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UNITED STATES OF AMERICA

DEPARTMENT OF ENERGY 

MEETING of the MV WORKING GROUP

Volume I

National Rural Electric Cooperative Association

4301 Wilson Blvd, Rm. C2

Arlington, VA

Wednesday

October 12, 2011

Facilitator:

Richard Parker

University of Connecticut Law School

Host:

National Rural Electric Cooperative Association 

(NRECA)
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Participants Identified: 

Rick Anderson

Fayetteville Public Works Commission

Tim Ballo

Earth Justice

1625 Massachusetts Avenue

Suite 702

Washington, DC 20036

Scott Beck

Lakeview Metals

Robert Berman

Berman Economics

1915 Orchid Court

Vienna, VA 22187

John Caskey 

Electrical Manufacturers Association

Greg Coulter

Consultant 

Prolec GE

Jim Creevy

National Electrical Manufacturers Association

1300 North 17th

Suite 1752

Street

Rosslyn, VA 22209

Andrew deLaski

ASAP

20 Belgrade Ave, Suite 1

Boston, MA 02131

Tom Eckman

Northwest Power and Conservation Council

Gary Fernstrom

Pacific Gas & Electric Company

13055 Parkhurst Dr

Oakland, CA 94619
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Chuck Foster

Edison Electric Institute

Carlos Gaytan

Prolec GE

Bruce Hirsch

Baltimore Gas and Electric

Gerald Hodge

Howard Industries

PO Box 1586 

Laurel, MS 39441

Philip Hopkinson

HVolt, Inc.

3704 High Ridge Rd.

Charlotte, NC 28270

Mike Hyland

American Public Power Association

Aaron Meyers

Cooper Power Systems 

Dave Millure

Metglas Incorporated

440 Allied Drive

Conway, SC 29526

Jim Murkowski

Allegheny Ludlum ATI

Steve Nadel

American Council for an Energy-Efficient Economy

Wes Patterson

ABB, Inc.

Eric Petersen 

AK Steel

Ray Polinski 

Allegheny Ludlum - ATI
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Steven Rosenstock

Edison Electric Institute

701 Pennsylvania Avenue NW

Washington, DC 20004-2696

Robin Roy

Natural Resources Defense Council

1200 New York Avenue, NW, Suite 400

Washington, DC 20005

Paul Ryan

Hitachi Metals America

800 Grand Avenue, Suite AG-6

Carlsbad, CA 92008

Bob Saint 

National Rural Electric Cooperative Association

Mahesh P. Sampat

EMS Consulting

1180 Brookview Dr

Athens, GA 30606

Jerry Schoen

AK Steel Corporation

705 Curtis Street

Middletown, OH 45043

Chuck Simmons

Progress Energy

Bob Smith

Federal Pacific

Jim Rakowski 

Allegheny ATI

Ken Winder

NRECA

Participants from DOE:

John Cymbalsky

DOE
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Participants from Navigant/LBL:

Brian Coffey

Navigant

Mike Rivest

Navigant

Rob Carmichael

Navigant

Matt Nardotti

Navigant Consulting

Chris Bolduc

Lawrence Berkley National Laboratory

Katie Coughlin

Lawrence Berkley National Laboratory

Presenters:

Brian Coffey

Navigant Consulting

1801 K St. NW

Suite 500

Washington, DC 20006

Chris Bolduc

Lawrence Berkley National Laboratory

1 Cyclotron Rd

Ms 90-4000

Berkeley, CA 94720

Washington, DC 20006
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AGENDA

 ITEM PAGE

Welcome, Mr. Parker 7

Self-Introductions 8

Agenda Review 13

Finalization of Rules of Procedure 92

Navigant Presentation, Mr. Coffey 21

Data Requests 22

Request to Changes to Analysis 42

Scaling Approaches 97

Review of Open Ended Questions 126

Next Steps 128

LBL Presentation, Mr. Bolduc 135

Transformer Loading 135

Transformer Lifetime 154

Base Constraint Installations 162

Pole Replacement 185

Rural Cooperatives 199

Equipment Price Trends 209

Electricity Prices 229

Evaluation Rates 229

Final Topics 246

Presentation, Mr. Hopkinson 261
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1 9:13 a.m.

3

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

4 MR. PARKER: Welcome everyone to our 

5 second meeting of the Medium Voltage Transformer 

6 Group. Sorry for the late start, we had a few 

7 technical difficulties caused by my pushing the 

8 wrong button on this polycom. But I think we have 

9 everybody back on the line now.

10 First I want to thank Bob Saint and the 

11 National Rural Electric Cooperative Association for 

12 hosting us here today in this beautiful conference 

13 room. It’s really a great help, not only having the 

14 conference room, but having the coffee and the 

15 refreshments beforehand, a nice set-up, so I thank 

16 you for that.

17 I also want to thank the DOE team over 

18 there, who worked hard to put this thing together 

19 for us, Jeremiah, Tatiana, and others, and John 

20 Cymbalsky who is going to be here, worked very hard 

21 during this set-up process to give us the technical 

22 capacity we need to get this on the record.

23 Also thanks to Navigant and to LBL staff 

24 who have been deluged with information from you all, 

25 and comments, and analysis, and so forth, and who 
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1 have been working around the clock to try to take 

2 all of that on board, and we’ll be talking a lot 

3 more about their analysis as we go on today. 

4 We’ve got a lot to cover. Let’s get right 

5 into it. Why don’t we go around the table first and 

6 everybody introduce themselves for the record for 

7 the court reporter. Then we’ll go around the back 

8 and then we’ll have introductions from people on the 

9 phone, and then we’ll get right into our agenda 

10 which I will pass out as we do our introductions and 

11 put on the screen.

12 Self-introductions

13 MR. PARKER: Richard Parker, University of 

14 Connecticut Law School.

15 MR. COFFEY: Brian Coffey, Navigant.

16 MR. SMITH: Bob Smith, Federal Pacific. 

17 Some of our comments we’re going to ask support Bill 

18 Hopkinson with everyone’s permission.

19 MR. HYLAND: Mike Hyland, American Public 

20 Power Association.

21 MR. SAINT: And I’m Bob Saint with the 

22 National Rural Electric Cooperative Association.

23 MR. ROSENSTOCK: Steve Rosenstock, Edison 

24 Electric Institute.

25 MR. HIRSCH: Bruce Hirsch, Baltimore Gas 
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1 and Electric.

2 MR. ANDERSON: Rick Anderson, Fayetteville 

3 Public Works Commission.

4 MR. SIMMONS: Progress Energy.

5 MR. FERNSTROM: I’m Gary Fernstrom from 

6 the Pacific Gas and Electric Company, representing 

7 the California investor-owned utilities, PG&E, the 

8 Southern California Edison Company, and Semper 

9 Utilities.

10 MR. BECK: Scott Beck, Lakeview Metals.

11 MR. PATTERSON: Wes Patterson, ABB, Inc.

12 MR. HODGE: Gerry Hodge from Howard 

13 Industry.

14 MR. POLINSKI: Ray Polinski from Allegheny 

15 Ludlum - ATI. Also with me is Jim Murkowski from 

16 Allegheny ATI, behind me, who will introduce 

17 himself, and also similarly, Phil Hopkinson is 

18 supporting us with some data and analysis as well. 

19 Thank you.

20 MR. BALLO: Tim Ballo with Earth Justice.

21 MR. CASKEY: John Caskey with Electrical 

22 Manufacturers Association.

23 MR. ECKMAN: Tom Eckman, Northwest Power 

24 and Conservation Council.

25 MR. MEYERS: Aaron Meyers, Cooper Power 
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1 Systems and similar to Bob and Ray, we have also 

2 Phil Hopkinson here representing us.

3 MR. PETERSEN: I’M Eric Petersen with AK 

4 Steel. Joining me shortly will be Jerry Schoen, 

5 also of AK Steel. His flight was delayed this 

6 morning. Also with AK Steel is, as well as several 

7 others, is Phil Hopkinson.

8 MR. PARKER: Excuse me just a second, 

9 Carlos. I understand the court reporter is having a 

10 bit of a hard time picking up the names, so please 

11 be sure you turn on your mic before you speak, and 

12 then turn it off at the end. I’m told that we only 

13 can have eight mics on at a time, so I have a cancel 

14 button which will turn off mics, but please help me 

15 with that so that we can -- and I guess for the 

16 people around the room, if you’ll just announce --

17 do we have a mic by the way for -- yes, so Jeremiah 

18 will carry the mic around so people can announce 

19 themselves around the wall as we go forward. So 

20 Jim, if you could do that when we get to that stage. 

21 Thanks. Go ahead, Carlos, sorry.

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

23 MR. MILLURE: David Millure, Metglas, 

24 Incorporated, joined by Paul Ryan from Hitachi 

25 Metals America and Robert Berman of Berman 
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1 Economics.

2 MR. ROY: Robin Roy, National Resources 

3 Defense Council.

4 MR. CYMBALSKY: John Cymbalsky, DOE.

5 MR. PARKER: Here around the table.

6 MR. RIVEST: Mike Rivest, Navigant 

7 Consulting.

8 MR. HOPKINSON: Phil Hopkinson, HVolt, 

9 Inc.

10 MR. COULTER: Greg Coulter, I’m a 

11 consultant supporting Prolec GE.

12 MR. CREEVY: Jim Creevy, National

13 Electrical Manufacturers Association.

14 MR. MURKOWSKI: Jim Murkowski, Allegheny 

15 Ludlum ATI.

16 MR. WINDER: Ken Winder, NRECA.

17 MR. FOSTER: Chuck Foster, representing 

18 Edison Electric Institute.

19 MR. BERMAN: Robert Berman, Berman 

20 Economics.

21 MR. RYAN: Paul Ryan, Hitachi Metals 

22 America, Metglas.

23 MR. CARMICHAEL: Rob Carmichael, Navigant 

24 Consulting.

25 MR. NARDOTTI: Matt Nardotti, Navigant 
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1 Consulting.

2 MS. COUGHLIN: Katie Coughlin, Lawrence 

3 Berkley National Laboratory.

4 MR. BOLDUC: Chris Bolduc, Lawrence 

5 Berkley National Laboratory.

6 MR. PARKER: Okay. That’s the people in 

7 the room. Why don’t we turn it over to the people 

8 on the phone. If you could chime in, let us know 

9 who you are. Anyone on the phone? Oh, they can’t 

10 talk at this time? Okay. 

11 My apologies. Apparently, the way it’s 

12 set up this time is that people on the phone will be 

13 e-mailing in to the webinar interface to Tatiana who 

14 will get your comments and relay them to me, or 

15 questions, and I will put them on the record. This 

16 is to try to avoid the confusion we had last time 

17 with phones ringing in the background and so forth, 

18 that proved to be quite disruptive for the meeting. 

19 So we will make sure that we get a record for the 

20 record, of the people who are on the phone so that 

21 people know who was there. 

22 But I just want to express my welcome to 

23 people on the phone and encourage you to send your 

24 comments, questions, if you have them, to Tatiana, 

25 and we’ll make sure that they get aired.
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1 So, thanks very much. Why don’t we get 

2 started. I have passing around -- I’m just passing 

3 around a sort of a draft agenda. 

4 Agenda Review

5 I apologize for the delay in getting this 

6 to you, which basically -- basically, what I’ve 

7 tried to do with this agenda -- we’ll try to get it 

8 on the screen here for the people joining in by 

9 webinar. What I’ve tried to do is just gather 

10 together what I think, working backwards from our 

11 deadlines, would be an ideal outcome for this 

12 meeting. I’m not sure we will achieve it all, but I 

13 think we should try. And it reflects the fact that 

14 a lot of new data, new information, new analytical 

15 concerns have been surfaced since the last meeting. 

16 I’ve been really impressed by the outpouring of 

17 interest and participation on line through the e18 mail interface, really engaging the issues in a 

19 substantive way. And I know that many of you have 

20 had conversations with Navigant and LBL staff about 

21 a wide variety of things that we’re just going to 

22 try to work through those issues in this meeting.

23 We do need to find a balance between, you 

24 know, doing more and more analysis and getting down 

25 to the business of actually negotiating the terms of 
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1 a proposed rule. And so these goals for the meeting 

2 sort of represent my first take as to what would be 

3 a desirable outcome. I think we do need to try to 

4 move beyond the analysis as soon as we can, I mean 

5 beyond methodological issues and the analysis as 

6 soon as we can, and actually get down to the 

7 business of talking about standards and what people 

8 can do.

9 At the same time, analysis is very 

10 important and we have a group of people around here 

11 who are expert and who take facts seriously, and who 

12 want to make sure that this is solidly grounded, and 

13 so we’re committed, I know the Department’s 

14 committed and the consultants are committed to 

15 giving you the best possible empirical foundation 

16 for your work.

17 So what I would propose, subject to your 

18 comments and thoughts, for this meeting, and our 

19 first item on the agenda is to agree on an agenda 

20 for this meeting, is that we basically use today to 

21 hear presentations from Navigant and LBL about their 

22 respective analysis of the engineering data and the 

23 LCC issues and manufacturing impacts, have a full 

24 discussion of those issues, and try to arrive by the 

25 end of tomorrow, by noon tomorrow, with a specific 
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1 charge to Navigant and LBL about what are the top 

2 priority issues that require further analysis or 

3 tweaks to the analysis and modifications of the 

4 analysis. What are the issues that really matter? 

5 We’re not going to have perfection here. There’s 

6 always -- you know, you can always, with infinite 

7 time and infinite resources, you can always have 

8 better and better analysis, but we have to find a 

9 balance between resources and time on the one hand, 

10 and real data needs on the other.

11 So the goal of this group and the goal of 

12 the meeting, I think, should be to really set 

13 priorities, clear priorities, and -- for what needs 

14 to be done to the analysis to give us the foundation 

15 we need for fruitful negotiations going forward. 

16 And I’ll just encourage Navigant and LBL 

17 to be frank and pushing back with regard to either 

18 timelines, or with regard to possibilities, you 

19 know, what can be done within the existing 

20 constraints and existing timelines. And what is the 

21 best way of dealing with any uncertainties that are 

22 there.

23 The other thing that has come up that many 

24 people have surfaced, both at the last meeting and 

25 in the e-mails that followed, was a concern about 
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1 the impact -- about manufacturing impacts. What is 

2 going to be the impact of various efficiency levels 

3 on steel supplies, on competitiveness in the steel 

4 market, on availability of steel. So I spoke with 

5 Eric Petersen, AK Steel, a couple of days ago, and 

6 he’s kindly agreed to give us -- to walk us through 

7 their presentation of those issues. So I thought it 

8 would be good to schedule that at some point.

9 And then, and really focus on that and try 

10 to get a sense of this recurring problem, you know, 

11 what are going to be the impacts. So we’ll have a 

12 discussion between the way AK Steel is coming at it 

13 and see if there are discrepancies between AK 

14 Steel’s analysis and Navigant-LBL analysis that 

15 needs to be discussed.

Again, I’m not sure that November 2nd 16 is 

17 the -- is totally achievable. I understand from our 

18 consultants that there may be some difficulties 

19 achieving, you know, finalizing the analysis by 

November 2nd 20 , particularly for the medium voltage and 

21 dry type, and low voltage transformers. Mike Rivest 

22 told me that he woke up this morning to new data 

23 coming in from manufacturers. There has not been a 

24 robust discussion or supply of data, apparently, for 

25 those particular product lines. The liquid immersed 
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1 is much further along, I understand, than medium 

2 voltage dry and low voltage.

3 So what I’d like to do I think at some 

4 point is just have Mike talk about, if you would, 

5 what -- put that in perspective and give us his 

6 thoughts on what is a reasonable timeline for 

7 getting revised engineering results to LBL for that. 

8 Does that sound feasible to you, Mike? I’ll just 

9 turn the mic over to you at some point in the 

10 conversation, and you talk about those concerns as 

11 they come up.

12 So, with that in mind, I propose that we 

13 put this out there. Any thoughts on this plan of 

14 action for the next day and a half? I just open the 

15 mics to you on that. By the way, I’m having a 

16 little -- I can’t -- my line of vision is a little 

17 bit constrained here. I’ll try to keep my eye on 

18 this side of the table, but either John or -- if 

19 John’s not available, Jeremiah behind will let me 

20 know if I’m not seeing your hand, and my apologies 

21 in advance if I miss. Yes. 

22 Jeremiah, you’re going to have to take the 

23 mic -- everybody’s going to have to speak into a mic 

24 for the court reporter.

25 MR. HOPKINSON: Thank you very much, 
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1 Richard, and it’s wonderful to meet you here today, 

2 finally. And my question is when comments are made, 

3 and I’m sure they will be, from people around the 

4 room, do you want disagreements to be voiced at the 

5 time, or do you want to have written comments sent 

6 in?

7 MR. PARKER: I think within reason it 

8 would be good to have --

9 MR. HOPKINSON: Oh, Phil Hopkinson.

10 MR. PARKER: I think it would be good to 

11 have, you know, within reason, express them at the 

12 time, and I will try to keep an eye on the clock and 

13 make sure that the discussion doesn’t get bogged 

14 down. That would be my job which I would try to 

15 execute. Mike.

16 MR. RIVEST: This is Mike Rivest, 

17 Navigant. Phil, I think the format we have in mind 

18 is much more workshop-like where, you know, problem 

19 solving, so this is not presentation and comment in 

20 writing, this is much more, here are the issues, can 

21 we work together to come up with solutions.

22 MR. PARKER: Any other comments around the 

23 table? Steve Rosenstock.

24 MR. ROSENSTOCK: Hi, Steve Rosenstock, 

25 EEI. You have an item that says Stakeholder 
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1 Presentations. Are there some PowerPoint slides or 

2 graphs that are going to be made available? I know 

3 there were a lot of reports flying around the last 

4 couple days via e-mail, but I didn’t know if there 

5 was separate presentations that were going to be for 

6 the engineering analysis?

7 MR. PARKER: Yes, I thought we would have 

8 -- start off with Brian Coffey from Navigant who’s 

9 sitting next to me here, who will present on the 

10 engineering analysis, and he has a little agenda 

11 that he’s put together which I will pass out and 

12 post on the -- Ron you have that on your screen for 

13 the webinar. And I have paper copies here for the 

14 people at the table when we get to that stage, we’ll 

15 pass it around. So, yes, there will be 

16 presentations that will -- and basically, the idea 

17 is just to provide a framework for discussion. It’s 

18 not a one-way street. Yes, Bob.

19 MR. SMITH: Richard, thank you. Bob Smith 

20 from Federal Pacific. The thing that Rob Greeson 

21 and I have been working on, and with Navigant in 

22 particular, as well as LBS is trying to reconcile 

23 the differences that we are seeing with the medium 

24 voltage design lines nine through 13. And with due 

25 respect, to try to meet the deadline, we are very 
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1 desirous of trying to get reconciliation with their 

2 method of calculating the designs and the way that 

3 we, as a manufacturer, would calculate the designs. 

4 Once we get to that point, we’re ready to go as fast 

5 and furiously as possible.

6 MR. PARKER: Great. Thanks, Bob, and I 

7 understand that Brian and others will be presenting 

8 an approach to dealing with that as we go forward. 

9 And I just want to express my cordial welcome to 

10 Phil Hopkinson. I’m glad he could be with us here 

11 today and that we worked out the issues that allowed 

12 him to participate in our discussions, and 

13 appreciate his good work. So, yes, that’s 

14 definitely on the agenda for today.

15 MR. BOLDUC: Chris Bolduc, LBL. If the 

16 committee would like, this afternoon, after the 

17 presentations, we would be willing to walk through 

18 the LCC analysis for clarity -- sorry, spreadsheet -

19 - to add clarity and answer questions as we go.

20 MR. PARKER: Right. We’ll try to move as 

21 quickly as we can. If we get to the engineering 

22 analysis early, you know, we will leave at least an 

23 hour and a half, and more, for the LBL analysis in 

24 late morning or afternoon. That’s on the agenda. 

25 Anything else? Seem like a reasonable way to 
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1 proceed? Any disagreement? Okay. 

2 Let’s just get started with the 

3 presentation, then. We have here -- I’m just 

4 passing around a sheet that contains the -- this is 

5 just basically a list of -- what I’m passing around 

6 is basically a list of the issues that Navigant 

7 staff identified from the very extensive -- both 

8 from the comments that came in on the previous 

9 meeting, and the very extensive e-mail traffic that 

10 followed it. What they’ve done, which I think is 

11 very helpful, is try to distill all of that 

12 discussion into categories, group it together into 

13 the logical categories, pick out the common 

14 elements, and Brian, I think, is just going to lead 

15 us through the Navigant response to the various 

16 concerns that have been raised, and I understand 

17 he’s got some creative ideas for dealing with these 

18 concerns that he’s worked out with DOE and Navigant 

19 staff. So, with that in mind, let me turn it over 

20 to Brian Coffey of Navigant. Thank you.

21 Navigant Presentation

22 MR. COFFEY: Thank you, Richard, and 

23 welcome everybody to the second negotiating session 

24 of the medium voltage group. Just to refresh 

25 everybody’s memory, in the first session both 
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1 Navigant and LBL gave overviews of their analyses as 

2 they stood currently, and then we had a period for 

3 feedback from the negotiating parties. In that 

4 period came a lot of different types of suggestions 

5 and questions and requests for data, and so I’ve --

6 we spent the interim trying to slice and dice and 

7 group all that and sniff out what were the most 

8 important things to be spending our time looking at, 

9 and then think of ways to answer those questions, 

10 provide those data, and solve those problems.

11 In this presentation, I’m going to walk 

12 through, as Richard said, some of those proposed 

13 responses, and hopefully get feedback from the 

14 committee about whether that makes sense.

15 Here are kind of the four headings that 

16 I’m going to go through:

17 1. Data requests that were made

18 2. Analytical changes that people would like to 

19 see implemented or floated

20 3. Some kind of pointed questions that were asked

21 4. Next steps, where do we go from here. And on 

22 that one, I’ll really be looking to hear from 

23 the room.

24 Data Requests

25 So, starting from the top, here are sort 
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1 of five things that a number of individuals re

2 requested. The first two are how does both the 

3 total weight of a transformer and the core weight 

4 vary as efficiency changes? So we’ll provide that 

5 data. The third item is -- I think it was Jerry 

6 Cochran of Cooper who first floated the idea, and 

7 that’s to have a bi-directional exchange of 

8 engineering data, both to allow everybody in the 

9 room to see some of the design details that DOE is 

10 taking as inputs and also to receive some feedback 

11 and information on how manufacturers design their 

12 transformers to meet the same requirements.

13 We’ve done a little bit of this in the 

14 past, and it’s, you know, for the purpose of model 

15 validation, and it can be a difficult thing to do 

16 because as everybody knows, if you have two 

17 manufacturers build a transformer to meet the same 

18 goal, at different times and different years, 

19 materials, prices change, people have different 

20 design approaches, and so you can end up with 

21 transformers that have very different 

22 characteristics, even though they’re serving the 

23 same application.

24 So if you’re looking to validate a 

25 modeling effort, it’s really important to make as 
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1 tightly controlled a comparison as you possibly can, 

2 and that really involves keeping materials, prices 

3 within a certain range, you know, the construction 

4 methods, whether it’s a core or a shell. Little 

5 things like that can really affect the output.

6 So we did e-mail that template out to the 

7 committee and sought feedback. I think we got two 

8 responses which were, in general, positive and so 

9 that’s something that we plan to use and I hope that 

10 -- this is sort of near -- this is the most upstream 

11 of the upstream portion of this whole analysis, and 

12 so that’s really important, schedule-wise, to have 

13 feedback on as quickly as you can provide it.

14 Here we are on the fourth item, a number 

15 of parties have expressed a desire to look at the 

16 impacts of different steel prices. Now these have 

17 changed a lot over the years relative to each other, 

18 and as I’ll show in some charts, your assumptions 

19 for steel prices can make a big impact in the 

20 outcome, both the economics of it and also where we 

21 determined, say, the point -- the efficiency point 

22 where different steel types can compete was a big 

23 one that the committee expressed a desire to look at 

24 at the last meeting.

25 And then the final one was simplified cost 
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1 efficiency plots so people could look at, really for 

2 each steel type, what sort of on the bottom 

3 frontier, you know, where the bulk of the purchasing 

4 is likely to be done.

5 So we’ve provided one of those already, 

6 the other four we’ll be happy to provide very 

7 shortly and hopefully, they’ll be of use to the 

8 negotiators.

9 MR. PARKER: Can you just state for the 

10 record what will be provided, which one?

11 MR. COFFEY: Oh, sure. I provided the 

12 third item, the template that could be used to 

13 exchange engineering data, and so that’s what we 

14 plan to use going forward.

15 MR. PARKER: Okay. Let’s pause here. Any 

16 thoughts, comments, questions on the data issues. I 

17 have a couple, but let me start with the table 

18 first. Brian, what data do you need and when do you 

19 need it by, and how long would it take once you get 

20 it to put it into the mix? And I guess this is a 

21 big issue -- this goes to Bob Smith’s concern and 

22 Rob Greeson’s. Can you go through that?

23 MR. COFFEY: Sure. We consider, you know, 

24 I have a slide in a second about sort of the 

25 hierarchy of the analysis priorities. We consider 
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1 this engineering validation to be absolutely top 

2 priority, and so this is something that -- this is a 

3 problem we would like to solve before anything else, 

4 make sure that everybody’s comfortable with the 

5 numbers and in particular the cost increments as you 

6 step from one efficiency level to the next. So, we 

7 would like feedback on that as soon as possible. 

8 Bob Smith and Rob Greeson of Federal Pacific have 

9 already been working with us in the medium voltage 

10 dry type space, so we’re thankful for that help and 

11 we hope that some others will follow suit. 

12 MR. PARKER: And the transformers that 

13 this is relevant to are the medium voltage dry type 

14 and low voltage, principally, right?

15 MR. COFFEY: We’re opening the door for 

16 feedback on anything. I think we’re most interested 

17 in receiving feedback on the medium voltage dry 

18 type.

19 MR. PARKER: Bob.

20 MR. SMITH: Bob Smith, Federal Pacific. 

21 Brian, are we still under the assumption that when 

22 we are plotting cost versus efficiency that those 

23 costs are really end user prices?

24 MR. COFFEY: So the prices on the charts 

25 are manufacturer’s selling prices, so that’s what a 
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1 manufacturer -- and we recognize that in some cases 

2 that can vary depending on the distribution channel, 

3 but that’s intended to be what the manufacturer 

4 receives for letting go of a transformer.

5 MR. SMITH: I don’t want to belabor the 

6 point, but in the medium voltage dry type 

7 transformer, we basically have three marketing 

8 channels. One direct to the utilities, one to the 

9 switch gear OEMs who go through distributors and the 

10 contractors, and one through distributors to 

11 contractors, all winding up with the end user. We 

12 have weighing factors on those three channels, and 

13 that’s the way we are expressing our prices, and 

14 when the appropriate time comes, I would like to 

15 discuss, if we could agree, on what those weighing 

16 factors should be and what the markup should be for 

17 each one of those steps in the channel.

18 MR. COFFEY: I think that’s useful 

19 discussion. I think when you ask two people to 

20 design transformers to a certain set of 

21 specifications and efficiency, and they come back 

22 and there’s a difference in the selling price, 

23 there’s a lot of reasons that that could happen, and 

24 it could be different assumptions about materials 

25 prices, it could be a different cost structure or 
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1 distribution channel, or it could be a difference in 

2 the design, and I think that the most important --

3 what we’re most interested in looking at first, is 

4 are there any design differences. Are the weights 

5 of the transformers comparable? Are the core sizes 

6 within a range? So I think we would look at that as 

7 the first priority.

8 MR. PARKER: Mike.

9 MR. RIVEST: So we laid out -- we have a 

10 presentation that sort of lays out the sequencing of 

11 the analysis, and I don’t think we had that specific 

12 issue there, about the markups. But just to answer 

13 that one, I think what we do is plot the 

14 manufacturing sales price to efficiency, and so 

15 really that becomes of ratio of revenue to materials 

16 -- revenue to costs, and I could -- I would know 

17 that by looking at your 10K. You just show me that 

18 and we can agree in a minute. And I won’t tell 

19 anybody.

20 MR. SMITH: That would certainly simplify 

21 the analysis, but we were told to use end user 

22 prices, to look at the impact on the end user. Is 

23 that still the way you’re approaching this?

24 MR. RIVEST: No, absolutely not. The 

25 apples to apples comparison here is the 
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1 manufacturer’s sales price. The end user -- so if 

2 you’re looking at the engineering analysis 

3 spreadsheet, which is transferred to the LCC. I 

4 think that’s what it’s called in the -- on line. 

5 That -- those are then marked up to the consumer by 

6 a factor.

7 MR. PARKER: Sorry, we can only speak into 

8 the mic. Jeremiah, can you --

9 MS. COUGHLIN: So the total -- this is 

10 Katie Coughlin, Lawrence Berkeley Lab. The LCC uses 

11 the total installed -- the term is the total 

12 installed cost, that’s the end user price. That 

13 includes the markups along the distribution channel, 

14 and the manufacturer selling price is what we get 

15 from the engineering. And those are actually both 

16 columns in the LCC spreadsheet, so it’s pretty 

17 straightforward to see the difference between those 

18 two numbers for all the designs.

19 MR. PARKER: Yes. Aaron.

20 MR. MEYERS: Aaron Meyers, Cooper Power 

21 Systems. I have a great appreciation for the work 

22 that Navigant and the DOE has done in preparing this 

23 analysis. I realize that it was quite extensive. 

24 My contention in the data analysis would be that 

25 there are several steps along the way and if small 
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1 mistakes are made in each step, they wind up 

2 compounding. And so when you reach the point where 

3 the analysis is complete, it’s pretty simple to 

4 connect the results of the analysis with reality by 

5 requesting quotations from real manufacturers, and I 

6 believe that that’s the work that Phil Hopkinson has 

7 attempted to do, and it has shown that there is a 

8 little bit of a disconnect there. So I would 

9 request that the DOE go out and seek quotations from 

10 manufacturers to validate the data. And the main 

11 thing that we’re concerned with is efficiency versus 

12 price, and so the price will be provided and the 

13 efficiency could be requested as part of the 

14 quotation. Thank you.

15 MR. RIVEST: So to -- Mike Rivest, 

16 Navigant. So to a large extent, the data request 

17 sheet that we sent out would allow us to do the 

18 proxy to that. So what we would do is -- that data 

19 request sheet includes your unit -- the number of 

20 pounds of steel, for example, for core steel, the 

21 windings, has gallons of oil, I think, so it has 

22 probably 90 percent of the material costs. That 

23 gets us pretty close with -- if we had a factor, 

24 like two, something like that, whatever that ratio 

25 is that you guys might be more familiar with than I. 
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1 It gets us pretty close. If we get quotations, then 

2 you’re quoting based on what steel price of today 

3 versus what we’re using -- I mean, we’re trying to 

4 common size -- that’s our difficulty -- and the 

5 quotes would be -- I see bid results -- I mean you 

6 can go on line right now, look at bid results, 

7 transformers, and you will see utilities posted bid 

8 results, and there’s significant variation between 

9 suppliers. And it doesn’t mean anybody’s wrong, it 

10 just means that the bidding’s different.

11 MR. MEYERS: Yeah, I would agree with you, 

12 Mike that the pricing of commodities is quite 

13 volatile in the marketplace, but it’s a reality of 

14 this transformer industry. And so we can’t go 

15 forward and make a decision on the payback and so 

16 forth based on a single point in time, we need to 

17 take that range into consideration. There was some 

18 information that was shared here this week that 

19 discussed amorphous core transformers and also 

20 grain-oriented and silicon steel transformers, and 

21 there was a period of time where a particular 

22 utility purchased amorphous core transformers 

23 because it made the most economic sense. That 

24 period of time was six years. Since that point in 

25 time, it’s flip-flopped and there’s nothing to say 
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1 that it won’t flip-flop back and forth several times 

2 in the future.

3 My request would be that we don’t nail 

4 down customers so that they have to purchase a 

5 particular style of transformer when the economics 

6 may not justify it on an ongoing basis. Thank you.

7 MR. RIVEST: Mike Rivest. Brian began to 

8 talk a little bit about this tool that we’ve put 

9 together called the price sensitivity tool. So what 

10 that does is it would allow you to input different 

11 steel prices. Now, our engineering analysis is like 

12 hundreds of spreadsheets that are linked, so we 

13 can’t -- we can’t make that usable. But what we can 

14 do is to run up a number of scenarios. And what 

15 we’re hoping to get out of this meeting is agreement 

16 on a range of steel prices for each of the major 

17 steels and then we will run for you all those 

18 scenarios and with a drop menu, you will be able to 

19 replot all of those graphs with the clouds, such 

20 that you can see how different assumptions about the 

21 price of M3 relative to amorphous might change the 

22 dynamics.

23 So that tool, Brian, I think it’s already 

24 ready, but with a limited number of price scenarios 

25 for each of the steels. So I think we recreated 
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1 scenarios, the high/low and reference case for all 

2 of the steels. And so we’re physically allowing 

3 three different prices for each of the steels. And 

4 you could then look at how the clouds move.

5 MR. COFFEY: That’s exactly right and I’ve 

6 got a copy of one of the spreadsheets so I can 

7 demonstrate for everyone how that might work and 

8 then we an send that out and everyone can try it at 

9 home and if there are any steel price sensitivity 

10 cases that people feel aren’t represented there, 

11 then, as Mike said, we can run those results and 

12 redistribute.

13 MR. PARKER: The idea, I think, for 

14 choosing the various steel prices for these 

15 scenarios, is to create a range, right, that’s 

16 bounded from the low end to the high end with some 

17 kind of a reasonable --

18 MR. RIVEST: So if we see that M3 steel is 

19 varied from $1.00 to $1.80, over the last five years 

20 for example, and amorphous has varied from $2.20 a 

21 pound to $2.60 a pound, you might want to take the 

22 extreme cases and run a scenario and see what that 

23 does to that breakeven point people have been 

24 talking about, and then run the other two extremes, 

25 and that would give you a different picture. Then, 
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1 today’s snapshot, which is $1.80 and whatever the 

2 numbers are. And that might address, partially, 

3 what you were talking about, not taking just one set 

4 of assumptions about pricing.

5 MR. MEYERS: For the record, Cooper Power 

6 is not anti-amorphous. In fact, we built amorphous 

7 core transformers and we do so today. We’re looking 

8 to expand our amorphous manufacturing. But keep in 

9 mind that the equipment that’s required in order to 

10 build grain-oriented silicone steel transformers, 

11 the same equipment is used to build M2, M3, M5, M6. 

12 M4, it doesn’t matter. The equipment required to 

13 build amorphous core transformers is quite different 

14 and it’s specialized. And if we find ourselves in a 

15 situation that was projected by the DOE in their 

16 demand forecast for various steels, where amorphous 

17 is really the only game in town, there will be 

18 significant capital investment required across the 

19 board for manufacturers.

20 And for Cooper Power Systems, I can’t say 

21 with certainty that that investment would be 

22 supported, and it would be a travesty to essentially 

23 eliminate a manufacturer and those jobs from the 

24 U.S. economy.

25 MR. PARKER: Thank you, you’ve been 
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1 waiting patiently. Greg.

2 MR. COULTER: Greg Coulter, Prolec, GE. I 

3 want to make a couple comments. One is, in your 

4 data request, we have spoken up and said we’re happy 

5 -- happy -- we find your data for liquid filled 

6 medium voltage close enough, not to go on. I think 

7 other ones have said the same thing. So, I believe 

8 you’re concentrating really on medium voltage dry, 

9 not liquid-filled. I think we’re ready to say let’s 

10 just use your data and charge on for that. That’s 

11 one.

12 Number two, I want to wander into the 

13 amorphous thing. We’re a little concerned about 

14 only using the price extremes for sensitivity 

15 analysis you’re talking about. We’re concerned when 

16 you see a scenario that switches everything from 

17 silicon steel to amorphous. We know if we had to 

18 get into amorphous big time, it’s a big investment 

19 decision. My guess is, for the manufacture of 

20 amorphous, they’re big investment decisions. I 

21 don’t believe anybody’s going to do that. You’re 

22 going to run out of capacity, and now you’re going 

23 to add capacity without a price change? I don’t 

24 think any business does that. I don’t think we 

25 would do that, so I think you’ve got to look maybe 
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1 outside the bands that you might have looked at in 

2 the past when you’re looking at a sensitivity 

3 analysis. We support doing the sensitivity 

4 analysis, but we’re happy doing it with your data.

5 MR. SCHOEN: Jerry Schoen, AK Steel. When 

6 you talk about doing a price sensitivity analysis, 

7 what we submitted was a price parity analysis. If 

8 the objective of the subcommittee is to achieve a 

9 competitive market, that’s established only when you 

10 have a choice of products which have basically price 

11 parity at a given point. Rather than arbitrarily 

12 pick highs and lows, you ought to calculate what the 

13 parity curves are. It’s a single calculation point 

14 and it gives you a much better grasp of what the 

15 market will likely look like.

16 MR. RIVEST: Jerry, I know we have -- so 

17 we have time slotted tomorrow to talk about steels, 

18 and I certainly want to hear more about what that 

19 price parity is. So this is a sort of a value --

20 this is what price does one steel have to be 

21 relative to the other to -- is that sort of what it 

22 is?

23 MR. SCHOEN: Yes.

24 MR. RIVEST: Okay. 

25 MR. MILLURE: Dave Millure. Metglas. To 
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1 Greg’s comment about the linkage between capacity 

2 expansion and pricing, like any manufacturer, we 

3 price to market conditions. We did an expansion in 

4 2009, and if you look at the prices between 2008 and 

5 2010, the prices went down in the face of that 

6 expansion. So expansion does not imply a price 

7 increase.

8 MR. HOPKINSON: Phil Hopkinson, HVolt, 

9 Inc. I think that there’s several fundamental 

10 issues that have come out of the discussion so far. 

11 The first is, I learned years ago that the only way 

12 to really figure out whether anything is correct or 

13 not is to dive into detail, and so in some of the 

14 analysis that I’ve done, I have created a 

15 spreadsheet and put down all of the OPS data against 

16 the average of the manufacturers’ data. And in 

17 doing that, I could see differences that we then 

18 brought back to our friends at OPS and they actually 

19 made some corrections and reissued the data in what 

20 I’ll call OPS-2.

21 So with that regard, I think the only way 

22 we could really see that there was a problem was to 

23 take it detail by detail and get enough of that to 

24 be able to find out where the problems were. 

25 So if you go the other alternative, which 
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1 is selling price versus efficiency from a number of 

2 manufacturers, you can tell in total, and I 

3 certainly applaud that as well. I think there’s 

4 nothing wrong with that. But if you’re trying to 

5 find where problems exist, the only way I know how 

6 to do it is to dive into detail.

7 I think the second thing is there are a 

8 lot of different steels, and the issue of what 

9 should be a minimum national standard on what kind 

10 of steel, if you can get to that decision then 

11 you’ll be a lot further ahead than to argue the 

12 points of an M3 versus amorphous versus an M6, or 

13 whatever. If you can limit what will be a minimum 

14 national standard, you will, in fact, be able to 

15 finally move on and get what is the final 

16 transformer price to the end user, which really is 

17 the only number that counts as far as what happens 

18 to selling price versus efficiency. It’s what is it 

19 to the guy who owns the transformer. 

20 MR. PARKER: Thank you. I think that a 

21 lot of the discussion about steel prices and the 

22 impact of steel prices on markets, you know, is 

23 stuff that we can reserve for the discussion that --

24 the period that we’ve set aside for that for later 

25 today. So why don’t we hold off on that further 
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1 discussion of the steel price impacts until we have 

2 that, because that raises a lot of methodological 

3 issues, analytical issues, not just data issues.

4 So what I’d like to do in this segment now 

5 is really focus on what data you need to simply 

6 predict accurately the manufacturing selling price, 

7 apart from materials price, which are obviously key, 

8 but any other issues that people want to raise that 

9 purely to the quality of the data. And if that’s 

10 the case, we need to table those issues now and we 

11 need to come up with a timeframe for you supplying 

12 the data. 

13 I understand that Navigant sent out their 

14 questionnaire, their template a couple weeks ago. 

15 They’ve had two responses so far. So, you know, 

16 we’re going to have to bring down -- we’re going to 

17 have to close the period for providing further data 

18 at some point. We can’t just assimilate more and 

19 more data coming in. So we have to have a deadline 

20 for this. 

21 So let’s get out on the table any other 

22 categories of data that people feel need to be 

23 supplied, discrepancies. Let’s have that discussion 

24 now and set up a timeframe for resolving it. 

25 Anything else, besides materials prices in terms of 
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1 data discrepancies leading to manufacturer’s selling 

2 price?

3 MR. SIMMONS: Yes, this Chuck Simmons, 

4 Progress Energy. I had a question as far as the 

5 sensitivity analysis with regards to the average 

6 transformer load. I think the initial analysis was 

7 based on a 45 percent average load, I believe for 

8 both dry and liquid field. And there’s been a lot 

9 of discussion that from, at least the utilities’ 

10 perspective, it’s more around the 20 to 30 percent, 

11 and I think it was a lot lower than that for some of 

12 the ...

