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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

Wed n es day October 12 , 201 1

**Facilitator :** 

Richard Parker University of Connecticut Law School

**Host :** 

National Rural Electric Cooperative Association ( NRECA)Executive Court Reporters (301) 565

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**Participants Identified:**

Rick Anderson Fayetteville Public Works Commission

Tim Ballo Earth Justice 1625 Massachusett s 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 Ma nufacturers Association 1300 North 17 th 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 D r Oakland, CA 94619Executive Court Reporters (301) 565

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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 2827 0

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

- ATIExecutive Court Reporters (301) 565

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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, Sui te 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 S teel 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 DOEExecutive Court Reporters (301) 565

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**Participants from Navigant**  **/LBL :** 

Brian Coffey Navi gant

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 Sui te 500 Washing t on, DC 20006

Chris Bolduc Lawrence Berkley National Laboratory 1 Cyclotron Rd Ms 90

- 4000 Berkeley, CA 94720 Washing t on, DC 20006Executive Court Reporters (301) 565

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**AGENDA**

**ITEM PAGE** 

Welcome, Mr. Parker 7

Self

- Introductions 8

Agend a Review 13

Finalization of Rules of Procedure 92

Navigant Presentation, Mr. Coffey 21

Data Requests 22

Request to Changes to Analy s is 42

Scaling App roache s 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

E valuation Rates 229

Final Topics 246

Presentation, Mr. Hopkinson 261Executive Court Reporters (301) 565

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9:13 a.m. 1

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

MR. PARKER: Welcome everyone to our 4

second meeting of the Medium Voltage Transformer 5

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

t echnical difficulties caused by my pushing the 7

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

everybody back on the line now. 9

First I want to thank Bob Saint and the 10

National Rural Electric Cooperative Association for 11

hosting us here today in this be autiful conference 12

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

conference room, but having the coffee and the 14

refreshments beforehand, a nice set

- up, so I thank 15

you for that. 16

I also want to thank the DOE team over 17

there, who worked hard to put t his thing together 18

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

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

during this set

- up process to give us the technical 21

capacity we need to get this on the record. 22

Also thanks to Navigant and to LBL staf f 23

who have been deluged with information from you all, 24

and comments, and analysis, and so forth, and who 25Executive Court Reporters (301) 565

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have been working around the clock to try to take 1

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

more about their analysis as we go on today. 3

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

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

everybody introduce themselves for the record for 6

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

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

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

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

put on the screen. 11

**Self**

**- introductions**  12

MR. PARKER: Richard Parker, University of 13

Connecticut Law School. 14

MR. COFFEY: Brian Coffey, Navigant. 15

MR. SMITH: Bob S mith, Federal Pacific. 16

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

Hopkinson with everyone’s permission. 18

MR. HYLAND: Mike Hyland, American Public 19

Power Association. 20

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

National Rural Electric Cooperative A ssociation. 22

MR. ROSENSTOCK: Steve Rosenstock, Edison 23

Electric Institute. 24

MR. HIRSCH: Bruce Hirsch, Baltimore Gas 25Executive Court Reporters (301) 565

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and Electric. 1

MR. ANDERSON: Rick Anderson, Fayetteville 2

Public Works Commission. 3

MR. SIMMONS: Progress Energy. 4

MR. FERNSTROM: I’ m Gary Fernstrom from 5

the Pacific Gas and Electric Company, representing 6

the California investor

- owned utilities, PG&E, the 7

Southern California Edison Company, and Semper 8

Utilities. 9

MR. BECK: Scott Beck, Lakeview Metals. 10

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

MR. HO DG E: Gerry Ho dg e from Howard 12

Industry. 13

MR. POLINSKI: Ray Polinski from Allegheny 14

Ludlum

- ATI. Also with me is Jim Mur kowski from 15

Allegheny ATI, behind me, who will introduce 16

himself, and also similarly, Phil H opk inson is 17

supporting us with some data and analysis as well. 18

Thank you. 19

MR. BALLO: Tim Ballo with Earth Justice. 20

MR. CASKEY: John Caskey with Electrical 21

Manufacturers Association. 22

MR. ECKMAN: Tom Eckman, Northwest Power 23

and Conservation Council. 24

MR. MEYERS: Aaron Meyers, Cooper Power 25Executive Court Reporters (301) 565

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Systems and similar to Bob and Ray, we have also 1

Phil Hopkinson here representing us. 2

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

Steel. Joining me shortly will be Jerry S c hoen, 4

also of AK Steel. His flight was delayed this 5

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

others, is Phil Hopkinson. 7

MR. PARKER: Excuse me just a second, 8

Carlos. I understand the court reporter is having a 9

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

be sure you turn on your mic before you sp eak, and 11

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

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

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

with that so that we can

-- and I guess for the 15

people around the room, if you’ll just ann ounce

-- 16

do we have a mic by the way for

-- yes, so Jeremiah 17

will carry the mic around so people can announce 18

themselves around the wall as we go forward. So 19

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

Thanks. Go ahead, Carlos, sorry. 21

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

MR. MILLURE: David Millure, Metglas, 23

Incorporated, joined by Paul Ryan from Hitachi 24

Metals America and Robert Berman of Berman 25Executive Court Reporters (301) 565

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Economics. 1

MR. ROY: Robin Roy, National Resources 2

Defense Council. 3

MR. CYMBALSKY: Jo hn Cymbalsky, DOE. 4

MR. PARKER: Here around the table. 5

MR. RIVEST: Mike Rivest, Navigant 6

Consulting. 7

MR. HOPKINSON: Phil Hopkinson, H Volt
, 8

Inc. 9

MR. COULTER: Greg Coulter, I’m a 10

consultant supporting Prolec GE. 11

MR. CREEVY: Jim Creevy, National 12

Electrical Manufacturers Association. 13

MR. MURKOWSKI: Jim Murkowski, Allegheny 14

Ludlum ATI. 15

MR. WINDER: Ken Winder, NRECA. 16

MR. FOSTER: Chuck Foster, representing 17

Edison Electric Institute. 18

MR. BERMAN: Robert Berman, Berman 19

Economics. 20

MR. RYAN: Paul Ryan, Hitachi Metals 21

America, Metglas. 22

MR. CARMICHAEL: Rob Carmichael, Navigant 23

Consulting. 24

MR. NAR D OTTI: Matt Nar d otti, Navigant 25Executive Court Reporters (301) 565

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Consulting. 1

MS. COUGHLIN: Katie Coughlin, Lawrence 2

Berkley National Laboratory. 3

MR. BOLDUC : Chris Bolduc , L awrence 4

Berkley National Laboratory. 5

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

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

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

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

talk at this time? Okay

. 10

My apologies. Apparently, the way it’s 11

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

e

- mailing in to the webinar interface to Tatiana who 13

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

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

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

with phones ringing in the background and so forth, 17

that proved to be quite disruptive for the meeting. 18

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

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

peop le know who was there. 21

But I just want to express my welcome to 22

people on the phone and encourage you to send your 23

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

and we’ll make sure that they get aired. 25Executive Court Reporters (301) 565

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So, thanks very much. Why don’t we get 1

star ted. I have passing around

-- I’m just passing 2

around a sort of a draft agenda. 3

**Agenda Review** 4

I apologize for the delay in getting this 5

to you, which basically

-- basically, what I’ve 6

tried to do with this agenda

-- we’ll try to get it 7

on the screen h ere for the people joining in by 8

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

together what I think, working backwards from our 10

deadlines, would be an ideal outcome for this 11

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

think we should try. And i t reflects the fact that 13

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

concerns have been surfaced since the last meeting. 15

I’ve been really impressed by the outpouring of 16

interest and participation on line through the e

17

mail interface, really engagin g the issues in a 18

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

had conversations with Navigant and LBL staff about 20

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

try to work through those issues in this meeting. 22

We do need to find a balance betw een, you 23

know, doing more and more analysis and getting down 24

to the business of actually negotiating the terms of 25Executive Court Reporters (301) 565

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a proposed rule. And so these goals for the meeting 1

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

a desirable outcome. I think we do n eed to try to 3

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

beyond methodological issues and the analysis as 5

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

business of talking about standards and what people 7

can do. 8

At the same time, analysis is very 9

important and we have a group of people around here 10

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

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

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

committed and the consultants are committed to 14

giving you the best possible empirical foundation 15

for your work. 16

So what I would propose, subject to your 17

comments and thoughts, for this meeting, and our 18

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

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

hear presentations from Navigant and LBL about their 21

respective analysis of the engineering data and the 22

LCC issues and manufacturing impacts, have a full 23

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

end of tomorrow, by noon tomorrow, with a specific 25Executive Court Reporters (301) 565

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c harge to Navigant and LBL about what are the top 1

priority issues that require further analysis or 2

tweaks to the analysis and modifications of the 3

analysis. What are the issues that really matter? 4

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

always

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

time and infinite resources, you can always have 7

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

balance between resources and time on the one hand, 9

and real data needs on the other. 10

So the goal of this group a nd the goal of 11

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

priorities, clear priorities, and

-- for what needs 13

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

we need for fruitful negotiations going forward. 15

And I’ll just encourage Navigant and LBL 16

to be frank and pushing back with regard to either 17

timelines, or with regard to possibilities, you 18

know, what can be done within the existing 19

constraints and existing timelines. And what is the 20

best way of dealing with any uncertainties that are 21

there

. 22

The other thing that has come up that many 23

people have surfaced, both at the last meeting and 24

in the e

- mails that followed, was a concern about 25Executive Court Reporters (301) 565

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the impact

-- about manufacturing impacts. What is 1

going to be the impact of various efficiency levels 2

on s teel supplies, on competitiveness in the steel 3

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

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

he’s kindly agreed to give us

-- to walk us through 6

their presentation of those issues. So I thought it 7

wo uld be good to schedule that at some point. 8

And then, and really focus on that and try 9

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

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

discussion between the way AK Steel is coming at it 12

and see if t here are discrepancies between AK 13

Steel’s analysis and Navigant

- LBL analysis that 14

needs to be discussed. 15

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

the

-- is totally achievable. I understand from our 17

consultants that there may be some difficulties 18

achievi ng, you know, finalizing the analysis by 19

November 2 nd , particularly for the medium voltage and 20

dry type, and low voltage transformers. Mike Rivest 21

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

coming in from manufacturers. There has not been a 23

robust discussion or supply of data, apparently, for 24

those particular product lines. The liquid immersed 25Executive Court Reporters (301) 565

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is much further along, I understand, than medium 1

voltage dry and low voltage. 2

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

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

what

-- put that in perspective and give us his 5

thoughts on what is a reasonable timeline for 6

getting revised engineering results to LBL for that. 7

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

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

conversation, and you talk about those concerns as 10

they come up. 11

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

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

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

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

little

-- I can’t

-- my line of vision is a little 16

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

this side of the table, but either John or

-- if 18

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

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

in advance if I miss. Yes. 21

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

mic

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

for the court reporter. 24

MR. HOPKINSON: Thank you very much, 25Executive Court Reporters (301) 565

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Richard, and it’s wonderful to meet you here today, 1

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

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

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

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

in? 6

MR. PARKER: I think within reason it 7

would be good to have

-- 8

MR. HOPKINSON: Oh, Phil Hopkinson. 9

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

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

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

make sure that the discussion doesn’t get bogged 13

down. That would b e my job which I would try to 14

execute. Mike. 15

MR. RIVEST: This is Mike Rivest, 16

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

is much more workshop

- like where, you know, problem 18

solving, so this is not presentation and comment in 19

writing, this is m uch more, here are the issues, can 20

we work together to come up with solutions. 21

MR. PARKER: Any other comments around the 22

table? Steve Rosenstock. 23

MR. ROSENSTOCK: Hi, Steve Rosenstock, 24

EEI. You have an item that says Stakeholder 25Executive Court Reporters (301) 565

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Presentations. Are there some PowerPoint slides or 1

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

there were a lot of reports flying around the last 3

couple days via e

- mail, but I didn’t know if there 4

was separate presentations that were going to be for 5

the engineering a nalysis? 6

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

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

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

engineering analysis, and he has a little agenda 10

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

post on the

-- Ron you have that on your screen for 12

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

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

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

presentations that will

-- and basically, the idea 16

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

not a one

- way street. Yes, Bob. 18

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

from Federal Pacific. The thing that Rob Greeson 20

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

particular, as well as LBS is trying to reconcile 22

the differences that we are seeing with the medium 23

voltage design lines nine through 13. And with due 24

respect, to try to meet the deadline, we are very 25Executive Court Reporters (301) 565

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desirous of trying to get reconciliation with their 1

method of calculating the designs and the way that 2

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

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

and furiously as possible. 5

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

understand that Brian and others will be presenting 7

an approach to deal ing with that as we go forward. 8

And I just want to express my cordial welcome to 9

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

today and that we worked out the issues that allowed 11

him to participate in our discussions, and 12

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

definitely on the agenda for today. 14

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

committee would like, this afternoon, after the 16

presentations, we would be willing to walk through 17

the LCC analysis for clarity

-- sorry, spreadsheet

- 18

- to add cl arity and answer questions as we go. 19

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

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

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

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

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

Anything else? Seem like a reasonable way to 25Executive Court Reporters (301) 565

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proceed? Any disagreement? Okay. 1

Let’s just get started with the 2

presentation, then. We have here

-- I’m just 3

passing around a sheet that contains the

-- this is 4

just basicall y a list of

-- what I’m passing around 5

is basically a list of the issues that Navigant 6

staff identified from the very extensive

-- both 7

from the comments that came in on the previous 8

meeting, and the very extensive e

- mail traffic that 9

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

very helpful, is try to distill all of that 11

discussion into categories, group it together into 12

the logical categories, pick out the common 13

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

us through the Navigant response to the various 15

concerns that have been raised, and I understand 16

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

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

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

to Brian Coffey of Navigant. Thank you. 20

**Navigant Presentation** 21

MR. COFFEY: Thank you, Richard, and 22

welcome everybody to the second negotiating session 23

of the medium voltage group. Just to refresh 24

everybody’s memory, in the first session both 25Executive Court Reporters (301) 565

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Navigant and LBL gave overviews of their analyses as 1

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

feedback from the negotiating parties. In that 3

period came a lot of different types of suggestions 4

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

-- 5

we spent the interim trying to slice and dice and 6

group all that and sniff out what were the most 7

important things to be spending our time looking at, 8

and then think of ways to answer those questions, 9

provide those data, and solve those problems. 10

In this presentation, I’m going to walk 11

through, as Richa rd said, some of those proposed 12

responses, and hopefully get feedback from the 13

committee about whether that makes sense. 14

Here are kind of the four headings that 15

I’m going to go through: 16

1. Data requests that were made 17

2. Analytical changes that people would like to 18

see implemented or floated 19

3. Some kind of pointed questions that were asked 20

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

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

the room. 23

**Data Requests** 24

So, starting from the top, here are sort 25Executive Court Reporters (301) 565

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of five thing s that a number of individuals re 1

requested. The first two are how does both the 2

total weight of a transformer and the core weight 3

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

data. The third item is

-- I think it was Jerry 5

Cochran of Cooper who fi rst floated the idea, and 6

that’s to have a bi

- directional exchange of 7

engineering data, both to allow everybody in the 8

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

taking as inputs and also to receive some feedback 10

and information on how manufacturer s design their 11

transformers to meet the same requirements. 12

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

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

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

because as everybody knows, if you have two 16

manufacture rs build a transformer to meet the same 17

goal, at different times and different years, 18

materials, prices change, people have different 19

design approaches, and so you can end up with 20

transformers that have very different 21

characteristics, even though they’re s erving the 22

same application. 23

So if you’re looking to validate a 24

modeling effort, it’s really important to make as 25Executive Court Reporters (301) 565

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tightly controlled a comparison as you possibly can, 1

and that really involves keeping materials, prices 2

within a certain range, you know, th e construction 3

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

things like that can really affect the output. 5

So we did e

- mail that template out to the 6

committee and sought feedback. I think we got two 7

responses which were, in general, positive and so 8

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

-- this is sort of near

-- this is the most upstream 10

of the upstream portion of this whole analysis , and 11

so that’s really important, schedule

- wise, to have 12

feedback on as quickly as you can provide it. 13

Here we are on the fourth item, a number 14

of parties have expressed a desire to look at the 15

impacts of different steel prices. Now these have 16

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

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

for steel prices can make a big impact in the 19

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

determined, say, the point

-- the efficiency point 21

where different steel types can compete was a big 22

one that the committee expressed a desire to look at 23

at the last me eting. 24

And then the final one was simplified cost 25Executive Court Reporters (301) 565

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efficiency plots so people could look at, really for 1

each steel type, what sort of on the bottom 2

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

is likely to be done. 4

So we’ve provided one of those already, 5

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

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

negotiators. 8

MR. PARKER: Can you just state for the 9

record what will be provided, which one? 10

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

third item, the template that could be used to 12

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

plan to use going forward. 14

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

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

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

fir st. Brian, what data do you need and when do you 18

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

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

big issue

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

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

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

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

hierarchy of the analysis priorities. We consider 25Executive Court Reporters (301) 565

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this engineering validation to be absolutely top 1

priority, and so this is something that

-- this is a 2

problem we would like to s olve before anything else, 3

make sure that everybody’s comfortable with the 4

numbers and in particular the cost increments as you 5

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

would like feedback on that as soon as possible. 7

Bob Smith and Rob Greeson of Federal Pacific have 8

already been working with us in the medium voltage 9

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

we hope that some others will follow suit. 11

MR. PARKER: And the transformers that 12

this is relevant to are the medium voltage d ry type 13

and low voltage, principally, right? 14

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

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

in receiving feedback on the medium voltage dry 17

type. 18

MR. PARKER: Bob. 19

MR. SMITH: Bob Smith, Federal Pacific. 20

Brian, are we still under the assumption that when 21

we are plotting cost versus efficiency that those 22

costs are really end user prices? 23

MR. COFFEY: So the prices on the charts 24

are manufacturer’s selling prices, so that’s what a 25Executive Court Reporters (301) 565

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manufacturer

-- and we re cognize that in some cases 1

that can vary depending on the distribution channel, 2

but that’s intended to be what the manufacturer 3

receives for letting go of a transformer. 4

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

point, but in the medium voltage dry type 6

tr ansformer, we basically have three marketing 7

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

switch gear OEMs who go through distributors and the 9

contractors, and one through distributors to 10

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

have weighi ng factors on those three channels, and 12

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

when the appropriate time comes, I would like to 14

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

factors should be and what the markup should be for 16

each one of tho se steps in the channel. 17

MR. COFFEY: I think that’s useful 18

discussion. I think when you ask two people to 19

design transformers to a certain set of 20

specifications and efficiency, and they come back 21

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

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

it could be different assumptions about materials 24

prices, it could be a different cost structure or 25Executive Court Reporters (301) 565

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distribution channel, or it could be a difference in 1

the design, and I think that the most important

-- 2

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

are there any design differences. Are the weights 4

of the transformers comparable? Are the core sizes 5

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

the first priority. 7

MR. PARKER: Mike. 8

MR. RIVEST: S o we laid out

-- we have a 9

presentation that sort of lays out the sequencing of 10

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

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

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

manufacturing sales price to e fficiency, and so 14

really that becomes of ratio of revenue to materials 15

-- revenue to costs, and I could

-- I would know 16

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

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

anybody. 19

MR. SMITH: That would ce rtainly simplify 20

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

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

that still the way you’re approaching this? 23

MR. RIVEST: No, absolutely not. The 24

apples to apples comparison here is the 25Executive Court Reporters (301) 565

- 0064 29

manufacturer’s sa les price. The end user

-- so if 1

you’re looking at the engineering analysis 2

spreadsheet, which is transferred to the LCC. I 3

think that’s what it’s called in the

-- on line. 4

That

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

a factor. 6

MR. PARKER: Sor ry, we can only speak into 7

the mic. Jeremiah, can you

-- 8

MS. COUGHLIN: So the total

-- this is 9

Katie Coughlin, Lawrence Berkeley Lab. The LCC uses 10

the total installed

-- the term is the total 11

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

includes the markups along the distribution channel, 13

and the manufacturer selling price is what we get 14

from the engineering. And those are actually both 15

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

straightforward to see the difference between those 17

two numbers for all the designs. 18

MR. PARKER: Yes. Aaron. 19

MR. MEYERS: Aaron Meyers, Cooper Power 20

Systems. I have a great appreciation for the work 21

that Navigant and the DOE has done in preparing this 22

analysis. I realize that it was quite extensive. 23

My contenti on in the data analysis would be that 24

there are several steps along the way and if small 25Executive Court Reporters (301) 565

- 0064 30

mistakes are made in each step, they wind up 1

compounding. And so when you reach the point where 2

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

connect the results of the analysis with reality by 4

requesting quotations from real manufacturers, and I 5

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

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

little bit of a disconnect there. So I would 8

request that the DOE go out and seek quotations from 9

manufacturers to validate the data. And the main 10

thing that we’re concerned with is efficiency versus 11

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

efficiency could be requested as part of the 13

quotation. Thank you. 14

MR. R IVEST: So to

-- Mike Rivest, 15

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

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

proxy to that. So what we would do is

-- that data 18

request sheet includes your unit

-- the number of 19

pounds of steel, for examp le, for core steel, the 20

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

probably 90 percent of the material costs. That 22

gets us pretty close with

-- if we had a factor, 23

like two, something like that, whatever that ratio 24

is that you guys might be more fam iliar with than I. 25Executive Court Reporters (301) 565

- 0064 31

It gets us pretty close. If we get quotations, then 1

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

versus what we’re using

-- I mean, we’re trying to 3

common size

-- that’s our difficulty

-- and the 4

quotes would be

-- I see bid resul ts

-- I mean you 5

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

transformers, and you will see utilities posted bid 7

results, and there’s significant variation between 8

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

just means that the bidding’s differe nt. 10

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

Mike that the pricing of commodities is quite 12

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

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

forward and make a decision on the payback and so 15

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

take that range into consideration. There was some 17

information that was shared here this week that 18

discussed amorphous core transformers and also 19

grain

- oriented and silicon steel transformers, and 20

there was a period of time where a particular 21

utility purchased amorphous core transformers 22

because it made the most economic sense. That 23

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

time, it’s flip

- flopped and there’s nothing to say 25Executive Court Reporters (301) 565

- 0064 32

that it won’t flip

- flop back and for th several times 1

in the future. 2

My request would be that we don’t nail 3

down customers so that they have to purchase a 4

particular style of transformer when the economics 5

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

MR. RIVEST: Mike Rivest. Bria n began to 7

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

together called the price sensitivity tool. So what 9

that does is it would allow you to input different 10

steel prices. Now, our engineering analysis is like 11

hundreds of spreadsheets that are linke d, so we 12

can’t

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

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

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

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

steels and then we will run for you all tho se 17

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

replot all of those graphs with the clouds, such 19

that you can see how different assumptions about the 20

price of M3 relative to amorphous might change the 21

dynamics. 22

So that tool, Brian, I think it’s al ready 23

ready, but with a limited number of price scenarios 24

for each of the steels. So I think we recreated 25Executive Court Reporters (301) 565

- 0064 33

scenarios, the high/low and reference case for all 1

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

three different prices for each of the steels. A nd 3

you could then look at how the clouds move. 4

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

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

demonstrate for everyone how that might work and 7

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

home and if ther e are any steel price sensitivity 9

cases that people feel aren’t represented there, 10

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

redistribute. 12

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

choosing the various steel prices for these 14

scenarios, is to create a ra nge, right, that’s 15

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

kind of a reasonable

-- 17

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

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

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

pound to $2.6 0 a pound, you might want to take the 21

extreme cases and run a scenario and see what that 22

does to that breakeven point people have been 23

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

and that would give you a different picture. Then, 25Executive Court Reporters (301) 565

- 0064 34

today’s snapshot, which is $1.80 and whatever the 1

numbers are. And that might address, partially, 2

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

of assumptions about pricing. 4

MR. MEYERS: For the record, Cooper Power 5

is not anti

- amorphous. In fact, we built amorp hous 6

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

to expand our amorphous manufacturing. But keep in 8

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

build grain

- oriented silicone steel transformers, 10

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

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

build amorphous core transformers is quite different 13

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

situation that was projected by the DOE in their 15

demand forecast for various steels, where amorphous 16

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

significant capital investment required across the 18

board for manufacturers. 19

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

with certainty that that investment would be 21

supported, and it would be a trave sty to essentially 22

eliminate a manufacturer and those jobs from the 23

U.S. economy. 24

MR. PARKER: Thank you, you’ve been 25Executive Court Reporters (301) 565

- 0064 35

waiting patiently. Greg. 1

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

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

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

-- happy

-- we find your data for liquid filled 5

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

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

you’re concentrating really on medium voltage dry, 8

not liquid

- fille d. I think we’re ready to say let’s 9

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

one. 11

Number two, I want to wander into the 12

amorphous thing. We’re a little concerned about 13

only using the price extremes for sensitivity 14

analysis you’re talking abou t. We’re concerned when 15

you see a scenario that switches everything from 16

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

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

decision. My guess is, for the manufacture of 19

amorphous, they’re big investment decisions. I 20

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

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

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

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

would do that, so I think you’ve got to look maybe 25Executive Court Reporters (301) 565

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outside the bands that you might have looked at in 1

the past when you’re looking at a sensitivity 2

analysis. We support doing the sensitivity 3

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

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

you talk abo ut doing a price sensitivity analysis, 6

what we submitted was a price parity analysis. If 7

the objective of the subcommittee is to achieve a 8

competitive market, that’s established only when you 9

have a choice of products which have basically price 10

parity at a given point. Rather than arbitrarily 11

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

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

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

market will likely look like. 15

MR. RIVEST: Jerry, I know we have

-- so 16

we have time slotted tomorrow to talk about steels, 17

and I certainly want to hear more about what that 18

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

-- 19

this is what price does one steel have to be 20

relative to the other to

-- is that sort of what it 21

is? 22

MR. SCHOEN: Yes. 23

MR. RIVEST: Okay. 24

MR. MILLURE: Dave Millure. Metglas. To 25Executive Court Reporters (301) 565

- 0064 37

Greg’s comment about the linkage between capacity 1

expansion and pricing, like any manufacturer, we 2

price to market conditions . We did an expansion in 3

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

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

expansion. So expansion does not imply a price 6

increase. 7

MR. HOPKINSON: Phil Hopkinson, H Volt
, 8

Inc. I think that there’s several fundamental 9

issues that have com e out of the discussion so far. 10

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

to really figure out whether anything is correct or 12

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

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

spreadsheet and put down al l of the OPS data against 15

the average of the manufacturers’ data. And in 16

doing that, I could see differences that we then 17

brought back to our friends at OPS and they actually 18

made some corrections and reissued the data in what 19

I’ll call OPS

- 2. 20

So with t hat regard, I think the only way 21

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

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

be able to find out where the problems were. 24

So if you go the other alternative, which 25Executive Court Reporters (301) 565

- 0064 38

is selling price versus effic iency from a number of 1

manufacturers, you can tell in total, and I 2

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

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

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

to do it is to dive into detail. 6

I th ink the second thing is there are a 7

lot of different steels, and the issue of what 8

should be a minimum national standard on what kind 9

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

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

points of an M3 versus amor phous versus an M6, or 12

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

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

finally move on and get what is the final 15

transformer price to the end user, which really is 16

the only number that counts as far as wh at happens 17

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

to the guy who owns the transformer. 19

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

lot of the discussion about steel prices and the 21

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

stuff that we can reserve for the discussion that

-- 23

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

today. So why don’t we hold off on that further 25Executive Court Reporters (301) 565

- 0064 39

discussion of the steel price impacts until we have 1

that, because that raises a lot of methodological 2

issues, analyti cal issues, not just data issues. 3

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

is really focus on what data you need to simply 5

predict accurately the manufacturing selling price, 6

apart from materials price, which are obviously key, 7

but any other issues tha t people want to raise that 8

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

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

need to come up with a timeframe for you supplying 11

the data. 12

I understand that Navigant sent out their 13

questionnaire, their template a couple weeks ago. 14

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

we’re going to have to bring down

-- we’re going to 16

have to close the period for providing further data 17

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

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

for this. 20

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

categories of data that people feel need to be 22

supplied, discrepancies. Let’s have that discussion 23

now and set up a timeframe for resolving it. 24

Anything else, besides mat erials prices in terms of 25Executive Court Reporters (301) 565

- 0064 40

data discrepancies leading to manufacturer’s selling 1

price? 2

MR. SIMMONS: Yes, this Chuck Simmons, 3

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

sensitivity analysis with regards to the average 5

transformer load. I think the initial analysis was 6

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

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

of discussion that from, at least the utilities’ 9

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

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

the ... 12

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

going to be talking about that as part of their 14

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

MR. SIMMONS: Okay. Thank you. 16

MR. SMITH: Bob Smith, Federal Pacific. 17

Richard, one t hing, for the medium voltage dries, we 18

would like to be certain that OPS and Navigant 19

understand the product that is being costed, and 20

there are, for medium voltage dries, there are 21

basically two categories, a high voltage general 22

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

unit substation transformer. It has been our 24

understanding that it is the unit substation 25Executive Court Reporters (301) 565

- 0064 41

transformer which includes the low voltage bus to 1

the switch gear, and the high voltage bus that 2

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

like to make sure that that is what is actually 4

being done. 5

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

actually have a category for that under the rubric 7

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

when

-- in Brian’s presentation in a few mi nutes. 9

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

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

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

Anything else on this. Wes, you’ve been

-- 13

MR. PATTERSON: this is Wes Patterson. 14

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

running the sensitivity analysis of changing just 16

the steel prices. The assumption there is that the 17

existing calculation design, of which there is 18

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

design doesn’t change w hen you changes the core 20

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

fallacy. Because in reality, the amount of 22

conductor will change relative to the amount of core 23

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

sure how much value we will get from that kind of an 25Executive Court Reporters (301) 565

- 0064 42

exercise. 1

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

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

by examining 2010 total shipments and overlaying the 4

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

easily see how either ac curate or inaccurate the DOE 6

data is relative to establishing the relationship of 7

price increase versus loss reduction. And I believe 8

that phenomena, price increase versus loss reduction 9

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

prices of units, not prices between product groups, 11

but the relationship of the change in price with the 12

change in loss reduction. 13

MR. PARKER: Brian, are we going to

-- did 14

you want to respond? 15

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

helpful commentary, and I think some of these 17

questions may be answered as I go through the 18

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

just keep pressing onward. 20

**Request to Changes to Analysis** 21

Here are a number of things that people 22

said that they would like to see or like to hav e 23

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

a market situation where a number of steel types can 25Executive Court Reporters (301) 565

- 0064 43

compete and be sold in transformers. Obviously, the 1

question is, at what efficiency levels for each 2

design line

-- what does that mean, so this goe s 3

into our core steel pricing tool, and we can 4

continue talking about whether that’s a useful way 5

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

make suggestions. 7

Materials, price updates, different 8

scenarios. There’s been discussion of the differ ent 9

techniques used for scaling, both

-- in particular, 10

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

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

to harmonize across one

- and three

- phase units, and 13

does that change in different transformer 14

applications. 15

As far as new product classes, there have 16

been proposals for perhaps setting liquid immersed 17

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

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

question of whether it would be beneficial to do in 20

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

useful or warranted to set standards for different 22

subtypes of liquid immersed transformers

-- poles, 23

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

thing. 25Executive Court Reporters (301) 565

- 0064 44

And the last is size and weight 1

constraints w hich really is treated in the LCC. So 2

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

Before I do, I want to touch on something 4

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

are our priorities in looking at the analysis? And 6

I think that the first t hing has to be achieving the 7

level of comfort with our existing representative 8

units. If these

-- these are the basis for really 9

everything else, the upstream portion of the 10

engineering, which is the upstream portion of the 11

whole analysis, and so if those

-- if we can’t agree 12

on those, then we

-- it’s tough to have the rest of 13

the discussion. 14

So the second thing is scaling. How do we 15

extend those representative unit results to the rest 16

of our covered space? 17

And then finally, we think the third 18

priorit y is looking at new equipment classes. 19

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

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

bit less useful. 22

The way that DOE sets equipment classes, 23

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

that there’s a differential consumer utility, in 25Executive Court Reporters (301) 565

- 0064 45

other words, if one type of product does something 1

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

second criterion is do the different equipment 3

classes have a different ability to meet different 4

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

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

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

can talk about today. 8

MR. RIVEST: Mike Rivest, Navigant. 9

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

So cl early, looking at the hierarchy here of 11

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

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

example. Possibly with the liquids, we an initiate 14

conversations about scaling, whereas with dries, I 15

think we’re still at the representative unit 16

validation stage. So when we talk about when things 17

might be ready, walking down the analysis and things 18

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

terms of discrete steps, segmenting the product 20

class, the produc t types and looking along the way. 21

And then depending on how we actually 22

perform the analysis for scaling, or for 23

extrapolating to other product classes, that can be 24

a very difficult exercise, or it could be relatively 25Executive Court Reporters (301) 565

- 0064 46

simple. It really depends on the e xtent to which we 1

can get stakeholder involvement and data. You guys 2

have great tools, in the liquid field universe at 3

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

think we’ll propose methods maybe for scaling there 5

that will depend on your involv ement. And for other 6

product classes it may be more difficult. 7

So I think to be able to answer the 8

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

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

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

- 11

- gives us our charge, basically. 12

MR. PARKER: So as I understand it from 13

Brian just now, basically, to make a final 14

assessment as to whether there’s a justification for 15

creating a new representative unit, they need 16

further data from the manufacture rs, is that right? 17

MR. RIVEST: It would not be a new 18

representative unit. It’s not a new representative 19

unit. We’re talking about new product cl a sse s

. 20

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

But the question is, do you need more information 22

than y ou have gotten from the manufacturers to make 23

that assessment? 24

MR. COFFEY: I think we would, as Mike 25Executive Court Reporters (301) 565

- 0064 47

just said, need some input from the committee as to 1

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

equipment classes, yes. 3

MR. PARKER: Is that an analytical 4

methodological concern, or is it a data? 5

MR. RIVEST: It’s a

-- we’ll get

-- we 6

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

MR. COFFEY: So moving

-- I’m sorry, is 8

there a

-- 9

MR. PARKER: Steve. 10

MR. ROSENSTOCK: Just a quick one, going 11

ba ck to the previous slide, there’s slides

-- 12

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

one or two follow

- up slides for discussion? I just 14

wanted to make clear so far. Thank you. 15

MR. COFFEY: So here’s the follow

- up

-- 16

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

MR. HIRSCH: Yeah, Bruce Hirsch, Baltimore 18

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

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

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

when we’re talking about network an d bulk type 22

transformers because of the constraints. But I just 23

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

area in Baltimore City with our existing system, so 25Executive Court Reporters (301) 565

- 0064 48

overhead transformers and pad mount are also an 1

issue to us when you’re talking about ch anges in 2

sizes. We’re not constrained

-- the weight issues 3

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

we also need to keep

-- we keep safety clearance 5

distances from other things that are out there in 6

that congested area. So that creates a big problem 7

for the utility industry. So I just think also 8

keeping that in mind when we make these changes. 9

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

to address some of that in their presentation too. 11

So to look at the first bullet here, which 12

is achieving comfort with the existing 13

representative units, I noted in the data section 14

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

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

the different design specifications that 17

representative units could have at differ ent 18

efficiencies. We consider this to be the first 19

priority and so we hoped to receive feedback 20

wherever someone feels there could be a discrepancy, 21

as soon as possible. 22

So we talked a little bit about how 23

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

sometimes not as useful, because if there’s a 25Executive Court Reporters (301) 565

- 0064 49

difference, it’s hard to know exactly where that 1

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

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

come to an understanding. 4

And the second point the re is that as 5

materials prices change, the designs that 6

manufacturers will produce to accomplish a certain 7

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

attempt to hold materials prices within a certain 9

range before you start comparing the designs that 10

t hey lead to. 11

The second priority in reworking some of 12

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

extend the results of a certain representative unit 14

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

what generates a standard for different KVA ra tings. 16

Historically, losses have been scaled 17

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

probably familiar with, where the losses of two 19

transformers

-- the ratio of the losses is set equal 20

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

power, an d you can see that in equation form right 22

there. Sure. 23

MR. PATTERSON: Wes Patterson. Yes, in 24

the existing standard between two KVA points you use 25Executive Court Reporters (301) 565

- 0064 50

the three

- quarter rule. But between KVA points, you 1

just arbitrarily pick numbers for losses. And that 2

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

other. So either the losses are following the 4

three

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

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

MR. COFFEY: No, I’ll explore that a 7

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

illustrate that point. 9

So several manufacturers have given 10

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

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

but sometimes there’s realities in the way that 13

things are manuf actured that deviates slightly from 14

the ideal and the observed behavior is a little bit 15

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

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

then sometimes at the extremes of the scaling range 18

you lose a little bit of accuracy. 19

The proposal here is to conduct some 20

limited analysis at the extremes of different KVA 21

ranges to determine or to help hint as to whether 22

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

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

representative units but it would be a couple of 25Executive Court Reporters (301) 565

- 0064 51

test cases to try to tack down what the behavior 1

across KVA is. 2

The benefits of this, we think, are that 3

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

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

range to be perhaps treated more accurately. And 6

then the third benefit, which maybe is less obvious 7

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

results for one type of transformer to a different 9

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

e xplain what I mean about this. 11

For example, if we wish to generalize 12

median BIL liquid results to higher or lower BIL 13

units that would ultimately, perhaps, get a separate 14

standard, this scaling methodology would permit 15

that. Wes Patterson has long been a proponent of 16

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

what that would entail, hearing from other 18

manufacturers as to whether that’s something that 19

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

some charts. 21

To talk about potential new equi pment 22

classes where we might use that scaling methodology, 23

DOE understands that BIL strongly affects the 24

efficiency in medium voltage dry type and in the 25Executive Court Reporters (301) 565

