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UNITED STATES OF AMERICA

DEPARTMENT OF ENERGY 

U.S. DEPARTMENT OF ENERGY

PUBLIC MEETING ON ENERGY CONSERVATION STANDARD

SUPPLEMENTARY ANALYSES FOR DISTRIBUTION TRANSFORMERS

U.S. Department of Energy

1000 Independence Avenue, SW

Washington, DC 20585

Room 8E-089

Wednesday

June 20, 20l2

Facilitator:

James Raba

U.S. Department of Energy
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Participants Identified:

Tim Ballo

Earthjustice

1625 Massachusetts Avenue

Suite 702

Washington, DC 20036

Robert Berman

Berman Economics

1915 Grand Court

Vienna, VA 22182

Dr. Edwin Brush

BBF & Associates

154 West 2nd Street, No. 219

Boston, MA 02127

John Caskey 

Electrical Manufacturers Association

1300 North 17TH Street, Suite 1752

Rosslyn, VA 22209

Greg Coulter

GE Prolec

2030 Yellowstone Drive

Fort Mill, SC 29707

Andrew deLaski

Appliance Standards Awareness Project

16 Cohasset Street

Boston, MA 02131

Chuck Foster 

Edison Electric Institute

Foster & Jamison

410 Rosedale Court

Warrenton, VA 20187

Carlos Gaytan

Prolec GE International

S.de R.L. de C.V.

Blvd. Carlos Salinas de Gortari

Km. 9.25 Apodaca, N.L. 66600

Mexico
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Steve Griffith

National Electrical Manufacturers Association

1300 North 17TH Street, Suite 1752

Rosslyn, VA 22209

Bruce Hirsch

Baltimore Gas and Electric

1068 North Front Street, Room 300

Baltimore, MD 21202

Alex Hoffman

American Public Power Association

1875 Connecticut Avenue, NW, Suite 1200

Washington, DC 20009

Gerald Hodge

Howard Industries, Inc.

PO Box 1588

Laurel, MS 39441

Richard Lyke

AK Steel Corporation

705 Curtis Street

Middletown, OH 45043

Aaron Meyers

Cooper Power Systems

1900 East North Street, M/S 1CC

Waukesha, WI 53188

Jerry Corkran

Cooper Power Systems

1900 East North Street

Waukesha, WI 53188

Steve Nadel

American Council for an Energy-Efficient Economy

529 14th Street N.W., Suite 600

Washington, DC 20045

Wes Patterson

Navigant Consultant

2705 Scottsdale Lane

Raleigh, NC 27613
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Ray Polinski 

ATI Allegheny Ludlum

585 Silicon Drive

Leechburg, PA 15656

Steven Rosenstock

Edison Electric Institute

701 Pennsylvania Avenue, NW

Washington, DC 20004

Bob Saint 

National Rural Electric Cooperative Association

4301 Wilson Boulevard, SS9-204

Arlington, VA 22203

Mahesh P. Sampat

EMS International Consulting Inc.

1180 Brookview Drive

Athens, GA 30606

Bob Smith

Federal Pacific

601 Old Airport Road

Bristol, VA 24201

Meili Sohl

Edison Electric Institute

701 Pennsylvania Avenue, NW

Washington, DC 20004

Webinar Participants (Identified):

Alan Traut

Power Partners

200 Newton Bridge Road

Athens, GA 30607

Alan Wilkes

Wilks Consulting

1049 Valley Road

Dyersburg, TN 38024

Ali Ghaforian

ERMCO, Inc.
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1040 Scott Terrace

Athens, GA 30606

Andrew Swisher

Engineering

7300 Fenwick Lane

Westminster, CA 92683

Antonio Trujillo

Cooper Power Systems

1900 North Street

Waukeshau, WI 53188

Bikash Basu

Distribution Apparatus

7300 Fenwick Lane, Room 169

Westminster, CA 92683

Brian Kaja

General Electric

7000 West Bert Kouns Industrial Loop

Shreveport, LA 71129

Carl Bush

PEMCO Corporation

P.O. Box 1319

Bluefield, VA 24605

Charles Drexler

Kentucky Association of Electric Cooperatives

4515 Bishop Lane

Louisville, KY 40220

Charles Simmons

Progress Energy

1418 Mechanical Boulevard

Garner, NC 27529

Craig DeRouen

ERMCO

2225 Industrial Road

Dyersburg, TN 38024

Daniel Peterson

Central Moloney, Inc.
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P.O. Box 6608

Pine Bluff, AR 71611

David Lis

Northeast Energy Efficiency Partnerships

91 Hartwell Avenue

Lexington, MA 02421

Makoto Shinohara

Hitachi

46-1 Tomioka

Tainai-shi, Japan 9592608

Dave Millure

Metglas Inc.

440 Allied Drive

Conway, SC 29526

Demetrios Thanasoulis

National Grid

175 Hicksville, NY 11801

Dong Kim

Engineering

1 Innovation Way

Pomona, CA 91768

Ebrima Cham

Consolidated Edison

1601 Bronxdale Avenue

Bronx, NY 10462

Eduardo Robles

Engineering

4100 Rio Bravo Suite 211

El Paso, TX 79902

Edward Varnado

IID Energy

333 East Barioni Boulevard

Imperial, CA 92251

Eric Petersen 

AK Steel Corporation

705 Curtis Street
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Middletown, OH 45053

Ishmael Leon

Prolec GE

Carlos Salinas de Gortari

Mexico 66600

James Rakowski

ATI Allegheny Ludlum

1300 Pacific Avenue

Natrona Heights, PA 15065

Jerry Allen

Metglas, Inc.

440 Allied Drive

Conway, SC 29526

Jerry Schoen

AK Steel Corporation

705 Curtis Street

Middletown, OH 45043

John Oates

LIPA

175 East Old Country Road

Hicksville, NY 11801

Joseph Rempe

Tacoma Power

3628 South 35th Street

Tacoma, WA 98409

Justin Rush

Westar Energy

4001 NE 14th

Topeka, KS 66612

Katie

Katie Coughlin

Lawrence Berkeley National Laboratory

MS 90-4000

Berkeley, CA 94729

Kenneth Winder

Moon Lake Electric Association, Inc.
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800 West U.S. Highway 40

Roosevelt, UT 84066

Kevin Oehlmann

Consolidated Edison

4 Irving Place

New York City, New York 10003

Linda Wilson

NYS Office of the Attorney General

120 Broadway

New York, NY 10271

Paul Ryan

HMA-Metglas

800 Grand Avenue

Carlsbad, CA 92008

Paul Sturgiou

Consolidated Edison

1601 Bronxdale Avenue

Bronx, NY 10462

Philip Hopkinson

HVOLT, Inc.

3704 High Ridge Road

Charlotte, NC 28270

Ray Harlow

Young & Company

530 South Marengo Avenue

Pasadena, CA 91101

Richard Lyke

AK Steel Corporation

705 Curtis Street

Middletown, OH 45043

Rob Carmichael

Navigant Consulting

1900 M Street

Washington, DC 20036

Robert Van Buskirk

U.S. Department of Energy
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1000 Independence Avenue, SW

Washington, DC 20585

Robin Roy

Natural Resources Defense Council

1152 15th Street

Washington, DC 20005

Seth Blumen

SRP

P.O. Box 52025

Phoenix, AZ 85072

Susmitha Tarlapally

ABB

500W Highway 94

Jefferson City, MO 65109

Tamara Johnson

Springfield Utility Board

P.O. Box 300

Springfield, OR 97477

Tom Petrosino

TRP Consulting

1917 Park Road

Charlotte, NC 28203

Wilton Cedeno

Consolidated Edison

4 Irving Place

New York, NY 10003

ConEd

Participants from DOE:

John Cymbalsky

U.S. Department of Energy

1000 Independence Avenue, SW

Washington, DC 20585

Alan Strasser

U.S. Department of Energy

1000 Independence Avenue, SW
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Washington, DC 20585

James Raba

U.S. Department of Energy

1000 Independence Avenue, SW

Washington, DC 20585

Participants from Navigant Consulting and Lawrence 

Berkeley National Laboratory:

Brian Coffey

Navigant Consulting

1900 M Street

Washington, DC 20036

Mike Rivest

Navigant Consulting

1900 M Street

Washington, DC 20036

Matthew Nardotti

Navigant Consulting

1900 M Street

Washington, DC 20036

Chris Bolduc

Lawrence Berkley National Laboratory

1 Cyclotron Rd

M/S 90-4000

Berkeley, CA 94720

Greg Rosenquist

Lawrence Berkley National Laboratory

1 Cyclotron Rd

M/S 90-4000

Berkeley, CA 94720

Pamela Costello

Navigant Consulting

1900 M Street

Washington, DC 20036

Presenters:

Brian Coffey

Navigant Consulting
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Chris Bolduc

Lawrence Berkley National Laboratory
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AGENDA

 ITEM PAGE

Welcome, Mr. Raba 8

Self-Introductions 12

Agenda Review 16

Regulatory History, Mr. Coffey 18

Navigant Presentation, Mr. Coffey

Added Liquid Immersed Equipment Classes 20

TSLs 34

LBL Presentation, Mr. Bolduc

Scaling 38

National Level Impacts, NIA Results 95
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1 9:13 a.m.

2 P R O C E E D I N G S

3 MR. RABA: Let’s get started. Please take 

4 your seats. Good morning everyone. Welcome to the 

5 Department of Energy’s Public Meeting, whether 

6 you’re in person or via the Webinar. This is the 

7 U.S. Department of Energy’s Public Meeting about the 

8 Supplementary Analysis for Liquid Immersed 

9 Distribution Transformers. Today is Wednesday, June 

20th 10 , the first day of summer, here in the Forrestal 

11 Building, Washington, D.C. 

12 My name is Jim Raba, Department of Energy. 

13 I will be the facilitator for today. So good to see 

14 you this morning. I’m glad you could make it here 

15 on time for an early start in the day. We have some 

16 opening remarks from our presiding officer, John 

17 Cymbalsky.

18 MR. CYMBALSKY: Thanks, Jim. Welcome 

19 everybody to the liquid immersed distribution 

20 transformer meeting. The title is very important 

21 here because that is the only focus of today’s 

22 meeting. Today we are not here to talk about any 

23 other topics relating to transformers. We have not 

24 revised analysis into the final rule. This is just 

25 supplementary work that we undertook based on 

26 comment, and based on what we talked about during 
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1 the negotiated rulemaking back last fall. We wanted 

2 to separate out some product classes and just take a 

3 look at the numbers, so that is our focus today. I 

4 appreciate the fact that people in the room might 

5 have other things to say about transformers and they 

6 submitted comments to our proposal. We are 

7 currently reviewing those comments so please don’t 

8 feel the need that you need to repeat comments that 

9 are not pertaining to this exact topic. We’d like 

10 to keep on point here, keep the meeting focused and, 

11 you know, we have several hours for this, but we’d 

12 like to keep it on focus.

13 Also I’d like to help with the Webinar, I 

14 think we finally figured out our technical issues, 

15 and what that came to be is that we were leaving 

16 microphones turned on when we’re not using them, and 

17 so when a voice on the phone came off the speakers 

18 it went into the microphone and caused feedback for 

19 the people on the phone, on the Webinar. So I would 

20 ask everybody, if you’re not speaking into your 

21 microphone, please switch it off, including the 

22 stand mics in the back. There’s an on/off switch. 

23 If you come up to speak in the mics on the stands, 

24 you switch it up to speak and then please when 

25 you’re done, switch it off and then this way 
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1 everyone on the phone can hear without feedback. At 

2 the last couple meetings it worked very well when we 

3 all adhered to this policy. 

4 With that, back to Jim, and again, thank 

5 you all for coming.

6 MR. RABA: I may be repeating some of what 

7 John said, but very helpful of course to keep us all 

8 on the same methodology, the same process. But 

9 today we’re going to focus on whether certain types 

10 of liquid immersed distribution transformers that 

11 are currently part of the same equipment classes 

12 warrant separation, to be separate into separate, 

13 distinct equipment classes. For example, where pole 

14 and pad mounted distribution transformers from the 

15 same equipment class, would they be more 

16 appropriately evaluated as separate equipment 

17 classes? And similarly, we’ll address the 

18 appropriateness of evaluating network and vault19 based liquid immersed distribution transformers as 

20 separate equipment classes.

21 I recall on February 10, 2012, Notice of 

Proposed Rulemaking, and during the February 23rd 22

23 public meeting, DOE asked for comments and whether 

24 certain types of liquid immersed distribution 

25 transformers should be separate, distinct equipment 
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1 classes. A number of interested parties submitted 

2 comments to support such an approach for pole and 

3 pad-mounted liquid immersed distribution 

4 transformers. In addition, they urged DOE to 

5 separate the equipment classes for network and 

6 vault-based distribution transformers with basic 

7 impulse rating levels of 200 kilovolts or more.

8 And since that time, our experts at 

9 Lawrence Berkeley National Laboratory, Navigant 

10 Consulting have prepared a supplemental analysis of 

11 trial efficiency standard levels that include life 

12 cycle cost and payback period analysis for each 

13 separate class of liquid immersed distribution 

14 transformers. ]

15 So today’s discussion, as John pointed 

16 out, will focus on that analysis. There’s been no 

17 modifications or analysis for dry type distribution 

18 transformers because of the purpose and the focus of 

19 today’s public meeting. So we want to hear from 

20 you, your comments, recommendations, data, and 

21 information.

22 So, we traditionally start off with 

23 introductions around the room, and then followed by 

24 introductions from those who are joining us via the 

25 Webinar. I’m going to start to my left. Turn your 
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1 microphone on before speaking, state your name and 

2 organization. Speak loud and clear and turn your 

3 microphone off when you finish speaking.

4 Self-introductions

5 MR. LYKE: I’m Richard Lyke, I’m 

6 representing AK Steel Corporation.

7 MR. BERMAN: Robert Berman, Berman 

8 Economics.

9 MR. GAYTAN: I’m Carlos Gaytan, Prolec GE.

10 MR. COULTER: Greg Coulter, GE Prolec.

11 MR. POLINSKI: Ray Polinski, ATI Allegheny 

12 Ludlum.

13 MR. SAINT: Bob Saint, representing the 

14 National Rural Electric Cooperative Association, 

15 NRECA.

16 MR. HIRSCH: Bruce Hirsch, Baltimore Gas 

17 and Electric, representing the Edison Electric 

18 Institute

19 . MR. ROSENSTOCK: Steve Rosenstock, Edison 

20 Electric Institute.

21 MR. HODGE: Gerry Hodge from Howard 

22 Industry.

23 MR. deLASKI: Andrew deLaski, Appliance 

24 Standards Awareness Project.

25 MR. CASKEY: John Caskey, National 
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1 Electrical Manufacturers Association.

2 MR. STRASSER: Alan Strasser, Department 

3 of Energy.

4 MR. CYMBALSKY: John Cymbalsky, DOE.

5 MR. SAMPAT: Mahesh Sampat, EMS 

6 Consulting.

7 MR. GRIFFITH: Steve Griffith, National 

8 Electrical Manufacturers Association.

9 MR. BRUSH: Ned Brush, consultant to the 

10 Copper Development Association.

11 MR. PATTERSON: Wes Patterson, consultant 

12 for Navigant.

13 MR. FOSTER: John Foster representing 

14 Edison Electric Institute.

15 MS. SOHL: Meili Sohl, representing Edison 

16 Electric Institute.

17 MR. RABA: Check to see if that microphone 

18 is on, please. Thank you.

19 MR. ROSENQUIST: Greg Rosenquist, Lawrence 

20 Berkeley National Laboratory. 

21 MR. BALLO: Tim Ballo with Earth Justice.

22 MR. RABA: In the back here.

23 MR. BOLDUC: Chris Bolduc, Lawrence 

24 Berkeley National Laboratory. 

25 MR. RIVEST: Mike Rivest, Navigant 
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1 Consulting.

2 MR. COFFEY: Brian Coffey, Navigant 

3 Consulting.

4 MR. NARDOTTI: Matt Nardotti, Navigant 

5 Consulting.

6 MR. RABA: Over here, yes.

7 MR. MEYERS: Aaron Meyers, Cooper Power.

8 MR. RABA: Welcome. Welcome. We welcome 

9 everyone now -- now for those who are on the 

10 webinar, there are a couple ways to provide 

11 questions and comment, but first of all, if you 

12 would raise your hands to introduce yourselves. 

13 Okay, nothing? Is there anybody on the phone at 

14 this time? Okay. No one on the phone now. There 

15 are a couple ways to do this --

16 PARTICIPANT: Jim, I think we have a 

17 technical difficulty. I know there are people that 

18 are on the phone that couldn’t maybe respond.

19 MR. RABA: Right. Via the phone, indicate 

20 you’d like to provide a question or comment by 

21 raising your hand in the “Go to Meeting” software. 

22 The moderator will be notified that your hand is 

23 raised. Once called upon, say your name and 

24 organization, and speak loud and clear. Does that 

25 help? Also you could gain access via the “Go to 
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1 Meeting.” Use the question window and go to meeting 

2 and submit a question that will be related to the 

3 moderator. If you’re providing a lengthy question, 

4 you’re asked by the organizer to ask your question 

5 via the phone, if we can get it to work. The 

6 function is best reserved for long, technical 

7 issues.

8 We’re writing things down now, those who 

9 can’t see the room. This again -- those who are 

10 participating on the phone via the webinar, welcome. 

11 We have quite a lot of people here. I’ll go top to 

12 bottom. Alan Traut, Alan Wilkes, Antonio Trujillo, 

13 Carl Bush, Charles Drexler, Charles Simmons, Daniel 

14 Peterson, Dave Millure, Demetrios Thanasoulis, Dong 

15 Kim, Ebrima Cham , Eric Peterson, Ishmael Leon, 

16 James Rakowski, Jerry Allen, Katie Coughlin, Kevin 

17 Oehlmann, Linda Wilson, Paul Sturgiou, Phil 

18 Hopkinson, Rob Carmichael, Robert Van Buskirk, Robin 

19 Roy, Tom Petrosino, and Wilton Cedeno .

20 Hands raised, first hand I see raised is 

21 Antonio Trujillo. The phone should work.

22 MR. TRUJILLO: I just wanted to make sure 

23 that you can hear us.

24 MR. RABA: Oh, good. That’s great. Good, 

25 you were right on cue, sir, thank you. Okay. Other 
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1 hands raised, Linda Wilson.

