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75–759CC 2001

ELECTRIC TRANSMISSION POLICY: REGIONAL

TRANSMISSION ORGANIZATIONS, OPEN ACCESS,

AND FEDERAL JURISDICTION

HEARING

BEFORE THE

SUBCOMMITTEE ON ENERGY AND AIR QUALITY

OF THE

COMMITTEE ON ENERGY AND

COMMERCE

HOUSE OF REPRESENTATIVES

ONE HUNDRED SEVENTH CONGRESS

FIRST SESSION

OCTOBER 10, 2001

Serial No. 107–64

Printed for the use of the Committee on Energy and Commerce

(

Available via the World Wide Web: http://www.access.gpo.gov/congress/house

COMMITTEE ON ENERGY AND COMMERCE

W.J. ‘‘BILLY’’ TAUZIN, Louisiana, Chairman

MICHAEL BILIRAKIS, Florida

JOE BARTON, Texas

FRED UPTON, Michigan

CLIFF STEARNS, Florida

PAUL E. GILLMOR, Ohio

JAMES C. GREENWOOD, Pennsylvania

CHRISTOPHER COX, California

NATHAN DEAL, Georgia

STEVE LARGENT, Oklahoma

RICHARD BURR, North Carolina

ED WHITFIELD, Kentucky

GREG GANSKE, Iowa

CHARLIE NORWOOD, Georgia

BARBARA CUBIN, Wyoming

JOHN SHIMKUS, Illinois

HEATHER WILSON, New Mexico

JOHN B. SHADEGG, Arizona

CHARLES ‘‘CHIP’’ PICKERING, Mississippi

VITO FOSSELLA, New York

ROY BLUNT, Missouri

TOM DAVIS, Virginia

ED BRYANT, Tennessee

ROBERT L. EHRLICH, Jr., Maryland

STEVE BUYER, Indiana

GEORGE RADANOVICH, California

CHARLES F. BASS, New Hampshire

JOSEPH R. PITTS, Pennsylvania

MARY BONO, California

GREG WALDEN, Oregon

LEE TERRY, Nebraska

JOHN D. DINGELL, Michigan

HENRY A. WAXMAN, California

EDWARD J. MARKEY, Massachusetts

RALPH M. HALL, Texas

RICK BOUCHER, Virginia

EDOLPHUS TOWNS, New York

FRANK PALLONE, Jr., New Jersey

SHERROD BROWN, Ohio

BART GORDON, Tennessee

PETER DEUTSCH, Florida

BOBBY L. RUSH, Illinois

ANNA G. ESHOO, California

BART STUPAK, Michigan

ELIOT L. ENGEL, New York

TOM SAWYER, Ohio

ALBERT R. WYNN, Maryland

GENE GREEN, Texas

KAREN MCCARTHY, Missouri

TED STRICKLAND, Ohio

DIANA DEGETTE, Colorado

THOMAS M. BARRETT, Wisconsin

BILL LUTHER, Minnesota

LOIS CAPPS, California

MICHAEL F. DOYLE, Pennsylvania

CHRISTOPHER JOHN, Louisiana

JANE HARMAN, California

DAVID V. MARVENTANO, Staff Director

JAMES D. BARNETTE, General Counsel

REID P.F. STUNTZ, Minority Staff Director and Chief Counsel

SUBCOMMITTEE ON ENERGY AND AIR QUALITY

JOE BARTON, Texas, Chairman

CHRISTOPHER COX, California

STEVE LARGENT, Oklahoma

Vice Chairman

RICHARD BURR, North Carolina

ED WHITFIELD, Kentucky

GREG GANSKE, Iowa

CHARLIE NORWOOD, Georgia

JOHN SHIMKUS, Illinois

HEATHER WILSON, New Mexico

JOHN SHADEGG, Arizona

CHARLES ‘‘CHIP’’ PICKERING, Mississippi

VITO FOSSELLA, New York

ROY BLUNT, Missouri

ED BRYANT, Tennessee

GEORGE RADANOVICH, California

MARY BONO, California

GREG WALDEN, Oregon

W.J. ‘‘BILLY’’ TAUZIN, Louisiana

(Ex Officio)

RICK BOUCHER, Virginia

RALPH M. HALL, Texas

TOM SAWYER, Ohio

ALBERT R. WYNN, Maryland

MICHAEL F. DOYLE, Pennsylvania

CHRISTOPHER JOHN, Louisiana

HENRY A. WAXMAN, California

EDWARD J. MARKEY, Massachusetts

BART GORDON, Tennessee

BOBBY L. RUSH, Illinois

KAREN MCCARTHY, Missouri

TED STRICKLAND, Ohio

THOMAS M. BARRETT, Wisconsin

BILL LUTHER, Minnesota

JOHN D. DINGELL, Michigan

(Ex Officio)

(II)

C O N T E N T S

Page

Testimony of:

Anderson, John, Executive Director, Electricity Consumers Resource

Council ........................................................................................................... 58

Bennett, James D., Commissioner, New York State Public Service Commission on behalf of National Association of Regulatory Utility Commissioners ...................................................................................................... 93

Cook, David N., General Counsel, North American Electric Reliability

Council ........................................................................................................... 42

English, Glenn, CEO, National Rural Electric Cooperative Association:

Morning session ......................................................................................... 38

Afternoon session ...................................................................................... 122

Esposito, Peter G., Vice President and Regulatory Counsel, Dynegy, Inc.

on behalf of Electric Power Supply Association ......................................... 135

Flynn, Peter, President, New England Power Company on behalf of Richard P. Sergel, National Grid USA ............................................................... 110

Fontes, Roger A., General Manager, Florida Municipal Power Agency

on behalf of American Public Power Association ....................................... 25

Franklin, Allen H., President, CEO & Chairman, Southern Company ....... 96

Gerken, Marc S., President, American Municipal Power-Ohio on behalf

of TAPS .......................................................................................................... 129

Harris, Phillip G., President and CEO, PJM Interconnection ...................... 49

Johnston, Robert, President and CEO, Municipal Electric Authority of

Georgia on behalf of The Large Public Power Council .............................. 113

Kanner, Marty, on behalf of Consumers for Fair Competition ..................... 63

Nordhaus, Robert R., Van Ness Feldman on behalf of Large Public Power

Council ........................................................................................................... 34

Schriber, Alan R., Chairman, Ohio Public Utilities Commission on behalf

of National Association of Regulatory Utility Commissioners .................. 11

Steffes, James D., Vice President of Government Affairs, Enron Corporation on behalf of Electric Power Supply Association .................................. 54

Szwed, Stanley F., Vice President, Transmission, Firstenergy Corp. on

behalf of Edison Electric Institute ............................................................... 15

Trabandt, Charles A., former FERC Commissioner ...................................... 140

Travieso, Michael J., Maryland People’s Counsel .......................................... 147

Vesey, Andrew M., Vice President Energy and Utilities for the CAP

Gemini Ernst & Young ................................................................................. 67

(III)

(1)

ELECTRIC TRANSMISSION POLICY: REGIONAL

TRANSMISSION ORGANIZATIONS, OPEN ACCESS, AND FEDERAL JURISDICTION

WEDNESDAY, OCTOBER 10, 2001

HOUSE OF REPRESENTATIVES,

COMMITTEE ON ENERGY AND COMMERCE,

SUBCOMMITTEE ON ENERGY AND AIR QUALITY,

Washington, DC.

The subcommittee met, pursuant to notice, at 9 a.m., in room

2123, Rayburn House Office Building, Hon. Joe Barton (chairman)

presiding.

Members present: Representatives Barton, Largent, Burr,

Whitfield, Norwood, Shimkus, Wilson, Bryant, Radanovich, Tauzin

(ex officio), Boucher, Sawyer, Wynn, Waxman, Rush, McCarthy,

Strickland, Barrett, and Luther.

Staff present: Sean Cunningham, majority counsel; Jason Bentley, majority counsel; Brendan Williams, legislative clerk; Hollyn

Kidd, legislative clerk; Sue Sheridan, minority counsel; and Rick

Kessler, minority counsel.

Mr. BARTON. The subcommittee will come to order. If our audience would find a seat.

We have an unusual situation this morning. We have two separate hearings with a separate lunch break in between. We also

have the Democratic Caucus meeting to elect a new Whip. I spoke

with the ranking member, Mr. Boucher, last evening and he agreed

that we could do our opening statements and then I would call a

recess until our Democrats got here to hear the testimony.

Now, it’s possible the Democratic Caucus will be all peace and

harmony, and there’ll be a unanimous consent election, but it’s

probable that it’s going to be fairly contested and take a number

of ballots, and the Democratic process will go slowly. So, it could

be that we’ll do opening statements and then recess until approximately 11 a.m. I hope that we have some folks show up before

then.

So we’re going to start our opening statements and get as many

as the Republicans on the record, and then wait until Mr. Boucher

and some of his colleagues come on the majority side.

So the Chair would recognize himself for an opening statement.

First, I want to thank all our panel members for coming back.

I believe this panel was scheduled to be here on September 11, and

as we all know a very bad thing happened that morning which required us to postpone this hearing. But we’re glad to have you all

2

here and I’m told that everybody that was here September 11 is

back here.

We give special thanks to Mr. English. We understand that

you’re going to be here this afternoon, too. So, we’ll get a double

dose of your wisdom.

We’re going to hear this morning about Siting, Incentives and

Reliability. It’s my belief that the Congress and the FERC should

do what it can to encourage the expansion of transmission capacity

where needed, particularly through private sector investment. The

FERC should take a new look at incentive rate making in the discussion draft that’s now publicly available. We have some incentives to make that happen.

I believe the States should continue their traditional role of

siting transmission lines, but I now believe that the Federal Government should impose a deadline on States for timely consideration for looking closely at transmission lines that are in the public

interest.

The discussion draft calls for the FERC to act as a backstop for

applicants after 1 year of work or lack thereof at the State level.

On reliability there is broad agreement that some organization or

organizations should have the power to enforce reliability standards. The question now is how to do it. Many on this subcommittee,

including my good friend Congressman Wynn of Maryland have

been leaders in encouraging consideration of reliability proposals.

Today we’re going to have before us several witnesses who are

all committed to some reliability legislation. I look forward especially to hearing that testimony and working with the members

about the proper plan to put that forward.

This afternoon after a short break in our second hearing we’re

going to reconvene and hear from the second panel on the RTOs

or regional transmission organizations. The issue of open access for

transmission and the jurisdictional issue of who should have jurisdiction over those RTOs.

I want to thank any of our witnesses who are already here in the

audience that are going to participate on the second panel.

Last night I released a revised discussion draft on a proposed

starting point on RTO policy. I would like to say that it is, at the

moment, my best guess about where the middle ground is on RTOs,

but it is a draft. And I certainly expect people, some people to be

for it and some people to be against it, and some people to be undecided and sit on the fence. That’s the whole reason we put out discussion drafts.

The language that we released late last evening all transmitting

utilities must file, perform or participate in an RTO, and that’s

all—A-L-L, not O-I-L.

FERC must approve RTO applications that meet—you’ve got to

wake up now. We got a lot of time this morning. Ralph Hall’s not

here to entertain you, so I’ve got to do the best that I can.

FERC must approve RTO applications that meet certain minimum standards, but may propose changes to applications if they

do not meet those standards. If there is no agreement, the FERC

in the discussion draft could order participation in an RTO, but the

applicant could appeal that FERC mandate to the Federal courts.

3

FERC shall continually enforce uniform market rules including

seams agreement between RTOs.

Finally, under the proposed draft language, the FERC may not

require approved RTOs to merge. So what we’ve tried to do is hit

a middle ground between a FERC mandate and let the FERC do

whatever it wants to give FERC no authority and let the private

sector participate or not participate as it so chooses.

It’s my personal belief that all utilities should be in an RTO. It’s

also my belief that there’s no magic about a specific number of

RTOs. The No. 4 has been bandied about quite a bit recently.

That’s a good number, but it’s not the only number out there.

There’s no magic about having three RTOs in the Eastern Interconnect and one in the Western Interconnect. I believe that if all—

A-L-L—utilities are in an RTO, the RTOs work well within themselves and with other RTOs, we will have greatly helped to establish a seamless national network.

The open access provision and the discussion draft are equal to

what was in the Electricity Restructuring legislation in 2944 in the

last Congress. There is a way to ensure equal terms and conditions

for transmission access while retaining the unique characteristics

of public power and coops. Now I want to pursue that, but I also

want to make sure that all who depend upon transmission lines to

sell power in the wholesale markets or to purchase wholesale

power for their consumers can gain the proper access to the bulk

power transmission network.

Finally, we’re going to welcome witness testimony on the jurisdiction issue. Who should have jurisdiction over the transmission

component of a bundled retail sale? This issue is wrapped up in the

RTO debate and it may be that members solve this issue when we

decide about RTOs. The Supreme Court just last week heard arguments on jurisdiction. I believe that the Congress should step in

and provide clarity to the law if a consensus is possible. I want an

appropriate role for the States, but I do think that we need a less

bulkanized system.

After this hearing and after the proper time period to let members digest the testimony in its written form, it’s my intent to begin

discussion of the subcommittee members on both sides of the aisle

on a second electricity draft. Mr. Boucher, of course, will be deeply

involved in it, as will full committee ranking member Mr. Dingell.

Electricity has not been and should not be, and as long as I’m

subcommittee chairman will not be a partisan issue. We have a

good base of member education and member interest on both sides

of the aisle. Time is short in this Congress. I’m under no illusions

that if the Congress adjourns very quickly, there’s a good chance

that we’ll have to roll this over to next spring. But there’s also a

possibility, and when I walked in I was told by staff that it looks

like the ice is beginning to break in the Senate and the energy bill

is going to go forward. So, I think there is a chance that if we could

have two good hearings today and member interest and the Congress stay in session longer than another week or 2, we could move

to a markup on this bill in this Congress in the next month or so.

I hope that’s the case. I would love to move a bill out of subcommittee and have it ready to go, perhaps, for discussion in a

4

comprehensive energy bill that we go to conference with the Senate.

Our goals for an electricity restructuring are several. In a simplified form, we want to increase the supply of electricity. We want

to improve the effective operation of our transmission grid and we

want to increase the capacity, at least the potential to increase the

capacity of our transmission grid.

Those of you that are here testifying on behalf of the various

State utilities today can help put those goals forward. Now, you

can help us toward a better function electricity system. As I’ve told

some of you privately, this is not the time to tell what you think

what I want to hear or what Mr. Boucher wants to hear, or anyone

else for that matter. It’s the time for you to tell us what you really

believe. Look beyond the interest of your special interests; look at

the broader national purpose. And if you’ll help us in that regard,

we can reach a compromise that’s good for the country.

So I look forward to these two hearings today. These are the last

two hearings I propose to hold unless we need to have a legislative

hearing on the bill that we introduce. So this is a very, very important day.

[The prepared statement of Hon. Joe Barton follows:]

PREPARED STATEMENT OF HON. JOE BARTON, CHAIRMAN, SUBCOMMITTEE ON ENERGY

AND AIR QUALITY

Today’s hearing takes the place of two hearings that were canceled during the

week of September 11. I would like to thank the members of the first panel for coming back. I know some of you were stranded here for a while last time.

This morning, we will hear about siting, incentives and reliability. I believe Congress and the FERC should do what it can to encourage the expansion of transmission capacity where needed, particularly through private sector investment.

FERC should take a new look at incentive ratemaking, and my discussion draft

would make that happen. States should continue their traditional role of siting

transmission lines, but I now believe the Federal government should impose a deadline on them for timely consideration and for looking closely at lines that are in the

public interest. My discussion draft calls for FERC to act as a ‘‘backstop’’ for applicants after one year of work at the State level.

On reliability, there is broad agreement that some organization or organizations

should have the power to enforce reliability standards. The question now is how to

do it. Many on this Subcommittee, including Congressman Wynn of Maryland, have

been leaders in encouraging consideration of reliability proposals. Today we have before us several witnesses who are all committed to passing some reliability legislation. I look forward to hearing the testimony and working with Members about the

proper plan to put forward.

Later today, after a break, we will reconvene and hear from a second panel on

Regional Transmission Organizations (RTOs), open access for transmission, and the

jurisdiction issue. If those witnesses are already here, I thank you for coming and

hope you enjoy Round One.

Just last night, I released a revised discussion draft with my proposed starting

point on RTO policy. In the language, all transmitting utilities must file to form or

participate in an RTO. FERC must approve RTO applications that meet certain

minimum standards but may propose changes to applications if they do not meet

the standards. If there is no agreement, FERC can order participation in an RTO

but the applicant can appeal to Federal courts. FERC shall continually enforce uniform market rules, including seams agreements between RTOs. Finally, FERC may

not require approved RTOs to merge.

I believe all utilities should be in RTOs. To me, there is no magic in having 3

RTOs in the eastern interconnect and 1 in the western interconnect. I believe that

if all utilities are in RTOs, and the RTOs work well within themselves and with

other RTOs, we will have greatly helped establish a seamless national network.

The open access provisions in the discussion draft are equal to what was in electricity restructuring legislation in the last Congress. There is a way to ensure equal

terms and conditions for transmission access while retaining the unique characterisVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00008 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
5

tics of public power and cooperatives, and I want to pursue that. But I also want

to make sure that all who depend on transmission lines to sell power on the wholesale markets, or to purchase wholesale power for their consumers, can gain the

proper access to the bulk-power transmission networks.

Finally, I welcome witness testimony on the ‘‘jurisdiction issue’’—who should have

jurisdiction over the transmission component of a bundled retail sale. This issue is

wrapped up in the RTO debate, and it may be that Members solve this issue when

we decide about RTOs. The Supreme Court just last week heard arguments on jurisdiction, and I believe that Congress should step in and provide clarity to the law

if a consensus is possible. I want an appropriate role for the States, but I want a

less balkanized system.After this hearing, I will begin discussions with Subcommittee Members on electricity. These, of course, will start with Subcommittee

Ranking Member Boucher and full Committee Ranking Member Dingell. Electricity

is not a partisan issue, and there is a good base of Member interest and education

on both sides of the aisle. If there is interest in moving forward, and if Congress

will remain in session for sufficient time, I will work to introduce a bill in the coming weeks and move toward markup. I look forward to working with all Members

and stakeholders for suggestions on revising the discussion draft.

Our goals with electricity restructuring should be many. Simplified, they are:

1. Increasing the supply of electricity;

2. Improving the effective operation of our transmission grid; and

3. Increasing the capacity of our transmission grid.

The witnesses today can help us on that path toward a better-functioning electricity system. I encourage your honesty and also your consideration of the national

interest. Now is the time to look beyond the reasons to oppose compromises or be

parochial. Now is the time to establish an electric grid and trading system for the

21st Century that we can all be proud of.

Mr. BARTON. We’d like to welcome Mr. Shimkus for an opening

statement. I’m assuming you were the first member here? Mr. Norwood was here first. Well, we’re going to welcome Mr. Norwood for

an opening statement then.

Mr. NORWOOD. Thank you, Mr. Chairman. I know it’s hard for

you to know which one of us was here first.

Mr. BARTON. Just glad you all both were here.

Mr. NORWOOD. I promised John I’d get that in.

Thanks for holding this hearing today on the important issue of

transmission and all the critical issues associated with that. I plan

to be brief with our statement and get as fast as we can to this

very impressive array of witnesses that we have.

Over the last 10 years marriages enacted both by the Congress

and the FERC, this country’s transmission network has undergone

significant changes evolving from what used to be historically small

wholesale power sales that ensured reliability. Today’s current

wholesale megamarket allows many different buyers and sellers to

transfer power back and forth from one end of the grid to the other.

In fact, the wholesale market today is now 400 percent larger than

it was just 10 years ago.

Unfortunately, our current infrastructure was not developed with

this new wholesale market in mind, and is really not equipped to

handle such large bulk power transfers efficiently and reliability.

Today bottleneck areas and problems of congestion on the grid are

common. With these growing pains it is clear, I believe, that this

committee and the Congress face new challenges to find thoughtful

and well-balanced solutions. That’s what really what this is all

about today.

I look forward to hearing the testimony from both panels today,

both panels, and commend this collection again of witness that you

have brought before us.

6

Mr. Chairman, as usual, I truly applaud your leadership in this

committee in trying to craft coherent national energy policy, and

we’re grateful for all the work that you do. And with that, I’ll yield

back.

Mr. BARTON. Thank you, distinguished gentleman from Georgia.

And we would welcome the gentleman from Illinois for an opening statement.

Mr. SHIMKUS. Thank you, Mr. Chairman. I appreciate this hearing and I want to welcome our panelists, both this one and the next

one. And I think it’ll be a long day, so I hope you got comfortable

seats.

The $64 million question this year has been what do we do about

transmission? So as long as many of us have been involved in this

process, this is my fifth year, it’s really boiled down to transmission

in the eyes of many of us.

Do we let FERC or the States have jurisdiction over siting, or is

there some mixture? Do we make RTOs mandatory or do we make

them voluntary, or we allow them to be voluntary? How many

RTOs do we have; the chairman mentioned that, 4, 8 or more?

What kind of incentives do we offer? The list goes on and on and

that is why today’s hearing and all you panelists here are so important to help us sort through some of this process as we have draft

legislation proposed and changes to drafts, and as the chairman as

said, willingness to continue to work through this process.

But the fact remains that we have to change the way the transmission system is run and governed. RTOs were the first step in

the process, but we still have a lot more to do. The whole industry

is dramatically different from the past. The era of big monopolies

and set service areas will soon be a thing of the past in most areas

of the Nation. Illinois is moving to the deregulated market, but

we’ve experienced three RTOs within the State of Illinois for a period of time.

Power will easily be generated in one State and be sent to another grid for use in other States, but the transmission infrastructure has not kept up with the demand. We have to make sure that

can happen without the problems.

The easier we can get power to consumers, the cheaper it will be

for them. The task ahead of us is not easy. There are a lot of different constituencies that have a lot of different ideas about how

we should proceed, and we’ve heard from many of those constituencies already and we look forward to working with the.

I believe Chairman Barton has shown that he’s ready for the

task, and really this subcommittee as we’ve dealt with it for many,

many years in working with our colleagues on the other side. We

are excited about getting to some compromise and moving forward.

And I look forward to working with the chairman on this issue.

Again, Mr. Chairman, thank you for this hearing and I yield

back my time.

Mr. BARTON. We thank the gentleman from Illinois.

We’d welcome the gentleman from Tennessee for an opening

statement.

Mr. BRYANT. Thank you, Mr. Chairman.

I, too, thank you for holding this hearing this morning, and I believe we have another one this afternoon. And I’m coming in late

7

and having to move between meeting and meeting, which I will

continue to do today, so I may be out as other members may be

out today. I want to go ahead and apologize to this very distinguished and numerous long panel here today. I think it’s better to

go one panel than 2 or 3 smaller panels. It cuts down on the number of questions we ask.

I heard the end of my colleague from Georgia, Mr. Norwood’s

statement, and it sounded very articulate and I’m very tempted to

adopt it, because he’s always a man of wisdom, and I may do part

of that. But I’m going to cut my—I will adopt his statement. I’m

sure our chairman’s was also good, and I’ll adopt his statement

also. I will add one comment and I will yield back my time after

that.

I’m not sure anyone on the panel, I haven’t had the opportunity

to see the statements yet, addresses this issue. But an open question as we move forward on the siting issues, the issue of acquiring

right-of-way, acquiring properties, eminent domain and that tension, and it’s tension I think is an understatement that exists with

property owners being from an area that is very mindful; representing a constituency that’s very mindful of property rights, I

want to make sure that we pay proper respect to that. And that

any governmental powers that we have out there or that we create

to expand, enlarge or whatever, eminent domain and the authority

to use it, I think we have to be careful in doing that.

On balance with the not-in-my-back-yard syndrome, I understand fully that we have a transmission problem in this country

and we have to move forward aggressively with the stability of legislation behind it, the force of law behind it to go ahead and built

new transmission. So we have to find that balance in there between protecting property rights and yet doing something for the

common good and avoid the not-in-my-back-yard syndrome.

So, it is a complicated issue, I understand. And perhaps someone

on this panel can address the eminent domain issues and who

should exercise that, should that be delegated to the private sector;

those kinds of things if it’s possible.

And with that, Mr. Chairman, I would yield back my time.

Mr. BARTON. Thank the gentleman.

Seeing no other members present, the Chair would ask unanimous consent that all members not present have the requisite

numbers of days to put their opening statement in the record in its

entirety at the appropriate point. Is there objection? Hearing none,

so order.

The Chair would also announce that Mr. Norwood, Mr. Bryant

and myself are going to briefly change parties, go as a block to the

Democratic Caucus, see what we can get for voting for either of the

candidates up for the Whip, probably some votes on health care for

Mr. Norwood, and I’ll takes votes on electricity bill and Mr. Bryant

can take votes on some good deed for the TVA, or something at

that point.

We’re going to be in recess. I would ask my first panel to not

wander too far. I think there’s an outside chance that we could get

started around 10. So you’re at liberty to move about the compound, but don’t go back to your offices. Let’s stay in this general

area.

8

And we will reconvene as soon as we have some of our Democratic friends here to start the panel.

[Brief recess.]

Mr. BARTON. The Chair recognize the distinguished ranking

member for an announcement on who the new Whip is, and for an

opening statement.

Mr. BOUCHER. Well, thank you, Mr. Chairman. I will have to disappoint you with regard to one of those matters, but not with regard to the other. We are still counting votes, and I was so interested in coming to take part in your hearing today that I left before

the result was announced. But I’m sure that all of us in due course

will find out what that result is.

Mr. BARTON. Okay.

Mr. BOUCHER. It will not be a secret.

Mr. BARTON. Well, there are several of us that are available for

a brief switch in parties if it’s so close that one or two votes makes

a difference.

Mr. BOUCHER. We would be glad to talk with each of those individuals, and if there are as many as six of them, that truly would

be excellent news for us.

Thank you very much, Mr. Chairman. Today’s hearings assemble

a group of expert witness who can help frame the questions at the

root of the electricity restructuring debate and indicate to us what

problems effect the Nation’s electricity system, and suggest how

Congress can improve the system through the passage of legislation.

Today we will hear from two panels on matters related to electricity transmission policies. This morning’s witnesses will address

the siting of new transmission lines and system reliability. And

this afternoon’s panel will address regional transmission organizations, matters relating to open access and the balance between

State and Federal jurisdiction.

I want to commend Chairman Barton for his diligent effort to

conduct thorough and balanced hearings on these matters of fundamental importance, and I also want to commend him for his usual

practice of working closely with members on our side as we approach these important considerations.

My State and many others have adopted some form of retail competition plan, although approximately one-half of the Nation remains subject to traditional utility structures. At this point I think

it seems unlikely that Congress will enact a direct retail competition mandate and our legislature debate, therefore, centers on electricity transmission policy questions including how best to allocate

existing transmission capacity and whether and to what extent,

and by what means the Federal Government should encourage the

construction of new transmission capacity.

We should also bear in mind that some of the most fundamental

questions regarding the balance between Federal and State authority over transmission were last week argued before the United

States Supreme Court, and a decision on those very important matters should be forthcoming from the Court in the near term. That

fact may influence to some extent our considerations in this subcommittee.

9

As we consider these matters it is essential to reflect not only on

the best policy approach, but also how much of the goal of our best

policy choices can be accomplished within the confines of existing

law. Does the FERC believe that it has sufficient authority under

the Federal Power Act to perform its responsibilities and to carry

it to the conclusions that it might desire to reach?

Beyond the issues relating to transmission policy, we have a

number of other associated concerns. What problems, for example,

arise from the continued application of PUHCA. If PUHCA is to be

repealed, what consumer protections need to be put in place in any

electricity legislation that we consider? Can we achieve a more efficient use of existing generator capacity through real-time pricing

and how can real-time pricing be encouraged? What are the merits

or the problems associated with the continued application of

PURPA. And what is the position of the Administration with regard to this entire set of issues and what legislative recommendations would the Administration make to us at this time?

These are questions that we will examine during the course of

this day and in future weeks. And as we do so I want to thank

Chairman Barton for his singular dedication to a major reform of

Federal policy with respect to electricity. And I very much look forward to working with him as we seek the best approach to these

complex matters.

Thank you, Mr. Chairman.

Mr. BARTON. We thank the gentleman.

[Additional statements submitted for the record follow:]

PREPARED STATEMENT OF HON. STEVE LARGENT, A REPRESENTATIVE IN CONGRESS

FROM THE STATE OF OKLAHOMA

Mr. Chairman, in light of the tragic events of September 11th, the Committee correctly chose to postpone the two hearings that we will be holding today. As someone

who has spent a considerable amount of time on the electricity restructuring issue,

and more specifically transmission related issues, I want to thank you for promptly

rescheduling these two very important hearings.

For those of us who are old enough to remember the movie ‘‘The Graduate,’’ there

is a memorable line from the film in which Dustin Hoffman’s character is offered

a one word piece of advice—‘‘plastics.’’ Well I believe there is one word that this

Subcommittee should keep in mind as it proceeds forward with comprehensive electricity restructuring legislation. That word is ‘‘transmission.’’

California’s energy problems earlier this year clearly demonstrated the economic

chaos caused by a lack of generation. That being said, if we do not clarify the rules

of the road for the interstate transmission system, generators will continue to be

precluded from moving power across State lines because of a lack of investment,

siting problems, a patchwork of different regulatory guidelines, or the abuse of market power.

As members of this Subcommittee and our witnesses know all too well, the current transmission system was not built for the number of wholesale transactions

that take place on a daily basis.

It was designed largely to supply intrastate demand. Yet since the enactment of

the Energy Policy Act of 1992, there has been an increase in interstate bulk power

transfers, something the existing system was not designed to handle.

Our current transmission system is analogous to the way our road system was

connected, or more accurately, not connected prior to the construction of our interstate highway system in the 1950s.

The regulation of our transmission system varies depending on whether the lines

run through an open state or a closed state. The regulation varies depending on the

ownership of the lines. Investor owned utilities are regulated by FERC while lines

owned or operated by municipals, co-ops, TVA, or BPA are largely exempt from

FERC regulation. Even the type of sale, be it an unbundled or bundled retail sale

is subject to different types of regulation.

10

It’s my hope that we can create some form of regulatory parity to put all industry

participants on an even playing field.

I believe FERC has taken several pro-active steps with the issuance of FERC Orders 888, 889, and 2000 to develop competitive wholesale power markets.

Clearly, FERC is not content to sit on the sidelines while industry and Congress

decide how to restructure. On September 26th newly appointed Commissioner Pat

Wood outlined a very ambitious, some say too ambitious, policy directed at the formation of competitive wholesale power markets.

Mr. Chairman, I know you recently released a draft of your comprehensive restructuring bill. With what time we have left in the remainder of the session, I look

forward to working with on this legislation, in particular Section 201 and Section

202, the open access and RTO provisions.

With that I look forward to hearing from our distinguished panels of witnesses

and I yield back.

