UNITED STATES OF AMERICA

DEPARTMENT OF ENERGY 

PUBLIC MEETING 

ON 

ENERGY CONSERVATION STANDARD

PRELIMINARY ANALYSIS FOR DISTRIBUTION TRANSFORMERS

U.S. Department of Energy

1000 Independence Avenue, SW

Washington, DC 20585

Room 1E-245

Tuesday

April 5, 2011

Chair:

James Raba
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Facilitator:

Douglas Brookman

Public Solutions

23 Bloomsbury Avenue

Baltimore, MD 21228

Participants Identified: 

Jerry Allen

Metglas, Inc.

440 Allied Drive

Conway, SC 29526

Peter Amos

Warner Power

40 Depot Street 03278

Warner, New Hampshire 

Timothy Ballo

EarthJustice

1625 Massachusetts Avenue

Suite 702

Washington, DC 20036

Robert Berman

Berman Economics

1915 Grand Court

Vienna, VA 22187

David Brender

Copper Development Association, Inc.

260 Madison Avenue

New York, NY 10016

Ned Brush

BBF & Associates

155 Pemaquid Loop

New Harbor, ME 04554

Carl Bush

PEMCO Corporation

PO Box 1319

Bluefield, VA 24605
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Scott Choinski

National Electrical Manufactures Association

1300 North 17th Street

Suite 1752

Rosslyn, VA 22209

Jim Creevy

National Electrical Manufacturers Association

1300 North 17th Street

Suite 1752

Rosslyn, VA 22209

Andrew deLaski

Appliance Standards Awareness Project

20 Belgrade Ave, Suite 1

Boston, MA 02131

Charles Drexler

Kentucky Association of Electric Cooperatives

4515 Bishop Lane

Louisville, KY 40218

Keith Earhart

Manufacturing Systems & Equipment, Inc.

2812 Chamber Drive

Monroe, NC 28110

Gary Fernstrom

Pacific Gas & Electric Company

13055 Parkhurst Dr

Oakland, CA 94619

Paul K. Goethe

Optimized Program Services

11 Bordeaux Place

Olmeted Township, OH 44138

Paul Goldstein

Robert Greeson

Federal Pacific

PO Box 8200

Bristol, VA 24203
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Gerald Hodge

Howard Industries, Inc.

PO Box 1586 

Laurel, MS 39441

Philip Hopkinson

HVolt, Inc.

3704 High Ridge Road

Charlotte, NC 28270

Richard Lyke

AK Steel Corporation

705 Curtis Street

Middletown, OH 45043

John Hurst

HEX TEC, LLC

2812 Chamber Drive

Monroe, NC 28110

Joanna Mauer

Appliance Standards Awareness Project

529 14th St. NW, Suite 600

Washington, DC 20045

Dave Millure

Metglas 

440 Allied Drive

Conway, SC 29526

Thomas Patzner

Schneider Electric

1010 Airpark Carrier Drive

Nashville, TN 37217

Nahid Pempin

Optimized Program Service, LLC

14532 Pearl Road

PO Box 360676

Strongsville, OH 44136

John Phouminh

Pepco Holdings, Inc.

3400 Benning Road, NE

Washington, DC 20019
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Steven Rosenstock

Edison Electric Institute

701 Pennsylvania Avenue NW

Washington, DC 20004

Robin Roy

Natural Resources Defense Council

1200 New York Avenue, NW, Suite 400

Washington, DC 20005

Paul Ryan

Hitachi Metals America, Ltd.

800 Grand Avenue, Suite AG-6

Carlsbad, CA 92008

Mahesh P. Sampat

EMS Consulting

1180 Brookview Drive

Athens, GA 30606

Jerry Schoen

AK Steel Corporation

705 Curtis Street

Middletown, OH 45043

Ronald Stahara

Central Moloney, Inc.

2400 West 6th Avenue

PO Box 6608

Pine Bluff AR 71611

Charlie Stephens

Northwest Energy Efficiency Alliance

421 SW Sixth Avenue, Suite 600

Portland, OR 97204

Alan Traut

Power Partners, Inc.

200 Newton Bridge Road

Athens, GA 30607-1180

Daniel Trombley

American Council for an Energy Efficient Economy

529 14th St. NW, Suite 600
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Washington, DC 20045

John W. Holt

National Rural Electric Cooperative Association

4301 Wilson Boulevard

Arlington, VA 22203

1801 K Street NW, Suite 500

Participants from Navigant Consulting:

Washington, DC 20006

Hisham Araji

Rob Carmichael

Pamela Costello

Mahima Gupta

Brian Coffey

Matthew Hartley

William Kohse

Christopher Lau

Zhimei Luo

1 Cyclotron Road, MS 90-4000

Participants form Lawrence Berkeley National 

Laboratory:

Berkeley, CA 94720

Gregory Rosenquist

Christopher Bolduc

Katie Coughlin

Participants from the U.S. Department of Energy:

James Raba
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Jennifer Tiedeman

Robert van Buskirk

Webinar Operator:

Hoi Yee Lam

Energetics, Inc.

Presenters:

Brian Coffey

Navigant Consulting

Matthew Hartley

Navigant Consulting

Gregory Rosenquist

Lawrence Berkley National Laboratory

Katie Coughlin

Lawrence Berkley National Laboratory
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AGENDA

 ITEM PAGE

Welcome

James Raba 10

Introductions

Douglas Brookman 11

Agenda Review

Douglas Brookman 13

Opening Statements 16

Regulatory History

Brian Coffey 26

Rulemaking Overview 

Brian Coffey 29

Scope of Coverage

Brian Coffey 32

Test Procedure

Brian Coffey 35

Market Assessment 

Brian Coffey 44

Technology Options

Brian Coffey 47

Screening Analysis

Brian Coffey 64

Engineering Analysis

Matthew Hartley 66

Markups for Product Price Determination

Gregory Rosenquist 140
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Energy Use and End-Use Load Characterization

Katie Coughlin 151

Life-Cycle Cost and Payback Period Analysis

Katie Coughlin 180

Shipments and National Impacts Analysis

Gregory Rosenquist 234

Preliminary Manufacturer Impact Analysis

Matthew Hartley 256

NOPR Analyses

Gregory Rosenquist 264

Closing Remarks 277
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2 MR. RABA: Good morning all. Welcome to 

3 the US Department of Energy public meeting on Energy 

4 Conservation Preliminary Analysis for Distribution 

5 Transformers Standards. My name is Jim Raba, I’m 

6 the project manager for distribution transformers, 

7 and today I’d like to welcome each and every one of 

8 you. Today our team of experts will be presenting, 

9 providing, informing and encouraging you -- to you -

10 - and from each one of you, we request your 

11 comments, feedback, data, and information about 

12 distribution transformers.

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

13 So, on behalf of the Department, I think 

14 the best way to do a good rulemaking overall, in the 

15 long run, is to work together. I heard some good 

16 things out there about -- everybody in the real 

17 world -- some good things about distribution 

18 transformers that we’re hoping we can also work 

19 together on this rulemaking. So with that, I would 

20 invite -- back to Doug again -- to go around the 

21 room.

22 MR. BROOKMAN: Right. It’s our tradition 
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1 to have introductions right here at the outset. If 

2 you’d say your name and organization or affiliation, 

3 you can also get used to using these microphones. 

4 For those of you who are seated at the table, you 

5 need to push the button, get the little green LED to 

6 come on, say you name and organizational 

7 affiliation. Let’s start over here.

8 Introductions

9 MR. DREXLER: Charlie Drexler, Kentucky 

10 Association of Electric Coops. 

11 MR. FERNSTROM: I’m Gary Fernstrom, 

12 Retired from and currently a temporary employee of 

13 the Pacific Gas and Electric Company.

14 MR. HODGE: Jerry Hodge from Howard 

15 Industries.

16 MR. PHOUMINH: John Phouminh, Pepco 

17 Holding, Inc.

18 MR. AMOS: Peter Amos, Warner Power, 

19 Warner, New Hampshire.

20 MR. PATZNER: Thomas Patzner, Schneider 

21 Electric.

22 MR. SCHOEN: Jerry Schoen, AK Steel 

23 Corporation.

24 MR. LYKE: Rick Lyke, AK Steel 

25 Corporation.
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1 MR. ALLEN: Jerry Allen, Metglas.

2 MR. RYAN: Paul Ryan, Hitachi Metals 

3 America.

4 MR. ROSENSTOCK: Steve Rosenstock, Edison 

5 Electric Institute.

6 MR. CREEVY: Jim Creevy, National 

7 Electrical Manufacturers Association.

8 MR. BROOKMAN: That did not turn on.

9 MR. BERMAN: Robert Berman, Berman 

10 Economics.

11 MR. BROOKMAN: Thank you.

12 MR. MILLURE: Dave Millure, Metglas.

13 MR. EARHART: Keith Earhart, MSE.

14 MR. HURST: John Hurst, HEX TEC, LLC.

15 MR. STEPHENS: Charlie Stephens, Northwest 

16 Energy Efficiency Alliance.

17 MR. TRAUT: Alan Traut, Power Partners, 

18 Incorporated.

19 MS. TIEDEMAN: Jennifer Tiedeman.

20 MR. BROOKMAN: And this will not be on the 

21 record, but please stand and say your name.

22 MR. COFFEY: Brian Coffey, Navigant.

23 MR. HARTLEY: Matt Hartley, Navigant 

24 Consulting.

25 MR. ROSENQUIST: Greg Rosenquist, Lawrence 
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1 Berkley National Laboratories.

2 MR. ROY: Robin Roy, Natural Resources 

3 Defense Council.

4 MS. MAUER: Joanna Mauer, Appliance 

5 Standards Awareness Project.

6 MR. GOLDSTEIN: Paul Goldstein.

7 MS. PEMPIN: Nahid Pempin.

8 MR. BRENDER: David Brender, Copper 

9 Development Association.

10 MR. BRUSH: Ned Brush, consultant to 

11 Copper Development Association. 

12 MR. RABA: I think that that’s all. We 

13 also have Hoy and also Hisham, right? Okay. 

14 Agenda Review

15 MR. BROOKMAN: All of you received a 

16 packet, I hope, as you registered this morning. It 

17 involves a bunch of PowerPoint slides which the 

18 Department and the Department’s contractors will be 

19 going through during the course of the day. Also 

the Federal Register

23 I’m going to do a very brief agenda 

24 review. That’s on Page 2 of your slide packet. 

25 Immediately following this agenda review, there are 

20 Notice, and the notice of the 

21 public meeting for this distribution transformers 

22 meeting.
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1 a few introductory slides by DOE. There’s an 

2 opportunity for anybody that wishes to do so to make 

3 brief introductory comments, key issues from your 

4 perspective, succinct, brief comments.

5 From there we’re going to go to more 

6 details on the Rulemaking Overview and Scope of 

7 Coverage, the Test Procedure. We’ll take a break 

8 mid-morning, round about ten or 10:15, perhaps as 

9 late as 10:30, and then we’ll move into more details 

10 on Market Technology Assessment and the Screening 

11 Analysis, Engineering Analysis. We’ll take lunch 

12 round about noon today. Everybody’s on their own 

13 for lunch as we get there, we’ll describe the 

14 details concerning lunch.

15 Following lunch or whenever we get there, 

16 Markups for Product Price Determination, followed by 

17 Energy Use and End-Use Load Characterization, Life18 Cycle Cost and Payback Period Analysis, Shipments 

19 and National Impacts Analysis. We’ll take a break 

20 mid-afternoon right about 2:45 or so, and then you 

21 can see the remaining items. A description of 

22 Preliminary Manufacturer Impact Analysis, the NOPR 

23 Analyses, and then an opportunity for closing 

24 remarks.

25 There’s yet another opportunity at the end 
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1 of the day for anybody that wishes to do so, to put 

2 some additional information into the record. This 

3 will be -- there will be a complete transcript of 

4 this meeting today, and so I’d ask for your 

5 consideration, if you would, please speak one at a 

6 time. Please say your name for the record each time 

7 you speak. You don’t need to say your 

8 organizational affiliation unless you’re in the 

9 habit of doing so, but please say your name each 

10 time you speak.

11 I’m going to be queuing people as best I 

12 can to speak. I also wish to encourage follow-on 

13 comments. It’s very useful for the Department 

14 sometimes, to have that back and forth. It enhances 

15 the record. Please be concise, share the air time 

16 today, there’s a lot to be said. There’s a lot to 

17 cover here. You’ll see there are over 100 slides -

18 - 140 some odd slides today to go through. 

19 And if you please keep the focus here. 

20 Please turn your cell phones on silent mode -- I’ll 

21 do that myself, and if you keep the sidebars to a 

22 minimum -- you’ve already gotten used to using the 

23 microphones, those of you that are seated at the 

24 table. Those of you who are not seated at the 

25 table, for comments, I would ask for you to find a 
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1 microphone on the two sides, the two wings of the 

2 tables there. 

3 And then finally, the Department’s tried 

4 to make these meetings accessible to anyone via the 

5 web, so we have web participants that are going to 

6 be following along, and they can see the slides. 

7 We’re also wanting to invite those that are joining 

8 the Department by web to write questions and 

9 comments. We will be trying to answer them 

10 selectively, especially if they haven’t been 

11 answered previously, if they’re not redundant, if 

12 they contribute value to the conversation.

13 One thing I’d say to everybody on the web 

14 and everybody in the room, Jim will say this as 

15 well, the Department really wants to receive your 

16 written comments. In addition to what’s said here 

17 today, please make sure that all your comments end 

18 up in writing and timely to the Department.

19 So I think that that is pretty much what I 

20 intended to cover. Have I forgotten anything major? 

21 So far, so good. Okay. So then let’s go then to 

22 Jim Raba for an overview.

23 Opening Statements

24 MR. RABA: This is in your packet. Well, 

25 again, welcome to today’s public meeting on 
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1 distribution transformers energy conservation 

2 standards. And really, the purpose of our meeting 

3 today is four-fold, in a way, to present, provide, 

4 encourage and inform. That is, to present the 

5 procedural and analytical approaches to evaluating 

6 energy conservation standards for distribution 

7 transformers; provide a forum for public discussion; 

8 and to encourage you to submit data, information, 

9 and written documents for this rulemaking process; 

10 and to inform interested parties; and to facilitate 

11 the rulemaking process. 

12 And to do that, you’ll see in the course 

13 of today’s public meeting, an issue box such as this 

14 one here, where at certain break time, as 

15 appropriate, we’ll invite your comments, data, and 

16 information about the topic at hand and throughout 

17 this presentation, identify specific issues, also 

18 raise for discussion on a slide such as this. And 

19 note that each of these issue boxes have a 

20 corresponding number for the questions in the 

21 technical support document, Chapter 2, as well as 

22 the executive summary. But the idea, there, is 

23 again, to invite your comments, data, information 

24 about distribution transformers. We need to hear 

25 from you in particular.
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1 And in all your correspondence, we’re 

2 looking for your feedback, and in this way, when you 

3 do write to us or communicate, we request that you 

4 would identify the distribution transformers 

5 rulemaking with a docket number, a request for 

6 information number for the record, and you can do 

7 this either by e-mail, postal mail, or hand courier. 

8 And these are the addresses.

9 Please note that the comment period closes 

April 18th 10 . We have a rather constrained time 

11 schedule to this rulemaking. Know this is really 

12 looking to the far end -- the end game, where it’ll 

13 get tighter and tighter at the very end, to meet our 

14 deadlines, but again, working together, as we said, 

15 we look forward to that and we appreciate again, all 

16 of us working together for this particular 

17 rulemaking.

18 So for now, we’ll turn it back over to our 

19 next presenter, and Doug -- any opening statements 

20 or remarks from the persons that are present today.

21 MR. BROOKMAN: Thank you. As reflected in 

22 the agenda, an opportunity for opening remarks here 

23 at the outset. I understand we have a few that are 

24 queued up to speak. Yes, please. Your name.

25 MR. PATZNER: Thomas Patzner. I’m a --
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1 from Schneider Electric, a local manufacturer of 

2 distribution transformers. Our main concern is that 

3 it does not seem like there’s been a timeline 

4 established for the low voltage check, and we’d like 

5 that established as soon as possible, because of the 

6 potential need for capital expenditures. And second 

7 of all, since the low voltage transformers are 

8 actually written into the law, is there any other 

9 processes that are going to occur in the timeline, 

10 because it’s not just part of the rule, it’s 

11 actually part of a law.

12 MR. BROOKMAN: Okay. 

13 MR. PATZNER: So those are the two main 

14 points we’d like to get clarified.

15 MR. BROOKMAN: Certainly, the Department, 

16 if you had a timeline in mind that would not pinch 

17 industry, they would like to see that coming from 

18 you. Yes, Jennifer.

19 MS. TIEDEMAN: Yes, Jennifer Tiedeman. 

20 MR. RABA: Microphone, please.

21 MS. TIEDEMAN: Can you hear me better now? 

22 We are constrained by the statute in terms of the 

23 LVDT by EPACT 05, so there really -- the standards 

24 are out there, so there’s not much we can do.

25 MR. BROOKMAN: Jennifer, is that in the 
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1 technical support document or someplace, what the 

2 constraint as imposed by the statute?

3 MR. RABA: Well, we can have -- I’m 

4 thinking ahead here -- we don’t have a switch the 

5 TSD. Note that we can probably put our web 

6 location. The intended timeline, because for the 

7 statutory requirements to consent for things like 

8 that, we have to meet certain deadlines, and then 

9 there’s an effective date when the rule is final, 

10 and compliance date. So those are pretty much set. 

11 But in the meantime, we can show you maybe along the 

12 way, the steps we’ll go through, with some sense of 

13 a timeline. We know it’s going to vary a little 

14 bit, because of actual reality of the real world and 

15 reviews we have to do here procedurally. So we will 

16 look at getting something up there on the web for 

17 everybody’s benefit, to know what the roadmap is 

18 ahead.

19 MR. BROOKMAN: Okay. Yes.

20 MR. PATZNER: So Jennifer, based on your 

21 comment, for low voltage to change, another law 

22 would have to give you the ability to change it, or?

23 MS. TIEDEMAN: It sounds like it. I’ll 

24 have to look into it and we’ll take it under 

25 consideration.
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1 MR. PATZNER: So it would have to go in 

2 front of Congress again?

3 MS. TIEDEMAN: It might.

4 MR. BROOKMAN: Thank you, Charles -- or 

5 thank you, Thomas. Steve Rosenstock.

6 MR. ROSENSTOCK: It’s not an opening 

7 statement, it’s a follow-on question.

8 MR. BROOKMAN: Yes.

9 MR. ROSENSTOCK: If that’s okay. I don’t 

10 want to interrupt. Since the standard was 

11 established and it’s in a covered product under DOE, 

12 so would it come under DOE regulatory, that it would 

13 not have to -- I thought that once Congress passed 

14 the law and that, that it’s covered by DOE 

15 regulations from now on, that it would be a DOE 

16 regulatory purview, rather than a Congressional, 

17 because it’s a covered product as far as --

18 MR. RABA: As I understand, we’re really 

19 kind of -- this will come up in just a moment here 

20 when Brian Coffey goes over the regulatory history 

21 of this rulemaking, but we’re kind of going back 

22 over it again. It was in the regulations, but we 

23 had it withdrawn by the courts for now for another 

24 look. So for now, we’re operating under current 

25 statute, and then if there’s anything underlying, 
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1 later on, it would have to go before the Congress. 

2 However, for this proceeding and for the future that 

3 we know of, it is a rulemaking under the Department 

4 of Energy’s rules and regulations, and procedures. 

5 So proceed along these lines, as long as we can, 

6 basically.

7 MR. BROOKMAN: Let’s see what the slides 

8 say about the regulatory impacts. Other brief 

9 opening remarks here at the outset. Yes, please --

10 that’s Charlie.

11 MR. DREXLER: Is this where I would read 

12 an opening statement?

13 MR. BROOKMAN: Yes.

14 MR. DREXLER: I guess I don’t need to read 

15 the whole thing.

16 MR. BROOKMAN: Yes, it’d be nice if you 

17 could summarize.

18 MR. DREXLER: Okay. My name is Charlie 

19 Drexler with Kentucky Association of Electric Coops. 

20 We’re going to also submit comments through NEMA, 

21 but I guess our main point, or the main thing I 

22 wanted to put across was that we think that the 

23 single phase in the liquid field distribution 

24 standards are adequate and already achieve --

25 represent the maximum energy savings that is 
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1 economically justified. There’s few types of 

2 equipment that have the efficiency and life and 

3 longevity of distribution transformers, and we think 

4 the regulation is high enough. 

5 The other thing is I think I give a couple 

6 examples in the write-up that cover it -- that shows 

7 that there’s not a whole lot of gain in efficiency 

8 in -- the biggest gain has already been made.

9 MR. BROOKMAN: All right, he’s got to 

10 speak more into the microphone.

11 MR. DREXLER: Also, we feel that -- we’re 

12 a small manufacturer and as a small manufacturer we 

13 would have a higher amount of capital impact as far 

14 as capital investment to meet any increased 

15 efficiency standards as well as a large amount of 

16 drainage capital. We’re also very concerned about 

17 core steel supply, as pointed out in the DOE thing. 

18 And that the rural electric coops are probably 

19 adverse or more hit by the DOE regulations because 

20 they serve, quite often the distribution 

21 transformers have one customer per coop or per 

22 transformer and are 25 percent loaded, so the energy 

23 savings on a transformer situation like that are 

24 quite less, and payback can be quite a bit longer 

25 than normal. That’s all. Thank you.
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1 MR. BROOKMAN: So those written comments 

2 will be helpful to the Department. Additional 

3 comments here at the outset? Yes, Steve Rosenstock.

4 MR. ROSENSTOCK: Steve Rosenstock, Edison 

5 Electric Institute. I just want to thank the 

6 Department for releasing the technical support 

7 document and for having this meeting. I realize 

8 that under the revised procedure that was announced 

9 last November, that information does not have to be 

10 provided to stakeholders until the NOPR stage, so I 

11 just want to thank the Department for providing this 

12 information, having the public meeting, and allowing 

13 us to make comments before the NOPR stage. I think 

14 that will help the Department in its deliberations. 

15 Thank you.

16 MR. BROOKMAN: Thank you. Other comments 

17 here at the outset? Key issues from the perspective 

18 of those seated at the table? Yes. Gary Fernstrom. 

19 MR. FERNSTROM: Gary Fernstrom, Pacific 

20 Gas and Electric Company. As others in the meeting 

21 today, PG&E is a large consumer and user of 

22 distribution transformers. However, PG&E is also

23 directed by the California Public Utilities 

24 Commission and state policy to be concerned about 

25 energy efficiency. And PG&E would very much like to 
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1 see the highest level of cost effective, economic 

2 efficiency built into transformers. This 

3 particularly includes core losses, which are a 

4 significant source of wasted energy in lightly 

5 loaded transformers of all kinds, those in 

6 distribution systems and buildings, namely, low 

7 voltage dry type transformers as well as utility 

8 distribution transformers.

9 MR. BROOKMAN: Thank you. Yes, please. 

10 Your name?

11 MR. HURST: My name is John Hurst and I’m 

12 with HEX TEC, LLC. As I read through these 

13 documents and part of the reason for our presence, I 

14 see that there’s a lot of absence of information, 

15 definitive information, about what you’re referring 

16 to as 120 degrees symmetric cores. And we’re 

17 actually building in pilot production symmetric 

18 cores, so we do have comparative labor costs and 

19 material savings, and we will make sure that that is 

sent to you by the 18th 20 . But I look at this table 

21 and it says increased labor cost, plus 55 percent. 

22 We actually find our labor costs lower than 

23 conventional construction.

24 MR. BROOKMAN: Okay. Thank you and we 

25 will be going through these slides one by one, so 
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1 there’s more opportunity for anybody to comment on 

2 the substance that is in them as we’re going along 

3 during the course of the day. But the Department is 

4 constantly in a search for good data, so they will 

5 certainly welcome that submission. Other brief 

6 introductory remarks before we jump into the 

7 details?

8 Okay, then, let’s proceed. We’re going to 

9 hear next from Brian Coffey.

10 Regulatory History

11 MR. COFFEY: Hi, Brian Coffey, Navigant 

12 Consulting. To the gentleman with the statutory 

13 background question, that was aptly timed because 

14 that’s the first thing I’m going to go into, so 

15 hopefully, we can answer your question and if not, 

16 there will be an opportunity to comment afterwards.

17 Here’s a little bit on the statutory 

18 background of this rulemaking. The Energy Policy 

19 Conservation Act of 1975, or EPCA, established the 

20 energy standards program. EPACT, in 1992, directed 

21 DOE to establish distribution transformers 

22 standards. After that, EPACT 2005 set standards for 

23 low voltage dry type units at the NEMA TP1 2002 

24 level. NEMA TP1 was a voluntary standard, and EPACT 

25 2005 codified that standard into law. 
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1 In 2007, DOE set its own standards for 

2 liquid immersed and medium voltage dry type 

3 transformers. Because EPACT 2005 had established 

4 standards for low voltage dry type, DOE stopped 

5 considering standards for them in the 2007 

6 rulemaking. After publishing that 2007 rule, DOE 

7 was sued by the state of California and some others, 

8 and part of the settlement agreement to that was 

9 that DOE would reexamine its analysis and by October 

10 of this year, publish either a notice proposing new 

11 standards, or a determination that standards 

12 required no amendment. If it does propose standards 

13 in October, DOE must then publish a final rule by 

14 October 1, 2012. So that’s where this rulemaking 

15 comes from.

16 MR. BROOKMAN: Let’s pause. Steve 

17 Rosenstock.

18 MR. ROSENSTOCK: A couple of questions. 

19 The first one, trying to address his question, are 

20 low voltage dry type transformers considered a 

21 covered product that would just from now on be DOE 

22 regulatory process versus Congressional act? I 

23 think that was kind of the crux of his question.

24 MR. BROOKMAN: Jennifer, please, the 

25 microphone.
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1 MR. ROSENSTOCK: And I have a follow-on 

2 question.

3 MS. TIEDEMAN: I do need to review the 

4 statute, but we are going to be considering LVDT --

5 distribution transformers -- amending this standard 

6 here, and we may opt to conduct a separate 

7 rulemaking for that. But again, I need to review.

8 MR. BROOKMAN: At this point, you’re not 

9 certain? Okay. Yes, Steve.

10 MR. ROSENSTOCK: Yes, just a quick one. 

11 And sort of a little with the dry-types, you forgot 

12 to put on the effective dates for the low voltage 

13 dry-types, effective date was January 1, 2007, and 

14 for the liquid filled and medium voltage, the 

15 effective date was January 1, 2010, 13 months ago, 

16 the new standards went into effect. I’m going to 

17 make comments later because technical support 

18 document does not reflect some of that information, 

19 that the standards just were bumped up 

20 significantly, less than 14 months ago. Thank you.

21 MR. BROOKMAN: Okay. Thank you.

22 MR. COFFEY: Before publishing its 2007 

23 standard, DOE published the test procedure for 

24 distribution transformers. That was based on the 

25 1998 version of an industry test procedure, NEMA 
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1 TP2. EISA 2007 requires that DOE amend test 

2 procedures within seven years of their publications. 

3 And so DOE is taking this opportunity now to review 

4 the test procedure and efficiency standards in 

5 parallel.

6 DOE is directed by statute to consider 

7 seven different factors in setting conservation 

8 standards for distribution transformers, and it does 

9 so in 11 specific analyses. Here you can see those 

10 factors and their corresponding analyses. The total 

11 projected energy savings, for example, are 

12 considered in the National Impact Analysis. We will 

13 be discussing each of these in greater detail today.

14 MR. BROOKMAN: So let’s just pause. I 

15 don’t recognize some of you, so I presume some of 

16 you are fairly new to this proceeding. Questions 

17 about what’s been covered so far? Okay. 

18 Rulemaking Overview 

19 MR. COFFEY: There are four main phases of 

20 a rulemaking: framework, preliminary analysis, 

21 Notice of Proposed Rulemaking, and Final Rule. Each 

22 stage includes a Federal Register Notice to place 

23 information in public view. At multiple points in 

24 the process, DOE invites both oral and written 

25 comments on its analysis. Those comments can be in 
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response to not only the Federal Register 

4 Most rulemakings begin with the 

5 publication of a framework document. Because DOE 

6 had published a distribution transformers final rule 

7 so recently, however, it opted to begin with our 

8 current stage, the preliminary analysis, wherein DOE 

9 presents its initial analytical results. Here you 

10 see the different analyses that form the preliminary 

11 analysis, and we’ll explore all of them in greater 

12 detail today.

1 Notice, 

2 but also technical support documentation, and 

3 analytical spreadsheets posted on DOE’s website.

Before October 1st 13 of this year, DOE may 

publish a Federal Register 

22 In the final rule, DOE once again revises 

23 its analysis and incorporates feedback received 

24 during the NOPR stage. Let’s take a look at the 

25 timeline for all these steps. So here you can see 

14 Notice, proposing a 

15 standard called a NOPR, and hold a public meeting, 

16 similar to this one, to receive feedback on that 

17 proposal. I say “may,” because it also has the 

18 option of publishing a determination asserting that 

19 new standards aren’t warranted. Here’s a diagram of 

20 all the NOPR analyses, which include a round of 

21 revisions for preliminary analysis.
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1 all those milestones we just talked about. DOE 

2 published the notice announcing this preliminary 

analysis meeting on the 2nd 3 of this past March. It 

4 will publish, this October, either a notice 

5 proposing new standards, or as I said, a 

6 determination asserting that no standards are 

7 warranted. A final rule, if needed, would be 

8 published in October of 2012 and have a compliance 

9 date of not later than January 1, 2016.

10 Although the compliance date of any 

11 amended standard would have to be no later than 

12 January 1, 2016, DOE may select an earlier one. DOE 

13 welcomes comment on the compliance date, and whether 

14 industry would feasibly be able to meet a date 

15 earlier than January 1, 2016.

16 MR. BROOKMAN: So here you see the 

17 Department’s first comment box, wherein they 

18 actively seek your comment as listed there on the 

19 timeline and the preceding slides. Steve 

20 Rosenstock.

21 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

22 With all other appliances that are covered by the 

23 Department, typically the Department does give three 

24 to five years for manufacturers to comply with 

25 standards, so that would be consistent with past 
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1 regulations.

2 MR. BROOKMAN: Thank you. Yes. Question? 

3 Additional comments?

4 Rulemaking Scope of Coverage

5 MR. COFFEY: So next I’ll talk about 

6 rulemaking scope and the current standards. Here’s 

7 an overview of the scope of this rulemaking, and of 

8 the efficiency standards currently in place. This 

9 may speak a little bit to the question that was 

10 asked earlier.

11 Distribution transformers can be divided 

12 into two categories: liquid immersed, and dry type. 

13 Dry type can be further divided into medium and low 

14 voltage dry type, depending upon input voltage. A 

15 medium voltage can be even further subdivided by 

16 BIL, or basic impulse insulation level.

17 The 2007 final rule set standards for 

18 liquid immersed and all three medium voltage dry 

19 type insulation levels. It didn’t set standards for 

20 low voltage dry type, because standards had been 

21 recently established in the EPACT 2005. So those 

22 are the current standards, and now I’ll talk about 

23 how all those terms are defined.

24 EPACT 2005 presented a definition of 

25 distribution transformer term, which DOE refined 
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1 during the 2006 test procedure rulemaking. 

2 Distribution transformers are defined by input and 

3 output voltage, frequency, and capacity. At the 

4 bottom here, you’ll see several types of 

5 transformers that are not considered distribution 

6 transformers, and therefore, are excluded from 

7 standards. Auto transformers and rectifier 

8 transformers, for example, are both currently 

9 excluded.

10 So here are definitions of the three types 

11 of distribution transformers that I mentioned. 

12 Liquid immersed units come in a huge range of sizes 

13 and are popular with utilities for their slightly 

14 higher efficiencies. Dry types, as I mentioned, are 

15 split into medium and low voltage classes, depending 

16 on whether their input voltage is above 600. Dry 

17 types typically have lower efficiencies, but are 

18 often used indoors or near waterways for their lower 

19 risk of leakage or fire.

20 MR. BROOKMAN: We have a question or a 

21 comment. Please use the microphone, and say your 

22 name for the record, please.

23 MR. BUSH: Carl Bush, PEMCO Corporation. 

24 In that list of exceptions, hadn’t underground 

25 mining transformers also been included in that list?
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1 MR. COFFEY: It had in the previous 

2 rulemaking, although no standards were set for them. 

3 I’m sorry, it was included in the scope of the 

4 rulemaking. It was not included in the list of 

5 exclusions.

6 MR. BUSH: So it should be included in the 

7 list of exclusions?

8 MR. COFFEY: It was not excluded in the 

9 past rulemaking.

10 MR. BUSH: Okay. We thought -- the 

11 industry was under the impression that it was 

12 included -- excluded.

13 MR. COFFEY: It’s sort of a subtlety. It 

14 wasn’t specifically excluded, but no standards were 

15 set for underground mining transformers. If that 

16 makes sense.

17 MR. BUSH: That makes sense. Thank you.

18 MR. BROOKMAN: Okay. Thanks for that. 

19 Other questions on this one? Yes, please.

20 MR. TRAUT: Alan Traut with Power 

21 Partners. In the revision that’s in process right 

22 now, is the area of the definition of the 

23 transformer, or the kVA ranges that are covered up 

24 for revision? Or is that fixed?

25 MR. COFFEY: DOE would welcome any 
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1 feedback you have on the matter.

2 MR. TRAUT: Okay. 

3 MR. BROOKMAN: Okay. There’s going to be 

4 more opportunity for comment on this. Other 

5 comments before we proceed?

6 Test Procedure

7 MR. COFFEY: So now we’ll go into a little 

8 bit more detail on the test procedure and some of 

9 the proposed changes that DOE is considering. 

10 We mentioned that DOE published a test 

11 procedure in April 2006, that was based on NEMA TP2, 

12 and used for all three of our transformer 

13 categories. That test procedure is codified in Part 

14 431 of Title 10 of the CFR. Manufacturers gave 

15 feedback suggesting some changes to the test 

16 procedure, so I’ll talk a little bit about those on 

17 the next slide. 

18 So here’s a change that DOE’s considering. 

19 Some transformers have secondary windings that can 

20 be connected either in series or in parallel. This 

21 is pretty common in small, liquid immersed pole 

22 mounted transformers, for example. The test 

23 procedure stipulates that testing must occur in the 

24 configuration that produces the highest losses, 

25 which is usually with the windings in parallel. The 
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1 efficiency difference between series and parallel 

2 secondary configurations, however, is pretty small, 

3 and most transformers are shipped with their 

4 secondary windings in series. IEEE standards 

5 actually require that the units be shipped with 

6 their windings in series, so currently a 

7 manufacturer has to configure the windings in 

8 parallel, test the unit, and then put them back in 

9 series to ship the transformer. DOE is proposing 

10 now to allow testing at any secondary winding 

11 configuration.

12 Since efficiency as tested in parallel and 

13 efficiency as tested in series usually increase or 

14 decrease together, DOE believes that series testing 

15 could not be used to circumvent standards. 

16 On the fourth bullet here, manufacturers 

17 noted that medium voltage dry type transformers may 

18 have different BIL ratings in different 

19 configurations and questioned which ratings should 

20 be used to assess compliance.

21 In response to these concerns, DOE 

22 proposes to allow testing in any secondary 

23 configuration and at the lowest BIL rating.

24 So here is a request for comment on those 

25 issues. DOE seeks comment on its proposal to amend 
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1 the test procedure to allow compliance testing in 

2 any secondary configuration. Should the proposed 

3 amendment apply to all covered distribution 

4 transformers or just a subset? DOE welcomes 

5 submission of any data that would support a 

6 conclusion. 

7 And the next is that DOE welcomes comment 

8 on its proposal to require compliance at the lowest 

9 BIL at which dual or multiple voltage transformers 

10 are rated to operate.

11 MR. BROOKMAN: Steve Rosenstock.

12 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

13 Nothing about the test procedure, just there does 

14 seem to be a mismatch between the handouts and the 

15 overheads -- just to let you know. There does seem 

16 significant sentences are kind of missing here, so.

17 MR. COFFEY: There were some insertions 

18 after those handouts were printed.

19 MR. BROOKMAN: Okay. So we’ll just leave 

20 that there.

21 MR. COFFEY: But the slide numbers should 

22 line up.

23 MR. BROOKMAN: Jim Raba. 

24 MR. RABA: We did have some editorial 

25 modifications ahead, so as this concludes today, 
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1 within a short period of time, you’ll see the actual 

2 presentation on our website. So what you see today, 

3 you’ll see later on, but for now we’re working from 

4 these as best we can do. Thank you very much for 

5 bringing it up.

6 MR. BROOKMAN: So let’s just see if there 

7 are any comments to respond to the Department’s 

8 inquiry. Your name, please.

9 MR. HOPKINSON: Phil Hopkinson, HVolt, 

10 Inc. The only thing that I would try to raise as an 

11 issue is that in the transformers that are selected 

12 to be designed as dual voltage rating, then in 

13 general, they’re not an even multiple of the series 

14 connection compared to the parallel connection, 

15 which means that already there are unused windings 

16 that will be in the parallel connection. So when 

17 you set the BIL for testing on the lowest BIL 

18 connection, what that really says is that the 

19 efficiency, fundamentally, is higher as a 

20 requirement for transformers that are tested that 

21 way than they are if they were on the higher BIL and 

22 so the dual voltage transformers, in effect, get a 

23 double whammy, because they already have to be 

24 designed bigger, just by the fact that there will be 

25 unused windings. And the second element is that 
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1 when they are tested on the lowest BIL efficiency 

2 requirement, then they have to be more efficient as 

3 well so that dual voltage dry type transformers 

4 tested that way, sound like they are being unduly 

5 required to be more efficient than single voltage 

6 transformers would be.

7 MR. BROOKMAN: Okay. Thank you. Other 

8 comments in response to these issue boxes. Yes, 

9 please. And your name.

10 MR. GREESON: Rob Greeson, Federal Pacific 

11 Transformer. I agree with Mr. Hopkinson’s approach 

12 there. On a reconnectable dry type -- we’re a 

13 manufacturer of dry type transformers -- and if the 

14 efficiency standards should be set at the lowest BIL 

15 rating, because of -- and this is not only for some 

16 of the facts that he stated, but for the fact of air 

17 clearances in dry type transformers -- when you’re 

18 at the higher voltage, operating voltage, you have 

19 to have more air clearances in that transformer, 

20 thus making it larger. So you are unduly 

21 restraining -- you’re making it more difficult to 

22 make those higher efficiencies at lower BIL ratings.