2 MS. WILSON: You just asked if anyone was 

3 on the phone, so I said yes.

4 MR. RABA: Thank you. Perfect. And James 

5 Rakowski’s hand is raised. Are you there sir?

6 MR. RAKOWSKI: Okay. I’m just trying to 

7 make sure.

8 MR. RABA: Okay. We can hear you. Thank 

9 you. I think we’ve got it worked out. So okay, I 

10 think we’ve solved the phone logistics. Thank you 

11 very much for your patience there in webinar land. 

12 It may be a good idea, when you do speak, turn your 

13 phone on, not speaking, turn your phone on mute to 

14 drown any other feedback that might get in the 

15 system.

16 Agenda Review

17 So, you all received a packet of 

18 information as you came in the door. I’ll refer to 

19 that packet. There’s an agenda. There is also a 

20 copy of the proposed rulemaking, or the Notice of 

21 Public Meeting for this, and also the slides for 

22 today’s presentation. 

23 I’ll start by briefly going over the 

24 agenda. From this agenda, after this, we’ll have 

25 our experts from Lawrence Berkeley National 
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1 Laboratory and Navigant Consulting give 

2 presentations on the supplemental analysis -- it’s 

3 in your packet of information -- after which we’ll 

4 entertain comments and discussion. Somewhere in 

5 here we’ll take a break around 10:30 or so this 

6 morning for a coffee break. There’s lots of 

7 opportunity for discussion about the trial standard

8 levels, life cycle cost and payback period analysis 

9 and more.

10 We’re scheduled to finish up today about 

11 one o’clock, so I think, not wanting to truncate the 

12 opportunity for comment and discussion, so we’ll go 

13 efficiently and rapidly forward. We’ll just see how 

14 long it takes for us to do this, otherwise if about 

15 twelve o’clock or so, or 12:30, we still have a fair 

16 piece to go, we’ll pause for lunch, return and go 

17 back at it. 

18 But so far, this is our agenda lineup, you 

19 can see it on your screen also at home. Are there 

20 any questions about the agenda, or comments? I see 

21 none at this point, hear none also. Okay. 

22 So, I’d ask for your consideration. Many 

23 of you are familiar with this process. Please speak 

24 one at a time. You have to turn the microphone on 

25 to speak. Each time, please say your name for the 
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1 record, and I’ll be cuing individuals by name as 

2 best I can so you know who’s in the queue. We’ll 

3 also encourage any follow-on comments. The back and 

4 forth between individuals is sometimes very helpful 

5 to the Department as it’s sorting through what to do 

6 with all this commentary. So please keep the focus 

7 here, turn you cell phones to silent mode if you 

8 would, please. Limit sidebar conversations. If you 

9 can, try to be concise, there’s a lot to be said.

10 Having read the PowerPoint slides last 

11 night, a lot of content here, so let’s see if we can 

12 keep it focused on the analysis today. I must say 

13 if we’re as disciplined in the discussion today as 

14 you were in introductions, then it bodes well for 

15 us, I think. 

16 So I’d like to proceed with the 

17 presentation slides. Brian, would you start us off, 

18 please. Brian Coffey, Navigant Consulting.

19 Regulatory History

20 MR. COFFEY: Can everybody hear me okay? 

21 I think some yes’s and some no’s. Yes’s? Great. 

22 So good morning. Brian Coffey with Navigant 

23 Consulting. First, let’s take a quick review of the 

24 rulemaking history. EPCA 2005 set standards for low 

25 voltage dry type transformers at the NEMA TP1 2002 
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1 level. In October of 2007, DOE issued a final rule 

2 establishing standards for both liquid immersed and 

3 medium voltage dry type transformers. DOE was sued 

4 on that rule relating to issues of environmental 

5 compliance, and that suit was settled. As a result 

6 of that settlement agreement, compliance was 

7 required in 2010 on the original schedule with 

8 standards established in that 2007 rule.

9 However, DOE agreed to an expedited 

10 timeline to determine whether or not to amend 

11 standards for liquid immersed and medium voltage dry 

12 type transformers. So along those lines, DOE 

13 publishes a Notice of Proposed Rulemaking in 

14 February of this year, which I’m sure everybody has 

15 seen, and then the final rule after that must be 

16 published by October 1, 2012 according to that 

17 settlement agreement.

18 So here’s a timeline of the major 

19 rulemaking events. We had our first look at the 

20 analysis in 2011, and a NOPR in February of this 

year. The final rule publishes on October 1st 21 with 

22 compliance required in January 2016. 

23 So what brings us here today? In response 

24 to the NOPR, several parties submitted written 

25 comments supporting new equipment classes for liquid 
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1 immersed distribution transformers. So this would 

2 include, potentially, pole mounted transformers, 

3 network and vault-based transformers, and those with 

4 BIL ratings of 200 kV. In response to that, DOE is 

5 providing supplementary analysis -- has provided 

6 supplementary analysis with several new trial 

7 standard levels and new equipment classes relating 

8 to those TSLs. And this is for liquid immersed 

9 transformers only.

10 The new TSLs which are lettered A through 

11 D. The original TSLs had numbers and the new ones 

12 have letters, just so everyone can distinguish. The 

13 new ones provide separate standards for pole 

14 mounted, network and vault-based, and 200 kV BIL15 rated transformers. 

16 I want to be clear that this supplementary 

17 analysis was conducted with the NOPR data and tools, 

18 so it’s not any kind of pre-final rule work, it’s an 

19 extension of what was done before. And just to 

20 reiterate, no modifications have been made to any of 

21 the dry type classes, low voltage dry or medium 

22 voltage dry are the same.

23 Added Liquid-Immersed Equipment Classes 

24 So now let me take you through those 

25 additional equipment classes and TSLs. There’s some 
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1 judgment involved in dividing a covered product 

2 scope into equipment classes, and DOE does it to 

3 maximize energy savings, maintain equipment utility, 

4 and minimize regulatory complexity. In this case, 

5 DOE saw strong stakeholder support for new liquid 

6 immersed equipment classes, including those for pole 

7 mounted transformers, network and vault-based 

8 transformers, and those with BIL ratings of 200 kV. 

9 So let me discuss those last two first. 

10 Network and vault-based transformers are 

11 generally located in underground concrete vaults in

12 dense urban areas where construction work can be 

13 done only at great cost. These units are generally 

14 built in the stacked core configuration, where H0 is 

15 really the best grade of steel that’s used. DOE 

16 understands that a very large fraction of these 

17 units are already being built with H0, and so 

18 manufacturers simply can’t use the next grade up of 

19 steel to avoid size increases. You know, if you’re 

20 not at the top grade and you really can’t get bigger 

21 or to do so would be of great cost, then you can hop 

22 up to a new steel grade and it’s expensive, but 

23 you’ve saved yourself the hassle of digging up the 

24 vault and replacing the whole thing. But if 

25 everybody is already at the top grade of steel, then 
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1 that trick can’t be played any more. So, depending 

2 on how much wiggle room there is in the vault, 

3 higher standards could mean very expensive vault 

4 replacements that would far outweigh the benefit of 

5 any energy savings obtained.

6 DOE believes that the market size by KVA 

7 for network and vault transformers is more or less 

8 five percent, but that’s something that DOE would 

9 like comment on. 

10 Moving to 200 kV BIL-rated transformers == 

11 yes, question?

12 MR. COULTER: This is Greg Coulter with GE 

13 Prolec. Can we ask or make comments as you talk, or 

14 are we going to wait to the end?

15 MR. COFFEY: No, as we go is great.

16 MR. COULTER: When you talk about network 

17 and vaults, we noticed that there was only a three18 phase category for them. There are network and 

19 vault single phase transformers, and we thought 

20 there ought to be a similar single phase category.

21 MR. COFFEY: So I’ll go through the 

22 equipment class structure. There is a single phase 

23 category.

24 MR. COULTER: For network and vaults?

25 MR. COFFEY: Yes.
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1 MR. COULTER: We just didn’t see that in 

2 the thing that came out. Okay. 

3 MR. COFFEY: I’ll go through the details 

4 of that in a second. But to continue with 200 kV

5 BIL-rated transformers. So basic impulse level is a 

6 measure of transformers’ resistance to very high 

7 voltage transients, which would often come from,

8 say, a lightning strike. The more protection a 

9 transformer has, the more difficult it is, difficult 

10 and costly, to pursue higher efficiency. Although 

11 in the past DOE has kept all liquid immersed BIL 

12 ratings together in a single equipment class, 

13 further increases will push the highest protection 

14 levels, the highest BIL ratings up into the steep 

15 portion of the cost curve, where the energy savings 

16 are less justifiable. 

17 There is some precedence in doing this. 

18 DOE already does so with medium voltage dry type 

19 transformers. And DOE believes that the market size 

20 for these 200 kV BIL-rated units is about one 

21 percent by kV, but again, comment would be 

22 appreciated. Yes, please.

23 MR. COULTER: This is Greg Coulter again. 

24 200 BIL represents almost nothing in the marketplace 

25 for these size transformers. Maybe a quarter of one 
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1 percent is more than generous. Maybe less than 200 

2 total transformers a year might be generous. We 

3 think that break is at 150 kV BIL. 200 BIL is 

4 meaningless in this size transformer. You need -- a 

5 big change happens when we have to go to 150 BIL, 

6 and we think that’s where the big changeover comes, 

7 where it makes it very different for us to meet some 

8 of these efficiency ratings. It’s not 200 BIL. We 

9 could care less. I think the majority of people in 

10 the room would care less about it. If it was 200 

11 BIL you might as well not have it. You’ve either 

12 got to make it meaningful or take it out entirely.

13 MR. COFFEY: That’s helpful. Thank you. 

14 Do you have a sense, offhand -- I’m putting you on

15 the spot here -- but do you have a sense offhand of 

16 what the market size would be by KVA if the line 

17 were drawn at 150? Do you have a gut instinct?

18 MR. COULTER: Yeah, my guess is it’s 

19 around three to four percent.

20 MR. COFFEY: Okay. Thank you.

21 MR. deLASKI: This is Andrew deLaski from 

22 the Appliance Standards Awareness Project, as a 

23 follow on for Greg. So Greg, just to help us 

24 understand, is there a bright line -- do you have 

25 products at 150 and products at 200? Is there a 
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1 space in between or is that -- you sell 150 or you 

2 sell 200, but you don’t sell 175s?

3 MR. COULTER: Simple answer is you’re 

4 exactly right. The breaks are 95, 125, 150, and 

5 200.

6 MR. deLASKI: Okay. So there is no in7 between?

8 MR. COULTER: There is no in-between. And 

9 there’s essentially no 200, so, you know, we’re big 

10 -- 150 at least you get some volume, and 200 there’s 

11 essentially no volume. In a good year, going back 

12 ten years ago, we might have sold 200 units as an 

13 industry of 200 BIL. That was a very good year.

14 MR. deLASKI: Right. Another follow on. 

15 We, in our comments, and in our response to the 

16 NOPR, and I guess you’re aware, you know, we 

17 suggested that the levels that were proposed by the 

18 Department didn’t really merit any separation of 

19 product classes for lower BIL -- for higher BIL 

20 products for poles or vaults. We thought that the 

21 proposal was of such modest improvement that the 

22 changes didn’t need special treatment. So I guess 

23 my question for you is, at what level does it become 

24 apparent to you that you would -- that it becomes 

25 challenging to built a high -- to even build a high 
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1 BIL over 150? In the levels that have been 

2 evaluated by the Department, is it at level one, 

3 level two, level three? Please use efficiency level 

4 because the TSLs, you know, we’ll get all lost in 

5 that.

6 MR. COULTER: There isn't an easy answer 

7 to that. But what we definitely see is a major 

8 shift, a major shift in the way we make product and 

9 the price of product, and the ability to meet the 

10 efficiency levels, when you get to the 150 BIL 

11 level. Certainly, at some of these efficiency 

12 levels we have talked about here, you’re out of 

13 where you can really compete with a silicon steel. 

14 You’ve really pushed it into an amorphous category. 

15 I mean, can we make them? Yeah. We make amorphous. 

16 We do it all the time, and we can handle it. The 

17 point is, you’re not competitive with silicon steel. 

18 And that’s -- that’s the criteria we were going by.

19 MR. deLASKI: Okay. For this three to 

20 four percent of the market that is 150 or greater.

21 MR. COULTER: Right.

22 MR. deLASKI: Okay. Great. Thanks.

23 MR. COFFEY: So thank you, that’s helpful. 

24 This is precisely what this meeting is for, is to 

25 get feedback on the equipment classes, how they’re 
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1 defined and the TSLs that accompany them. Yes, 

2 please.

3 MR. MEYERS: Aaron Meyers, Cooper Power. 

4 Andrew, to answer your question more specifically, 

5 it’s less than five percent that are greater than 

6 150 and above, from essentially last year’s shipment 

7 data for Cooper, and for 200 kV it’s like a tenth of 

8 a percent. 

9 MR. deLASKI: Your numbers are pretty 

10 similar to Greg’s.

11 MR. MEYERS: Supporting Greg’s comment 

12 earlier, 200 kV is essentially nothing, and it’s 

13 less than five percent for 150 and above. And 

14 that’s on a per unit basis.

15 MR. COFFEY: Okay. Well, great. Let me 

16 take you through the new equipment class structure. 

17 Here you can see -- here we’re showing how the new 

18 equipment class structure relates to the old. You 

19 have the old on the left. In the past, it was 

20 simple. There is equipment class one for single 

21 phase, and equipment class two for three phase. And 

22 now on the right, each of these equipment classes is 

23 subdivided into the letters A, B, C, and D. One 

24 thing to note is that 1A and 2A are the classes for 

25 anything that doesn’t meet the definition of 
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1 something else, so it’s a catch-all. It’s not -- in 

2 the analysis that was published on line, we 

3 initially had gotten into the habit of referring to 

4 them as pad-mounted transformers, but we realize 

5 that there could be other units here and there that 

6 maybe aren’t thought of as traditional pad-mount 

7 units, per se. So this is sort of the -- 1A and 2A 

8 is the default class.

9 1B and 2B are specifically for pole 

10 mounted units, overhead poles. And 1C and 2C are 

11 for network and vaults, one and three phase. And 

12 then 1D and 2D are for the 200 kV units.

13 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

14 But based on the testimony, you might -- these could 

15 change, correct?

16 MR. COFFEY: They could.

17 MR. ROSENSTOCK: Thank you.

18 MR. COFFEY: That’s what today is for, is 

19 to receive feedback on that.

20 MR. RABA: Brian, we have a hand raised 

21 from Alan Wilkes. Alan, go ahead, please.

22 MR. WILKES: I would like to be unmuted on 

23 my internet.

24 MR. RABA: You’re on, sir.

25 MR. WILKES: Yes, I’d like to be unmuted.
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1 MR. RABA: You’re on.

2 MR. WILKES: Thank you.

3 MR. CYMBALSKY: No, no. Only if he has a 

4 question will he be unmated. Do you have a 

5 question?

6 MR. RABA: Do you have a question, Mr. 

7 Wilkes?

8 MR. WILKES: No, not at this present time.

9 MR. CYMBALSKY: So, Mr. Wilkes, you will 

10 be unmuted only if you have a question, otherwise, 

11 all the phones will be muted until there is a 

12 question. So if you have a question, raise your 

13 hand and we’ll unmute you, okay?

14 MR. WILKES: Thank you.

15 MR. COFFEY: So now let’s take a look at 

16 what we have for representative units. Two tables. 

17 Left hand table is single phase, and the right hand, 

18 three. Equipment classes 1B and 2A, so that’s the 

19 right column in the left table and the left column 

20 in the right table, those each have two design lines 

21 which makes the scaling simple, because one can 

22 simply choose ELs for each design line 

23 independently, and then fit the line in logarithmic 

24 space for a smooth, straightforward, and self25 consistent standard.
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1 Equipment class 1A, that’s on the far 

2 left, only has a single representative unit, so 

3 there are a few more decisions to be made there, 

4 which I’ll talk through. And then finally, 

5 equipment class 2B. So these are the three-phase 

6 pole mounts, and it’s DOE’s understanding that the 

7 vast majority of three-phase pole mounted 

8 transformers are constructed by triplexing three 

9 single phase cores. So, really it’s like three 

10 single phase units in one housing. And if that’s 

11 true, then it follows that the transformers should 

12 be as efficient as each of its constituent cores, 

13 only at three times the power level.

14 And so DOE, in equipment class 2B, DOE 

15 shows here that the equipment class 2B standards 

16 begin scaling from the single phase pole mounts in 

17 1B, where there are two design lines and a little 

18 bit more robust analysis. Yes, please.

19 MR. ROSENSTOCK: Steve Rosenstock, Edison 

20 Electric Institute. In terms of the three-phase 

21 pole mount, 750 to 2500, it says scaled -- it says 

22 scaled from this slide, and then the following 

23 slide. I guess one -- and again, I appreciate this 

24 information, but it seems like at least in the 

25 information that we’ve received so far we have no 
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1 way of knowing kind of where that falls in terms of 

2 the various ELs. So we’re kind of -- it’s kind of 

3 opaque. It says it’s scaled, but we have no idea, 

4 does that really kind of correspond to an EL1, or an 

5 EL2 or an EL3, or what numbers are we talking about 

6 there? I couldn’t find any information about where 

7 those numbers actually lie in the information that 

8 was sent out by DOE. It just says scaled, and then 

9 there’s an overall analysis, but I couldn’t -- I 

10 couldn’t find it, maybe I wasn’t looking in the 

11 right place. Where do those numbers fall, I say in 

12 terms of the ELs?

13 MR. COFFEY: Sure. I have some tables 

14 that I’m going to present that may answer that 

15 question, but I can say, just for your own 

16 intuition, the three phase poles are going to have 

17 the same efficiency standard as the one phase pole 

18 with the same -- I’m sorry, one-third the KVA 

19 rating. So a single phase pole at 100 KVA, would 

20 receive the same standard as a three phase pole at 

21 300 KVA, and that’s because the way that they’re 

22 most commonly built is to just put three single 

23 phase 100 KVA cores in one housing. But we’ll look 

24 at the TSL charts.

25 MR. RABA: Brian, one more thing too, we 
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1 have a hand raised from Mr. Antonio Trujillo on the 

2 phone. Mr. Trujillo, you’re live, go ahead please.

