

Table IV.1—Distribution Transformer Equipment Classes

EC #

Insulation

Voltage

Phase

BIL Rating

kVA Range

Liquid-Immersed

Medium

Single

10-833 kVA

Liquid-Immersed

Medium

Three

15-2500 kVA

Dry-Type

Low

Single

15-333 kVA

Dry-Type

Low

Three

15-1000 kVA

Dry-Type

Medium

Single

20-45kV BIL

15-833 kVA

Dry-Type

Medium

Three

20-45kV BIL

15-2500 kVA

Dry-Type

Medium

Single

46-95kV BIL

15-833 kVA

Dry-Type

Medium

Three

46-95kV BIL

15-2500 kVA

Dry-Type

Medium

Single

≥ 96kV BIL

75-833 kVA

Dry-Type

Medium

Three

≥ 96kV BIL

225-2500 kVA

ABB commented that the currently defined equipment classes do not cover the product scope as defined in 10 CFR part 431.192, which defines medium-voltage as between 601 V and 34.5 kV. Therefore, it recommended changing the equipment classes analyzed, or at least revising the definition in the CFR. (ABB, No. 14 at p. 9)

DOE is uncertain of how its current equipment classes are inconsistent with its published definition of “medium-voltage dry-type” and requests further comment on the issue.

a. Less-Flammable Liquid-Immersed Transformers

In the August 2006 standards NOPR, DOE solicited comments about how it should treat distribution transformers filled with an insulating fluid of higher flash point than that of traditional mineral oil. 71 FR 44369 (August 4, 2006). Known as “less-flammable, liquid-immersed” (LFLI) transformers, these units are marketed to some applications where a fire would be especially costly and traditionally served by the dry-type market, such as indoor applications.

During preliminary interviews with manufacturers, DOE was informed that LFLI transformers might offer the same utility as dry-type transformers since they were unlikely to catch fire. Manufacturers also stated that LFLI transformers could have a minor efficiency disadvantage relative to traditional liquid-immersed transformers because their more viscous insulating fluid requires more internal ducting to properly circulate.

In the October 2007 final rule, DOE determined that LFLI transformers should be considered in the same equipment class as traditional liquid-immersed transformers. DOE concluded that the design of a transformer (

i.e.,

dry-type or liquid-immersed) was a performance-related feature that affects the energy efficiency of the equipment and, therefore, dry-type and liquid-immersed should be analyzed separately. Furthermore, DOE found that LFLI transformers could meet the same efficiency levels as traditional liquid-immersed units. As a result, DOE did not separately analyze LFLI transformers, but relied on the analysis for the mineral oil liquid-immersed transformers. 72 FR 58202 (October 12, 2007).

For the preliminary analysis, DOE revisited the issue in light of additional research on LFLI transformers and conversations with manufacturers and industry experts. DOE first considered whether LFLI transformers offered the same utility as dry-type equipment, and came to the same conclusion as in the last rulemaking. While LFLI transformers can be used in some applications that historically use dry-type units, there are applications that cannot tolerate a leak or fire. In these applications, customers assign higher utility to a dry-type transformer. Since LFLI transformers can achieve higher efficiencies than comparable dry-type units, combining LFLIs and dry-types into one equipment class may result in standard levels that dry-type units are unable to meet. Therefore, DOE decided not to analyze LFLI transformers in the same equipment classes as dry-type distribution transformers.

Similarly, DOE revisited the issue of whether or not LFLI transformers should be analyzed separately from traditional liquid-immersed units. DOE concluded, once again, that LFLI transformers could achieve any efficiency level that mineral oil units could achieve. Although their insulating fluids are slightly more viscous, this disadvantage has little efficiency impact, and diminishes as efficiency increases and heat dissipation requirements decline. Furthermore, at least one manufacturer suggested that LFLI transformers might be capable of higher efficiencies than mineral oil units because their higher temperature tolerance may allow the unit to be downsized and run hotter than mineral oil units. Additionally, HVOLT agreed with DOE that high temperature liquid-filled transformer insulation systems have a similar space factor to mineral oil systems and should thus have similar losses. (HVOLT, No. 33 at p. 2) For these reasons, DOE believes that LFLI transformers would not be disproportionately affected by standards set in the liquid-immersed equipment classes. Therefore, DOE did not consider LFLI in a separate equipment class for the NOPR analysis.