23 The other part of that is, you know, 

24 there’s really not a great deal of these 

25 transformers. We build a few a year, but it just 
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1 seems like it complicates those transformers too 

2 much to try to -- it almost essentially bumps it up 

3 to the next standard level in efficiency for that 30 

4 BIL, because you have so much extra material in the 

5 transformer. It just makes it very difficult to get 

6 the core losses down. And so we support the idea 

7 that on a reconnectable transformer, to just go with 

8 the lowest BIL efficiency rating. I mean highest. 

9 Sorry, got it backwards. Thank you.

10 MR. BROOKMAN: All right, thank you. Yes, 

11 Alan.

12 MR. TRAUT: Alan Traut, Power Partners. I 

13 just wanted to comment on the first issue there, on 

14 the reconnectable secondaries and liquid filled 

15 transformers specifically. Just to differentiate it 

16 from what’s been discussed here, those windings are 

17 almost always exactly two to one, so in both cases, 

18 both the series and the parallel position, both 

windings are fully engaged. The I2 19 R loss is nearly 

20 identical in either connection, and the only 

21 difference in loss is a very subtle difference in 

22 stray loss. So we support this issue and would 

23 recommend that DOE adopt it.

24 MR. BROOKMAN: Thank you. Helpful 

25 comments. Additional comments at this time? Okay. 
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1 MR. COFFEY: To the two gentlemen that had 

2 commented on the first issue -- I’m sorry, the 

3 second issue as it’s laid out on the slide --

4 sounded like you were agreeing with each other, but 

5 maybe disagreeing with DOE’s proposals, so I would 

6 encourage both of you and any other people who might 

7 agree with that, to submit a comment rehashing what 

8 they said, and also proposing what test method might 

9 be appropriate in these cases.

10 In addition to the secondary windings 

11 issue, DOE received comments from manufacturers 

12 suggesting other changes to the test procedure. One 

13 is of whether reconfigurable primaries could also be 

14 tested in their most efficient configuration. 

15 Reconfigurable primaries experience larger 

16 efficiency variation than secondaries, however, and 

17 would still need to be tested in their least 

18 efficient arrangement.

19 Another area of interest is reference 

20 loading points. Currently they are 50 percent for 

21 liquid immersed and medium voltage dry type, and 35 

22 percent for low voltage dry type. DOE welcomes 

23 comments on those items and on any other issues 

24 related to the test procedure.

25 MR. AMOS: Can I just make a comment on 
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1 that. Peter Amos from Warner Power. And I would 

2 like to mention we will follow up after the meeting 

3 with written submissions concerning modified test 

4 procedures which would better capture core 

5 deactivation technologies which currently can’t be 

6 picked up with the present test procedures.

7 MR. BROOKMAN: Thank you. Other -- Gary 

8 Fernstrom.

9 MR. FERNSTROM: Gary Fernstrom. Can I ask 

10 for a clarification. What is a core deactivation 

11 technology?

12 MR. BROOKMAN: Peter?

13 MR. AMOS: One of the speakers from 

14 Pacific Gas and Electric, on my right, mentioned 

15 that they had concerned about the core losses in 

16 distribution transformers, particularly at low power 

17 levels where the efficiency rolls off because the 

18 core losses, of course, are constant, 24/7. And one 

19 of the technologies that we’ve been working on at 

20 Warner Power is the ability to reduce those core 

21 losses at low levels of power consumption. This is 

22 getting more and more important in buildings as 

23 building efficiency measures start to kick in and 

24 possibly looking ahead, the average power 

25 consumption will actually go down in buildings, and 
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1 transformer core losses will start to become more 

2 significant.

3 MR. BROOKMAN: Thank you. Steve 

4 Rosenstock.

5 MR. ROSENSTOCK: May I follow up again for 

6 clarification. Is that a control feature that’s 

7 built into the transformer, or is an add-on type of 

8 component that an owner could --

9 MR. AMOS: Steve, it’s a very simple 

10 thing. As opposed to having one 75 kVA transformer, 

11 we’re using three 25 kVAs, one of which is a base 

12 load unit that runs all the time, and then the other 

13 two are switched in and out on demand, with a 

14 control system.

15 MR. ROSENSTOCK: So it’s a built-in 

16 feature?

17 MR. AMOS: Yes, it’s a built in feature.

18 MR. ROSENSTOCK: Thank you very much.

19 MR. BROOKMAN: Okay. Yes, is it --

20 Thomas.

21 MR. PATZNER: Thomas Patzner. I’d like to 

22 expand on your question. There’s also research 

23 going on to do more than just controlling the 

24 transformer itself, so expect other items where 

25 there would be add-on features to do the same thing 
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1 to control core losses.

2 MR. BROOKMAN: These comments though 

3 relate to how you might modify the test procedure, 

4 correct.

5 MR. PATZNER: I was just answering his 

6 question. There could be add-ons as well.

7 MR. BROOKMAN: So let’s press on then, 

8 okay.

9 MR. COFFEY: And we will touch on the 

10 subject in a little bit. 

11 Market and Technology Assessment and

12 Screening Analysis

13 MR. COFFEY: Well, that brings us to the 

14 Market and Technology Assessment and Screening 

15 Analysis. Here’s an overview of the preliminary 

16 analysis stage that we presented before. You can 

17 see that these two analyses are circled and they’re 

18 the two most upstream components. 

19 Market and Technology Assessment 

20 characterizes the distribution transformer market 

21 and industry, identifies technology options that can 

22 be used to improve efficiency and establishes 

23 equipment classes. The Screening Analysis screens 

24 out technology options that DOE won’t consider in 

25 the engineering analysis, based on four screening 
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1 criteria that we’ll go through in a little bit.

2 So here’s a diagram of all that. You can 

3 see that the Market and Technology Assessment 

4 yields technology options that are considered in the 

5 Screening Analysis. The technology options that 

6 aren’t screened out are renamed design options and 

7 passed on to the engineering analysis for further 

8 consideration. The Market and Technology Assessment 

9 also establishes equipment classes which, unlike the 

10 design options, just feed directly into the 

11 Engineering Analysis.

12 DOE breaks its scope of coverage down into 

13 equipment classes by the type of energy used, 

14 capacity, and any performance-related features that 

15 affect consumer utility or efficiency. Equipment 

16 classes are important because each equipment class 

17 ultimately gets its own standard. There are a large 

18 number of distribution transformer equipment 

19 classes, so DOE placed them into ten groupings, 

20 based on type of insulation, number of phases, 

21 voltage level, and for medium voltage dry type, 

22 basic impulse insulation level, BIL.

23 Here are the details of the ten equipment 

24 class groupings. Simple one and three phase 

25 groupings for liquid immersed and low voltage dry 
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1 type. Medium voltage dry type was further 

2 subdivided by insulation level, just as it was in 

3 the 2007 rulemaking. So there are six medium 

4 voltage dry type groupings instead of two.

5 MR. BROOKMAN: Let’s pause there. Alan.

6 MR. TRAUT: I’d like to make a comment on 

7 the first class there, a single phase liquid filled 

8 transformers. What we’ve experienced in the year9 plus now that these standards have been in effect, 

10 is particularly above 500 kVA, single phase, it 

11 becomes very difficult to manufacture transformers 

12 to meet the efficiency and live within weight and 

13 size constraint that our users can live with. 

14 Looking at the shipment history for those 

15 transformers, I think it’s in one of the tables in 

16 here, there’s a total of five transformers that met 

17 that category. I think the Department and energy 

18 savings would be much further ahead to eliminate 

19 transformers above 500 kVA, but perhaps consider 5 

20 kVA single phase transformers.

21 MR. BROOKMAN: Thank you. Five models?

22 MR. TRAUT: No, instead of a lower limit 

23 of ten kVA, consider a lower limit of five kVA.

24 MR. BROOKMAN: Okay. 

25 MR. COFFEY: So here are the market 
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1 details on equipment class groupings, both by units 

2 shipped and by MVA capacity. DOE used both NEMA 

3 data and conducted its own research to generate 

4 these numbers. DOE uses this information to focus 

5 its attention on the market segments with the 

6 highest volume, and the data is important in both 

7 the national impact analysis and the shipments 

8 analysis. You can see that the single phase liquid 

9 immersed and three phase low voltage dry type have 

10 the highest shipment volumes, for example, and the 

11 single phase medium voltage dry type have the 

12 lowest.

13 Technology Options

14 MR. COFFEY: So now I’ll go into 

15 technology options. Here are the technology options 

16 that can be used to improve efficiency in 

17 distribution transformers. Before I go through 

18 these, I should say that there are two main types of 

19 losses in transformers: core losses and coil losses. 

20 Sometimes you can improve the efficiency of one 

21 without affecting the other by using a lower loss 

22 core or coil material. Those correspond to the 

23 first two technology options listed. The third 

24 technology option is modified geometry, which we’re 

25 using to refer to say, changing the core winding 
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1 cross section, or volts per turn. The general 

2 characteristic of these geometry modifications, in 

3 contrast to materials changes, is that they usually 

4 reduce either core or coil losses, but not both, and 

5 they increase the one that doesn’t get reduced. 

6 Manufacturers try to optimize geometry depending on 

7 materials, prices, and application. 

8 The last two technology options are new 

9 this time around. Symmetric core designs and core 

10 deactivation technology. They weren’t considered in 

11 the 2007 rulemaking, and so we’ll spend a minute 

12 now, discussing them. 

13 So here’s symmetric core designs. They’re 

14 only for three phase applications and different from 

15 conventional three phase transformers, because each 

16 leg is equally spaced from every other. Potential 

17 advantages included reduced weight, volume, losses, 

18 noise, vibration, stray magnetic fields, in rush 

19 current, and harmonics. Some of the concerns with 

20 this technology might be intellectual property, 

21 manufacturability of volume, and the fact that it’s 

22 not well suited for wye connections.

23 So here’s a comment on that. DOE seeks 

24 comment on symmetric core designs, the 

25 practicability to manufacture, and whether they 
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1 offer potential for efficiency improvement. In 

2 particular, DOE seeks comment on applications where 

3 symmetric core may be infeasible. Finally, DOE 

4 seeks comment on concerns related to intellectual 

5 property and manufacturability to scale.

6 MR. BROOKMAN: Steve Rosenstock.

7 MR. ROSENSTOCK: Steve Rosenstock. Yeah. 

8 Is there a concern about this product under a 

9 specific patent by one manufacturer or is that -- is 

10 that the concern?

11 MR. HURST: There shouldn’t be because 

12 there are actually quite a number of 120 degree 

13 symmetric transformers cores out, so there should be 

14 plenty of variance.

15 MR. BROOKMAN: Thank you, John. Yes.

16 MR. HOPKINSON: Brian, I meant to say good 

17 morning to you.

18 MR. COFFEY: Good morning, Phil.

19 MR. HOPKINSON: What I would try to kind 

20 of give a little background on this particular --

21 symmetrical core technology goes back to at least 

22 the 1930s when this concept had been patented back 

23 at that time. So long since patents that 

24 fundamentally relate to the configurations would be 

25 expired. But there may be specific patents with 
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1 different kinds of construction that go using the 

2 fundamental nature.

3 I would, though, point to a couple other 

4 things. I would say first that for utility 

5 transformers, which fundamentally would be liquid 

6 filled transformers, then the wye-wye configuration 

7 is by and far the most common configuration that is 

8 going to be in the industry. So in order to use 

9 this technology, one would need to add a delta 

10 winding to it, which would take away from the 

11 benefits of shared core that would go along with the 

12 use of this technology and cancel the effect of it.

13 In the case of industrial and commercial 

14 transformers, many of those are delta-wye, and so in 

15 that area it could, in fact, have application. But 

16 we also must consider that there is not a whole lot 

17 of volume for industrial transformers less than 300 

18 kVA if they’re going to be medium voltage, bringing 

19 power into a facility. If they are low voltage dry 

20 types, within the facility, those also could be 

21 delta-wye and that would be a possible area where 

22 they could be used, except for the fact that the 

23 configuration certainly would require wound core and 

24 so that would be fundamentally different than stack 

25 core which the industry largely is based on, in the 
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1 low voltage drys. What that would say is that 

2 manufacturers would have a considerable investment 

3 required to change their facilities to use wound 

4 core, and in fact then, to make it into a 

5 configuration that would work here.

6 The other dimension, I would say, is that 

7 when one goes to large wound cores that might affect 

8 kVA sizes beyond 300 kVA, all the way up to the 2500 

9 kVA, then there is -- with wound core there is going 

10 to be large sizes and those cores will tend to buzz, 

11 and they will make an objectionable, audible noise. 

12 So I would say there’s a lot of constraints in the 

13 application that would suggest this technology is 

14 going to have very limited use.

15 MR. HURST: Can I respond to you, Phil?

16 MR. BROOKMAN: Say your name for the 

17 record.

18 MR. HURST: John Hurst. We have actually 

19 been three years looking at that, and unfortunately 

20 since you don’t have direct information you have 

21 some mistakes in what you commented. We will supply 

22 data by the written comment time, but the 

23 construction of a three phase wound core by the 

24 configuration we use is not -- does not induce 

25 additional audible sound. The equipment to produce 
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1 it is significantly less expensive than flat stack 

2 steel equipment for the same size, and the labor 

3 production times are lower. So I think that, 

4 barring other information in the marketplace, I 

5 think we’d invite you to come see.

6 MR. BROOKMAN: So John, that’s the kind of 

7 information that the Department really likes to see, 

8 so your written comments would be very helpful.

9 MR. HURST: Yes.

10 MR. BROOKMAN: I would invite all of you, 

11 please look at slide 35. The Department is asking 

12 for some rather specific comment. We’ve received 

13 some good comment, I want to make sure we cover this 

14 sufficiently on symmetric core design. 

15 Practicability to manufacture, designs are feasible 

16 or infeasible, and technology and feasibility of 

17 manufacturing on large scale. No additional 

18 comment? Okay. 

19 MR. COFFEY: So that was the first new 

20 technology option in this rulemaking, and now I’ll 

21 talk about the second one, which is core 

22 deactivation technology. This technology tries to 

23 reduce core losses by replacing one transformer with 

24 several smaller ones that can be switched on and off 

25 in response to load variation. There’s a control 
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1 unit that decides how many transformers to have in 

2 service at any given time.

3 DOE is only aware of this technology being 

4 used with low voltage dry type transformers, and as 

5 we’ll see on the next slide, core deactivation is 

6 best suited for low root-mean-square loadings.

7 Here’s a sample efficiency versus loading 

8 curve. The red line represents traditional low 

9 voltage dry type transformer whose efficiency rises 

10 sharply, peaks around 35 percent, and gradually 

11 falls with rising load losses. Core deactivation 

12 bank has a more piecemeal curve as its units are 

13 switched on and off. The important take-away here 

14 is that efficiency might exceed that of a 

15 conventional transformer at low loadings, but it 

16 will always do worse at high loads due to the 

17 inherently worse efficiency of the smaller 

18 transformers. That’s all else held equal, of 

19 course.

20 While core deactivation technology could 

21 potentially save energy over certain load cycles, 

22 the current test procedure tests at only one load 

23 point, and wouldn’t reflect those energy savings. 

24 One way of capturing the energy savings for core 

25 deactivation technology, without altering the tested 
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1 efficiency of conventional units, is to use a 

2 weighted average of efficiencies at several load 

3 factors. 

4 Here’s a sample calculation. DOE would, 

5 of course, need more research to determine the 

6 appropriate loading points and their respective 

7 weights to use in a calculation. 

8 DOE did not analyze core deactivation 

9 technology in the preliminary analysis, but does 

10 intend to do so in the NOPR. It will mathematically 

11 scale down conventional transformer designs, group 

12 them into sets, and evaluate the combined cost and 

13 efficiency over several loading arrangements. 

14 One further twist is to use non-identical 

15 component transformers, which could offer the 

16 greatest efficiency, but has the added challenge of 

17 impedance matching.

18 Finally, DOE understands that applying 

19 core deactivation in medium voltage applications may 

20 have some additional challenges related to 

21 switching. I don’t know if this non-identical thing 

22 is obvious to anyone. This is just the thought that 

23 since one of the transformers would be in service 

24 the most often, you’d like to allocate more of your 

25 design resources to that, and less to the one that 
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1 is the first to be switched off.

2 So now we have a comment. DOE seeks 

3 comment on its proposal to use a weighted average 

4 loss calculation to capture the efficiency segments 

5 of core deactivation. And on the technology in 

6 general, DOE requests input on any considerations 

7 necessary for analyzing core deactivation systems of 

8 non-identical transformers on applications where 

9 core deactivation would be useful and how core 

10 deactivation would relate to the current test 

11 procedure.

12 MR. BROOKMAN: Yes, Please. Is it Robert?

13 MR. BERMAN: Just a question. Will DOE be 

14 looking at effects of stress?

15 MR. BROOKMAN: Bob, is the little green 

16 light on?

17 MR. BERMAN: Yeah. Will DOE also be 

18 looking at the potential differences in stress and 

19 wear on the transformer as you’re activating and 

20 deactivating?

21 MR. COFFEY: You mean that if one is used 

22 more often, it could wear more quickly?

23 MR. BERMAN: No, I’m talking about 

24 equipment switched on and off, more often the stress

25 -- there might be additional stress for the 
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1 switching of it on and off.

2 MR. COFFEY: DOE would certainly be 

3 interested in learning about that.

4 MR. BERMAN: Are you -- is DOE considering 

5 any testing on that?

6 MR. COFFEY: We haven’t so far, but if 

7 it’s important and people comment on that, we’d 

8 certainly look into it.

9 MR. BROOKMAN: Steve Rosenstock.

10 MR. ROSENSTOCK: Steve Rosenstock, EEI 

11 again. Just to clarify, you’re only looking at this 

12 for low voltage dry type transformer technologies, 

13 not medium voltage dry type or liquid filled, 

14 correct?

15 MR. COFFEY: At the current time, that’s 

16 correct.

17 MR. ROSENSTOCK: Okay. And again, is it -

18 - again, what is going to be in this October --

19 well, again, it’s a difference in terms of again, 

20 what the time frame to any revision to the test 

21 procedure. That wasn’t me -- it was talked about 

22 you’re going to do it, but again, in terms of timing 

23 of October 2011, October 2012, whether if you are 

24 considering low voltage dry type, this could be a 

25 big issue for manufacturers.
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1 MR. BROOKMAN: Yes. Thomas.

2 MR. PATZNER: Thomas Patzner. I have 

3 basically two questions. Number one, since it’s 

4 basically a bank of transformers, are you going to 

5 redefine the definition to include banks, because 

6 today the definition of transformer says 

7 transformer. Being in that case, all three 25s 

8 would have to be measured at the 35 percent and then 

9 banked together, based on the way I read the current 

10 definition.

11 MR. BROOKMAN: Thank you.

12 MR. PATZNER: And number two. I don’t 

13 understand the need to change it. I see the 

14 benefits of no core losses being turned off, but I 

15 see that as an opportunity for manufacturers to work 

16 with utilities and market to differentiate 

17 themselves. I do not see a need for somebody that’s 

18 using this technology to not have to comply at 35 

19 percent. They would then be able to market to LEED 

20 and other organizations the benefits of the losses.

21 MR. BROOKMAN: Thank you. Gary.

22 MR. FERNSTROM: Gary Fernstrom. This may 

23 be a little off this subject, but as long as we’re 

24 talking about transformer loading, has DOE 

25 considered the impact on losses of increasing non-
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1 linearity and harmonics in building distribution 

2 loads?

3 MR. COFFEY: I think DOE would certainly 

4 be interested in receiving comment on that matter.

5 MR. FERNSTROM: Well, the question was, 

6 has DOE considered that?

7 MR. COFFEY: Not expressly so far.

8 MR. FERNSTROM: Thank you.

9 MR. BROOKMAN: Yes, Peter.

10 MR. AMOS: Peter Amos, Warner Power. Let 

11 me give a little background to this whole 

12 consideration of core deactivation technology. If 

13 you go and dig down in the DOE’s own website, you’ll 

14 find reports and data relating to the average level 

15 of power running through building dry type 

16 distribution transformers. And even though they’re 

17 tested it at 35 percent, the average building 

18 transformer is running at about 25 percent, and the 

19 data isn’t clear on that, but there are some cases 

20 which indicate lower. Certainly if you look at the 

21 ASHRAE reports relative to schools, then the numbers 

22 are lower still.

23 So we have a legacy population, a lot of 

24 transformers out there, running at considerably 

25 below their optimum efficiency point. Then if you 
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1 overlay that with efforts that are going on through 

2 the DOE and other agencies, to improve building 

3 efficiency, which after all is one of the biggest 

4 ways this country can save energy. Buildings use 40 

5 percent of the nation’s energy bill. That 25 

6 percent average load in fact go down in the years to 

7 come, and there’s talk of significant energy savings 

8 in buildings that have been studied.

9 So, you know, if we do nothing about 

10 transformers, we could see building transformers 

11 running at 20 or even 15 percent of their nameplate 

12 rating. That’s way off the sweet spot, and it’s 

13 sliding down the curve, and at that point the 

14 efficiency becomes deplorable. So that is the 

15 reason for this approach.

16 MR. BROOKMAN: Thank you.

17 MR. HURST: Can I go back -- John Hurst. 

18 Could I get an answer? I wonder if you were 

19 referring to making harmonic mitigation transformers 

20 and the impact of that design on core efficiency and 

21 total core weight?

22 MR. BROOKMAN: Gary.

23 MR. FERNSTROM: Gary Fernstrom. I’m not 

24 sure I understand the question. I was simply asking 

25 whether or not, with increasing harmonics in 
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1 buildings, the impact of that had been considered on 

2 energy losses.

3 MR. HURST: Well, we’re on the same 

4 question, just perhaps a different look at it, 

5 because if we build transformers that are well 

6 suited to harmonic mitigation, we may change the 

7 core construction and core content. And I don’t 

8 know whether that’s interactive or be considered as 

9 interactive in the process in particular looking at 

10 low voltage distribution transformers.

11 MR. HURST: I don’t know the answer to the 

12 question either, that’s why I asked.

13 MR. BROOKMAN: Yes, please. Phil.

14 MR. HOPKINSON: Phil Hopkinson, HVolt, 

15 Inc. I took an approach of trying to say, well, 

16 let’s say that we take the exact example that has 

17 been posed, which is a 75 kVA three phase -- I’m 

18 sorry, 75 kVA single phase and three 25 kVA single 

19 phase, and so the very first thing I did was to make 

20 the presumption that they were low voltage dry types 

21 so that the energy efficiency measurement would be 

22 at 35 percent load. And for each of the 

23 transformers then, I wrote the losses down as one 

24 would normally optimize, to what would be core loss 

25 and what would be load loss. 
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1 Then I took the DOE proposed load figures, 

2 which were zero percent load, 15 percent load, 35 

3 percent load, 50 percent load, and 75 percent load. 

4 And then what I did was compute, on an Excel 

5 spreadsheet, the losses that would go if we had a 25 

6 kVA by itself running each of those loads, if we had 

7 two 25 kVAs running each of those loads, if we had 

8 three 25 kVAs running each of those loads, and one 

9 75 kVA as the base running each of those loads.

10 What do you think the answer was? Well, 

11 the answers worked out that at zero percent load, 

12 there was a benefit. At 15 percent load, the 75 kVA 

13 won, and at every higher load the 75 kVA won. So 

14 what I would say from that, if the loading was

15 between zero and 15 percent, there would definitely 

16 be an area where one could in fact potentially have 

17 a benefit. 

18 But I think maybe the right thing would 

19 be, if in fact we have, as Peter proposed, a school 

20 or something that had very low utilization, 

21 especially at night, maybe on a clock you say, 

22 okay, we’re just fundamentally going to turn 

23 everything off except one transformer that feeds 

24 clocks and I don’t know, stuff that is basically 

25 trickle load. And then during the day, we’re just 
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1 going to turn the real transformer on and forget it. 

2 That might be the right way to handle this, 

3 otherwise, you know, it didn’t seem to come out a 

4 winner. 

5 But this is an area that -- it’s not the 

6 first time it’s been posed. When I was working for 

7 one of the major corporations, the same thing had 

8 been posed, so basically I looked at it the same way 

9 the last time, and I’m getting the same answers.

10 MR. BROOKMAN: Thank you. I want to make 

11 sure that we’re trying to be responsive to the 

12 questions that are in these comment boxes, to the 

13 extent possible. And as I read them, they’re really 

14 quite specific. So to deal with the specific 

15 questions that are here, that’ll be very helpful to 

16 the Department. And I want to make sure as we go 

17 along today that we try and stay focused on the 

18 topic at hand, and not provide a more general 

19 seminar.

20 MR. AMOS: I’d just like to make a very 

21 brief comment as response to Phil. I’d like to 

22 share with you some data, Phil, because intuitive, 

23 you think you switch these on one-third and two24 third power, but that’s not the sweet spot. You can 

25 optimize it further than that. We can talk about it 
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1 off-line. 

2 MR. BROOKMAN: Yes, and there’ll be an 

3 opportunity over lunch, for example. Then 

4 additional comments on the specific questions you 

5 see here listed in issue three and six. Okay. 

6 We’re moving on.

7 MR. COFFEY: That wraps up the technology 

8 portion, so now we’re at the screening analysis.

9 MR. BROOKMAN: Maybe we should pause and 

10 take a break right now.

11 MR. COFFEY: That’s all right.

12 MR. BROOKMAN: Want to do that? It’s now 

13 ten minutes after ten. How many of you are not used 

14 to walking around in the Forrestal Building? Okay. 

15 So, you need to wear your badge, visible, when 

16 you’re walking around in the building, and there’s a 

17 coffee shop one floor below us. Either take the 

18 elevators here, or you can go down the stairwell. 

19 One floor below is a Dunkin Donuts. They’re not 

20 very efficient, rather move slowly, so go quickly if 

21 you’re going to get coffee. There are restrooms on 

22 both ends of the hallway, and we’ll resume at 10:25.

23 (Whereupon, the meeting was recessed for a 

24 21 minute period.)

25 MR. BROOKMAN: Let’s start. As a 
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1 housekeeping matter, the Department likes to supply 

2 a list, actually a Xerox copy of all the business 

3 cards of the attendees, and typically when people 

4 register, the Department tries to grab a business 

5 card, and a few of them are missing, and we’d like 

6 to get them to Brenda, who is right over here, so 

7 that they can make those copies. I have five or six 

8 names here -- Chris Bolduc, LBNL, Sampat, ASAP, Greg 

9 Rosenquist, Paul Goethe, Gary Fernstrom, and William 

10 Kohse from Navigant. So if you get a business card 

11 to Brenda, then the Department can provide that 

12 list.

13 So we’re going to then proceed -- we’re 

14 going to continue where we left off, which is slide 

15 41, and we’re back with Brian Coffey.

16 Screening Analysis

17 MR. COFFEY: Okay. So just to remind 

18 everybody, we finished with technology assessment, 

19 and now we’re at the screening analysis. The 

20 purpose of this is to remove the screening options 

21 that DOE won’t consider in the engineering analysis. 

22 DOE evaluates technology options on four criteria: 

23 technological feasibility, practicability to 

24 manufacturer install and service, adverse impacts on 

25 equipment utility or availability to consumers, and 
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1 on any impacts to health and safety. 

2 Here’s a list of the technology options 

3 DOE screened out and the criteria they failed on. 

4 The majority were screened out due to technological 

5 feasibility and having no working prototypes. A 

6 couple of them were screened out on the basis of 

7 practicability to manufacture. Nanotechnology 

8 composites are new to this rulemaking, but the other 

9 six options were also screened out in the 2007 

10 rulemaking. 

11 Comments on screening. DOE knows of no 

12 current commercial efforts or prototype designs that 

13 employ nanotechnology composites in distribution 

14 transformers, but welcomes comments on such 

15 technology and its implications for the future of 

16 the industry. DOE invites comments on the 

17 technology options tentatively eliminated during the 

18 screening analysis. DOE also welcomes comment on 

19 any proprietary concerns relevant to the design 

20 options considered in the analysis.

21 MR. BROOKMAN: Jerry. Comment? Please 

22 say your name for the record. 

23 MR. ALLEN: Jerry Allen from Metglas. I 

24 don’t know how this relates, but there are high 

25 temperature transformers using Nomex and esters, and 
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1 I don’t know that would be an advantage or 

2 disadvantage, but their lines are being sold today, 

3 with high temperature material in them. Nomex wire 

4 insulation and ester fluids.

5 MR. COFFEY: Those actually are materials 

6 that we do consider, and this would sort of refer to 

7 materials not being used in transformers today.

8 MR. BROOKMAN: So elements that have been 

9 screened out are the ones that are listed here. 

10 Yes, please. Is it Dave?

11 MR. MILLURE: Yes, Dave Millure, Metglas. 

12 We concur about amorphous metals in stack core 

13 configuration is technically infeasible. 

14 MR. BROOKMAN: Okay. Thank you. That’s 

15 helpful to get that. And no comments so far on 

16 nanotechnology composites. Anyone wish to weigh in 

17 on that one since it’s a new item? Okay. We’re 

18 going to move on then.

19 MR. COFFEY: Well, this actually concludes 

20 my portion of the presentation, so I’ll invite my 

21 colleague, Matt Hartley up to discuss the 

22 engineering analysis.

23 Engineering Analysis

24 MR. HARTLEY: Hi. My name is Matt 

25 Hartley. I’m with Navigant Consulting, and we are 
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1 going to now discuss the engineering analysis. The 

2 purpose of the engineering analysis is to develop a 

3 relationship between the efficiency of a 

4 distribution transformer and the manufacturer’s 

5 selling price for that unit. DOE uses design 

6 options discussed previously to characterize this 

7 relationship. The cost and efficiency outputs of 

8 the engineering analysis are then used downstream 

9 for the life cycle costs and payback period 

10 analysis, and the national impacts analysis.

11 This slide shows how DOE -- the key steps 

12 that DOE used in the engineering analysis. First, 

13 DOE subdivided its equipment class groupings into 13 

14 design lines with similar design principles, and 

15 identified a representative unit for analysis within 

16 each design line. Then DOE identified different 

17 design option combinations to characterize the range 

18 of possible efficiencies for the rep unit. Next, 

19 DOE developed cost inputs such as materials prices, 

20 markups, and labor requirements. 

21 DOE then used a software model to create 

22 hundreds of optimized designs for each design option 

23 combination, based on different A and B factors, 

24 which I’ll explain in a few minutes.

25 These designs yielded varying levels of 
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1 efficiency, so DOE developed candidate standard 

2 levels, or CSLs, to identify specific levels of 

3 efficiency for the analysis. Finally, DOE scaled 

4 the results from the representative units to the 

5 other unanalyzed kVA ratings and equipment classes. 

6 As a general note, the majority of the 

7 engineering analysis followed the same methodology 

8 as DOE’s 2007 rulemaking. I’ll try to point out any 

9 specific areas where the analysis differs from the 

10 2007 rulemaking, but for those who were involved in 

11 the previous rulemaking, much of this information 

12 will seem familiar.

13 So as we saw previously, each of the ten 

14 equipment class groupings span a range of kVA 

15 ratings. In the engineering analysis, DOE 

16 subdivided these equipment classes into 13 design 

17 lines to group kVA ratings based on similar 

18 principles of design construction, such as core 

19 configuration. Since DOE will ultimately need to 

20 scale to unanalyzed kVA ratings, it selected each 

21 design line to span a range of ratings based --

22 where the 0.75 scaling rule would provide accurate 

23 results. 

24

25 Once the design lines were selected, DOE 
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1 identified a single representative unit for each 

2 design line. DOE bases its engineering analysis on 

3 these representative units. And representative 

4 units selected were chosen based on high volume 

5 ratings within a design line, and also to provide a 

6 good reference point kVA for scaling to the other 

7 unanalyzed ratings within that design line.

8 Again, for those who are familiar with the 

9 2007 rulemaking, these representative units will 

10 look familiar because they are the same ones.

11 So we’ll now take a closer look at the 

12 design lines and representative units selected for 

13 the engineering analysis. So these colorful tables 

14 illustrate how DOE subdivided its equipment class 

15 groupings. The larger tables here represent 

16 equipment class groupings, while each colored 

17 segment represents a different design line. Within 

18 the design lines, a label indicates which kVA rating 

19 was selected as the represented unit. 

20 So you can see for single phase, liquid 

21 immersed units, DOE considered three design lines. 

22 Design lines one and two span the same kVA range, 

23 but examine any potential differences between 

24 rectangular pad-mounted units and round pole mounted 

25 units. And then design line three characterizes the 
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1 set of larger single phase liquid immersed units, 

2 with a representative unit of 500 kVA.

3 Similar tables to these can be found in 

4 Chapter 5 of the TSD, including data for low voltage 

5 dry type and medium voltage dry type units.

6 This table shows additional descriptive 

7 information about the representative units. You’re 

8 looking at the first three design lines, and the 

9 column all the way on the right indicates the 

10 characteristics of the representative unit that DOE 

11 selected for its analysis. So, for example, the 

12 bottom row shows that for its analysis of single 

13 phase, liquid immersed distribution transformers, 

14 between 250 and 833 kVA, DOE analyzed a 500 kVA unit 

15 with a 65 degree temperature rise, operating at 60 

16 hertz, with a 14400 volt primary and a 277 volt 

17 secondary.

18 During its preliminary manufacturer 

19 interviews, DOE heard that the primary voltage of 

20 these single phase units should be changed to 12470 

21 grounded wye / 7200 volt, which has a higher 

22 shipment volume than the selected primary. However, 

23 DOE retained its original primary voltage because 

24 it’s in the same insulation class as the recommended 

25 voltage, but may result in a costlier unit making it 
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1 a more stringent analysis.

2 However, DOE would seek further comment on 

3 the primary voltage used for these first three 

4 design lines, or any other issue pertaining to the 

5 representative units for single phase liquid 

6 immersed units.

7 MR. BROOKMAN: So comments related to that 

8 you see in issue box seven. Yes, Alan.

9 MR. TRAUT: Just a comment on the single 

10 phase liquid immersed units. I would support the 

11 change to the 14400 volt -- because that increase 

12 that you mentioned, as that provides a more 

13 stringent analysis, you could take that to the 

14 extreme and look at 19920 as the extreme in that 

15 case too and realize that all units below that would 

16 be able to meet the standard. 

17 One question I have in the details for 

18 design lines one, two, and three, it’s not clear 

19 that they’re all at the same BIL rating. Design 

20 line one, I could not find a BIL rating. Design 

21 line two is at 125; and design line three was at 150 

22 BIL. I’m not sure if that was intentional or if 

23 it’s just an inconsistency in the analysis. That’s 

24 just a question.

25 MR. HARTLEY: So for liquid immersed 
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1 transformers, DOE does not divide up its equipment 

2 classes by BIL, however, we would welcome comment on 

3 any other suggestions on how to approach that.

4 MR. BROOKMAN: Yes, Please, Alan.

5 MR. TRAUT: Just to follow up on that. 

6 The standard BIL rating for a 14400 liquid immersed 

7 would be 125 BIL.

8 MR. BROOKMAN: In doing so, would you 

9 describe what additional utility would be at having 

10 that rating in there?

11 MR. TRAUT: Well, when you’re doing the 

12 design work, you need to specify the BIL, and as I 

13 said, in the three design lines, they’re not 

14 consistent. So I think at the minimum we would need 

15 to be consistent and establish one BIL rating for 

16 14400 volt for all three design lines to make them 

17 consistent.

18 MR. BROOKMAN: Other comments on liquid 

19 immersed design lines and their representative 

20 units. Yes. Please.

21 MR. HODGE: Jerry Hodge from Howard. I 

22 think we would support the 125 BIL also, because in 

23 general that’s what ANSI is calling for for 14400 

24 volt transformers, so it makes sense to use 125.

25 MR. BROOKMAN: Thank you. It’s helpful 
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1 for the Department to receive affirmative comments 

2 as well, just so you know. 

3 MR. STAHARA: Ron Stahara, Central 

4 Moloney. Just a technical comment on item two. You 

5 have the rating for the 25 kVA pole unit as 240/120, 

6 and the standard is 120/240. It does have a 

7 significant difference.

8 MR. BROOKMAN: Okay. Thank you. Good 

9 clarification. Yes, please Alan.

10 MR. TRAUT: One additional comment on --

11 specifically on design line three. As I mentioned 

12 earlier, I think having standards above 500 kVA does 

13 not really impact energy efficiency use nationally, 

14 and also makes it very difficult and cumbersome for 

15 both users and manufacturers of transformers. So we 

16 would support a top limit of 500 kVA for the 

17 standard, but retain 500 kVA as the design line for 

18 that group. The reason being that size and weight 

19 constraints are very critical, particularly in that 

20 group of transformers. So I would also like to 

21 encourage the Department to look at setting a 

22 maximum weight, and perhaps a maximum tank size or 

23 dimension on those transformers when doing the 

24 analysis.

25 Some of the transformers that came out of 
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1 the analysis were 6000 pounds, and there’s no way 

2 anyone’s going to hang that up on a pole. So we

3 need to put some practical limits, and specifically 

4 on design line three.

5 MR. BROOKMAN: So then your specific 

6 thoughts on what they would be would be helpful.

7 MR. TRAUT: Right. I’ll do that in the 

8 written comments to the Department.

9 MR. PHOUMINH: I have another comment as 

10 well.

11 MR. BROOKMAN: Just one moment. Your name 

12 is?

13 MR. PHOUMINH: John Phouminh.

14 MR. BROOKMAN: Thank you, John. Please.

15 MR. PHOUMINH: On top of the weight and 

16 the sizes, I prefer the height as well, because 

17 it’s, you know, changing out transformer, we don’t 

18 want to change out the building, if possible.

19 MR. BROOKMAN: Okay. Gary Fernstrom.

20 MR. FERNSTROM: Maybe some of the -- this 

21 is Gary Fernstrom. Maybe some of the other 

22 utilities around the table could respond to this. 

23 I’m puzzled by the concern about weight for large 

24 transformers. The ones that I typically see in the 

25 PG&E service territory are pad mount, because of 
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1 underground requirements, and we’re not typically 

2 hanging large distribution transformers on poles. 

3 Is that unique to California and not a practice 

4 across the country?

5 MR. BROOKMAN: Alan, you want to try that 

6 one?

7 MR. TRAUT: Well, there are customers that 

8 hang 500 kVAs on poles.

9 MR. FERNSTROM: Yes, but the question is, 

10 certainly there are and must be, but is that 

11 prevalent, or is it more prevalent to have surface 

12 mounted transformers in that size range?