- 0064 52

2007 rulemaking, DOE established equipment classes 1

by BIL for

-- there were high, medium, and low bins

. 2

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

factor in liquid immersed units, but perhaps still 4

significant if standards rise further, so there’s

-- 5

we’ve been hearing that the current standards maybe 6

produce too low a standard for lower BIL units tha n 7

what we analyzed, and maybe too stringent a standard 8

for the higher BIL units. 9

And so the proposal is that we would scale 10

to different BILs if the committee thought it were 11

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

scaling methodology that I’m going to continue to 13

talk about. So keep that in mind. 14

MR. PARKER: Yes, Steve. 15

MR. ROSENSTOCK: Steve Rosenstock, EEI. 16

So basically on the previous slide

-- in that 17

proposal, I know you’re

-- so basically you’d not 18

only be scaling on the KVAs for t he single phase 19

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

cross

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

of

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

three efficiency levels based on BILs? Is that

-- 23

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

about it, that if the committee decided it were 25Executive Court Reporters (301) 565

- 0064 53

warranted and workable, then, yeah, maybe it could 1

end up with something similar to what’s currently 2

done in the medium voltage dry type space. 3

MR. ROSENSTOCK: Thank you. 4

MR. PARKER: Any other comm ents on this 5

before we move on? Yes, Phil. 6

MR. HOPKINSON: Phil Hopkinson. For those 7

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

have some inputs that they’ve been sending me e

9

mails this morning, but would suggest that perhaps a 10

high BIL design s in liquid fill should be broken out 11

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

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

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

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

to 34.5 KV, 15 0 KV

- BIL apparatus, and also what it 16

looked like for dual

- voltage designs. And certainly 17

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

drops off quite dramatically up there as far as what 19

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

was the ba se of what we were trying to collect the 21

data to. 22

MR. PARKER: Okay. Thank you. 23

MR. PATTERSON: This is Wes Patterson, 24

ABB. Recognized that for this voltage class we’re 25Executive Court Reporters (301) 565

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talking an upper end of 200 BIL, not 150. So the 1

problem is much worse at 200. 2

I think that for distribution transformers 3

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

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

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

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

scope o f 200 BIL according to IEEE. 8

MR. HOPKINSON: I think that the material 9

in print from the DOE said that they were limiting 10

to 150 KV

- BIL, which certainly would go along with 11

any of the separable connector ratings, because they 12

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

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

transformer, should be 200 KV

- BIL as Wes Patterson 15

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

think that was in the scope of what would be 17

considered a distribution transfor mer. 18

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

way the standard was actually published, the way the 20

standard was actually written and published, it 21

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

is exclude over 150 BIL in the liquid filled 23

definition , but we have not done that. 24

MR. PARKER: I take it there’s significant 25Executive Court Reporters (301) 565

- 0064 55

sales volume in these higher BILs for which

-- 1

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

little sales volume at 200 BIL. The problem is 3

you’re looking at five percent of the volum e driving 4

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

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

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

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

currently written. 9

MR. PARKER: Any though ts on the best way 10

to accommodate that problem? Phil. 11

MR. HOPKINSON: Phil Hopkinson. I think 12

the best way to do it is to not include 200 KV

- BIL 13

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

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

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

deleting that one and putting it at 150 KV

- BIL, 17

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

and most of the distribution transformers are, then 19

the 150 KV

- BIL would take you to the highest end of 20

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

mostly class 2 kinds of transformers, you definitely 22

will have the 200 and higher. 23

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

reasonably accurately through 150, or do you still 25Executive Court Reporters (301) 565

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need adjustments if you exclude. 1

M R. COFFEY: That set

-- the l75 is used 2

for KVA, so this would be slightly different from 3

that. 4

MR. PATTERSON: Richard, I think when you 5

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

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

line of effic iency. So they have a straight line 8

that goes KVA versus efficiency or watts, and 9

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

higher BIL. 11

MR. SMITH: Bob Smith, Federal Pacific. 12

With respect to the 150 versus 200 KV

- BIL for medium 13

voltage drive s, most of the manufacturers are making 14

ventilated open drive transformers at 35 KV, which 15

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

manufacturers are making cast resin coils which at 17

this same voltage can go to 200 KV

- BI L , however I 18

look at that as a spe cial class of medium voltage 19

drives and would encourage us to stay with the 150 20

KV

- BIL as the upper limit. 21

MR. PARKER: Yes, Steve. 22

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

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

definitional issue, so if there is some sort of 25Executive Court Reporters (301) 565

- 0064 57

cutoff in definition in what’s covered, maybe that 1

might help in terms of some of this discussion in 2

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

the top of my head, but

-- does DOE cover it in the 4

first place, I’m not

-- I don’t exact ly remember. 5

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

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

I don’t know what comes from EPAC

- 92 or just the 8

2007 rulemaking. 9

The second thing, and I think Brian will 10

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

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

of BIL levels in terms of efficiency standards? For 13

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

- 14

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

slide, how many bins are w e talking about in terms 16

of BIL standards? 17

MR. COFFEY: That’s probably something 18

we’d be interested from hearing

-- to hear from the 19

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

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

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

just a desire to speak. 23

MR. HO DG E: Gerry Hodge from Howard 24

Industry. I concur with Phil about having the 25Executive Court Reporters (301) 565

- 0064 58

standard only go to 150 BIL because we don’t

-- we 1

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

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

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

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

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

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

have to go to am orphous, possibly, to get the 200 8

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

materials you can use for real high BILs. 10

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

issue is whether to try to create a separate 12

category for the higher BILs or simply exclud e it 13

from the rulemaking altogether, is that right? 14

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

there’s no lawyer in the room so

-- 16

MR. PARKER: Yeah, I think when you 17

exclude something from the rulemaking

-- 18

MR. RIVEST: I know that we an exclude 19

som ething, we can create a class for it and

-- if 20

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

there’s

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

exclude it. Maybe you can create a separate class 23

and not change the standard, perhaps, but that 24

really is an issue for the lawyers. 25Executive Court Reporters (301) 565

- 0064 59

MR. PARKER: Yes, Andrew. He needs a mic. 1

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

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

percent

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

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

that you could leave the standard as is for those 6

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

So it strikes me that we suggested in our comments 8

that you could do three classes of BILs

-- I think I 9

said two

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

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

for purposes of our discussion, disregard those over 12

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

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

actually going to get us moving towards

-- 15

MR. PARKER: Thank you. Aaron. 16

MR. MEYERS: Aaron Meyers, Cooper Power 17

Systems. We would support either exclusion or 18

creating a separate product class. The only request 19

that we would have is that we are seeing commercial 20

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

point, 150 KV

- BIL connectors. So if we are 22

separating this, I would just ask that that be 23

clarified or resolved within the definition. 24

MR. COFFEY: Does anyone have thoughts on 25Executive Court Reporters (301) 565

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the right way to treat those cases? 1

MR. HOPKINS ON: I ran a working group for 2

ten years on dielectric test tables for distribution 3

transformers, and we finally ended up that the limit 4

for distribution transformers in IEEE is 150 KV

- BIL 5

for liquid, and 200 KV

- BIL was the limit for class 2 6

transformers s o that I view this as clearly a 7

distribution transformer, 150 KV

- BIL and below, and 8

that goes certainly with the bulk of production. I 9

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

are at 200 KV

- BIL, of the total population of the 11

transformers that a re out there. It’s small. 12

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

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

a separate class created for greater than 150 BIL 15

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

agree that the recommendation will be no change in 17

the standard for that tiny equipment class. Is that 18

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

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

proposed, basically, creating a new class for 21

greater than 150 BIL for this tiny cat egory, and 22

keeping it the same? 23

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

could go either way. 25Executive Court Reporters (301) 565

- 0064 61

MR. PARKER: Speak into the mic, yeah. We 1

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

of one percent, but Aaron, go ahead. 3

MR. MEYERS: In respon se to Brian’s 4

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

150 KV separable connectors, the coil insulation 6

really drives the design, so my recommendation would 7

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

BIL class. 9

MR. PARKER: Great. D o we have agreement 10

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

Aaron will work with Brian on the exact way to 12

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

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

that in the interest of moving forw ard, we will 15

agree that that will simply be left at the current 16

standard. Is that a fair representation? Mike. 17

MR. RIVEST: Assuming that that stands, 18

would there be further breakdowns for BIL for liquid 19

fill? 20

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

on that. Is there any

-- any dissent from that? 22

Are we in agreement on treatment of that tiny 23

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

issues? Yes. On BIL. 25Executive Court Reporters (301) 565

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MR. HOPKINSON: What I would recommend is 1

that for a liquid filled transformers, 9 5 KV

- BIL and 2

below would be one equipment class, and above that 3

all the way up to 150 KV

- BIL would be the second 4

equipment class. 5

MR. PARKER: Any

-- Gerry. 6

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

and we would eliminate 200 BIL from the definition 8

of t ransformers? That’s what you would recommend? 9

MR. HOPKINSON: Yeah. 10

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

MR. HOPKINSON: And this is Phil again. 12

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

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

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

be one equipment class, and 125 and 150 KV

- BIL would 16

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

of 110 KV

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

is really a class 2 transformer definition, so in 19

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

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

his head. 22

MR. COULTER: I would get concerned

-- 23

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

eliminating 200 BIL. It’d become real easy any time 25Executive Court Reporters (301) 565

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somebody bought a 35 KV to say I just want a 200 BIL 1

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

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

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

within the legal scope but to recommend no change in 5

the efficiency level for it. 6

MR. PARKER: Wes Patterson. 7

MR. PATTERSON: Yeah, I think I presented 8

or gave out a PowerPoint that showed the 9

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

Brian, you got it, right? 11

MR. COFFEY: Ye ah, I think

-- 12

MR. PATTERSON: I think everybody did. 13

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

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

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

Like easily 80 percent level. And then it drops 17

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

it becomes insignificant above 125. Right. 124, 19

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

relative. So you take the biggest circle all the 21

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

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

So to keep the world simple, my 24

recommendation would be to follow Phil’s suggestion 25Executive Court Reporters (301) 565

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and simply say 95 BIL and below, you’ve got this 1

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

circles and these li ttle red dots,

-- 3

MR. PARKER: You have to speak into the 4

mic. 5

MR. COULTER:

-- would be another class. 6

Including 200. You would have rolled 200 into the 7

second class, the upper class. 8

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

150 and 200? 10

MR. C OULTER: Phil, that would be my 11

recommendation to keep the standard somewhat simple, 12

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

number of units that are shipped at those ranges, 14

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

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

watts. 17

MR. HOPKINSON: I would call on my good 18

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

that Gerry would probably make words like at 200 KV

20

BIL, the efficiency will drop off a lot so if we 21

limit the materials to w hat will be used in the 22

transformer and then if we go with the efficiency 23

that will work for that transformer, then I think 24

you’ll find that you’re not going to like the answer 25Executive Court Reporters (301) 565

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when you put 200 KV

- BIL into the pot. But, Gerry 1

would you comment? 2

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

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

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

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

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

you’ve got to t ake something else out or you’ve got 8

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

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

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

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

to have to do someth ing better to maintain that one 13

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

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

- 150 15

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

sure it warrants another range, because the quantity 17

just doesn’t

-- 18

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

further analysis or discussion, but I think the idea 20

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

current

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

you’re objecting to Wes’

-- I take it you have a 23

problem wi th Wes’ suggestion that we just mandate 24

that it meet the standards for the lower BIL. So if 25Executive Court Reporters (301) 565

- 0064 66

that’s the case, why don’t we just propose to follow 1

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

back? 3

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

area are pred icated on the notion that we’re looking 5

for significant increase in transformer minimum 6

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

participating in this process. Now we’re interested 8

in focusing on those parts of the market that have 9

significant sales and therefore drive significant 10

energy savings and the related benefits. So, our 11

view on this particular issue is that I think the 12

break point of 95 BIL makes sense, because the 13

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

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

-- this is my recommendation, a little different 16

than yours, Wes

-- 17

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

market. 19

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

what

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

from th at break point up to 150 would be your second 22

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

depending upon getting final resolution of the legal 24

issue of whether these things are in or out in the 25Executive Court Reporters (301) 565

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current market before saying some people

-- seems to 1

be some disagreement over that

-- but things over 2

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

recognizing right now that that one, in all 4

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

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

ready to suggest that as a preliminary suggestion 7

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

sales are at. 9

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

standard for the highest BIL ratings should be the 11

same as the mid

- range, once we see the analysis come 12

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

analysis for purposes of this committee. 14

MR. PATTERSON: The concern is that we 15

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

which means then we will never reach significant 17

improvement. If we want to achieve signifi cant 18

improvement we cannot included them just like we 19

can’t include the network. 20

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

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

thanks to your explaining that in the very first 23

meeting that we had, and I suggest that breaking 24

these down by BIL levels is

-- I think I’m hearing 25Executive Court Reporters (301) 565

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consensus on this point, and that we should

-- 1

MR. PARKER: Any objection to that 2

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

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

approach then that I understand is three BIL 5

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

one for greater than 150. The greater than 150 7

would remain within the scope of this group unless 8

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

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

now. At least that would be the recommendation of 11

the group. I really think we need to move on

-- 12

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

MR. ROSENSTOCK: Numerical. Less than or 14

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

to 150

-- 16

MR. PARKER: Yes. 17

MR. ROSENSTOCK:

-- greater than 150. 18

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

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

was helpful discussion there. The second new 21

equipment class area, or potenti al new equipment 22

class area comes in the liquid space, where there 23

have been suggestions to, as with BIL, maybe 24

subsegment by the type of transformer being 25Executive Court Reporters (301) 565

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produced, so that could be pads, that could be 1

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

co ntext of DOE’s criteria for setting equipment 3

classes, is there a different utility to the 4

consumer, the consumer in this case being the 5

purchaser of the transformer. And is there a 6

differential ability to meet efficiency standards? 7

So I’d like to open t he floor for discussion of that 8

and suggestions for how it might be done. 9

MR. PATTERSON: Wes Patterson. So you 10

have two criteria, right, one is different utility 11

to the customer? So pad mount transformers is a 12

total different utility than a pole mount , which is 13

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

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

MR. PARKER: We got it. 16

MR. PATTERSON: So for sure, those four 17

categories, now when you change substation to say 18

all other, catch phra se, right. Instead of saying 19

substation, because that’s a specific class of 20

transformer , right, so my recommendation would be 21

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

others. And they have different utilities which 23

meet your first criteria, wh ich can be looked up in 24

standards. 25Executive Court Reporters (301) 565

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MR. PARKER: There’s a microphone behind 1

you, Bob. 2

MR. BERMAN: Robert Berman, Berman 3

Economics. Wes, can you cross

- sell one utility into 4

another? Can I buy a network vault transformer and 5

use it on a pad? 6

MR. PAT TERSON: No. It’s not possible. 7

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

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

flip

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

vault. 11

MR. BERMAN: I understand that. 12

MR. PATTERSON: You can take a network

- - 13

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

it onto a pad. 15

MR. PATTERSON:

-- and drop it onto a pad, 16

but since it sells for three times what the pad 17

sells for

-- economically, it’s insane. 18

MR. BERMAN: Okay. That works. 19

MR. DeLASKI: A follow

- up to that, though, 20

is that

-- so a network transformer is a very 21

sophisticated piece of equipment, where there are 22

transformers that go in vaults that are not network 23

transformers. 24

MR. PATTERSON: That's correct. And 25Executive Court Reporters (301) 565

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they’re space constrained also. 1

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

have

-- but they would not have that incremental in 3

price, is my understanding. 4

MR. PATTERSON: Yes, they will still have 5

that incremental in price

-- that incremental in 6

price

-- 7

MR. DeLASKI: The same increment? 8

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

have the cooling space required that an open 10

transformer has. One of the problems with 11

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

to limit the perimeter loss. 13

MR. DeLASKI: Sure. 14

MR. PATTERSON: So yo u can do it two ways. 15

You can do it by either increasing the amount of 16

radiators that you put on the transformer, which 17

increases its footprint, or you can design the heat 18

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

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

MR. DeLASKI: So you said

-- I think you 21

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

top of your head, you said

-- 23

MR. PATTERSON: The network is unique 24

because it’s got these gigantic expensive network 25Executive Court Reporters (301) 565

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protector on it. 1

MR. DeL ASKI: Right, you said it was a 2

three

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

MR. PATTERSON: Easily. 4

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

say off the top of your head? 6

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

basic level as the network. Runs v ery high. 8

PARTICIPANT: It won’t have the network 9

protector. 10

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

protector. 12

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

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

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

to have to

-- I like the free

- flow conversation, but 16

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

bit more formal so that people announce their names 18

before they give their comment. Go ahead. 19

MR. SAMPAT: This is Mahesh P. Sampat, EM S 20

Consulting. The vault transformer would be cheaper 21

than the network transformer because it will not 22

have the network protector, but more expensive than 23

the pad mount transformer. I concede with that. 24

Only additional comment I got is if you look at the 25Executive Court Reporters (301) 565

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pad mount transformer versus pole type, single 1

phase, there is a desire among the manufacturers to 2

keep the same efficiency so that can use same core 3

and coil between single phase pad and single phase 4

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

equipme nt class for pad mount. The cost structure 6

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

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

that would be my comment. 9

MR. PARKER: Okay. 10

MR. PATTERSON: Wes Patterson, again. 11

Mahesh

-- 12

MR. P ARKER: Excuse me just a second. Can 13

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

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

webinar people crazy with the feedback on the mics. 16

MR. PATTERSON: Actually, the driver for 17

distinguishing the pad and the pole has to do with 18

the complication of the weight and size change on 19

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

constraints about the weight and size restriction on 21

the pole that would prohibit us from pushing the pad 22

mount efficiencies as much as we could. 23

MR. PARKER: Just a second, Phil. 24

MR. ROSENSTOCK: Steve Rosenstock, to 25Executive Court Reporters (301) 565

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follow up what Bruce said earlier today, especially 1

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

could be some safety consideration with other 3

utilities l ocated nearby that, even if they wanted 4

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

because they’re physically and maybe legally limited 6

in terms of their

-- I’ll say their height, length, 7

width, depth ratios in the space that they already 8

have. They c annot expand any of the dimensions 9

whatsoever. 10

MR. PARKER: Okay. Phil. 11

MR. HOPKINSON: Phil Hopkinson. What I 12

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

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

vault and networks, then

-- and I have not yet 15

knocked off substation because I think that belongs 16

in. But the vault and network have protection for 17

immersion in water to oftentimes the vaults get 18

flooded, and so those are particularly heavy

- gauged 19

steel and they are also treated with a surfac e 20

protectant, and they’re different. And they 21

oftentimes also have a temperature class of 55 22

degrees rise instead of 65 degrees C rise, so 23

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

it’s not worth considering in this group. 25Executive Court Reporters (301) 565

- 0064 75

On the one to the l eft, I would say that 1

on pad mounted transformers, they’re a little 2

different than pole types because they’re generally 3

in pole types, more of a stub

- out kind of 4

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

the bushings, and yes, there are lead losse s and 6

stray and etti losses associated with the tanks on 7

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

where the bus work runs parallel to the core clamps 9

and to other parts that can heat up and cause 10

greater degree of stray and etti loss. And so p ad 11

mounts are somewhat unique in themselves also. And 12

the substation transformers would be in the same 13

kind of category. 14

MR. ANDERSON: Rick Anderson, Fayetteville 15

PWC. Question about substation transformers. 16

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

12 KV, are you? I don’t see that as

-- 18

MR. PATTERSON: No. The

-- Wes Patterson 19

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

There are a class of transformers which are

-- 21

various companies have different names for it, but 22

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

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

subs, secondary unit subs, and full subs. We’re 25Executive Court Reporters (301) 565

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talking only 36 KV, right. But the way it’s 1

constructed, the tank and the bushing configuration 2

is similar to the subst ations the utility guy 3

normally think about. 4

MR. PARKER: Gary Fernstrom. 5

MR. FERNSTROM: Richard, Gary Fernstrom 6

speaking for the California utilities. The way 7

transformers are used across the country is diverse, 8

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

very large pole mount transformers. So the height 10

is a consideration of the transformer, because you 11

have the clearance between the primary and secondary 12

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

of a consideration, so we’re not rea l concerned 14

about change in the diameter of pole mount 15

transformers in the size that we purchase. 16

And secondly, getting to Andrew’s point, 17

the vast majority of transformers are not vault 18

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

not substation t ransformers, for sure. So in the 20

interest of getting at the majority of the market, 21

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

Thanks. 23

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

think that’s helpful, and I do want to focus on the 25Executive Court Reporters (301) 565

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majority of the ma rket. One thing that we need to 1

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

Counsel here, but I feel pretty confident as a 3

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

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

regulation that applies to ma nufacturers and is 6

enforced vis

- à

- vis manufacturers. And so there 7

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

create a separate equipment class for network and 9

substation, or vault transformers, there needs to be 10

a way of translating that into som e specification 11

for the physical design of the product so that 12

you’re not having to

-- the manufacturer is on 13

notice that this kind of equipment class is subject 14

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

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

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

that’s not the way

-- my understanding, and correct 18

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

the way the efficiency standards have worked in the 20

past. There’s not an administrative apparat us for 21

gathering that kind of information. These are 22

standards designed according to physical 23

characteristics of equipment class, so we have to 24

think of specifications for that. Wes. 25Executive Court Reporters (301) 565

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MR. PATTERSON: Wes Patterson. There is 1

IEEE product standards speci fically for a class of 2

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

and a class of product called network transformers, 4

that are well established in the industry, which has 5

all the physical characteristics of each one of 6

those three products. 7

MR. COFFEY: I think in general DOE often 8

likes to take established industry standards as a 9

starting point for doing things like setting 10

equipment classes. The question would be, are these 11

adequate? Do they constitute a loophole in any 12

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

is a vault and come up with a water

- tight set

-- no 14

pun intended

- set of specifications that someone 15

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

a vault transformer, these are the standards that it 17

must meet. And t hose would presumably be linked to 18

the features of that device that generated the cost 19

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

gauge steel or the water

- tight coating. That’s the 21

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

this exercise. 23

MR. PARKER: Wes, does the IEEE 24

specification do that, in your view? 25Executive Court Reporters (301) 565

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MR. PATTERSON: Yes, it does. So you 1

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

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

just rewrite the IEEE one into a DOE document. 4

MR. PARKER: Would that cover the vault as 5

well as the network? 6

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

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

could tweak it to cover the vaults. 9

MR. PARKER: Okay. Is there general 10

consensus in followi ng the IEEE specifications and 11

working out within the next very short period, any 12

tweaks that we need to do to

-- what’s that? Excuse 13

me. John. 14

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

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

think we need m ore time to look into these 17

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

things we cannot decide right at this table. 19

MR. PARKER: Yes, Andrew. 20

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

looking first to the IEEE standard makes sense. I 22

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

But I think that starting with industry standards 24

makes sense. And then we want to make sure that it 25Executive Court Reporters (301) 565

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satisfies the criteria that Brian just laid out. 1

We went through a similar experience in 2

negotiating new home refrigerator standards recently 3

where we negotiated new standards for refrigerators, 4

but we created a new class for built

- in units. It’s 5

a space

- constrained refrigerator, okay, and a new 6

class was created, recommended by us and industry, 7

together, an d formed the basis for a consensus 8

recommendation that the government move forward on 9

through a different kind of negotiation, but a 10

negotiated standard that I think quite likely would 11

not have happened in a normal rulemaking, contested 12

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

advantages of the process we’re engaged in here 14

today is that we can talk about creating these kind 15

of product classes that I think might not happen in 16

a contested rulemaking. 17

DOE

-- there’s a vault issue and this 18

network issu e came up extensively during the last 19

rulemaking, and DOE decided not to set separate 20

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

is

-- I agree with the notion that we should 22

separate out these products for analytic purposes 23

and see what standards

- - see what the analysis 24

says. They may or may not ultimately decide on a 25Executive Court Reporters (301) 565

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separate standard for them, but it’s useful to 1

separate them out. 2

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

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

group making a

-- n othing that we do binds the 5

Department. It’s our recommendation. 6

MR. CYMBALSKY: So I guess the approach is 7

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

don’t

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

to adopt these IEEE things right now. That ’s all. 10

MR. DeLASKI: This is Andrew again, just 11

to amplify on that. So we, using my example again, 12

we actually spent a lot of time on that definition, 13

how you define a built

- in refrigerator, and in fact 14

the lawyers got involved in depth, because we were 15

very concerned that

-- about loopholes, that 16

suddenly that thing we’re calling a vault 17

transformer is now being installed on pads as the 18

lowest cost option of our marketplace. So that’s 19

the kind of thing we want to be looking at to make 20

sure we’re not cr eating a loophole that undermines 21

what we’re trying to accomplish. 22

That takes a

-- an industry standard 23

typically wasn’t designed for that purpose, avoiding 24

loopholes, so we have to make sure that it serves 25Executive Court Reporters (301) 565

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that purpose which is being repurposed for. 1

M R. PARKER: Okay. That’s a good point. 2

Phil. 3

MR. HOPKINSON: Yeah, Richard and John, 4

and by the way, John, nice to actually see you here 5

this morning. My son also works for the DOE. He 6

told me to tell you he’s working hard. 7

The title of C57.12.40 i s “IEEE standard 8

requirements for secondary network transformers, 9

subway and vault types.” And I have the scope here 10

and so on too. So if you would like, I can just 11

send, I think my normal communication has been to 12

send to either Richard and the whole gro up or to 13

send just to Brian Coffey, however you wish to have 14

it submitted. But it’s a big standard. 15

MR. PARKER: Why don’t you just send it 16

around. Yes, Bob. 17

MR. BERMAN: Robert Berman, Berman 18

Economics. With those definitions and 19

specifications, wh en we look at them, if there could 20

be some way of identifying what the differences are 21

from one specification to the next, and then for 22

those of us that read dollars rather than 23

engineering notation, and maybe sensitive to how 24

something might cross from on e market to another, if 25Executive Court Reporters (301) 565

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you could

-- if we could look at the cost of some of 1

those differences, then that could help us with the 2

question of loopholes, I think. 3

MR. PARKER: So I guess the

-- go ahead, 4

sorry. 5

MR. ROSENSTOCK: Just a quick one. Steve 6

R osenstock, EEI. These are technical definitions. 7

There’s nothing about the specific design or 8

application or anything else. These are purely 9

technical definitions about what they are, as 10

defined by IEEE. It’s not

-- you really can’t use 11

them to do any sort of economic comparisons because 12

these are purely technical or descriptors. So I 13

don’t think you’d be able to use these technical 14

definitions that hopefully the parties could agree 15

to do any sort of that analysis that you’re 16

referring to. 17

MR. BERMAN : Yeah, Robert Berman, Berman 18

Economics. The technical definitions talk about how 19

the transformers are built and building it in 20

different ways so I assume is a different cost. And 21

what I’d like to get an understanding of is

-- is it 22

a different

-- to wh at extent is there a different 23

cost? Is the difference, you know, yellow paint in 24

one area and not in another kind of thing, which 25Executive Court Reporters (301) 565

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would have a very low cost, or is the difference, as 1

Wes points out, it’s got this

-- these protectors on 2

it that are hugely expensive, and that’s a big 3

difference? If we can see what the differences are, 4

to see whether or not they’re not only different 5

products from an engineering application 6

perspective, but are also different products from an 7

economic perspective so that we can take a look and 8

see what they would look like in the market. 9

MR. PARKER: Is it possible to get, from 10

either Navigant or people around the table, a short 11

concise summary of the key physical differences 12

between the network

- slash

- vault type transforme rs 13

and the regular pad mount that we could look at, 14

both to determine whether we have adequate data to 15

create a separate category for them analytically, as 16

well as to address the loophole question? Wes. 17

MR. PATTERSON: As a first pass, Wes 18

Patterson

-- as a first pass, at the last meeting I 19

gave a PowerPoint. I provided a picture of each of 20

these. All we have to do is look at the picture. 21

You don’t have to be any more enlightened than 22

looking at that picture to say, we’re looking at 23

apples, oranges an d pears. Just look at the 24

picture. 25Executive Court Reporters (301) 565

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MR. PARKER: Well, in a term sheet or any 1

kind of legal or quasi legal document, we’re going 2

to have to have some kind of specification that goes 3

beyond a picture, I think, so that we can indicate 4

what transformers fal l into which category. 5

MR. MILLURE: Dave Millure, Metglas. I’m 6

assuming we’ll also be able to break the market and 7

the energy savings out by these new classifications 8

so that we can see what the impact is of different 9

efficiency levels versus the diffe rent design lines. 10

MR. PARKER: Have you gathered data for 11

network and vault transformers? 12

MR. COFFEY: I think to do that economic 13

calculations

-- and this is really an LBL question, 14

but I think insofar as there is data available for 15

that, we could st art to talk about doing it. But I 16

think at this point we don’t really know exactly 17

what that would be. 18

MR. RIVEST: So if we were to make 19

decisions based on these new classes, we wouldn’t 20

know what the impacts are on energy savings? 21

MS. COUGHLIN: For the purposes of the 22

LCC, if the cost efficiency relationship is 23

different

-- 24

MR. PARKER: Excuse me, this is Katy 25Executive Court Reporters (301) 565

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Coughlin, LBL. 1

MS. COUGHLIN: Yeah. Essentially we would 2

need to see whether the cost efficiency relationship 3

is substantially differen t, and if it is, we would 4

run an LCC based on the data for that particular 5

product class. So it’s an open question at this 6

point whether the price efficiency relationship is 7

going to be significantly different, because again, 8

it’s the increase in price as you increase 9

efficiency that affects the LCC results. 10

MR. PARKER: Is there a prima fasciae 11

reason to believe that there is a major difference? 12

Wes? 13

MR. PATTERSON: If the issue is not 14

absolute unit price, but price change for lost 15

improvement, then I believe what you will find is 16

the underlying physics for that characteristic will 17

be the same in all four of them, no different. What 18

does change is restrictions on size, weight, 19

application. But the physics of the transformer 20

will be the same across a ll four of them. 21

MR. RIVEST: This is Mike Rivest. I 22

think, you know, in different rulemakings we stumble 23

upon this type of problem of space constraints, and 24

we’ve handled it differently in different 25Executive Court Reporters (301) 565

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rulemakings. So Andrew described a situation where 1

w e basically created a new product class because we 2

were limiting the size of the product to very 3

specific, a very specific opening. And so we 4

created a constraint on the size, and then did an 5

engineering analysis that had dimensional 6

constraints. And whe n you create dimensional 7

constraints it means that you quickly get into more 8

expensive steels. So you don’t have the same range 9

of design options that you do if you don’t have a 10

space constraint. So that’s one way of dealing with 11

that kind of problem. 12

Another way of dealing with this problem, 13

which is the way that pole mounts was treated in the 14

earlier rulemaking, is to internalize the costs of 15

pole changeouts, and bring it inside the cost of the 16

end user installation cost, and sort of distribute 17

it acr oss all users. So that’s the way of handling 18

the situation. 19

So the incremental cost might be the same, 20

assuming you had the same amount of space. Here 21

it’s sort of a hybrid. It’s

-- in a replacement 22

situation it might be more like the refrigerator. 23

I n a new construction situation, it might be more 24

like a full mount. So I guess you could go either 25Executive Court Reporters (301) 565

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way. But I could see doing an analysis here with 1

the engineering that would simply limit the outward 2

dimensions. 3

MR. PARKER: Katy, did you want to 4

respo nd? 5

MS. COUGHLIN: I wanted to mention that we 6

already included in the LCC the installation issues 7

associated with space constrained and weight issues 8

with poles. And that’s going to be reviewed this 9

afternoon, so we may want to table this discussion 10

un til this afternoon, and then once we present in 11

more detail how the installation issue has been 12

dealt with, you can comment on whether you think it 13

needs further improvement. 14

MR. ROSENSTOCK: Steve Rosenstock, EEI. 15

Does that include the vault issues as well? Thank 16

you. 17

MR. DeLASKI: Was there a response to 18

Steve’s question? 19

MS. COUGHLIN: Yes, it does. 20

MR. ROSENSTOCK: So, just to be clear, so 21

then

-- 22

MR. PARKER: Andrew DeLaski. 23

MR. DeLASKI:

-- the analysis includes 24

costs for vault changes, that’s embedded in the 25Executive Court Reporters (301) 565

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analysis. Now that’s just spread right over through 1

averaging. 2

MS. COUGHLIN: Well, again, we can get 3

into the details this afternoon, that may be more 4

efficient. The analysis deals with space 5

constraints, so if the installation is space 6

constrained, then we go through some additional 7

steps to go through the LCC. 8

MR. DeLASKI: But do you know off

- hand, I 9

know we’ll get it this afternoon, but are there

-- 10

do you have some portion of units that you say, oh, 11

this one

-- the vaul t’s too small so we have to make 12

adjustments because the vault won’t hold the bigger 13

transformer? 14

MR. BOLDUC : Hi, Chris Bolduc , LBL. The 15

issue with pole costs, because it’s

-- 16

MR. DeLASKI: Sir, I said vault. 17

MR. BOLDUC : I’m sorry. 18

MR. DeLASKI: Excuse me. 19

MR. BOLDUC : With vault it’s examined as a 20

separate group, with the LCC, it’s examined 21

specifically to sub

- group. We add additional 22

markups to the installation of the transformer and 23

we present results. They were in the draft chapter 24

seven that was distributed earlier. 25Executive Court Reporters (301) 565

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That issue of pole costs, we have an 1

algorithm for pole replacement, we’ll review it in 2

the afternoon. Pole replacement is handled much 3

like Mike suggested, where the incremental change in 4

installation cost is spread out ac ross the entire 5

analysis. Based on feedback from the committee and 6

past rulemakings, we’ve

-- it sounds like pole 7

replacement is a far more common occurrence than 8

vault replacement. 9

MR. PARKER: Thank you. Carlos. 10

MR. GAYTAN: Carlos Gaytan, Prolec, G E. 11

We already have some consideration of the four 12

classes for pole mounts and pad mounts in the way we 13

define the design lines. The design line one is a 14

50 KVA rectangular tank, so you need to consider 15

that’s a pad mount design. Design line two is a 25 16

KVA round tank, so the design is well created for 17

pole mount designs. 18

And I agree with Wes’ statement that the 19

deltas from the baseline are

-- can be consistent, 20

and the only change is the baseline price, because 21

of the physical differences in accessor ies and bank 22

requirements. 23

MR. PARKER: Okay. So I take it then that 24

the two things that I’m taking away from this is 25Executive Court Reporters (301) 565

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that it may not be a huge issue if the delta for the 1

network and vault are not different from the deltas 2

for the pad mount. And second ly, that we’ll get 3

some further illumination from this when LBL does 4

their analysis this afternoon. So why don’t we 5

table this discussion until then, and come back to 6

it when we have that analysis. Then I think we will 7

be able to decide what to do once w e have that. 8

So I think this is a good time for a 9

break. Why don’t we take like a 15

- minute restroom 10

break, come back here at 11:30 and we’ll wrap up 11

Brian’s presentation of engineering issues. Thanks. 12

(Whereupon, at 11:12 the meeting was 13

recessed fo r a 40 minute period , reconvening at 14

11:52 a.m .) 15

MR. PARKER: Okay. Thanks everybody. 16

Let’s get started. Just a couple of follow

- up items 17

from the first discussion. I thought it was very 18

helpful. With regard to the data exchange, I think 19

we need to work on finalizing that. I understand 20

that Navigant is working with Bob Smith and Bob 21

Greeson on meeting their concerns. If there are 22

other issues, if you want to raise it, I think the 23

point is now is the time to do it. This is upstream 24

of everything el se, so if you have concerns just 25Executive Court Reporters (301) 565

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about the data, not policy calls about what kinds of 1

metals should be chosen, but problems with 2

validating the data, particularly for medium voltage 3

dry type where I think new data is still coming in. 4

Please get those in t o the mix really right away, 5

because we need to finalize that absolutely as soon 6

as possible so that we can plug that into the LCC 7

analysis and so forth. 8

So we’ll work through Friday with low 9

voltage. We should be looking for early next week 10

to get an y further input that you want into the mix. 11

You’ve had the template now for a couple of weeks, 12

so please consider this the last gavel call for that 13

and we’ll ask at that point, probably next week, but 14

very soon for Navigant to incorporate that and make 15

-- and come back to the group with any adjustments 16

that are needed. 17

Also I should mention, that just on a 18

process point, that I’ll be working with the 19

Navigant staff to set up a share point web interface 20

so that the group can communicate more efficiently 21

e lectronically. It will allow us to create 22

discussion threads that we’ll organize the 23

discussions topically so that there will be one 24

single site. You won’t have to sort through all of 25Executive Court Reporters (301) 565

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the e

- mails that have come in. There will be one 1

single site that you can go to and look at what 2

comments have been posted, and reply to comments, to 3

create a new thread if you want to create a new 4

thread. I will moderate that. We should have that 5

up, I understand from the technical staff, that that 6

should be up by early next week to middle of next 7

week. So that will help facilitate our work, I 8

think between meetings substantially. 9

But we do need to really put the data 10

stuff

-- the data issues to bed, make any 11

adjustments that are needed and have that finalized 12

very, ve ry soon so that LBL can do their LCC 13

analysis, confident that they have the right data. 14

Of course that presumes certain

-- the resolution 15

of certain issues like what equipment classes and so 16

forth, and we’ll need to finalize that discussion 17

before we adj ourn for this meeting as well. 18

I also missed a discussion we should have 19

at the beginning of the meeting. I had on the 20

agenda an item about rules of procedure. Let me 21

just talk about that very, very quickly. 22

**Finalization of Rules of Procedure**  23

In our first meeting we agreed on rules of 24

procedure after an extensive discussion. After that 25Executive Court Reporters (301) 565