b. Pole- and Pad-Mounted Liquid-Immersed Distribution Transformers

During negotiations, several parties raised the question of whether pole-mounted, pad-mounted, and possibly other types of liquid-immersed transformers should be considered in separate equipment classes. (ABB, Pub. Mtg. Tr., No. 89 at p. 230) DOE acknowledges that as standards rise, transformer types which previously had similar incremental costs may start to diverge and requests comment on whether and why separate equipment classes are warranted for pole-mounted, pad-mounted, and other types of liquid-immersed distribution transformers.

c. BIL Ratings in Liquid-Immersed Distribution Transformers

During negotiations, several parties raised the question of whether liquid-immersed distribution transformers should have standards set according to BIL rating, as do medium-voltage, dry-type distribution transformers. (ABB, Pub. Mtg. Tr., No. 89 at p. 218) DOE acknowledges that as standards rise, BIL ratings which previously had similar incremental costs may start to diverge and requests comment on whether and why separate equipment classes are warranted for liquid-immersed transformers of different BIL ratings. DOE requests particular comment on how many BIL bins are appropriate to cover the range and where the specific boundaries of those bins should lie.

3. Technology Options

The technology assessment provides information about existing technology options to construct more energy-efficient distribution transformers. There are two main types of losses in transformers: no-load (core) losses and load (winding) losses. Measures taken to reduce one type of loss typically increase the other type of losses. Some examples of technology options to improve efficiency include: (1) Higher-grade electrical core steels, (2) different

conductor types and materials, and (3) adjustments to core and coil configurations.

In consultation with interested parties, DOE identified several technology options and designs for consideration. These technology options are presented in Table IV.2. Further detail on these technology options can be found in chapter 3 of the preliminary TSD.

Table IV.2—Options and Impacts of Increasing Transformer Efficiency

No-load losses

Load losses

Cost impact

To decrease no-load losses

Use lower-loss core materials

Lower

No change *

Higher.

Decrease flux density by:

Increasing core cross-sectional area (CSA)

Lower

Higher

Higher.

Decreasing volts per turn

Lower

Higher

Higher.

Decrease flux path length by decreasing conductor CSA

Lower

Higher

Lower.

Use 120° symmetry in three-phase cores **

Lower

No change

TBD.

To decrease load losses

Use lower-loss conductor material

No change

Lower

Higher.

Decrease current density by increasing conductor CSA

Higher

Lower

Higher.

Decrease current path length by:

Decreasing core CSA

Higher

Lower

Lower.

Increasing volts per turn

Higher

Lower

Lower.

* Amorphous core materials would result in higher load losses because flux density drops, requiring a larger core volume.

** Sometimes referred to as a “hexa-transformer” design.

HYDRO-Quebec (IREQ) notified DOE that a new iron-based amorphous alloy ribbon for distribution transformers was developed that has enhanced magnetic properties while remaining ductile after annealing. Further, IREQ noted that a distribution transformer assembly using this technology has been developed. (IREQ, No. 10 at pp. 1-2)

DOE was not able to analyze the described material in the NOPR phase of the rulemaking, but intends to explore it further in the final rule. Two of the challenges facing amorphous steel include availability of the raw material and core manufacturing capacity. DOE seeks comment and analysis about amorphous steels that offer greater raw material availability and greater capacity to manufacture amorphous core steel.

a. Core Deactivation

As noted previously, core deactivation technology employs the concept that a system of smaller transformers can replace a single, larger transformer. For example, three 25 kVA transformers operating in parallel could replace a single 75 kVA transformer.