3 MR. TRUJILLO: My questions is, just the 

4 example that you described, is that only for poles? 

5 Is it going to be different for pads?

6 MR. COFFEY: That’s right.

7 MR. TRUJILLO: Okay. Thank you.

8 MR. CASKEY: John Caskey, NEMA. And 

looking at the original NOPR from February 10th 9 I 

10 think it is, and in there you had various design 

11 lines, like, for example, design line one was liquid 

12 immersed single phase rectangular tank, ten to 167 

13 KVA range, and then you have a representative sample 

14 there. Do those DLs relate at all to the DLs in the 

15 most recent additional analysis?

16 MR. COFFEY: They do. That’s a good 

17 point. So the ELs are the same for all the design 

18 lines. Again, this is an extension of the NOPR 

19 analysis, and so all of the ELs and TSLs that 

20 existed in the NOPR exist in this analysis, they 

21 haven’t changed. The only thing that DOE has done 

22 is added new TSLs using the existing ELs and gave 

23 them letters A through D.

24 MR. CASKEY: I’m not sure I asked the 

25 question correctly. What I’m looking up here where 
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1 you have the DL1 for 1A which goes from 10 KVA up to 

2 833 KVA, how does that definition of that DL1 relate 

3 to the definition of DL1 that’s in the NOPR 

published February 10th 4 .

5 MR. COFFEY: So the design line itself is 

6 exactly the same. What’s different is how it’s 

7 being scaled to derive standards for equipment 

8 classes. And previously, that table that you’re 

9 looking at on the left, all three of those rep units 

10 were in a single class because we didn’t have poles 

11 and pads and networks and vaults. But now, we’ve 

12 got two design lines in the 1B equipment class for 

13 pole mounts, and only one rep unit in the 1A class 

14 for everything else. And so as you’ll see, I’ll 

15 describe that you need to make some decisions about 

16 how you’re going to scale that unit. How can we use 

17 the information for all three design lines to 

18 construct an appropriate standard.

19 MR. CASKEY: Okay. So just to make sure I 

20 understand. So basically the DLs from the February 

10th 21 NOPR and the DLs in this additional analysis are 

22 the same, and the definition of the ELs and the 

23 efficiency levels are the same but the scaling may 

24 throw them off in some areas?

25 MR. COFFEY: That’s right.
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1 MR. CASKEY: Okay. Thanks.

2 Trial Standard Levels

3 MR. COFFEY: So now let’s talk about TSLs. 

4 DOE has added four new trial standard levels to 

5 cover these equipment classes, and they’re lettered 

6 A through D. And just to refresh everybody’s 

7 memory, TSLs are sets of standards that DOE chooses 

8 from when proposing a standard and when actually 

9 setting one. And what it does is, for each 

10 equipment class, chooses ELs, packages them up, and 

11 then that becomes a TSL. So some of the TSLs, you 

12 can see in the chart here, which ELs go with which 

13 equipment class and design line. And so there will 

14 be some overlap, right, so a single EL can exist in 

15 multiple TSLs. Yes, please.

16 MR. ROSENSTOCK: Steve Rosenstock, Edison 

17 Electric Institute. In the Notice of Proposed 

18 Rulemaking there were seven TSLs and now there’s 

19 four more, so basically since it is a final rule 

20 stage, basically all 11 are in play, correct?

21 MR. COFFEY: That's correct.

22 MR. ROSENSTOCK: And there could be other 

23 TSLs if you do any other analysis, correct?

24 MR. COFFEY: There’s -- that’s 

25 theoretically possible, but --
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1 MR. ROSENSTOCK: We could suggest 

2 alternative TSLs in our comments, correct?

3 MR. COFFEY: Sure, yes.

4 MR. ROSENSTOCK: Would they be considered?

5 MR. COFFEY: Yes.

6 MR. ROSENSTOCK: Thank you.

7 MR. deLASKI: As a follow on to that --

8 MR. RABA: Andrew deLaski.

9 MR. deLASKI: Thank you. My recollection, 

10 and I think the Department’s been pretty clear in 

11 both this NOPR and other NOPRs for other products 

12 that the TSLs are options that are considered. They 

13 are at the level of the analyses, but as we saw with 

14 the transformer rule in 2007, they sometimes can 

15 define a rule that might be in between those levels, 

16 so that is a -- the levels are, depending on the 

17 input from stakeholders in large part, and how the 

18 analysis comes out -- so that’s my recollection of 

19 how things work. Brian’s nodding so I think that 

20 was --

21 MR. COFFEY: It’s a fair summary, thank 

22 you.

23 MR. ROSENSTOCK: And again, as another 

24 summary -- Steve Rosenstock, EEI -- there were 

25 levels in the 2007 rule, I’ll say levels one through 
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1 five, I think one through five, one through six, and 

2 when you did the final rule, you kind of mixed and 

3 matched based on the one phase, three phase and it 

4 turned out to be levels two, three, or four, four 

5 and a half, depending on the type of transformer and 

6 whether it was pad or pole mounted, single or three 

7 phase. So, you know, you mixed and matched last 

8 time, so it’s kind of -- again, just for a 

9 reference, that’s what happened last time, that you 

10 mixed and matched between different levels, 

11 basically.

12 MR. deLASKI: And that four and a half was 

13 an in-between level. Thank you.

14 MR. COFFEY: Okay. And so of course to 

15 make a cluttered slide even more cluttered here is, 

16 for each design line and TSL, the corresponding EL 

17 efficiency value, losses in watts, and then implied 

18 percentage loss reduction from the baseline. So in 

19 the rightmost column you see sort of what that block 

20 corresponds to, ELs, efficiencies, losses, and then 

21 percentage reductions depending on how you find it 

22 most intuitive to think about.

23 MR. RABA: Steve Rosenstock, go ahead 

24 please.

25 MR. ROSENSTOCK: Steve Rosenstock, EEI. 
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1 On the losses, is that the total losses at the 

2 specified testing level? I guess it was -- liquid 

3 filled I guess it was 50 percent -- is that the 

4 estimated losses at the 50 percent loading?

5 MR. COFFEY: That’s right.

6 MR. ROSENSTOCK: Thank you.

7 MR. BERMAN: Robert Berman, Berman 

8 Economics. Just a request, at the end of the 

9 presentation, can you make these types of tables 

10 available on the web at much higher resolution so 

11 those of us with glasses --

12 MR. RABA: Yes, we will do that, 

13 definitely.

14 PARTICIPANT: Speak into the mic please.

15 MR. BERMAN: So those of us with glasses 

16 can read them.

17 MR. COFFEY: Yes, absolutely. Thank you. 

18 We’ll try to make sure that everything is legible 

19 and in the event that something isn’t, I can 

20 absolutely provide a higher res table.

21 (Comment off microphone)

22 MR. COFFEY: So there’s a lot of 

23 information here, but I think it should be in your 

24 handouts if you’d like to spend some more time with 

25 it, and next we’ll discuss how these ELs are scaled 
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1 from each design line to become a fully fledged set 

2 of standards.

3 Scaling

4 Just to review, trial standard levels or 

5 TSLs include efficiency levels only for DOE’s 

6 representative units. To derive standards for the 

7 rest of the scope of coverage, DOE does what is 

8 called scaling analysis. Most of our equipment 

9 classes have at least two representative units for 

10 which, as I noted, a standard is constructed by 

11 fitting a straight line along a logarithmic space. 

12 So you pick an EL for each one and two points give 

13 you a line, and then that’s a standard. 

14 But in the cases of equipment classes 

15 having only a single point, there are a couple of 

16 options. Just to recap. DOE uses two scaling 

17 points for classes 1B, 2A and 2B. Those each have 

18 two points, so it’s easy to derive a line. Class 

19 1A, which is the single phase catch all class, has 

20 only one scaling point, and that’s at design line 

21 one. And so now we’ll look at where the different 

22 options for deriving a standard for that equipment 

23 class.

24 PARTICIPANT: Brian, just to clarify, the 

25 handouts have it --
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1 MR. COFFEY: The handouts, I should say, I 

2 think 1A and 2A may be switched.

3 PARTICIPANT: Okay. So the presentation 

4 is correct, but the handout has a typo, just to be 

5 clear.

6 MR. COFFEY: Thank you. And a copy of 

7 this presentation will be posted on DOE’s website, 

8 so don’t worry about making all the annotations or 

9 anything like that. This will be sent out in its 

10 current form.

11 I think all of this is best discussed 

12 using an example. What we’re looking at here is a 

13 plot of loss versus KVA, and they’re both 

14 logarithmic for equipment classes 1A and 1B. Again, 

15 so that’s single phase catch-all and single phase 

16 pole mounted. We have pole mount design lines at 

17 both 25 and 500 KVA, that’s for 1B, and a pad mount 

18 design line at 50 KVA for 1A. At each of those KVAs 

19 you’ll see a string of dots for each efficiency 

20 level, or EL, and because they’re a little bit 

21 packed together, we also have zoom-ins at the end of 

22 each line in the corners. So it looks like there 

23 are kind of three plots on here, but actually the 

24 top left corner and the bottom right corner are just 

25 zoomed in versions of the ELs, so you can more 
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1 accurately see where the crossing happens.

2 So how does the scaling work? Well, if we 

3 choose ELs at 25 and 500 KVA for equipment class 1B, 

4 that gives us a straight line. We can divide the 

5 line for equipment class 1A, so that’s the 50 KVA 

6 class by taking an EL at 50 KVA for that design line 

7 and assuming similar physics, or a similar slope. 

8 If we assume that losses grow with KVA at the same 

9 rate, we get a line parallel to the first, that’s 

10 the blue line. So again, because this is a loss

11 plot, lower is more efficient. Fewer losses means a 

12 more efficient transformer.

13 So this is just TSL B which is an example, 

14 and we can see that it gives sort of a high standard 

15 at 500 KVA, maybe, just an eyeball test, maybe it’s 

16 EL-2.5, so that’s one outcome of this, right. And 

17 so now let’s look at, well, if you found that would 

18 be high, what would be another possibility?

19 So now we’re looking at the same plot, 

20 again equipment classes 1A and 1B, TSL B still, and 

21 the red line is identical to what we just saw, it’s 

22 identical here. It runs through the same -- but the 

23 blue line that you can see, instead of being 

24 parallel, is converging with the red line at the end 

25 of DOE’s scope of coverage. So at 833 KVA, these 
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1 two lines meet. So it’s a little bit less stringent 

2 at the higher KVAs, you can see it’s running through 

3 maybe that orange circle which is about 1.5, so it’s 

4 comparatively less stringent at the higher KVAs, but 

5 then if you look down at the lower KVAs, it’s gotten 

6 more stringent. And DOE’s understanding is that in 

7 this particular market segment, there are very, very 

8 few sales at the high KVAs. The single phase KVAs 

9 are really a very, very -- you know, let’s say 250 

10 and above, I think are a pretty small portion of the 

11 market. 

12 So for purposes of this analysis and this 

13 discussion, we’ve shown all of our tables using the 

14 parallel scaling technique.

15 MR. RABA: Go ahead Steve.

16 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

17 Just trying to interpret the scaling. It looks like 

18 you’re trying to have the same delta in terms of 

19 loss reductions, again at 50 percent loading with 

20 your scaling, is that correct? You’re attempting to 

21 do that for all of the equipment classes? You’re 

22 trying to do parallel scales in terms of possible 

23 ranges of ELs?

24 MR. COFFEY: So I’m not sure I understand 

25 your question.
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1 MR. ROSENSTOCK: Well, you show the 

2 parallel lines and then you show the converging 

3 ones, in terms of some of the new, I’ll say the new 

4 TSLs or maybe the old ones, were you trying to keep 

5 looking at parallel numbers for all of the ELs, that 

6 you tried to prevent converging?

7 MR. COFFEY: Not necessarily prevent. 

8 These are just two options. You know, I framed the 

9 -- what is the task at hand here? And the task at 

10 hand is to create a standard for an equipment class 

11 that has only a single point. So if you choose an 

12 El for that point, you’ve defined a standard right 

13 there, but then you have a line running through it 

14 and the slope of that line can vary. And what that 

15 does is makes it comparatively more or less 

16 stringent at higher or lower KVAs. 

17 So what I’m trying to overview here is the 

18 different ways that one might go about doing this, 

19 and one of the options is to assume similar physics 

20 as were present in the pole mounted transformers, 

21 and you have a parallel line, and another option is 

22 to have those two standards converge as you go up in 

23 KVA.

24 MR. ROSENSTOCK: Okay. Steve Rosenstock, 

25 EEI. So the Y axis scale -- it’s a regular scale, 
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1 it’s not logarithmic, it’s a regular scaling on the 

2 Y axis side. It says, you know, it goes from minus 

3 2.3 to positive point three, and it says loss -- I 

4 guess I’m a little confused by that. I’m not sure 

5 what that Y axis really means at the different KVAs. 

6 One way to read it is, you know, some of the things 

7 actually increase losses, if it’s above zero?

8 MR. COFFEY: So the axis is in the log of 

9 loss, so both axes are actually logarithmic, and 

10 that’s the way that you get a straight line. 

11 MR. ROSENSTOCK: That’s a logarithmic

12 scale on the left?

13 MR. COFFEY: Both of them. So the numbers 

14 are actually the result of the log themselves. So 

15 not a lot of intuitive meaning, but just to, I 

16 guess, have it there. The -- yes.

17 MR. RIVEST: So I struggled with this 

18 graph myself quite a bit.

19 MR. RABA: Mike, this is the first time.

20 MR. RIVEST: Oh, and I fully appreciate 

21 that. You may recall from previous conversations 

22 and from the previous rulemaking that when we 

23 analyze a specific KVA rating, like 25 KVA, and we 

24 all debate and talk about if EL1 is the right one, 

25 or EL2, or EL3. But we never had LCC results at 
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1 larger KVA ratings versus smaller KVA ratings. So 

2 what we’re trying to do is say, okay, what we’ve 

3 done a 25 KVA. If we extend it to the other KVA 

4 ratings to get the equivalent stringency, which for 

5 a manufacturer might mean the same steel, or the 

6 same construction, typical construction. So what we 

7 did in the last rulemaking is we used the .75 

8 scaling rule, and the .75 scaling rule looks like a 

9 straight line with a slope of .75 in this one viewed 

10 this way. 

11 The problem we got into in the last 

12 rulemaking is that we picked an EL for one KVA 

13 rating, another EL for another KVA rating and then 

14 had to fit a line through it and try to come up with 

15 a smooth curve. So here we’re defining the 

16 standards right away to be a straight line so we 

17 don’t get this mismatch at the end. And the way 

18 we’re doing that is we’re defining -- we’ve got EL1 

19 for the 500 KVA. We have EL1 or point five, 

20 whatever the TSLs defines for the 25 KVA, and we’re 

21 right away drawing a straight line through, and 

22 we’re saying that’s what the standard would look 

23 like. And it comes very close to .75, but it’s not 

24 always .75. Sometimes it goes as high as .79 and 

25 we’ve seen .76. 
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1 So where we have those two dots at 25 and 

2 500, we draw the line and we know we’ve got a nice 

3 uniform standard. Where we only have that one dot, 

4 we need to extend that dot to the other KVA ratings. 

5 We could do like in the last rule and just use .75, 

6 and that’s certainly one option. Another option is 

7 to take the same slope as for the other product 

8 class, the poles having the same slope as the pads

9 is what we’re talking about. And that would give us 

10 .76, which is pretty close. And that’s all this is. 

11 It’s not very intuitive, but the end 

12 result, I think Brian is going to show, is that it 

13 creates a nice smooth curve. When we look at this 

14 standard now as efficiency versus KVA.

15 MR. COFFEY: So yes, I can pull that up. 

16 This is equipment class 1A, so this is just one of 

17 those lines, and now we’ve --

18 MR. RIVEST: So -- Mike Rivest again. If 

19 you look at the light blue, which is the lowest line 

20 here, and now we’ve got on one axis efficiency, and 

21 on the other axis, KVA. So higher is more 

22 efficient. Our baseline is that light blue. And by 

23 looking at that you would make the observation that 

24 the current standard seems to be more stringent on 

25 the low KVA ratings than it is on the high. I think 
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1 that’s what we’re hearing also, that we heard during 

2 these workshops. So our proposed standard, TSL1, 

3 you’ll notice that, compared to the baseline, it can 

4 be a significant improvement in efficiency or it can 

5 be a minimal, depending on the area between those 

6 two lines.

7 And you’ll notice that TSL A and TSL 1 --

8 this is for pads, I imagine, so TSL A is more 

9 stringent than the proposed level for pads. TSL B 

10 is more stringent than TSL A, et cetera. If you 

11 look at this for the product class for poles now, 

12 you’ll see that TSL A is equal in stringency to what 

13 has already been proposed. So TSL A as far as poles 

14 is concerned, is the same as the proposal, because 

15 those lines are on top of each other. 

16 MR. RIVEST: Very close.

17 MR. COFFEY: Very close. So although 

18 earlier in the table you saw one, zero, one for TSL 

19 1, and 1.5, one for TSL A, that’s actually a gross 

20 simplification of what that TSL looks like because 

21 in the previous instance we had to fit a line 

22 through three curves -- through three points rather 

23 than two, so there was like an averaging there. We 

24 were a little higher, a little less than one in some 

25 cases, a little higher than zero in other KVA 
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1 ratings, because we couldn’t have done a smooth 

2 standard by having a zero, one, zero.

3 MR. RABA: Question over there. Go ahead.

4 MR. CASKEY: Yeah, John Caskey, NEMA. If 

5 you can go back to the other slide for just a 

6 second, just to make sure -- one more earlier. 

7 Okay. So on this X axis it looks like it’s KVA, and 

8 it’s starting at 25, and you said that’s log, so 

9 what is the right hand end of that axis?

10 MR. COFFEY: (off microphone`) ... ... [the 

11 limit of DOE’s] scope of coverage ...

12 MR. CASKEY: Okay. 

13 MR. COFFEY: If you didn’t hear that, the 

14 farthest right for which we have ELs is 500 KVA, 

15 that’s our design line 3 unit. The scope of 

16 coverage extends all the way to 833 for single 

17 phase.

18 MR. CASKEY: Okay. Then on the Y axis is 

19 the loss. Are there units that go with those 

20 numbers?

21 MR. COFFEY: So it’s the logarithm of 

22 watts, you could say. Logarithm of power.