PREPARED STATEMENT OF HON. W.J. ‘‘BILLY’’ TAUZIN, CHAIRMAN, COMMITTEE ON

ENERGY AND COMMERCE

First, let me thank Chairman Barton for continuing this series of hearings on our

Nation’s electric power industry. In today’s two-part hearing we will focus on the

transmission system—the infrastructure that is necessary for getting power efficiently and reliably from the generator to the consumer, and the competitive interstate marketplace that is needed to ensure affordable electricity supplies.

Attention to reliable transmission goes in hand with Committee efforts to assure

that our Nation has an affordable, reliable electricity supply that will keep pace

with the demands of the 21st Century. This will require that we put an end to the

uncertainty over the operation and governance of the interstate transmission system

and establish clearly defined rules for competitive wholesale markets.

Since 1992, Congress has encouraged the development of competitively generated

wholesale power, which resulted in a general decline in electricity prices, as well

as cleaner and more efficient production of power. The increased efficiency came at

an essential time. The Energy Information Administration recently reported that,

since 1990, as retail electricity sales (our demand) grew by 26%, power generating

capacity increased by only 10%, and transmission capacity grew only 15%. So our

success fueling the recent period of economic growth with electricity was achieved

only because we were able to generate more power, more economically from existing

plants.

Yet success generating power more efficiently would have been meaningless without the ability to deliver the electricity to where it was economic and most needed.

This has prompted a rethinking of our Nation’s interstate transmission system and

has made clear that we need a vibrant, accessible interstate transmission system

if we hope to deliver the full benefits of that low-priced power to consumers.

According to the Electric Power Research Institute, the number of wholesale

power transactions increased 400% over the past decade—on a patchwork system

designed to serve individual utilities. At the same time, investment in transmission

infrastructure has steadily declined.

We now know that the coordinated use of a number of transmission systems can

allow a low-cost producer in one state to sell power cheaply to buyers in another.

As our demand for electricity continues to grow, it is becoming more important than

ever that we have the ability to share electric power freely within regions and

among states. To do this, we cannot continue to view transmission as individual

power lines; we must look at it as part of a broader, interstate system.

Therefore, it is critical that our Nation begin designing and building modern, 21st

Century transmission systems. This, of course, will require a legal and regulatory

framework to make it happen.

We must look at a variety of issues to determine how best to proceed in these

matters. Today’s hearing will allow us to focus on grid reliability, transmission

siting issues, and incentives to encourage new transmission-system investments.

This afternoon, we will hear testimony on the formation of Regional Transmission

Organizations (RTOs), open access to transmission, and the role of the Federal government and States in ensuring that we have vibrant, competitive wholesale power

markets. It will be a long day, but very informative.

It is important that we address these issues, especially at this time of uncertainty

over our Nation’s energy security. I thank Chairman Barton for holding these hearings, and I look forward to the testimony of our witnesses.

11

Mr. BARTON. We have 8 of our 10 panelists here. We’re going to

start with Mr. Schriber and just head right down the line, and we’ll

make sure that Mr. Nordhaus and Mr. Ken get here and get an opportunity to participate.

We’re going to welcome you, Mr. Schriber, as Chairman of the

Ohio Public Utilities Commission. He’s here on behalf of the National Association of Regulatory Utility Commissioners. Put your

statement in the record and ask you to summarize it in 5 minutes.

STATEMENTS OF ALAN R. SCHRIBER, CHAIRMAN, OHIO PUBLIC UTILITIES COMMISSION ON BEHALF OF NATIONAL ASSOCIATION OF REGULATORY UTILITY COMMISSIONERS;

STANLEY F. SZWED, VICE PRESIDENT, TRANSMISSION,

FIRSTENERGY CORP. ON BEHALF OF EDISON ELECTRIC INSTITUTE; ROGER A. FONTES, GENERAL MANAGER, FLORIDA

MUNICIPAL POWER AGENCY ON BEHALF OF AMERICAN

PUBLIC POWER ASSOCIATION; ROBERT R. NORDHAUS, VAN

NESS FELDMAN ON BEHALF OF LARGE PUBLIC POWER

COUNCIL; GLEN ENGLISH, CEO, NATIONAL RURAL ELECTRIC

COOPERATIVE ASSOCIATION; DAVID N. COOK, GENERAL

COUNSEL, NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL; PHILLIP G. HARRIS, PRESIDENT AND CEO, PJM INTERCONNECTION; JAMES D. STEFFES, VICE PRESIDENT OF GOVERNMENT AFFAIRS, ENRON CORPORATION ON BEHALF OF

ELECTRIC POWER SUPPLY ASSOCIATION; JOHN ANDERSON,

EXECUTIVE DIRECTOR, ELECTRICITY CONSUMERS RESOURCE COUNCIL; MARTY KANNER ON BEHALF OF CONSUMERS FOR FAIR COMPETITION; ANDREW M. VESEY, VICE

PRESIDENT, ENERGY AND UTILITIES, FOR THE CAP GEMINI

ERNST & YOUNG

Mr. SCHRIBER. Thank you, sir. And thank you for giving me the

opportunity to testify here today.

In addition to being Chairman of the Public Utilities Commission

of Ohio, I’m also Chairman of the Ohio Power Siting Board, and

I’m prepared to talk about many of the issues that you’ve raised

earlier and have spoken of, but I’ll stick specifically to power siting

at this point.

Ohio, I believe, has perhaps more authority as a siting board

than most States, and it’s been a very effective siting board. It’s

very socialized in the way it’s constructed. I, as Chairman of the

Public Utilities Commission, I’m also Chairman of the Power Siting

Board. We have the Director of the EPA, Department of Health,

Department of Development, Agriculture, Natural Resources, Engineers and legislative members that comprise our board.

In order to receive approval for construction of a new facility in

Ohio an entity, any entity, must apply for and obtain a certificate

of need and convenience and environmental compatibility.

I will point, and I think what’s come to my mind as a casual observer, is that a lot of the issues that we see, and if you were to

scan the testimony, come into whether it should be State or Federal issues who should exercise the power in this regard with respect to siting. And although a lot of arguments can be made either

way, I believe very strongly, and I think reality suggests, that the

12

States for various reasons have some issues before them which we

can handle as far as siting is concerned.

Most of the siting issues turn out to be landowner issues, and

these as State authorities we become very intimately involved with.

Many of the issues regarding siting have to do with natural resources within the State, and a lot of them have to do with agricultural land, the displacement of agricultural land and the optimum

use of agricultural land.

As a State authority we move much, much faster than might be

done in either other States or at the Federal level. And we certainly have the infrastructure already in place.

In Ohio our authority enables us to look beyond State boundaries

in proceedings with other jurisdictions when we site major power

plants, transmission lines or gas pipe lines. For electric power lines

the statute requires that we look to the grid to the facilities beyond

the State boundaries to make sure we are compatible with that.

And finally, in Ohio our jurisdictional trigger goes to all facilities.

So not only would a public utility who needs or wants to build a

facility have to come before the Ohio Power Board, but any facilities. It could be a merchant company, it could be a nonpublic utility. so that in effect in Ohio we believe we have sort of a one-stop

shop where all utilities or nonutilities that wish to build facilities

would come before us.

I would say that our record speaks for itself. It’s not before you,

but our record would suggest that since in the years 2000 and 2001

we’ve added 2200 megawatts of electricity, most are gas peaking

plants, although we have combined cycle baseload gas plants under

construction, by and large we move people in and out within 6

months upon application.

I would also point out that we have a pipeline, the Independence

Pipeline that has been proposed through Ohio over which FERC

has jurisdiction. That pipeline has taken years. It’s been a contentious debate for over 2 years. Interestingly, although FERC has jurisdiction, we’ve gotten thousands of letters because for some reason, I think that may be obvious, that the State authorities are

those who usually get the flake when things don’t quite work out

for the landowners within our States.

So, if Ohio could be a model for other States, I would say that

would be an optimum solution in my mind. Now, does this mean

that FERC could not adopt the Ohio model? They probably could,

but as I’ve suggested because of our sensitivity to landowners, because of our sensitivity to the use of our resources, I would suggest

that the States would, if they could, be somehow compelled to

adopt our model, move forward much more expeditiously in power

siting.

And I’ll stop with that. As I said, I could go on other issues, but

we have a lot of panelists here. And I appreciate the opportunity

to be here.

[The prepared statement of Alan R. Schriber follows:]

PREPARED STATEMENT OF ALAN SCHRIBER, CHAIRMAN, OHIO PUBLIC UTILITIES

COMMISSION

Mr. Chairman and Members of the Subcommittee: Good morning. My name is

Alan Schriber. I am the Chairman of the Ohio Public Utilities Commission. I am

here today on behalf of the National Association of Regulatory Utility CommisVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00016 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
13

sioners, commonly known as NARUC. I greatly appreciate the opportunity to appear

before the House Energy and Commerce Subcommittee on Energy and Air Quality

and I respectfully request that NARUC’s written statement be included in today’s hearing record as if fully read.

NARUC is a quasi-governmental, nonprofit organization founded in 1889. Its

membership includes the State public utility commissions for all States and territories. NARUC’s mission is to serve the public interest by improving the quality and

effectiveness of public utility regulation. NARUC’s members regulate the retail rates

and services of electric, gas, water and telephone utilities. We have the obligation

under State law to ensure the establishment and maintenance of such energy utility

services as may be required by the public convenience and necessity, and to ensure

that such services are provided at rates and conditions that are just, reasonable and

nondiscriminatory for all consumers.

I would like to begin today by addressing electric transmission siting.

NARUC strongly disagrees with the presumption permeating here in Washington

that ‘‘the root cause of all transmission congestion problems in this country is State

eminent domain and siting authority, and therefore the Federal government must

step in.’’ This theory is, at best, simplistic.

As a nation, we want the lights to come on whenever we flip the switch. We want

to run consumer goods using electricity that is inexpensive. We want to be able to

be employed by and own stock in companies that produce these electric-powered

consumer goods. We want our companies to be able to buy power at interruptible

rate levels, but never have to be interrupted.

However, we do not want generation facilities fouling the air, water, and land, nor

do we want transmission lines running through our communities or near our schools

or homes. We do not want gas pipelines running under our feet or near our communities. We do not want to pay any additional costs associated with renewable energy. We do not want to spend the money necessary on research to find technologies

to replace the energy sources we currently depend upon.

Therefore, the conclusion that we must draw from all of this is that a major impediment to siting energy infrastructure in general and electric transmission in particular is the great difficulty in getting public acceptance for needed facilities. Quite

frankly, this tells us that no matter where siting responsibility falls, with State government or the Federal government, siting energy infrastructure will not be easy

and there will be no ‘‘quick fix’’ to this situation.

Giving the Federal Energy Regulatory Commission (FERC) eminent domain and

siting authority is not a panacea. Beyond the practical matter of the time FERC

would need to be prepared to assume this new role and the additional funds that

Congress would need to appropriate to accomplish this, how many examples actually

exist where a State action (or inaction) is solely responsible for unreasonably preventing a needed transmission project?

Currently, the States have the responsibility and authority to site transmission.

In fact, the transmission infrastructure that is currently in operation now has received State siting approval. Additionally, those projects that are in the planning

stages are being planned with State approval in mind.

Make no mistake, NARUC and its membership understand that additional transmission is necessary in all regions of the country. NARUC’s members are also well

aware of the difficulties involved with the siting of these facilities. The fact remains

that in spite of these difficulties, the States have been successful in siting the electric transmission infrastructure that exists today. However, we must also continue

to be cognizant of the basic laws of physics. As much as we all would like to be

able to move electrons from wherever they are produced to wherever they are needed, like we can with natural gas molecules, the electric transmission system is not

able to accommodate those types of transactions. In other words, the transmission

system as it now exists was not built to handle the types of wholesale transactions

that a competitive market will require. This means we will have to be innovative

to make the system function the way we need it to function.

For instance, as we look for innovative ideas, we can begin by remembering that

generation and transmission are substitutable. A State may determine that a transmission line is not necessary if, for example, distributed generation is used instead,

thereby saving valuable resources and protecting citizens from the unnecessary

costs of the transmission project. FERC does not now have the ability to make such

a determination, and we do not support proposals to expand FERC authority over

generation.

NARUC believes that the States should do more to improve upon the tremendous

success story of the nation’s electricity infrastructure. States exercising jurisdiction

over the siting and certification of transmission facilities should not discriminate

against interstate facilities, meaning that in general, interstate facilities should be

14

sited, certificated, and otherwise regulated under the same standards and procedures as intrastate facilities.

NARUC supports voluntary regional bodies that permit the States in which an

interstate transmission facility is proposed to be sited, to issue certificates authorizing the construction of the proposed facility through collective decisionmaking. If

States choose to retain certification authority for themselves, there should be agreed

upon mechanisms to resolve disputes where individual States involved have come

to conflicting and/or inconsistent determinations in their respective deliberations.

These voluntary regional bodies could: address siting of transmission; identify regional bulk power market needs for State siting agencies to consider in their respective deliberations; and, plan for the construction of new interstate transmission facilities.

Congress should affirm that States have the primary authority to establish, operate and govern these voluntary regional siting bodies, and FERC could act as an

appropriate ‘‘backstop’’ authority where States or regions fail to act. Additionally,

Congress should provide an explicit grant of authority to the States and FERC to

act in cooperation.

Until all stakeholders (residential and commercial consumers, industrial consumers, utilities, energy suppliers and marketers, transmission owners and environmentalists) begin to make sacrifices, it will continue to be extremely difficult to improve our electric transmission system. We as public officials must also try to use

our positions to apply reason rather than fanning the flames of emotion.

Mr. Chairman, NARUC would like to thank you for efforts to produce legislative

language that does not take the draconian step of overt Federal preemption of State

authority over siting and eminent domain for transmission facilities. However, for

the reasons I have just mentioned, NARUC must respectfully oppose the Federal

transmission siting provisions found in section 402 of your electricity legislation discussion draft.

I would now like to briefly comment on reliability.

The reliability of the nation’s electric system is one of the most important issues

in this debate, and NARUC believes that Federal legislation must indeed address

this subject. NARUC continues to support the NERC process that has developed legislation mandating compliance with industry-developed reliability standards and

provides explicit authority to FERC and the States to cooperate to enforce those

standards. NARUC also supports legislation that includes workable mechanisms to

support energy efficiency programs that enhance reliability.

Enforcement of operational standards and criteria should be supervised by the

FERC in cooperation with the States through existing State authority, joint boards,

or other mechanisms. Enforcement of compliance with planning and system adequacy standards should rest first with the States and regional bodies. Congress

should explicitly affirm the public interest in transmission grid reliability and the

need for mandatory compliance with reliability standards. Congress should expressly include in legislation: (1) a savings clause to protect existing State authority

to ensure reliable transmission service, and (2) a regional advisory role for the

States.

Federal legislation should also facilitate effective decisionmaking by the States

and recognize the authority of the States to create regional mechanisms including,

but not limited to, inter-state compacts or regional reliability boards, to ensure

transmission reliability. NARUC cannot support reliability language that fails to

provide a continuing role for States in ensuring reliability of all aspects of electrical

service, including generation, transmission, and power delivery services or results

in FERC’s preemption of State authority to ensure safe and reliable service to retail

consumers. State officials will be held accountable by the public when the lights fail

to stay on. Because of this responsibility, State officials and regulators are particularly concerned that they be able to act effectively to ensure uninterrupted electricity service.

NARUC witnesses have appeared before your Subcommittee many times prior to

today requesting a State savings clause and a regional advisory role for the States.

However, the Chairman’s electricity discussion draft legislation fails to include these

two ‘‘must have’’ provisions. Mr. Chairman, NARUC must therefore respectfully oppose the reliability title of your discussion draft.

The third topic I was asked to comment on today was ‘‘incentive rates.’’ NARUC

has begun to hold discussions on this issue, though we have not developed an official position as of yet. I would be happy to provide you with my own thoughts on

this topic during the question and answer portion of this hearing.

Thank you for your time and attention. NARUC members and staff look forward

to working with the members of this Subcommittee to put forth a successful national energy policy. Thank you again and I look forward to your questions.

15

Mr. BARTON. Thank you, Mr. Schriber.

We now want to hear from Mr. Stanley Szwed, who is Vice President of Transmission for FirstEnergy Corporation. He’s here on behalf of the Edison Electric Institute.

Your statement’s in the record, we would ask you to summarize

it in 5 minutes.

STATEMENT OF STANLEY F. SZWED

Mr. SZWED. Thank you, Mr. Chairman. And I do very much appreciate the opportunity to testify here today.

I’m Stan Szwed, Vice President of Transmission for FirstEnergy

Corp of Akron, Ohio, and I am testifying on behalf of the Edison

Electric Institute.

Mr. Chairman, thank you also for your discussion draft. It includes good provisions on nearly all of the transmission priorities

that we support.

My testimony today will focus first on why transmission is critical to competition and reliable electric service, and second on specific legislative recommendations.

Mr. Chairman, wholesale competition is here, so is retail competition in many States. Transmission capacity is critical to competition. There is not enough of it and, clearly, it is a Federal responsibility. If you want competition to work, Congress must address transmission needs. It’s that simple.

Transmission is the critical backbone of the entire electrical network. It is not a service that would be nice to have that we won’t

have enough of, like broadband, for example. This is electricity and

we all depend on it daily.

We do have the greatest transmission network in the world, but

it wasn’t built for what we’re trying to accomplish in competitive

markets today. The transmission system we have today, many

times we can’t get power from a point A to a point B. It’s no one’s

fault. The lines simply were just not designed to move power between points that people now want to connect to. So we have to

transform what I call a system of local roads network into what we

need now, and that is more of an interstate highway system. And

the key to building the highway system we all want is to set the

right regulatory atmosphere necessary to attract investment.

In essence, with the formation of regional transmission organizations, RTOs, we’re establishing a separate new industry. If Congress and FERC get sidetracked on the perfect RTO size and

boundaries, if Congress and FERC bog down on the perfect rules

of the road, we’ll be in the theoretical classroom forever.

Investors want us out of the classroom and into operation. Turning off investors will stifle competitive markets and harm consumers. Our collective efforts to get it perfect will not mean getting

it at all.

Now I’d like to turn my attention to suggesting seven specific legislative aspects that we would ask to be considered in any legislative work done. The first is that of reforming transmission rate

making.

Congress should reform transmission rate making to reflect risks

in the new transmission industry and to make transmission a reaVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00019 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
16

sonable investment proposition. Returns on transmission assets

should be in line with assets in industries with equal risk.

The Barton discussion draft section 401 is a good step. We also

thank Congressman Sawyer and Burr for introducing H.S. 2814

which would reform transmission rate making. In the last Congress

this subcommittee adopted by voice vote the rate reform provisions

from their similar 1999 legislation.

Second, we do need to reform transmission siting. EEI supports

a FERC siting rule which States are unable to act on new transmission line applications. If a State failed to act on an application

or materially altered it, FERC could issue a certificate of public

convenience and necessity for a transmission line. This is essentially what the Barton discussion draft calls for.

Third, adopt mandatory reliability standards. Effective competitive markets need to have mandatory reliability standards. We also

believe there should be a single national reliability organization.

The discussion draft contains reliability provisions we generally

support.

Fourth, remove tax barriers. We need to allow tax deferred sales

and tax free spinoffs of transmission property as provided in H.R.

4 Such taxes impede RTO formation. This language resulted from

an agreement between investor owned and public power providers

of electricity. Thank you for including this in your discussion draft

as well.

Five, repeal the Holding Company Act. It is a significant disincentive for transmission investment if entities with more than a

10 percent ownership stake in RTOs are required to become a registered holding company. the Holding Company Act is outdated. It

has no benefit to customers and in stifling progress on policy goals.

We should simply get rid of it.

Six, avoid RTO mandate authority for FERC. Congress should

not mandate RTO participation or authorize FERC to do so. RTOs

are forming and mandate authority for FERC is risky. Investors

must know their investments cannot be summarily forced into a

structure with wholly different financial fundamentals.

And last, streamline section 203 of the Federal Power Act. The

Barton discussion draft would repeal this section, and we support

repealing it as we support other measures that address the lengthy

and duplicative FERC reviews.

Thank you, Mr. Chairman. Your actions will have very important

consequences for our future infrastructure needs.

[The prepared statement of Stanley F. Szwed follows:]

PREPARED STATEMENT OF STANLEY F. SZWED, VICE PRESIDENT-TRANSMISSION,

FIRSTENERGY CORP. ON BEHALF OF EDISON ELECTRIC INSTITUTE

INTRODUCTION

Thank you for the opportunity to testify before the Subcommittee today. I am

Stan Szwed, Vice President of Transmission for FirstEnergy Corp. FirstEnergy is

a diversified energy services company headquartered in Akron, Ohio, and is the nation’s 10th largest electric utility. We serve 2.2 million customers in Northern Ohio

and Western Pennsylvania. We are in the final stages of our proposed merger with

New Jersey-based GPU. GPU serves 2.1 million customers in Pennsylvania and

New Jersey. When our merger is completed, FirstEnergy will be the 4th largest electric utility in the nation based on customers served. As Vice President of Transmission, I am responsible for the operation of the FirstEnergy transmission system—that is, managing the electric power grid and keeping it available 24 hours

17

1 As the PA Consulting Group stated in its 2001 report, ‘‘Transmission represents only a small

portion of the cost of electricity, but has a substantial effect on the success of electricity markets

by increasing access to supplies and reducing electricity prices. However, the inability of the restructuring process to adequately address as yet the needs of the transmission sector is jeopardizing the health of both the sector and of the entire electric power industry, which it supports.’’

Roger Gale et al., PA Consulting Group, The Future of Electric Transmission in the United

States § 1-1 (2001). 2 Eric Hirst and Brendan Kirby, Edison Electric Institute, Transmission Planning for a Restructuring U.S. Electricity Industry 8 (2001). 3 Id.

4 Id. at v. 5The Western States Power Crisis vi (2001). 6 Hirst and Kirby, supra note 2, at 5.

a day, seven days a week, 365 days a year. Our system—and others like it in three

major interconnections in North America—is always on.

I am testifying today on behalf of the Edison Electric Institute (EEI), the association of U.S. shareholder-owned electric utilities and industry affiliates and associates worldwide. I am pleased to have the opportunity to testify before the Subcommittee on critical transmission issues that should be addressed in electricity restructuring legislation.

At the outset, let me express my sympathies to all those affected by the attacks

on America on September 11, which was the date this hearing was originally scheduled to have taken place. Electric transmission facilities are critical infrastructure,

and the industry takes very seriously its responsibility to maintain the security and

reliability of those facilities.

EEI is a leader in advocating public policy to support competitive electric generation markets with market-based pricing and a wide diversity of market participants.

EEI and its members firmly believe that market-oriented restructuring of the electric industry remains the best opportunity to provide consumer benefits and to develop reliable new sources of supply. To accomplish this goal, EEI strongly supports

passage of comprehensive energy legislation.

FirstEnergy has been an industry leader on electric transmission issues. With

many partners, we have accomplished groundbreaking work to develop what was,

when we proposed it, a first of its kind: a for-profit transmission company as a regional transmission organization. During the course of our work, we have tried to

help policy makers set the right course for transmission. I hope that my experience

on these two efforts—the development of a for-profit RTO (The Alliance) and the

promotion of proper federal policy on transmission—will be of value for the Committee.

BACKGROUND

The Energy Information Administration (EIA) projects that more than 1,300 new

power plants will need to be built between now and 2020, to meet our economy’s

electricity needs. However, without an adequate transmission system, that power

will not get to where it is needed.1

In many areas transmission capacity has not expanded to keep pace with new demands to support competition. Utilities built the bulk of today’s transmission system before the advent of wholesale and retail electricity competition, primarily to

move power limited distances and to bolster reliability. The current transmission

grids were not designed to serve as the interstate super-highway system for competitive electricity markets. Therefore, it should not come as any surprise that

transmission congestion is on the rise.

Fundamental changes in the industry are imposing tremendous demands on

transmission systems to carry more and more transactions across even greater distances. Between August 1999 and 2000, transmission congestion in the Eastern

Interconnection grew by more than 200 percent.2 In the first quarter of 2001, this

transmission congestion was already three times the level experienced during the

same period in 2000.3

Maintaining transmission adequacy at current levels would require about $56 billion in investment during the present decade.4 The Electric Power Research Institute (‘‘EPRI’’) estimates it will cost up to $30 billion to bring the western regional

transmission system back to a stable condition and $1 billion to $3 billion a year

after that to maintain this condition in the face of continued growth.5 Such investment must come from transmission-owning companies and, ultimately, from investors.

This will be a major challenge. The fact is—annual investment in transmission

has been declining by almost $120 million a year for the past 25 years.6 TransVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00021 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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7 Id.

8 National Energy Policy with Respect to Federal, State, and Local Impediments to the Siting

of Energy Infrastructure: Hearing Before the Senate Comm. on Energy and Nat. Resources, 107th

Cong. (2001) (statement of David N. Cook, General Counsel, North American Electric Reliability

Council). 9 Roger Gale et al., supra note 1 at § 1-1.

mission investment in 1999 was less than half of what it had been 20 years earlier.7

As the North American Electric Reliability Council (‘‘NERC’’) testified earlier this

year: ‘‘[i]n North America 10 years ago we had a little less than 200,000 circuitmiles of high voltage transmission lines. Right now we have about 200,000 circuitmiles of those lines. And ten years from now we are projecting that we will have

just over 200,000 circuit-miles of high voltage transmission lines.’’ 8 For a graphical

representation of the decline in transmission investment over the last 25 years and

the increase in the number of wholesale transactions using the transmission system,

please refer to the charts included at the end of this testimony.

THE TRANSMISSION BUSINESS

The new transmission business must be able to make a case for itself. It must

be able to demonstrate to investors, employees, customers, regulators, suppliers, and

others that it can perform and grow—that it can be a stand-alone enterprise. For

a stand-alone transmission company operating independently of affiliated generators, distribution companies or other market participants, this means it must demonstrate that it can attract investment, recruit and keep highly talented, highly motivated people, and pay a just and reasonable return to its owners. Investors need

to know that investing in the new transmission industry has commensurate opportunity for reward as investments of similar risk.

Federal and state regulatory policies seek to promote competition for electric service by permitting both retail customers and generators access to the transmission

system on a nondiscriminatory basis. In particular, the FERC, by promoting the formation of regional transmission organizations, is requiring transmission service to

be furnished by large multi-state organizations independent of transmission owners.

This policy requires the transmission business to stand on its own in providing reliable transmission service, expanding its facilities to support growing competition for

electric service, and providing reasonable compensation to stockholders. Since reliable and readily available transmission service is one of the keys to effective competition, a regulatory environment absolutely, without fail, must be created that

gives this new transmission business the opportunity not simply to survive, but to

thrive. California demonstrates that we cannot overlook the direct relationship between investing to keep up with changing demands and electric reliability.

Open access to transmission facilities, which FERC required in Order No. 888,

means that transmission lines once solely used for the vertically integrated company

that owned the line, are now part of an interstate transmission system that could

be used by anyone. The problem is that as a whole, the systems were not built to

serve as an interstate highway. They were built to deliver electricity from a specific

power plant to a specific load center within the regulated service area of a single

utility or utility system. The separation of transmission from the traditional utility

and the transfer of control over transmission service to RTOs introduce new requirements and dictate a new approach to ensuring reliability of transmission service.

The new transmission industry will need to compete with the private sector to attract investment, build a business, and serve its customers. Don’t just take my word

for how important it is to get the new transmission industry right. The PA Consulting Group stated in its 2001 report that ‘‘the inability of the restructuring process to adequately address as yet the needs of the transmission sector is jeopardizing

the health of both the sector and of the entire electric power industry, which it supports...[The] lack of additional incentives in the face of new risks lies at the heart

of many of the problems now facing the transmission sector.’’ 9

In a comprehensively regulated service such as transmission, setting out the right

business proposition depends very heavily on Congress and federal regulators establishing the right federal policies. I especially want to commend Representatives

Sawyer and Burr, who have looked at transmission from the perspective of trying

to increase investment, encourage construction and expand markets. FirstEnergy

endorses their legislation, H.R. 2814, and encourages the Committee to include it

or similar elements in any electricity restructuring legislation. Based on the legislative principles outlined above, an electricity bill should address the following areas:

19

10 Id. 11 In recent years the S&P 500 companies have, on average, yielded a rate of return on equity

(ROE) of approximately 20 percent, while vertically integrated electric utilities have lagged behind at 10-13 percent on average. See Joint Comments of Kit Konolige et al., regarding the Commission’s Notice of Proposed Rulemaking on Regional Transmission Organizations, at 9, FERC

Docket No. RM99-2-00.

Reform Transmission Rates

Congress should provide definitive pricing direction to FERC with the policy goal

of having a healthy, robust transmission system for the nation that can help deliver

the many benefits of electric competition to all consumers. As such, Congress should

reform transmission rate making to reflect the risks and uncertainties in the brand

new transmission industry. FERC has a legal obligation to set rates that simultaneously protect consumers’ interests in having reasonable rates and investors’ interests in reasonable returns. However, transmission rate reform, which many parties

acknowledge is needed, has been too long in coming. As has been noted, ‘‘The transmission sector, as the provider of services to participants in both the wholesale and

retail markets, has... seen an increase in risk, but there has been little if any increase in potential rewards.’’ 10 The best thing for consumers is a robust, growing

transmission network, and it will require some different regulation to bring that

about.

We support transmission rate reform so that returns on transmission assets are

in line with assets in industries having commensurate risk.11 The September 21,

2001, electricity discussion draft circulated by Chairman Barton (‘‘Barton discussion

draft’’) directs FERC to conduct a rulemaking that would improve transmission

rates with the goal of promoting the expansion and improvement of interstate transmission networks. We also support innovative rate treatments, such as allowing

transmission owners to share with customers some of the financial benefits of providing more cost-effective service.

We believe that if reform of transmission pricing is undertaken, prices for delivered electricity will remain stable and may even decline. Generation accounts for

the lion’s share of electricity costs—some 75%. A more vigorous transmission sector

should strengthen competition. Increasing access to supply should lead to more competition and lower delivered prices.

The President’s National Energy Policy Report called for the Department of Energy to work with FERC to encourage the use of incentive rate making proposals.

H.R. 2814, the bill introduced by Representatives Sawyer and Burr, also directs

FERC to utilize innovative transmission pricing policies. Chairman Barton’s discussion draft contains helpful language on this point. And H.R. 2944, the electricity bill

passed by this Subcommittee in 1999, included innovative pricing language. FERC

is moving in the right direction on issues like these, but encouragement from Congress, especially in the form of legislative language directing FERC to consider the

need for transmission investment and expansion when setting rates, is very important.

Reform Transmission Siting

One of the key impediments to increasing transmission capacity is the problem

of siting new lines, particularly lines that are built to facilitate interstate power

transactions. To help site new transmission lines, EEI supports giving FERC a role

as backstop. This backstop would come into play only when states are unable or unwilling to act on the application. Under this proposal, if a state failed to act on an

application, or materially altered it, FERC would be given the authority to issue a

certificate of public convenience and necessity for a transmission line. FERC would

have similar authority if other Federal agencies failed to act or materially altered

a regionally approved proposal.