13 MR. TRAUT: I think for single phase 

14 transformers, it’s probably more prevalent to be 

15 pole mounted.

16 MR. BROOKMAN: I thought your comment, 

17 Alan, went to the technology of the testing and all 

18 that -- your earlier comment.

19 MR. FERNSTROM: We were talking about the 

20 size and weight issues. You’re talking about a 500 

21 kVA single phase transformer?

22 MR. TRAUT: Yes.

23 MR. FERNSTROM: That astonishes me too, 

24 because we rarely see really, really large single 

25 phase units when you start getting up into that 
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1 size, you know, we typically use three phase.

2 MR. BROOKMAN: Alan, go ahead.

3 MR. TRAUT: The volume in those sizes is 

4 very small, however there are utilities that buy 

5 round tank transformers in design line three. 

6 Design line three is a round tank transformer. They 

7 do buy those transformers and hang them on poles. 

8 The IEEE standards cover those transformers up to 

9 500 kVA for pole mounting, and it becomes very 

10 difficult to make a transformer that will hang on a 

11 pole and meet the existing standards, much less 

12 further or more stringent efficiency requirements.

13 MR. FERNSTROM: I can appreciate that. 

14 Maybe we should give some consideration to changing 

15 the design and mounting that type of transformer on 

16 the ground.

17 MR. BROOKMAN: Jerry, you were next in the 

18 queue.

19 MR. HODGE: Yes, we too have --

20 MR. BROOKMAN: Jerry, say your name again.

21 MR. HODGE: Jerry Hodge from Howard 

22 Industries.

23 MR. BROOKMAN: You need to say your name -

24 - Wendy has got to get all this on the record, so 

25 please say your name. Jerry.
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1 MR. HODGE: We too build transformers that 

2 have to be mounted on a pole, and weight and 

3 dimensions are very critical, and it’s something I 

4 think needs to be addressed while we’re making these 

5 rules.

6 MR. BROOKMAN: Okay. Thank you. So for 

7 you, all of you to comment, weigh in with the 

8 specifics, that’s what the Department will need. 

9 Yes.

10 MR. PHOUMINH: John Phouminh. The biggest 

11 size of transformers that will be hanged on pole is 

12 333 kVA. That was on the previous DOE, and before 

13 then as well, TSL2 or NEMA TP1. With the new 

14 standard coming in place, we don’t know what we’re 

15 facing. Given the height, possible the height 

16 extensions, maybe the weight as well, maybe we will 

17 consider reducing it to maybe 167 or 250. We don’t 

18 know. But height is an issue, and weight -- so does 

19 the weight, but height is the most important to us.

20 MR. BROOKMAN: Okay. 

21 MR. STAHARA: Ron Stahara, Central 

22 Moloney. We’re a manufacturer of liquid filled 

23 distribution transformers, and we do face a lot of 

24 limitations for the larger kVAs, both in weight, 

25 height, and many dimensions, round, tall. And 
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1 another issue that we have not addressed, with the 

2 DOE requirements impedance for specific utilities. 

3 The impedance of the transformer becomes an issue as 

4 we get larger for specific utilities. There may be 

5 a standard impedance that we can utilize, but there 

6 are requirements within certain industrial utilities 

7 that we find difficult to meet.

8 MR. BROOKMAN: Okay. Other comments on 

9 this, in this series? Yes, please. Your name for 

10 the record.

11 MR. SAMPAT: Yes, Mahesh Sampat, EMS 

12 Consulting. Specifically for design line two, where 

13 we are looking at 25 kVA transformer, the question I 

14 had was the document says 25 percent of unit will 

15 result in pole change. Can you comment on that, and 

16 does that apply to all units within that -- for all 

17 kVA, or is it just for 25 kVA? It’s not clear.

18 MR. HARTLEY: When you say 25 percent 

19 require pole change, I believe that number would 

20 have come from our consumer impact analysis. I 

21 don’t have the answer to that off the top of my 

22 head.

23 MR. SAMPAT: It seems that number is high, 

24 because typical pole limitation is 1000 pounds, so 

25 like 10, 15, 25 kVA doesn’t reach anywhere near 1000 
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1 pounds, and if you just keep those three kVA, that’s 

2 70 percent of the units right there. So 70 percent 

3 of the units don’t even come into picture. So I 

4 will revisit that question.

5 MR. BROOKMAN: That’s helpful. Thank you. 

6 Yes, please, Robert.

7 MR. BERMAN: Yes, when you do revisit that 

8 question, you may also want to take into 

9 consideration that the pole issue is often, in many 

10 areas, an issue for joint pole association, because 

11 poles do more than simply hang transformers. They 

12 hang all kinds of telecommunications equipment, 

13 sometimes with or without the permission of the 

14 utility, which is a particular problem in some 

15 areas. So to ascribe the cost of a pole to a 

16 efficiency standard and a transformer seems like a 

17 bit of a stretch, given what the reality is for how 

18 poles are bought and considered. So you might want 

19 to look into that.

20 MR. BROOKMAN: Good. Thank you. Other 

21 comments? We’re about to move on to the next 

22 section. Okay. 

23 MR. HARTLEY: Similar to the previous 

24 slide, this slide shows detailed information for two 

25 other representative units that DOE is specifically 
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1 seeking comment on. The representative units for 

2 design lines five and 13. On this slide, DOE would 

3 like to specifically call out the primary voltages 

4 of the representative units, highlighted in red. 

5 For design line five, DOE currently uses a primary 

6 voltage of 24940 grounded wye / 14400 volt delta. 

7 However, during preliminary manufacturer interviews, 

8 some manufacturers recommended that DOE change the 

9 primary voltage to be 12470 delta, because this 

10 voltage has a higher shipment volume and is more 

11 costly than a comparable wye primary.

12 DOE is aware that the grounded wye voltage 

13 connection currently used is more common for 

14 residential distribution transformers, while the 

15 proposed delta primary connection is most common for 

16 industrial distribution transformers. 

17 Now looking at design line 13, DOE heard 

18 that a different primary voltage would be more 

19 appropriate than the 12470 volt primary selected for 

20 this 125 kV BIL unit. Some manufacturers stated 

21 that a 125 kV BIL insulation class should use a 

22 primary voltage of 24940 volts rather than the 

23 voltage currently selected. 

24 So at this time, DOE requests comment on 

25 the appropriate primary voltages to use for these 
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1 two representative units.

2 MR. HURST: John Hurst. In the real 

3 world, dry type medium voltage three phase units, 

4 2000 kVA 12470, 480/277 with a 95 kV BIL is the 

5 workhorse of that market.

6 MR. HARTLEY: So I should point out that 

7 design line 13 is the only representative unit, the 

8 only design line that’s selected to specifically 

9 look at the highest BIL insulation class. So as 

10 Brian mentioned previously, we divide medium voltage 

11 dry type into three BIL groupings, so the BIL 

12 selected of 125 cannot change. That’s part of the 

13 definition of this design line. However, we do 

14 examine other BILs for other design lines, which 

15 aren’t presented here on this slide.

16 MR. BROOKMAN: Please. Your name.

17 MR. GREESON: Robert Greeson, Federal 

18 Pacific Transformer. In the area of the BIL, the 

19 12470, as you pointed out, was predominantly more of 

20 a 95 kV BIL, but given the fact this is specifically 

21 for 96 to 150, we believe that a more appropriate 

22 voltage would be 24900 volts -- or somebody said 

23 24940. When we say 125 kV BIL for a dry type, it’s 

24 usually in the 24-9 range. The maximum usually we 

25 see, for say a 12470 is around 110, but majority are 
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1 60 and 95. So for that design line, though, and 

2 that BIL rating, I think 24940 or 24900 is 

3 appropriate.

4 MR. BROOKMAN: Thank you.

5 MR. HURST: John Hurst again. What drives 

6 the representative unit selection? History or the 

7 marketplace?

8 MR. HARTLEY: So -- as we mentioned, we 

9 divide the equipment class groupings -- we divide 

10 the equipment classes into 13 equipment class 

11 groupings. They’re not all pictured here, but these 

12 are meant to span the entire range of covered 

13 product, and then within those design lines, we 

14 select a single representative unit. So I think 

15 where your comment is coming from, you’re talking 

16 about a 95 kV BIL. DOE does examine a 

17 representative unit at that level. It’s not 

18 presented on this slide here. It wasn’t one that we 

19 were specifically seeking comment on, although it is 

20 outlined in Chapter 5, and for that unit, there is a 

21 corresponding representative unit that we examined. 

22 And we would welcome comment if any of the 

23 specifications for that representative unit should 

24 be changed.

25 MR. BROOKMAN: Other comments on these two 
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1 design lines as described here? Yes, Alan.

2 MR. TRAUT: One final comment on the three 

3 phase liquid immersed. I guess we would support the 

4 use of the 14400 volt 125 BIL coil voltage as the 

5 means of analysis for all liquid filled design 

6 lines. That would also include design line four 

7 which is not listed here.

8 MR. BROOKMAN: Okay. Thank you. Other 

9 comments on this? We’d like to move on. Okay. 

10 MR. HARTLEY: Okay. At this time DOE 

11 requests comment on any other aspects pertaining to 

12 the design lines and representative units selected 

13 for the engineering analysis. So here we went 

14 through a few selected ones. All 13 are outlined in 

15 the technical support document. We’d like to 

16 receive comment on any other design line 

17 representative units.

18 MR. BROOKMAN: Yes, Thomas.

19 MR. PATZNER: Thomas Patzner. For the low 

20 voltage three phase, we would suggest you add a 

21 third design line, and that third design line would 

22 be the 15 kVA, and it’s not really required for the 

23 engineering analysis, but we feel it would be 

24 extremely beneficial in the national impact 

25 analysis, because those products are readily 
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1 available in the marketplace, and excluded. So if 

2 you raise the efficiencies of the 15 kVA, the market 

3 might trend to go to a sealed transformer that is 

4 currently excluded because they’re readily 

5 available. So we believe it would be beneficial to 

6 add the 15 kVAs so that when you do the national 

7 impact, you could do the national impact with a 

8 shift from distribution to sealed, with those 

9 volumes.

10 MR. BROOKMAN: Phil -- if you could --

11 thank you. Then other -- you see the issue box 

12 there. This is the all other comments on this 

13 subject matter box. So additional comments? Okay. 

14 We’re moving on then.

15 MR. HARTLEY: After identifying 

16 representative units for analysis, DOE selected 

17 design options to characterize the range of 

18 efficiencies possible for each of these rep units. 

19 DOE selected these design options from the list of 

20 potential technology options that were not screened 

21 out of the analysis. When selecting design options, 

22 DOE tried to capture the most common designs in the 

23 industry, and also the maximum efficiency level for 

24 each rep unit. 

25 These include various core configurations, 
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1 core steels, and winding materials. A table here 

2 presents the various designs that were considered in 

3 the analysis for each of these options. So as you 

4 can see, DOE considered a large variety of design 

5 types, including wound and stacked cores with and 

6 without mitering, various core steels from M12 all 

7 the way up to SA1 amorphous, and both aluminum and 

8 copper windings. As a note, in this rulemaking, DOE 

9 is considering amorphous cores for all of its dry 

10 type design lines, whereas in the previous 2007 

11 rulemaking, DOE only looked at amorphous core 

12 designs for its liquid immersed design lines.

13 This slide presents an example of the 

14 different design option combinations selected for a 

15 representative unit, and you’re looking at design 

16 line seven, three phase, 75 kVA low voltage dry type 

17 rep unit. In general, these options are presented 

18 in ascending order of efficiency, starting with an 

19 M12 stacked, but lapped core, and aluminum windings, 

20 all the way up to an SA1 amorphous core, using 

21 copper windings as the maximum efficiency level.

22 In the analysis, several design option 

23 combinations using aluminum conductors were not 

24 modeled in time to include in the downstream 

25 analyses, such as design options seven and nine 
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1 here. While these design options are not included 

2 in the current life cycle cost or national impacts 

3 analyses, DOE presents them in the engineering 

4 analysis for comment, and intends to include them in 

5 the NOPR analyses.

6 DOE distinguishes these designs from the 

7 reference case design option combinations and calls 

8 them supplementary design option combinations in 

9 Chapter 5 of the TSD. I should also add that all 

10 design option combinations for each representative 

11 unit are presented in Chapter 5 of the TSD.

12 MR. BROOKMAN: I hesitate to put you in a 

13 mess. Mahesh.

14 MR. SAMPAT: Mahesh Sampat, EMS 

15 Consulting. One of the design options that’s not 

16 considered in low voltage dry is the wound core.

17 MR. HARTLEY: For dry types, we have not 

18 looked at wound core, as we’ve heard and found that 

19 typically the stack core would be most common. 

20 While there are many design options that could be 

21 considered, DOE has to focus in on select ones, but 

22 we do welcome comment on other considerations for 

23 why wound core should be examined specifically.

24 MR. SAMPAT: It just -- it may allow 

25 manufacturer to stay with the conventional material 
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1 but still gain the higher efficiency than the stack 

2 core. So wound core, conventional construction, may 

3 fit between stack and amorphous.

4 MR. BROOKMAN: So those written comments 

5 would be really helpful, because this design option 

6 combination -- that’s important for the Department. 

7 Gary.

8 MR. FERNSTROM: Gary Fernstrom. I’d like 

9 to second that. I think it’s important for DOE in 

10 its analysis to look at all of the opportunities, 

11 particularly what I would characterize as the low 

12 hanging fruit, or -- you know, get the biggest 

13 impact for the dollar spent, and leaving this 

14 particular design out, it is definitely an 

15 oversight.

16 MR. BROOKMAN: Thank you. Andrew deLaski.

17 MR. deLASKI: So I just -- I was trying to 

18 understand the response back from DOE on why it 

19 wasn’t considered in the initial analysis? I 

20 missed what you said, if you could just restate 

21 that?

22 MR. HARTLEY: Sure. Obviously, there are 

23 a multitude of different design option combinations 

24 that could be selected, and DOE has to focus in on 

25 key ones, so what we’ve tried to do is look at the 
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1 ones that we consider to be the most popular in the 

2 industry, and also the ones that can achieve the 

3 highest efficiency level. Specifically here, we 

4 were looking at design option combinations that were 

5 analyzed in the previous rulemaking, and a few 

6 additional combinations of materials. So for the 

7 wound cores, I think that’s a material that if 

8 stakeholders feel would be -- have a significant 

9 impact on the analysis, that’s something DOE’s 

10 interested in hearing.

11 MR. deLASKI: Right. I think the 

12 important thing is to get -- don’t forget that cost 

13 to save energy, not just -- you need the whole 

14 curve, not -- the whole continuum, not just what 

15 people are doing today, and what the best is, but 

16 what’s the continuum look like, and that’s what 

17 we’re trying to show here.

18 And then I had a question about the models 

19 that you starred here, the design options that you 

20 starred. And if you have -- these aluminum --using 

21 aluminum as the both primary and secondary conductor 

22 was something that you included in a subsequent 

23 analysis, so it’s not represented -- just to be 

24 clear -- that did not flow through to the subsequent 

25 levels of this analysis?
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1 MR. HARTLEY: That's correct. In this 

2 case, design seven and nine, which we call 

3 supplementary, were not completed in time to flow 

4 through to the life cycle cost or national impacts. 

5 They’re presented in Chapter 5 for comment, and DOE 

6 does intend to use them moving forward in the 

7 analyses, but they won’t be reflected in any of the 

8 economic results.

9 MR. deLASKI: And do those options tend to 

10 be lower cost options than the other options that 

11 are modeled here?

12 MR. HARTLEY: In general, the aluminum 

13 conductors, compared to the copper conductors, would 

14 be a lower cost, and typically, a slightly lower 

15 efficiency. So they just generate a different space 

16 on our cost efficiency span.

17 MR. deLASKI: Okay. Thank you.

18 MR. BROOKMAN: Mahesh.

19 MR. SAMPAT: I guess before you come up 

20 with the final ruling -- Mahesh Sampat, EMS 

21 Consulting, excuse me. But before you come up with 

22 the final ruling, you will factor in the value of 

23 the supplementary designs, is that correct?

24 MR. HARTLEY: Absolutely. Moving forward 

25 in the analysis, the supplementary designs will be 
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1 folded in to the reference case results.

2 MR. BROOKMAN: Okay. Steve Rosenstock.

3 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

4 Again, to follow on, basically so, you know, our 

5 comment period is in two weeks, but these two 

6 designs won’t be reflected until the NOPR stage, is 

7 that correct? Until the technical support document 

8 is updated for the -- possible either the NOPR or 

9 the determination stage?

10 MR. HARTLEY: They are reflected in 

11 Chapter 5 of the technical support document, 

12 currently. Soon actually we’ll be looking at just 

13 an example of some of the outputs, a couple points 

14 to show that the different designs are considered. 

15 They are included in Chapter 5, so DOE does seek 

16 comment on them. We just wanted to clarify that 

17 they did not flow through to the economic analyses, 

18 so they won’t be reflected in the later analyses.

19 MR. ROSENSTOCK: Thank you.

20 MR. BROOKMAN: I was just flipping back to 

21 the slide eight, where DOE says the comment period 

closes April 18th 22 , is that correct?

23 MR. RABA: Yes.

24 MR. BROOKMAN: So you have -- yes, pardon 

25 me, Jerry.
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1 MR. ALLEN: (off microphone)

2 MR. BROOKMAN: Jerry, pardon me. Will you 

3 turn your microphone on?

4 MR. ALLEN: Okay. When you say full 

5 mitered, do you mean full miters as opposed to step 

6 lap?

7 MR. HARTLEY: Yes. We’re looking at a 

8 full miter core.

9 MR. ALLEN: Because I’m wondering if step 

10 lap should be considered in some of those bigger 

11 units of dry types.

12 MR. BROOKMAN: What would be your logic 

13 for that?

14 MR. ALLEN: Lower core losses.

15 MR. BROOKMAN: Okay. 

16 MR. HURST: John Hurst. I must have been 

17 behind the times here because I thought we were 

18 looking at seven and nine and the examples, and my 

19 question really is, things that are not on this 

20 list, if you get information can it at least be 

21 considered in some kind of sidebar way according to 

22 this? I mean we’re thinking 75 kVA amorphous 

23 symmetrical core transformers.

24 MR. BROOKMAN: John, what are you 

25 suggesting is missing that should be included?
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1 MR. HURST: I think that a -- in the core 

2 configuration, we make -- we make symmetrical wound 

3 core SA1 75 kVA distribution transformers in a cost4 competitive fashion in production with achieving the 

5 same efficiencies using silicon steel.

6 MR. BROOKMAN: As I understand it, one 

7 thing I really like about these slides, if you look 

8 at the chevrons on the left hand side, it

9 illustrates in the stream of analysis that it’s 

10 conducting, what they’re trying to accomplish in 

11 that segment. And so as I understand it, these are 

12 the possible design options, and you’re saying, 

13 John, that what you do falls outside of this 

14 representative range of design options?

15 MR. HURST: Yes.

16 MR. BROOKMAN: Okay. Good. That’s really 

17 fine.

18 MR. HARTLEY: And I’d like to actually 

19 add, DOE did consider a symmetric core sensitivity 

20 analysis which we’ll be discussing in a few slides, 

21 so we actually do look at symmetric cores for design 

22 line seven. We’re distinguishing that from what’s 

23 here which we consider to be a reference case at 

24 this point.

25 MR. BROOKMAN: So additional comments on 
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1 this, especially these two slides here? Okay. 

2 MR. HARTLEY: We may have actually already 

3 covered some of this ground, but DOE would like to 

4 welcome comment on any other design option 

5 combinations selected for the preliminary analysis, 

6 specifically actually, we’re seeking comment on any 

7 design option combinations that would yield an 

8 efficiency between that of the domain refined steels 

9 that were considered and the amorphous steel.

10 MR. BROOKMAN: We’ve covered it? No 

11 additional comment? Okay. 

12 MR. HARTLEY: In the next step of the 

13 engineering analysis, DOE develops cost inputs. A 

14 list of materials prices was determined for a five 

15 year time frame and the total labor hours required 

16 to build each design were determined through 

17 conversations with manufacturers and industry 

18 experts. DOE considered 2010 materials prices for 

19 its reference case analysis, but also looked at high 

20 and low materials price sensitivities based on 2008 

21 and 2006 data, respectively. 

22 Next, DOE calculated markups to use in its 

23 analysis to account for items such as scrap and 

24 handling, factory overhead, and non-production 

25 costs. A fully burdened labor rate was also 
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1 calculated to determine the total labor cost. These 

2 markups are presented on a table on this slide which 

3 shows the markup amount and a brief explanation.

4 For scrap and handling, DOE reduced the 

5 standard 2.5 percent markup to 1.5 percent for 

6 prefabricated amorphous cores. DOE also accounted 

7 for additional scrap when analyzing fully mitered 

8 cores. 

9 For factory overhead, DOE applied a 12.5 

10 percent markup to all designs, including amorphous 

11 designs using a prefabricated core. Additionally, 

12 DOE accounted for shipping costs in the 

13 manufacturer’s cost calculation, because DOE 

14 understands that these costs are typically borne by 

15 the manufacturer and included in their profit markup 

16 calculations.

17 This treatment of shipping costs is 

18 different from what DOE did in the 2007 rulemaking, 

19 where shipping costs are accounted for after the 

20 manufacturer’s profit markup.

21 The remaining markups are explained in 

22 this table, and also in further detail in Chapter 5 

23 of the TSD. 

24 MR. BROOKMAN: Steve Rosenstock.

25 MR. ROSENSTOCK: Steve Rosenstock, Edison 
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1 Electric Institute. Just kind of curious, that 

2 shipping cost, is it -- what fuel price was that set 

3 on?

4 MR. HARTLEY: I don’t know the exact fuel 

5 price off the top of my head. I believe it’s 

6 outlined in Chapter 8 of the TSD.

7 MR. ROSENSTOCK: Because I -- again, Steve 

8 Rosenstock -- I figure it would be directly related 

9 to the cost of probably diesel fuel for commercial, 

10 industrial type transportation, and rather high 

11 these days. Thanks.

12 MR. BROOKMAN: Okay. Mahesh.

13 MR. SAMPAT: I don’t know about the 

14 markup, but if I look at the liquid filled 

15 transformer, and if I look at the final price of the 

16 unit, it’s significantly higher than market price. 

17 Somewhere in the cost rollup, either the material 

18 cost is overstated or the markups are overstated. 

19 The end result is significantly higher than the 

20 market prices.

21 MR. BROOKMAN: As you look at this table, 

22 can you tell where the discrepancy is? Or anybody 

23 else? That’s what DOE’s asking for here. Robert.

24 MR. BERMAN: Yeah, I think one place where 

25 the discrepancy may be is that -- it’s been my 
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1 experience that manufacturers don’t price this way, 

2 necessarily. That they will look at what their 

3 costs are for the unit, and look at what the market 

4 is in terms of competition, and what they’re going 

5 to have to do in order to make a competitive bid. 

6 The factory overhead, the shipping, 

7 anything else that is on top of the cost -- those 

8 are all the same dollars, and to try to account for 

9 those separately and come up with a separate number 

10 for each is going to end up overstating what the 

11 total price or cost is going to be.

12 MR. BROOKMAN: How would you suggest then, 

13 DOE approach this analysis?

14 MR. BERMAN: I think that we need to leave 

15 the markup and the business strategy to the 

16 manufacturer, and focus the analysis only at the 

17 cost level, and stop right at what it costs to 

18 manufacture -- material and labor and so forth, to 

19 assemble the finished unit, and stop there.

20 MR. HARTLEY: I’d just like to clarify. 

21 These markups are used to develop the cost, with the 

22 exception of non-production markup, which includes a 

23 profit factor. There are then subsequent markups to 

24 account for distribution channels, and those will be 

25 covered later on in the presentation.
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1 MR. BROOKMAN: DOE’s trying to figure out 

2 some reasonable way to do this, and so any specific 

3 ideas for how they can get it more accurate would be 

4 most welcome. Andrew deLaski.

5 MR. deLASKI: Well, based on the prior 

6 comment, maybe this belongs later, but I’ll say it 

7 now just to get it on the record, which is that one 

8 approach to get the final cost -- and I know you’re 

9 doing right now, you’re doing the cost to 

10 manufacturer -- would be to go talk to utility 

11 companies, find out what they pay. Go to the 

12 market, you have a market here, readily, utility 

13 companies that have to seek rates to pay for this 

14 equipment from utility commissions, and I would 

15 believe you’d have some success in getting data from 

16 the market. And if you do that, one of the things 

17 you need to do is make sure you go to a range of 

18 utility companies, because I suspect that the 

19 largest companies face different pricing than a 

20 small coop. I think you also need to look at that 

21 range of prices that are paid in the marketplace.

22 MR. BROOKMAN: Jerry.

23 MR. ALLEN: Yeah, one thing I did, I went 

24 out on the internet and looked at public bids in the 

25 utilities. The prices were way lower than your 
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1 final costs. You’re probably up by 1.6, 1.7. And 

2 those bids wouldn’t be the people who would get the 

3 lowest cost anyway, because they’re not the big 

4 utilities.

5 MR. BROOKMAN: So that’s publicly 

6 available on the web?

7 MR. ALLEN: Publicly available on the 

8 internet. I found a lot of them. I don’t know how

9 many of them would be out there if you dig for a few 

10 days, but I got quite a -- five or six examples --

11 price list of a range of kVAs of oil filled anyway, 

12 and I think one dry type.

13 MR. BROOKMAN: Maybe in your written 

14 comments you could say what the sources were?

15 MR. ALLEN: Yeah.

16 MR. BROOKMAN: Okay. Thank you for that. 

17 Steve Rosenstock.

18 MR. ROSENSTOCK: Steve Rosenstock. EEI. 

19 We are going to submit some cost data -- we had 

20 asked the members what their experience had been 

21 over the last few years, so we’re going to have some 

22 -- I’ll just say it’s data based on the information 

23 received from member companies that we will submit 

24 with our comments.

25 MR. BROOKMAN: Okay. Thanks. So 
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1 additional comments, perhaps final? We’re about to 

2 move on here. Okay. 

3 MR. HARTLEY: Okay. I’m actually going to 

4 go to a slide that you won’t have in your deck, so 

5 please follow along with the screen. We’ve actually 

6 already covered much of this ground, but I just want 

7 to open up a few items specifically for comment. 

8 First, DOE is seeking comment on its 

9 decision to use 2010 materials prices in the 

10 reference case scenario, and other years’ materials 

11 prices for its sensitivity analyses, as opposed to 

12 doing a five year average price.

13 Second, I’ll read them out here and then 

14 we can just go through them. DOE is welcoming 

15 comment on its decision to use the same factory 

16 overhead markup for designs that use a prefabricated 

17 amorphous core, as we do for designs where the 

18 manufacturer actually produces the core.

19 And finally, DOE is seeking comment on its 

20 decision to include shipping costs in the 

21 engineering analysis as a component of 

22 manufacturer’s selling price.

23 MR. BROOKMAN: Comments in response to 

24 these comment boxes. Steve Rosenstock.

25 MR. ROSENSTOCK: Steve Rosenstock EEI. In 
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1 terms of issue 13, we agree with that approach. We 

2 think that’s -- you know, there’s been quite the 

3 gyration in commodities prices over the last several 

4 years, so I think this approach is a real approach.

5 MR. BROOKMAN: Yes, Alan.

6 MR. TRAUT: With respect to the material 

7 prices, I mean I agree with the sensitivity analysis 

8 and 2010 is as good as any, although 2011 is proving 

9 to be even higher commodity cost than 2010. Also it 

10 appears that when you look at the individual 

11 categories, for example, copper and aluminum, it 

12 seems to be rather disjointed in perhaps the metal 

13 prices that are underlying those costs are not 

14 equal. For example, I think in some of the cases 

15 the copper wires were too low and the aluminum wires 

16 were too high. It doesn’t appear that they were all 

17 developed with the same base metal cost underlying 

18 them.

19 It would be helpful if the Department 

20 could develop a model for -- specifically for 

21 conductors -- that worked off of published indices, 

22 such as COMEX or LME for those metals, and added 

23 convergent cost to get to the various wire sizes. 

24 That way, we would know that the conductors, both 

25 copper and aluminum, are on the same basis when the 
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1 analysis is done.

2 MR. BROOKMAN: And would you repeat those 

3 published sources are?

4 MR. TRAUT: COMEX, for example, for 

5 copper, and the London Metals Exchange, LME for 

6 aluminum. They’re very typical.

7 MR. BROOKMAN: Okay. 

8 MR. HARTLEY: One thing I would add to 

9 that, what would be useful for us is to know, once 

10 we take those base prices, what sorts of markups and 

11 what ... those markups should be applied to reach a 

12 final price.

13 MR. BROOKMAN: Yes, Andy deLaski.

14 MR. deLASKI: Commenting on the issue 

15 boxes, just to respond to those issues 14 and 15. 

16 In 14 you say that you made a kind of a decision on 

17 how to handle the markup for amorphous core, 

18 basically treating it the same, whether it’s a 

19 prefabricated core or whether the manufacturer is 

20 putting up their own core. And why that decision?

21 MR. HARTLEY: So DOE is using the same 

22 factor of markup on all its designs, and this is 

23 meant to account for factory overhead that would be 

24 plant-wide, and from our experience, what we’ve seen 

25 is that typically an amorphous core production area 
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1 would be a relatively small part of the production 

2 facility, and therefore we thought it would be 

3 appropriate to give it the same markup as the rest 

4 of the production floor, but we do welcome comment 

5 on why that should be different.

6 MR. deLASKI: Okay. And then in the next 

7 issue, again, did you find data in the market that 

8 indicated this is the practice?

9 MR. HARTLEY: From conversations that 

10 we’ve had with several manufacturers, we had 

11 received this comment which is why we actually 

12 changed the handling of shipment costs for this 

13 rulemaking as opposed to how they were treated in 

14 the previous rulemaking. That was not a complete 

15 survey of all manufacturers, which is why we’re 

16 asking for comment on it here.

17 MR. BROOKMAN: Alan.

18 MR. TRAUT: Just one comment on the markup 

19 side, in my experience, the factory overhead is a 

20 markup on labor content rather than materials, and 

21 if it were done in that manner, this question might 

22 go away, because the labor associated with making 

23 the core would not be in there. Also, with 

24 amorphous cores, I think there needs to be something 

25 -- I’m speaking specifically on liquid filled right 
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1 now -- I think there needs to be an additional core 

2 assembly time allowance for amorphous cores. That’s 

3 presently not in the analysis.

4 MR. BROOKMAN: Factory overhead doesn’t 

5 include materials, Alan? 

6 MR. TRAUT: Typically, no.

7 MR. BROOKMAN: Wow. 

8 MR. HURST: John Hurst. I support the 

9 fact that many -- at least I’m more experienced in 

10 the dry type market -- most dry type manufacturers 

11 do burden labor with overhead, and then the other 

12 question, having to do with -- well, I guess I can 

13 address this in comment -- but, I certainly have the 

14 experience to understand extra handling used for 

15 large, fragile, amorphous cores. I made 2500 kVA ... 

16 cores and they were challenging. But I think that 

17 this leaves out construction methods that would make 

18 that not the case, and I think that the hardware 

19 also leaves out construction methods where that’s 

20 not the case. So I will provide information 

21 regarding that in my written comment.

22 MR. BROOKMAN: Thank you. So have we 

23 moved to 16 yet? Let’s move on to the next slide 

24 and cover that.

25 MR. HARTLEY: Okay. Actually, this is the 
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1 item that Mr. Hurst was just referring to, so it’s a 

2 special case. DOE adjusted its estimates for labor 

3 hours and hardware costs for large, dry type 

4 designs, using an amorphous core. Manufacturers and 

5 industry experts informed DOE that large dry type 

6 designs using an amorphous core would require 

7 special handling considerations, because the 

8 amorphous material is very thin and could become 

9 difficult to work with in such a large core. 

10 As a result, DOE increased the labor 

11 requirements for each of these amorphous designs by 

12 ten hours over the other design options within those 

13 rep units. Similarly, DOE heard that large dry type 

14 amorphous designs would require additional bracing 

15 to contain the coil and prevent short-circuit 

16 problems. Industry experts estimated this 

17 incremental bracing as seven percent of the core and 

18 coil weight, which equals about $230 to $330 dollars 

19 per design. 

20 At this time, DOE requests comment on 

21 these additional cost considerations for amorphous 

22 designs in large amorphous design lines, which would 

23 be design lines 10, 12, and 13. DOE also seeks 

24 comment on whether these additional costs should 

25 apply to liquid immersed amorphous design lines that 
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1 are 1500 kVA and greater. 

2 MR. BROOKMAN: So Matt, this is something 

3 of a midpoint representation or something, is that 

4 right?

5 MR. HARTLEY: Which?

6 MR. BROOKMAN: Well, these additional 

7 labor costs and hardware costs. John, your comment 

8 suggested that specialization could diminish these 

9 costs.

10 MR. HURST: Yes.

11 MR. BROOKMAN: I thought I heard you, yes.

12 MR. HURST: I made both kinds, and what 

13 I’m making now has substantially lower costs in 

14 those areas.

15 MR. BROOKMAN: So those comments in 

16 writing to the Department, most helpful.

17 MR. HARTLEY: And just to clarify, that 

18 those designs -- are you saying they’re not using 

19 the distributed gap wound core configuration that we 

20 look at for these amorphous designs? Is it 

21 different?

22 MR. HURST: Well, a distributed gap is not 

23 really a wound core.

24 MR. HARTLEY: I’m sorry, yeah.

25 MR. HURST: But yes, that’s what I’m 
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1 saying.

2 MR. BROOKMAN: Thanks, John. That’s 

3 helpful. Comments on slide 56? Okay. Let’s keep 

4 moving along here.

5 MR. HARTLEY: The next step in the 

6 engineering analysis is to model optimized designs 

7 for each of the design option combinations that were 

8 previously identified. DOE contracted with 

9 Optimized Program Service to model these optimized 

10 designs. For each design option combination, OPS 

11 created designs based on over 500 combinations of 

12 different A and B values. A and B values represent 

13 the present value of future core losses and winding 

14 losses, respectively. And these valuation inputs 

15 are oftentimes used by customers in the industry 

16 when placing an order, and are described in more 

17 detail in Chapter 5 of the TSD. 

18 After running all the A and B combinations 

19 for each design option, and removing any designs 

20 below the minimum efficiency level, DOE was left 

21 with approximately 2500 unique designs for each of 

22 the 13 representative units, not including 

23 additional supplementary designs that we mentioned 

24 previously.

25 For each of these designs, DOE receives 
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1 data on the construction, windings, electrical 

2 analysis, and bill of materials. Using the bill of 

3 materials and the materials prices discussed 

4 previously, DOE is able to determine the materials 

5 cost of each design. DOE then applies the other 

6 cost factors and markups to determine the total 

7 manufacturer’s selling price. 

8 A temperature corrected efficiency is also 

9 determined from OPS’s electrical analysis report. 

10 DOE uses these manufacturer’s selling price and 

11 efficiency pairings for each design as outputs for 

12 the engineering analysis and inputs to its 

13 downstream analyses. A complete listing of all 

14 engineering outputs, including MSP and efficiency is 

15 available on DOE’s distribution transformers 

16 website. 

17 And here we’re showing you a graph that 

18 illustrates the basic outputs of the engineering 

19 analysis, the efficiency and manufacturer’s selling 

20 price of the rep unit. Each of the dots on this 

21 graph corresponds to a unique, optimized design, and 

22 the different colors indicate the various design 

23 option combinations considered for the rep unit. 

24 So for example, in this chart, the pink 

25 dots represent designs that use an amorphous core 
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1 and copper windings. And charts such as these are 

2 available in Chapter 5 of the TSD.

3 Moving along, as Brian mentioned 

4 previously, DOE considered symmetric core designs 

5 for its preliminary analysis, though they were not 

6 considered in DOE’s 2007 rulemaking. DOE’s 

7 symmetric core analysis is presented as a 

8 sensitivity in the preliminary analysis, separate 

9 from the reference case results. DOE was unable to 

10 identify a company that could model this core 

11 configuration, but it was able to gather information 

12 on this core design through manufacturing 

13 interviews, published literature, and by examining a 

14 handful of designs provided by manufacturers.

15 After analyzing the information gained 

16 through these data sources, DOE identified three 

17 design changes that are typical of symmetric core 

18 designs, which are typically that core losses and 

19 core weight are reduced, while labor requirements 

20 are increased. While the data DOE received showed 

21 varying levels of impacts on these three 

22 characteristics, DOE was able to identify ranges of 

23 impacts. Based on these ranges, DOE selected a 

24 median value that it used to make rough adjustments 

25 to these three characteristics in each of its 
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1 traditional core designs, as outlined in this table.

2 DOE understands that these approximations 

3 are simply rough adjustments, but wanted to provide 

4 data for discussion. 

5 The next slide here is requesting comment 

6 on symmetric core designs and specifically the 

7 adjustments that were used to estimate symmetric 

8 core cost efficiency relationships. So I think we 

9 had already heard that, perhaps -- the labor 

10 requirement adjustment should not be increased, but 

11 held constant. At this time, DOE would welcome any 

12 further comments on its analysis of symmetric core 

13 designs.

14 MR. BROOKMAN: Yeah, let’s return to slide 

15 60 on the screen. So let’s get comments on this. 

16 Mahesh, do you want to -- No? John, go ahead. 

17 The adjustments that the Department’s 

18 asking for comment on, as reflected in the bottom of 

19 slide 60, reduced core losses, they call this a 

20 range of impacts. Reduced core losses, 15.5 percent 

21 -- minus 15.5 percent. Reduce the core weight, 

22 minus 17.5 percent; and increase labor costs plus 55 

23 percent.

24 MR. HURST: I guess my retirement plan is 

25 worthless now.
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1 MR. BROOKMAN: So be more specific then.

2 MR. HURST: Comparing 75 kVA three phase 

3 low voltage distribution transformer rated CSL3 or 

4 in that vicinity, our labor time is exactly the same 

5 as one of the major manufacturer’s labor time, and I 

6 can build that same transformer with no additional 

7 labor at 99.2 efficient. I certainly don’t need to 

8 build it there, but -- and my materials are now --

9 that’s comparing to a very, very bad cut core in 

10 terms of the fact that the machine that is cutting 

11 that butt lap core is very old and does a lot of 

12 damage, so there may be people who are further along 

13 in that business, but a major manufacturer is doing 

14 that in the marketplace, and surviving.

15 So our complete core production time is 

16 less than our cutting and stacking. The losses are 

17 lower and the total materials cost is less.