DOE understands that winding losses are proportionally smaller at lower load factors, but for any given current, a smaller transformer will experience greater winding losses than a larger transformer. As a result, those losses may be more than offset by the smaller transformer's reduced core losses. As loading increases, winding losses become proportionally larger and eventually outweigh the power saved by using the smaller core. At that point, the control unit (which consumes little power itself) switches on an additional transformer, which reduces winding losses at the cost of additional core losses. The control unit knows how efficient each combination of transformers is for any given loading, and is constantly monitoring the unit's power output so that it will use the optimal number of cores. In theory, there is no limit to the number of transformers that may operate in parallel in this sort of system, but cost considerations would imply an optimal number.

DOE spoke with a company that is developing a core deactivation technology. Noting that many dry-type transformers are operated at very low loadings a large percentage of the time (

e.g.,

a building at night), the company seeks to reduce core losses by replacing a single, traditional transformer with two or more smaller units that could be activated and deactivated in response to load demands. In response to load demand changes, a special unit controls the transformers and activates and/or deactivates them in real-time.

Although core deactivation technology has some potential to save energy over a real-world loading cycle, those savings might not be represented in the current DOE test procedure. Presently, the test procedure specifies a single loading point of 50 percent for liquid-immersed and MVDT transformers, and 35 percent for LVDT. The real gain in efficiency for core deactivation technology comes at loading points below the root mean square (RMS) loading specified in the test procedure, where some transformers in the system could be deactivated. At loadings where all transformers are activated, which may be the case at the test procedure loading, the combined core and coil losses of the system of transformers could exceed those of a single, larger transformer. This would result in a lower efficiency for the system of transformers compared to the single, larger transformer.

In response to the preliminary analysis, NEMA commented that core deactivation technology is unrelated to the design of a transformer, but rather is related to the system of which it is a part. Therefore, NEMA commented, it is outside the scope of this rulemaking, because all transformers must comply with DOE regulations. (NEMA, No. 13 at p. 3) ABB agreed that core deactivation technology is not related to the design of a transformer, but rather related to the design of the system in which the transformer is deployed. ABB noted that core deactivation technology input voltage source is disconnected from the transformer terminals, similar to a switchgear component and, as such, is not an integral element of the distribution transformer any more than a disconnect switch or circuit breaker. ABB commented that DOE does not consider other systems for energy efficiency, but if it is to look at core deactivation technology, perhaps it should also consider technologies that maintain the load power factor closer to unity. (ABB, No. 14 at pp. 3, 6)

Howard Industries (HI) commented that core deactivation technology does not currently exist for liquid-immersed transformers, and has not been evaluated for feasibility. In its opinion, core deactivation technology could cause several issues, such as flicker problems and in-rush current/surge protection. Additionally, HI believed that there are patent issues for this technology. For these reasons, HI recommended that DOE not consider core deactivation technology for liquid-immersed transformers. (HI, No. 23 at pp. 4, 11) Edison Electric Institute (EEI) agreed that core deactivation should not be considered for liquid-immersed transformers, which face significant load diversity because multiple buildings and/or homes can be served by a single transformer. EEI commented that, due to this load diversity, it is highly unlikely that core deactivation would provide energy savings for liquid-immersed transformers. (EEI, No. 29 at pp. 4-5)

HVOLT commented that core deactivation is not feasible. Based on HVOLT calculations, core deactivation only achieves fewer losses than a single, full-sized unit when loaded below 15 percent. Core deactivation also requires considerations for impedance, regulation, switching devices, and transformer reliability, making the technology unattractive for efficiency regulations. (HVOLT, No. 33 at pp. 2-3) Furthermore, HVOLT performed loading analyses of core deactivation technology and found that the only loading point where it beats traditional transformers was at zero percent. (HVOLT, Pub. Mtg. Tr., No. 34 at p. 60) However, Warner Power indicated that HVOLT's analysis was based on assumed numbers rather than actual designs and stated that core deactivation technology is more efficient than HVOLT's analysis indicated. (WP, Pub. Mtg. Tr., No. 34 at p. 62) Warner Power also commented that the 0.75 scaling factor did not accurately capture the efficiency of the smaller component transformers in a core deactivation system and asserted that it would prefer to see a linear scaling factor (WP, No. 30 at pp. 6-7, 11). Furthermore, Warner Power pointed out that core deactivation technology is better suited for many small loads than for large, discrete loads. The multiple, smaller loads create a smooth load profile throughout the day without sudden large demands. (WP, No. 30 at p. 7) Warner Power also commented that, for core deactivation technology, it is important to note that the secondary and tertiary component transformers do not typically power on at 33 percent and 66 percent load. Rather, the switching point is where the system operates with the lowest total losses and is specific to the transformer design. (WP, No. 30 at p. 7) Finally, Warner Power stated that core deactivation technology allows a transformer to achieve higher efficiency at low loading values. WP hypothesized that average power consumption will go down in buildings and transformer core losses will start to become more significant, thus making core deactivation technology more desirable. (WP, Pub. Mtg. Tr., No. 34 at p. 42)