23 MR. CASKEY: Okay. 

24 MR. RIVEST: Mike Rivest again. What 

25 Brian -- the issue that we’re trying to get your 
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1 feedback on that Brian’s been discussing is that we 

2 need to go with our blue line through this dot. And 

3 we want to have a straight line go through that dot. 

4 If we -- and this is a point -- we can go parallel; 

5 we can pivot upwards or downwards, but it’s a zero 

6 net gain if you will in terms of the overall 

7 standard. Now if we pivot up like this, then we’re 

8 making this more stringent. And the thought is that 

9 the impact is really down here, for the poles. So 

10 it’s more important that we get this close as 

11 possible to getting through this dot at EL point 

12 five? Is that what -- we’re depending on the 

13 standard -- so it’s more important to get this dot 

14 right, go through this dot and get this dot right, 

15 than to go through this dot and get this dot. 

16 MR. RABA: Greg.

17 MR. COULTER: This is Greg Coulter with GE 

18 Prolec. This is kind of a key issue in this point. 

19 As I used to have a professor say, one point is a 

20 dot, two points is a straight line, three points is 

21 a curve. So you’re trying to take one point and 

22 essentially all you have -- even when you say you 

23 have two points there, you really only have one 

24 point -- so you’re trying to make it work. I think 

25 I’ve been clear in my comments before. It isn’t 
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1 .75. The scaling factor is not .75. It’s only 

2 close across short distances -- it’s only close 

3 across short distances of KVA. The point is, as 

4 manufacturers, our construction changes. We use a 

5 different construction for a 25 KVA than we do for a 

6 50, and we don’t build any 500s, so I never cared 

7 what you did at that point anyway. But when you get 

8 up to 167, where you do have volume, from ten to 

9 167, we did care. But we have different 

10 construction. Our low KVAs are constructed 

11 completely different, strip versus wire -- I don’t 

12 want to go into all the differences with competitors 

13 sitting in the room, but, you know, that’s a simple 

14 one, and I think most people do that. So, this kind 

15 of becomes important.

16 It’s less important when the efficiencies 

17 aren’t so tough, but as we’re getting close to where 

18 any of us can do things, and it’s now becoming very 

19 important on this particular point. It is always 

20 easier to do these efficiencies a little bit more at 

21 higher KVAs. KVA just tends to be more efficient 

22 and that’s why it’s on that curve. It’s the slope 

23 of the curve that makes a big difference. So even 

24 the difference between a converging and a straight 

25 line makes a big difference at this point. I don’t 
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1 believe it’s that important to get a straight line 

2 through 25 and 50. Your 25 is a pole, your 50 is a 

3 pad. There are different points. And so it’s kind 

4 of important to pick a point, and then I don’t know 

5 how else you can do it. It’s too late to come with 

6 more design lines, so you’ve got to use some kind of 

7 scaling, but you’ve got to be a little bit 

8 conservative in the scaling because of where we are. 

9 And at 25 KVA and at 50 KVA, which is the heart of 

10 the volume, you can scale off of it, but you’ve got 

11 to get those points pretty close to right and scale. 

12 I’m more on a converging side than the straight line 

13 side. If I understand the converging -- I mean this 

14 is the first time I’ve seen it, but it looks to me 

15 like that has a little more generous -- it’s a 

16 little more generous at the low KVAs. I’m wrong? 

17 You’re shaking your head. I misread that chart?

18 MR. COFFEY: Let me -- I think you are for 

19 converging if converging means converging at low 

20 levels as opposed to what we have here is converging 

21 at high KVAs. So you’re for converging, but not our 

22 -- a different kind of converging. So of these two, 

23 you’re for the parallel, but you would prefer that 

24 we consider converging at low KVA.

25 MR. COULTER: Where all the volume is, 
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1 yes.

2 MR. COFFEY: But of course, if we have 

3 total convergence, then we haven’t separated pads 

4 from poles. So the question is at what KVA would we 

5 converge, if it was on the small side. Is it 25, is 

6 it ten? 

7 MR. COULTER: Well, first, it may not be 

8 the same slope. You have a slope through those 

9 KVAs, but it’s a different slope when you go up, 

10 which is truly what happens, by the way. This is 

11 not -- so .75 just doesn’t work across the --

12 MR. COFFEY: So what’s important to get is 

13 the range between what KVA and what KVA. Where’s 

14 the -- where’s 80 percent of the volume right now?

15 MR. COULTER: KVA 50 and below.

16 MR. COFFEY: Fifty and below, but not 

17 zero, not one KVA>

18 MR. COULTER: Ten.

19 MR. COFFEY: Ten --

20 MR. COULTER: Tens, 15s and 25s is 

21 probably -- on a pole line, that’s going to be 80 

22 percent of your volume. Tens, 15s and 25s. On pad 

23 line, now, it’s going to be --

24 MR. RABA: Would you like to make a 

25 comment --
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1 MR. COULTER: That 500 KVA point has no 

2 meaning. It’s not even very good. The 500 KVA is 

3 not very good. But my point is, we never cared 

4 because we don’t make 500 KVAs --

5 PARTICIPANT: Some people do.

6 MR. COULTER: But some people do and some 

7 people buy them. But they don’t buy many. The 

8 point is, get the low points --

9 MR. COFFEY: I see what you’re saying.

10 MR. RABA: Steve.

11 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

12 Just as a follow up, there are customers that buy 

13 the 500 KVAs. I’m a little concerned about, well, 

14 put it high, who cares? Well, still the customers 

15 care because they’re the ones who are going to be 

16 paying and it will be totally uneconomical for them.

17 MR. COULTER: Steve, that was not my 

18 point. My point is it’s not as important as getting 

19 the low ones right, that’s it.

20 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

21 appreciate that but it could be very important to 

22 those people who buy them, if they’re facing huge up 

23 front costs for minimal efficiency gains. And if 

24 you look forward to TSL 1B, yeah that one right 

25 there, just a quick one -- this is for the pole 
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1 mount and under TSL 1, doesn’t TSL 1 equal the base 

2 for that one? But you show it as a different value, 

3 so I got a little confused when I was looking at 

4 that one.

5 MR. COFFEY: TSL zero is the base. TSL 1 

6 is the proposed level.

7 MR. ROSENSTOCK: TSL 1 is base.

8 MR. COFFEY: Excuse me?

9 MR. ROSENSTOCK: For pole mount.

10 (comments off microphone)

11 MR. ROSENSTOCK: I’m looking at the chart 

12 here, design line two, yes. And --

13 MR. COFFEY: I’m sorry. I think what 

14 you’re remembering, Steve, is in the NOPR proposal, 

15 the nominal proposal for design line 2 was EL-0.

16 MR. ROSENSTOCK: Right.

17 MR. COFFEY: But because of the scaling 

18 Mike mentioned before, there were three points in 

19 that single equipment class, and so to derive a 

20 standard, you know, you can’t hit three points with 

21 a single line unless you happen to be really lucky 

22 with the points. So what wound up happening is this 

23 curve ended up being roughly EL point five for 

24 design line two, roughly EL point four for design 

25 line one, and roughly EL-1.1 for design line three. 
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1 Because to run through each of the points would have 

2 created this physically inconsistent disjoint 

3 standard that wouldn’t have made sense. So with the 

4 three points in one class, the best fit line was 

5 really the best that DOE could do.

6 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

7 respect that and I understand what they’re doing, 

8 but there are many other standards where there’s, 

9 quote, “disjointed curves,” just based on analysis 

10 of the market, analysis of the economics, analysis 

11 of everything that’s in there. I understand.

12 MR. RIVEST: I think the difference here 

13 Steve is here we were getting reversals in 

14 direction. So a curve -- it’s okay if it’s on a 

15 line if it’s a curve where it’s, you know, but if it 

16 looks like a camel’s back, a two humped camel is 

17 what we were getting.

18 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

19 There are other efficiency standards where I believe 

20 you get very interesting results where there is high 

21 efficiency gains for some products and lower 

22 efficiency gains for other products, and it would 

23 not be a smooth curve. I haven’t seen them. I 

24 haven’t seen the logarithmic curves, but just based 

25 on other -- just from the results of other standards 
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1 for other products, you know, it’s, you know, --

2 especially the ones with multiple product classes, 

3 I’ve seen situations where --

4 MR. RIVEST: So this is the same product 

5 class. It would be as if we took a water heater 

6 standard, which is an equation by gallons, and then 

7 we had reversals in the stringency. We would say 

8 the 40 gallon is one level and then you go down to 

9 50 and then back up to 60. That’s just not --

10 MR. ROSENSTOCK: But in that case -- well, 

11 Steve Rosenstock, EEI -- the water heater curve it’s 

12 a few percent up to 55 gallons and then it’s 120 

13 percent for over 55 gallons on the electric side --

14 MR. RIVEST: But it doesn’t do this.

15 MR. ROSENSTOCK: Okay, so it does this and 

16 then this. It still might not be a smooth curve 

17 like --

18 MR. RIVEST: I wish I hadn’t brought up 

19 water heaters.

20 MR. RABA: Okay. We have a hand raised 

21 from Aaron Meyers, please.

22 MR. MEYERS: Aaron Meyers, Cooper Power. 

23 I do appreciate the effort to smooth the curve 

24 because we feel that it does represent more reality, 

25 but all of the analysis that we’ve done so far has 
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1 been using the previous scaling factor. So we 

2 really haven’t assessed what the impact will be when 

3 you raise the efficiency. For instance, for 1500 

4 KVAs for three phase, you see 2B, that’s a pretty 

5 substantial increase in efficiency, and I don’t know 

6 how or if that’s reflected in the economic analysis.

7 MR. COFFEY: It should be reflected since 

8 that’s one of the design lines, right, five.

9 MR. MEYERS: Yes.

10 MR. COFFEY: So five is the three phase 

11 pad at 1500 KVA.

12 MR. MEYERS: That’s a significant 

13 increase in efficiency.

14 MR. COFFEY: We have later in this 

15 presentation, the actual -- we’re showing 

16 graphically here what - how the different TSLs 

17 relate. We also have in tabular form the actual 

18 numbers for each KVA. The efficiency values 

19 themselves.

20 MR. RABA: In the back, please step to the 

21 microphone. Please, your name.

22 MR. PATTERSON: Wes Patterson. Brian, go 

23 back to that chart. Yeah, if I remember right, 

24 design line five is a 1500 KVA, three phase, which 

25 is those dots on the 1500 scale. I mean you have 
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1 actual design lines on those, it’s not 

2 extrapolation.

3 MR. COFFEY: That’s right, so it would be 

4 on this equipment class 2A analysis. Because it’s a 

5 pad mount.

6 MR. PATTERSON: Thank you for that 

7 clarification. 

8 MR. RABA: Greg.

9 MR. COULTER: This is Greg Coulter. 

10 Here’s another case where there comes a major change 

11 in design. 500 KVA and below are pretty much free12 form for three phase pads. You go above there, you 

13 have to meet the 5.75 percent impedance, which puts 

14 a major restriction on what we can do, and that’s 

15 one of the reasons why we always thought there was a 

16 major shift in the efficiencies when you get to 

17 that. You know, meeting that impedance forces us to 

18 put, I’ll call it blank space in the design, but 

19 we’ve got to add space between the coil just to 

20 drive the impedance up to meet standards, which is 

21 space is not available to make these things more 

22 efficient. Matter of fact, by standards they almost 

23 become less efficient at high KVAs. It’s almost a 

24 force of the 5.75 set impedance requirement.

25 MR. RABA: Wes, you’re up.
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1 MR. PATTERSON: Wes Patterson again. 

2 Greg, on this chart, the two design lines, one’s a 

3 150, the other one is a 1500. So the entire 

4 analysis of those dots is done on a physical design 

5 which should accommodate this change in the 

6 impedance. In those dots that are on those curves. 

7 Those two curves represent the situation that you’re 

8 describing.

9 MR. COULTER: Well, I’m not sure I agree 

10 with that, Wes, because, you know, you would only 

11 have two points on a curve.

12 MR. PATTERSON: We only have --

13 MR. COULTER: You have 150 and you have 

14 1500. And everything else is a curve fit.

15 MR. PATTERSON: And everything else is 

16 trying to make some kind of fit.

17 MR. COULTER: And all I’m saying is, I 

18 don’t think the 1500 is the same curve as the 150 

19 because of this impedance issue.

20 MR. PATTERSON: It may not be. It may not 

21 be, but then neither is the curve for 500.

22 MR. COULTER: That was the point I was 

23 making earlier.

24 MR. PATTERSON: So if we look at the 

25 existing standard, which is the baseline, as a 
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1 result of how the existing standard was written, you 

2 can see that hook that took place right there --

3 it’s what, 700 KVA or something.

4 MR. COULTER: It happens to be 500 --

5 between 500 and 750.

6 MR. PATTERSON: Right, it was 500.

7 MR. COULTER: Because there was a major 

8 design shift between 500 and 750. That’s why --

9 that’s the reason we always thought it was there, 

10 made perfect sense. But now it’s being taken out 

11 because looks like you’re trying to fit a curve 

12 between all those points that aren’t the same 

13 points. Here you truly have a major --

14 MR. PATTERSON: The end result was that 

15 the 500 efficiency was the same efficiency as the 

16 750.

17 MR. COULTER: Yes. Yes.

18 MR. PATTERSON: Okay. But that -- in some 

19 cases, naturally, that is not the case. And not 

20 across all manufacturers is that the case.

21 MR. COULTER: Well, we didn’t say it was 

22 perfect. We just said it had more sense to it than 

23 it does not.

24 MR. PATTERSON: But not across all 

25 manufacturers.
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1 MR. COULTER: We have other manufacturers 

2 in the room. Let them speak.

3 MR. RABA: We had three hands left to 

4 right, go ahead please.

5 MR. POLINSKI: Ray Polinski, ATI 

6 Allegheny. Just a comment, feeding on what Greg 

7 says. Why would we change the scaling that 

8 practically has worked. It’s proven, it’s 

9 practical. It’s how it’s been done. And to 

10 arbitrarily change it --

11 MR. RIVEST: Mike Rivest. This is nothing 

12 arbitrary here, okay. This was proposed -- we got 

13 comments on this, there is nothing arbitrary. We’re 

14 not in this situation here, look at TSL 1 and TSL A, 

15 and they’re the same, so --

16 MR. RABA: Do you have follow on, Ray?

17 MR. POLINSKI: Again, I’m not a

18 transformer engineer so I’ll stand back and let the 

19 transformer engineers speak, but what I heard Greg 

20 say is just that in practice he feels that the 

21 existing scaling, although it’s not smooth, and that 

22 may cause some people to have heartburn, it is, in 

23 fact, it works. And so why in the world we would 

24 change that. Mike you can explain.

25 MR. RABA: We saw Steve and then Andrew 
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1 after that.

2 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

3 Looking at all these curves, there’s some sort of 

4 inflection point, whether it’s at 100 KVA or at 500 

5 KVA, it appears to be -- if I’m doing the bottom 

6 notes right, it’s 100, 250, 500, is that -- or is 

7 that 333? I’m not sure exactly where they, you 

8 know, it just goes from 100 to 1000, so I don’t 

9 know where the vertical lines are, but just looking 

10 at these, there’s no perfect curves that they have 

11 now, but I think part of the reason was when DOE did 

12 their last analysis was that they were matching the 

13 single phase to the three phase efficiencies for 

14 different transformers as a way to lower 

15 manufacturing costs, as I recall. That was a way to 

16 assist them, so you didn’t get the perfect curves, 

17 but if it lowered the cost of higher efficiency 

18 units, it’s kind of a win-win situation. 

19 So, I’m not personally, you know, I know 

20 we’re going to get the economics later, if standards 

21 come up where it’s not a perfectly smooth curve, 

22 that might be okay because that’s where the 

23 economics are better for both the manufacturers and 

24 the steel makers as well as the utilities, just 

25 because you raise -- if you raise it too high and it 
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1 just distorts the market, and the prices skyrocket, 

2 and then it’s not economical.

3 MR. RIVEST: Let’s think about what we’re 

4 talking about here. We have a dot at 1500, which is 

5 already EL1. That one’s not going anywhere. That’s 

6 where it is. We have one at 150, which is at EL1, 

7 that’s not going anywhere. So we’re talking about 

8 creating a standard across from that 150 dot to that 

9 1500 dot. We have it now, which is a straight line 

10 fit in log-log space. Okay. It creates this 

11 smooth, function, one seen as efficiency times KVA. 

12 What is it I’m hearing that you -- what -- we can do 

13 a .75 scale across both of those and then we have a 

14 discontinuity, and we end up with something like 

15 that.

16 Now, that’s not going to lower the 

17 standard necessarily. That’s going to make it --

18 probably make the 150 more stringent because -- and 

19 make the 15 -- I don’t know, I can’t anticipate. 

20 But I don’t think the area under is going to really 

21 change.

22 MR. RABA: Andrew.

23 MR. deLASKI: Andrew deLaski, Appliance 

24 Standards Awareness Project. So just to be clear, 

25 Brian, the levels, TSL1 you show on your graph here, 
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1 these are levels that were proposed. People have 

2 commented on these levels.

3 MR. COFFEY: That’s right.

4 MR. deLASKI: People have taken positions 

5 on this. This has been pretty clearly noticed and 

6 comment. This is not something new.

7 MR. COFFEY: No, exactly.

8 MR. deLASKI: So you guys have been doing 

9 this now, as you said, you’ve been doing this for 

10 quite a while. This isn’t new. The thing I wanted 

11 to ask Greg, just to follow on to your comment about 

12 -- I don’t understand, again, some of the 

13 engineering constraints you’re describing, which is 

14 that you add blank space -- I know you’re describing 

15 it in simple terms so people like me, and I 

16 appreciate that, and that -- but why does that make 

17 it harder to be efficient?

18 MR. COULTER: In simple terms, we have to 

19 make -- the way we make stuff more efficient is we 

20 try to put it in more compact space, that’s the best 

21 way you can do it. If you take out insulation, take 

22 out blank space in the design, you can get the 

23 winding in the core smaller. Here, we are forced to 

24 put space in between the winding and the core just 

25 to force impedance into the design. So we’re not 
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1 able to fill that space up with winding. It’s more 

2 compact, so we’re essentially adding losses, mostly 

3 winding losses to the design.