18 MR. BROOKMAN: Thank you, so the specifics 

19 would be very helpful to the Department.

20 MR. HURST: Certainly.

21 MR. AMOS: I would just like to concur 

22 with John.

23 MR. BROOKMAN: Peter, please.

24 MR. AMOS: Yes, Peter Amos. I would just 

25 like to concur with John Hurst and maybe those of us 
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1 who are involved in some of these symmetric cores 

2 have not been as effective in communicating with DOE 

3 as we should, but I think it certainly needs to be 

4 addressed in the written response, because there are 

5 some significant errors here which I think would 

6 create -- essentially the wrong output from this 

7 whole exercise, and I think that would be a real 

8 pity.

9 MR. BROOKMAN: I think some of you are 

10 fairly new to these proceedings. Your data can be 

11 shielded when sent to Navigant -- that’s correct, 

12 right? So that you can disclose whatever your level 

13 of comfort is, knowing that it won’t be seen by 

14 anybody else. Okay, final comments on this segment? 

15 MR. HARTLEY: Okay. Once DOE generated 

16 all its designs in the engineering analysis, it 

17 selected several candidate standard levels, or CSLs, 

18 to analyze various efficiency benchmarks. The CSLs 

19 span the range of distribution transformer 

20 efficiencies for each representative unit, from the 

21 baseline efficiency of the current standard level, 

22 to the maximum technologically feasible efficiency 

23 level. 

24 When selecting CSLs, DOE considered 

25 several criteria. First, DOE selected levels that 
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1 harmonized across its single phase and three phase 

2 rep units. So, for example, DOE considered an 

3 efficiency level of 99.27 percent for design line 

4 one, a 50 kVA single phase unit, and then the same 

5 efficiency for design line four, a 150 kVA three 

6 phase unit. 

7 Second, DOE examined equally spaced 

8 efficiency increments between the baseline 

9 efficiency and the max tech efficiency. 

10 Lastly, DOE considered several benchmark 

11 efficiency levels such as NEMA Premium for low 

12 voltage dry type transformers.

13 These discrete CSLs allowed DOE to analyze 

14 incremental increases in efficiency and serve as the 

15 basis for trial standard levels selected in the 

16 NOPR, which we’ll discuss in just a moment. 

17 So here we’re showing you the same graph 

18 from before, but with the various CSLs superimposed 

19 over the data. Here CSL zero through six 

20 characterize the efficiency increments DOE examined 

21 between the baseline efficiency and the max-tech 

22 efficiency. As you can see, multiple design option 

23 combinations can meet the efficiency levels for CSL 

24 zero through two. However, CSLs three through six 

25 can only be met using an amorphous core design. 
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1 The supporting designs for this chart can 

2 be found in the engineering analysis file as posted 

3 on DOE’s distribution transformers website, and 

4 figures such as this one for all the design lines 

5 can be found in Chapter 5 of the TSD.

6 MR. BROOKMAN: Steve Rosenstock. 

7 MR. ROSENSTOCK: Steve Rosenstock, Edison 

8 Electric Institute. You said something about 

9 equally spaced efficiency increments. Is that 

10 really necessary? I just -- I mean there’s 

11 different increments on different design lines, so I 

12 don’t -- again, it’s a matter of -- it’s minor, but 

13 last time the numbers changed. I know the levels 

14 changed between the preliminary analysis and the 

15 NOPR, so these candidate standard levels can change 

16 as they turn into trial standard levels at a 

17 potential NOPR stage, correct?

18 MR. HARTLEY: That's correct.

19 MR. ROSENSTOCK: And I guess the other 

20 thing is, CSL zero really represents, again from the 

21 last rulemaking, that was trial standard level three 

22 or four for this design line -- this was, in the 

23 last rulemaking again. It’s shown as baseline, and 

24 it’s kind of missing from the technical support 

25 documents, it’s not showing just the baseline is so 
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1 much more improved compared to 2005 or 2007 unit out 

2 there. Again, I can’t remember if it was level 

3 three or level four, this design line that was 

4 eventually chosen for the standard, but that 

5 baseline unit is significantly more efficient than 

6 what’s out there in the marketplace that’s currently 

7 in use today. And I think that is an element that’s 

8 missing from a lot of this analysis.

9 MR. BROOKMAN: Gary Fernstrom.

10 MR. FERNSTROM: That’s sort of, I think, 

11 Steve phrased a philosophical question, is the 

12 purpose of this proceeding to reassess the past 

13 decision, or is it to look at where we are and 

14 evaluate a further improvement?

15 MR. BROOKMAN: Do you have a point of 

16 advocacy?

17 MR. FERNSTROM: Well, I believe the 

18 purpose of the proceeding was to reassess the prior 

19 decision.

20 MR. BROOKMAN: Andrew deLaski.

21 MR. deLASKI: Just a clarification 

22 question. So in your table, or on this scatter 

23 chart, does this scatter plot include the alternate 

24 designs that we discussed earlier?

25 MR. HARTLEY: It does. In Chapter 5 of 
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1 the TSD, we show this chart without the alternative 

2 designs, and then again with the alternative 

3 designs, so you can identify the new ones.

4 MR. deLASKI: Okay. So this information 

5 in the table includes the alternate design?

6 MR. HARTLEY: That's correct. So, for 

7 example, on this one, the red dots, the amorphous, 

8 SA1 amorphous with aluminum conductors, those are a 

9 supplementary design.

10 MR. deLASKI: Okay, but I didn’t -- I did 

11 not see the design option seven, which was H0-DR

12 aluminum-aluminum.

13 MR. HARTLEY: The chart here is design 

14 line one, which is different from the one I 

15 presented earlier.

16 MR. deLASKI: Okay. Thanks for clearing 

17 that up.

18 MR. BROOKMAN: Steve Rosenstock.

19 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

20 think -- I want to thank you for this chart, I think 

21 it’s extremely helpful to show people what you’ve 

22 done with the analysis, and basically my looking 

23 through the technical support document, all the 

24 other charts are in Chapter 5 of the technical 

25 support documents, so for other people, the charts 
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1 are -- I think they’re very helpful, and they’re in 

2 Chapter 5 for people’s reference.

3 MR. HARTLEY: And just to piggyback on 

4 that, there’s also an Excel file, three of them, 

5 posted on DOE’s website, that contains design 

6 information for every single one of these dots. So 

7 if you’re interested in digging to the details, it 

8 is there.

9 MR. BROOKMAN: Phil, yes. Find a 

10 microphone.

11 MR. HOPKINSON: Phil Hopkinson, HVOLT, 

12 Inc. Matt, very nice presentation, but one -- a 

13 couple thoughts that I have. First, I would suggest 

14 that it really is a reassessment of what we looked 

15 at the last time around based on, perhaps, new 

16 economic parameters. So the cost of electric energy 

17 that would power the transformers, the cost of the 

18 materials that goes into the transformers, and maybe 

19 the look at what loadings might be for the 

20 foreseeable future. 

21 In looking at it for a national standard, 

22 we should have something that is doable, with known 

23 technology, and not require an invention, and not 

24 require putting a lot of manufacturers out of 

25 business. So in looking at that, I would just 
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1 encourage the DOE not to get too exuberant to going 

2 into materials that would push that envelope to the 

3 point where manufacturers are crowded out of the 

4 industry that already is under stress.

5 A second parameter I would have is, as I 

6 have looked at the material costs that are in the 

7 base of going forward, I think that -- I applaud the 

8 concept of using 2010 data to the extent that we 

9 have access and know what it is. I have looked at 

10 one piece of data and I’m -- somewhat calibrated --

11 and on that one I question whether, in fact, we 

12 really have the 2010 data. And that really comes 

13 down to copper foil or copper wire. When I see 

14 something that I’m looking at in the newspaper 

15 daily, which is the COMEX price of copper, that 

16 would be copper bullion, and that’s not copper that 

17 has work done to it to make it into foil or make it 

18 into wire. And copper bullion today is in the order 

19 of $4.30 a pound. But the material for the copper 

20 foil in the optimization studies was shown as $4.30 

21 a pound as well. 

22 And when I then talked to a few 

23 manufacturers, I’m hearing numbers more like $6.50 a 

24 pound for the finished foil. So I would say that 

25 the concept of using 2010 data is absolutely great, 
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1 but make sure we really have a good calibration on 

2 that and are using current prices that are reality.

3 MR. BROOKMAN: Thank you. Alan.

4 MR. TRAUT: Just to follow up on Phil’s 

5 comment, and support it actually. That’s what I was 

6 talking about earlier by using a COMEX base metal 

7 cost plus conversion cost to get those materials 

8 into workable conductor arrangements like strip or 

9 wire, the same process.

10 MR. BROOKMAN: Okay. Yes, John.

11 MR. HURST: John Hurst again. The 

12 fabrication cost varies with the diameter of the 

13 wire, and the aluminum small wire is more expensive 

14 fabrication than copper. Some of those things get 

15 fairly complex, don’t they?

16 MR. TRAUT: Yes, I mean you can take it 

17 down to the individual wire size. I think the DOE’s 

18 done a reasonable job of breaking those up into 

19 ranges. For example, I think one is seven to ten 

20 gauge wire, and then wires smaller than that. But, 

21 I mean, I’d be happy to get into those details at 

22 the appropriate time.

23 MR. BROOKMAN: That’d be great, not only 

24 the break points, but how to go from COMEX listing 

25 to the more finished product, that would be helpful 
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1 to them. Thomas.

2 MR. PATZNER: Thomas. To follow up on 

3 Steve’s comment, it would be nice if we could label 

4 CSL zero instead of CSL zero, that it’s the 2005 

5 energy act for the low voltage, it’s 431 for the 

6 medium and the liquid. Because then we’d know that 

7 it went into effect in 2010 or 2007. So if we could 

8 not call it CSL zero, we could call -- you know, 

9 label it exactly what those levels were, where it 

10 was mandated.

11 MR. BROOKMAN: Yes, Joanna.

12 MS. MAUER: Joanna Mauer. In the -- with 

13 the model that was used to come up with these data 

14 points, is it possible to specify an efficiency 

15 level and have the model kind of come up with the 

16 optimum combination of core material, core 

17 configuration, et cetera? Or is this -- or do you 

18 have to specify the design options?

19 MR. HARTLEY: The way that DOE does the 

20 analysis is we specify the design options and then 

21 we provide OPS with a list of over 500 A and B 

22 values, which will then generate a span of different 

23 efficiencies. I don’t know if perhaps OPS could 

24 address the question of whether or not the targeted 

25 efficiency level could be designed.
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1 MR. BROOKMAN: Your name, please.

2

3 MS. PEMPIN: It’s Nahid, OPS. I want to 

4 make sure that I understood your question. You were 

5 mentioning that if our program or software, you 

6 would specify a specific efficiency, and then the 

7 program optimize that efficiency -- is that what the 

8 question was?

9 MS. MAUER: Yes, instead of specifying the 

10 core material --

11 MS. PEMPIN: No, it’s not exactly working 

12 just to the efficiency. The program considers all 

13 the costs. It considers the core, the conductor, 

14 and the kind of strength, the impedance -- they have 

15 the boundary for impedance. It also looks at the --

16 flux density it has the -- what is most commonly 

17 used for specific core material, it will go -- it 

18 will tell the minimum flux density and then the 

19 maximum flux density, and maybe a starter design 

20 with the initial flux density. And then based on 

21 the A and B value, whether the A value’s overcoming 

22 the B, which one is higher, then it decides to 

23 design to the highest flux density or the lower flux 

24 density. And so there’s a lot of different points 

25 that you have to consider, plus the losses. So if 
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1 you take the prices maybe, in such a way that you 

2 just want to meet the efficiency, but it’s not going 

3 to be practical because it’s going to be very 

4 expensive. So you’re not going to be looking only 

5 at the efficiency, you have to look at the costs 

6 also.

7 MS. MAUER: But you couldn’t specify an 

8 efficiency and come up with the lowest cost design 

9 to meet that efficiency level?

10 MS. PEMPIN: In a way, at the end, it will 

11 work out that way, because it will come and say this 

12 is the lowest -- because it has to keep iterate to 

13 get the best out of the material, but if the copper 

14 is more expensive than the aluminum, then it decides 

15 to use prices that are lower than -- at the 

16 comparison. So it goes to the lower pricing because 

17 we know the cost will go down, and then at the end, 

18 it’s sometimes just one design by itself, could be 

19 like 4000 iterations before it comes up with the 

20 solution, and maybe we look at that solution and 

21 then if we want to do changes, maybe, then it would 

22 start over again to make sure that the final 

23 solution is acceptable.

24 MR. BROOKMAN: Would you say your name 

25 again, please?
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1 MS. PEMPIN: Nahid.

2 MR. BROOKMAN: Thank you. Robert, there 

3 was a gentleman in the back that had a comment. 

4 Please find a microphone. Your name, please.

5 MR. LAU: Chris Lau with Navigant 

6 Consulting. Just to follow on those comments. Phil 

7 had expressed concern about some of the higher 

8 efficiency design options impacting manufacturers. 

9 That’s part of the rulemaking process. DOE does 

10 consider impact on manufacturers. It’s one of the 

11 selection criteria, and we’ll cover this in more 

12 detail after the lunch break. However, shortly 

13 after this public meeting, DOE will begin scheduling 

14 manufacturer interviews to get a better 

15 understanding of how these design options will 

16 impact industry. And manufacturers that wish to 

17 participate in those interviews can talk to Matt or 

18 myself, and we will speak with you and schedule 

19 those.

20 To address one of Doug’s earlier comments, 

21 in those manufacturer interviews, it is possible to 

22 place an NDA agreement with Navigant Consulting, and 

23 share confidential information. That will then be 

24 anonymized into industry values and will be used in 

25 the rulemaking, and will not be publicly 
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1 distributed.

2 MR. BROOKMAN: Thank you. Robert.

3 MR. BERMAN: Robert Berman, Berman 

4 Economics. To follow up on the question there and 

5 to clarify my understanding of the optimization 

6 process, a number of utilities that we talked to 

7 will not supply an A and B factor on the order, but 

8 will just give me a transformer of a particular size 

9 that meets DOE standards at the least initial cost, 

10 least fixed cost. Can the model do something 

11 without A and B factors, or do you have to do 

12 something with A and B factors in order to get the 

13 model to optimize?

14 MR. BROOKMAN: Whoever answers, find a 

15 microphone. Your name, please.

16 MR. GOETHE: Paul Goethe, Optimized 

17 Program Service. This optimization routine that we 

18 use has been in the public use for the past 47 

19 years, and over that time we have enhanced many 

20 features to accommodate new materials, new 

21 processes, new means of constructing transformers. 

22 And we work pretty close with many manufacturers 

23 that keep us honest in our results. But the 

24 procedure we’re using for the DOE now is technically 

25 optimizing for cost, and as we do that, we use the A 
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1 and B factors knowing the utilities may not use 

2 those. But they are mechanist to drive our programs 

3 towards higher and higher efficiency, each run. And 

4 so we get the results we want by having a range of 

5 designs with different efficiencies plotted against 

6 their cost. So unfortunately, we don’t optimize 

7 specifically for cost. We’ve had people ask for 

8 that, and some day we might, but presently we 

9 optimize for cost, with that solution influenced by 

10 material cost and the A and B factors that Navigant 

11 has given us to use.

12 MR. BROOKMAN: Okay. Thank you.

13 MR. HARTLEY: And this is Matt Hartley, I 

14 would also just like to add, while we do base the 

15 designs on A and B factors, later on you’ll hear 

16 from Lawrence Berkley National Labs in the life17 cycle cost analysis we look at consumer impacts 

18 where they do consider what they call a consumer 

19 choice model, where some consumers will purchase 

20 based on an A and B decision, and others will 

21 purchase based on a lowest first cost.

22 MR. BROOKMAN: So we’re going to keep 

23 going here.

24 MR. HARTLEY: Okay. Assuming DOE decides 

25 that amended standards are justified, it will select 
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1 trial standard levels, or TSLs, based on various 

2 groupings of CSLs during the NOPR phase of the 

3 rulemaking. For example, DOE may group CSLs based 

4 on per phase harmonization, minimum life cycle 

5 costs, or maximum net present value across various 

6 representative units. These TSLs help DOE to 

7 characterize any interaction between different 

8 design lines or equipment classes. Also, during the 

9 NOPR phase, DOE selects its proposed standard level 

10 from one of these TSLs. 

11 At this time, DOE invites comment on the 

12 criteria it should use as the basis for selecting 

13 TSLs in the NOPR.

14 MR. BROOKMAN: Comments on the criteria 

15 the Department should use as the basis for selection 

16 of TSLs. Steve Rosenstock.

17 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

18 Just remembering from last time, you know there’s a 

19 ton of data in the technical support document, and 

20 then again on the timing, it would be very helpful 

21 to have summary tables of any proposed trial 

22 standard levels and how they relate to the candidate 

23 standard levels, because last time there were 

24 differences and it was rather interesting process to 

25 see where all the new numbers were compared to the 
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1 old numbers, and then how that affected all of the 

2 economic analysis, life cycle cost analysis, energy 

3 analysis, et cetera. So, if there is a way -- if 

4 the decision is that there will be new standards, 

5 and if there are going to be significantly different 

6 TSLs from CSLs, which obviously could happen, 

7 especially if you’re optimizing rather to energy 

8 savings than present value, then please, if at all 

9 possible, provide summary tables, especially in the 

Federal Register 

18 MR. BROOKMAN: Phil.

10 Notice, so that people can see 

11 exactly old versus new and then kind of see where 

12 maybe -- and maybe on some of these charts, show the 

13 old CSLs and maybe the new TSLs so people can see 

14 kind of what’s really going on in terms of the new 

15 values, because they do make a significant 

16 difference in terms of impacts on manufacturers and 

17 customers -- utilities. Thank you.

19 MR. HOPKINSON: Well, let me talk about 

20 life cycle cost minimization. And when a lot of the 

21 manufacturers looked at what was considered the life 

22 cycle cost minimization the last time around, and 

23 for single phase transformers somewhere between TSL 

24 four and five, came out as the answer. When I was 

25 getting feedback, some manufacturers felt at the 
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1 time that the time period used was for a life longer 

2 than for 30 years. I would certainly encourage us 

3 not to use more than 30 years in the face of trying 

4 to determine what the minimum life cycle cost would 

5 be for the transformer. 

6 And of course, energy cost is a huge 

7 piece, so that is the electric -- what is going to 

8 be the cost of electricity? So if we have low cost 

9 electricity, then you don’t end up with as valuable 

10 a benefit from reducing the losses. If we have 

11 extremely high cost electricity, then, in fact, we 

12 can drive much, much further with efficiency. But 

13 it all ought to be economic driven, and it all ought 

14 to be life cycle cost minimization, or when we did 

15 TP1, we set it on a basis of a three to five year 

16 return on incremental investment, based on what we 

17 thought the willingness to pay. But fundamentally, 

18 it’s got to be economics that drives it. Okay. 

19 MR. BROOKMAN: Okay. Thanks. Andrew 

20 deLaski.

21 MR. deLASKI: I think it’s been the 

22 Department’s practice, but I just want to reinforce 

23 that two levels, you know, we certainly want to see 

24 as part of the TSL would be the minimum LCC point 

25 and also the maximum level that’s cost effective, 
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1 which typically would be above the LCC.

2 I also would encourage the Department to 

3 consider a TSL that retained a variety of core 

4 materials as an option, something that’s modeled at 

5 the maximum level that retains a variety of core 

6 materials, and I’ll figure out how to phrase that 

7 more clearly in my written comments.

8 And I think also just to emphasize that of 

9 late the Department has tended to include a pretty 

10 wide range of TSLs, and I think that’s a good 

11 practice and would urge the Department to continue 

12 to have a wide range of TSLs for consideration.

13 MR. BROOKMAN: Robert.

14 MR. BERMAN: Robert Berman, Berman 

15 Economics. I’d like to follow up on that also with 

16 a suggestion that we should keep in mind that what 

17 this is is an energy savings pro --

18 MR. BROOKMAN: I’m sorry, closer to the 

19 microphone.

20 MR. BERMAN: We should keep in mind that 

21 what this is is standards are all about is energy 

22 savings, in particular savings of kilowatt hours, so 

23 what -- one of the things we might want to look at, 

24 once we develop our savings estimates, is what’s the 

25 cost per kilowatt hour saved, and how does that 
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1 compare with the other energy savings programs.

2 MR. BROOKMAN: Okay. Yes, Jerry.

3 MR. SCHOEN: Jerry Schoen, AK Steel 

4 Corporation. One of the concerns I have of working 

5 for industrial company is, you have an existing 

6 fleet out there, transformers that in some extent is 

7 a resource, and those resources can be refurbished 

8 and put back into service. You have to keep an eye 

9 on what is the cost of refurbishing distribution 

10 transformers because today it’s not commonly done. 

11 But if distribution transformers get to be an 

12 extremely expensive item, utilities can very easily 

13 put back what they used to do, which was have 

14 essentially an in-house shop to take transformers 

15 out of service and refurbish them. Often the 

16 insulation is the aspect that needs to be replaced. 

17 The core is fine, it’ll last 30 years, 100 years, as 

18 long as it’s kept in, you know, not shorted out or 

19 corroded. But that needs to be, I think, a concern, 

20 that if you impose a very high economic cost for new 

21 equipment on utilities, they’ll look at their 

22 existing inventory and figure out how to essentially 

23 patch it up for another 20 years.

24 MR. BROOKMAN: Okay. Thank you. Paul, do 

25 you have a comment? No? Okay. Joanna.
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1 MS. MAUER: Joanna Mauer. Just two quick 

2 clarification questions regarding the TSLs in the 

3 preliminary TSD. For the equipment classes that 

4 only encompass one design line, do the TSL numbers 

5 correspond to the same CSL numbers? In other words, 

6 does TSL3 correspond to CSL3?

7 MR. HARTLEY: They don’t necessarily have 

8 to. To the extent, possible, DOE might maintain 

9 that, but a TSL is typically a grouping of different 

10 CSLs and sometimes that will align with the same CSL 

11 number, but other times, certain TSLs might be 

12 composed of three different equipment class 

13 groupings, where one out of those three would not 

14 match the number.

15 MR. BROOKMAN: Yes, Mahesh.

16 MR. SAMPAT: Mahesh Sampat. I guess to 

17 follow up on Jerry’s comment. If the transformer is 

18 refurbished by an outside entity, then they have to 

19 comply with the new regulation. So --

20 MR. BROOKMAN: Jerry, go ahead.

21 MR. SAMPAT: If the utilities themselves 

22 repair it, then it’s not, but if it’s done by 

23 another company, it’s just like buying another 

24 transformer.

25 MR. BROOKMAN: Jerry’s next, go ahead.
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1 MR. SCHOEN: Jerry Schoen. As we 

2 understood it, if the transformer changes 

3 possession, which is legal possession, but a 

4 transformer could be taken out of service by a 

5 utility, shipped to a subcontractor to have it 

6 refurbished, without changing ownership, it would 

7 still be the possession of the utility. It’s done 

8 all the time, and it’s a very common practice in 

9 heavy industry today. We do it at our firm as well.

10 MR. BROOKMAN: At which point that 

11 refurbished transformer would not need to meet the 

12 new standard?

13 MR. SCHOEN: As we understand it, yes, 

14 that’s true.

15 MR. BROOKMAN: Steve Rosenstock.

16 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

17 was just going to give an analogy to another 

18 appliance, like a refrigerator. A 20-year-old 

19 refrigerator that’s repaired does not have to meet 

20 the new standards, whether it’s done by the 

21 homeowner or by a repair shop. You know, they need 

22 to put in new gaskets or new insulation, or even a 

23 new compressor, that refrigerator is not required to 

24 meet the new energy efficiency standards.

25 MR. BROOKMAN: Mahesh.
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1 MR. SAMPAT: Yes, Mahesh Sampat again. My 

2 understanding was if the ownership changes, then it 

3 has to comply. If it’s subcontract, then I agree, 

4 it does not have to. And that fits with the 

5 representative analogy. Ownership doesn’t change.

6 MR. BROOKMAN: Okay. We’re going to move 

7 on to our next set of slides.

8 MR. HARTLEY: Okay. We’re on our last 

9 point here, and I’ll try to move quickly for the 

10 sake of everyone getting lunch. The final step in 

11 the engineering analysis is to scale the efficiency 

12 levels of the representative units to the other 

13 unanalyzed kVA ratings. Similar to the 2007 

14 rulemaking, DOE did not directly analyze single 

15 phase medium voltage dry type units because of their 

16 low shipment volume and MVA capacity shipped, as 

17 Brian discussed previously.

18 Rather, DOE scaled to these equipment 

19 classes by dividing the kVA rating of the three 

20 phase medium voltage dry type units by three, so as 

21 to maintain the per phase kVA amount. The table on 

22 this slide shows the kVA rating for each three phase 

23 representative unit that was directly analyzed for 

24 the medium voltage dry type design lines, and the 

25 corresponding scaled kVA rating for the single phase 
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1 medium voltage dry type design lines.

2 Aside from scaling to the single phase 

3 medium voltage dry type design lines, DOE also 

4 scaled to each kVA rating that was not directly 

5 analyzed by a representative unit. To do this 

6 scaling, DOE relied on the 0.75 scaling rule, which 

7 states that total transformer losses scale by the 

8 ratio of kVA sizes raised to the 0.75 power, when 

9 design characteristics, such as frequency, and basic 

10 impulse insulation level ratings are maintained 

11 constant. By holding certain parameters constant, 

12 DOE can use the 0.75 scaling rule to scale losses, 

13 dimensions, and costs from its analyzed rep units to 

14 the unanalyzed kVA ratings.

15 So for example, consider design line 

16 seven, a three phase, low voltage dry type design 

17 line that spans kVAs from 15 to 150. DOE analyzed a 

18 representative unit at 75 kVA for this design line. 

19 The corresponding efficiencies for the remaining kVA 

20 ratings within design line seven can be determined 

21 using the 0.75 scaling rule. This approach is 

22 similar to what was done in DOE’s 2007 rulemaking, 

23 and further detail on the 0.75 scaling rule can be 

24 found in Appendix 5B of the TSD.

25 During preliminary manufacturer 
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1 interviews, some manufacturers indicated that the 

2 scaled results from the 2007 rulemaking made it 

3 difficult to manufacture compliant transformers for 

4 certain kVA ranges.

5 DOE welcomes comment on the accuracy of 

6 the 0.75 scaling rule, and whether an improved 

7 scaling methodology exists. DOE also seeks comment 

8 on the extent of the impact that the previous scaled 

9 standard levels have had on certain kVA ranges, and 

10 any considerations that DOE should account for in 

11 this analysis.

12 MR. BROOKMAN: As a process note, very 

13 shortly we’re going to go to lunch, for those of you 

14 that are getting antsy, so let’s respond to this 

15 issue box here about the 0.75 scaling rule, and 

16 other potential methodologies. Steve Rosenstock.

17 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

18 Just as a follow up, this equation says, again, 

19 total losses. That’s core and coil losses that 

20 you’re modeling for these different design lines, is 

21 that -- is that correct?

22 MR. HARTLEY: Yes.

23 MR. ROSENSTOCK: And so the next part is, 

24 are you then transferring that into costs, using 

25 that same scaling factor?
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1 MR. HARTLEY: There is a scaling factor 

2 outlined in Appendix 8B for cost, and there are 

3 slightly different variations, depending which 

4 variables you’re holding constant, different 

5 formulas that you can use for costs or dimensions. 

6 They’re all outlined in Appendix 8B.

7 MR. ROSENSTOCK: Okay. It just seemed 

8 like it sounded like you’re using this specific 

9 formula for all those other parameters that may or 

10 may not be associated with the losses, so -- okay, 

11 thank you.

12 MR. BROOKMAN: Comments on the 0.75 

13 scaling rule? Or other potential approaches? Alan.

14 MR. TRAUT: Specifically, with the liquid 

15 filled design line three, the large kVA 

16 transformers, I think that’s part of what led to 

17 perhaps our frustration with the very large 

18 transformers, is that the design work was done with 

19 the 500 kVA and extrapolated to 833, and those 

20 extrapolations just don’t hold true. There’s too 

21 many outside constraints, both from a utilities 

22 specifications standpoint and from the manufacturer 

23 limitations standpoint. I think in very large 

24 transformers, those scaling rules break down.

25 MR. BROOKMAN: What would you suggest?
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1 MR. TRAUT: I think in the -- in design 

2 line three, we probably need to analyze not just the 

3 mid-point, but perhaps the smallest and the largest 

4 within that category.

5 MR. BROOKMAN: Yes, please, your name.

6 MR. GREESON: Rob Greeson, Federal Pacific 

7 Transformer. It’s been our experience that for the 

8 dry type, on the lower end kVAs, it’s much more 

9 difficult to meet the efficiency levels for the 

10 current requirements than the higher. It probably 

11 has something to do with this -- I don’t really know 

12 what the answer is, because the beauty of that 0.75 

13 rule is it allowed an enormous amount of analysis to 

14 be done. Without it, I mean, it would have been 

15 extremely difficult. It might be better to try to 

16 introduce some other designs, but then on the other 

17 hand, you may have to take some good with the bad, 

18 because the analysis could become a little bit 

19 overwhelming as far as the complexity of it.

20 Bottom line, I’m not really sure what the 

21 answer is, but I’m going to -- we’re going to try to 

22 send some information on that might show how that 

23 0.75 rule really relates to our real world designs, 

24 and see where those curves fall. But in reality, I 

25 don’t know if in the long run we’re going to have 
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1 enough time to really sort out all these issues, and 

2 we may just have to live with it, but we’re going to 

3 do what we can to try to submit some information to 

4 maybe kind of look at this information about the 

5 0.75 rule, to get closer.

6 It works very well at closer kVAs. But if 

7 they get too far in the extremities, that’s where 

8 you can run into some issues.

9 MR. BROOKMAN: Jerry. Microphone, Jerry, 

10 microphone.

11 MR. ALLEN: Sorry about that. Scaling 

12 rule applies, but it assumes that you have the same 

13 percentage insulation in the cross section of 

14 conductor in all the transformers. Part of the 

15 thing that’s happening is they get smaller, you’ve 

16 got more insulation because the BIL’s the same. In 

17 bigger ones, you may have cooling problems in 

18 addition to weight problems. So then, and when you 

19 get into really large sizes, you’re sitting at 5.75 

20 percent impedance and it’s going to change. So 

21 there’s going to be variations, but I agree, the --

22 I don’t know what to do about it, because like you 

23 said, the analysis is getting huge as it is.

24 MR. BROOKMAN: I think it’s pretty clear 

25 the Department’s trying to find some way for a 
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1 reasonable representation that’s simple, right, or 

2 simpler. And so some thought on how they might do 

3 that would be very, very helpful to the Department. 

4 Steve Rosenstock.

5 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

6 Based on this conversation, if you go back to the 

7 previous slide, from what I’m hearing it sounds like 

8 for this one in particular, it sounds like, again, 

9 it seems like the scaling within one data point 

10 might be okay, but you’re going out two or three 

11 data points, you might need a different scale it 

12 sounds like. I’m sorry to do that to you, but 

13 that’s what it -- just based on this conversation, 

14 it’s like there might be a certain range where it 

15 works really well, but then, get out the range, it’s 

16 like standard deviation, you get outside that 

17 standard deviation, you might need a new formula.

18 MR. BROOKMAN: As I cast my eyes around 

19 the room, I see a lot of head nodding up and down to 

20 that comment, so perhaps in your written comments 

21 you could be a little more specific so the 

22 Department has some additional guidance on this 

23 point. Yes, Phil.

24 MR. HOPKINSON: Thank you. I can see more 

25 people on this side of the room than the other side. 
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1 I’ve done looks at these scaling factors for years 

2 and frankly, I like them pretty well, and they do a 

3 good job. But I would say that there are limits for

4 the materials sizes so that -- the size of material 

5 might not really be available to the extent that you 

6 thought that it was going to be there, and you will 

7 end up not being exact using these scaling factors, 

8 but it’s pretty close. So I encourage us to stay 

9 with the same scaling factors we’ve got.

10 MR. BROOKMAN: Okay. Thank you. Or find 

11 some way to specify the exceptions, or whatever they 

12 would be, right. Final comments on this section, 

13 because we’re about to go to lunch. I think I’ve 

14 cast the die right there.

15 Let’s go to lunch. It’s ten minutes after 

16 12. It takes an hour pretty much to eat. Don’t go 

17 off campus. Do not leave the building. 

18 (Whereupon, at 12:11 p.m., the meeting in 

19 the above captioned matter was adjourned for lunch 

20 recess, to reconvene at 1:14 p.m.)

21
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2 1:14 p.m.

1 AFTERNOON SESSION

3 MR. BROOKMAN: Over the lunch break, the 

4 Department has made Xerox copies of business cards 

5 as promised, and I think that Brenda has distributed 

6 them. If you don’t have a copy, then you can still 

7 get one at the registration desk. 

8 So we made really good progress this 

9 morning, the nature and tenor of the comment was 

10 really useful. Let’s proceed. Greg Rosenquist.

11 Markups for Product Price Determination

12 and Payback Period Analysis

13 MR. ROSENQUIST: I am Greg Rosenquist from 

14 Lawrence Berkley National Laboratory. I’ll be 

15 starting the afternoon off with talking about the 

16 markups analysis. And this is to reorient you to 

17 the flow diagram for the preliminary analyses, the 

18 outputs from the market analysis gets fed into the 

19 life cycle cost and payback period analysis.

20 The purpose is fairly straightforward, 

21 it’s to transfer the manufacturing cost in the 

22 engineering analysis into prices seen by the 

23 customers purchasing these transformers. First step 

24 is to characterize how the equipment is being 

25 distributed from the manufacturer to the customer, 
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1 and for each party involved in that distribution, 

2 the Department looks at that party’s direct costs, 

3 expenses and profits to determine the markup. 

4 Now for all markups with the exception of 

5 the manufacturer markup, DOE relied on RS means 

6 electrical cost data. This was able to be used to 

7 develop the markups for our contractor materials, 

8 labor, equipment, and those items. Also the 

9 Department used sales tax rates by the census 

10 division for each census division and large state, 

11 and then aggregated that up to a national value for 

12 purposes downstream in the NIA analysis, but that 

13 data came from a place called the Sales Tax Clearing 

14 house.

15 The output from all of this is what’s 

16 called baseline markups. These are the markups 

17 associated with transforming current transformer 

18 manufacturing cost for equipment being sold today, 

19 into prices that the customer has to pay. So these 

20 markups do not change with the standard level, they 

21 stay constant over all the efficiency levels that 

22 were analyzed.

23 This shows some graphics of distribution 

24 channels that the Department developed. There’s one 

25 distribution channel for liquid immersed and one for 
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1 dry type transformers. Most of the transformers 

2 liquid immersed go to utility customers, so DOE 

3 developed a relatively simple distribution channel 

4 that goes from the manufacturer to manufacturer’s 

5 representative, or distributor, and finally to the 

6 utility. In the case of dry type transformers, most 

7 of those transformers go to commercial and 

8 industrial installations, which are installed by 

9 electrical contractor. So in addition to the 

10 manufacturer markup, the manufacturer’s 

11 representative or distributor markup, there’s also 

12 an electrical contractor markup before it gets to 

13 the point of installation.

14 MR. BROOKMAN: Yes, please, Steve.

15 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

16 As I thought we did with some other appliances, 

17 commercial appliances, we -- another distribution 

18 channel was manufacturer or manufacturer’s 

19 representative to I’ll say chain accounts or 

20 multisite accounts where they might have their own 

21 staff that might be installing, or their own 

22 contractors, so there might be another distribution 

23 channel where they may or may not be using the 

24 electrical contractors. So I think that was 

25 discussed with other commercial products out there 
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1 in the past and incorporated -- especially if it was 

2 like roof-top PAC units, for example. Thank you.

3 MR. BROOKMAN: John.

4 MR. HURST: John Hurst. What about ESCOs? 

5 Increasingly representing a channel to the 

6 industrial sector.

7 MR. ROSENSTOCK: I’m just talking about 

8 the C&I customer -- but absolutely, yes.

9 MR. ROSENQUIST: Again, the Department has 

10 characterized that using the simple distribution 

11 channel that if there’s input that could -- from you 

12 all about different distribution channels that are 

13 more appropriate, it certainly would be considered 

14 for the NOPR.

15 I’ll move on then to show the results from 

16 the markup analysis. You can see this tabulates 

17 results for liquid immersed transformers and dry 

18 type transformers. All the same players are 

19 involved in both types of transformers with the 

20 exception for dry type, it has a markup on the 

21 contract materials. The result is an overall markup 

22 of 1.64 for the liquid immersed, and 1.93 for the 

23 dry type. 

24 And the issue here that the DOE is 

25 specifically seeking comment on is on the 
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1 distributor markups. 

2 MR. BROOKMAN: We have a discrepancy --

3 MR. ROSENQUIST: Yeah, in your handout, 

4 those numbers are incorrect. That was a late catch. 

5 These are the numbers that are actually being used. 

6 And I think as Doug mentioned before, this 

7 presentation -- or Jim Raba mentioned before -- this 

8 presentation will be on the DOE website.

9 So the issue at hand here is DOE is 

10 looking for a specific comment on the markups, but 

11 more specifically on the distributor markups because 

12 information from the last rulemaking analysis from 

13 2007, were used to develop these markups and DOE is 

14 concerned that information may be out of date. So 

15 again, it’s looking for any input as to whether 

16 these numbers are still relevant.

17 MR. BROOKMAN: So how do they look? Yes, 

18 Robert.

19 MR. BERMAN: Robert Berman, Berman 

20 Economics. I’m not sure I’m reading this right. 

21 Are you saying that you don’t -- that there isn’t a 

22 distribution channel that goes from manufacturer 

23 direct to utility?

24 MR. ROSENQUIST: Well, it is in the form 

25 of the manufacturer’s representative. So, there’s a 
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1 step that goes from -- if the manufacturer is 

2 selling to the utility, it goes from the 

3 manufacturer, to a manufacturer’s representative, 

4 which may or may not be in house, and then to the 

5 utility.

6 MR. BERMAN: So you have two manufacturer 

7 markups, one for his representative and one for the 

8 manufacturer?

9 MR. ROSENQUIST: That’s right.

10 MR. BERMAN: Okay. Thanks for the 

11 clarification.

12 MR. BROOKMAN: Mahesh.

13 MR. SAMPAT: Mahesh Sampat. I think the 

14 manufacturer’s represent company, but the position 

15 of transformer goes from manufacturer to end user or 

16 utility directly. Manufacturer’s representative 

17 doesn’t take position.