13 MR. PARKER: Chuck, I think that LBL’s 

14 going to be talking about that as part of their 

15 presentation. So why don’t we discuss that then.

16 MR. SIMMONS: Okay. Thank you.

17 MR. SMITH: Bob Smith, Federal Pacific. 

18 Richard, one thing, for the medium voltage dries, we 

19 would like to be certain that OPS and Navigant 

20 understand the product that is being costed, and 

21 there are, for medium voltage dries, there are 

22 basically two categories, a high voltage general 

23 purpose, which is just a basic transformer, and a 

24 unit substation transformer. It has been our 

25 understanding that it is the unit substation 
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1 transformer which includes the low voltage bus to 

2 the switch gear, and the high voltage bus that 

3 should be the product that is being costed. We’d 

4 like to make sure that that is what is actually 

5 being done.

6 MR. PARKER: That’s a good comment and we 

7 actually have a category for that under the rubric 

8 of changes to analysis, which I think we’ll get to 

9 when -- in Brian’s presentation in a few minutes. 

10 So it’s a great point, it does affect the data that 

11 will be gathered, so it’s perfectly valid to raise 

12 it now, but we will cover that very shortly. 

13 Anything else on this. Wes, you’ve been --

14 MR. PATTERSON: this is Wes Patterson. 

15 I’d just like to comment on the challenges with 

16 running the sensitivity analysis of changing just 

17 the steel prices. The assumption there is that the 

18 existing calculation design, of which there is 

19 roughly 40,000 of them in the DOE database, that 

20 design doesn’t change when you changes the core 

21 steel price. That’s an assumption. But that’s a 

22 fallacy. Because in reality, the amount of 

23 conductor will change relative to the amount of core 

24 steel when I change my relative pricing. So I’m not 

25 sure how much value we will get from that kind of an 
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1 exercise.

2 And the other point I’d like to make is 

3 that, as I look at least at the liquid filled data, 

4 by examining 2010 total shipments and overlaying the 

5 DOE data on top of the total shipments, then one can 

6 easily see how either accurate or inaccurate the DOE 

7 data is relative to establishing the relationship of 

8 price increase versus loss reduction. And I believe 

9 that phenomena, price increase versus loss reduction 

10 is the key driver to the LCC analysis, not absolute 

11 prices of units, not prices between product groups, 

12 but the relationship of the change in price with the 

13 change in loss reduction.

14 MR. PARKER: Brian, are we going to -- did 

15 you want to respond?

16 MR. COFFEY: No, I think this is all 

17 helpful commentary, and I think some of these 

18 questions may be answered as I go through the 

19 presentation. So, if everybody’s okay with it, I’ll 

20 just keep pressing onward.

21 Request to Changes to Analysis

22 Here are a number of things that people 

23 said that they would like to see or like to have 

24 looked at. The first is the TSL that corresponds to 

25 a market situation where a number of steel types can 
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1 compete and be sold in transformers. Obviously, the 

2 question is, at what efficiency levels for each 

3 design line -- what does that mean, so this goes 

4 into our core steel pricing tool, and we can 

5 continue talking about whether that’s a useful way 

6 to look at it, and also open the floor for others to 

7 make suggestions.

8 Materials, price updates, different 

9 scenarios. There’s been discussion of the different 

10 techniques used for scaling, both -- in particular, 

11 at the end of scaling ranges, you know, high and low 

12 KVAs, and also a question about what’s the right way 

13 to harmonize across one- and three-phase units, and 

14 does that change in different transformer 

15 applications.

16 As far as new product classes, there have 

17 been proposals for perhaps setting liquid immersed 

18 standards by BIL, this is what DOE does in the 

19 medium voltage dry type space, and there’s a 

20 question of whether it would be beneficial to do in 

21 the liquid space also. And also whether it would be 

22 useful or warranted to set standards for different 

23 subtypes of liquid immersed transformers -- poles, 

24 pads, substations, network vaults, that sort of a 

25 thing.
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1 And the last is size and weight 

2 constraints which really is treated in the LCC. So 

3 I’ll go through these and expand upon them.

4 Before I do, I want to touch on something 

5 that I mentioned earlier, and that’s, you know, what 

6 are our priorities in looking at the analysis? And 

7 I think that the first thing has to be achieving the 

8 level of comfort with our existing representative 

9 units. If these -- these are the basis for really 

10 everything else, the upstream portion of the 

11 engineering, which is the upstream portion of the 

12 whole analysis, and so if those -- if we can’t agree 

13 on those, then we -- it’s tough to have the rest of 

14 the discussion.

15 So the second thing is scaling. How do we 

16 extend those representative unit results to the rest 

17 of our covered space?

18 And then finally, we think the third 

19 priority is looking at new equipment classes. 

20 That’s a useful thing to do, but if one and two 

21 haven’t happened, then the discussion is a little 

22 bit less useful. 

23 The way that DOE sets equipment classes, 

24 just to refresh everybody’s memory, is if it finds 

25 that there’s a differential consumer utility, in 
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1 other words, if one type of product does something 

2 for the consumer that another doesn’t, and the 

3 second criterion is do the different equipment 

4 classes have a different ability to meet different 

5 efficiency levels. So if there’s a case that those 

6 two things are true, then I think the door is open 

7 for a new equipment class, but that’s something we 

8 can talk about today.

9 MR. RIVEST: Mike Rivest, Navigant. 

10 Brian, if you can come back to the previous slide? 

11 So clearly, looking at the hierarchy here of 

12 analysis priorities, we’re in a different stage with 

13 the medium dry than we are with the liquids, for 

14 example. Possibly with the liquids, we an initiate 

15 conversations about scaling, whereas with dries, I 

16 think we’re still at the representative unit 

17 validation stage. So when we talk about when things 

18 might be ready, walking down the analysis and things 

19 like that, I think it would be helpful to think in 

20 terms of discrete steps, segmenting the product 

21 class, the product types and looking along the way.

22 And then depending on how we actually 

23 perform the analysis for scaling, or for 

24 extrapolating to other product classes, that can be 

25 a very difficult exercise, or it could be relatively 
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1 simple. It really depends on the extent to which we 

2 can get stakeholder involvement and data. You guys 

3 have great tools, in the liquid field universe at 

4 least, because it’s a very customized industry, so I 

5 think we’ll propose methods maybe for scaling there 

6 that will depend on your involvement. And for other 

7 product classes it may be more difficult. 

8 So I think to be able to answer the 

9 questions of when the analysis will be ready, we’ll 

10 need to decide exactly what we do, how we do it, and 

11 we can’t answer that until the group here helps us -

12 - gives us our charge, basically.

13 MR. PARKER: So as I understand it from 

14 Brian just now, basically, to make a final 

15 assessment as to whether there’s a justification for 

16 creating a new representative unit, they need 

17 further data from the manufacturers, is that right?

18 MR. RIVEST: It would not be a new 

19 representative unit. It’s not a new representative 

20 unit. We’re talking about new product classes.

21 MR. PARKER: A new product class. Okay. 

22 But the question is, do you need more information 

23 than you have gotten from the manufacturers to make 

24 that assessment?

25 MR. COFFEY: I think we would, as Mike 
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1 just said, need some input from the committee as to 

2 what’s the right way to extend the analysis to new 

3 equipment classes, yes.

4 MR. PARKER: Is that an analytical 

5 methodological concern, or is it a data?

6 MR. RIVEST: It’s a -- we’ll get -- we 

7 have slides on that, right? Yeah, good.

8 MR. COFFEY: So moving -- I’m sorry, is 

9 there a --

10 MR. PARKER: Steve.

11 MR. ROSENSTOCK: Just a quick one, going 

12 back to the previous slide, there’s slides --

13 everywhere there’s a point, there’s going to be like 

14 one or two follow-up slides for discussion? I just 

15 wanted to make clear so far. Thank you.

16 MR. COFFEY: So here’s the follow-up --

17 MR. PARKER: Sorry, we had a comment here.

18 MR. HIRSCH: Yeah, Bruce Hirsch, Baltimore 

19 Gas and Electric. I know we talked about that you 

20 were going to talk more about the weight and size of 

21 transformers, and a lot of times that’s considered 

22 when we’re talking about network and bulk type 

23 transformers because of the constraints. But I just 

24 want to point out that we’re in a very constrained 

25 area in Baltimore City with our existing system, so 
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1 overhead transformers and pad mount are also an 

2 issue to us when you’re talking about changes in 

3 sizes. We’re not constrained -- the weight issues 

4 are a problem when it comes to the pole loading, but 

5 we also need to keep -- we keep safety clearance 

6 distances from other things that are out there in 

7 that congested area. So that creates a big problem 

8 for the utility industry. So I just think also 

9 keeping that in mind when we make these changes.

10 MR. COFFEY: Great. I think LBL’s going 

11 to address some of that in their presentation too.

12 So to look at the first bullet here, which 

13 is achieving comfort with the existing 

14 representative units, I noted in the data section 

15 that we sent out this template, I think it was 

16 roughly a week and a half ago to receive input on 

17 the different design specifications that 

18 representative units could have at different 

19 efficiencies. We consider this to be the first 

20 priority and so we hoped to receive feedback 

21 wherever someone feels there could be a discrepancy, 

22 as soon as possible. 

23 So we talked a little bit about how 

24 selling price by efficiency, just on its own, is 

25 sometimes not as useful, because if there’s a 
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1 difference, it’s hard to know exactly where that 

2 might lie. So Phil noted that the more detail that 

3 can be provided, I think the more expediently we can 

4 come to an understanding.

5 And the second point there is that as 

6 materials prices change, the designs that 

7 manufacturers will produce to accomplish a certain 

8 job will vary, so I think you have to make some 

9 attempt to hold materials prices within a certain 

10 range before you start comparing the designs that 

11 they lead to.

12 The second priority in reworking some of 

13 the analysis is scaling, that’s what we do when we 

14 extend the results of a certain representative unit 

15 to the rest of the KVA range. Ultimately, this is 

16 what generates a standard for different KVA ratings.

17 Historically, losses have been scaled 

18 using the .75 rule, which I think everybody is 

19 probably familiar with, where the losses of two 

20 transformers -- the ratio of the losses is set equal 

21 to the ratio of their KVA ratings raised to the .75 

22 power, and you can see that in equation form right 

23 there. Sure.

24 MR. PATTERSON: Wes Patterson. Yes, in 

25 the existing standard between two KVA points you use 
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1 the three-quarter rule. But between KVA points, you 

2 just arbitrarily pick numbers for losses. And that 

3 is a fallacy. You cannot do one and not do the 

4 other. So either the losses are following the 

5 three-quarter rule across all KVAs, or it’s not 

6 following it anywhere. You can’t be half pregnant.

7 MR. COFFEY: No, I’ll explore that a 

8 little bit. I’ve got some graphs that I think 

9 illustrate that point.

10 So several manufacturers have given 

11 feedback on this and this exponent of .75 is derived 

12 from just laws of physics, and in general it’s true, 

13 but sometimes there’s realities in the way that 

14 things are manufactured that deviates slightly from 

15 the ideal and the observed behavior is a little bit 

16 higher or lower, maybe, than .75. And so the 

17 concern is that if you’re using .75 across the range 

18 then sometimes at the extremes of the scaling range 

19 you lose a little bit of accuracy.

20 The proposal here is to conduct some 

21 limited analysis at the extremes of different KVA 

22 ranges to determine or to help hint as to whether 

23 the .75 is the right thing, or if something else 

24 should be used. So this wouldn’t be wholesale new

25 representative units but it would be a couple of 
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1 test cases to try to tack down what the behavior 

2 across KVA is.

3 The benefits of this, we think, are that 

4 it would allow the slope to assume a value, other 

5 than .75. It would allow the ends of the scaling

6 range to be perhaps treated more accurately. And 

7 then the third benefit, which maybe is less obvious 

8 at first glance, is that it could allow extension of 

9 results for one type of transformer to a different 

10 but similar type. I’ll go into more detail and 

11 explain what I mean about this.

12 For example, if we wish to generalize 

13 median BIL liquid results to higher or lower BIL 

14 units that would ultimately, perhaps, get a separate 

15 standard, this scaling methodology would permit 

16 that. Wes Patterson has long been a proponent of 

17 this and we would be interested in, after I show 

18 what that would entail, hearing from other 

19 manufacturers as to whether that’s something that 

20 could work. I’ll return to that scaling point with 

21 some charts.

22 To talk about potential new equipment 

23 classes where we might use that scaling methodology, 

24 DOE understands that BIL strongly affects the 

25 efficiency in medium voltage dry type and in the 
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1 2007 rulemaking, DOE established equipment classes 

2 by BIL for -- there were high, medium, and low bins. 

3 We’ve heard that BIL is a little bit less of a 

4 factor in liquid immersed units, but perhaps still 

5 significant if standards rise further, so there’s --

6 we’ve been hearing that the current standards maybe 

7 produce too low a standard for lower BIL units than 

8 what we analyzed, and maybe too stringent a standard 

9 for the higher BIL units.

10 And so the proposal is that we would scale 

11 to different BILs if the committee thought it were 

12 useful and warranted, and we would do so using the 

13 scaling methodology that I’m going to continue to 

14 talk about. So keep that in mind.

15 MR. PARKER: Yes, Steve.

16 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

17 So basically on the previous slide -- in that 

18 proposal, I know you’re -- so basically you’d not 

19 only be scaling on the KVAs for the single phase 

20 three base, but then you’re going to do kind of a 

21 cross-scaling for BILs, so there could be, instead 

22 of -- so for 15 KVA three phase, there could be 

23 three efficiency levels based on BILs? Is that --

24 MR. COFFEY: That’s how I’ve been thinking 

25 about it, that if the committee decided it were 
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1 warranted and workable, then, yeah, maybe it could 

2 end up with something similar to what’s currently 

3 done in the medium voltage dry type space.

4 MR. ROSENSTOCK: Thank you.

5 MR. PARKER: Any other comments on this 

6 before we move on? Yes, Phil.

7 MR. HOPKINSON: Phil Hopkinson. For those 

8 who were not able to be here at the meeting, I did 

9 have some inputs that they’ve been sending me e10 mails this morning, but would suggest that perhaps a 

11 high BIL designs in liquid fill should be broken out 

12 too because for data that I have not sent in, and I 

13 report that I sent to you, Richard, I did collect 

14 and have the data, and Brian Coffey also does, of 

15 what the cost curve looked like when we tried to go 

16 to 34.5 KV, 150 KV-BIL apparatus, and also what it 

17 looked like for dual-voltage designs. And certainly 

18 at high BIL. And the fact is that the efficiency 

19 drops off quite dramatically up there as far as what 

20 you can reach with the same set of materials, and M3 

21 was the base of what we were trying to collect the 

22 data to.

23 MR. PARKER: Okay. Thank you.

24 MR. PATTERSON: This is Wes Patterson, 

25 ABB. Recognized that for this voltage class we’re 
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1 talking an upper end of 200 BIL, not 150. So the 

2 problem is much worse at 200.

3 I think that for distribution transformers 

4 it doesn’t ... If you follow how the DOE has defined 

5 the transformers, they simply said 36 KV and down. 

6 So any unit that’s rated at 36 KV, 2500 KVA must 

7 meet the DOE standard, and that then falls under the 

8 scope of 200 BIL according to IEEE.

9 MR. HOPKINSON: I think that the material 

10 in print from the DOE said that they were limiting 

11 to 150 KV-BIL, which certainly would go along with 

12 any of the separable connector ratings, because they 

13 can’t go beyond that either. Now, it is true that 

14 36 KV, 34.5 KV should be, if it’s a delta connected 

15 transformer, should be 200 KV-BIL as Wes Patterson 

16 clearly points out, and he’s correct. But I don’t 

17 think that was in the scope of what would be 

18 considered a distribution transformer.

19 MR. PATTERSON: It may be, Phil, but the 

20 way the standard was actually published, the way the 

21 standard was actually written and published, it 

22 scopes all the way to 200 BIL. So what we could do 

23 is exclude over 150 BIL in the liquid filled 

24 definition, but we have not done that.

25 MR. PARKER: I take it there’s significant 
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1 sales volume in these higher BILs for which --

2 MR. PATTERSON: No, Richard, there’s very 

3 little sales volume at 200 BIL. The problem is 

4 you’re looking at five percent of the volume driving 

5 95 percent of the losses. This is the challenge. 

6 So we could either ignore it, or we can accommodate 

7 it, or we can force the standard to the lowest 

8 common denominator, which would be 200 BIL, as it’s 

9 currently written.

10 MR. PARKER: Any thoughts on the best way 

11 to accommodate that problem? Phil.

12 MR. HOPKINSON: Phil Hopkinson. I think 

13 the best way to do it is to not include 200 KV-BIL 

14 in the scope. There’s not enough volume to worry 

15 about. You’re not going to save enough energy to 

16 make it worthwhile to do it. And I just recommend 

17 deleting that one and putting it at 150 KV-BIL, 

18 which, if it’s going to be a dead trunk transformer, 

19 and most of the distribution transformers are, then 

20 the 150 KV-BIL would take you to the highest end of 

21 what’s available. If you go to live trunks and 

22 mostly class 2 kinds of transformers, you definitely 

23 will have the 200 and higher.

24 MR. PARKER: Okay. Does the .75 cover you 

25 reasonably accurately through 150, or do you still 
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1 need adjustments if you exclude.

2 MR. COFFEY: That set -- the l75 is used 

3 for KVA, so this would be slightly different from 

4 that.

5 MR. PATTERSON: Richard, I think when you 

6 -- if we work along scaling philosophy, what you’ll 

7 find is that there will be a parallel shift in the 

8 line of efficiency. So they have a straight line 

9 that goes KVA versus efficiency or watts, and 

10 there’ll be a parallel shift up when you get to the 

11 higher BIL.

12 MR. SMITH: Bob Smith, Federal Pacific. 

13 With respect to the 150 versus 200 KV-BIL for medium 

14 voltage drives, most of the manufacturers are making 

15 ventilated open drive transformers at 35 KV, which 

16 has an upper limit in BIL of 150 KV. Some 

17 manufacturers are making cast resin coils which at 

18 this same voltage can go to 200 KV-BIL, however I 

19 look at that as a special class of medium voltage 

20 drives and would encourage us to stay with the 150 

21 KV-BIL as the upper limit.

22 MR. PARKER: Yes, Steve.

23 MR. ROSENSTOCK: Yes, this may be more for 

24 -- a couple questions. I think there’s a 

25 definitional issue, so if there is some sort of 
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1 cutoff in definition in what’s covered, maybe that 

2 might help in terms of some of this discussion in 

3 terms of 150 versus 200. Again, I don’t have it off 

4 the top of my head, but -- does DOE cover it in the 

5 first place, I’m not -- I don’t exactly remember. 

6 And so on that higher end of the range is it, quote, 

7 “a covered product”? That’s a definitional issue. 

8 I don’t know what comes from EPAC-92 or just the 

9 2007 rulemaking.

10 The second thing, and I think Brian will 

11 get to this is how many bins are we talking about? 

12 I think with the medium voltage there’s three bins 

13 of BIL levels in terms of efficiency standards? For 

14 liquid filled, I heard a number of 150, and I just -

15 - Brian, I guess you’ll probably get to this on a 

16 slide, how many bins are we talking about in terms 

17 of BIL standards?

18 MR. COFFEY: That’s probably something 

19 we’d be interested from hearing -- to hear from the 

20 committee on, you know, how many bins would be 

21 needed to accurately treat this issue. So we’ll be 

22 looking for that. I see two, one, or maybe that’s 

23 just a desire to speak.

24 MR. HODGE: Gerry Hodge from Howard 

25 Industry. I concur with Phil about having the 
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1 standard only go to 150 BIL because we don’t -- we 

2 really don’t make that many 200 BILs. When you do, 

3 you’ve got to put a lot more insulation in there, 

4 and so that’s going to take up a lot of space where 

5 you can’t put the active materials in. And they 

6 become enormous in size and you may be using the M2 

7 or M3 for your 124 or 150 BIL, but you’re going to 

8 have to go to amorphous, possibly, to get the 200 

9 BIL. So it drives up your limits, the types of 

10 materials you can use for real high BILs.

11 MR. PARKER: So as I understand it, the 

12 issue is whether to try to create a separate 

13 category for the higher BILs or simply exclude it 

14 from the rulemaking altogether, is that right?

15 MR. RIVEST: This is Mike Rivest. I think 

16 there’s no lawyer in the room so --

17 MR. PARKER: Yeah, I think when you 

18 exclude something from the rulemaking --

19 MR. RIVEST: I know that we an exclude 

20 something, we can create a class for it and -- if 

21 it’s a covered product now, I don’t know that 

22 there’s -- I don’t know that you can suddenly 

23 exclude it. Maybe you can create a separate class 

24 and not change the standard, perhaps, but that 

25 really is an issue for the lawyers.
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1 MR. PARKER: Yes, Andrew. He needs a mic.

2 MR. DeLASKI: I don’t know what the sales 

3 are of over 150, I think it might be less than a 

4 percent -- so it strikes me that this is an issue we 

5 shouldn’t spend too much time on. It seems to me 

6 that you could leave the standard as is for those 

7 products and let’s focus on where the sales are at. 

8 So it strikes me that we suggested in our comments 

9 that you could do three classes of BILs -- I think I 

10 said two -- so you could give two or three and you 

11 can capture it, and then I think we could just not, 

12 for purposes of our discussion, disregard those over 

13 150, given the sales volume, and focus on where the 

14 sales are at. And let’s move on to things that are 

15 actually going to get us moving towards --

16 MR. PARKER: Thank you. Aaron. 

17 MR. MEYERS: Aaron Meyers, Cooper Power 

18 Systems. We would support either exclusion or 

19 creating a separate product class. The only request 

20 that we would have is that we are seeing commercial 

21 requests for 200 BIL core coil design, but to Phil’s 

22 point, 150 KV-BIL connectors. So if we are 

23 separating this, I would just ask that that be 

24 clarified or resolved within the definition.

25 MR. COFFEY: Does anyone have thoughts on 
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1 the right way to treat those cases?

2 MR. HOPKINSON: I ran a working group for 

3 ten years on dielectric test tables for distribution 

4 transformers, and we finally ended up that the limit 

5 for distribution transformers in IEEE is 150 KV-BIL 

6 for liquid, and 200 KV-BIL was the limit for class 2 

7 transformers so that I view this as clearly a 

8 distribution transformer, 150 KV-BIL and below, and 

9 that goes certainly with the bulk of production. I 

10 think it’s less than a quarter of one percent that 

11 are at 200 KV-BIL, of the total population of the 

12 transformers that are out there. It’s small.

13 MR. PARKER: Okay. So I think with that, 

14 I will propose that we agree now that there will be 

15 a separate class created for greater than 150 BIL 

16 and that following Andrew’s suggestion, that we just 

17 agree that the recommendation will be no change in 

18 the standard for that tiny equipment class. Is that 

19 what you proposed, Andrew? Did I get it right? I 

20 guess he’s speaking. Andrew, is that what you 

21 proposed, basically, creating a new class for 

22 greater than 150 BIL for this tiny category, and 

23 keeping it the same?

24 MR. DeLASKI: (off mic) I don’t know, I 

25 could go either way. 
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1 MR. PARKER: Speak into the mic, yeah. We 

2 need to not spend too much more time on the quarter 

3 of one percent, but Aaron, go ahead.

4 MR. MEYERS: In response to Brian’s 

5 question as to how to define 200 BIL core coil with 

6 150 KV separable connectors, the coil insulation 

7 really drives the design, so my recommendation would 

8 be to treat 200 BIL core coil designs within the 200 

9 BIL class.

10 MR. PARKER: Great. Do we have agreement 

11 on that? Then that we will create this class that 

12 Aaron will work with Brian on the exact way to 

13 specify the class that we’re treating as a separate 

14 equipment class in terms of BIL and core coil, and 

15 that in the interest of moving forward, we will 

16 agree that that will simply be left at the current 

17 standard. Is that a fair representation? Mike.

18 MR. RIVEST: Assuming that that stands, 

19 would there be further breakdowns for BIL for liquid 

20 fill?

21 MR. PARKER: Well, let’s get a resolution 

22 on that. Is there any -- any dissent from that? 

23 Are we in agreement on treatment of that tiny 

24 category so we can move on? Okay. Now, any other 

25 issues? Yes. On BIL.
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1 MR. HOPKINSON: What I would recommend is 

2 that for a liquid filled transformers, 95 KV-BIL and 

3 below would be one equipment class, and above that 

4 all the way up to 150 KV-BIL would be the second 

5 equipment class.

6 MR. PARKER: Any -- Gerry.

7 MR. HODGE: Phil, you’re saying 150 BIL 

8 and we would eliminate 200 BIL from the definition 

9 of transformers? That’s what you would recommend?

10 MR. HOPKINSON: Yeah.

11 MR. HODGE: That’s what I would recommend.

12 MR. HOPKINSON: And this is Phil again. 

13 What I would recommend is that the 200 or higher is 

14 not included in the scope of what we’re trying to 

15 get to a new rulemaking on, and 95 and below would 

16 be one equipment class, and 125 and 150 KV-BIL would 

17 be a second. Now, you know, there’s a fair amount 

18 of 110 KV-BIL out there as well as 95, but that 110 

19 is really a class 2 transformer definition, so in 

20 that sense, I would go with 95 and below as one, and 

21 125 and 150 as the other. Greg Coulter is shaking 

22 his head.

23 MR. COULTER: I would get concerned --

24 this is Greg Coulter. I’d get concerned about just 

25 eliminating 200 BIL. It’d become real easy any time 
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1 somebody bought a 35 KV to say I just want a 200 BIL 

2 now instead of 150, and they’re outside the limits. 

3 I think you’ve got to keep it in there. I think the 

4 proposal is not to eliminate it, but to keep it 

5 within the legal scope but to recommend no change in 

6 the efficiency level for it. 

7 MR. PARKER: Wes Patterson.

8 MR. PATTERSON: Yeah, I think I presented 

9 or gave out a PowerPoint that showed the 

10 distribution of the losses by KVA and BIL. At least 

11 Brian, you got it, right?

12 MR. COFFEY: Yeah, I think --

13 MR. PATTERSON: I think everybody did. 

14 And if you look at this thing you can clearly see 

15 where the loss in the system is residing. Okay. 

16 And for sure it’s on 95 BIL, that’s the big bear. 

17 Like easily 80 percent level. And then it drops

18 down to 125 BIL, which is the next bucket. And then 

19 it becomes insignificant above 125. Right. 124, 

20 150, and the red dots is the losses on the grid, 

21 relative. So you take the biggest circle all the 

22 dots are relative to the biggest circle. So all the 

23 losses are here. Then we get lower and lower. 

24 So to keep the world simple, my 

25 recommendation would be to follow Phil’s suggestion 
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1 and simply say 95 BIL and below, you’ve got this 

2 level of losses; and above 95, which includes these 

3 circles and these little red dots, --

4 MR. PARKER: You have to speak into the 

5 mic.

6 MR. COULTER: -- would be another class. 

7 Including 200. You would have rolled 200 into the 

8 second class, the upper class. 

9 MR. HOPKINSON: That would go for a 125, 

10 150 and 200?

11 MR. COULTER: Phil, that would be my 

12 recommendation to keep the standard somewhat simple, 

13 and the volume impact is very low. If I look at the 

14 number of units that are shipped at those ranges, 

15 you can see from the chart the number of units, 

16 we’re talking very small units, very small amount of 

17 watts.

18 MR. HOPKINSON: I would call on my good 

19 friend, Gerry Hodge to make comment, but I think 

20 that Gerry would probably make words like at 200 KV21 BIL, the efficiency will drop off a lot so if we 

22 limit the materials to what will be used in the 

23 transformer and then if we go with the efficiency 

24 that will work for that transformer, then I think 

25 you’ll find that you’re not going to like the answer 
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1 when you put 200 KV-BIL into the pot. But, Gerry 

2 would you comment?

3 MR. HODGE: Well, first of all, we don’t 

4 make that many 200 BILs, we really don’t. But we do 

5 right now, we have to meet the DOE requirements on 

6 200 BIL, and as I said, you have to put a lot more 

7 insulation in to meet 200 BIL. And when you do that 

8 you’ve got to take something else out or you’ve got 

9 to use better material. You may have to go to 

10 copper instead of aluminum. You may have to go M2 

11 instead of M3. You may have to go to amorphous 

12 instead of M2, whatever it may be. But you’re going 

13 to have to do something better to maintain that one 

14 number, that one efficiency number that you’re given 

15 to work with. And now we an have a range of 125-150 

16 BIL and then another range for 200 BIL, but I’m not 

17 sure it warrants another range, because the quantity 

18 just doesn’t --

19 MR. PARKER: It’s a range that requires 

20 further analysis or discussion, but I think the idea 

21 is to move forward, we would just keep it at the 

22 current -- just keep it at the current level. If 

23 you’re objecting to Wes’ -- I take it you have a 

24 problem with Wes’ suggestion that we just mandate 

25 that it meet the standards for the lower BIL. So if 
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1 that’s the case, why don’t we just propose to follow 

2 Andrew’s approach. Andrew did you want to come 

3 back?

4 MR. DeLASKI: Yes, so my remarks in this 

5 area are predicated on the notion that we’re looking 

6 for significant increase in transformer minimum 

7 efficiency standards. Okay. That’s why we’re here 

8 participating in this process. Now we’re interested 

9 in focusing on those parts of the market that have 

10 significant sales and therefore drive significant 

11 energy savings and the related benefits. So, our 

12 view on this particular issue is that I think the 

13 break point of 95 BIL makes sense, because the 

14 volume of the sales is below 95 BIL, and then having 

15 a class from 95 to 150 makes sense. There’s a small 

16 -- this is my recommendation, a little different 

17 than yours, Wes --

18 MR. PATTERSON: The 95 is the bulk of the 

19 market.

20 MR. DeLASKI: Right. Thank you. That’s 

21 what -- So then, without leaving a doughnut hole, 

22 from that break point up to 150 would be your second 

23 class. And then we have a third class, okay, 

24 depending upon getting final resolution of the legal 

25 issue of whether these things are in or out in the 
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1 current market before saying some people -- seems to 

2 be some disagreement over that -- but things over 

3 150 would be a third class, and I think I’m 

4 recognizing right now that that one, in all 

5 likelihood, we would agree to leave it where it is 

6 today, leave the standard where it is today. I’m 

7 ready to suggest that as a preliminary suggestion 

8 right now, because I want to focus on where the 

9 sales are at. 

10 Now, it may be, Wes, that we find that the 

11 standard for the highest BIL ratings should be the 

12 same as the mid-range, once we see the analysis come 

13 back broken down. But I think we need to see that 

14 analysis for purposes of this committee.

15 MR. PATTERSON: The concern is that we 

16 have the 200 BIL drive the standard for the 95, 

17 which means then we will never reach significant 

18 improvement. If we want to achieve significant 

19 improvement we cannot included them just like we 

20 can’t include the network.

21 MR. DeLASKI: And that’s an insight that 

22 we gained I think in our very first meeting, and 

23 thanks to your explaining that in the very first 

24 meeting that we had, and I suggest that breaking 

25 these down by BIL levels is -- I think I’m hearing 
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1 consensus on this point, and that we should --

2 MR. PARKER: Any objection to that 

3 approach? Let’s move on then. Good. Agreed. 

4 Thank you Andrew, and Wes and everybody. So the 

5 approach then that I understand is three BIL 

6 classes. One for under 95, one for 96 to 150 and 

7 one for greater than 150. The greater than 150 

8 would remain within the scope of this group unless 

9 DOE counsel tells us that it’s legal to exclude it, 

10 and it would remain at the same standard as it is 

11 now. At least that would be the recommendation of 

12 the group. I really think we need to move on --

13 Steve, if it’s something very short, very quick.

14 MR. ROSENSTOCK: Numerical. Less than or 

15 equal to 95. Greater than 95 to less than or equal 

16 to 150 --

17 MR. PARKER: Yes.

18 MR. ROSENSTOCK: -- greater than 150.

19 MR. PARKER: Yes. Agreed? Okay. Got it.

20 MR. COFFEY: Okay. Great. I think that 

21 was helpful discussion there. The second new 

22 equipment class area, or potential new equipment 

23 class area comes in the liquid space, where there 

24 have been suggestions to, as with BIL, maybe 

25 subsegment by the type of transformer being 
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1 produced, so that could be pads, that could be 

2 poles, substations, networks or vaults, and in the 

3 context of DOE’s criteria for setting equipment 

4 classes, is there a different utility to the 

5 consumer, the consumer in this case being the 

6 purchaser of the transformer. And is there a 

7 differential ability to meet efficiency standards? 

8 So I’d like to open the floor for discussion of that 

9 and suggestions for how it might be done.

10 MR. PATTERSON: Wes Patterson. So you 

11 have two criteria, right, one is different utility 

12 to the customer? So pad mount transformers is a 

13 total different utility than a pole mount, which is 

14 a total different utility than a network. Do I need 

15 to elaborate or is this clear to everybody? Okay. 

16 MR. PARKER: We got it.

17 MR. PATTERSON: So for sure, those four 

18 categories, now when you change substation to say 

19 all other, catch phrase, right. Instead of saying 

20 substation, because that’s a specific class of 

21 transformer, right, so my recommendation would be 

22 pad, pole, network, submersible vault, and then all 

23 others. And they have different utilities which 

24 meet your first criteria, which can be looked up in 

25 standards.
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1 MR. PARKER: There’s a microphone behind 

2 you, Bob.

3 MR. BERMAN: Robert Berman, Berman 

4 Economics. Wes, can you cross-sell one utility into 

5 another? Can I buy a network vault transformer and 

6 use it on a pad?

7 MR. PATTERSON: No. It’s not possible.

8 MR. BERMAN: It’s not possible. Okay. 

9 MR. PATTERSON: It’s impossible to do the 

10 flip-flop. You cannot take a pad and drop it in the 

11 vault.

12 MR. BERMAN: I understand that.

13 MR. PATTERSON: You can take a network --

14 MR. BERMAN: I can take a network and drop 

15 it onto a pad.

16 MR. PATTERSON: -- and drop it onto a pad, 

17 but since it sells for three times what the pad 

18 sells for -- economically, it’s insane.

19 MR. BERMAN: Okay. That works.

20 MR. DeLASKI: A follow-up to that, though, 

21 is that -- so a network transformer is a very 

22 sophisticated piece of equipment, where there are 

23 transformers that go in vaults that are not network 

24 transformers.

25 MR. PATTERSON: That's correct. And 
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1 they’re space constrained also.

2 MR. DeLASKI: Right, but they wouldn’t 

3 have -- but they would not have that incremental in 

4 price, is my understanding.

5 MR. PATTERSON: Yes, they will still have 

6 that incremental in price -- that incremental in 

7 price --

8 MR. DeLASKI: The same increment?

9 MR. PATTERSON: Yes, because they don’t 

10 have the cooling space required that an open 

11 transformer has. One of the problems with 

12 transformer design is you’ve got to get the heat out 

13 to limit the perimeter loss.

14 MR. DeLASKI: Sure.

15 MR. PATTERSON: So you can do it two ways. 

16 You can do it by either increasing the amount of 

17 radiators that you put on the transformer, which 

18 increases its footprint, or you can design the heat 

19 out of it. Things that go down in the vault are 

20 designed with the heat out of them to begin with.

21 MR. DeLASKI: So you said -- I think you 

22 said on a network, you said, I assume just off the 

23 top of your head, you said --

24 MR. PATTERSON: The network is unique 

25 because it’s got these gigantic expensive network 
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1 protector on it.

2 MR. DeLASKI: Right, you said it was a 

3 three-times price, I think is what you said.

4 MR. PATTERSON: Easily.

5 MR. DeLASKI: And the vault, or would you 

6 say off the top of your head?

7 MR. PATTERSON: I’d say it’s in the same 

8 basic level as the network. Runs very high. 

9 PARTICIPANT: It won’t have the network 

10 protector.

11 MR. PATTERSON: It won’t have the network 

12 protector.

13 MR. PARKER: Excuse me. We have to follow 

14 the custom of announcing your name. This is for the 

15 court reporter and for the record. So we’re going 

16 to have to -- I like the free-flow conversation, but 

17 we’re going to have to slow it down and be a little 

18 bit more formal so that people announce their names 

19 before they give their comment. Go ahead.

20 MR. SAMPAT: This is Mahesh P. Sampat, EMS 

21 Consulting. The vault transformer would be cheaper 

22 than the network transformer because it will not 

23 have the network protector, but more expensive than 

24 the pad mount transformer. I concede with that. 

25 Only additional comment I got is if you look at the
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1 pad mount transformer versus pole type, single 

2 phase, there is a desire among the manufacturers to 

3 keep the same efficiency so that can use same core 

4 and coil between single phase pad and single phase 

5 pole. So I’m not sure why we need a separate 

6 equipment class for pad mount. The cost structure 

7 is different, but it’s an incremental cost. It has 

8 nothing to do with core coil and the efficiency. So 

9 that would be my comment.

10 MR. PARKER: Okay. 

11 MR. PATTERSON: Wes Patterson, again. 

12 Mahesh --

13 MR. PARKER: Excuse me just a second. Can 

14 I interrupt, if everybody who’s not speaking could 

15 turn their mics off, apparently we’re driving our 

16 webinar people crazy with the feedback on the mics.

17 MR. PATTERSON: Actually, the driver for 

18 distinguishing the pad and the pole has to do with 

19 the complication of the weight and size change on 

20 the pole, not so much its efficiency. There are 

21 constraints about the weight and size restriction on 

22 the pole that would prohibit us from pushing the pad 

23 mount efficiencies as much as we could.

24 MR. PARKER: Just a second, Phil.

25 MR. ROSENSTOCK: Steve Rosenstock, to 
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1 follow up what Bruce said earlier today, especially 

2 in urban areas, it’s not weight and size, there also 

3 could be some safety consideration with other 

4 utilities located nearby that, even if they wanted 

5 to go to a bigger size transformer, they can’t 

6 because they’re physically and maybe legally limited 

7 in terms of their -- I’ll say their height, length, 

8 width, depth ratios in the space that they already 

9 have. They cannot expand any of the dimensions 

10 whatsoever.

11 MR. PARKER: Okay. Phil.

12 MR. HOPKINSON: Phil Hopkinson. What I 

13 would say on each of the classes, to begin with, to 

14 go over to the far right and knock off both the 

15 vault and networks, then -- and I have not yet 

16 knocked off substation because I think that belongs 

17 in. But the vault and network have protection for 

18 immersion in water to oftentimes the vaults get 

19 flooded, and so those are particularly heavy-gauged 

20 steel and they are also treated with a surface 

21 protectant, and they’re different. And they 

22 oftentimes also have a temperature class of 55 

23 degrees rise instead of 65 degrees C rise, so 

24 they’re just plain different and the result of it is 

25 it’s not worth considering in this group.
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1 On the one to the left, I would say that 

2 on pad mounted transformers, they’re a little 

3 different than pole types because they’re generally 

4 in pole types, more of a stub-out kind of 

5 connection. The coils come up and the leads go to 

6 the bushings, and yes, there are lead losses and 

7 stray and etti losses associated with the tanks on 

8 poles, but it gets worse on large, three phase pads, 

9 where the bus work runs parallel to the core clamps 

10 and to other parts that can heat up and cause 

11 greater degree of stray and etti loss. And so pad 

12 mounts are somewhat unique in themselves also. And 

13 the substation transformers would be in the same 

14 kind of category. 

15 MR. ANDERSON: Rick Anderson, Fayetteville 

16 PWC. Question about substation transformers. 

17 You’re not talking about 230 KV stepping it down to 

18 12 KV, are you? I don’t see that as --

19 MR. PATTERSON: No. The -- Wes Patterson 

20 -- no, we’re not talking about 230 KV primary. 

21 There are a class of transformers which are --

22 various companies have different names for it, but 

23 yeah, it’s built like a big 230 KV substation, but 

24 it’s only 36 KV primer. So you have primary unit 

25 subs, secondary unit subs, and full subs. We’re 
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1 talking only 36 KV, right. But the way it’s 

2 constructed, the tank and the bushing configuration 

3 is similar to the substations the utility guy 

4 normally think about.

5 MR. PARKER: Gary Fernstrom.

6 MR. FERNSTROM: Richard, Gary Fernstrom 

7 speaking for the California utilities. The way 

8 transformers are used across the country is diverse, 

9 but at least out in California, we don’t use very, 

10 very large pole mount transformers. So the height 

11 is a consideration of the transformer, because you 

12 have the clearance between the primary and secondary 

13 on the pole. However, the diameter is not so much 

14 of a consideration, so we’re not real concerned 

15 about change in the diameter of pole mount 

16 transformers in the size that we purchase.