NRECA and the NRECA Transmission & Distribution Engineering Committee (T&DEC) commented that core deactivation technology would be extremely difficult to successfully implement from an economical viewpoint. (NRECA/T&DEC, No. 31 and 36 at p. 2) Southern Company (SC) agreed and noted that core deactivation technology does not seem practical or cost-effective because it would use more materials than a single transformer, which would increase the weight and cost of the unit. SC further noted that the increased weight could be problematic for pole-mounted transformers. (SC, No. 22 at p. 3)

FPT commented that DOE should not consider core deactivation in the efficiency standard rulemaking at this time because it is only advantageous in certain situations with low loading requirements, and thus only represents a small portion of the market. (FPT, No. 27 at p. 3) Rather, FPT suggested that DOE encourage users to de-energize the LVDT from the primary switch/breaker. FPT also noted that the technology would face challenges with medium-voltage transformers, such as pre-strikes, re-strikes, ferroresonance, and reducing the life of the primary circuit sectionalizing device. (FPT, No. 27 at p. 3)

Berman Economics was interested to know if DOE would also be looking at the potential differences in stress and wear on the transformer as one is activating and deactivating the core deactivation transformer. (BE, Pub. Mtg. Tr, No. 34 at p. 62)

DOE appreciates all of the comments from interested parties regarding core deactivation technology. DOE understands that core deactivation technology is most easily implemented in LVDT distribution transformer designs. Implementing core deactivation technology in medium-voltage distribution transformers is possible, but poses difficulties for switching the primary and secondary connections. For the NOPR, DOE has not fully quantified these difficulties because it did not directly analyze core deactivation technology, although DOE believes it may be possible to evaluate the technology using its existing transformer designs. DOE also acknowledges that operating a core deactivation bank of transformers instead of a single unit may save energy and lower LCC for certain consumers. At present, however, DOE is adopting the position that each of the constituent transformers must comply with the energy conservation standards under the scope of the rulemaking.

b. Symmetric Core

DOE understands that several companies worldwide are commercially producing three-phase transformers with symmetric cores—those in which each leg of the transformer is identically connected to the other two. The symmetric core uses a continuously wound core with 120-degree radial symmetry, resulting in a triangularly shaped core when viewed from above. In a traditional core, the center leg is magnetically distinguishable from the other two because it has a shorter average flux path to each. In a symmetric core, however, no leg is magnetically distinguishable from the other two.

One manufacturer of symmetric core transformers cited several advantages to the symmetric core design. These include reduced weight, volume, no-load losses, noise, vibration, stray magnetic fields, inrush current, and power in the third harmonic. Thus far, DOE has seen limited cost and efficiency data for only a few symmetric core units from testing done by manufacturers. DOE has not seen any designs for symmetric core units modeled in a software program.

DOE understands that, because of zero-sequence fluxes associated with wye-wye connected transformers, symmetric core designs are best suited to delta-delta or delta-wye connections. While traditional cores can circumvent the problem of zero-sequence fluxes by introducing a fourth or fifth unwound leg, core symmetry makes extra legs inherently impractical. Another way to mitigate zero-sequence fluxes comes in the form of a tertiary winding, which is delta-connected and has no external connections. This winding is dormant when the transformer's load is balanced across its phases. Although symmetric core designs may, in theory, be made tolerant of zero-sequence fluxes by employing this method, this would come at extra cost and complexity.