The proposal to grant FERC a key role in siting new transmission lines has

gained support across the political spectrum. The President’s National Energy Policy

Report recommends developing legislation to grant FERC siting authority for new

transmission. The Barton discussion draft would grant FERC a backstop role if a

state lacked authority to site a new transmission line, withheld approval or delayed

final approval for more than one year. H.R. 2814 also would grant FERC a similar

backstop role. In his draft bill on electricity legislation, Senate Energy Committee

Chairman Bingaman proposed granting FERC siting authority.

It made sense in 1935 when the Federal Power Act was adopted to leave transmission siting authority with the states, since transmission lines were generally

local in nature. It also made sense for Congress to grant FERC’s predecessor, the

Federal Power Commission, authority to make siting decisions for natural gas pipelines, since they tend to be interstate in nature. Now, however, our transmission

20

12 Hearing on S.206 ‘‘The Public Utilities Holding Company Act of 2001: Before the Senate

Comm. on Banking, Housing and Urban Affairs, 107th Cong. (2001) (Statement of Cynthia A.

Marlette, Deputy General Counsel, Federal Energy Regulatory Commission).

system is being asked to meet obligations similar to natural gas pipelines: move

large amounts of energy across long distances and across state lines.

FirstEnergy endorses federal siting authority, even though in Ohio we have a

comparatively good siting process. In the early 1970s, Ohio established a transmission siting board. Today in Ohio, if you propose a transmission facility, the application need only be approved by the state siting board. The applicant must demonstrate a need in Ohio for the facility, and must demonstrate that environmental

considerations are given due regard. Once these thresholds are met, the board

issues a certificate on environmental compatibility and public need. Roughly 28

states have siting statutes, while the remaining states retain roles for local authorities in siting decisions.

We understand that the issue of federal eminent domain authority raises concern.

Of course, to carry out necessary siting, there must be a certificate of public convenience and necessity issued. Only then may the holder of the certificate exercise the

authority. The FERC currently has authority to issue certificates for natural gas

pipelines and for electric transmission for hydroelectric projects. In addition, the federal electric utilities that own transmission have eminent domain authority.

Electric utilities currently exercise the power of eminent domain when issued

state certificates of public convenience and necessity if they are unable to acquire

the rights-of-way through other means. EEI recently surveyed its member companies on their use of eminent domain authority. The companies that responded have

transmission operations in 39 states. They reported acquiring 4,107 miles of transmission line rights-of-way over the last five years, involving more than 14,000 parcels of land. Of those parcels, only 417—or 2.9 percent—required the use of eminent

domain authority. Utilities clearly exercise eminent domain as a last resort.

Remove Tax Barriers

Congress should enact tax reform to remove disincentives to formation of regional

transmission organizations and to provide incentives for new investment. Specifically, we need to allow for tax-deferred sales and tax-free spinoffs of transmission

property, as provided for in H.R. 4. This language resulted from an agreement between the Edison Electric Institute, the American Public Power Association, and the

Large Public Power Council. In addition, we need to accelerate depreciation periods

for transmission property, as called for in S. 596, introduced by Senator Bingaman.

Forming a for-profit transmission company or transco, which is what my company

and many others are doing to comply with Order No. 2000, is extremely difficult,

and is complicated by the tax laws. To meet the Order’s independence requirement,

many utilities would prefer to find a way to divest transmission assets. In other

cases where government action requires a taxpayer to sell property, the tax code

prevents incursion of tax penalties. If utilities sell transmission property and reinvest the proceeds into other utility property, taxes should be deferred until a taxable

event involving the property occurs. If utilities spin off transmission property, this

should not be considered a taxable event.

As for depreciation of transmission assets, the depreciation period should be

brought into line with periods for property in other industries, given the changed

circumstances under which the industry must attract capital.

Remove PUHCA Barriers

Congress should repeal the Public Utility Holding Company Act. It is now a significant barrier to investment in RTOs. When the Senate Banking Committee held

a hearing on S. 206, the Public Utility Holding Company Act of 2001 (which has

now been adopted by that committee by a 19-1 vote), Cindy Marlette, FERC’s Deputy General Counsel, testified to the impact of PUHCA on RTO formation, stating:

PUHCA may cause unnecessary regulatory burdens to utilities who, in compliance with Commission policy and regulations, seek to form or join regional

transmission organizations (RTOs)... Under PUHCA, any entity that owns or

controls facilities used for the transmission of electric energy—such as an

RTO—falls within the definition of public utility company, and any owner of ten

percent or more of such a company would be a holding company and potentially

could be required to become a registered holding company. This could serve as

a significant disincentive for investments in independent for-profit transcos that

qualify as RTOs.12

Put simply, the Holding Company Act stifles investment in the emerging independent transmission industry. As EEI member companies attempt to raise financVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00024 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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ing for newly forming RTOs, they are discovering that PUHCA’s restrictions are a

significant concern to Wall Street firms and a barrier to investment.

Avoid Market Structuring Authority for FERC

Congress should avoid giving FERC new authority to restructure the industry. As

noted above, RTOs are forming. This process is already subject to intense FERC review and approval.

FirstEnergy has been actively involved in RTO formation for the last four years.

Our company joined the Alliance filing in June 1999, well before Order No. 2000

was issued. With four major FERC orders behind us, each conditionally approving

our filings and encouraging us to continue, the Alliance is nearing operations. And

we are not alone; electric utilities in the Northeast and the Southeast have also

spent countless hours and invested millions of dollars in efforts to form their own

RTOs. Giving FERC additional authority to alter the process at this stage could

damage and impede the progress already made. Now is certainly not the time to

increase uncertainty. With 98 percent or more of investor-owned transmission assets

committed to RTOs in development, the industry is demonstrating that many proposals in the last Congress for additional RTO authority were unnecessary. FERC

is an economic regulatory agency. Market structuring decisions should remain primarily where they reside today—in the Department of Justice, Federal Trade Commission, and with the state antitrust authorities.

Furthermore, if the federal government focuses the transmission debate on the

authority of the commission to restructure the industry, it conditions the industry

to be concerned with regulation, and not with making transmission systems work.

The businessmen will be regulatory experts, not transmission experts. Lately my

colleagues and I have spent a lot of time negotiating our way through regulatory

changes and policy debates, when what we need to do most is run this critical business and focus on customer satisfaction.

Adopt Mandatory Reliability Standards

In a competitive electricity market, voluntary reliability rules that market participants may or may not obey, depending on their economic incentives, will not work.

We have already seen market participants bending and even ignoring the existing

voluntary rules for their own gain. The North American Electric Reliability Council

(NERC) is reporting numerous violations of its voluntary reliability rules. A comprehensive restructuring bill should include provisions to ensure reliability standards developed by technical experts are mandatory and enforceable on all market

participants, with FERC oversight. Also, the rules should apply uniformly to provide

stability and security for new markets with new boundaries.

The President’s National Energy Policy Report calls for such legislation. H.R. 312,

legislation introduced by Representative Wynn, contains reliability provisions developed by NERC and numerous industry stakeholders. H.R. 2814 includes the same

reliability provisions. H.R. 2944, as approved by this Subcommittee in 1999, contained similar provisions. Also, the Senate passed a version of this bill last year.

The Barton discussion draft contains different language, but we believe its overall

goal is consistent with the previous proposals and that, with a few modifications,

this language would be acceptable to a majority of EEI’s member companies.

Streamline Merger Review Authority

Congress should streamline, at the very least, the review of dispositions of utility

property by the FERC under Section 203 of the Federal Power Act. Among other

things, this review is a barrier to consolidation of transmission networks and formation of RTOs.

Section 203 of the Federal Power Act is currently a ‘‘one-size-fits-all’’ provision that applies to the disposition of all jurisdictional assets with a value of $50,000 or

more. It applies to everything from a simple sale of a transmission substation to

the most complicated utility transactions. FERC reviews of dispositions of property

under section 203 take far too long and are often duplicative of reviews conducted

by other agencies. For some transactions, review is required by FERC, the Department of Justice, the Federal Trade Commission, the Securities and Exchange Commission, the Nuclear Regulatory Commission, and each affected state. Utility transactions should be reviewed by the government, commensurate with the way transactions involving other industries are reviewed. However, the massive, time-consuming, duplicative review specific to the electric utility industry is contrary to consumer interests because it delays companies’ ability to respond to market needs and

needlessly increases transaction costs.

Both the Barton discussion draft and H.R. 2814 would repeal Section 203 of the

Federal Power Act, which grants FERC authority to review public utilities’ disposition of property, consolidation and purchase of securities. This eliminates duplicaVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00025 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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tive federal merger reviews, leaving the Department of Justice or Federal Trade

Commission to review such mergers.

THE ALLIANCE RTO

FirstEnergy is one of the leaders in forming the Alliance Transco Limited Liability Company (Alliance Transco LLC) that we anticipate will be qualified as the Alliance RTO. We anticipate that an affiliate of National Grid USA, itself part of a

worldwide independent transmission-only company, will be the independent Managing Member of Alliance Transco LLC. As part of the transaction, National Grid

expects to make very substantial investments in Alliance Transco LLC to fund startup and to acquire assets. Alliance Transco LLC will be a for-profit transmission

company. The business of the company will be to provide transmission service. The

EEI member companies that now own the transmission assets expected to be controlled by Alliance Transco LLC will become its customers, aligning their interests

more closely with other generators and utilities. As I mentioned, with two years of

regulatory proceedings behind us and substantial approvals already obtained, Alliance Transco will be ready to operate by the end of this year in accordance with

the ambitious timetable set by Order No. 2000 if it gets final approval from FERC

this fall.

Over the last four years, and especially since the first Alliance filing in 1999, a

major portion of my daily activity and the people I work with has been focused on

forming the Alliance. The model we built has attracted five newer members to the

Alliance, which will now be able to provide transmission service roughly from the

Gateway Arch in St. Louis to Kitty Hawk, North Carolina. It will link large load

centers such as Chicago, Cleveland, and Northern Virginia.

Alliance is but one RTO being developed by EEI member companies. In each case

and under each model, there are business and human challenges that must be overcome. On the business side, we are focused on crafting and executing the business

and financial arrangements necessary to establish electric transmission institutions

that can serve growing competitive markets for electricity. This is the cutting edge

of financial restructuring.

On the human side, the new transmission industry will need experienced and

highly trained, highly motivated personnel. It takes experienced people to run these

systems. The system operators are the finest people around. The last thing they

want to happen is to reduce load or have a blackout. They take pride in making

sure that we effectively balance resources and load, and they work day and night—

literally 24 hours a day, seven days a week, 365 days a year—to keep the lights

on. We must keep these operators. However, without the right business proposition,

and without some certainty about the direction and promise of this emerging industry, how will we keep them?

I implore you to craft legislation in such a way that accelerates and does not retard the development of this new transmission industry and the start-up of RTOs

in development.

CONCLUSION

Our country needs a comprehensive electricity restructuring bill. And since transmission is the backbone of the entire industry, Congress needs to ensure that wholesale electricity markets are capable of delivering adequate, affordable and reliable

electricity to consumers. Without sufficient transmission capacity it won’t happen.

Transmission is the linchpin to well-functioning wholesale and retail markets. We

look forward to working with this Subcommittee to develop the transmission reforms necessary to enable the industry to launch the independent transmission businesses of the future and close the transmission investment gap.

23

24

25

Mr. BARTON. Thank you, Mr. Szwed.

We now want to hear from Mr. Roger Fontes, is that correct?

Who is the General Manager of the Florida Municipal Power Agency and he’s here on behalf of the American Public Power Association.

You’re recognized for 5 minutes.

STATEMENT OF ROGER A. FONTES

Mr. FONTES. Good morning, Mr. Chairman, and thank you, members of the subcommittee for the opportunity to testify today.

I am testifying on behalf of the American Public Power Association which represents 2,000 publicly owned utilities serving 40 million customers.

APPA supports the implementation of Federal policies that will

establish effective wholesale competition, and we share the view of

many members of the subcommittee that getting the transmission

issue right is the key to achieving that goal. Nowhere is this more

evident than in my State of Florida where we have inadequate

interstate connections with other States and where prior transmission discrimination has led to lengthy litigation on transmission

access issues.

Getting it right means resolving all of the issues you have identified for these hearings today, but you’ve also asked the panel to

specifically address three key ones: Siting, incentive rates and reliability of the grid. So let me address each of these.

Siting. It is widely recognized that the Nation’s transmission system is weak and highly constrained. These problems inhibit competition and threaten reliability. The biggest obstacle to new transmission lines is the difficulty of siting.

Currently the balkanized State-by-State process is not working.

Since these facilities are necessary to support interstate commerce,

a Federal role is appropriate and essential. APPA supports the concept of Federal eminent domain authority for major transmission

facilities and in that regard we support section 402 of the chairman’s draft bill.

Given the political problems involved, however, we think this authority should only be used after appropriate consultation and cooperation with State and local governments. Thus, we suggest that

this section be expanded to include an authority to create States

creating joint siting boards that mirror RTO boundaries, require

these boards to provide one-shop review and approval processes for

RTO approved facilities and provide FERC with siting authority if

States fail to establish boards or act on RTO plans.

Regarding incentive rates. Many transmission owners are urging

Congress to direct FERC to institute incentive rates to encourage

transmission construction. We strongly believe that this is the

wrong approach and is unnecessary. We must stop looking to the

entities that both own transmission and generation to build new

transmission facilities. The risk of losing generation sales to competitors by building new transmission is so great that we believe

the incentive will not help. And extensive profits really only spill

through to higher consumer rates for everyone.

Indeed, the chairman’s discussion draft includes a proposal, and

we respectfully request that it be deleted.

26

First, really, the obstacle to transmission is not the lack of capital or investors. The main obstacle is siting. Transmission is a low

risk traditionally regulated utility investment. It has been successful in attracting capital at reasonable and regulated rates of return. I believe Thomas Lane from Goldman Sachs testified before

your committee in late July and said ‘‘There is definitely a role in

the markets for low risk/low return investments, which is what

transmission represents.’’ We agree with this statement.

A recent example of this is Department of Energy’s request for

interest in constructing what’s now become the famous Path 15 in

California, which I understand garnered more than a dozen responses.

Second, additional legislation is not needed. FERC already has

existing authority to approve innovative or performance based

rates. FERC has had an incentive rate policy since 1992. Personally I find it ironic that the same time large transmission owners

are demanding higher rates to build new transmission, they are

steadfastly refusing to allow public power and cooperative system

to be paid by RTO’s for their prior transmission investments. Congress should not support this gambit.

Transmission will be built if we resolve siting issues and support

FERC’s authority to require RTOs to have the full authority to

plan and construct the grid.

Reliability. Certainly events of the past year have reenforced the

importance of maintaining and improving the reliability of the

transmission system. APPA supports enactment of Federal legislation to establish a national electric reliability organization to set

and enforce reliability standards with FERC oversight. In this regard we support section 301 of the chairman’s draft. We also support some changes to that section as proposed by the NERC, National Electric Reliability Council, that would impart, underscore

the need for FERC to oversee implementation of the standards and

enforce compliance by RTOs and others using the Nation’s transmission grid.

Thank you for the opportunity to be here today. Public power

looks forward to working with the subcommittee to address these

issues for the benefits of all consumers. Thank you.

[The prepared statement of Roger A. Fontes follows:]

PREPARED STATEMENT OF ROGER A. FONTES, GENERAL MANAGER AND CEO, FLORIDA

MUNICIPAL POWER AGENCY, ON BEHALF OF THE AMERICAN PUBLIC POWER ASSO- CIATION

Thank you, Chairman Barton, Ranking Member Boucher and Members of the

Subcommittee for this opportunity to testify. I am pleased to appear today on behalf

of the American Public Power Association to discuss several important issues involved in restructuring the nation’s electric transmission grid.

I am General Manager and CEO of the Florida Municipal Power Agency (FMPA),

a joint action agency providing wholesale power and other services to 29 municipal

electric utilities in Florida. APPA represents the interests of more than 2,000 publicly owned electric utility systems across the country, serving approximately 40 million customers. APPA member utilities include state public power agencies and municipal electric utilities that serve some of the nation’s largest cities. However, the

vast majority of these publicly owned electric utilities serve small and medium-sized

communities in 49 states, all but Hawaii. In fact, 75 percent of our members are

located in cities with populations of 10,000 people or less.

Public power systems’ first and only purpose is to provide reliable, efficient service

to their local customers at the lowest possible cost. Like hospitals, public schools,

police and fire departments, and publicly owned water and waste water utilities,

27

public power systems are locally created governmental institutions that address a

basic community need: they operate to provide an essential public service, reliably

and efficiently, at a reasonable, not-for-profit price. Publicly owned utilities also

have an obligation to serve the electricity needs of their customers and they have

maintained that obligation, even in states that have introduced retail competition.

And, because they are governed democratically through their state and local government structures, public power systems operate in the sunshine, subject to open

meeting laws, public record laws and conflict of interest rules. Most, especially the

smaller systems, are governed by an elected city council, while an elected or appointed board independently governs others. Democratically governed, not-for-profit,

obligated to serve all customers—understanding the underlying structure and mission of public power is essential in crafting balanced electricity legislation that will

maintain industry diversity and promote the consumer interest.

Wholesale Competition First—the Role of the Federal Government

There is only one reason for Congress to enact comprehensive electric utility restructuring legislation—to promote wholesale competition for the benefit of all consumers. The overriding objective must be to restructure the industry in a way that

has a high probability of benefiting all classes of consumers with no degradation of

reliability of service.

Moving from a monopoly model to a competitive model is very difficult. Those in

this transition who are threatened with a loss of market control can be expected to

fight tenaciously to retain competitive advantages or seek to gain market power.

The biggest obstacles to the creation of robust wholesale competition in the electric

utility industry are: 1) the inadequacies of our nation’s transmission infrastructure;

2) the failure to establish on a comprehensive basis efficient, competitively neutral

regional transmission organizations and to plan, construct, operate and provide the

transmission service needed for regional markets to succeed, and; 3) the pervasive

existence of market power in regional generation markets that can be exercised to

keep prices for consumers well above truly competitive levels.

The evidence of the continuing abuse of transmission and generation market

power is abundantly clear from the hearing record of this Subcommittee. The vast

majority of witnesses from very diverse constituencies and interests that have appeared at Subcommittee hearings over the past five years—whether it was on specific restructuring legislation or in response to the western electricity crisis of the

past year—have pleaded for Congress to address this problem.

Because they involve interstate commerce, Congress can only address the market

power problems in generation and transmission. Federal antitrust laws may remedy

problems in mature markets, but they are not effective to guide the transition to

competition for industries, like the electric utility industry, that must evolve from

highly concentrated monopolies. Antitrust laws cannot convert such industries to

ones that are capable of being controlled by competitive forces.

The identification of market abuses in any modern industry is hard, but in the

electric utility industry, it is extremely difficult. Electricity is a real-time product.

It is literally consumed as it is produced. It cannot be stored. This makes transactions in the electricity market very vulnerable to subtle discrimination and manipulation, including the ability to withhold transmission from competitors through reservations of capacity for ‘‘reliability’’ and to manipulate the timing of maintenance

of strategically located generation and transmission facilities. For these reasons, the

primary federal antitrust agencies, the Federal Trade Commission and the Department of Justice, have previously testified in favor of remedying the electricity market structure.

Transmission: the Key to Competition

Since today’s hearing is focused on transmission issues and how they are addressed in Chairman Barton’s discussion draft, my testimony will delineate transmission provisions that are essential in federal restructuring legislation and will

also cite specific provisions in the draft bill, including those that could be modified

or eliminated. It is important to remember, however, that generation markets and

the transmission system are inextricably linked. In particular, it is essential that

federal legislation provide the Federal Energy Regulatory Commission (FERC) with

authority to prevent and, where necessary, remedy the exercise of market power.

It is widely recognized that our current transmission system is weak and highly

constrained. The weaknesses of the grid not only threaten reliability; they undermine our ability to achieve robust competition. Competitive wholesale markets simply cannot work unless numerous competitors are able to deliver their product to

buyers. Today, our regional grids are characterized by ever increasing congestion

leading to more and more interruptions and providing buyers with fewer and fewer

28

reliable choices of supply. We need to fix the grid, physically by enabling prompt

construction of needed facilities, and institutionally by providing for independent,

competitively neutral planning, operation, and service.

Thus, APPA shares the view of many Members of the Subcommittee that getting

transmission ‘‘right’’ is the key to building an effective, competitive wholesale market and that expansion of the grid is critical to making the interstate transmission

system more robust and efficient.

The way to achieve these goals is four-fold:

1) reform the balkanized, state-by-state transmission siting process;

2) stop looking exclusively to entities that own both generation and transmission to

build new transmission facilities. The risk of losing generation sales to competitors by building more transmission is so great that these entities will not do

it without hefty incentive payments—payments that will unnecessarily increase

electricity costs for consumers;

3) grant FERC the authority to establish large, rationally scoped and truly independent Regional Transmission Organizations (RTOs) with full authority to

plan and expand the regional transmission system; and

4) ensure that RTOs fully compensate all transmission owners—whether large

vertically-integrated utilities, smaller transmission dependent utilities, or a

non-industry investors—for their investment in transmission facilities turned

over to an RTO’s control and operation.

The Chairman’s draft admirably addresses the first item, goes in the wrong direction on the second, and has not yet addressed the third and fourth.

Regional Planning and Siting

The Administration’s National Energy Policy Report directed Department of Energy Secretary Abraham to ‘‘develop legislation to grant authority to obtain rightsof-way for electricity transmission lines, with the goal of creating a reliable national

transmission grid.’’ APPA supports the approach employed in Section 402 of the discussion draft that provides FERC with siting authority when States or other entities

designated to review siting requests are either unable or unwilling to act.

As the Subcommittee reviews the discussion draft, we would suggest that these

additional provisions be added to Section 402 to further streamline the siting process:

1) Authorize the creation of joint state siting boards that mirror RTO boundaries.

2) Require theses siting boards to provide a one-stop review and approval process

for facilities in approved RTO regional plans.

3) Establish reasonable deadlines within which these siting boards must act on RTO

plans. Although Chairman Barton’s draft authorizes FERC to be given siting

authority on a particular project if a State or siting entity has failed to act within a year, we believe that certain projects may need more immediate action.

4) Grant the RTO federal eminent domain authority for the project so that it will

not have to proceed in multiple state courts under different standards once a

project has been approved either by a joint board or by FERC.

As the Chairman has acknowledged by including FERC siting authority in his

draft, the adequacy of the interstate transmission grid is vital to our nation’s economic and security interests and should be addressed on the national level. The current bureaucratic maze of state regulations and the threat of possible judicial action

in multiple state courts substantially hinder the siting of new interstate transmission lines. By substituting a single joint siting process for reviewing projects in

multiple states that are subject to different rules and standards, investors will be

able to proceed with much greater certainty that a project will be approved and

completed.

Incentive Pricing

We are aware that some transmission owners have been urging Congress to legislate to direct FERC to institute ‘‘incentive,’’ ‘‘innovative,’’ or ‘‘negotiated’’ rates to encourage owners to expand the grid. In fact, the Chairman’s draft directs FERC to

conduct a rulemaking on incentive and performance-based transmission rates. This

provision is unnecessary; APPA believes that FERC, under the Federal Power Act

and Order 888, already has sufficient authority and flexibility to design transmission rates to ‘‘promote economically efficient transmission and generation of electricity.’’ These rates remain subject to the ‘‘just, reasonable, and not unduly discriminatory or preferential’’ standard that has been the hallmark of FERC ratemaking authority. (This standard was recently affirmed by FERC in Order 2000 on

RTOs.) Further, APPA believes that incentive rates will undoubtedly lead to increases in overall transmission costs, which are decidedly not in the public interest.

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1Policy Statement on Incentive Regulation, 61 FERC ¶ 61,167 (1992).

As is mentioned above and will be discussed in more detail below, the most significant impediment to achieving a robust transmission system is the current, fractured, siting process. Because the Chairman’s discussion draft addresses this most

vital of transmission-related issues, the codification of ‘‘incentive,’’ ‘‘performancebased,’’ ‘‘innovative,’’ or ‘‘negotiated’’’ rates is unnecessary and the wrong approach.

For these and the following reasons, we feel strongly that Section 401 should be

eliminated from the draft bill.

Additional Legislation Is Not Necessary; FERC Is Already Empowered to Approve Innovative or Performance-Based Rates:

Legislation endorsing innovative rate-making to encourage transmission owners to

join RTOs, invest in new facilities, and operate the transmission system efficiently

is not necessary. The Federal Power Act (FPA) already makes ample room for incentives and performance-based rates that satisfy the ‘‘just, reasonable, and not unduly

discriminatory or preferential’’ standard that is the hallmark of utility rate-making.

In addition to this fundamental standard, Section 212(a) of the Federal Power Act,

which FERC has read into Sections 205 and 206, already provides FERC all the

flexibility needed to design rates to ‘‘promote economically efficient transmission and

generation of electricity,’’ but subject to the essential protections of the ‘‘just, reasonable and not unduly discriminatory or preferential’’ standard. Requests for additional legislative pricing authority should be recognized for what they are—requests

for rates that would not otherwise meet the longstanding and fundamental requirement that rates be just, reasonable, and in the public interest.

The concept of incentive rates is not new to FERC. Since 1992, FERC has had

an incentive rate policy.1 That long-standing policy recognizes that to be fair, ‘‘Incentive rate-making must simultaneously protect customers’ interest and offer potential rewards to the utility for good performance.’’ They also must be balanced: ‘‘[I]ncentive regulation should be designed to penalize utilities that fail to achieve

these efficiencies—opportunities for reward should be offset by symmetric downside

risk.’’ The policy statement establishes sound regulatory standards to guide evaluation of incentive rates, including the requirement to quantify benefits to consumers

and maintain quality of service.

FERC’s RTO rulemaking, Order 2000, expressly endorses its 1992 incentive rate

policy and applies it to the RTO context. In Order 2000, FERC both outlined a series of incentives and pricing innovations that RTOs could propose, and endorsed

performance-based rates. FERC’s RTO rule expressly invites rate treatments, such

as rate moratoriums, rates of return that consider ‘‘risk premiums and account for

demonstrated adjustment in risk,’’ and ‘‘non-traditional depreciation schedules for

new transmission investment,’’ 18 C.F.R. § 35.34(e). At the same time, the Commission’s rule requires a demonstration as to ‘‘how any proposed rate treatment would

help achieve the goals of Regional Transmission Organizations, including efficient

use of and investment in the transmission system and reliability benefits to consumers,’’ as well as a cost-benefit analysis.

Existing law expresses policies on reasonable incentives and rate innovations, and

demonstrates that new incentive rate legislation is not necessary. Existing law gives

FERC ample authority to provide balanced and justified rate incentives and performance-based rates that foster investment in and efficient operation of an expanded grid capable of supporting a robust competitive market, and ensuring reliable service to all consumers. No additional pricing language is needed to permit

pricing innovations or incentives that meet the Federal Power Act’s just and reasonable and not unduly preferential standard.

FERC has the ability to approve performance-based rates that reward above-average performance in the timely and cost-effective construction of needed facilities, but

FERC also has the ability to penalize poor performance and significant congestion

not remedied in a reasonable time. It needs no new congressional directive to reward RTOs that reduce their costs, increase throughput and customer satisfaction,

and eliminate congestion, while enhancing reliability.

Some proposals appear designed to raise rates to a level where the requirements

of Order 2000 and FERC’s incentive rate policy would not be satisfied, and to rewrite the FPA’s long-revered rate-making standard. By legislating incentives, without requiring the quantification of benefits to consumers and any cost benefit analysis, the legislation would tip the balance achieved by the just and reasonable

standard, as reflected in Order 2000. In addition, some proposals would provide for

incentive rates even where a transmission owner does not join an RTO.

As to RTOs, these proposals would legislate continued ‘‘pancaked’’ rates that violate Order 2000. A centerpiece of Order 2000 is the elimination of cumulative

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pancaked rates (or tolls) that must be paid whenever a transaction crosses the corporate boundaries separating one transmission owner from the next, a rate practice

that FERC found to impede development of competitive markets. To remove such

barriers to competition, FERC’s RTO rule expressly requires: ‘‘Customers under the

Regional Transmission Organization tariff must not be charged multiple access fees

for the recovery of capital costs for transmission service over facilities that the Regional Transmission Organization controls’’ 18 C.F.R. § 35.34(l)(ii).

In addition, it is neither necessary nor appropriate for Congress to legislate utility

rates of return. This determination, which FERC makes with the help of expert testimony, as well as information from the financial community on what would constitute an appropriate rate of return should be left to an expert agency, governed

by long-standing Supreme Court precedent as to what rate of return is reasonable.

Lastly, and most inappropriate for a monopoly service, is the proposal of some

IOUs for ‘‘negotiated rates’’ that are expressly ‘‘without regard to costs.’’ FERC has

repeatedly found non-discriminatory, open access transmission service to be the necessary foundation for competitive wholesale markets that the Energy Policy Act of

1992 intended to foster. Negotiated rates would undermine this fundamental policy

objective. Vertically integrated transmission owners could use this provision to burden their competitors, for example, by refusing to provide service on a timely basis,

or without extensive or expensive litigation, absent ‘‘voluntary’’ agreement to an extortionate rate. Indeed, congressional authorization of ‘‘negotiated’’ rates would signal a ‘‘Back to the Future’’ approach, inviting the very discrimination and self-preferences that formed the factual foundation for Order 888 and FERC’s open access

requirements.

Even as they relate to RTOs, ‘‘negotiated rates’’ are a bad idea. RTOs, while independent of market participants, are still transmission monopolists, providing a service essential to their electricity markets, and our nation’s economic well being. The

concept of rate ‘‘negotiation’’ makes no sense in this context, where customers are

necessarily captive to the RTO on which their loads or generations are located.

RTOs, seeking to maximize profit from their expansive regional transmission monopoly, might well be tempted to use ‘‘negotiated rates’’ as a mechanism to extract

excess profits for providing customers the service to which they should be entitled

at regulated rates. (Of course, the just and reasonable requirement does not prevent

compensation to RTOs for providing enhanced or expedited service.) Indeed, protecting consumers from the ability of public utilities to insist on excessive charges

for essential services is a core purpose of the FPA and the fundamental premise for

subjecting monopoly services to be regulated, just and reasonable, and not unduly

discriminatory or preferential rates.

Enhancing FERC’s Authority to Require RTOs that Have Full Authority to Plan and

Cause Expansion of the Regional Grid is a Far More Effective Way to Ensure

Investment in a Robust and Reliable Transmission System:

Today, the only parties that can build additions to the integrated transmission

grid are the existing transmission owners. A weakness of many of the RTOs being

formed is that they are not permitted to construct transmission lines themselves,

but have to order or cajole existing vertically integrated owners to construct. This

gives tremendous leverage to the owners. It should not surprise anyone that owners

in this negotiating position are holding out for higher rates of return and depreciation schedules much shorter than the useful life of facilities, while the situation gets

worse.