17 And secondly, getting to Andrew’s point, 

18 the vast majority of transformers are not vault 

19 mounted, they’re not network transformers, they’re 

20 not substation transformers, for sure. So in the 

21 interest of getting at the majority of the market, 

22 we should be looking at pad mounts and pole mounts. 

23 Thanks.

24 MR. PARKER: Yes, thank you, Gary. I 

25 think that’s helpful, and I do want to focus on the 
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1 majority of the market. One thing that we need to 

2 bear in mind, we don’t have Dan Cohen from General 

3 Counsel here, but I feel pretty confident as a 

4 lawyer that he would make this point, so I’ll make 

5 it on his behalf, and that is that this is a 

6 regulation that applies to manufacturers and is 

7 enforced vis-à-vis manufacturers. And so there 

8 needs to be some way to specify, if you’re going to 

9 create a separate equipment class for network and 

10 substation, or vault transformers, there needs to be 

11 a way of translating that into some specification 

12 for the physical design of the product so that 

13 you’re not having to -- the manufacturer is on 

14 notice that this kind of equipment class is subject 

15 to this standard, as opposed to, well, we will be 

16 subject to this standard if we sell it to this kind 

17 of user at the end of the day. Because I think 

18 that’s not the way -- my understanding, and correct 

19 me if I’m wrong, but my understanding is that’s not 

20 the way the efficiency standards have worked in the 

21 past. There’s not an administrative apparatus for 

22 gathering that kind of information. These are 

23 standards designed according to physical 

24 characteristics of equipment class, so we have to 

25 think of specifications for that. Wes.
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1 MR. PATTERSON: Wes Patterson. There is 

2 IEEE product standards specifically for a class of 

3 products called pad, a class of product called pole, 

4 and a class of product called network transformers, 

5 that are well established in the industry, which has 

6 all the physical characteristics of each one of 

7 those three products.

8 MR. COFFEY: I think in general DOE often 

9 likes to take established industry standards as a 

10 starting point for doing things like setting 

11 equipment classes. The question would be, are these 

12 adequate? Do they constitute a loophole in any 

13 regard? Or, you know, we would need to define what 

14 is a vault and come up with a water-tight set -- no 

15 pun intended - set of specifications that someone 

16 could look at a vault and say unambiguously, this is 

17 a vault transformer, these are the standards that it 

18 must meet. And those would presumably be linked to 

19 the features of that device that generated the cost 

20 increase in the first place, whether it’s the heavy 

21 gauge steel or the water-tight coating. That’s the 

22 kind of way that we need to be thinking in doing 

23 this exercise.

24 MR. PARKER: Wes, does the IEEE 

25 specification do that, in your view?
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1 MR. PATTERSON: Yes, it does. So you 

2 could start with it as a definition, and then we 

3 could do like we did with the test code, we could 

4 just rewrite the IEEE one into a DOE document.

5 MR. PARKER: Would that cover the vault as 

6 well as the network?

7 MR. PATTERSON: I’m not so sure as Phil is 

8 with the vault, but it could be tweaked. The DOE 

9 could tweak it to cover the vaults.

10 MR. PARKER: Okay. Is there general 

11 consensus in following the IEEE specifications and 

12 working out within the next very short period, any 

13 tweaks that we need to do to -- what’s that? Excuse 

14 me. John.

15 MR. CYMBALSKY: Yeah, I mean, we’re making 

16 -- I think you’re trying to make decisions that I 

17 think we need more time to look into these 

18 standards, and if there’s test procedures, these are 

19 things we cannot decide right at this table.

20 MR. PARKER: Yes, Andrew.

21 MR. DeLASKI: So in principle, I think, 

22 looking first to the IEEE standard makes sense. I 

23 haven’t read it yet. We want to be able to read it. 

24 But I think that starting with industry standards 

25 makes sense. And then we want to make sure that it 
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1 satisfies the criteria that Brian just laid out. 

2 We went through a similar experience in 

3 negotiating new home refrigerator standards recently 

4 where we negotiated new standards for refrigerators, 

5 but we created a new class for built-in units. It’s 

6 a space-constrained refrigerator, okay, and a new 

7 class was created, recommended by us and industry, 

8 together, and formed the basis for a consensus 

9 recommendation that the government move forward on 

10 through a different kind of negotiation, but a 

11 negotiated standard that I think quite likely would 

12 not have happened in a normal rulemaking, contested 

13 rulemaking process. I think it’s one of the 

14 advantages of the process we’re engaged in here 

15 today is that we can talk about creating these kind 

16 of product classes that I think might not happen in 

17 a contested rulemaking. 

18 DOE -- there’s a vault issue and this 

19 network issue came up extensively during the last 

20 rulemaking, and DOE decided not to set separate 

21 standards for these at that time. So I think this 

22 is -- I agree with the notion that we should 

23 separate out these products for analytic purposes 

24 and see what standards -- see what the analysis 

25 says. They may or may not ultimately decide on a 
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1 separate standard for them, but it’s useful to 

2 separate them out.

3 MR. PARKER: Okay. Fine. John, could you 

4 amplify a little bit? Is there a problem with this 

5 group making a -- nothing that we do binds the 

6 Department. It’s our recommendation.

7 MR. CYMBALSKY: So I guess the approach is 

8 to look at it, and we can agree to look at it. We 

9 don’t -- we can’t make the statement that we agree 

10 to adopt these IEEE things right now. That’s all.

11 MR. DeLASKI: This is Andrew again, just 

12 to amplify on that. So we, using my example again, 

13 we actually spent a lot of time on that definition, 

14 how you define a built-in refrigerator, and in fact 

15 the lawyers got involved in depth, because we were

16 very concerned that -- about loopholes, that 

17 suddenly that thing we’re calling a vault 

18 transformer is now being installed on pads as the 

19 lowest cost option of our marketplace. So that’s 

20 the kind of thing we want to be looking at to make 

21 sure we’re not creating a loophole that undermines 

22 what we’re trying to accomplish.

23 That takes a -- an industry standard 

24 typically wasn’t designed for that purpose, avoiding 

25 loopholes, so we have to make sure that it serves 
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1 that purpose which is being repurposed for.

2 MR. PARKER: Okay. That’s a good point. 

3 Phil.

4 MR. HOPKINSON: Yeah, Richard and John, 

5 and by the way, John, nice to actually see you here 

6 this morning. My son also works for the DOE. He 

7 told me to tell you he’s working hard.

8 The title of C57.12.40 is “IEEE standard 

9 requirements for secondary network transformers, 

10 subway and vault types.” And I have the scope here 

11 and so on too. So if you would like, I can just 

12 send, I think my normal communication has been to 

13 send to either Richard and the whole group or to 

14 send just to Brian Coffey, however you wish to have 

15 it submitted. But it’s a big standard.

16 MR. PARKER: Why don’t you just send it 

17 around. Yes, Bob.

18 MR. BERMAN: Robert Berman, Berman 

19 Economics. With those definitions and 

20 specifications, when we look at them, if there could 

21 be some way of identifying what the differences are 

22 from one specification to the next, and then for 

23 those of us that read dollars rather than 

24 engineering notation, and maybe sensitive to how 

25 something might cross from one market to another, if 
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1 you could -- if we could look at the cost of some of 

2 those differences, then that could help us with the 

3 question of loopholes, I think.

4 MR. PARKER: So I guess the -- go ahead, 

5 sorry.

6 MR. ROSENSTOCK: Just a quick one. Steve 

7 Rosenstock, EEI. These are technical definitions. 

8 There’s nothing about the specific design or 

9 application or anything else. These are purely 

10 technical definitions about what they are, as 

11 defined by IEEE. It’s not -- you really can’t use 

12 them to do any sort of economic comparisons because 

13 these are purely technical or descriptors. So I 

14 don’t think you’d be able to use these technical 

15 definitions that hopefully the parties could agree 

16 to do any sort of that analysis that you’re 

17 referring to.

18 MR. BERMAN: Yeah, Robert Berman, Berman 

19 Economics. The technical definitions talk about how 

20 the transformers are built and building it in 

21 different ways so I assume is a different cost. And 

22 what I’d like to get an understanding of is -- is it 

23 a different -- to what extent is there a different 

24 cost? Is the difference, you know, yellow paint in 

25 one area and not in another kind of thing, which 
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1 would have a very low cost, or is the difference, as 

2 Wes points out, it’s got this -- these protectors on 

3 it that are hugely expensive, and that’s a big 

4 difference? If we can see what the differences are, 

5 to see whether or not they’re not only different 

6 products from an engineering application 

7 perspective, but are also different products from an 

8 economic perspective so that we can take a look and 

9 see what they would look like in the market.

10 MR. PARKER: Is it possible to get, from 

11 either Navigant or people around the table, a short 

12 concise summary of the key physical differences 

13 between the network-slash-vault type transformers 

14 and the regular pad mount that we could look at, 

15 both to determine whether we have adequate data to 

16 create a separate category for them analytically, as 

17 well as to address the loophole question? Wes.

18 MR. PATTERSON: As a first pass, Wes 

19 Patterson -- as a first pass, at the last meeting I 

20 gave a PowerPoint. I provided a picture of each of 

21 these. All we have to do is look at the picture. 

22 You don’t have to be any more enlightened than 

23 looking at that picture to say, we’re looking at 

24 apples, oranges and pears. Just look at the 

25 picture.
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1 MR. PARKER: Well, in a term sheet or any 

2 kind of legal or quasi legal document, we’re going 

3 to have to have some kind of specification that goes 

4 beyond a picture, I think, so that we can indicate 

5 what transformers fall into which category.

6 MR. MILLURE: Dave Millure, Metglas. I’m 

7 assuming we’ll also be able to break the market and 

8 the energy savings out by these new classifications 

9 so that we can see what the impact is of different 

10 efficiency levels versus the different design lines.

11 MR. PARKER: Have you gathered data for 

12 network and vault transformers?

13 MR. COFFEY: I think to do that economic 

14 calculations -- and this is really an LBL question, 

15 but I think insofar as there is data available for 

16 that, we could start to talk about doing it. But I 

17 think at this point we don’t really know exactly 

18 what that would be.

19 MR. RIVEST: So if we were to make 

20 decisions based on these new classes, we wouldn’t 

21 know what the impacts are on energy savings?

22 MS. COUGHLIN: For the purposes of the 

23 LCC, if the cost efficiency relationship is 

24 different --

25 MR. PARKER: Excuse me, this is Katy 
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1 Coughlin, LBL.

2 MS. COUGHLIN: Yeah. Essentially we would 

3 need to see whether the cost efficiency relationship 

4 is substantially different, and if it is, we would 

5 run an LCC based on the data for that particular 

6 product class. So it’s an open question at this 

7 point whether the price efficiency relationship is 

8 going to be significantly different, because again, 

9 it’s the increase in price as you increase 

10 efficiency that affects the LCC results.

11 MR. PARKER: Is there a prima fasciae

12 reason to believe that there is a major difference? 

13 Wes?

14 MR. PATTERSON: If the issue is not 

15 absolute unit price, but price change for lost 

16 improvement, then I believe what you will find is 

17 the underlying physics for that characteristic will 

18 be the same in all four of them, no different. What 

19 does change is restrictions on size, weight, 

20 application. But the physics of the transformer 

21 will be the same across all four of them.

22 MR. RIVEST: This is Mike Rivest. I 

23 think, you know, in different rulemakings we stumble 

24 upon this type of problem of space constraints, and 

25 we’ve handled it differently in different 
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1 rulemakings. So Andrew described a situation where 

2 we basically created a new product class because we 

3 were limiting the size of the product to very 

4 specific, a very specific opening. And so we 

5 created a constraint on the size, and then did an 

6 engineering analysis that had dimensional 

7 constraints. And when you create dimensional 

8 constraints it means that you quickly get into more 

9 expensive steels. So you don’t have the same range 

10 of design options that you do if you don’t have a 

11 space constraint. So that’s one way of dealing with 

12 that kind of problem.

13 Another way of dealing with this problem, 

14 which is the way that pole mounts was treated in the 

15 earlier rulemaking, is to internalize the costs of 

16 pole changeouts, and bring it inside the cost of the 

17 end user installation cost, and sort of distribute 

18 it across all users. So that’s the way of handling 

19 the situation.

20 So the incremental cost might be the same, 

21 assuming you had the same amount of space. Here 

22 it’s sort of a hybrid. It’s -- in a replacement 

23 situation it might be more like the refrigerator. 

24 In a new construction situation, it might be more 

25 like a full mount. So I guess you could go either 
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1 way. But I could see doing an analysis here with 

2 the engineering that would simply limit the outward 

3 dimensions.

4 MR. PARKER: Katy, did you want to 

5 respond?

6 MS. COUGHLIN: I wanted to mention that we 

7 already included in the LCC the installation issues 

8 associated with space constrained and weight issues 

9 with poles. And that’s going to be reviewed this 

10 afternoon, so we may want to table this discussion 

11 until this afternoon, and then once we present in 

12 more detail how the installation issue has been 

13 dealt with, you can comment on whether you think it 

14 needs further improvement.

15 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

16 Does that include the vault issues as well? Thank 

17 you.

18 MR. DeLASKI: Was there a response to 

19 Steve’s question?

20 MS. COUGHLIN: Yes, it does.

21 MR. ROSENSTOCK: So, just to be clear, so 

22 then --

23 MR. PARKER: Andrew DeLaski.

24 MR. DeLASKI: -- the analysis includes 

25 costs for vault changes, that’s embedded in the 
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1 analysis. Now that’s just spread right over through 

2 averaging.

3 MS. COUGHLIN: Well, again, we can get 

4 into the details this afternoon, that may be more 

5 efficient. The analysis deals with space 

6 constraints, so if the installation is space 

7 constrained, then we go through some additional 

8 steps to go through the LCC. 

9 MR. DeLASKI: But do you know off-hand, I 

10 know we’ll get it this afternoon, but are there --

11 do you have some portion of units that you say, oh, 

12 this one -- the vault’s too small so we have to make 

13 adjustments because the vault won’t hold the bigger 

14 transformer?

15 MR. BOLDUC: Hi, Chris Bolduc, LBL. The 

16 issue with pole costs, because it’s --

17 MR. DeLASKI: Sir, I said vault.

18 MR. BOLDUC: I’m sorry.

19 MR. DeLASKI: Excuse me.

20 MR. BOLDUC: With vault it’s examined as a 

21 separate group, with the LCC, it’s examined 

22 specifically to sub-group. We add additional 

23 markups to the installation of the transformer and 

24 we present results. They were in the draft chapter 

25 seven that was distributed earlier.
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1 That issue of pole costs, we have an 

2 algorithm for pole replacement, we’ll review it in 

3 the afternoon. Pole replacement is handled much 

4 like Mike suggested, where the incremental change in 

5 installation cost is spread out across the entire 

6 analysis. Based on feedback from the committee and 

7 past rulemakings, we’ve -- it sounds like pole 

8 replacement is a far more common occurrence than 

9 vault replacement.

10 MR. PARKER: Thank you. Carlos.

11 MR. GAYTAN: Carlos Gaytan, Prolec, GE. 

12 We already have some consideration of the four 

13 classes for pole mounts and pad mounts in the way we 

14 define the design lines. The design line one is a 

15 50 KVA rectangular tank, so you need to consider 

16 that’s a pad mount design. Design line two is a 25 

17 KVA round tank, so the design is well created for 

18 pole mount designs. 

19 And I agree with Wes’ statement that the 

20 deltas from the baseline are -- can be consistent, 

21 and the only change is the baseline price, because 

22 of the physical differences in accessories and bank 

23 requirements.

24 MR. PARKER: Okay. So I take it then that 

25 the two things that I’m taking away from this is 
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1 that it may not be a huge issue if the delta for the 

2 network and vault are not different from the deltas 

3 for the pad mount. And secondly, that we’ll get 

4 some further illumination from this when LBL does 

5 their analysis this afternoon. So why don’t we 

6 table this discussion until then, and come back to 

7 it when we have that analysis. Then I think we will 

8 be able to decide what to do once we have that.

9 So I think this is a good time for a 

10 break. Why don’t we take like a 15-minute restroom 

11 break, come back here at 11:30 and we’ll wrap up 

12 Brian’s presentation of engineering issues. Thanks.

13 (Whereupon, at 11:12 the meeting was 

14 recessed for a 40 minute period, reconvening at 

15 11:52 a.m.)

16 MR. PARKER: Okay. Thanks everybody. 

17 Let’s get started. Just a couple of follow-up items 

18 from the first discussion. I thought it was very 

19 helpful. With regard to the data exchange, I think 

20 we need to work on finalizing that. I understand 

21 that Navigant is working with Bob Smith and Bob 

22 Greeson on meeting their concerns. If there are 

23 other issues, if you want to raise it, I think the 

24 point is now is the time to do it. This is upstream 

25 of everything else, so if you have concerns just 
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1 about the data, not policy calls about what kinds of 

2 metals should be chosen, but problems with 

3 validating the data, particularly for medium voltage 

4 dry type where I think new data is still coming in. 

5 Please get those in to the mix really right away, 

6 because we need to finalize that absolutely as soon 

7 as possible so that we can plug that into the LCC 

8 analysis and so forth. 

9 So we’ll work through Friday with low 

10 voltage. We should be looking for early next week 

11 to get any further input that you want into the mix. 

12 You’ve had the template now for a couple of weeks, 

13 so please consider this the last gavel call for that 

14 and we’ll ask at that point, probably next week, but 

15 very soon for Navigant to incorporate that and make 

16 -- and come back to the group with any adjustments 

17 that are needed.

18 Also I should mention, that just on a 

19 process point, that I’ll be working with the 

20 Navigant staff to set up a share point web interface 

21 so that the group can communicate more efficiently 

22 electronically. It will allow us to create 

23 discussion threads that we’ll organize the 

24 discussions topically so that there will be one 

25 single site. You won’t have to sort through all of 
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1 the e-mails that have come in. There will be one 

2 single site that you can go to and look at what 

3 comments have been posted, and reply to comments, to 

4 create a new thread if you want to create a new 

5 thread. I will moderate that. We should have that 

6 up, I understand from the technical staff, that that 

7 should be up by early next week to middle of next 

8 week. So that will help facilitate our work, I 

9 think between meetings substantially.

10 But we do need to really put the data 

11 stuff -- the data issues to bed, make any 

12 adjustments that are needed and have that finalized 

13 very, very soon so that LBL can do their LCC 

14 analysis, confident that they have the right data. 

15 Of course that presumes certain -- the resolution 

16 of certain issues like what equipment classes and so 

17 forth, and we’ll need to finalize that discussion 

18 before we adjourn for this meeting as well.

19 I also missed a discussion we should have 

20 at the beginning of the meeting. I had on the 

21 agenda an item about rules of procedure. Let me 

22 just talk about that very, very quickly.

23 Finalization of Rules of Procedure

24 In our first meeting we agreed on rules of 

25 procedure after an extensive discussion. After that 
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1 meeting, one person said to me, well, you know, we 

2 haven’t had a legal counsel look at this, and could 

3 we have them vet it first. So I went back to the 

4 group by e-mail and one said, well, you know, I’ll 

5 open this up to any objections, if people have them, 

6 based upon legal counsel if they feel that there are 

7 legal issues raised. So let me just ask if there 

8 are any -- I consider that we still have an 

9 agreement, but it can be annulled, I suppose, if 

10 anybody finds, on the basis of their talks back home 

11 that they have major problems with the rules of 

12 procedure or timeline that we’ve agreed. So let me 

13 just say, ask the group now is there anybody that 

14 wanted to raise a concern about the ground rules 

15 that we adopted before, based upon their 

16 considerations back home since the last meeting.

17 MR. ROSENSTOCK: Steve Rosenstock, EEI, 

18 not a concern, but just double-checking again. I 

19 think -- I just remember there were so many votes 

20 taken about what the consensus is, just double21 checking that everyone is, under 3A, that this is 

22 the final version of what the consensus is going to 

23 be. I just remember a series of votes, and I think 

24 we came out to this, but there were some concerns 

25 about how many negative votes or anything, so I just 
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1 wanted to make sure that this was what everybody --

2 what we finally, you know, wound up with. I’m 

3 pretty sure it is, but there were some questions.

4 MR. PARKER: Yes. I think what was agreed 

5 was that consensus would mean unanimity, but a no 

6 vote or an abstention would not defeat a finding of 

7 unanimity, that only no votes would be counted as 

8 undermining a consensus.

9 MR. ROSENSTOCK: Thank you.

10 MR. PARKER: Okay. I don’t think we need 

11 another vote unless there’s somebody who wants to 

12 ask for another vote. Okay. Great. We’ll consider 

13 those finally finally adopted, then.

14 Let’s return then to Brian. I think we 

15 made our way -- two-thirds of the way through his 

16 bullets. I think he’ll turn now to resolving and 

17 responding to some of the open-ended questions that 

18 were raised last meeting and in the e-mails. 

19 Thanks Brian.

20 MR. COFFEY: Well, I’m not quite to the 

21 questions yet, but I think -- what I heard with 

22 respect to this issue of new liquid equipment 

23 classes was that really the cost increments weren’t 

24 that different across these different types of 

25 units, it’s more that there’s sometimes an issue of 
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1 limited space for certain applications. And so --

2 and maybe weight too, so dimensional and mass 

3 constraints. And if that were the case, that sounds 

4 to me like something that probably does not require 

5 new equipment classes, but would require an 

6 economic treatment and incorporation of those costs. 

7 Right now, we handle that in the LCC, and so if 

8 nobody objects, I’ll let LBL speak to that in their 

9 presentation.

10 MR. ECKMAN: Just one point on that, if 

11 the economics turn out --

12 MR. PARKER: Tom Eckman.

13 MR. ECKMAN: Yeah, Tom Eckman from 

14 Northwest Council. If the economics of 

15 installation, not manufacturing, but the economics 

16 of installation turn out to drive the different 

17 efficiency level because the installation costs turn 

18 out to produce a different life cycle cost, then 

19 that may be a reason for dividing the classes. If 

20 that doesn’t turn out to be the case, then it’s no 

21 reason to divide the classes. So it’s really 

22 contingent on what the analysis shows, in my mind, 

23 to see whether or not we get a different answer for 

24 pad, pole, and network/vault, based on installation 

25 costs. So looking at them separately without 
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1 peanut-buttering them all together to see whether 

2 you get a different life cycle cost answer, before 

3 we decide on whether or not there needs to be 

4 product classes makes sense.

5 MR. PARKER: Thank you. Wes.

6 MR. PATTERSON: Wes Patterson. If the 

7 difference will be based on an economic evaluation, 

8 I believe that when the DOE looked at the cost of 

9 pole change, they were just figuring the cost for 

10 the pole itself, and not changing the other utility 

11 lines that are on the pole, and that is the 

12 significant cost driver on the poles. With the pads 

13 or the networks, the network transformers and the 

14 vault transformers, it’s -- essentially what we’re 

15 talking about is going into Manhattan and digging up 

16 the sidewalk and making a bigger hole in the ground. 

17 That can become extremely expensive very quick, and 

18 I don’t know how those costs have been factored into 

19 the LBL analysis.

20 MR. PARKER: So I think LBL’s going to 

21 address that when they make their presentation.

22 MR. COFFEY: Okay. Then I think we can 

23 move on. 

24 Scaling Approach

25 I did promise to overview quickly the 
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1 scaling approach that I had mentioned earlier that 

2 could be used for instance, in the BIL case, so I’ll 

3 go through that quickly right now. 

4 Here we’ve got an efficiency versus a KVA 

5 plot, and don’t make too much of absolute numbers. 

6 It’s just to show that maybe there are two types of 

7 equipment that have sort of different cost 

8 efficiency trajectories, maybe one’s a high BIL case 

9 and another is a low BIL case. And so here are the 

10 curves. 

11 If you plot -- you know, every efficiency 

12 implies a loss, right, at a given loading point, so 

13 we can show this equivalently by plotting losses 

14 versus KVA, and we end up with something that looks 

15 like this. Of course, the red curve, which was on 

16 top in the previous plot is now below the blue curve 

17 because the more efficient unit has lower losses.

18 These are both power law functions, so 

19 they’re both the KVA raised to a number, and 

20 historically these numbers are both .75, and so the 

21 nice feature about power law functions is that if 

22 you plot them in log space, they become straight 

23 lines, and the slopes of those lines are equal to 

24 the exponent that you were raising your variable to.

25 So, again, we can show this same data 
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1 equivalently, like this, and we’ve got now the log 

2 of KVA on the X axis and the log of losses on the Y 

3 axis. And so now we’ve got two types of products 

4 and we’re discussing whether they’re going to have 

5 different standards, and the way that we could 

6 adjust that is by figuring out what this offset is. 

7 And so that’s where maybe some test cases or even 

8 feedback from manufacturers could be taken and used 

9 to estimate what this offset is that I’m indicating 

10 in yellow here. And so then from that you back out 

11 what are the losses and then what are the 

12 efficiencies that that implies.

13 I don’t know if I’m going into a good 

14 level of detail here. This is something that Wes 

15 has talked a lot about, if you want to add to this.

16 MR. PATTERSON: Yes, I think this was 100 

17 percent the way you should do it. And we can 

18 provide you the offset. For the level of accuracy 

19 that we’re going to obtain, it is going to be 

20 sufficiently accurate.

21 MR. COFFEY: Okay, great. 

22 MR. PARKER: Any other comments on this?

23 MR. COFFEY: I’m basically saying here 

24 what I’ve said in the discussion. I’m asking, is it 

25 a useful methodology for treating the scenarios that 
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1 we talked about before with BILs, potential 

2 equipment classes, though it sound like we may not 

3 need those. And so we would need some corroborating 

4 engineering data on transformers designed to certain 

5 As and Bs to determine what that proper offset is.

6 MR. PATTERSON: Wes Patterson again. I 

7 think the focus on A and B may not be appropriate, 

8 that a better focus would be on the change in 

9 losses.

10 MR. COFFEY: So I think -- there’s a 

11 question, you know, when you have these two curves 

12 of where do these curves come from? What are you 

13 holding constant to get that offset? And if you 

14 looked at the market today, the medium voltage dry 

15 type -- well, let’s say the liquid even, there are 

16 different transformers sold at different BILs and 

17 the higher BIL units presumably have different 

18 costs, maybe higher costs, and different 

19 efficiencies, maybe lower efficiencies. So when 

20 you’re looking to compare a mid-level BIL unit to a 

21 high level BIL unit, you have to hold something 

22 constant to make that comparison. And the thought 

23 that we were having was that maybe you hold constant 

24 someone’s evaluation of loss, so you say someone 

25 with four to one A to B factor would purchase this 
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1 type of medium BIL transformer and this type of high 

2 BIL transformer, and from there you would derive 

3 your offset. Something’s got to be held constant. 

4 So that’s something we can talk about.

5 MR. HOPKINSON: Brian, Phil Hopkinson. 

6 What I would say is that the OPS program is actually 

7 a pretty good, useful tool. Of course it needs 

8 calibration. But at the same time, I think that 

9 it’s run by A and B factors so if you tell it that 

10 you want to run a 95 KV-BIL, then you’re going to 

11 get, after you’ve given it an A and a B, you’re 

12 going to get a series of designs that will tell you 

13 what it would be for different steels and different 

14 conductors and so on. 

15 So you have to really calibrate it, you’ve 

16 got to give it a starting point. If you want to do 

17 it at 150 KV-BIL, it’ll do that too, but again, you 

18 have to identify what the value of the watt saved 

19 and what the load assumption that really gives you 

20 the B value. 

21 So I think that when we get into finally 

22 settling on the vision -- I’m going to take this 

23 opportunity, Richard, if I could -- and the vision 

24 of what we’re trying to get to, there’s really only 

25 three things. The first is, what’s the value of a 
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1 watt saved? And when I get a chance this afternoon, 

2 I’ll come back to it and get a chance to tell you 

3 what I did, and if you don’t like it, it’s quite all 

4 right, but I would like to see what you like better 

5 and get into a discussion on that. But we need to 

6 settle on what the value of a watt saved is the 

7 first thing.

8 The second is the loading assumption, 

9 because that’s going to set up the B value, and 

10 you’ve got to know what the RMS equivalent load is 

11 that the transformer is used at. Again, I’ve got a 

12 method and I think the EEI guys will have some other 

13 thoughts, maybe supporting thoughts, but those ought 

14 to get out on the table, and we need to settle on 

15 that loading assumption because that’s going to give 

16 the final thing, which is the material and selling 

17 price curve versus the efficiencies.

18 And I think we have, in agreement with 

19 what’s gone on at OPS, gotten the liquid filled 

20 transformers so we’re reasonably close over a narrow 

21 range of efficiencies. At the high end of 

22 efficiency I still see some issues that I haven’t 

23 figured out exactly what caused them.

24 On dry types, huge differences and so we 

25 haven’t settled those yet, but we’ll come back. But 
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1 we do need to settle on the three factors: the value 

2 of a watt, the loading assumption, and then the cost 

3 curve and after that I can certainly go home and not 

4 come back to these meetings, even though they’re 

5 great, and I think the rest would be for the 

6 stakeholders to decide what they really want to use.

7 MR. PARKER: Thank you. Yes, I think --

8 go ahead, yes.

9 MR. ANDERSON: Let me take this, Steve. 

10 Rick Anderson, Fayetteville PWC. Phil, you’re 

11 right. What’s really critical in this is the B 

12 factor. How you load transformers in Baltimore is 

13 different than the way you load transformers in 

14 Raleigh. A pad goes in a subdivision, that’s 

15 different than a pole out on a rural distribution 

16 line. So one size does not fit all. So, generally, 

17 when you go back and look at pads, and poles, you 

18 have single phase pads, and they’re loaded a certain 

19 way. You have three-phase pads, they’re loaded a 

20 certain way.

21 Pole type transformers are loaded 

22 differently than three-phase pads, so one size does 

23 not fit all. We really do need to come up with a 

24 consensus on loading. If you look in the National 

25 Electric code, there’s diversity tables for electric 
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1 ranges. We have no diversity tables for electric 

2 utility applications because it varies. We’ve got 

3 one user here, Ken, he’s out on the west coast up in 

4 the mountains and he’s got to derate his 

5 transformers by eight percent just due to his 

6 elevation. So it’s not one size fits all. We need 

7 to be really clear when we turn around and say this 

8 is the characteristic of a single phase pole, single 

9 phase pad, three phase pad, vault, substation type 

10 transformer. It’s all different so we just need to 

11 be cognizant of that as we look at the data going 

12 forward.

13 MR. PARKER: Yes, Steve.

14 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

15 In terms of some of the scaling factors, I know it 

16 seems like there’s a lot between Wes and Brian and 

17 some other folks, but I’m wondering -- again, these 

18 charts show nice linear relationship -- well 

19 logarithmic, nice relationship, but obviously, like 

20 design line four is 150 KVA and it’s supposed to 

21 represent anywhere from 15 KV up to 500, and 

22 couldn’t there be multiple factors or couldn’t there 

23 be multiple variables, depending on whether you 

24 going above kind of the design line versus below, 

25 and would you be able to incorporate that into the 
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1 analysis?

2 MR. COFFEY: I mean there are always more 

3 variables, but what we’re trying to put our finger 

4 on is the scaling behavior with KVA and these 

5 curves, they’re linear in log space. They have 

6 different increments when plotted in cost efficiency 

7 space. So I mean I think this permits for modifying 

8 the cost efficiency behavior until we find something 

9 that everyone’s comfortable with. Does that answer 

10 your question?

11 MR. ROSENSTOCK: Well -- partially, but 

12 I’m just saying if the data shows that it’s 

13 different -- it’s a different K factor -- again, 

14 just say if you’re -- for transformers below the 

15 design line in that group, versus above, would you 

16 be able to incorporate that into the analysis? If 

17 the data shows that. For some reason the curve 

18 going smaller is a lot different than the curve 

19 going higher, and can you do that if for whatever 

20 reason the data shows different K factors, can you 

21 put that into the analysis?

22 MR. COFFEY: So that sounds like a 

23 secondary consideration and not -- maybe not an 

24 unimportant one, but, you know, I was thinking about 

25 it as first we would try to identify what’s the 
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1 scaling behavior within a K factor, and then if 

2 there was some heterogeneity across K factors, maybe 

3 after that then you make that adjustment. 

4 MR. PARKER: Let’s do this because I think 

5 this is an important technical issue. I think the 

6 issues about load factors and loss valuations are 

7 things that are going to come up in the LBL 

8 analysis, and those are cross-cutting issues that 

9 are very important and that’s going to have to be 

10 resolved. I think the issues about what is this 

11 offset here, it sounds to me like the people who are 

12 technically proficient believe that this is a 

13 technically sound methodological approach, and what 

14 I would propose is that we just have a working group 

15 work together on sort of finalizing this, giving 

16 Brian and the Navigant team the data that they need 

17 in the next few days as quickly as possible, to 

18 assess this load factor and then we’ll have a report 

19 back to me and to the group with the recommendation 

20 as soon as you have it, so that we could, hopefully, 

21 get this scaling issue, the final details of it, put 

22 to rest. I don’t think we can probably resolve that 

23 here if you need more data. I don’t think it has to 

24 be resolved here as long as we have a process for 

25 resolving it.
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1 So why don’t you please give, if you‘re 

2 interested or willing to work on this group, talk to 

3 Brian at our next break, form a group and work on

4 getting the analysis from your company or from your 

5 peers and let’s try to get a report done just as 

6 soon as they can get it done. And we’ll send it out 

7 by e-mail to the group, or put it up on the share 

8 point site and see if we can get by electronic 

9 means, that consensus on how to handle that, rather 

10 than spend more time on it now. Does that seem like 

11 a reasonable way to go?

12 Okay. Let’s go on then.

13 MR. COFFEY: Okay. So that wraps up 

14 scaling. At the last meeting, negotiators discussed 

15 the possibility of having a TSL that permitted 

16 grain-oriented steel and amorphous steel to compete 

17 in the market. And the charge was that we would 

18 meet with the steel suppliers and ask about what 

19 were their thoughts for -- what would this mean? 

20 How would you define this competitive market? And 

21 we agreed in principle on selling prices as a metric 

22 for equivalence, and there’s some caveats to that, 

23 but with, particularly in the case of what are the 

24 materials’ prices. But our operating hypothesis was 

25 that if two similar transformers, vary significantly 
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1 in price, one will probably not get purchased. So 

2 if you’re going to contend that two types of 

3 transformers are competitive, they’ve got to be in 

4 the same ball park.

5 So as an example of how we might look at 

6 that, here’s our design line five plot as it 

7 currently stands, and there’s a lot of colors of 

8 dots here, so let’s kind of zoom in on the action.

9 The bright green dots are the M3 

10 transformers. And so if you draw a line through the 

11 kind of lower right boundary of that, you get 

12 something like this. The yellow dots are ZEMH 

13 transformers, and so doing the same thing, you get 

14 that. And then these sort of maroon-salmon dots are 

15 amorphous units, and those have a flatter slope like 

16 this, as we currently modeled them.

17 And so when you say what’s the price 

18 equivalence, you can just start by looking at where 

19 those two curves, or those two lines intersect. For 

20 the ZEMH amorphous intersection, it would be about 

21 right here in efficiency. And you might say, well, 

22 they’re pretty close in that region so we’re just 

23 going to pick that CSL that it’s close to as the 

24 competitive point. That could be a judgment, and 

25 then it would be right here, pretty close to each 
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1 other. The M3 curve and the amorphous curve don’t 

2 intersect until a little bit lower, down here. So 

3 that’s the kind of -- and we will be releasing a 

4 tool, as I mentioned earlier, to allow some 

5 manipulation of the different steel prices for 

6 whatever value people can find in that, and that 

7 will obviously influence the intersection points of 

8 these two frontiers. 

9 So if someone said, well, I want to look 

10 at the case where M3 is a little bit cheaper than 

11 the M3 transformers get commensurately cheaper, then 

12 the intersection point moves to there. You can see 

13 that just the green curve moved, and the 

14 intersection of selling price walks upwards.

15 So I think people probably have a range of 

16 ideas about where materials’ prices are today, and 

17 where they might be headed in the future, and so 

18 this can allow folks to try it at home and pick 

19 their own scenarios and see what the outcomes are. 

20 Hopefully, that can be useful.

21 MR. ANDERSON: Rick Anderson, 

22 Fayetteville. Is that real data, Brian?

23 MR. COFFEY: This is our current design 

24 line five data.

25 MR. ANDERSON: So I want to make sure I 
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1 understand what I’m looking at. For an increase in 

2 efficiency from 99.45 to say, 99.5, I’m going to pay 

3 an additional $10,000 for the same transformer? 

4 What I’m buying today? I’m going to pay $10,000 

5 more? That doesn’t make any sense to me. From a 

6 user -- from a user standpoint. You’re basically 

7 telling me I’m going to get married to this and I 

8 have no choice, but to pay another $10,000 for what 

9 I’m using today, I don’t get that.

10 PARTICIPANT: (Comment off mic)

11 MR. ANDERSON: That doesn’t make any sense 

12 to me, to pay that much more money, $10,000 more, 

13 for an increase in efficiency of .05 percent? I’m 

14 thinking about the little old lady that I’m serving, 

15 that’s going to kill her.

16 MR. PATTERSON: Wes Patterson here, if I 

17 may. One of the problems that I see in the 

18 discussion is we talk about a tiny little change in 

19 efficiency, but that tiny little change represents a 

20 50 percent reduction in the losses. And I think in 

21 the context of the conversation, it would be better 

22 if we always looked at the change in loss, rather 

23 than the change in the percent efficiency. Because 

24 in that example we’re discussing right now, we’re 

25 talking about cutting the losses in half.
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1 MR. FERNSTROM: Gary Fernstrom from PG&E. 

2 I don’t think it’s really either of these things. 

3 It’s the economic value of the energy savings 

4 looking forward into the future. So, you know, 

5 whether it’s a half of a percent, or point five 

6 percent, or a 50 percent reduction in losses, the 

7 question is how much value is there associated with 

8 eliminating those losses for your little old lady 

9 customer, versus the initial investment. And that’s 

10 the question we have to answer.

11 PARTICIPANT: (Comment off mic)

12 MR. FERNSTROM: Yeah, that’s what the life 

13 cycle cost analysis is all about.

14 MR. PARKER: Right. I think that does --

15 that’s what their analysis should get at, whether 

16 the energy savings down the road justify the 

17 increased cost or not, and if the -- and if it’s 

18 excessive -- it should translate into the little old 

19 lady’s electric bill. Yes.

20 MR. SCHOEN: Gerry Schoen, AK Steel. When 

21 you look -- Richard, this is kind of a question for 

22 you, but it’s been asked before -- when you look at 

23 a cost escalation of about 40 percent, are you 

24 likely going to replace that transformer with a new 

25 transformer costing much more, or send it out and 
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1 have it rebuilt and put back into service.

2 MR. PARKER: I’m going to have it 

3 rebuilt.

4 MR. SCHOEN: We talked about in one of the 

5 earlier meetings about the tipping point between a 

6 refurbished decision versus a new decision. How 

7 much more -- Steve Rosenstock put an excellent paper 

8 out showing the cost escalation in transformer 

9 efficiency, compliance cost since 2010, that shows 

10 transformers have already gone up way above 

11 inflation. How much more does that go before it 

12 tips us back into a rebuilt. Because if you move 

13 from the two to three percent rebuilt return to 

14 service rate, which we have today, to 30, the life 

15 cycle cost analysis, it has to reflect that too. At 

16 least it should.

17 MR. HIRSCH: Bruce Hirsch, Baltimore Gas 

18 and Electric. Just to add to that, I just want to 

19 let everyone know, we’ve reached that point with 

20 some designs we’re using now, and the drivers aren’t 

21 necessarily the cost, but it is the size and the 

22 weight, where we can’t get a transformer to meet the 

23 current standards that will fit the area we need to 

24 put it in. So what we’re doing now is we’re doing 

25 more refurbishing of old transformers for particular 
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1 lines because that’s the only solution we have 

2 today.

3 MR. HYLAND: Mike Hyland with APPA. I 

4 just want to echo on that. We represent the 

5 municipal utilities and we are the most compact, 

6 customer-wise, of all the entities, and we have many 

7 of our utilities that are 100 percent -- 100 percent 

8 underground. So they are just vaults and certain 

9 pad mounts. So, there’s a huge issue on space. Not 

10 only that, we’ve hit the same tipping point with a 

11 few of our members where we’ve moved to just 

12 refurbishing where we can. You also have to 

13 understand that our business model, we are 100 

14 percent non-profit, so every single dollar is going 

15 to be put on the customer. There’s no going to a 

16 PUC asking for a rate increase. There’s no profit 

17 to be taken from. This is going to the consumer. 

18 Every single dollar we talk about here is going to 

19 the consumers and that is a huge issue for us when 

20 we’re also being asked to spend our money other 

21 places, on the savings per watt, whether it is 

22 energy efficiency lighting, we’re talking about the 

23 refrigerators. You’re getting to the point of where 

24 should we be spending our money.