Using this tertiary winding, DOE believes that symmetric core designs can service nearly all distribution

transformer applications in the United States. Most dry-type transformers have a delta connection and would not require a tertiary winding. Similarly, most liquid-immersed transformers serving the industrial sector have a delta connection. These market segments could use the symmetric core design without any modification for a tertiary winding. However, in the United States most utility-operated distribution transformers are wye-wye connected. These transformers would require the tertiary winding in a symmetric core design.

DOE understands that symmetric core designs are more challenging to manufacture and require specialized equipment that is currently uncommon in the industry. However, DOE did not find a reasonable basis to screen this technology option out of the analysis, and is aware of at least one manufacturer producing dry-type symmetric core designs commercially in the United States.

For the preliminary analysis, DOE lacked the data necessary to perform a thorough engineering analysis of symmetric core designs. To generate a cost-efficiency relationship for symmetric core design transformers, DOE made several assumptions. DOE adjusted its traditional core design models to simulate the cost and efficiency of a comparable symmetric core design. To do this, DOE reduced core losses and core weight while increasing labor costs to approximate the symmetric core designs. These adjustments were based on data received from manufacturers, published literature, and through conversations with manufacturers. Table IV.3 indicates the range of potential adjustments for each variable that DOE considered and the mean value used in the analysis.

Table IV.3—Symmetric Core Design Adjustments

Range

[Percentage changes]

Core losses (W)

Core weight (lbs)

Labor hours

Minimum

−0.0

−12.0

+10.0

Mean

−15.5

−17.5

+55.0

Maximum

−25.0

+100.0

DOE applied the adjustments to each of the traditional three-phase transformer designs to develop a cost-efficiency relationship for symmetric core technology. DOE did not model a tertiary winding for the wye-wye connected liquid-immersed design lines (DLs). Based on its research, DOE believes that the losses associated with the tertiary winding may offset the benefits of the symmetric core design and that the tertiary winding will add cost to the design. Therefore, DOE modeled symmetric core designs for the three-phase, liquid-immersed design lines without a tertiary winding to examine the impact of symmetric core technology on the subgroup of applications that do not require the tertiary winding.

NPCC and NEEA jointly commented that DOE should revise its assumptions about costs and limitations of symmetric core designs in accordance with information provided by manufacturers of these technologies. (NPCC/NEEA, No. 11 at p. 2) Furthermore, NPCC and NEEA noted that DOE should revise its analysis for symmetric core designs to account for labor costs that mirror those of conventional core designs. NPCC and NEEA recommended that DOE request additional data from manufacturers that are producing this technology. (NPCC/NEEA, No. 11 at pp. 4, 6)

Hex Tec (HEX) commented that DOE should consider a symmetric core design using amorphous core steel in its evaluation. (HEX, No. 35 at p. 1) It noted that there are several variations of the symmetric core design being made around the world and that licenses are available. Furthermore, it commented that amorphous metal suppliers are emerging in India and China, concluding that there are no barriers to adopting symmetric core technology with an amorphous core. (HEX, No. 35 at p. 1) Hex Tec pointed out that amorphous units up to 3 MVA in size have been produced using Evans distributed gap core construction, but are labor intensive and difficult to produce, and concluded that amorphous designs are easier to make using a symmetric core. (HEX, No. 35 at p. 1) Finally, Hex Tec submitted a letter written by the Vice President of Research & Development at Metglas that indicates that symmetric core units using amorphous steel of 15 to 100 kVA demonstrated core losses of 0.13 Watts/lb at an induction of 1.2 T. The letter also noted that audible sound levels were low. (HEX, No. 35 at p. 14)

Hammond (HPS) commented that its analytical and prototype work indicated that symmetric core designs do not experience a core loss advantage but do have higher manufacturing costs. (HPS, No. 3 at p. 2) However, Hex Tec commented that it builds symmetric cores with labor costs and material savings that are comparable to those incurred by conventional construction. (HEX, Pub. Mtg. Tr., No. 34 at p. 25) Hex Tec noted that the equipment to produce symmetric wound cores is significantly less expensive than flat stack steel equipment and that the labor production times are lower. (HEX, Pub. Mtg. Tr., No. 34 at p. 52) Hex Tec added that labor requirements, both TAC time and process times, are lower for symmetric core designs than for conventional designs. (HEX, No. 35 at p. 2)