4 You know, how big it is, I don’t know. 

5 But it’s certainly a design change. It’s one of 

6 those reasons why the .75 scaling factor doesn’t 

7 work across, especially three phase pads. It’s 

8 probably the most prime example I could give. It 

9 works better for all the 750 KVA and above to be at 

10 that, but for the 599 KVA and below, on a .75 

11 scaling factor, but it doesn’t scale across the 

12 whole curve.

13 If I look at that line, what you’re really 

14 seeing is the lower KVAs are really moving up, 

15 they’re having to be more efficient versus what they 

16 used to be. That’s essentially what it’s showing. 

17 You start getting where the heart -- where the meat 

18 of the KVA is for three phase, it’s actually not as 

19 big a change. It’s a little bit arguing against 

20 what we might like. But the point is, I don’t think 

21 -- I think there’s a point where the curves are --

22 the curves ought to have a slightly different shape. 

23 In other words, a discontinuance in the curve. It 

24 was there before. I think this one here is an 

25 obvious place for it -- it ought to be there. Now 
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1 how big an issue that is on total losses, I don’t 

2 know, in total, I don’t know.

3 You know, in all our analysis, you know, 

4 if this was there and it was in all the data we saw 

5 back in February, we missed it. We were probably 

6 just looking, ourselves, at the 150 and the 1500 and 

7 that was it, and making all our analysis off of 

8 those changes, versus all the KVAs in between. We 

9 didn’t pick up that this had changed like this.

10 MR. RABA: Wes Patterson.

11 MR. PATTERSON: The first thing I want to 

12 point out is that the -- what they show with the 

13 orange dot, TSL1, that was in the NOPR in February, 

14 that was in the proposal in the NOPR in February. 

15 What this chart is showing is that with the new 

16 equipment classes for poles, there is no change 

17 between the February NOPR and today on that chart. 

18 So the TSL A and the TSL1 are identical lines. 

19 That’s what that chart is showing.

20 Now, coming back to the discussion about 

21 was the NOPR in February correct or incorrect? The 

22 assumption, Greg, that you’re making is that because 

23 I’ve got to go to five percent impedance, I have to 

24 add space in the high-low in order to jack the 

25 impedance. But I can also modify the turns to jack 
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1 the impedance, and not add any space whatsoever.

2 MR. COULTER: (comment off microphone)

3 MR. PATTERSON: But the efficiency balance 

4 can still be maintained and follow that .75 slope. 

5 In an optimization system, yes it can. I can 

6 balance those two elements at any time. So it 

7 doesn’t really change the physical relation. This 

8 is a characteristic of a manufacturing practice, not 

9 a physics of the design of the transformer. I can 

10 change the turns ratio and still accomplish that 

11 curve.

12 MR. RIVEST: In any case, Greg -- Mike 

13 Rivest -- we’re here to get your comments and to the 

14 extent that you can document and maybe if we had 

15 even market data that shows on the high end, not the 

16 baseline, because all the baselines are going to be 

17 hovering on that blue line anyway, but if there was 

18 some empirical way that we can justify another 

19 scaling, that’s why we’re here.

20 MR. RABA: Carlos.

21 MR. GAYTAN: Carlos Gaytan, Prolec GE. 

22 One comment about the equipment classes 1B and 2B 

23 which are for pole mounts, is really with a KVA 

24 score -- according to the IEEE standards, the pole 

25 mount transformers have a limit of up to 500 KVA for 
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1 both single phase and three phase, and there might 

2 be a confusion when we interpret the tables and 

3 these charts for, especially for equipment class 2B 

4 for three phase, because beyond -- even at the 500 

5 KVA level, probably the majority of the pole mounted 

6 transformers are not mounted on a pole, but rather 

7 on a platform above the ground level. But above 500 

8 KVA, we consider them to be distribution substation 

9 transformers, and there might be a confusion whether 

10 those probably which have a singular construction 

11 with pole mounted transformers that are mounted on 

12 the floor level, if they should be considered as 

13 part of that equipment class, or because they are 

14 within that KVA range, or if they have to be in 

15 equipment classes 1A and 2A. That’s my comment.

16 MR. COFFEY: Thank you.

17 MR. RABA: Additional comments? Good 

18 exchange so far, very lively. Go ahead, Brian.

19 MR. COFFEY: So we show the graphical 

20 representation of what’s going on, which is 

21 intuitive, to see certain trends. We also have some 

22 tables for each TSL. This is TSL A, we’ve got all 

23 four equipment classes, TSL B, TSL C, TSL D. So I 

24 can linger on one of these if someone would like to 

25 make a point, but otherwise they’ll be in your 
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1 handouts to be reviewed at your leisure. And if 

2 there aren’t any questions, I will invite up Chris 

3 Bolduc to talk about some of the economic results.

4 MR. RABA: Before we do that, Steve you 

5 had something?

6 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

7 Just trying to look over all of the tables, and just 

8 in terms of the scaling, I’m just trying to -- you 

9 said the, on this equipment class 2B scaling, just 

10 double checking -- they’re scaled with the 1B at the 

11 higher KVA levels, correct?

12 MR. COFFEY: Higher KVA? What do you mean 

13 by that?

14 MR. ROSENSTOCK: Well, equipment class 2B 

15 is the three phase pole above a certain KVA level, 

16 correct? I’m looking at the representative unit.

17 MR. COFFEY: 2B is for all three phase 

18 units.

19 MR. ROSENSTOCK: All three phase pole 

20 mounts, okay.

21 MR. COFFEY: And so the way that we’ve 

22 done the scaling is to give 2B the efficiency 

23 standard of the 1B product of one-third the KVA. 

24 So, for example, if you look at a 50 KVA in 1B, it’s 

25 99.11 at TSL B, that’s the page I’m on right now, so 
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1 the 150 for the three phase has that same efficiency 

2 value.

3 MR. ROSENSTOCK: Thank you. I hadn’t seen 

4 the numbers before, so I just wanted to verify that, 

5 thank you.

6 MR. RABA: Any additional comments on 

7 Brian’s presentation? Thank you very much. This is 

8 a good time to take a break. We’ve got a lot of 

9 content yet to go ahead on the economic analysis, so 

10 we’re going to take a break at this time.

11 Looking ahead at the rest of the day, I 

12 think we’re pretty much on schedule, so if we took a 

13 break now we return here at say, quarter to 11 by 

14 that clock. Those of you who are not familiar with 

15 the Forrestal Building, you need to wear your 

16 visitor’s badge up high and visible ... 

17 (Whereupon, at 10:30 a.m., the meeting was 

18 recessed for a 23 minute period, and reconvened at 

19 10:53 a.m.)

20 MR. RABA: This afternoon -- late this 

21 morning -- we’ll begin with Chris Bolduc, Navigant 

22 Consulting, who will be doing the economic analyses, 

23 and we’ve received the photocopies of your business 

24 cards you turned in. Did everybody get one? If you 

25 didn’t I can give them to you here right now, or 
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1 Brenda’s got them at the front desk. Pass them 

2 along, please. So if you haven’t given Brenda your 

3 business card, the Department keeps track of who’s 

4 here so they can keep you informed later on.

5 A couple folks have joined us in the 

6 course of the meeting. Would you care to introduce 

7 yourselves.

8 MR. NADEL: Steve Nadel, ACEEE.

9 MR. RABA: Thank you, Steve. Anybody else 

10 join us more recently? Okay. Great. Let’s 

11 continue. Start now again, resume, with Chris 

12 Bolduc.

13 Economic Analysis

14 MR. BOLDUC: Good morning, my name is 

15 Chris Bolduc from Lawrence Berkeley National Lab. 

16 I’m here to present the economic analysis. So I’d 

17 like to start by saying that for the economic 

18 results that were presented in the documents that 

19 were sent out, and in today’s presentation, we did 

20 our utmost to use the same spreadsheet tools that 

21 were shared for the NOPR analysis. What we can say 

22 is that in the LCC spreadsheets we added a custom 

23 efficiency field for the NOPR during the reg neg 

24 sessions, which we exercised to analyze the new ELs. 

25 The only exception in this case is for design line 3 
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1 which we’ve cast for today and what we’re talking 

2 about is a pole mounted transformer, and so we added 

3 the pole replacement algorithms or methodology that

4 was used in design line 2 to design line 3, and I’ll 

5 talk about that in more detail when we get there.

6 Again, the new -- with the NIA we used --

7 we just remixed the TSLs and the NIA to produce the 

8 impact results. 

9 So, it’s a bit of a convention for these 

10 slides I’m about to show, is that we have the 

11 proposed rule in green and any new analysis 

12 highlighted in orange. Here we have design line 1 

13 which we’re casting as a single phase, 50 KVA, for 

14 lack of a better term, a pad mount or other 

15 transformer. You can see that the new EL at 1.5 

16 follows the trend that we would expect it to. 

17 There’s really -- there’s really nothing new to see 

18 here. I’d be happy to take your questions if 

19 anybody has anything to ask. Ray.

20 MR. POLINSKI: Ray Polinski, ATI Allegheny 

21 Ludlum. One thing, Chris, if it’s somewhere in the 

22 report, if you can just direct me to where the 

23 data’s at, but again, as we get to the 1.5 level, 

24 what percentage of the transformers -- how much are 

25 amorphous and what percentage of them, you know, are 
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1 M3 transformers? The question is the availability, 

2 how much amorphous is used versus M3 at the 1.5 

3 level?

4 MR. BOLDUC: Okay. I hear you. I don’t 

5 have the exact numbers in front of me, but I do have 

6 the larger steel components for these results. And

7 in this case for design line 1, this is 49 percent 

8 SA1 and it’s 46 percent M2 -- was the mix that 

9 produced these results.

10 MR. POLINSKI: Ray Polinski, ATI 

11 Allegheny. Thanks, Chris. And the tonnage or 

12 weight that you have, do you have any -- one thing I 

13 think that’s been communicated here repeatedly is 

14 that, you know, M2 -- M3, very readily available; M2 

15 much more limited availability from a supply 

16 standpoint.

17 MR. BOLDUC: So your question is do I have 

18 for the meeting today, a projection of steel tonnage 

19 that would be required to meet the standard?

20 MR. POLINSKI: I think I’ve seen those in 

21 past reports, you know, in the past analyses, hey we 

22 need 250,000 tons or so many pounds, and that just, 

23 you know, the question is, is there the available 

24 capacity today or potential in 2016, to meet the 

25 standard, the materials available to meet the 
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1 standard? That’s always been my understanding from 

2 day one of the committee meeting was, hey, we want 

3 to make sure we’ve got standards in which we have 

4 adequate material supply to promote a robust 

5 competition and to ensure that we can supply and 

6 make the standard. So that was my question.

7 MR. BOLDUC: Thanks, Ray. Regrettably, 

8 no, we do not have projections of the volume of 

9 steel that would be required to meet each of the new 

10 ELs today. Moving on --

11 MR. POLINSKI: One last question. That’s 

12 something you would have before you would propose a 

13 standard?

14 MR. BOLDUC: That would be part of the 

15 final rule package,

16 PARTICIPANT: Greg Coulter wants to go on 

17 the record -- that was a no.

18 MR. RABA: Aaron.

19 MR. BOLDUC: Yes.

20 MR. MEYERS: Aaron Meyers, Cooper Power 

21 Systems. This is really the crux of the issue here, 

22 is, you know, you can look at these numbers and 

23 appreciate the work that went into the economic 

24 analysis, but without robust competition between M3 

25 and amorphous, I mean you’re putting all your eggs 
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1 in one basket, and we felt that that was probably 

2 the driving factor behind the original Notice of 

3 Proposed Rulemaking, and all the new trial standard 

4 levels that we’re evaluating here, essentially are 

5 considering an amorphous only world. And we don’t 

6 believe that that’s the direction, the right 

7 direction for the country to move in, much less for 

8 manufacturers of transformers or core steel.

9 MR. BOLDUC: If I may rebut, Aaron. At 

10 the end, there’s some summary slides and the new 

11 TSLs are not 100 percent amorphous for all the new 

12 TSLs. 

13 MR. RABA: Jerry, then Andrew.

14 MR. CORKRAN: Back when we had our last 

15 meeting and we ended up at EL-1, the reason we went 

16 along with that was to try to end the process 

17 because that was the highest that we, as 

18 manufacturers, could make using M3 core steel. And 

19 we try to make higher loss levels, we’re not 

20 competitive with amorphous, so you’re saying 100 

21 percent amorphous -- the DOE data agrees with that -

22 - anything over one, your own data, says 100 percent 

23 amorphous, want to go back and look at your studies. 

24 And so now when you’re talking about these higher 

25 levels it’s kind of -- it’s kind of like we’re 
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1 starting over and I’d really hate to see it. I 

2 thought we had an agreement and now looks like we 

3 don’t.

4 MR. CYMBALSKY: John Cymbalsky, DOE. So, 

5 an agreement, I’m not -- the only agreement that the 

6 Reg Neg committee produced was not relating to this 

7 topic at all. And this is additional analysis. We 

8 didn’t have 1.5 analyzed in the NOPR. That’s what 

9 this is for, so you’re seeing new numbers and I 

10 don’t think you can draw the conclusion you just 

11 drew, because this was never shown before. You 

12 haven’t seen this, so if we can go through the deck 

13 and we can see what shakes out here. Thank you.

14 MR. RABA: Question from Dave Millure on 

15 the phone. Then to you Andrew. David, you’re live. 

16 Go ahead.

17 MR. MILLURE: Thank you. Dave Millure of 

18 Metglas. I believe to say 100 amorphous at EL-1.5 

19 is not at all accurate. We are talking about things 

20 that are not the subject of this meeting, first of 

21 all, but there are some major manufacturers that 

22 will tell you that silicon steel and amorphous are 

23 competitive at 1.5. So I suggest we just move on.

24 MR. RABA: Andrew, thank you for your 

25 patience. Go ahead. This is Jim. Thanks, David.
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1 MR. deLASKI: I want to come back to a 

2 point that you made, Chris, a few minutes ago. Can 

3 you tell me again what the percent -- what the steel 

4 mix is at EL-1 on this slide?

5 MR. BOLDUC: EL-1, one moment please.

6 MR. deLASKI: I think you just said it, 

7 but I’m not sure I caught it.

8 MR. BOLDUC: At EL-1 it’s 88 percent M3. 

9 At EL-1.5, the LCC picks the lowest first cost 

10 units, and from that sample it’s 49 percent 

11 amorphous, 46 percent M2.

12 MR. RABA: Bob Saint.

13 MR. SAINT: This is Bob Saint from NRECA 

14 and I’m still wondering if this whole analysis is 

15 credible, because it doesn’t appear that you have 

16 addressed the power cost issues that we’ve raised 

17 before. And I was wondering if you were going to 

18 address those later, or --

19 MR. BOLDUC: Bob, that was a comment 

20 directed at the NOPR analysis. The presentation 

21 today is an extension of the NOPR analysis. We did 

22 receive your comment. That’s all I can say, we 

23 received your comment, thank you.

24 MR. RABA: Again, let’s keep the focus of 

25 the meeting. Please. Aaron, back to you, then 
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1 Steve. 

2 MR. MEYERS: Aaron Meyers, Cooper Power. 

3 Again, I appreciate the analysis that was generated. 

4 When we talked before we were concerned about the 

5 crossover point between amorphous and M3, and we 

6 went back and used our actual design program to 

7 identify the crossover point, and for -- we looked 

8 at 25 KVA poles, 50 KVA poles, 25 KVA pads, 50 KVA 

9 pads, 500 KVA pads, 1500 KVA pad, and in no case was 

10 it at the EL-1. The closest to EL-0.5. So I’ll 

11 make that point and would like to go on the record 

12 by saying that is the point of maximum 

13 competitiveness from Cooper’s point of view, and the 

14 slope of the grain-oriented curve is so steep that 

15 once you go beyond that it very quickly becomes one 

16 material choice only, and that’s amorphous.

17 MR. deLASKI: Just to follow up on that, 

18 this is Andrew deLaski, if I could. Again, as we 

19 discussed last fall, of course, that analysis is 

20 very sensitive to the relative price of the 

21 materials, that’s what drives it, right. So, --

22 MR. MEYERS: That’s why I said it was 

23 steep. That’s why I said the steepness of the 

24 grain-oriented curve runs away from the amorphous 

25 curve very quickly, and so I wouldn’t want to go 
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1 beyond that point because the M3 curve can’t 

2 compete.

3 MR. RABA: First Steve Rosenstock, then 

4 Robert Berman.

5 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

6 Again, getting back to the economic analysis, the 

7 spreadsheet that was sent out with the announcement, 

8 it was --

9 MR. BOLDUC: Design line 3?

10 MR. ROSENSTOCK: -- design line 3, yes, 

11 and I was looking at a couple of tabs. I just want 

12 to kind of ask about the numbers in there. First of 

13 all, on the summary tab, it had information about 

14 average no load energy price, average load loss 

15 energy price, average no load demand price, average 

16 load loss demand price. And as I was --

17 MR. BOLDUC: Steve, again, this sounds 

18 like a continuation of Bob Saint’s comment, which is 

19 regard to the no load energy price, is that right?

20 MR. ROSENSTOCK: Well, and a load energy 

21 price that was used for this A, B, C, and D. 

22 Weren’t these used for the A, B, C, and D?

23 MR. BOLDUC: They were. They were also 

24 used in the NOPR, as I stated before. This is the

25 same economic analysis. The only change for design 
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1 line 3 was the inclusion of the pole replacement 

2 algorithm or methodology.

3 MR. ROSENSTOCK: Okay. And just a very 

4 quick follow up. In the spreadsheet there was a tab 

5 for sensitivity analysis, and that tab was blank.

6 MR. BOLDUC: That’s right. That’s not 

7 implemented yet.

8 MR. ROSENSTOCK: Will part of the 

9 sensitivity be using the power prices that were 

10 suggested by the utilities?

11 MR. BOLDUC: Can’t say.

12 MR. ROSENSTOCK: Thank you.

13 MR. CYMBALSKY: Again, that’s not part of 

14 the meeting, Steve. 

15 MR. RABA: Robert Berman, you’re up first.

16 MR. BERMAN: Robert Berman, Berman 

17 Economics. One point that we should keep in mind in 

18 terms of reading the results and crossover points 

19 and so forth, is if we expect -- if we find at the 

20 crossover, whatever the crossover point is, we would 

21 expect to find 50 percent sales of one material and 

22 50 percent sales of the other. That is, the 

23 likelihood is 50:50 at that point. If we find that 

24 at EL-0, for example, that that’s the crossover 

25 point and we find that amorphous -- that’s the 
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1 crossover point that would suggest that 50 percent 

2 market share for amorphous and that doesn’t exist. 