18 MR. ROSENQUIST: Okay. So you’re saying 

19 that there shouldn’t be a markup associated with 

20 that? 

21 MR. SAMPAT: Right. They are paid 

22 commission on sale, but there is no markup.

23 MR. BROOKMAN: Okay. All that cost is 

24 embedded in the manufacturer’s cost.

25 MR. SAMPAT: Right.
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1 MR. BROOKMAN: You’re saying?

2 MR. SAMPAT: Yes.

3 MR. BROOKMAN: Okay. Andrew deLaski.

4 MR. deLASKI: I’ll ask the question a 

5 little different way, which is that in the current 

6 analysis, is the markup for a manufacturer’s 

7 representative and a distributor the same, or --

8 MR. ROSENQUIST: Yes.

9 MR. deLASKI: It is the same?

10 MR. ROSENQUIST: Yes.

11 MR. deLASKI: You’re treating a 

12 manufacturer rep as if they acted the same as a 

13 distributor.

14 MR. ROSENQUIST: That's correct.

15 MR. deLASKI: That just seems improper to 

16 me, and needs to be revisited. It’s a different 

17 relationship when a manufacturer sends directly to a 

18 customer than through a distributor, that’s a

19 different relationship. You need to problem that 

20 some.

21 MR. BROOKMAN: Thank you, Paul.

22 MR. RYAN: Paul Ryan, Hitachi Metal Sub. 

23 Following on that comment, is this assume a 100 

24 percent of the time, this channel? Because as it 

25 states in the second bullet, the manufacturer is 
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1 going directly to the large utility with, in many 

2 cases, without even a representative or distribution 

3 sale channel. So there would be no markup in that 

4 case. In a large percentage of cases. So I think 

5 your applying this to 100 percent of the cases is 

6 not correct.

7 MR. BROOKMAN: Okay. Thank you. Other 

8 comments, not only on these representations of the 

9 actual markups, but also on the assigned values 

10 here. As Greg said, the Department is very 

11 interested if things have changed from when these 

12 were done previously in 2007, if current conditions 

13 mean these should change. Steve Rosenstock.

14 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

15 There might be a difference in the sales tax, I know 

16 that some jurisdictions have raised sales taxes over 

17 the last couple years, due to budget issues.

18 MR. ROSENQUIST: The sales tax are 

19 current, or relatively current. It’s just the 

20 distributor markups that aren’t.

21 MR. ROSENSTOCK: Thank you.

22 MR. BROOKMAN: So generally, these look 

23 pretty good. John.

24 MR. SCHOEN: You don’t see too many 

25 contractors who are picking up 52 percent.
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1 MR. ROSENQUIST: Again, that’s actually 43 

2 percent. These are the correct numbers, not the 

3 ones in your handout.

4 MR. BROOKMAN: Yes, we -- for the record, 

5 the installation under liquid immersed --

6 installation labor-slash-equipment, should be 1.43. 

7 So additional comments and specifics on these 

8 markups, because we’re about to move on. Andrew.

9 MR. deLASKI: Are you now on equipment 

10 prices or --

11 MR. ROSENQUIST: This will be it.

12 MR. deLASKI: This is Andrew deLaski from 

13 ASAP. Earlier I suggested that the Department 

14 should go verify its pricing by talking to some 

15 utilities, and then over lunch it occurred to us 

16 that one utility that should be able to provide DOE 

17 good data is Bonneville Power Administration. DOE 

18 has got within bounds of this one building, a major 

19 -- within this one building, there’s a major buyer 

20 of distribution transformers in the form of 

21 Bonneville. They should be able to provide good 

22 data for the Department and there may be others that 

23 the Department has access to through the federal 

24 power agencies, that may be able to give good data. 

25 Just one source to look into.
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1 MR. ROSENQUIST: Right. And there was an 

2 attempt on our part to go through the internet, as I 

3 think someone mentioned this morning, and we found 

4 bids for transformers. The problem we have I that 

5 we didn’t find any settlements to actually confirm 

6 that was the price that was actually used to 

7 purchase the equipment, so we felt -- didn’t feel 

8 entirely comfortable going out with those bids.

9 MR. BROOKMAN: Charlie Stephens.

10 MR. STEPHENS: Charlie Stephens. My 

11 organizations actually is funded by 135 different 

12 electric utilities, and some of them are fairly 

13 large, and some of them are very, very, very small. 

14 But I think I can probably get you some data from at 

15 least some of those utilities, and I will go home 

16 and do what I can to pull that together.

17 MR. BROOKMAN: Thank you. Gary, done? 

18 Final comments on this? Anything else you want to 

19 say about pricing? That was it. Okay. Phil, find 

20 a microphone.

21 MR. HOPKINSON: As I sit here thinking 

22 about the ramifications, if a transformer became a 

23 whole lot more energy efficient and therefore more 

24 expensive, would that say that they would be the 

25 same contractor flavor that would go in it, or would 
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1 it change?

2 MR. ROSENQUIST: Right now we’re assuming 

3 it doesn’t change.

4 MR. HOPKINSON: Well, I want to be a 

5 contractor.

6 MR. SCHOEN: No you don’t.

7 MR. ROSENQUIST: Looking for comment on 

8 that, because as I mentioned before, we assume that 

9 the markups do not change from the baseline to the 

10 higher efficiency transformers.

11 MR. BROOKMAN: Steve Rosenstock.

12 MR. ROSENSTOCK: I think there is one 

13 issue on the liquid filled side, in particular, is 

14 that if there’s certain increments, whether it’s 

15 weight or size, or height, that not efficiency16 related, but have to do with installation, then some 

17 of those values might be -- will increase more, you 

18 know, if there’s structural reinforcement or if 

19 there’s any sort of vault change-out, things like 

20 that. There might be some non-efficiency issues 

21 that would tend to possibly, on the installation 

22 side in particular, increase some of those factors.

23 MR. ROSENQUIST: For volt transformers, 

24 specifically, that’s why the subgroups that we’ve 

25 identified, for the subgroup analysis. So, at least 
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1 that one we plan on covering.

2 MR. BROOKMAN: Okay. Then.

3 Energy Use and End-Use Load Characterization

4 MS. COUGHLIN: My name is Katie Coughlin. 

5 I work at Lawrence Berkley National Lab, and I’ll be 

6 taking you through the energy use and the LCC 

7 analyses.

8 So for the energy use determination, the 

9 purpose here is to develop the annual energy use 

10 parameters that are needed for the LCC, 

11 specifically. So it’s not a general study of energy 

12 use in transformers, it’s really to develop those 

13 aspects of energy use that affect the economic 

14 valuation of the losses. 

15 And so just to provide an overview. The 

16 energy use, obviously, refers to the losses in the 

17 transformers, and we have two sources of losses. 

18 We’ve changed terminology, the core losses here are 

19 called the no-load losses, because they exist 

20 irrespective of whether there’s any load on the 

21 transformers, and then the coil losses are referred 

22 to as the load losses. So in some sense there’s a 

23 sort of simplified analysis that you can do to 

24 summarize the losses on a unit. The no-load losses, 

25 assuming the transformer is energized 8760 hours per 
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1 year, is just the engineering parameter which we 

2 call NL, which is the no-load loss rate times the 

3 number of hours. And for the load losses there is 

4 an engineering parameter which we call LL, which 

5 gives you the rate of load loss when the 

6 transformers is loaded at its rated capacity. That 

7 varies with the square of the load on the 

8 transformer. In the engineering literature, this is 

9 often represented through something called the loss 

10 factor, LSF, which is the average value of the 

11 square of the load on the transformer. And if you 

12 knew that average value to high accuracy for a unit, 

13 you could just multiply that by the number of hours 

14 and that would give you the total annual load 

15 losses.

16 Now, for this particular analysis, we 

17 wanted to do something slightly more elaborate 

18 because in a real system, you have both varying load 

19 losses hour by hour, day by day, and you have 

20 varying electricity costs. So the energy use 

21 analysis is designed to try to capture the effect of 

22 the variability in losses and associate that with 

23 variability in electricity costs. 

24 And so the equation at the bottom here is 

25 just the actual operating cost of the transformer is 
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1 the sum over all the time periods of the transformer 

2 loss in a time period times the electricity loss in 

3 that time period. And this creates sort of a 

4 separation in our analysis procedure for the two 

5 equipment classes, because liquid immersed 

6 transformers are primarily owned by utilities, so 

7 the appropriate cost to use there is sort of a 

8 production cost of electricity, and that varies on -

9 - we’re using an hourly variation to capture that.

10 For the dry type transformers, the 

11 assumption in the LCC is that these are primarily 

12 owned by building owners and operators, so they are 

13 typically billed for electricity on a tariff, so the 

14 assumption there is that’s a monthly bill that they 

15 have to pay, and so the energy use parameters that 

16 we need to determine for dry type transformers are 

17 the inputs that determine their monthly bill.

18 In the next few slides, in the energy use 

19 analysis, I’ll explain first what we have done for 

20 the liquid immersed, and then what we did for the 

21 dry type transformers.

22 So to represent the utility system within 

23 the United States for the liquid immersed, we’re 

24 using regional breakdown of the country. We’re 

25 using the electricity market module of regions that 
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1 are used in the National Energy Modeling System. 

2 The map on the bottom gives the regional breakdown. 

3 So there’s 13 of these regions and they follow, 

4 roughly, NERC regions with some subdivisions in the 

5 western area. And the data that we need for this 

6 analysis are -- to get the hourly price estimate, 

7 we’re using FERC Form 714 filings. These are filed 

8 each year by utilities. They give an hourly load 

9 for the utility service area or control area, and an 

10 hourly either a system lambda, which you can think 

11 of as the cost of the next unit that will be 

12 dispatched in that hour, or we also, for regions 

13 that have electricity wholesale markets, we use the 

14 day ahead market clearing price. So these again are 

15 intended to represent the margin cost of meeting the 

16 next increment of load. Because improvements in 

17 efficiency are going to decrease that marginal 

18 demand.

19 So, as I said --

20 MR. BROOKMAN: Steve Rosenstock. 

21 MR. ROSENSTOCK: A question. I believe 

22 you said you used the cost production of power. 

23 Shouldn’t the cost not be the generation, 

24 transmission, and distribution cost, because we’re 

25 talking about distribution transformers here. So G, 
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1 T, and D adds to the cost at the point of the 

2 distribution transformer, not just the G factor.

3 MS. COUGHLIN: That’s right. So in the 

4 LCC, we have essentially a capacity cost component 

5 of the total operating costs, so --

6 MR. ROSENSTOCK: But it -- but you -- I 

7 don’t -- when you say you have the capacity cost 

8 component, I thought I understood you to say that 

9 was from the market generating price.

10 MS. COUGHLIN: No, there’s a separate --

11 when I get to the LCC -- the operating cost include 

12 an energy term, essentially, and a capacity term.

13 MR. ROSENSTOCK: And the capacity term 

14 includes the transmission and distribution?

15 MS. COUGHLIN: Right.

16 MR. ROSENSTOCK: Thank you.

17 MS. COUGHLIN: Yes, so this is just the 

18 energy use part. This is the equation. We have the 

19 load loss parameter times the hourly load scaled to 

20 the maximum load, times the marginal production 

21 costs. And for this analysis, or for this 

22 discussion, was to assume that the hourly load is 

23 scaled by the transformer capacity. The LCC is 

24 slightly more complicated, but the complications are 

25 not that relevant here.
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1 MR. ROSENSTOCK: Maybe one more quick 

2 question. In determining the load, do you use the 

3 kVA load or the kW load?

4 MS. COUGHLIN: I think the --

5 MR. ROSENSTOCK: This goes to my earlier 

6 question about power factor, harmonics, all of that. 

7 So, the load that’s meaningful on the transformer is 

8 the kVA load, including harmonic parasitics that may 

9 not contribute to the work being done, but 

10 contribute to the transformer loss.

11 MS. COUGHLIN: Yeah, I don’t think that 

12 the LLC contains a parameter to include a power 

13 factor, but I don’t know that we have used or put a 

14 lot of analysis in determining what that number 

15 should be.

16 MR. ROSENSTOCK: Okay. So my 

17 recommendation is that some factor be utilized to 

18 account for harmonics and power factor or kVA load 

19 if it isn't already.

20 MS. COUGHLIN: Okay. So overall, the goal 

21 of this analysis is to understand what’s the 

22 correlation between the load on an individual 

23 transformer and the price that is set overall for 

24 the system in which that transformer exists. And 

25 the way we approach this, is we break it down into 
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1 two pieces. 

2 Now we know that from just looking at the 

3 system-wide data from FERC, that the hourly system 

4 price is correlated with the hourly system load, so 

5 we will have one model that captures that 

6 correlation. And then we expect that since, in some 

7 sense, the system load is simply the sum of all the 

8 loads of the components within the system, there 

9 should be a correlation between the load on the 

10 transformer in a given hour, and the load on the 

11 given system. So we have the second piece of the 

12 model that captures that correlation.

13 And so for the first one, the relationship 

14 between hourly system load and hourly system price, 

15 the plot here shows for one of the NERC region -- I 

16 think this is the northeast -- there is a scatter 

17 plot -- this is 2008 data. On the vertical axis is 

18 the system price, and on the horizontal axis is the 

19 system load. Yes.

20 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

21 So this is just -- this is just one of the systems, 

22 not -- because I --

23 MS. COUGHLIN: Right.

24 MR. ROSENSTOCK: -- I saw all of the -- I 

25 saw different colors, you’ve got to look -- this is 
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1 just a representative of one of the regional 

2 systems?

3 MS. COUGHLIN: Yes, that’s correct. So we 

4 have 13 of these plots, one for each region.

5 MR. ROSENSTOCK: And do these -- do the 

6 different colors represent different generation 

7 technologies, or just different loads, different 

8 energy uses?

9 MS. COUGHLIN: I’ll get to that in just a 

10 moment, yes. Essentially that’s just a visual aide 

11 to help understand how we did the model.

12 MR. ROSENSTOCK: Okay. And this is --

13 you’re just using 2008 data. The reason I ask is 

14 that especially for 2010 in areas like ERCOT (ph) 

15 and Pacific northwest, with so much wind coming on 

16 line, there were times when low loads, that 

17 basically the system price went down to one cent per 

18 kilowatt hour or less. Because there was all this 

19 generation that you can’t turn off, and there wasn’t 

20 a load to match it, so some of them actually, at 

21 least at the lower loads, the price went down 

22 significantly.

23 MS. COUGHLIN: That’s right, and some of 

24 these plots you could see --

25 MR. BROOKMAN: We wish.
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1 MR. ROSENSTOCK: Yes, great idea, but.

2 MR. FERNSTROM: So this is Gary Fernstrom. 

3 I have one more thought too, thinking about this in 

4 business terms, you’re using essentially the utility 

5 cost of power in your transformer analysis. Those 

6 kilowatt hours could be sold, and the revenue that 

7 the utility is deprived of is a consequence of these 

8 losses, is not its cost, it’s what it could have 

9 sold the kilowatt hours for. So I would suggest 

10 that we ought to be using the customer price across 

11 the board, not the utility cost.

12 MS. COUGHLIN: Yeah, I’ll just mention 

13 that the -- this is basically consistent -- there’s 

14 an IEEE document on valuing transformer losses that 

15 builds up these costs out of energy production costs 

16 and capacity costs, and that was our motivation for 

17 using this approach.

18 MR. FERNSTROM: If I may, either way the 

19 IEEE thinks about it, it’s the responsibility of the 

20 government to find the most cost-effective energy 

21 efficiency standards, and from a business point of 

22 view, it’s the lost revenue that is affecting 

23 utility operations, not just the lost cost.

24 MR. BROOKMAN: Steve Rosenstock.

25 MR. ROSENSTOCK: Steve Rosenstock, EEI. 
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1 Based on -- different utilities will treat those 

2 transformer losses in multiple ways. Some will use 

3 just use the wholesale, and some will say it’s a 

4 kilowatt hour that could be sold, then some have 

5 pretty sophisticated models in terms of how they 

6 value what’s happening at the liquid filled 

7 transformer side. So there’s a range of how 

8 utilities treat the value of the transformer energy 

9 losses. I’m encouraging utilities to submit 

10 information to DOE in terms of how they treat the 

11 value of these losses.

12 MR. FERNSTROM: Indeed, but I thought this 

13 proceeding was about society, and I think the 

14 business perspective is the society perspective.

15 MR. BROOKMAN: Robert.

16 MR. BERMAN: I just have a question. Are 

17 you also looking at, particularly where there’s more 

18 efficient transformers due to the more efficient 

19 core, that there is a capacity savings as well?

20 MS. COUGHLIN: Yes.

21 MR. BERMAN: Other than the kilowatt hours 

22 savings, which may be quite substantial in systems 

23 like PJM?

24 MS. COUGHLIN: Yes, that’s considered in 

25 the LCC, yeah.
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1 MR. HURST: John Hurst. Did you make any 

2 attempt at all to understand what the cost of 

3 upgrading transmission and distribution to feed 

4 concentrated power demands, locations, which would 

5 be utility costs in the trillions of dollars, where 

6 efficiency can basically defer part of that cost? 

7 Did you make any judgment on that?

8 MS. COUGHLIN: Well, let’s see -- yeah, in 

9 the extent that we have location-specific costs 

10 associated with transmission and distribution, 

11 they’re taken out of NEMS (ph).

12 MR. HURST: No, what I’m saying is that 

13 New York city is using more power than is readily 

14 available. If ... Point comes off line, that’ll be a 

15 lot more. But how are you going to get power there? 

16 What you’re going to have to do is upgrade the 

17 transmission and distribution, and the transmission 

18 and distribution cost is trillions of dollars, and 

19 so the utility is going to have to pass that cost on 

20 and it should be reflected in terms of the benefits 

21 of reducing the -- or improving the efficiency and 

22 reducing the losses in those concentrated areas, so 

23 that you don’t have to transmit so much energy into 

24 them.

25 MR. BROOKMAN: Charlie.
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1 MR. STEPHENS: Charlie Stephens. The 

2 Northwest has discovered that that’s actually 

3 economically true, that a lot of envisioned 

4 investments in transmission and distribution that 

5 were planned and expected never happened because of 

6 the efficiency that was actually occurring at the 

7 end of the line and in the middle. And so we have 

8 now been able to avoid hundreds of millions of 

9 dollars, actually, in transmission and distribution 

10 investments on the basis of the efficiencies, so I 

11 would have to concur.

12 MR. BROOKMAN: Steve Rosenstock.

13 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

14 Again, this is starting to get to mix apples and 

15 oranges a little bit. A lot of that efficiency was 

16 on the customer side, not on the transformer side, 

17 and so obviously, as you increase customer 

18 efficiency, the loads go down or you might not need 

19 as much capacity. There are going to be some 

20 situations, talking about New York City, where if 

21 one power plant or one key supply line goes down, 

22 you’ll have to build a new one out regardless. 

23 They’re going to have to build a separate line, or a 

24 separate power plant or other configurations where 

25 you’re not going to be able to defer any costs.
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1 MR. BERMAN: That’s not what I’m referring 

2 to. I’m not referring to specifics. I’m referring 

3 to the general circumstance. Our transmission and 

4 distribution network in the United States is archaic 

5 and falling apart.

6 MR. ROSENSTOCK: I disagree with that 

7 strongly, sir.

8 MR. BERMAN: Well, you’re wrong. 

9 MR. ROSENSTOCK: No, I’m right. Thank 

10 you.

11 MR. BERMAN: Who do you work for?

12 MR. ROSENSTOCK: The Edison Electric 

13 Institute, and --

14 MR. BERMAN: I know who you are.

15 MR. BROOKMAN: You guys can take that out 

16 on the road. Additional comments on this series of 

17 issues, and let’s return to Katie.

18 MS. COUGHLIN: So going back to this, so 

19 again, this analysis attempts to model something 

20 that’s fairly generic, so that’s one of the reasons 

21 why perhaps some of these issues haven’t been dealt 

22 with. So what we’re doing here -- again, the goal 

23 of this particular piece of the calculation is 

24 simply to express the correlation that exists 

25 between system loads and system prices. So the 
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1 stripes on this graph, essentially, the way we do it 

2 is fairly straightforward. We take the data and 

3 then we just sort it into bins based on the size of 

4 the load, which is along the horizontal axis, and 

5 then within each bin we calculate the average price, 

6 and we calculate a distribution of positive and 

7 negative increments to the average price for each 

8 bin. And that defines a model that allows us, given 

9 a value for the system load, to come up with an 

10 estimate of the system price. So we can use this to 

11 develop an hourly simulation of a system price.

12 And then the second component of the 

13 calculation is to understand the correlation between 

14 the load on an individual transformer, and the load 

15 on the system as a whole, that the transformer is a 

16 part of. So this is essentially a statistical 

17 problem. If you think conceptually, the system load 

18 is the sum of the loads in all the transformers. 

19 What we’re asking is, what is the -- given that I 

20 know that the system load is, say, at 50 percent of 

21 its maximum value, what is the probability that any 

22 single one of those transformers is at a given load 

23 value relative to its maximum capacity.

24 So this is defined in the analysis using a 

25 joint probability distribution function, which is 
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1 what’s plotted here, so that tells you that if the 

2 system load is -- so both sets of data are divided 

3 up into bins between the minimum value and the 

4 maximum value. And the probability is just the 

5 number of times you find that the system load in one 

6 of its bins, and the transformer load in the other 

7 one of its bins. But what this allows us to do 

8 within the calculation is if we know the system load 

9 value, then we can predict, based on this 

10 distribution, an estimate of the transformer load 

11 value.

12 So we have the system load value. We have 

13 a price that gets associated with the system load. 

14 And we have a transformer load that gets associated 

15 with the system load, and that allows us to 

16 construct this model of the operating cost.

17 MR. BROOKMAN: I saw Robert first.

18 MR. BERMAN: Robert Berman, Berman 

19 Economics. Did you ground proof any of this with 

20 coincident/non-coincident peaks on primary and 

21 secondary for actual systems, or with load factors 

22 for maximum utility systems versus the system load 

23 factors?

24 MS. COUGHLIN: We have very little data 

25 that is specific to transformers. We used building 
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1 data to try to validate the modeling approach. So 

2 we have hourly building load data for approximately 

3 800 buildings --

4 MR. BERMAN: So you didn’t look at the 

5 utilities’ figures on load factors?

6 MS. COUGHLIN: We don’t have those on an 

7 individual transformer level. We made some effort 

8 to get data about transformers, but we were not 

9 successful. So that’s something that we’d be very 

10 interested in seeing. I would say that on a 

11 technical level, any data that is provided to the 

12 Department could very easily be incorporated into 

13 this analysis, so, yes, we’re very interested in 

14 receiving information that’s specific to 

15 transformers.

16 MR. BROOKMAN: Jerry.

17 MR. SCHOEN: Jerry Schoen, AK Steel. When 

18 you talk about looking at the load factors, the way 

19 I’m reading this is you’re looking at them through 

20 the course of a 24 hour day. Did you look at them, 

21 for example, in the course of the 24 hour day that I 

22 would care the most about is the 24 hour day in 

23 August?

24 MS. COUGHLIN: This is actually a year. 

25 This is 8760 hours of a year.
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1 MR. SCHOEN: Is that accurate? Because 

2 frankly, what little I know about the utilities, 

3 when they are in trouble, it’s in August. The 

4 summer air conditioning peak, or peak demand load, 

5 and that’s when everything is running flat out, 

6 including the transformers. Because people are 

7 running their air conditioners. And again, that 

8 would be regionally sensitive.

9 MR. BROOKMAN: Steve Rosenstock.

10 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

11 think there’s -- yeah, peak loads are either mid12 summer or mid-winter, depending on the utility, 

13 where located, et cetera. Again, this is just an 

14 average day -- this has been over 8760 hours. 

15 They’re not looking at the peak day for at least 

16 this part of the analysis, so they’re just combining 

17 all the data. And I guess the other question I was 

18 going to say is you’re saying commercial buildings. 

19 Do you have some data that breaks out commercial 

20 versus industrial buildings, because the load 

21 factors will be significantly different between 

22 commercial and industrial buildings.

23 MS. COUGHLIN: In the previous analysis, 

24 they did do some detailed analysis of the load 

25 shapes associated with commercial versus industrial, 
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1 but did not actually find significant difference, 

2 and so --

3 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

4 I’m very surprised. I’ve got use of the EPRI (ph) 

5 data that for a lot of commercial buildings, the 

6 load factor -- the overall load factor, not on a per 

7 transformer basis, when you look at the building, 

8 typical load factors of a commercial building tend 

9 to be at the 50, 55 percent. Industrial buildings, 

10 especially if they run two or three shifts, they 

11 tend to have load factors in the 70, 80, even 90 

12 percent range. So that does surprise me.

13 MR. BROOKMAN: Follow on, Robert.

14 MR. BERMAN: Robert Berman, Berman 

15 Economics. Continuing on with that, at the 

16 residential level, you’re going to be looking at 

17 load factors probably well south of 45 percent in 

18 some cases, in the high 30s, and indeed they will, 

19 as the gentleman points out, design those 

20 transformers for at least the maximum load at the 

21 peak time, and probably by 20 percent on top of that 

22 just to be sure, in some cases, which is going to 

23 make the load factor against name plate even 

24 smaller.

25 MS. COUGHLIN: Yes, we did separate 
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1 residential buildings from commercial and industrial 

2 for developing the distribution function.

3 MR. BERMAN: But as residential buildings, 

4 excuse me, is that a single family house or is that 

5 an apartment building in New York?

6 MS. COUGHLIN: I think these are mostly 

7 single family and small multifamily. There’s no 

8 question that the data set that we have is limited. 

9 MR. BERMAN: Because your transformer 

10 sizes at that point, they’re going to be very 

11 different, and I’m wondering whether or not a 

12 neighborhood or a system average load factor, which 

13 isn’t transformer specific, but might be assumed to 

14 be the same for all transformers within a secondary 

15 system, might be more accurate than trying to 

16 identify particular transformers or particular 

17 buildings?

18 MS. COUGHLIN: Well, again, the purpose 

19 here is to estimate the annual operating cost 

20 associated with energy losses. So again, what --

21 all we really need in terms of the transformer loads 

22 is the degree to which they are correlated with the

23 ups and downs of these hourly varying system prices. 

24 So, in some sense, the precision of this calculation 

25 does not need to be as high as other aspects of 
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1 loading analysis.

2 MR. BROOKMAN: Charlie Stephens.

3 MR. STEPHENS: Yeah, I would just add, we 

4 do this all the time with all the end uses that we 

5 serve in the Pacific Northwest, looking at all kinds 

6 of -- the valuation of energy saved or load saved. 

7 And what I’m seeing here looks fairly consistent 

8 with what I’m seeing. Your numbers, at least the 

9 distributions I’m seeing in front of me here look 

10 fairly consistent, in general terms, with what we 

11 see when we do our modeling. So I don’t really see 

12 an issue so far here, and I’m not sure there’s a lot 

13 of industrial that’s relevant to this. Some, but a 

14 lot of it looks like commercial, and a lot of 

15 residential looks like commercial, like high rise 

16 buildings in New York. In fact, they are classified 

17 as commercial in our system.

18 So anyway, I think you’re on a good track 

19 here from what I can see, and I don’t see anything 

20 inconsistent with what we know where we are.

21 MR. BROOKMAN: Okay. 

22 MS. COUGHLIN: So that’s it for the liquid 

23 immersed. So for the dry type transformers, again, 

24 the assumption here is that they are built in the 

25 same way that general commercial industrial 
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1 installations are built, which is there’s a tariff 

2 and you get a monthly bill. And in the LCC, the 

3 sample of transformer owners is built out of the 

4 CBEC’s sample of buildings. We use buildings from 

5 1992 and 1995, because for a large subset of those, 

6 through surveys, we have monthly data for the 

7 building on electricity consumption and electricity 

8 demand, so that allows us to define a monthly load 

9 factor for each building. And based on those 

10 monthly load factors and some statistical modeling, 

11 we estimate the loss factor and also responsibility 

12 factor, which are then used to calculate the total 

13 cost for that month, of the losses.

14 So I will review that part of the 

15 calculation again when we get to the LCC. The next 

16 two slides, I’m just going to explain how we did the 

17 modeling of the loss factor and responsibility 

18 factor as a function of the load factor. And again, 

19 we have this collection that I mentioned of a few 

20 hundred commercial and industrial buildings. So 

21 essentially what you can do is you can just go and 

22 calculate for all of those buildings, the monthly 

23 value of the loss factor, the load factor, and the 

24 responsibility factor, which is defined here as the 

25 square of the individual load in the hour of the 
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1 peak of the aggregate load.

2 So based on all that data, we just 

3 constructed some relevant, but simple statistical 

4 models. First of all, for the loss factor, we used 

5 this expression. I think there’s an error in the 

6 notes that LF2 in the equation -- that 2 should be a 

7 superscript. So this is a rule that’s often used in 

8 trying to estimate loss factors based on load 

9 factors. The value, K, is a parameter that is in 

10 between zero and one. So this equation is sort of 

11 mathematically correct, and there’s always some 

12 value of K that will satisfy this equation. 

13 So what we did is we took our building 

14 data and our calculations for each month and each 

15 building loss factor and load factor, and deduced 

16 the value of K that went with that, and then we used 

17 these distributions of values of K for this group of 

18 buildings. And what you find is that there’s a 

19 dependence of the shape of the distribution on the 

20 range of the load factor for the building. So the 

21 model uses three distributions, one for low load 

22 factors, one for medium load factors, and one for 

23 high load factors.

24 Again, the load factor is part of the data 

25 set in our customers sample. So you know the load 
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1 factor, you use the distribution to pull out a value 

2 of this parameter K, and then you calculate the loss 

3 factor.

4 MR. BROOKMAN: Would you say that there’s 

5 a discrepancy between this and the notes?

6 MS. COUGHLIN: Just in the equation, the 

7 LF squared is written LF2 --

8 MR. BROOKMAN: Is see, thank you. Wanted 

9 to point that out. Gary Fernstrom.

10 MR. FERNSTROM: Could you please help me 

11 to understand what the responsibility factor is 

12 supposed to mean?

13 MS. COUGHLIN: Sure. Responsibility 

14 factor is -- this is the way of looking -- again, so 

15 for the commercial installations, you get a monthly 

16 demand charge, so we’re trying to estimate what the 

17 transformer load might contribute to the building 

18 peak demand. That is what the responsibility factor 

19 tells you.

20 MR. FERNSTROM: Thank you.

21 MS. COUGHLIN: And, so again, the approach 

22 that we use is data driven. We take the data that 

23 we have, we simply calculate responsibility factors 

24 and the scatter plot here shows the responsibility 

25 factors as a function of load factor. So again, you 
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1 see there’s some correlation. Obviously, if the 

2 load factor is very high, that means the loads are 

3 very flat, that means the responsibility factor will 

4 be close to one. If the load factor is very low, 

5 that means the load is very variable and the 

6 responsibility factor is more difficult to predict.

7 So that general effect is captured in the 

8 model that we use here, essentially -- I won’t go 

9 into details, but we model this distribution of 

10 responsibility factors as a function of the load 

11 factor.

12 MR. BROOKMAN: Question? Steve.

13 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

14 And again, this is for the data that you have for 

15 both commercial and industrial facilities?

16 MS. COUGHLIN: Right. They’re mixed 

17 together, yes.

18 MR. ROSENSTOCK: So they’re all together 

19 in this graph here -- this data set? Okay. It does 

20 -- if you look at it again, each dot is a data 

21 point, it just seems like even with low load 

22 factors, it does seem to be significant number that 

23 have responsibility factors that are well above 

24 point seven or point eight. I thought it would be a 

25 little bit more spread out, but it seems like 
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1 they’re all clustered, kind of up high. I’m just 

2 kind of curious as to why the data isn’t a little 

3 bit more spread out on this graph. It seems like 

4 there’s a heavier weight, even at the lower load 

5 factors.

6 MS. COUGHLIN: Yes, this is -- it’s 

7 difficult to say, again, we have a limited amount of 

8 data and more data is always better, so if --

9 MR. ROSENSTOCK: So again, I’m not sure in 

10 which part of the technical support document, is 

11 there a general kind of result in terms of what the 

12 responsibility -- overall responsibility factor is?

13 MS. COUGHLIN: Again, what we do is we 

14 take this and we use this to construct another 

15 distribution function. So given the load factor, 

16 then you pick the responsibility factor from the 

17 distribution, and that’s what goes into the LCC.

18 MR. BROOKMAN: Robert.

19 MR. van BUSKIRK: Robert van Buskirk, DOE. 

20 Also these responsibility factors are based on 

21 monthly data, right?

22 MS. COUGHLIN: That’s right. 

23 MR. van BUSKIRK: Yes, so a big thing -- a 

24 big factor that affects the responsibility factor is 

25 the correlation between the peak on the transformer 
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1 and the peak of the overall load, and when you’re 

2 shortening the time period to a month, rather than 

3 the year, those correlations are going to be more on 

4 top of each other, and that’s why that probably 

5 looks different than most of the responsibility 

6 factors.

7 MR. BROOKMAN: Thank you. Other questions 

8 at this juncture? We’re going to keep going here.

9 MS. COUGHLIN: Okay. Well, we do have --

10 so we have isolated a couple of issues. Of course, 

11 comment on anything is welcome. Metered hourly data 

12 -- everybody wants it, nobody has it. So if there’s 

13 any possibility of getting any kind of field 

14 measured data for transformers, we are very 

15 interested in seeing it and using it to validate or 

16 improving these models.

17 Another question that we ran into is 

18 understanding the way that dry type transformers are 

19 installed in large buildings, so essentially, for 

20 this analysis, we are forced to use the whole 

21 building load as a stand-in for a transformer load, 

22 but within a large building, depending on how 

23 they’re installed and wired into the building 

24 circuits, that may or may not be a good 

25 approximation. So any information about 
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1 installation practices for, say, a 30 story 

2 building, would be very useful.

3 MR. BROOKMAN: Steve.

4 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

5 For the first issue, as I recall and I think I 

6 mentioned it the last time, NYSERDA (ph) did a 

7 pretty big study in the 90s about building 

8 transformer loads. They did some end use studies. 

9 It’s ten year old data, probably, but it still might 

10 be relevant for your information, for your model.

11 In terms of installation practices, I’ll 

12 just, looking at your Chapter 8, basically, for the 

13 dry type design lines that you have, it basically 

14 says property owners, commercial companies, 

15 government offices are about 81 percent of the 

16 owners for the dry type, medium or low voltage, and 

17 19 percent are industrial. At least in office 

18 buildings, at least in ones I’ve been kind of 

19 familiar with, doing audits, a lot of times the dry 

20 type transformers really are just knocking it down 

21 from 277480 down to 12208, and they’re really just 

22 serving receptacles, lights, office equipment, 

23 computers, networks, et cetera. They tend to --

24 I’ll say it’s kind of a non-HVAC load in a way, at 

25 least in some of the office buildings, or they’re 
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1 just in there for tenant use, when they decide to 

2 use it, especially for multi-story office buildings.

3 Again, for the low voltage ones in 

4 particular, a lot of them tend to be non-HVAC so 

5 they may have less of an impact in terms of 

6 responsibility factor.

7 MR. HURST: John Hurst. Have you ever 

8 been in New York?

9 MR. ROSENSTOCK: I’m sorry?

10 MR. HURST: Have you ever been in New 

11 York?

12 MR. ROSENSTOCK: I have, yes.

13 MR. HURST: All right. There are 30,000 

14 network transformers in New York.

15 MR. ROSENSTOCK: I’m talking about 

16 building ones, not --

17 MR. HURST: Those are building 

18 transformers, that’s how the building is served, 480 

19 volts.

20 MR. ROSENSTOCK: Right. But then there’s 

21 the other ones that can knock it down even further, 

22 12208 for all the other stuff too.

23 MR. HURST: Or for that matter -- I’m just 

24 saying there’s lots of buildings where HVAC in large 

25 installations is served by dry type transformers 
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1 indoors. There’s a lot more than little 600 volt.

2 MR. BROOKMAN: John, thank you. Tom is 

3 next.

4 MR. PATZNER: I’m going to supply this 

5 data in my comments, but you guys actually published 

6 the percentage of buildings that are appliances, 

7 computers, electronics and so forth. From that data 

8 you can break it down into 480 volt loads and 208 

9 volt loads. So for the dry type distribution, the 

10 building percentages have already been tracked by 

11 EEAI, so you guys published it. So I have it on a 

12 slide already, I’ll put it in my written comments. 

13 But you will see that the low voltage dry is only 

14 going to be approximately 25 percent of electricity 

15 in the building, that’s all that’s still using 120 

16 volts, and then the medium voltage are going to be 

17 75 percent of electricity, because that’s all the

18 480 Y 277. So you guys actually track all those 

19 other appliances, and we know which of those 

20 appliances are at 120, and which ones are at 480 or 

21 277, so you can quickly get the split for the dry 

22 type transformers for your loading factors. And 

23 I’ll add that to my comment.

24 MR. BROOKMAN: Thank you. Other sources 

25 of data that we would identify at this point? The 
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1 Department, of course, always looking for data. 

2 Thomas. Please.

3 MR. PATZNER: I would suggest that the 

4 DOE, or their consultant firms, adds to their 

5 interview, performance contract companies. Since 

6 the 90s, actually the last five years, there’s a 

7 large number of companies that are tracking the 

8 losses in buildings because they assign performance 

9 contractors with the end users. They’re probably 

10 going to be reluctant to give the information to the 

11 DOE, but they probably would work with your 

12 consultant and there’s a lot of data out there, 

13 because it’s really easy to meter all the way down 

14 to outlets today. And companies are doing it, they 

15 are signing performance contracts with the people 

16 that are installing the data, and so there’s an 

17 avenue of a stakeholder that I do not believe you 

18 guys have looked at yet, that should be able to 

19 supply you some of that data.

20 MR. BROOKMAN: Okay. Thank you. We’re 

21 about -- final comments on this?

22 Life-Cycle Cost and Payback Period Analysis

23 MS. COUGHLIN: Okay. So now we’ll 

24 move on to the LCC, the life cycle cost analysis. 

25 So life cycle cost is where we combine everything 
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1 you’ve heard about up to this point into an estimate 

2 of what is essentially the total -- life cycle cost 

3 is the total ownership cost of the transformer. 

4 So the purpose here is to understand the 

5 way the life cycle cost is impacted by the standard, 

6 and this analysis for transformers differs somewhat 

7 from other products because the way that the 

8 efficiency standard affects the population of 

9 designs is simply to eliminate some designs from the 

10 overall set of designs that would be available. So 

11 it’s quite possible for a set of designs to be 

12 available under all standard levels.