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meeting, one person said to me, well, you know, we 1

haven’t had a legal counsel look at this, and could 2

we have them vet it first. So I went back to the 3

group by e

- mai l and one said, well, you know, I’ll 4

open this up to any objections, if people have them, 5

based upon legal counsel if they feel that there are 6

legal issues raised. So let me just ask if there 7

are any

-- I consider that we still have an 8

agreement, but it c an be annulled, I suppose, if 9

anybody finds, on the basis of their talks back home 10

that they have major problems with the rules of 11

procedure or timeline that we’ve agreed. So let me 12

just say, ask the group now is there anybody that 13

wanted to raise a conce rn about the ground rules 14

that we adopted before, based upon their 15

considerations back home since the last meeting. 16

MR. ROSENSTOCK: Steve Rosenstock , EEI, 17

not a concern, but just double

- checking again. I 18

think

-- I just remember there were so many vote s 19

taken about what the consensus is, just double

20

checking that everyone is, under 3A, that this is 21

the final version of what the consensus is going to 22

be. I just remember a series of votes, and I think 23

we came out to this, but there were some concerns 24

abo ut how many negative votes or anything, so I just 25Executive Court Reporters (301) 565

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wanted to make sure that this was what everybody

-- 1

what we finally, you know, wound up with. I’m 2

pretty sure it is, but there were some questions. 3

MR. PARKER: Yes. I think what was agreed 4

was that con sensus would mean unanimity, but a no 5

vote or an abstention would not defeat a finding of 6

unanimity, that only no votes would be counted as 7

undermining a consensus. 8

MR. ROSENSTOCK: Thank you. 9

MR. PARKER: Okay. I don’t think we need 10

another vote unle ss there’s somebody who wants to 11

ask for another vote. Okay. Great. We’ll consider 12

those finally finally adopted, then. 13

Let’s return then to Brian. I think we 14

made our way

-- two

- thirds of the way through his 15

bullets. I think he’ll turn now to resol ving and 16

responding to some of the open

- ended questions that 17

were raised last meeting and in the e

- mails. 18

Thanks Brian. 19

MR. COFFEY: Well, I’m not quite to the 20

questions yet, but I think

-- what I heard with 21

respect to this issue of new liquid equipme nt 22

classes was that really the cost increments weren’t 23

that different across these different types of 24

units, it’s more that there’s sometimes an issue of 25Executive Court Reporters (301) 565

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limited space for certain applications. And so

-- 1

and maybe weight too, so dimensional and mass 2

const raints. And if that were the case, that sounds 3

to me like something that probably does not require 4

new equipment classes, but would require an 5

economic treatment and incorporation of those costs. 6

Right now, we handle that in the LCC, and so if 7

nobody ob jects, I’ll let LBL speak to that in their 8

presentation. 9

MR. ECKMAN: Just one point on that, if 10

the economics turn out

-- 11

MR. PARKER: Tom Eckman. 12

MR. ECKMAN: Yeah, Tom Eckman from 13

Northwest Council. If the economics of 14

installation, not manufact uring, but the economics 15

of installation turn out to drive the different 16

efficiency level because the installation costs turn 17

out to produce a different life cycle cost, then 18

that may be a reason for dividing the classes. If 19

that doesn’t turn out to be th e case, then it’s no 20

reason to divide the classes. So it’s really 21

contingent on what the analysis shows, in my mind, 22

to see whether or not we get a different answer for 23

pad, pole, and network/vault, based on installation 24

costs. So looking at them separat ely without 25Executive Court Reporters (301) 565

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peanut

- buttering them all together to see whether 1

you get a different life cycle cost answer, before 2

we decide on whether or not there needs to be 3

product classes makes sense. 4

MR. PARKER: Thank you. Wes. 5

MR. PATTERSON: Wes Patterson. If the 6

difference will be based on an economic evaluation, 7

I believe that when the DOE looked at the cost of 8

pole change, they were just figuring the cost for 9

the pole itself, and not changing the other utility 10

lines that are on the pole, and that is the 11

sig nificant cost driver on the poles. With the pads 12

or the networks, the network transformers and the 13

vault transformers, it’s

-- essentially what we’re 14

talking about is going into Manhattan and digging up 15

the sidewalk and making a bigger hole in the ground. 16

That can become extremely expensive very quick, and 17

I don’t know how those costs have been factored into 18

the LBL analysis. 19

MR. PARKER: So I think LBL’s going to 20

address that when they make their presentation. 21

MR. COFFEY: Okay. Then I think we can 22

move on. 23

**Scaling Approach** 24

I did promise to overview quickly the 25Executive Court Reporters (301) 565

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scaling approach that I had mentioned earlier that 1

could be used for instance, in the BIL case, so I’ll 2

go through that quickly right now. 3

Here we’ve got an efficiency versus a KVA 4

plo t, and don’t make too much of absolute numbers. 5

It’s just to show that maybe there are two types of 6

equipment that have sort of different cost 7

efficiency trajectories, maybe one’s a high BIL case 8

and another is a low BIL case. And so here are the 9

curves. 10

If you plot

-- you know, every efficiency 11

implies a loss, right, at a given loading point, so 12

we can show this equivalently by plotting losses 13

versus KVA, and we end up with something that looks 14

like this. Of course, the red curve, which was on 15

top i n the previous plot is now below the blue curve 16

because the more efficient unit has lower losses. 17

These are both power law functions, so 18

they’re both the KVA raised to a number, and 19

historically these numbers are both .75, and so the 20

nice feature about p ower law functions is that if 21

you plot them in log space, they become straight 22

lines, and the slopes of those lines are equal to 23

the exponent that you were raising your variable to. 24

So, again, we can show this same data 25Executive Court Reporters (301) 565

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equivalently , like this, and we’ve got now the log 1

of KVA on the X axis and the log of losses on the Y 2

axis. And so now we’ve got two types of products 3

and we’re discussing whether they’re going to have 4

different standards, and the way that we could 5

adjust that is by figuring out what thi s offset is. 6

And so that’s where maybe some test cases or even 7

feedback from manufacturers could be taken and used 8

to estimate what this offset is that I’m indicating 9

in yellow here. And so then from that you back out 10

what are the losses and then what ar e the 11

efficiencies that that implies. 12

I don’t know if I’m going into a good 13

level of detail here. This is something that Wes 14

has talked a lot about, if you want to add to this. 15

MR. PATTERSON: Yes, I think this was 100 16

percent the way you should do it . And we can 17

provide you the offset. For the level of accuracy 18

that we’re going to obtain, it is going to be 19

sufficiently accurate. 20

MR. COFFEY: Okay, great. 21

MR. PARKER: Any other comments on this? 22

MR. COFFEY: I’m basically saying here 23

what I’v e said in the discussion. I’m asking, is it 24

a useful methodology for treating the scenarios that 25Executive Court Reporters (301) 565

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we talked about before with BILs, potential 1

equipment classes, though it sound like we may not 2

need those. And so we would need some corroborating 3

engineerin g data on transformers designed to certain 4

As and Bs to determine what that proper offset is. 5

MR. PATTERSON: Wes Patterson again. I 6

think the focus on A and B may not be appropriate, 7

that a better focus would be on the change in 8

losses. 9

MR. COFFEY: So I think

-- there’s a 10

question, you know, when you have these two curves 11

of where do these curves come from? What are you 12

holding constant to get that offset? And if you 13

looked at the market today, the medium voltage dry 14

type

-- well, let’s say the liq uid even, there are 15

different transformers sold at different BILs and 16

the higher BIL units presumably have different 17

costs, maybe higher costs, and different 18

efficiencies, maybe lower efficiencies. So when 19

you’re looking to compare a mid

- level BIL unit to a 20

high level BIL unit, you have to hold something 21

constant to make that comparison. And the thought 22

that we were having was that maybe you hold constant 23

someone’s evaluation of loss, so you say someone 24

with four to one A to B factor would purchase this 25Executive Court Reporters (301) 565

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t ype of medium BIL transformer and this type of high 1

BIL transformer , and from there you would derive 2

your offset. Something’s got to be held constant. 3

So that’s something we can talk about. 4

MR. HOPKINSON: Brian, Phil Hopkinson. 5

What I would say is th at the OPS program is actually 6

a pretty good, useful tool. Of course it needs 7

calibration. But at the same time, I think that 8

it’s run by A and B factors so if you tell it that 9

you want to run a 95 KV

- BIL, then you’re going to 10

get, after you’ve given it an A and a B, you’re 11

going to get a series of designs that will tell you 12

what it would be for different steels and different 13

conductors and so on. 14

So you have to really calibrate it, you’ve 15

got to give it a starting point. If you want to do 16

it at 150 KV

- BIL, it’ll do that too, but again, you 17

have to identify what the value of the watt saved 18

and what the load assumption that really gives you 19

the B value. 20

So I think that when we get into finally 21

settling on the vision

-- I’m going to take this 22

opportu nity, Richard, if I could

-- and the vision 23

of what we’re trying to get to, there’s really only 24

three things. The first is, what’s the value of a 25Executive Court Reporters (301) 565

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watt saved? And when I get a chance this afternoon, 1

I’ll come back to it and get a chance to tell you 2

what I did, and if you don’t like it, it’s quite all 3

right, but I would like to see what you like better 4

and get into a discussion on that. But we need to 5

settle on what the value of a watt saved is the 6

first thing. 7

The second is the loading assumption, 8

beca use that’s going to set up the B value, and 9

you’ve got to know what the RMS equivalent load is 10

that the transformer is used at. Again, I’ve got a 11

method and I think the EEI guys will have some other 12

thoughts, maybe supporting thoughts, but those ought 13

to get out on the table, and we need to settle on 14

that loading assumption because that’s going to give 15

the final thing, which is the material and selling 16

price curve versus the efficiencies. 17

And I think we have, in agreement with 18

what’s gone on at OPS, gott en the liquid filled 19

transformers so we’re reasonably close over a narrow 20

range of efficiencies. At the high end of 21

efficiency I still see some issues that I haven’t 22

figured out exactly what caused them. 23

On dry types, huge differences and so we 24

haven’t settled those yet, but we’ll come back. But 25Executive Court Reporters (301) 565

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we do need to settle on the three factors: the value 1

of a watt, the loading assumption, and then the cost 2

curve and after that I can certainly go home and not 3

come back to these meetings, even though they’re 4

gre at, and I think the rest would be for the 5

stakeholders to decide what they really want to use. 6

MR. PARKER: Thank you. Yes, I think

-- 7

go ahead, yes. 8

MR. ANDERSON: Let me take this, Steve. 9

Rick Anderson, Fayetteville PWC. Phil, you’re 10

right. What’ s really critical in this is the B 11

factor. How you load transformers in Baltimore is 12

different than the way you load transformers in 13

Raleigh. A pad goes in a subdivision, that’s 14

different than a pole out on a rural distribution 15

line. So one size does no t fit all. So, generally, 16

when you go back and look at pads, and poles, you 17

have single phase pads, and they’re loaded a certain 18

way. You have three

- phase pads, they’re loaded a 19

certain way. 20

Pole type transformers are loaded 21

differently than three

- phas e pads, so one size does 22

not fit all. We really do need to come up with a 23

consensus on loading. If you look in the National 24

Electric code, there’s diversity tables for electric 25Executive Court Reporters (301) 565

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ranges. We have no diversity tables for electric 1

utility applications becaus e it varies. We’ve got 2

one user here, Ken, he’s out on the west coast up in 3

the mountains and he’s got to derate his 4

transformers by eight percent just due to his 5

elevation. So it’s not one size fits all. We need 6

to be really clear when we turn around a nd say this 7

is the characteristic of a single phase pole, single 8

phase pad, three phase pad, vault, substation type 9

transformer. It’s all different so we just need to 10

be cognizant of that as we look at the data going 11

forward. 12

MR. PARKER: Yes, Steve. 13

MR. ROSENSTOCK: Steve Rosenstock, EEI. 14

In terms of some of the scaling factors, I know it 15

seems like there’s a lot between Wes and Brian and 16

some other folks, but I’m wondering

-- again, these 17

charts show nice linear relationship

-- well 18

logarithmic, nic e relationship, but obviously, like 19

design line four is 150 KVA and it’s supposed to 20

represent anywhere from 15 KV up to 500, and 21

couldn’t there be multiple factors or couldn’t there 22

be multiple variables, depending on whether you 23

going above kind of the d esign line versus below, 24

and would you be able to incorporate that into the 25Executive Court Reporters (301) 565

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analysis? 1

MR. COFFEY: I mean there are always more 2

variables, but what we’re trying to put our finger 3

on is the scaling behavior with KVA and these 4

curves, they’re linear in log space. They have 5

different increments when plotted in cost efficiency 6

space. So I mean I think this permits for modifying 7

the cost efficiency behavior until we find something 8

that everyone’s comfortable with. Does that answer 9

your question? 10

MR. ROSEN STOCK: Well

-- partially, but 11

I’m just saying if the data shows that it’s 12

different

-- it’s a different K factor

-- again, 13

just say if you’re

-- for transformers below the 14

design line in that group, versus above, would you 15

be able to incorporate that into the analysis? If 16

the data shows that. For some reason the curve 17

going smaller is a lot different than the curve 18

going higher, and can you do that if for whatever 19

reason the data shows different K factors, can you 20

put that into the analysis? 21

MR. COFFEY : So that sounds like a 22

secondary consideration and not

-- maybe not an 23

unimportant one, but, you know, I was thinking about 24

it as first we would try to identify what’s the 25Executive Court Reporters (301) 565

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scaling behavior within a K factor, and then if 1

there was some heterogeneity acros s K factors, maybe 2

after that then you make that adjustment. 3

MR. PARKER: Let’s do this because I think 4

this is an important technical issue. I think the 5

issues about load factors and loss valuations are 6

things that are going to come up in the LBL 7

ana lysis, and those are cross

- cutting issues that 8

are very important and that’s going to have to be 9

resolved. I think the issues about what is this 10

offset here, it sounds to me like the people who are 11

technically proficient believe that this is a 12

technically sound methodological approach, and what 13

I would propose is that we just have a working group 14

work together on sort of finalizing this, giving 15

Brian and the Navigant team the data that they need 16

in the next few days as quickly as possible, to 17

assess this l oad factor and then we’ll have a report 18

back to me and to the group with the recommendation 19

as soon as you have it, so that we could, hopefully, 20

get this scaling issue, the final details of it, put 21

to rest. I don’t think we can probably resolve that 22

here if you need more data. I don’t think it has to 23

be resolved here as long as we have a process for 24

resolving it. 25Executive Court Reporters (301) 565

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So why don’t you please give, if you‘re 1

interested or willing to work on this group, talk to 2

Brian at our next break, form a group and work on 3

getting the analysis from your company or from your 4

peers and let’s try to get a report done just as 5

soon as they can get it done. And we’ll send it out 6

by e

- mail to the group, or put it up on the share 7

point site and see if we can get by electronic 8

mean s, that consensus on how to handle that, rather 9

than spend more time on it now. Does that seem like 10

a reasonable way to go? 11

Okay. Let’s go on then. 12

MR. COFFEY: Okay. So that wraps up 13

scaling. At the last meeting, negotiators discussed 14

the possibil ity of having a TSL that permitted 15

grain

- oriented steel and amorphous steel to compete 16

in the market. And the charge was that we would 17

meet with the steel suppliers and ask about what 18

were their thoughts for

-- what would this mean? 19

How would you define this competitive market? And 20

we agreed in principle on selling prices as a metric 21

for equivalence, and there’s some caveats to that, 22

but with, particularly in the case of what are the 23

materials’ prices. But our operating hypothesis was 24

that if two simila r transformers, vary significantly 25Executive Court Reporters (301) 565

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in price, one will probably not get purchased. So 1

if you’re going to contend that two types of 2

transformers are competitive, they’ve got to be in 3

the same ball park. 4

So as an example of how we might look at 5

that, here’ s our design line five plot as it 6

currently stands, and there’s a lot of colors of 7

dots here, so let’s kind of zoom in on the action. 8

The bright green dots are the M3 9

transformers. And so if you draw a line through the 10

kind of lower right boundary of th at, you get 11

something like this. The yellow dots are ZEMH 12

transformers, and so doing the same thing, you get 13

that. And then these sort of maroon

- salmon dots are 14

amorphous units, and those have a flatter slope like 15

this, as we currently modeled them. 16

An d so when you say what’s the price 17

equivalence, you can just start by looking at where 18

those two curves, or those two lines intersect. For 19

the ZEMH amorphous intersection, it would be about 20

right here in efficiency. And you might say, well, 21

they’re prett y close in that region so we’re just 22

going to pick that CSL that it’s close to as the 23

competitive point. That could be a judgment, and 24

then it would be right here, pretty close to each 25Executive Court Reporters (301) 565

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other. The M3 curve and the amorphous curve don’t 1

intersect until a l ittle bit lower, down here. So 2

that’s the kind of

-- and we will be releasing a 3

tool, as I mentioned earlier, to allow some 4

manipulation of the different steel prices for 5

whatever value people can find in that, and that 6

will obviously influence the inters ection points of 7

these two frontiers. 8

So if someone said, well, I want to look 9

at the case where M3 is a little bit cheaper than 10

the M3 transformers get commensurately cheaper, then 11

the intersection point moves to there. You can see 12

that just the gre en curve moved, and the 13

intersection of selling price walks upwards. 14

So I think people probably have a range of 15

ideas about where materials’ prices are today, and 16

where they might be headed in the future, and so 17

this can allow folks to try it at home and pick 18

their own scenarios and see what the outcomes are. 19

Hopefully, that can be useful. 20

MR. ANDERSON: Rick Anderson, 21

Fayetteville. Is that real data, Brian? 22

MR. COFFEY: This is our current design 23

line five data. 24

MR. ANDERSON: So I want to make s ure I 25Executive Court Reporters (301) 565

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understand what I’m looking at. For an increase in 1

efficiency from 99.45 to say, 99.5, I’m going to pay 2

an additional $10,000 for the same transformer? 3

What I’m buying today? I’m going to pay $10,000 4

more? That doesn’t make any sense to me. From a 5

user

-- from a user standpoint. You’re basically 6

telling me I’m going to get married to this and I 7

have no choice, but to pay another $10,000 for what 8

I’m using today, I don’t get that. 9

PARTICIPANT: (Comment off mic) 10

MR. ANDERSON: That doesn’t ma ke any sense 11

to me, to pay that much more money, $10,000 more, 12

for an increase in efficiency of .05 percent? I’m 13

thinking about the little old lady that I’m serving, 14

that’s going to kill her. 15

MR. PATTERSON: Wes Patterson here, if I 16

may. One of the pro blems that I see in the 17

discussion is we talk about a tiny little change in 18

efficiency, but that tiny little change represents a 19

50 percent reduction in the losses. And I think in 20

the context of the conversation, it would be better 21

if we always looked at the change in loss, rather 22

than the change in the percent efficiency. Because 23

in that example we’re discussing right now, we’re 24

talking about cutting the losses in half. 25Executive Court Reporters (301) 565

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MR. FERNSTROM: Gary Fernstrom from PG&E. 1

I don’t think it’s really either of thes e things. 2

It’s the economic value of the energy savings 3

looking forward into the future. So, you know, 4

whether it’s a half of a percent, or point five 5

percent, or a 50 percent reduction in losses, the 6

question is how much value is there associated with 7

e liminating those losses for your little old lady 8

customer, versus the initial investment. And that’s 9

the question we have to answer. 10

PARTICIPANT: (Comment off mic) 11

MR. FERNSTROM: Yeah, that’s what the life 12

cycle cost analysis is all about. 13

MR. PAR KER: Right. I think that does

-- 14

that’s what their analysis should get at, whether 15

the energy savings down the road justify the 16

increased cost or not, and if the

-- and if it’s 17

excessive

-- it should translate into the little old 18

lady’s electric bill. Y es. 19

MR. SCHOEN: Gerry Schoen, AK Steel. When 20

you look

-- Richard, this is kind of a question for 21

you, but it’s been asked before

-- when you look at 22

a cost escalation of about 40 percent, are you 23

likely going to replace that transformer with a new 24

tran sformer costing much more, or send it out and 25Executive Court Reporters (301) 565

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have it rebuilt and put back into service. 1

MR. PARKER: I’m going to have it 2

rebuilt. 3

MR. SCHOEN: We talked about in one of the 4

earlier meetings about the tipping point between a 5

refurbished decision vers us a new decision. How 6

much more

-- Steve Rosenstock put an excellent paper 7

out showing the cost escalation in transformer 8

efficiency, compliance cost since 2010, that shows 9

transformers have already gone up way above 10

inflation. How much more does that g o before it 11

tips us back into a rebuilt. Because if you move 12

from the two to three percent rebuilt return to 13

service rate, which we have today, to 30, the life 14

cycle cost analysis, it has to reflect that too. At 15

least it should. 16

MR. HIRSCH: Bruce Hirs ch, Baltimore Gas 17

and Electric. Just to add to that, I just want to 18

let everyone know, we’ve reached that point with 19

some designs we’re using now, and the drivers aren’t 20

necessarily the cost, but it is the size and the 21

weight, where we can’t get a transfo rmer to meet the 22

current standards that will fit the area we need to 23

put it in. So what we’re doing now is we’re doing 24

more refurbishing of old transformers for particular 25Executive Court Reporters (301) 565

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lines because that’s the only solution we have 1

today. 2

MR. HYLAND: Mike Hyland wi th APPA. I 3

just want to echo on that. We represent the 4

municipal utilities and we are the most compact, 5

customer

- wise, of all the entities, and we have many 6

of our utilities that are 100 percent

-- 100 percent 7

underground. So they are just vaults and ce rtain 8

pad mounts. So, there’s a huge issue on space. Not 9

only that, we’ve hit the same tipping point with a 10

few of our members where we’ve moved to just 11

refurbishing where we can. You also have to 12

understand that our business model, we are 100 13

percent n on

- profit, so every single dollar is going 14

to be put on the customer. There’s no going to a 15

PUC asking for a rate increase. There’s no profit 16

to be taken from. This is going to the consumer. 17

Every single dollar we talk about here is going to 18

the consum ers and that is a huge issue for us when 19

we’re also being asked to spend our money other 20

places, on the savings per watt, whether it is 21

energy efficiency lighting, we’re talking about the 22

refrigerators. You’re getting to the point of where 23

should we be sp ending our money. 24

MR. PARKER: Aaron. 25Executive Court Reporters (301) 565

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MR. MEYERS: Aaron Meyers. I think it’s a 1

little bit

-- I’m at a loss for a better way to 2

describe this, but deceiving to the American public 3

to have three years ago adopted an efficiency 4

standard which looks at t he payback period based on 5

what was formerly a non

- evaluated transformer, to 6

adopt that standard, and now to look at the new 7

standard as being the baseline without considering 8

the fact that those two payback periods will need to 9

sum. There’s nothing to pr event the Department from 10

getting together two years from now and looking at a 11

payback period from the point of the new efficiency 12

standard, and justifying based on that. 13

So if the payback period two years ago was 14

15 years, and we adopt an efficiency s tandard with 15

another 15 year payback, the old lady that Richard 16

referred to, she’s going to be dead before that ever 17

justifies itself. 18

MR. FERNSTROM: Well, I have a comment on 19

that. Gary Fernstrom again. I’d like to talk about 20

the little old man, beca use I’m close to fitting 21

that model. And yeah, I’ll probably be dead before 22

the 15, 20 year payback occurs, but we’ve got a lot 23

of other things to consider. There are people that 24

are going to continue to live through that period of 25Executive Court Reporters (301) 565

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time, and we are conce rned about energy waste and 1

the economics of all this. 2

MR. PARKER: So these are some of the 3

issues that I think are going to come up when we get 4

down to negotiating the final thing. I’d like to 5

focus here just on the methodology if we could, and 6

make s ure that we have comfort there, and then when 7

we’re talking about what our positions are, all this 8

comes to the fore. 9

Just to clarify, as I understand it, this 10

negotiation takes place within a legal framework 11

that requires DOE to review its energy stan dards and 12

change them

-- or not change them, but at least 13

review them to whether to change them, every six 14

years. And so what’s going into effect now won’t 15

take effect until 2016. We have an issue that legal 16

counsel is talking about with the ... project ab out 17

the flexibility of the complaints they issue. But I 18

think under any scenario you’re looking at quite a 19

delay before these standards actually are

-- take 20

effect, so it’s not coming up

-- it’s not happening 21

right away. 22

Steve, did you want to

-- 23

MR. ROSENSTOCK: Just a quick one, Mr. 24

Parker. With other standards there has been even 25Executive Court Reporters (301) 565

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longer time periods when new standards took the 1

place of older standards, sometimes ten years. Gas 2

furnaces has been almost 20 years, so, you know, 3

when you say that in terms of the appliance 4

rulemaking, six years is not

-- is not that long 5

compared to other products. 6

Also, I want to get back to this graph 7

real quick. I’ll talk about the refurbishment 8

later, but I think part of the issue, and again, 9

there’s all the gra phs and I appreciate this, but I 10

think with some of these metals the lines kind of 11

stop at a certain efficiency levels with certain 12

metals. I mean, for example, there might not be any 13

yellow dots above 99.52, but it kind of looks like 14

the yellow line is g oing further, when on one’s 15

making them. So there could be an issue where 16

you’re doing some of these comparisons and it all 17

depends where they cross over, but there might be 18

some design lines where the lines stop all of a 19

sudden because there’s no designs at a certain 20

efficiency level. So again, just data possible just 21

for analytical purposes. 22

MR. PATTERSON: Sure, John, on Steve’s 23

point, the different grades of steel have physical 24

limitations as to how far they can go in efficiency. 25Executive Court Reporters (301) 565

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So when you examin e this data you’ll see there’s an 1

asymptotic k ick up on each grade of steel at a 2

certain level, that’s what you’re referring to in 3

this yellow dot. All of a sudden it’s going to go 4

to infinity as you approach a certain point, and 5

that’s the characteristic s of the grades of steel. 6

MR. ECKMAN: Just on that point. Because 7

of that kick up, those tend to be high leverage 8

points in the fitting of that linear curve, so the 9

question is how you dealt with that. Was it just 10

fit through the ones where it was phy sically 11

possible to build at that transfer level of 12

efficiency? 13

MR. COFFEY: All I was looking to show 14

here, I mean these are just tangents to the curve. 15

Of course they’re going to change their slope as you 16

move in efficiency, and I was more looking to 17

illustrate the concept than suggest that we would 18

blindly take whatever intersection we found. 19

MR. ECKMAN: Yeah, if you’re just looking 20

at the locus of where the dots all are possible, 21

then the lines are less

-- are far less relevant 22

because of the slo pe being driven by a few points 23

way high, or a few points way low. 24

MR. PARKER: Great. 25Executive Court Reporters (301) 565

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MR. DeLASKI: Andrew DeLaski, ASAP. Thank 1

you for doing this. This is actually a very helpful 2

for us to understand how the different core 3

materials stack up, so to speak. The question I had 4

for you, Brian, is you did a

-- you did a

-- as you 5

were talking it through, I was trying to follow you 6

and at the end you gave a scenario and said, what if 7

steel prices were a little bit lower, and could you 8

run through that ex ample again? 9

MR. COFFEY: Sure. I think we’ve heard 10

considerable concern about what the steel prices are 11

today and what they might be in the future. What I 12

was trying to show here was that the conclusion 13

about which efficiency represented competitivene ss 14

between grain

- oriented and amorphous steels, what we 15

find that efficiency level to be is quite sensitive 16

to our assumptions about what the material prices 17

are. And so the objective of this tool is to allow 18

you, as individuals, to dial in some different 19

scenarios and see what the outcome is. I hope that 20

would have some value, because

-- I mean that’s 21

feedback we heard was that people would like to have 22

this capability, so

-- 23

MR. DeLASKI: Yeah, I think that will be 24

valuable. So that’s a tool that’s n ot yet available 25Executive Court Reporters (301) 565

- 0064 119

but will be soon, is that

-- what’s the status of 1

that? 2

MR. COFFEY: So we have that. I mean 3

we’ve built it. I think we probably just want to 4

glance it over one more time to make sure 5

everything’s working the way that it should be. We 6

just added two more price cases that were slightly 7

less extreme than the ones that we had published 8

previously, so I would say in the very near future 9

we’ll be sending that out and letting people tinker. 10

MR. DeLASKI: Great. 11

MR. ANDERSON: Brian , to W es’ point, can 12

we see the loss improvements

-- 13

MR. PARKER: Richard Anderson. 14

MR. ANDERSON: Richard Anderson, sorry. 15

Can we see the loss improvements, maybe the percent 16

increase versus the efficiency because, you know, 17

for the lay person to see that change in efficiency 18

versus cost doesn’t make any sense, you know. So it 19

would be more helpful to see the improvements in 20

losses versus efficiency. 21

MR. COFFEY: Yeah, I mean there’s a one to 22

one correspondence between efficiency and losses, so 23

we could spend the time remapping this into a 24

different coordinate system. It would just be 25Executive Court Reporters (301) 565

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plotting a different variable, and if the committee 1

thought that were helpful, we could send that out 2

also. 3

MR. ANDERSON: Rick Anderson, Fayetteville 4

PWC. If there’s a one to one relationship, as a 5

user, I can’t stomach a 40 percent increase in cost 6

for a .05 percent increase in efficiency. I can’t 7

stomach that. 8

MR. BALLO: Tim Ballo, Earth Justice. 9

You’re talking about a 40 percent increase in cost, 10

you’re only look ing at three. You’re ignoring the 11

pink line and the yellow line. 12

MR. PARKER: Well, I think what this shows 13

is that for amorphous it’s a pretty flat curve, and 14

for M3 it’s a very steep curve, which I think is 15

what people have been saying all along. I t hink it 16

might help to have losses on the X axis instead of 17

overall efficiency. Greg. 18

MR. COULTER: This is Greg Coulter, Prolec 19

GE. We presented curves of the same data that I 20

think more accurately represents what’s happening, 21

That is not the shape of the curve for M3 that 22

you’re implying. It just takes off like a shot as 23

you go up in efficiency. And I think a more 24

accurate representation is to look at this on what 25Executive Court Reporters (301) 565

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the limits of what these steels can deliver. 1

PARTICIPANT: (comment off mic) 2

MR. C OULTER: I think that’s just a 3

problem with Navigant’s data. Amorphous is not 4

quite the way we showed on our curve, and this does 5

make it somewhat competitive at lower efficiencies. 6

I just think that’s a problem with

-- there is some 7

data point problems. But overall, I think a more 8

adequate way to present this is to show that there’s 9

absolute limits of what these core steels can 10

deliver. And it isn't a line like this, it goes 11

asymptotic at some of these higher efficiencies. 12

PARTICIPANT: ... if you disc uss this, 13

you’ve got to really see what the M3, M2 ... can 14

deliver. 15

MR. HOPKINSON: Phil Hopkinson HVolt. I 16

certainly agree with Greg Coulter. Every once in a 17

while, we agree. And also with Wes’ comments. Once 18

in a while we agree too. But what I would say is 19

that in the report that I have issue that I would 20

like to summarize, I won’t obviously get a chance to 21

go more than that, summarize this afternoon, I have 22

shown what the manufacturers who supplied data gave 23

me in comparison and what the delta price as well as 24

the delta watts going from one efficiency level to 25Executive Court Reporters (301) 565

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the next one, to the next one up and so on. And so 1

that you will be able to see from that what it costs 2

per watt saved to go from one efficiency to another. 3

And I really do think that watts, if it were plotted 4

on this curve, as Wes proposes, is really the right 5

way to look at it, because then you can, in fact, 6

extract directly the difference in selling price for 7

the difference in watts and get the dollars per 8

watt. And now if we compare that against the value 9

of a watt saved, there’s your answers. 10

MR. MEYERS: Let me just reiterate the 11

point that when considering these metals, when you 12

make the switch over or transition to amorphous 13

metal, entirely new equipment is required to 14

assemble those . It’s not like switching from M3 to 15

M2, and I’m not expressing a favor for either one or 16

the other, but if a manufacturer is set up for one 17

or the other, it becomes difficult, and if the 18

entire market is shifted in one direction or the 19

other, most manufa cturers will not have the capital 20

equipment to support that. 21

MR. PARKER: Yeah, I think manufacturing 22

impact is something that will have to be considered 23

and I think we might have a discussion about that 24

either this afternoon or tomorrow morning. I thin k 25Executive Court Reporters (301) 565

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that’s a valid point. 1

All right. So I take it that it’s doable 2

then to express the X axis in terms of losses as 3

opposed to micropercentage gains in efficiency, and 4

can we

-- can we agree then that in terms of the 5

linearity versus the non

- linearity, th is is

-- that 6

really wasn’t your point with this presentation. 7

That’s agreed that it’s non

- linear, and that we’ll 8

work on getting a more accurate shape to the curve 9

in the future

-- future postings. Right. 10

MR. COFFEY: That’s right. 11

MR. PARKER: Stev e, did you want to 12

comment? 13

MR. ROSENSTOCK: Steve Rosenstock, EEI. 14

The only thing I was going to say was, you know, 15

just looking at the data that DOE presented for the 16

same efficiency level, you’re going to have a wide 17

range of losses, so maybe if you want to put a 18

median or average value in there, that’s fine, but, 19

you know, there is

-- at each efficiency level 20

there’s going to be a range of core and coil losses 21

and so it’s not just one number to use if you’re 22

going to do that. So I don’t know how you ’re going 23

to represent it, but maybe a median value, but there 24

are going to be differences for the same rated 25Executive Court Reporters (301) 565

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efficiency level. 1

MR. COFFEY: No, I think there’s

-- there 2

would be a one

- to

- one correlation of efficiency and 3

total losses. The core and coil losses, you’re 4

right, are a different story and if we wish to have 5

that, then we can talk about that too, but I think 6

it’s easy enough to show this same space remapped to 7

a coordinate, and that’s total losses would be a 8

one

- to

- one correlation. 9

PARTICIP ANT: (comment off mic) 10

MR. HOPKINSON: Yeah. Basically if you 11

finally agree on a load, and for medium voltage we 12

have, up to this point, used 50 percent RMS 13

equivalent load, then the load loss gets normalized 14

down to what it would be present at that 50 percent 15

load, the core loss gets added and at peak 16

efficiency core loss equals load loss. So the two 17

of them should be about the same at that measurement 18

point of efficiency. So if we agree this afternoon, 19

when I get a chance to address it, that 50 perc ent 20

load is still the one to use, then the watts in 21

total should track, and Brian was correct on that. 22

DR. SALIVE: Aaron, anything else? 23

MR. MEYERS: My comment was similar to 24

Phil’s, that the load losses would be taken at a 25Executive Court Reporters (301) 565

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quarter of the value, and once you do that, it would 1

track linearly. But that there is a wide range of 2

total losses that could be represented that all 3

amount to the same efficiency value. So it may be 4

better to think about it as an improvement in the 5

inefficiencies, so if you’re at 99.5 percent moving 6

point five percent would be like ten percent 7

improvement or something like that. Yeah, you look 8

at the reduction in inefficiency

-- it’s like a 9

double negative of sorts. 10

MR. BERMAN: Robert Berman, Berman 11

Economics. If we’re goin g to look at specific 12

measuring points for the losses, then it might be a 13

good idea to look at some alternatives as well and 14

see what the implications are. We’ve got

-- we’re 15

heard some comments from a number of the utilities 16

that some of them have loads of

-- in the low to 17

mid

- 30’s, others are more rural utilities probably 18

have even loads as low as the mid

- 20’s. It might be 19

a good idea to see what the effect is of using the 20

50 percent load factor on the actual load factor in 21

the utility. That is to say, instead of a 22

comparison of the load loss divided by four, 23

compared to the loss at the square of the load 24

factor. It gets

-- the difference in savings gets 25Executive Court Reporters (301) 565

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substantial for the lower load factor utilities. 1

MR. PARKER: Yeah, and we’ll be talking 2

about lo ad factors again this afternoon . Let’s hold 3

off on that for now. Okay, I think it’s been 4

helpful. Let’s move on then to the

-- because we’re 5

near the end of our time, past the end of our time 6

actually

-- let’s move on to a quick review of the 7

open

- ended questions from Brian. Thanks. 8

**Review of Open**

**- Ended Questions**  9

MR. COFFEY: Sure. So just to wrap that 10

up really quickly. What we learned was that, the 11

conclusion about which efficiency is competitive is 12

sensitive to your assumptions about materials 13

pr ices. We will be providing a tool for people to 14

dial in their own assumptions. 15

We talked about weight briefly in the last 16

meeting, but we were thinking about it more in 17

weight doesn’t really drive the purchasing 18

decisions, within a certain range, and fu rthermore, 19

actually itself requires an implicit assumption 20

about the relative pricing of the metals. So it 21

doesn’t really solve the problem in our opinion. 22

So the plan here is to seek input on 23

materials prices and have best guess high and low 24

cases and then provide the opportunity to look at 25Executive Court Reporters (301) 565

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their own scenarios and discuss. 1

And that brings us to open questions, or I 2

had a couple of very pointed questions that I saw 3

and I’m going to try to address. 4

CSL and El selection, how is that done? 5

You know, th ere’s not a hard and fast methodology. 6

There’s a general thought to covering the efficiency 7

range evenly to allow some debate about what’s the 8

proper standard. And then when we went from the 9

CSLs to the ELs, which as we’ve said, are 10

functionally identica l, we tried to place them at 11

boundaries of materials so that

-- because we 12

thought that might be where the rubber meets the 13

road, where a lot of the debate was held. So that’s 14

how that was done. 15

Compliance of actively cooled 16

transformers. This has been a question raised by 17

several manufacturers over the years. We had 18

written a memo to DOE , so it’s something that’s not 19

-- it’s not presently spelled out in the standard. 20

The decision was that the intent really wasn’t to 21

cover transformers in their active state of cooling 22

when fans or pumps are engaged, and so compliance 23

would be established at the passively cooled rating. 24

So we’ll be writing that more formally eventually, 25Executive Court Reporters (301) 565