3 There’s no data that suggests that that’s the case, 

4 so you’ve got some real data, then, to check your 

5 crossover point calculations.

6 MR. RABA: Thank you. The other Steve.

7 MR. NADEL: Steve Nadel, ACEEE. A process 

8 suggestion. Looks like everybody’s ready to pounce, 

9 making points before we even barely begun this 

10 discussion. Perhaps we should let them present the 

11 results and then everybody can pounce based on this 

12 presentation, rather than based on any preconceived 

13 notion before the presentation.

14 MR. CYMBALSKY: I’d prefer a different 

15 word than pounce. But that’s just me.

16 MR. RABA: Jerry, no pouncing, but go 

17 ahead.

18 MR. CORKRAN: I’ll pounce -- regarding Mr. 

19 Berman’s crossover points, I totally disagree on the 

20 50 percent, and based on -- it’s not based on any 

21 designs, I don’t believe we have the ability to make 

22 transformer designs. But anyhow, my other point you 

23 guys are considering M2, but M2 is only available in 

24 a very limited quantity along with making M3. So 

25 you should not be considering M2. When you get past 
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1 M3, you’re leaving the market behind. You guys were 

2 thinking M2, but M2 is, I think, something like 18 

3 percent of the market is all it can be M2, so it 

4 just doesn’t come out any different than that. The 

5 steel manufacturers, I’m hopeful, will confirm that.

6 PARTICIPANT: Yeah.

7 MR. CORKRAN: So I think it’s very 

8 important you guys do not lock in on saying well, 

9 we’ve got M2 available, because it’s not available.

10 MR. LYKE: This is Rick Lyke, AK Steel. I 

11 can confirm that we can’t make 100 percent M2. We 

12 have to have a good market for M3 because the 

13 targets in terms of chemistry and processing are 

14 much tighter to make that product.

15 PARTICIPANT: But we’ve got to jump on 

16 that.

17 MR. LYKE: So we need, yeah, M3 is the 

18 volume product we can put out. We can put out some 

19 M2, but 15 to 20 percent, probably.

20 MR. RABA: Okay. Thank you. Go ahead, 

21 Chris, we’ll proceed. Again, good comments back, 

22 good exchange. Go ahead, please. 

23 MR. BOLDUC: Thank you. Right now on this 

24 slide here we have a DL-2 where we analyzed at half

25 an EL. I think the one thing I’d like to point out 
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1 here in the appendix 1A, the median LCC savings was 

2 -- this was presented as minus $533 dollars. That 

3 was incorrect. We have it corrected here as a 

4 positive $20 dollars, in bold. 

5 Overall, what we do see on this design 

6 line, which is you can see in the actual -- the 

7 payback period is illustrated very well, is that 

8 when we move from below EL-1 to El-1 and higher, we 

9 see a full transition that the LCC is picking 

10 amorphous steel from the design sample. In this 

11 case, the mix of steel that is used to produce these 

12 results was 90 percent M2. 

13 MR. RABA: Ray.

14 PARTICIPANT: At 0.5.

15 MR. BOLDUC: At 0.5, that’s correct.

16 MR. POLINSKI: Ray Polinski, ATI 

17 Allegheny. Again, I started off by saying early on 

18 that I disagreed the way -- the same comment as was 

19 made before. We can’t make 100 percent M2, either 

20 M2 is a very select processing parameter, its 

21 chemistry, et cetera. And so the one comment here 

22 for design line 2 was my understanding when the 

23 initial NOPR came out, just again, when the initial 

24 NOPR came out, there was a scaling issue and so EL-0 

25 was for design line 2, but it ended up being like 
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1 point four because of scaling issues. We not only 

2 made separate categories, and the fact that at point 

3 five you need 90 percent M2, again, I just go on the 

4 record that design line 2 should be a true EL-0. At 

5 zero. There’s no need to scale it to point four 

6 because we’re not scaling, we’ve mixed up the 

7 categories, so I just want to make that comment.

8 MR. BOLDUC: Okay. I’d like to counter 

9 just a little bit here. So I just really want to be 

10 clear that the steel percentages that I’m stating 

11 are the steels that -- they’re from the units that 

12 were selected from the design sample by the LCC 

13 spreadsheet. It’s just an artifact of the modeling.

14 MR. deLASKI: Andrew deLaski, if I can 

15 follow on, because -- so Ray, I guess I’m a little 

16 confused because at the NOPR hearing you supported 

17 the Department’s proposal, and the proposal’s levels 

18 were clear, they’re laid out in the NOPR, and it was 

19 essentially the levels -- it was the levels that you 

20 read, as you said, they had the scale because of the 

21 pads and the poles were in a single class. And so 

22 at the time, when you read that analysis, did you 

23 think that it would require you to have 90 percent 

24 M2 for the poles?

25 MR. POLINSKI: Ray Polinski, ATI 
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1 Allegheny. Andrew, yeah, we had the initial meeting 

2 and generally, as I say, the NOPR was 1, 0, 1, 1, 1. 

3 There was some issues with one -- we were in favor, 

4 you know, of maybe going a little higher on the 

5 pads, but by the comment period which was due by 

April 10th 6 I believe, we were very clear in the 

7 comment period that, you know, for design line 2, 

8 the point four level or point five level would 

9 really make the M3 not competitive. And so that’s 

10 the facts. I mean, you can look at the crossover 

11 charts that were prepared for the DOE by Navigant 

12 and you can see where M3’s slightly not competitive 

13 at the base case for design line 2. That’s the 

14 facts. 

15 MR. deLASKI: That’s the Navigant 

16 analysis, and it’s one analysis. I think we’ve 

17 heard each manufacturer has run analysis, and we’ve 

18 heard different information from manufacturers over 

19 the course of the docket and the negotiation. I 

20 mean this point of the crossover, we’ve been talking 

21 about it for a long time now, and I don’t think that 

22 the Navigant analysis is dispositive. And I think 

23 that the reaction of the manufacturers to the NOPR 

24 indicates to us that it’s not. Because folks 

25 thought, the manufacturers and the steel industry, 
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1 supported the NOPR. So to me that’s a pretty strong 

2 indication that the NOPR didn’t put us into all M2 

3 frame of design lines.

4 MR. POLINSKI: Ray Polinski, ATI 

5 Allegheny. Again, Andrew, to your point, as I say, 

6 we realize that there’s no perfect analysis, but the 

7 analysis we were told we were supposed to comment on 

8 was the analysis that was presented by the DOE. And 

9 to your point, if the NEMA members, they feel that 

10 they can survive at a design line 2 average EL-0, 

11 which is really a point four, well, we respect that, 

12 they make the transformers. But the data that we 

13 have, based on the data that we’re making these 

14 decisions on, it’s -- the crossover point is where 

15 M3 is not competitive at zero, that’s just the 

16 facts.

17 MR. deLASKI: And what do people use to 

18 build baseline transformers today by and large?

19 MR. POLINSKI: You’re asking me?

20 MR. deLASKI: Yeah.

21 MR. POLINSKI: You’d have to ask the 

22 transformer guys, I think it’s --

23 MR. deLASKI: Wes, what are you guys using 

24 for baseline transformers?

25 MR. PATTERSON: M3.
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1 MR. deLASKI: And it’s competitive --

2 (comments off mic)

3 MR. deLASKI: People are voting M3 as the 

4 baseline transformer, that’s what’s being used 

5 today. If it’s not competitive, again, it speaks to 

6 the flaws in the Navigant analysis, that it’s not 

7 truly telling us where this crossover is, and I 

8 think that’s the point that we want to make is that 

9 if the crossover continues to be a problem with the 

10 crossover, it’s not the purpose of the meeting 

11 today, John, so I’ll keep it brief, but we continue 

12 to have this problem. It is a critical issue -- it 

13 is the critical issue in the docket, absolutely it’s 

14 the critical issue in the docket, where we have the 

15 competition so we have robust competition amongst 

16 suppliers. We’ve all agreed on this from, I think, 

17 our first meeting.

18 MR. CYMBALSKY: I agree, so maybe I can 

19 just step in and say the Department understands 

20 that, appreciates that, gets that, and we will look 

21 very, very strongly at that. So maybe we can just -

22 - we all get it, let’s just --

23 MR. POLINSKI: Can I make one last 

24 comment, John, please. You know, because Andrew 

25 made a lot of comments directly at me, and the only 
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1 thing is -- and I would ask the transformer guys to 

2 comment. I’m not a transformer engineer as I said 

3 before, and I just don’t know, to your point, if M3 

4 is used at today’s baseline standards, and meets the 

5 standard, but is that due to availability of 

6 amorphous? If there was more amorphous available, 

7 would it be still a lower cost transformer? I don’t 

8 know the answer to that question. You say M3 is 

9 being used, but is it being used at a slight cost 

10 disadvantage? That’s what the charts suggest.

11 MR. RABA: Aaron.

12 MR. MEYERS: Aaron Meyers, Cooper Power 

13 Systems. A couple points here. First of all, 

14 regarding the 50 percent breakdown that Mr. Berman 

15 brought up, I mean, a little bit of that has to do 

16 with manufacturing capacity. So if a manufacturer 

17 has the capacity to build twenty times more 

18 conventional steel transformers than amorphous, 

19 obviously there’s not going to be a 50:50 split. 

20 And that also somewhat addresses the point as to 

21 what transformer manufacturers are building baseline 

22 transformers with today. It’s hinging somewhat on 

23 equipment capacity. 

24 The other point here is regarding the life 

25 cycle cost analysis and the fact that it’s free to 
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1 use 90 percent M2 in certain cases, rather than 

2 being limited by the supply. And I’m curious to 

3 know what the outcome would be in terms of life 

4 cycle costs if M3 were substituted for M2 in this 

5 analysis, would it still be positive? 

6 And my final comment/question is that 

7 there was information provided to the DOE regarding 

8 loading factors and whether or not that will play 

9 into the sensitivity analysis or new life cycle cost 

10 analysis, because when combined with the energy cost 

11 and the loading, I don’t really -- I guess I don’t 

12 believe this, this life cycle cost. I don’t believe 

13 that there is a big benefit for the nation to even 

14 advance beyond where we’re at today.

15 MR. RABA: John.

16 MR. CASKEY: I don’t want to go back and 

17 hash everything either, but okay, so when we did --

18 when the NOPR was released and we provided comments 

19 on the NOPR, we had an opportunity to see those 

20 scatter diagrams and to try and figure out what the 

21 mix of steels were in those design lines and 

22 efficiency levels. Is there -- and I don’t know if 

23 this is the same as what Greg had asked earlier, but 

24 can we get the percentages that you’re rattling off 

25 up there now for the different -- for particularly 
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1 the new efficiency levels, can we get those 

2 percentages like within the next couple of days so 

3 that we can factor that into our final comments that 

4 we submit relative to this new analysis?

5 And I realize before he says anything, 

6 that certainly the model is the model and we’ve all 

7 argued with the pros and cons of it, and you guys 

8 are doing the best job you can to get in the right 

9 ballpark, but where there are radical shifts, it 

10 would be nice to know that it’s being produced by 

11 the model because that drives everything else.

12 MR. RIVEST: So -- this is Mike Rivest. 

13 Since everyone is bringing this up, I’m going to 

14 have to say something. Remember, we are modeling 

15 one KVA. We have modeled one specific voltage 

16 primary, one specific secondary, one specific BIL. 

17 I caution you to make radical predictions on steel 

18 mix based on that, I mean, and dismissing experience 

19 and what the knowledge of the people in this room 

20 is. So to say that these are the facts and these 

21 are the only facts, is incorrect. There are other 

22 facts that weigh in this decision. We did not model 

23 every voltage, every KVA, every BIL rating, and 

24 that’s just the truth.

25 MR. deLASKI: So Mike, to follow on, that 
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1 implies that you can’t estimate steel tonnage based 

2 on your model.

3 MR. RIVEST: You know, I think that with 

4 the precision we’re trying to have here that you 

5 should rely on other information than just what’s 

6 coming out of that. And that’s why when I hear, 

7 well, what’s the mix coming out at EL-1.5, M2 versus 

8 M3, we didn’t even model every kind of steel there 

9 is. We didn’t model every design -- every way these 

10 things can be designed. There’s a much more variety 

11 in the market than what we can model.

12 MR. RABA: Steve R and then Steve N 

13 afterwards.

14 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

15 Mr. Rivest I appreciate that but don’t you have to 

16 rely on the information from the models to make the 

17 ultimate decision?

18 MR. RIVEST: We have to rely on the 

19 information in the docket.

20 MR. ROSENSTOCK: And the information that 

21 you receive from stakeholders, yes, both?

22 MR. RIVEST: Yes.

23 MR. ROSENSTOCK: Thank you.

24 MR. NADEL: And actually my point -- Steve 

25 Nadel from ACEEE -- and my point is picking up on 
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1 that, basically we have one snapshot from this 

2 Navigant analysis. We have lots of other 

3 information in the docket. What I heard John say is 

4 he’s going to look at all that information. 

5 Everybody recognizes crossover point is key, and we 

6 look at that whole set of information and he decides 

7 is it level zero, is it level 2.5 or where in 

8 between is that crossover point.

9 MR. RABA: Deep breath. Should we 

10 proceed, Chris.

11 MR. BOLDUC: Yes, thank you. So these are 

12 the results for DL-3, and this is where we added the 

13 pole replacement algorithm. So we used the same 

14 methodology that we used in DL-2. We went back to 

15 RS-means 2011, the same source for our pole 

16 replacement estimates that we used in the NOPR. We 

17 increased the pole replacement cost by the -- adding 

18 an additional crew, I believe it’s called a heavier 

19 crane, to increase the overall pole replacement 

20 cost. This pushed the distribution from around

21 $5800 up to close to $8000 per pole replacement.

22 We also scaled the weight change out

23 thresholds. So we took the 150 pounds that was used 

24 for DL-2, we scaled it with the .75 scaling rule up 

25 to 1418 pounds. Now I’m going to be very honest 
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1 here, perhaps a bad thing, but we found that the 

2 actual number of pole replacements with this 

3 configuration was negligible, less than two percent. 

4 The factor that came down to it was the minimum 

5 weight threshold of 1418 pounds. 

6 Now also in this meeting, Carlos 

7 maintained that for these larger KVA transformers, 

8 they’re usually mounted on platform type 

9 installations. That was not clear to me when we 

10 were doing the analysis. Looking through product 

11 catalogs, we did find many mounting brackets that 

12 would hold up to 6000 pounds of transformer for each 

13 arm, so that’s based on -- this is not based on 

14 using a platform, it’s based on poles. Steve.

15 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

16 In the new appendix 1A that you put out, you show, 

17 in table 1-A.3.4 you talk about summary of weight 

18 for pole mounted design lines by efficiency level. 

19 And it looks -- and again, you show minimum, 

20 average, and maximum, and the average -- I’ll just 

21 use the average values for now -- that was 22,812 

22 pounds, and you do the scaling and it says, well, it 

23 won’t be until 1400 pounds, that’s 4200 pounds and 

24 based on the data that you have in this appendix, it 

25 says you don’t get to that until efficiency level 7.
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1 MR. BOLDUC: As I said, it’s a shortcoming 

2 that we would like comment on.

3 MR. ROSENSTOCK: Okay. And again, I think 

4 you received some comment that the delta --

5 sometimes the delta of the transformer isn’t as 

6 important as a certain weight limit on the pole. 

7 That even if you only go up a couple hundred pounds, 

8 if that’s enough to get to the structural weight 

9 maximum of the pole because of the other utilities 

10 on the pole, for example, in utility areas, just 

11 that small delta based on everything else could lead 

12 to the change out. I know the modeling and you’re 

13 scaling it, but again I think we’ve sent you 

14 information, the fact that especially in urban areas 

15 with combined utilities on the same pole, that it’s 

16 not just the delta of the transformer, it’s the 

17 delta to certain structural maximums on the pole.

18 MR. BOLDUC: Thanks.

19 MR. ROSENSTOCK: Again, I have to be 

20 honest, I want to be fair. I’m not sure how you 

21 model that. You might want to say for a percentage 

22 of the poles, especially if you have a -- if there’s 

23 some way to analyze urban versus non-urban poles, 

24 that might be one way to do it in terms of some of 

25 your analysis. If there’s a way to find that data 
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1 out.

2 MR. BOLDUC: Thanks, Steve. Moving on to 

3 DL-4. Again what we’re seeing here is pretty much 

4 an extension of the NOPR analysis, what we would 

5 expect. At around EL-2 we do see the switchover in 

6 the LCC picking amorphous, that’s why we see the 

7 decrease in payback periods. 

8 And likewise in DL-5. Robert.

9 MR. BERMAN: Robert Berman, Berman 

10 Economics. Can we go back? I’m processing a little 

11 slowly today.

12 MR. BOLDUC: Sure thing.

13 MR. BERMAN: Why do the payback periods --

14 why is the chart U-shaped on efficiency levels?

15 MR. BOLDUC: The payback, yes. This is 

16 because we’re seeing a transition to amorphous.

17 MR. BERMAN: That --

18 MR. BOLDUC: Around EL-2.

19 MR. BERMAN: That talks about a decline, 

20 and then the -- going back up again is?

21 MR. BOLDUC: That’s the increase -- if you 

22 remember the engineering curves --

23 MR. BERMAN: Increased costs. Okay. All 

24 right, and that -- that’s fairly flat, then. Okay. 

25 MR. BOLDUC: Aaron?
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1 MR. MEYERS: Aaron Meyers, Cooper. 

2 Looking at design line 5 here and the mean retail 

3 cost, in EL-1 it’s $28,000 and change. EL-1.5 it’s 

4 $25,000 and we generally see the cost of the 

5 transformer going up with the efficiency level. And 

6 so I’m wondering is that responsible for driving 

7 this payback period for the transformer of 1.1 years 

8 which kind of seems unbelievably good, I guess.

9 MR. BOLDUC: Yeah, that looks -- it does 

10 look --

11 PARTICIPANT: Suspicious.

12 MR. BOLDUC: -- suspicious, thank you. I 

13 don’t have an explanation for that, Aaron, I’ll have 

14 to take a look at the model just to make sure 

15 everything is reported correctly. Thanks.