25 MR. PARKER: Aaron.
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1 MR. MEYERS: Aaron Meyers. I think it’s a 

2 little bit -- I’m at a loss for a better way to 

3 describe this, but deceiving to the American public 

4 to have three years ago adopted an efficiency 

5 standard which looks at the payback period based on 

6 what was formerly a non-evaluated transformer, to 

7 adopt that standard, and now to look at the new 

8 standard as being the baseline without considering 

9 the fact that those two payback periods will need to 

10 sum. There’s nothing to prevent the Department from 

11 getting together two years from now and looking at a 

12 payback period from the point of the new efficiency 

13 standard, and justifying based on that. 

14 So if the payback period two years ago was 

15 15 years, and we adopt an efficiency standard with 

16 another 15 year payback, the old lady that Richard 

17 referred to, she’s going to be dead before that ever 

18 justifies itself.

19 MR. FERNSTROM: Well, I have a comment on 

20 that. Gary Fernstrom again. I’d like to talk about 

21 the little old man, because I’m close to fitting 

22 that model. And yeah, I’ll probably be dead before 

23 the 15, 20 year payback occurs, but we’ve got a lot 

24 of other things to consider. There are people that 

25 are going to continue to live through that period of 
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1 time, and we are concerned about energy waste and 

2 the economics of all this.

3 MR. PARKER: So these are some of the 

4 issues that I think are going to come up when we get 

5 down to negotiating the final thing. I’d like to 

6 focus here just on the methodology if we could, and 

7 make sure that we have comfort there, and then when 

8 we’re talking about what our positions are, all this 

9 comes to the fore. 

10 Just to clarify, as I understand it, this 

11 negotiation takes place within a legal framework 

12 that requires DOE to review its energy standards and 

13 change them -- or not change them, but at least 

14 review them to whether to change them, every six 

15 years. And so what’s going into effect now won’t 

16 take effect until 2016. We have an issue that legal 

17 counsel is talking about with the ... project about 

18 the flexibility of the complaints they issue. But I 

19 think under any scenario you’re looking at quite a 

20 delay before these standards actually are -- take 

21 effect, so it’s not coming up -- it’s not happening 

22 right away. 

23 Steve, did you want to --

24 MR. ROSENSTOCK: Just a quick one, Mr. 

25 Parker. With other standards there has been even 
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1 longer time periods when new standards took the 

2 place of older standards, sometimes ten years. Gas 

3 furnaces has been almost 20 years, so, you know, 

4 when you say that in terms of the appliance 

5 rulemaking, six years is not -- is not that long 

6 compared to other products.

7 Also, I want to get back to this graph 

8 real quick. I’ll talk about the refurbishment 

9 later, but I think part of the issue, and again, 

10 there’s all the graphs and I appreciate this, but I 

11 think with some of these metals the lines kind of 

12 stop at a certain efficiency levels with certain 

13 metals. I mean, for example, there might not be any 

14 yellow dots above 99.52, but it kind of looks like 

15 the yellow line is going further, when on one’s 

16 making them. So there could be an issue where 

17 you’re doing some of these comparisons and it all 

18 depends where they cross over, but there might be 

19 some design lines where the lines stop all of a 

20 sudden because there’s no designs at a certain 

21 efficiency level. So again, just data possible just 

22 for analytical purposes.

23 MR. PATTERSON: Sure, John, on Steve’s 

24 point, the different grades of steel have physical 

25 limitations as to how far they can go in efficiency. 
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1 So when you examine this data you’ll see there’s an 

2 asymptotic kick up on each grade of steel at a 

3 certain level, that’s what you’re referring to in 

4 this yellow dot. All of a sudden it’s going to go 

5 to infinity as you approach a certain point, and 

6 that’s the characteristics of the grades of steel.

7 MR. ECKMAN: Just on that point. Because 

8 of that kick up, those tend to be high leverage 

9 points in the fitting of that linear curve, so the 

10 question is how you dealt with that. Was it just 

11 fit through the ones where it was physically 

12 possible to build at that transfer level of 

13 efficiency?

14 MR. COFFEY: All I was looking to show 

15 here, I mean these are just tangents to the curve. 

16 Of course they’re going to change their slope as you 

17 move in efficiency, and I was more looking to

18 illustrate the concept than suggest that we would 

19 blindly take whatever intersection we found.

20 MR. ECKMAN: Yeah, if you’re just looking 

21 at the locus of where the dots all are possible, 

22 then the lines are less -- are far less relevant 

23 because of the slope being driven by a few points 

24 way high, or a few points way low.

25 MR. PARKER: Great.
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1 MR. DeLASKI: Andrew DeLaski, ASAP. Thank 

2 you for doing this. This is actually a very helpful 

3 for us to understand how the different core 

4 materials stack up, so to speak. The question I had 

5 for you, Brian, is you did a -- you did a -- as you 

6 were talking it through, I was trying to follow you 

7 and at the end you gave a scenario and said, what if 

8 steel prices were a little bit lower, and could you 

9 run through that example again?

10 MR. COFFEY: Sure. I think we’ve heard 

11 considerable concern about what the steel prices are 

12 today and what they might be in the future. What I 

13 was trying to show here was that the conclusion 

14 about which efficiency represented competitiveness 

15 between grain-oriented and amorphous steels, what we 

16 find that efficiency level to be is quite sensitive 

17 to our assumptions about what the material prices 

18 are. And so the objective of this tool is to allow 

19 you, as individuals, to dial in some different

20 scenarios and see what the outcome is. I hope that 

21 would have some value, because -- I mean that’s 

22 feedback we heard was that people would like to have 

23 this capability, so --

24 MR. DeLASKI: Yeah, I think that will be 

25 valuable. So that’s a tool that’s not yet available 
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1 but will be soon, is that -- what’s the status of 

2 that?

3 MR. COFFEY: So we have that. I mean 

4 we’ve built it. I think we probably just want to 

5 glance it over one more time to make sure 

6 everything’s working the way that it should be. We

7 just added two more price cases that were slightly 

8 less extreme than the ones that we had published 

9 previously, so I would say in the very near future 

10 we’ll be sending that out and letting people tinker.

11 MR. DeLASKI: Great.

12 MR. ANDERSON: Brian, to Wes’ point, can 

13 we see the loss improvements --

14 MR. PARKER: Richard Anderson.

15 MR. ANDERSON: Richard Anderson, sorry. 

16 Can we see the loss improvements, maybe the percent 

17 increase versus the efficiency because, you know, 

18 for the lay person to see that change in efficiency 

19 versus cost doesn’t make any sense, you know. So it 

20 would be more helpful to see the improvements in 

21 losses versus efficiency.

22 MR. COFFEY: Yeah, I mean there’s a one to 

23 one correspondence between efficiency and losses, so 

24 we could spend the time remapping this into a 

25 different coordinate system. It would just be 
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1 plotting a different variable, and if the committee 

2 thought that were helpful, we could send that out 

3 also.

4 MR. ANDERSON: Rick Anderson, Fayetteville 

5 PWC. If there’s a one to one relationship, as a 

6 user, I can’t stomach a 40 percent increase in cost 

7 for a .05 percent increase in efficiency. I can’t 

8 stomach that.

9 MR. BALLO: Tim Ballo, Earth Justice. 

10 You’re talking about a 40 percent increase in cost, 

11 you’re only looking at three. You’re ignoring the 

12 pink line and the yellow line.

13 MR. PARKER: Well, I think what this shows 

14 is that for amorphous it’s a pretty flat curve, and 

15 for M3 it’s a very steep curve, which I think is 

16 what people have been saying all along. I think it 

17 might help to have losses on the X axis instead of 

18 overall efficiency. Greg.

19 MR. COULTER: This is Greg Coulter, Prolec 

20 GE. We presented curves of the same data that I 

21 think more accurately represents what’s happening, 

22 That is not the shape of the curve for M3 that 

23 you’re implying. It just takes off like a shot as 

24 you go up in efficiency. And I think a more 

25 accurate representation is to look at this on what 
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1 the limits of what these steels can deliver.

2 PARTICIPANT: (comment off mic)

3 MR. COULTER: I think that’s just a 

4 problem with Navigant’s data. Amorphous is not 

5 quite the way we showed on our curve, and this does 

6 make it somewhat competitive at lower efficiencies. 

7 I just think that’s a problem with -- there is some 

8 data point problems. But overall, I think a more 

9 adequate way to present this is to show that there’s 

10 absolute limits of what these core steels can 

11 deliver. And it isn't a line like this, it goes 

12 asymptotic at some of these higher efficiencies.

13 PARTICIPANT: ... if you discuss this, 

14 you’ve got to really see what the M3, M2 ... can 

15 deliver.

16 MR. HOPKINSON: Phil Hopkinson HVolt. I 

17 certainly agree with Greg Coulter. Every once in a 

18 while, we agree. And also with Wes’ comments. Once 

19 in a while we agree too. But what I would say is 

20 that in the report that I have issue that I would 

21 like to summarize, I won’t obviously get a chance to 

22 go more than that, summarize this afternoon, I have 

23 shown what the manufacturers who supplied data gave 

24 me in comparison and what the delta price as well as 

25 the delta watts going from one efficiency level to 
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1 the next one, to the next one up and so on. And so 

2 that you will be able to see from that what it costs 

3 per watt saved to go from one efficiency to another. 

4 And I really do think that watts, if it were plotted 

5 on this curve, as Wes proposes, is really the right 

6 way to look at it, because then you can, in fact, 

7 extract directly the difference in selling price for 

8 the difference in watts and get the dollars per 

9 watt. And now if we compare that against the value 

10 of a watt saved, there’s your answers.

11 MR. MEYERS: Let me just reiterate the 

12 point that when considering these metals, when you 

13 make the switch over or transition to amorphous 

14 metal, entirely new equipment is required to 

15 assemble those. It’s not like switching from M3 to 

16 M2, and I’m not expressing a favor for either one or 

17 the other, but if a manufacturer is set up for one 

18 or the other, it becomes difficult, and if the 

19 entire market is shifted in one direction or the 

20 other, most manufacturers will not have the capital 

21 equipment to support that.

22 MR. PARKER: Yeah, I think manufacturing 

23 impact is something that will have to be considered 

24 and I think we might have a discussion about that 

25 either this afternoon or tomorrow morning. I think 
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1 that’s a valid point.

2 All right. So I take it that it’s doable 

3 then to express the X axis in terms of losses as 

4 opposed to micropercentage gains in efficiency, and 

5 can we -- can we agree then that in terms of the 

6 linearity versus the non-linearity, this is -- that 

7 really wasn’t your point with this presentation. 

8 That’s agreed that it’s non-linear, and that we’ll 

9 work on getting a more accurate shape to the curve 

10 in the future -- future postings. Right.

11 MR. COFFEY: That’s right.

12 MR. PARKER: Steve, did you want to 

13 comment?

14 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

15 The only thing I was going to say was, you know, 

16 just looking at the data that DOE presented for the 

17 same efficiency level, you’re going to have a wide 

18 range of losses, so maybe if you want to put a 

19 median or average value in there, that’s fine, but, 

20 you know, there is -- at each efficiency level 

21 there’s going to be a range of core and coil losses 

22 and so it’s not just one number to use if you’re 

23 going to do that. So I don’t know how you’re going 

24 to represent it, but maybe a median value, but there 

25 are going to be differences for the same rated 
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1 efficiency level.

2 MR. COFFEY: No, I think there’s -- there 

3 would be a one-to-one correlation of efficiency and 

4 total losses. The core and coil losses, you’re 

5 right, are a different story and if we wish to have 

6 that, then we can talk about that too, but I think 

7 it’s easy enough to show this same space remapped to 

8 a coordinate, and that’s total losses would be a 

9 one-to-one correlation.

10 PARTICIPANT: (comment off mic)

11 MR. HOPKINSON: Yeah. Basically if you 

12 finally agree on a load, and for medium voltage we 

13 have, up to this point, used 50 percent RMS 

14 equivalent load, then the load loss gets normalized 

15 down to what it would be present at that 50 percent 

16 load, the core loss gets added and at peak 

17 efficiency core loss equals load loss. So the two 

18 of them should be about the same at that measurement 

19 point of efficiency. So if we agree this afternoon, 

20 when I get a chance to address it, that 50 percent 

21 load is still the one to use, then the watts in 

22 total should track, and Brian was correct on that.

23 DR. SALIVE: Aaron, anything else?

24 MR. MEYERS: My comment was similar to 

25 Phil’s, that the load losses would be taken at a 
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1 quarter of the value, and once you do that, it would 

2 track linearly. But that there is a wide range of 

3 total losses that could be represented that all 

4 amount to the same efficiency value. So it may be 

5 better to think about it as an improvement in the 

6 inefficiencies, so if you’re at 99.5 percent moving 

7 point five percent would be like ten percent 

8 improvement or something like that. Yeah, you look 

9 at the reduction in inefficiency -- it’s like a 

10 double negative of sorts.

11 MR. BERMAN: Robert Berman, Berman 

12 Economics. If we’re going to look at specific 

13 measuring points for the losses, then it might be a 

14 good idea to look at some alternatives as well and 

15 see what the implications are. We’ve got -- we’re 

16 heard some comments from a number of the utilities 

17 that some of them have loads of -- in the low to 

18 mid-30’s, others are more rural utilities probably 

19 have even loads as low as the mid-20’s. It might be 

20 a good idea to see what the effect is of using the 

21 50 percent load factor on the actual load factor in 

22 the utility. That is to say, instead of a 

23 comparison of the load loss divided by four, 

24 compared to the loss at the square of the load 

25 factor. It gets -- the difference in savings gets 
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1 substantial for the lower load factor utilities.

2 MR. PARKER: Yeah, and we’ll be talking 

3 about load factors again this afternoon. Let’s hold 

4 off on that for now. Okay, I think it’s been 

5 helpful. Let’s move on then to the -- because we’re 

6 near the end of our time, past the end of our time 

7 actually -- let’s move on to a quick review of the 

8 open-ended questions from Brian. Thanks.

9 Review of Open-Ended Questions

10 MR. COFFEY: Sure. So just to wrap that 

11 up really quickly. What we learned was that, the 

12 conclusion about which efficiency is competitive is 

13 sensitive to your assumptions about materials 

14 prices. We will be providing a tool for people to 

15 dial in their own assumptions.

16 We talked about weight briefly in the last 

17 meeting, but we were thinking about it more in 

18 weight doesn’t really drive the purchasing 

19 decisions, within a certain range, and furthermore, 

20 actually itself requires an implicit assumption 

21 about the relative pricing of the metals. So it 

22 doesn’t really solve the problem in our opinion.

23 So the plan here is to seek input on 

24 materials prices and have best guess high and low 

25 cases and then provide the opportunity to look at 
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1 their own scenarios and discuss.

2 And that brings us to open questions, or I 

3 had a couple of very pointed questions that I saw 

4 and I’m going to try to address.

5 CSL and El selection, how is that done? 

6 You know, there’s not a hard and fast methodology. 

7 There’s a general thought to covering the efficiency 

8 range evenly to allow some debate about what’s the 

9 proper standard. And then when we went from the 

10 CSLs to the ELs, which as we’ve said, are 

11 functionally identical, we tried to place them at 

12 boundaries of materials so that -- because we 

13 thought that might be where the rubber meets the 

14 road, where a lot of the debate was held. So that’s 

15 how that was done.

16 Compliance of actively cooled 

17 transformers. This has been a question raised by 

18 several manufacturers over the years. We had 

19 written a memo to DOE, so it’s something that’s not 

20 -- it’s not presently spelled out in the standard. 

21 The decision was that the intent really wasn’t to 

22 cover transformers in their active state of cooling 

23 when fans or pumps are engaged, and so compliance 

24 would be established at the passively cooled rating. 

25 So we’ll be writing that more formally eventually, 
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1 but that’s just to have a short answer to the 

2 question.

3 These next two, I think, are items where 

4 probably DOE will need to weigh in and think about 

5 what the policy decision is, and that’s compliance 

6 of transformers with multiple BIL ratings, and 

7 compliance of transformers with multiple primary and 

8 secondary windings. And right now the stipulation 

9 is that they be tested in the configuration that 

10 produces the highest losses, so that’s how 

11 compliance is assessed right now, and I think these 

12 questions that people have been asking would 

13 represent a shift in how compliance was established 

14 and so -- I’m not giving a direct answer right now 

15 but just acknowledging receipt of those and saying 

16 that’s something that DOE will think about and give 

17 an answer to.

18 MR. PATTERSON: Wes Patterson. The 

19 standard doesn’t say they have to be tested at that,

20 they say they must be in compliance with the 

21 standard in the worst loss connection. You have two 

22 ways to meet compliance, AEDM or test. Right?

23 MR. COFFEY: That's correct. Thanks for 

24 that. 

25 Next Steps
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1 So with that, just next steps, and we 

2 talked about a lot of these already, but I’ve got 

3 some action items to work on, and I think some of 

4 you also have some areas where we’re looking to you 

5 for data and information. So with that, I’m done 

6 and I will turn the floor over to Richard and LBL.

7 MR. PARKER: Any comments or questions on 

8 the open-ended -- questions on this segment? Steve.

9 MR. ROSENSTOCK: Again, it’s more of a 

10 process question. I know that a lot of data has 

11 been flying around the last few days, and I know if 

12 there’s going to be a revision to the engineering 

13 analysis, that’s kind of your focus, just in terms 

14 of timing and in terms of any updates, you know, the 

15 next meeting is scheduled for -- after this one --

is scheduled for November 8th 16 . What kind of time --

17 as the analysis gets updated, what kind of timing 

18 are we looking at? Again, I know, maybe speaking a 

19 little ahead, especially as we get into the LCC 

20 issues, but in my view I think it would really help 

21 all the parties if, you know, if there’s going to be 

22 a final update to the analysis that all parties are 

23 able to review it at least several days ahead of the 

24 next meeting. Because, you know, this is the first 

25 time I saw this presentation. I thought it was 
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1 really helpful, but having something a little ahead 

2 of time could have given at least a chance to 

3 provide even more useful information. So, is there 

4 a thought that the next, I’ll say the final 

5 iteration of this, just to make it easy for Brian so 

6 he doesn’t deal with us forever, would it be 

7 possible to get the next iteration finished at least 

8 several days before the next meeting?

9 MR. RIVEST: Steve, this is Mike Rivest. 

10 I think it’s -- I hate to do this, but it depends on 

11 when we get the data and when we stop getting data. 

12 At some point -- so any data we get, we will make 

13 every effort to use. The likelihood that we can use 

14 it for this next revision just increases as we get 

15 it earlier. So to get you something for the next 

16 meeting, realistically, if we get any data past the 

17 end of next week, for example, it’s just going to be 

18 hard. Because after we’re done with the 

19 engineering, we have to give it over to LBL to do 

20 some LCC, and it’s really the LCC that shows the 

21 impact of any decisions.

22 MR. PARKER: Well that was why I sort of 

23 arbitrarily and perhaps optimistically put in 

November 2nd 24 as the time for the analysis to come 

25 back, which would mean getting the data to Navigant 
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1 and LBL, of course, well in advance of that. I 

2 think we do need to have that discussion, because --

3 MR. RIVEST: On the one hand, I don’t want 

4 to discourage people from giving data later if they 

5 need more time.

6 MR. PARKER: Yeah, but there is a time 

7 value to data.

8 MR. RIVEST: Just want to make it into the 

9 next round.

10 MR. PARKER: And it’s going to get 

11 discounted if it comes in -- at a high discount rate

12 if it comes in after a point at which we can 

13 actually take it on board.

14 MR. CYMBALSKY: John Cymbalsky, DOE. So 

15 from DOE’s point of view, we’re still on the hook 

for a NOPR to be published by February 1st

24 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

16 , so if 

17 things get bogged down in this process, based on 

18 analysis or whatever else, we will still move 

19 forward with what we think is our best data that 

20 have been provided by you guys, and we will still 

21 write a NOPR in the meantime, because we have to. 

22 So I think we have to lock down the analysis in 

23 short order and really move this process forward.

25 MR. PARKER: Excuse me, Steve, I think 
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1 Andrew had his hand up.

2 MR. DeLASKI: So, Brian, you said you had 

3 a number of action items and to do’s coming out of 

4 this, and things that you’re hoping to get from 

5 manufacturers. Maybe after lunch will make sense 

6 for you to come back and just tell us what those 

7 are. A nice summary from this morning, I think 

8 would help to get the data that you need, so people 

9 know what you’re expecting of them. Maybe you 

10 already know this because you’re the manufacturers 

11 and I’m not, maybe you followed all that, but maybe 

12 coming after lunch that would be helpful to have 

13 that. What are those to do’s? What are you 

14 expecting people to give you? So that we have a 

15 real specific list.

16 MR. RIVEST: Mike Rivest. I think the 

17 open item from this morning is the product classes 

18 that we left open for liquids. I mean, that can 

19 make -- that can be a lot of analysis, so if we 

20 decide to break out the poles, the pads, the vaults 

21 -- I don’t think we had resolution on that, if that 

22 was going to be creating new product classes or not. 

23 So that’s a decision to make today, I hope.

24 MR. PARKER: Brian tells me he thinks he 

25 can do, over lunch, we’ll try to get him some time 
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1 to eat lunch as well, but do a short list of action 

2 items and we do need to set a timeline for getting 

3 your data to them, beyond which we just won’t be 

4 able to accept it because, you know, it’s gone on 

5 long enough, I think. Aaron.

6 MR. MEYERS: Aaron Meyers. My question is 

really to John Cymbalsky. Has the February 1st

10 MR. CYMBALSKY: Yes, I think I saw an email that said that we were good for February 1

7 date 

8 been decided by the courts? Is that -- I haven’t 

9 heard any final date on that.

st

12 MR. MEYERS: Okay. Thank you.

11 .

13 MR. CYMBALSKY: Given we’re way past 

October 1st

15 MR. PARKER: Steve, one, very quickly.

14 .

16 MR. ROSENSTOCK: Well, just, and again, I 

know there’s February 1st

20 MR. PARKER: Okay. With that in mind, 

21 let’s break for lunch. It’s almost one o’clock now, 

22 we’ll plan on reconvening here at two.

17 , but it’s also -- it’s a 

18 NOPR or determination that the current standard can 

19 stay in place. Thank you.

23 (Whereupon, at 12:51 p.m., the meeting in 

24 the above captioned matter was adjourned for lunch 

25 recess, to reconvene at 2:00 p.m.)

26
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2 2:04 p.m.

1 AFTERNOON SESSION

3 MR. PARKER: Hi everyone. Welcome back 

4 from lunch. Hope you enjoyed it. Why don’t we get 

5 started. Sorry, we’re getting started again a few 

6 minutes late by my best resolution to get started on 

7 time. We have lots to cover this afternoon, 

8 grateful to have Chris Bolduc from Lawrence Berkeley 

9 Labs to present basically how they do their life 

10 cycle analysis, the key inputs into that analysis, 

11 and I think, and I’m hoping that a lot of what he 

12 says will help everybody get on the same page with 

13 what we need to do at this meeting, which is to 

14 indicate what changes, if any, need to be done to 

15 the analysis and what inputs that are not currently 

16 resolved would need to be as they go forward.

17 So without further ado, let me turn it 

18 over to Chris. If we could have everybody’s 

19 attention please around the table, I’d appreciate 

20 it. And let’s try to kept the questions at this 

21 stage limited to clarifying questions, because I 

22 think a lot of this stuff fits together, and rather 

23 than jump in, please kind of hold your questions 

24 unless it’s a short, clarifying question. We’ll try 

25 to get through the presentation and then we’ll come 
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1 back and look at the individual pieces of it and see 

2 where we need to go from there. Okay. Go ahead, 

3 Chris. Thanks.

4 LBL Presentation 

5 MR. BOLDUC: Thank you. Good afternoon. 

6 My name is Christopher Bolduc from Laurence Berkeley 

7 National Lab. I’m going to be going over some of 

8 the inputs to the LCC that have been causing 

9 confusion or there’s some question surrounding.

10 Transformer Loading

11 Without further ado, the first input that 

12 we want to look at is transformer loading. In 

13 particular we define transformer loading with three 

14 variables: load factor, the RMS load on the 

15 transformer, and the loss factor. These have been 

16 gone over in previous meetings several times.

17 What I would like to focus on right now is 

18 the RMS load. And so in this next slide shows the 

19 RMS loads that we used for design line 1. And as 

20 you can see, it’s a distribution, and it’s centered 

21 around 34 percent is the mean value. I know there’s 

22 been a lot of misconception about the LCC model 

23 surrounding the RMS load. Some people think it’s a 

24 straight single value of 50 percent. I believe 45 

25 percent is the number that’s been bandied around. 
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1 For the liquid immersed transformers, we 

2 try to load the transformer at around 33 to 35 

3 percent. It varies a little bit because it’s a 

4 Monteocarlo (ph) simulation. There’s a slight rant 

5 (ph) nature to the load, but the load shape that we 

6 run through the LCC is as shown on the screen here.

7 PARTICIPANT: (Question off mic)

8 MR. BOLDUC: Thirty-four percent is the 

9 number that was used in the 2007 rule also so there 

10 has been buy-in through stakeholdering. Also we’ve 

11 heard from several utilities over the course of the 

12 rulemaking that they tend to load transformers in 

13 the 30 to 35 percent range. Naturally for rural co14 ops we drop this by 25 percent, so we’re loading in 

15 the high 20’s.

16 MR. HOPKINSON: (Question off mic)

17 MR. BOLDUC: That's correct. 

18 MR. HOPKINSON: And the basis for the RMS 

19 -- there’s no metering on RMS. How do you get to it 

20 as a utility?

21 MR. BOLDUC: I’m going to redirect that to 

22 Katy. Can you repeat the question?

23 MR. HOPKINSON: Yeah, Kate, how do you get 

24 to RMS equivalent load? Is it just the model or is 

25 it something that somebody actually has recorded 
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1 information on over a lengthy period of time and 

2 then computed it?

3 MS. COUGHLIN: Are you asking how the 

4 utilities arrived at the figure of 30 to 35 percent?

5 MR. HOPKINSON: Yes.

6 MS. COUGHLIN: I don’t know. That’s a 

7 metering question, so that’s not something that we 

8 have information on. Those are just comments that 

9 were submitted.

10 MR. HOPKINSON: Steve, do you know 

11 anything about that? 

12 MR. ANDERSON: Chris? Rick Anderson, 

13 Fayetteville PWC. We have some information dating 

14 back into the 90s that generally says the load 

15 factor is in the order of 25 percent. Okay. And I 

16 saw your maximum there is 56 percent. Is that the 

17 peak on the transformer?

18 MR. BOLDUC: No, that’s not the peak on 

19 the transformer.

20 MR. ANDERSON: Okay. We’ve got data and, 

21 you know, several of us have data. We need to give 

22 that to you?

23 MR. BOLDUC: We would appreciate it and we 

24 could hold it in confidence, okay.

25 MR. ANDERSON: The other thing is is that 
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1 you’re looking at a 50 KVA pad, I guess.

2 MR. BOLDUC: In this example, yes.

3 MR. ANDERSON: And what we also need to 

4 recognize is that that’s generally going to be the 

5 single phase residential application.

6 MR. BOLDUC: Uh-huh (yes.)

7 MR. ANDERSON: And that pad mounts, you’re 

8 going to put those in a subdivision where 

9 everything’s nice and compact, and you can get 

10 numerous services, say five, or for one KVA 

11 transformer. However, on an overhead transformer in 

12 a rural application, it’s really going to be like 

13 the transformer is dedicated solely to that one 

14 individual service. So as you go through this, I’d 

15 like for you to keep in mind that you have, for pad 

16 mount applications, you’re talking more so about a 

17 subdivision. When you talk about overhead 

18 applications you’re really looking at more of a 

19 rural application.

20 The other thing is is that when you start 

21 to get over 50 KVA on an overhead transformer, you 

22 start to bank them for three phase. So you may have 

23 three 75’s serving a commercial application, and 

24 that load factor changes. In other words, we don’t 

25 load a rural overhead application the same way we 
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1 serve a three phase commercial service. And that’s 

2 going to influence the load factor and the maximum 

3 peak that the transformer sees. 

4 So, you know, a lot of the discussion 

5 earlier has centered around the transformer 

6 manufacturers and how they construct it. We’re 

7 users. We use it. We’re married to it. We buy it 

8 and we live with it for 30 years, and generally 

9 speaking we’re not going to buy a dump truck if we 

10 can do it with a golf cart.

11 MR. BOLDUC: Understood. We’ve also heard 

12 anecdotal evidence that larger transformers would be 

13 loaded at a higher RMS load. If anybody on the 

14 committee could send us data or corroborate that, we 

15 would appreciate it. We’d also like an idea of how 

16 much the magnitude of that difference. It would be 

17 helpful. Any more questions?

18 MR. SMITH: Just a comment on that last 

19 statement. I think all you’re going to get is 

20 anecdotal evidence on that. It sounds reasonable, 

21 but I’m not sure there’s a way to verify that.

22 MR. BOLDUC: All right. Thank you. 

23 Steve.

24 MR. ROSENSTOCK: Steve Rosenstock, EEI. A 

25 clarification. On this curve, this loading curve, 
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1 the distribution, was that based on I’ll say kind of 

2 a classic bell curve type of distribution, or is 

3 this based on some of the utility data that kind of 

4 came in and that showed that it really, you know, 

5 I’m just kind of curious about the shape of the 

6 curve in terms of --

7 MR. BOLDUC: We’ve made no effort to shape 

8 the curve. I got it based on utility data.

9 MS. COUGHLIN: (off mic)

10 MR. ROSENSTOCK: It’s model.

11 MR. BOLDUC: I’m sorry if people didn’t 

12 hear that, it’s simply modeled output.

13 MR. ROSENSTOCK: Thank you.

14 MR. WINDER: Chris, question on what your 

15 meaning is for the maximum of 56 percent and a 

16 minimum of 17. And then is this your model that you 

17 apply on a long-term basis like every year, this is 

18 the kind of model that you’re using for that whole 

19 year, for that long of a period?

20 MR. BOLDUC: This would be -- yes, this 

21 would be the model that we use for the life of the 

22 transformer.

23 MR. HOPKINSON: Phil Hopkinson, HVolt. 

24 Question for you on peak load with cold load pickup. 

25 If I look at my own residence, my peak load could be 
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1 30 KVA. MY RMS equivalent is around eight KVA, and 

2 my average is about 3.65 KVA on a yearly basis. So 

3 if the peak load, with the cold load pick up, and if 

4 my neighbors are in the same boat where we lose 

5 power from a storm or something, turn it back on, 

6 everything in the house wants power. The 

7 regulation, impedance drop and regulation is going 

8 to be huge if we have a transformer not designed for 

9 a robust winding that is part of it. Is that any 

10 consideration, that is, is regulation and impedance 

11 any consideration in your work?

12 MR. BOLDUC: No.

13 MR. HOPKINSON: It ought to be.

14 MR. BOLDUC: Okay. Katie Coughlin has a 

15 comment.

16 MS. COUGHLIN: I just wanted to emphasize 

17 that this is a distribution, so we have in the LCC 

18 there are 10,000 transformers simulated. Each 

19 simulation has its own individual RMS load. In 

20 fact, what happens in the LCC is somewhat more 

21 complicated. There’s a simulation of the load at a 

22 higher time resolution, an annual, and there’s a

23 correlation of loads with electricity prices. So 

24 what you’re looking at here is simply an output of 

25 the simulation model that demonstrates that for this 
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1 particular design line, these are the RMS average 

2 over the year that ended up being selected. But the 

3 calculation is not just based on an RMS load, and 

4 when you look at a different design line, it will be 

5 selecting from a different customer base. We might 

6 be using different assumptions about the -- we have 

7 different simulation models for residential versus 

8 commercial installations of liquid immersed 

9 transformers. So you’ll actually see a different 

10 distribution for each design line.

11 MR. WINDER: Still a question that hasn’t 

12 been answered about the maximum you said 50 percent 

13 and the minimum 17. Did that get answered?

14 MR. BOLDUC: No.

15 MR. WINDER: Oh, Ken Winder, NRECA.

16 MS. COUGHLIN: What they represent is the 

17 -- for this design line, the highest RMS load in 

18 that ensemble of simulations was 56 percent, and the 

19 lowest was 17 percent.

20 MR. HOPKINSON: (off mic) I would suggest 

21 that it goes much higher. Every transformer I’ve ... 

22 with on a residential system certainly goes to more 

23 than 100 percent of nameplate load for cold load 

24 pickup, and those, oh, to the range of 70 percent on 

25 peaks on a regular basis. I’ve never seen anything 
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1 where the peak alone never went above 56 percent. I 

2 just think that’s --

3 MS. COUGHLIN: This is RMS. This is not 

4 peak. This is RMS.

5 MR. BOLDUC: Yes, we have a separate --

6 we’ll be showing a separate histogram of peak loads. 

7 Wes.

8 MR. PATTERSON: Wes Patterson. When you 

9 say RMS, over what time period are you talking 

10 about?

11 MR. BOLDUC: Be one year.

12 MR. PATTERSON: So you have a transformer 

13 somewhere in your data set that you’re assuming is 

14 loaded 24 hour day at 56 percent load.

15 MR. BOLDUC: Over a year, a calendar year. 

16 8760.

17 MR. BOLDUC: Exactly.

18 MR. PATTERSON: Okay. Thank you.

19 MR. BOLDUC: What we were hoping for is 

20 some of the utility reps could comment.

21 MR. ECKMAN: Can I clarify that, because I

22 don’t think that’s what you do, Katie. I mean you 

23 have a transformer that has a load profile that’s 

24 given to it that gets a varying load over the course 

25 of a year, not a fixed load factor over the course 
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1 of the year. It varies by day or hour, I don’t know 

2 what the time increments are.

3 MS. COUGHLIN: Right. And then --

4 MR. ECKMAN: But the RMS --

5 MR. PATTERSON: And the RMS equivalent is 

6 17 percent --

7 MR. ECKMAN: -- over the course of the 

8 entire year, but not at any given --

9 MR. PATTERSON: Right, but it cycles up 

10 and down, but the RMS equivalent for a year, low end 

11 is 17, high end is 56, and it’s got that shape.

12 MR. ANDERSON: Question. Chris, I guess 

13 for Katie. The 10,000 trials -- I’m sorry.

14 MR. PARKER: I’m just giving your name.

15 MR. ANDERSON: I’m sorry, Rick Anderson, 

16 Fayetteville PWC. The 10,000 trials, where did you 

17 get that from? I mean, did you just make that up or 

18 -- I don’t mean to be a wise guy, where did you get 

19 the 10,000 trials from? Did you -- you didn’t have 

20 utility metered data, or you just kind of figured 

21 that’s what happened, or how did you get those 

22 trials? And the reason why I ask, Katie, is because 

23 I mean we have 15 minute demand interval data, so 

24 I’m curious was that real or was it fabricated, for 

25 lack of a better term?
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1 MS. COUGHLIN: Okay. So it’s -- what we 

2 are using, we have hourly building data, so we’re 

3 using hourly building load shapes as a proxy for 

4 transformer load shapes. And so the statistical 

5 analysis begins with hourly building data for a few 

6 thousand year-long records. And we also -- we’ve 

7 developed a method for correlating transformer loads 

8 with an aggregate system load. So if you take 100 

9 hourly loads and add them together, and that’s your 

10 sort of proxy as the system load, then we correlate 

11 the individual transformer loads with the local 

12 system load and we use FERC Form 714 data for hourly 

13 system loads to deal with sort of geographic 

14 variation and things like weather effects that may 

15 affect the kind of overall level of loading. 

16 The model’s built out of as much data as 

17 we can find, and if you actually have transformer 

18 reader loads, we’d be very interested in seeing 

19 those to compare those statistics. Because again, I 

20 want to emphasize that the LCC really ends up being 

21 dependent only on certain statistical measures of 

22 these loads, and they may not end up looking 

23 terribly different from what we already have, and 

24 that’s something that we can check quite quickly if 

25 we can get hold of the data.
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1 MR. PARKER: So just for my benefit, what 

2 data precisely would you be looking for then, and by 

3 when?

4 MS. COUGHLIN: We’d be looking for hourly 

5 metered transformer loads.

6 MR. ANDERSON: I think it’s fair to say 

7 that the utilities, collectively, need to give that 

8 to you, but I think what you’re going to see is 

9 different load curves for different applications, 

10 you know, commercial, industrial, three-phase pads, 

11 single-phase pads, single-phase poles, up to a 

12 certain KVA, and then it’s going to become a 

13 commercial application where it’ll probably look 

14 more like a three-phase pad. But it sounds like you 

15 tried to back into this load shape, based on the 

16 FERC forms, and that -- much of this is not actual 

17 load data.

18 MS. COUGHLIN: Right. We do have -- with 

19 the building data we do have residential and 

20 commercial buildings and we have developed the 

21 curves separately from that, but yeah, so we’ve got 

22 building data and we’ve got FERC data. That’s 

23 really all we have at this point.

24 MR. HOPKINSON: Phil Hopkinson, HVolt. 

25 With electric vehicle charging it’s been proposed 
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1 that the full charge level would be about 40 

2 kilowatt hours. If you have to put that on, you 

3 know, it’s different load cycles, 8 KVA while the 

4 charging is taking place is assumed to be what most 

5 people would do, but we’re just sitting here looking 

6 at the Nissan Leaf that now is set up for a rapid 

7 charge, so it will charge in ten minutes. Well, do 

8 that calculation and you’ll see that the 8 KVA goes 

9 a whole lot higher. And of course, impedance 

10 regulation and the impact on temperature rise and 

11 losses all come hand in hand.

12 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

13 With the electric vehicles I know that effect will 

14 be discussed later. The charging rate is really 

15 going to depend on the vehicle and what the customer 

16 chooses. Vehicles will be able to charge at 120 

17 volts, so 1.0, 1.4 KW. Level two chargers, they’re 

18 either going to be around 3.3 KW or 6.6 KW, based on 

19 SAE J1772. You’re talking about the Nissan, some of 

20 those quick chargers, based on the charger mount 

21 system, yes, they’re going to be 40 or 50 KW, but 

22 there’s -- they’re going to be in commercial 

23 applications, they’re not going to be in residential 

24 applications. So again, the vehicles could have an 

25 impact on some of this, but again, they might not. 
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1 And again, that’s -- I don’t know if they’re really 

2 going to play a big role in some of this. And also, 

3 you also have to remember about all the other 

4 appliance centers have gone to effect that lower all 

5 the existing loads, clothes washers, dishwashers, 

6 air conditioners, et cetera, TV sets with air energy 

7 star, so there could be a balancing out based on --

8 MR. PARKER: I hate to be a killjoy, but 

9 we have to recall that we do have a timeframe for 

10 this rulemaking, and while it would be nice to come 

11 up with more data about how electric vehicles and 

12 charging will affect future demand growth and effect 

13 loading factors, we really need to be focusing our 

14 attention now on coming up with a closed dataset 

15 that can be used for doing a final analysis that 

16 will be ready in the next couple of weeks. 

17 So I hope that, you know, we’ve had a long 

18 time to come forward with this data, but we are now 

19 at the point where we actually have to start 

20 producing results. So we need to start thinking 

21 about what can we do, what is the most efficient way 

22 to use the time available, to use the resources 

23 available, to use the data that we have. If a 

24 limited amount of data can be used to generate a 

25 single offset or supplemental what have you, that 
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1 will apply a simple corrective, that’s fine. But I 

2 don’t think that we can be in a position now of sort 

3 of fundamentally redoing the analysis based on new 

4 data. And remember also that we’re in the business 

5 of creating standards for a design line, you know, 

6 regardless of the application. There’s not really 

7 the flexibility, as we heard from Dan Cohen in the 

8 prior meeting, there’s not really the ability to say 

9 we’re going to have one efficiency level for design 

10 line one going into this use, and another efficiency 

11 level for design line one going into another use. 

12 You have to look at all of the various uses and come 

13 up with the right fit for that design line overall. 

14 And that’s just the constraint of law. It’s also a 

15 practical constraint. So I hope that helps us keep 

16 focused.

17 MR. ROSENSTOCK: But, Mr. Parker, Steve 

18 Rosenstock, but this morning there was going to be a 

19 little bit of a breakout for different design lines 

20 if we break it out, pad versus pole, versus network. 

21 There is going to be a little bit of split-up based 

22 on some of the transformer application. Maybe not 

23 end-use load, but based on application.

24 MR. PARKER: It’s going to have to be 

25 based up physical characteristics of the product, 
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1 that’s what we discussed with network involved 

2 transformers, that -- we’ll see first if there’s a 

3 requirement for a separate break-out based upon 

4 their price versus efficiency performance, the 

5 margin, but the main thing is that there has to be 

6 some kind of a physical distinction between the 

7 network involved on the one hand and the regular on 

8 the other hand, or else you don’t have basis for 

9 creating a separate equipment class. Andrew.

10 MR. DeLASKI: I’ll be brief. From the 

11 conversation from this morning, it strikes me that 

12 Chris has just presented the RMS load. The data 

13 that LBL has put together based on, as Katie 

14 described, substantial building load data and the 

15 FERC forms. I’ve heard Richard say he’s got some 

16 data, he’s going to share with the consultant. 