- 0064 128

but that’s just to have a short answer to the 1

question. 2

These next two, I think, are items where 3

probably DOE will need to weigh in and think about 4

what the policy decision is, and that’s compliance 5

of transformers with multiple BIL ratings, and 6

compliance of transformers with multiple primary and 7

secondary windings. And right now the stipulation 8

is that they be tested in the configuration that 9

produces the highest losses, so that’s how 10

compliance is assessed right now, and I think these 11

questions that people have been asking would 12

represent a shift in how compliance was established 13

an d so

-- I’m not giving a direct answer right now 14

but just acknowledging receipt of those and saying 15

that’s something that DOE will think about and give 16

an answer to. 17

MR. PATTERSON: Wes Patterson. The 18

standard doesn’t say they have to be tested at that, 19

they say they must be in compliance with the 20

standard in the worst loss connection. You have two 21

ways to meet compliance, AEDM or test. Right? 22

MR. COFFEY: That's correct. Thanks for 23

that. 24

**Next Steps** 25Executive Court Reporters (301) 565

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So with that, just next steps, and we 1

talked a bout a lot of these already, but I’ve got 2

some action items to work on, and I think some of 3

you also have some areas where we’re looking to you 4

for data and information. So with that, I’m done 5

and I will turn the floor over to Richard and LBL. 6

MR. PARKE R: Any comments or questions on 7

the open

- ended

-- questions on this segment? Steve. 8

MR. ROSENSTOCK: Again, it’s more of a 9

process question. I know that a lot of data has 10

been flying around the last few days, and I know if 11

there’s going to be a revisi on to the engineering 12

analysis, that’s kind of your focus, just in terms 13

of timing and in terms of any updates, you know, the 14

next meeting is scheduled for

-- after this one

-- 15

is scheduled for November 8 th . What kind of time

-- 16

as the analysis gets updat ed, what kind of timing 17

are we looking at? Again, I know, maybe speaking a 18

little ahead, especially as we get into the LCC 19

issues, but in my view I think it would really help 20

all the parties if, you know, if there’s going to be 21

a final update to the analy sis that all parties are 22

able to review it at least several days ahead of the 23

next meeting . Because, you know, this is the first 24

time I saw this presentation. I thought it was 25Executive Court Reporters (301) 565

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really helpful, but having something a little ahead 1

of time could have given a t least a chance to 2

provide even more useful information. So, is there 3

a thought that the next, I’ll say the final 4

iteration of this, just to make it easy for Brian so 5

he doesn’t deal with us forever, would it be 6

possible to get the next iteration finishe d at least 7

several days before the next meeting? 8

MR. RIVEST: Steve, this is Mike Rivest. 9

I think it’s

-- I hate to do this, but it depends on 10

when we get the data and when we stop getting data. 11

At some point

-- so any data we get, we will make 12

every e ffort to use. The likelihood that we can use 13

it for this next revision just increases as we get 14

it earlier. So to get you something for the next 15

meeting, realistically, if we get any data past the 16

end of next week, for example, it’s just going to be 17

hard . Because after we’re done with the 18

engineering, we have to give it over to LBL to do 19

some LCC, and it’s really the LCC that shows the 20

impact of any decisions. 21

MR. PARKER: Well that was why I sort of 22

arbitrarily and perhaps optimistically put in 23

Novemb er 2 nd as the time for the analysis to come 24

back, which would mean getting the data to Navigant 25Executive Court Reporters (301) 565

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and LBL, of course, well in advance of that. I 1

think we do need to have that discussion, because

-- 2

MR. RIVEST: On the one hand, I don’t want 3

to discourage people from giving data later if they 4

need more time. 5

MR. PARKER: Yeah, but there is a time 6

value to data. 7

MR. RIVEST: Just want to make it into the 8

next round. 9

MR. PARKER: And it’s going to get 10

discounted if it comes in

-- at a high discount rate 11

if it comes in after a point at which we can 12

actually take it on board. 13

MR. CYMBALSKY: John Cymbalsky, DOE. So 14

from DOE’s point of view, we’re still on the hook 15

for a NOPR to be published by February 1 st

MR. ROSENSTOCK: Steve Rosenstock, EEI. 24 , so if 16

things get bogged down in this process, based on 17

analysis or whatever else, we will still move 18

forward with what we think is our best data that 19

have been provided by you guys, and we will still 20

write a NOPR in the meantime, because we have to. 21

So I think we have to lock down the analysis in 22

sho rt order and really move this process forward. 23

MR. PARKER: Excuse me, Steve, I think 25Executive Court Reporters (301) 565

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Andrew had his hand up. 1

MR. DeLASKI: So, Brian, you said you had 2

a number of action items and to do’s coming out of 3

this, and things that you’re hoping to get from 4

manufacturers. Maybe after lunch will make sense 5

for you to come back and just tell us what those 6

are. A nice summary from this morning, I think 7

would help to get the data that you need, so people 8

know what you’ re expecting of them. Maybe you 9

already know this because you’re the manufacturers 10

and I’m not, maybe you followed all that, but maybe 11

coming after lunch that would be helpful to have 12

that. What are those to do’s? What are you 13

expecting people to give y ou? So that we have a 14

real specific list. 15

MR. RIVEST: Mike Rivest. I think the 16

open item from this morning is the product classes 17

that we left open for liquids. I mean, that can 18

make

-- that can be a lot of analysis, so if we 19

decide to break out the poles, the pads, the vaults 20

-- I don’t think we had resolution on that, if that 21

was going to be creating new product classes or not. 22

So that’s a decision to make today, I hope. 23

MR. PARKER: Brian tells me he thinks he 24

can do, over lunch, we’ll try to ge t him some time 25Executive Court Reporters (301) 565

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to eat lunch as well, but do a short list of action 1

items and we do need to set a timeline for getting 2

your data to them, beyond which we just won’t be 3

able to accept it because, you know, it’s gone on 4

long enough, I think. Aaron. 5

MR. M EYERS: Aaron Meyers. My question is 6

really to John Cymbalsky. Has the February 1 st

MR. CYMBALSKY: Yes, I think I saw an e

10

mail that said that we were good for Februa ry 1 date

7

been decided by the courts? Is that

-- I haven’t 8

heard any final date on that. 9

st

MR. MEYERS: Okay. Thank you. 12 . 11

MR. CYMBALSKY: Given we’re way past 13

October 1 st

MR. PARKER: Steve, one, very quickly. 15 . 14

MR. ROSENSTOCK: Well, just, and again, I 16

know there’s February 1 st

MR. PARKER: Okay. With that in mind, 20

let’s break for lunch. It’s almost one o’clock now, 21

we’ll plan on reconvening here at two. 22 , but it’s also

-- it’s a 17

NOPR or determination that the current standard can 18

stay in place. Thank you. 19

(Whereupon, at 12:51 p.m., the meet ing in 23

the above captioned matter w as adjourned for lunch 24

recess , to reconvene at 2:00 p .m.) 25

26Executive Court Reporters (301) 565

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2:04 p.m. 2 AFTERNOON SESSION 1

MR. PARKER: Hi everyone. Welcome back 3

from lunch. Hope you enjoyed it. Why don’t we get 4

started. Sorry, we’re getting started again a few 5

minutes late by my best resolution to get started on 6

time. We have lots to cover this afternoon, 7

grateful to have Chris Bolduc from Lawrence Berkeley 8

Labs to present basically how they do their life 9

cycle analysis, the key inputs into that analysis, 10

and I think, and I’m hoping t hat a lot of what he 11

says will help everybody get on the same page with 12

what we need to do at this meeting, which is to 13

indicate what changes, if any, need to be done to 14

the analysis and what inputs that are not currently 15

resolved would need to be as they go forward. 16

So without further ado, let me turn it 17

over to Chris. If we could have everybody’s 18

attention please around the table, I’d appreciate 19

it. And let’s try to kept the questions at this 20

stage limited to clarifying questions, because I 21

think a lo t of this stuff fits together, and rather 22

than jump in, please kind of hold your questions 23

unless it’s a short, clarifying question. We’ll try 24

to get through the presentation and then we’ll come 25Executive Court Reporters (301) 565

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back and look at the individual pieces of it and see 1

where w e need to go from there. Okay. Go ahead, 2

Chris. Thanks. 3

**LBL Presentation** 4

MR. BOLDUC: Thank you. Good afternoon. 5

My name is Christopher Bolduc from Laurence Berkeley 6

National Lab. I’m going to be going over some of 7

the inputs to the LCC that have been causing 8

confusion or there’s some question surrounding. 9

**Transformer Loading** 10

Without further ado, the first input that 11

we want to look at is transformer loading. In 12

particular we define transformer loading with three 13

variables: load factor, the RMS load on the 14

transformer, and the loss factor. These have been 15

gone over in previous meetings several times. 16

What I would like to focus on right now is 17

the RMS load. And so in this next slide shows the 18

RMS loads that we used for design line 1. And as 19

y ou can see, it’s a distribution, and it’s centered 20

around 34 percent is the mean value. I know there’s 21

been a lot of misconception about the LCC model 22

surrounding the RMS load. Some pe o ple think it’s a 23

straight single value of 50 percent. I believe 45 24

percent is the number that’s been bandied around. 25Executive Court Reporters (301) 565

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For the liquid immersed transformers, we 1

try to load the transformer at around 33 to 35 2

percent. It varies a little bit because it’s a 3

Monteocarlo (ph) simulation. There’s a slight rant 4

(ph) nature to the load, but the load shape that we 5

run through the LCC is as shown on the screen here. 6

PARTICIPANT: (Question off mic) 7

MR. BOLDUC: Thirty

- four percent is the 8

number that was used in the 2007 rule also so there 9

has been buy

- in through stakeholdering . Also we’ve 10

heard from several utilities over the course of the 11

rulemaking that they tend to load transformers in 12

the 30 to 35 percent range. Naturally for rural co

13

ops we drop this by 25 percent, so we’re loading in 14

the high 20’s. 15

MR. HOPKINSON: (Qu estion off mic) 16

MR. BOLDUC: That's correct. 17

MR. HOPKINSON: And the basis for the RMS 18

-- there’s no metering on RMS. How do you get to it 19

as a utility? 20

MR. BOLDUC: I’m going to redirect that to 21

Katy. Can you repeat the question? 22

MR. HOPKINSON : Yeah, Kate, how do you get 23

to RMS equivalent load? Is it just the model or is 24

it something that somebody actually has recorded 25Executive Court Reporters (301) 565

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information on over a lengthy period of time and 1

then computed it? 2

MS. COUGHLIN: Are you asking how the 3

utilities arrived at the figure of 30 to 35 percent? 4

MR. HOPKINSON: Yes. 5

MS. COUGHLIN: I don’t know. That’s a 6

metering question, so that’s not something that we 7

have information on. Those are just comments that 8

were submitted. 9

MR. HOPKINSON: Steve, do you know 10

an ything about that? 11

MR. ANDERSON: Chris? Rick Anderson, 12

Fayetteville PWC. We have some information dating 13

back into the 90s that generally says the load 14

factor is in the order of 25 percent. Okay. And I 15

saw your maximum there is 56 percent. Is tha t the 16

peak on the transformer? 17

MR. BOLDUC: No, that’s not the peak on 18

the transformer. 19

MR. ANDERSON: Okay. We’ve got data and, 20

you know, several of us have data. We need to give 21

that to you? 22

MR. BOLDUC: We would appreciate it and we 23

could hold i t in confidence, okay. 24

MR. ANDERSON: The other thing is is that 25Executive Court Reporters (301) 565

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you’re looking at a 50 KVA pad, I guess. 1

MR. BOLDUC: In this example, yes. 2

MR. ANDERSON: And what we also need to 3

recognize is that that’s generally going to be the 4

single phase resid ential application. 5

MR. BOLDUC: Uh

- huh (yes.) 6

MR. ANDERSON: And that pad mounts, you’re 7

going to put those in a subdivision where 8

everything’s nice and compact, and you can get 9

numerous services, say five, or for one KVA 10

transformer. However, on an overhead transformer in 11

a rural application, it’s really going to be like 12

the transformer is dedicated solely to that one 13

individual service. So as you go through this, I’d 14

like for you to keep in mind that you have, for pad 15

mount applications, you’re tal king more so about a 16

subdivision. When you talk about overhead 17

applications you’re really looking at more of a 18

rural application. 19

The other thing is is that when you start 20

to get over 50 KVA on an overhead transformer, you 21

start to bank them for three p hase. So you may have 22

three 75’s serving a commercial application, and 23

that load factor changes. In other words, we don’t 24

load a rural overhead application the same way we 25Executive Court Reporters (301) 565

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serve a three phase commercial service. And that’s 1

going to influence the load fa ctor and the maximum 2

peak that the transformer sees. 3

So, you know, a lot of the discussion 4

earlier has centered around the transformer 5

manufacturers and how they construct it. We’re 6

users. We use it. We’re married to it. We buy it 7

and we live with it for 30 years, and generally 8

speaking we’re not going to buy a dump truck if we 9

can do it with a golf cart. 10

MR. BOLDUC: Understood. We’ve also heard 11

anecdotal evidence that larger transformers would be 12

loaded at a higher RMS load. If anybody on the 13

committee could send us data or corroborate that, we 14

would appreciate it. We’d also like an idea of how 15

much the magnitude of that difference. It would be 16

helpful. Any more questions? 17

MR. SMITH: Just a comment on that last 18

statement. I think all you ’re going to get is 19

anecdotal evidence on that. It sounds reasonable, 20

but I’m not sure there’s a way to verify that. 21

MR. BOLDUC: All right. Thank you. 22

Steve. 23

MR. ROSENSTOCK: Steve Rosenstock, EEI. A 24

clarification. On this curve, this loading cur ve, 25Executive Court Reporters (301) 565

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the distribution, was that based on I’ll say kind of 1

a classic bell curve type of distribution, or is 2

this based on some of the utility data that kind of 3

came in and that showed that it really, you know, 4

I’m just kind of curious about the shape of the 5

curve in terms of

-- 6

MR. BOLDUC: We’ve made no effort to shape 7

the curve. I got it based on utility data. 8

MS. COUGHLIN: (off mic) 9

MR. ROSENSTOCK: It’s model. 10

MR. BOLDUC: I’m sorry if people didn’t 11

hear that, it’s simply modeled output. 12

MR. R OSENSTOCK: Thank you. 13

MR. WINDER: Chris, question on what your 14

meaning is for the maximum of 56 percent and a 15

minimum of 17. And then is this your model that you 16

apply on a long

- term basis like every year, this is 17

the kind of model that you’re using f or that whole 18

year, for that long of a period? 19

MR. BOLDUC: This would be

-- yes, this 20

would be the model that we use for the life of the 21

transformer. 22

MR. HOPKINSON: Phil Hop k inson, HVolt. 23

Question for you on peak load with cold load pickup. 24

If I loo k at my own residence, my peak load could be 25Executive Court Reporters (301) 565

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30 KVA. MY RMS equivalent is around eight KVA, and 1

my average is about 3.65 KVA on a yearly basis. So 2

if the peak load, with the cold load pick up, and if 3

my neighbors are in the same boat where we lose 4

power from a storm or something, turn it back on, 5

everything in the house wants power. The 6

regulation, impedance drop and regulation is going 7

to be huge if we have a transformer not designed for 8

a robust winding that is part of it. Is that any 9

consideration, t hat is, is regulation and impedance 10

any consideration in your work? 11

MR. BOLDUC: No. 12

MR. HOPKINSON: It ought to be. 13

MR. BOLDUC: Okay. Katie Coughlin has a 14

comment. 15

MS. COUGHLIN: I just wanted to emphasize 16

that this is a distribution, so we ha ve in the LCC 17

there are 10,000 transformers simulated. Each 18

simulation has its own individual RMS load. In 19

fact, what happens in the LCC is somewhat more 20

complicated. There’s a simulation of the load at a 21

higher time resolution, an annual, and there’s a 22

correlation of loads with electricity prices. So 23

what you’re looking at here is simply an output of 24

the simulation model that demonstrates that for this 25Executive Court Reporters (301) 565

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particular design line, these are the RMS average 1

over the year that ended up being selected. But th e 2

calculation is not just based on an RMS load, and 3

when you look at a different design line, it will be 4

selecting from a different customer base. We might 5

be using different assumptions about the

-- we have 6

different simulation models for residential ver sus 7

commercial installations of liquid immersed 8

transformers. So you’ll actually see a different 9

distribution for each design line. 10

MR. WINDER: Still a question that hasn’t 11

been answered about the maximum you said 50 percent 12

and the minimum 17. Did th at get answered? 13

MR. BOLDUC: No. 14

MR. WINDER: Oh, Ken Winder, NRECA. 15

MS. COUGHLIN: What they represent is the 16

-- for this design line, the highest RMS load in 17

that ensemble of simulations was 56 percent, and the 18

lowest was 17 percent. 19

MR. HOPKINS ON: (off mic) I would suggest 20

that it goes much higher. Every transformer I’ve ... 21

with on a residential system certainly goes to more 22

than 100 percent of nameplate load for cold load 23

pickup, and those, oh, to the range of 70 percent on 24

peaks on a regular basis. I’ve never seen anything 25Executive Court Reporters (301) 565

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where the peak alone never went above 56 percent. I 1

just think that’s

-- 2

MS. COUGHLIN: This is RMS. This is not 3

peak. This is RMS. 4

MR. BOLDUC: Yes, we have a separate

-- 5

we’ll be showing a separate histogram of pea k loads. 6

Wes. 7

MR. PATTERSON: Wes Patterson. When you 8

say RMS, over what time period are you talking 9

about? 10

MR. BOLDUC: Be one year. 11

MR. PATTERSON: So you have a transformer 12

somewhere in your data set that you’re assuming is 13

loaded 24 hour day at 56 percent load. 14

MR. BOLDUC: Over a year, a calendar year. 15

8760. 16

MR. BOLDUC: Exactly. 17

MR. PATTERSON: Okay. Thank you. 18

MR. BOLDUC: What we were hoping for is 19

some of the utility reps could comment. 20

MR. ECKMAN: Can I clarify that, because I 21

don’t think that’s what you do, Katie. I mean you 22

have a transformer that has a load profile that’s 23

given to it that gets a varying load over the course 24

of a year, not a fixed load factor over the course 25Executive Court Reporters (301) 565

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of the year. It varies by day or hour, I don’t k now 1

what the time increments are. 2

MS. COUGHLIN: Right. And then

-- 3

MR. ECKMAN: But the RMS

-- 4

MR. PATTERSON: And the RMS equivalent is 5

17 percent

-- 6

MR. ECKMAN:

-- over the course of the 7

entire year, but not at any given

-- 8

MR. PATTERSON: R ight, but it cycles up 9

and down, but the RMS equivalent for a year, low end 10

is 17, high end is 56, and it’s got that shape. 11

MR. ANDERSON: Question. Chris, I guess 12

for Katie. The 10,000 trials

-- I’m sorry. 13

MR. PARKER: I’m just giving your name. 14

MR. ANDERSON: I’m sorry, Rick Anderson, 15

Fayetteville PWC. The 10,000 trials, where did you 16

get that from? I mean, did you just make that up or 17

-- I don’t mean to be a wise guy, where did you get 18

the 10,000 trials from? Did you

-- you didn’t have 19

utilit y metered data, or you just kind of figured 20

that’s what happened, or how did you get those 21

trials? And the reason why I ask, Katie, is because 22

I mean we have 15 minute demand interval data, so 23

I’m curious was that real or was it fabricated, for 24

lack of a better term? 25Executive Court Reporters (301) 565

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MS. COUGHLIN: Okay. So it’s

-- what we 1

are using, we have hourly building data, so we’re 2

using hourly building load shapes as a proxy for 3

transformer load shapes. And so the statistical 4

analysis begins with hourly building data for a few 5

thousand year

- long records. And we also

-- we’ve 6

developed a method for correlating transformer loads 7

with an aggregate system load. So if you take 100 8

hourly loads and add them together, and that’s your 9

sort of proxy as the system load, then we correlat e 10

the individual transformer loads with the local 11

system load and we use FERC Form 714 data for hourly 12

system loads to deal with sort of geographic 13

variation and things like weather effects that may 14

af f ect the kind of overall level of loading. 15

The model ’s built out of as much data as 16

we can find, and if you actually have transformer 17

reader loads, we’d be very interested in seeing 18

those to compare those statistics. Because again, I 19

want to emphasize that the LCC really ends up being 20

dependent only on cer tain statistical measures of 21

these loads, and they may not end up looking 22

terribly different from what we already have, and 23

that’s something that we can check quite quickly if 24

we can get hold of the data. 25Executive Court Reporters (301) 565

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MR. PARKER: So just for my benefit, what 1

data pr ecisely would you be looking for then, and by 2

when? 3

MS. COUGHLIN: We’d be looking for hourly 4

metered transformer loads. 5

MR. ANDERSON: I think it’s fair to say 6

that the utilities, collectively, need to give that 7

to you, but I think what you’re going t o see is 8

different load curves for different applications, 9

you know, commercial, industrial, three

- phase pads, 10

single

- phase pads, single

- phase poles, up to a 11

certain KVA, and then it’s going to become a 12

commercial application where it’ll probably look 13

more like a three

- phase pad. But it sounds like you 14

tried to back into this load shape, based on the 15

FERC forms, and that

-- much of this is not actual 16

load data. 17

MS. COUGHLIN: Right. We do have

-- with 18

the building data we do have residential and 19

commerc ial buildings and we have developed the 20

curves separately from that, but yeah, so we’ve got 21

building data and we’ve got FERC data. That’s 22

really all we have at this point. 23

MR. HOPKINSON: Phil Hopkinson, HVolt. 24

With electric vehicle charging it’s been proposed 25Executive Court Reporters (301) 565

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that the full charge level would be about 40 1

kilowatt hours. If you have to put that on, you 2

know, it’s different load cycles, 8 KVA while the 3

charging is taking place is assumed to be what most 4

people would do, but we’re just sitting here looki ng 5

at the Nissan Leaf that now is set up for a rapid 6

charge, so it will charge in ten minutes. Well, do 7

that calculation and you’ll see that the 8 KVA goes 8

a whole lot higher. And of course, impedance 9

regulation and the impact on temperature rise and 10

los ses all come hand in hand. 11

MR. ROSENSTOCK: Steve Rosenstock, EEI. 12

With the electric vehicles I know that effect will 13

be discussed later. The charging rate is really 14

going to depend on the vehicle and what the customer 15

chooses. Vehicles will be able t o charge at 120 16

volts, so 1.0, 1.4 KW. Level two chargers, they’re 17

either going to be around 3.3 KW or 6.6 KW, based on 18

SAE J1772. You’re talking about the Nissan, some of 19

those quick chargers, based on the charger mount 20

system, yes, they’re going to be 4 0 or 50 KW, but 21

there’s

-- they’re going to be in commercial 22

applications, they’re not going to be in residential 23

applications. So again, the vehicles could have an 24

impact on some of this, but again, they might not. 25Executive Court Reporters (301) 565

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And again, that’s

-- I don’t know if t hey’re really 1

going to play a big role in some of this. And also, 2

you also have to remember about all the other 3

appliance centers have gone to effect that lower all 4

the existing loads, clothes washers, dishwashers, 5

air conditioners, et cetera, TV sets wit h air energy 6

star, so there could be a balancing out based on

-- 7

MR. PARKER: I hate to be a killjoy, but 8

we have to recall that we do have a timeframe for 9

this rulemaking, and while it would be nice to come 10

up with more data about how electric vehicles and 11

charging will affect future demand growth and effect 12

loading factors, we really need to be focusing our 13

attention now on coming up with a closed dataset 14

that can be used for doing a final analysis that 15

will be ready in the next couple of weeks. 16

So I hope that, you know, we’ve had a long 17

time to come forward with this data, but we are now 18

at the point where we actually have to start 19

producing results. So we need to start thinking 20

about what can we do, what is the most efficient way 21

to use the time a vailable, to use the resources 22

available, to use the data that we have. If a 23

limited amount of data can be used to generate a 24

single offset or supplemental what have you, that 25Executive Court Reporters (301) 565

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will apply a simple corrective, that’s fine. But I 1

don’t think that we can be in a position now of sort 2

of fundamentally redoing the analysis based on new 3

data. And remember also that we’re in the business 4

of creating standards for a design line, you know, 5

regardless of the application. There’s not really 6

the flexibility, as we he ard from Dan Cohen in the 7

prior meeting, there’s not really the ability to say 8

we’re going to have one efficiency level for design 9

line one going into this use, and another efficiency 10

level for design line one going into another use. 11

You have to look at a ll of the various uses and come 12

up with the right fit for that design line overall. 13

And that’s just the constraint of law. It’s also a 14

practical constraint. So I hope that helps us keep 15

focused. 16

MR. ROSENSTOCK: But, Mr. Parker, Steve 17

Rosenstock, but t his morning there was going to be a 18

little bit of a breakout for different design lines 19

if we break it out, pad versus pole, versus network. 20

There is going to be a little bit of split

- up based 21

on some of the transformer application. Maybe not 22

end

- use loa d, but based on application. 23

MR. PARKER: It’s going to have to be 24

based up physical characteristics of the product, 25Executive Court Reporters (301) 565

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that’s what we discussed with network involved 1

transformers, that

-- we’ll see first if there’s a 2

requirement for a separate break

- out ba sed upon 3

their price versus efficiency performance, the 4

margin, but the main thing is that there has to be 5

some kind of a physical distinction between the 6

network involved on the one hand and the regular on 7

the other hand, or else you don’t have basis for 8

creating a separate equipment class. Andrew. 9

MR. DeLASKI: I’ll be brief. From the 10

conversation from this morning, it strikes me that 11

Chris has just presented the RMS load. The data 12

that LBL has put together based on, as Katie 13

described, substantial b uilding load data and the 14

FERC forms. I’ve heard Richard say he’s got some 15

data, he’s going to share with the consultant. 16

That’s one utility, that’s one set of circumstances. 17

Hopefully other utilities will share data as well. 18

And then the analyst will determine how does that 19

influence what the assumptions are. So I wonder if 20

we can move on from the RMS load. I think Chris has 21

other topics for us to cover. Hopefully we’ll get 22

data from more than one utility. 23

MR. PARKER: Well, I just don’t know if 24

g etting data from the utilities around the table 25Executive Court Reporters (301) 565

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will be enough to be a fair representation of the 1

whole industry, because remember, this is a group 2

that is

-- that we’re creating a standard for 3

industry, not just for utilities around the table. 4

MR. DeLAS KI: Right. And I also think, no, 5

Richard said his numbers make up about 25 percent 6

for this particular design line, which seems to me 7

is within that distribution. I’m not sure we’re 8

going to see a whole lot of variation. I think the 9

distribution may be confirmed, it may not be 10

confirmed, but the thing is just get the data or we 11

can talk all day long here, but Chuck’s got data. 12

He’s a big utility. Let’s have the utility submit 13

the data and see how it shakes out. 14

MR. MEYERS: Aaron Meyers, Cooper Power

. 15

We’ve heard some testimony or conversation about 16

loading and some speculation as to the effects of 17

electric vehicles on loading as we go forward. The 18

charter of this subcommittee is to do what’s right 19

by the United States public, and when we’re 20

conside ring a payback period of 30 years, we really 21

need to consider some of the changes that will occur 22

over that time period. And my question for the 23

committee is what information is needed in order to 24

consider that? Obviously, vehicle manufacturers 25Executive Court Reporters (301) 565

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have put together business cases and so forth to 1

invest money in the growth of electric vehicles and 2

they have some sales forecast around that. Is that 3

what’s required, or is loading as a topic not up for 4

debate? Should it stay what it is now or are we 5

going to s ubmit data and then have that open for 6

being changed in the future? If that is the case, 7

then I would agree with Richard that data from those 8

participating around the table is probably not 9

sufficient to arrive at a conclusion. It’s probably 10

good informat ion, but to make a standard, I would 11

argue that it’s probably not sufficient. 12

MR. ANDERSON: Well, to your point, I 13

don’t think much about it, Aaron, that’s voodoo to 14

me. We’ve got real data and I think

-- I don’t know 15

if it’s possible for the transform er manufacturers, 16

you know, they’re given A and B factors, and really 17

what we’re talking about here in particular are B 18

factors. Now everybody’s cost to energy varies, and 19

if you can possibly find out from your customers 20

what their costs are, then you can actually back 21

into the load factor and the peak. You could 22

reverse engineer it, if you knew what their actual 23

costs were in the calculation. Then that would be 24

true indicative of what the utilities’ practices are 25Executive Court Reporters (301) 565

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when it comes to loading transformers. 1

MR. PARKER: Okay. So why don’t we say 2

then that the utilities around the table will work 3

with Chris over the next few days, basically

-- 4

excuse me Bob

-- and supply your data. Chris, can 5

you do a quick run to see if whatever data they have 6

makes a diff erence and just give us a ground true? 7

MR. BOLDUC: We would compare the 8

submitted data against our model and then you’d use 9

the data to calibrate, is essentially what we’d do. 10

So yes, any data, as we’ve maintained since the 11

preliminary analysis, would be welcomed and used., 12

would be welcomed and used. 13

MR. PARKER: Okay. Great. Bob, we’re 14

going to have to move on, sorry. Wes. 15

MR. PATTERSON: Wes Patterson. Do we have 16

a different chart for each design line or is it the 17

same chart for all design li nes? 18

MR. BOLDUC: They differ slightly, 19

depending on design lines. 20

MR. PATTERSON: But they basically look 21

like that? 22

MR. BOLDUC: Essentially they do have the 23

same shape. I’m going to show you design line

-- 24

the slide for design line 12 next. 25Executive Court Reporters (301) 565

- 0064 154

As you can see we’ve modeled this slightly 1

higher load. It’s a much larger transformer. I 2

don’t have the mean lines on the graph, I’m sorry 3

about that, but. 4

MR. PATTERSON: Chris, your source for 5

this information was the same data set for the 6

liquids? Th is is a dry. 7

MR. BOLDUC: The source for this dataset 8

were building surveys. No, it was the same dataset. 9

MS. COUGHLIN: This is Katie Coughlin, 10

LBL. No, the quick answer is no, it’s a different 11

dataset, because these are mostly transformers 12

installe d in buildings, so we’re not relying so much 13

on utility data. This dataset is a combination of 14

the hourly building loads that we have, which are a 15

small set essentially, and information from the CBEC 16

surveys, which give a much broader representation of 17

th e building population. 18

**Transformer Lifetime** 19

MR. BOLDUC: Thank you. On this next 20

slide , the next issue I’d like to address is 21

transformer lifetime. The analysis currently uses 22

an average transformer lifetime of 32 years, with 23

the decay added on to it o f 0.5 percent per year 24

after year 15 for corrosive failure or lightning 25Executive Court Reporters (301) 565

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strikes in the field. I just wanted to show you the 1

distribution. It’s not a fixed 32 year lifetime. 2

It’s a distribution of lifetimes that centers on 32. 3

I know on the e

- mail ther e’s been a little 4

discussion about using EEI’s number of 21 years. 5

I’ve read the article. I’ve read the standard from 6

EEI. It’s a document that’s based on transformer 7

installation lifetime. The EEI article or document 8

policy goes on to say that it’s no t

-- 9

MR. MILLURE: Chris, it’s IEEE’s. 10

MR. BOLDUC: Thanks. Sorry. A little 11

nervous, thank you. It also goes on to say it’s not 12

about transformer lifetime, and we believe the 21 13

years is an inappropriate lifetime to use in the 14

analysis. 15

MR. ANDERS ON: Excuse me, sorry. Rick 16

Anderson, so I’m not to be a wiseguy again, Chris, 17

but you don’t believe what the IEEE says is what you 18

said. So you’ve got all these engineers who live 19

with this stuff and you just don’t buy it. 20

MR. BOLDUC: No, I’m not say ing that I 21

don’t buy it. I’m saying that the analysis that was 22

done to come up with the 21 years is different than 23

the analysis

-- is different than I believe what 24

you’ll see in the field. 25Executive Court Reporters (301) 565

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MS. COUGHLIN: The number in the IEEE is

- 1

- it’s kind of a des ign specification. It’s 2

actually

-- it’s a definition based on certain 3

assumptions about how the design functions at full 4

load. So it’s not a measurement in any sense of how 5

a transformer lifetime

-- what an expected 6

transformer lifetime in the field wou ld be. It’s 7

just a different

-- it’s a different specification. 8

MR. CYMBALSKY: Rick, didn’t you say we 9

have to live with these things for 30 years? 10

MR. SAMPAT: Mahesh P. Sampat
, EMS 11

Consulting . The IEEE document they are describing 12

is basically a t hermal life of an insulation. If 13

transformer is loaded

-- basically what the document 14

says is that if insulation is handling 105 degrees 15

Centigrade, how long that insulation would last. 16

PARTICIPANT: Talking about loss of life. 17

MR. SAMPAT: Loss of li fe, and all your 18

loading data then derives after that. So

-- and 19

there is a five

- to

- one factor, so for varying 20

degrees, they look at when the insulation life ends, 21

then have a factor of five

- to

- one safety factor, and 22

works out to be 21 years or whatever t hat they are 23

describing. But it is dealing with the insulation 24

life, okay, and at 105 degrees Centigrade. 25Executive Court Reporters (301) 565

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MR. HOPKINSON: Phil Hopkinson, HVolt. 1

But the question is, what are the utilities using to 2

amortize transformers right now? 3

MR. ANDERSON: Rick Anderson, Fayetteville 4

PWC. Utilities typically use 30 year book life. 5

MR. FERNSTROM: Can I add something? This 6

is Gary from PG&E representing the California 7

utilities. Our transformers last 40, 50 years. And 8

because of the current economic situati on, we’re 9

typically not replacing them unless they burn out. 10

MR. PARKER: Bob. 11

MR. SMITH: This is Bob Smith, Federal 12

Pacific. One of the things that I think you’re 13

referring to and where you’re coming up with the 21 14

years is the IEEE loading guides. I’m not familiar 15

with the liquid IEEE document, but for the dry type 16

the IEEE C5796 basically says if a transformer’s 17

loaded at a

-- a dry type transformer is loaded at 18

main plate around the clock, it’s thermal life 19

expectancy is 20 years, 20 years if it’ s a 150 20

degree rise transformer. If it were a 115 degree 21

rise transformer, that calculation becomes 338 22

years. If it were an 80 degree rise transformer, it 23

comes out to be roughly 9100 years. 24

The point I’m trying to make is that with 25Executive Court Reporters (301) 565

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these transformers being so lightly loaded, they’re 1

going to last a lot longer than 20 years. 2

MR. PARKER: Steve. 3

MR. ROSENSTOCK: Just a quick one. 4

Someone asked about amortizing. In the past, it 5

used to be that, as far as I know, at least investor 6

utilities would am ortize over 30 years, that was 7

federal law. Several years ago, the law changed 8

that transmission industry assets can now be 9

depreciated over 15 years

-- as a reference point 10

for people. Thank you. 11

MR. PARKER: The tax code is always the 12

tax code. 13

MR. ROSENSTOCK: Just as a point of 14

reference. 15

MR. MEYERS: Thanks, Steve. Aaron Meyers, 16

Cooper Power systems. I would contest that it’s not 17

the insulation system and not the core coil that 18

degrades beyond 20 years, but it’s the tank instead. 19

So I’ve bee n on a pad replacement here within the 20

last two months, and it was not the core coil that 21

failed, it was not the insulation system that 22

failed, they were replacing it because the tank was 23

rusting, the bushings were leaking, and that 24

represents a safety con cern out in the field. 25Executive Court Reporters (301) 565

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MR. HOPKINSON: How many years out? 1

MR. MEYERS: How many years out was what? 2

MR. BOLDUC: How old was the transformer? 3

MR. MEYERS: That one was a 1972 unit. 4

MR. BOLDUC: All right. Thirty

- nine 5

years. So maybe we should increase our lifetime? 6

MR. PARKER: We need to get moving. I 7

don’t hear around the table a strong basis for 8

disagreeing with their lifetime median, right. 9

Gary. 10

MR. FERNSTROM: Gary from PG&E again. 11

Responding to your point about the tank, yes, alon g 12

the California coast, we see corrosion and that’s 13

probably the principal contributor. However, 14

looking across the entire country, only two edges, 15

slivers, are coastal and we don’t get salty fog and 16

corrosion through the rest of our system. So the 17

trans formers do last a long time, and I think DOE’s 18

analysis ought to contemplate a longer life. 19

MR. PARKER: Okay. 20

MR. MEYERS: Aaron, Cooper. Is there 21

anyone

-- a lot of this is perception, and 22

sometimes perception is swayed by recent experience, 23

and so I’m wondering, do any of the utilities have 24

real data as far as replacement lifetime and so 25Executive Court Reporters (301) 565

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forth that could be brought forth? Because we have 1

-- it doesn’t apply in this case because it was not 2

for the United States, but for one of our 3

international c ustomers, has data which suggests 4

that their replacement is 16 years. That may be a 5

function of their system, it may not be. But rather 6

than base this on perception, it would be better to 7

base it on real data that’s collected and can be 8

statistically eva luated. 9

MR. ANDERSON: Rick Anderson, Fayetteville 10

PWC. One thing we did do, Aaron, I think everybody 11

did, was

-- we had to replace all our PCB oil 12

transformers and anything that was manufactured 13

prior to ’78 had to come out, so all that stuff was 14

repl aced, whether it was good or bad, and so now 15

we’re just beginning to get to that 30 year point. 16

So whether they last 40 years, we really don’t know, 17

because we were supposed to change out all the PCB 18

oil transformers, what, no later than 1978, or 19

that’s w hen they changed manufacturing. 20

MR. PARKER: Andrew. 21

MR. DeLASKI: It just strikes me that you 22

got a lot of utility around the table here, a lot of 23

expertise, and I don’t hear anybody saying less than 24

30 years. I just, you know, if anything, the 25Executive Court Reporters (301) 565

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exper ience of the folks around this table seems to 1

indicate that may be the bottom of the range. I 2

mean you got data from the transformers you replaced 3

30 years ago, and now you’re starting to learn 4

what’s happened with those transformers. You’re 5

saying 40 or 50 years. I don’t hear anybody else 6

who’s actual utilities saying it’s shorter than 7

that, or shorter than the 30. Again, someone’s 8

grasping for straws here. I think we should move 9

on. 10

MR. PARKER: Let’s move on. Thank you. 11

MR. WINDER: Ken Winder, NRECA. One 12

question is when you look at the life from your 13

studies and at 34 years, let’s say that we have one 14

that failed, what do you do at that time? Does that 15

enter into your operating costs in terms of 16

replacement and how you deal with that? Or ho w do 17

you use that 34 year lifetime? 18

MR. BOLDUC: At the end of the 19

transformer’s lifetime, the simulation for that 20

transformer ends, so we do not model a replacement 21

after the life of the transformer. So in our sample 22

of 10,000, as we saw in the distrib ution, some 23

transformers will have a life of five years, ten 24

year, 50 years, 60 years, but the average 25Executive Court Reporters (301) 565

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transformer life in the simulation is 32 years. 1