Hex Tec submitted data showing that the weight of three-phase, 75 kVA LVDT symmetric core designs ranged from 390 to 600 pounds between 98.6 and 99.2 percent efficiency. These weights are lower than the weights of comparably efficient designs using conventional cores. (HEX, No. 35 at p. 7) Hex Tec also submitted data comparing the efficiency, dimensions, core and coil material content, and cost of several conventional designs for three-phase, 75 kVA LVDT units to those of otherwise identical symmetric core designs. (HEX, No. 35 at p. 8) Hex Tec noted it took the same amount of labor time as a major conventional-design manufacturer to produce a three-phase 75 kVA LVDT rated at CSL3,

and that it was able to do so with lower material costs. (HEX, Pub. Mtg. Tr., No. 34 at p. 110) Hex Tec also submitted data showing comparisons between the weight, losses, and costs of conventional core designs and symmetric core designs at 1000

kVA and 2000 kVA for MVDTs. (HEX, No. 35 at pp. 9-10)

“Candidate Standard Levels” (CSLs) are analogous to the Efficiency Levels (ELs) DOE utilizes together in the NOPR to create Trial Standard Levels (TSLs). This particular commenter refers to CSL3 from the 2007 rulemaking, not the present one.

Warner Power pointed out that recent improvements in the manufacturing process for symmetric core designs, leveraged by increasing volumes, will bring labor costs down to approximately 10 percent below labor costs for conventional cores. (WP, No. 30 at p. 3) Warner Power commented that symmetric cores use a wound core with no scrap and approximately 15 percent lower weight than that of conventional cores. (WP, No. 30 at p. 3) Warner felt that DOE's symmetric core analysis contained some significant errors that would generate the wrong output, and that the manufacturing cost estimates for symmetric cores were overstated. (WP, No. 30 at p. 9; WP Pub. Mtg. Tr., No. 34 at p. 111)

Power Partners commented that DOE should not set a standard based on symmetric core designs because they are not common in the industry and could place an unreasonable burden on smaller manufacturers who would be unable to invest in the equipment necessary for the technology. (PP, No. 19 at p. 2) NEMA agreed, commenting that symmetric core is in its infancy and has low penetration in the industry and should not be introduced into the regulation until it has been proven in the marketplace. (NEMA, No. 13 at p. 3) FPT commented that symmetric core technology should not be used as the basis for increasing efficiency levels and noted that, while the technology may be advantageous in some areas, it may present problems with larger transformers. (FPT, No. 27 at pp. 3-4, 13) Warner Power disagreed and stated that symmetric core designs and core deactivation technology should be included in the scope of DOE's analysis, recommending several symmetric core and core deactivation design option combinations. (WP, No. 30 at p. 9)

NEEA reiterated that symmetric core manufacturers have stated that there should not be any patent concerns for the technology, since it is not yet patented. (NEEA, No. 11 at p. 4; NEEA, Pub. Mtg. Tr., No. 34 at p. 261) Howard Industries disagreed and commented that DOE should not consider symmetric core technology because it is patented by Hexaformer AB of Sweden, which would result in increased licensing costs. (HI, No. 23 at pp. 3-4, 6-7, 11) Furthermore, HI noted that no manufacturers in North America currently produce the design for liquid-immersed units. (HI, No. 23 at pp. 3-4, 6-7, 11) HI also pointed out that Hexaformer AB does not produce units higher than 200 kVA and 24 kV, whereas most utilities require larger kVA sizes and 35 kV. (HI, No. 23 at pp. 3-4, 6-7, 11) Finally, Howard commented that all efficiency improvements for symmetric core liquid-immersed designs are theoretical at this point. (HI, No. 23 at pp. 3-4, 6-7, 11)