17 That’s one utility, that’s one set of circumstances. 

18 Hopefully other utilities will share data as well. 

19 And then the analyst will determine how does that 

20 influence what the assumptions are. So I wonder if 

21 we can move on from the RMS load. I think Chris has 

22 other topics for us to cover. Hopefully we’ll get 

23 data from more than one utility.

24 MR. PARKER: Well, I just don’t know if 

25 getting data from the utilities around the table 
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1 will be enough to be a fair representation of the 

2 whole industry, because remember, this is a group 

3 that is -- that we’re creating a standard for 

4 industry, not just for utilities around the table.

5 MR. DeLASKI: Right. And I also think, no, 

6 Richard said his numbers make up about 25 percent 

7 for this particular design line, which seems to me 

8 is within that distribution. I’m not sure we’re 

9 going to see a whole lot of variation. I think the 

10 distribution may be confirmed, it may not be 

11 confirmed, but the thing is just get the data or we 

12 can talk all day long here, but Chuck’s got data. 

13 He’s a big utility. Let’s have the utility submit 

14 the data and see how it shakes out.

15 MR. MEYERS: Aaron Meyers, Cooper Power. 

16 We’ve heard some testimony or conversation about 

17 loading and some speculation as to the effects of 

18 electric vehicles on loading as we go forward. The 

19 charter of this subcommittee is to do what’s right 

20 by the United States public, and when we’re 

21 considering a payback period of 30 years, we really 

22 need to consider some of the changes that will occur 

23 over that time period. And my question for the 

24 committee is what information is needed in order to 

25 consider that? Obviously, vehicle manufacturers 
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1 have put together business cases and so forth to 

2 invest money in the growth of electric vehicles and 

3 they have some sales forecast around that. Is that 

4 what’s required, or is loading as a topic not up for 

5 debate? Should it stay what it is now or are we 

6 going to submit data and then have that open for 

7 being changed in the future? If that is the case, 

8 then I would agree with Richard that data from those 

9 participating around the table is probably not 

10 sufficient to arrive at a conclusion. It’s probably 

11 good information, but to make a standard, I would 

12 argue that it’s probably not sufficient.

13 MR. ANDERSON: Well, to your point, I 

14 don’t think much about it, Aaron, that’s voodoo to 

15 me. We’ve got real data and I think -- I don’t know 

16 if it’s possible for the transformer manufacturers, 

17 you know, they’re given A and B factors, and really 

18 what we’re talking about here in particular are B 

19 factors. Now everybody’s cost to energy varies, and 

20 if you can possibly find out from your customers 

21 what their costs are, then you can actually back 

22 into the load factor and the peak. You could 

23 reverse engineer it, if you knew what their actual 

24 costs were in the calculation. Then that would be 

25 true indicative of what the utilities’ practices are 
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1 when it comes to loading transformers.

2 MR. PARKER: Okay. So why don’t we say 

3 then that the utilities around the table will work 

4 with Chris over the next few days, basically --

5 excuse me Bob -- and supply your data. Chris, can 

6 you do a quick run to see if whatever data they have 

7 makes a difference and just give us a ground true?

8 MR. BOLDUC: We would compare the 

9 submitted data against our model and then you’d use 

10 the data to calibrate, is essentially what we’d do. 

11 So yes, any data, as we’ve maintained since the 

12 preliminary analysis, would be welcomed and used., 

13 would be welcomed and used.

14 MR. PARKER: Okay. Great. Bob, we’re 

15 going to have to move on, sorry. Wes.

16 MR. PATTERSON: Wes Patterson. Do we have 

17 a different chart for each design line or is it the 

18 same chart for all design lines?

19 MR. BOLDUC: They differ slightly, 

20 depending on design lines.

21 MR. PATTERSON: But they basically look 

22 like that?

23 MR. BOLDUC: Essentially they do have the 

24 same shape. I’m going to show you design line --

25 the slide for design line 12 next.
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1 As you can see we’ve modeled this slightly 

2 higher load. It’s a much larger transformer. I 

3 don’t have the mean lines on the graph, I’m sorry 

4 about that, but.

5 MR. PATTERSON: Chris, your source for 

6 this information was the same data set for the 

7 liquids? This is a dry.

8 MR. BOLDUC: The source for this dataset 

9 were building surveys. No, it was the same dataset.

10 MS. COUGHLIN: This is Katie Coughlin, 

11 LBL. No, the quick answer is no, it’s a different 

12 dataset, because these are mostly transformers 

13 installed in buildings, so we’re not relying so much 

14 on utility data. This dataset is a combination of 

15 the hourly building loads that we have, which are a 

16 small set essentially, and information from the CBEC 

17 surveys, which give a much broader representation of 

18 the building population.

19 Transformer Lifetime

20 MR. BOLDUC: Thank you. On this next 

21 slide, the next issue I’d like to address is 

22 transformer lifetime. The analysis currently uses 

23 an average transformer lifetime of 32 years, with 

24 the decay added on to it of 0.5 percent per year 

25 after year 15 for corrosive failure or lightning 
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1 strikes in the field. I just wanted to show you the 

2 distribution. It’s not a fixed 32 year lifetime. 

3 It’s a distribution of lifetimes that centers on 32.

4 I know on the e-mail there’s been a little 

5 discussion about using EEI’s number of 21 years. 

6 I’ve read the article. I’ve read the standard from 

7 EEI. It’s a document that’s based on transformer 

8 installation lifetime. The EEI article or document 

9 policy goes on to say that it’s not --

10 MR. MILLURE: Chris, it’s IEEE’s.

11 MR. BOLDUC: Thanks. Sorry. A little 

12 nervous, thank you. It also goes on to say it’s not 

13 about transformer lifetime, and we believe the 21 

14 years is an inappropriate lifetime to use in the 

15 analysis.

16 MR. ANDERSON: Excuse me, sorry. Rick 

17 Anderson, so I’m not to be a wiseguy again, Chris, 

18 but you don’t believe what the IEEE says is what you 

19 said. So you’ve got all these engineers who live 

20 with this stuff and you just don’t buy it.

21 MR. BOLDUC: No, I’m not saying that I 

22 don’t buy it. I’m saying that the analysis that was 

23 done to come up with the 21 years is different than 

24 the analysis -- is different than I believe what 

25 you’ll see in the field. 
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1 MS. COUGHLIN: The number in the IEEE is -

2 - it’s kind of a design specification. It’s 

3 actually -- it’s a definition based on certain 

4 assumptions about how the design functions at full 

5 load. So it’s not a measurement in any sense of how 

6 a transformer lifetime -- what an expected 

7 transformer lifetime in the field would be. It’s 

8 just a different -- it’s a different specification.

9 MR. CYMBALSKY: Rick, didn’t you say we 

10 have to live with these things for 30 years?

11 MR. SAMPAT: Mahesh P. Sampat, EMS 

12 Consulting. The IEEE document they are describing 

13 is basically a thermal life of an insulation. If 

14 transformer is loaded -- basically what the document 

15 says is that if insulation is handling 105 degrees 

16 Centigrade, how long that insulation would last.

17 PARTICIPANT: Talking about loss of life.

18 MR. SAMPAT: Loss of life, and all your 

19 loading data then derives after that. So -- and 

20 there is a five-to-one factor, so for varying 

21 degrees, they look at when the insulation life ends, 

22 then have a factor of five-to-one safety factor, and 

23 works out to be 21 years or whatever that they are 

24 describing. But it is dealing with the insulation 

25 life, okay, and at 105 degrees Centigrade.
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1 MR. HOPKINSON: Phil Hopkinson, HVolt. 

2 But the question is, what are the utilities using to 

3 amortize transformers right now?

4 MR. ANDERSON: Rick Anderson, Fayetteville 

5 PWC. Utilities typically use 30 year book life.

6 MR. FERNSTROM: Can I add something? This 

7 is Gary from PG&E representing the California 

8 utilities. Our transformers last 40, 50 years. And 

9 because of the current economic situation, we’re 

10 typically not replacing them unless they burn out.

11 MR. PARKER: Bob.

12 MR. SMITH: This is Bob Smith, Federal 

13 Pacific. One of the things that I think you’re 

14 referring to and where you’re coming up with the 21 

15 years is the IEEE loading guides. I’m not familiar 

16 with the liquid IEEE document, but for the dry type 

17 the IEEE C5796 basically says if a transformer’s 

18 loaded at a -- a dry type transformer is loaded at 

19 main plate around the clock, it’s thermal life 

20 expectancy is 20 years, 20 years if it’s a 150 

21 degree rise transformer. If it were a 115 degree 

22 rise transformer, that calculation becomes 338 

23 years. If it were an 80 degree rise transformer, it 

24 comes out to be roughly 9100 years.

25 The point I’m trying to make is that with 
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1 these transformers being so lightly loaded, they’re 

2 going to last a lot longer than 20 years.

3 MR. PARKER: Steve.

4 MR. ROSENSTOCK: Just a quick one. 

5 Someone asked about amortizing. In the past, it 

6 used to be that, as far as I know, at least investor 

7 utilities would amortize over 30 years, that was 

8 federal law. Several years ago, the law changed 

9 that transmission industry assets can now be 

10 depreciated over 15 years -- as a reference point 

11 for people. Thank you.

12 MR. PARKER: The tax code is always the 

13 tax code.

14 MR. ROSENSTOCK: Just as a point of 

15 reference.

16 MR. MEYERS: Thanks, Steve. Aaron Meyers, 

17 Cooper Power systems. I would contest that it’s not 

18 the insulation system and not the core coil that 

19 degrades beyond 20 years, but it’s the tank instead. 

20 So I’ve been on a pad replacement here within the 

21 last two months, and it was not the core coil that 

22 failed, it was not the insulation system that 

23 failed, they were replacing it because the tank was 

24 rusting, the bushings were leaking, and that 

25 represents a safety concern out in the field.
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1 MR. HOPKINSON: How many years out?

2 MR. MEYERS: How many years out was what?

3 MR. BOLDUC: How old was the transformer?

4 MR. MEYERS: That one was a 1972 unit.

5 MR. BOLDUC: All right. Thirty-nine 

6 years. So maybe we should increase our lifetime?

7 MR. PARKER: We need to get moving. I 

8 don’t hear around the table a strong basis for 

9 disagreeing with their lifetime median, right. 

10 Gary.

11 MR. FERNSTROM: Gary from PG&E again. 

12 Responding to your point about the tank, yes, along 

13 the California coast, we see corrosion and that’s 

14 probably the principal contributor. However, 

15 looking across the entire country, only two edges, 

16 slivers, are coastal and we don’t get salty fog and 

17 corrosion through the rest of our system. So the 

18 transformers do last a long time, and I think DOE’s 

19 analysis ought to contemplate a longer life.

20 MR. PARKER: Okay. 

21 MR. MEYERS: Aaron, Cooper. Is there 

22 anyone -- a lot of this is perception, and 

23 sometimes perception is swayed by recent experience, 

24 and so I’m wondering, do any of the utilities have 

25 real data as far as replacement lifetime and so 
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1 forth that could be brought forth? Because we have 

2 -- it doesn’t apply in this case because it was not 

3 for the United States, but for one of our 

4 international customers, has data which suggests 

5 that their replacement is 16 years. That may be a 

6 function of their system, it may not be. But rather 

7 than base this on perception, it would be better to 

8 base it on real data that’s collected and can be 

9 statistically evaluated.

10 MR. ANDERSON: Rick Anderson, Fayetteville 

11 PWC. One thing we did do, Aaron, I think everybody 

12 did, was -- we had to replace all our PCB oil 

13 transformers and anything that was manufactured 

14 prior to ’78 had to come out, so all that stuff was 

15 replaced, whether it was good or bad, and so now 

16 we’re just beginning to get to that 30 year point. 

17 So whether they last 40 years, we really don’t know, 

18 because we were supposed to change out all the PCB 

19 oil transformers, what, no later than 1978, or 

20 that’s when they changed manufacturing.

21 MR. PARKER: Andrew.

22 MR. DeLASKI: It just strikes me that you 

23 got a lot of utility around the table here, a lot of 

24 expertise, and I don’t hear anybody saying less than 

25 30 years. I just, you know, if anything, the 
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1 experience of the folks around this table seems to 

2 indicate that may be the bottom of the range. I 

3 mean you got data from the transformers you replaced 

4 30 years ago, and now you’re starting to learn 

5 what’s happened with those transformers. You’re 

6 saying 40 or 50 years. I don’t hear anybody else 

7 who’s actual utilities saying it’s shorter than 

8 that, or shorter than the 30. Again, someone’s 

9 grasping for straws here. I think we should move 

10 on.

11 MR. PARKER: Let’s move on. Thank you.

12 MR. WINDER: Ken Winder, NRECA. One 

13 question is when you look at the life from your 

14 studies and at 34 years, let’s say that we have one 

15 that failed, what do you do at that time? Does that 

16 enter into your operating costs in terms of 

17 replacement and how you deal with that? Or how do 

18 you use that 34 year lifetime?

19 MR. BOLDUC: At the end of the 

20 transformer’s lifetime, the simulation for that 

21 transformer ends, so we do not model a replacement 

22 after the life of the transformer. So in our sample 

23 of 10,000, as we saw in the distribution, some 

24 transformers will have a life of five years, ten 

25 year, 50 years, 60 years, but the average 
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1 transformer life in the simulation is 32 years.

2 This is specifically for Phil. This is 

3 the peak load factor we use in the model, and it 

4 ranges from 50 to 130 percent, with an average of 

5 around 88, 87 percent. 

6 All right. We’ll keep rolling. Thank 

7 you. 

8 Base Constraint Installations

9 Base constraint installations. So in the 

10 model we address base constraints situations --

11 installations for design lines four and five. These 

12 were specified in the 2007 NODA as units that would 

13 be installed in vaults. Conversation earlier today 

14 from Wes Patterson might change that, depending on 

15 how things go with the new product lines and classes 

16 in the engineering. 

17 What I’d like to talk about instead of 

18 which design lines are impacted, is really the way 

19 that we model the costs associated with installing 

20 our vault. We looked at two scenarios, two 

21 situations. The first one is where the vault is 

22 enlarged to take in a new transformer, and the 

23 second is that the customer is forced to buy a more 

24 expensive transformer at the same or less volume as 

25 the transformer in the base case.
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1 In the first instance, we scaled the 

2 values from the 2007 NODA, where the initial 

3 installation cost, as soon as you have to break 

4 ground to change the vault, it’s going to be $1840. 

5 And then with a volumetric charge for the difference 

6 between the base case and the standards case 

7 transformer, of $26, or $28. 

8 What’s not listed here is we also have an 

9 extreme case that can be modeled that we run as a 

10 sensitivity in the subgroups analysis, where the 

11 initial cost is $30,000 and the per cubic foot 

12 charge is $377. This is to take into account those 

13 situations where you’re tearing up the street, or as 

14 Wes said, digging up downtown Manhattan to put in a 

15 new transformer.

16 In the second instance, it’s very simple. 

17 In the LCC we compare the selected design of the 

18 standards case against this assigned base case, and 

19 we compare the volumes, and if the volume -- and the 

20 transformer cannot be selected from the engineering 

21 sample unless it is of equal or lesser volume. And 

22 again, it’s described in Chapter 11 with results. 

23 That has been distributed. Yes, Steve.

24 MR. ROSENSTOCK: Steve Rosenstock, Edison 

25 Electric Institute. I was looking at Chapter 11 --
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1 MR. BOLDUC: Did you get blank numbers?

2 MR. ROSENSTOCK: No.

3 MR. BOLDUC: Good.

4 MR. ROSENSTOCK: No, no. All the numbers 

5 are in here. But the results show space constraint, 

6 but it doesn’t show the sensitivity case results in 

7 this chapter. Where would someone be able to find 

8 those?

9 MR. BOLDUC: If they’re not there, that 

10 would have been an oversight. It is a draft. I 

11 will try to get those out later this week.

12 MR. ROSENSTOCK: Because I think -- this 

13 is Steve Rosenstock, EEI -- especially for those 

14 utilities, you know, with urban transformers, that -

15 - you call that extreme, that $30,000, but maybe 

16 that is extreme, but less extreme could be $15-

17 $20,000 that a lot of them could be facing. So I 

18 think -- I know that’s your extreme case, but again, 

19 for ones in the urban environment, that could be 

20 very significant -- that is going to be their 

21 lifecycle for those units.

22 MR. BOLDUC: That’s understood. That’s 

23 why we compute it as a subgroup.

24 MR. ROSENSTOCK: Good. And again, when do 

25 you think that kind of information, that sensitivity 
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1 case result would be published or would be available 

2 to committee members.

3 MR. BOLDUC: I think it’s very likely that 

4 I’ll be able to get you -- I’ll be able to provide 

5 results for the sensitivity next week, based on the 

6 current engineering.

7 MR. FERNSTROM: This is Gary from PG&E and 

8 the California IOUs. Let’s talk for a moment about 

9 what really happens when a vault transformer needs 

10 to be replaced. So there’s two cases, it’s either a 

11 network transformer or it’s not, it’s in a vault. 

12 We tend to size our vault transformers pretty big to 

13 account for load growth, so the one need for 

14 replacement is load has grown. What are we likely 

15 to do, well, let’s put some fans in there. That’s 

16 the cheapest solution. If it comes to be that the 

17 transformer needs to be replaced, we’ll replace it, 

18 but it’s costly and that would probably be our last 

19 choice. If we do have to replace it and it turns 

20 out that a standard might result in a larger 

21 transformer, maybe we could choose a little smaller 

22 size and put some fans in there. So it would be 

23 rare when we would be wanting to replace a whole 

24 transformer vault in order to solve a problem.

25 MR. DeLASKI: In the modeling -- this is 
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1 Andrew DeLaski -- in the analysis as it exists 

2 today, what incidents do you attribute to this 

3 scenario, the scenario one and two?

4 MR. BOLDUC: We run the scenarios 

5 separately. We don’t try to model them into the 

6 LCC. We don’t have sufficient data that says what 

7 percentage of units are installed --

8 MR. DeLASKI: This is just a separate --

9 MR. BOLDUC: It’s a subgroup. This is 

10 similar to how we handle the rural electric coops 

11 and municipal utilities, these are identified as the 

12 populations that would have different economic 

13 constraints, and so we analyze them completely 

14 separately.

15 MR. DeLASKI: But to Gary’s point, at this 

16 point you don’t have an estimate of the size of the 

17 population.

18 MR. BOLDUC: We’ve heard -- I’ve seen 

19 numbers that point five percent of sales, a very 

20 small number installed in vaults.

21 MR. DeLASKI: Of sales?

22 MR. BOLDUC: Sorry, of installations. No, 

23 they would be sales, I’m sorry. Excuse me, sales.

24 MR. DeLASKI: Point five percent of sales 

25 are installed in vaults are numbers that you’ve 
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1 heard, through your --

2 MR. BOLDUC: It’s an old number, yes.

3 MR. DeLASKI: But that doesn’t speak to 

4 the question of the portion of that point five 

5 percent that actually run into these size 

6 constraints.

7 MR. BOLDUC: No, it doesn’t.

8 MR. FERNSTROM: Gary from PG&E. So, 

9 clearly, for some utilities this is a big problem. 

10 Manhattan, San Francisco. However, across the whole 

11 nation, downtown urban area network systems with a 

12 lot of vaults represent a small portion of the 

13 market.

14 MR. BOLDUC: Thank you.

15 MR. PARKER: My understanding also from --

16 Katie, correct me if I’m wrong -- is that even for 

17 that tiny fraction of utilities that do have severe 

18 space constraints that they can’t deal with, along 

19 the lines that Gary Fernstrom indicated, it’s 

20 usually, if not always, possible to achieve a 

21 significantly higher energy efficiency standard by 

22 moving to a different, to a higher grade of metal so 

23 you could change the design of the transformer 

24 before you would actually just enlarge it?

25 MR. BOLDUC: Yeah, that would be point 
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1 number two, where you select a more expensive unit, 

2 you’re not selecting on first cost, you’re selecting 

3 up the price scale for a unit that will fit in your 

4 current installation.

5 MR. FERNSTROM: Yah, when we buy these 

6 types of transformers, we buy them on specification, 

7 not as a commodity purchase.

8 MR. BOLDUC: Right. And the other thing 

9 I’d like to emphasize is --

10 MR. HYLAND: Can I jump on that?

11 MR. BOLDUC: -- is that the replacement 

12 transformer in the model is the same size 

13 transformer in terms of capacity as the unit it’s 

14 replacing. You’re not scaling up the transformer at 

15 all in terms of this model.

16 MR. HYLAND: I was just going to jump on 

17 what you said -- Mike Hyland, EPPA -- many municipal 

18 governments, we do buy on first cost, and we have 

19 to, by law.

20 MR. PARKER: Wes.

21 MR. PATTERSON: When you look across the 

22 liquid filled, medium voltage market, about 85 

23 percent represents pads and poles in revenue 

24 dollars, 15 percent in revenue dollars is 

25 substations, networks, all those other stuff, and 
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1 the networks are about half of that 15 percent, not 

2 point five percent.

3 MR. BOLDUC: Okay. Can you -- would you 

4 be able to provide us with actual shipments data to 

5 that effect?

6 MR. PATTERSON: Yeah, we --

7 MR. BOLDUC: In terms of units sold?

8 MR. PATTERSON: Yeah, our company shipment 

9 data.

10 MR. BOLDUC: I’d appreciate that. Thank 

11 you.

12 MR. PARKER: Greg.

13 MR. COULTER: Greg Coulter, Prolec GE. 

14 We’re a little concerned about your point two up 

15 there.

16 MR. BOLDUC: Okay. 

17 MR. COULTER: We’re not too sure how you 

18 can -- anytime you’re going to go higher efficiency, 

19 it’s going to be larger. So the point is, as you 

20 try to meet these sizes with a higher efficiency, 

21 that transformer gets larger, and so you come into a 

22 size or a space requirement, a space issue on these 

23 vaults, especially in these urban settings, 

24 Manhattan, we’re talking, San Francisco. There is 

25 no way to go higher price and meet the size. 
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1 There’s no way to make it smaller and still meet the 

2 efficiency. And I don’t think this is the minority 

3 case. I mean, you picked ConEd, which is probably 

4 the biggest network user, they probably use 40 

5 percent of all the networks purchased. Maybe in San 

6 Francisco you’re using another 15, 20 percent of the 

7 networks purchased. That’s two great big users of 

8 them, they’re not a minority. We don’t see how 

9 number two ever works. We can’t imagine that model 

10 ever being able to do that.

11 MR. HIRSCH: Bruce Hirsch, Baltimore Gas 

12 and Electric. I guess I just wanted to comment on 

13 some of the things Gary said with respect to our 

14 system. You know, if it’s a load groove, that type 

15 of an issue, whether you like it or not, those types 

16 of charges get put into the customers’ hands so 

17 they’ve got to pay for that extra cost of installing 

18 those transformers. They’ve also got to work with 

19 us to provide the areas to make room so that we can 

20 fit the transformers into where we need. 

21 The real issue is replacement 

22 transformers. If you have a transformer that fails, 

23 it’s normally an area where it’s serving a very 

24 large customer, or maybe a large of very large, 

25 influential, high profile customers, and we need 
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1 something that’s going to go back into that hole 

2 right away to fix it. We can’t go and increase the 

3 vault size. 

4 Another thing is, in a downtown area, very 

5 seldom can you increase the vault size, there’s no 

6 room, absolutely no room. We’re totally gridlocked 

7 in Baltimore City with respect to that kind of 

8 stuff. So, you know, size and when you’re talking 

9 networks or vaults, weight isn’t the big problem, 

10 but it’s the size of the transformers that become a 

11 real strangulation point for us.

12 MR. BOLDUC: Thank you.

13 MR. BERMAN: Robert Berman, Berman 

14 Economics. That may be on a very individual basis, 

15 that there may be problems, but I know that ConEd 

16 reports that they’ve been increasing the efficiency 

17 of their transformers. They’ve been strongly 

18 encouraged to do so by the Public Service 

19 Commission. Is that a fair way to put it, Steve. 

20 And they have been increasing the efficiency 

21 significantly of the transformers. They have a few 

22 transformers above ground, but the vast majority of 

23 the ConEd system is network transformers 

24 underground, in vaults. So it’s possible. They’ve 

25 done it.
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1 MR. HYLAND: Mike Hyland, APPI. I don’t 

2 think you can argue from the specific down to the 

3 general, though. Just because one utility may have 

4 oversized some vaults from the time they built the 

5 city of Chicago, doesn’t mean that every utility can 

6 do that.

7 MR. PATTERSON: That’s also a little bit 

8 anecdotal, because yes, ConEd is trying to improve 

9 their efficiencies, but going from a high loss N6 

10 grade (ph) to the initial 2010 standard was a 

11 significant bump for them and they have run into 

12 problems now, trying to even use the 2010 standard 

13 and apply it in New York. This has become a real 

14 bottleneck. That’s why I pushed that maybe we 

15 should consider them separate.

16 MR. HOPKINSON: Phil Hopkinson, and also 

17 what I would say is efficiencies implemented for 

18 improvement by ConEd to date are not yet to the 

19 point where the costs go sky high, so when we look 

20 at trying to bump from here to higher efficiency, 

21 the transformer, to Greg’s point earlier, going to 

22 get a whole lot bigger.

23 MR. PARKER: So what I’m hearing then is 

24 that depending upon what the -- ballpark we end up 

25 in the negotiations about what efficiency levels 
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1 we’re talking about, the space constraint may or may 

2 not be a big thing. If you’re talking about a small 

3 bump up, it may be reasonable to assume that 

4 virtually everybody, by making some incremental 

5 adjustments to their materials and so forth, might 

6 can fit everything into the line, fit in the 

7 existing space. But a very significant increase in 

8 efficiency might at that point raise issues about 

9 space constraint which would then require us to, at 

10 that point, consider whether or not there needs to 

11 be a separate subcategory created for vault and 

12 network. Is that right? 

13 Okay. So if that’s the case, maybe we 

14 should table that issue and see -- I hate to keep 

15 kicking the can down the road, but that’s one thing 

16 that since we don’t have a lot of data on it now, 

17 may fruitfully await the discussion in the 

18 negotiations about seeing where we actually are with 

19 regard to efficiency levels, and then come back at 

20 that point to see if we have a real issue or not. 

21 Does that make sense?

22 MR. ROSENSTOCK: Mr. Parker, I agree, but 

23 I also want to say -- this is Steve Rosenstock, 

24 Edison Electric Institute -- at the plenary analysis 

25 stage I do not -- several utilities did raise this 
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1 issue and provided information. I know a person 

2 from PEPCO discussed their views on this issue, and 

3 I’m pretty sure that other utilities with urban 

4 environments did. I believe they provided data for 

5 DOE to use for the revised analysis. Thank you.

6 MR. PARKER: There’s two issues. One is, 

7 you know, what are their current space constraints, 

8 and secondly, what would they be, under hypothetical 

9 new standard that might be of a higher efficiency? 

10 So, good. Any other comments on this before we move 

11 on? Go ahead.

12 MR. SMITH: Bob Smith at Federal Pacific. 

13 Richard, my question is, from the information you’ve 

14 been given by Wes Patterson and Greg Coulter, which 

15 is covering a significant portion of the network 

16 transformer users, don’t you have enough information 

17 to go ahead and make a decision that we do have 

18 space constraints with network transformers?

19 MR. PARKER: Well, I guess the question is 

20 not whether there are space constraints, but whether 

21 there are space constraints that cannot be met by 

22 moving to higher grade metals or some other 

23 transformer design, right, and that could depend on 

24 the efficiency levels. Is that a fair 

25 representation of what you were saying, Greg, 
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1 earlier? Greg says he agrees.

2 MR. PATTERSON: Just a point of note.

3 MR. PARKER: Wes Patterson.

4 MR. PATTERSON: Wes Patterson, ABB. When 

5 we did the design database for medium voltage liquid 

6 filled, somehow or another we made the assumption 

7 the whole universe was wound core. These 

8 transformers, by and large, are stacked core made 

9 with different steels. So be careful.

10 MR. BOLDUC: Thank you.

11 MR. PARKER: Yes, Andrew.

12 MR. DeLASKI: Yes, so we suggested that 

13 DOE, in terms of the analysis, Mike asked before 

14 lunch it would be helpful to have the product 

15 classes, so I would suggest, you know, that 

16 separating out the vault and network transformers as 

17 a separate class for analysis purposes will give us 

18 more information on which to negotiate as this 

19 process rolls forward. So I think it is useful to 

20 separate it out, whether it ultimately gets a 

21 different standard or the same standard is something 

22 for us to discuss as this committee does its work. 

23 But I’d rather have the data, have a separate 

24 analysis that we could look at, rather than wish I 

25 had it later on.
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1 MR. PARKER: Fair point. Mike Rivest 

2 needs a mic.

3 MR. RIVEST: No feedback, all right. Mike 

4 Rivest. Well, I’m sort of in a box. If it’s a 

5 separate product class, what parameters do we put on 

6 the engineering analysis to create a new engineering 

7 analysis, or is this not an engineering analysis 

8 issue. Is this a matter of doing separate economics 

9 with volt costs? What does it mean here to do a 

10 separate analysis for a product class with space 

11 constraints.

12 MR. PARKER: This is Tom. Yes, go ahead, 

13 Greg.

14 MR. ECKMAN: I think this means that a 

15 separate life cycle cost analysis.

16 MR. PARKER: All right, Tom Eckman.

17 MR. ECKMAN: This is a life cycle cost 

18 analysis question because it’s an installation, not 

19 a manufacturing issue. So it’s the cost that is 

20 installation-related to determine whether that space 

21 constraint has a dampening effect on how big you can 

22 make the units and how efficient they could be given 

23 that size constraint. So it’s an economic question, 

24 it’s not an engineering question.

25 MR. RIVEST: I don’t think you can have a 
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1 product class if you don’t have a separate 

2 engineering, because -- no, but I’m not -- I’m not 

3 being very philosophical --

4 MR. COULTER: This is Greg Coulter with 

5 Prolec GE. I’m leaning towards I don’t think you 

6 ought to do a separate analysis, only due to time. 

7 I would like to see what efficiencies we come up 

8 with. I think that’s the right approach, and see 

9 then if that’s an issue for a product line that 

10 represents such a small percentage of the overall 

11 group, that whether you put it in at the higher 

12 efficiency or not, probably isn't going to make a 

13 big difference to you or anybody else in the room. 

14 It’s still a very small number of units. They just 

15 get lumped into this three-phase grouping, and 

16 because of that we become concerned, we as 

17 manufacturers, users that have to live with the 

18 dimensions. We know what dimensions we have to 

19 meet, they know what dimensions they have to meet. 

20 And we’re concerned now that as we talk some of 

21 these higher efficiency levels, we could get into 

22 trouble. You may not get to that efficiency, 

23 because we don’t know what’s going to come out, so 

24 we have to raise the issue. But it’s still a very 

25 small percentage of the total units.
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1 MR. PARKER: I think Andrew’s point that a 

2 small percentage of extreme outliers in terms of 

3 cost could shape the analysis for a category that is 

4 distinct from that. Is that right, Andrew?

5 MR. DeLASKI: It’s that you may ultimately 

6 want a different standard -- you may ultimately 

7 prefer a different standard for these products, but 

8 you’re saying why spend all this time and effort and 

9 money on an analysis for a quarter of a percent of 

10 the market, or maybe it’s more, Wes --

11 MR. PATTERSON: Five.

12 MR. DeLASKI: -- five percent of the 

13 market. Now, ultimately, somebody will, I think, is 

14 what Don’s going to tell us in a second, they have 

15 to have an analysis on which to base their proposed 

16 rule, but it may not be that this committee has to 

17 solve today, or next four weeks.

18 MR. COULTER: Well, you know, and I don’t 

19 have a problem putting data together for this 

20 either, I just have a problem that I think at this 

21 stage, to develop a whole new class that everybody’s 

22 going to have to go out and do all this work, is 

23 going to put us way off here in left field while we 

24 ought to be moving forward where the majority of the 

25 market is, and carve this out.
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1 MR. DeLASKI: So we pounced on the 

2 analysis for Mike to figure out later.

3 MR. COULTER: He has enough analysis to 

4 do. We toss this at him, I don’t see --

5 MR. DeLASKI: Good point.

6 MR. COULTER: Okay. That’s my only 

7 comment.

8 MR. PARKER: Steve.

9 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

10 think we have to consider the end users as well, the 

11 utilities with urban customers that could have the 

12 higher number of these network transformers. Yeah, 

13 maybe it’s a small number, but it terms of 

14 percentage of costs or especially if you are adding 

15 in some of these added installation costs, yeah, 

16 maybe it’s only -- it could be like ten percent of 

17 their transformers or 15, or ConEd, you know, it 

18 might be 30 percent of their transformers, and 50 or 

19 60 percent of their capital expenditures. So for 

20 certain utilities, especially the ones with the 

21 higher number of these units, the numbers might be 

22 small but the dollar impacts could be significantly 

23 larger. Thank you.

24 MR. PARKER: Just want to add, I’m 

25 certainly not a technical person, but I have been 
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1 around the block with politics, both in Washington 

2 and out, and I do know all it takes is couple of 

3 anecdotes to make some big media stories that may be 

4 the tail of the dog, but will nonetheless grab 

5 public attention in a big way. So I think because 

6 of that, you know, you have to take the vault 

7 situation seriously and not create a situation where 

8 either you have a low standard that’s driven for 

9 99.9 percent of the market it’s driven by vault 

10 concerns, or figure one size fits all standard, 

11 ignores those concerns and creates a couple, or 

12 perhaps a handful of bad results. 

13 But really bad results get all the tabloid 

14 new going as a case study in how this group messed 

15 up. So I think, you know, we do need to take those 

16 -- from a political standpoint, you need to take 

17 those extreme cases seriously. I don’t think they 

18 should drive the analysis for the whole category, 

19 but you also don’t want to create a train wreck that 

20 a couple of horror stories will come back and hurt 

21 you later on.

22 MR. PATTERSON: Wes Patterson. Mike, just 

23 to set your mind at ease, if I’m correct that the 

24 rate of change of cost with respect to change of 

25 loss is the primary driver out of the engineering 
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1 analysis, then all the data you have can be applied 

2 to the networks. So there’s not another engineering 

3 analysis that’s needed, it’s just using the data 

4 appropriately. So I don’t think we have to 

5 duplicate your stuff, but we might be able to 

6 segment them out for their own life cycle cost 

7 analysis.

8 MR. RIVEST: That’s definitely doable.

9 MR. DeLASKI: I think I wrap up this point 

10 in the interest of trying to move ahead, but it 

11 strikes me that I don’t hear anybody disagreeing 

12 that taking a separate look at network transformers 

13 makes sense. No one’s disagreed with that notion. 

14 And back to the point I made this morning is that 

15 our interest is focusing on savings and we want to 

16 see significant increases for the transformers that 

17 represent the vast majority of sales, of MDA, and if 

18 that means the standards sit still for, or be modest 

19 for some relatively small applications, then that, 

20 we think, is something that we’d like to be able to 

21 have on the table and be able to discuss.

22 MR. PARKER: (comment off mic)

23 MR. DeLASKI: I’m not sure you want to go 

24 there yet, Richard, do we?

25 MR. PARKER: No, but it sounds to me like 
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1 what you’re talking about -- Andrew, it sounds to me 

2 like what you’re talking about is actually creating 

3 a separate, like we did in the other case, creating 

4 a separate -- for the BIL -- creating a separate 

5 category, but keeping it the same, right?

6 MR. DeLASKI: Yeah. I don’t know what the 

7 level would be, but this is something that we were 

8 willing to discuss.

9 MR. PARKER: Right. Right, and --

10 MR. DeLASKI: Willing to discuss. I mean, 

11 that’s how you -- those are the kinds of solutions 

12 that I think ultimately would enable us to --

13 MR. PARKER: If you can come up with a 

14 physical specification for these things that makes 

15 sense, that distinguishes them from the rest of the 

16 category -- the rest of the transformers in this 

17 class. And I understood from Brian Coffey that that 

18 should be possible, is that right?

19 MR. COFFEY: To physically distinguish 

20 them?

21 MR. PARKER: Yes.

22 MR. COFFEY: (off mic) ... treat them 

23 differently, so I think I heard from the 

24 manufacturers that it’s pretty obvious which is 

25 which, but I think we would have to have another 
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1 conversation about the exact language.

2 MR. DeLASKI: One thing that might --

3 Andrew again -- one thing that might be useful would 

4 be if some folks in the subgroup wanted to come back 

5 and tell us what is it -- I mean, I hear WES, 

6 there’s an IEEE definition that’s helpful, but I 

7 think what ultimately what we would need to have is 

8 what are the things, what is it about these

9 transformers that make them expensive, and let’s 

10 make sure that we’re capturing that in a regulatory 

11 definition.

12 PARTICIPANT: (comment off mic)

13 MR. DeLASKI: Yeah, made of titanium, or 

14 something? Let’s capture -- you can do it -- if 

15 it’s something that can be done.

16 MR. PARKER: So is this something that we 

17 can form a group on? I think that’s a nice 

18 suggestion -- that would basically work reasonably, 

19 intensively over the next few days to gather 

20 whatever data there is available, and make a 

21 recommendation to the group about whether there 

22 needs to be a separate category or whether it’s 

23 going to be treated the same? 

24 MR. DeLASKI: My suggestion, not whether 

25 it just needs to be treated separately, just how do 
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1 you define it? Can you -- it only has to happen in 

2 the next three days, and people can be thinking 

3 about how do you define the category in a way that 

4 is --

5 MR. PARKER: Well, I think it would be 

6 good if we -- if we can get a group together to do 

7 that, to see whether you need to define a category, 

8 and if so, how you would do it.

9 MR. DeLASKI: If you need to define a 

10 category, again, will ultimately be linked to how --

11 what we can do with respect to improving the 

12 standards for the main categories. So that’s why 

13 I’m saying all this is contingent on this process 

14 being able to move forward, so I think, you know, I 

15 hope we can move on --

16 MR. PARKER: But I thought you said 

17 earlier that it would be nice to have the data so 

18 that we don’t have a train wreck at the end.

19 MR. DeLASKI: The definition.

20 MR. PARKER: The definition, right. 

21 PARTICIPANT: (Comment off mic)

22 MR. DeLASKI: That would be good to have 

23 that data, and that would help us make decisions, 

24 and I think especially since we’re capturing -- I 

25 don’t know how you guys -- how the different market 
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1 shares split among different --

2 PARTICIPANT: (off mic)

3 MR. DeLASKI: Sounds good.

4 PARTICIPANT: (off mic)

5 MR. DeLASKI: So we have data, and then we 

6 have the definition, and that gives us the building 

7 blocks to be able to move forward.

8 MR. BOLDUC: Great.

9 MR. PARKER: Anybody else volunteering for 

10 that group? Wes? Greg? Andrew, can you be -- you 

11 want to be involved, or you want to be monitor.

12 MR. DeLASKI: I’ll join that group.

13 MR. PARKER: Okay. Great. And then work 

14 with Chris on that. Thank you. 

15 Pole Replacement

16 MR. BOLDUC: Next slide is pole 

17 replacement. The preliminary analysis presentation 

18 there was some confusion in the comments as to how 

19 the pole replacement algorithm worked. It’s a very 

20 simple algorithm. If the replacement transformer 

21 weighs more than 1000 pounds, the LCC spreadsheet 

22 warrants that a pole replacement is needed and I 

23 think the pole replacement cost is $2000. There’s 

24 some additional adders on top of that, again, it’s 

25 for the same size unit. It only impacts design line 
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1 two, the 25 KV round tank, and so the question for 

2 us is, first of all, is the 1000 pound threshold 

3 correct for transformer of that size, for single4 phase, 25 KVA transformer? And then a follow-on 

5 question for that is, does the committee have 

6 suggestions on how to monitize the impacts of other 

7 people’s wires on the pole and the opportunity cost 

8 that’s lost while replacing the poles? Or sorry, 

9 the cost replacing the poles with these other 

10 equipment on them.

11 MR. PARKER: Steve.

12 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

13 Again, this is off the top of my head, as I recall 

14 there was ... from PEPCO earlier this year that said 

15 that -- Potomac Electric Power Company in D.C. --

16 that said the number was either 800 or 900 pounds, 

17 where if the weight of the new transformer was above 

18 either 800 or 900, especially in Washington, D.C., 

19 there were certain rules in terms of -- certain 

20 regulations in terms of the pole replacement as well 

21 as the crew that was required for it, and the 

22 installation that was required for the replacement 

23 system, and that was filed with DOE. You should 

24 have access to it. So again, that’s one that comes 

25 right off the top of my head in terms of that one. 
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1 And then, you know, I know Bruce talked about safety 

2 clearances. I don’t know if he could address that.