13 So the way that the -- I’ll give you an 

14 overview of the way the LCC works, and then we’re 

15 going to walk through each one of the individual 

16 inputs to the LCC. So what we have set up in this 

17 spreadsheet is -- what we’re trying to do is 

18 simulate a population of transformers, and we’re 

19 actually trying to simulate the loads on the 

20 transformers as they would be installed in the 

21 field. So it’s more complicated than just the 

22 loading assumed in the test procedure.

23 Typically, these are the things -- if you 

24 open up the spreadsheet you can set a lot of these 

25 parameters yourself when you do a run. Typical run 
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1 is 10,000 iterations or 10,000 transformers. And 

2 for each one of those transformers, we go through 

3 each one of the steps that I’m going to outline, and 

4 we calculate the life cycle cost for that 

5 transformer. And we repeat that whole set of 10,000 

6 calculations for each candidate standard level. So 

7 we have a distribution of LCC results at every 

8 single standard level that we can consider. 

9 Within the simulation, there are a number 

10 of variables that contain some random variation. 

11 This includes the specific choice of design for the 

12 baseline and for the standard level at each 

13 candidate standard level. The transformer loading 

14 parameters have some random variability in them. 

15 The transformer price load correlation, as I 

16 described, would have some variability, and the 

17 transformer lifetime will have some variability.

18 As I said, the effect of an amended 

19 standard is to take some of the designs that are 

20 available at even the base case, and remove them 

21 from the choices in the overall design set.

22 So let me just give you a graphical 

23 illustration of what I mean by that. This is a plot 

24 for design line one, candidate standard level one. 

25 On the vertical axis we have the load losses, and on 
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1 the horizontal axis, the no-load losses. These are 

2 the engineering parameters. And then this cloud of 

3 points represents all of the designs that are in the 

4 table that we received from the engineering 

5 analysis.

6 In the -- the triangles represent designs 

7 that would be selected in the base case of the 

8 current standard, and then the green circles are 

9 designs that would be selected under some -- under 

10 candidate standard level one. So you see there’s a 

11 decent number of designs that are not selected under 

12 any standard level, and there’s a decent number of 

13 designs that survive -- that are selected under both 

14 scenarios. 

15 And then the effect of the standard is 

16 roughly approximated by this dashed line. It’s 

17 going to cut off some designs that have low 

18 efficiency according to the test procedure.

19 So this flow chart illustrates the series 

20 of calculations that we go through for each 

21 individual transformer. We have these A and B 

22 parameters, which are used to define the customer 

23 choice model, the process of the customer choosing a 

24 transformer. And we have the -- we have actual data 

25 for A and B values. Then we have the table of 
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1 transformer designs, so we have a customer, and the 

2 customer gets assigned an A and B value that is 

3 translated into the choice of the design, then we 

4 can calculate the markups and installed cost. Then 

5 we move down and we do the loading calculation, so 

6 we have a model for the transformer loading, and we 

7 have our electricity costs and prices. So we do 

8 this simulation of the operating cost and the -- and 

9 so we calculate annual operating cost based on that 

10 simulation of the load and price variation.

11 Then we take the annual operating cost and 

12 we want to extend that out over the lifetime of the 

13 transformer, so we have some trends that escalate 

14 the electricity price, that gives us the operating 

15 cost over the lifetime of the transformer. 

16 And then to finish up with the economics, 

17 we have a discount rate which is applied to future 

18 operating cost savings, and we apply that discount 

19 rate, we get a net present value associated with the 

20 lifetime operating cost. And then within all these 

21 calculations there is some ability to adjust for 

22 different compliance dates and variability in the 

23 lifetime.

24 So the next few slides, we’re going to 

25 step through, essentially, these blue boxes, the 
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1 ones that we haven’t discussed yet in any detail, 

2 and go over the additional inputs to this analysis.

3 MR. BROOKMAN: Why don’t you just pause 

4 for a moment. Questions about any of this? The 

5 flow chart is really complicated, I think many have 

6 seen it before. Questions before we proceed? Okay. 

7 MS. COUGHLIN: And I just remind you once 

8 again that because of the different ownership 

9 categories and the different electricity pricing 

10 structures for liquid immersed versus dry type 

11 transformers, there are some differences within -- I 

12 mean, overall, both sets of spreadsheets work the 

13 same, but there are some differences in the details 

14 of how the operating cost savings are calculated.

15 So again, liquid immersed, the operating 

16 cost is evaluated using hourly variation in both 

17 transformer loads and prices, and for dry type, it’s 

18 monthly variation in the transformer load parameters 

19 and the electricity prices.

20 So with these A and B values, essentially 

21 what we want to represent in the model is the sort 

22 of, in some general sense, what people do when they 

23 purchase a transformer. So, again, we use this IEEE 

24 document that I mentioned earlier as a guideline to 

25 kind of standardize method for evaluating the total 
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1 emission cost of the transformer, and in that type 

2 of calculation, we have these two parameters, A and 

3 B. So A is essentially the net present value or the 

4 equivalent first cost as it is called, a no-load 

5 loss, in dollars per watt; and B is the equivalent 

6 first cost -- there’s an error here, that should be 

7 load losses for the Bs in dollars per watt.

8 So the percentage of purchasers who 

9 actually go through the trouble of evaluating the 

10 total ownership cost is a variable in the LCC. And 

11 those purchasers are referred to as evaluators. The 

12 assumption is is if you’re not an evaluator, you are 

13 simply going to buy the cheapest design that meets 

14 your other engineering criteria. And within the 

15 LCC, we set up certain -- a number of scenarios 

16 where the percentage of owners who do this 

17 evaluation is defined as shown in this table. And 

18 the default scenario is that for liquid immersed, 

19 about 75 percent of purchasers are going to 

20 evaluate. For low voltage dry type, it’s ten 

21 percent. For medium, it’s 50 percent, and for high, 

22 it’s 80 percent. And we also consider sensitivity 

23 scenarios in which no one evaluates, and scenarios 

24 in which everyone evaluates.

25 MR. BROOKMAN: Steve Rosenstock. 
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1 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

2 For liquid immersed, I haven’t asked, but several 

3 years ago it seemed like the ratio was 50:50 of 

4 these investor owned utilities that were evaluating 

5 versus non evaluating. I don’t know what the ratio 

6 is now. I’m going to encourage members to provide 

7 information to DOE to let you know if they’re 

8 evaluating on the TOC basis.

9 MR. BROOKMAN: Steve, you actually did a 

10 survey or something?

11 MR. ROSENSTOCK: Last time, last go round, 

12 I believe, or there was -- in 2005, I think there 

13 was other data, other surveys out there that 

14 discussed it. I don’t know if Oak Ridge did it or 

15 some of there was some information, especially after 

16 deregulation, a lot of people stopped evaluating, in 

17 the late 90s. 

18 But on the other hand, for the dry type 

19 in particular, and I said this last time, I’ve 

20 worked with commercial customers and I don’t know of 

21 any commercial or industrial customers that use both 

22 A or B values to evaluate any equipment that they’re 

23 buying. They’re looking at dollar per kilowatt 

24 hour, or dollar per ... peak demand. They’re not 

25 assigning different values to no-load versus load 
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1 losses on a transformer. It’s just like any other 

2 appliance, you have different initial cost, you have 

3 different energy uses, they’re doing life cycle 

4 cost, they’re saying okay, which one -- if they’re 

5 doing life cycle, which one is lower energy cost, 

6 they don’t care whether it’s load or no-load. It’s 

7 just an energy cost is an energy cost.

8 So again, I understand and appreciate all 

9 the Department’s done, but especially for commercial 

10 and industrial owners, using A and B is not really a 

11 good model of the marketplace out there because 

12 they’re not evaluating them separately. For them, 

13 it’s just energy cost, regardless of the loading of 

14 the transformer, and they want to model them and 

15 decide which one has life cycle cost. It’s LCC.

16 MS. COUGHLIN: So we’ve actually attempted 

17 to take that into account. We call it A and B, and 

18 we need the A and B parameters because we need that 

19 to link with the designs that are in the engineering 

20 table, but for the dry type transformers, our method 

21 of estimating A and B is actually based on their 

22 monthly marginal demand and energy prices. So it 

23 does correspond much more closely to the way the --

24 an owner who is billed by a tariff would evaluate 

25 those losses.
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1 MR. BROOKMAN: Keep going, Steve.

2 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

3 And again, but it’s not -- they’re not necessarily -

4 - those transformers are not necessarily doing 

5 marginal, they’re doing base load consumption as 

6 well. It’s not just marginal. That’s the other 

7 key. 

8 MR. BROOKMAN: You’re --

9 MR. ROSENSTOCK: I’m talking about the dry 

10 type, I’m sorry. They’re not -- the transformers 

11 are not -- they’re not just using electricity at the 

12 margin, they’re using it at the base load as well.

13 MR. BROOKMAN: Thomas and then Charlie.

14 MR. PATZNER: Steve, I’d like to -- Thomas 

15 Patzner -- I’d like to expand. In my opinion, A and 

16 B are sufficient, but I believe it would be 

17 unoccupied where you only have no-load, and then 

18 occupied, which is how customers are starting to 

19 look at their consumption. And then the occupied 

20 would be A plus B. So if you’re talking to a 

21 commercial user, they’re looking at when they’re not 

22 occupied in the building, where the no-load is going 

23 to be there, and then they’re looking at when 

24 they’re occupied, where you’re going to have people 

25 plugging in devices and turning them on. So it 
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1 would be A plus B for the second scenario, and just 

2 A for the first scenario. And you could take it 

3 back to your transformer designs.

4 MR. BROOKMAN: Charlie.

5 MR. STEPHENS: Charlie Stephens. We’ve 

6 been doing efficiency programs with our commercial 

7 and industrial customers for 30 years now, and 

8 pretty much uniformly in most of them, not all of 

9 them, but most of them are sophisticated enough that 

10 they know what their loads are going to be on the 

11 building. They estimate them, they take the trouble 

12 to estimate them anyway, and they know what kind of 

13 a transformer they’re going to need. And if you’ve 

14 got an industrial customer that’s running an 80 

15 percent load factor on the system because they are 

16 three shift paper mill, they know that they need a 

17 transformer with low load losses, and that’s what 

18 they buy. So they’re doing it. They’re not stupid. 

19 It costs them a lot of money to pick the wrong 

20 transformer, especially if you’re a big customer, 

21 which includes a big 30 story commercial building, 

22 like UNICO owns a lot of. 

23 So we work with these folks, to this day, 

24 and in fact, we’re working with a lot of our 

25 industrial customers right now, to help them 
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1 increase the sophistication of their load models so 

2 that they can do a better job of estimating their 

3 losses. So this is going on all the time, but I 

4 would say that your choices of ten percent, 50 and 

5 80, based on the size of the transformer are 

6 probably not -- they’re not unreasonable.

7 MR. BROOKMAN: But Charlie, are you 

8 talking about the northwest?

9 MR. STEPHENS: No, actually, I’m just 

10 talking about the business community that we work 

11 with. Most of the corporations that we work with 

12 are not northwest corporations, they’re national and 

13 international corporations, and the people that do 

14 this are -- some of them are based in Philadelphia, 

15 and they’re doing the load calcs for a paper mill in 

16 Oregon. So, you know, they’re not -- these are 

17 business people who understand that it’s costing 

18 them more and more money to have losses they don’t 

19 need to have if they just do their homework.

20 MR. BROOKMAN: Robert.

21 MR. van BUSKIRK: So Robert van Buskirk, 

22 Department of Energy. I’d like to clarify that, to 

23 some extent the use of A and B factors on the dry 

24 type transformers is more a mathematical convenience 

25 than the decision of how DOE thinks customers are 
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1 making their decisions. There’s an equivalence to 

2 some extent between a minimum life cycle cost 

3 calculation and an equivalent A and B for that 

4 particular transformer choice. And when the 

5 Department is estimating an A and B factor for that 

6 dry type transformer selection decision, the 

7 Department is trying to pick the A and B values that 

8 are equivalent, mathematically equivalent, to the 

9 minimum life cycle cost calculation that a customer 

10 might actually go through.

11 MR. BROOKMAN: So I think it might be 

12 useful to have confirmation of what Charlie’s 

13 talking about, that -- I guess both medium to large 

14 commercial and industrial, they’re making some 

15 pretty informed decisions here, I guess. I don’t 

16 know on the residential side, but --

17 MR. HURST: John Hurst.

18 MR. BROOKMAN: Yes.

19 MR. HURST: Most data processing -- I mean 

20 most buildings, most commercial buildings, run large 

21 data processing loads. A contractor estimating 

22 nowadays is going to estimate more power per square 

23 foot than he would have ten years ago, or 20 years 

24 ago, and it’s a 24 hour cycle. The original cycle 

25 for those buildings used to be like, let’s see, I 
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1 think it used to be like 80 percent or 90 percent 

2 during the day and half of that during the midday, 

3 and then at night it was dropped down. Those things 

4 are not true in large commercial buildings any 

5 longer.

6 MR. BROOKMAN: Yes, Paul.

7 MR. RYAN: Paul Ryan. Just want to go 

8 back to liquid filled side. I urge the DOE or its 

9 consultants to reevaluate the evaluation scenario, 

10 75 percent is much too high. The IOUs as Robert 

11 Berman commented earlier, often ask the transformer 

12 OEM to give them DOE’s as cheaply as they can. 

13 That’s a first cost analysis. It’s not a TOC 

14 analysis. I would guess that that’s probably a 

15 maximum value of 15 percent. So 15 and 75, there’s 

16 a big deviation there, so I think the Department and 

17 its consultants needs to reevaluate the evaluation 

18 of TOC.

19 MR. BROOKMAN: Gary Fernstrom. Thank you.

20 MR. FERNSTROM: Are we talking with this 

21 number -- the number of individual utilities, or are 

22 we taking into account the size of utilities with 

23 respect to number of customers served, or portion of 

24 the country served. I can assure you that PG&E uses 

25 some life cycle cost approach for looking at 
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1 transformers, and I would venture a guess that most 

2 of the other large utilities that serve a large 

3 portion of the nation do similarly. 

4 MS. COUGHLIN: Yes, so this percentage is 

5 the percentage of transformers in simulation. So 

6 the probability that a transformer will be owned by 

7 one of the utilities is defined by the total annual 

8 sales of that utility. So more of the transformers 

9 will be owned by the larger utilities. But yes, the 

10 75 percent is just for the population of 

11 transformers, and we have not, I believe, 

12 implemented any kind of rule about to take utility 

13 information and define whether that utility would be 

14 more likely to evaluate. But we could implement 

15 that if we receive reliable data on how that should 

16 be done.

17 MR. BROOKMAN: It seems like we’re getting 

18 not clarity on how we’re segmenting all of this, but 

19 maybe someone would comment about what they think 

20 the faults might be. Jerry, you’re next in the 

21 queue.

22 MR. SCHOEN: Jerry Schoen, AK Steel. All 

23 of these transformers are now regulated to some 

24 extent to a minimum efficiency level. So isn't 

25 there a default TOC built into that evaluation? So 
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1 there is no such thing as a non-evaluator? They are 

2 just DOE compliant, would be the first box, and then 

3 above that --

4 MR. BROOKMAN: I saw Robert first, and 

5 then Andrew.

6 MR. BERMAN: In answer to your question, 

7 you can design to A and B factors and get a TOC 

8 based on your A and B factors. Or you can say give 

9 me DOE as cheaply as possible, at which point I’ll 

10 take the efficiency number, don’t even think about A 

11 and B, and see how cheaply I can build a transformer 

12 that’s going to meet that efficiency value. That’s 

13 a very different cost than if I build a transformer 

14 to TOC, and say what’s the initial cost of that 

15 transformer, and buy based on that initial cost 

16 versus the TOC. I’m still buying a TOC transformer. 

17 So if I evaluate it based on TOC and I’m really 

18 looking at it based on initial cost, I’ve got a very 

19 significant upward bias in the cost of the 

20 transformer. 

21 In addition to that, if we say TOC, 

22 there’s a number of utilities out there that do 

23 something called band of equivalence, which doesn’t 

24 give you TOC, and is a way of doing risk analysis 

25 that makes the economy shudder.
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1 MR. BROOKMAN: So that last comment was 

2 from Jerry. Andrew is in the queue and then Steve.

3 MR. deLASKI: I wanted to make the band of 

4 equivalence point as well, and so now I’m hearing 

5 quite a -- the 75 percent number, I believe, is the 

6 same number that was used in the last rulemaking, is 

7 that correct? For evaluation of the liquid 

8 immersed?

9 MS. COUGHLIN: Yes.

10 MR. deLASKI: So I guess there’s a few 

11 comments on that. One is that it strikes me that 

12 there’s a reasonable possibility that some utilities 

13 that were evaluating before, now aren’t, for what 

14 has been described before. I see some nodding 

15 around the table here. And now there are minimum 

16 DOE standards, let’s just buy the minimum. Give me 

17 the minimum, DOE’s taking care of this, I’m not 

18 going to worry about A and B any more. I think it 

19 may -- I think it’s worth checking into, has 

20 practice changed because now there is a standard 

21 where there wasn’t one before?

22 And then I think the other thing that I am 

23 concerned about is, is if you ask the utility, do 

24 you do any evaluation, and they say yes, what does 

25 that mean? 
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1 PARTICIPANT: Everybody’s going to say 

2 they do it.

3 MR. deLASKI: Of course they’re going to 

4 say they do it. Yeah, of course I do evaluation. 

5 It’s almost a question of pride. But my 

6 understanding, and this is from talking to people 

7 while I’ve been in and out of this technology over 

8 the last 15 years, is that there has been this 

9 practice of band of equivalence, which is you do the 

10 analysis, and then you ignore it. So I think we 

11 have to -- this 75 percent number is -- strikes me 

12 as probably too high. I wish I had a better number 

13 for you. I heard 15 percent over here. The 

14 manufacturers probably have a better sense than I 

15 do, I’m sure they do, and utilities have the best 

16 sense.

17 MR. BROOKMAN: Does anybody -- since we’re 

18 on our number right now, anybody wish to speculate 

19 what that number is? Any additional thoughts on 

20 that number?

21 PARTICIPANT: Which number now? Hold on.

22 MR. BROOKMAN: We’re talking about the 

23 default number.

24 MS. COUGHLIN: Default evaluators.

25 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 
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1 gave an estimate based on, again, older data. It 

2 seemed like it was half and half, based on whether 

3 it was EI survey or just other trade press data.

4 MR. BROOKMAN: This is a thing for which 

5 comment would be very --

6 MR. ROSENSTOCK: I am going to urge my 

7 members to provide to DOE are they using TOC, how 

8 they’re evaluating, why that information -- and also 

9 in terms of band of equivalence, another way to look 

10 at it is in Monte Carlo analysis. You’re getting 

11 multiple bids from multiple vendors, multiple 

12 losses, multiple prices -- they’re all into their 

13 calculations, there’s spreadsheets, and then as we 

14 know, because you’re forecasting over a 30 year 

15 lifetime, you’re going to do a band of equivalence 

16 because of high, low, medium, any sort of cost 

17 parameters that might be going on. That’s why they 

18 do a band of equivalence, because for the long term, 

19 there’s that bandwidth that they’re looking at in 

20 terms of what’s really going to happen over the next 

21 30 years.

22 Just like a lot of people -- just like EIA 

23 does with their high, medium reference of load, they 

24 predict different outcomes based on different 

25 parameters. In a way, it’s their version of band of 
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1 equivalence. Thank you.

2 MR. BROOKMAN: Yes.

3 MR. deLASKI: Just to follow onto that. 

4 So my understanding of that process, Steve, correct 

5 me, because people know better than I do, but that 

6 process tends to lead to a lowest first cost 

7 transformer purchase. That’s what I understand 

8 happens.

9 MR. ROSENSTOCK: It’s hard to -- but 

10 again, --

11 MR. deLASKI: But what it leads to is 

12 lowest first cost, not to actually evaluate 

13 transformers. 

14 MR. PATZNER: But my fear in this climate 

15 is going to be -- you’re going to go to the 

16 utilities and every single one of them say, of 

17 course we evaluate, DOE requires it and they’ll give 

18 you the numbers that are in the rule, because that’s 

19 actually what they’re using.

20 MR. BROOKMAN: Thank you, Jerry, and I 

21 also saw the other Jerry, pardon me. Yes. Jerry, 

22 you had a comment as well? Okay.

23 Well, let me ask, Katie, is there anything 

24 else that you want to put to this crowd that you 

25 would like them to talk about?
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1 MS. COUGHLIN: I don’t think so. I mean 

2 we actually have identified this as one of the 

3 issues, so we’ll come back to it as an issue box, 

4 but I think -- we may be overestimating in this 

5 discussion the importance of the fraction of people 

6 who evaluate. Because if a utility is evaluating, 

7 is putting some value on losses, and they’re doing 

8 that accurately, it’s very likely that they won’t be 

9 impacted by the standard. Because the design that 

10 they would purchase would be available under the 

11 standard. It’s a fairly subtle point, though.

12 MR. BROOKMAN: Mahesh.

13 MR. SAMPAT: Mahesh Sampat. I think the -

14 - if you go about asking the question, do you 

15 evaluate? Everybody’s going to say they are going 

16 to evaluate, okay. I think maybe the different way 

17 to phrase the question would be, do you buy DOE or 

18 DOE plus? And how many people buy DOE plus? And 

19 that number is probably what needs to go there.

20 MS. COUGHLIN: Yes, I believe -- we’ve 

21 looked at the purchases -- the market share of TP1 

22 or TP2 or whatever, and that helps inform these

23 numbers, but yes, it’s just an estimate.

24 MR. SAMPAT: It’s more efficient than DOE. 

25 How many people really buy more efficient than DOE?
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1 That’s the question.

2 MS. COUGHLIN: Okay. Let’s move on. I’m 

3 not sure -- we spent a lot of time talking about 

4 this, I don’t want to spend too much time on the 

5 subject. This is essentially the A and B values 

6 that are in the spreadsheet model, were taken from 

7 data. So we have the older survey data that was 

8 used in the first analysis, and then we did our own 

9 survey just going through the internet, looking for 

10 transformer bids which provide the A and B values.

11 We did an analysis to check whether or not 

12 the distribution of A and B has changed 

13 significantly between the most recent year and the 

14 earlier data years, and we couldn’t find any 

15 evidence of a trend in either A or B. 

16 So within the LCC spreadsheet, there’s a 

17 little -- again, a little statistical model that if 

18 your customer is an evaluator, that we assign to 

19 them an A and a B value, and then once we have that,

20 we get the design from the design table. 

21 And as I mentioned, for the dry type, we 

22 call it an A and B so that we can connect to the 

23 design table, but really it’s based on a very 

24 simplified ownership cost based on that building’s 

25 cost of electricity.
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1 The issues for comment -- well, evaluation 

2 rates, so we covered that. Again, we’re also 

3 interested in anything that might change -- if 

4 you’re dealing with buildings, large buildings with 

5 multiple transformers, whether there’s any reason 

6 why some subcategories of transformers would be 

7 treated differently than others. And how we might 

8 relate that purchase practice to the data that we 

9 have for the buildings, such as the building size, 

10 the number of floors, the principal building 

11 activity.

12 MR. BROOKMAN: So you can see the comment 

13 boxes. Please take a peek, see if there’s any 

14 additional comments are warranted at this time. 

15 Okay, so we’re moving on.

16 MS. COUGHLIN: Okay. So the total 

17 installed cost is what goes into the LCC, so we get 

18 the purchase price with the manufacturer markups 

19 from the engineering analysis, and then as Greg 

20 Rosenquist went through, we add the --

21 MR. BROOKMAN: Can you just pause for a 

22 moment?

23 MS. COUGHLIN: Sure.

24 MR. BROOKMAN: Let’s just everybody stand 

25 up. Just for just a -- just stretch for just a 
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1 minute. We’ve hit kind of a dead spot here and 

2 we’re not going to allow that to persist. Okay. 

3 Get a breath of fresh air -- well, air. Okay. Now 

4 let’s resume. Okay. Total installed costs.

5 MS. COUGHLIN: So total installed costs 

6 include the markups, sales taxes, and then any 

7 additional installation costs that are required. 

8 And this is where consideration of weight and size 

9 do come into the LCC. 

10 For the electricity prices, for the liquid 

11 immersed, the hourly marginal electricity production 

12 costs come from the FERC filings, and as I said, in 

13 areas where the wholesale market, we use the day 

14 ahead market clearing price, otherwise we use the 

15 system lambda. And we have prices for each of these 

16 EMM regions that are defined within the national 

17 energy modeling system.

18 Now we do include in the LCC, the capacity 

19 savings that would be associated with improved 

20 transformer efficiency. So based on our statistical 

21 model of the loads, we can estimate this 

22 responsibility factor, the transformer load at the 

23 hour of the system peak. And then we use data that 

24 we pull out of NEMS on capacity costs for generation 

25 capacity either for base load or for peaking load, 
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1 or really mid-merit load, and transmission 

2 distribution costs, and then the capital recovery 

3 factors that essentially give you financing costs 

4 associated with those investments.

5 So those are used to define the capacity 

6 cost piece of the operating costs for the 

7 transformer. This is only done for liquid immersed.

8 For dry type, it’s essentially -- this is 

9 the demand piece of the monthly electricity billing.

10 MR. BROOKMAN: Robert.

11 MR. BERMAN: Robert Berman, Berman 

12 Economics. I’m a little confused about an apparent 

13 inconsistency and I’m just wondering why it’s there. 

14 You’re using tariff rate or price for the dry type 

15 and utility cost for the liquid immersed. What are 

16 we looking at the cost of? Or the cost to?

17 MS. COUGHLIN: The cost of providing the 

18 electricity that is dissipated in the transformer.

19 MR. BERMAN: So that would still be the 

20 utility cost for the dry type as well. The tariff 

21 rate that they’re getting, and a large number of 

22 these customers aren’t even on tariff, they’re on 

23 contract that you may not even see, is -- it’s going 

24 to include a T&D of the customer component as well, 

25 it’s what the tariff is based on. The cost that 
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1 you’re using on the liquid immersed side is 

2 basically generation cost, or generation and 

3 transmission cost. The bus bar, if you will. 

4 MS. COUGHLIN: Well, it’s avoided capacity 

5 cost.

6 MR. BERMAN: Avoided capacity cost. But 

7 it’s not an avoided capacity cost for the dry type, 

8 and I think you probably ought to be doing it 

9 consistently, at least so that you could add the 

10 numbers together.

11 MS. COUGHLIN: Well, the dry type -- the 

12 assumption is that essentially the meter is before 

13 the transformer, so the customer pays for the 

14 electricity that is being dissipated by the 

15 transformer. So the value to the customer, or the 

16 person who is buying the transformer is what they 

17 pay according to the tariff. And that’s what the 

18 LCC calculates.

19 MR. BROOKMAN: Is that true? The meter is 

20 there before the transformer? Yes. Okay. Gary.

21 MR. FERNSTROM: I’m still confused about 

22 this capacity component, so could you go -- there we 

23 go. You say the capacity component is derived from 

24 the auctions for regions with function capacity 

25 markets. So you have a factor, then, that you apply 
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1 to the market capacity cost, through which you 

2 derive the T&D --

3 MS. COUGHLIN: Right. Well, this is just 

4 for the generation capacity, so that essentially 

5 what we’re after is an annualized dollars per 

6 kilowatt that we can say when you know, you shave 

7 the peak load by a certain number of kilowatts and 

8 we assign a value. There are some regions where 

9 there is a capacity market, so we used capacity 

10 market data to get that dollars per kilowatt.

11 MR. FERNSTROM: Okay. So I’m trying to 

12 understand where the T&D cost shows up.

13 MS. COUGHLIN: The T&D cost is added to 

14 the generation cost. The T&D cost is taken from the 

15 NEMS, what’s used in NEMS to value T&D additions.

16 MR. FERNSTROM: So that’s some factor 

17 applied to the generalized generation capacity cost?

18 MS. COUGHLIN: It’s added. So you have 

19 the shaving of the peak, which is kilowatts, and 

20 then you have two pieces in the avoided cost. You 

21 have the avoided generation and the avoided T&D.

22 MR. FERNSTROM: Where do you get the 

23 avoided T&D from?

24 MS. COUGHLIN: From NEMS, from -- so 

25 there’s a table in NEMS that is used within the 
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1 annual energy outlook to define the cost of 

2 expanding the system.

3 MR. FERNSTROM: Okay. Thank you.

4 MR. BROOKMAN: Robert. You okay? Got it. 

5 Okay. So this -- other questions or comments on 

6 this dense material? I thought it was well covered, 

7 but I thought it was pretty dense. Okay. So we’re 

8 moving on and for those of you that are wondering, 

9 it’s about 10, 15 minutes or so we’re going to take 

10 a break.

11 MS. COUGHLIN: So okay. For the 

12 electricity price for the dry type transformers, 

13 probably the most important thing on this slide is 

14 the reference, if you’re interested, there’s a 

15 report on how -- the methodology that we have used 

16 to develop a tariff-based marginal electricity 

17 price, or average electricity price for commercial 

18 buildings. Within the LCC, the main thing that you 

19 need to know is that each building actually has a 

20 dollars per kilowatt hour value for energy, and a 

21 dollars per kilowatt value for changes in demand. 

22 So the energy savings, and the demand savings are 

23 both accounted for at the level of an individual 

24 customer in the LCC. 

25 And again, those are converted to an 
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1 annual operating cost. We include the seasonal 

2 rates variation in electricity rates, and then the 

3 whole annual cost is escalated, using the AEO price 

4 forecast.

5 MR. BROOKMAN: Yes, please, Steve.

6 MR. ROSENSTOCK: Steve Rosenstock, Edison 

7 Electric Institute. A couple questions. In your 

8 TSD you show that about 20 percent of the 

9 transformers of the dry type ones are owned by 

10 industrial customers. Are you using MEC’s data for 

11 the industrial customer for that portion of the 

12 analysis?

13 MS. COUGHLIN: We don’t have -- MEC’s 

14 provides very little data at the building level, so 

15 what we have done is we took a subset of the CBEC’s 

16 buildings, which we believed would have loads that 

17 are similar to industrial buildings, and then we --

18 so those are large buildings or buildings like 

19 refrigerated warehouse, which are very use specific 

20 -- and then we adjusted the weights using 

21 information from MEC’s on floor space associated 

22 with industrial buildings.

23 MR. ROSENSTOCK: Okay. And in terms of 

24 the utility tariffs, how are they broken out in 

25 terms of -- do you have -- are they covered -- for 
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1 example, investor-owned utilities serve about 70 

2 percent of the customers, and unions and coops serve 

3 about 30 percent. Are the tariffs broken out in a 

4 similar percentage in terms of customers served?

5 MS. COUGHLIN: Yes, the tariffs 

6 essentially have a weight associated with them that 

7 is related to the customer accounts that are in EIA 

8 for each utility.

9 MR. ROSENSTOCK: Thank you.

10 MS. COUGHLIN: Okay. So moving along, 

11 this is the energy price forecast that comes out of 

12 the energy outlook. So we have three scenarios: the 

13 reference case scenario, then there’s the high price 

14 and the low price scenario. So what you have here 

15 is essentially, this is an escalation factor that’s 

16 used over the lifetime of the transformer to scale 

17 the value of the operating costs. And this has been 

18 converted to a real dollar escalation factor. And I 

19 believe the AEO forecast stops in 2020, so we use a 

20 different method to estimate the growth beyond 2020 

21 to -- so that we can look at the operating cost over 

22 the full lifetime of the transformer.

23 MR. BROOKMAN: Yes, Robert.

24 MR. BERMAN: Robert Berman, Berman 

25 Economics. If I’m reading this graph right, you’re 
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1 forecasting a price in real terms for 2035 that’s 

2 five percent higher than what it was in 2008? Yes, 

3 2008.

4 MS. COUGHLIN: Yes, this is what AEO gives 

5 us this year, yes.

6 MR. BERMAN: Okay, just --

7 MR. PHOUMINH: Yes, John Phouminh. I’m 

8 looking at your graph there and it seems like you 

9 used 35 years life expectancy of the transformers?

10 MS. COUGHLIN: We’ll get to that. It’s a 

11 distribution with a mean of 32 years.

12 MR. PHOUMINH: Thirty-two?

13 MS. COUGHLIN: Yes.

14 MR. PHOUMINH: I believe there ought to be 

15 used at 30 years, not 32. AOE draft, you know the 

16 one that you reference on slide 89, if I’m not 

17 mistaken, I think they use a 30, not 32.

18 MR. BROOKMAN: I think they’re going to 

19 describe that a little further.

20 MS. COUGHLIN: Yes.

21 MR. BROOKMAN: Now, there were a few more 

22 -- in a little bit, to describe the distribution 

23 life.

24 MS. COUGHLIN: Yes, we’ll get to that in a 

25 moment, yes.
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1 MR. BROOKMAN: Gary Fernstrom.

2 MR. FERNSTROM: So you’re showing a 

3 dramatic drop in price from maybe 2007 to 2011, and 

4 then a very gradual increase after that. I’d like 

5 to know where I can sign up for that deal. That 

6 looks almost too good to be true.

7 MS. COUGHLIN: Yeah, and as I said, this 

8 is the Annual Energy Outlook, so it’s really -- we 

9 don’t really have any control over these numbers, so 

10 I -- yeah. This is the Energy Information Agency 

11 forecast.

12 MR. BROOKMAN: Energy Information 

13 Administration. Go ahead Steve.

14 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

15 Yeah, what they’re doing is they’re looking 

16 backwards, based on -- the values from 2005 to 2009 

17 are just based on the past history, based on the 

18 actual data. Because 2008, remember, $140 per 

19 barrel of oil and $12.00 per million BTU natural 

20 gas. That’s why you see that spike up. Natural gas 

21 now, we’re $1.40 per million BTU, that’s had a huge 

22 difference on electric prices, that’s why you see --

23 again, that’s just referring what actually happened 

24 in the marketplace, especially for someone on the 

25 marginal generation. And then just trying to 
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1 predict afterwards, you’ll see -- and they always 

2 have the band width.

3 MR. BROOKMAN: Well it’s their forecast 

4 that DOE is using, so let’s move on.

5 MS. COUGHLIN: So we have discount rates. 

6 Discount rates are used to discount the value of 

7 future operating cost savings. We use debt and 

8 equity -- cost of debt and equity. Cost of equity 

9 is used, standard modeling procedure, the capital 

10 asset pricing model. We use data obtained from this 

11 DemaDor (ph) online website, and essentially try to 

12 break down the cost of capital for different 

13 categories of transformer purchasers and then come 

14 up with a weighted average based on the distribution 

15 of transformer purchases across those different 

16 categories. 

17 So this table gives the ownership 

18 categories and then the discount rate that’s 

19 calculated for that ownership category. The third 

20 column, the number of observations is just the 

21 original data set. That doesn’t have anything to do 

22 with the way they’re weighted in the LCC 

23 calculation.

24 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

25 Just out of curiosity, do you have information on 
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1 what kind of variance or standard deviation within 

2 these categories?

3 MS. COUGHLIN: That might be in the TSD, 

4 yeah. I don’t know.

5 MR. ROSENSTOCK: Which chapter? I’m 

6 sorry.

7 MS. COUGHLIN: It’s in the spreadsheet. 

8 You can look at that in the spreadsheet. In the 

9 spreadsheet the discount rate is treated as a 

10 distribution and you will find that within the 

11 distribution in there.

12 MR. ROSENSTOCK: Okay. Thank you.

13 MS. COUGHLIN: Service lifetime. So we’re 

14 using the document prepared by ORNL that came up 

15 with a service lifetime of 32 years. The 

16 transformer simulation uses a distribution of 

17 lifetime, so each individual transformer will have a 

18 lifetime drawn from that distribution. We assume a 

19 failure rate of half a percent per year, due to 

20 whatever random defects or problems, and then in the 

15th 21 year of the transformer’s life, additional rate 

22 of failure of half percent per year kicks in due to 

23 wear and tear, corrosion, that sort of thing. 

24 MR. BERMAN: Robert Berman, Berman 

25 Economics. Have you thought about using the 
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1 regulatory R curves that the -- the depreciation 

2 curves that the regulatory commissions use? We’re 

3 talking about, particularly for utilities, 

4 transformers and --

5 MR. BROOKMAN: Robert, is your microphone 

6 on?

7 MR. BERMAN: Yes. Have you thought about 

8 using the R curves that utility commissions, 

9 regulators, use.

10 MS. COUGHLIN: I’m not familiar with that, 

11 sir.

12 MR. BERMAN: This is the depreciation, 

13 standard depreciation curves for different types of 

14 equipment.

15 MS. COUGHLIN: This is just the lifetime. 

16 This is not a depreciation. So this is just failure 

17 rates.

18 MR. BERMAN: That’s what those curves are 

19 based on.

20 MR. BROOKMAN: Let’s hear Charlie Stephens 

21 here.

22 MR. STEPHENS: Yeah, I would argue against 

23 using depreciation curves for anything. I’ve never 

24 found one in recent times that has anything to do 

25 with physical reality, and I think you can 
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1 depreciate 90 percent of a commercial investment in 

2 a building in eight years, so that doesn’t mean the 

3 building dies in ten or 12. So I think you probably 

4 need to -- I like the 32 years, and I read the -- I 

5 actually read the ORNL report, or most of it, at one 

6 point, and I think they came up with a reasonable 

7 number. So I don’t think it would make much of a 

8 difference if it moved to 30 or moved to 34, 

9 actually.

10 MR. BROOKMAN: Robert, you want to chime 

11 in here?

12 MR. van BUSKIRK: Yes, Robert van Buskirk, 

13 DOE. If -- I think if DOE was to consider using 

14 depreciation curves, it would need, in addition to 

15 that comment, the method for converting depreciation 

16 curves into a physical lifetime curve. Because the 

17 model uses a physical lifetime curve. Yes, Robert 

18 van Buskirk, DOE. If -- I think if DOE was to 

19 consider using depreciation curves, it would need, 

20 in addition to that comment, the method for 

21 converting depreciation curves into a physical 

22 lifetime curve. Because the model uses a physical 

23 lifetime curve.

24 MR. BROOKMAN: Thank you. So it’s 

25 useful that you provided the OR&L citation here, so 
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1 anybody can take a peek at that that wanted to.