A key factor discouraging construction is the fact that owners of local generation

who also own transmission have a significant conflict of interest when it comes to

transmission construction that will open their generation up to competition. For instance, a new transmission line may cost $200,000,000 ($100,000,000 of equity) and

the FERC return on equity may be 12%, or $12,000,000 per year. But construction

of the line may also expose the owner to losses of up to $30,000,000 a year in generation sales. Thus, it is not surprising that such an owner will be reluctant to build

transmission and needs a large incentive to proceed.

A second important problem with looking to existing, vertically-integrated transmission owners to finance the transmission needed is that many of these owners are

diversifying into unregulated generation and other investments that have significantly different risk profiles than transmission. If a company is willing to take high

risk and its ‘‘hurdle’’ rate to justify new investments is a 15-20% return with a 5-

8 year payback, a transmission investment is not going to pass the test without a

major incentive paid by captive customers. This is particularly true in light of the

competitive downside to major transmission improvements for an owner of local generation. Similarly, transmission projects are not going to meet the investment criteria of venture capitalists or those interested in Internet stocks. This does not

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mean, however, that the rate of return for transmission should compete with the

potential returns for those alternative investments, which involve much more risk.

Notwithstanding, owner attempts to justify incentives by claiming that transmission is risky is quite untrue. Transmission is the prototypical low risk, traditional, regulated utility investment that has been very successful in attracting capital at reasonable, regulated rates of return.

The most significant risk associated with transmission is in getting facilities built

in the first place ( the long lead times required to build and the fact that a line

may ultimately not get built because of siting controversy. This risk can be mitigated by allowing recovery of prudent planning and siting costs for facilities in approved RTO plans, whether or not the facilities are ultimately built.

But once a transmission line is built, the risk is relatively low, and certainly significantly lower than with generation. A good example is the recent Fitch Report

on the new American Transmission Company in Wisconsin, a transco that began operations on January 1, 2001. As the report points out, over 95% of this transmission-only company’s revenue requirement is guaranteed by recovery from its

firm, network customers regardless of changes in load, weather, etc. The way costs

are allocated and charged under FERC procedures to the network customers of a

monopoly transmission system provides a very certain and steady recovery of revenues. The primary remaining risk is that variable O&M costs (which are minor) will

exceed what is included in rates, or that management will do a poor job otherwise

and the authorized return will not be realized. This risk profile certainly does not

justify a rate of return on equity in excess of a just and reasonable regulated utility

return ( or accelerated depreciation, for that matter.

There is certainly adequate capital in the markets for a safe, regulated annuitytype investment, which is what monopoly transmission should be. The new RTO regime needs to be designed to attract capital for projects from investors that are looking for solid 11-12% utility returns, year in and year out, with low risk ( the risk

being that the return may go to 10% in one year or up to 13% in another. These

are very different investors than those looking for a 15-30% return and are willing

to risk 0-5% or a loss.

As Thomas Lane, Managing Director, Goldman Sachs & Co. testified to this Subcommittee on July 27, ‘‘There is definitely a role in the markets for a lower risk,

lower return investment which is what transmission represents. Whether it’s 11%-

12%, somewhere in that neighborhood is what we still need to ferret out with the

investor base.’’ There is no reason to think that ‘‘cost plus’’ regulation, plus a reasonable return

on prudent investment, will be insufficient to attract investment in transmission,

without added ‘‘inducements.’’ Cost plus rate-making has been blamed for inducing

over-investment in expensive generation facilities, pre-competitive generation markets; a utility would only earn more by building more. Once decisions to expand

transmission are divorced from existing owners, with their competitive and financial

conflicts of interest, this same regulatory regimen would be ample to spur investment.

For these reasons, we believe it is very important that RTOs be specifically authorized in legislation to build transmission—whether they are for profit or nonprofit organizations—or, if they choose, to bid out passive ownership. If there is a major

transmission project the cost of which will be $100,000,000, the RTO should be able

to finance the project itself as a regulated utility or raise the needed capital by bidding out the return required, taxes, and depreciation (the fixed costs of ownership).

Individual companies or pools of investors, willing to be passive owners and looking

for the solid annuity-type of return of a monopoly transmission utility will certainly

bid.

In addition, public power and co-op systems should be not only permitted, but also

encouraged, to finance at least their share of transmission additions through debt.

This will help keep the cost of service down for everyone.

To this end, it is essential that RTOs be structured to compensate all transmission owners—whether a large vertically-integrated utility, a smaller transmission dependent utility, or a non-industry investors in transmission—for their investment in transmission facilities. Transmission expansion (and RTO participation)

will be discouraged if, as is now proposed by several RTOs, transmission dependent

utilities that own transmission are to be paid only a fraction of their revenue requirement (if that) for transmission facilities turned over to an RTO’s control and

operation. RTOs will not fulfill their purpose if only incumbent large transmission

owners are fully compensated for their transmission investment.

In other words, we should not accept transmission owner efforts to retain exclusive rights to construct while seeking rate incentives as an inducement to do so.

Rather than granting existing owners an exclusive right to build for RTOs and givVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00035 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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ing in to their incentive demands, we should enable RTOs to put competitive pressure on the cost of capital.

Thus, Congress should adopt legislation that arms FERC with authority to require formation of large, rationally-scoped and truly independent regional transmission organizations with full authority to plan and expand the regional transmission system. This would fully separate transmission from generation interests,

so expansion decisions are not influenced by how the expansion affects the value of

the transmission owner’s generation. Providing RTOs the authority to cause needed

construction by the transmission owner or others opens the doors to market-based

means to get the needed transmission constructed efficiently—by bidding out construction to third parties.

Reliability

APPA supports the goal of the Chairman’s draft in creating a national electric reliability organization to set and enforce reliability standards, subject to FERC oversight. The Administration’s National Energy Policy report also calls for enactment

of mandatory reliability standards by an independent body and overseen by FERC

to ‘‘address the problems created by increased demands on the transmission system

that have resulted from changes within the industry brought on by wholesale competition.’’

Even though the United States has the most reliable electric system in the world,

the electricity crisis in the West demonstrated the delicate balance between reliability and the markets within which the electric grid must operate. Consequently,

great care needs to be taken to ensure that the current level of reliability is not

sacrificed in any restructuring of the industry. As the industry has become more

competitive, more participants have been executing an increasingly greater number

of transactions every day. The focus of most of these transactions is on short-term

costs rather than on system stability.

The North American Electric Reliability Council (NERC) and its regional councils

currently promulgate and implement standards to ensure the adequate availability

of electricity throughout the country. This voluntary system of compliance with reliability standards works reasonably well in the regulated environment in which the

industry previously operated, but it will not continue to provide the necessary safeguards in a competitive market nor in an era of heightened threats of terrorist attacks.

It is our understanding that NERC has submitted suggested changes to Title III,

Section 301, of the Chairman’s draft bill. APPA concurs with NERC’s comments,

and would underscore the need for FERC to oversee the implementation of reliability standards and enforce compliance by RTOs. The Chairman’s draft should be

modified to explicitly require this obligation to comply. RTOs will be responsible for

the reliable operation of the bulk system in real time. They also need to be responsible themselves by complying with reliability standards.

OTHER TRANSMISSION ISSUES

FERC Transmission Jurisdiction

Local control is one of the most fundamental aspects of public power. However,

it is difficult to envision effective wholesale markets, which, as noted, APPA strongly supports, without some degree of federal involvement in public power transmission that is part of the regional grid. APPA members have struggled with the

problem of balancing the retention of local control with the recognition that transmission is a matter of interstate commerce. While publicly owned utilities with

transmission facilities are not anxious to be subjected to FERC jurisdiction, the limited jurisdiction contemplated in Chairman Barton’s restructuring bill (H.R. 2944)

from the last Congress, known as FERC-lite, is an acceptable compromise and is

consistent with APPA policy. In essence, FERC-lite would extend FERC jurisdiction

to public, cooperative, and federal utilities with transmission facilities interconnected to the national grid. The FERC-lite language makes the important exception, however, that FERC would not be given the authority to set transmission rates

for these transmitting utilities. Instead, FERC would determine whether the rates

to others are comparable to those charged to themselves. If they are not, FERC

would remand the issue to the publicly owned utility.

While the Chairman’s draft includes the essential provisions of this FERC-lite approach, unfortunately, it also includes new provisions giving FERC the authority to

order refunds by public power systems, and in so doing, providing FERC authority

over public power systems’ transmission rates under Sections 205 and 206 of the

Federal Power Act. The combination of these authorities, in fact, results in very

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heavy federal regulation of public power and cannot be supported by APPA. We suggest that the provisions related to FERC refund authority be deleted.

The issue of transmission jurisdiction in a bundled vs. unbundled transaction is

an important issue now before the U.S. Supreme Court. Within APPA’s membership, there are different positions on this issue. Transmission dependent utility

(TDU) members believe that service to them must be fully comparable to utility

owners’ own use of the system. The native load of a TDU system should not be shed

before the native load of the owner or there can be no fair competitive market. Public power transmission owners that are vertically integrated are equally concerned

that FERC not interfere with their primary obligation to provide highly reliable,

economic service to the consumers that own them and for whom their systems have

been built.

Creation of Regional Transmission Organizations (RTOs)

The single most important step that can be taken to achieve the goal of a robust

transmission system is the establishment of large, truly independent RTOs that

have primary planning responsibility for the regional grids under their control.

APPA continues to support the authority of FERC to establish and require public

utility participation in strong, truly independent RTOs in order to facilitate the development of vigorously competitive retail markets. Any federal legislation should

provide FERC with the authority needed to achieve this goal. In addition to mandating true independence, and sufficient size, and rational scope of RTOs, the statutory criteria should accommodate the unique characteristics and legal requirements

of public power to ensure that public power’s participation by FERC order is not

inconsistent with state laws and constitutional requirements. Furthermore, the additional criteria for public power participation must be consistent with bond covenant requirements and should not impair control of local system operations of reliable and economic service to customers of public power systems.

In order for an RTO to be effective in promoting a competitively neutral transmission system, it must have several specific characteristics. It must be independent

to ensure that owners of transmission cannot exercise vertical market power. It

must have boundaries that are rational and that eliminate the current balkanization and gerrymandering of the grid. It must take into consideration the needs

of all stakeholders—including the needs of public power transmitting utilities—to

ensure fair and equitable treatment of all users. In addition, while it may be appropriate for FERC rates to reward excellent performance as previously discussed, it

is not appropriate for FERC to provide incentives for participation in RTOs. Instead,

RTO participation should be a key condition to enjoying the benefits of market pricing and relaxed wholesale regulation.

It is absolutely essential to clarify FERC’s legal authority to accomplish these objectives or we will experience continued long delays and unnecessary litigation.

Without a clarification of FERC’s authority, utilities will continue to resist and

delay RTO formation—and the current chaotic state of development will continue

indefinitely.

Publicly owned utilities have been willing to participate in RTOs which are consistent with the specific criteria set forth by FERC in Order No. 888 and clarified

in Order No. 2000. In fact, FERC commissioners and various FERC orders have specifically addressed public power participation, not to encourage public power systems to join but rather to encourage private utilities to let them join on fair and

reasonable terms.

RTO Participation

FERC has indicated that it believes it currently has the authority to order jurisdictional utilities to participate in RTOs, and we agree that restructuring legislation

should affirm this existing authority while expressly confirming and providing for:

1) The authority asserted in Order No. 2000 to order RTO participation by a jurisdictional utility to remedy undue discrimination or anti-competitive effects and

as a condition for mergers or market based rates. Legislation should also confirm FERC’s authority that was the foundation for Order No. 888.

2) Recognition and reinforcement of FERC’s existing authority to require RTO participation as a condition to authorizing market-based rates for jurisdictional

utility wholesale power sales. Where such authority has already been granted,

FERC should be required to review those prior actions and determine whether,

absent the participation of the wholesale supplier in an RTO, continued marketbased wholesale rates are consistent with promoting competition or in the public interest.

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3) RTO participation by jurisdictional utilities should be a necessary condition in determining proposed mergers of vertically integrated utilities are consistent with

the public interest.

4) RTO participation by jurisdictional utilities should be a condition precedent to

any relaxation of Public Utility Holding Company Act (PUHCA) requirements.

5) As mentioned above, FERC should be allowed to reward superior performance by

RTOs, but prevented from providing financial incentives simply for RTO participation.

6) FERC must have the authority and responsibility to ensure that RTOs are capable of providing the infrastructure and services required for competition to

thrive. This authority should include the responsibility to determine what constitutes ‘‘independence’’ of RTO operations from control, direct or indirect, of the

owners of transmission committed to the RTO (as well as other market participants); whether a proposed RTO will have the authority to operate, control,

plan and cause expansion of the grid for the benefit of all customers; and what

boundaries are necessary to ensure a regional scope sufficiently broad so as to

ensure development of robust and efficient regional electricity markets.

In addressing the participation of non-jurisdictional utilities—public power systems and rural electric cooperatives—FERC should be given the ability to direct

RTOs to accommodate their unique tax and legal requirements. And, if a RTO also

administers wholesale markets, FERC should—after reviewing all market rules, tariffs and protocols promulgated by the RTO—make a finding that the rules and protocols do not allow sellers or buyers to exercise market power.

Regarding the issue of FERC mandating the participation of non-jurisdictional

utilities in RTOs, deference should be provided to publicly owned utilities, similar

to the restraints on FERC jurisdiction over transmission facilities noted above. Specifically, APPA recommends that FERC’s authority to order publicly owned utilities

to join a regional transmission organization should be limited to situations in which

FERC finds that (1) the publicly owned transmission owner has (a) engaged in

undue discrimination in the provision of transmission services, or (b) abused its control over transmission so as to disadvantage competitors; and (2) that the FERC

open access transmission tariff has not and is not likely to remedy the problem. In

such cases, APPA agrees FERC should be authorized to require the publicly owned

utility at issue to surrender control of its transmission to an independent regional

transmission organization that meets FERC RTO criteria.

We also believe Congress, in clarifying FERC’s authority to order utilities to join

RTOs, should take into consideration the cost consequences of such action. Clearly,

RTOs should decrease, not increase, total transmission costs. Cost shifts and increases have been a very significant problem for public power systems in California.

Obviously, it would be imprudent for a public power system, which has financed

transmission with public funds, to join an RTO that will significantly increase the

cost of power to its customers. Some cost shifting may be inevitable, but any FERC

action in this area should be premised on the principle that adverse cost consequences for utilities ordered to join RTOs should be held to the minimum possible.

This is particularly important with respect to public power systems that have constructed their facilities with public funds.

APPA appreciates the Subcommittee’s willingness to address the important issue

of comprehensive electric utility restructuring legislation and the key role of the

transmission system in fostering a competitively neutral wholesale electric market

for the benefit of all consumers.

Mr. BARTON. Thank you very much.

We now want to hear from Mr. Robert Nordhaus, whose with

Van Ness Feldman. He’s here on behalf of The Large Public Power

Council.

Your statement’s in the record. We’d ask you to summarize it for

5 minutes.

STATEMENT OF ROBERT R. NORDHAUS

Mr. NORDHAUS. Mr. Chairman, members of the subcommittee,

I’m Robert Nordhaus here on behalf of LLPC. I’m standing in for

our originally scheduled witness, Chuck Manning of Austin Energy

who was not able to make it back for this hearing.

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By way of background, LLPC is an association of the 22 largest

public power systems in the country, and among our members are

the principal public power transmission owners.

We will have a witness in the afternoon who will address a number of specific issues with respect to FERC jurisdiction and RTO

policy. I’m addressing three matters; reliability, siting and transmission rate making.

With respect to reliability, LLPC does support the general approach of the NERC consensus bill from last year. We realize the

consensus seems to have evaporated, but we do believe that it is

necessary to provide for mandatory reliability standards and for an

enforcement mechanism that applies to all players in the electric

power industry.

FERC’s authority now is limited. The mechanism for enforcing

the current voluntary reliability standards if largely limited to contracts and tariffs and there’s no public suasion behind them. So, we

would recommend that any comprehensive electric restructuring

legislation include provisions that make the current voluntary

standards mandatory, provide for an adequate enforcement mechanism. We do believe that it’s appropriate for the day-to-day work

in developing standards and enforcing them be delegated to a private organization acting under FERC supervision.

With respect to siting, the LLPC support carefully circumscribed

eminent domain authority. We think that it’s important to make

sure that those who exercise this authority do it after a careful coordination with whatever regional transmission planning mechanisms are set up, presumably through RTOs, and that the interests

of State and local governments in the process be respected.

We have suggested in the testimony a couple of things. One is

that the committee may wish to limit the exercise of this authority,

the eminent domain authority, in the chairman’s bill discussion

draft to RTOs and to transmission owners acting with the approval

of an RTO whose transmission is under the operation of an RTO.

Similarity, as we look at where the real problem is, it may be that

a further condition that could be appropriate is that the exercise

of this authority be predicated on a finding by FERC that it’s necessary to ensure adequacy of interstate transmission service.

With respect to rate making, the LLPC believes that the starting

point for transmission rate making should be cost service rate. In

our testimony we set out several circumstances under which it may

be appropriate to depart from that. As a general matter, we do not

think that market based rates for transmission services are feasible

or appropriate under virtually any circumstances.

With respect to negotiated rates, we suggest that that may be

possible where the transmission users has an unqualified right to

elect a cost based rate in lieu of a negotiated rate.

With respect to performance based rates, we think that there’s

actually some significant latitude for coming up with workable performance rates using a split savings formula that gives a portion

of efficiency savings or savings through construction of new transmission facilities, a portion of the savings to the transmission

owner as long as a portion of the savings is reserved for the transmission users.

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With respect to incentive rates generally, our view has been, particularly with rates of return, that current rates of return look

pretty good compared to what investors are doing on the stock market right now. That the place for incentive rates of return is not

for all transmission investment, but perhaps for critically needed

new investments, and that’s something that we think could be considered.

I would also echo Mr. Fontes’ point, and that is FERC does have

adequate authority under existing law to deal with all of these

issues. It’s not clear that it needs to be addressed in legislation.

Mr. Chairman, those are our remarks. And with that, I’ll yield

to the next speaker. We thank you.

[The prepared statement of Robert R. Nordhaus follows:]

PREPARED STATEMENT OF ROBERT R. NORDHAUS ON BEHALF OF THE LARGE PUBLIC

POWER COUNCIL

My name is Robert R. Nordhaus and I appear today on behalf of the Large Public

Power Council (LPPC). I am a member of the law firm of Van Ness Feldman, PC,

and serve as outside counsel to LPPC. The LPPC is an association of 22 of the largest public power systems in the United States. LPPC member systems directly or

indirectly provide reliable, affordably-priced electricity to approximately 18 million

customers and we own and operate over 44,000 megawatts of generation and approximately 26,000 circuit miles of transmission lines. LPPC members are located

in states and territories representing every region of the country, including several

states represented by members of this Committee—such as Tennessee, Texas, California, New York, and Arizona.

LPPC members are publicly-owned, service-focused and committed to the local

residents and communities they serve. The benefits of their reliable and cost-effective provision of generation, transmission, and distribution service flow directly to

their customers and communities.

Mr. Chairman and members of the Subcommittee, the LPPC appreciates your efforts to develop comprehensive electricity legislation. The LPPC supports the enactment of comprehensive legislation that promotes a competitive, efficient wholesale

power market of benefit to all consumers. The LPPC believes that a robust wholesale market should be encouraged and supports efforts to increase competition so

long as low-cost, reliable service is ensured for consumers.

The LPPC also appreciates the efforts this Subcommittee has made to advance

the debate on how to achieve a competitive market that benefits consumers. The

Large Public Power Council offers its continued assistance in crafting legislation to

facilitate competitive markets. The LPPC has reviewed the Discussion Draft dated

September 21, 2001, issued by Chairman Barton, and while we will not comment

extensively on this draft, my testimony and that of Bob Johnston later today will

highlight several of LPPC’s specific concerns. We understand that this is a discussion draft and that it is intended to foster significant discussion among the affected

parties and the Committee members. The LPPC would like to continue to participate in this dialogue.

I would like to comment on the issues that are the focus of the Committee’s attention today.

INCENTIVE RATES

The LPPC supports the continued establishment of transmission rates according

to well-established, cost-based rate principles. Allowed rates of return should be sufficient, as determined under conventional approaches, to compensate transmission

owners for the risk and costs caused by increased use of the existing transmission

facilities and reasonable costs to attract capital for the new transmission construction. However, the costs related more appropriately to the generation or distribution

businesses of the transmission owner should not be included. Given the substantial

uncertainties accompanying the restructuring of transmission ownership and operation, as well as the nature of the business going forward, it may be premature to

depart from cost-based ratemaking principles in establishing transmission rates.

We do not support the concept of market-based rates for transmission service. Except for isolated circumstances involving the construction of merchant transmission

facilities, there is no evidence of competition among transmission providers for

wholesale or retail customer business. Only a tiny minority of wholesale or retail

37

customers enjoy physical interconnections with more than one transmission provider. Under current circumstances, there is no competitive market pressure to limit

transmission rates; thus there is no economic justification for implementing marketbased transmission rates.

The LPPC believes that the establishment of transmission rates through negotiations between transmission providers and customers should be permitted only when

the customer has either or both of two demonstrated alternatives: the ability economically to continue to conduct business without the proposed transmission service

or the availability of the transmission provider’s cost-based default tariff (similar to

the ‘‘recourse rate’’ in natural gas regulation). The use of negotiated rates may also

be appropriate when lining up customers for a new merchant or project-financed

transmission facility.

Finally, the LPPC is willing to consider the appropriateness of a performancebased or other form of incentive rate for transmission service. We believe that the

building of new transmission should be encouraged and believe that properly structured incentive rates might be able to encourage such investment. However, any incentives must be tied to acceptable and demonstrable benchmarks of performance.

An acceptable proposal could provide for a ‘‘split the savings’’ formula under which

the transmission provider would be permitted to retain a percentage of demonstrated savings achieved through improved efficiency of operation (as compared

to an accepted baseline cost of service) or through construction of new facilities that

relieve congestion and lower transmission users’ congestion costs. The form of incentives or savings must not disadvantage or discriminate among different types of

wholesale energy customers or transactions. In addition, we believe that such proposals should be made only in the context of a filing by an RTO or subsidiary organization encompassing more than one transmission provider’s system, (e.g., an independent transmission company).

Section 401 of the Discussion Draft directs FERC to conduct a rulemaking to establish incentive rate policies, designed to promote expansion of and improvements

in the transmission network. The LPPC urges a more narrow application than is

contemplated by the Discussion Draft. For example, while we could support higher

rates of return for critical new transmission investment, we would not support a

general increase in rates of return for sunk investments that is unrelated to changes

in market interest rates or equity returns.

SITING ISSUES

A thorough review of the various processes that serve as a barrier to constructing

new power generation and to the more efficient use of existing power generation

should be undertaken. There are multiple, sometimes duplicative permitting requirements for new generation facilities. In addition, various regulatory requirements make construction of new facilities time-consuming, costly, and unpredictable. Recognizing the need for a more efficient and transparent permitting system,

the LPPC would encourage a review of the permitting requirements for new and existing generation and, where possible, require that the processes be streamlined,

conducted in parallel and expedited to the maximum degree feasible. The LPPC supports the creation of an inter-agency process among the Environmental Protection

Agency, the Department of Interior, FERC, and the Nuclear Regulatory Commission

that would streamline the current requirements.

Coordination of federal approvals on the multiple permits would reduce time-lines,

uncertainty, and costs for companies constructing or modifying generation facilities.

Given the importance of getting power on line, this issue can make a real contribution to a comprehensive energy strategy.

The difficulty in constructing new transmission facilities and upgrading existing

facilities on a timely basis is one of the key obstacles to assuring the delivery of

low-cost, reliable electric power to consumers. Prompt federal and state action is

necessary to enable transmission providers to install new facilities and upgrades

where needed. The LPPC supports giving FERC carefully circumscribed authority

to provide transmission-owning RTOs or ISOs the right of eminent domain if they

demonstrate that the installation of transmission facilities is required to ensure adequate and reliable service. Owners of transmission facilities under operational control of an RTO or ISO would be given similar authority. Section 402 of the Discussion Draft provides federal eminent domain authority to an applicant seeking to

construct or modify transmission facilities. As currently drafted, there is no requirement that the transmission facility be part of a regional planning process or approved by an RTO or ISO, or that it be necessary to enhance or improve reliability

or economy of service. The LPPC would urge that this provision be revised to provide the eminent domain authority to the RTO (or to transmission owners whose

38

facilities are operated by an RTO) and that the role of the state and local governments be given greater weight. One possibility would be to limit exercise of this authority to circumstances where adequacy of interstate service is at issue.

The LPPC also supports the development and use of mechanisms—such as interstate transmission siting agencies or joint boards (comprised of members of federal

and state regulatory agencies)—that encourage the coordination of federal and state

environmental permitting and certification activities.

RELIABILITY

As the recent crisis in the West has demonstrated, great care must be taken to

ensure the continued and reliable supply of electricity as the industry is restructured. The LPPC supports mandatory reliability criteria and standards developed by

national or regional reliability organizations overseen by FERC. We supported the

NERC reliability consensus legislation last Congress. Although it appears that the

consensus has evaporated at this time, we remain committed to supporting the general concepts contained in that legislation. The LPPC believes that there is a need

to clarify FERC authority over reliability, that there should be binding electric reliability standards, and that there should be a clear mechanism to enforce these reliability standards.

The LPPC believes that regional modeling should be done to assess the impacts

of the creation and development of RTOs on the transmission grid. As the transmission grid is regionalized, an evaluation of the lessons learned should be done so

that reliability is ensured and the potential benefits are maximized.

We believe that any legislative proposal should make it clear that compliance with

reliability organization rules or standards does not subject entities to the jurisdiction of FERC for purposes other than to ensure reliability. Also, reliability standards need to be supported by long-term contracts that will ensure the availability

of operating reserves.

CONCLUSION

As the Subcommittee continues to move forward with electricity legislation, the

LPPC offers our continued assistance. We look forward to helping you to develop

comprehensive electricity legislation that addresses our concerns, garners wide support and can ultimately be enacted. I will be happy to answer any questions you

have.

Mr. BARTON. We thank you, Mr. Nordhaus.

We now want to hear from Mr. Glenn English, who is CEO of

the National Rural Electric Cooperative Association. He’s also a

distinguished former Member of the House of Representatives.

Your statement’s in the record in its entirety, and we would welcome you to summarize it in 5 minutes.

STATEMENT OF GLENN ENGLISH

Mr. ENGLISH. Thank you very much, Mr. Chairman. I appreciate

that, and I want to follow up on what Mr. Nordhaus was talking

about, focus on one particular aspect of the draft that was circulated and one that, quite frankly, I find to be very puzzling.

It has to do with the whole question of incentive rates. We’ve had

a lot of discussion about incentive rates. What does not seem to be

generally recognized is the fact the Federal Energy Regulatory

Commission already has the authority for incentive rates. That’s

under the existing law. They are required to provide incentive rates

that are just and reasonable.

Well, that gives anyone an awful lot of discretion to simply use

your judgment to determine what is just and reasonable, what is

necessary to get this job done. But it appears from the language

in the draft that that simply is not adequate. So if it is not adequate, obviously that brings one to the conclusion that if you are

including just and reasonable to be redefined in this legislation,

then you must be attempting to redefine it to something that’s unVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00042 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
39

just and unreasonable. And quite frankly, I have a hard time understanding how in the world anyone could justify insisting that

the Federal Energy Regulatory Commission in effect grant rates

that are unjust and unreasonable. That’s what I find to be particularly disturbing about this proposed legislation.

Now, as it stands now we think the Federal Energy Regulatory

Commission has all the authority they need to use their good judgment and to act in the public interest. There is no disagreement

over the fact that there needs to be more transmission built in this

country. There is no disagreement over the fact that this country

needs a transmission system to meet the needs of the country everywhere. And we all join in supporting that. But this particular

segment to give the Federal Energy Regulatory Commission more

tools, instead it takes away the tools that FERC has and it requires

the FERC to act in a way that they find to be unfair. To act in a

way that will obviously discriminate against the consumers of this

country.

And, in fact, I think a very strong case can be made, Mr. Chairman, that this particular provision is nothing but a transfer of

wealth from the consumers of this country to the utilities that are

building this transmission.

Now, the outrage with regard to this particular section doesn’t

stop there, Mr. Chairman, because it isn’t just new transmission

that would come under this new provision of requiring the Federal

Energy Regulatory Commission to provide more than what they

feel to be just and reasonable. They’re required now to provide it

on transmission that already exists.

now, if we were in fact going to raise rates to consumers with

regard to the transmission line to require that consumers pay an

unjust and an unreasonable rate on existing transmission, we

would hope that there would be something done with that money

that’d be productive. But there’s absolutely nothing in this legislation that require those funds to be used to build new transmission.

In fact, there’s nothing to prohibit the additional funds from being

overseas. That simply doesn’t make any sense, Mr. Chairman.

So we find this to be a very unfair segment and certainly we

think that at the very least if consumers are going to be required

to pay an unfair, an unjust and unreasonable amount of money for

transmission in this country that there should be some provision

that requires that money to be used to build new transmission in

this country.

Now, what we find to make far more sense, and since we’re going

to get out of the classroom and out of the academics with regard

to this issue, Mr. Chairman, is your own State of Texas. We think

your own State of Texas has the right approach with regard to

building transmission of this country, and we take note of the fact

for all of those that are interested in more than an academic exercise, that this year in the State of Texas three-quarters of a billion

dollars is going to be building transmission. And next year they already have scheduled over a billion dollars of more transmission

being built in the State of Texas. But they don’t find that there’s

any requirement for an unjust or unreasonable rate. In the State

of Texas that’s being done with a 10-percent return on investment,

40

which is in line with what the testimony was for this committee

from the investment community from Goldman Sachs.

In addition, Mr. Chairman, there are no incentives that are being

provided in the State of Texas. There’s no accelerated depreciation

as this legislation includes in the State of Texas, but they’re building transmission in the State of Texas. Now, if it can be done in

the State of Texas, I’d ask you why can’t it be done in the rest of

this country. It has certainty, Mr. Chairman, in the State of Texas;

that’s the reason. They let others do it in the State of Texas. They

open it up and let everybody compete. Anybody that wants to build

transmission, let them do it. That’s what they do in the State of

Texas.

And they let the shareholders, all those people that are going to

be using it and making the decision on where that transmission is

going to be built.

Now, that makes sense, Mr. Chairman. And I would suggest to

you if we’re going to do something productive in this legislation on

building transmission, that we should in fact allow FERC to use

the State of Texas proposal in order to build transmission in this

country. Give them the options. You know, if you feel it’s necessary,

give FERC whatever authority they feel they need to get this job

done, but let’s not limit the options. Let’s not require the FERC to

do something that’s contrary to what their good judgment allows.

Mr. Chairman, I’d only say if it’s good enough for the State of

Texas, it’s good enough for the rest of this country.