This is specifically for Phil. This is 2

the peak load factor we use in the model, and it 3

ranges from 5 0 to 130 percent, with an average of 4

around 88, 87 percent. 5

All right. We’ll keep rolling. Thank 6

you. 7

**Base Constraint Installations** 8

Base constraint installations. So in the 9

model we address base constraints situations

-- 10

installations for design lines four and five. These 11

were specified in the 2007 NODA as units that would 12

be installed in vaults. Conversation earlier today 13

from Wes Patterson might change that, depending on 14

how things go with the new product lines and classes 15

in the engineering. 16

What I’d like to talk about instead of 17

which design lines are impacted, is really the way 18

that we model the costs associated with installing 19

our vault. We looked at two scenarios, two 20

situations. The first one is where the vault is 21

enlarged to take in a new transformer, and the 22

second is that the customer is forced to buy a more 23

expensive transformer at the same or less volume as 24

the transformer in the base case. 25Executive Court Reporters (301) 565

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In the first instance, we scaled the 1

values from the 2007 NODA, where the initial 2

ins tallation cost, as soon as you have to break 3

ground to change the vault, it’s going to be $1840. 4

And then with a volumetric charge for the difference 5

between the base case and the standards case 6

transformer, of $26, or $28. 7

What’s not listed here is w e also have an 8

extreme case that can be modeled that we run as a 9

sensitivity in the subgroups analysis, where the 10

initial cost is $30,000 and the per cubic foot 11

charge is $377. This is to take into account those 12

situations where you’re tearing up the stre et, or as 13

Wes said, digging up downtown Manhattan to put in a 14

new transformer. 15

In the second instance, it’s very simple. 16

In the LCC we compare the selected design of the 17

standards case against this assigned base case, and 18

we compare the volumes, and if the volume

-- and the 19

transformer cannot be selected from the engineering 20

sample unless it is of equal or lesser volume. And 21

again, it’s described in Chapter 11 with results. 22

That has been distributed. Yes, Steve. 23

MR. ROSENSTOCK: Steve Rosenstock, Ed ison 24

Electric Institute. I was looking at Chapter 11

-- 25Executive Court Reporters (301) 565

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MR. BOLDUC: Did you get blank numbers? 1

MR. ROSENSTOCK: No. 2

MR. BOLDUC: Good. 3

MR. ROSENSTOCK: No, no. All the numbers 4

are in here. But the results show space constraint, 5

but it doesn’t s how the sensitivity case results in 6

this chapter. Where would someone be able to find 7

those? 8

MR. BOLDUC: If they’re not there, that 9

would have been an oversight. It is a draft. I 10

will try to get those out later this week. 11

MR. ROSENSTOCK: Because I think

-- this 12

is Steve Rosenstock, EEI

-- especially for those 13

utilities, you know, with urban transformers, that

- 14

- you call that extreme, that $30,000, but maybe 15

that is extreme, but less extreme could be $15

- 16

$20,000 that a lot of them could be facing. So I 17

think

-- I know that’s your extreme case, but again, 18

for ones in the urban environment, that could be 19

very significant

-- that is going to be their 20

lifecycle for those units. 21

MR. BOLDUC: That’s understood. That’s 22

why we compute it as a subgroup. 23

MR. ROSENSTOCK: Good. And again, when do 24

you think that kind of information, that sensitivity 25Executive Court Reporters (301) 565

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case result would be published or would be available 1

to committee members. 2

MR. BOLDUC: I think it’s very likely that 3

I’ll be able to get you

-- I’ll be abl e to provide 4

results for the sensitivity next week, based on the 5

current engineering. 6

MR. FERNSTROM: This is Gary from PG&E and 7

the California IOUs. Let’s talk for a moment about 8

what really happens when a vault transformer needs 9

to be replaced. So th ere’s two cases, it’s either a 10

network transformer or it’s not, it’s in a vault. 11

We tend to size our vault transformers pretty big to 12

account for load growth, so the one need for 13

replacement is load has grown. What are we likely 14

to do, well, let’s put so me fans in there. That’s 15

the cheapest solution. If it comes to be that the 16

transformer needs to be replaced, we’ll replace it, 17

but it’s costly and that would probably be our last 18

choice. If we do have to replace it and it turns 19

out that a standard might result in a larger 20

transformer, maybe we could choose a little smaller 21

size and put some fans in there. So it would be 22

rare when we would be wanting to replace a whole 23

transformer vault in order to solve a problem. 24

MR. DeLASKI: In the modeling

-- thi s is 25Executive Court Reporters (301) 565

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Andrew DeLaski

-- in the analysis as it exists 1

today, what incidents do you attribute to this 2

scenario, the scenario one and two? 3

MR. BOLDUC: We run the scenarios 4

separately. We don’t try to model them into the 5

LCC. We don’t have sufficient data that says what 6

percentage of units are installed

-- 7

MR. DeLASKI: This is just a separate

-- 8

MR. BOLDUC: It’s a subgroup. This is 9

similar to how we handle the rural electric coops 10

and municipal utilities, these are identified as the 11

populations that would have different economic 12

constraints, and so we analyze them completely 13

separately. 14

MR. DeLASKI: But to Gary’s point, at this 15

point you don’t have an estimate of the size of the 16

population. 17

MR. BOLDUC: We’ve heard

-- I’ve seen 18

numbers that poin t five percent of sales, a very 19

small number installed in vaults. 20

MR. DeLASKI: Of sales? 21

MR. BOLDUC: Sorry, of installations. No, 22

they would be sales, I’m sorry. Excuse me, sales. 23

MR. DeLASKI: Point five percent of sales 24

are installed in vaults are numbers that you’ve 25Executive Court Reporters (301) 565

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heard, through your

-- 1

MR. BOLDUC: It’s an old number, yes. 2

MR. DeLASKI: But that doesn’t speak to 3

the question of the portion of that point five 4

percent that actually run into these size 5

constraints. 6

MR. BOLDUC: No, it doe sn’t. 7

MR. FERNSTROM: Gary from PG&E. So, 8

clearly, for some utilities this is a big problem. 9

Manhattan, San Francisco. However, across the whole 10

nation, downtown urban area network systems with a 11

lot of vaults represent a small portion of the 12

market. 13

MR. BOLDUC: Thank you. 14

MR. PARKER: My understanding also from

-- 15

Katie, correct me if I’m wrong

-- is that even for 16

that tiny fraction of utilities that do have severe 17

space constraints that they can’t deal with, along 18

the lines that Gary Fernstrom i ndicated, it’s 19

usually, if not always, possible to achieve a 20

significantly higher energy efficiency standard by 21

moving to a different, to a higher grade of metal so 22

you could change the design of the transformer 23

before you would actually just enlarge it? 24

MR. BOLDUC: Yeah, that would be point 25Executive Court Reporters (301) 565

- 0064 168

number two, where you select a more expensive unit, 1

you’re not selecting on first cost, you’re selecting 2

up the price scale for a unit that will fit in your 3

current installation. 4

MR. FERNSTROM: Yah, when we buy th ese 5

types of transformers, we buy them on specification, 6

not as a commodity purchase. 7

MR. BOLDUC: Right. And the other thing 8

I’d like to emphasize is

-- 9

MR. HYLAND: Can I jump on that? 10

MR. BOLDUC:

-- is that the replacement 11

transformer in the mod el is the same size 12

transformer in terms of capacity as the unit it’s 13

replacing. You’re not scaling up the transformer at 14

all in terms of this model. 15

MR. HYLAND: I was just going to jump on 16

what you said

-- Mike Hyland , EPPA

-- many municipal 17

governmen ts, we do buy on first cost, and we have 18

to, by law. 19

MR. PARKER: Wes. 20

MR. PATTERSON: When you look across the 21

liquid filled, medium voltage market, about 85 22

percent represents pads and poles in revenue 23

dollars, 15 percent in revenue dollars is 24

substa tions, networks, all those other stuff, and 25Executive Court Reporters (301) 565

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the networks are about half of that 15 percent, not 1

point five percent. 2

MR. BOLDUC: Okay. Can you

-- would you 3

be able to provide us with actual shipments data to 4

that effect? 5

MR. PATTERSON: Yeah, we

-- 6

MR. BOLDUC: In terms of units sold? 7

MR. PATTERSON: Yeah, our company shipment 8

data. 9

MR. BOLDUC: I’d appreciate that. Thank 10

you. 11

MR. PARKER: Greg. 12

MR. COULTER: Greg Coulter, Prolec GE. 13

We’re a little concerned about your point two up 14

there. 15

MR. BOLDUC: Okay. 16

MR. COULTER: We’re not too sure how you 17

can

-- anytime you’re going to go higher efficiency, 18

it’s going to be larger. So the point is, as you 19

try to meet these sizes with a higher efficiency, 20

that transformer gets larger, and so y ou come into a 21

size or a space requirement, a space issue on these 22

vaults, especially in these urban settings, 23

Manhattan, we’re talking, San Francisco. There is 24

no way to go higher price and meet the size. 25Executive Court Reporters (301) 565

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There’s no way to make it smaller and still meet the 1

efficiency. And I don’t think this is the minority 2

case. I mean, you picked ConEd, which is probably 3

the biggest network user, they probably use 40 4

percent of all the networks purchased. Maybe in San 5

Francisco you’re using another 15, 20 percent of the 6

networks purchased. That’s two great big users of 7

them, they’re not a minority. We don’t see how 8

number two ever works. We can’t imagine that model 9

ever being able to do that. 10

MR. HIRSCH: Bruce Hirsch, Baltimore Gas 11

and Electric. I guess I just wanted to comment on 12

some of the things Gary said with respect to our 13

system. You know, if it’s a load groove, that type 14

of an issue, whether you like it or not, those types 15

of charges get put into the customers’ hands so 16

they’ve got to pay for that extr a cost of installing 17

those transformers. They’ve also got to work with 18

us to provide the areas to make room so that we can 19

fit the transformers into where we need. 20

The real issue is replacement 21

transformers. If you have a transformer that fails, 22

it’ s normally an area where it’s serving a very 23

large customer, or maybe a large of very large, 24

influential, high profile customers, and we need 25Executive Court Reporters (301) 565

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something that’s going to go back into that hole 1

right away to fix it. We can’t go and increase the 2

vault size. 3

Another thing is, in a downtown area, very 4

seldom can you increase the vault size, there’s no 5

room, absolutely no room. We’re totally gridlocked 6

in Baltimore City with respect to that kind of 7

stuff. So, you know, size and when you’re talking 8

networks o r vaults, weight isn’t the big problem, 9

but it’s the size of the transformers that become a 10

real strangulation point for us. 11

MR. BOLDUC: Thank you. 12

MR. BERMAN: Robert Berman, Berman 13

Economics. That may be on a very individual basis, 14

that there may b e problems, but I know that ConEd 15

reports that they’ve been increasing the efficiency 16

of their transformers. They’ve been strongly 17

encouraged to do so by the Public Service 18

Commission. Is that a fair way to put it, Steve. 19

And they have been increasing t he efficiency 20

significantly of the transformers. They have a few 21

transformers above ground, but the vast majority of 22

the ConEd system is network transformer s 23

underground, in vaults. So it’s possible. They’ve 24

done it. 25Executive Court Reporters (301) 565

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MR. HYLAND: Mike Hyland, APPI. I don’t 1

think you can argue from the specific down to the 2

general, though. Just because one utility may have 3

oversized some vaults from the time they built the 4

city of Chicago, doesn’t mean that every utility can 5

do that. 6

MR. PATTERSON: That’s also a li ttle bit 7

anecdotal, because yes, ConEd is trying to improve 8

their efficiencies, but going from a high loss N 6 9

grade (ph) to the initial 2010 standard was a 10

significant bump for them and they have run into 11

problems now, trying to even use the 2010 standard 12

and apply it in New York. This has become a real 13

bottleneck. That’s why I pushed that maybe we 14

should consider them separate. 15

MR. HOPKINSON: Phil Hopkinson, and also 16

what I would say is efficiencies implemented for 17

improvement by ConEd to date are not yet to the 18

point where the costs go sky high, so when we look 19

at trying to bump from here to higher efficiency, 20

the transformer, to Greg’s point earlier, going to 21

get a whole lot bigger. 22

MR. PARKER: So what I’m hearing then is 23

that depending upon what the

-- ballpark we end up 24

in the negotiations about what efficiency levels 25Executive Court Reporters (301) 565

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we’re talking about, the space constraint may or may 1

not be a big thing. If you’re talking about a small 2

bump up, it may be reasonable to assume that 3

virtually everybody, by making some incremental 4

adjustments to their materials and so forth, might 5

can fit everything into the line, fit in the 6

existing space. But a very significant increase in 7

efficiency might at that point raise issues about 8

space constraint which would then requir e us to, at 9

that point, consider whether or not there needs to 10

be a separate subcategory created for vault and 11

network. Is that right? 12

Okay. So if that’s the case, maybe we 13

should table that issue and see

-- I hate to keep 14

kicking the can down the ro ad, but that’s one thing 15

that since we don’t have a lot of data on it now, 16

may fruitfully await the discussion in the 17

negotiations about seeing where we actually are with 18

regard to efficiency levels, and then come back at 19

that point to see if we have a re al issue or not. 20

Does that make sense? 21

MR. ROSENSTOCK: Mr. Parker, I agree, but 22

I also want to say

-- this is Steve Rosenstock, 23

Edison Electric Institute

-- at the plenary analysis 24

stage I do not

-- several utilities did raise this 25Executive Court Reporters (301) 565

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issue and provided i nformation. I know a person 1

from PEPCO discussed their views on this issue, and 2

I’m pretty sure that other utilities with urban 3

environments did. I believe they provided data for 4

DOE to use for the revised analysis. Thank you. 5

MR. PARKER: There’s two issues. One is, 6

you know, what are their current space constraints, 7

and secondly, what would they be, under hypothetical 8

new standard that might be of a higher efficiency? 9

So, good. Any other comments on this before we move 10

on? Go ahead. 11

MR. SMITH: Bob Smith at Federal Pacific. 12

Richard, my question is, from the information you’ve 13

been given by Wes Patterson and Greg Coulter, which 14

is covering a significant portion of the network 15

transformer users, don’t you have enough information 16

to go ahead and m ake a decision that we do have 17

space constraints with network transformers? 18

MR. PARKER: Well, I guess the question is 19

not whether there are space constraints, but whether 20

there are space constraints that cannot be met by 21

moving to higher grade metals or some other 22

transformer design, right, and that could depend on 23

the efficiency levels. Is that a fair 24

representation of what you were saying, Greg, 25Executive Court Reporters (301) 565

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earlier? Greg says he agrees. 1

MR. PATTERSON: Just a point of note. 2

MR. PARKER: Wes Patterson. 3

MR. PATTERSON: Wes Patterson, ABB. When 4

we did the design database for medium voltage liquid 5

filled, somehow or another we made the assumption 6

the whole universe was wound core. These 7

transformers, by and large, are stacked core made 8

with different steels. So be careful. 9

MR. BOLDUC: Thank you. 10

MR. PARKER: Yes, Andrew. 11

MR. DeLASKI: Yes, so we suggested that 12

DOE, in terms of the analysis, Mike asked before 13

lunch it would be helpful to have the product 14

classes, so I would suggest, you know, that 15

separ ating out the vault and network transformers as 16

a separate class for analysis purposes will give us 17

more information on which to negotiate as this 18

process rolls forward. So I think it is useful to 19

separate it out, whether it ultimately gets a 20

different st andard or the same standard is something 21

for us to discuss as this committee does its work. 22

But I’d rather have the data, have a separate 23

analysis that we could look at, rather than wish I 24

had it later on. 25Executive Court Reporters (301) 565

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MR. PARKER: Fair point. Mike Rivest 1

needs a m ic. 2

MR. RIVEST: No feedback, all right. Mike 3

Rivest. Well, I’m sort of in a box. If it’s a 4

separate product class, what parameters do we put on 5

the engineering analysis to create a new engineering 6

analysis, or is this not an engineering analysis 7

issu e. Is this a matter of doing separate economics 8

with volt costs? What does it mean here to do a 9

separate analysis for a product class with space 10

constraints. 11

MR. PARKER: This is Tom. Yes, go ahead, 12

Greg. 13

MR. ECKMAN: I think this means that a 14

separ ate life cycle cost analysis. 15

MR. PARKER: All right, Tom Eckman. 16

MR. ECKMAN: This is a life cycle cost 17

analysis question because it’s an installation, not 18

a manufacturing issue. So it’s the cost that is 19

installation

- related to determine whether that space 20

constraint has a dampening effect on how big you can 21

make the units and how efficient they could be given 22

that size constraint. So it’s an economic question, 23

it’s not an engineering question. 24

MR. RIVEST: I don’t think you can have a 25Executive Court Reporters (301) 565

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product clas s if you don’t have a separate 1

engineering, because

-- no, but I’m not

-- I’m not 2

being very philosophical

-- 3

MR. COULTER: This is Greg Coulter with 4

Prolec GE. I’m leaning towards I don’t think you 5

ought to do a separate analysis, only due to time. 6

I would like to see what efficiencies we come up 7

with. I think that’s the right approach, and see 8

then if that’s an issue for a product line that 9

represents such a small percentage of the overall 10

group, that whether you put it in at the higher 11

efficiency or not, probably isn't going to make a 12

big difference to you or anybody else in the room. 13

It’s still a very small number of units. They just 14

get lumped into this three

- phase grouping, and 15

because of that we become concerned, we as 16

manufacturers, users that have to live with the 17

dimensions. We know what dimensions we have to 18

meet, they know what dimensions they have to meet. 19

And we’re concerned now that as we talk some of 20

these higher efficiency levels, we could get into 21

trouble. You may not get to that e fficiency, 22

because we don’t know what’s going to come out, so 23

we have to raise the issue. But it’s still a very 24

small percentage of the total units. 25Executive Court Reporters (301) 565

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MR. PARKER: I think Andrew’s point that a 1

small percentage of extreme outliers in terms of 2

cost could s hape the analysis for a category that is 3

distinct from that. Is that right, Andrew? 4

MR. DeLASKI: It’s that you may ultimately 5

want a different standard

-- you may ultimately 6

prefer a different standard for these products, but 7

you’re saying why spend al l this time and effort and 8

money on an analysis for a quarter of a percent of 9

the market, or maybe it’s more, Wes

-- 10

MR. PATTERSON: Five. 11

MR. DeLASKI:

-- five percent of the 12

market. Now, ultimately, somebody will, I think, is 13

what Don’s going to tel l us in a second, they have 14

to have an analysis on which to base their proposed 15

rule, but it may not be that this committee has to 16

solve today, or next four weeks. 17

MR. COULTER: Well, you know, and I don’t 18

have a problem putting data together for this 19

ei ther, I just have a problem that I think at this 20

stage, to develop a whole new class that everybody’s 21

going to have to go out and do all this work, is 22

going to put us way off here in left field while we 23

ought to be moving forward where the majority of the 24

market is, and carve this out. 25Executive Court Reporters (301) 565

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MR. DeLASKI: So we pounced on the 1

analysis for Mike to figure out later. 2

MR. COULTER: He has enough analysis to 3

do. We toss this at him, I don’t see

-- 4

MR. DeLASKI: Good point. 5

MR. COULTER: Okay. That’s my only 6

comment. 7

MR. PARKER: Steve. 8

MR. ROSENSTOCK: Steve Rosenstock, EEI. I 9

think we have to consider the end users as well, the 10

utili ties with urban customers that could have the 11

higher number of these network transformers. Yeah, 12

maybe it’s a small numbe r, but it terms of 13

percentage of costs or especially if you are adding 14

in some of these added installation costs, yeah, 15

maybe it’s only

-- it could be like ten percent of 16

their transformers or 15, or ConEd, you know, it 17

might be 30 percent of their transfo rmers, and 50 or 18

60 percent of their capital expenditures. So for 19

certain utilities, especially the ones with the 20

higher number of these units, the numbers might be 21

small but the dollar impacts could be significantly 22

larger. Thank you. 23

MR. PARKER: Jus t want to add, I’m 24

certainly not a technical person, but I have been 25Executive Court Reporters (301) 565

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around the block with politics, both in Washington 1

and out, and I do know all it takes is couple of 2

anecdotes to make some big media stories that may be 3

the tail of the dog, but will none theless grab 4

public attention in a big way. So I think because 5

of that, you know, you have to take the vault 6

situation seriously and not create a situation where 7

either you have a low standard that’s driven for 8

99.9 percent of the market it’s driven by va ult 9

concerns, or figure one size fits all standard, 10

ignores those concerns and creates a couple, or 11

perhaps a handful of bad results. 12

But really bad results get all the tabloid 13

new going as a case study in how this group messed 14

up. So I think, you kno w, we do need to take those 15

-- from a political standpoint, you need to take 16

those extreme cases seriously. I don’t think they 17

should drive the analysis for the whole category, 18

but you also don’t want to create a train wreck that 19

a couple of horror storie s will come back and hurt 20

you later on. 21

MR. PATTERSON: Wes Patterson. Mike, just 22

to set your mind at ease, if I’m correct that the 23

rate of change of cost with respect to change of 24

loss is the primary driver out of the engineering 25Executive Court Reporters (301) 565

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analysis, then all the data you have can be applied 1

to the networks. So there’s not another engineering 2

analysis that’s needed, it’s just using the data 3

appropriately. So I don’t think we have to 4

duplicate your stuff, but we might be able to 5

segment them out for their own lif e cycle cost 6

analysis. 7

MR. RIVEST: That’s definitely doable. 8

MR. DeLASKI: I think I wrap up this point 9

in the interest of trying to move ahead, but it 10

strikes me that I don’t hear anybody disagreeing 11

that taking a separate look at network transformer s 12

makes sense. No one’s disagreed with that notion. 13

And back to the point I made this morning is that 14

our interest is focusing on savings and we want to 15

see significant increases for the transformers that 16

represent the vast majority of sales, of MDA, and if 17

that means the standards sit still for, or be modest 18

for some relatively small applications, then that, 19

we think, is something that we’d like to be able to 20

have on the table and be able to discuss. 21

MR. PARKER: (comment off mic) 22

MR. DeLASKI: I’m n ot sure you want to go 23

there yet, Richard, do we? 24

MR. PARKER: No, but it sounds to me like 25Executive Court Reporters (301) 565

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what you’re talking about

-- Andrew, it sounds to me 1

like what you’re talking about is actually creating 2

a separate, like we did in the other case, creating 3

a sep arate

-- for the BIL

-- creating a separate 4

category, but keeping it the same, right? 5

MR. DeLASKI: Yeah. I don’t know what the 6

level would be, but this is something that we were 7

willing to discuss. 8

MR. PARKER: Right. Right, and

-- 9

MR. DeLASKI: W illing to discuss. I mean, 10

that’s how you

-- those are the kinds of solutions 11

that I think ultimately would enable us to

-- 12

MR. PARKER: If you can come up with a 13

physical specification for these things that makes 14

sense, that distinguishes them from the rest of the 15

category

-- the rest of the transformers in this 16

class. And I understood from Brian Coffey that that 17

should be possible, is that right? 18

MR. COFFEY: To physically distinguish 19

them? 20

MR. PARKER: Yes. 21

MR. COFFEY: (off mic) ... treat them 22

d ifferently, so I think I heard from the 23

manufacturers that it’s pretty obvious which is 24

which, but I think we would have to have another 25Executive Court Reporters (301) 565

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conversation about the exact language. 1

MR. DeLASKI: One thing that might

-- 2

Andrew again

-- one thing that might be useful would 3

be if some folks in the subgroup wanted to come back 4

and tell us what is it

-- I mean, I hear WES, 5

there’s an IEEE definition that’s helpful, but I 6

think what ultimately what we would need to have is 7

what are the things, what is it about these 8

transformers that make them expensive, and let’s 9

make sure that we’re capturing that in a regulatory 10

definition. 11

PARTICIPANT: (comment off mic) 12

MR. DeLASKI: Yeah, made of titanium, or 13

something? Let’s capture

-- you can do it

-- if 14

it’s something t hat can be done. 15

MR. PARKER: So is this something that we 16

can form a group on? I think that’s a nice 17

suggestion

-- that would basically work reasonably, 18

intensively over the next few days to gather 19

whatever data there is available, and make a 20

recommend ation to the group about whether there 21

needs to be a separate category or whether it’s 22

going to be treated the same? 23

MR. DeLASKI: My suggestion, not whether 24

it just needs to be treated separately, just how do 25Executive Court Reporters (301) 565

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you define it? Can you

-- it only has to happen in 1

the next three days, and people can be thinking 2

about how do you define the category in a way that 3

is

-- 4

MR. PARKER: Well, I think it would be 5

good if we

-- if we can get a group together to do 6

that, to see whether you need to define a categor y, 7

and if so, how you would do it. 8

MR. DeLASKI: If you need to define a 9

category, again, will ultimately be linked to how

-- 10

what we can do with respect to improving the 11

standards for the main categories. So that’s why 12

I’m saying all this is contingent on this process 13

being able to move forward, so I think, you know, I 14

hope we can move on

-- 15

MR. PARKER: But I thought you said 16

earlier that it would be nice to have the data so 17

that we don’t have a train wreck at the end. 18

MR. DeLASKI: The definition. 19

MR. PARKER: The definition, right. 20

PARTICIPANT: (Comment off mic) 21

MR. DeLASKI: That would be good to have 22

that data, and that would help us make decisions, 23

and I think especially since we’re capturing

-- I 24

don’t know how you guys

-- how the dif ferent market 25Executive Court Reporters (301) 565

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shares split among different

-- 1

PARTICIPANT: (off mic) 2

MR. DeLASKI: Sounds good. 3

PARTICIPANT: (off mic) 4

MR. DeLASKI: So we have data, and then we 5

have the definition, and that gives us the building 6

blocks to be able to move forwa rd. 7

MR. BOLDUC: Great. 8

MR. PARKER: Anybody else volunteering for 9

that group? Wes? Greg? Andrew, can you be

-- you 10

want to be involved, or you want to be monitor. 11

MR. DeLASKI: I’ll join that group. 12

MR. PARKER: Okay. Great. And then work 13

wit h Chris on that. Thank you. 14

**Pole Replacement** 15

MR. BOLDUC: Next slide is pole 16

replacement. The preliminary analysis presentation 17

there was some confusion in the comments as to how 18

the pole replacement algorithm worked. It’s a very 19

simple algorithm. I f the replacement transformer 20

weighs more than 1000 pounds, the LCC spreadsheet 21

warrants that a pole replacement is needed and I 22

think the pole replacement cost is $2000. There’s 23

some additional adders on top of that, again, it’s 24

for the same size unit. It only impacts design line 25Executive Court Reporters (301) 565

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two, the 25 KV round tank, and so the question for 1

us is, first of all, is the 1000 pound threshold 2

correct for transformer of that size, for single

3

phase, 25 KVA transformer? And then a follow

- on 4

question for that is, does the committee have 5

suggestions on how to monitize the impacts of other 6

people’s wires on the pole and the opportunity cost 7

that’s lost while replacing the poles? Or sorry, 8

the cost replacing the poles with these other 9

equipment on them. 10

MR. PARKER: Steve. 11

MR. ROSENSTOCK: Steve Rosenstock, EEI. 12

Again, this is off the top of my head, as I recall 13

there was ... from PEPCO earlier this year that said 14

that

-- Potomac Electric Power Company in D.C.

-- 15

that said the number was either 800 or 900 pounds, 16

where if the weight of the new transformer was above 17

either 800 or 900, especially in Washington, D.C., 18

there were certain rules in terms of

-- certain 19

regulations in terms of the pole replacement as well 20

as the crew that was required for it, and the 21

installation t hat was required for the replacement 22

system, and that was filed with DOE. You should 23

have access to it. So again, that’s one that comes 24

right off the top of my head in terms of that one. 25Executive Court Reporters (301) 565

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And then, you know, I know Bruce talked about safety 1

clearances. I don’t know if he could address that. 2

MR. PARKER: Yeah, Bruce. 3

MR. HIRSCH: Yeah, I’d just like to add 4

too that those weights not only affect the pole 5

loading, which require poles to be replaced, but as 6

you get up in size in the weight of the transfo rmer, 7

our trucks can’t handle that transformer, lifting it 8

up onto the pole, so we have to run cranes out and 9

that kind of stuff, so you drive the price up of 10

doing that job tremendously. So that’s an important 11

thing. 12

The other thing, and I mentioned it a 13

little earlier, is from the standpoint of NESE (ph) 14

requirement

-- 15

MR. PARKER: What’s that? 16

MR. HIRSCH: I’m sorry. 17

MR. PARKER: Do you have data on what that 18

weight is, what you’re

-- 19

MR. HIRSCH: Yeah, I can provide something 20

on that. 21

MR. P ARKER: Okay. That would be helpful. 22

MR. HIRSCH: The other thing is from the 23

standpoint of NESE (ph) clearances and safety 24

regulations, in the alleys of Baltimore City, and 25Executive Court Reporters (301) 565

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I’m sure any city like D.C. and cities like 1

Baltimore, you run into these clear ance issues with 2

respect to how close you are to buildings, how close 3

you are to the public utilities, so as you drive the 4

size of the units up, then you have to put bigger 5

poles, sometimes you can’t do that in a completely 6

paved alley type of thing, so we run into all those 7

issues right now. 8

Like I said, we have started actually, 9

under certain product lines, to actually rebuild old 10

transformers so that we could continue to use those 11

that we can indeed put into those locations and 12

maneuver them into place with our existing 13

equipment. All that adds into it. So, yeah, I can 14

put some stuff together for you on that. 15

MR. BOLDUC: Just a follow

- up question, 16

Bruce. In the current engineering data, the height 17

and the width of the units are constrained by comm on 18

tank size. So would that suffice to accommodate the 19

clearance issue? 20

MR. HIRSCH: If the height and the width 21

are constrained

-- you’re saying let the weight go, 22

but the height and the width are constrained? 23

MR. BOLDUC: Yes, exactly. 24

MR. HIRSCH: I guess I wasn’t aware that 25Executive Court Reporters (301) 565

- 0064 189

they could do that, but yeah, if the height and the 1

width are constrained, you’re okay. 2

MR. BOLDUC: Robert. 3

MR. BERMAN: Robert Berman, Berman 4

Economics. There are also a number of various, I 5

understand, there’s somethin g called a joint pole 6

association for areas where communications companies 7

and so forth use poles with

-- the same poles as the 8

electric companies, so those would be cost shared. 9

How common those are, I don’t know. It’s an 10

additional problem, I understan d, with poachers in 11

California, but perhaps that might even drive the 12

cost down, because you identify the poachers at that 13

point. 14

MR. FERNSTROM: Are you suggesting that 15

some California hunters don’t know the difference 16

between a deer and a utility tran sformer? 17

(Laughter.) 18

MR. BERMAN: That’s what I’ve heard from 19

some utilities in California, yes. 20

MR. FERNSTROM: Gary Fernstrom, PG&E. I’d 21

like to make a comment about this

-- besides the 22

deer hunter. We don’t mount a lot of really big 23

transformers on poles, so anything over maybe 160 24

KVA, as an integral unit, doesn’t go on a pole. And 25Executive Court Reporters (301) 565

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the second thing is, really big pole mount 1

transformers are a very small portion of our 2

distribution system. So as we’ve discussed with 3

some of these other issues, I believe the case of 4

the transformer that’s going to weigh too much for 5

the pole is a very small percent of the market. 6

MR. BOLDUC: Wes. 7

MR. PATTERSON: You said this applies to 8

design line two. And design line two is, I think, a 9

25 KVA transformer. Right? But the pole mount 10

business sells, you know, from like 10 KVA up 11

through 833 KVA single

- phase. And there’s a sw... 12

that’s three

- phase. So how did you take this data 13

and apply it to that entire market segment, which is 14

also 30 percent of the entir e liquid filled market? 15

How do we extend this data? Like that thousand 16

pounds, is that 17

http://www.etsy.com/listing/81629136/chunky

- cowl

18

hand

- knit

- in

- autumn

- tweed ? Or is that thousand 19

pounds for an 833 transformer? 20

MR. BOLDUC: That would be a thousand 21

pounds for a 25 KVA transformer. 22

MR. PATTERSON: And then you use the 23

three

- quarter rule to scale it up? 24

MR. BOLDUC: We would actually scale the 25Executive Court Reporters (301) 565

- 0064 191

results up in the NIA to calculate impacts. We 1

wouldn’t be calculating life cycle costs. We’re 2

only cal culating the life cycle cost with pole 3

impacts with 25 KVA transformers. 4

MR. PATTERSON: Only on 25? 5

MR. BOLDUC: Yes. 6

MR. MEYERS: Aaron Meyers, Cooper. So do 7

any of your 25 KVA transformers exceed 1000 pounds? 8

MR. BOLDUC: No, they do not. 9

MR. MEYERS: And let me also ask, is the 10

$2000 based in reality or was it an arbitrary number 11

that was chosen? 12

MR. BOLDUC: It was a number that was used 13

in the 2007 final rule. We kept. 14

MR. MEYERS: Was it arbitrarily chosen 15

then or was it based in fac t? 16

MR. BOLDUC: I can’t speak to that rule, 17

sorry. 18

MR. PARKER: Steve. 19

MR. ROSENSTOCK: Steve Rosenstock, EEI. 20

Again, thank you for this slide, but why not

-- why 21

didn’t you do any analysis for design line one, 50 22

KVA? Single phase. 23

MR. BOLDUC: They’re pad mounted. 24

MR. ROSENSTOCK: All pad mounts? 25Executive Court Reporters (301) 565

- 0064 192

MR. BOLDUC: Yeah. 1

MR. PATTERSON: Understand that this means 2

that the life cycle analysis is only looking at data 3

for 50 KVA pads, and it’s ignoring 75 percent of the 4

entire market. I don’t unde rstand how that life 5

cycle analysis can have any value whatsoever, if all 6

I do is examine it at a single KVA construction 7

product. It makes no sense. 8

MR. MEYERS: Aaron Meyers, I’m in full 9

agreement with Wes. 10

MR. ANDERSON: Rick Anderson, Fayetteville 11

PWC. 12

(Comments off mic.) 13

MR. BOLDUC: I’m sorry, the LCC, we pick 14

the rep units that we do the LCC’s out of. We then 15

scale the results to the different product classes 16

for

-- to calculate the national impacts. 17

MR. MEYERS: Aaron Meyers

-- 18

MR. PATTERSON: The assumption there is 19

that all of the economic analysis on the 25 KVA 20

applies equally to everything that’s under that 21

design line, or even worse yet, under the equipment 22

class grouping. Right? We had a design line two, 23

right, which had a re presentative unit of a 25 KVA 24

unit, which, for point of reference, is never sold 25Executive Court Reporters (301) 565

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in North America. So here’s a design, a particular 1

design, when you take all its individual ratings, we 2

don’t even sell those things. But can you use it to 3

represent what we do sell, and the answer is yes. 4

But you can’t use it to represent everything that’s 5

under the scope of design line two without 6

extrapolating the data properly. I don’t understand 7

how there’s any merit in doing an economic analysis 8

on the 25 KVA and ext ending that to a 500 KVA. 9

Makes no sense. Because when we turn around and we 10

pick these efficiency standard levels, we didn’t use 11

a common ratio on them. Somebody picked and chose, 12

here’s a high efficiency on this one, and low 13

efficiency on this other K VA rating. In the same 14

design line group. Made no sense. 15

MS. COUGHLIN: So

-- this is Katie 16

Coughlin, LBL. I mean, this is actually taking us 17

back to the issue of the representative units, which 18

we started with in the last meeting, because I think 19

you had some criticisms about the representative 20

units not being sufficiently representative of the 21

market. 22

MR. PATTERSON: Yeah. 23

MS. COUGHLIN: So that’s fine, I mean, and 24

the issue

-- these things are

-- these decisions are 25Executive Court Reporters (301) 565

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sort of made upstream of the LCC, so to create an 1

individual LCC for a particular type of product, we 2

need to have all that engineering data laid out. So 3

if you can come up with a quick way of taking the 25 4

KVA engineering data and extrapolating it to a 50 5

KVA

-- 6

MR. PATTERSON: Wh ich I think we can. 7

MS. COUGHLIN: If you can do that, then we 8

can create a separate LCC spreadsheet for that

-- 9

for that installation, that’s not a problem. But we 10

do need to have

-- 11

MR. PATTERSON: We can do the LCC analysis 12

on the motable KVA stand ards that are within that 13

design line. 14

MS. COUGHLIN: Well, we can do an LCC for 15

-- let’s just say one more KVA, right, 50 KVA would 16

be sufficient to get at some of these issues? 17

MR. PATTERSON: I don’t know, if nothing 18

else we should take the ones whe re the major MVA 19

shipments take place. 20

MS. COUGHLIN: Yeah, I’m just saying that 21

there’s a

-- 22

MR. PATTERSON: Like the two largest MVA 23

shipments in pole mounts and say, we’re going to do 24

it on those. 25Executive Court Reporters (301) 565

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MS. COUGHLIN: Okay. So if we can come up 1

with a way of converting the existing engineering 2

data for the 25 KVA to something acceptable at those 3

higher capacities, then we can create an LCC and we 4

can, if we need to modify some of these installation 5

constraints, we can do that. That’s a feasible 6

modifi cation of the analysis. So just leave it at 7

that and then you can

--- 8

MR. PATTERSON: Who do I work with on 9

this? 10

MS. COUGHLIN: I guess, just the 11

consultants, so all of us. 12

MR. PARKER: Yes, who else would like to 13

be involved in that group? Aaron, you don’t. 14

Anybody else who wants to be involved

-- basically 15

if you have data or you have issues involving 16

different KVA ratings and are concerned that this 17

unit may not reflect

-- 18

MR. ANDERSON: Rick Anderson, Fayetteville 19

PWC. I think the user need s to work with the 20

manufacturer to make sure the practical side is 21

covered there. So I’d be delighted to work with 22

Wes. 23

MR. HOPKINSON: Phil Hopkinson, HVolt. 24

One thing I might propose, since I did the market 25Executive Court Reporters (301) 565