2 MS. COUGHLIN: So this just shows the 

3 graph of the distribution that’s used, so the blue 

4 bars are essentially the failure rates -- it’s the 

5 reliability, and then the pink bars give you the 

6 age. So along the horizontal axis we have the 

7 transformer age, and the pink bars are the fraction 

8 of transformers that are retired at a particular 

9 age. So although the mean in this distribution is 

10 32 years, you can see that it’s quite broad. So 

11 there’s quite a bit of variability in the 

12 transformer lifetimes that are used in the LCC 

13 calculation.

14 So this is an issue where we realize that 

15 more information would be very helpful since the 

16 transformer lifetime does have a big impact on the 

17 economics. So any information, any quantitative 

18 information on transformer lifetimes, or early 

19 replacement, or anything else that might affect this 

20 distribution would be appreciated.

21 MR. BROOKMAN: And then you see a comment 

22 box, issue 25. Any additional things to be said

23 about replacement and maintenance practices, other 

24 sources of data? At this time? John.

25 MR. PHOUMINH: Well, I was going to 
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1 comment that, you know, with reference to the 

2 maintenance practice and the cost associated with 

3 that, it’s so hard to quantify because not all the 

4 units are the same, even the same unit you install 

5 today, five months or six years later, five years 

6 later, ten years later, one might fail and one would 

7 not. I cannot see that you will get that data 

8 easily. This is from the utility perspective. And 

9 with the lifetime of the transformer for 32 years, I 

10 think that’s a little long. I would say between 25 

11 to 30 would be maybe is doable. That’s my comment.

12 MR. BROOKMAN: Okay. I’m going to suggest 

13 we take a break right now. It’s 2:50. Let’s see if 

14 we can do this in ten minutes. We’re running a 

15 little bit behind. Last -- the last slides that 

16 will be presented today, tend to go more quickly 

17 than the ones that preceded it. But we still need 

18 to get back here and make it through the rest of 

19 this. So we’ll resume, try and resume at three 

20 o’clock. 

21 (Whereupon, the meeting was recessed for a 

22 10 minute period.)

23 MR. BROOKMAN: Here we go. Okay. 

24 MS. COUGHLIN: So we finished the 

25 discussion of the inputs to the LCC, and I’m going 
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1 to present very briefly some results for three 

2 representative design lines. So we have design line 

3 one, which is a liquid immersed, single phase. This 

4 unit is 50 kVA, pad mounted. Design line seven is 

5 the dry type, three phase, low voltage. The unit 

6 being analyzed here is 75 kVA. And then design line 

7 12 is the three phase dry type medium voltage. In 

8 this case, the representative unit is 1500 kVA. So 

9 I’m just going to show a couple of charts of results 

10 for each one of these design lines.

11 So the first set of charts, this is the 

12 total installed cost as a function of the test 

13 procedure efficiency level. So this is the purchase 

14 price plus all the other costs, the markups and 

15 installation costs. And so you can see the cost 

16 increases by approximately a factor of two over the 

17 range of efficiencies considered, a little bit less 

18 for DL12. 

19 Now there’s going to be three plots that 

20 summarize the LCC savings. So what we’re attempting 

21 to do here is show you the distribution of LCC 

22 savings results on a single chart. So what we do to 

23 get LCC savings, we have our base case set of 

24 designs and our 10,000 transformers, and we get 

25 aggregate LCCs -- we get an LCC for each one of 
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1 those transformers in the base case. And then we go 

2 through each standard level, and a particular 

3 transformer may find that as you go up to a 

4 different standard level the design has to change 

5 because a design has been eliminated at that 

6 standard level that was used in the base case. So 

7 in that case, for that transformer, you’re going to 

8 get a change in the LCC. They will have LCC 

9 savings.

10 Any transformer that picks the same design 

11 for all standard levels will not have any savings 

12 associated with it. 

13 So we have a distribution of LCC savings 

14 for each of the CSLs. The two farthest apart points 

15 on these plots are the five percent and 95 

16 percentiles for the LCC savings, which is on the 

17 vertical axis. And then the rectangle is the 25 to 

18 75 percentile of the LCC savings. And then there’s 

19 a little -- it printed out, but for some reason it’s 

20 not showing up on this chart, but you’ll see it on 

21 your printout, there’s a little bar in the center 

22 that represents the median, and then there’s a box 

23 that represents the average LCC savings.

24 So, for example, for design line one, for 

25 CSLs two, three, and four, there’s essentially 
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1 positive LCC savings for 95 percent of the designs, 

2 and then there’s -- for CSL one there’s negative LCC 

3 savings, which means an overall cost associated with 

4 the standard for roughly 25 percent, and then over 

5 on CSL five and six, you’re also seeing a tail of 

6 negative LCC savings.

7 And then design line seven, you see a 

8 similar pattern. So essentially there’s a point at 

9 which LCC savings start to become negative as you go 

10 up in standard level, which is generally what we 

11 would expect. And this is design line 12.

12 So there’s a -- I believe it’s an appendix 

13 to the TSD has -- 8C -- Appendix 8C has charts like 

14 this and tables for all the design lines, giving the 

15 distribution of LCC savings under these candidate 

16 standard levels.

17 MR. BROOKMAN: Andrew deLaski.

18 MR. deLASKI: I’m wondering -- this is, as 

19 you said, what you would typically expect in this 

20 sort of distribution. I’m a little curious about 

21 the CSL one and design line one and design line 12 

22 where you show that the whisker has a negative LCC 

23 at CSL one. It’s a little unusual to see that.

24 MS. COUGHLIN: What that means is 

25 essentially the -- people pick designs that on the 
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1 total ownership cost basis are actually costing them 

2 money because the losses are very high. So if you 

3 pick the cheapest transformer that has the lowest 

4 purchase price, you may still end up losing money 

5 in an LCC sense because you have to pay for the --

6 you have to pay the operating costs. And since we 

7 have all this variability in our estimate of the 

8 operating costs, you’re going to have cases where 

9 you may have a highly loaded transformer with a long 

10 lifetime, where the operating costs in the 

11 simulation will deviate from a simple approximation.

12 I think -- is that -- yes, that’s it, so 

13 that’s the last LCC slide.

14 MR. SAMPAT: May I ask just one quick 

15 question. Is it fair to say the one at the lower 

16 CLS is cost of losses, and the one at the other 

17 extreme is initial cost of the product is what’s 

18 driving LCC lower? Or that’s too generalization?

19 MS. COUGHLIN: Almost, yes. Yeah, I mean 

20 there is this factor again, because the load loss is 

21 dependent on the loading, it’s a little bit hard to 

22 separate them, but certainly, in a statistical 

23 sense, the loads are the same, no matter how much 

24 you pay for the transformer. So the different 

25 variation here is due to the valuation of the 
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1 losses.

2 MR. BROOKMAN: Steve Rosenstock.

3 MR. ROSENSTOCK: Steve Rosenstock.

4 MR. BROOKMAN: Turn on your mike, Steve.

5 MR. ROSENSTOCK: Sorry, Steve Rosenstock, 

6 EEI. I guess it was the title, you’re showing a 

7 level seven for design line one in Chapter 8. I 

8 guess that was a typo. There is no CSL seven. You 

9 just repeated it, sorry. Same thing, sorry about 

10 that, thank you.

11 MR. BROOKMAN: Joanna.

12 MS. MAUER: Joanna Mauer. I just had a 

13 couple of clarifying questions regarding the payback 

14 period calculations. The mean payback period, which 

15 I believe is what’s summarized in the executive 

16 summary, is that essentially an average of the 

17 10,000 payback periods that are calculated in the 

18 Monte Carlo analysis?

19 MS. COUGHLIN: Yes.

20 MS. MAUER: And then in the LCC in payback 

21 period chapter, I think both the mean and the 

22 payback of an average transformer are reported and 

23 my understanding is that the payback of the average 

24 transformer is the average incremental cost divided 

25 by the average operating, or first year operating 
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1 cost savings?

2 MS. COUGHLIN: I think it’s three years. 

3 It’s three years. I think there’s a -- what we call 

4 a simple payback. So it’s the purchase price with,

5 I think it’s the first three years of the operating 

6 cost savings. And it’s different from the LCC which 

7 does the entire lifetime.

8 MS. MAUER: Thank you. And I think 

9 there’s a number of cases, both different design 

10 lines and different CSL levels where there’s a 

11 significant difference between the mean payback 

12 period and the payback period of the average 

13 transformer, with the mean payback period often 

14 beings significantly higher. Could you explain a 

15 little bit about what’s driving that difference?

16 MS. COUGHLIN: Well, yes, in a general 

17 sense, because you have a lot of variability, if you 

18 do the calculation individually for each 

19 transformer, and then you take the average of all 

20 those calculations, you’ll get one answer. But 

21 because you’re doing a ratio, if you take the 

22 average of the numerator, and then the average of 

23 the denominator, and take that ratio, you can get a 

24 slightly different answer. And it really just 

25 depends on how much variability there is in the 
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1 individual -- in each individual case.

2 MS. MAUER: And is it fair to say that it 

3 might be kind of a small number of transformers 

4 either that are -- have low loading or something 

5 that could essentially skew the mean?

6 MS. COUGHLIN: It can be. Yeah, it can 

7 have like sort of outliers that will sort of skew 

8 the -- some of the averages, yeah. It’s difficult 

9 to say in a very general way.

10 MS. MAUER: And just -- sorry, one more 

11 question. One more question, I think. In other 

12 rulemakings, I think DOE often reports both a mean 

13 and a median, and they seem to often refer more to 

14 the median in summary tables and such. I assume, to 

15 kind of avoid this situation --

16 MS. COUGHLIN: Yeah, the median is sort of 

17 the dividing point, so the median is the number such 

18 that half of the transformers in the sample have a 

19 lower LCC, and half of them would have a higher LCC. 

20 So, yes, it’s just another piece of information. 

21 And the median is in those charts, and it’s usually 

22 very close to the average, but again, if you have a 

23 very strangely shaped distribution, you can have a 

24 difference between the median and the average.

25 MS. MAUER: And was there a particular 
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1 reason for reporting the mean payback periods in the 

2 executive summary, or was that just --

3 MS. COUGHLIN: I think it’s just 

4 customary.

5 MS. MAUER: Thank you.

6 MR. BROOKMAN: Robert.

7 MR. BERMAN: Robert Berman, Berman 

8 Economics. Joanna makes a very good point. The 

9 mean of the payback period does not equal to the 

10 mean of the mean transformer size. What you’re 

11 looking for under the Monte Carlo, I guess, is the 

12 mythical typical representative transformer, based 

13 on those distributions, what transformer is most 

14 likely to be selected? Once you’ve selected that 

15 transformer, calculate the payback period for that 

16 transformer, don’t calculate the average of the 

17 payback periods.

18 MS. COUGHLIN: Right, that’s what we do. 

19 I mean, this is really -- these are sort of ways of 

20 presenting summary results, right. But we’re really 

21 working with this full distribution of calculations.

22 MR. BERMAN: If you’re looking at the 

23 output of the Monte Carlo model under payback 

24 period, it’s giving you the mean of the paybacks.

25 MS. COUGHLIN: Right, which would be the 
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1 mean of the distribution of paybacks.

2 MR. BERMAN: That’s what it’s giving you, 

3 that’s correct. That’s a different number than if 

4 you calculate the payback period associated with the 

5 mean transformer. And the number that you want for 

6 evaluation purposes is the payback period associated 

7 with that particular transformer, with that average 

8 or representative transformer that you’ve selected, 

9 not the average of the payback periods of all the 

10 transformers you’ve looked at.

11 MR. BROOKMAN: Jerry. Go ahead.

12 MR. ALLEN: (Mic not on) If you add up 

13 all the payback periods together, you’ll always get 

14 a number that’s larger than what you’ll get if you 

15 take the transformer ... figure out what the payback 

16 of each individual one of those, add them all up, 

17 and you divide by the denominator, so it skews the 

18 payback period is longer than it really is. You 

19 can’t average the payback period --

20 MS. COUGHLIN: Right, well there’s no --

21 okay, again. The LCC models the population of 

22 transformers. So the analysis is trying to actually 

23 model a population. So the statistical description 

24 of that is through the median and the mean of the 

25 population, because in reality you have a population 
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1 of transformers, and that’s what this analysis is 

2 trying to represent.

3 MR. BROOKMAN: Jerry, go ahead.

4 MR. ALLEN: You have to take each 

5 individual year, figure each individual payback, 

6 figure out ... add them all up, divide by the number 

7 of transformers and get the payback that way. You 

8 can’t add the payback years together. If you do 

9 that, it’s skewing and you’ll always get a bigger 

10 number.

11 MR. BROOKMAN: Okay. Steve Rosenstock.

12 MR. ROSENSTOCK: Steve Rosenstock, EEI 

13 again. Looking at Appendix 8C, and for design line 

14 one, which is one one of the graphs, it talks about 

15 -- there’s a chart in here about the payback period, 

16 and it says, “transformers having an undefined 

17 payback” -- I’m assuming those are the transformers 

18 that have higher life cycle cost, there is no 

19 payback -- is that a correct assumption?

20 MS. COUGHLIN: That’s right.

21 MR. ROSENSTOCK: Okay. So that’s -- okay, 

22 higher LCC on that one. Okay. Just wanted to 

23 double check that just in case I wasn’t missing 

24 anything. Now in terms -- so obviously that’s not 

25 shown in these charts here, just as undefined can’t 
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1 be shown in there. Because under CSL one there’s 

2 seven percent having undefined payback or higher LCC 

3 costs under your simulations. Okay. Thank you.

4 MR. BROOKMAN: Charlie? Okay. We’re 

5 moving on. Andrew first.

6 MR. deLASKI: I think the reason why this 

7 last issue is important, the Department reports both 

8 numbers, and a casual reader goes, okay, mean, 

9 average means the same thing, but that’s not clear 

10 in the materials presented thus far. So I 

11 understand that you’re providing both, they’re both 

12 provide some information. One’s in the executive 

13 summary, which gives a lot of prominence to it. So 

14 it’s an issue of presentation here and I think I’m 

15 getting arguments about which numbers are proper 

16 numbers, basically for decision making, and they 

17 actually -- in some cases they diverge quite a bit.

18 MS. COUGHLIN: Okay. So we have just two 

19 slides left, and this is -- these are to discuss 

20 these emerging technologies that were described in 

21 the engineering analysis. So this is extremely 

22 preliminary, and the emerging technologies have not 

23 been included in the LCC, per se. So what we’re 

24 trying to do here is just get a very rough picture 

25 of what the economics of these designs might look 
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1 like. And again, within the specific context of how 

2 we have set up the LCC models. 

3 And one of the things that we are not able 

4 to do at this point is include these designs as one 

5 of the choices for the existing -- within the 

6 existing set of designs. So, for the symmetric core 

7 technologies, to get a picture of the economics, 

8 what we did is we just created an LCC in which all 

9 of the designs use symmetric core, and we just 

10 wanted to see if they would be affordable using the 

11 estimates of total life cycle cost.

12 So the procedure was exactly the same as 

13 what I’ve outlines for the regular designs, except 

14 all of these now have symmetric cores. And so 

15 essentially what you see is that you can run these 

16 designs through our LCC and the additional purchase 

17 price appears to be compensated by operating cost 

18 savings. So the LCC results are comparable to what 

19 they were for the rest of the design lines.

20 And then the second issue is for the core 

21 deactivation technology. So this was an even cruder 

22 calculation than the -- we didn’t actually do an LCC 

23 here, so what we did -- so let me first say, again, 

24 this is not meant to be a statement about core 

25 deactivation in general. This is question of 
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1 whether we can bring core deactivation technologies 

2 into the LCC the way we have currently structured 

3 it.

4 So, to remind you, the idea behind core 

5 deactivation technology is, instead of installing a 

6 unit -- a transformer that has capacity K, I install 

7 three transformers with capacity K divided by three, 

8 and I have a control system that will deenergize --

9 turn two of them on and off, depending on the load 

10 level. So if you do this, you could end up with a 

11 decrease in the no-load losses, because when the 

12 loads are very low, I just shut off the extra two 

13 transformers. 

14 The problem that arises when you try to 

15 take this design and fit it into our LCC picture is 

16 how am I going to decide when someone would not buy 

17 a transformer of capacity K and buy three that are 

18 capacity K over three? I mean, what is the decision 

19 process for doing that? So as a first draft to 

20 understanding the economics, we just said, well 

21 let’s just assume we have a load loss and no-load 

22 loss parameter for the large capacity transformer. 

23 Let’s just assume we replace it with three that have 

24 the same engineering parameters in the small 

25 capacity. So if we do that replacement, it’s a very 
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1 simple calculation to estimate the losses that would 

2 occur under that configuration.

3 Now, of course, if you -- this may be 

4 clear to some of you who have looked at transformer 

5 loading a lot. Because of this scaling rule, when 

6 you decrease the size of a transformer, you don’t 

7 decrease the losses by as much as you decrease the 

8 capacity. So in general, when you take -- just 

9 replace a larger transformer with three smaller 

10 ones, and don’t change any of the design parameters, 

11 and you use the same distribution of loads that we 

12 were using for the low voltage, which is the 35 

13 percent RMS, then you end up not really actually 

14 getting any energy savings. And the cost of three 

15 small transformers is slightly larger than one large 

16 transformer. So in that replacement scenario, it’s 

17 not cost effective.

18 And the message here, I think, for further 

19 analysis of this technology is that in order to

20 understand when the control technology is going to 

21 be useful, you really need to have a better 

22 understanding of the load distribution. And that’s 

23 going to have an enormous impact on your evaluation 

24 of the losses. And with the current setup in the 

25 LCC and the engineering, we really only consider the 
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1 load loss and no-load loss rates, and we don’t 

2 actually have a way of associating a load 

3 distribution with a customer selection process.

4 So that is the problem that we need to 

5 address to understand how to incorporate this 

6 technology into our consideration of improved 

7 efficiency. And any comments on that would be 

8 appreciated.

9 MR. BROOKMAN: Phil.

10 MR. HOPKINSON: Yeah, I’ve got one. I 

11 think that there are another set of costs, switches 

12 that would turn these transformers on and off is 

13 certainly a cost. There is a consideration too, for 

14 regulation in Flicker (ph) that we didn’t talk 

15 about, but it would be a serious, serious deal. If 

16 you took a 75 kVA intended application, and only a 

17 25 kVA on, and on came a motor that was significant, 

18 then it’s lights out time. So we’ve got that, and 

19 then we’ve got end rush currents associated with 

20 turning these transformers on and off. So this is 

21 not a cake walk, and should not be entertained too 

22 lightly, and I didn’t find any benefit in it anyway, 

23 when I did the analysis.

24 MR. BROOKMAN: Okay. Thank you. So we 

25 want to receive final comment on core deactivation. 
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1 Peter.

2 MR. AMOS: A real quick one, to Phil’s 

3 comment. This core deactivation technology was 

4 really meant to address, say, a multi-occupancy 

5 residential building where you have lots of small 

6 incremental loads, but you don’t just have a 1000 

7 horsepower motor or something kicking in, like you 

8 might find in industrial premises. So when you look 

9 at lots of little loads turning on and off, the 

10 flicker issue goes away. 

11 We were also thinking that the best 

12 manifestation of this is with the 120 degree 

13 symmetric core transformers, which have much lower 

14 end rush currents than stacked core transformers.

15 MR. BROOKMAN: Thank you. So I’m eager 

16 for us to keep going here.

17 MR. ROSENSTOCK: Just a quick question of 

18 clarification on that. On the last slide, the 

19 symmetric core slide, Katie, did you say -- where 

20 does amorphous material become the core material? 

21 At which CSL?

22 MS. COUGHLIN: All of them.

23 MR. ROSENSTOCK: Those are all amorphous?

24 MS. COUGHLIN: All of them are amorphous, 

25 yes. Is that right? Which one -- Okay, two, three 
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1 and above, sorry.

2 MR. ROSENSTOCK: Excuse me?

3 MS. COUGHLIN: CSL two or three.

4 MR. ROSENSTOCK: Is where amorphous 

5 material comes in?

6 MS. COUGHLIN: Yes.

7 (Discussion off microphones)

8 MR. BROOKMAN: Okay. Next we’re going to hear from 

9 Greg Rosenquist.

10 Shipments and National Impacts Analysis

11 MR. ROSENQUIST: Okay. I’m back here. 

12 I’m Greg Rosenquist from Lawrence Berkley National 

13 Laboratory. I’m going to walk your through the 

14 National Impacts Analysis. And again, to reorient 

15 you all to these analyses and where they fit in the 

16 flow diagram, they are at the end of the analysis. 

17 Again, for the National Impacts Analysis, it takes 

18 the outputs from the LCC and payback period 

19 analysis, as well as the shipments forecast for the 

20 shipments analysis to determine the national 

21 impacts.

22 Okay. So shipments analysis is actually a 

23 key part of the national impact analysis, and its 

24 purpose is to basically estimate the impact of 

25 standards on base case shipments forecast, that is, 
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1 shipments without standards, any new standards. 

2 The method it uses to do this is to 

3 develop a shipments model that relies on various 

4 inputs, most importantly, historical shipments, and 

5 again, it does this only for the products that are 

6 under this rulemaking, which are dry type and liquid 

7 type of transformers. 

8 Again, there’s two purposes, I mean, two 

9 main functions of this shipments model, one is to 

10 calculate shipments annually, over time, for each of 

11 the equipment classes that we’re analyzing, and also 

12 to keep track of the inventory or stock of 

13 equipment, and furthermore, also to keep track of 

14 the age of that stock, because there are inputs that 

15 are going to be fed from the LLC analysis that are 

16 going to be age-dependent, and so we need to know 

17 that in order to assign those values properly to the 

18 age of the stock.

19 The purpose of the National Impacts 

20 Analysis is to determine the national energy 

21 savings, the national economic impacts to the 

22 standards, and for the national energy savings, this 

23 is determine in quads or quadrillion BTUs, or 10 to 

the 15th 24 BTUs, and it’s determined as source energy 

25 savings, that is, taking into account transmission 
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1 and distribution losses, as well as the power plant 

2 efficiency. Again, these energy savings are 

3 calculated annually over a forecast period of 30 

4 years from the assumed compliance date of 2016, out 

5 to 2045. 

6 The national economic impacts are 

7 calculated in billions of dollars with a term called 

8 the net present value, or NPV. Keeps track annually 

9 of the operating cost savings and the increased 

10 total installed cost over time, and then discounts 

11 both of those future forecast values to a present 

12 value using discount rates.

13 This slide goes over all the inputs that 

14 are fed into the shipments model. I’ll go over this 

15 relatively quickly, so stop me if you have any 

16 questions. Again, as I said before, historical 

17 shipments are a key part of the shipments model. 

18 Two data sources were used to come up with 

19 historical shipments. Shipments from HVOLT for the 

20 years 2001 and 2009, and then quantity index data 

21 from the US Bureau of Economic Analysis for 1997 to 

22 2008. 

23 Market share data is also important to 

24 define what share of transformers are dry type 

25 versus liquid type, and also what share of 
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1 transformers are by kVA or capacity. The market 

2 shares by transformer type are forecasted based upon 

3 the growth rate in electricity sales forecasted by 

4 the EIA, the Energy Information Administration. And 

5 the market share by kVA or capacity was determined 

6 with HVOLT data for the years 2001 and 2009. 

7 The shipments model keeps track of 

8 replacements, which again is a fraction of overall 

9 shipments, by using the same retirement function 

10 that was developed for the life cycle cost analysis. 

11 And again, since the shipments model keeps track of 

12 the stock, or inventory of transformers. This 

13 retirement function tells us at what age these 

14 transformers fail and they need to be replaced.

15 Base case shipments are forecasted, again, 

16 as I mentioned earlier, when electricity growth 

17 sales from the EIA. For liquid immersed 

18 transformers it’s done with the electricity sales to 

19 all sectors, while for dry type transformers, it’s 

20 done with electricity sales to the commercial and 

21 industrial sectors.

22 New capacity shipments are those shipments 

23 for just that, new installed capacity due to 

24 electrical system expanding. And these are deduced 

25 by taking the difference between the forecasted 
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1 shipments in the base case, and the replacement 

2 shipments. 

3 And then finally, the standard case 

4 forecasted shipments are based upon the exact same 

5 inputs that were used for the base case shipments, 

6 except one important difference, an elasticity is 

7 developed -- a purchase price elasticity is 

8 developed to figure out how these standards impact 

9 the base case shipments forecast.

10 So now I’m going to focus a little bit 

11 more on what was done to estimate market shares. As 

12 I briefly went over before, the equipment class 

13 market shares are based upon data by HVOLT, at least 

14 for 2009, and then they were forecast out to the 

15 future based upon these growth rates in electricity 

16 sales by the EIA. And the market share data was 

17 based upon, again, data by HVOLT for the year 2009 

18 by capacity, by kVA rating, and the values in 2009 

19 were held constant over the forecast period from 

20 2016 to 2045.

21 So this comes to the first issue in the 

22 National Impacts Analysis, which is basically 

23 looking for comment on the market share data. I 

24 mean, there’s very little market share data that was 

25 used here, but we just had to rely on something to 
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1 try to get again, the fraction that our dry type and 

2 liquid immersion and also what fraction our 

3 transformers are by kVA rating.

4 MR. BROOKMAN: Yes, Jerry.

5 MR. ALLEN: It would be --

6 MR. BROOKMAN: Jerry, turn on your 

7 microphone, please. Jerry, turn on your microphone.

8 MR. ALLEN: I did it again, sorry. ... 

9 there are a lot more low voltage and medium voltage 

10 dry types than indicated in here, and my gut feeling 

11 is that the numbers are more like this, because I 

12 just don’t see that many dry types compared to 

13 liquid filled. But I’m hoping somebody out there’s 

14 got better data on that. 

15 And the other thing I wanted to say on 

16 those big ones, like 667 kVA single phase and 883, 

17 833, those are strange units, I agree, but I 

18 actually found one order for eight 667s from one 

19 company. So I’m not real sure whether we’re catching 

20 everything.

21 MR. ROSENQUIST: Are you looking at the

22 next slide? Is that what you’re --

23 MR. ALLEN: I’m looking at -- I’m talking 

24 about when you distribute the MVA per year, when you 

25 -- one of them’s distribution over kVA which was the 
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1 second part of what I said. The first part of what 

2 I said is the MVA and low voltage dry type per year, 

3 and the MVA and medium voltage dry type per year 

4 seem to be low according to a couple of sources that 

5 I have that I can’t divulge. I just hope somebody 

6 can find something out.

7 MR. BROOKMAN: But Jerry, you’re not 

8 referring to a document we have in front of us yet? 

9 The numbers -- the numbers you’re talking about, we 

10 don’t have -- that’s your personal experience?

11 MR. ALLEN: Yeah.

12 MR. BROOKMAN: Yeah, okay. Just wanted 

13 to confirm. Good, that’s useful, and for you to 

14 find a way to disclose them and do a non-disclosure 

15 agreement or whatever so that that data can make it 

16 into the right hands and be shielded at the same 

17 time.

18 MR. ALLEN: I’ll try with one guy anyway.

19 MR. BROOKMAN: Okay. 

20 MR. HOPKINSON: Could I just make a 

21 comment on that? 

22 MR. BROOKMAN: Phil, go ahead.

23 MR. HOPKINSON: Phil Hopkinson, HVOLT. In 

24 the first place what I would tell you is I didn’t 

25 just make up these numbers by myself, that there are 
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1 a lot of spies that I have all over the place, and I 

2 pulled them all in and most of the manufacturers 

3 have people that are good spy sources for me and so 

4 have done a pretty good job of keeping me 

5 calibrated, and I certainly called those numbers in.

6 Now, the other dimension, I’d say, is 

7 compared to 2002 kind of data, so that recognize 

8 that 2009 was quite a blip downward, so that when 

9 some of us calibrated what was going on back in the 

10 2002, 2003 timeframe, and remember I did this market 

11 survey back at that time too, and this is very much 

12 like church. If you can demonstrate you can do a 

13 job once, it’s yours for life. So the volume did 

14 decrease significantly in 2009. Now is that 

15 something that is going to be with us for a long 

16 period of time is -- you know, Jerry, I can’t really 

17 tell you. We can’t even forecast a tsunami very 

18 well.

19 But I would say that whatever we have in 

20 2009, certainly I think is pretty close to what 2009 

21 was. But is it going to be representative of the 

22 next 30 years? That’s an awfully interesting 

23 question, isn’t it. And I think that you’re going 

24 to have to have a significant resumption of housing 

25 for liquid filled transformers, and you’re going to 
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1 have actually a significant resumption of 

2 manufacturing in the United States, right, in order 

3 to get the industrial and commercial transformers 

4 going strong again. So it’s a snapshot in time.

5 MR. BROOKMAN: Okay. Thank you. Steve.

6 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

7 Looking at this slide, you know, again, with all the 

8 other things happening out there in terms of either

9 housing markets or just especially end use 

10 efficiency, this -- the projection again, and it is 

11 obviously just a projection, of increasing --

12 obviously there’s hopefully an increase from 2009 --

13 but if you look at the trend, especially since I’ll 

14 say 1980, it’s been flat or declining. If you do 

15 like a best fit curve, or a best -- it’s not showing 

16 an increase. And obviously you’re going with 2009 

17 and you’re adjusting from a horrible year, 

18 obviously. But to show the values going well above 

19 100,000, I don’t know. Maybe, but it just -- just 

20 look at those -- again, a 30 year compared to 

21 obviously six years is a difference, but I don’t 

22 know. I have my doubts. Thank you.

23 MR. BROOKMAN: Okay. Thank you.

24 MR. ROSENQUIST: I think everyone’s now 

25 referring to the next slide, which shows the actual 
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1 forecast. And of course, the shipments model is 100 

2 percent accurate with the back cast, right, but it’s 

3 -- but you both have been speaking to, which is the 

4 forecast, and again, it’s just based upon the 

5 electricity sales growth from the EIA, and of course 

6 it’s not going to capture all those peaks and 

7 valleys that are seen in the historical data. So if 

8 people feel it’s more representative to just do a 

9 line fit to the data, rather than to tie it to that 

10 electricity sales forecast, then DOE would certainly 

11 like to hear that.

12 MR. BROOKMAN: Gary.

13 MR. FERNSTROM: Gary Fernstrom. Well, in 

14 looking at the forecast, did you include not only 

15 unit shift to account for growth, but ones to 

16 account for failures of the large growth in 

17 transformers that occurred in the 60s and 70s, that 

18 would probably be reaching the end of their useful 

19 life?

20 MR. ROSENQUIST: Well, to the extent that 

21 they’re failing in these out years, yes. But I have 

22 to remind you that again, the growth rate in the 

23 overall base case forecast is tied to that growth 

24 rate in the electricity sales. And so we are 

25 calculating replacements as a function of -- by 
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1 using this retirement function, right, but then that 

2 difference between base case shipments forecast, 

3 which is the overall shipments, and the replacements 

4 is just made up with new capacity shipments. So --

5 MR. FERNSTROM: So replacements are 

6 included in the base?

7 MR. ROSENQUIST: Replacements are included 

8 in the base case, right.

9 MR. FERNSTROM: Thank you.

10 MR. ROSENQUIST: And they’re always less 

11 than the overall growth.

12 MR. BROOKMAN: Steve Rosenstock.

13 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

14 Again, just for historical reasons, growth rate in 

15 the 70s, early 80s was about three percent, then it 

16 was down to two percent -- and again, I’m talking 

17 about electric sales. And then it was one percent -

18 - one and a half percent in the 90s, and 2000s. 

19 There were a few years where the growth rate was 

20 negative, and EEI’s projecting about a point four 

21 percent, compared to years when they were probably 

22 projecting two or three or four percent. So again, 

23 that also, in terms of these increasing MVAs, again, 

24 you know, EIA’s been showing lower and lower growth 

25 rates which should have an impact on the shipment 
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1 value, puts you on the slope.

2 MR. BROOKMAN: Gary, yes.

3 MR. FERNSTROM: Gary Fernstrom. Maybe 

4 just with more thought about that, I think energy 

5 efficiency has had an effect, at least out in 

6 California, so maybe electric sales haven’t grown 

7 that much, but the number of customers, and I think 

8 consequently the number of transformers has 

9 continued to grow. So it’s not unreasonable to 

10 think that we don’t have dramatically increased 

11 sales, but there are increases in the transmission 

12 and distribution system, including transformers.

13 MR. BROOKMAN: Okay. 

14 MR. ROSENSTOCK: Steve Rosenstock EEI, as 

15 a follow up. The current rate of customers has also 

16 gone down in the last several years. Look at the 

17 EIA data.

18 MR. BROOKMAN: Okay. Thanks.

19 MR. FERNSTROM: Well, the growth rate may 

20 have gone down, but there’s still growth. So, you 

21 know, there hasn’t been a decline of residences and 

22 buildings, at least that I know of.

23 MR. ROSENSTOCK: No, but there’s a high --

24 Steve Rosenstock, EEI -- there’s higher vacancy 

25 rates in residential buildings, and -- which 
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1 obviously destroys a load, and then also industrial, 

2 there has been a reduction in the number of 

3 industrial customers. Look at the 2009 data.

4 MR. FERNSTROM: Yeah, but the transformer 

5 that is there doesn’t come out. We don’t follow 

6 around to every building that’s vacant and take the 

7 transformer out. It’s still there incurring losses. 

8 And not producing much revenue to boot. 

9 MR. BROOKMAN: Charlie Stephens.

10 MR. STEPHENS: I would have to agree with 

11 Gary. Our own forecasts, recent forecasts in the 

12 Northwest Six Power Plan, basically suggests almost 

13 no growth in electricity sales, electricity 

14 generation and consumption. But we do show over a 

15 million people coming to our region during that same 

16 period.

17 MR. BROOKMAN: So, Greg, keep going.

18 MR. ROSENQUIST: Okay, so I just went over 

19 this slide with the base case shipments forecast. 

20 This slide’s about estimating what the standards 

21 case shipments forecast are. And again, as I said 

22 earlier, all the same inputs that were used to 

23 develop the base case shipments forecast are used to 

24 develop the standards case with this one important 

25 exception. We developed a purchase price elasticity 
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1 to take into account the increased purchase price 

2 and the operating cost saving due to standards and 

3 their impact on the base case shipments forecast. 

4 So for immersed liquid transformers, this was done 

5 by predicting the variability in the observed 

6 capacity, the peak ratio, and developing a function 

7 for it as a function of the variability of 

8 transformer price and efficiency.

9 What we did to do this is that we got this 

10 historical data from FERC Form 1, which provides, by 

11 utility, the installed capacity, as well as the 

12 maximum load or peak capacity of each utility. So 

13 again, for all these utilities we have these 

14 capacity to peak ratios, and we can come up with a 

15 nationally representative value by doing a weighted 

16 average calculation based upon the installed 

17 capacity of each utility.

18 Again, we plot that, or look at that 

19 against the changes in price and efficiency for 

20 liquid immersed transformers and derive this 

21 elasticity of -0.04, meaning that in general, a ten 

22 percent increase in price results in a point four 

23 percent drop in shipments. So this elasticity is 

24 fairly inelastic, and what that implies is that 

25 utility customers are not all that sensitive to 
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1 purchase price, and that they’re more concerned 

2 about having an excess capacity for probably --

3 maybe continued electricity growth.

4 I’ll stop there and see if anyone has any 

5 questions.

6 MR. BROOKMAN: Steve.

7 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

8 Is there -- I’m just kind of curious, is there more 

9 recent FERC data that could be used?

10 MR. ROSENQUIST: For whatever reason, they 

11 stopped publishing this data in 2001.

12 MR. ROSENSTOCK: Okay. And the reason I 

13 ask is especially for like commodity prices are 

14 three to four times higher than they were in the 

15 1990s.

16 MR. BROOKMAN: Okay. Thank you.

17 MR. ROSENQUIST: For dry type transformers 

18 there were no historical prices to use, so we had to 

19 use a proxy piece of equipment to derive a purchase 

20 price elasticity, and DOE chose to use commercial 

21 interior air conditioners, again, because it’s a 

22 commercial piece of equipment and dry type 

23 transformers are installed in commercial buildings 

24 as well as industrial installations. The elasticity 

25 from that analysis on commercial interior air 
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1 conditioners from 2005 yielded a very inelastic 

2 price elasticity of -0.02, again representing the 

3 fact that if you had a ten percent in purchase 

4 price, you’d have only a point two percent drop in 

5 shipments.

6 Which is seen by these next two charts, 

7 showing forecast for the base case in each of these 

8 candidate standard levels for liquid immersed and 

9 dry type transformers. You see because of the very 

10 inelastic elasticities, there’s a very, very small 

11 drop even at the max tech levels for each of the 

12 transformer types.

13 MR. BROOKMAN: Steve.

14 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

15 There was a discussion of refurbishing rates and 

16 there are utilities that refurbish transformers, and 

17 again, looking at the executive summary for some of 

18 these CSLs where, for example, design line one, CSL 

19 one, incremental cost selling price estimated at 

20 $234 versus CSL six of $2109. I think there might 

21 be a bigger impact than what you’re showing here. I 

22 can’t honestly -- I can model it, but I’m going to 

23 ask my members their thoughts on the impact on 

24 shipments, especially at the higher CSL levels. 

25 Thank you.
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1 MR. ROSENQUIST: Okay. This next slide 

2 talks about the affected stock, that is the 

3 percentage of the stock that’s actually impacted by 

4 a new standard. The way we do this, again, 

5 shipments model that tracks the inventory or stock 

6 of transformers by vintage. And again, that allows 

7 us to figure out how many shipments are coming in at 

8 what age. And these charts illustrate this concept 

9 I’m trying to get across that the affected stock 

10 grows over time, due to a standard.

11 For example, in 2018, which is just two 

12 years after the assumed compliance date, there’s 

13 only a small fraction of the stock that’s affected, 

14 basically the new shipments that have come in in the 

15 two years after the compliance date. But when you 

16 get to 2035 and 2045, a much greater share of the 

17 affected stock -- there’s a much greater share of 

18 the affected stock. And again, this illustrates the 

19 fact that the impact of standards are not immediate, 

20 right, it grows over time as the transformer stock 

21 turns over due to the replacements an the addition 

22 of new transformers with the added electrical 

23 capacity of the power system.

24 And this next slide goes over all the 

25 inputs to the National Impacts Analysis besides the 
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1 shipments forecasts. And the first three inputs are 

2 the total customer cost, repair and maintenance cost 

3 annual load and no-load losses come from the life

4 cycle cost analysis as average values. In addition 

5 to those three inputs, there’s also the peak 

6 responsibility factor and the RMS loading -- again, 

7 they all come from the LCC analysis as average 

8 values.