Southern Company commented that symmetric core technology is not feasible for utility applications because they require wye-wye connections, while symmetric cores have a delta connection. SC noted that, while a tertiary winding may enable the symmetric core design to be connected in the system, SC has had trouble in the past with tertiary windings and has discontinued purchasing transformers that use them. (SC, No. 22 at p. 2) Howard Industries and HVOLT also noted that most utility transformers are wye-wye connected and would need a delta tertiary winding to use symmetric core technology, which would drive down efficiency while increasing costs. (HI, No. 23 at pp. 3-4, 6-7, 11; HVOLT, Pub. Mtg. Tr., No. 34 at p. 50; HVOLT, Pub. Mtg. Tr., No. 34 at p. 50)

DOE attempts to consider all designs that are technologically feasible and practicable to manufacture and believes that symmetric core designs can meet these criteria. However, DOE has not been able to obtain or produce sufficient data to modify its analysis of symmetric cores since the preliminary analysis. Therefore, although not screened out, DOE has not considered symmetric core designs for its NOPR analyses. DOE welcomes comment and submission of engineering data that would be useful in analyzing symmetric core designs in the final rule.

c. Intellectual Property

In setting standards, DOE seeks to analyze the efficiency potentials of commercially available technologies and working prototypes as well as the availability of those technologies to the market at-large. If certain market participants own intellectual property that enable them to reach efficiencies that other participants practically cannot, amended standards may reduce the competitiveness of the market.

In the case of distribution transformers, stakeholders have raised potential intellectual property concerns surrounding both symmetric core technology and amorphous metals in particular. DOE currently understands that symmetric core technology itself is not proprietary, but that one of the more commonly employed methods of production is the property of the Swedish company Hexaformer AB. However, Hexaformer AB's method is not the only one capable of producing symmetric cores. Moreover, Hexaformer AB and other companies owning intellectual property related to the manufacture of symmetric core designs have demonstrated an eagerness to license such technology to others that are using it to build symmetric core transformers commercially today.

Warner Power commented that the well-known symmetric core design (Hexaformers) is subject to worldwide patents for the core winding and assembly process, but multiple licenses have been authorized and the IP owner has indicated it will entertain additional licenses. The basic design concept is not patented, and several other manufacturers make symmetric cores, so patents should not be a limiting factor. (WP, No. 30 at pp. 3-4)

EEI noted that, if certain higher-efficiency designs are covered by patents, then the number of manufacturers may decrease, which would increase transformer prices. It recommended that DOE discuss any relevant patents and indicate whether they will be in place after 2016. (EEI, No. 29 at p. 10)

DOE understands that symmetric core technology may ultimately offer a lower-cost path to higher efficiency, at least in certain applications, and that few symmetric cores are produced in the United States. However, DOE notes again that it has been unable to secure data that are sufficiently robust for use as the basis for an energy conservation standard, but encourages interested parties to submit data that would assist in DOE's analysis of symmetric core technology.

B. Screening Analysis

DOE uses the following four screening criteria to determine which design options are suitable for further consideration in a standards rulemaking:

Technological feasibility.

Technologies incorporated in commercial products or in working prototypes will be considered to be technologically feasible.

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.

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.

Safety of technologies.

If it is determined that a technology will have significant adverse impacts on health or safety, it will not be considered further. (10 CFR part 430, subpart C, appendix A)

In the preliminary analysis, DOE identified the technologies for improving distribution transformer efficiency that were under consideration. DOE developed this initial list of design options from the technologies identified in the technology assessment. Then DOE reviewed the list to determine if the design options are practicable to manufacture, install, and service; would adversely affect equipment utility or equipment availability; or would have adverse impacts on health and safety. In the engineering analysis, DOE only considered those design options that satisfied the four screening criteria. The design options that DOE did not consider because they were screened out are summarized in Table IV.4.

Table IV.4—Design Options Screened Out of the Analysis

Design option excluded

Eliminating screening criteria

Silver as a Conductor Material

Practicability to manufacture, install, and service.

High-Temperature Superconductors

Technological feasibility; Practicability to manufacture, install, and service.

Amorphous Core Material in Stacked Core Configuration

Technological feasibility; Practicability to manufacture, inst

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