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study, is take the histogram of data that’s already 1

in that study and use that for the number of units 2

times the KVA rating, and that certainly will give 3

you the MVA impact. And of course you’re going to 4

find a huge quantity at 15 KVA, another huge 5

quantity at 25 KVA, lesser quantity at 50, but wh en 6

you move the MVA

-- I haven’t gone back to look at 7

it again

-- but that data is available so that you 8

should be able to use not just your company data but 9

try to do it on what we call the market size. 10

MR. FERNSTROM: So this is Gary from PG&E. 11

I’d li ke to elaborate on a comment that Andrew made 12

earlier. I think being able to address some of 13

these differences between the analytic approach 14

that’s taken and the market, is a real value that 15

these types of negotiations have that we can get to 16

in the offic ial DOE rulemaking process. So the more 17

we can have these kinds of discussions, irrespective 18

of how tedious they may be, I think we’re going to 19

get to a lot better result than we would just 20

through the typical adversarial rulemaking process. 21

MR. PARKER: Thank you. Aaron. 22

MR. MEYERS: My question is for Chris 23

regarding the scaling. Is the weight scaled up and 24

then this additional charge applied to the units 25Executive Court Reporters (301) 565

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that scale above 1000 pounds? Or is your analysis 1

based on the fact that there are no units i n the 25 2

KVA design line where this applies, and then you 3

scale the 25 KVA design line up, also extrapolating 4

the fact that there are no units that are above 1000 5

pounds? I just want that point to be clarified. 6

MR. BOLDUC: Yes, it’s the latter. 7

MR. MEYERS: So essentially that was not 8

considered

-- the weight was not considered in the 9

analysis at all? 10

MR. BOLDUC: No, no, the weight

-- in 11

regard to pole mounting, you’re correct

-- you’re 12

correct, it was incorrect implemented. Weight is

-- 13

additio nal cost associated with installing 14

transformers are applied as a function of weight on 15

the transformer. These costs are scaled as the 16

transformer scales up, as the rep unit is scaled in 17

size to the product class. 18

MR. DeLASKI: This is Andrew. My 19

reco llection, and again, I haven’t read this 20

recently, but that there is some number of 21

transformer installations for which the LCC does 22

assume a pole change out. You’re suggesting that 23

the way you’re doing the analysis, it must be zero. 24

Am I right? 25Executive Court Reporters (301) 565

- 0064 198

MR. BO LDUC: I don’t know if I’m really 1

suggesting anything, I’m asking how the analysis was 2

done. Is it considered in the larger KVA? 3

MR. DeLASKI: My recollection, Katie, or 4

of course you guys can remember

-- and there are 5

some installations in which you wo uld assume

-- in 6

which the analysis shows a pole change

- out? 7

MS. COUGHLIN: Yeah, I think

-- the 8

clarification here is that, let’s say it was 9

correctly implemented for 25 KVA and incorrectly 10

extrapolated to higher KVA. And we can correct that 11

extrapolat ion. 12

MR. DeLASKI: Perfect. 13

MR. PARKER: Okay. So we’ll have Wes and 14

Aaron, if he’s willing, work on that. Are you 15

willing to work on that? And Richard Anderson. And 16

report back to us as soon as they have results on 17

whether and how that changes t he analysis, but 18

basically to give

-- basically to give

-- the basic 19

deliverable is that they should work together to 20

give LBL the data that they need, the engineering 21

data they need to do a revised life cycle cost. Is 22

that right? 23

MR. BOLDUC: Correct. For poles. Okay. 24

Shall we move on? 25Executive Court Reporters (301) 565

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MR. WINDER: Ken Winder, NRECA. I 1

question the $2000. A lot of that pole replacement 2

has to be done with hot line work and I think we 3

ought to have some utility input into that to at 4

least review it, and we will ce rtainly furnish that 5

information to Chris. 6

MR. BOLDUC: Thank you. That would be 7

appreciated. 8

**Rural Cooperatives**  9

MR. BOLDUC: Rural coops have been 10

identified as a subgroup in the analysis. We talked 11

about it earlier in the loading. This slide 12

bas ically rehashes this issue. The key factor for 13

rural coops that differ

-- that make them differ 14

from the rest of the population is that they’re 15

loaded at lower levels. In this analysis we used a 16

ballpark factor of 0.75 to adjust the load factor on 17

the RM S loading on the transformer. We are 18

continuing to do that this time around. 19

MR. ANDERSON: Rick Anderson, Fayetteville 20

PWC. Why wouldn’t you include the municipals in 21

that? 22

MR. BOLDUC: We do include the municipals 23

as a subgroup, but we adjust the loading upwards on 24

municipals. Again, we’ve heard that they are loaded 25Executive Court Reporters (301) 565

- 0064 200

at higher levels in primarily urban municipal 1

utilities . There just wasn’t as much e

- mail fervor 2

on the muni side of things as there was for rural 3

coops. 4

MR. HYLAND: I can

-- as I promise d you, I 5

can get you data within a week, but I disagree with, 6

just because they’re urban does not mean they’re 7

heavily loaded. All the information that we got 8

since we’ve started meeting is just the opposite. 9

Some of these ... is just like gas and water is 10

telling us, is 17 percent. 11

MR. BOLDUC: Did you say it’s similar to ... 12

rural coops loading, perhaps? 13

MR. HYLAND: Well, we’re not as

-- well, 14

yeah, but I want to be sure that we understand here, 15

it’s tough to categorize that way. You go to 16

Ne braska, my users are very much like a coop. You 17

go to downtown L.A., it doesn’t look like a coop. 18

But they’re both munis. So I go to Seattle and look 19

at a network transformers, I go to some of my munis 20

right outside Boston, it’s the same as Boston. Bu t 21

in the middle of Montana, middle of Alaska, they’re 22

like coops. 23

MS. COUGHLIN: So, again, this is Katie 24

Coughlin. So the way we deal with that is to use 25Executive Court Reporters (301) 565

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these simulations where we have a distribution of 1

loading characteristics. So if we can character ize 2

that range of possibilities with appropriate 3

weights, then we can account for that in the LCC. 4

MR. SAINT: Well, and I think the reason, 5

I think the reason why you segmented out rural coops 6

is because in rural areas, most likely there is one 7

customer per transformer, and for example, the 8

minimum size transformer that’s purchased may be 15 9

KVA for a 5 KVA maximum load, or probably 3.7 order 10

-- percent RMS load. So that automatically means 11

that the transformer is loaded less than rated. So 12

I think tha t’s a justification for segmenting rural 13

areas versus urban areas. I can’t speak to the 14

loading in urban areas, but in rural areas they’re 15

definitely loaded less than the transformer rating, 16

in the general case. 17

MR. BOLDUC: Thank you. 18

MR. HYLAND: An d I can agree to that, Bob, 19

but that gets to the diversity issue being that it 20

would be tough to figure out. I mean, I’d have to 21

give you all 2000 utility data points. In the state 22

of Nebraska, which is as rural and farm country as 23

you’re going to get in this United States is 100 24

percent municipalities. 25Executive Court Reporters (301) 565

- 0064 202

MR. SAINT: Well, all the public power 1

districts in Nebraska are members, except for two. 2

We include the rural public power districts in that 3

rural coop category. 4

MS. COUGHLIN: There’s a

-- again, I don’t 5

want to go into too much detail, but there are

-- 6

what we have used in the life cycle cost spread 7

sheet as our sort of sampling base, is the list of 8

utilities that are in NEIA. So if you would like to 9

extend the set of utilities that are being inc luded 10

in our low loading subgroup, we call it rural, but 11

it can be anything you want. So again, if you want 12

to provide some specific suggestions of how to 13

segregate that population of the utilities, then we 14

can implement that quite easily. 15

MR. ECKMAN: A question for

-- this is Tom 16

Eckman. I have a question for Michael and Robert. 17

In the data that you guys have, do you have 18

information on customers per line mile? 19

MR. SAINT: Yeah. Oh, yeah, we have that 20

data. 21

MR. ECKMAN: So that may be a way to 22

s egment them. Something like that. Because in 23

Seattle

-- Seattle’s clearly got more than one 24

customer per 50 line mile, but in Nebraska, that 25Executive Court Reporters (301) 565

- 0064 203

might be a usual cover. So if you’ve got that, you 1

might have classes that you can use to move 2

customers in the IA database or utilities in the IA 3

database, whether they’re public or private. It’s 4

really the density of the population per line mile 5

that’s going to dictate what kind of transformer 6

they’re going to have. So maybe you guys could work 7

on that and that might be a way to get at that 8

information, because I think it’s probably

-- it 9

might even be in EIA database, I’m not sure. 10

MR. SAINT: Well, we have it in our 11

database and the average is seven customers per 12

mile. In urban areas it’s more like 60. 13

MR. ECKMAN: And there may be a cut plane 14

that you could use there to segregate, get the 15

weights for loading based on that, rather than 16

public/private. Or whether they’re municipals or 17

coops. 18

MR. ROSENSTOCK: Steve Rosenstock, EEI. 19

That second number, tha t 60 is all urban areas 20

including IOUs and munis, so Mike have a different 21

number for the municipal segment. 22

MR. ECKMAN: I’m just saying it probably 23

would apply to

-- whether it’s IOU or public, you 24

just use the customer per line mile as the aggregate 25Executive Court Reporters (301) 565

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p er density transformers and you get a better idea 1

of what the loadings are. I mean, a better 2

segmentation that way, rather than whether this

-- 3

you’ve got urban and rural. Pacific Core serves all 4

over Utah and Nevada, and it’s got

-- it looks like 5

a coop out there. So whether it’s an IOU or not, 6

just because it serves Salt Lake City, half of its 7

customer base is in rural areas. 8

MR. PARKER: So as I understand it, the 9

idea is to categorize it based on population 10

density, create a subgroup that is define d according 11

to some kind of population density threshold that 12

would then be

-- 13

MR. ECKMAN: I think it’s customers per 14

line mile, and that’s a surrogate for how many 15

transformers you’ve got per customer. It’s a pretty 16

close

-- you know you’re not runnin g a distribution 17

from the transformer seven miles to the next 18

customer. It’s not going to happen. 19

MR. PARKER: So we’re really focusing in 20

on rurals. Does that work for you, Bob? 21

MR. SAINT: Yeah, we can provide that 22

information, but for our members, there are few, 23

mostly island area that are very dense. There’s 24

some areas in Alaska, for example, that are very 25Executive Court Reporters (301) 565

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dense because they don’t

-- between towns there’s 1

nothing. 2

MR. PARKER: One transformer serves the 3

whole town? 4

MR. SAINT: Right. And one coop serves 50 5

towns, but they’re not interconnected. But we can 6

provide you the list from our membership and it will 7

be 99 percent rural, and how you want to divide it, 8

there’s several

-- IEEE, as far as their reliability 9

calculation looks at, I think, less than 30 is rural 10

per mile, between 30 and 60 is suburban, and over 60 11

is urban. And you can argue that too all day long. 12

But I’m not 100 percent clear on what data you need. 13

You want the load or the number of customers that 14

are classified as rural, or the number of utilities 15

that are primarily rural? Most utilities have all. 16

MS. COUGHLIN: We can

-- I suggest we 17

discuss this off line and we can go through the 18

details. 19

MR. SAINT: That’s fine. 20

MR. PARKER: Okay. John. 21

MR. CASKEY: Yes, John Caskey, NEMA. And 22

I can understand that this is an issue, particularly 23

dealing with the loading on the rural

- related 24

transformers, but I’m not sure what you do with the 25Executive Court Reporters (301) 565

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results. I mean, in the case of a vault 1

transformer, I know that that physically is 2

different than a pad mount transformer. But in this 3

case, I’m not sure how this plays out relative to a 4

manufacturer producing one transformer at a certain 5

efficiency for a rural cooperative and a different 6

transformer for an investor

- run utility. I’m ju st 7

not sure how that plays out in the long run, or 8

would this put a constraint on the efficiency that 9

we as a group might pick for the entire class of 10

transformers? 11

MS. COUGHLIN: Yes, so the purpose is to

- 12

- again, what the LCC tries to do is it tries t o 13

simulate this wide variety of conditions and then 14

you get the probability that any given transformer 15

that is produced ends up in one of those conditions. 16

So we’re trying to actually predict to the extent 17

possible, the real life cycle cost of transformer s 18

installed in all these varying conditions. So what 19

this would have the effect of doing is changing the 20

weighting of different load profiles in the LCC for 21

the entire design line. And that will then, in 22

turn, affect which efficiency levels look cost 23

eff ective. 24

MR. PARKER: So it’s not purely a 25Executive Court Reporters (301) 565

- 0064 207

distributive analysis. It’s not just a question of 1

looking at what the impacts on rurals would be, it 2

will actually go into a statistical analysis that 3

will affect efficiency standards for the entire 4

line. 5

MR. GAYTAN: Carlos Gaytan, Prolec GE. On 6

the Chapter 11 of the LCC analysis, it has a 7

statement that “Virtually all rural cooperatives 8

perform some type of economic evaluation of economic 9

transformer losses.” My question is, do you have 10

data that supports that statement, and if that data 11

can be validated with inputs from the utilities? 12

I’m looking at the 11.5.2. 13

MR. BOLDUC: Right. You’re referring to 14

the A and B parameter selection? 15

MR. GAYTAN: Yes. It says that virtually 16

all of the rural cooperat ives perform some sort of 17

economic evaluation of losses. 18

MR. BOLDUC: That statement is

-- to come 19

up with that statement we did a survey of A and B 20

bids for transformers on the market. And pretty 21

much

-- most coops that we found have a public 22

bidding p rocess, and of those, most of them actually 23

specified As and Bs in their bid documents. 24

MR. PARKER: Okay. So what I hear around 25Executive Court Reporters (301) 565

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the table, correct me if I’m wrong, is that we’ll 1

form a group on this as well that Ken will work and 2

Bob Saint, anybody els e want to be on this group? 3

Will work with them on coming up with first 4

validating the criteria, which the IEEE might be 5

one, to categorize this group, and see whether the 6

assumed loading factors that are currently in the 7

model are accurate for this group . Is that a fair 8

statement of what we’re doing going forward? And if 9

not, to make a recommendation as soon as possible as 10

to what adjustment needs to be made. 11

With regard to the weight, do you have 12

data that goes to what the percentage of all 13

transform er sales are going to rurals so that you 14

know how to weight this in the statistical model? 15

MR. BOLDUC: Right, EEI

-- or sorry, IEEE 16

861 has the market shares of the electricity sales 17

by type. 18

MR. PARKER: And do those track the 19

definitions of rural th at are being proposed around 20

the table here? 21

MR. BOLDUC: I actually think coops are 22

broken out separately. 23

MR. PARKER: Okay. Well, we’ll leave it 24

to the group to work out the details of that so we 25Executive Court Reporters (301) 565

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don’t get further mired in that. Great. Want to 1

m ove on to your next slide quickly, equipment price 2

trends? 3

**Equipment Price Trends** 4

MR. BOLDUC: Yes, thank you. Equipment 5

price trends. In recent analysis we’ve been looking 6

at equipment price trends over time for commercial 7

equipment. The first rulem aking to do this was 8

refrigerators, also called “learning”. For 9

transformers, we took the data series from the 10

Bureau of Labor Statistics, the ... price index for 11

transformer equipment and deflated it over the GDP, 12

the change in GDP, and came up with three scenarios. 13

In these scenarios, the price trends are used to 14

either

-- to adjust the overall impacts, the MTV 15

impacts over time in the NIA. So we’ve come up with 16

three scenarios. 17

The first scenario is the default 18

scenario, which is flat, so no

-- no pri ce trend or 19

no price increase over time. The second trend is a 20

low price trend scenario, which looks at the entire 21

transformer PPI data series, and it shows a slight 22

decline over time. And that’s from 1967 to 2010. 23

And the third scenario, we’ve taken th e last 20 24

years of transformer prices, and that shows a 25Executive Court Reporters (301) 565

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relatively steep upswing in transformer prices. 1

I’ll show you that on the next page what the chart 2

looks like. 3

So these are our projections. The red 4

line is the high price trend where we find a 5

se nsitivity in the NIA. And the dotted green line 6

is the low price trend. Steve. 7

MR. ROSENSTOCK: Steve Rosenstock, EEI. 8

Again, just to

-- I appreciate this very much, and 9

the flat line is really

-- is that a constant 10

nominal price or a constant relativ e to inflation? 11

MR. BOLDUC: Constant relative to 12

inflation. 13

MR. ROSENSTOCK: Okay. So in your high 14

price scenario and the red line, you are assuming 15

prices that are increasing higher, at a faster rate 16

than inflation, which is what’s happened over the 17

last several years, correct? 18

MR. BOLDUC: In the red line, yes. 19

MR. ROSENSTOCK: And those

-- the results? 20

MR. BOLDUC: The results aren’t published 21

yet. 22

MR. ROSENSTOCK: Okay. So, and again, 23

that’s going to be of interest to all end use rs in 24

ter ms of that sensitivity case. Thank you. 25Executive Court Reporters (301) 565

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MR. BOLDUC: Andrew. 1

MR. DeLASKI: Chris, again, my vision’s 2

not great. What’s

-- the inflection point, is it 3

where the data starts going up, is that around 2005? 4

MR. BOLDUC: 2003. Yes, so seven years 5

isn’t really enough time to project a long term 6

trend from. We took the past 20 years. 7

MR. DeLASKI: The 2003, is that consistent 8

with what you manufacturers observed? 9

(Discussion off mic) 10

MR. DeLASKI: And that in

-- well, then 11

there’s a slight drop aga in

-- again, I’m having 12

trouble reading the graph, but that’s

-- 13

PARTICIPANT: (off mic) 14

MR. DeLASKI: Okay. Then maybe next 15

year’s data will reflect that. And this is data 16

that you gathered with interviews with 17

manufacturers? 18

MR. BOLDUC: This is data published by the 19

Bureau of Labor and Statistics. 20

MR. DeLASKI: ... PPI data. 21

MR. BOLDUC: Yes. 22

PARTICIPANT: (off mic) On the 23

transformers or

-- 24

MR. BOLDUC: Distribution trends from 25Executive Court Reporters (301) 565

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manufacturing and specialty equipment, I believe. 1

MR. SCHO EN: Jerry Schoen, AK Steel. I 2

think you ought to look at the price of steam coal, 3

the price of copper, the price for aluminum, and the 4

price of just iron ore and plot it on that same 5

graph. And I think you’ll find out that’s what’s 6

driving that. 7

MR. B OLDUC: We do

-- in the appendices 8

that isn’t published yet, I really apologize, we do 9

a plot where we take aluminum, steel, copper, and we 10

do plot it against this, and it does show about a 11

one year lag between rise in commodity prices and 12

fluctuation in t ransformer prices. 13

MR. PARKER: This is good. Why don’t we 14

take

-- are there any other concerns with this? I 15

want to take a break very soon, but let’s see if we 16

can

-- any concerns that we have with this and then 17

we’ll break. Aaron. 18

MR. MEYERS: Bas ed on the

-- Aaron Meyers 19

-- based on the

-- what I would call violent swings 20

here, do you feel that the sensitivity that you’re 21

projecting is sufficient, or how much do you feel

-- 22

how confident are you that that will capture the 23

real swings in price? 24

M R. BOLDUC: We do a sensitivity to put 25Executive Court Reporters (301) 565

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balance on the price. 1

MR. PATTERSON: The driver for the 2

transformer price increasing starting in 2003, the 3

prime driver was a shortage of core steel. Right? 4

It wasn’t so much cost of commodities, it was 5

shortage and capacity to produce and meet the 6

demand. This is what drove it. Now that was an 7

unusual bubble, but that bubble could reemerge, 8

depending on what it is we do with an efficiency 9

standard. We may not have production capacity of 10

steel to meet the deman d. 11

MR. PARKER: Sounds like there could be a 12

short term and a longer term adjustment

-- price 13

impact, right, with the short term spike in prices 14

caused by a shift in patterns created by the 15

standard, perhaps, followed by a decline later as 16

capacity catch es up to the demand? 17

MR. PATTERSON: Yes, Richard. If you’re 18

concept of short term is a seven to ten year window. 19

MR. BOLDUC: Steve. 20

MR. ROSENSTOCK: I was going to say, just 21

in terms of some of this is just the impact of just 22

rising global demand on all of this, especially with 23

the economies in developing world growing at eight 24

to ten percent clips, which means doubling over the 25Executive Court Reporters (301) 565

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next ten, seven to ten years. That could also have 1

another

-- I think you’ve captured sensitivities 2

fine, but based on j ust world

-- growth in other 3

countries, and their terms of electrification and 4

installing this experiment, I think this is a fair 5

representation myself. I know you don’t have to do 6

the global demand into this analysis, obviously, but 7

I think there is

-- t hat’s part of the underlying 8

growth in the cost, my view, my personal view. 9

MR. PARKER: Chuck. 10

MR. SIMMONS: Yes, Chuck Simmons, Progress 11

Energy. Back around 2009, Progress Energy looked at 12

the impending final rule in effect and at that time 13

we were expecting

-- we went out to vendors, and we 14

were looking at an average of 25 to 35 percent 15

increase in transformer prices. But, I guess, lucky 16

to us, the economy tanked in 2009 and yeah, we still 17

realized price increases on the average of probably 18

eight t o 13 percent, and core steel was a big thing 19

back I guess in the 2005 to 2007 range. There were 20

vendors on allotments, so , you know, that’ s very 21

scary to us as a utility, to not be able to serve 22

our customers if the efficiency requirements were 23

going to require certain levels. 24

MR. DeLASKI: Chuck

-- this is Andrew. I 25Executive Court Reporters (301) 565

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just wanted to make sure I understood you right. 1

So, the price increases that you actually observed 2

close to 2010 implementation were on the order of 3

eight to 13 percent. 4

MR. SIMMONS: Yes. 5

MR. DeLASKI: But your analysis, that was 6

because demand was dropping overall for transformers 7

because of the economy going down, the housing 8

starts, et cetera, et cetera. 9

MR. SIMMONS: That's correct. 10

MR. DeLASKI: But the actual impact on 11

pric es that you observed was on the order of eight 12

to 13 percent. 13

MR. HOPKINSON: Phil Hopkinson, HVolt. 14

Question for you is at what point in the price curve 15

would you expect the rebuild market to take off, and 16

how would that impact this curve? 17

MR. PARKER : Anybody want to comment on 18

that? 19

MR. SIMMONS: Well, this is Chuck Simmons, 20

Progress Energy. I don’t have a specific number in 21

mind, but I know our repair of older units has 22

really picked up, and we’re looking at third parties 23

to repair units. It’s

-- I think all utilities will 24

have to, in turn, do that in order to justify

-- in 25Executive Court Reporters (301) 565

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fact, as Bruce mentioned, some of the tighter 1

restraint units, but network vaults and some 2

overhead units, we would have to rebuild or else 3

face enormous costs in replacement

. 4

MR. HOPKINSON: Well, my question comes 5

back to, if you know that in advance, is there a 6

constraint on what this negotiating committee can 7

work up as a proposed standard that would not 8

destroy the market? 9

MR. FERNSTROM: This is Gary from PG&E. 10

Let me make a quick comment on that. As Chuck 11

noted, we rebuilt some transformers too, but 12

typically they’re the specialty transformers. We 13

don’t usually rebuild commodity transformers, which 14

would be the 65 percent of the market we’ re talking 15

about the medi um sized pole mounts and pad mounts. 16

PARTICIPANT: (comment off mic) 17

MR. FERNSTROM: Okay. So, Chuck

-- 18

MR. HOPKINSON: I don’t think that’s 19

universally true. I think a lot of people do it. 20

MR. FERNSTROM: Well, it sounds like, you 21

know, we do th ings differently, and in California we 22

don’t. It sounds like Chuck does. 23

MR. HIRSCH: Just to try to answer your 24

question a little bit more. I mean, take an a... 25Executive Court Reporters (301) 565

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curve where it’s going to kick in, crystal ball 1

signs, depending on how steep that red curve is

-- 2

and by the way, I’d like to point out that that 3

curve doesn’t show what would happen if you get into 4

material shortages. Look at the curve from 2003 to 5

2009, that’s what it’ll look like. If it goes that 6

route, then certainly we’re going to be kick ing in, 7

looking at rebuilding transformers. 8

Like Gary, we don’t do a lot of 9

rebuilding. It’s the special units. But our 10

rebuild, or our refurbishment guidelines are based 11

on the cost of replacement, so

-- and they’ve been 12

in the past if it costs less than 20 percent of the 13

cost for replacement, we would refurbish. So as 14

that cost of the new unit goes up, we’re going to 15

refurbish more under those guidelines. 16

MR. ANDERSON: I think the

-- Rick 17

Anderson, Fayetteville PWC. I think we see costs go 18

up. I think the utilities will become more 19

aggressive in their protection philosophies. We’ll 20

see a lot more lightning protection. We’ll get more 21

conservative on the fusing, which in turn means when 22

storms come along, the lights are going to go out 23

more oft en. Okay. Because they’re going to make a 24

conscious choice to protect the asset and not have 25Executive Court Reporters (301) 565

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to go out and buy a new one. Make the one that’s in 1

there last much longer. So I think what you’ll see 2

is reliability indices become poorer as we try to 3

protec t the asset. 4

MR. PARKER: Let’s take a ten minute, ten 5

or 15 minute break. Do people have a problem, we’re 6

running a little bit late. Is it possible to stay a 7

little bit past five, or do people need to break out 8

of here at five

-- do we have to leave a t five? 9

(Whereupon, at 4:03 p.m., the meeting was 10

recessed for a 23 minute period, and reconvened at 11

4:26 p.m.) 12

MR. PARKER: Okay. Let’s get started. 13

First, I passed around a sheet that I thought, in my 14

absent

- minded professor mode, I thought it had 15

already been passed around, and I’m apologize for 16

not getting it to you at the beginning. But this is 17

just basically the issues that are presented, and 18

we’ve already, as you can see, we’ve already worked 19

through quite a number of them: transformer load 20

fa ctor, transformer peak load factor, lifetime, 21

space constrained units, pole replacement, rural 22

cooperatives. We’ll finish up with equipment price 23

trends. This gives you an idea, though of what we 24

have left to do. So we still have some more work to 25Executive Court Reporters (301) 565

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do an d let’s just see how much we can do. 1

We were talking about equipment price 2

trends. I guess what I’d like to do is just get a 3

sense of the group, recognizing that we’re 4

prognosticating, we’re guessing about the future, 5

anything can happen. Is there a st rong sense that 6

this is not a reasonable range of price assumptions 7

on balance? Because we need to really, as you can 8

see, we have a lot to accomplish and we need to 9

think about, you know, what is the critical path, 10

what do we need to go forward? Does th is need to be 11

altered, or doesn’t it? So, let’s just have a very 12

quick discussion on that and hopefully we can

-- we 13

can reach consensus on that and move on. 14

MR. HOPKINSON: This is Phil, and I heard 15

some good input from the utility guys over here that 16

they said that a 20 percent cost differential 17

between a rebuild and a new transformer would be the 18

point where they would consider the rebuild. So if 19

that number is a go to the bank number, then you 20

might be able to plug it into the model and see 21

where th e curve ought to peak. 22

MR. PARKER: That’s a 20 percent 23

manufacturing selling price? Excuse me. 24

PARTICIPANT: Yeah. 25Executive Court Reporters (301) 565

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MS. COUGHLIN: We actually need an 1

indepen den t estimate of the cost of rebuild. 2

MR. PARKER: Where would that come from? 3

MS. COUG HLIN: That’s the question. We 4

haven’t seen any data on that, so if someone can 5

give us that

-- an estimate. I mean we could cook 6

something up based on the distribution of costs, 7

labor, materials, et cetera, but it would be more 8

useful if people who have experience with the issue 9

would submit that information. 10

MR. SIMMONS: Chuck Simmons, Progress 11

Energy. We were just speaking, Gary and myself, 12

after

-- before our break

-- and when we’re 13

repairing these, we repair those that we just do 14

simple replace t he bushings, gaskets, simple 15

repairs, so we nowhere approach

-- we probably 16

approach 20 percent of the cost of a new unit to 17

repair. I mean I can give you some data that we’ve 18

recently done for those repairs, if that’s

-- 19

MS. COUGHLIN: I think we may b e talking 20

about two things here. So that sounds like 21

maintenance costs, which are part of the ownership 22

costs. 23

MR. HODGE: Gerry Hodge from

-- 24

MR. HOPKINSON: You had some concepts, and 25Executive Court Reporters (301) 565

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I think that the concepts are correct that repair 1

that would invo lve a core coil would be something 2

where you’d use the new winding and you’d have a 3

cost of stripping down a unit, putting the core back 4

in and putting probably new bushings in it. But if 5

it comes down to that, you really end up with a 6

winding that won’t get any bigger than what was 7

there from before, and you

-- but it will be a new 8

winding still, so that you’ll have a cost associated 9

with it, and you’d have a cost of magnetic core that 10

disappears and you didn’t have to buy a new one. 11

But you have a lot m ore labor with it, so I don’t 12

know what that would work out in in number. But you 13

probably could get to it. 14

MR. HODGE: Gerry Hodge from Howard. I 15

haven’t analyzed that, what it would cost, but 16

basically you could use most of the existing parts 17

if you had a coil failure, and let’s just say it’s a 18

1985 transformer, well, we could bring that in and 19

we could wind a new coil exactly like the one that 20

was wound in 1985, and take it apart, disassemble 21

the cores. You know, the core is the most expensive 22

part of the transformer. Most likely, you could 23

reuse the cores and the tank and bushings, unless 24

they’re broke. So you’d have to put some numbers 25Executive Court Reporters (301) 565

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together, but a person could save a lot of money, I 1

think, in rebuilding, if they want to get into that. 2

Now , we’re not advocating that in a way, 3

but that is a business that somebody could get into. 4

MR. PARKER: It seems to me that if the 5

transformer, if the rebuild costs exceeds

-- the 6

price goes up above 20 percent of

-- from the 7

current price, then it’s che aper to rebuild. If 8

that’s the case then, there’s no

-- you would never 9

rebuild unless it reaches 20 percent. So if you can 10

validate that number, that would be sort of the cap 11

on the permissible price. Is that what people are 12

saying? 13

MR. ROSENSTOCK: Steve Rosenstock, EEI. I 14

think a better way to put would be it wouldn’t have 15

an impact on the price, it would have an impact on 16

the shipments. That as, let’s say, if you’re 17

looking at the red line, the sensitivity case, and 18

again if you want to use Bruce ’s ratio of rebuild 19

cost as a percentage of the new transformer cost, 20

that’s going to have an impact on the actual 21

shipments and that’s not going to change the actual 22

price of the transformer. I think that’s the

-- 23

again, in terms of modeling, if there ‘s a way to 24

model, especially in the top case, maybe in the 25Executive Court Reporters (301) 565

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reference case

-- and again, I don’t have the data 1

in terms of the cost of rebuild versus a new, but if 2

you want to use that ratio, then you might want to 3

say that this is going to have an impact on the 4

shipments because as the price increase, especially 5

if it’s above inflation, and the rebuilt price does 6

not increase at that same rate, then the percentage, 7

as you go on, the percentage of rebuilds increases 8

over time. I don’t know what that rate is. So not 9

on the price, but on the shipments, which obviously 10

spills over into all the other energy savings, et 11

cetera for the life cycle cost and impact analysis. 12

MR. PARKER: Andrew. 13

MR. DeLASKI: I haven’t heard anything 14

thus far that I think would h elp anyone to be able 15

to model the rate of rebuilding. So it strikes me 16

as being an exercise

-- Steve’s right, I mean 17

ultimately, this will affect the shipments, which 18

affects the NIA. It’s not going to affect the life 19

cycle cost analysis. So I think ul timately it’s not 20

going to have an impact on the standard selected in 21

a serious way. So I guess I would suggest that it’s 22

an interesting conversation. I don’t think it’s one 23

that’s going to have a significant impact on the 24

standards within the range in w hich we’re likely to 25Executive Court Reporters (301) 565

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be discussing. 1

PARTICIPANT: (off mic) ... doesn’t make 2

sense. 3

MR. DeLASKI: My point is that it’s going 4

to affect the NIA, not the LCC. 5

PARTICIPANT: (off mic comment) 6

MR. HOPKINSON: If the market disappears

-- 7

MR. DeLASKI: E xcuse me, it’s what? I’m 8

not saying

-- okay, if someone can give me data that 9

would indicate the rate at which you would expect 10

rebuild to happen based on price change, that would 11

be something you could model. But thus far all I’m 12

hearing is speculation. I also think there’s a lot 13

of confusion here about what is a rebuild? There is 14

maintenance and then there is rebuilding. So, these 15

are two different things. It’s not the same, and I 16

think the rate at which we’re seeing rebuilding, 17

actually rewinding a transformer is where the 18

existing market is, pretty small, and there’s a lot 19

of money to be made here, as Gerry suggests, it 20

hasn’t happened thus far, so what’s the magic 21

threshold that people are speculating about, and 22

what do we have that’s more than sp eculation? 23

So I just suggest that we could spend a 24

lot of time on this, but we’re not going to get any 25Executive Court Reporters (301) 565

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clarity. 1

MR. HOPKINSON: I think you’d have to make 2

an assignment in order to get the answer back, but I 3

bet you could get it. 4

MR. RIVEST: Mike Ri vest. I’m starting to 5

feel like the Michael McCabe in the room. 6

PARTICIPANT: With an engineering law 7

degree. 8

MR. RIVEST: With an engineering law 9

degree, and like the historian. In the clothes 10

washer rulemaking, the replacement was modeled and 11

it wa s modeled as

-- a decision was made as to 12

whether at the end of life there would be a replace 13

versus repair decision. And a portion of the 14

washers, rather than being replaced, were being 15

repaired, and that was called the life extension. 16

So it might

-- th e repair might extend the life 17

another five, six years. 18

What that had as an impact on the rule is 19

that it reduced shipments for manufacturers for an 20

amount of time. It also reduced the national energy 21

savings because you weren’t retiring that stock. So 22

that’s how it played out in that rule. 23

MR. MEYERS: Aaron Meyers, Cooper. The 24

difference here in distribution transformers from 25Executive Court Reporters (301) 565

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washing machines are really most anything else that 1

you could compare to is that those machines have 2

moving parts, moving pa rts which wear. The 3

transformer has no moving parts. If you were to 4

disassemble a 30

- year old transformer and pull the 5

core out of it, which has been immersed in mineral 6

oil, that core is going to look like new. That core 7

can be used again. And manufac turers will have a 8

serious economic decision to make as to whether or 9

not to expand or explore the rebuild market versus 10

new transformers. Based on I think some of the data 11

that we saw earlier, Rick you were looking at a 12

transformer that went from $15,000 to $25,000. If 13

you can rebuild that transformer and still keep the 14

old core so there’s no cost involved in that, you 15

might be able to get a replacement that’s $15,000 or 16

less than $15,000. And that can be a compelling 17

economic decision for customers to make. 18

MR. FERNSTROM: This is Gary from PG&E. 19

The core

-- if the transformer burns out, the core 20

isn’t going to look the same. If the core looks 21

brand new, the only reason you’d rebuild it is if 22

something happened to the bushings or the case, and 23

that’ s not commonly the case. Where most of the 24

transformers we’re replacing now, we’re replacing on 25Executive Court Reporters (301) 565

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burn

- out, otherwise we would be buying new 1

transformers for new construction, and we’d be 2

replacing transformers where their capacity has been 3

exceeded. And w here the capacity’s been exceeded, 4

the transformer may well have been overheated and 5

might not have been a really good candidate for 6

rebuilding. 7

MR. PARKER: Okay. It sounds to me like 8

we need to move on. Did I get around the table, is 9

there a sense th at this is a reasonable set of price 10

trends, all things considered, given what Gary has 11

just said, or do we need further discussion of this? 12

By the silence, everybody’s consent. We need to 13

move on. Let’s move on. 14

MR. NADEL: I wanted to say one thing on 15

this whole rewind issue

-- Steve Nadel from ACEEE. 16

MR. PARKER: Yeah, right. 17

MR. NADEL: This is an issue, I agree is 18

probably not a big issue, but it’s an issue that 19

potentially can be managed. One of the things that 20

we can do, ACEEE, and some of the other people 21

around the room is educate the utility commissioners 22

through NARUC on how it will lower consumers’ energy 23

bills, lower the losses, if they actually purchase a 24

new, more efficient transformer instead of rewinding 25Executive Court Reporters (301) 565

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an old one. So there are t hings that we 1

collectively can do, not all of us, but many of us, 2

to help keep this problem in check. 3

MR. PARKER: Great. Thank you, let’s move 4

on then if

-- Mike, yes. 5

MR. HYLAND: Who said it’s a problem. The 6

rebuilding. It’s an option, not a prob lem. I just 7

want to make sure we’re clear on that. 8

MR. HOPKINSON: This isn’t that tough, 9

then. I think that I can help if I’m commissioned 10

to do it, but it comes down like this. If we take 11

the cost based replacement and go back and rewing 12

and go thr ough the steps that we talked here, it’s 13

probably in the range of an 80 percent of the 14

selling price of today’s new one, not of the new new 15

one. So if the new new one gets to be 20 percent 16

higher in price, then the difference now becomes 40 17

percent, so t hat basically we can take the delta 18

selling price divided by the change in watts to go 19

from where we are today with design efficiency zero, 20

up to EL1, let’s say, and we can see the dollars per 21

watt and it’s going to be real big, which would say 22

that probab ly we cannot justify a full 20 percent 23

change in selling price before the market 24

disappears. 25Executive Court Reporters (301) 565

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MR. PARKER: Okay. Thanks. Let’s move 1

on. 2

**Electricity Prices** 3

MR. BOLDUC: The next slide is basically 4

electricity prices for the results that you’ve seen 5

and the NOPR used, AEO’s electricity price trends 6

for 2011 to scale the existing prices in the 7

analysis. Not a large impact. AEO 2011 is the most 8

recent version of AEO. No questions, great. Thank 9

you. 10

**Evaluation Rates** 11

Also this refers to the

-- in the c onsumer 12

choice model, prospective transformer purchasers who 13

evaluate using As and Bs, A and B factors. These 14

have been revised since the preliminary analysis. 15

They’ve been revised downward based on a comment 16

from stakeholders and this committee. So for the 17

transformers that we’re talking about today, those 18

would be the liquid immersed transformers, design 19

lines one through five. We assume a 50 percent 20

evaluation rate. And then for the small and medium 21

-- small capacity, medium voltage, dry type 22

transf ormers, we use ten percent. And for high 23

capacity, medium voltage, we used 20 percent. 24

MR. HOPKINSON: How do you plug that in? 25Executive Court Reporters (301) 565

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MR. BOLDUC: I’m sorry? How do we plug 1

that in? 2

MR. HOPKINSON: Yeah. 3

MR. BOLDUC: In the LCC model? In the 4

LCC, for every iteration, we assume that for a 5

liquid immersed transformer, each iteration of the 6

simulation is a 50 percent chance of being either a 7

lower first cost purchase, or a purchase that’s 8

evaluated with As and Bs. 9

MR. HOPKINSON: (off mic) 10

MR. BOLDU C: In terms of efficiency, it 11

can mean that those who evaluate may buy a 12

transformer that is of higher efficiency than the 13

current standard. 14

MR. MEYERS: All right. Aaron Meyers, 15

Cooper. I can tell you that that is way off base. 16

MR. BOLDUC: Would y ou like to provide a 17

number? 18

MR. MEYERS: Sure, I’ll provide a number. 19

I would say that between 80 and 90 percent of 20

purchases made are within two

- hundredths of the DOE 21

efficiency level. So, the purchase

-- or sorry, the 22

efficiency level is being drive n mainly by material 23

availability: core steel widths, winding conductor 24

increments, things like that. So if you’re 25Executive Court Reporters (301) 565

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targeting something that’s at the DOE minimum, 1

oftentimes the end result isn’t the DOE minimum, it 2

might be a hundredth of a percent of effi ciency 3

higher. So looking at that slice of the pie, in 4

excess of 80 percent, probably closer to 90 percent, 5

are at the minimum DOE level. 6

MR. BOLDUC: Okay. Can you provide data 7

to us on purchases by efficiency. 8

MR. MEYERS: I have the data but there may 9

a confidentiality issue there. 10

MR. BOLDUC: If you could look into it or 11

aggregate it somehow

-- 12

MR. MEYERS: We can discuss it later. 13

MR. BOLDUC: Yeah, I’d appreciate it. 14

MR. PARKER: And you’re also covered by a 15

confidentiality agreement, r ight. 16

MR. BOLDUC: Right. 17

MR. NADEL: Steve Nadel , ACEEE. Question. 18

What about bands of equivalence? Because in our 19

experience, while A and B are commonly used, as 20

often a band of equivalence is used that pretty much 21

cancels out the whole calculatio ns. 22

MR. BOLDUC: Right. I’m going to redirect 23

that to Katie. 24

MS. COUGHLIN: The reason why this makes a 25Executive Court Reporters (301) 565

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difference is that in the LCC, if someone is already 1

purchasing an efficient transformer within the 2

standard, it doesn’t necessarily affect them, t hat’s 3

the actual impact that we’re trying to capture. So 4

we

-- and when we

-- because there’s some 5

uncertainty in the prices that are output by the 6

engineering analysis, we do a sort of version of the 7

band of equivalence is to put some random noise on 8

the prices so that you’re not always selecting the 9

mathematically lowest price in the dataset, because 10

we know those prices are uncertain to within a few 11

percent. So there’s essentially a band along the 12

bottom of the price efficiency curve which 13

represents t he designs that are selected at lowest 14

first cost. And we could do some post

- processing

-- 15

we don’t know that if that essentially drops you 16

down to most

-- essentially and A and B of close to 17

zero, that may have that effect, but it does create 18

some variab ility in the design selection. 19

MR. NADEL: Steve Nadel. I think it’s 20

two different issues. Yes, it’s price variation. 21

You should model that. But I would agree with the 22

earlier comment that if it’s A and B modeling 23

without a band of equivalence, you’ re way over

24

estimating, and I would lower that percentage to 25Executive Court Reporters (301) 565

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take account of the fact that a band of equivalence 1

means a lot less people are truly doing that life 2

cycle analysis. 3

MS. COUGHLIN: Yeah, I’d also like to 4

point out that you don’t necessarily have a change 5

in efficiency because you have an A and B value. 6

The efficiency is a two

- parameter function of the 7

two types of losses, so you could be buying the same 8

efficiency, but you could have slightly different 9

design criteria. 10

MR. PARKER: Steve. 11

MR. ROSENSTOCK: Just a quick one. You 12

know I think we also discussed, had some issues, but 13

we also said that at least for the investor

- owned 14

utilities, there are certain states where investor

15

owned utilities are required to use total owning 16

cost and us ing A and B values. I know Maryland, 17

California, I’m not sure what other

-- I think 18

Washington, Vermont, D.C.