16 National Level Impacts: NIA Results

17 MR. BOLDUC: So what we have here is we 

18 have the proposed standard in green, and we have 

19 additional TSLs A, B, C, and D off on the right. As 

20 you can imagine, what we’re seeing here is we’re 

21 actually across the proposed TSLs or the new TSLs, 

22 we are seeing an extension that we would expect from 

23 the LCC results that were fed in there. Do you have 

24 any questions? Jerry.

25 MR. CORKRAN: Jerry Corkran, Cooper Power. 
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1 Regarding your proposed TSL-1 what did your 

2 calculations show for the percentage of amorphous 

3 and percentage of grain-oriented core steel?

4 MR. BOLDUC: For TSL-1? I don’t have 

5 those numbers. I’m sorry. Steve.

6 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

7 Just to clarify, on the second line of that, where 

8 it says equipment cost, that’s the change in 

9 equipment cost compared to the base, right?

10 MR. BOLDUC: That’s right.

11 MR. ROSENSTOCK: Thank you.

12 MR. BOLDUC: Yes. Okay. So 

13 disaggregating these national level impacts to give 

14 an illustrative overview of what the savings might 

15 be for pads and poles as separate equipment classes, 

16 the Department basically assumed a 70:30 split. 

17 It’s a very rough estimate for the impacts of the 

18 pole mounted or -- sorry, equipment class 1A, which 

19 is the all other equipment class, and 1B. A number 

20 of reasons for this: one, at the time, we did not 

21 have the disaggregated data that we needed to 

22 separate the shipments by pads and poles, and also 

23 we wanted to go forward with the NOPR tools. So 

24 these numbers are very soft. I’d just like 

25 everybody to keep that under consideration.
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1 Likewise, for the three phase, we assume 

2 that 95 percent of the savings would be attributed 

3 to the pad or all other three phase transformers; 

4 only five percent would be attributed to three phase 

5 pole mounted.

6 So, in summary, for TSL A, which is very, 

7 very close to what the proposed standard was, we’re 

8 looking at point four five (0.45) quads of savings, 

9 NPV of close to .93 billion at seven percent, and 

10 4.66 at three percent discount rates. For most 

11 equipment classes we have a net benefit greater than 

12 60 percent. These are based on the LCC numbers.

13 In terms of the physical changes in the 

14 transformers which I know people are very concerned 

15 about, we’re showing a weight increase of between a 

16 four percent for DL-3 and a ten percent weight 

17 increase for DL-2. Aaron.

18 MR. MEYERS: I did look at 25 KVA poles 

19 and 50 KVA poles, only poles, because that’s what 

20 we’re primarily concerned with here, and to go to 

21 EL-2 and keeping with M3, there was a 40 percent 

22 increase in weight for both of them. So I just 

23 figured I’d throw that out as a piece of information 

24 as the DOE’s looking for feedback.

25 MR. BOLDUC: Sure, can you include that in 
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1 the written comment afterwards?

2 MR. MEYERS: Sure.

3 MR. BOLDUC: Thanks. Steve.

4 MR. ROSENSTOCK: Chris, again, thank you 

5 for this information, but I just want to double 

6 check. You said the volume increase of 14 percent. 

7 When you say footprint, that’s length by width --

8 MR. BOLDUC: That’s right.

9 MR. ROSENSTOCK: -- in terms of pad? 

10 Okay, I just wanted to double-check.

11 MR. BOLDUC: And likewise, moving on to 

12 TSL B. We’re looking at point six (0.6) quads of 

13 savings, and 1.2 billion in NPV at seven percent, 

14 with 6.4 billion at three percent discount rates. 

15 And again, we don’t see a large change in the pole 

16 mounted transformers, I believe. We do see a larger 

17 change in the single phase pad mounts in terms of 

18 weight. Volume increases are all quite small. 

19 But we do see a change in the materials 

20 mix in the very bottom line. I can read this out, 

21 but everybody looks like they’re reading it -- able 

22 to read it just fine. Robert.

23 MR. BERMAN: Robert Berman, Berman 

24 Economics. Could you say a few words about how 

25 those percentages are calculated on the results, the 
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1 last line on the slide. I’m not sure -- I’m trying 

2 to do the -- I’m trying to visualize the 

3 calculation.

4 MR. BOLDUC: So this is the sampling --

5 sorry. These are the results from the LCC sample, 

6 the percentage of units selected by the LCC at each 

7 EL for each design line. 

8 MR. BERMAN: Okay, so these are the 

9 percentage of units --

10 MR. BOLDUC: That make up the simulation.

11 MR. BERMAN: -- that make up the 

12 simulation?

13 MR. BOLDUC: Sorry, the simulated results.

14 MR. BERMAN: So that’s what’s included in 

15 the sample space, not what necessarily wins?

16 MR. BOLDUC: This was what was selected by 

17 the LCC. There are many more materials inside the 

18 sample space, but this is the percentage of core 

19 materials that was sampled by the LCC.

20 MR. BERMAN: Selected as least cost or?

21 MR. BOLDUC: Yes, lowest least cost or 

22 lowest TOC. These numbers are available on the 

23 summary results tab of all the LCC worksheets, 

24 workbooks. Greg.

25 MR. COULTER: This is Greg Coulter. I 
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1 have a question. If I just look at TSL A and B up 

2 there.

3 MR. BOLDUC: Yes.

4 MR. COULTER: The efficiency class 1A and 

5 1B. 1B is poles. Between TSL A and TSL B, the 

6 efficiency levels are exactly the same.

7 MR. BOLDUC: That’s right.

8 MR. COULTER: But --

9 MR. BOLDUC: The savings are different.

10 MR. COULTER: The savings are different.

11 MR. BOLDUC: That’s right. That’s an 

12 artifact of the rough 70:30 split, or 95:5 split I 

13 mentioned earlier.

14 MR. COULTER: But you have that covered 

15 under equipment class B, right? I’m not too sure, 

16 you know, one’s poles. Poles didn’t change, only 

17 pads would change --

18 MR. BOLDUC: That’s right.

19 MR. COULTER: Why does a pad change affect 

20 a pole change?

21 MR. BOLDUC: We didn’t have the numbers to 

22 change the NIA -- we didn’t have the specific pole 

23 versus pad by KVA rating in terms of shipments to 

24 modify the NIA to give you a more accurate answer. 

25 Right now, these are illustrative numbers that we 
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1 think this is what is possible. It’s a long way of 

2 saying we took equipment class 1 and we split it 

3 70:30 at each TSL for poles and pads.

4 MR. CYMBALSKY: And we’ll take comment on 

5 what those percentages --

6 MR. BOLDUC: Oh, yeah, we’d love those 

7 numbers.

8 MR. CYMBALSKY: -- should be. If you 

9 think they’re different, we’d love to know what they 

10 are.

11 MR. COULTER: My comment is simple. Once 

12 you know the percentage, it don’t change whether 

13 you’re an A, B, C, or D. So your pole class up 

14 there should not have changed whether I’m in A, B, 

15 C, or D. That’s my point. So no change in 

16 efficiency should have been no change in the energy 

17 savings.

18 MR. BOLDUC: Well, I understand, Greg. I 

19 thought my -- I mean whether it’s 60:40, I don’t 

20 care, 70:30, 80:20, those numbers shouldn’t have 

21 changed. That’s all.

22 MR. COULTER: I don’t see how those 

23 numbers could change with no change in efficiency. 

24 Same volume.

25 MR. BOLDUC: I don’t have those volume 
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1 numbers, Greg. This is my point. Andrew, I 

2 understand you had a written comment. Does this 

3 answer your question?

4 MR. deLASKI: It doesn’t, but I’ll keep 

5 puzzling over it.

6 MR. BOLDUC: Okay. Thanks. TSL C, which 

7 we’d like to state was the advocates final position 

8 from the Reg Neg, which we finally have here today. 

9 PARTICIPANT: (Comment off microphone)

10 MR. BOLDUC: I’m trying. That would save 

11 roughly 1.3 quads over the analysis period. NPV of 

12 2.99 billion at seven percent, and 13.51 billion at 

13 three percent. And again, the physical

14 characteristics. Do I have any questions? 

15 MR. ROSENSTOCK: So, Chris, this is Steve 

16 again. At the bottom there, again, just based on 

17 the model it’s basically either 79 to 100 percent 

18 amorphous?

19 MR. BOLDUC: That’s right.

20 MR. ROSENSTOCK: Across all design lines, 

21 right?

22 MR. BOLDUC: That's correct.

23 MR. ROSENSTOCK: And then the other part 

24 is M2?

25 MR. BOLDUC: Yep.
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1 MR. ROSENSTOCK: Thanks.

2 MR. BOLDUC: And again, TSL D, which is a 

3 modified version of TSL C, if you will. Where we’re 

4 seeing 1.2 quads of energy over the analysis period, 

5 and 12.93 billion in savings at seven percent, and 3 

6 billion at three percent. Thank you.

7 So moving on to the comments sought --

8 shall I keep going? So for this, you know, we’d 

9 really like to reiterate that we’re -- after your 

10 comments on the new equipment classes, the new ELs, 

11 we also -- well, we’re seeking comment on all 

12 aspects of this analysis for the final rule. In 

13 particular, comments on 

14 the new equipment classes, pole/pad, 

15 network/vault, 200 KVA, BIL, any new TSLs. 

16 Opportunity for other energy savings. 

17 The appropriateness of efficiency levels for 

18 each class

19 The pole replacement costs, which I believe 

20 I’ve gone over

21 And the shipments data of all types.

22 Robert.

23 MR. BERMAN: Robert Berman, Berman 

24 Economics. One thing I haven’t seen in this that 

25 would seem to be pretty relevant to think about 
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1 is potential for substitutability. That is to 

2 say, take the 200 KV BIL class for example. If I 

3 hold that, just for the sake of argument, if I 

4 hold that at EL-0 and increase 150 to El-2, am I 

5 better off buying -- is it cheaper for me to buy 

6 a 200 KV BIL when what I really need is a 150? 

7 Do I create distortions on that? Similarly, I 

8 guess I don’t have any -- problem doesn’t appear 

9 to come up with poles and pads, because I can’t -

10 - I can’t use a pole transformer on a pad, I 

11 guess, even if I run the wires up and down. But 

12 for bulk transformers if I take a look at the 

13 minimum requirements for a vault, according to 

14 the specs, rather than the price of a typical 

15 vault transformer which likely includes lettuce, 

16 tomato, pickle, and onion, is it cost effective, 

17 is there a trade-off on cost or what is the 

18 tradeoff on cost for vault versus pads? Here we 

19 don’t have a -- our current mix data doesn’t help 

20 us because if we’re going into a type of 

21 transformer that’s technically substitutable, and 

22 start changing efficiencies and relative prices, 

23 we might get the market responding in ways we 

24 never thought of before. And I’m just interested 

25 in what opportunities there might be for that 
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1 response.

2 MR. BOLDUC: Thank you. Tim.

3 MR. BALLO: Tim Ballo, Earth Justice. 

4 Just following on to Robert’s comment. I think 

5 during the workgroup that developed the 

6 definition for the network and vault 

7 transformers, we had some data from ABB and from 

8 Progress Energy that suggested that there was a 

9 fairly significant price premium for vault units 

10 meeting the IEEE standard. However, as was 

11 pointed out on one of the earlier slides, 

12 something like 90 percent of vault transformers 

13 use a very high quality steel. And if I was a 

14 utility and wanted to buy a really low cost 

15 transformer, if I were to order one meeting the 

16 IEEE vault requirements but not having that high 

17 quality core, what would the cost differential 

18 be? And it seems like there’s an awful lot of 

19 potential here for a submersible transformer 

20 meeting the IEEE requirements to be sold and 

21 installed on a pad. So I’m wondering, is there 

22 any analysis available for what that cost 

23 differential is for just meeting the submersible 

24 requirements? 

25 MR. RABA: Wes.
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1 MR. PATTERSON: Wes Patterson. My 

2 understanding was that the existing standard 

3 already applies to the networks, so they can’t be 

4 made any lower than the existing standard. And 

5 to comply with the existing standard has already 

6 forced those products into the high grade steel.

7 MR. BALLO: So I guess my question is, are 

8 they using the high grade steel to meet the 

9 standard within the dimensional constraints of 

10 fitting into the vaults?

11 MR. PATTERSON: And the answer to that is, 

12 yes.

13 MR. BALLO: Okay, but if I’m producing a 

14 unit that while having to be submersible, 

15 wouldn’t have to fit into the vault, do I then 

16 have to use the high grade steel? If I’m 

17 producing a unit with the purpose of, although 

18 it’s name plated as a vault unit, it’s nudge, 

19 nudge, going to be sold and installed on a pad. 

20 It seems like I wouldn’t have to still use the 

21 high grade steel at that point.

22 MR. PATTERSON: There’s a couple of 

23 dimensions to answer this question. One is you 

24 cannot install a unit designed as a network or a 

25 vault on a pad. If we’re talking about pad mount 
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1 transformers. Because those are in publicly 

2 accessible areas and these units are not designed to 

3 be safe for access to the general public. By 

4 compliance with that standard, they cannot be 

5 physically deployed in a pad installation. One 

6 could say, okay, you’d be crazy enough to put one in 

7 for a substation transformer in restricted access 

8 area, however the cost of these units run 80 percent 

9 more than a standard transformer, because of all the 

10 other requirements within the standard. Not just --

11 I mean, even before we went into the high grade 

12 steel, these things carried an 80 percent premium to 

13 them.

14 MR. HIRSCH: Let me interrupt?

15 MR. RABA: Go ahead. We have an answer 

16 here, perhaps? Thank you, Wes.

17 MR. HIRSCH: Bruce Hirsch, Baltimore Gas 

18 and Electric. I don’t know if I have an answer, but 

19 from a utility standpoint, I can tell you that I’d 

20 much rather put a pad mounted transformer up than to 

21 put a submersible unit. Submersible transformers, I 

22 mean we talk about the weight of the steel and 

23 everything, quite honestly, the maintenance of 

24 anything that’s underground is extremely high, so 

25 there’s just a tremendous amount of cost. I just 
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1 don’t believe that any utility would take a vault 

2 design and put it on a pad somewhere, don’t make any 

3 sense at all. Utilities would try to put a pad 

4 mount transformer in a vault, but it’s bought by the 

5 pad mount standards, and quite honestly, wouldn’t 

6 last very long because of the corrosion issues. So 

7 I think those are the things that you really need to 

8 take into account. There’s a direct difference 

9 between a network or a vault type transformer than a 

10 pad mount transformer, from the utility’s point. 

11 The other thing I’d like to point out too 

12 is, from the utility’s standpoint that has a big 

13 city, Baltimore, we don’t have an option. We are 

14 told we will be putting things underground, so we’re 

15 mandated to go with the networks and the vaults we 

16 buy, and we are not expanding that system at all. 

17 Very few units are bought for new installations. 

18 They all -- most of what we buy are replacement 

19 installations, that’s the size limitations that we 

20 run into in the discussions that we’ve had.

21 So I think it’s important to know. I 

22 think most of the utility business in networks and 

23 vaults is replacement type transformers, and using 

24 one for the other just -- it just doesn’t make any 

25 sense financially to a utility to do that.
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1 MR. RABA: Perhaps you had an answer. 

2 Thank you very much. It was very helpful, Bruce, 

3 thank you. We have a caller on the line waiting, 

4 Kevin Alman. You’re live, go ahead, sir.

5 MR. OEHLMANN: Thanks. Kevin Oehlmann

6 from Con Edison in New York. Just to kind of, I 

7 guess, tie into what -- hello, can you hear me?

8 MR. RABA: Yes, we can.

9 MR. OEHLMANN: Just to tie in to some of 

10 what the individual from Baltimore was saying. We 

11 have approximately 26,000 network transformers 

12 installed throughout New York City. We cannot 

13 install those on pads and we do not put pad mount 

14 transformers in vaults. The cost associated with 

15 expanding vaults, if we could do that, would be 

16 quite high in New York City, just because there is 

17 no real estate to do so, and it would have a 

18 significant financial impact to our rate payers, 

19 should we have to go in that direction.

20 MR. RABA: Thank you. Very helpful. Very 

21 helpful. Thank you, Kevin. Bob Berman.

22 MR. BERMAN: Robert Berman, Berman 

23 Economics. I understand it’s not cost effective to 

24 put a pad in a vault, for exactly the reasons you 

25 say -- suggest. But if I were to make a pad vault 
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1 transformer accessible or non-accessible, for 

2 example, if I put a hood on the only thing that’s 

3 showing to the public, on the connectors on top, so 

4 that was basically locked down the same way as a pad 

5 transformer is locked, could I not put it on a pad 

6 if it was cheaper to do so? Again, Jerry’s quite 

7 correct, I’ve never designed a transformer, but the 

8 question is, how is the market likely to respond if 

9 we start changing cost significantly. We’ve got a 

10 set of IEEE standards that were set up, that says 

11 nobody puts vault transformers on pads and nobody 

12 puts pad transformers in vaults, and this is what 

13 you’ve got to do to have the electronics correct, 

14 this is what the standard is. Those standards do 

15 not, nor should they try to conceive of what happens 

16 if, through regulation, we decide to distort 

17 relative prices dramatically. And my question is, 

18 what happens if, through regulation, we distort 

19 relative prices? And what is the amount of 

20 distortion in relative prices that we’re talking 

21 about? So I think we need to calculate what that 

22 is, and that’s not a question of what does a typical 

23 vault transformer sell for, or what does a typical 

24 network transformer sell for. That is, what do I 

25 have to do to qualify something as a vault under the 
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1 standard?

2 MR. RABA: Thank you, Robert. We have 

3 several hands up. We have one caller who was first, 

4 David Millure, go ahead, we’ll put you live.

5 MR. MILLURE: Thanks. Dave Millure, 

6 Metglas. We were talking earlier about the 200 BILs 

7 for the vaults and I think Greg Coulter said that we 

8 should move that down to 150. My question is, if we 

9 move it down to 150 and carve that out, then if you 

10 want to buy a 125 at some new higher efficiency 

11 standard, versus a 150 at the existing efficiency 

12 standard, would not the 125 BIL higher move to a 

13 150? So you’re talking market size. We heard about 

14 five percent for the 150 and above, maybe we should 

15 talk a 25 percent, whatever it is, for the 125 and 

16 above, would be the actual impact of that carve out. 