3 MR. PARKER: Yeah, Bruce.

4 MR. HIRSCH: Yeah, I’d just like to add 

5 too that those weights not only affect the pole 

6 loading, which require poles to be replaced, but as 

7 you get up in size in the weight of the transformer, 

8 our trucks can’t handle that transformer, lifting it 

9 up onto the pole, so we have to run cranes out and 

10 that kind of stuff, so you drive the price up of 

11 doing that job tremendously. So that’s an important 

12 thing.

13 The other thing, and I mentioned it a 

14 little earlier, is from the standpoint of NESE (ph) 

15 requirement --

16 MR. PARKER: What’s that?

17 MR. HIRSCH: I’m sorry.

18 MR. PARKER: Do you have data on what that 

19 weight is, what you’re --

20 MR. HIRSCH: Yeah, I can provide something 

21 on that.

22 MR. PARKER: Okay. That would be helpful.

23 MR. HIRSCH: The other thing is from the 

24 standpoint of NESE (ph) clearances and safety 

25 regulations, in the alleys of Baltimore City, and 
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1 I’m sure any city like D.C. and cities like 

2 Baltimore, you run into these clearance issues with 

3 respect to how close you are to buildings, how close 

4 you are to the public utilities, so as you drive the 

5 size of the units up, then you have to put bigger 

6 poles, sometimes you can’t do that in a completely 

7 paved alley type of thing, so we run into all those 

8 issues right now.

9 Like I said, we have started actually, 

10 under certain product lines, to actually rebuild old 

11 transformers so that we could continue to use those 

12 that we can indeed put into those locations and 

13 maneuver them into place with our existing 

14 equipment. All that adds into it. So, yeah, I can 

15 put some stuff together for you on that.

16 MR. BOLDUC: Just a follow-up question, 

17 Bruce. In the current engineering data, the height 

18 and the width of the units are constrained by common 

19 tank size. So would that suffice to accommodate the 

20 clearance issue?

21 MR. HIRSCH: If the height and the width 

22 are constrained -- you’re saying let the weight go, 

23 but the height and the width are constrained?

24 MR. BOLDUC: Yes, exactly.

25 MR. HIRSCH: I guess I wasn’t aware that 
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1 they could do that, but yeah, if the height and the 

2 width are constrained, you’re okay.

3 MR. BOLDUC: Robert.

4 MR. BERMAN: Robert Berman, Berman 

5 Economics. There are also a number of various, I 

6 understand, there’s something called a joint pole 

7 association for areas where communications companies 

8 and so forth use poles with -- the same poles as the 

9 electric companies, so those would be cost shared. 

10 How common those are, I don’t know. It’s an 

11 additional problem, I understand, with poachers in 

12 California, but perhaps that might even drive the 

13 cost down, because you identify the poachers at that 

14 point.

15 MR. FERNSTROM: Are you suggesting that 

16 some California hunters don’t know the difference 

17 between a deer and a utility transformer?

18 (Laughter.)

19 MR. BERMAN: That’s what I’ve heard from 

20 some utilities in California, yes.

21 MR. FERNSTROM: Gary Fernstrom, PG&E. I’d 

22 like to make a comment about this -- besides the 

23 deer hunter. We don’t mount a lot of really big 

24 transformers on poles, so anything over maybe 160 

25 KVA, as an integral unit, doesn’t go on a pole. And 
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1 the second thing is, really big pole mount 

2 transformers are a very small portion of our 

3 distribution system. So as we’ve discussed with 

4 some of these other issues, I believe the case of 

5 the transformer that’s going to weigh too much for 

6 the pole is a very small percent of the market.

7 MR. BOLDUC: Wes.

8 MR. PATTERSON: You said this applies to 

9 design line two. And design line two is, I think, a 

10 25 KVA transformer. Right? But the pole mount 

11 business sells, you know, from like 10 KVA up 

12 through 833 KVA single-phase. And there’s a sw... 

13 that’s three-phase. So how did you take this data 

14 and apply it to that entire market segment, which is 

15 also 30 percent of the entire liquid filled market? 

16 How do we extend this data? Like that thousand 

17 pounds, is that 

18 http://www.etsy.com/listing/81629136/chunky-cowl19 hand-knit-in-autumn-tweed? Or is that thousand 

20 pounds for an 833 transformer?

21 MR. BOLDUC: That would be a thousand

22 pounds for a 25 KVA transformer.

23 MR. PATTERSON: And then you use the 

24 three-quarter rule to scale it up?

25 MR. BOLDUC: We would actually scale the 
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1 results up in the NIA to calculate impacts. We 

2 wouldn’t be calculating life cycle costs. We’re 

3 only calculating the life cycle cost with pole 

4 impacts with 25 KVA transformers.

5 MR. PATTERSON: Only on 25?

6 MR. BOLDUC: Yes.

7 MR. MEYERS: Aaron Meyers, Cooper. So do 

8 any of your 25 KVA transformers exceed 1000 pounds?

9 MR. BOLDUC: No, they do not.

10 MR. MEYERS: And let me also ask, is the 

11 $2000 based in reality or was it an arbitrary number 

12 that was chosen?

13 MR. BOLDUC: It was a number that was used 

14 in the 2007 final rule. We kept.

15 MR. MEYERS: Was it arbitrarily chosen 

16 then or was it based in fact?

17 MR. BOLDUC: I can’t speak to that rule, 

18 sorry.

19 MR. PARKER: Steve.

20 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

21 Again, thank you for this slide, but why not -- why 

22 didn’t you do any analysis for design line one, 50 

23 KVA? Single phase.

24 MR. BOLDUC: They’re pad mounted.

25 MR. ROSENSTOCK: All pad mounts?
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1 MR. BOLDUC: Yeah.

2 MR. PATTERSON: Understand that this means 

3 that the life cycle analysis is only looking at data 

4 for 50 KVA pads, and it’s ignoring 75 percent of the 

5 entire market. I don’t understand how that life 

6 cycle analysis can have any value whatsoever, if all 

7 I do is examine it at a single KVA construction 

8 product. It makes no sense.

9 MR. MEYERS: Aaron Meyers, I’m in full 

10 agreement with Wes.

11 MR. ANDERSON: Rick Anderson, Fayetteville

12 PWC. 

13 (Comments off mic.)

14 MR. BOLDUC: I’m sorry, the LCC, we pick 

15 the rep units that we do the LCC’s out of. We then 

16 scale the results to the different product classes 

17 for -- to calculate the national impacts.

18 MR. MEYERS: Aaron Meyers --

19 MR. PATTERSON: The assumption there is 

20 that all of the economic analysis on the 25 KVA 

21 applies equally to everything that’s under that 

22 design line, or even worse yet, under the equipment 

23 class grouping. Right? We had a design line two, 

24 right, which had a representative unit of a 25 KVA 

25 unit, which, for point of reference, is never sold 
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1 in North America. So here’s a design, a particular 

2 design, when you take all its individual ratings, we 

3 don’t even sell those things. But can you use it to 

4 represent what we do sell, and the answer is yes. 

5 But you can’t use it to represent everything that’s 

6 under the scope of design line two without 

7 extrapolating the data properly. I don’t understand 

8 how there’s any merit in doing an economic analysis 

9 on the 25 KVA and extending that to a 500 KVA. 

10 Makes no sense. Because when we turn around and we 

11 pick these efficiency standard levels, we didn’t use 

12 a common ratio on them. Somebody picked and chose, 

13 here’s a high efficiency on this one, and low 

14 efficiency on this other KVA rating. In the same 

15 design line group. Made no sense.

16 MS. COUGHLIN: So -- this is Katie 

17 Coughlin, LBL. I mean, this is actually taking us 

18 back to the issue of the representative units, which 

19 we started with in the last meeting, because I think 

20 you had some criticisms about the representative 

21 units not being sufficiently representative of the 

22 market.

23 MR. PATTERSON: Yeah.

24 MS. COUGHLIN: So that’s fine, I mean, and 

25 the issue -- these things are -- these decisions are 
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1 sort of made upstream of the LCC, so to create an 

2 individual LCC for a particular type of product, we 

3 need to have all that engineering data laid out. So 

4 if you can come up with a quick way of taking the 25 

5 KVA engineering data and extrapolating it to a 50 

6 KVA --

7 MR. PATTERSON: Which I think we can.

8 MS. COUGHLIN: If you can do that, then we 

9 can create a separate LCC spreadsheet for that --

10 for that installation, that’s not a problem. But we 

11 do need to have --

12 MR. PATTERSON: We can do the LCC analysis 

13 on the motable KVA standards that are within that 

14 design line.

15 MS. COUGHLIN: Well, we can do an LCC for 

16 -- let’s just say one more KVA, right, 50 KVA would 

17 be sufficient to get at some of these issues?

18 MR. PATTERSON: I don’t know, if nothing 

19 else we should take the ones where the major MVA 

20 shipments take place.

21 MS. COUGHLIN: Yeah, I’m just saying that 

22 there’s a --

23 MR. PATTERSON: Like the two largest MVA 

24 shipments in pole mounts and say, we’re going to do 

25 it on those.
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1 MS. COUGHLIN: Okay. So if we can come up 

2 with a way of converting the existing engineering 

3 data for the 25 KVA to something acceptable at those 

4 higher capacities, then we can create an LCC and we 

5 can, if we need to modify some of these installation 

6 constraints, we can do that. That’s a feasible 

7 modification of the analysis. So just leave it at 

8 that and then you can ---

9 MR. PATTERSON: Who do I work with on 

10 this?

11 MS. COUGHLIN: I guess, just the 

12 consultants, so all of us.

13 MR. PARKER: Yes, who else would like to 

14 be involved in that group? Aaron, you don’t. 

15 Anybody else who wants to be involved -- basically 

16 if you have data or you have issues involving 

17 different KVA ratings and are concerned that this 

18 unit may not reflect --

19 MR. ANDERSON: Rick Anderson, Fayetteville 

20 PWC. I think the user needs to work with the 

21 manufacturer to make sure the practical side is 

22 covered there. So I’d be delighted to work with 

23 Wes.

24 MR. HOPKINSON: Phil Hopkinson, HVolt. 

25 One thing I might propose, since I did the market 
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1 study, is take the histogram of data that’s already 

2 in that study and use that for the number of units 

3 times the KVA rating, and that certainly will give 

4 you the MVA impact. And of course you’re going to 

5 find a huge quantity at 15 KVA, another huge 

6 quantity at 25 KVA, lesser quantity at 50, but when 

7 you move the MVA -- I haven’t gone back to look at 

8 it again -- but that data is available so that you 

9 should be able to use not just your company data but 

10 try to do it on what we call the market size.

11 MR. FERNSTROM: So this is Gary from PG&E. 

12 I’d like to elaborate on a comment that Andrew made 

13 earlier. I think being able to address some of 

14 these differences between the analytic approach 

15 that’s taken and the market, is a real value that 

16 these types of negotiations have that we can get to 

17 in the official DOE rulemaking process. So the more 

18 we can have these kinds of discussions, irrespective 

19 of how tedious they may be, I think we’re going to 

20 get to a lot better result than we would just 

21 through the typical adversarial rulemaking process.

22 MR. PARKER: Thank you. Aaron.

23 MR. MEYERS: My question is for Chris 

24 regarding the scaling. Is the weight scaled up and 

25 then this additional charge applied to the units 
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1 that scale above 1000 pounds? Or is your analysis 

2 based on the fact that there are no units in the 25 

3 KVA design line where this applies, and then you 

4 scale the 25 KVA design line up, also extrapolating 

5 the fact that there are no units that are above 1000 

6 pounds? I just want that point to be clarified.

7 MR. BOLDUC: Yes, it’s the latter. 

8 MR. MEYERS: So essentially that was not 

9 considered -- the weight was not considered in the 

10 analysis at all?

11 MR. BOLDUC: No, no, the weight -- in 

12 regard to pole mounting, you’re correct -- you’re 

13 correct, it was incorrect implemented. Weight is --

14 additional cost associated with installing 

15 transformers are applied as a function of weight on 

16 the transformer. These costs are scaled as the 

17 transformer scales up, as the rep unit is scaled in 

18 size to the product class.

19 MR. DeLASKI: This is Andrew. My 

20 recollection, and again, I haven’t read this 

21 recently, but that there is some number of 

22 transformer installations for which the LCC does 

23 assume a pole change out. You’re suggesting that 

24 the way you’re doing the analysis, it must be zero. 

25 Am I right?
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1 MR. BOLDUC: I don’t know if I’m really 

2 suggesting anything, I’m asking how the analysis was 

3 done. Is it considered in the larger KVA?

4 MR. DeLASKI: My recollection, Katie, or 

5 of course you guys can remember -- and there are 

6 some installations in which you would assume -- in 

7 which the analysis shows a pole change-out?

8 MS. COUGHLIN: Yeah, I think -- the 

9 clarification here is that, let’s say it was 

10 correctly implemented for 25 KVA and incorrectly 

11 extrapolated to higher KVA. And we can correct that 

12 extrapolation. 

13 MR. DeLASKI: Perfect.

14 MR. PARKER: Okay. So we’ll have Wes and 

15 Aaron, if he’s willing, work on that. Are you 

16 willing to work on that? And Richard Anderson. And 

17 report back to us as soon as they have results on 

18 whether and how that changes the analysis, but 

19 basically to give -- basically to give -- the basic 

20 deliverable is that they should work together to 

21 give LBL the data that they need, the engineering 

22 data they need to do a revised life cycle cost. Is 

23 that right?

24 MR. BOLDUC: Correct. For poles. Okay. 

25 Shall we move on?
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1 MR. WINDER: Ken Winder, NRECA. I 

2 question the $2000. A lot of that pole replacement 

3 has to be done with hot line work and I think we 

4 ought to have some utility input into that to at 

5 least review it, and we will certainly furnish that 

6 information to Chris.

7 MR. BOLDUC: Thank you. That would be 

8 appreciated.

9 Rural Cooperatives

10 MR. BOLDUC: Rural coops have been 

11 identified as a subgroup in the analysis. We talked 

12 about it earlier in the loading. This slide 

13 basically rehashes this issue. The key factor for 

14 rural coops that differ -- that make them differ 

15 from the rest of the population is that they’re 

16 loaded at lower levels. In this analysis we used a 

17 ballpark factor of 0.75 to adjust the load factor on 

18 the RMS loading on the transformer. We are 

19 continuing to do that this time around. 

20 MR. ANDERSON: Rick Anderson, Fayetteville 

21 PWC. Why wouldn’t you include the municipals in 

22 that?

23 MR. BOLDUC: We do include the municipals 

24 as a subgroup, but we adjust the loading upwards on 

25 municipals. Again, we’ve heard that they are loaded 
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1 at higher levels in primarily urban municipal 

2 utilities. There just wasn’t as much e-mail fervor 

3 on the muni side of things as there was for rural 

4 coops.

5 MR. HYLAND: I can -- as I promised you, I 

6 can get you data within a week, but I disagree with, 

7 just because they’re urban does not mean they’re 

8 heavily loaded. All the information that we got 

9 since we’ve started meeting is just the opposite. 

10 Some of these ... is just like gas and water is 

11 telling us, is 17 percent.

12 MR. BOLDUC: Did you say it’s similar to ... 

13 rural coops loading, perhaps?

14 MR. HYLAND: Well, we’re not as -- well, 

15 yeah, but I want to be sure that we understand here, 

16 it’s tough to categorize that way. You go to 

17 Nebraska, my users are very much like a coop. You 

18 go to downtown L.A., it doesn’t look like a coop. 

19 But they’re both munis. So I go to Seattle and look 

20 at a network transformers, I go to some of my munis 

21 right outside Boston, it’s the same as Boston. But 

22 in the middle of Montana, middle of Alaska, they’re 

23 like coops.

24 MS. COUGHLIN: So, again, this is Katie 

25 Coughlin. So the way we deal with that is to use 
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1 these simulations where we have a distribution of 

2 loading characteristics. So if we can characterize 

3 that range of possibilities with appropriate 

4 weights, then we can account for that in the LCC.

5 MR. SAINT: Well, and I think the reason, 

6 I think the reason why you segmented out rural coops 

7 is because in rural areas, most likely there is one 

8 customer per transformer, and for example, the 

9 minimum size transformer that’s purchased may be 15 

10 KVA for a 5 KVA maximum load, or probably 3.7 order 

11 -- percent RMS load. So that automatically means 

12 that the transformer is loaded less than rated. So 

13 I think that’s a justification for segmenting rural 

14 areas versus urban areas. I can’t speak to the 

15 loading in urban areas, but in rural areas they’re 

16 definitely loaded less than the transformer rating, 

17 in the general case.

18 MR. BOLDUC: Thank you.

19 MR. HYLAND: And I can agree to that, Bob, 

20 but that gets to the diversity issue being that it 

21 would be tough to figure out. I mean, I’d have to 

22 give you all 2000 utility data points. In the state 

23 of Nebraska, which is as rural and farm country as 

24 you’re going to get in this United States is 100 

25 percent municipalities. 
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1 MR. SAINT: Well, all the public power 

2 districts in Nebraska are members, except for two. 

3 We include the rural public power districts in that 

4 rural coop category.

5 MS. COUGHLIN: There’s a -- again, I don’t 

6 want to go into too much detail, but there are --

7 what we have used in the life cycle cost spread 

8 sheet as our sort of sampling base, is the list of 

9 utilities that are in NEIA. So if you would like to 

10 extend the set of utilities that are being included 

11 in our low loading subgroup, we call it rural, but 

12 it can be anything you want. So again, if you want 

13 to provide some specific suggestions of how to 

14 segregate that population of the utilities, then we 

15 can implement that quite easily.

16 MR. ECKMAN: A question for -- this is Tom 

17 Eckman. I have a question for Michael and Robert. 

18 In the data that you guys have, do you have 

19 information on customers per line mile?

20 MR. SAINT: Yeah. Oh, yeah, we have that 

21 data.

22 MR. ECKMAN: So that may be a way to 

23 segment them. Something like that. Because in 

24 Seattle -- Seattle’s clearly got more than one 

25 customer per 50 line mile, but in Nebraska, that 
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1 might be a usual cover. So if you’ve got that, you 

2 might have classes that you can use to move 

3 customers in the IA database or utilities in the IA 

4 database, whether they’re public or private. It’s 

5 really the density of the population per line mile 

6 that’s going to dictate what kind of transformer 

7 they’re going to have. So maybe you guys could work 

8 on that and that might be a way to get at that 

9 information, because I think it’s probably -- it 

10 might even be in EIA database, I’m not sure.

11 MR. SAINT: Well, we have it in our 

12 database and the average is seven customers per 

13 mile. In urban areas it’s more like 60.

14 MR. ECKMAN: And there may be a cut plane 

15 that you could use there to segregate, get the 

16 weights for loading based on that, rather than 

17 public/private. Or whether they’re municipals or 

18 coops.

19 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

20 That second number, that 60 is all urban areas 

21 including IOUs and munis, so Mike have a different 

22 number for the municipal segment.

23 MR. ECKMAN: I’m just saying it probably 

24 would apply to -- whether it’s IOU or public, you 

25 just use the customer per line mile as the aggregate 
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1 per density transformers and you get a better idea 

2 of what the loadings are. I mean, a better 

3 segmentation that way, rather than whether this --

4 you’ve got urban and rural. Pacific Core serves all 

5 over Utah and Nevada, and it’s got -- it looks like 

6 a coop out there. So whether it’s an IOU or not, 

7 just because it serves Salt Lake City, half of its 

8 customer base is in rural areas.

9 MR. PARKER: So as I understand it, the 

10 idea is to categorize it based on population 

11 density, create a subgroup that is defined according 

12 to some kind of population density threshold that 

13 would then be --

14 MR. ECKMAN: I think it’s customers per 

15 line mile, and that’s a surrogate for how many 

16 transformers you’ve got per customer. It’s a pretty 

17 close -- you know you’re not running a distribution 

18 from the transformer seven miles to the next 

19 customer. It’s not going to happen.

20 MR. PARKER: So we’re really focusing in 

21 on rurals. Does that work for you, Bob?

22 MR. SAINT: Yeah, we can provide that 

23 information, but for our members, there are few, 

24 mostly island area that are very dense. There’s 

25 some areas in Alaska, for example, that are very 
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1 dense because they don’t -- between towns there’s 

2 nothing.

3 MR. PARKER: One transformer serves the 

4 whole town?

5 MR. SAINT: Right. And one coop serves 50 

6 towns, but they’re not interconnected. But we can 

7 provide you the list from our membership and it will 

8 be 99 percent rural, and how you want to divide it, 

9 there’s several -- IEEE, as far as their reliability 

10 calculation looks at, I think, less than 30 is rural 

11 per mile, between 30 and 60 is suburban, and over 60 

12 is urban. And you can argue that too all day long. 

13 But I’m not 100 percent clear on what data you need. 

14 You want the load or the number of customers that 

15 are classified as rural, or the number of utilities 

16 that are primarily rural? Most utilities have all.

17 MS. COUGHLIN: We can -- I suggest we 

18 discuss this off line and we can go through the 

19 details.

20 MR. SAINT: That’s fine.

21 MR. PARKER: Okay. John.

22 MR. CASKEY: Yes, John Caskey, NEMA. And 

23 I can understand that this is an issue, particularly 

24 dealing with the loading on the rural-related 

25 transformers, but I’m not sure what you do with the 
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1 results. I mean, in the case of a vault 

2 transformer, I know that that physically is 

3 different than a pad mount transformer. But in this 

4 case, I’m not sure how this plays out relative to a 

5 manufacturer producing one transformer at a certain 

6 efficiency for a rural cooperative and a different 

7 transformer for an investor-run utility. I’m just 

8 not sure how that plays out in the long run, or 

9 would this put a constraint on the efficiency that 

10 we as a group might pick for the entire class of 

11 transformers?

12 MS. COUGHLIN: Yes, so the purpose is to -

13 - again, what the LCC tries to do is it tries to 

14 simulate this wide variety of conditions and then 

15 you get the probability that any given transformer 

16 that is produced ends up in one of those conditions. 

17 So we’re trying to actually predict to the extent 

18 possible, the real life cycle cost of transformers 

19 installed in all these varying conditions. So what 

20 this would have the effect of doing is changing the 

21 weighting of different load profiles in the LCC for 

22 the entire design line. And that will then, in 

23 turn, affect which efficiency levels look cost 

24 effective.

25 MR. PARKER: So it’s not purely a 
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1 distributive analysis. It’s not just a question of 

2 looking at what the impacts on rurals would be, it 

3 will actually go into a statistical analysis that 

4 will affect efficiency standards for the entire 

5 line.

6 MR. GAYTAN: Carlos Gaytan, Prolec GE. On 

7 the Chapter 11 of the LCC analysis, it has a 

8 statement that “Virtually all rural cooperatives 

9 perform some type of economic evaluation of economic 

10 transformer losses.” My question is, do you have 

11 data that supports that statement, and if that data 

12 can be validated with inputs from the utilities? 

13 I’m looking at the 11.5.2.

14 MR. BOLDUC: Right. You’re referring to 

15 the A and B parameter selection?

16 MR. GAYTAN: Yes. It says that virtually 

17 all of the rural cooperatives perform some sort of 

18 economic evaluation of losses.

19 MR. BOLDUC: That statement is -- to come 

20 up with that statement we did a survey of A and B 

21 bids for transformers on the market. And pretty 

22 much -- most coops that we found have a public 

23 bidding process, and of those, most of them actually 

24 specified As and Bs in their bid documents.

25 MR. PARKER: Okay. So what I hear around 
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1 the table, correct me if I’m wrong, is that we’ll 

2 form a group on this as well that Ken will work and 

3 Bob Saint, anybody else want to be on this group? 

4 Will work with them on coming up with first 

5 validating the criteria, which the IEEE might be 

6 one, to categorize this group, and see whether the 

7 assumed loading factors that are currently in the 

8 model are accurate for this group. Is that a fair 

9 statement of what we’re doing going forward? And if 

10 not, to make a recommendation as soon as possible as 

11 to what adjustment needs to be made.

12 With regard to the weight, do you have 

13 data that goes to what the percentage of all 

14 transformer sales are going to rurals so that you 

15 know how to weight this in the statistical model?

16 MR. BOLDUC: Right, EEI -- or sorry, IEEE 

17 861 has the market shares of the electricity sales 

18 by type.

19 MR. PARKER: And do those track the 

20 definitions of rural that are being proposed around 

21 the table here?

22 MR. BOLDUC: I actually think coops are 

23 broken out separately.

24 MR. PARKER: Okay. Well, we’ll leave it 

25 to the group to work out the details of that so we 
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1 don’t get further mired in that. Great. Want to 

2 move on to your next slide quickly, equipment price 

3 trends?

4 Equipment Price Trends

5 MR. BOLDUC: Yes, thank you. Equipment 

6 price trends. In recent analysis we’ve been looking 

7 at equipment price trends over time for commercial 

8 equipment. The first rulemaking to do this was 

9 refrigerators, also called “learning”. For 

10 transformers, we took the data series from the 

11 Bureau of Labor Statistics, the ... price index for 

12 transformer equipment and deflated it over the GDP, 

13 the change in GDP, and came up with three scenarios. 

14 In these scenarios, the price trends are used to 

15 either -- to adjust the overall impacts, the MTV 

16 impacts over time in the NIA. So we’ve come up with 

17 three scenarios.

18 The first scenario is the default 

19 scenario, which is flat, so no -- no price trend or 

20 no price increase over time. The second trend is a 

21 low price trend scenario, which looks at the entire 

22 transformer PPI data series, and it shows a slight 

23 decline over time. And that’s from 1967 to 2010. 

24 And the third scenario, we’ve taken the last 20 

25 years of transformer prices, and that shows a 
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1 relatively steep upswing in transformer prices. 

2 I’ll show you that on the next page what the chart 

3 looks like.

4 So these are our projections. The red 

5 line is the high price trend where we find a 

6 sensitivity in the NIA. And the dotted green line 

7 is the low price trend. Steve.

8 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

9 Again, just to -- I appreciate this very much, and 

10 the flat line is really -- is that a constant 

11 nominal price or a constant relative to inflation?

12 MR. BOLDUC: Constant relative to 

13 inflation.

14 MR. ROSENSTOCK: Okay. So in your high 

15 price scenario and the red line, you are assuming 

16 prices that are increasing higher, at a faster rate 

17 than inflation, which is what’s happened over the

18 last several years, correct?

19 MR. BOLDUC: In the red line, yes.

20 MR. ROSENSTOCK: And those -- the results?

21 MR. BOLDUC: The results aren’t published 

22 yet.

23 MR. ROSENSTOCK: Okay. So, and again, 

24 that’s going to be of interest to all end users in 

25 terms of that sensitivity case. Thank you.
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1 MR. BOLDUC: Andrew.

2 MR. DeLASKI: Chris, again, my vision’s 

3 not great. What’s -- the inflection point, is it 

4 where the data starts going up, is that around 2005?

5 MR. BOLDUC: 2003. Yes, so seven years 

6 isn’t really enough time to project a long term 

7 trend from. We took the past 20 years.

8 MR. DeLASKI: The 2003, is that consistent 

9 with what you manufacturers observed?

10 (Discussion off mic)

11 MR. DeLASKI: And that in -- well, then 

12 there’s a slight drop again -- again, I’m having 

13 trouble reading the graph, but that’s --

14 PARTICIPANT: (off mic)

15 MR. DeLASKI: Okay. Then maybe next 

16 year’s data will reflect that. And this is data 

17 that you gathered with interviews with 

18 manufacturers?

19 MR. BOLDUC: This is data published by the 

20 Bureau of Labor and Statistics.

21 MR. DeLASKI: ... PPI data.

22 MR. BOLDUC: Yes.

23 PARTICIPANT: (off mic) On the 

24 transformers or --

25 MR. BOLDUC: Distribution trends from 
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1 manufacturing and specialty equipment, I believe.

2 MR. SCHOEN: Jerry Schoen, AK Steel. I 

3 think you ought to look at the price of steam coal, 

4 the price of copper, the price for aluminum, and the 

5 price of just iron ore and plot it on that same 

6 graph. And I think you’ll find out that’s what’s 

7 driving that.

8 MR. BOLDUC: We do -- in the appendices 

9 that isn’t published yet, I really apologize, we do 

10 a plot where we take aluminum, steel, copper, and we 

11 do plot it against this, and it does show about a 

12 one year lag between rise in commodity prices and 

13 fluctuation in transformer prices.

14 MR. PARKER: This is good. Why don’t we 

15 take -- are there any other concerns with this? I 

16 want to take a break very soon, but let’s see if we 

17 can -- any concerns that we have with this and then 

18 we’ll break. Aaron.

19 MR. MEYERS: Based on the -- Aaron Meyers 

20 -- based on the -- what I would call violent swings 

21 here, do you feel that the sensitivity that you’re 

22 projecting is sufficient, or how much do you feel --

23 how confident are you that that will capture the 

24 real swings in price?

25 MR. BOLDUC: We do a sensitivity to put 
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1 balance on the price.

2 MR. PATTERSON: The driver for the 

3 transformer price increasing starting in 2003, the 

4 prime driver was a shortage of core steel. Right? 

5 It wasn’t so much cost of commodities, it was 

6 shortage and capacity to produce and meet the 

7 demand. This is what drove it. Now that was an 

8 unusual bubble, but that bubble could reemerge, 

9 depending on what it is we do with an efficiency 

10 standard. We may not have production capacity of 

11 steel to meet the demand.

12 MR. PARKER: Sounds like there could be a 

13 short term and a longer term adjustment -- price 

14 impact, right, with the short term spike in prices 

15 caused by a shift in patterns created by the 

16 standard, perhaps, followed by a decline later as 

17 capacity catches up to the demand?

18 MR. PATTERSON: Yes, Richard. If you’re 

19 concept of short term is a seven to ten year window.

20 MR. BOLDUC: Steve.

21 MR. ROSENSTOCK: I was going to say, just 

22 in terms of some of this is just the impact of just 

23 rising global demand on all of this, especially with 

24 the economies in developing world growing at eight 

25 to ten percent clips, which means doubling over the 
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1 next ten, seven to ten years. That could also have 

2 another -- I think you’ve captured sensitivities 

3 fine, but based on just world -- growth in other 

4 countries, and their terms of electrification and 

5 installing this experiment, I think this is a fair 

6 representation myself. I know you don’t have to do 

7 the global demand into this analysis, obviously, but 

8 I think there is -- that’s part of the underlying 

9 growth in the cost, my view, my personal view.

10 MR. PARKER: Chuck.

11 MR. SIMMONS: Yes, Chuck Simmons, Progress 

12 Energy. Back around 2009, Progress Energy looked at 

13 the impending final rule in effect and at that time 

14 we were expecting -- we went out to vendors, and we 

15 were looking at an average of 25 to 35 percent 

16 increase in transformer prices. But, I guess, lucky 

17 to us, the economy tanked in 2009 and yeah, we still 

18 realized price increases on the average of probably 

19 eight to 13 percent, and core steel was a big thing 

20 back I guess in the 2005 to 2007 range. There were 

21 vendors on allotments, so , you know, that’s very 

22 scary to us as a utility, to not be able to serve 

23 our customers if the efficiency requirements were 

24 going to require certain levels.

25 MR. DeLASKI: Chuck -- this is Andrew. I 
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1 just wanted to make sure I understood you right. 

2 So, the price increases that you actually observed 

3 close to 2010 implementation were on the order of 

4 eight to 13 percent.

5 MR. SIMMONS: Yes.

6 MR. DeLASKI: But your analysis, that was 

7 because demand was dropping overall for transformers 

8 because of the economy going down, the housing 

9 starts, et cetera, et cetera.

10 MR. SIMMONS: That's correct.

11 MR. DeLASKI: But the actual impact on 

12 prices that you observed was on the order of eight 

13 to 13 percent.

14 MR. HOPKINSON: Phil Hopkinson, HVolt. 

15 Question for you is at what point in the price curve 

16 would you expect the rebuild market to take off, and 

17 how would that impact this curve?

18 MR. PARKER: Anybody want to comment on 

19 that?

20 MR. SIMMONS: Well, this is Chuck Simmons, 

21 Progress Energy. I don’t have a specific number in 

22 mind, but I know our repair of older units has 

23 really picked up, and we’re looking at third parties 

24 to repair units. It’s -- I think all utilities will 

25 have to, in turn, do that in order to justify -- in 
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1 fact, as Bruce mentioned, some of the tighter 

2 restraint units, but network vaults and some 

3 overhead units, we would have to rebuild or else 

4 face enormous costs in replacement.

5 MR. HOPKINSON: Well, my question comes 

6 back to, if you know that in advance, is there a 

7 constraint on what this negotiating committee can 

8 work up as a proposed standard that would not 

9 destroy the market?

10 MR. FERNSTROM: This is Gary from PG&E. 

11 Let me make a quick comment on that. As Chuck 

12 noted, we rebuilt some transformers too, but 

13 typically they’re the specialty transformers. We 

14 don’t usually rebuild commodity transformers, which 

15 would be the 65 percent of the market we’re talking 

16 about the medium sized pole mounts and pad mounts.

17 PARTICIPANT: (comment off mic)

18 MR. FERNSTROM: Okay. So, Chuck --

19 MR. HOPKINSON: I don’t think that’s 

20 universally true. I think a lot of people do it.

21 MR. FERNSTROM: Well, it sounds like, you 

22 know, we do things differently, and in California we 

23 don’t. It sounds like Chuck does.

24 MR. HIRSCH: Just to try to answer your 

25 question a little bit more. I mean, take an a... 
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1 curve where it’s going to kick in, crystal ball 

2 signs, depending on how steep that red curve is --

3 and by the way, I’d like to point out that that 

4 curve doesn’t show what would happen if you get into 

5 material shortages. Look at the curve from 2003 to 

6 2009, that’s what it’ll look like. If it goes that 

7 route, then certainly we’re going to be kicking in, 

8 looking at rebuilding transformers. 

9 Like Gary, we don’t do a lot of 

10 rebuilding. It’s the special units. But our 

11 rebuild, or our refurbishment guidelines are based 

12 on the cost of replacement, so -- and they’ve been 

13 in the past if it costs less than 20 percent of the 

14 cost for replacement, we would refurbish. So as 

15 that cost of the new unit goes up, we’re going to 

16 refurbish more under those guidelines.

17 MR. ANDERSON: I think the -- Rick 

18 Anderson, Fayetteville PWC. I think we see costs go 

19 up. I think the utilities will become more 

20 aggressive in their protection philosophies. We’ll 

21 see a lot more lightning protection. We’ll get more 

22 conservative on the fusing, which in turn means when 

23 storms come along, the lights are going to go out 

24 more often. Okay. Because they’re going to make a 

25 conscious choice to protect the asset and not have 
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1 to go out and buy a new one. Make the one that’s in 

2 there last much longer. So I think what you’ll see 

3 is reliability indices become poorer as we try to 

4 protect the asset.

5 MR. PARKER: Let’s take a ten minute, ten 

6 or 15 minute break. Do people have a problem, we’re 

7 running a little bit late. Is it possible to stay a 

8 little bit past five, or do people need to break out 

9 of here at five -- do we have to leave at five?

10 (Whereupon, at 4:03 p.m., the meeting was 

11 recessed for a 23 minute period, and reconvened at 

12 4:26 p.m.)

13 MR. PARKER: Okay. Let’s get started. 

14 First, I passed around a sheet that I thought, in my 

15 absent-minded professor mode, I thought it had 

16 already been passed around, and I’m apologize for 

17 not getting it to you at the beginning. But this is 

18 just basically the issues that are presented, and 

19 we’ve already, as you can see, we’ve already worked 

20 through quite a number of them: transformer load 

21 factor, transformer peak load factor, lifetime, 

22 space constrained units, pole replacement, rural 

23 cooperatives. We’ll finish up with equipment price 

24 trends. This gives you an idea, though of what we 

25 have left to do. So we still have some more work to 
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1 do and let’s just see how much we can do.

2 We were talking about equipment price 

3 trends. I guess what I’d like to do is just get a 

4 sense of the group, recognizing that we’re 

5 prognosticating, we’re guessing about the future, 

6 anything can happen. Is there a strong sense that 

7 this is not a reasonable range of price assumptions 

8 on balance? Because we need to really, as you can 

9 see, we have a lot to accomplish and we need to 

10 think about, you know, what is the critical path, 

11 what do we need to go forward? Does this need to be 

12 altered, or doesn’t it? So, let’s just have a very 

13 quick discussion on that and hopefully we can -- we 

14 can reach consensus on that and move on.

15 MR. HOPKINSON: This is Phil, and I heard 

16 some good input from the utility guys over here that 

17 they said that a 20 percent cost differential 

18 between a rebuild and a new transformer would be the 

19 point where they would consider the rebuild. So if 

20 that number is a go to the bank number, then you 

21 might be able to plug it into the model and see 

22 where the curve ought to peak.

23 MR. PARKER: That’s a 20 percent 

24 manufacturing selling price? Excuse me.

25 PARTICIPANT: Yeah.
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1 MS. COUGHLIN: We actually need an 

2 independent estimate of the cost of rebuild.

3 MR. PARKER: Where would that come from?

4 MS. COUGHLIN: That’s the question. We 

5 haven’t seen any data on that, so if someone can 

6 give us that -- an estimate. I mean we could cook 

7 something up based on the distribution of costs, 

8 labor, materials, et cetera, but it would be more 

9 useful if people who have experience with the issue 

10 would submit that information.

11 MR. SIMMONS: Chuck Simmons, Progress 

12 Energy. We were just speaking, Gary and myself, 

13 after -- before our break -- and when we’re 

14 repairing these, we repair those that we just do 

15 simple replace the bushings, gaskets, simple 

16 repairs, so we nowhere approach -- we probably 

17 approach 20 percent of the cost of a new unit to 

18 repair. I mean I can give you some data that we’ve 

19 recently done for those repairs, if that’s --

20 MS. COUGHLIN: I think we may be talking 

21 about two things here. So that sounds like 

22 maintenance costs, which are part of the ownership 

23 costs.

24 MR. HODGE: Gerry Hodge from --

25 MR. HOPKINSON: You had some concepts, and 
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1 I think that the concepts are correct that repair 

2 that would involve a core coil would be something 

3 where you’d use the new winding and you’d have a 

4 cost of stripping down a unit, putting the core back 

5 in and putting probably new bushings in it. But if 

6 it comes down to that, you really end up with a 

7 winding that won’t get any bigger than what was 

8 there from before, and you -- but it will be a new 

9 winding still, so that you’ll have a cost associated 

10 with it, and you’d have a cost of magnetic core that 

11 disappears and you didn’t have to buy a new one. 

12 But you have a lot more labor with it, so I don’t 

13 know what that would work out in in number. But you 

14 probably could get to it.

15 MR. HODGE: Gerry Hodge from Howard. I 

16 haven’t analyzed that, what it would cost, but 

17 basically you could use most of the existing parts 

18 if you had a coil failure, and let’s just say it’s a 

19 1985 transformer, well, we could bring that in and 

20 we could wind a new coil exactly like the one that 

21 was wound in 1985, and take it apart, disassemble 

22 the cores. You know, the core is the most expensive 

23 part of the transformer. Most likely, you could 

24 reuse the cores and the tank and bushings, unless 

25 they’re broke. So you’d have to put some numbers 
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1 together, but a person could save a lot of money, I 

2 think, in rebuilding, if they want to get into that.

3 Now, we’re not advocating that in a way, 

4 but that is a business that somebody could get into.

5 MR. PARKER: It seems to me that if the 

6 transformer, if the rebuild costs exceeds -- the 

7 price goes up above 20 percent of -- from the 

8 current price, then it’s cheaper to rebuild. If 

9 that’s the case then, there’s no -- you would never 

10 rebuild unless it reaches 20 percent. So if you can 

11 validate that number, that would be sort of the cap 

12 on the permissible price. Is that what people are 

13 saying?

14 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

15 think a better way to put would be it wouldn’t have 

16 an impact on the price, it would have an impact on 

17 the shipments. That as, let’s say, if you’re 

18 looking at the red line, the sensitivity case, and 

19 again if you want to use Bruce’s ratio of rebuild 

20 cost as a percentage of the new transformer cost, 

21 that’s going to have an impact on the actual 

22 shipments and that’s not going to change the actual 

23 price of the transformer. I think that’s the --

24 again, in terms of modeling, if there ‘s a way to 

25 model, especially in the top case, maybe in the 
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1 reference case -- and again, I don’t have the data 

2 in terms of the cost of rebuild versus a new, but if 

3 you want to use that ratio, then you might want to 

4 say that this is going to have an impact on the 

5 shipments because as the price increase, especially 

6 if it’s above inflation, and the rebuilt price does 

7 not increase at that same rate, then the percentage, 

8 as you go on, the percentage of rebuilds increases 

9 over time. I don’t know what that rate is. So not 

10 on the price, but on the shipments, which obviously 

11 spills over into all the other energy savings, et 

12 cetera for the life cycle cost and impact analysis.