-- they’re required. So 19

it might be lower

-- I don’t know how much lower 20

it’s going to be lower, and again, that’s just the 21

investor

- owned, not

-- I’m not going to speak f o r 22

the m unis and coops. But it’s not a bad number to 23

use, in our view. 24

MR. PARKER: Andrew. 25Executive Court Reporters (301) 565

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MR. DeLASKI: I think we had a similar 1

conversation in our first meeting, and I don’t know 2

if Aaron was there or not, were you at ou r first 3

meeting Aaron. 4

MR. MEYERS: I was on the phone. 5

MR. DeLASKI: Okay. But I think at that 6

same meeting that we heard from the manufacturers, a 7

number of manufacturers, that in their experience 8

that about ten percent of sales were above DOE 9

minim um standards. I see a lot of nodding heads, 10

for the record, around the table. 11

PARTICIPANT: (off mic) ... more than five 12

percent higher ... 13

MR. DeLASKI: For your company. 14

MR. PARKER: Wes Patterson just said that 15

for the record, that 30 percent of pole mounted 16

liquid immersed, per his company were evaluators? 17

MR. DeLASKI: No, he said

-- 18

MR. PARKER: Were more than five percent. 19

MR. MEYERS: Speaking for my company, pole 20

mounts are the product class where the greatest 21

percentages above the DOE, s o the pad mount class, 22

substation class, everything else, is typically 23

right at the DOE

-- 24

MR. DeLASKI: So in the pole mount class 25Executive Court Reporters (301) 565

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you’re see more differentiation above the level. 1

MR. MEYERS: Yes. 2

MR. DeLASKI: So, I guess my question, so 3

that

-- m y question, I guess, to LBL or to an 4

analyst is, how does that square with your 50 5

percent evaluator? Can that square with your 50 6

percent evaluator? 7

MS. COUGHLIN: Yeah, I mean, this is 8

something

-- this is extremely easy to change this 9

number. You go into the spreadsheet, you type it in 10

and you run it, so it’s

-- we have been carrying 11

this around as a kind of default value, but there’s 12

no reason why you can’t

-- if people can agree on 13

the numbers that are appropriate, and if you want to 14

have those num bers vary by design line, we can do 15

that. So for us, I don’t think it’s really worth 16

our time to try to defend the 50 percent. If you 17

have a number that you think is defensible and we 18

can go on record, then we can take that number and 19

work with it. 20

MR. BOLDUC: Sorry, I would just like to 21

ask a question. Is the primary driver of purchasing 22

units that are at or very close to the DOE standard, 23

price? 24

PARTICIPANT: Yes. 25Executive Court Reporters (301) 565

- 0064 236

MR. BOLDUC: That is the primary driver. 1

Okay. So I can tell you in the LCC we d o see units 2

selected of the higher efficiency curve, but the 3

price is usually within

-- it is within 15 percent 4

of the unit in the base case. So it could be an 5

artifact of

-- we perturbed the unit prices by 15 6

percent, so this could be an artifact that wa s 7

carried through from the engineering curves. 8

MR. MEYERS: Aaron Meyers. Some people do 9

look at windows, but 15 percent is probably much too 10

large, something on the order of five percent, maybe 11

two percent might be more reasonable. 12

MR. BOLDUC: Yeah, so you’re saying two to 13

five percent difference in same

-- same spec to 14

transformers between different manufacturer s, they 15

will compete to within two to five percent in price? 16

MR. MEYERS: No. I’m saying that you can 17

place a window on price and losses, and within that 18

window there might be some variation. So if a 19

customer can purchase a unit that’s more efficient, 20

sorry

-- let me see, what were you saying about the 21

15 percent? That it is 15 percent

-- 22

MR. BOLDUC: We perturbate the 23

manufacturer’s se lling price of the transformers by 24

15 percent in the LCC to account for different 25Executive Court Reporters (301) 565

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market scenarios. It’s a random between zero and 15 1

percent every iteration of the run. What happens in 2

this case is a base case unit, if it’s plus 15 3

percent and a unit of a higher efficiency range is 4

actually at zero, someone

-- an evaluator will pick 5

the higher efficiency unit at no additional cost. 6

They look the same in the LCC. 7

MR. HOPKINSON: Phil Hopkinson, HVolt. 8

From my experience in dealing with total owning 9

co st, most of the manufacturers’ computer programs 10

will print out the top ten designs, and of those top 11

ten, some of them are going to be higher efficiency 12

with

-- so they’re all the same TOC, but some will 13

be higher efficiency with higher selling price, and 14

others will be lower efficiency with lower selling 15

price. But they both have the same TOC. The one 16

that almost always gets picked is the one with lower 17

selling price at the same TOC, because ultimately, 18

it’s the low first cost that still otherwise hits 19

their criteria that the market is after. Does that 20

make sense? 21

MR. BOLDUC: Yeah, and that’s precisely 22

what the LCC does. 23

MR. MEYERS: Yeah, to expand on what Phil 24

just said. The windowing, if they specify a TOC, 25Executive Court Reporters (301) 565

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you can provide the lowest total owni ng cost, but if 1

there’s one that’s slightly less efficient, but is 2

correspondingly a great deal cheaper, they will pick 3

the one that is less efficient with the lower first 4

cost. It’s really working in the reverse, like good 5

enough. That’s exactly true. 6

MR. GAYTAN: Carlos Gaytan, Prolec GE. 7

Our data shows that at least 80 percent of the 8

transformers are within that window of five percent 9

of the DOE minimum efficiency on one hand, and also 10

in addition to the band of equivalence influence, 11

there may be o ther cases in which the evaluation 12

factors are used, but at certain values below the 13

threshold where the design optimization process 14

leads to a

-- anyhow the DOE minimum efficiency 15

design. So the

-- at the end, those lower than 16

average evaluation factors do not lead to a higher 17

efficiency design. 18

MR. COFFEY: Okay. And just a little more 19

information. You could end up with As and Bs in the 20

spreadsheet that would put you lower than minimum 21

efficiency, and you would buy the minimum efficiency 22

for a standa rd. 23

MR. MILLURE: Dave Millure, Metglas. Just 24

an observation. We were talking about the issue of 25Executive Court Reporters (301) 565

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poles and the weight of the transformer. It’s 1

interesting, 30 percent of the transformers being 2

sold for poles are over DOE, so they’re already some 3

of th e way up the curve where we’re going. So they 4

are, the heavier units required are going up the 5

poles already. 6

MR. ROSENSTOCK: Steve Rosenstock, EEI. 7

But it doesn’t say what percentage weight increase. 8

If it’s a five pound increase, most people can 9

ha ndle that, I think. 10

MR. CYMBALSKY: So, Chris, is there a way 11

to benchmark your models so that the market share 12

of, I guess, the liquid immersed comes out to 30 13

percent that the market buys up on efficiency? 14

Based on whatever you set that 50 percent or 15

whatever? 16

MR. BOLDUC: We can look at it and we can 17

make

-- let me just say, we’ll review the model and 18

we’ll take

-- 19

MR. CYMBALSKY: It seems to me that if 20

they’re saying 30 percent buy

- up, then 50 percent 21

evaluating is probably not bad, because 20 pe rcent 22

are still buying least cost. 23

MS. COUGHLIN: But the fine point here is 24

that, as Chris mentioned, if you’re evaluating, and 25Executive Court Reporters (301) 565

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your evaluation would lead you to buy something less 1

efficient than DOE, you buy DOE. So we really

-- we 2

don’t have quite en ough information to distinguish 3

between evaluation and actually purchasing above the 4

minimum standard level. I also should mention, we 5

do sensitivities at zero evaluators and 100 percent 6

evaluators, and there actually it’s surprisingly 7

little impact on m ost of the efficiency levels 8

because the As and Bs that we have from our surveys 9

are pretty low, so even if you’re evaluating, you’re 10

not necessarily buying an efficient unit on that 11

basis. 12

MR. PARKER: So if that’s the case, maybe 13

we don’t need to belab or it late in the day. 14

MR. SAINT: So what I’m hearing is that 15

even those folks that evaluate by A and B factor, 16

they may be buying a more efficient transformer, 17

most of them aren’t, but some of them may be, but 18

it’s not that much more efficient. And so I’m not 19

sure why it matters how many are evaluating because 20

it really doesn’t matter, they’re buying pretty much 21

the same transformer, the minimum standard 22

transformer today. 23

Now if we increase that efficiency level, 24

then no one will be evaluating tra nsformers because 25Executive Court Reporters (301) 565

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it costs more

-- the totaling cost is out of the 1

water. So I’m not sure why it makes any difference 2

how many people evaluate, because today, at least, 3

it doesn’t matter whether they evaluate or not, very 4

much. And if we increase it at a ll, no one will 5

need to evaluate because we’re not buying the most 6

cost

- effective transformer, period, anyway. 7

MR. PARKER: So what I’m hearing around 8

the table is basically there is a

-- a gut reaction 9

that a smaller fraction are buying by evaluation 10

th an 50 percent, and if the standard goes up, that 11

ratio is going to go even further down, and so 12

perhaps a prudent course would be just to agree on a 13

lower ratio, say 20 to 30 percent, or even lower 14

than that. 15

PARTICIPANT: Ten. 16

MR. PARKER: Ten percent ? And again, this 17

doesn’t seem to be a fundamental

-- and we can do a 18

sensitivity analysis for what happens if you 19

increase it to 40 percent or down to zero percent, 20

but let the base case be then ten to 20 percent. 21

Steve. 22

MR. ROSENSTOCK: In terms of th e analysis, 23

again, I think what’s important is where we end up, 24

and if the data is showing that 30 percent are 25Executive Court Reporters (301) 565

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buying above those DOE minimum levels, then that 1

number should be used in any of the energy savings 2

and life cycle cost analysis. 3

MR. PARKER: Okay. Andrew. 4

MR. DeLASKI: We heard, if I remember 5

correctly, spinning back the conversation, I think I 6

heard Wes say it was 30 percent for pole mount 7

transformers. He’s got his pie charts here, and 8

will share them, I suspect, with the agency. So I 9

t hink it does

-- there’s data, I suspect that the 10

manufacturers have data, and I guess sounds like a 11

subcommittee should get together and share that with 12

the consultants and base the analysis on what we see 13

in the market. 14

MR. PARKER: Do we have

-- are th ere any 15

issues

-- low voltage is a separate committee, but 16

for medium voltage dry type, do these look like 17

reasonable figures for people? Is it mostly in the 18

liquid immersible we have the issue? You need more 19

data? 20

MR. HOPKINSON: In dry types, my 21

impr ession is almost every customer takes the 22

minimum efficiency, so if that puts that number at a 23

pretty high to those who just buy on low first cost 24

of whatever is a permissible transformer. And of 25Executive Court Reporters (301) 565

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course those transformers are not going to 1

utilities, they’ re going to the industrial/ 2

commercial market which is not using a 30 year 3

period to amortize costs, they’re down closer to a 4

seven year period. 5

MR. ROSENSTOCK: Steve Rosenstock, EEI. I 6

would agree with that. The primary market for the 7

last three bul lets are commercial or industrial 8

customers. None of them are working with A and B 9

factors because they’re doing their own economics 10

based on their own traditional commercial and 11

industrial terms. They’re not worried about the 12

price of wholesale power wh en they’re doing their 13

analysis. 14

MR. PARKER: So I think that’s helpful. 15

Why don’t we

-- Phil, go ahead. 16

MR. HOPKINSON: Oh, I am just burning with 17

a question because you’ve done a great job here, 18

Chris, and I do commend you even though I’ve been 19

back and forth arguing with myself to see if I agree 20

with you. But the question that I have is the 21

subject that you were working on before, you didn’t 22

bring me to where I wanted you to, and that was you 23

were talking loading and I wanted to know, are you 24

going to recommend any change to the point where 25Executive Court Reporters (301) 565

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losses are measured? So we’re using 50 percent for 1

medium voltage, and that’s what we’re working here, 2

we’re using 50 percent of name plate today as the 3

test standard, and I would pontificate just a little 4

bit m ore, because I’ve thought this through quite a 5

long time, and it goes like this, that at 50 percent 6

of name plate, core loss equals load loss at 50 7

percent load. Now, let’s look what happens if you 8

go to 35 percent load. At that point, core loss 9

equals l oad loss at 35 percent load, and the loss 10

ratio between load loss divided by core loss is ten 11

to one. And while at 50 percent load it’s four to 12

one. 13

So now, then I heard from my friend Robert 14

Berman back there, well, how about 18 percent load. 15

If you go to 18 percent load, the loss ratio is 42 16

to one. Now the implications of that are that as 17

you go down and down and down in efficiency, where 18

you measure the efficiency, it’s going to result in 19

transformers being sold that are low on core loss, 20

they wi ll be, but they will have very high 21

regulation and impedance, and you turn on your 22

refrigerator and your voltage drops from 120 down to 23

40. Now you can’t really tolerate that, and 24

probably Steve Rosenstock and my utility friends 25Executive Court Reporters (301) 565

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over here would say, ah! But if you’re only looking 1

at efficiency

-- you’ve got to get the rest of the 2

picture, so that what I say is, I love the 50 3

percent load point for measuring efficiency because 4

it does guarantee that you’re going to have some 5

robustness out of the winding t oo. And I didn’t 6

hear you say it, but I wanted to hear you say it, 7

that’s why I was kind of teeing you up for it. Does 8

that make sense? 9

MR. BOLDUC: I understand

-- I think I 10

understand what you’re talking about, Phil, but the 11

test procedure isn’t some thing that is in our 12

purview and I’m going to wait for your presentation 13

actually before speaking about it, thank you. 14

MR. PARKER: Let’s see if we can put this 15

thing to bed, either with an agreement on evaluation 16

rates that are workable from the standpo int of just 17

a heuristic model, understanding that there will be 18

a sensitivity analysis, or a process for going 19

forward. Because we’re absolutely at the end of our 20

time, and we need to wrap up. So what I would 21

suggest is that

-- is there an agreement that 22

basically these numbers are okay for the others, or 23

shall they be lowered to say, ten percent for the 24

commercial as the base case. Can we just

-- again, 25Executive Court Reporters (301) 565

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this is

-- 1

MR. CYMBALSKY: Are we going to look at 2

the data from Wes and some of the other guys? 3

MR. PARKER: So you want

-- do you have 4

data for the whole market segment, Wes, or just

-- 5

MR. PATTERSON: (off mic comment.) 6

MR. BOLDUC: Well, can we come back to 7

that and I’ll just flip through the last two slides? 8

MR. PARKER: Okay. 9

**Final Topics** 10

MR. BOLDUC: Sure. So it’s been suggested 11

that as the efficiency rises in the model, there 12

will be a lack of diversity in terms of possible 13

design combinations, As and Bs, available to be 14

purchased. While this holds true at the extreme, 15

that would be M axtech, you get a very small amount 16

of A and B values, or combinations that you can make 17

transformers out of, in the intervening efficiency 18

levels there is quite an amount of designs that can 19

be used to meet the standard. 20

On this graph, on the vertical a xis, we 21

have load losses, the horizontal axis we have no 22

load losses. The red triangles represent 23

transformer designs in the base case. The green 24

dots represent transformers selected, in this case 25Executive Court Reporters (301) 565

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it would be the first efficiency level, EL1, and you 1

can see that there’s, aside from the fact that we’re 2

picking amorphous core at EL1, you can see there is 3

quite a range of transformer designs that meet 4

standard. 5

Press up the efficiency, the next slide is 6

efficiency level 3. It does decrease, but there’s 7

still a fair amount of designs. And then at 8

Maxtech, there are very, very few. I see a lot of 9

confused faces. Do I have any questions? 10

MR. ROSENSTOCK: Steve Rosenstock, EEI. I 11

think we’ve been used to the other slides that were 12

showing design lines, so this is the first time 13

we’ve seen a graph like this, so that’s why you have 14

the confused

-- I see exactly what you’re doing and 15

you’re representing the data differently, which I 16

appreciate the

-- the problem comes in that, you 17

know, we’re used to diffe rent dots for different, 18

you know, all the combinations of metallurgical 19

designs, and now you have the same data kind of done 20

differently so that’s why you got the confused 21

looks, at least from my point of view. 22

MR. BOLDUC: Yeah, in this particular 23

plot , the grouping on the left, those are actually 24

marked as core designs, the load/no load losses. 25Executive Court Reporters (301) 565

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MR. ROSENSTOCK: And the other thing, 1

Steve Rosenstock, EEI, the other thing is that we’ve 2

been kind of focused on design lines one through 3

five for the most part, so design line seven is, you 4

know, just

-- 5

MR. BOLDUC: I’m sorry, that’s a typo 6

actually. It is design line one. 7

MR. ROSENSTOCK: Thank you. Phil. 8

MR. HOPKINSON: For my simple brain and 9

not a real smart brain, but what I would tell you is 10

w hen you’re over here, oh, at 120 watts of no load 11

loss and 300 watts of core loss, that would be a 12

transformer with a two and a half to one loss ratio, 13

and that would be optimized for maybe 70 percent or 14

80 percent of rated load. So that would be one that 15

doesn’t fit too well with where we are. 16

When we’re looking at one with 100 watts 17

and 500 watts, that’s a five to one ratio, and that 18

would be optimized at 40 percent of load. So if we 19

had that loss ratio, a five to one ratio, that would 20

be optimized fo r 40 percent and maybe you’d even 21

want to test it at 40 percent of name plate, but at 22

least that’s the way the numbers look like they fit. 23

If you’re over here with the amorphous and 24

you are at

-- let’s go 40 and 400, that is a ten to 25Executive Court Reporters (301) 565

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one loss ratio, and the optimum for that turns out 1

to be at 35 percent of load. So that’s just things 2

to kind of think about. Okay. That make any sense? 3

MR. PARKER: My sense this is not an 4

action item. 5

MR. BOLDUC: This is for illustrative 6

purposes. This is the fin al slide. 7

MR. PARKER: Wes. 8

MR. PATTERSON: Coming back to how much 9

product is actually moved that is lower losses than 10

the DOE standard, both single

- phase and three

- phase 11

across all of what I see, 40 percent was within five 12

percent of the DOE standard , 60 percent was more 13

than five percent lower losses. 14

MR. MEYERS: The data that I looked at 15

suggested that for single

- phase pads, 81 percent 16

were within .02 percent of the efficiency, the 17

minimum efficiency; 82 percent

-- sorry, 81 percent 18

of three

- phas e pads, 82 percent of single

- phase 19

pads, 81 percent of single

- phase poles, and 93 20

percent of substations. 21

MR. ROSENSTOCK: Steve Rosenstock, EEI. 22

As a follow

- up

-- 23

MR. PARKER: Excuse me, Aaron, is that 24

from your

-- what is that data now? 25Executive Court Reporters (301) 565

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MR. MEYERS : That’s greater than a year’s 1

worth of shipment data. 2

MS. COUGHLIN: Are these

-- these are all 3

liquid immersed or

-- 4

MR. MEYERS: That's correct. 5

MR. BOLDUC: Can you share that? Can you 6

mail that to me? 7

MR. MEYERS: I’m not going to mail the 8

actual data, but

-- 9

MR. BOLDUC: You shared the percentages. 10

MR. SAMPAT: This is Mahesh Sampat, EMS 11

Consulting. Basically all it says is you are 12

adjusting one segment of the market and then ABB is 13

addressing another segment of the market. That’s 14

all it says. 15

MR. MEYERS: What my real concern was with 16

the 50 percent evaluation is if you’re assuming that 17

those that have evaluation formulas do not see any 18

additional cost for moving to higher efficiency, I 19

would argue that that assumption is false. An d 20

furthermore, with the evaluation formulation, you 21

move higher with your efficiency standard

-- the 22

evaluation formula essentially is specifying a 23

preferred ratio of no load losses to load losses, so 24

it allows customers to right

- size the transformer 25Executive Court Reporters (301) 565

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for t he application or the industry that they serve, 1

and if we move the efficiency level up further to 2

the point where it becomes too expensive for them to 3

try to balance that ratio, and also meet the minimum 4

efficiency, they’re only going to buy to the minimum 5

efficiency, which will be wrong

- sizing it for their 6

application. Or Rick, I think you had mentioned, 7

you’re buying a tank when a golf cart would suffice. 8

And that’s the fear in raising the efficiency, is 9

that we’re raising the efficiency, but with a fix ed 10

loading factor, and not allowing the customers to 11

make the decision based on their system. 12

MR. ANDERSON: Rick Anderson, Fayetteville 13

PWC. I’d like to follow up with Aaron. The think 14

is is that we’re limited, as a user, how to apply 15

these things. I ’ll go back to the subdivision. If 16

we could put six services on one transformer, we 17

would. Okay. But what happens, and it goes back a 18

little bit to what Phil was saying about impedance 19

and regulation. When you start to go too far, you 20

have voltage drop , and that’s just a fact of life we 21

have to live with. So I think as users, we’re 22

really trying very hard to buy the most efficient 23

transformer based on the best information we have. 24

And our systems are limited, physically, to voltage 25Executive Court Reporters (301) 565

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drop. 1

If you tu rn around and say, all right, 2

here’s the loading, and you have to be this much 3

better at being efficient, we’re going to buy it, 4

but you ain’t going to see it, because we’re not 5

going to change the way we apply them. So I’m not 6

really sure we’re getting a nywhere

-- we’re really 7

accompl ishing anything. We’re going to buy a dump 8

truck what we can do with a golf cart. 9

MR. BOLDUC: Thank you. Steve. 10

MR. ROSENSTOCK: Steve Rosenstock, EEI. 11

Again, I don’t know how it fits into the analysis, 12

but I know for

-- I think for all utilities, but I 13

know for investor

- owned utilities, they’re required 14

-- voltage drop on a regular basis has shown up to 15

be less than five percent. The range. Some are 16

three percent, but typically they’re allowed a range 17

of plus or minu s five percent, that’s it. So they 18

have to make sure whatever design they use does not 19

-- is probably a lot less, to be on the safe side, a 20

lot less than five percent, three percent. 21

MR. HOPKINSON: Could I respond to

-- I 22

think that’s a really good poi nt, and I’ve seen 23

those numbers for a good many years in my career, 24

and I would ask you to amplify, because maybe we can 25Executive Court Reporters (301) 565

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knock off this thing on loading this afternoon if 1

we’re lucky. And utility purchases when you do have 2

A and B factors have had a loss ratio that has 3

actually been pretty narrow range. Now, it’s been 4

proposed by some that, I think Mr. Berman back here 5

proposed that these loss ratios that are in the A 6

and B selection are not thought out well by the 7

utilities, and that they’re somewhat cap riciously 8

chosen. And yet I see loss ratios that are three to 9

one or four to one, and very few that are five to 10

one. I never see them any higher than that. And my 11

question is, what is the basis of the total owning 12

cost formula that you have out there, a nd especially 13

the B factor, and how have you arrived at it. Is 14

it, in fact, capriciously chosen? 15

MR. BERMAN: Can I respond to that since I 16

was stated to have said something which I didn’t? 17

MR. PARKER: Okay. You’ve got it. 18

MR. BERMAN: Pardon? 19

MR. PARKER: Very quickly. 20

MR. BERMAN: Okay. Robert Berman, Berman 21

Economics. I never said anything like that. The 22

comment was made basically that discussing 23

efficiency, measured efficiency versus efficiency in 24

the field, if you take a transformer a nd design it 25Executive Court Reporters (301) 565

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at 50 percent load, as has been suggested, and then 1

put it in the field and operate at 35 percent load 2

or a 25 percent load, you get a much lower 3

efficiency than what you set the standard at. If 4

that’s what you want, that’s fine, but you need to 5

understand that that’s how the numbers work. 6

MR. HOPKINSON: If I had the time to make 7

my presentation, which I haven’t been given, if I 8

had the time, the loss curve and the efficiency 9

curve from up to 50 percent, if you set it at 50 10

percent and make that 99 percent efficiency, if you 11

drop back to 35 percent, you’ll see that you’re 12

within two

- tenths of a percent of that same 13

efficiency. And in terms of total watts that are 14

dissipated, you’re basically in a really fine range. 15

And I’ve got curves to s how it. 16

MR. PARKER: Okay. We are past our time. 17

What I’d like to do is basically stop there for now. 18

What I think we’ve done in this is just walk through 19

the LBL engineering data and identify a number of 20

areas where we have basic agreement, things li ke 21

peak load factors, transformer lifetime, electricity 22

prices. There are other areas where more work needs 23

to be done. What we’re going to try to do this 24

evening is basically come up with a list, a to do 25Executive Court Reporters (301) 565

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list, a task list, that pulls together, I think, 1

what we heard during the discussion today, along 2

with some suggestions to nudge along those areas 3

where we didn’t

-- nudge along the process where we 4

didn’t agree on a process. We’ll put that on the 5

table for you first thing in the morning and see if 6

we c an get agreement, not only on a process, which I 7

think we’ve been discussing, but think about a 8

timetable for doing this, how soon can we get this, 9

and working backwards from our deadlines. And 10

what’s the right process for putting it into a 11

planned timeli ne. 12

So, we’ll do that tomorrow. We’ll also 13

hear from AK Steel on their analysis of the 14

competitive

-- the steel competitive impacts of 15

alternative efficiency levels. There is, remember, 16

a sort of a competitiveness TSL breakpoint that we 17

were talking ab out in the first meeting that we need 18

to try to see if we an pin down, so that will be a 19

priority for tomorrow morning. So I hope to allow a 20

fair amount of time for that. So we’ll work on 21

that. 22

And then I’ll ask Rob Carmichael of 23

Navigant to talk a lit tle bit about the 24

manufacturing impacts, to get at Aaron’s concern 25Executive Court Reporters (301) 565

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about the retooling costs and so forth, so we’ll 1

have a discussion about that. 2

So there’s a lot to do tomorrow. We’ll 3

start

-- we’ll start bright and early at nine 4

o’clock here and we’ ll try to end at 12 or no later 5

than 12:30, and hopefully we’ll be able to finish 6

our work. So think about timeline, think about what 7

really needs to be done with this. We’ll come back 8

with what we see as the consensus of the group as 9

process moving forw ard. And we’ll try to end 10

tomorrow with a specific charge to Navigant and LBL 11

on what needs to be done. Yes. 12

MR. ROSENSTOCK: Mr. Parker, just a few 13

things. There are a few other bullet points on 14

this, the one

- pager in terms of forced non

- optimal 15

tran sformer purchases and then changes to the 16

analysis. Is that at some point tomorrow as well 17

after the other presentations? 18

MR. BOLDUC: No, I’m sorry, Steve, I wrote 19

this list at six o’clock this morning, so it was a 20

little bit behind

-- under the weathe r, shall we 21

say. The forced non

- optimal transformer purchases 22

were the last four slides that we saw. 23

MR. ROSENSTOCK: Okay. 24

MR. BOLDUC: And impact of electric 25Executive Court Reporters (301) 565

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vehicles we discussed earlier in the presentation, 1

basically, don’t account for it. And the addition 2

of a new LCC subsgroup and data center is for low 3

voltage transformers. So none of the last

-- 4

MR. ROSENSTOCK: Low voltage dry type. 5

MR. BOLDUC: Low voltage dry type, that’s 6

right. 7

MR. ROSENSTOCK: Okay. 8

MR. PARKER: Eric, yes. 9

MR. PETERSEN: One of the things we’ve 10

talked about quite a few times here is Mr. 11

Hopkinson’s

-- this is Eric Petersen, AK Steel

-- 12

Mr. Hopkinson’s presentation. I just wanted to 13

understand how would we integrate that information 14

into our discussion, into our agenda? 15

MR. PARKER: The presentation on

-- 16

MR. HOPKINSON: (off mic) On loading

-- 17

MR. PARKER:

-- loading

-- 18

MR. HOPKINSON:

-- and product cost and in 19

workable watts ... 20

MR. PARKER: Okay. Maybe what we should 21

do then is we’ll

-- maybe wha t we should do is start 22

with that tomorrow, and we will get that on the 23

table because that will feed in with the way we deal 24

with the request for data. Fair enough? 25Executive Court Reporters (301) 565

- 0064 258

MR. PETERSEN: Thank you. 1

MR. PARKER: Okay. 2

MR. DeLASKI: The time? I’m just 3

con cerned about our time here. I mean we’ve got an 4

agenda for tomorrow that’s already stacked up. 5

You’ve got three hours. We discussed loading today, 6

so why are we going back to loading. 7

MR. HOPKINSON: (comment off mic) 8

MR. PARKER: I guess the questi on is can 9

we do this in a work group, which I think is what we 10

discussed doing , not in the plenary. 11

MR. DeLASKI: I think we also have to 12

recognize, as Chris stated, that the test method is 13

not open for negotiation. 14

MR. HOPKINSON: Well, that’s right, so if 15

that’s true, but are the numbers open. So the 16

method was fine, but if we change from 50 percent to 17

35 percent, and the load actually turns out to be 18

greater than 35 percent, then that’s when it really 19

kills you on watts lost. It’s not if you go a 20

l ittle bit under, because the watts difference are 21

very small then. It’s on the up side, and you’ll 22

see the shapes of the curves, they fall off quickly 23

from the point where you optimize. 24

MR. DeLASKI: I hear you. I thought where 25Executive Court Reporters (301) 565

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that was left today was that different utilities 1

were going to provide data to the LBL to get to 2

corroborate whether their loading data is correct. 3

MR. BOLDUC: Yeah, and that’s what I’ve 4

heard from the meeting today, is we’re receiving 5

data. I think the committee criticized t hat 33 6

percent

-- 7

MR. DeLASKI: I don’t doubt that it’s 8

sensitive, it’s important. I think we have a 9

process for getting it. 10

MR. HOPKINSON: That doesn’t really quite 11

do it. Why do the utilities have A and B factors

-- 12

why do they have a B factor tha t’s so close to the A 13

factor? Why do they have one that is in a four to 14

one range as opposed to a ten to one range. And I 15

know the answer, but you haven’t said it and so if 16

you just give them equivalent load, that doesn’t 17

tell you the base of what the te sting point should 18

be. And I think it should stay at 50 percent, and I 19

haven’t heard anybody say that you agree with that 20

yet, and if you just say yes, I agree, I leave. 21

MR. PARKER: Is there agreement that the 22

test procedure should be at 50 percent. 23

MR. HOPKINSON: Yes, this is a test 24

procedure issue. 25Executive Court Reporters (301) 565

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MR. PARKER: Okay. Good. We’re done. 1

Thank you, folks. 2

MR. BOLDUC: Phil’s happy, then we can 3

leave I guess. 4

MR. PARKER: All right. Are we ready 5

then? In that case we will go back to our orig inal 6

plan, which was to start with

-- 7

MR. POLINSKI: Richard, this is Ray 8

Polinski, Allegheny ATI. Again, why

-- I just don’t 9

understand why we don’t take another half hour

-- I 10

thought we were going to work until six tonight 11

anyhow, it’s only 5:30, and why don’t we hear from 12

some of Mr. Hopkinson’s comments. I guess the whole 13

group would benefit from that. We’ve listened to so 14

much stuff, information, today, I don’t know, it 15

just

-- 16

MR. PARKER: We were going to work until 17

six on those days when we only had two days. This 18

was not

-- we have three days

-- a day and a half

-- 19

full day and a half for each committee, so this 20

wasn’t a day that we had allocated until six. 21

MR. MEYERS: I think the question was 22

posed earlier whether we could work longer , and I 23

don’t think 20 minutes constitutes really working 24

longer. I would agree with Mr. Polinski in favor of 25Executive Court Reporters (301) 565

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working longer tonight, however long it needs to be, 1

I’m willing to support that. 2

PARTICIPANT: I can agree to that too. 3

PARTICIPANT: I woul d say we flew a long 4

distance for this, this is important topic, that’s 5

why we’re here. 6

MR. PARKER: Other comments? People want 7

to work later

-- 8

MR. POLINSKI: I’m just saying, if he 9

wants to give his presentation, that’s fine. 10

MR. CYMBALSKY: I ’d rather do it now than 11

run out of time tomorrow. 12

MR. PARKER: Okay. Fair enough. Okay. 13

(Whereupon, the meeting was off the record 14

for a brief period.) 15

MR. PARKER: Excuse me, everyone, if we 16

could have your attention and we will work through 17

th is analysis. 18

**Presentation** 19

MR. HOPKINSON: Take the one on loading 20

first, please. Everybody in this room should have a 21

copy of this because I mailed it to distribution. 22

But I would take you down to this set of curves is 23

one that is particularly intere sting. And you’ll 24

see a light curve at the bottom which seems to 25Executive Court Reporters (301) 565