9 Now, another important aspect to the NIA 

10 is that -- are these customer evaluation rates which 

11 Katie spoke about earlier. Again, all of these 

12 inputs I just described are dependent upon what 

13 percentage of transformer purchasers are evaluating 

14 their decision -- evaluating their decision on how -

15 - what sort of efficiency transformer they should 

16 purchase. So all the inputs from the LCC analysis 

17 reflect that customer evaluation rate. So all the 

18 inputs coming from the LCC analysis reflect, again, 

19 those customer evaluation rates before they go into 

20 the NIA.

21 Then next inputs are the marginal energy 

22 and demand prices. Again, those average prices are 

23 taken from the LCC analysis, and as Katie mentioned 

24 in the LCC analysis, we just use the same forecast 

25 from the AEO 2010 to forecast how those prices 
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1 change over time.

2 We then have electricity site to source 

3 conversion factors, which are used again to convert 

4 those site savings to source savings, taking into 

5 account distribution and transmission losses and the 

6 power plant efficiency. To convert the load losses 

7 -- I mean the no-load losses, average heat rates, or 

8 average conversion factors from the AEO are used for 

9 the entire power sector. To convert the load losses 

10 from site savings to source savings, the average 

11 heat rates or conversion factors for gas fired power 

12 plants are used. 

13 Next set of inputs are the discount rates. 

14 These come straight from the Office of Management 

15 and Budget. They’re seven percent and three 

16 percent. Again, these are used to convert future 

17 operating costs and future equipment cost to a 

18 present value, and it’s brought to a present value 

19 to a present year, which is 2010 for this analysis.

20 I’ll keep on going if there’s no 

21 questions. One of the things that was touched upon 

22 in the engineering analysis is the fact that the 

23 analysis in the engineering in the LCC was done for 

24 13 design lines, and for each one of those 13 design 

25 lines a representative unit was chosen. But in the 
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1 NIA we have to take care of all 115 kVA or capacity 

2 ratings, so some conversion has to be done to 

3 convert those LCC inputs that are for specific 

4 representative units and specific design lines into 

5 these 115 different kVA ratings.

6 And this is done with this 0.75 scaling 

7 rule that was discussed earlier in the engineering 

8 analysis. 

9 Next are the customer evaluation rates. 

10 This table you saw again earlier in the LCC analysis 

11 that was presented by Katie. Again, what’s 

12 important to say is that the LCC inputs are 

13 dependent upon these customer evaluation rates, 

14 reflect those customers that are purchasing --

15 making their decisions based upon these customer 

16 evaluation rates. Again, as pointed out earlier, 

17 variability in the As and Bs are used to capture the 

18 variability in these evaluation rates.

19 So is there any -- I’m going to stop here 

20 again if there’s any questions about this. If not, 

21 I’ll continue to move on to the next issue, which 

22 are these customer evaluation rates in the LCC 

23 analysis again, they were used to determine what 

24 percent of customers are evaluating their economic 

25 decision. In the NIA analysis, we assume that the 
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1 percentage of the population evaluating is constant 

2 over time, as well as the evaluation criteria 

3 staying constant over time. 

4 So DOE is looking for input as to whether 

5 that’s a valid assumption, and if it isn’t how those 

6 evaluation rates and evaluation criteria would 

7 change.

8 MR. BROOKMAN: So we’ve had actually a 

9 fair amount of discussion on this previously, but 

10 additional thoughts on both criteria and rates. 

11 Steve Rosenstock.

12 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

13 don’t know if you’re going to be able to do it, but 

14 is there a way to model scenarios based on -- at 

15 different CSLs, because that could have a huge 

16 impact in terms of evaluation -- what percentage of 

17 customers are going to evaluate.

18 MR. ROSENQUIST: Yeah, we can do it in the 

19 spreadsheet model, it’s just a question of what to 

20 base those rates on.

21 MR. ROSENSTOCK: Thank you.

22 MR. BROOKMAN: So let’s do the last.

23 MR. ROSENQUIST: Okay. This slide just 

24 shows an example of the sort of output generated for 

25 the national economic impacts. And this is showing 
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1 the non-discounted impacts for CSL three. First you 

2 have the overall chart on the top, and then 

3 desegregated into liquid immersed and dry type on 

4 the bottom. The blue columns on the top represent 

5 the operating cost savings due to the standard 

6 level, and it grows over time as transformers 

7 saturate into the stock. And the green bars 

8 represent the non-discounted increases in equipment 

9 costs. The red line is the net of those two, and 

10 you can see in this case that the crossover point 

11 where operating costs equal equipment cost is around 

12 ten years after the compliance date.

13 The other thing to note too is that again, 

14 our forecast period is from 2016 to 2045, but the 

15 model tracks the operating cost savings of all the 

16 units installed into the stock before 2045. So that 

17 long tail is due to all these units, again, slowly 

18 retiring over time. And since the retirement 

19 function has such a long tail, I think around 60 

20 years, they actually track this out to 2100.

21 And this last slide just shows a summary 

22 of the National Impacts Analysis results for each 

23 candidate standard level, and for liquid immerse and 

24 dry type transformers. I don’t think there’s any 

25 need to go over the specific numbers here, but if 
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1 you do have any questions, I’ll certainly entertain 

2 trying to answer them.

3 MR. BROOKMAN: No questions on that? 

4 Okay, so let’s move to the final segment. 

5 Preliminary Manufacturer Impact Analysis

6 MR. HARTLEY: Okay. Again, my name is 

7 Matt Hartley with Navigant Consulting. We’re going 

8 to now speak about the preliminary manufacturer 

9 impact analysis. You can see here in the flow 

10 diagram where it comes into the analyses. It’s a 

11 little bit separate during the preliminary analysis.

12 The purpose of the manufacturer impact 

13 analysis, or the MIA, is to qualitatively and 

14 quantitatively assess the impacts of amended energy 

15 conservation standards on manufacturers of 

16 distribution transformers. A key output of this 

17 analysis is the change in industry net present 

18 value, or INPV, resulting from amended standards.

19 DOE normally performs the MIA in three 

20 phases, which we’ll explore on the next slide. In 

21 the first phase, DOE creates an industry profile 

22 that builds on the market and technology assessment. 

23 This market profile is then updated through 

24 interviews with the manufacturers, and this 

25 typically takes place during the preliminary 
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1 analysis, which is the phase of rulemaking that 

2 we’re discussing currently.

3 During this time, DOE identifies the key 

4 issues concerning manufacturers, which brings us 

5 into phase two. In phase two, which spans the NOPR 

6 and the final rule analyses, DOE builds a straw man 

7 industry cash flow model called the government 

8 regulatory impact model, or the GRIM, to forecast 

9 free cash flows in the industry. It does this for 

10 the base case and the standards case, and calculates 

11 an industry net present value, which is the main 

12 output of the GRIM.

13 Also in phase two, DOE develops an 

14 interview guide that it will use to guide its 

15 subsequent discussions with manufacturers during MIA 

16 interviews, which will take place in phase three. 

17 During these interviews, DOE speaks with a variety 

18 of different manufacturers to receive feedback on 

19 the items listed in the interview guide. And this 

20 is what previously, before lunch, Chris had 

21 mentioned we’ll be scheduling soon after this 

22 meeting, and taking place over the next few months.

23 As he also mentioned, these interviews are 

24 nearly always conducted with a non-disclosure 

25 agreement in place, so that no proprietary 
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1 information would be shared publicly, but rather 

2 aggregated across all the responses.

3 Following the interviews, DOE will refine 

4 the GRIM and evaluate other qualitative issues, such 

5 as manufacturer capacity, employment impacts, and 

6 impacts on competition. 

7 But taking a step back to what was done 

8 for the preliminary analysis, during our preliminary 

9 manufacturing impact analysis, DOE identified three 

10 main issues for manufacturers. First, we identified 

11 a potential issue of core steel availability. 

12 Manufacturers indicated that there’s a limited 

13 global supply of higher efficiency steels such as M2 

14 and amorphous steel, and that higher standard levels 

15 may not be feasible for volume production given the 

16 current steel supply.

17 Second, manufacturers expressed concern 

18 over equipment conversion costs, large capital 

19 investments, retooling, and stranded assets. 

20 Certain technologies, such as mitering and symmetric 

21 cores require specialized equipment which would 

22 require a large capital investment for 

23 manufacturers. 

24 And then lastly, intellectual property 

25 concerns could be an issue for manufacturers, 
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1 because many symmetric core and core deactivation 

2 designs are patented. And if higher standard levels 

3 were based on these technologies, it could place 

4 certain manufacturers at a disadvantage in the 

5 marketplace.

6 MR. BROOKMAN: Dave.

7 MR. ROSENSTOCK: Steve Rosenstock, EEI.

8 MR. BROOKMAN: Steve, Dave’s first. 

9 MR. ROSENSTOCK: I’m sorry.

10 MR. BROOKMAN: Sorry, Steve.

11 MR. MILLURE: Dave Millure, Metglas. 

12 There are actually two global suppliers now of 

13 amorphous metal, the other one being An Tai in 

14 Beijing. They’ve announced aggressive expansion in 

15 their plants, at least 40 kilotons, although to our 

16 knowledge, they’re not doing any export, all that 

17 steel stayed in China. But we have heard them going 

18 to 100, so at some point their exports will probably 

19 be coming.

20 MR. BROOKMAN: And all the manufacturing 

21 is in China at this time.

22 MR. MILLURE: Of An Tai, yes.

23 MR. BROOKMAN: Steve.

24 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

25 If there’s public information available, do these 
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1 patents last well past any sort of, well, I’ll say 

2 2016 or 2017 when a new standard would take effect? 

3 If that information is available?

4 MR. HARTLEY: It’s not information that we 

5 have readily available.

6 MR. BROOKMAN: Robert.

7 MR. ROSENSTOCK: Steve, I’m sorry, I think 

8 that’s incredibly important because, depending on 

9 the candidate standard level, if these are the 

10 technologies that are basically mandated, and 

11 there’s a patent, then there’s a lot of -- obviously 

12 a lot of market issues involved with that, so if 

13 there’s information available, I think that it would 

14 help stakeholders in some of their comments in terms 

15 of gee, if the patents last well past 2016, let’s 

16 say to 2020 or 17 year patent, could be 2025 plus, 

17 that could be a very big deal.

18 MR. BROOKMAN: Robert.

19 MR. BERMAN: Robert Berman, Berman 

20 Economics. I’d like to point out that it’s not 

21 really the supply today that’s relevant, but it’s 

22 the shape of the supply curve that’s relevant. What 

23 you’re observing as supply, assuming the market is 

24 functioning, is also demand. If the demand changes, 

25 one would hope that the supply would change, and 
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1 that over time lines can be added to both the steel 

2 production as well as amorphous production. The 

3 question is how do costs behave as lines are added, 

4 and it looks like those are constant cost 

5 industries.

6 MR. BROOKMAN: Charlie Stephens.

7 MR. STEPHENS: Charlie Stephens. I 

8 thought we heard earlier from the symmetric core 

9 design folks that the design really wasn’t patented. 

10 It wasn’t that there weren’t some patents associated 

11 with some of the equipment being produced, but the 

12 design itself wasn’t patented.

13 MR. HARTLEY: Yeah, DOE has received 

14 different information on this. We do know several 

15 designs that are patented. We’ve not had a chance 

16 to follow up with Mr. Hurst who made that comment 

17 about the designs that aren’t patented.

18 MR. BROOKMAN: Gary Fernstrom.

19 MR. FERNSTROM: Earlier we talked about 

20 wound core using conventional electrical steel as an 

21 option that hadn’t been considered. I hope you will 

22 consider that and see how it fits into this 

23 conclusion.

24 MR. BROOKMAN: Thank you. Do you have a 

25 comment, Jerry? Okay. Yes.
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1 MR. FERNSTROM: And maybe one more thing. 

2 My comment is with respect to low voltage dry type 

3 transformers, because utility ones are wound core 

4 already.

5 MR. HARTLEY: The last slide we have here 

6 is just a request for comment. So DOE requests 

7 comment on the identification of key issues that 

8 were presented on the previous slide, and we also 

9 welcome comment on the supply of core steels that 

10 are used in the analysis, and specifically looking 

11 at grain oriented silicone steel, such as M3 and M2 

12 and as we discussed, amorphous steel.

13 MR. BROOKMAN: Andrew.

14 MR. deLASKI: So just to be clear, in your 

15 prior slide, you identified only one supplier for 

16 amorphous ribbon. Dave commented that there was 

17 another in China now. Are there any patent issues 

18 that you’re aware of in relationship to other 

19 manufacturers entering that market? A question for 

20 Dave, maybe.

21 MR. SCHOEN: Amorphous?

22 MR. deLASKI: Yes.

23 MR. MILLURE: The basic patent was called 

24 planar flow-casting, and that ran out in ’99. So 

25 there are really no patent barriers to entering 
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1 amorphous metal production. It’s just know-how

2 barriers.

3 MR. HARTLEY: What we have heard from 

4 other information sources is that just the process 

5 of developing the material can be very difficult. 

6 It’s been compared to more of an art than a science. 

7 And so we’re aware of other companies who have 

8 attempted to create it and have not achieved a 

9 material that has the same specifications of what 

10 would be considered a Metglas amorphous steel.

11 MR. SAMPAT: Yes, Mahesh Sampat. In that 

12 respect, electrical steel is also an art. Not a lot 

13 of people can make that.

14 PARTICIPANT: I appreciate that, Mahesh.

15 MR. BROOKMAN: Okay, I -- yes. Paul.

16 MR. RYAN: Paul Ryan. My concern with 

17 bullet number two is certain technology options 

18 often require large capital investments. I think 

19 you need to define a large capital investment, 

20 because I’m looking at the technologies that you 

21 list there, and from my understanding and knowledge, 

22 none of those -- well, other than the miter, the 

23 miter does require a large capital investment, but 

24 the other, core -- amorphous core production, 

25 symmetric core technology, I don’t think requires a 
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1 large capital investment. So I think you need to 

2 define what “large” means.

3 MR. HARTLEY: Sure, and at this point, 

4 these are general -- almost by design, this is 

5 really just identifying key issues of which DOE will 

6 hone in in more detail during the next phase of the 

7 rulemaking

8 MR. BROOKMAN: Okay. Let’s press on then.

9 MR. HARTLEY: Okay. At this point, I’ll 

10 invite Greg Rosenquist up to discuss the NOPR 

11 analyses.

12 NOPR Analyses

13 MR. ROSENQUIST: You saw this slide at the 

14 beginning of today’s presentation. It shows all the 

15 different analyses that are done for the NOPR. One 

16 set is the revision to the preliminary analyses, 

17 which are engineering, LCC, and national impact 

18 analysis. This is based on all of your comments and 

19 other stakeholder comments. And then the rest of 

20 these analyses are also performed, which are all 

21 downstream of the NIA.

22 So with regards to the revisions to the 

23 preliminary analysis, as I just said, what DOE does 

24 is it looks at all the comments that are submitted 

25 and determines what those issues are and how they’re 
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1 going to address them. And so based upon how they 

2 determine they’re going to address them, they’ll 

3 revise the engineering analyses, the life cycle cost 

4 and the national impact analyses accordingly.

5 Okay. So the next phase is the life cycle 

6 cost subgroup analysis, and its purpose is to 

7 evaluate impacts to any subset of customers that may 

8 be disproportionately impacted by the standards. 

9 The method is the same approach that’s used for the 

10 overall LCC and payback period analysis, same tools, 

11 same inputs. It’s just analyzed for that smaller 

12 set of customers. The output is the same, which is 

13 just life cycle cost savings and payback periods.

14 For the 2007 analysis, DOE looked at three 

15 subgroups. One were municipal utilities because 

16 they serve more diverse urban loads. Another were 

17 rural electric cooperatives because they serve 

18 smaller loads. And the third were vault installed 

19 transformers because there are space constraints on 

20 those type of transformers, so if a transformer has 

21 to get larger, these types of transformers would 

22 have to incur an additional cost beyond a normal 

23 transformer. 

24 DOE also wants to note that they are 

25 particularly sensitive to how increase in purchase 
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1 price may impact on some subset -- some subgroup of 

2 consumers beyond those just listed.

3 So the next phase is the manufacturer 

4 impact analysis which Matt just went over quickly. 

5 A full blown MIA will be done for the NOPR. 

6 The next analysis is the unit utility 

7 impact analysis, and its purpose is to investigate 

8 the impact of standards on electric utilities, 

9 primarily on electrical sales and installed 

10 generation capacity, and that the mix of that 

11 generation capacity. The method relies on taking 

12 national energy savings results from the national 

13 impact analysis and feeding them into the national 

14 energy modeling system, also called NEMS. NEMS is 

15 used to conduct the forecast for the annual energy 

16 output. 

17 And as I just mentioned, again, the 

18 outputs are electricity sales by region, the mix of 

19 how the installed generation capacity is affected, 

20 and also how that mix of electricity generation 

21 capacity is affected.

22 The next analysis is an employment impact 

23 analysis, and its purpose is to determine how 

24 standards impact national employment. And the model 

25 that’s used is called ImSET, which is a model that 
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1 was developed by PNNL and analyzes 188 different 

2 sectors throughout the economy to see how the impact 

3 on transformer price and operating cost savings 

4 ripple throughout the economy, and resulting in what 

5 type of job loss or gain from that rippling through 

6 the economy.

7 I did want to note that the direct 

8 employment impacts for transformer manufacturers are 

9 analyzed directly in the manufacturer impact 

10 analysis. And again, the output is looking at how 

11 these standards affect overall job employment in the 

12 United States.

13 The next analysis is the environmental 

14 assessment and its purpose is to determine how 

15 standards impact emissions from power plants in the 

16 case of distribution transformers. Again, the 

17 method relies on taking the energy savings results 

18 from the national impact analysis, and inputting 

19 them into NEMS. And the output are estimates of 

20 national emission reductions of CO2, NOX and 

21 mercury. So CO2 is the primary emission reported, 

22 followed by mercury, and followed by NOX, and NOX 

23 are only reported for those 22 states where there 

24 aren’t currently capped on the emission of NOX. 

25 And I just wanted to note that SO2, 
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1 because it’s capped by Clear Air Act amendments, no 

2 physical emissions reductions are being reported for 

3 SO2. 

4 MR. ROSENSTOCK: Question?

5 MR. BROOKMAN: Please, Steve.

6 MR. ROSENSTOCK: Steve Rosenstock, EEI. A 

7 couple weeks ago the EPA announced a rule called the 

8 Utility Mac Rule on utility boiler mercury and 

9 particularly in the matter of emissions. That rule 

10 is going to take effect in 2014. Will that rule be 

11 incorporated into the analysis?

12 MR. ROSENQUIST: Yes, it will because the 

13 AEO of 2011 will incorporate any legislation that’s 

14 on the books in its forecast, so if that is actually 

15 a final rule, then it will be addressed by the AEO.

16 MR. ROSENSTOCK: It’s a final rule. I 

17 don’t know -- are you talking about AEO 2012? 

18 Because wasn’t 2011 published yet?

19 MR. ROSENQUIST: Yes, you’re right, it’ll 

20 be in AEO 2012, not 11, unless 11 tried to forecast 

21 that legislation coming down the pike, but typically 

22 it doesn’t do that.

23 MR. ROSENSTOCK: So for the purposes of 

24 the -- so for the purposes of the decision in 

25 October, can it be accounted for?
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1 MR. ROSENQUIST: We can explore that, 

2 because there have been cases in the past where 

3 legislation has come on the books and the folks over 

4 at EIA have been willing to try to do some 

5 incorporation of those.

6 MR. ROSENSTOCK: Steve Rosenstock. Yeah, 

7 this is a regulation under the Clean Air Act. It’s 

8 not a law, this is a regulation announced by EPA.

9 MR. ROSENQUIST: Yes, it tries to also 

10 account for those sort of final rules that come out 

11 from the regulatory agencies.

12 MR. ROSENSTOCK: Thank you.

13 MR. ROSENQUIST: Okay. The next slide 

14 goes over the fact that DOE is now monitizing 

15 emission of reductions, specifically for carbon and 

16 NOX. For CO2, DOE is now calculating a social cost 

17 to carbon based upon the dollar per ton value to C 

18 here on this slide, and these dollar per ton values 

19 came about from an interagency assessment. So this 

20 is not dealt, necessarily, by DOE alone, but through 

21 government agencies throughout the government.

22 I just also want to note too that NOX is 

23 currently being monitized -- NOX reductions are 

24 currently being monitized by DOE.

25 MR. BROOKMAN: Gary Fernstrom.
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1 MR. FERNSTROM: Question on the prior 

2 slide. I’d like to make sure I understand that. 

3 You saying in states where emissions are capped, 

4 those particular emissions are not considered?

5 MR. ROSENQUIST: That’s right. That's 

6 correct.

7 MR. FERNSTROM: That is -- help ignorant 

8 me to understand that. That is why? Because --

9 wouldn’t -- because presumably there’s no reduction 

10 as a result of these savings? 

11 MR. ROSENQUIST: That’s right. Because 

12 there’s rules in place in the 28 states that are 

13 capped that -- I think it’s more or less modeled, I 

14 think, how the SO2 is dealt with, that is, through 

15 trading and capping. So I don’t have all the 

16 details on that but there have been, I think, an EPA 

17 rule -- I think it’s a clean air interstate rule 

18 that does result in capped emissions in those 28 

19 states.

20 MR. BROOKMAN: The perception is that 

21 they’ll stay the same.

22 MR. FERNSTROM: But it seems to me that if 

23 there is a savings by a reduction in an emission 

24 source, that that would still be a savings, even 

25 though there may be a cap.
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1 MR. BROOKMAN: Phil, do you want to chime 

2 in here?

3 MR. HOPKINSON: Greg, I can’t have any 

4 problem with SOX reduction, NOX reduction, mercury 

5 or methane, but what’s this CO2 stuff? That’s plant 

6 food.

7 MR. ROSENQUIST: It’s a larger issue than 

8 is in this room at the moment. Do you want to --

9 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

10 What the issue is, especially for SO2 under the acid 

11 rain program, there’s been a declining cap the last 

12 20 years. So if you look at the numbers, the amount 

13 of SO2 actually emitted has gone by about 70 percent 

14 over the last 20 years. But since it can be traded, 

15 basically if you save those kilowatt hours in one 

16 area utility, that power pool can trade it with 

17 another area so that there’s no physical reduction 

18 just because it can be either traded or it allows 

19 the plant to transfer it to somewhere else.

20 MR. FERNSTROM: Well, if it’s a national 

21 standard, I guess it could be traded to some area 

22 that doesn’t have a cap? Is that it?

23 MR. ROSENQUIST: No, it’s a matter of 

24 basically saying that -- again, if the amount was 

25 ten last year and it’s five this year, and someone 
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1 else is at three and two, and the person gets down 

2 to two, they can sell it to someone else and they’ll 

3 go up to three if they want to. It’s still at five, 

4 regardless of what happens to the end use. What 

5 happens at the power plant is going to basically 

6 stay the same because of the cap. I hope I kind of 

7 -- that’s kind of in general what the theory is 

8 behind what’s happening with their saying it’s not 

9 going to have an impact on the power plant 

10 emissions.

11 MR. FERNSTROM: So emissions resulting 

12 from the federal standards can be sold by those who 

13 comply with the standards? That -- I don’t 

14 understand this. Presumably it all makes sense, but 

15 -- thank you.

16 MR. BROOKMAN: Do you understand the SO2 

17 stuff? 

18 MR. FERNSTROM: No.

19 MR. BROOKMAN: No, you don’t. That’s a 

20 cap and trade thing.

21 MS. COUGHLIN: If I can just make a 

22 clarifying comment? This is Katie Coughlin from 

23 LBL. The standard will lower the cost of complying 

24 with the cap, that’s the general expected economic 

25 impact of the standard, but it will not change total 
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1 emissions under the cap.

2 MR. BROOKMAN: Robert.

3 MR. BERMAN: Robert Berman, Berman 

4 Economics. That statement is exactly right. The 

5 other piece of that too, or to extend on that, is 

6 that to the extent that you are doing your analysis 

7 on a transformer level, then those benefits should 

8 be attributed to the particular transformer and 

9 standard that’s responsible for the reduction.

10 MR. BROOKMAN: Okay. And then Greg, you 

11 have another slide or two?

12 MR. ROSENQUIST: Okay, which comes to our 

13 next issue which speaks to how to value the carbon -

14 - CO2 and NOX emissions savings from the standard. 

15 Basically, DOE is inviting comment on the values 

16 that it plans to use for doing this monitization.

17 MR. BROOKMAN: Steve Rosenstock.

18 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

19 You’re asking about energy security related 

20 externalities? I don’t know if I’ve seen that in 

21 other rulemakings. Is that -- are you -- is that in 

22 terms of imported oil or imported other fuels or 

23 imported materials? I guess I’m not sure how DOE is 

24 going to talk about energy security in the context 

25 of this rulemaking.
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1 MR. ROSENQUIST: Well, to the extent that 

2 can be quantified in the price of carbon, then it 

3 will be, but if it can’t be, then -- then it won’t.

4 MR. BROOKMAN: Does that phrase, “energy 

5 security related externalities,” does it relate to 

6 the emissions listed in 140?

7 MR. ROSENQUIST: Not necessarily. I mean, 

8 again, when we talked about energy security 

9 externalities it’s different than the externalities 

10 associated with the carbon savings. 

11 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

12 Thank you. That energy security is a totally 

13 different issue than emissions.

14 MR. ROSENQUIST: Right. So currently, 

15 current DOE rules that, to my knowledge, is not 

16 being captured.

17 MR. BROOKMAN: Jerry. Get the microphone, 

18 Jerry.

19 MR. ALLEN: I’m wondering in this whole 

20 thing, you talk about the social cost of carbon. 

21 Aren’t you really just saying that there’s a social 

22 cost of, let’s say sulfur dioxide. It’s not money 

23 that the utility could get, but it’s whether it 

24 would -- agricultural productivity loss, human 

25 health effects, et cetera. Since those aren’t 
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1 changing since there’s already a cap, you’re not 

2 considering them, and that’s really what the logic 

3 is?

4 MR. ROSENQUIST: There’s no cap on carbon.

5 MR. ALLEN: No, there’s no cap on carbon, 

6 but I’m saying you’re considering social cost of all 

7 these things.

8 MR. ROSENQUIST: There isn’t a market 

9 price for CO2 right now in the US, at least not 

10 nationwide, so that’s the reason it’s being called 

11 social cost to carbon.

12 MR. ALLEN: Yeah, but what I’m saying is 

13 if you’re considering, let’s say on sulfur dioxide, 

14 you’re considering that a social cost, then if it’s 

15 capped and it’s not going to get any lower because 

16 of what you do, then you don’t count it. Isn’t that 

17 the logic behind what they’re doing? Isn’t that it? 

18 It’s social cost, not what it saves the utility by 

19 trading the money to somebody else.

20 MR. BROOKMAN: Steve Rosenstock.

21 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

22 With SO2 or NOX, those aren’t social costs. Those 

23 are estimated market cost based on the trading on 

24 the market place. The carbon is a -- it’s also, 

25 with SO2 and NOX, DOE is looking domestically. 
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1 Social cost is a “global cost” and they’re taking it 

2 out to the year 2300 and trying to do a present 

3 value of that.

4 MR. BROOKMAN: We have one more slide to 

5 cover.

6 MR. ROSENQUIST: The last step in the NOPR 

7 analyses is what’s called the regulatory impact 

8 analysis, and its purpose is to investigate 

9 alternatives to mandatory standards, that is, non10 regulatory alternatives to standards. And these can 

11 include things like manufacturer tax credits, 

12 consumer tax credits, rebates, all government 

13 purchase programs, early replacement programs, 

14 things of that like.

15 The method is to make modifications to the 

16 spreadsheet that’s developed for the national impact 

17 analysis and make changes to key inputs, 

18 specifically, how equipment efficiency is changed by 

19 these different non-regulatory alternatives.

20 And the output is very similar to the 

21 national impact analysis. It provides both national 

22 energy savings and net present value due to each one 

23 of these alternatives.

24 MR. BROOKMAN: Comments on that 

25 description of regulatory impact analysis? That was 
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1 your final slide? Thank you, Greg. 

2 I think that we had really excellent 

3 presentations today, so I think maybe we should 

4 actually do a round of applause. We seldom do that.

5 (Applause.)

6 MR. BROOKMAN: Well done. That was pretty 

7 complicated stuff. 

8 Closing Remarks

9 MR. BROOKMAN: Now is an opportunity for 

10 anybody that wishes to do so, to make a closing 

11 remark, brief summary remarks about things that have 

12 not yet been covered sufficiently.

13 Okay, so then -- yes, please. Say your 

14 name again.

15 MR. STAHARA: Ron Stahara, Central 

16 Moloney. We’re a manufacturer of liquid filled 

17 transformers. One thing that we didn’t address --

18 we kind of addressed the issues relative to weight 

19 and dimensions and possibly impedances. One thing 

20 that as a product line that we did not address is 

21 vaults or submersible type transformers. There are 

22 existing vaults that they have to go in, whether 

23 they be round or rectangular, whatever shape, and 

24 that would be my concern of any increase in 

25 efficiency.
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1 I think there are some limitations now 

2 with where we’re at with the efficiencies to meet 

3 existing dimensional requirements for submersible 

4 type transformers. And that’s something that would 

5 be of concern.

6 MR. BROOKMAN: Okay. Ned spoke with me at 

7 lunch, he had a few other issues he wished to raise. 

8 Please.

9 MR. BRUSH: Ned Brush. Just very quickly, 

10 I’d like to suggest that DOE look into and perhaps 

11 evaluate going to much larger sizes of transformers, 

12 because to sort of resolve the conflict here that 

13 Mahesh suggested for the current covered range of 

14 kVA sizes, many people that I’ve talked with among 

15 the utilities, and I’ve attended most of the 

16 electric transformer meetings and so on, say, well 

17 yes, we’re buying to DOE. Well, the DOE standards 

18 translates, if Phil is still here, to about an A 

19 value of roughly $4.00 as I recall, $4.00 plus or 

20 minus, and B of $1.00, $1.10, something like that. 

21 Well, a number of these utilities say they have been 

22 buying to that standard.

23 Well, if you were to increase this up to 

24 perhaps, I think the suggestion is 10 MVA -- I saw 

25 some of that in writing -- but even going up to 30, 
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1 you then cover the substation transformers, which 

2 are part of the distribution system in the sense 

3 that you’re dropping from overhead transmission 

4 levels down to maybe 13-8 for distribution, or 

5 something like that. 

6 But anyway, there are perhaps from the 

7 2500 kVA up to 30 MVA, you’re talking about maybe 

8 7000 units a year, and there are huge disparities 

9 here because some of these customers, some of these 

10 utilities are actually buying to lowest first cost, 

11 which in that range, not covered by DOE -- I mean 

12 they say they’re buying to DOE, but some of them are 

13 buying them closer to zero-zero for those much 

14 larger units. They’re heavier loaded than these 

15 units that are currently covered but are further 

16 down the distribution system, closer to the 

17 customer.

18 However, there is some good news on this 

19 also. Because I spoke with three different 

20 utilities that are actually buying to DOE plus, 

21 which is what Mahesh was referring to here, and 

22 they’re actually buying to A values that are between 

23 six and eight dollars. For the DOE covered units, 

24 some of those same utilities, however, are buying 

25 the larger units, which are typically substation 
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1 size and so on, to things like $1.80, $3.20 and so 

2 on. In other words, values for A that are below the 

3 values of the currently covered units that are up 

4 through 2500 kVA.

5 So I’d just like to suggest that that be 

6 looked at and perhaps expand the definition of what 

7 you are covering so that some utility that says, 

8 yes, we’re buying to DOE or DOE plus, they in fact 

9 are doing that, because the national energy savings 

10 for the heavily loaded units there could be much 

11 larger at the 7000 or so units a year in that 

12 category. Very substantial.

13 MR. BROOKMAN: Okay. Thanks, Ned. 

14 Additional comments? Yes, Jerry.

15 MR. SCHOEN: Jerry Schoen, AK Steel. In 

16 the assessment of emission reductions, the wording 

17 that I see in here is all focused on carbon, which 

18 is an implication that those plants are going to be 

19 coal fired. If -- when coal costs $1.67 per million 

20 BTUs, methane costs about three times that, and my 

21 suspicion would be most of the plants that would be 

22 brought up and down would be gas fired, as opposed 

23 to coal fired. And is that calculation -- is this 

24 calculation going to look at what plants would be 

25 handling the -- what’s the right word -- over base 
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1 load?

2 MR. BROOKMAN: So the contractor crews are 

3 nodding their heads saying “yes.” For the record. 

4 Gary Fernstrom.

5 MR. FERNSTROM: That’s true for the I6 squared R coil losses, but the core losses are base 

7 loaded.

8 MR. BROOKMAN: Let’s let Robert go first.

9 MR. BERMAN: Robert Berman, Berman 

10 Economics. Core losses are not base load. Core 

11 losses are basically the loss associated with the 

12 plant that could be taken off line, the savings is 

13 the power. Currently it’s likely to be an older 

14 plant. It’s going to have the highest cost. It’s 

15 going to have a cost much higher than the average 

16 fuel cost. It’s going to have a cost higher than 

17 what’s reflected in the A values, as a matter of 

18 fact. But no, it is very definitely not the base 

19 load.

20 MR. FERNSTROM: Well, maybe I’m 

21 misunderstanding something. I thought that these 

22 transformers, when they were connected to the grid 

23 continuously incurred magnetic hysteresis losses 

24 and that’s what we’re talking about here, and that 

25 would be base load because --
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1 MR. BERMAN: No, excuse me. You are 

2 correct that they continually incur those losses, 

3 but those losses have different values at different 

4 times. The base load is there all the time, but 

5 that base load will never be taken down if you 

6 reduce the demand. The unit that is taken down when 

7 you reduce the demand is the high cost unit, not the 

8 low cost unit. It’s the last unit that’s dispatched 

9 that’s taken down. 

10 MR. SCHOEN: If I may, they would look at 

11 that from a standpoint of what does it cost me in 

12 terms of fuel to generate that last amp of 

13 electricity? Typically, that highest cost unit 

14 would be solar or natural gas. Coal, nuclear power 

15 plants, the wind ... and hydros are running 

16 continuously.

17 MR. BROOKMAN: Steve Rosenstock. 

18 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

19 And in terms of some of this, you have to remember 

20 that there’s over 30 states that have renewable 

21 portfolio standards, and certain states, like Texas, 

22 six years ago wind comprised about one and a half 

23 percent of the electricity produced in the ERCOT 

24 (ph) area. In 2010, that was eight percent. There 

25 were times in Texas when wind was 20, 25 percent of 
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1 the generation in Texas. So -- in other areas, 

2 obviously. There’s certain areas in California, 

3 they’re putting in a bunch of solar, so and 

4 sometimes part of that peak load will be solar or 

5 wind, and if you’re looking at emissions, there is 

6 no impact on emissions with those power plants being 

7 part of the peak mix, or base load mix, depending on 

8 -- especially for wind, especially, typically 

9 operates at the highest load at night.

10 MR. FERNSTROM: Okay. So I think our 

11 confusion stems from what’s meant by base load, and 

12 the point I want to have everyone agree on is these 

13 core losses occur continuously.

14 MR. BROOKMAN: Okay. Thank you. Andrew 

15 deLaski.

16 MR. deLASKI: I just want to follow on the 

17 comment made by the gentleman from Central Moloney 

18 about vault transformers. This was discussed a 

19 great deal on the docket in 2007, there was a lot of 

20 discussion to it. I think there was some discussion 

21 about some transformers that aren’t covered by the 

22 proceeding and some that are. 

23 I think it’s a valid issue. It should be 

24 looked at. I’d also want to recognize that I would 

25 say utilities that serve some of the densest urban 
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1 neighborhoods in the country, ultimately supported 

2 the CSL -- or TSL4 last docket, were comfortable 

3 with that, despite the impacts on size.

4 Working at higher levels now, that implies 

5 other changes, but the Department has to be very 

6 careful in analyzing this issue because of -- it is 

7 a complicated issue because it involves vault size 

8 and the step ups that are involved. When you 

9 actually trigger those costs, one that deserves 

10 consideration, but it needs to be looked at very 

11 carefully.

12 MR. BROOKMAN: John.

13 MR. PHOUMINH: Thank you. I’d like to 

14 compliment Central Moloney for bringing up the 

15 issue. Pepco, especially in this area, we serve in 

16 this building too, maybe outside of this building, 

17 we have a vault outside in the public space, and 

18 those vault is limited, typically 6 × 14, 6 × 18. 

19 If you were to increase the unit efficiency, that 

20 could be higher, that could be larger, could be 

21 longer, could be wider, and if we have to replace 

22 the units, if they fail for some reason, or maybe 

23 time to change out when it reaches its useful life, 

24 we have a problem, big time.
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1 MR. BROOKMAN: Got you, understand. Okay. 

2 These final comments, I think, have been interesting 

3 and useful. Additional final comments before I turn 

4 it back to Jim Raba for is closing remarks. Steve 

5 Rosenstock.

6 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

7 Just one thing. I think, especially with the -- I 

8 think there were new participants which I’m always 

9 happy to see. It might be helpful, especially with 

10 a lot of the information that DOE is asking for, to 

have a comment period that’s later than April 18th 11 . 

12 Thank you.

13 MR. BROOKMAN: Okay. Thank you. Jim 

14 Raba, it’s back to you.

15 MR. RABA: Well, I think we all agree that 

16 today’s been most productive from the Department’s 

17 point of view. Certainly the participation of 

18 yourselves, coming this way to be present, and those 

19 in our webinar, again, thank you for being with us 

20 today. A special appreciation to facilitator Doug 

21 Brookman, webinar operator Hoi Yee.

22 (Applause.)

23 MR. RABA: Our transcriber in the 

24 background here, and our presenters, and those 

25 behind the scenes whom you didn’t see worked very 
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1 hard to support the presenters too. 

2 So on behalf of the Department of Energy, 

3 I appreciate your being here so much. 

4 We now move on to the next phase, 

5 rulemaking process, which will either be a 

6 determination that standards for distribution 

7 transformers need not be amended, or a Notice of 

8 Proposed Rulemaking to amend those standards, based 

9 upon your comments and input, data and information 

10 which you see where to send and when it’s due. 

11 Thank you very much, the Department of Energy 

12 appreciates all. You deserve a round of applause 

13 again. Thank you.

14 (Applause.)

15 (Whereupon, at 4:30 p.m., the meeting in 

16 the above captioned matter was adjourned.)