Thank you very much.

[The prepared statement of Glenn English follows:]

PREPARED STATEMENT OF GLENN ENGLISH, CHIEF EXECUTIVE OFFICER, NATIONAL

RURAL ELECTRIC COOPERATIVE ASSOCIATION

INTRODUCTION

Chairman Barton and Members of the Subcommittee, I appreciate this opportunity to continue our dialogue on the restructuring of the electric utility industry.

For the record, I am Glenn English, CEO of the National Rural Electric Cooperative

Association, the Washington-based association of the nation’s nearly 1,000 consumer-owned, not for profit electric cooperatives.

These cooperatives are locally governed by boards elected by their consumer owners, are based in the communities they serve and provide electric service in 46

states. The 35 million consumers served by these community-based systems continue to have a strong interest in the Committee’s activities with regard to restructuring of the industry.

Electric cooperatives comprise a unique component of the industry. Consumerowned, consumer-directed electric cooperatives provide their member-consumers the

opportunity to exercise control over their own energy destiny. As the electric utility

industry restructures, the electric cooperative will be an increasingly important option for consumers seeking to protect themselves from the uncertainties and risks

of the market. I would like to thank you, Mr. Chairman, and Members of the Committee for your receptiveness to the concerns and viewpoints of electric cooperatives.

TRANSMISSION RELIABILITY

North America needs the electric transmission equivalent of the interstate highway system. The current transmission system cannot reliably handle the dramatic

increase in transactions since the enactment of the 1992 Energy Policy Act. Transmission deficiencies are contributing to wholesale and retail electric market failures

that are harming consumers.

Based on the following reasons, NRECA does not believe that these problems can

be solved only by offering utilities high incentive transmission rates or other financial incentives to build transmission.

41

1FERC has also been encouraging the submission of incentive transmission rate proposals. According to FERC in Order 2000, ‘‘we have approved five ISOs [independent system operators]

with innovative transmission pricing, but otherwise have received few innovative transmission

pricing proposals.’’ 2FERC’s Pricing Policy for Transmission Services, 59 Fed. Reg. 55,031 (1994) (codified at 18

C.F.R. Part 2); Formation of Regional Transmission Organizations, 65 Fed. Reg. 810, 913 (2000)

(codified at 18 C.F.R. Part 35).

• FERC’s Existing Authority. FERC already has the authority to establish incentive

transmission rates. FERC issued a policy statement in 1994 that would permit

‘‘more flexibility to utilities to file innovative pricing proposals...’’ In Order

2000, FERC stated that it was ‘‘critically important for RTOs [regional transmission organizations] to develop ratemaking practices that... provide incentives for transmission owning utilities to efficiently operate and invest in their

systems.’’ 1 In testimony before the Energy and Air Quality Subcommittee on

September 20, 2001, Deputy Secretary of Energy Frank Blake stated that

‘‘FERC has great flexibility under current law to set transmission rates at a

level to attract investment.’ Since FERC has existing ratemaking authority to

approve incentive transmission rates, legislative language is unnecessary.

• Higher Electricity Prices for Consumers. Currently, FERC has wide discretion in

determining whether a public utility’s transmission rate is reasonable. Legislative language requiring FERC to approve incentive transmission rates is designed solely to handcuff FERC by curtailing its authority to reject unreasonably high transmission rates, resulting in higher electricity prices for consumers. Also, by limiting FERC’s ability to reject unreasonable rates, the opportunity for profiteering based on transmission rates exists.

• The Investment Community Is Unconvinced. During the July 26 hearing before

the Energy and Air Quality Subcommittee, Thomas Lane, Managing Director in

Goldman Sachs Energy and Power Group, responded to Member questions and

stated that there is a role for transmission rates that include the more traditional return on investment of around 12%. Since Wall Street believes that investments will flow into the transmission sector based on the current rate structure, it is unnecessary to force FERC to rubber stamp unreasonable rates.

• Lack of Newly Constructed Transmission. Legislative language forcing FERC to

approve incentive transmission rates will not automatically result in the construction of new transmission for two reasons. First, the language fails to guarantee that transmission facilities will, in fact, be built in exchange for FERC’s

approval of incentive rates. Second, the language would require FERC to approve incentive rates for the operation of existing transmission facilities. High

rates of return associated with existing transmission facilities will act as disincentives to the construction of new transmission that is needed to support a

robust wholesale market.

• Impediment to Generation Markets. The interstate transmission system should

exist to enhance the competitive generation market not to balkanize it further.

Any approach that allows individual companies with a financial interest in the

energy market to control transmission would have the unwelcome effect of

erecting tollgates on the interstate system, thereby narrowing generation markets and protecting the existing power of local generators.

NRECA is concerned that the incentive approach would raise the rates of return

and increase the costs for consumers, the intended beneficiaries of lower prices from

competition. Also, FERC not only has that authority under existing law, but also

has been encouraging utilities to propose innovative incentive-based rate designs for

years.2 In fact, FERC recently offered utilities a 300 basis-point increase in the rate

of return and a 7-year recovery period if they would build transmission in the West

by a stated deadline.

Given FERC’s current efforts to encourage innovative rates, NRECA is concerned

that legislative language establishing only incentive rates may handcuff FERC, limiting the agency’s ratemaking discretion at a critical time in the development of a

competitive industry.

As an option to legislating higher rates of return, NRECA believes Congress

should lower the risk of building transmission. Congress should direct FERC to

allow any entity that builds a qualifying transmission project to recover its costs.

By reducing the risk, Congress could encourage institutional investors and others

looking for low risk investments invest in improvements to the nation’s transmission

grid.

To qualify for assured cost recovery, NRECA believes that transmission projects

must:

42

3FERC’s Pricing Policy for Transmission Services, 59 Fed. Reg. 55,031 (1994) (codified at 18

C.F.R. Part 2); Formation of Regional Transmission Organizations, 65 Fed. Reg. 810, 913 (2000)

(codified at 18 C.F.R. Part 35).

—be identified through a regional joint-planning process that coordinates and has

oversight for the reliable operation of the regional transmission system —be constructed according to best engineering practices —be operated by the relevant Regional Transmission Organization (RTO) —offer service pursuant to traditional cost-of-service principles, with the cost-ofservice analysis taking into account the low risk provided by FERC’s obligation

to assure cost recovery.

By mitigating risk, spreading the cost of new facilities broadly, and enabling new

competitors to build transmission, NRECA’s approach to new transmission helps to

ensure that the interstate highway system can be built at the lowest possible cost

to consumers.3

ELECTRIC RELIABILITY

Since 1968, the electric utilities of the United States, Canada, and part of Mexico

have worked together through NERC to develop voluntary standards that have provided North America with the most reliable energy in the world.

The introduction of restructuring, however, is putting pressure on the voluntary

system. Under regulation, regulators have placed a premium on reliability and utilities were guaranteed to recover reasonable reliability-related expenses. In a competitive environment, however, investor-owned utilities are rewarded for cutting

costs and no one has the authority to ensure that those cost-cutting measures do

not degrade the reliability of the bulk transmission system.

It is necessary for Congress to replace NERC with a new self-regulating industry

organization that has the authority, under FERC oversight, to develop and enforce

mandatory reliability standards.

For that reason, NRECA supports the NERC consensus language that has been

included in several bills introduced in the House and Senate. That language would

require FERC to approve a new North American Electric Reliability Organization

that would have the power to ensure the reliable operation of the interstate bulk

transmission grid. NRECA believes that similar legislation needs to be enacted as

soon as possible.

NRECA opposes a competing proposal that would grant authority over reliability

directly to FERC. The Commission lacks the expertise or the resources to address

reliability on its own. There are questions whether it has been able to handle adequately its existing mandate to regulate wholesale markets. Responsibility for the

reliability of the nation’s grid would strain its existing staff even further. On the

other hand, while stronger enforcement authority is needed, there is no question

that NERC has done an admirable job of setting reliability standards. Congress

should not reject an industry-based model that has worked extremely well for over

20 years.

Mr. BARTON. Well, I don’t know about all that, but it’s certainly

well spoken. You can always tell a former congressman.

Mr. ENGLISH. Well, and someone from Oklahoma, you don’t know

how difficult it was for me to say that, Mr. Chairman.

Mr. BARTON. Well, your team won the football game on Saturday,

so you got the right to come here and pontificate a little bit.

Mr. ENGLISH. Well, thank you very much.

Mr. BARTON. It goes with the territory.

We now want to hear from Mr. David Cook who is general counsel for the North American Electric Reliability Council.

Your statements in the record, and we ask you to summarize in

5 minutes.

STATEMENT OF DAVID N. COOK

Mr. COOK. Good morning, Mr. Chairman, Mr. Boucher and members of the subcommittee.

My name is David Cook. I am general counsel for the North

American Electric Reliability Council (NERC).

43

I appreciate the opportunity to testify this morning on the critical issue of assuring the continued reliability of the North American bulk power system. NERC strongly urges Congress to enact

reliability legislation in this session of Congress. NERC and a

broad coalition of State, consumer and industry representative support legislation that would transform the current set of voluntary

electric system operating guidelines into a set of mandatory transmission system reliability rules, developed and enforced by an industry-led self-regulatory organization with FERC oversight in the

United States. For more than 30 years a voluntary industry based

system for maintaining the reliability of the bulk electric system

has worked very well. But for the reasons outlined in my testimony, voluntary standards will not serve us well for the future.

This past June 14 major organizations wrote to the Congress and

the Administration in support of legislation making the reliability

rules mandatory and authorizing creation of an industry electric reliability organization subject to FERC oversight in the U.S. Such

an organization would be the best position to marshal the technical

expertise and market expertise of the whole industry to develop

rules for running the higher complex interconnected transmission

system. Such an organization would be able to focus on reliability

as its primary mission while the electric industry and electricity

markets continue to evolve and new forms of business organizations come into existence.

An electric reliability organization would also address the international nature of the interconnected grid. That organization with

participation from the U.S., Canadian and Mexican interests could

,subject to regulatory oversight from those countries, develop the

common set of rules necessary to operate the interconnected grid

that spans national borders.

This subcommittee approved one version of the NERC coalition

language when it passed H.R. 2944 in 1999. Last year the Senate

passed the NERC consensus legislative proposal as S. 2071, but hat

bill was not considered in the House.

The President’s National Energy Policy endorses development of

legislation authorizing an industry self-regulatory organization

subject to FERC oversight in the U.S.

I wanted to thank to Mr. Wynn and those who joined him in reintroducing that proposal this year as a H.R. 312. I also want to

acknowledge Mr. Burr and Mr. Sawyer for including the NERC

language as part of their bill, H.R. 2814.

Since the June letter those groups have worked with others to

develop a shorter less detailed version of the reliability legislation.

I have submitted a copy of that revised language with my testimony.

The revised legislation provides for the creation of a self-regulatory organization under FERC oversight of reliability. In addition, it provides FERC with greater flexibility and authority to

oversee the work of the electric reliability organization. It clarifies

the role of the electric reliability organization and regional transmission organizations. And it includes definitions of ‘‘adequacy’’

and ‘‘security’’ to more clearly delineate the scope of that organization’s authority.

44

A number of organizations have announced they will support the

revised version of the legislations, others are still reviewing the

matter.

With respect to the September 21 discussion draft circulated by

Chairman Barton, NERC believes that Title II with the changes

that we have recommended in correspondence included with my

testimony provides a workable basis to move forward on reliability

legislation. NERC stands ready to work with the members of the

subcommittee and their staff as well as others in the industry to

make improvements to the language, but we continue to believe

that creation of an industry electric reliability organization is critical.

The need to change how we deal with reliability is clear. Mr.

Chairman, I was in Colorado last month and heard you say to

those in the industry now is the time to act. I completely agree

with you. The electric industry is undergoing profound changes and

our system of reliability needs to change to keep pace.

The events of September 11 served to underscore the importance

of the effort. As this subcommittee has heard, NERC plays a critical role in the protection of the security of our electric transmission infrastructure. In the future it will be that new electric reliability organization that serves as a point of contact and coordination on this industry-wide security efforts.

Those who would simply give the job of reliability to FERC without authorizing an industry electric reliability organization ignore

this important function currently served by NERC.

NERC urges Congress to adopt legislation authorizing creation of

such an organization for reliability and for security.

Thank you very much. Be happy to answer your questions.

[The prepared statement of David N. Cook follows:]

PREPARED STATEMENT OF DAVID N. COOK, GENERAL COUNSEL, NORTH AMERICAN

ELECTRIC RELIABILITY COUNCIL

Good morning, Mr. Chairman and members of the Subcommittee. My name is

David Cook and I am General Counsel for the North American Electric Reliability

Council (NERC).

Summary

NERC strongly urges Congress to enact reliability legislation in this session of

Congress. NERC and a broad coalition of state, consumer, and industry representatives are supporting legislation that would transform the current set of voluntary

electric system operating guidelines into a set of mandatory transmission system reliability rules, promulgated and enforced by an industry-led reliability organization,

with FERC oversight in the United States. NERC firmly believes that steps must

be taken now to ensure the continued reliability of the electricity transmission system if the Nation is to reap the benefits of competitive electricity markets. The

changes taking place as the electric industry undergoes restructuring are recasting

the long-established relationships that reliably provided electricity to the Nation’s

homes and businesses. Those changes will not jeopardize the reliability of our electric transmission system IF we adapt how we deal with reliability of the bulk power

system to keep pace with the rest of the changes that the electric industry is now

experiencing. NERC believes that the best way to do this is through an independent, industry self-regulatory organization, modeled after the securities industry,

where the Securities and Exchange Commission has oversight of several self-regulatory organizations (the stock exchanges and the National Association of Securities

Dealers).

NERC is a not-for-profit organization formed after the Northeast blackout in 1965

to promote the reliability of the bulk electric systems that serve North America. It

works with all segments of the electric industry as well as consumers and regulators

to ‘‘keep the lights on’’ by developing and encouraging compliance with rules for the

45

reliable operation of these systems. NERC comprises ten Regional Reliability Councils that account for virtually all the electricity supplied in the United States, Canada, and a portion of Baja California Norte, Mexico.

What is Reliability?

Reliability means different things to different people. For the consumer it could

mean, ‘‘Does the light come on when I flip the switch?’’ Or, ‘‘Does a momentary

surge or blip re-boot my computer or cause me to lose a whole production run of

computer chips I was manufacturing?’’ To NERC, reliability means making sure that all the elements of the bulk power

system are operated within equipment and electric system thermal, voltage, and

stability limits so that instability, uncontrolled separation, or cascading failures of

that system will not occur as a result of sudden disturbances such as electric short

circuits or unanticipated failure of system elements. It also means planning, designing, and operating each portion of the bulk power system in a manner that will promote security in interconnected operations, not burden other interconnected systems, and not interfere with the functioning of competitive markets.

NERC sets the standards by which the grid is operated from moment to moment,

as well as the standards for what needs to be taken into account when one plans,

designs, and constructs an integrated system that is capable of being operated securely. The NERC standards do not specify how many generators or transmission

lines to build, or where to build them. They do indicate what tests the future system

must be able to meet to ensure that it is capable of secure operation. NERC’s rules,

which are not enforceable, have generally been followed, but that is starting to

change. As economic and political pressures on electricity suppliers increase, NERC

is seeing an increase in the number and severity of rules violations. Hence, the voluntary approach is no longer adequate for maintaining the reliability of the bulk

power system. Just as the rest of the electric industry is changing, the reliability

infrastructure must change too.

Voluntary Reliability Rules Will Not Work in a More Competitive Electric Industry

NERC’s formation in 1968 was the electric industry’s response to legislation that

had been introduced in the Congress following the 1965 blackout in the Northeast.

That legislation would have given the then Federal Power Commission (FPC) a central role in the reliability of the bulk electric system. Instead of adopting that legislation, Congress opted for an industry-led effort. For more than thirty years, this

industry-based voluntary system has worked very well and we have had an extremely reliable electric system. But the reliability rules or standards have no enforcement mechanism. Peer pressure has been the only means available to achieving

compliance.

As good as that system has been, voluntary standards will not suffice in the future. Here is why:

• The grid is now being used in ways for which it was not designed.

• There has been a quantum leap in the number of hourly transactions, and in the

complexity of those transactions.

• Transmission providers and other industry participants that formerly cooperated

willingly are now competitors.

• Rate mechanisms that in the past permitted utilities to recover the costs of operating systems reliably are no longer in place, or are inadequate given increased

risks and uncertainties.

• The single, vertically integrated utility that formerly performed all reliability

functions for an area is being disaggregated, which means that reliability responsibilities are being divided among many participants.

• Some entities appear to be deriving economic benefit or gaining competitive advantage from bending or violating the reliability rules.

• Construction of additional transmission capacity has not kept pace with either the

growth in demand or the construction of new generating capacity, meaning the

existing grid is being used much more aggressively.

A number of factors have contributed to our present circumstance. Demand has

been steadily increasing over the past decade and is expected to increase. This past

summer several utilities in the Eastern Interconnection experienced new all-time

peak demands on their systems. The good news is that merchant generators are

now building or planning to build hundreds of new plants across the country to

meet this increased demand. The bad news is that the same is not true for transmission.

Ten years ago North America had a little less than 200,000 circuit-miles of high

voltage transmission lines. Today we have about 200,000 circuit-miles of lines. Ten

years from now we are projecting that we will have just a little over 200,000 circuitVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00049 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
46

miles of high voltage transmission lines. All of these new generators will need to

access the transmission grid to get their power to where it is needed. For the most

part, however, the transmission dollars that are being spent today are just to connect new generation to the grid; they are not going to build major new power lines

that will strengthen the grid’s ability to move large blocks of electricity from one

part of the country to another, or in some instances, such as Texas, from one part

of a State to another. That lack of additional transmission capacity means that we

will increasingly experience limits on our ability to move power, and that commercial transactions that could displace higher priced generation with lower priced generation will not occur.

Moreover, the existing grid is being pushed harder and is being used in ways for

which it was not designed. Historically, each utility built its generating stations

close to load centers, which were largely cities. As the cities grew, the electric systems grew with them, spreading outward from the center. The weakest part of the

electric grid is generally where one system abuts another. Initially, utilities installed connections between adjacent systems for emergency purposes and to share

generating reserves to keep costs down. Gradually those interconnections were

strengthened so that adjoining utilities could buy and sell electricity when one had

lower cost generation available than did the other. But these systems were not designed to move large blocks of power from one part of the country to another, across

multiple systems, as is happening today. The volume and complexity of transactions

on the grid have grown enormously since the advent of open access transmission.

Electric industry restructuring adds to the challenge. In the past, vertically integrated utilities with monopoly franchise service territories had complete responsibility for all aspects of their electric systems. They planned and built their transmission systems, ensured that sufficient generation was constructed, and operated

and maintained their transmission and distribution systems, all to serve customers

within designated service areas. With restructuring, there may no longer be a designated group of consumers for which to plan service. Instead, responsibilities to

construct and maintain generation, transmission, and distribution are being divided

among multiple entities. In some cases, those responsibilities may be falling between the cracks. Regional Transmission Organizations (RTOs) may provide a

means to reintegrate some of these functions. But the RTO proposals that have been

filed to date vary considerably in the extent to which the RTO will have the authority to plan and expand the transmission system, not only to connect new generation,

but also to meet broader needs of wide-area reliability and commerce.

The result of all this is that the transmission grid is being increasingly stressed.

NERC is seeing more congestion on the grid, for more hours of the day. NERC is

also seeing increasing violations of its reliability rules. If these trends continue, we

risk the increased likelihood of grid failure.

Legislation is Needed to Ensure Bulk Power System Reliability in a More Competitive Electricity Market

We need legislation to change from a system of voluntary transmission system reliability rules to one that has an industry-led organization promulgating and enforcing mandatory rules, backed by FERC in the United States and by the appropriate

regulators in Canada and Mexico. In August 1997, NERC convened a panel of outside experts to recommend the best way to ensure the continued reliability of North

America’s interconnected bulk electric systems in a competitive and restructured

electric industry. On a parallel track, in the aftermath of two major system outages

that blacked out significant portions of the West in July and August 1996, the Secretary of Energy convened a task force on reliability, chaired by former Congressman Phil Sharp. Both groups came to the same conclusion: The current system of

voluntary guidelines should be transformed into a system of mandatory, enforceable

reliability rules, AND the best way to accomplish that was to create an independent

industry self-regulatory organization, patterned after the self-regulatory organizations in the securities industry, with oversight in the United States by the Federal

Energy Regulatory Commission.

On June 18, 2001, NERC and a broad coalition of state, consumer, and industry

representatives (the American Public Power Association, the Canadian Electricity

Association, the Edison Electric Institute, Institute for Electrical and Electronics

Engineers—USA, the Large Public Power Council, the National Association of Regulatory Utility Commissioners, the National Association of State Energy Officials, the

National Association of State Utility Consumer Advocates, the National Electrical

Manufacturers’ Association, the National Rural Electric Cooperative Association, the

Northwest Regional Transmission Association, the Transmission Access Policy

Study Group, and the Western Interconnection Coordination Forum) sent a letter

to each member of the House Energy and Commerce Committee in support of legisVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00050 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
47

lation to authorize creation of such an industry self-regulatory organization to develop and enforce reliability rules. That legislation would accomplish the following

goals:

• Reliability rules would be mandatory and enforceable.

• Rules would apply to all operators and users of the bulk power system in North

America.

• Rules would be fairly developed and fairly applied by an independent, industry

self-regulatory organization drawing on the technical expertise of industry

stakeholders.

• FERC would oversee that process within the United States.

• Approach would respect the international character of the interconnected North

American electric transmission system.

• Regional entities would have a significant role in implementing and enforcing

compliance with these reliability standards, with delegated authority to develop

appropriate regional reliability standards.

This Subcommittee approved one version of the NERC legislative language when

it passed H.R. 2944 in 1999. Last year the Senate passed the NERC consensus legislative proposal as S. 2071, but that bill was not considered in the House. This year,

Mr. Wynn and a number of other members have reintroduced the NERC legislative

proposal (H.R. 312). In addition, the President’s National Energy Policy endorses development of legislation authorizing an industry self-regulatory organization subject

to FERC oversight within the U.S.

Since the June letter, the organizations supporting the NERC reliability legislation have continued to work with representatives from across the electric industry,

as well as state and consumer interests, in an effort to strengthen and broaden support for the legislation. One of the major criticisms of the earlier legislative language has been that the proposal is longer and more detailed than may be appropriate for a legislative enactment. To address that concern, as well as to respond

to other concerns that have been raised over the recent months, we have developed

revised legislative language that is shorter, less detailed, and more flexible to accommodate whatever structural changes emerge in the industry. I have attached a

copy of that language to my testimony.

The revised legislation preserves from the earlier version the essential features

for authorizing creation of a self-regulatory electric reliability organization. In addition, the revised legislation:

• provides FERC with additional flexibility and authority in shaping the development of the electric reliability organization and in overseeing its ongoing standards development and enforcement activities;

• clarifies the respective roles of the electric reliability organization and evolving regional transmission organizations; and

• includes definitions of ‘‘adequacy’’ and ‘‘security,’’ the two components of reliability.

Together with the state savings clause from the earlier legislation, these new definitions place bounds on the scope of the electric reliability organization’s standardsetting authority.

Under this legislation, FERC can assure harmonization of reliability standards

developed by the electric reliability organization and market rules in two ways.

First, FERC must approve the process by which reliability rules are developed. The

legislation requires that process to be open, balanced, not dominated by one particular sector, and consistent with the requirements of due process. FERC can assure that market interests are adequately represented in that process. Second,

FERC must approve the reliability rules before they take effect. If, despite the balanced process, a proposed reliability rule intrudes too far into commercial or market

activities, FERC can reject the proposed rule and direct the electric reliability organization to make appropriate changes.

Changes to this revised reliability legislation were made just before the horrific

events of September 11, and those events have interrupted efforts by those who

have supported the NERC legislation in the past, as well as others, to complete

their review of this language. In light of the Subcommittee’s hearing schedule and

the Chairman’s stated desire to move forward on electric restructuring legislation,

including reliability, NERC believes it appropriate to submit the proposed language

to the Subcommittee now. NERC as well as all those that supported the earlier language believe this revised legislative proposal to be a considerable improvement

over the earlier language, but it maintains all the essential features of that earlier

language. Support for this proposal is not unanimous, and doubtless the language

can be improved further. NERC is prepared to work with Members of this SubVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00051 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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committee and Subcommittee staff, as well as with others from the industry, to

make whatever changes are necessary.

In addition, on September 21 Chairman Barton released a discussion draft of electric restructuring legislation. NERC commented on Title III, the reliability provisions of that draft, in a letter to Chairman Barton on October 2. A copy of that letter is attached to my testimony. NERC believes that Title III of the September 21

discussion draft, with the changes recommended in our October 2 letter, would form

a workable basis for moving forward with reliability legislation. NERC stands ready

to work with Members of this Subcommittee and Subcommittee staff, as well as

with others in the industry, to develop appropriate language. What is critical is that

we act now to update how we deal with reliability, even as the rest of the electric

industry is undergoing profound changes. The horrific events of September 11 only

serve to underscore the importance of that effort.

An Industry Self-Regulatory Organization Is the Best Approach for Developing and

Enforcing Reliability Standards

Having an industry self-regulatory organization develop and enforce reliability

rules under government oversight takes advantage of the huge pool of technical expertise that the industry has been able to bring to bear on this subject over the last

30 plus years. FERC does not now possess and is not likely to achieve anything approaching the level of technical sophistication inherent in the NERC standard-setting process, which involves dozens of committees and working groups and thousands of professionals representing all segments of the electric industry. Having

FERC itself set the reliability standards through its rulemaking proceedings, even

if based on advice from outside organizations, converts matters that ought to be resolved by those with technical engineering expertise and commercial markets expertise into matters that are the province of lawyers. These complex rules need to be

worked out together, using a fair and open process, in a collaborative fashion by all

segments of the industry.

The electric industry is in a great state of flux, as regional transmission organizations are forming, reforming, and consolidating. The path is not yet clear about how

many RTOs there will be, or how extensive will be the participation in those RTOs,

or when they will all come into existence. With all the uncertainty as to who will

ultimately operate and plan the interconnected transmission system, it is more important than ever that an industry-led self-regulatory organization be created to establish and enforce reliability standards applicable to the entire North American

grid, regardless of who owns or manages it. The self-regulatory organization can

focus on reliability as its primary mission, even while new market structures and

new RTOs are being formed. Because FERC will provide oversight of the self-regulatory organization in the U.S., FERC can ensure that the self-regulatory organization’s actions and FERC’s evolving RTO policies are closely coordinated.

An industry self-regulatory organization also addresses the international character of the interconnected grid. There is strong Canadian participation within

NERC now, and that is expected to continue with the new organization. Having reliability rules developed and enforced by a private organization in which varied interests from both countries participate, with oversight in the United States by FERC

and with oversight by provincial regulators in Canada, is a practical and effective

way to address the common set of rules needed for the international grid. Otherwise, U.S. regulators would be dictating the rules that Canadian interests must follow—a prospect that would be unacceptable to Canadian industry and government

alike. Or regulators on either side of the border might decide to set their own rules,

which would be a recipe for chaos. There are also efforts under way to interconnect

more fully the electric systems in Mexico with those in the United States, primarily

to expand electricity trade between the two countries. Expanded international electricity trade is a key element of the President’s National Energy Policy. With that

increased trade, the international nature of the self-regulatory organization will

take on even more importance, further underscoring the necessity of having an industry self-regulatory organization, rather than FERC, set and enforce compliance

with grid reliability standards.

Conclusion

NERC commends the Subcommittee for attending to the critical issue of ensuring

the reliability of the interconnected bulk power system as the electric industry undergoes restructuring. A new electric reliability oversight system is needed now. The

continued reliability of North America’s high-voltage electricity grid, and the security of the consumers whose electricity supplies depend on that, is at stake. An industry self-regulatory system is superior to a system of direct government regulation for setting and enforcing compliance with grid reliability rules. The revised

49

NERC Coalition legislative language presents the best approach for achieving that

goal. It is also the approach that has had the most consistent, widespread support

among industry, state, and consumer interests. Title III of the September 21 discussion draft, with the changes we have recommended, would also provide a workable

basis for moving forward. It would then contain the essential features of the NERC

approach. The reliability of North America’s interconnected transmission grid need

not be compromised by changes taking place in the industry, provided reliability legislation is enacted now.

Mr. BARTON. Thank you, Mr. Cook.

We now want to hear from Mr. Phillip Harris, who is President

and CEO of the PJM Interconnection in the northeast or the Atlantic Mid-Atlantic.

Your testimony is in the record and we ask that you summarize

in 5 minutes, please.

STATEMENT OF PHILLIP G. HARRIS

Mr. HARRIS. Thank you, Mr. Chairman.

Someone once said that in addressing complex public policy that

the main thing was to keep the main thing the main thing. And

the main thing is about customers. This is all about ensuring customers of the benefit of competitive price generation. That was the

intent of the amendments to the Federal Power Act in 1992 and

the fact that certain missteps have occurred in implementation in

certain areas of the country should not overshadow that in the midAtlantic region, a region that has now grown to serve seven States

plus the District of Columbia, competition has worked. This represents about 10 percent of the electric capacity in this Nation.

What we have found is that FERC already has the authorities

they need for the most part under the Federal Power Act. Encouragement of this Congress should be to encourage FERC to get

through the transition. In our area, we’ve got most of the transition

and it’s working, and the numbers are somewhat staggering. But

from that practical experience for 10 percent of the Nation’s electricity supply, we have certain facts that we think are an indicator

of how to move through the transition sooner.

We know there are those who suggest complex additions to law

to create new organizations with exclusive authorities. But we believe this is a step background.

To my testimony I’ve attached a graph that really tries to demonstrate that electricity is a giant ecological system. It touches the

very fabric of all our lives; from the fuel that is used to the ultimate choice by the consumer. We simply can’t carve out a transmission only reliability standard without realizing the effects on

everything else.

We have also discovered that there are no such things anymore

as pure reliability standards. When you truly have competition that

delivers value to customers, then ultimately the economics provide

the value. Competition does work and competition can increase the

liability. And with the technology that is rapidly advancing today,

we’ve been able to find solutions to what was heretofore seen as

only reliability problems. And these technological solutions do

work.

We’ve also seen the emergence of new organizations such as the

Gas Industry Standards Board that’s been remarkable in what

they’ve accomplished over the past few years. They have interVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00053 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
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national cooperation. They are voluntarily developing standards.

They’re receiving accreditation from the American National Standards Institute as a standard setting body and then their standards

go to FERC, which are approved as a model that should also be

looked at.

And also we have found in the past 5 years of working with competition that our compliance with NERC standards has improved,

not deteriorated.

There are also those who seem to think that the competition is

simply about transmission. It is not. It is about providing value to

customers through competitive price generation. This means that

you need to have regional planning protocols. FERC Order 2000

stipulates that all RTOs will be involved with regional planning.