13 MR. PARKER: Andrew.

14 MR. DeLASKI: I haven’t heard anything 

15 thus far that I think would help anyone to be able 

16 to model the rate of rebuilding. So it strikes me 

17 as being an exercise -- Steve’s right, I mean 

18 ultimately, this will affect the shipments, which 

19 affects the NIA. It’s not going to affect the life 

20 cycle cost analysis. So I think ultimately it’s not 

21 going to have an impact on the standard selected in 

22 a serious way. So I guess I would suggest that it’s 

23 an interesting conversation. I don’t think it’s one 

24 that’s going to have a significant impact on the 

25 standards within the range in which we’re likely to 
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1 be discussing.

2 PARTICIPANT: (off mic) ... doesn’t make 

3 sense.

4 MR. DeLASKI: My point is that it’s going 

5 to affect the NIA, not the LCC.

6 PARTICIPANT: (off mic comment)

7 MR. HOPKINSON: If the market disappears--

8 MR. DeLASKI: Excuse me, it’s what? I’m 

9 not saying -- okay, if someone can give me data that 

10 would indicate the rate at which you would expect 

11 rebuild to happen based on price change, that would 

12 be something you could model. But thus far all I’m 

13 hearing is speculation. I also think there’s a lot 

14 of confusion here about what is a rebuild? There is 

15 maintenance and then there is rebuilding. So, these 

16 are two different things. It’s not the same, and I 

17 think the rate at which we’re seeing rebuilding, 

18 actually rewinding a transformer is where the 

19 existing market is, pretty small, and there’s a lot 

20 of money to be made here, as Gerry suggests, it 

21 hasn’t happened thus far, so what’s the magic 

22 threshold that people are speculating about, and 

23 what do we have that’s more than speculation?

24 So I just suggest that we could spend a 

25 lot of time on this, but we’re not going to get any 
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1 clarity.

2 MR. HOPKINSON: I think you’d have to make 

3 an assignment in order to get the answer back, but I 

4 bet you could get it.

5 MR. RIVEST: Mike Rivest. I’m starting to 

6 feel like the Michael McCabe in the room.

7 PARTICIPANT: With an engineering law 

8 degree.

9 MR. RIVEST: With an engineering law 

10 degree, and like the historian. In the clothes 

11 washer rulemaking, the replacement was modeled and 

12 it was modeled as -- a decision was made as to 

13 whether at the end of life there would be a replace 

14 versus repair decision. And a portion of the 

15 washers, rather than being replaced, were being 

16 repaired, and that was called the life extension. 

17 So it might -- the repair might extend the life 

18 another five, six years.

19 What that had as an impact on the rule is 

20 that it reduced shipments for manufacturers for an 

21 amount of time. It also reduced the national energy 

22 savings because you weren’t retiring that stock. So

23 that’s how it played out in that rule.

24 MR. MEYERS: Aaron Meyers, Cooper. The 

25 difference here in distribution transformers from 
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1 washing machines are really most anything else that 

2 you could compare to is that those machines have 

3 moving parts, moving parts which wear. The 

4 transformer has no moving parts. If you were to 

5 disassemble a 30-year old transformer and pull the 

6 core out of it, which has been immersed in mineral 

7 oil, that core is going to look like new. That core 

8 can be used again. And manufacturers will have a 

9 serious economic decision to make as to whether or 

10 not to expand or explore the rebuild market versus 

11 new transformers. Based on I think some of the data 

12 that we saw earlier, Rick you were looking at a 

13 transformer that went from $15,000 to $25,000. If 

14 you can rebuild that transformer and still keep the 

15 old core so there’s no cost involved in that, you 

16 might be able to get a replacement that’s $15,000 or 

17 less than $15,000. And that can be a compelling 

18 economic decision for customers to make.

19 MR. FERNSTROM: This is Gary from PG&E. 

20 The core -- if the transformer burns out, the core 

21 isn’t going to look the same. If the core looks 

22 brand new, the only reason you’d rebuild it is if 

23 something happened to the bushings or the case, and 

24 that’s not commonly the case. Where most of the 

25 transformers we’re replacing now, we’re replacing on 
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1 burn-out, otherwise we would be buying new 

2 transformers for new construction, and we’d be 

3 replacing transformers where their capacity has been 

4 exceeded. And where the capacity’s been exceeded, 

5 the transformer may well have been overheated and 

6 might not have been a really good candidate for 

7 rebuilding.

8 MR. PARKER: Okay. It sounds to me like 

9 we need to move on. Did I get around the table, is 

10 there a sense that this is a reasonable set of price 

11 trends, all things considered, given what Gary has 

12 just said, or do we need further discussion of this? 

13 By the silence, everybody’s consent. We need to 

14 move on. Let’s move on.

15 MR. NADEL: I wanted to say one thing on 

16 this whole rewind issue -- Steve Nadel from ACEEE.

17 MR. PARKER: Yeah, right.

18 MR. NADEL: This is an issue, I agree is 

19 probably not a big issue, but it’s an issue that 

20 potentially can be managed. One of the things that 

21 we can do, ACEEE, and some of the other people 

22 around the room is educate the utility commissioners 

23 through NARUC on how it will lower consumers’ energy 

24 bills, lower the losses, if they actually purchase a 

25 new, more efficient transformer instead of rewinding 
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1 an old one. So there are things that we 

2 collectively can do, not all of us, but many of us, 

3 to help keep this problem in check.

4 MR. PARKER: Great. Thank you, let’s move 

5 on then if -- Mike, yes.

6 MR. HYLAND: Who said it’s a problem. The 

7 rebuilding. It’s an option, not a problem. I just 

8 want to make sure we’re clear on that. 

9 MR. HOPKINSON: This isn’t that tough, 

10 then. I think that I can help if I’m commissioned 

11 to do it, but it comes down like this. If we take 

12 the cost based replacement and go back and rewing 

13 and go through the steps that we talked here, it’s 

14 probably in the range of an 80 percent of the 

15 selling price of today’s new one, not of the new new 

16 one. So if the new new one gets to be 20 percent 

17 higher in price, then the difference now becomes 40 

18 percent, so that basically we can take the delta 

19 selling price divided by the change in watts to go 

20 from where we are today with design efficiency zero, 

21 up to EL1, let’s say, and we can see the dollars per 

22 watt and it’s going to be real big, which would say 

23 that probably we cannot justify a full 20 percent 

24 change in selling price before the market 

25 disappears.
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1 MR. PARKER: Okay. Thanks. Let’s move 

2 on.

3 Electricity Prices

4 MR. BOLDUC: The next slide is basically 

5 electricity prices for the results that you’ve seen 

6 and the NOPR used, AEO’s electricity price trends 

7 for 2011 to scale the existing prices in the 

8 analysis. Not a large impact. AEO 2011 is the most 

9 recent version of AEO. No questions, great. Thank 

10 you.

11 Evaluation Rates

12 Also this refers to the -- in the consumer 

13 choice model, prospective transformer purchasers who 

14 evaluate using As and Bs, A and B factors. These 

15 have been revised since the preliminary analysis. 

16 They’ve been revised downward based on a comment 

17 from stakeholders and this committee. So for the 

18 transformers that we’re talking about today, those 

19 would be the liquid immersed transformers, design 

20 lines one through five. We assume a 50 percent 

21 evaluation rate. And then for the small and medium 

22 -- small capacity, medium voltage, dry type 

23 transformers, we use ten percent. And for high 

24 capacity, medium voltage, we used 20 percent.

25 MR. HOPKINSON: How do you plug that in?
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1 MR. BOLDUC: I’m sorry? How do we plug 

2 that in?

3 MR. HOPKINSON: Yeah.

4 MR. BOLDUC: In the LCC model? In the 

5 LCC, for every iteration, we assume that for a 

6 liquid immersed transformer, each iteration of the 

7 simulation is a 50 percent chance of being either a 

8 lower first cost purchase, or a purchase that’s 

9 evaluated with As and Bs. 

10 MR. HOPKINSON: (off mic)

11 MR. BOLDUC: In terms of efficiency, it 

12 can mean that those who evaluate may buy a 

13 transformer that is of higher efficiency than the 

14 current standard.

15 MR. MEYERS: All right. Aaron Meyers, 

16 Cooper. I can tell you that that is way off base.

17 MR. BOLDUC: Would you like to provide a 

18 number?

19 MR. MEYERS: Sure, I’ll provide a number. 

20 I would say that between 80 and 90 percent of 

21 purchases made are within two-hundredths of the DOE 

22 efficiency level. So, the purchase -- or sorry, the 

23 efficiency level is being driven mainly by material 

24 availability: core steel widths, winding conductor 

25 increments, things like that. So if you’re 
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1 targeting something that’s at the DOE minimum, 

2 oftentimes the end result isn’t the DOE minimum, it 

3 might be a hundredth of a percent of efficiency 

4 higher. So looking at that slice of the pie, in 

5 excess of 80 percent, probably closer to 90 percent, 

6 are at the minimum DOE level.

7 MR. BOLDUC: Okay. Can you provide data 

8 to us on purchases by efficiency.

9 MR. MEYERS: I have the data but there may 

10 a confidentiality issue there.

11 MR. BOLDUC: If you could look into it or 

12 aggregate it somehow --

13 MR. MEYERS: We can discuss it later.

14 MR. BOLDUC: Yeah, I’d appreciate it.

15 MR. PARKER: And you’re also covered by a 

16 confidentiality agreement, right.

17 MR. BOLDUC: Right.

18 MR. NADEL: Steve Nadel, ACEEE. Question. 

19 What about bands of equivalence? Because in our 

20 experience, while A and B are commonly used, as 

21 often a band of equivalence is used that pretty much 

22 cancels out the whole calculations.

23 MR. BOLDUC: Right. I’m going to redirect 

24 that to Katie.

25 MS. COUGHLIN: The reason why this makes a 
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1 difference is that in the LCC, if someone is already 

2 purchasing an efficient transformer within the 

3 standard, it doesn’t necessarily affect them, that’s 

4 the actual impact that we’re trying to capture. So 

5 we -- and when we -- because there’s some 

6 uncertainty in the prices that are output by the 

7 engineering analysis, we do a sort of version of the 

8 band of equivalence is to put some random noise on 

9 the prices so that you’re not always selecting the 

10 mathematically lowest price in the dataset, because 

11 we know those prices are uncertain to within a few 

12 percent. So there’s essentially a band along the 

13 bottom of the price efficiency curve which 

14 represents the designs that are selected at lowest 

15 first cost. And we could do some post-processing --

16 we don’t know that if that essentially drops you 

17 down to most -- essentially and A and B of close to 

18 zero, that may have that effect, but it does create 

19 some variability in the design selection.

20 MR. NADEL: Steve Nadel. I think it’s 

21 two different issues. Yes, it’s price variation. 

22 You should model that. But I would agree with the 

23 earlier comment that if it’s A and B modeling 

24 without a band of equivalence, you’re way over25 estimating, and I would lower that percentage to 
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1 take account of the fact that a band of equivalence 

2 means a lot less people are truly doing that life 

3 cycle analysis.

4 MS. COUGHLIN: Yeah, I’d also like to 

5 point out that you don’t necessarily have a change 

6 in efficiency because you have an A and B value. 

7 The efficiency is a two-parameter function of the 

8 two types of losses, so you could be buying the same 

9 efficiency, but you could have slightly different 

10 design criteria.

11 MR. PARKER: Steve.

12 MR. ROSENSTOCK: Just a quick one. You 

13 know I think we also discussed, had some issues, but 

14 we also said that at least for the investor-owned 

15 utilities, there are certain states where investor16 owned utilities are required to use total owning 

17 cost and using A and B values. I know Maryland, 

18 California, I’m not sure what other -- I think 

19 Washington, Vermont, D.C. -- they’re required. So 

20 it might be lower -- I don’t know how much lower 

21 it’s going to be lower, and again, that’s just the 

22 investor-owned, not -- I’m not going to speak for

23 the munis and coops. But it’s not a bad number to 

24 use, in our view.

25 MR. PARKER: Andrew.
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1 MR. DeLASKI: I think we had a similar 

2 conversation in our first meeting, and I don’t know 

3 if Aaron was there or not, were you at our first 

4 meeting Aaron.

5 MR. MEYERS: I was on the phone.

6 MR. DeLASKI: Okay. But I think at that 

7 same meeting that we heard from the manufacturers, a 

8 number of manufacturers, that in their experience 

9 that about ten percent of sales were above DOE 

10 minimum standards. I see a lot of nodding heads, 

11 for the record, around the table.

12 PARTICIPANT: (off mic) ... more than five 

13 percent higher ...

14 MR. DeLASKI: For your company.

15 MR. PARKER: Wes Patterson just said that 

16 for the record, that 30 percent of pole mounted 

17 liquid immersed, per his company were evaluators?

18 MR. DeLASKI: No, he said --

19 MR. PARKER: Were more than five percent.

20 MR. MEYERS: Speaking for my company, pole 

21 mounts are the product class where the greatest 

22 percentages above the DOE, so the pad mount class, 

23 substation class, everything else, is typically 

24 right at the DOE --

25 MR. DeLASKI: So in the pole mount class 
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1 you’re see more differentiation above the level.

2 MR. MEYERS: Yes.

3 MR. DeLASKI: So, I guess my question, so 

4 that -- my question, I guess, to LBL or to an 

5 analyst is, how does that square with your 50 

6 percent evaluator? Can that square with your 50 

7 percent evaluator?

8 MS. COUGHLIN: Yeah, I mean, this is 

9 something -- this is extremely easy to change this 

10 number. You go into the spreadsheet, you type it in 

11 and you run it, so it’s -- we have been carrying 

12 this around as a kind of default value, but there’s 

13 no reason why you can’t -- if people can agree on 

14 the numbers that are appropriate, and if you want to 

15 have those numbers vary by design line, we can do 

16 that. So for us, I don’t think it’s really worth 

17 our time to try to defend the 50 percent. If you 

18 have a number that you think is defensible and we 

19 can go on record, then we can take that number and 

20 work with it.

21 MR. BOLDUC: Sorry, I would just like to 

22 ask a question. Is the primary driver of purchasing 

23 units that are at or very close to the DOE standard, 

24 price?

25 PARTICIPANT: Yes.
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1 MR. BOLDUC: That is the primary driver. 

2 Okay. So I can tell you in the LCC we do see units 

3 selected of the higher efficiency curve, but the 

4 price is usually within -- it is within 15 percent 

5 of the unit in the base case. So it could be an 

6 artifact of -- we perturbed the unit prices by 15 

7 percent, so this could be an artifact that was 

8 carried through from the engineering curves.

9 MR. MEYERS: Aaron Meyers. Some people do 

10 look at windows, but 15 percent is probably much too 

11 large, something on the order of five percent, maybe 

12 two percent might be more reasonable.

13 MR. BOLDUC: Yeah, so you’re saying two to 

14 five percent difference in same -- same spec to 

15 transformers between different manufacturers, they 

16 will compete to within two to five percent in price?

17 MR. MEYERS: No. I’m saying that you can 

18 place a window on price and losses, and within that 

19 window there might be some variation. So if a 

20 customer can purchase a unit that’s more efficient, 

21 sorry -- let me see, what were you saying about the 

22 15 percent? That it is 15 percent --

23 MR. BOLDUC: We perturbate the 

24 manufacturer’s selling price of the transformers by 

25 15 percent in the LCC to account for different 
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1 market scenarios. It’s a random between zero and 15 

2 percent every iteration of the run. What happens in 

3 this case is a base case unit, if it’s plus 15 

4 percent and a unit of a higher efficiency range is 

5 actually at zero, someone -- an evaluator will pick 

6 the higher efficiency unit at no additional cost. 

7 They look the same in the LCC.

8 MR. HOPKINSON: Phil Hopkinson, HVolt. 

9 From my experience in dealing with total owning 

10 cost, most of the manufacturers’ computer programs 

11 will print out the top ten designs, and of those top 

12 ten, some of them are going to be higher efficiency 

13 with -- so they’re all the same TOC, but some will 

14 be higher efficiency with higher selling price, and

15 others will be lower efficiency with lower selling 

16 price. But they both have the same TOC. The one 

17 that almost always gets picked is the one with lower 

18 selling price at the same TOC, because ultimately, 

19 it’s the low first cost that still otherwise hits 

20 their criteria that the market is after. Does that 

21 make sense?

22 MR. BOLDUC: Yeah, and that’s precisely 

23 what the LCC does.

24 MR. MEYERS: Yeah, to expand on what Phil 

25 just said. The windowing, if they specify a TOC, 
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1 you can provide the lowest total owning cost, but if 

2 there’s one that’s slightly less efficient, but is 

3 correspondingly a great deal cheaper, they will pick 

4 the one that is less efficient with the lower first 

5 cost. It’s really working in the reverse, like good 

6 enough. That’s exactly true.

7 MR. GAYTAN: Carlos Gaytan, Prolec GE. 

8 Our data shows that at least 80 percent of the 

9 transformers are within that window of five percent 

10 of the DOE minimum efficiency on one hand, and also 

11 in addition to the band of equivalence influence, 

12 there may be other cases in which the evaluation 

13 factors are used, but at certain values below the 

14 threshold where the design optimization process 

15 leads to a -- anyhow the DOE minimum efficiency 

16 design. So the -- at the end, those lower than 

17 average evaluation factors do not lead to a higher 

18 efficiency design.

19 MR. COFFEY: Okay. And just a little more 

20 information. You could end up with As and Bs in the 

21 spreadsheet that would put you lower than minimum 

22 efficiency, and you would buy the minimum efficiency 

23 for a standard.

24 MR. MILLURE: Dave Millure, Metglas. Just 

25 an observation. We were talking about the issue of 
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1 poles and the weight of the transformer. It’s 

2 interesting, 30 percent of the transformers being 

3 sold for poles are over DOE, so they’re already some 

4 of the way up the curve where we’re going. So they 

5 are, the heavier units required are going up the 

6 poles already.

7 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

8 But it doesn’t say what percentage weight increase. 

9 If it’s a five pound increase, most people can 

10 handle that, I think.

11 MR. CYMBALSKY: So, Chris, is there a way 

12 to benchmark your models so that the market share 

13 of, I guess, the liquid immersed comes out to 30 

14 percent that the market buys up on efficiency? 

15 Based on whatever you set that 50 percent or 

16 whatever?

17 MR. BOLDUC: We can look at it and we can 

18 make -- let me just say, we’ll review the model and 

19 we’ll take --

20 MR. CYMBALSKY: It seems to me that if 

21 they’re saying 30 percent buy-up, then 50 percent 

22 evaluating is probably not bad, because 20 percent 

23 are still buying least cost.

24 MS. COUGHLIN: But the fine point here is 

25 that, as Chris mentioned, if you’re evaluating, and 
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1 your evaluation would lead you to buy something less 

2 efficient than DOE, you buy DOE. So we really -- we 

3 don’t have quite enough information to distinguish 

4 between evaluation and actually purchasing above the 

5 minimum standard level. I also should mention, we 

6 do sensitivities at zero evaluators and 100 percent 

7 evaluators, and there actually it’s surprisingly 

8 little impact on most of the efficiency levels 

9 because the As and Bs that we have from our surveys 

10 are pretty low, so even if you’re evaluating, you’re 

11 not necessarily buying an efficient unit on that 

12 basis.

13 MR. PARKER: So if that’s the case, maybe 

14 we don’t need to belabor it late in the day. 

15 MR. SAINT: So what I’m hearing is that 

16 even those folks that evaluate by A and B factor, 

17 they may be buying a more efficient transformer, 

18 most of them aren’t, but some of them may be, but 

19 it’s not that much more efficient. And so I’m not 

20 sure why it matters how many are evaluating because 

21 it really doesn’t matter, they’re buying pretty much 

22 the same transformer, the minimum standard 

23 transformer today.

24 Now if we increase that efficiency level, 

25 then no one will be evaluating transformers because 
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1 it costs more -- the totaling cost is out of the 

2 water. So I’m not sure why it makes any difference 

3 how many people evaluate, because today, at least, 

4 it doesn’t matter whether they evaluate or not, very 

5 much. And if we increase it at all, no one will 

6 need to evaluate because we’re not buying the most 

7 cost-effective transformer, period, anyway.

8 MR. PARKER: So what I’m hearing around 

9 the table is basically there is a -- a gut reaction 

10 that a smaller fraction are buying by evaluation 

11 than 50 percent, and if the standard goes up, that 

12 ratio is going to go even further down, and so 

13 perhaps a prudent course would be just to agree on a 

14 lower ratio, say 20 to 30 percent, or even lower 

15 than that.

16 PARTICIPANT: Ten.

17 MR. PARKER: Ten percent? And again, this 

18 doesn’t seem to be a fundamental -- and we can do a 

19 sensitivity analysis for what happens if you 

20 increase it to 40 percent or down to zero percent, 

21 but let the base case be then ten to 20 percent. 

22 Steve.

23 MR. ROSENSTOCK: In terms of the analysis, 

24 again, I think what’s important is where we end up, 

25 and if the data is showing that 30 percent are 
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1 buying above those DOE minimum levels, then that 

2 number should be used in any of the energy savings 

3 and life cycle cost analysis.

4 MR. PARKER: Okay. Andrew.

5 MR. DeLASKI: We heard, if I remember 

6 correctly, spinning back the conversation, I think I 

7 heard Wes say it was 30 percent for pole mount 

8 transformers. He’s got his pie charts here, and 

9 will share them, I suspect, with the agency. So I 

10 think it does -- there’s data, I suspect that the 

11 manufacturers have data, and I guess sounds like a 

12 subcommittee should get together and share that with 

13 the consultants and base the analysis on what we see 

14 in the market.

15 MR. PARKER: Do we have -- are there any 

16 issues -- low voltage is a separate committee, but 

17 for medium voltage dry type, do these look like 

18 reasonable figures for people? Is it mostly in the 

19 liquid immersible we have the issue? You need more 

20 data?

21 MR. HOPKINSON: In dry types, my 

22 impression is almost every customer takes the 

23 minimum efficiency, so if that puts that number at a 

24 pretty high to those who just buy on low first cost 

25 of whatever is a permissible transformer. And of 
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1 course those transformers are not going to 

2 utilities, they’re going to the industrial/ 

3 commercial market which is not using a 30 year 

4 period to amortize costs, they’re down closer to a 

5 seven year period.

6 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

7 would agree with that. The primary market for the 

8 last three bullets are commercial or industrial 

9 customers. None of them are working with A and B 

10 factors because they’re doing their own economics 

11 based on their own traditional commercial and 

12 industrial terms. They’re not worried about the 

13 price of wholesale power when they’re doing their 

14 analysis.

15 MR. PARKER: So I think that’s helpful. 

16 Why don’t we -- Phil, go ahead.

17 MR. HOPKINSON: Oh, I am just burning with 

18 a question because you’ve done a great job here, 

19 Chris, and I do commend you even though I’ve been 

20 back and forth arguing with myself to see if I agree 

21 with you. But the question that I have is the 

22 subject that you were working on before, you didn’t 

23 bring me to where I wanted you to, and that was you 

24 were talking loading and I wanted to know, are you 

25 going to recommend any change to the point where 
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1 losses are measured? So we’re using 50 percent for 

2 medium voltage, and that’s what we’re working here, 

3 we’re using 50 percent of name plate today as the 

4 test standard, and I would pontificate just a little 

5 bit more, because I’ve thought this through quite a 

6 long time, and it goes like this, that at 50 percent 

7 of name plate, core loss equals load loss at 50 

8 percent load. Now, let’s look what happens if you 

9 go to 35 percent load. At that point, core loss 

10 equals load loss at 35 percent load, and the loss 

11 ratio between load loss divided by core loss is ten 

12 to one. And while at 50 percent load it’s four to 

13 one. 

14 So now, then I heard from my friend Robert 

15 Berman back there, well, how about 18 percent load. 

16 If you go to 18 percent load, the loss ratio is 42 

17 to one. Now the implications of that are that as 

18 you go down and down and down in efficiency, where 

19 you measure the efficiency, it’s going to result in 

20 transformers being sold that are low on core loss, 

21 they will be, but they will have very high 

22 regulation and impedance, and you turn on your 

23 refrigerator and your voltage drops from 120 down to 

24 40. Now you can’t really tolerate that, and 

25 probably Steve Rosenstock and my utility friends 
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1 over here would say, ah! But if you’re only looking 

2 at efficiency -- you’ve got to get the rest of the 

3 picture, so that what I say is, I love the 50 

4 percent load point for measuring efficiency because 

5 it does guarantee that you’re going to have some 

6 robustness out of the winding too. And I didn’t 

7 hear you say it, but I wanted to hear you say it, 

8 that’s why I was kind of teeing you up for it. Does 

9 that make sense?

10 MR. BOLDUC: I understand -- I think I 

11 understand what you’re talking about, Phil, but the 

12 test procedure isn’t something that is in our 

13 purview and I’m going to wait for your presentation 

14 actually before speaking about it, thank you.

15 MR. PARKER: Let’s see if we can put this 

16 thing to bed, either with an agreement on evaluation 

17 rates that are workable from the standpoint of just 

18 a heuristic model, understanding that there will be 

19 a sensitivity analysis, or a process for going 

20 forward. Because we’re absolutely at the end of our 

21 time, and we need to wrap up. So what I would 

22 suggest is that -- is there an agreement that

23 basically these numbers are okay for the others, or 

24 shall they be lowered to say, ten percent for the 

25 commercial as the base case. Can we just -- again, 
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1 this is --

2 MR. CYMBALSKY: Are we going to look at 

3 the data from Wes and some of the other guys?

4 MR. PARKER: So you want -- do you have 

5 data for the whole market segment, Wes, or just --

6 MR. PATTERSON: (off mic comment.)

7 MR. BOLDUC: Well, can we come back to 

8 that and I’ll just flip through the last two slides?

9 MR. PARKER: Okay.

10 Final Topics

11 MR. BOLDUC: Sure. So it’s been suggested 

12 that as the efficiency rises in the model, there 

13 will be a lack of diversity in terms of possible 

14 design combinations, As and Bs, available to be 

15 purchased. While this holds true at the extreme, 

16 that would be Maxtech, you get a very small amount 

17 of A and B values, or combinations that you can make 

18 transformers out of, in the intervening efficiency 

19 levels there is quite an amount of designs that can 

20 be used to meet the standard.

21 On this graph, on the vertical axis, we 

22 have load losses, the horizontal axis we have no 

23 load losses. The red triangles represent 

24 transformer designs in the base case. The green 

25 dots represent transformers selected, in this case 
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1 it would be the first efficiency level, EL1, and you 

2 can see that there’s, aside from the fact that we’re 

3 picking amorphous core at EL1, you can see there is 

4 quite a range of transformer designs that meet 

5 standard. 

6 Press up the efficiency, the next slide is 

7 efficiency level 3. It does decrease, but there’s 

8 still a fair amount of designs. And then at 

9 Maxtech, there are very, very few. I see a lot of 

10 confused faces. Do I have any questions?

11 MR. ROSENSTOCK: Steve Rosenstock, EEI. I 

12 think we’ve been used to the other slides that were 

13 showing design lines, so this is the first time 

14 we’ve seen a graph like this, so that’s why you have 

15 the confused -- I see exactly what you’re doing and 

16 you’re representing the data differently, which I 

17 appreciate the -- the problem comes in that, you 

18 know, we’re used to different dots for different, 

19 you know, all the combinations of metallurgical 

20 designs, and now you have the same data kind of done 

21 differently so that’s why you got the confused 

22 looks, at least from my point of view.

23 MR. BOLDUC: Yeah, in this particular 

24 plot, the grouping on the left, those are actually 

25 marked as core designs, the load/no load losses.
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1 MR. ROSENSTOCK: And the other thing, 

2 Steve Rosenstock, EEI, the other thing is that we’ve 

3 been kind of focused on design lines one through 

4 five for the most part, so design line seven is, you 

5 know, just --

6 MR. BOLDUC: I’m sorry, that’s a typo 

7 actually. It is design line one.

8 MR. ROSENSTOCK: Thank you. Phil.

9 MR. HOPKINSON: For my simple brain and 

10 not a real smart brain, but what I would tell you is 

11 when you’re over here, oh, at 120 watts of no load 

12 loss and 300 watts of core loss, that would be a 

13 transformer with a two and a half to one loss ratio, 

14 and that would be optimized for maybe 70 percent or 

15 80 percent of rated load. So that would be one that

16 doesn’t fit too well with where we are.

17 When we’re looking at one with 100 watts 

18 and 500 watts, that’s a five to one ratio, and that 

19 would be optimized at 40 percent of load. So if we 

20 had that loss ratio, a five to one ratio, that would 

21 be optimized for 40 percent and maybe you’d even 

22 want to test it at 40 percent of name plate, but at 

23 least that’s the way the numbers look like they fit.

24 If you’re over here with the amorphous and 

25 you are at -- let’s go 40 and 400, that is a ten to 
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1 one loss ratio, and the optimum for that turns out 

2 to be at 35 percent of load. So that’s just things 

3 to kind of think about. Okay. That make any sense?

4 MR. PARKER: My sense this is not an 

5 action item. 

6 MR. BOLDUC: This is for illustrative 

7 purposes. This is the final slide.

8 MR. PARKER: Wes.

9 MR. PATTERSON: Coming back to how much 

10 product is actually moved that is lower losses than 

11 the DOE standard, both single-phase and three-phase 

12 across all of what I see, 40 percent was within five 

13 percent of the DOE standard, 60 percent was more 

14 than five percent lower losses.

15 MR. MEYERS: The data that I looked at 

16 suggested that for single-phase pads, 81 percent 

17 were within .02 percent of the efficiency, the 

18 minimum efficiency; 82 percent -- sorry, 81 percent 

19 of three-phase pads, 82 percent of single-phase 

20 pads, 81 percent of single-phase poles, and 93 

21 percent of substations.

22 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

23 As a follow-up --

24 MR. PARKER: Excuse me, Aaron, is that 

25 from your -- what is that data now?
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1 MR. MEYERS: That’s greater than a year’s 

2 worth of shipment data.

3 MS. COUGHLIN: Are these -- these are all 

4 liquid immersed or --

5 MR. MEYERS: That's correct.

6 MR. BOLDUC: Can you share that? Can you 

7 mail that to me? 

8 MR. MEYERS: I’m not going to mail the 

9 actual data, but --

10 MR. BOLDUC: You shared the percentages.

11 MR. SAMPAT: This is Mahesh Sampat, EMS 

12 Consulting. Basically all it says is you are 

13 adjusting one segment of the market and then ABB is 

14 addressing another segment of the market. That’s 

15 all it says.

16 MR. MEYERS: What my real concern was with 

17 the 50 percent evaluation is if you’re assuming that 

18 those that have evaluation formulas do not see any 

19 additional cost for moving to higher efficiency, I 

20 would argue that that assumption is false. And 

21 furthermore, with the evaluation formulation, you 

22 move higher with your efficiency standard -- the 

23 evaluation formula essentially is specifying a 

24 preferred ratio of no load losses to load losses, so 

25 it allows customers to right-size the transformer 
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1 for the application or the industry that they serve, 

2 and if we move the efficiency level up further to 

3 the point where it becomes too expensive for them to 

4 try to balance that ratio, and also meet the minimum 

5 efficiency, they’re only going to buy to the minimum

6 efficiency, which will be wrong-sizing it for their 

7 application. Or Rick, I think you had mentioned, 

8 you’re buying a tank when a golf cart would suffice. 

9 And that’s the fear in raising the efficiency, is 

10 that we’re raising the efficiency, but with a fixed 

11 loading factor, and not allowing the customers to 

12 make the decision based on their system.

13 MR. ANDERSON: Rick Anderson, Fayetteville 

14 PWC. I’d like to follow up with Aaron. The think 

15 is is that we’re limited, as a user, how to apply 

16 these things. I’ll go back to the subdivision. If 

17 we could put six services on one transformer, we 

18 would. Okay. But what happens, and it goes back a 

19 little bit to what Phil was saying about impedance 

20 and regulation. When you start to go too far, you 

21 have voltage drop, and that’s just a fact of life we 

22 have to live with. So I think as users, we’re 

23 really trying very hard to buy the most efficient 

24 transformer based on the best information we have. 

25 And our systems are limited, physically, to voltage 
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1 drop. 

2 If you turn around and say, all right, 

3 here’s the loading, and you have to be this much 

4 better at being efficient, we’re going to buy it, 

5 but you ain’t going to see it, because we’re not 

6 going to change the way we apply them. So I’m not 

7 really sure we’re getting anywhere -- we’re really 

8 accomplishing anything. We’re going to buy a dump 

9 truck what we can do with a golf cart.

10 MR. BOLDUC: Thank you. Steve.

11 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

12 Again, I don’t know how it fits into the analysis, 

13 but I know for -- I think for all utilities, but I 

14 know for investor-owned utilities, they’re required 

15 -- voltage drop on a regular basis has shown up to 

16 be less than five percent. The range. Some are 

17 three percent, but typically they’re allowed a range 

18 of plus or minus five percent, that’s it. So they 

19 have to make sure whatever design they use does not 

20 -- is probably a lot less, to be on the safe side, a 

21 lot less than five percent, three percent.

22 MR. HOPKINSON: Could I respond to -- I 

23 think that’s a really good point, and I’ve seen 

24 those numbers for a good many years in my career, 

25 and I would ask you to amplify, because maybe we can 
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1 knock off this thing on loading this afternoon if 

2 we’re lucky. And utility purchases when you do have 

3 A and B factors have had a loss ratio that has 

4 actually been pretty narrow range. Now, it’s been 

5 proposed by some that, I think Mr. Berman back here 

6 proposed that these loss ratios that are in the A 

7 and B selection are not thought out well by the 

8 utilities, and that they’re somewhat capriciously 

9 chosen. And yet I see loss ratios that are three to 

10 one or four to one, and very few that are five to 

11 one. I never see them any higher than that. And my 

12 question is, what is the basis of the total owning 

13 cost formula that you have out there, and especially 

14 the B factor, and how have you arrived at it. Is 

15 it, in fact, capriciously chosen?

16 MR. BERMAN: Can I respond to that since I 

17 was stated to have said something which I didn’t? 

18 MR. PARKER: Okay. You’ve got it.

19 MR. BERMAN: Pardon?

20 MR. PARKER: Very quickly.

21 MR. BERMAN: Okay. Robert Berman, Berman 

22 Economics. I never said anything like that. The 

23 comment was made basically that discussing 

24 efficiency, measured efficiency versus efficiency in 

25 the field, if you take a transformer and design it 
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1 at 50 percent load, as has been suggested, and then 

2 put it in the field and operate at 35 percent load 

3 or a 25 percent load, you get a much lower 

4 efficiency than what you set the standard at. If 

5 that’s what you want, that’s fine, but you need to 

6 understand that that’s how the numbers work.

7 MR. HOPKINSON: If I had the time to make 

8 my presentation, which I haven’t been given, if I 

9 had the time, the loss curve and the efficiency 

10 curve from up to 50 percent, if you set it at 50 

11 percent and make that 99 percent efficiency, if you 

12 drop back to 35 percent, you’ll see that you’re 

13 within two-tenths of a percent of that same 

14 efficiency. And in terms of total watts that are 

15 dissipated, you’re basically in a really fine range. 

16 And I’ve got curves to show it.

17 MR. PARKER: Okay. We are past our time. 

18 What I’d like to do is basically stop there for now. 

19 What I think we’ve done in this is just walk through 

20 the LBL engineering data and identify a number of 

21 areas where we have basic agreement, things like 

22 peak load factors, transformer lifetime, electricity 

23 prices. There are other areas where more work needs 

24 to be done. What we’re going to try to do this 

25 evening is basically come up with a list, a to do 
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1 list, a task list, that pulls together, I think, 

2 what we heard during the discussion today, along 

3 with some suggestions to nudge along those areas 

4 where we didn’t -- nudge along the process where we 

5 didn’t agree on a process. We’ll put that on the 

6 table for you first thing in the morning and see if 

7 we can get agreement, not only on a process, which I 

8 think we’ve been discussing, but think about a 

9 timetable for doing this, how soon can we get this, 

10 and working backwards from our deadlines. And 

11 what’s the right process for putting it into a 

12 planned timeline.

13 So, we’ll do that tomorrow. We’ll also 

14 hear from AK Steel on their analysis of the 

15 competitive -- the steel competitive impacts of 

16 alternative efficiency levels. There is, remember, 

17 a sort of a competitiveness TSL breakpoint that we 

18 were talking about in the first meeting that we need 

19 to try to see if we an pin down, so that will be a 

20 priority for tomorrow morning. So I hope to allow a 

21 fair amount of time for that. So we’ll work on 

22 that.

23 And then I’ll ask Rob Carmichael of 

24 Navigant to talk a little bit about the 

25 manufacturing impacts, to get at Aaron’s concern 
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1 about the retooling costs and so forth, so we’ll 

2 have a discussion about that. 

3 So there’s a lot to do tomorrow. We’ll 

4 start -- we’ll start bright and early at nine 

5 o’clock here and we’ll try to end at 12 or no later 

6 than 12:30, and hopefully we’ll be able to finish 

7 our work. So think about timeline, think about what 

8 really needs to be done with this. We’ll come back 

9 with what we see as the consensus of the group as 

10 process moving forward. And we’ll try to end 

11 tomorrow with a specific charge to Navigant and LBL 

12 on what needs to be done. Yes.

13 MR. ROSENSTOCK: Mr. Parker, just a few 

14 things. There are a few other bullet points on 

15 this, the one-pager in terms of forced non-optimal 

16 transformer purchases and then changes to the 

17 analysis. Is that at some point tomorrow as well 

18 after the other presentations?

19 MR. BOLDUC: No, I’m sorry, Steve, I wrote 

20 this list at six o’clock this morning, so it was a 

21 little bit behind -- under the weather, shall we 

22 say. The forced non-optimal transformer purchases 

23 were the last four slides that we saw.

24 MR. ROSENSTOCK: Okay. 

25 MR. BOLDUC: And impact of electric 
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1 vehicles we discussed earlier in the presentation, 

2 basically, don’t account for it. And the addition 

3 of a new LCC subsgroup and data center is for low 

4 voltage transformers. So none of the last --

5 MR. ROSENSTOCK: Low voltage dry type.

6 MR. BOLDUC: Low voltage dry type, that’s 

7 right.

8 MR. ROSENSTOCK: Okay. 

9 MR. PARKER: Eric, yes.

10 MR. PETERSEN: One of the things we’ve 

11 talked about quite a few times here is Mr. 

12 Hopkinson’s -- this is Eric Petersen, AK Steel --

13 Mr. Hopkinson’s presentation. I just wanted to 

14 understand how would we integrate that information 

15 into our discussion, into our agenda?

16 MR. PARKER: The presentation on --

17 MR. HOPKINSON: (off mic) On loading --

18 MR. PARKER: -- loading --

19 MR. HOPKINSON: -- and product cost and in 

20 workable watts ...

21 MR. PARKER: Okay. Maybe what we should 

22 do then is we’ll -- maybe what we should do is start 

23 with that tomorrow, and we will get that on the 

24 table because that will feed in with the way we deal 

25 with the request for data. Fair enough?
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1 MR. PETERSEN: Thank you.

2 MR. PARKER: Okay. 

3 MR. DeLASKI: The time? I’m just 

4 concerned about our time here. I mean we’ve got an 

5 agenda for tomorrow that’s already stacked up. 

6 You’ve got three hours. We discussed loading today, 

7 so why are we going back to loading.

8 MR. HOPKINSON: (comment off mic)

9 MR. PARKER: I guess the question is can 

10 we do this in a work group, which I think is what we 

11 discussed doing, not in the plenary.

12 MR. DeLASKI: I think we also have to 

13 recognize, as Chris stated, that the test method is 

14 not open for negotiation.

15 MR. HOPKINSON: Well, that’s right, so if 

16 that’s true, but are the numbers open. So the 

17 method was fine, but if we change from 50 percent to 

18 35 percent, and the load actually turns out to be 

19 greater than 35 percent, then that’s when it really 

20 kills you on watts lost. It’s not if you go a 

21 little bit under, because the watts difference are 

22 very small then. It’s on the up side, and you’ll 

23 see the shapes of the curves, they fall off quickly 

24 from the point where you optimize.

25 MR. DeLASKI: I hear you. I thought where 
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1 that was left today was that different utilities 

2 were going to provide data to the LBL to get to 

3 corroborate whether their loading data is correct.

4 MR. BOLDUC: Yeah, and that’s what I’ve 

5 heard from the meeting today, is we’re receiving 

6 data. I think the committee criticized that 33 

7 percent --

8 MR. DeLASKI: I don’t doubt that it’s 

9 sensitive, it’s important. I think we have a 

10 process for getting it.

11 MR. HOPKINSON: That doesn’t really quite 

12 do it. Why do the utilities have A and B factors --

13 why do they have a B factor that’s so close to the A 

14 factor? Why do they have one that is in a four to 

15 one range as opposed to a ten to one range. And I 

16 know the answer, but you haven’t said it and so if 

17 you just give them equivalent load, that doesn’t 

18 tell you the base of what the testing point should 

19 be. And I think it should stay at 50 percent, and I 

20 haven’t heard anybody say that you agree with that 

21 yet, and if you just say yes, I agree, I leave.