17 Thank you.

18 MR. RABA: Thank you. We’ve got more 

19 hands coming up. Let’s take these in turn, please. 

20 I think you were next, Andrew.

21 MR. deLASKI: Go ahead.

22 MR. RABA: Okay, passing on. Jerry.

23 MR. CORKRAN: Regarding the different 

24 equipment classes that we discussed --

25 (comment off microphone)
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1 MR. CORKRAN: Good point, any comments on 

2 the comment.

3 MR. COULTER: I would like to comment 

4 because he mentioned me. 

5 MR. CORKRAN: Go ahead Greg. Greg 

6 Coulter.

7 MR. COULTER: This is Greg Coulter. I 

8 think Dave Millure has an excellent point, actually. 

9 It’s a point we’re concerned about. If you would 

10 suggest that 150 BIL was the new cutoff rather than 

11 200, well, people would just start ordering 

12 everything as 150 BIL and get a lower efficiency. 

13 So we’d be concerned about that too. There’s ways 

14 to cover that. The easiest way, it’s really a 

15 voltage issue. BIL is a simple way of talking about 

16 this for purposes of meeting like this, but there’s 

17 certain voltages have to be 150 BIL, and there’s 

18 certain voltages do not, and we’d really make that a 

19 voltage cutoff, not a BIL cutoff. At least that 

20 would be my suggestion the way that’s handled. 

21 These voltages are 150 BIL and above and they would 

22 be subject to different efficiency levels than these 

23 other voltages. And you cannot use the wrong 

24 voltage in these cases. Thank you.

25 MR. RABA: Thank you. And now are there 
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1 additional -- I think you were going to -- Bruce, 

2 you had something there?

3 MR. HIRSCH: Yes, Bruce Hirsch, Baltimore 

4 Gas and Electric. Just answering Bob’s comments 

5 before. I think in one of these meetings earlier, 

6 somebody likened it to using a Sherman tank when a 

7 Chevy Cruiser would do. That’s essentially what 

8 you’d be talking about if we were using a network 

9 transformer. Inherently they’re more expensive 

10 because of the thickness of the steel, and it’s 

11 built that way to withstand subsurface requirements. 

12 Certainly I’m not naïve enough to say that somebody 

13 wouldn’t use a tank to drive back and forth to work

14 once in a while. So it’s possible. It certainly is 

15 possible that you can take a network transformer, 

16 make it safe enough and set it out in the open. 

17 It’s hard to believe that anybody would do it. 

18 And I think also that if that’s ever done, 

19 what happens is it now doesn’t meet the requirements 

20 of a network, it’s got to meet the requirements of a 

21 pad mount, and it would fall under the auspice of 

22 the efficiency standards that were required. But 

23 anyway, I think you’ve just got to understand the 

24 differences there. Can somebody misuse equipment, 

25 certainly they can, but I think in this case it’s a 
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1 big if. It’s a big if.

2 MR. RABA: We saw over here. Go ahead, 

3 please.

4 MR. HOFFMAN: Alex Hoffman, American 

5 Public Power Association. I was just going to 

6 reiterate it based on conversations with various 

7 municipal utilities, especially since Wes just 

8 mentioned that we were talking about a transformer 

9 that’s 80 percent more expensive by design. So it’s 

10 not just price, and I hope -- presumably this 

11 standard is not intending to raise the cost of a 

12 transformer by 80 percent. But there’s also like 

13 was mentioned, safety issues, these are very 

14 serious, and they have legal ramifications. There’s 

15 good design issues, so it’s really not efficient to 

16 put these vault -- pad transformers in vaults, 

17 because the life cycle of your equipment receives a 

18 major impact there. As it is designed and installed 

19 -- or designed by an electrical engineer, there’s 

20 licensing implications. So the engineer has an 

21 ethical obligation not to do something like this and 

22 can -- there’s a ramification. There are sets after 

23 sets after sets of ramifications for mis-installing 

24 a vault -- a pad transformer in a vault. And so I 

25 just thought I would reiterate that because I think 
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1 it’s really important point in this discussion.

2 MR. RABA: I saw Andrew first, or are you 

3 going to comment on these also, Andrew?

4 MR. deLASKI: Yes, I guess I would just 

5 try to summarize by saying, you know, we have 

6 expressed in the past that we are comfortable with, 

7 if DOE does go to standards that are significantly 

8 higher than what has been proposed with separating 

9 out classes. But I think the point’s been raised 

10 today suggest that there’ll need to be a hard look 

11 at the definitions to make sure that we’re not going 

12 to abuse it. I hear you Bruce. A network 

13 transformer -- we’re not that worried about that 

14 based on our review of IEEE. The vault definition, 

15 we’re not sure the IEEE definition is as tight --

16 certainly it’s not as tough as the network 

17 definition. So the vaults give us a little bit of 

18 pause, and we would like a hard look at that 

19 definition and urge the Department to do so as well. 

20 Is the vault definition tight enough.

21 And then to avoid someone -- the market 

22 changing in a way that we don’t anticipate, so it’s 

23 the unanticipated consequences that we’re trying to 

24 avoid here. And Greg, thank you for your suggestion 

25 of voltage. I think -- and we’re also very 
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1 concerned that 150 that that just becomes not five 

2 percent, but the whole market. So there’s going to 

3 have to be something tighter on that. So I think if 

4 we go with high BILs, 200 doesn’t seem like much of 

5 a risk, or go to 150 then that’s going to have to be 

6 controlled in some other way. And again, if we’re 

7 talking about higher levels, I think it’s totally 

8 appropriate to have those conversations.

9 MR. RABA: First Robert, then Bob, then 

10 Steve. Then I think we’ll get back to cue you 

11 Jerry.

12 MR. BERMAN: It’s really important to look 

13 at the costs on this, and the importance of cross14 substitutability. We’ve already got a huge hole in 

15 the regs now on pad transformers in that step up 

16 transformers for wind aren’t covered. If I buy a 

17 wind transformer, I can use it on a distribution 

18 network. The -- whether or not this is done or the 

19 extent to which it’s being done, I don’t know. But 

20 the -- in looking across, trying to see what the 

21 costs are, I was a little surprised to see in terms 

22 of selling price that the network transformers were 

23 just a little bit more expensive than non-network 

24 vaults, with a whole lot more electronics on them. 

25 And I’m wondering if a lot of these -- the question 
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1 is, are a lot of these vault transformers being 

2 purchased with switchgear that would not be 

3 purchased on pad mount transformers necessarily, and 

4 that are not required to meet the IEEE definition of 

5 a switch.

6 In looking at that, it seemed to me that 

7 Yeah, the case has to be -- is a lot more expensive. 

8 I took a look at a copper bearing steel tank that 

9 was maybe much thicker, three times the cost of the 

10 existing tank. Everything that I can come up with, 

11 other than the electronics which, as Jerry points 

12 out, I don’t design transformers so I don’t know 

13 about. I can get up to a ten percent difference in

14 cost by goosing some of those items. That tells me 

15 that there’s a lot more in what’s being sold as a 

16 vault transformer than is absolutely required to 

17 meet the specs. So the concern is, is it possible 

18 within the standard, to put a sign on something that 

19 says, this is a vault transformer because it meets 

20 this standard, and sell it in the market as a pad?

21 MR. RABA: Bob?

22 MR. SAINT: It seems to me that you’re 

23 drawing at straws trying to come up with something 

24 that really has no validity. I don’t think that 

25 electric utilities are going to misuse, misapply 
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1 transformers. They’re just not going to do that, 

2 because of the reasons stated in this room. 

3 However, there is another thing that maybe 

4 should be concerned about, even more than this is 

5 the use of rebuilt transformers, to save money, and 

6 that may be -- to me, that’s more of a -- that’s 

7 more likely to occur than a utility misusing a new 

8 transformer. And certainly that is a valid concern 

9 that has been addressed in this room before because 

10 they’re not under this rule. And as the prices go 

11 up, more and more utilities are going to be looking 

12 at rebuilt transformers rather than buying a new 

13 transformer, because of the size requirement that 

14 may occur, and the efficiency drives the cost up too 

15 much.

16 MR. CYMBALSKY: Thanks, Bob. We’ve been 

17 through that set of bushes, woods, and so I don’t 

18 want to rehash that argument, please.

19 MR. SAINT: Thank you.

20 MR. RABA: That was helpful, Bob. First 

21 Steve, then Kevin Oehlmann on the phone. Steve.

22 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

23 hear the concern about possible substitution because 

24 one type of transformer might have a higher standard 

25 compared to the other, and involved would be the 
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1 baseline, which by the way, is increased based on 

2 the 2007 standards. They all -- all their standards 

3 went up as a result of the final rule in 2007 that 

4 took effect in 2010. So the standards for networks 

5 and vaults actually have gone up as result of the 

6 2010 standard. So they’ve already had an increase 

7 in efficiency because of the last rulemaking. 

8 That’s one thing to consider.

9 The second thing, just to summarize, 

10 there’s a lot of regulations where you’re not 

11 allowed to build -- put a pad mount transformer in a 

12 city. It’s just not allowed. Thou shalt put it 

13 underground. Baltimore, New York, other cities, 

14 even other new smaller cities, you know, a lot of 

15 them have plans where you’re putting infrastructure 

16 underground for aesthetic reasons. So even if the 

17 economics said well, put in a pad or substitute it, 

18 the local regulations say, thou shalt not. Period. 

19 You would violate the law, and utilities don’t like 

20 to violate laws. Trust me on that one. Thank you.

21 MR. RABA: We’ll trust you, Steve. Thank 

22 you. That was helpful. Kevin on the phone, please. 

23 Go ahead. Your turn.

24 MR. OEHLMANN: Thank you. Once again, 

25 Kevin Alman in New York City. I guess I hear some 
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1 discussions on, I guess in relation to the 

2 definition of the equipment classes. I do have a 

3 concern with the definition in the current language 

4 for a network transformers. As I mentioned earlier, 

5 we do have 26,000 network transformers installed 

6 here in New York City. That’s kind of an onus to 

7 maintain. We are the single largest user of network 

8 transformers in the United States. I believe Pepco 

9 has between 4500 and 5000, same thing with PSE&G, 

10 and then the numbers go down from there.

11 The transformers that I specify do not 

12 meet all the requirements of IEEE 6740, so that 

13 seems to be discontinuity. And in some cases they 

14 achieve the standard, but we don’t get a primary 

15 switch compartment here at ConEd, that’s kind of 

16 beyond the scope of this presentation anyway. But 

17 certainly I would think that if there was going to 

18 be a separate equipment class for network 

19 transformers that the ones used here in New York

20 City should fall into that category.

21 MR. RABA: Thank you, Kevin. Impressive. 

22 New York, of course. John.

23 MR. CASKEY: I’m not sure if we’ve beat up 

24 this issue enough, but I mean I’m looking at the 

25 slide there, and I’m prepared to give sort of a 
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1 general statement about, you know, that we certainly 

2 -- if you’d like me to do that at this point.

3 MR. CYMBALSKY: Yes, that’s great. I 

4 instructed Jim that we should close that topic down.

5 MR. CASKEY: Okay. So certainly we 

6 appreciate DOE and Navigant and the rest, and LBL, 

7 for all the work that they’ve done on looking at 

8 these new equipment classes. Certainly we support 

9 very strongly -- NEMA -- this is John Caskey from 

10 NEMA -- the idea of breaking out the poles and the 

11 pads. We haven’t come to 100 percent consensus 

12 within NEMA because there are some manufacturers 

13 that produce the poles and pads cores that are, you 

14 know, basically the same, so if the efficiency 

15 between the poles and the pads are the same, for 

16 some of those manufacturers it makes it easier on 

17 the manufacturing process that they can use the same 

18 components as to whether you’re using it as a pole, 

19 or whether you’re using it as a pad. So there are 

20 some benefits there.

21 But beyond that, certainly there are 

22 weight and height restrictions associated with 

23 putting a transformer on a pole, and breaking out 

24 the efficiency standard different from between a 

25 pole and a pad makes some sense and allowing the pad 
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1 efficiency standard to be higher than the pole makes 

2 some common sense from our perspective. 

3 We’ll provide more detailed comments 

before the deadline, which I think is the 26th 4 or 

27th 5 on that issue.

MR. BOLDUC: The 29th 6 .

MR. CASKEY: the 29th 7 . On the issue of 

8 network and vault, we agree with Andrew when he said 

9 that there needs to be some additional work done on 

10 the definition, and we’ll provide some additional 

11 help on that, dealing with wordsmithing, on the 

12 definition of network and vault as well as where it 

13 is submersible -- the terminology submersible fit 

14 into that, because from our perspective not all 

15 vaults are necessarily submersible transformers. 

16 And also we were talking about the 

17 concerns of the vaults. And in my earlier life I 

18 actually worked for Pacific Gas and Electric Company 

19 as well as Virginia Power, and had been in quite a 

20 few vaults, and I think the real driving force is 

21 there, is that it is virtually impossible to modify 

22 the size of the transformer that’s in there. I 

23 mean, you basically have to rip out the side of the 

24 building, or you have to do some major 

25 reconstruction in order to put in a larger vault 
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1 transformer than what’s already there. So I mean 

2 that’s really the driving force in trying to leave 

3 them even though they have increased in 2010, but 

4 leaving that efficiency the same as what it is 

5 relative to 2010.

6 The 200 KVA BIL, we’re still having some 

7 discussions about that. Certainly, as Greg says, 

8 the leaving it at the 200 KV BIL, there’s a very 

9 small market out there to deal with that. 

10 Internally, to NEMA, we’ve talked about whether it 

11 just should be terminology of greater than 95 BIL, 

12 or whether it should be the 150 BIL that Greg has 

13 talked about, so we’re trying to resolve that 

14 internally and look at some of the market shares and 

15 things like that relative to that. But certainly 

16 leaving it at the current 200 KV BIL doesn’t make a 

17 whole lot of sense. So we will work on, you know, 

18 what Greg has recommended dealing with the voltage 

19 definitions and how they apply to the different 

20 BILs.

21 Certainly we’ve reviewed the new TSLs. 

22 We’ll provide some comments on those. 

23 Dealing with the utility pole replacement 

24 costs, you know, that’s a utility issue, so NEMA is 

25 not going to report on that.
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1 And the shipment data, we don’t have the 

2 information as granular as you would like, so we 

3 really won’t be able to provide the information for 

4 that. Hopefully you can get it from other sources, 

5 by working directly with the manufacturers. 

6 So again, we appreciate the opportunity to 

7 participate in this and breaking out some of these 

8 different equipment classes, and we’ll provide 

9 comments on all this stuff. Thank you.

10 MR. BOLDUC: Thank you, John.

11 MR. RABA: Chris, did you want to -- oh, 

12 did you want to say something, Jerry?

13 MR. CORKRAN: Jerry Corkran, Cooper Power. 

14 The DOE had a request that we supply the percentage 

15 pads and poles and the selling prices and all, and 

16 our managers discussed it and decided that was such 

17 confidential information that they didn’t feel like 

18 disclosing that even though it might go to NEMA who 

19 we love very much, of course, but still we’ve got to 

20 keep it within the company. We won’t share that. 

21 But one thing I admire DOE for trying to 

22 get accurate information and would suggest, if we 

23 think back on the -- when I read through the DOE 

24 selection of 30 percent loading for single phase, 

25 and 35 percent for three phase, and I go through 
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1 that, I really would suggest that the DOE go to 

2 Edison Electric, EEI and find out what loading -- I 

3 imagine they could get 100 utility companies to tell 

4 you exactly what their loading is. They’ve got the 

5 metering, they’ve got the -- and that’s such 

6 critical to the calculations of your payback on the 

7 loading, that if that’s incorrect and Wisconsin 

8 Electric sent you a memo where they said 42 percent 

9 for single phase and 55 percent for three phase, and 

10 that’s with 1.2 million customers -- and that’s just 

11 one company, but they’re telling you that your 

12 loading is way off at 30 and 35 percent. And the 30 

13 and 35 percent is like having an A to B factor of 

14 eleven to one. And I’ve never seen a utility -- and 

15 if you think about utilities, they’ve got lots of 

16 computers now, they know what they’re doing, and why 

17 would they put a transformer in that’s only to be 

18 loaded at 30 percent? They know what their loads 

19 are. Thirty years ago they might not have known 

20 what their loads are, but they do now.

21 And so I would request that you go back 

22 and look at those numbers. It would be easy to 

23 change calculations if you find out you don’t have 

24 accurate numbers. I don’t think you do have 

25 accurate numbers. But I request that you take a 
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1 look at it. Get Steve to -- I think Steve could 

2 give you 100 utilities that would give them, 

3 couldn’t you, Steve?

MR. ROSENSTOCK: No. By June 29th 4 , no.

5 MR. RABA: Thank you, Jerry. Should we 

6 proceed on, Chris. Steve, let’s move on.

7 MR. BOLDUC: Those numbers can come in 

past June 29th 8 .

9 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

10 We don’t want to be blamed for DOE missing any 

11 deadlines. No, thank you.

12 MR. BOLDUC: I’ll take the hit for you, 

13 pal. No more comment extensions for you.

14 I’d like to thank you all very much. In 

15 summary, it’s all up there. Your feedback is 

requested by the 29th 16 of June. Thank you.

17 MR. CYMBALSKY: Thanks everybody for 

18 coming, we really appreciate it.

19 MR. RABA: Okay, from our part here, it’s 

20 tradition to distribute evaluation forms. We would 

21 like to hear from you about these proceedings and 

22 how we an improve them. So pass these this way.

23 PARTICIPANT: I thought it went great.

24 MR. RABA: Okay. 

25 (Whereupon, at 12:13 p.m., the meeting in 
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REPORTER'S CERTIFICATE

This is to certify that the attached proceedings 

before:

U.S. DEPARTMENT OF ENERGY

In the Matter of:

PUBLIC MEETING ON ENERGY CONSERVATION STANDARD

SUPPLEMENTARY ANALYSES FOR DISTRIBUTION TRANSFORMERS

Were held as herein appears and that this is the 

original transcript thereof for the file of the 

Department, Commission, Board, Administrative Law 

Judge or the Agency.

Further, I am neither counsel for or related to 

any party to the above proceedings.

Wendy Greene 

 Official Reporter

Dated: June 25, 2012