From 1994 to 1996 we developed a regional planning protocol for

the mid-Atlantic area. This was a venture that involved the environmental community, all the States, deciding agencies in our

States. Our regional planning protocol has resulted in over $700

million of transmission construction that is currently underway.

Our current plans see no need for anything major that would be

an impediment over the next 5 or 10 year horizon. The problem is

getting to regional planning and get it into effect throughout the

Nation, that then begins to solve the problem of siting and the coordination that’s necessary to move forward.

We have also found that keeping the emphases on the consumer

creates value. Over the 5 years we have seen the customer prices

in PJM go to less than $100 99 percent of the time. Our competition has shown that 71 percent of the time the price has been less

than $30.

We have 7,000 megawatts of new generation under construction.

We have 40,000 megawatts from 140 different companies under different stages of planning for generation construction. This is competition that works and competition that FERC can put into place

with their current authorities.

We think the evidence for competition is viable and the evidence

is real. We think there are probably three simple things that we

would suggest to you as you look forward to your legislative activities.

One, you should send a clear, simple and flexible authority of

FERC to address all the reliability issues.

We think you should encourage and support the FERC to get

through the transition. The problem is the transition. We get

through the transition that will enable regional planning and competition to provide value to customers sooner rather than later is

the key to success.

And third, ensure that FERC has the resources to be effective in

enforcement actions in a 21st century information economy.

Thank you, Mr. Chairman.

[The prepared statement of Phillip G. Harris follows:]

PREPARED STATEMENT OF PHILLIP G. HARRIS, PRESIDENT AND CEO, PJM

INTERCONNECTION, L.L.C.

‘‘The future requires a higher sophistication in acknowledging and dealing with differences...’’

Peter F. Drucker

51

This insightful quotation from Peter Drucker sums up the challenge for all of us

in the electric industry sector. As policymakers and as members of the industry, we

must achieve 21st century information solutions which ensure that our policies and

institutions match the efficiency and pace of this speed of light product known as

electricity.

My name is Phillip Harris. I am the President and CEO of PJM Interconnection,

the country’s only fully functioning FERC-approved Regional Transmission Organization (RTO). We operate the largest competitive electricity market in the world,

serving over 8% of the U.S. population. We also ensure the reliability of the electric

power grid in a five-soon to be seven-state region including Washington D.C. (and

this Capitol Building) as well as all or parts of New Jersey, Pennsylvania, Delaware,

Maryland, Virginia, West Virginia and Ohio. We are honored to have been designated as the platform for use in FERC’s planned Northeast RTO (NE RTO). As

evidenced on the attached chart, the proposed NE RTO will encompass approximately 183,000 MW and is larger than the entire western grid of the United States

and western Canada.

The critical test of any idea is the test of use. In the PJM region, restructuring

of this industry has worked to deliver real value to the 24 million inhabitants therein. During the year 2000, PJM spot market prices were below $100/MWH 99% of

the time and approximately 71% of the time our prices were less than $30/MWH.

New investment in this capital-intensive industry is flocking to our region. Over 140

new generating projects have been announced, which would add over 40,000 MW

of generation to our region, as well as over $700 million in new and upgraded transmission investment. We were recently designated by Business Week as one of the

top 50 businesses in the United States successfully integrating Internet technologies—the only utility to receive such designation. More than 70 nations have

sent delegates to PJM to learn about its market model and the operation of the grid

in the mid-Atlantic region. The Pennsylvania retail restructuring plan has been

widely recognized as the most successful in the nation.

With this background, I wish to address the fundamental points the Subcommittee raised in its October 5 letter.

I. THE CURRENT STATUS AND FUTURE OUTLOOK FOR THIS INDUSTRY

Congress decreed competition in bulk power electric markets as the law of the

land back in 1992. Although nine years later this vision has yet to be realized in

much of this country, in the PJM region, with the support of our States and our

market participants we have been able to meet Congress’ expectations. The key to

our success has really been quite simple—we have made our mission the efficient

assimilation, use and widespread dissemination of information that makes the markets work.

As the attached chart indicates, despite the product moving at the speed of light,

this industry has traditionally been operated through various ‘‘silos’’ of data and operation with little in the way of networking and integration. There were separate

silos of data associated with the acquisition and delivery of fuel, the generation of

electricity, its transmission and ultimately its distribution. Each of these silos operated as autonomous islands with little sharing of data. For example, even though

the actions of a residential customer in flipping on a light switch had a speed-oflight effect back at the generating station, due to the lack of effective information

flows, the customers receive bills for usage weeks later with no ability to evaluate,

in real time, the economic effect of their actions. So too the transmission system was

sized and built years earlier to deliver power from generating stations to load centers at peak times with little thought given to siting such lines at places that would

relieve critical congestion on that system. In short, even though the physics of the

product was sending us key information in real time, we didn’t adequately listen

to those signals and instead built infrastructure in an inefficient manner reflecting

that failure.

By the same token, we have created silos in the form of institutions which govern

the delivery of this product. We have the NERC looking at reliability standards, the

FERC looking at markets, the DOE looking at infrastructure and the state PUCs

looking at retail issues. Some of this can be expected from the natural evolution of

our laws over time. However, just at the time we should be looking to network these

different functions and break down these walls, NERC urges you to create yet a new

silo—an industry organization, with funding authority granted by Congress, which

would dictate standards on the physical operation of only the bulk transmission system without regard as to whether those standards properly integrate with the functioning of the marketplace—a role beyond its competence. You can’t pigeonhole reliability standards and separate it from the marketplace and retail electric programs

52

any more than you can design a pen cap without also working in the design of the

pen. There is no ‘‘pure’’ reliability issue separate from economics. For example, with

an effective demand response system, customers though the marketplace will be voting with their dollars on the level of reliability of service they seek. They will be

individually deciding whether they wish to incur a temporary curtailment of service

and should receive economic compensation for so doing. No ‘‘core’’ national reliability

standard can take the place of empowering customers to make economic decisions

in their best interest. For this reason, we should avoid creating a new silo called

‘‘reliability.’’ However, to date RTO development in the country has also involved the creation

of silos. In the northeast we have three ISOs, each with their own rules despite the

fact that the New York, PJM and New England markets (as well as the ECAR market) are essentially one large market crying out for a uniform set of rules and operations. We have proposed solutions in the FERC mediation process that will enable

those markets to rapidly network into one while still maintaining essential local

practices and enhancing the security and operation of the northeast grid. We need

to embrace these solutions rather than slow them down.

It is for those reasons, as you wrestle with provisions dealing with reliability,

RTOs, siting, etc., we urge you not to create new ‘‘silos’’ of institutions that look at

parts, rather than the networked whole. In the PJM region, we have worked to

avoid such silos, to the degree practicable:

—The PJM States work directly with us as the RTO, rather than having disparate

sets of rules that change at every border. Our State PUCs deserve much credit

for their leadership in making this happen.

—We integrate reliability standards and the marketplace on a daily basis. We have

networked our regional reliability organization very closely with the market

participants and the states because the needs of the marketplace and reliability

are interdependent.

—We have come up with new solutions in our PJM West marketplace, to network

the needs for delivery of capacity with a vibrant marketplace while retaining

their local reliability standards.

Through the intended creation of four large RTOs in the country, the new FERC

has set forth a vision which can work to network all of these important functions

and, for the first time, match the borders of natural markets in the country. This

is a wise and forward-thinking policy that deserves all of our support. We believe

FERC needs all of our support to make the right decisions to put these large RTOs

in place rapidly and ensure participation therein, in order to deliver real and measurable results to customers.

II. HOW CONGRESS CAN HELP

What can this Congress do to further these efforts? We would recommend the following:

1. Reliability Issues—Congress should adopt simplified reliability legislation assigning the ultimate responsibility for devising and enforcing mandatory reliability

standards to the FERC. As noted before, the pace of change and the speed of light

of this product mandate that we not ‘‘hard wire’’ in new private institutions with

their self-regulating ability to, in effect, tax the public. Rather, the FERC should

have the flexibility to assign all or parts of these tasks to different entities as it

sees fit. Flexibility and simplicity should be the hallmark of reliability legislation.

We have proposed legislation that would accomplish this and stand ready to work

with you and others to refine any proposed reliability provisions.

2. Siting—Congress should provide deference to decisions reached through balanced regional planning processes that are open and which do not favor transmission solutions over generation solutions or one technology over another. State

siting processes should be part of the planning process undertaken by the RTO and

State siting decisions arrived at through such open balanced regional processes

should be afforded Federal and State deference. By embracing and enhancing open

regional planning processes that involve the states, Congress would avoid the Hobson’s Choice of favoring federalization of siting or continuing individual state decisions that could conflict with one another.

3. More Standardization of Market Design—FERC needs to more clearly delineate

the exact market functions to be performed by emerging RTOs and ensure a certain

degree of standardization of design, so as to promote the free flow of information

to enable commerce in this speed of light product. We remain concerned that while

we have the ISOs involved in facilitating the markets in the northeast, in much of

the rest of the country the developing RTOs seem to want to remain passive grid

operators with no obligation to ensure a vibrant marketplace.

53

As I indicated at the beginning the RTOs maintain critical data in real time on

each aspect of the production and delivery of electricity. Neither retail competition

nor your direction for vibrant wholesale competition back in 1992 will work without

a clear role for the RTO to assimilate and distribute that critical information to the

marketplace in real time. After all, the New York Stock Exchange would not work

very well without the publication of prices. So too the RTOs must have a role in

facilitating the marketplace by timely assimilating and delivering that critical data

to serve as a ‘‘platform’’ on which competition can flourish.

Although we must allow for a certain degree of regional flexibility, the FERC’s

prior approach of letting a thousand flowers bloom has not worked quickly enough

to keep up with the needs of this speed-of-light product. We are heartened by the

creation of an Energy Industry Standards Board using the successful Gas Industry

Standards Board model. Their model presumes a linkage between wholesale gas, retail gas, wholesale electric and retail electricity services. A model much more functional for networking the needs of the 21st Century. By the same token, we believe

the new FERC’s initiatives outlined so far are worthy of this Congress’ full support.

This is not the time to ‘‘dumb down’’ what is otherwise needed by these still immature markets.

4. FERC Resources—Congress should ensure that FERC is fully staffed and has

the resources needed to appropriately monitor the markets and regulate in those

areas where the market is not properly functioning. This is not the time to pull the

rug out of FERC’s efforts to deliver on the promise of the Energy Policy Act of 1992

and Order 2000.

5. Enhancing Grid Security through a Hierarchical Network Model—The events

of September 11 have made us painfully aware of the need to keep security of infrastructure foremost in our minds. Unfortunately, those that presume ‘‘silos’’ proffer

the risk inherent in them. Whereas the value of networked organizations provide

resiliency, security and connectivity to meet the heightened security challenges of

this century.

The creation of large RTOs under the Regional Network Model that PJM proposed

for the Northeast will significantly enhance the security and continuity of the national grid. Under the PJM Regional Network Model approach, data and responsibility will be decentralized among multiple paths while, through a hierarchical design, the benefits of integration and uniformity are realized. This is far more secure

than the system that presently exists, wherein we have individual ‘‘silos’’ of security

responsibility among each of the individual utilities in much of the country. If models such as those we proposed are accepted by the FERC, we can go a long way to

ensuring the benefits of a networked model while strengthening those decentralized

features necessary to resist terrorist or cyber attack. In short, the NE RTO, if designed correctly, will enhance the security and reliability of the northeast grid from

what presently exists today.

6. Role of Technology—The nation is moving rapidly to networked information

through advanced technology. FERC should have these advanced tools and the staff

resources to use them in order to identify and be responsive to market dysfunctions

in a timely manner. And even more importantly, in writing laws in the electricity

area, Congress should provide broad authority to the FERC and other government

institutions rather than codifying constraints which will tie the agency’s hands. New

technology solutions that we have not even dreamed of will solve problems that

seem intractable today. But if we hard-wire in solutions and institutions, we will

unknowingly stifle that very technology we so much want to succeed.

Our message is simple: with the wise use of information and with institutions

such as the FERC having broad and flexible authority and a clear mission to promote competitive markets, our laws and institutions can begin to catch up and operate nearer to the speed and efficiency of this product known as electricity. At PJM,

we have used the assimilation and ubiquitous delivery of information to empower

our customers to meet their needs. We believe that this Congress should embrace

similar 21st century solutions. We at PJM look forward to working with you to

achieve this important goal.

Mr. BARTON. Thank you, Mr. Harris.

We now want to hear from Mr. James Steffes, who is Vice President of Governmental Affairs for ENRON Corporation. He’s here on

behalf of the Electric Power Supply Association.

Your statement’s in the record in its entirety. We would ask that

you summarize it in 5 minutes.

54

STATEMENT OF JAMES D. STEFFES

Mr. STEFFES. Thank you, Mr. Chairman.

My name is Jim Steffes. I’m pleased to be here today representing the member companies of the Electric Power Supply Association (EPSA), of which I presently serve as Chairman of the

Regulatory Affairs Committee.

I would first like to discuss reliability. It’s a fair statement that

just about everyone within the industry agrees on the need to implement mandatory reliability standards. The old system of voluntary compliance no longer ensures a reliable network. It is also

a fair statement that there is not consensus on how best to develop

and enforce these mandatory standards.

EPSA recommends that Congress provide FERC with a straight

forward delegation of authority to implement and enforce mandatory reliability standards. This authority, coupled with FERC’s current economic regulation of wholesale electricity markets, will best

provide for reliable and low cost electricity service for American

consumers.

We do not think that enacting reliability language that tries to

separate commercial matters from reliability matters is the right

approach. It is critical that reliability legislation be aligned with

FERC’s approach to nondiscriminatory open access transmission

and most importantly, to appropriate size RTOs.

EPSA is also troubled by proposed language that would hard

wire significant issues such as mandating the role of regional reliability entities. These issues are better left to the flexibility of the

regulatory process. FERC should evaluate the merits of this and

other issues in a rulemaking proceeding. It is simply unwise to

statutorily mandate the authority of regional reliability entities.

We are equally troubled by any limit on FERC’s ability to seek

necessary reliability rule changes on its own motion. Our industry

continues to change at a rapid pace. Unfortunately, if we leave reliability rule changes in the hands of a self-regulating organization,

it is highly likely that we will never reach consensus on the most

pressing matters. A good example is the question over the independence of security coordinators. This issue has been discussed for

many years inside NERC, but no consensus has reached the NERC

Board of Trustees. I would submit that given the nature of the

issue, none will.

The latest NERC legislative proposal still contains procedural

mechanisms that limit, rather than enhance, FERC’s role on moving forward with reliability matters.

EPSA respectfully recommends that Congress direct FERC to establish and enforce mandatory reliability standards. The approach

we support is based on the traditional model that Congress normally follows: Establish a general a policy and direct the appropriate agency, FERC, to carry it out. This is not to say that we disagree with an industry led standard setting organization. We believe that the industry has the knowledge and technical skills to

continue to staff this work. We simply want to make it clear that

FERC is in charge.

Let me conclude on this topic by reiterating the central message.

Trying to divorce commercial matters from reliability matters

makes no sense in a competitive electricity market. Too many subVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00058 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
55

jects. In fact, I would argue all subjects are both reliability and

commercial in nature.

In sum, the best way to strengthen reliability and establish robust competitive markets is to leave FERC with the discretion to

make appropriate changes to a mandatory reliability regime as

changes in the industry require.

Let me end by making two points on siting and incentive rates.

First, while physical improvements in the grid may be necessary,

FERC and Congress must first focus on getting the rules of access

right. Implementing right sized and well functioning RTOs and ensuring that all users take transmission service in a nondiscriminatory manner will properly define where more transmission is

needed.

Second, while EPSA has no hostility toward the idea of incentive

rates, we truly wonder if any additional language is needed. FERC

clearly has authority to be flexible in setting an allowable rate of

return.

In conclusion, Mr. Chairman, EPSA wishes to thank you and the

subcommittee for this opportunity to discuss our views on these important issues. We look forward to continuing to work with you and

your colleagues as you develop electricity legislation in the weeks

to come.

Thank you.

[The prepared statement of James D. Steffes follows:]

PREPARED STATEMENT OF JAMES D. STEFFES, VICE PRESIDENT, GOVERNMENT

AFFAIRS, ENRON CORP. ON BEHALF OF THE ELECTRIC POWER SUPPLY ASSOCIATION

Mr. Chairman and members of the Subcommittee, my name is Jim Steffes. I am

a Vice President, Government Affairs for Enron Corp. based in Houston, Texas,

where my responsibilities center on regulatory policy including the topics you are

considering in this hearing. Enron is one of the world’s leading energy, commodities

and services companies. Enron markets electricity and natural gas, delivers energy

and other physical commodities, and provides financial and risk management services to customers around the world.

I am pleased to be here today representing Enron and the member companies of

the Electric Power Supply Association (EPSA), of which I presently serve as chairman of the Regulatory Affairs Committee. EPSA is the national trade association

representing competitive power suppliers, including independent power producers,

merchant generators and power marketers. EPSA members provide reliable, competitively priced electricity from environmentally responsible facilities in U.S. and

global power markets. On behalf of the competitive power industry, I thank you for

this opportunity to address reliability, siting and transmission pricing incentives, as

you consider electricity issues.

RELIABILITY

Mr. Chairman, regarding the fundamental subject of the reliability of the bulkpower transmission system, there is general agreement on the need to replace today’s voluntary standards with mandatory standards that apply to all system users.

However, there is not a consensus on how best to develop and enforce mandatory

standards. It is critical that reliability legislation be consistent with the Federal Energy Regulatory Commission’s (FERC’s) approach to non-discriminatory, open access

transmission, including large Regional Transmission Organizations (RTOs), if we

are to bring the benefits of competition to consumers.

Congress faces an important choice between two alternative legislative approaches

to achieving mandatory reliability standards. Under the first approach, Congress

could enact a lengthy electric reliability title sponsored by the North American Electric Reliability Council (NERC) that entombs numerous details in statute that are

normally left to the flexibility of the regulatory process. Under the second approach,

Congress could instead place mandatory reliability standards squarely under

FERC’s jurisdiction and direct the agency to promptly conduct a rulemaking to esVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00059 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
56

tablish an efficient standards-setting process and an effective enforcement mechanism. We strongly favor the latter approach for the following reasons.

NERC and those in its self-described ‘‘consensus group’’ continue to advocate what

we and others regard as an unworkable regime that seeks to draw a false line between reliability and commercial matters. The NERC proposal would hand over ‘‘reliability issues’’ to a newly created ‘‘self-regulating organization.’’ The problem with

this strategy is that too many subjects are not purely either reliability or commercial in nature; in fact they are inseparable. For example, scheduling of specific

power transactions over a transmission system is a commercial matter with reliability implications. Because FERC is squarely responsible for commercial practices

in the electric industry, NERC’s reliability approach will undermine FERC’s responsibilities under the Federal Power Act.

Given the importance Enron and other EPSA members attach to reliability, we

participated in extensive discussions with NERC and others over the past several

years to attempt to resolve our differences. While that process did not produce an

agreement, we commend the extensive efforts that produced several legislative proposals, including the version NERC released last month. However, while the text

of NERC’s latest proposal is shorter, it is still needlessly lengthy and cumbersome

because it seeks to tackle matters best left to FERC.

Unfortunately, the latest NERC proposal is still laden with procedural mechanisms and delegations of authority that limit, rather than enhance, FERC’s role on

reliability matters. It is clear to us from participating in the NERC discussions that

those who endorse its approach intentionally seek to limit FERC’s authority over

reliability in the name of enhancing reliability. For example, the NERC legislation

proposes to create a new ‘‘self-regulating organization’’ that is in many respects

independent from FERC. While there is certainly a key role for industry input on

reliability standards, the ‘‘self regulating organization’’ as NERC proposes it would

be too removed from FERC’s general regulatory responsibility over wholesale power

markets.

Similarly, while it may make sense for FERC to defer to specific regional entities

or approve regional variances from otherwise uniform reliability rules, FERC should

evaluate the merits of doing so on a case-by-case basis. It is simply unwise, as the

NERC legislation proposes, to statutorily mandate across-the-board regional reliability entities and regional rules variances. If those seeking approval of such entities can make a strong case in a particular instance, then they should make that

case to FERC for its determination based on a factual record. FERC should not be

forced to accept those entities or variances by force of federal law.

The approach we support is based on the traditional model that Congress normally follows of setting a general policy and directing the appropriate regulatory

agency to carry it out, subject to congressional oversight. With reliability, we respectfully recommend that Congress direct FERC to establish mandatory reliability

standards. After receiving public comments, FERC should determine the appropriate role of an industry organization to recommend standards and when to permit

regional variances, among other details. Nothing is gained by giving regulators a

responsibility as important as keeping the lights on and then tying their hands.

In sum, the agreed upon interdependent goals of strengthening reliability and establishing robust competitive markets can best be achieved by leaving FERC with

the discretion to make appropriate changes to a mandatory reliability regime as

changes in the bulk power system require. Both the Bush Administration and Senate Energy Chairman Bingaman appear headed in a direction on reliability consistent with our views.

SITING

The transmission grid is the backbone of the wholesale power market. Enron and

EPSA have repeatedly argued in favor of regulatory reform that provides consistent,

non-discriminatory access to the grid.

Beyond improved rules regarding access, we support efforts to enhance the interstate grid. The siting of new or expanded transmission facilities is critical to meeting the needs of power consumers. As you know, siting issues are presently handled

at the state or local level. While this may have made sense at some time in the past,

these policies need to be re-examined to allow for a reliable and low cost system.

The Subcommittee is well aware of ‘‘Path 15’’ in California. This transmission bottleneck has existed for many years, in spite of a well-documented need for improvements. Last winter, the impact of poor siting policies was felt by thousands of businesses and families in northern California when this bottleneck prevented available

surplus power from southern California to reach the electricity-starved markets in

the north. Path 15 is not an isolated example.

57

Members of Congress and the Administration have proposed new policies that

would make the siting process of interstate transmission facilities reflect interstate

priorities. EPSA strongly endorses these reforms as necessary and appropriate. It

will continue to be important to consider carefully the demands of the citizens in

the towns and states where new transmission facilities are built. However, the

siting process must also reflect regional and national priorities. Whether Congress

adopts a new policy patterned on the successful program that allows new interstate

natural gas pipelines to be built, or crafts a new approach that starts at the state

and regional level, but uses a federal siting ‘‘backstop,’’ the time has come for new

ideas and a new approach.

TRANSMISSION INCENTIVES

The need for reform of the siting process is often coupled with a call for new financial incentives for transmission. In general, Enron and EPSA have no objection

to allowing a higher return on the development of critically needed transmission facilities. In at least one instance, EPSA has made a direct plea to FERC to raise the

rate-of-return for transmission facilities. However, we have three caveats with regards to any policy that would expand or enhance financial incentives:

First, FERC clearly has authority to be flexible in setting an allowable rate-ofreturn for new facilities. Anyone advocating new legislative authority or requirements should first demonstrate why this existing authority is insufficient to encourage new development.

Second, if the Congress endorses new policies to create new financial incentives,

the projects to receive these incentives should be determined by FERC with input

from a balanced, independent organization, such as an RTO.

Third, if higher rates for new facilities are contingent upon a determination of

critical need, it will be important to ensure that this policy does not inadvertently

encourage a disregard of timely upgrades in the expectation that improvements to

deteriorated infrastructure will bring a greater reward.

INTER-RELATIONSHIP OF TRANSMISSION POLICY ISSUES

While the Subcommittee will hear testimony later today on Regional Transmission Organizations (RTOs), we want to stress how appropriately structured

RTOs are the strongest foundation for sound transmission policies, including those

topics being considered in this hearing.

In our view, it is critical that Congress support the formation of RTOs of sufficient

size and configuration in order to facilitate strong regional power markets that will

bring power from where it exists to where it is needed. If this overriding objective

is achieved, other benefits will flow to consumers.

For example, reliability will be enhanced as large RTOs provide transmission

service in a non-discriminatory manner to those that have power so they may bring

power to where it is needed to meet demand. Well functioning markets—the very

goal of FERC’s RTO policy—will ensure reliability. Similarly, RTOs as FERC envisions them maximize efficient use of generation and transmission assets, reducing

(though not eliminating) the need for some facilities and related siting decisions. As

to incentives, investments for the benefit of regional markets are more likely to be

made when those assets are operated within the type of RTO structure we support,

rather than as part of vertically integrated utility systems.

Attached is a letter that EPSA sent to Chairman Barton and members of the Subcommittee last month on pending legislation that centers on transmission incentives

and RTO policy (H.R. 2814, the ‘‘Interstate Transmission Act’’). The letter provides

further details on these important points. Please place this letter in the hearing

record.

CONCLUSION

In conclusion, Mr. Chairman, we thank you and the Subcommittee for this opportunity to present these views on reliability, siting and transmission pricing incentives in the context of non-discriminatory, open access transmission. We look forward to continuing to work with you and your colleagues as you develop electricity

legislation in the weeks to come.

Mr. BARTON. We thank you.

We want to hear now from Dr. John Anderson, who is the Executive Director of the Electricity Consumers Resource Council.

Your testimony is in the record, and we ask that you summarize

it in 5 minutes.

58

STATEMENT JOHN ANDERSON

Mr. ANDERSON. Thank you very much, Mr. Chairman.

Large industrial customers understand that the transmission

grid is the linchpin of America’s electricity system. Without adequate transmission capacity, the system fails. Similarly, without

standards to ensure reliability, even a system with adequate generation and transmission will not be able to deliver power to end

users on a regular and efficient basis.

The transmission system is in need of improvement. We need to

have existing congestions in transmission mitigated, and we need

the transmission system to be operated in a nondiscriminatory

manner. Specifically, no owner of transmission facilities should use

those facilities to benefit its generation at the expensive of others.

Today I do address the three issues central to this hearing. First

is the issue of incentive based rates for transmission, sometimes

called innovative pricing or performance based rates. This issue

has received much attention before this subcommittee, even today

before the subcommittee and, of course, FERC.

We must remember that transmission is built and operated in

the framework of a monopoly not competitive. ELCON members

certainly believe that transmission owners should have a reasonable opportunity to recover prudently incurred costs and earn a

just and reasonable return on the investment dollars that they put

into transmission. But they should not get more than that.

Simply put, you can try to drive a monopolist, but if you try you

should not expect to get the results that you were seeking.

The rate of return authorized for a monopoly transmission investment should reflect the risk that incurred. Generally investment in transmission is low risk. This subcommittee heard testimony from Goldman Sachs earlier and from several other people,

and I refer you to that.

If transmission owners and transmission investors can first demonstrate a higher degree of risk, then a higher rate of return might

be acceptable. But they should have to demonstrate that first.

Section 401 of Chairman Barton’s draft dealing with incentive

rates strikes me as overly prescriptive, unnecessary and undesirable. Ordering FERC to establish transmission pricing policies

based on incentive based performance rates, both directs and confines FERC regardless of whether its expertise or market conditions may otherwise indicate.

I find it particularly ironic that this subcommittee would want to

legislate so precisely when FERC only 2 weeks ago on September

25 under the leadership of its new Bush appointed Chairman, Pat

Wood, a good Aggie, embarked on an ambitious new plan—— Mr. BARTON. There’s no such thing as a bad Aggie.

Mr. ANDERSON. Thank you very much. Mr. Chairman, I stand

corrected. Thank you very much.

Simply put, legislative direction such as is included in section

401 of the draft bill is unnecessary. It would severely limit FERC’s

ability to respond to market developments and should not be included.

The second issue is siting, specifically the issue of whether a Federal right of eminent domain should exist to facilitate such siting.

I find it almost contradictory that some who support providing fiVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00062 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
59

nancial incentives for new transmission oppose Federal right of

eminent domain.

Congress recognized long ago that FERC should have the right

of eminent domain in the siting of new natural gas pipelines. We

believe the same right should exist for the siting of new transmission. Electricity clearly is interstate in nature.

The language in section 402 of your bill establishing a Federal

backstop for transmission siting is generally positive. However, I

emphasize that even a Federal backstop will not change the protective attitudes of transmission owners who do not want new transmission capacity because it would jeopardize their own generation.

The third issue is often called reliability, but in reality is simply

the creation of a new electric reliability organization. ELCON and

our members seek large seamless nondiscriminatory electricity

markets. We support a strong top down reliability organization

subject to FERC oversight. That organization must have fair and

representative governance procedure. It should set uniform national reliability and commercial practice standards and procedures

for North America. A one stop shop, to speak.

RTOs should implement, not set the standards. There’s no

discernable need either for affiliated regional reliability entities or

regional advisory bodies, nor is there a need to statutorily prescribe

variances or mandates.

The proposal put forth in section 301 of your bill is a noble effort.

It recognizes that we do not need the complicated duplicative structure and process that was an integral part of the bill originally created under the auspices of NERC.

When ELCON first considered this issue we believed that reliability and commercial practices were separate components that

could be treated separately. We now no longer hold that position.

Although NERC purports that its standards and missions are confined to reliability, they actually overlap substantially with commercial practices. Simply stated, it is impossible to separate reliability from commercial issues so one organization should handle

both.

In conclusion, ELCON seeks large nondiscriminatory seamless

electricity markets. Such markets would benefit all customers by

providing the opportunity to purchase electricity that is lower

prices and more efficiently produced. We do not need artificial financial incentives to transmission owners or anyone else to get

there. We need markets. We need a Federal approach since electricity is interstate in nature. And we need a means of siting new

transmission that is efficient and effective. And finally, we need

one set of rules, not several.

Mr. Chairman, thank you very much for the opportunity to be

here with you.

[The prepared statement of John Anderson follows:]

PREPARED STATEMENT OF JOHN ANDERSON, EXECUTIVE DIRECTOR, THE ELECTRICITY

CONSUMERS RESOURCE COUNCIL

Mr. Chairman, members of the Subcommittee, thank you very much for the opportunity to testify at this hearing this morning.

As you know, ELCON, formally the Electricity Consumers Resource Council, is

the national association representing large industrial users of electricity. Our member companies come from virtually every segment of the manufacturing community.

60

Large industrial customers understand that the transmission grid is the lynchpin

of America’s electricity system. Without adequate transmission capacity, the system

fails. Similarly, without standards to ensure reliability, even a system with adequate generation and transmission will not be able to deliver power to end users

on a regular and efficient basis.

The transmission system is in need of improvement. We need to have existing

congestions in transmission mitigated, and we need the transmission system to be

operated in a nondiscriminatory manner. Specifically no owner of transmission facilities should use those facilities to benefit its generation. For the most part, the

shortcomings in our transmission system are the result of a series of events.

America’s transmission grid—still governed essentially by a 1935 statute—has

been asked to change from a country road to an interstate highway. Electricity is

being bought and sold in ways that had never been imagined.

In recent years there has been uncertainty about how the transmission grid would

be operated. Logically, monopoly transmission owners have been reluctant to make

necessary investments in improving or expanding the transmission market to relieve transmission congestions that often protected their own inefficient generation.

This is an understandable, but undesirable, result of increasing competition in generation. Additionally, electricity restructuring on a state-by-state basis has presented transmission owners with an uncertain future, which has also contributed

to a hesitant investment pattern.