- 0064 26 2

disappear on us, but that is a utility curve for 1

loading in the summer in the southeast. So you’ll 2

see light loading at night, and obviously peaking 3

during the day, and that certainly makes sense. 4

But the RMS equivalent of that is a more 5

like the heavy black line, so what they have done, 6

and of course it changes seasonally as well as it 7

does

-- well, I guess that would be a better way to 8

say it, it just changes seasonally during the year. 9

Now if we go beyond this

-- Robert, I 10

didn’t

-- I don’t see Robert right now

-- but I 11

didn’t really mean to shortcut the issue of what 12

happens to watts, but my point is we have 13

transformers that are optimized for different peak 14

conditions on here. Some of the curves that I have 15

are optimized for much bigger differentials and what 16

happens with the dotted line, it’s optimized for 17

about 30 percent load, and the one that is the 18

dashed line is optimized for about 45 percent load. 19

What you’ll see is it doesn’ t make too much 20

difference for loads that are less than that, as far 21

how many watts are involved. What happens, though, 22

is if you don’t guess right and the loading turns 23

out to be much heavier, then in fact, the watts are 24

going to be severely impacted bec ause both the 25Executive Court Reporters (301) 565

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efficiency falls off, but the load is higher, so in 1

terms of total watts, it’s a lot of watts. So my 2

point is stick with that 50 percent. We don’t know 3

anything more, none of us do. I don’t either, to 4

make things more precise than that, bu t it has 5

worked well for decades. And I mean going way back 6

into the 1960s and before. And I have no basis to 7

recommend anything different than the 50 percent as 8

a test plan, I think it’s a good one. Okay. So 9

that’s on loading. Any questions on that? Yes, 10

Rick. 11

MR. ANDERSON: Rick Anderson, Fayetteville 12

PWC. I want to make sure I understand what you’re 13

saying, Phil, is that your opinion is that the load 14

factors for, say, residential customers are 50 15

percent. 16

MR. HOPKINSON: Yes. That’s for the t est 17

point. That’s for the test point. Now if the load 18

factor turns out to be less than 50 percent, the 19

watts differential from there versus a transformer 20

that was actually optimized at 35 percent would be 21

pretty small. But if you put the load factor at 35 22

percent and say I’m going to make my test at 35 23

percent too, then you’ll have a ten to one loss 24

ratio of no load to full load, and the impedance 25Executive Court Reporters (301) 565

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regulation, flicker, all the bad things that you 1

don’t want are going to come roaring in. If you 2

make it 42 to one for an 18 percent load factor, it 3

just becomes a ridiculous transformer. So stick 4

with the 50 percent of name plate load as the test 5

point, and if your load factor happens to be a 6

little less, it’s kind of a so what. Does that make 7

sense? 8

MR. P ARKER: Any dissent? Yes, Steve. 9

MR. HOPKINSON: Mike. 10

MR. PARKER: Sorry. 11

MR. RIVEST: So this argument is about the 12

test procedure

-- 13

MR. HOPKINSON: It is in fact about the 14

test procedure, yes. 15

MR. RIVEST: Okay. 16

MR. HOPKINSON: But it ad dressed an issue 17

that both I tried to track what the no load and full 18

load losses of transformers have been over a long 19

period of time, and then they have supported the 50 20

percent measurement point as well. And by 21

agreement, we agreed to stay with it anyh ow so that 22

this is kind of water over the dam, but it does help 23

to clarify what the shape of those curves are. And 24

they fall off fast on the higher load side, and 25Executive Court Reporters (301) 565

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they’re almost the same on the lower load side, so 1

keep it at 50 percent, we don’t know any more than 2

that right now, I don’t think. Richard. 3

MR. ANDERSON: Just a little bit of 4

clarity, Phil. Most of the time the transformers 5

are lightly loaded, at night, spring, fall, and so 6

as a user we’re putting out there and sizing it to 7

make sure that we don’t blow them up on Christmas 8

and fourth of July, right. So what we see is that 9

95 percent of the time, the transformer is lightly 10

loaded, so a lot of time is spent lightly loaded, 11

when watts lost are very low. However, at those 12

peak times, Christma s, fourth of July, you can make 13

up so much more of those losses when the transformer 14

is peaking, right. So the peak load that’s applied 15

on the transformer is critical to the watts lost. 16

MR. HOPKINSON: I think all the way 17

around, both my utility friends that are here and 18

those that are not here who would stand up and bark 19

on this issue, they would say very much the same 20

thing, so I fully agree with you. Okay. 21

So I could take you through a mound of 22

data but if we have cinched the sale, I’ve learned 23

y ears ago we should shut up and leave

-- on that one 24

point. 25Executive Court Reporters (301) 565

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Let’s go back now and get off from this 1

presentation and go over to the presentation on the 2

economics, analysis. Can you go back to assumptions 3

in here. I’m not sure everybody agrees with the 4

a ssumptions, and you don’t have to, but if you don’t 5

like them, they are the basis of my report. So I 6

would take you down through, first, that the 7

manufacturers

-- why do I do this report at all? 8

Basically, I’ve been working for

-- and very closely 9

with B rian and Mike and the Navigant people, and 10

doing my best to help calibrate the OPS model, and 11

we’ve talked to the OPS people, and in fact they 12

made some fixes to the program. So I think it’s 13

been good work. 14

Then many other stakeholders come to 15

another m eeting that I am chairman of, and that’s an 16

IEEE transformers committee, and there’s about 100 17

people that typically come into my meeting and it 18

takes place every six months, and the next one will 19

be two weeks from now in Boston. And at that

-- 20

it’s utili ty people, it’s manufacturers, both NEMA 21

and non

- NEMA, it’s consultants. But a lot of them 22

have issues and they brought those issues to me back 23

maybe three years ago when they were concerned that 24

some of the efficiencies that were proposed in the 25Executive Court Reporters (301) 565

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DOE docu ments that we could easily get to, they 1

said, look, we have exhaustive search computer 2

programs and they’re not finding any designs. Now 3

how could that be? Well, the only way it could be 4

is that there were errors in the OPS data, and so 5

the work was to t ry to get to that. And we’ve had a 6

good working relationship so that I certainly think 7

that we’re doing things on the right path. And I 8

have absolute respect for the Navigant people. I 9

think you guys and ladies are very professional and 10

we’ve worked clo sely together and I’ve seen nothing 11

that says we have anything that is counter to that. 12

It’s just not. 13

But it is a process that we are going 14

through for every product line, and we have 15

actually, to this point, fixed a good many of the 16

product lines. The one that we have not really 17

fixed yet is the medium voltage dries, and I think 18

that Bob and Rob Greeson would certainly

-- actually 19

Wes back there, would all parrot that, that that 20

still needs some work. 21

But why don’t we go down then

-- one of 22

the th ings that I was after when I did an analysis 23

to support Navigant, was I talked to small 24

manufacturers as well as big manufacturers, and the 25Executive Court Reporters (301) 565

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reason for it is I didn’t want to have anything that 1

would come out in efficiency that would put the 2

little guys out of business. 3

For material prices, I had the 4

manufacturers give me their 2011 data. Now some of 5

them used standard material prices, and some of them 6

used actual dynamic prices that were current 7

purchases. And I couldn’t do anything but average 8

them, frankly. And I did and that’s what the basis 9

of doing those designs were. 10

And the other thing is that when we went 11

to number four, I didn’t use

-- because the 12

manufacturers who were doing the designs were using 13

engineering computer programs, and they were not 14

necessarily using production programs. And the 15

result is that there was not a real connect with 16

their marketing organizations to see how the selling 17

price would vary with material. But I can tell you 18

as a graduate of the university of hard knock s, 19

working for three of the major manufacturers, that 20

we guarded very preciously the materials to sales 21

ratio and we certainly never wanted to see that 22

rise. So that we were always trying to protect 23

that. And I used that, in other words, I had a 24

spreadsh eet that I developed and I had the 25Executive Court Reporters (301) 565

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manufacturers fill out that spreadsheet, and many of 1

them I sent back to the drawing board and told them, 2

you didn’t do it right. Do it again. And they did. 3

But when I got that done, I could see 4

whether it looked reas onable or whether anybody was 5

gamesmanshipping it, and actually, there were not. 6

And it was well done, and with that I had a starting 7

point of material to selling price. 8

Since I had that, I used that ratio on 9

future selling prices for each of the produc t lines 10

as we looked at what would happen if we went to the 11

next level of efficiency. And Matt Hartley had 12

given me some OPS designs as a starting point. 13

Those were OPS

- 1 I will call, before we went back 14

and had discussions and fixed, and then there was an 15

OPS

- 2 that actually was a whole lot closer to the 16

manufacturers. So I certainly think the process was 17

good. 18

Then items number six down here, is M3 19

core material and aluminum conductor. Why is that? 20

Well, this was 95 KV

- BIL and it felt to me, after 21

talking to the steel makers and actually my friends 22

at OPS asked me to talk to the

-- not at OPS, at 23

Navigant

-- asked me to talk to the domestic steel 24

makers to see, in fact, what material they could 25Executive Court Reporters (301) 565

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support. And what they came back with was M3. 1

Well, m y copper friends would love to have it be all 2

copper, of course, but I really thought that 3

conductors also should be available so that 4

depending on pricing and other factors, that a 5

manufacturer could choose either one. 6

So I asked the manufacturers to give me 7

data that would be M3 and aluminum, as far as they 8

could go with efficiency, and I used that to develop 9

the cost curves. On the economic value, as you get 10

down to number eight, I assumed a 30 year period for 11

both utility transformers and for indus trial/ 12

commercial transformers, but frankly, after thinking 13

about it more, I questioned whether 30 years really 14

ought to be applied to the industrial/commercial 15

because they’ve got different decisions. That is, 16

they wouldn’t do those voluntarily. They w ould go 17

to maybe a seven year payback period so that it’s a 18

question, is that a valid assumption. But that’s 19

what I had in there. 20

I also used a present worth based on a 21

three percent rate of inflation and seven percent 22

cost of money. So, again, you can question whether 23

that is a good arrangement, but at least I have 24

given the algorithm in the report so that if you 25Executive Court Reporters (301) 565

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don’t like those numbers, you just plug in and 1

you’ll get numbers perhaps you like better. But at 2

least I’ve got the algorithms in there. 3

So, finally, what I’m trying to get to is 4

incremental selling price, going from base level 5

zero to base level one, or to level one, level two, 6

level three, level four, and you’ll be able to see 7

in the charts what I came up with for dollars per 8

watt against the

-- what I think is the best value 9

per watt. Okay. 10

For present worth of a watt saved, what I 11

started with was EIA data on what certainly makes 12

sense, and I’ve had good help from several people 13

including my GE friends as well as from Federal 14

Pacifi c, in calibrating and finding the data on the 15

EIA site, but what comes down to wholesale power for 16

utilities in 2011 has averaged four and a half cents 17

per kilowatt hour. Okay. And so if they can sell 18

it for that, I figure their costs can’t be any 19

higher than that, and that’s what I used in my 20

analysis to finally get to, on a yearly basis, that 21

would be 39 cents a watt. 22

Now I just got something back from Memphis 23

Power and Light, saying, nope, our number is 14 24

cents per watt. Well, maybe it is, but tha t’s not 25Executive Court Reporters (301) 565

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what I used. I used 39 cents here. 1

And on the industrial and commercial side, 2

the cost per kilowatt hour was listed as 6.7 cents 3

per kilowatt hour. So that would give me a higher 4

cost in one year, of 58.7 cents. 5

Then, on items one, two, thr ee, four, and 6

five

-- so basically design lines one, two, four and 7

five are utility transformers, for the most part, 8

and so they would take the owning cost formula that 9

you’ll see in a moment that would go with utility 10

transformer, versus the medium voltag e dries are 11

almost 100 percent industrial, so they would take a 12

different number. 13

Load growth, I put in as a zero. Why did 14

I do that? Because in my experience, certainly over 15

the last decade, haven’t seen a whole lot of load 16

growth. You put a transf ormer in and you size it 17

appropriately and for the most part, load stays 18

pretty constant on it. And if it’s in an industrial 19

environment from all the industrial environments 20

I’ve been in, if you get substantial load growth, 21

you’re going to add new transfo rmers. So they get 22

pretty dedicated. 23

This algorithm, right up here, uniform 24

series present worth factor. Well, it’s not so 25Executive Court Reporters (301) 565

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uniform, but what it says is that a rate of 1

inflation, that’s the R factor, number of years is 2

the N factor, and G is the growth factor. So if you 3

don’t like my numbers, I don’t have any problem with 4

that, but I would say put in different numbers, but 5

what I used

-- a three percent inflation, a seven 6

percent interest rate, 30 years, I get a 17 7

multiplier. So it would be 17 times t he first year 8

cost of power, would give you that value per watt, 9

and that works out to $6.71 for utility transformers 10

and $9.91 for industrial. Now, you know, for those 11

customers who evaluate losses, I got back from my 12

manufacturing friends that the avera ge A factor for 13

those that go beyond the mandatory utility, are 14

$5.91 a watt. And so that’s not so far from the 15

$6.71 that’s here, that I’d say it passes the test 16

of reasonableness. 17

On the commercial industrial, again, I 18

used the 30 year period, but it’ s a question of 19

whether that’s relevant or whether it ought to be 20

brought down to a much shorter period, because let’s 21

say if you didn’t have a mandatory requirement, then 22

the industrials have many investment opportunities, 23

and they really have a hurdle ra te that requires 24

something more than 25 percent return on investment 25Executive Court Reporters (301) 565

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to make it past other competing investments. So it 1

really comes down to questioning whether the 30 2

years is a relevant number. 3

But then again, I’m not even sure that any 4

recommendati ons that I might have or others in this 5

room, make any difference, because I’m not sure if 6

this is part of the negotiating team’s purview. But 7

perhaps it is. But if it is, I think with this 8

relationship, with perhaps different numbers even, 9

would be some thing that the negotiating team can 10

concentrate on and decide whether you like this, 11

whether you want to change it, and get agreement. 12

Because there’s really only three things 13

that ultimately the team needs to settle on. 14

**•** The first is, the load factor and the testing 15

point, and we’ve basically agreed on 50 16

percent, so I’m happy on that point. 17

**•** The second is the value of a watt saved, and 18

that’s right here. So take this or change it, 19

but the team needs to get to a conclusion on 20

it. 21

**•** And the third is the cost curve as a function 22

of efficiency. 23

So let me take you down and look at some 24

of the results. This chart is particularly good, 25Executive Court Reporters (301) 565

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and the reason that it is is because I’ve taken, on 1

design line one, the 50 KVA single

- phase pad and 2

with the new OPS data

-- so this is the data that 3

came out August 31 st

And if we go from efficiency level one to 11

efficiency level two, it costs $20 a watt, and if we 12

go from there to efficien cy level three, it costs 13

$53 a watt. So it looks to me, as my simplistic 14

mind, if this is correct, then the value

-- if the 15

value is correct it says well you really don’t have 16

a basis to even get as far as design efficiency 17

level one before you’ve run out of gas. It’s a big 18

picture kind of thing, but that one made so much 19

sense. 20 , and it’s corrected so that it’s

4

basically comparable data. But what you will see is 5

the manufacturers’ data up at the top says that if 6

we go from design line zero to design line one, that 7

the increase in s elling price is $400 while the 8

watts saved are 20, and so we get a cost per watt to 9

go to that next level of 20 by this calculation. 10

Now, on OPS

- 1 it certainly looked like 21

where the people came into my IEEE meeting and were 22

concerned

-- they thought that the OPS data was 23

presenting an easier picture to go hig her 24

efficiency, they were correct. And you will see 25Executive Court Reporters (301) 565

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that in some of these numbers. It’s been corrected. 1

There’s still some issues, but basically you’re a 2

lot closer now with what the manufacturers gave me 3

to roll up. 4

If you walk down from here, I’ll j ust show 5

you how the plots work. Here’s with ZDMH too. I 6

think the point about ZDMH and my steel friends 7

could talk forever about it, but the point is it’s 8

not even sold in the United States, and it’s not 9

really a viable material to be plugged in as a pl ace 10

to base the standard. 11

Here’s a scatter plot that is pretty good. 12

The M is what the manufacturers gave me, and 13

actually if you don’t go too far in efficiency, 14

especially if you could look at the change that came 15

in after correction, the OPS data is c loser, and I 16

would say in the small efficiency change range that 17

it’s doable. It’s comparable, an the OPS data is 18

okay. If you go up too high in efficiency, it’s not 19

okay, and I’ve got suspects for why it’s not, and 20

what I think that it is is the lead l oss, stray 21

loss, tank loss goes up, and I don’t think that it’s 22

reflected in the discussion I’ve had with Naheed 23

(ph), I don’t think it’s reflected in the program. 24

I think that she does a good job with the 25Executive Court Reporters (301) 565

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core and winding, but if the lead loss gets too high 1

then it gets to be a controller at the highest 2

efficiencies because what it does is give a fixed 3

value of watts. So let’s say you had 2000 watts on 4

an arbitrary transformer, and 1000 of it turned out 5

to be lead, stray, eddy (ph), tank, then you’ve on ly 6

got 1000 watts left to put in the core and coil, and 7

they get much bigger. 8

So if we looked at the spreadsheet

-- this 9

is what I was talking earlier, that on the 10

spreadsheet, I can’t work with just selling price 11

because it doesn’t tell me anything. So I came up 12

with a whole series of parameters that I wanted the 13

manufacturers to give me data on, and they did. And 14

with that I then could sort out where there were 15

problems. Like in the single

- phase pad with the 16

OPS

- 1 data, if you look down at gallons of oil, it 17

was showing 21.9, and the manufacturers were showing 18

up with 41.3. And they were pretty tightly spaced, 19

so the manufacturers were close. So what was wrong? 20

And that program was fixed for OPS

- 2, so it has 21

actually been repaired. 22

But there wa s an algorithm error in the 23

program and, you know, I’m a crude programmer, 24

really crude, but I might think I’ve done a good job 25Executive Court Reporters (301) 565

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until I’ve reviewed it with somebody and then you 1

find that I didn’t do a good job, then I obviously 2

fix it. And that’s really the process that went on 3

here. 4

Total weight is another one that is quite 5

interesting. If you look down, it’s about five 6

items down. Total weight and going across, you’ll 7

see that the manufacturers had a whole lot higher 8

total weight as well, and as you go to higher 9

efficiencies, that kept increasing. So we really 10

had that piece to try to get a sense on too. And 11

then the weight of the core and the weight of the 12

winding. And it just told me that I really think 13

the manufacturers data is close to the rig ht answer. 14

Now you can argue the selling price, 15

because we tried to use selling price to the end 16

user as Bob Smith was talking about earlier on up 17

front. And so it’s off by

-- it’s overstated by 18

some percentage to what it would be at just the 19

manufact urer’s location. But that same relationship 20

was true for every one of the product lines we went 21

through. 22

Design line two on poles actually was a 23

lot closer, and if anything, the OPS data overstated 24

the price on the smaller efficiencies, and then 25Executive Court Reporters (301) 565

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underst ated it a little on the higher. But the 1

result is, you’ll see, that I’m coming up with, for 2

the manufacturers, $13.50 per KVA

-- per watt saved, 3

I should say, to go from zero to efficiency one. 4

And the OPS data would have said it cost more to 5

make that f irst step. I don’t think it does. So I 6

would say the manufacturers’ data is believable, and 7

that’s really the only data I can trust because 8

that’s the only one that I can see all of the facts 9

on. 10

Going down further, the scatter plot and 11

the manufacture rs’ curve is the top one

-- no, it’s 12

this one here that comes up, and OPS

- 1 veered off, 13

but it veered off because it went to amorphous. And 14

when I got OPS

- 2, I pulled off the M3 data from it, 15

and it looks like, as Wes had said earlier, that the 16

slopes are about the same for the poles of the OPS

- 2 17

versus the manufacturers. So I think that was good 18

feedback work. 19

Design line four. I think in this one 20

that the slopes were not too far different, but it’s 21

very strange. If you came across on OPS

- 1, you’d 22

se e that, oh, all of a sudden it got cheap. Well, 23

the reason that it did is it went to amorphous 24

again, to make a change. But if you stayed with M3, 25Executive Court Reporters (301) 565

- 0064 280

then they were not so awfully bad, but go down to 1

look at the scatter plot, you’ll see the 2

manufacturers’ c urve in M’s and you’ll see OPS

- 1 3

down below, and then OPS

- 2 is above it, and it can 4

go as far as efficiency level one and then it starts 5

to go to different steel. It went over to M2. So, 6

I’m not saying that that’s not a good thing to do, 7

but I think for

-- if the assumption is that we’re 8

going to try to find an efficiency that can be 9

doable with M3, then we really ought to constrain 10

the place where we go to such that in fact that it 11

works. 12

On this one, they had the same gallons of 13

oil problems that OPS

- 1 was showing 31.79 and the 14

manufacturers were coming up with 130. So basically 15

anything that was a rectangular tank, the OPS first 16

version was under calculating , and again, N aheed 17

(ph) found the formula problem and she’s fixed it. 18

So all of the rectangu lar tanks were that way. But 19

if you look at total weight too, total weight on 20

this one, the manufacturers were close at the 2700 21

pounds, and OPS

- 1 was 1700 pounds, and that spread 22

went across and got bigger. So again, I would tell 23

you that the one that I believe is the 24

manufacturers’ data. 25Executive Court Reporters (301) 565

- 0064 281

Let’s take design line five had some 1

really strange parts to it. The dollars per watt to 2

go to the first efficiency, we were coming up with 3

$17 on that, and of course, if the value per watt is 4

only $6.71, it really s ays that financially, it 5

doesn’t justify. 6

The plot, C curve 1 for OPS

- 1, was way 7

below

-- after you got past about 99.5 percent 8

efficient, because it went over to amorphous. The 9

manufacturers’ curve, on M3, took a steep rise and 10

it went up to $87,000 at the efficiency level four. 11

So this is the 1500 KVA. 12

Again, what we look at here is first the 13

gallons of oil had that same calculation error as 14

was present in any of the rectangular tanks. But 15

the total weight was a very strange one too because 16

down here, you’ll see a spread of maybe 3000 pounds, 17

2500 pounds at that efficiency. Way over to the 18

right, at the highest efficiency, the difference 19

between the manufacturers and OPS

- 1 was 10,000 20

pounds. 21

MR. PARKER: Sorry, can we have those

-- 22

can we have on the record, Mike and David, did you 23

want to

-- 24

MR. MILLURE: Yeah, Dave Millure, Metglas. 25Executive Court Reporters (301) 565

- 0064 282

He’s comparing an M3 design to an SA

- 1 design and

-- 1

MR. HOPKINSON: It is true, but it has the 2

compounding error of lead loss, tank loss, bus loss 3

that frank ly, they don’t really have a good, 4

accurate calculation on. So if the manufacturers 5

give them those numbers, they get it. But if you 6

don’t give it to them, then they really don’t have 7

it. 8

MR. MEYERS: Phil, is the column on the 9

far right, is that the m anufacturers’ amorphous 10

design? 11

MR. HOPKINSON: It is. 12

MR. MEYERS: So the manufacturers’ 13

amorphous design is 19,000 pounds and OPS’ is 14

10,000, is that correct? 15

MR. HOPKINSON: That is correct. 16

MR. MEYERS: Would you say that’s an 17

apples to apples comparison? 18

MR. HOPKINSON: Well, I think it is. 19

MR. PARKER: Mike, you want to respond? 20

He needs the mic. 21

MR. RIVEST: Phil, that was one 22

manufacturer submitted one data point, and I have

-- 23

I have all the data from all the manufacturers, and 24

I can tell you there is, you know, Phil is 25Executive Court Reporters (301) 565

- 0064 283

presenting an aggregation of four manufacturers. 1

Having aggregated data for many years, I can say 2

that averaging creates all sorts of issues. So, 3

Phil, so, you know, my take

- away from your 4

presentation is that you wo uld like this rule to be 5

based on M3 steel, that M3 steel has a much sharper 6

curve, correct: 7

MR. HOPKINSON: (off mic) It is ... 8

availability. 9

MR. RIVEST: Right. And that

-- I think 10

that’s my main take

- away. I think that at the 11

current analysis is in fairly good agreement when 12

comparing steels

-- the same grades of steels

-- 13

MR. HOPKINSON: (off mic) At low 14

efficiencies, the OPS

- 2 is

-- 15

MR. PARKER: Excuse me, you’re going to 16

have to speak into the mic. 17

MR. HOPKINSON: I think at low 18

efficiencie s, that is if you don’t change too far, 19

then the OPS

- 2 data is not so far off, and I think 20

Wes would agree with that, with the analysis that 21

he’s done with sales. He’s not selling transformers 22

that are way over to the far right, because there 23

haven’t bee n any orders for those kind. 24

MR. PARKER: Wes Patterson, ABB. 25Executive Court Reporters (301) 565

- 0064 284

MR. PATTERSON: Wes Patterson, ABB. I 1

sell units that are more than 40 percent lower than 2

the current standard, which is putting us all the 3

way up at the highest energy efficiency level the y 4

had. And my findings have been, at least on liquid 5

filled, that if you ignore the absolute value, and 6

look at the trends of the data, the trend of the 7

data is fairly good. 8

MR. HOPKINSON: But wait a minute. You’re 9

using amorphous in that analysis too , I think. 10

MR. PATTERSON: That's correct. I use 11

amorphous. I use M2. I use M3. 12

MR. HOPKINSON: Yeah, I agree. 13

MR. PATTERSON: I use M6. I use H

- zero, I 14

use H

- 1, which they didn’t include

-- the DOE didn’t 15

include in their analysis. 16

MR. HOPKINS ON: No, I know. I would say 17

that Mike’s comment is valid too that yes, we didn’t 18

have very much input on the amorphous so there could 19

have been amorphous designs that maybe would be more 20

optimal. But what happened was we were told to use 21

the efficiency of 99.69

-- they didn’t get quite to 22

99.69, they got 99.67 and they went aluminum

- copper, 23

so they had an aluminum low voltage and a copper 24

high voltage. So if you have to use the copper

- 25Executive Court Reporters (301) 565

- 0064 285

copper, you would have had a different design, that 1

would have been one of the factors that would have 2

changed it. And if the efficiency was allowed just 3

to go down a few points, it would bring the cost 4

down dramatically, because the core weight got 5

really out of line and the winding weight got really 6

out of line. So tha t’s what my observation is on 7

this data. 8

But what I would say is, that’s so far to 9

the right that certainly if the assumption of an M3 10

is going to be valid, then you wouldn’t want to go 11

that far to the right anyway. 12

MR. RIVEST: You know, I think it re flects 13

the fact that we are out of that take off area, so 14

maybe they’re both valid, it’s just that you don’t 15

have to be off by a lot to be way off. 16

MR. HOPKINSON: I think you’re right. 17

MR. POLINSKI: Ray Polinski, ATI 18

Allegheny. And the reason I was pushing everyone 19

sticking around, and the reason we asked Phil to do 20

this and then you’ll see some of the excellent data 21

from AK Steel as well is, the last meeting I thought 22

we had a consensus, and I think Andrew said it, a 23

number of people said it, hey we do not want to go 24

to a standard where we’re sole sourced. We want to 25Executive Court Reporters (301) 565

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go to a standard where we’ve got multiple materials. 1

Selections. I mean, I’m just quoting you, I don’t 2

know on that. 3

MR. DeLASKI: That’s a misquote. I said 4

that

-- 5

(overspeaking ) 6

MR. POLINSKI: You said that you wanted 7

to have a standard that would be satisfied by 8

multiple materials. 9

MR. DeLASKI: You’re changing what I said. 10

I said I wanted to evaluate a level that told us 11

what would happen. That’s very different than I 12

w ant a standard at that level. 13

MR. POLINSKI: Well, again, I think 14

everyone said that they didn’t want it to be sole 15

sourced. 16

MR. DeLASKI: I never said

-- I didn’t say 17

that. 18

MR. POLINSKI: Okay, fine, then I stand

-- 19

MR. DeLASKI: I’m interested in that 20

point. 21

MR. POLINSKI: Okay, that’s all I’m 22

saying. That’s what this is showing is that

-- 23

MR. DeLASKI: What you’re suggesting is 24

that

-- 25Executive Court Reporters (301) 565

- 0064 287

MR. POLINSKI: The M3

-- 1

MR. DeLASKI:

-- if you want multiple 2

suppliers, then no change. 3

MR. POLINSK I: No, no. I’m saying just 4

let’s not start talking about levels three, four, 5

five, six, seven . I’m saying maybe we’re in the 6

range of zero, no change, to a two, or something 7

like that. That’s all I’m saying. 8

So let’s start narrowing our focus here 9

because we’re so all over the place we’re never 10

going to get anywhere if we keep talking about

-- 11

we’re out on Pluto. Let’s just stay here on earth. 12

We’ve got to get into the meat of the discussion, 13

that’s my point. 14

MR. DeLASKI: Yeah, I’m all for gett ing 15

the meat. I think that’s useful. But I think just 16

to be clear, our interest was in evaluating multiple 17

levels to tell us impacts

-- showing the impacts on 18

the steel manufacturer to something that we think is 19

part of this discussion and we need to und erstand 20

that. 21

MR. POLINSKI: It’s not just the impact on 22

the steel manufacturers, it’s the impact on the 23

marketplace of, you know, when you have

-- when you 24

don’t have adequate supply

-- if we produce a 25Executive Court Reporters (301) 565

- 0064 288

standard that you don’t have an adequate supply to 1

meet the standard, I mean, there’s nothing worse

-- 2

there’s nothing worse than that. What about Rick? \ 3

MR. DeLASKI: Yeah, it’s a level we were 4

looking at, but not was the constraint on decision

5

making. And I also think it’s important that

-- 6

Phil, than k you for putting this work in, and I 7

think you’re doing this on behalf of Allegheny and 8

AK

-- 9

MR. HOPKINSON: They are two of my 10

supporters, and I actually have three transformer 11

manufacturers who also supported this work so far. 12

Federal Pacific is one , Cooper is one, and Kentucky 13

Association of Electric Coops is one. So

-- 14

Kentucky, for those of you who don’t know it, is a 15

small liquid

- filled manufacturer and of course they 16

would like to stay a liquid

- filled manufacturer in 17

the future. So they were v ery interested in making 18

sure that what I had for information was something 19

that would keep them in business. 20

MR. DeLASKI: And I guess I also would 21

suggest that for the purposes of our discussion, I 22

mean ultimately the government’s going to make 23

decisio ns based on the government’s analysis. 24

MR. HOPKINSON: Yes. 25Executive Court Reporters (301) 565

- 0064 289

MR. DeLASKI: And for purposes of this 1

negotiation I think we need to focus on the 2

Navigant/LBL analysis because that’s the basis for 3

the decision

- making that ultimately will be made by 4

the go vernment. 5

MR. HOPKINSON: Just before I wrap it up

- 6

- down to the dry type because that one looks like 7

it does need work, and I know the Federal Pacific 8

guys are particularly interested. Now, for the 9

manufacturers to go to efficiency level one, their 10

co st increase wasn’t as it was on the liquid filled 11

transformers. But they were really starting with a 12

TP1 kind of a number before, so it would make sense 13

that there could be some room in that particular 14

product, if there’s economic justification and on 15

the dollars per watt that is used against it. 16

On the scatter plot, the manufacturers 17

were way up here to the top with again, M3 and 18

aluminum, and OPS

- 1 and OPS

- 2 were virtually 19

unchanged. There wasn’t much change. And the 20

reason there wasn’t is that we di dn’t have 21

sufficient data when we went back and talked to the 22

people at OPS to give them something that they could 23

get their teeth in and that they could fix. Now 24

that data has been accumulated and I think Federal 25Executive Court Reporters (301) 565

- 0064 290

Pacific, and I think Wes, you’re not goin g to stay 1

quiet, will be back talking to them to get them to 2

modify the program. 3

MR. PARKER: What are the specific 4

modifications to the program that you want again? 5

MR. HOPKINSON: Well, I think to begin 6

with, and I will steal Bob’s thunder, unless he 7

would like to make it, but I would say that one of 8

the things is that the design that is picked to use 9

was a secondary unit substation, which has buses and 10

leads and lots of loss associated with it, and the 11

design that OPS

- 1 and 2 have used is the

-- just a 12

plain vanilla with stub

- outs on the leads, so it 13

doesn’t have all those losses. Now when those 14

losses get

-- 15

PARTICIPANT: (comment off mic) 16

MR. HOPKINSON: And it’s not 17

representative of the market, that’s the other 18

point. So that’s the biggest d ifference, and I 19

don’t know, Bob, you want to talk any more. 20

MR. SMITH: Design lines 9 through 13. 21

Bob Smith of Federal Pacific. Phil is correct. We 22

-- we’re very concerned about selecting the right 23

design for medium voltage dries, and we felt that 24

s hould be a unit substation design, which included 25Executive Court Reporters (301) 565

- 0064 291

the secondary bus all the way out to switch gear, 1

and the high voltage bus to the high voltage switch, 2

and not just the core and coil by itself as you 3

would have with a high voltage general purpose 4

transfor mer. And I think there was some issues as 5

to how OPS was calculating the stray losses. 6

MR. HOPKINSON: I think there is too. 7

MR. SMITH: Long story short, is that when 8

they did not include the losses, the strays and the 9

buses, that caused us to have t o go to a large core 10

and coil to get to the selected efficiency level 11

than we would otherwise have to do if those losses 12

were included. 13

MR. PARKER: So as I take it, then, this 14

is a question about whether the right representative 15

unit was chosen for

-- 16

MR. SMITH: That is correct. 17

MR. PARKER:

-- the design line. Right. 18

Which brings us full circle back to where we started 19

this morning. 20

MR. SMITH: Well, there is good news. 21

MR. PARKER: With item number one, yes. 22

MR. SMITH: There is good news. Rob and 23

Naheed (ph) have hit upon design line 11. That’s a 24

CSL

- 2 design that they were working on, and they are 25Executive Court Reporters (301) 565

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in agreement with that and are confident that they 1

can move forward with the other design lines and the 2

other efficiency levels. So that is happening at 3

the moment. 4

MR. PARKER: Good. Excellent. 5

MR. HOPKINSON: That pretty well 6

summarizes what I had. I think that anything beyond 7

this was just going to be to suggest that the 8

negotiating team look closely at what the 9

manufacturers’ cost is , but it’s based on that 10

assumption of M3 and aluminum, and if you change 11

that assumption, of course it would be different 12

cost. 13

MR. PARKER: And that is of course, a 14

policy decision about whether there should be a 15

constraint for a particular kind of met al built into 16

the modeling, and I think should be treated as a 17

policy decision. 18

So as I understand it, basically what 19

Phil’s very helpful analysis does is sort of provide 20

a window into the way that choice of parameters can 21

affect the analysis. What he’s done is a kind of a 22

back of the envelope version of what I think LBL 23

tried to do systematically by incorporating 24

distributions for these various parameters into 25Executive Court Reporters (301) 565

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their analysis. He did identify some other areas 1

where there can be some changes made, some 2

r epresentative unit

-- in terms of defining new 3

representative units. I think we have a process for 4

dealing with that. And so I think we should

-- we 5

are in pretty good shape then in terms of converging 6

our analyses for drawing on Phil’s insights and Bob 7

Smith’s work to come up with a single analysis that 8

will accommodate these tweaks, basically, in the 9

area of representative units so that we get one set 10

of numbers to work off by the next meeting. Steve, 11

did you want to chime in? 12

MR. NADEL: Yes, I want ed to pick up very 13

briefly on this little conversation that Ray and 14

Andrew had, in terms of tomorrow. We think it would 15

be useful to set aside a little time at the end of 16

the day to put on the table some concepts about how 17

we might get to yes, as opposed to a talkathon. We 18

have some thoughts that we want to present, and I 19

say that not to say, oh, gee, it has to be blank or 20

blank, but some ideas for people to think about. 21

Because if we’re going to make progress, we have to 22

make a lot of progress next meet ing. 23

MR. PARKER: Right. 24

MR. NADEL: We want to float some ideas at 25Executive Court Reporters (301) 565

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the end of today so people could think about it as 1

oppose to surprise people, and I wanted to mention 2

today, because other people may want to also flow 3

concepts for us all to be thi n king about in the 4

period between now and November 10 th

MR. PARKER: Yes, good. That’s very 7

helpful. Thank you. We’ll definitely do that. 8 or whatever the 5

date was. 6

PARTICIPANT: We would agree with that 9

that there should be some time set aside for 10

co mmittee members to float concepts or ideas, 11

because I believe that we might have some ideas in 12

that regard as well. 13

MR. PARKER: Great. Most welcome. Thank 14

you. Aaron. 15

MR. MEYERS: I may be alone in this, but 16

I’ve made travel plans based on the end of the 17

meeting being at noon, so if there’s a full agenda 18

and this is going to be added, is there a 19

possibility to start early? 20

MR. PARKER: How do people feel? I think 21

we could probably start

-- eight? 22

MR. MEYERS: Start at eight? 23

MR. ROSENSTOCK: Steve Rosenstock, EEI. 24

Knowing the local traffic, I think 8:30 might be the 25Executive Court Reporters (301) 565

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earliest, just to be fair to people commuting within 1

the area. 8:30 might be the earliest that everybody 2

could get here. And also I would ask for an e

- mail 3

to be sent out, some people I believe left early, to 4

be sure that all the committee members know that 5

we’re going to try to start early. 6

MR. CYMBALSKY: Yeah, the room’s available 7

starting at seven. 8

MR. NADEL: Does that accommodate the new 9

item on the agenda? 10

MR. PARKER : 8:30, the extra half hour? 11

MR. MEYERS: Yes, I would say we add the 12

extra half hour. We’re going to have to be much 13

more rigid about, oops, you’ve got five more 14

minutes, we’re wrapping up this discussion. The 15

early topics get all the attention and t hen we never 16

get to the later ones. 17

MR. PARKER: Well, Aaron, the key is we 18

don’t have any more presentations. Not that I’m 19

aware of. 20

PARTICIPANT: For the record, Phil’s 21

presentation was the most efficient. 22

MR. PARKER: Thank you everybody. We’ll 23

see you tomorrow at 8:30. 24

(Whereupon, at 6:25 p.m., the meet ing in 25Executive Court Reporters (301) 565

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the above captioned matter was adjourned , to be 1

reconvened tomorrow morning, Thursday, October 13, 2

2011 at 8:30 a.m.) 3

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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