22 MR. PARKER: Is there agreement that the 

23 test procedure should be at 50 percent.

24 MR. HOPKINSON: Yes, this is a test 

25 procedure issue.
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1 MR. PARKER: Okay. Good. We’re done. 

2 Thank you, folks.

3 MR. BOLDUC: Phil’s happy, then we can 

4 leave I guess.

5 MR. PARKER: All right. Are we ready 

6 then? In that case we will go back to our original 

7 plan, which was to start with --

8 MR. POLINSKI: Richard, this is Ray 

9 Polinski, Allegheny ATI. Again, why -- I just don’t 

10 understand why we don’t take another half hour -- I 

11 thought we were going to work until six tonight 

12 anyhow, it’s only 5:30, and why don’t we hear from 

13 some of Mr. Hopkinson’s comments. I guess the whole 

14 group would benefit from that. We’ve listened to so 

15 much stuff, information, today, I don’t know, it 

16 just --

17 MR. PARKER: We were going to work until 

18 six on those days when we only had two days. This 

19 was not -- we have three days -- a day and a half --

20 full day and a half for each committee, so this 

21 wasn’t a day that we had allocated until six. 

22 MR. MEYERS: I think the question was 

23 posed earlier whether we could work longer, and I 

24 don’t think 20 minutes constitutes really working 

25 longer. I would agree with Mr. Polinski in favor of 
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1 working longer tonight, however long it needs to be, 

2 I’m willing to support that.

3 PARTICIPANT: I can agree to that too.

4 PARTICIPANT: I would say we flew a long 

5 distance for this, this is important topic, that’s 

6 why we’re here.

7 MR. PARKER: Other comments? People want 

8 to work later --

9 MR. POLINSKI: I’m just saying, if he 

10 wants to give his presentation, that’s fine. 

11 MR. CYMBALSKY: I’d rather do it now than 

12 run out of time tomorrow.

13 MR. PARKER: Okay. Fair enough. Okay.

14 (Whereupon, the meeting was off the record 

15 for a brief period.)

16 MR. PARKER: Excuse me, everyone, if we 

17 could have your attention and we will work through 

18 this analysis.

19 Presentation

20 MR. HOPKINSON: Take the one on loading 

21 first, please. Everybody in this room should have a 

22 copy of this because I mailed it to distribution. 

23 But I would take you down to this set of curves is 

24 one that is particularly interesting. And you’ll 

25 see a light curve at the bottom which seems to 
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1 disappear on us, but that is a utility curve for 

2 loading in the summer in the southeast. So you’ll 

3 see light loading at night, and obviously peaking 

4 during the day, and that certainly makes sense.

5 But the RMS equivalent of that is a more 

6 like the heavy black line, so what they have done, 

7 and of course it changes seasonally as well as it 

8 does -- well, I guess that would be a better way to 

9 say it, it just changes seasonally during the year.

10 Now if we go beyond this -- Robert, I 

11 didn’t -- I don’t see Robert right now -- but I 

12 didn’t really mean to shortcut the issue of what 

13 happens to watts, but my point is we have 

14 transformers that are optimized for different peak 

15 conditions on here. Some of the curves that I have 

16 are optimized for much bigger differentials and what 

17 happens with the dotted line, it’s optimized for 

18 about 30 percent load, and the one that is the 

19 dashed line is optimized for about 45 percent load. 

20 What you’ll see is it doesn’t make too much 

21 difference for loads that are less than that, as far 

22 how many watts are involved. What happens, though, 

23 is if you don’t guess right and the loading turns 

24 out to be much heavier, then in fact, the watts are 

25 going to be severely impacted because both the 
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1 efficiency falls off, but the load is higher, so in 

2 terms of total watts, it’s a lot of watts. So my 

3 point is stick with that 50 percent. We don’t know 

4 anything more, none of us do. I don’t either, to 

5 make things more precise than that, but it has 

6 worked well for decades. And I mean going way back 

7 into the 1960s and before. And I have no basis to 

8 recommend anything different than the 50 percent as 

9 a test plan, I think it’s a good one. Okay. So 

10 that’s on loading. Any questions on that? Yes, 

11 Rick.

12 MR. ANDERSON: Rick Anderson, Fayetteville 

13 PWC. I want to make sure I understand what you’re 

14 saying, Phil, is that your opinion is that the load 

15 factors for, say, residential customers are 50 

16 percent.

17 MR. HOPKINSON: Yes. That’s for the test 

18 point. That’s for the test point. Now if the load 

19 factor turns out to be less than 50 percent, the 

20 watts differential from there versus a transformer 

21 that was actually optimized at 35 percent would be 

22 pretty small. But if you put the load factor at 35 

23 percent and say I’m going to make my test at 35 

24 percent too, then you’ll have a ten to one loss 

25 ratio of no load to full load, and the impedance 
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1 regulation, flicker, all the bad things that you 

2 don’t want are going to come roaring in. If you 

3 make it 42 to one for an 18 percent load factor, it 

4 just becomes a ridiculous transformer. So stick 

5 with the 50 percent of name plate load as the test 

6 point, and if your load factor happens to be a 

7 little less, it’s kind of a so what. Does that make 

8 sense?

9 MR. PARKER: Any dissent? Yes, Steve.

10 MR. HOPKINSON: Mike.

11 MR. PARKER: Sorry.

12 MR. RIVEST: So this argument is about the 

13 test procedure --

14 MR. HOPKINSON: It is in fact about the 

15 test procedure, yes.

16 MR. RIVEST: Okay. 

17 MR. HOPKINSON: But it addressed an issue 

18 that both I tried to track what the no load and full 

19 load losses of transformers have been over a long 

20 period of time, and then they have supported the 50 

21 percent measurement point as well. And by 

22 agreement, we agreed to stay with it anyhow so that 

23 this is kind of water over the dam, but it does help 

24 to clarify what the shape of those curves are. And 

25 they fall off fast on the higher load side, and 
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1 they’re almost the same on the lower load side, so 

2 keep it at 50 percent, we don’t know any more than 

3 that right now, I don’t think. Richard.

4 MR. ANDERSON: Just a little bit of 

5 clarity, Phil. Most of the time the transformers 

6 are lightly loaded, at night, spring, fall, and so 

7 as a user we’re putting out there and sizing it to 

8 make sure that we don’t blow them up on Christmas 

9 and fourth of July, right. So what we see is that 

10 95 percent of the time, the transformer is lightly 

11 loaded, so a lot of time is spent lightly loaded, 

12 when watts lost are very low. However, at those 

13 peak times, Christmas, fourth of July, you can make 

14 up so much more of those losses when the transformer 

15 is peaking, right. So the peak load that’s applied 

16 on the transformer is critical to the watts lost.

17 MR. HOPKINSON: I think all the way 

18 around, both my utility friends that are here and 

19 those that are not here who would stand up and bark 

20 on this issue, they would say very much the same 

21 thing, so I fully agree with you. Okay. 

22 So I could take you through a mound of 

23 data but if we have cinched the sale, I’ve learned 

24 years ago we should shut up and leave -- on that one 

25 point.
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1 Let’s go back now and get off from this 

2 presentation and go over to the presentation on the 

3 economics, analysis. Can you go back to assumptions 

4 in here. I’m not sure everybody agrees with the 

5 assumptions, and you don’t have to, but if you don’t 

6 like them, they are the basis of my report. So I 

7 would take you down through, first, that the 

8 manufacturers -- why do I do this report at all? 

9 Basically, I’ve been working for -- and very closely 

10 with Brian and Mike and the Navigant people, and 

11 doing my best to help calibrate the OPS model, and 

12 we’ve talked to the OPS people, and in fact they 

13 made some fixes to the program. So I think it’s 

14 been good work.

15 Then many other stakeholders come to 

16 another meeting that I am chairman of, and that’s an 

17 IEEE transformers committee, and there’s about 100 

18 people that typically come into my meeting and it 

19 takes place every six months, and the next one will 

20 be two weeks from now in Boston. And at that --

21 it’s utility people, it’s manufacturers, both NEMA 

22 and non-NEMA, it’s consultants. But a lot of them 

23 have issues and they brought those issues to me back 

24 maybe three years ago when they were concerned that 

25 some of the efficiencies that were proposed in the 
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1 DOE documents that we could easily get to, they 

2 said, look, we have exhaustive search computer 

3 programs and they’re not finding any designs. Now 

4 how could that be? Well, the only way it could be 

5 is that there were errors in the OPS data, and so 

6 the work was to try to get to that. And we’ve had a 

7 good working relationship so that I certainly think 

8 that we’re doing things on the right path. And I 

9 have absolute respect for the Navigant people. I 

10 think you guys and ladies are very professional and 

11 we’ve worked closely together and I’ve seen nothing 

12 that says we have anything that is counter to that. 

13 It’s just not. 

14 But it is a process that we are going 

15 through for every product line, and we have 

16 actually, to this point, fixed a good many of the 

17 product lines. The one that we have not really 

18 fixed yet is the medium voltage dries, and I think 

19 that Bob and Rob Greeson would certainly -- actually 

20 Wes back there, would all parrot that, that that 

21 still needs some work.

22 But why don’t we go down then -- one of 

23 the things that I was after when I did an analysis 

24 to support Navigant, was I talked to small 

25 manufacturers as well as big manufacturers, and the 
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1 reason for it is I didn’t want to have anything that 

2 would come out in efficiency that would put the 

3 little guys out of business. 

4 For material prices, I had the 

5 manufacturers give me their 2011 data. Now some of 

6 them used standard material prices, and some of them 

7 used actual dynamic prices that were current 

8 purchases. And I couldn’t do anything but average 

9 them, frankly. And I did and that’s what the basis 

10 of doing those designs were. 

11 And the other thing is that when we went 

12 to number four, I didn’t use -- because the 

13 manufacturers who were doing the designs were using 

14 engineering computer programs, and they were not 

15 necessarily using production programs. And the 

16 result is that there was not a real connect with 

17 their marketing organizations to see how the selling 

18 price would vary with material. But I can tell you 

19 as a graduate of the university of hard knocks, 

20 working for three of the major manufacturers, that 

21 we guarded very preciously the materials to sales 

22 ratio and we certainly never wanted to see that 

23 rise. So that we were always trying to protect 

24 that. And I used that, in other words, I had a 

25 spreadsheet that I developed and I had the 
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1 manufacturers fill out that spreadsheet, and many of 

2 them I sent back to the drawing board and told them, 

3 you didn’t do it right. Do it again. And they did.

4 But when I got that done, I could see 

5 whether it looked reasonable or whether anybody was 

6 gamesmanshipping it, and actually, there were not. 

7 And it was well done, and with that I had a starting 

8 point of material to selling price.

9 Since I had that, I used that ratio on 

10 future selling prices for each of the product lines 

11 as we looked at what would happen if we went to the 

12 next level of efficiency. And Matt Hartley had 

13 given me some OPS designs as a starting point. 

14 Those were OPS-1 I will call, before we went back 

15 and had discussions and fixed, and then there was an 

16 OPS-2 that actually was a whole lot closer to the 

17 manufacturers. So I certainly think the process was 

18 good.

19 Then items number six down here, is M3 

20 core material and aluminum conductor. Why is that? 

21 Well, this was 95 KV-BIL and it felt to me, after 

22 talking to the steel makers and actually my friends 

23 at OPS asked me to talk to the -- not at OPS, at 

24 Navigant -- asked me to talk to the domestic steel 

25 makers to see, in fact, what material they could 
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1 support. And what they came back with was M3. 

2 Well, my copper friends would love to have it be all 

3 copper, of course, but I really thought that 

4 conductors also should be available so that 

5 depending on pricing and other factors, that a 

6 manufacturer could choose either one. 

7 So I asked the manufacturers to give me 

8 data that would be M3 and aluminum, as far as they 

9 could go with efficiency, and I used that to develop 

10 the cost curves. On the economic value, as you get 

11 down to number eight, I assumed a 30 year period for 

12 both utility transformers and for industrial/ 

13 commercial transformers, but frankly, after thinking 

14 about it more, I questioned whether 30 years really 

15 ought to be applied to the industrial/commercial 

16 because they’ve got different decisions. That is, 

17 they wouldn’t do those voluntarily. They would go 

18 to maybe a seven year payback period so that it’s a 

19 question, is that a valid assumption. But that’s 

20 what I had in there.

21 I also used a present worth based on a 

22 three percent rate of inflation and seven percent 

23 cost of money. So, again, you can question whether 

24 that is a good arrangement, but at least I have 

25 given the algorithm in the report so that if you 
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1 don’t like those numbers, you just plug in and 

2 you’ll get numbers perhaps you like better. But at 

3 least I’ve got the algorithms in there.

4 So, finally, what I’m trying to get to is 

5 incremental selling price, going from base level 

6 zero to base level one, or to level one, level two, 

7 level three, level four, and you’ll be able to see 

8 in the charts what I came up with for dollars per 

9 watt against the -- what I think is the best value 

10 per watt. Okay. 

11 For present worth of a watt saved, what I 

12 started with was EIA data on what certainly makes 

13 sense, and I’ve had good help from several people 

14 including my GE friends as well as from Federal 

15 Pacific, in calibrating and finding the data on the 

16 EIA site, but what comes down to wholesale power for 

17 utilities in 2011 has averaged four and a half cents 

18 per kilowatt hour. Okay. And so if they can sell 

19 it for that, I figure their costs can’t be any 

20 higher than that, and that’s what I used in my 

21 analysis to finally get to, on a yearly basis, that 

22 would be 39 cents a watt.

23 Now I just got something back from Memphis 

24 Power and Light, saying, nope, our number is 14 

25 cents per watt. Well, maybe it is, but that’s not 
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1 what I used. I used 39 cents here.

2 And on the industrial and commercial side, 

3 the cost per kilowatt hour was listed as 6.7 cents 

4 per kilowatt hour. So that would give me a higher 

5 cost in one year, of 58.7 cents. 

6 Then, on items one, two, three, four, and 

7 five -- so basically design lines one, two, four and 

8 five are utility transformers, for the most part, 

9 and so they would take the owning cost formula that 

10 you’ll see in a moment that would go with utility 

11 transformer, versus the medium voltage dries are 

12 almost 100 percent industrial, so they would take a 

13 different number. 

14 Load growth, I put in as a zero. Why did 

15 I do that? Because in my experience, certainly over 

16 the last decade, haven’t seen a whole lot of load 

17 growth. You put a transformer in and you size it 

18 appropriately and for the most part, load stays 

19 pretty constant on it. And if it’s in an industrial 

20 environment from all the industrial environments 

21 I’ve been in, if you get substantial load growth, 

22 you’re going to add new transformers. So they get 

23 pretty dedicated.

24 This algorithm, right up here, uniform 

25 series present worth factor. Well, it’s not so 
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1 uniform, but what it says is that a rate of 

2 inflation, that’s the R factor, number of years is 

3 the N factor, and G is the growth factor. So if you 

4 don’t like my numbers, I don’t have any problem with 

5 that, but I would say put in different numbers, but 

6 what I used -- a three percent inflation, a seven 

7 percent interest rate, 30 years, I get a 17 

8 multiplier. So it would be 17 times the first year 

9 cost of power, would give you that value per watt, 

10 and that works out to $6.71 for utility transformers 

11 and $9.91 for industrial. Now, you know, for those 

12 customers who evaluate losses, I got back from my 

13 manufacturing friends that the average A factor for 

14 those that go beyond the mandatory utility, are 

15 $5.91 a watt. And so that’s not so far from the 

16 $6.71 that’s here, that I’d say it passes the test 

17 of reasonableness.

18 On the commercial industrial, again, I 

19 used the 30 year period, but it’s a question of 

20 whether that’s relevant or whether it ought to be 

21 brought down to a much shorter period, because let’s 

22 say if you didn’t have a mandatory requirement, then 

23 the industrials have many investment opportunities, 

24 and they really have a hurdle rate that requires 

25 something more than 25 percent return on investment 
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1 to make it past other competing investments. So it 

2 really comes down to questioning whether the 30 

3 years is a relevant number. 

4 But then again, I’m not even sure that any 

5 recommendations that I might have or others in this 

6 room, make any difference, because I’m not sure if 

7 this is part of the negotiating team’s purview. But 

8 perhaps it is. But if it is, I think with this 

9 relationship, with perhaps different numbers even, 

10 would be something that the negotiating team can 

11 concentrate on and decide whether you like this, 

12 whether you want to change it, and get agreement. 

13 Because there’s really only three things 

14 that ultimately the team needs to settle on. 

15 • The first is, the load factor and the testing 

16 point, and we’ve basically agreed on 50 

17 percent, so I’m happy on that point.

18 • The second is the value of a watt saved, and 

19 that’s right here. So take this or change it, 

20 but the team needs to get to a conclusion on 

21 it.

22 • And the third is the cost curve as a function 

23 of efficiency.

24 So let me take you down and look at some 

25 of the results. This chart is particularly good, 
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1 and the reason that it is is because I’ve taken, on 

2 design line one, the 50 KVA single-phase pad and 

3 with the new OPS data -- so this is the data that 

came out August 31st

11 And if we go from efficiency level one to 

12 efficiency level two, it costs $20 a watt, and if we 

13 go from there to efficiency level three, it costs 

14 $53 a watt. So it looks to me, as my simplistic 

15 mind, if this is correct, then the value -- if the 

16 value is correct it says well you really don’t have 

17 a basis to even get as far as design efficiency 

18 level one before you’ve run out of gas. It’s a big 

19 picture kind of thing, but that one made so much 

20 sense.

4 , and it’s corrected so that it’s 

5 basically comparable data. But what you will see is 

6 the manufacturers’ data up at the top says that if 

7 we go from design line zero to design line one, that 

8 the increase in selling price is $400 while the 

9 watts saved are 20, and so we get a cost per watt to 

10 go to that next level of 20 by this calculation. 

21 Now, on OPS-1 it certainly looked like 

22 where the people came into my IEEE meeting and were 

23 concerned -- they thought that the OPS data was 

24 presenting an easier picture to go higher 

25 efficiency, they were correct. And you will see 
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1 that in some of these numbers. It’s been corrected. 

2 There’s still some issues, but basically you’re a 

3 lot closer now with what the manufacturers gave me 

4 to roll up.

5 If you walk down from here, I’ll just show 

6 you how the plots work. Here’s with ZDMH too. I 

7 think the point about ZDMH and my steel friends 

8 could talk forever about it, but the point is it’s 

9 not even sold in the United States, and it’s not 

10 really a viable material to be plugged in as a place 

11 to base the standard.

12 Here’s a scatter plot that is pretty good. 

13 The M is what the manufacturers gave me, and 

14 actually if you don’t go too far in efficiency, 

15 especially if you could look at the change that came 

16 in after correction, the OPS data is closer, and I 

17 would say in the small efficiency change range that 

18 it’s doable. It’s comparable, an the OPS data is 

19 okay. If you go up too high in efficiency, it’s not 

20 okay, and I’ve got suspects for why it’s not, and 

21 what I think that it is is the lead loss, stray 

22 loss, tank loss goes up, and I don’t think that it’s 

23 reflected in the discussion I’ve had with Naheed 

24 (ph), I don’t think it’s reflected in the program.

25 I think that she does a good job with the 
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1 core and winding, but if the lead loss gets too high 

2 then it gets to be a controller at the highest 

3 efficiencies because what it does is give a fixed 

4 value of watts. So let’s say you had 2000 watts on 

5 an arbitrary transformer, and 1000 of it turned out 

6 to be lead, stray, eddy (ph), tank, then you’ve only 

7 got 1000 watts left to put in the core and coil, and 

8 they get much bigger. 

9 So if we looked at the spreadsheet -- this 

10 is what I was talking earlier, that on the 

11 spreadsheet, I can’t work with just selling price 

12 because it doesn’t tell me anything. So I came up 

13 with a whole series of parameters that I wanted the 

14 manufacturers to give me data on, and they did. And 

15 with that I then could sort out where there were 

16 problems. Like in the single-phase pad with the 

17 OPS-1 data, if you look down at gallons of oil, it 

18 was showing 21.9, and the manufacturers were showing 

19 up with 41.3. And they were pretty tightly spaced, 

20 so the manufacturers were close. So what was wrong? 

21 And that program was fixed for OPS-2, so it has 

22 actually been repaired.

23 But there was an algorithm error in the 

24 program and, you know, I’m a crude programmer, 

25 really crude, but I might think I’ve done a good job 
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1 until I’ve reviewed it with somebody and then you 

2 find that I didn’t do a good job, then I obviously 

3 fix it. And that’s really the process that went on 

4 here.

5 Total weight is another one that is quite 

6 interesting. If you look down, it’s about five 

7 items down. Total weight and going across, you’ll 

8 see that the manufacturers had a whole lot higher 

9 total weight as well, and as you go to higher 

10 efficiencies, that kept increasing. So we really 

11 had that piece to try to get a sense on too. And 

12 then the weight of the core and the weight of the 

13 winding. And it just told me that I really think 

14 the manufacturers data is close to the right answer. 

15 Now you can argue the selling price, 

16 because we tried to use selling price to the end 

17 user as Bob Smith was talking about earlier on up 

18 front. And so it’s off by -- it’s overstated by 

19 some percentage to what it would be at just the 

20 manufacturer’s location. But that same relationship 

21 was true for every one of the product lines we went 

22 through.

23 Design line two on poles actually was a 

24 lot closer, and if anything, the OPS data overstated 

25 the price on the smaller efficiencies, and then 
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1 understated it a little on the higher. But the 

2 result is, you’ll see, that I’m coming up with, for 

3 the manufacturers, $13.50 per KVA -- per watt saved, 

4 I should say, to go from zero to efficiency one. 

5 And the OPS data would have said it cost more to 

6 make that first step. I don’t think it does. So I 

7 would say the manufacturers’ data is believable, and 

8 that’s really the only data I can trust because 

9 that’s the only one that I can see all of the facts 

10 on.

11 Going down further, the scatter plot and 

12 the manufacturers’ curve is the top one -- no, it’s 

13 this one here that comes up, and OPS-1 veered off, 

14 but it veered off because it went to amorphous. And 

15 when I got OPS-2, I pulled off the M3 data from it, 

16 and it looks like, as Wes had said earlier, that the 

17 slopes are about the same for the poles of the OPS-2 

18 versus the manufacturers. So I think that was good 

19 feedback work.

20 Design line four. I think in this one 

21 that the slopes were not too far different, but it’s 

22 very strange. If you came across on OPS-1, you’d 

23 see that, oh, all of a sudden it got cheap. Well, 

24 the reason that it did is it went to amorphous 

25 again, to make a change. But if you stayed with M3, 
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1 then they were not so awfully bad, but go down to 

2 look at the scatter plot, you’ll see the 

3 manufacturers’ curve in M’s and you’ll see OPS-1 

4 down below, and then OPS-2 is above it, and it can 

5 go as far as efficiency level one and then it starts 

6 to go to different steel. It went over to M2. So, 

7 I’m not saying that that’s not a good thing to do, 

8 but I think for -- if the assumption is that we’re 

9 going to try to find an efficiency that can be 

10 doable with M3, then we really ought to constrain 

11 the place where we go to such that in fact that it 

12 works.

13 On this one, they had the same gallons of 

14 oil problems that OPS-1 was showing 31.79 and the 

15 manufacturers were coming up with 130. So basically 

16 anything that was a rectangular tank, the OPS first 

17 version was under calculating, and again, Naheed 

18 (ph) found the formula problem and she’s fixed it. 

19 So all of the rectangular tanks were that way. But 

20 if you look at total weight too, total weight on 

21 this one, the manufacturers were close at the 2700 

22 pounds, and OPS-1 was 1700 pounds, and that spread 

23 went across and got bigger. So again, I would tell 

24 you that the one that I believe is the 

25 manufacturers’ data.
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1 Let’s take design line five had some 

2 really strange parts to it. The dollars per watt to 

3 go to the first efficiency, we were coming up with 

4 $17 on that, and of course, if the value per watt is 

5 only $6.71, it really says that financially, it 

6 doesn’t justify. 

7 The plot, C curve 1 for OPS-1, was way 

8 below -- after you got past about 99.5 percent 

9 efficient, because it went over to amorphous. The 

10 manufacturers’ curve, on M3, took a steep rise and 

11 it went up to $87,000 at the efficiency level four. 

12 So this is the 1500 KVA.

13 Again, what we look at here is first the 

14 gallons of oil had that same calculation error as 

15 was present in any of the rectangular tanks. But 

16 the total weight was a very strange one too because 

17 down here, you’ll see a spread of maybe 3000 pounds, 

18 2500 pounds at that efficiency. Way over to the 

19 right, at the highest efficiency, the difference 

20 between the manufacturers and OPS-1 was 10,000 

21 pounds.

22 MR. PARKER: Sorry, can we have those --

23 can we have on the record, Mike and David, did you 

24 want to --

25 MR. MILLURE: Yeah, Dave Millure, Metglas. 
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1 He’s comparing an M3 design to an SA-1 design and --

2 MR. HOPKINSON: It is true, but it has the 

3 compounding error of lead loss, tank loss, bus loss 

4 that frankly, they don’t really have a good, 

5 accurate calculation on. So if the manufacturers 

6 give them those numbers, they get it. But if you 

7 don’t give it to them, then they really don’t have 

8 it.

9 MR. MEYERS: Phil, is the column on the 

10 far right, is that the manufacturers’ amorphous 

11 design?

12 MR. HOPKINSON: It is.

13 MR. MEYERS: So the manufacturers’ 

14 amorphous design is 19,000 pounds and OPS’ is 

15 10,000, is that correct?

16 MR. HOPKINSON: That is correct.

17 MR. MEYERS: Would you say that’s an 

18 apples to apples comparison?

19 MR. HOPKINSON: Well, I think it is.

20 MR. PARKER: Mike, you want to respond? 

21 He needs the mic.

22 MR. RIVEST: Phil, that was one 

23 manufacturer submitted one data point, and I have --

24 I have all the data from all the manufacturers, and 

25 I can tell you there is, you know, Phil is 
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1 presenting an aggregation of four manufacturers. 

2 Having aggregated data for many years, I can say 

3 that averaging creates all sorts of issues. So, 

4 Phil, so, you know, my take-away from your 

5 presentation is that you would like this rule to be 

6 based on M3 steel, that M3 steel has a much sharper 

7 curve, correct:

8 MR. HOPKINSON: (off mic) It is ... 

9 availability.

10 MR. RIVEST: Right. And that -- I think 

11 that’s my main take-away. I think that at the 

12 current analysis is in fairly good agreement when 

13 comparing steels -- the same grades of steels --

14 MR. HOPKINSON: (off mic) At low 

15 efficiencies, the OPS-2 is --

16 MR. PARKER: Excuse me, you’re going to 

17 have to speak into the mic.

18 MR. HOPKINSON: I think at low 

19 efficiencies, that is if you don’t change too far, 

20 then the OPS-2 data is not so far off, and I think 

21 Wes would agree with that, with the analysis that 

22 he’s done with sales. He’s not selling transformers 

23 that are way over to the far right, because there 

24 haven’t been any orders for those kind.

25 MR. PARKER: Wes Patterson, ABB.
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1 MR. PATTERSON: Wes Patterson, ABB. I 

2 sell units that are more than 40 percent lower than 

3 the current standard, which is putting us all the 

4 way up at the highest energy efficiency level they 

5 had. And my findings have been, at least on liquid 

6 filled, that if you ignore the absolute value, and 

7 look at the trends of the data, the trend of the 

8 data is fairly good.

9 MR. HOPKINSON: But wait a minute. You’re 

10 using amorphous in that analysis too, I think.

11 MR. PATTERSON: That's correct. I use 

12 amorphous. I use M2. I use M3.

13 MR. HOPKINSON: Yeah, I agree.

14 MR. PATTERSON: I use M6. I use H-zero, I 

15 use H-1, which they didn’t include -- the DOE didn’t 

16 include in their analysis.

17 MR. HOPKINSON: No, I know. I would say 

18 that Mike’s comment is valid too that yes, we didn’t 

19 have very much input on the amorphous so there could 

20 have been amorphous designs that maybe would be more 

21 optimal. But what happened was we were told to use 

22 the efficiency of 99.69 -- they didn’t get quite to 

23 99.69, they got 99.67 and they went aluminum-copper, 

24 so they had an aluminum low voltage and a copper 

25 high voltage. So if you have to use the copper-
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1 copper, you would have had a different design, that 

2 would have been one of the factors that would have 

3 changed it. And if the efficiency was allowed just 

4 to go down a few points, it would bring the cost 

5 down dramatically, because the core weight got 

6 really out of line and the winding weight got really 

7 out of line. So that’s what my observation is on 

8 this data.

9 But what I would say is, that’s so far to 

10 the right that certainly if the assumption of an M3 

11 is going to be valid, then you wouldn’t want to go 

12 that far to the right anyway.

13 MR. RIVEST: You know, I think it reflects 

14 the fact that we are out of that take off area, so 

15 maybe they’re both valid, it’s just that you don’t 

16 have to be off by a lot to be way off.

17 MR. HOPKINSON: I think you’re right.

18 MR. POLINSKI: Ray Polinski, ATI 

19 Allegheny. And the reason I was pushing everyone 

20 sticking around, and the reason we asked Phil to do 

21 this and then you’ll see some of the excellent data 

22 from AK Steel as well is, the last meeting I thought 

23 we had a consensus, and I think Andrew said it, a 

24 number of people said it, hey we do not want to go 

25 to a standard where we’re sole sourced. We want to 
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1 go to a standard where we’ve got multiple materials. 

2 Selections. I mean, I’m just quoting you, I don’t 

3 know on that.

4 MR. DeLASKI: That’s a misquote. I said 

5 that --

6 (overspeaking)

7 MR. POLINSKI: You said that you wanted 

8 to have a standard that would be satisfied by 

9 multiple materials.

10 MR. DeLASKI: You’re changing what I said. 

11 I said I wanted to evaluate a level that told us 

12 what would happen. That’s very different than I 

13 want a standard at that level.

14 MR. POLINSKI: Well, again, I think 

15 everyone said that they didn’t want it to be sole 

16 sourced.

17 MR. DeLASKI: I never said -- I didn’t say 

18 that.

19 MR. POLINSKI: Okay, fine, then I stand --

20 MR. DeLASKI: I’m interested in that 

21 point.

22 MR. POLINSKI: Okay, that’s all I’m 

23 saying. That’s what this is showing is that --

24 MR. DeLASKI: What you’re suggesting is 

25 that --
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1 MR. POLINSKI: The M3 --

2 MR. DeLASKI: -- if you want multiple 

3 suppliers, then no change.

4 MR. POLINSKI: No, no. I’m saying just 

5 let’s not start talking about levels three, four, 

6 five, six, seven. I’m saying maybe we’re in the 

7 range of zero, no change, to a two, or something 

8 like that. That’s all I’m saying. 

9 So let’s start narrowing our focus here 

10 because we’re so all over the place we’re never 

11 going to get anywhere if we keep talking about --

12 we’re out on Pluto. Let’s just stay here on earth. 

13 We’ve got to get into the meat of the discussion, 

14 that’s my point.

15 MR. DeLASKI: Yeah, I’m all for getting 

16 the meat. I think that’s useful. But I think just 

17 to be clear, our interest was in evaluating multiple 

18 levels to tell us impacts -- showing the impacts on 

19 the steel manufacturer to something that we think is 

20 part of this discussion and we need to understand 

21 that.

22 MR. POLINSKI: It’s not just the impact on 

23 the steel manufacturers, it’s the impact on the 

24 marketplace of, you know, when you have -- when you 

25 don’t have adequate supply -- if we produce a 
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1 standard that you don’t have an adequate supply to 

2 meet the standard, I mean, there’s nothing worse --

3 there’s nothing worse than that. What about Rick?\

4 MR. DeLASKI: Yeah, it’s a level we were 

5 looking at, but not was the constraint on decision6 making. And I also think it’s important that --

7 Phil, thank you for putting this work in, and I 

8 think you’re doing this on behalf of Allegheny and 

9 AK --

10 MR. HOPKINSON: They are two of my 

11 supporters, and I actually have three transformer 

12 manufacturers who also supported this work so far. 

13 Federal Pacific is one, Cooper is one, and Kentucky 

14 Association of Electric Coops is one. So --

15 Kentucky, for those of you who don’t know it, is a 

16 small liquid-filled manufacturer and of course they 

17 would like to stay a liquid-filled manufacturer in 

18 the future. So they were very interested in making 

19 sure that what I had for information was something 

20 that would keep them in business.

21 MR. DeLASKI: And I guess I also would 

22 suggest that for the purposes of our discussion, I 

23 mean ultimately the government’s going to make 

24 decisions based on the government’s analysis.

25 MR. HOPKINSON: Yes.
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1 MR. DeLASKI: And for purposes of this 

2 negotiation I think we need to focus on the 

3 Navigant/LBL analysis because that’s the basis for 

4 the decision-making that ultimately will be made by 

5 the government.

6 MR. HOPKINSON: Just before I wrap it up -

7 - down to the dry type because that one looks like 

8 it does need work, and I know the Federal Pacific 

9 guys are particularly interested. Now, for the 

10 manufacturers to go to efficiency level one, their 

11 cost increase wasn’t as it was on the liquid filled 

12 transformers. But they were really starting with a 

13 TP1 kind of a number before, so it would make sense 

14 that there could be some room in that particular 

15 product, if there’s economic justification and on 

16 the dollars per watt that is used against it.

17 On the scatter plot, the manufacturers 

18 were way up here to the top with again, M3 and 

19 aluminum, and OPS-1 and OPS-2 were virtually 

20 unchanged. There wasn’t much change. And the 

21 reason there wasn’t is that we didn’t have 

22 sufficient data when we went back and talked to the 

23 people at OPS to give them something that they could 

24 get their teeth in and that they could fix. Now 

25 that data has been accumulated and I think Federal 
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1 Pacific, and I think Wes, you’re not going to stay 

2 quiet, will be back talking to them to get them to 

3 modify the program.

4 MR. PARKER: What are the specific 

5 modifications to the program that you want again?

6 MR. HOPKINSON: Well, I think to begin 

7 with, and I will steal Bob’s thunder, unless he

8 would like to make it, but I would say that one of 

9 the things is that the design that is picked to use 

10 was a secondary unit substation, which has buses and 

11 leads and lots of loss associated with it, and the 

12 design that OPS-1 and 2 have used is the -- just a 

13 plain vanilla with stub-outs on the leads, so it 

14 doesn’t have all those losses. Now when those 

15 losses get --

16 PARTICIPANT: (comment off mic)

17 MR. HOPKINSON: And it’s not 

18 representative of the market, that’s the other 

19 point. So that’s the biggest difference, and I 

20 don’t know, Bob, you want to talk any more.

21 MR. SMITH: Design lines 9 through 13. 

22 Bob Smith of Federal Pacific. Phil is correct. We 

23 -- we’re very concerned about selecting the right 

24 design for medium voltage dries, and we felt that 

25 should be a unit substation design, which included 
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1 the secondary bus all the way out to switch gear, 

2 and the high voltage bus to the high voltage switch, 

3 and not just the core and coil by itself as you 

4 would have with a high voltage general purpose 

5 transformer. And I think there was some issues as 

6 to how OPS was calculating the stray losses.

7 MR. HOPKINSON: I think there is too.

8 MR. SMITH: Long story short, is that when 

9 they did not include the losses, the strays and the 

10 buses, that caused us to have to go to a large core 

11 and coil to get to the selected efficiency level 

12 than we would otherwise have to do if those losses 

13 were included.

14 MR. PARKER: So as I take it, then, this 

15 is a question about whether the right representative 

16 unit was chosen for --

17 MR. SMITH: That is correct.

18 MR. PARKER: -- the design line. Right. 

19 Which brings us full circle back to where we started 

20 this morning.

21 MR. SMITH: Well, there is good news.

22 MR. PARKER: With item number one, yes.

23 MR. SMITH: There is good news. Rob and 

24 Naheed (ph) have hit upon design line 11. That’s a 

25 CSL-2 design that they were working on, and they are 
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1 in agreement with that and are confident that they 

2 can move forward with the other design lines and the 

3 other efficiency levels. So that is happening at 

4 the moment.

5 MR. PARKER: Good. Excellent.

6 MR. HOPKINSON: That pretty well 

7 summarizes what I had. I think that anything beyond 

8 this was just going to be to suggest that the 

9 negotiating team look closely at what the 

10 manufacturers’ cost is, but it’s based on that 

11 assumption of M3 and aluminum, and if you change 

12 that assumption, of course it would be different 

13 cost.

14 MR. PARKER: And that is of course, a 

15 policy decision about whether there should be a 

16 constraint for a particular kind of metal built into 

17 the modeling, and I think should be treated as a 

18 policy decision.

19 So as I understand it, basically what 

20 Phil’s very helpful analysis does is sort of provide 

21 a window into the way that choice of parameters can 

22 affect the analysis. What he’s done is a kind of a 

23 back of the envelope version of what I think LBL 

24 tried to do systematically by incorporating 

25 distributions for these various parameters into 
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1 their analysis. He did identify some other areas 

2 where there can be some changes made, some 

3 representative unit -- in terms of defining new 

4 representative units. I think we have a process for 

5 dealing with that. And so I think we should -- we 

6 are in pretty good shape then in terms of converging 

7 our analyses for drawing on Phil’s insights and Bob 

8 Smith’s work to come up with a single analysis that 

9 will accommodate these tweaks, basically, in the 

10 area of representative units so that we get one set 

11 of numbers to work off by the next meeting. Steve, 

12 did you want to chime in?

13 MR. NADEL: Yes, I wanted to pick up very 

14 briefly on this little conversation that Ray and 

15 Andrew had, in terms of tomorrow. We think it would 

16 be useful to set aside a little time at the end of 

17 the day to put on the table some concepts about how 

18 we might get to yes, as opposed to a talkathon. We 

19 have some thoughts that we want to present, and I 

20 say that not to say, oh, gee, it has to be blank or 

21 blank, but some ideas for people to think about. 

22 Because if we’re going to make progress, we have to 

23 make a lot of progress next meeting. 

24 MR. PARKER: Right.

25 MR. NADEL: We want to float some ideas at 
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1 the end of today so people could think about it as 

2 oppose to surprise people, and I wanted to mention 

3 today, because other people may want to also flow 

4 concepts for us all to be thinking about in the 

period between now and November 10th

7 MR. PARKER: Yes, good. That’s very 

8 helpful. Thank you. We’ll definitely do that.

5 or whatever the 

6 date was.

9 PARTICIPANT: We would agree with that 

10 that there should be some time set aside for 

11 committee members to float concepts or ideas, 

12 because I believe that we might have some ideas in 

13 that regard as well.

14 MR. PARKER: Great. Most welcome. Thank 

15 you. Aaron.

16 MR. MEYERS: I may be alone in this, but 

17 I’ve made travel plans based on the end of the 

18 meeting being at noon, so if there’s a full agenda 

19 and this is going to be added, is there a 

20 possibility to start early?

21 MR. PARKER: How do people feel? I think 

22 we could probably start -- eight?

23 MR. MEYERS: Start at eight?

24 MR. ROSENSTOCK: Steve Rosenstock, EEI. 

25 Knowing the local traffic, I think 8:30 might be the 
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1 earliest, just to be fair to people commuting within 

2 the area. 8:30 might be the earliest that everybody 

3 could get here. And also I would ask for an e-mail 

4 to be sent out, some people I believe left early, to 

5 be sure that all the committee members know that 

6 we’re going to try to start early.

7 MR. CYMBALSKY: Yeah, the room’s available 

8 starting at seven.

9 MR. NADEL: Does that accommodate the new 

10 item on the agenda?

11 MR. PARKER: 8:30, the extra half hour?

12 MR. MEYERS: Yes, I would say we add the 

13 extra half hour. We’re going to have to be much 

14 more rigid about, oops, you’ve got five more 

15 minutes, we’re wrapping up this discussion. The 

16 early topics get all the attention and then we never 

17 get to the later ones.

18 MR. PARKER: Well, Aaron, the key is we 

19 don’t have any more presentations. Not that I’m 

20 aware of.

21 PARTICIPANT: For the record, Phil’s 

22 presentation was the most efficient.

23 MR. PARKER: Thank you everybody. We’ll 

24 see you tomorrow at 8:30.

25 (Whereupon, at 6:25 p.m., the meeting in 
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1 the above captioned matter was adjourned, to be 

2 reconvened tomorrow morning, Thursday, October 13, 

3 2011 at 8:30 a.m.)

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REPORTER'S CERTIFICATE

This is to certify that the attached proceedings 

before:

U.S. DEPARTMENT OF ENERGY

VOLUME I

In the Matter of:

MEETING OF THE MV WORKING GROUP

Were held as herein appears and that this is the 

original transcript thereof for the file of the 

Department, Commission, Board, Administrative Law 

Judge or the Agency.

Further, I am neither counsel for or related to 

any party to the above proceedings.

 Official Reporter

Wendy Greene 

Dated: October 18, 2011