Of late, given the increased attention being paid to our increasingly inadequate

transmission grid, there have been a number of proposals put forth. Some we find

positive, some negative, some simply incomplete.

INCENTIVES:

Let me turn first to an issue that has received much attention before this Subcommittee and before the Federal Energy Regulatory Commission—that is the issue

of incentive-based rates for transmission, sometimes called innovative pricing or

performance-based rates. ELCON has paid considerable attention to this issue, and

in fact ELCON published an ‘‘Issue Profile’’ entitled Performance-Based Regulation

in August 2000. That report is available at our web site, http://www.elcon.org/Documents/pbr—profile.pdf.

ELCON members are perhaps the pinnacle of capitalism. They compete in world

markets. They are keenly aware of rates for investment and return on investment,

of risk and aversion to risk.

Some people seem to think that increased competition in generation in some way

changes the fact the transmission remains monopolistic. There is a basic difference

between competitive markets, such as those in which ELCON members participate,

and monopoly markets which is where we find owners of electricity transmission.

We understand perfectly well that the underlying theory of ‘‘incentive regulation’’

is intuitively appealing. This accounts for the growing popularity of proposals to provide ‘‘incentives’’ for transmission.

But we must remember—transmission is built and operated in the framework of

a monopoly market. ELCON members certainly believe that transmission owners

should have a reasonable opportunity to recover prudently incurred costs and earn

a just and reasonable return on the investment dollars they place in transmission.

But they should not get any more than that. Simply put, you can try to bribe a monopolist, but if you try, you should not expect to achieve the result that you are

seeking.

We must also keep in mind that investment in transmission is essentially lowrisk. As this Subcommittee heard from a Goldman Sachs analyst at an earlier hearing, a return in the historical 11-12 percent range usually is adequate. It will stimulate appropriate investment dollars. If transmission owners and transmission investors can first demonstrate a higher degree of risk, a higher rate of return might be

acceptable.

This was clearly illustrated in a recent report prepared by the financial analysts

Fitch on the newly formed American Transmission Company, a transmission-only

company not affiliated with any one utility. That report states that ATC’s ‘‘costs are

recouped through an annual revenue requirement passed through rates to ‘‘network’’

customers’ and that those network customers contribute over 95 percent of ATC’s

annual revenues. This is yet another illustration that investment in transmission

is intrinsically low risk.

‘‘Incentives’’ beyond cost of service for new monopoly transmission investments

fail on several counts.

First, cost-of-service regulation should provide adequate economic incentives, because utilities are allowed to recover prudently-incurred costs and earn a virtually

61

guaranteed rate of return with almost no downside risk. There is no need to embellish any monopoly transmission owner’s potential earnings as long as this guarantee

applies.

Second, incentives cannot make a monopolist behave as a real competitor unless

the monopolist is allowed to fail. Changing the rate of return does not change the

underlying problem. The only way to minimize this problem is to structure the regulatory process in ways that minimize the potential for improper strategic behavior

and gamesmanship.

Third, traditional cost-of-service regulation is not lacking workable incentive

mechanisms. In fact, under cost-of-service, regulators often establish bandwidths

around allowed returns that reward exceptional behavior or exceptional risk and

punish the opposite. But those who want to construct new transmission must first

demonstrate that such risk exists.

Section 401 of the ‘‘Barton draft,’’ dealing with incentive rates, strikes me as overly prescriptive, unnecessary and undesirable. Ordering FERC to establish transmission-pricing policies based on ‘‘incentive-based and performance-based’’ rate

treatments both directs and confines FERC regardless of whether its expertise or

market conditions may otherwise indicate. Further, requiring FERC to report to

Congress every year, assessing both ‘‘the level of transmission investments in the

preceding year and assessment of the level and sufficiency of the Commission’s allowed financial returns’’ will likely result in an upward spiral of rates of return on

investment that might never end.

(Parenthetically I am reminded of the old, probably politically incorrect, joke

where the crazy man is singing off-color and off-key tunes outside an apartment at

two o’clock in the morning. One apartment dweller asks him to stop and the crazy

man says yes, for five dollars. The apartment dweller throws him five dollars and

the crazy may goes away. But he comes back the next night, louder, more off-color,

and more off-key. The apartment dweller comes to the window and is about the

throw out five dollars when the crazy man say, no, tonight the rate is ten dollars.

After all, he says, ‘‘I may be crazy, but I am not stupid.’’)

I find it particularly ironic that this Subcommittee would want to legislate so precisely when FERC, only two weeks ago on September 25, under the leadership of

its new Bush-appointed chairman, Pat Wood (Texas A&M, 1985), embarked on an

ambitious new plan for ‘‘Making Markets Work.’’ Although we do not support every

provision of Chairman Wood’s plan, it comprehensively addresses the need for infrastructure improvement and expansion with the stated objective of providing ‘‘clarity

of cost recovery to infrastructure investors.’’ FERC already has the authority to approve higher rates of return, FERC has the authority to approve incentive-based

rates, and FERC has the authority to create innovative rate structures (for example,

FERC included such a requirement in Order 2000).

Simply put, legislative direction such as is included in Section 401 of the draft

bill is unnecessary, would severely limit FERC’s ability to respond to market developments, and should not be included.

SITING:

Now let me turn to transmission siting and, specifically, the issue of whether a

federal right of eminent domain should exist to facilitate such siting.

I find it almost contradictory that some who support providing financial incentives

for new transmission oppose a federal right of eminent domain.

Those who wish to build new transmission are faced with a myriad of different

state rules and regulations. What has been called NIMBY—not in my backyard—

has grown into BANANA—build absolutely nothing anywhere near anything. But

a word of caution—unless you change the underlying motives of transmission owners, establishing a simpler procedure, while helpful, will not get the job done.

Congress recognized long ago that FERC should have the right of eminent domain

in the siting of new natural gas pipelines. We believe that the same right should

exist for the siting of new transmission. It is clearly interstate in nature. Since citizens in one state may object to new power lines that provide power to citizens in

another, it is up to the Federal government—in this instance FERC—to provide a

means to overcome such provincialism and ensure that the needed infrastructure is

in place. Because, in truth, all citizens will benefit from a well functioning, reliable,

electricity grid.

The language in Section 402 of the draft bill, establishing a ‘‘Federal backstop’’

for transmission siting, is generally positive. However, a two-step process will by

definition result in less, not more, transmission capacity. And even a Federal backstop will not change the protective attitudes of transmission owners who do not

want new transmission capacity because it would jeopardize their own generation.

62

RELIABILITY:

That brings me to my last point—what is often called reliability but in reality is

simply the creation of a new electric reliability organization.

ELCON and ELCON members seek large, seamless, nondiscriminatory electricity

markets. We support a strong ‘‘top-down’’ reliability organization that sets uniform

national standards and procedures for North America. RTOs should implement, not

set, standards. We favor fewer levels of bureaucracy. We believe questions of reliability should be decided as quickly as possibility, and we seek rules of the road

for reliability that are consistent so that buyers and sellers face a seamless electricity market. Rules intended to increase reliability should not unnecessarily intrude into commercial practices.

ELCON has been working with the North American Electric Reliability Council

(or NERC) for over four years in an attempt to draft legislation that would authorize

an appropriate new reliability organization. We need a new organization because

NERC as presently operating has no statutory authority. This means NERC has no

enforcement or funding authority, and no antitrust immunity. NERC was created

for the market of the 1960’s; it is not designed for the markets of the twenty-first

century.

ELCON helped draft and then supported what is sometimes called the consensus

reliability language first proposed in February 1999. That language has been revised several times over, and ELCON continues to this day to participate in NERC

drafting sessions that, in truth, seem to be moving away from consensus at every

meeting. The reason for the increasing lack of consensus is not really surprising.

As we see the wholesale market continue to develop—what happened in California,

what is happening with RTOs, what is happening at FERC—we realize that what

was proposed two and a half years ago is inappropriate for today’s electricity world.

It was too detailed, too cumbersome and too prescriptive. It should not be adopted.

As you are well aware, FERC is attempting to establish five large regional transmission organizations. These RTOs would be in charge of the operation of the grid

within their regions. A critical question is who will draft the necessary reliability

and commercial standards, a national standards organization or each RTO individually? If RTOs can draft their own standards, why do we need a national reliability

organization?

The proposal put forth in Section 301 of the Barton draft is a noble effort. It recognizes that we do not need the complicated, duplicative structure and process that

was an integral part of the bill created under the auspices of NERC.

The most recent version of the legislative language coming out of the NERC process establishes a new North American Reliability Organization (or NAERO) as well

as a series of new Affiliated Regional Reliability Entities (or ARREs). The geography

of the ARREs is expected to be identical to the geography of the RTOs. But the division of responsibility between the two is unclear.

We contend that the ARREs are at best redundant and at worst counter-productive. They will contribute to a variety of rules and regulations and heighten the

‘‘seams’’ issue of how power flows from one RTO to another. More importantly, those

who propose that ARREs be granted the right to ask for variances for different reliability standards in each RTO only increase those dangers. And those who suggest

that ARREs be allowed to seek such variances directly from FERC are really seeking a balkanized electricity grid rather than a unified one. We are pleased that the

Barton draft language does not envision or sanction such entities.

Finally the NERC ‘‘consensus’’ language proposes, in statute, the creation of Regional Advisory Bodies which also may offer proposals to FERC and whose proposals

shall receive ‘‘deference’’ from FERC. Again, ELCON does not believe that we should

create RTOs with each responsive to multiple masters. This will Balkanize the electricity marketplace. Again, we are pleased the Barton draft does not include or create such bodies.

ELCON and ELCON members believe that RTOs can best serve the purpose of

implementing national reliability standards and administering those standards for

purpose of operating a reliable grid. The standards should be established by a national organization. We do not need ARREs. We do not need Regional Advisory

Boards. And we certainly do not need a process that gives deference to regional

groups, which, again, can only lead to Balkanization. It is the interest of consumers

and in the interest of reliability to create a system with as few levels of bureaucracy

as necessary.

That leads to one more issue—the question of standards for reliability versus

standards for commercial practices. When ELCON first considered this issue, we believed these were two separate components that should be treated separately. We

know longer hold that position. Although NERC purports that its standards and its

63

mission are confined to reliability, we believe that they overlap substantially with

commercial practices. It is impossible to separate reliability from commercial issues.

Along those lines, the Gas Industry Standards Board has approved a proposal that

it become an Energy Industry Standards Board to develop appropriate commercial

standards for electricity, with the understanding that they might also affect reliability. I don’t know if this question needs to be addressed in legislation or by

FERC, but it should at least be considered.

Optimally, we believe that any standard-setting organization created needs to address questions of both reliability and commercial practices—a one-stop shop so to

speak. It should be a strong ‘‘top-down’’ organization, subject to FERC oversight and

approval, that establishes standards and practices. There is no discernible need for

affiliated regional reliability entities or regional advisory bodies. Nor is there a need

to statutorily prescribe variances or mandates for deference. There should be an

antitrust exemption based on ‘‘rule of reason,’’ rather than on a rebuttable presumption. And this body should have a just and reasonable funding mechanism.

CONCLUSION:

In conclusion, ELCON seeks large, nondiscriminatory, seamless electricity markets. Such a grid would benefit all consumers, providing all consumers with the opportunity to purchase electricity that is lower priced, more efficiently produced. We

do not need artificial financial ‘‘incentives’’—to transmission owners or anyone

else—to get there. We need a federal approach. We need a means of siting new

transmission that is not fraught with danger. And we need one set of rules, not several.

Thank you Mr. Chairman.

Mr. BARTON. We thank you, Doctor.

We’d now like to hear from Mr. Marty Kanner whose the coordinator for Consumers for Fair Competition.

His statement’s in the record and you’re recognized for 5 minutes.

STATEMENT OF MARTY KANNER

Mr. KANNER. Thank you very much, Mr. Chairman, members of

the subcommittee.

You’ve heard this morning that transmission is critical to ensuring competitive markets. You’ve also heard that transmission system is constrained, and you’ve heard from a number of witnesses

that incentive rates are unnecessary to relieve those constraints

and provide the seamless highway of commerce that’s needed. So

my challenge this morning is to add what you’ve already heard.

Some have suggested that incentive rates boosting the return on

investment is necessary in order to attract the capital needed to invest in the transmission system. It’s absolutely true that the failure to invest in the transmission network is related to economics.

But it’s not the economics associated with the rate of return on

those investments, rather it’s the economics of the competing business; generation. When we have vertically integrated utilities any

transmission constraint boosts the prices that can be charged for

generation within that constraint and effectively preclude the introduction of competitors.

Looking at the economics, looking at the comparative investment

and generation assets and transmission assets, it’s absolutely true

that if you follow the dollars maintaining constraints boosts profits.

Simply adding to the return that can occur on the transmission

system won’t relieve those incentives, won’t change the economics.

It’s simple: The economics dictate that transmission constraints are

a good thing for transmission owners.

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So the question then is what do you do to relieve the constraints

and is it necessary to provide incentives. Before I answer that

question, I’d like to go beyond.

In the various proposals including section 401 in the chairman’s

discussion draft, as well as the bill introduced by Mr. Sawyer and

Mr. Burr there is not a limit on those incentives to just new investments. Rather, incentives would also inure to efficient operation of

the grid, to participate in RTOs, even to those that are already

RTO participants. Again, those are needed.

FERC has already taken steps to encourage RTO participation.

And efficient functioning of the transmission grid should be a requirement for a monopoly owner, not something that we need to

provide sweet monopoly candy for people that do their job.

On negotiated rates, it violates the basic tenant of the Federal

Power Act. The Federal Power Act requires just reasonable, not unduly discriminatory or preferential rates. There’s no way to ensure

that if parties can simply have a sidebar agreement and tell transmission users it’s take it or leave it. Pay what we are saying or else

you don’t get access. And there’s no way for others, whether it’s

competing transmission users or FERC to determine whether that

negotiated rate was fairly and reasonably entered into.

As you’ve heard today, there’s plenty of latitude within the Federal Power Act to ensure just and reasonable rates—to require just

and reasonable rates and ensure that transmission owners receive

a reasonable rate of return. In fact, that’s precisely what the just

and reasonable standard calls for. It requires that rates are neither

extraordinary to transmission users, nor confiscatory for transmission providers. Within those bounds, there’s tremendous latitude for the commission to ensure that rates reflect the risk associated with the investment and they are provided sufficient incentives to do what’s necessary for the system, which makes me wonder then what is the hidden agenda?

As you know, many utilities are seeking to sell or spin off their

transmission assets. If utilities are no longer going to be transmission owners, why are they pushing so hard for incentive rates?

The only conclusion I can come to is that they’re looking to boost

the asset value for those sales. If they can promise a potential purchaser that you’ll get a 20 percent return on the investment, they

can increase the sale price that they can otherwise attract.

If this is, in fact, the hidden agenda, then we need to make sure

that transmission rates are based on the depreciated book value

and not on the premium paid when new parties purchase these

same assets. Otherwise, all we’re doing is churning the assets and

ensuring that transmission rates are higher.

So what can be done? You’ve heard from a number of my colleagues today. We need a system that ensures access to all parties

under the same terms. We need viable vibrant RTOs that have the

authority to plan and ensure investment in the system. That’s all

that’s needed, Mr. Chairman. Incentive rates clearly are not.

[The prepared statement of Marty Kanner follows:]

PREPARED STATEMENT OF MARTY KANNER ON BEHALF OF CONSUMERS FOR FAIR

COMPETITION

Mr. Chairman, members of the Subcommittee, I am Marty Kanner. I am testifying today on behalf of the Consumers for Fair Competition (CFC), an ad hoc coaliVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00068 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
65

tion of consumer-owned utilities, small and large electric consumer representatives,

small business interests, and others. While the interests of these organizations are

diverse, we are unified in the belief that Congress and the Federal Energy Regulatory Commission (FERC) must take clear and significant steps to promote the

market structure needed to foster and sustain effective competition in wholesale

electric markets, and its associated consumer benefits.

CFC commends you, Mr. Chairman, for focusing attention on the needs of the

electric transmission system. As the members of this Subcommittee know, the transmission system is the highway of commerce for the electric utility industry. As many

of you also realize, today’s electric highway system is in need of drastic repair. We

are all by now familiar with Path 15—the North-South constraint in California that

contributed to several of the State’s rolling blackouts as well as higher electricity

prices. Unfortunately, while Path 15 may be one of the most infamous constraints,

it is far from the only one. Throughout the country there are constrained paths that

inhibit wholesale power transactions, limit generation competition (and consequently increase rates), create ‘‘load pockets’’ in which market power can be exerted, and threaten system reliability.

There is a glaring need for additional investment in the transmission system.

Some have suggested—incorrectly—that the lack of transmission investment is a result of inadequate returns on those investments and that ‘‘incentive rates’’ are needed to cure this problem. In fact, they go far beyond investment in transmission additions, calling for incentive rates to reward efficient management of the transmission

system, entice membership in Regional Transmission Organization, promote deployment of new technologies and assure system reliability. While all of these goals are

important, incentive rates for transmission—especially rates that are set outside the

bounds of the ‘‘just and reasonable’’ standard that has guided nearly seventy years

of utility regulation—are unnecessary and harmful to consumers.

TRANSMISSION RETURNS ARE NOT DRIVING AWAY INVESTMENT

Some have suggested that the lack of utility investment in transmission is directly

caused by inadequate returns on those investments—utilities aren’t investing in

transmission because they can’t attract capital at 10-12% returns. These assertions

are simply untrue.

Utility transmission investments are not competing with the high-flying returns

of high-risk investments. Traditionally, utility stocks were the investment of choice

for low-risk investors—widows and orphans. Many utilities today are restructuring

themselves to become pure wires companies or to separate their merchant, competitive operations from their ‘‘traditional’’ business in regulated functions. As noted before this Subcommittee on July 27 by Thomas Lane, Managing Director of Goldman

Sachs, ‘‘There is definitely a role in the markets for a lower risk, lower return investment which is what transmission represents.’’ Transmission is a monopoly service. As a monopoly function, its use must be

priced at cost, with a rate of return that reflects the low risk associated with a monopoly function.

OTHER FACTORS DISCOURAGE TRANSMISSION INVESTMENT

The lack of adequate investment in the nation’s transmission system is due to factors other than return:

1. Competing Profit Motives. It is absolutely true that economics drives the failure of utilities to invest in transmission—but it is not the economics associated

with the rate of return on transmission investment. The transmission network

is owned by vertically integrated utilities with significant investment in generation facilities. Transmission constraints serve to boost the price that can be

charged for generation within that constraint and to frustrate market entry by

potential competitors. It is more profitable to maintain a constraint and we

should not seek to bribe utilities to relieve those constraints.

2. Transmission Siting. Many transmission additions cannot be built—or are severely delayed—because of the current transmission siting regime. CFC does

not have a position on the appropriateness of federal siting authority. However,

we recognize that the current regime is a contributing factor to the inadequacy

of transmission investment.

3. Uncertainty Associated With RTOs. Some utilities may have foregone or delayed investment in transmission as the world of RTOs sorts itself out. Utilities,

assuming that the cost of those investments will be recovered through the RTO,

may seek to avoid a rate case fight before state regulators. I want to emphasize,

however, that RTOs can be the cure to needed transmission investment, as I

will explain later.

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4. Uncertainty Associated With Technology and Generation Investment. The

industry is going through significant changes. It is possible that a narrow subset of transmission investments could be rendered moot by the siting of new

generation. However, I would note that there are less harmful means of addressing this potentially uncertainty. Moreover, effective transmission planning

by an RTO can minimize or eliminate this uncertainty.

INCENTIVE RATES ARE EVEN LESS JUSTIFIED FOR GENERAL TRANSMISSION FUNCTIONS

My testimony has focused on transmission incentive rates for new investment.

However, the advocates of incentive rates go far beyond new investment—calling for

incentives for joining RTOs, rewarding existing RTOs, limiting rate pancaking, promoting efficient operation and reliability.

Why are we providing incentives for RTO membership when most utilities have

already joined RTOs under FERC Order 2000, itself a ‘‘voluntary’’ mandate, and

FERC has taken additional steps to prompt RTO participation? What purpose do

‘‘sign up’’ incentives serve for those RTOs that already exist? Why should we provide

incentives to limit rate pancaking when FERC Order 2000 already calls for the

elimination of rate pancaking?

NEGOTIATED RATES VIOLATE THE UNDERLYING TENET OF FERC REGULATION

The notion of ‘‘negotiated rates’’—FERC approving rates without regard to cost—

is most abhorrent. The Federal Power Act prevents the charging of rates that are

‘‘unjust, unreasonable, unduly discriminatory or preferential’’. Negotiated rates can

violate each of those standards. A transmission owner can impose excessive charges

and tell the transmission user to ‘‘take it or leave it’’. Alternately, a transmission

owner can discriminate between competing generation developers, facilitating interconnection only for the generator willing to pay top dollar. Moreover, if FERC (and

competitors) are unable to review the underlying costs, no one will know if the negotiated deal reflects a fair rate or simply the transmission equivalent of ‘‘an offer you

can’t refuse’’.

INCENTIVE RATES: THE HIDDEN AGENDA?

Many utilities are seeking to sell or spin-off their transmission assets. If utilities

are no longer going to be in the transmission game, why are they calling so loudly

for incentive rates. I fear that the underlying motivation is to increase the market

value of those assets. Didn’t we already see this phenomenon in the sell-off of utility

generation assets (a study by Professor Harry Trebing shows that 93% of those were

for well above book value)—with its obvious negative impacts for consumers in California? Potential investors may be willing to pay a higher purchase premium if they

can be assured of inflated returns.

If this is, in fact, the hidden agenda, it is critical that we ensure that future transmission rates are based on the underlying book value of transmission assets and not

on the acquisition cost.

‘‘JUST AND REASONABLE’’ REMAINS THE PROPER STANDARD

The Federal Power Act directs FERC to ensure that all transmission rates are

‘‘just and reasonable’’. This standard provides sufficient latitude for FERC to: (1) adjust rates of return to reflect any increase in investment risk, (2) allow performance

based rates to reward exceptional performance that benefits consumers, (3) send

price signals (e.g., congestion pricing) to encourage investment to relieve constraints.

Significantly for the members of CFC, the ‘‘just and reasonable’’ standard also requires that consumers do not pay extortionary rates.

There is significant risk of consumer harm in flipping that model and directing

FERC to provide incentive rates every time a transmission owner comes forward.

HOW DO WE RELIEVE TRANSMISSION CONSTRAINTS?

Mr. Chairman, I have spent my testimony critiquing the notion of incentive rates.

But given the reality of today’s transmission constraints, I feel obligated to also offer

constructive suggestions for relieving those constraints.

1. Ensure Fair and Equal Access. ‘‘Phantom’’ transmission constraints exist

throughout the system. Transmission owners reserve more transmission capacity than is needed, creating artificial constraints that impede transactions.

Similarly, inadequate or untimely postings of available transmission capacity

suggest constraints that do not exist. Congress must ensure full, fair and equal

access for all parties to the nation’s transmission grid.

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2. Independent Planning. As noted above, vertically integrated utilities have little

economic incentive to relieve constraints. RTOs—as independent managers of

the grid—must have robust and effective planning authority and responsibility.

3. Authority to Compel Construction. All to often, utilities will ignore or defer

transmission investment needs. RTOs must have the authority to compel utilities to build needed transmission. If utilities are unable or unwilling, then the

RTO should be authorized to build the facilities itself or solicit competitive bids.

CONCLUSION

There is no doubt that significant investment in the nation’s transmission system

is needed. However, incentive transmission rates are not the cure. Transmission

rates—as a monopoly service—must continue to be guided by the ‘‘just and reasonable’’ standard.

Mr. BARTON. We thank you, Mr. Kanner.

Before we recognize Mr. Vesey, the Chair wishes to make a

housekeeping announcement. We’re moving expeditiously through

this panel. Based on the number of members present and those expected to be present, I think we can conclude the questioning of

this panel by approximately noon. Given that, we have called the

representatives for the second panel and we’re going to start the

second hearing at 1 p.m. instead of at 2.

So those of you that need to go make phone calls.

We expect to start the second hearing at 1 p.m. instead of 2.

We’ve notified the panelists and they’re agreeable. So if people

need to know that information, please be notified.

We now want to welcome our last testifier on the first hearing,

Mr. Andrew Vesey, who is Vice President Energy and Utilities for

the Cap Gemini Ernst & Young L.L.C.

Your testimony is in the record, we recognize you for 5 minutes.

STATEMENT OF ANDREW M. VESEY

Mr. VESEY. Thank you, Mr. Chairman.

Over the past 25 years capital investment in the transmission

system has remained stable despite rising off system sales and falling reserve margins. However, since the mid-1970’s the transmission system has grown at half the rate of demand. Transmission sector needs investment.

Today’s transmission goods grew incremental over time as the industry met the requirements of growth and the pressures for increased reliability. There was little reason to believe, however, that

the current structure’s the most economic or the most reliable in

light of current market needs. In some parts of the country inadequate transmission capacity already diminishes the prospect for

competitive power markets.

On the rate of return regulation utilities make money by investing in assets. The apparent lack of investment in transmission is

most likely the result of the market not believing that the owners

of transmission have the ability to generate future revenues sufficient to cover their costs and provide a competitive return.

If the market is doubtful, it is because the cost of capital used

to establish prices is believed to be too low. Too low because the

market sees risks that are not being acknowledge in the rate making process.

What are these risks? Well, among them are competition. Competitions of the grid exist now and will grow over time. The emergence of distributed generation technology such as small gas turVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00071 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
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bines and fuel cells provides the potential of bypassing the transmission grid and the risk of straining transmission investment.

Difficulty of siting new facilities is also one of the risks not recognized. With the passage of the Energy Policy Act of 1992 the transmission grid was required to act as a common carrier for bulk

power transactions. It is this new responsibility that has revealed

that the system, which was interconnected for liability purposes,

could not longer be relied upon for the level of interregional commerce demanded by the bulk power markets.

Significant investment in interregional transmission capacity is

needed. The current siting process, however, is ill-equipped to adequately handle this type of project given the mismatch between

those incurring the costs and those receiving the benefits of this

type of project across local, State and regional boundaries.

Finally, there’s the investment risk associated with ongoing activities regarding the governance of transmission owning entities to

ensure independence for market participants. The desire to separate asset ownership from the control and operation of those assets,

if not done thoughtfully, has the potential of seriously deluding the

powerful incentives provided by the market on for profit asset owning enterprises.

There is today no clear consensus as to which business structure

is optimal for owning transmission assets. The rules of the road are

not fully written, and indeed may be different region-to-region.

So how do we ensure the proper investments are made? One approach may be to simply have regulators provide higher rates of return in line with perceived risks. While fully compensating investors for risks is an absolute necessity, if these increased profits are

earned through the current rate of return framework, they will at

best only deliver a narrow range of the needed investments, not the

broad range required by the new competitive markets. And at

worse, they may result in over-building.

The new competitive market is significantly different from the

markets in which today’s transmission business is developed. It is

a market potentially made up of thousands of commodity suppliers,

hundreds of service providers and millions of individual consumers.

It is characterized by high transaction costs and low barriers to

entry and exit by both sellers and buyers.

The network not only has to effectively manage the flow of electricity, but also has to manage the flow of information and cash.

Traditional rates of rate of return regulation rewards firms for

placing assets on the ground to transport electricity. This new competitive market requires firms to be rewarded for behaviors that

promote customer focused, market driven solutions to facilitate

commerce.

With properly designed pricing transmission companies will succeed only by maximizing throughput, maintaining broad nondiscriminatory access and making system investments to maintain

optimal congestion levels. When the benefits of lower costs and

higher volume flow to the bottom line, transmission companies will

seek efficient decisions inducing competitively neutral solutions.

They will find the most cost effective, not the most asset intensive

answers to customer needs and they will devise innovative operating procedures and a range of tailored cost effective offerings that

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1This testimony is based in large measure on the material presented in the book ‘‘Unlocking

The Benefits of Restructuring: A Blueprint For Transmission’’, By Shimon Awerbuch, Leonard

Hyman and Andrew Vesey, Published by Public Utilities Report Inc; Vienna, Virginia, November 1999.

fully utilize their facilities. But most importantly, they will be driven to enrich their customers by maximizing the value of commerce

along their networks.

Thank you.

[The prepared statement of Andrew M. Vesey follows:]

PREPARED STATEMENT OF ANDREW M. VESEY,1 VICE PRESIDENT, CAP GEMINI ERNST

& YOUNG LLC

Over the past 20 years capital investment in transmission remained relatively

stable, in real terms, despite rising off-system transactions and falling reserve margins. In the 10 years preceding the Northeast Blackout of 1965, and in the decade

following, utilities did build high voltage lines at a rapid pace that kept up with

growing demand. From the mid-1970s to the present, however, the transmission system has grown at less than half the pace of demand.

With generating reserves falling and transmission plant showing little expansion,

transmission operators have responded by running the system in emulation of justin-time inventory management concepts, which rely on coordination of all suppliers

without the ‘‘safety-net’’ provided by system availability in excess of current needs.

This operational response will work only as long as all suppliers continue to produce

and ship on schedule and as long as buyers readily can find alternative suppliers.

The transmission sector needs investment. Our transmission grids grew incrementally over time as the industry met the requirements of growth and the pressure

for increased reliability. There is little reason to believe, however, that the current

structure is the most economic or the most reliable in light of current market needs.

Moreover it is doubtful that the existing structure represents an appropriate tradeoff between economy and reliability, or that it incorporates the levels of reliability

that customers want. In some parts of the country inadequate transmission capacity

already diminishes the prospects for competitive power markets and decreases the

system reliability during power plant outages. System operators, fortunately, have

learned to compensate for some of the physical deficiencies by running the networks

more efficiently.

It is not clear, however, that transmission owners have avoided physical expansion because they could achieve their goals through the clever operation of their systems: owners more likely decided to avoid expansion because of siting difficulties or

inadequate potential returns on their investments. The siting difficulties are well

documented, but they have to be placed in the context of incentives, as well. Under

rate-of-return regulation, utilities make money by investing in plant. Utility managers, therefore, never have avoided large, lumpy investments when they expected

that the allowed rate of return would equal or exceed their cost of capital.

Capital flows to a business based on the markets expectation that the business’s management has the ability to use the capital to generate a stream of revenue that

exceeds the cost of generating that revenue by an amount that is at least equal to

the next best use of that capital. Simply stated capital flows to return. The market’s ‘‘expectation’’ is based on consideration of all the risks to which the generation of

revenue is exposed and the period of time to fully recapture the invested capital and

its return. The flow of capital to a business is directly proportional to that business’s management’s ability to create value by generating earnings that are greater than

the business’s cost of capital in the long run.

The apparent lack of investment in the transmission sector is most likely the result of the market not believing that the business has the ability to generate future

revenues sufficient to cover its cost and provide a competitive return. Under rateof-return regulation the amount of revenue required is predetermined by calculating

a unit price which, based on forecasted sales, will generate sufficient revenue to

cover all production costs plus a profit. Calculating the firm’s cost of capital determines the profit. If the market is doubtful that revenues are sufficient to yield the

required return it is because the cost of capital used to establish prices is too low.

It is too low because the market sees risks that are not being compensated for in

the ratemaking process.

Among the risk that the market sees are:

• Competitive challenges to transmission’s monopoly status

• Difficulty in obtaining right-of-way and siting new transmission

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• The Evolving regulatory framework governing transmission

Firstly, competition to the grid does exist and will grow over time. The rapid expansion of distributed generation technology such as gas-fired turbines as well as

the advent of fuel cells clearly suggest that the role of transmission may change significantly over the next one or two decades. This competitive pressure should provide powerful incentives to a profit-oriented transmission owner to provide high

quality service, efficiently manage embedded plant, and to add new capacity (where

warranted) to enhance the functioning of the system, rather than lose market share

to competitors. This new capacity, incidentally, would not be limited to wires and

structures, but must be extended to include software, information systems, and new

electronic and technical devices. All of which enhance the firm’s capability to facilitate high value commerce in the emerging competitive electric energy market.

As mentioned earlier, the emergence of distributed generation technology has the

potential of contesting the monopoly status of the transmission sector. This raises

the increased specter of bypassing the transmission grid and the risk of stranding

transmission investment.

Secondly, the current interconnected electric grid evolved over time to (1) transport energy from remotely located generating stations to local load centers required

to serve local load, (2) aggregate diverse local load to lower overall generation investments and (3) enhance local reliability by inter-connecting neighboring systems.

All these objectives provided local benefits in either cost or reliability. The cost and

environmental impacts of providing right-of-way for transmission was evaluated

against the anticipated local benefits. On the occasion when a transmission line

crossed local jurisdictional or State boundaries the siting process became much more

difficult as parities that bore costs did not readily perceive the benefits.

With the passage of the Energy Policy Act of 1992, the transmissions grid was

required to evolve further to act as a common carrier for bulk power transactions.

It is this last responsibility that has revealed that the system that was interconnected for reliability purposes could no longer be relied upon for the level of

inter-regional commerce demanded by the bulk power market. Significant new investment in inter-regional transmission is required. The traditional local siting process is ill equipped to adequately handle this type of investment given the increased

mismatch between those incurring the cost and those receiving the benefits, a

source of considerable investment risk.

Finally, the ongoing activities regarding the governance of transmission owning

entities to ensure independence from market participants through the creation of

new entities such as RTOs, ISOs and TRANSCOs creates investment risk. The separation of asset ownership from the control and operation of those assets, if not done

correctly, has the potential of seriously diluting the powerful incentive provided by

profit maximization. There is today no clear consensus as to which business structure is optimal for transmission. The rules of the road are not yet fully developed

and may be different region to region.

So how do we ensure that the proper investments are made? One approach might

be to conclude that all that is needed is to compensate transmission owners by having regulators provide them with higher rates-of-returns, commensurate with the

perceived risks. While fully compensating investors for risk is absolutely necessary,

if these returns are gained through the current rate-of-return regulatory framework

they will at best only deliver a narrow range of investments not the broad range

required in the new competitive electric energy markets. At worst they may result

in non-value-adding over investment.

To understand why this is so it is important to change our view of transmission

from as an enabler of the generation market to an enabler of commerce in the competitive electric markets.

The pre-1992 view of transmission was as a transportation system delivering electricity from company owned large plants, distant from company owned loads, to

ratepayers over a system of company owned wires. Our post-1992 view has been

modified to transmission being a transportation system delivering electricity from

independently owned large plants, distant from loads, to customers over a system

of company and non-company owned wires. While this view accurately describes the

current state of transmission it does not accurately reflect the role of transmission,

i.e. how transmission creates value in the new competitive market. It will not help

identify the types of investment needed or give guidance on how best to induce firms

to make those investments.

A more helpful view of transmission is as a network, facilitating commerce in a

competitive energy market, where every consumer is a potential repackager and reseller of product and every one connected to the network is a customer.

A network is a set of dynamic, sustainable, value-producing relationships between

parties with common interest. A network can be physical or virtual .The network

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is a medium through which exchanges between the parties can take place. The exchanges can be knowledge, information, or goods and services. The network is viable

as long as it is value adding by offering those using it an economic advantage over

alternative relationships.

The set of dynamic, sustainable, value producing relationships between parties

with common interest in this case is the competitive energy market. This competitive market is significantly different from the markets in which today’s transmission

businesses developed and currently operate. It is a market made up of thousands

of commodity suppliers, hundreds of service providers and millions of consumers.

High transaction costs and low barriers to entry and exit by both sellers and buyers

characterize it. The network manages not only the flow of electricity but also the

flow of information and cash. Traditional rate of return regulation rewards firms for

placing assets in the ground. The new competitive market requires behaviors that

promote customer focused, market driven solutions by having transmission businesses rewarded for:

• Providing access and throughput at lowest cost

• Efficiently utilizing its assets

• Providing new service offerings

• Efficiently meeting open access, service quality and other, public policy objectives

• Maximizing throughput subject to efficient reliability constraints

• Promoting volume and commerce: increasing the value of transactions

We need to move from seeking to create incentives that focus mainly on inducing

capital investments in new transmission lines to those that induce the correct organizational behaviors. With properly designed pricing, flow based, market driven,

transmission companies succeed by maximizing throughput, maintaining broad,

nondiscriminatory access and making system investments to maintain ‘‘optimal’’

congestion levels.

When the benefits of lower cost and higher volume flow to the bottom line, transmission companies will:

• Seek efficient decisions—inducing competitively neutral solutions

• Find the most cost effective—not the most asset intensive solution to customer

needs

• Drive to enrich customers—maximizing the value of commerce along the network

• Devise innovative operating procedures and a range of tailored, cost effective offerings that fully utilize its facilities subject to efficient reliability constraints

Mr. BARTON. Thank you.

The Chair would recognize himself for the first 5 minutes of

questions, and we’re only going to have one 5 minute round.

Mr. Schriber, I thought your testimony was excellent, as it was

the last time you testified before us or your representative.

What do you think the position would be of the various State

PUCs if we put in the Ohio model as a Federal model for States

for follow with regards to siting decisions?

Mr. SCHRIBER. Mr. Chairman, I think, at least in my interface

with the other States, they would be delighted, I think, to share

the same statutory authority we have.

Many States have no power siting boards. We have neighboring

States that rely almost entirely upon homerule. As a result, we

have many, many more projects sited in Ohio than we would find

in neighboring States. I would therefore suggest that the States

would probably relish the opportunity to adopt the types of authority that we’ve been given by the State legislature.

Mr. BARTON. Okay. Is there anybody on the panel that is opposed

to the general provision in the pending draft that gives Federal

backstop authority on siting if the States fail to act? Is there anybody that opposes that backstop? I see nobody shaking their heads

or doing anything. So the Chair is going to announce that nobody

opposes it.

Mr. BOUCHER. You haven’t asked the members yet, Mr. Chairman.

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Mr. BARTON. Well, I know. But the members are going to tell me.

I’m not worried about that.

On the reliability issue, we’ve got two different views here. We’ve

gone one view, we have a gentleman that represents NERC that

says be fairly prescriptive and put it into the law. We’ve got another view that our friend from ENRON put into the record that

FERC can do it, just give the FERC the authority.

I will note that some people’s positions have changed since the

last Congress, and that could be because we have a different FERC

Commission, but that’s just an observation. That may not be reliability.

Is this really a technical issue? Should we let the technicians do

it because it’s an engineering problem or is reliability more of a

policy issue and we need to let the political mechanism handle it?

Mr. Cook, would you like to answer that?

Mr. COOK. Yes, Mr. Chairman. And let me speak to the issue

that’s been raised as well about the inner relationship between reliability rules and the commercial rules.

I agree with Dr. Anderson that they are inner linked. It’s why

NERC has gone to an independent board of directors, it’s why

we’ve added a market interface committee to our current committee

structure. It’s why we involve all segments of the industry including customers in our standard setting process to make sure that

those commercial impacts are picked up as we go forward.

In fact, Dr. Anderson sits on the Executive Committee of our Operating Committee.

And in the new model I would expect that that same kind of attention to those issues would happen.

The draft requires that no single sector can veto a standard, that

no two sectors can control it and it encourages broad participation

in the standard setting process. So in the first instance, it would

not simply be the engineers only that would be making those judgment, it would be a collective judgment by industry participants.

But the organization would be able to muster a lot of technical expertise to bring to bear on those subjects. And it would come together at FERC because the organization would be under FERC

oversight, the standards would not actually take effect until FERC

said they could.

So that, it’s a way to get the technical expertise of the industry

brought to bear on these issues. And if in the inclusive standard

making process that hasn’t flushed out the commercial impacts and

figured out way to accomplish both commercial purposes and reliability purposes, FERC is still there in a sense as an overseer backstop role to make sure that those issues get attended to. That’s the

structure of our proposal.

Mr. BARTON. Mr. Steffes.

Mr. Steffes?

Mr. SCHRIBER. I want to highlight again the inner relationship

between commercial and reliability matters. And while NERC proposes that they will begin to, you know, create an opportunity for

the commercial elements to be recognized, we simply have found

that on the hard questions—and I bring up the one in my oral testimony, the independence of security coordinators. On the hard

questions a consensus body can’t make that decision.

73

The NERC draft, even the modified NERC draft I think continues to say that FERC could say that’s not the model we want,

but we can’t get them to pull in the right answer.

This industry is changing at a tremendously fast pace. We need

FERC to be able to say I need a new rule, I need a new rule to

ensure reliability to ensure the competitive markets continue to

work. And we don’t see that unless you just provide general oversight—general policy to FERC. That’s our kind of——

Mr. BARTON. My time has expired. I’m going to let Mr. Harris

answer this question, then I’m going to go to Mr. Boucher.

Mr. HARRIS. Thank you, Mr. Chairman.

What we’ve experienced in dealing with this issue from retail

choice all the way through the wholesale system is that reliability

isn’t just a wholesale problem. It is an ecological system. It involves

all elements. And so the only area that you can really deal with

that is under a FERC oversight.

FERC ultimately has to make the determination. We’re also finding that we can give solutions economically to what used to be reliability solutions, and many of these are driven at the retail level.

You just can’t carve out something that says it’s only a wholesale

issue.

We would suggest that FERC has the authority and through a

rulemaking process they can come up with the right organizational

structure where it involves NARU or GSBI, whatever, but FERC

can create a structure that is vibrant and robust to deal with the

technical issues that are going to be emerging, and that would be

the appropriate way to address the question.

Mr. BARTON. Thank you. I’m going to not ask this as a question,

just make a comment. I thought it was very interesting that my

good friend, Mr. English, basically defined incentive rates by definition as just and unreasonable, and then gave a very elegant statement justifying his definition.

I want to put on record that the Chair doesn’t take as definitionally correct that incentive rates are unreasonable by definition.

That’s a debate that we’ll have as we go to markup.

With that, I would recognize my good friend, Mr. Boucher, for 5

minutes for questions.

Mr. BOUCHER. Well, thank you very much, Mr. Chairman. And

I want to join with you in thanking these panelists for their very

excellent presentations here this morning. We have been informed

by what you have told us, and appreciate your taking the time to

share your views.

But there is a kind of a generalized belief and some anecdotal

evidence that we do not have adequate transmission capacity in the

Nation, but I’m not aware of precise studies that pinpoint where

the deficiencies are. And I would like, as an opening matter, ask

if anybody here is aware of either governmental studies that clearly demonstrate inadequate capacity or perhaps think tank studies

that lead to the conclusion. And if you do, can you point us to

those? Is anyone aware of studies? Mr. Szwed?

Mr. SZWED. Yes, I think maybe one place you can turn is to the

North American Electrical Liability Council. There’s a lot of efforts

that are done in terms of assessing the adequacy of the transVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00077 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
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mission system as well as the adequacy of generation across the

United States.

I think you can also look toward evidence in terms of evidence

of the number of transactions that are taking place and the degrees

of where they’re have been issues or curtailments that have taken

place to give you an indication of areas where there are in fact is

congestion and perhaps where additional transmission capability

could be enhanced.

Mr. BOUCHER. All right. That’s helpful.

Mr. Cook, would you care to comment?

Mr. COOK. There are certain interfaces that are congested on a

fairly regular basis. One comes to mind in the Wisconsin area that

is pretty limiting on commerce a fair amount of time. And there’s

some other places like that in the country that can be identified.

There are also the circumstance, though, that these limits can

change from season to season, year to year depending on weather

patterns, for example.

Last year there was considerable congestion in the central part

of the country, Tennessee/Kentucky and so on, as sort of relatively

lower costs power from cooler areas tried to move south.

This year, it’s interesting, the congestion was there but it was in

a northbound direction because of the temperature differentials

sort of went the other way.

So attention to this issue does require, you know, paying attention to that kind of thing as well.

There are currently some studies underway to try to get a better

handle on this and focus on it.

Mr. BOUCHER. Whose performing those studies?

Mr. COOK. The Department of Energy, I understand, has got a

current study underway.

We issue an assessment, a 10-year assessment every year that

pays some attention to these issues and documents that kind of

stuff.

Mr. BOUCHER. What was your most recent assessment?

Mr. COOK. The most recent assessment was last—it would have

been last October/November. Our board is considering this year’s

10 year assessment at its meeting next week in Vancouver, and it

will be available shortly after that.

Mr. BOUCHER. Well, I would like to ask, Mr. Chairman, that we

receive for the record a copy of the assessment that you issued last

year and also the upcoming one to the extent that they focus on

the question of inadequate transmission capacity and document

those instances in which there are notable deficiencies.

Mr. Chairman, if it’s appropriate, I would ask that that be made

a part of this record.

And I would ask Mr. Cook that you provide it.

Mr. COOK. I’ll be happy to make sure that the subcommittee has

that material.

Mr. BOUCHER. It just seems to me that if we’re going to legislate

on the question of capacity, whether it be through incentive pricing

or some backstop Federal authority to order that new capacity be

built in the event that the States fail to act, that we at least ought

to be absolutely confident that there is a significant problem for us

to address.

75

And I’ll note again the generalized belief that there is, but we

really don’t have detailed evidence of that.

Let me ask a little bit about the notion of incentive pricing, and

I acknowledge that there is a debate about whether or not it’s a

good idea.

I would like to ask this panel whether you believe it’s a good idea

or not whether you think that the FERC has current statutory authority to order incentive pricing should FERC believe that it is a

good idea? Does anyone want to comment on FERC’s current statutory authority with regard to incentive pricing?

I think we heard very adequately from our good friend Mr.

English on that very subject, so let me call on Dr. Anderson.

Mr. ANDERSON. Yes, sir. I think that it’s pretty clear that they

have the authority. They’ve already included an incentive rate provision in their Order 2000, and that has not resulted in any significant problems.

I think also to relate back to your last question, which I think

is a very good one, there certainly are areas of the country where

there are transmission constraints. But as Mr. Cook said, they

change from hour-to-hour as various power flows change. I would

relate that back to the incentive area also.

It would not be appropriate, in my view, for you to legislate

across the board incentives to build transmission. It’s got to be

much more targeted than that. It’s got to be targeted to where

there are constraints. And I think the idea of getting a study is a

good idea. It’s going to be a very, very difficult one because it’s a

moving target.

But I think very strongly that the Commission has authority and

has already taken action on incentives.

Mr. BOUCHER. Thank you, Dr. Anderson.

Who would like to offer a competing view? Mr. Szwed?

Mr. SZWED. Yes. I would like to say a couple of things.

First of all, I would agree, FERC does have latitude and authority to deal with alternative forms of pricing today. But I don’t think

we’ve seen any evidence of that at all recently in anything that’s

really been implemented by anyone.

And I think as we think about transmission and we think about

transmission moving into a separate business, a separate situation

apart from other aspects of a vertically integrated utility where it

is a business that needs investment, it needs people, it needs innovation to be able to do and in order to be able to effect to meet the

goal of achieving broad competition and securing the infrastructure

of the U.S., I think what Congress needs to do here is even though

FERC may have that authority, is through legislation perhaps provide a stronger encouragement for FERC to—consist with the policy of having the reliable and efficient grid to support competition,

to use the authority they have with respect to incentive pricing and

put those kind of things to encourage investment and attract investment in the transmission grid.

Mr. BOUCHER. Thank you, Mr. Szwed.

Does anyone else want to comment on that issue?

Mr. KANNER. If I could, Congressman.

I think it’s absolutely correct that FERC has the authority for incentive rates, performance based rates to allow congestion pricing.

76

The boundaries, as I said in my testimony, are what’s just and reasonable. What’s not confiscatory to consumers or—I’m sorry—extraordinary to consumers or confiscatory to the company.

Transmission owners have the right to challenge a FERC rate of

return, to say we need more money to reflect the sorts of risks that

Mr. Vesey suggested exist. As long as those rates and rates of return fall within that zone of reasonableness and just and reasonable rates, then there’s nothing to complain about. It’s what the perimeters that FERC uses in setting rates.

In terms of establishing separate transmission companies, we

heard from Goldman Sachs that that sort of transmission distribution utility is likely to be lower risk and therefore require a lower

rate of return, not a higher rate.

Mr. BOUCHER. Mr. English, would you like to have the last word

on this?

Mr. ENGLISH. I’m reluctant to do so, Mr. Boucher.

But the issue’s judgment, that’s what we’re really talking about.

We’ve got people who don’t like the way that FERC has exercised

the authority that they have, and it’s been their judgment that this

is the fair, the just and reasonable way of doing it. So what this

is all about is redefining just and reasonable so that they have to

define the way and set aside their judgment.

Mr. BOUCHER. You would agree that they have the authority to

provide for incentive pricing should they choose to do so?

Mr. ENGLISH. There’s absolutely no question about it. It’s in the

law.

Mr. BOUCHER. Okay. It seems to me that everyone agrees with

that, and that’s an important consideration for us as we go about

making our decisions.

So the issue really for us is, as I suppose as you phrase it, Mr.

English, and that is given the fact that FERC can do this, should

we take the next step and require that they do it?

Well, thank you all very much. This is a helpful discussion.

And thank you, Mr. Chairman.

Mr. BARTON. The gentleman’s time expired.

I recognize the gentleman from Tennessee, Mr. Bryant for 5 minutes.

Mr. BRYANT. I thank the chairman.

As I mentioned to you, I was going to be in and out. I’m in again,

and so I’ve missed your testimony and I’m not sure anyone has addressed the issue specifically as I raised it regarding the siting and

the eminent domain, and things like that.

So, let me go ahead and ask a couple of questions related to that,

and really open the panel to those of you that might feel you need

to say something on this, that you’re qualified to talk about this.

But in the draft of this bill the States will continue to have eminent domain authority over transmission siting, but after 1 year

there’s kind of a backstop where FERC if the State hasn’t responded, FERC can go ahead and site the proposal. They’ll be given

the power to step and site new transmission if the courts determine

that it’s in the public interest, so you still got the public interest

test of course.

My questions relate to how you would define and how we would

define or how we would anticipate public interest being defined, as

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well as who would be exercising authority along. I know the State

law would apply in the beginning, but once the FERC got involved

would there be the possibility that—I don’t know. Would there be

the possibility that there could be different entities authorized, delegated the authority of eminent domain beyond the governmental

entity? In other words, private companies? And I may be getting

a little far afield.

We’ve had situation in Tennessee in regard to pipelines where

there were actually private company delegated that authority. And

they were out trying to condemn land to put their pipeline in. And,

again, it caused quite a—in my part of the State. But it was very

controversial and I’m just looking for some input on, again, how do

we mitigate, I guess, to some extent the consequences of eminent

domain and how you define a public use as well as limiting it, perhaps, to a public entity, governmental entity to exercise that

power?

Yes, sir? Is that Mr. Harris?

Mr. HARRIS. Yes, sir. It’s interesting in listening to the discussion, because it’s very difficult to make an informed decision without the right information.

What we’ve developed in the mid-Atlantic is a regional transmission planning protocol that’s been approved by the FERC. This

was so important in the mid-Atlantic region that we decided that

this had to be developed before we began commercial operations in

1997.

This regional plan has the input of all effected parties; the

States, the environmental community, the transmission owners,

the generators, everyone participates in the planning.

The information on the plan is made ubiquitously available so

that generation can compete and transmission planning can be enhanced.

For the areas that we serve, we now have nearly $700 million

worth of transmission planned and under construction. Our regional plan, which is publicly available, shows that those transmission expansion plans will meet the needs for the region for the

next 5 to 10 years, and this is updated several times a year.

So in order to get down to do you really have a problem or not,

you need to determine what is the information.

Mr. BRYANT. Well, could I ask you something?

Mr. HARRIS. It may be that there’s not a problem.

Mr. BRYANT. Could I ask you when you were talking about the

regional plans, and again RTOs, I guess, contemplate regional type

organizations. They cross State lines.

And in this regional plan that you have experience with, you

have different States with different State eminent domain laws.

Mr. HARRIS. That’s right.

Mr. BRYANT. And what happens there when there’s a conflict in

that, let’s say, or one State cannot get access to that portion of the

region that’s needed for this plan to work because of their laws?

Mr. HARRIS. That’s a good question. I think ultimately you have

to believe in the common sense of good people. When you provide

the right information and people participate, they understand what

the issue; that we’re looking at things over a broad region. They

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see what is necessary to affect the common good of the public for

the whole region.

And when you also actually look at the data, back to Mr. Boucher’s problem of what really is the problem you’re trying to fix;

when you actually look at the hard numbers and see what you

need to do, what often you find is a matter of an enhancement

here. We have areas where one utility is building something that

is actually solving another problem for another utility in another

State, but it’s the most economical way to do it, and it’s getting

done.

So the answer is get to the real hard issues, develop the fact,

allow broad public participation, understand the issue and then see

what we need to do. And what we’ve seen in this area, which is

a very sensitive area in the mid-Atlantic region, is that we’ve been

able to solve this problem.

Now, should we have an episode where we cannot, maybe we’d

have to come back. But we’re saying we’re able to see the synergy

between the State, the regional and the local needs to work together in a way for the common good. We think this is a better way

of doing it to the future.

Mr. BRYANT. Yes. I think maybe I’m talking to the policymakers,

and I think that’s good and it may ultimately be that the courts

and the various State legislatures decide this. Ultimately the

courts decide these kinds of conflicts of law.

Mr. English, you’ve had experience on all sides of this.

Mr. ENGLISH. I’m afraid so, and probably no group is effected

more than electric cooperatives as far as land wise, 46 States

across this country on this particular issue.

I think this goes to the heart of a real question that this committee needs to answer, and that is the question of what is the objective of this legislation? Are you attempting to deal with all

transmission, no matter whether it be local, regional or national?

Or are you truly trying to do something along the lines of identifying what needs to be a national grid? And if you’re trying to do

that, this gets into the question of whether or not you’re going to

identify what portions of the existing system and how that needs

to be linked up with other regions of the country to develop that

grid. That would narrow considerably what you’re talking about in

the area of eminent domain. And I imagine that makes it far more

acceptable to the States. Certainly makes it more acceptable to our

members, and I would think to a lot of members of this committee.

But if you’re going to just simply have a blanket FERC provide

eminent domain as the final decider of this issue for transmission

no matter what its purpose, no matter where it’s built, then I think

that that’s a different matter. And, obviously, that takes this bill,

makes this a much more narrow bill and that may not be what this

committee wants to focus truly on the national aspects of the transmission issue and leave the rest to the States.

Mr. BRYANT. Congressman, I’d ask unanimous consent for 1 additional minute so that the gentleman on the end can respond. Unanimous consent.

Mr. SCHRIBER. Thank you, Mr. Chairman.

Congressman, I would point out that the Natural Gas Act provides for FERC State joint participation. In Ohio, as I testified, I

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believe we have a fairly broad authority to site facilities, we have

engaged in those joint proceedings with anyone at the Federal level

which is provided for. And I also pointed out, and I think you can

imagine that in Tennessee if a landowner was exceptionally upset

or aggrieved, you may get a letter. But I can assure you that your

State authorities would really feel the heat, as we would in Ohio.

So I would propose, as I have proposed that the States who are

very sensitive to landowner issues, who are sensitive to—very sensitive to the allocation of our land resources or the appropriate authorities, and I think that on a joint basis either regionally or regionally and with Federal participation a lot of the eminent domain, a lot of the siting problems can be overcome.

Mr. BRYANT. Thank you.

I thank the chairman for yielding me that additional time.

Mr. LARGENT. The gentleman’s time has expired.

Recognize the gentleman from Ohio for 5 minutes for questions.

Mr. Sawyer?

Mr. SAWYER. Thank you, Mr. Chairman.

Let me just take a moment to thank Chairman Barton for this

hearing. I genuinely believe that of all of the hearings that have

been called on this large and complex matter, that this particular

gathering of people in these two panels may represent the central

issues in the entire question of how we go about building a Federal

framework within which to enable all of the things that are going

on in the States.

It is critical to making available the assets necessary to real competition in a variety of regional grids throughout the United States.

And so I want to thank Chairman Barton, and I want to thank

our participants today. There are a lot of unanswered questions,

and I just regret that we don’t have more time today to undertake

some of those questions.

Let me further thank a couple of Ohioans who are here again.

I regret that other matters before elements of this Congress prevented me from being able to be here to help them give appropriate

introduction.

And finally, let me just say that I hope that our panelists this

morning would respond in writing to questions or, perhaps, in conversation in the coming weeks to a much wider range of questions

than I have the capacity to grasp today.

Mr. COOK. Be happy to do that, yes, sir.

Mr. SAWYER. Please. Thank you.

Let me turn to Stan Szwed. You have been involved in setting

up the Alliance RTO. You’ve suggested that the flexibility to set up

an entity that can attract the kind of investment that it will take

to grow and nurture and facilitate real transmission entities. Can

you give us examples of what that means in terms of attracting investment and how FERC authority to mandate RTO participation

would effect that decision?

Mr. SZWED. I think just generally, the Alliance RTO is a structure which is developed around the for-profit independent transmission company where there is an independent owner/operator of

transmission assets. And, in fact, in the development of the Alliance regional organization, we have in fact attracted a strategic investor because of the construct and structure of the model as well

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as trying to provide for opportunity for that strategic investor to

see that the regulatory process would, in fact, hopefully put in

place a reasonable rate program and mechanism for which business

could thrive and survive, and have a longevity and for future investment to be made.

So we’re in that process of development today. And, in fact, the

Alliance in many respects with a few additional rulings from FERC

on a couple of matters that are pending, is well positioned to be

in operation as early as the end of this year. And what I’m concerned about in mandate language or mandate authority is we in

the utility business across so many of our investor owned companies, I think something like 98 percent of the investor owned utility

transmission assets are in some form of developing RTO. If we suddenly start changing the rules and mandating authority, that could

upset a great deal of effort that has gone today and just may not

get to a situation where we are in fact or would have operating

RTOs in place sooner than later.

Maybe just one more comment to add on that. I kind of think

that in the development of all these RTO structures, earlier in my

remarks I outlined what I thought was necessary no matter how

many RTOs there are across the United States. The seven points

that I outlined in my testimony are what we believe are important

to have a successful transmission network and infrastructure in

the United States. And we, the EEI companies, believe that very

strongly.

Mr. SAWYER. Thank you very much.

Glenn English, it’s good to see you.

Mr. ENGLISH. Thank you very much, Mr. Sawyer.

Mr. SAWYER. If we give FERC the authority to ensure the recovery of costs for new transmission facilities, it seems to me that

those entities that take advantage of the FERC’s protection ought

to be subject to FERC’s rules. The question that I would have for

those entities like cooperatives receiving that protection, aren’t

they receiving a significant benefit without any of the attendant responsibilities under the Federal Power Act?

Mr. ENGLISH. I guess the question I have for you, are you talking

about in the construction of transmission?

Mr. SAWYER. Yes.

Mr. ENGLISH. Well, most of the transmission that we have is very

localized, as I’m sure that you know.

Mr. SAWYER. Yes.

Mr. ENGLISH. It’s basically a transmission that applies to our

own membership. We have a great sensitivity about this question

of whether our membership, which actually owns the utility to provide power for themselves, is going to be able to continue to govern

their own asset. We’re a little bit unique and different in that we’re

not third parties that have an investment; we’re people that actually own our own utility. We invest in that utility to provide for our

needs.

If you’re talking about the government coming in and then

breaking that up, that would be much like someone coming in and

telling you we want to get between you and your constituents. And

we want, Congressman, don’t be listening to what your constituents tell you, we want to tell you how we should operate.

81

Mr. SAWYER. Happens all the time.

Mr. ENGLISH. Happens all the time. And if you stay in office, you

don’t listen to them, do you? Because, you know, the issue here I

think is that particular question.

As far as going out and building transmission, keep in mind

we’re very dependent on this transmission system in this country.

We’re probably more dependent than anybody else. Any costs that

are unnecessary, any unnecessary costs going in that system get

passed on to our members. We have great objection of that and concern.

We believe that the judgment of FERC should, in fact, determine

what is just and reasonable. And what we’ve strongly believed is

that any attempt to override that is telling those FERC Commissioners you must rule on something that you feel is unjust and unreasonable. You must provide that benefit.

What we think would make a lot more sense, as I said earlier

in my testimony, let’s broaden out the options that FERC has. Let’s

let FERC use some additional judgment. But what this proposed

draft does, it restricts what FERC does. It says you can no longer

use your judgment. It says you must do something that you, obviously, feel is unjust and unreasonable. That’s what we think is unfair.

We’d like to see this opened up. Let’s use the experience of

what’s gone on in this country, let’s use the Texas model, which by

the way this legislation we note does not effect Texas. Texas is exempt as far as the provisions of FERC on the incentive provisions

contained this bill on unjust and unreasonable.

We think that we ought to go the other way and let’s take the

Texas model in which they’re building three-quarters of a billion

dollars worth of transmission this year, going to build another billion next year, it’s scheduled; let’s take that model and bring that

into FERC and give FERC the opportunity to use that option.

Mr. LARGENT. The gentleman’s time’s expired.

Mr. SAWYER. Then I will yield it back.

Mr. LARGENT. I’m going to yield myself 5 minutes to ask a few

questions.

It seems to me the issue that, Mr. English, you raise is one that’s

been handled in past pieces of legislation where we were able to

craft some language that separated the definition of what is distribution versus what is transmission as it relates to cooperates

that you all basically signed off on it. It seems to me that what I

heard you saying earlier that’s the same sort of mindset that we

should have when it comes to developing this national grid versus

trying to give FERC authority over every line that carries electricity, is that correct?

Mr. ENGLISH. To a certain extent. I think the real issue we have

is a practical one. You know, FERC’s very limited as far as the resources they have available.

You know, one could really look at this; if we were interested in

deluding the influence of FERC, if we wanted to try to make sure

that FERC was ineffective, let’s just give them a lot of jurisdiction

and no more resources to do it. We’ll spread them so darn thin they

can’t get the job done under any circumstances. And I think that’s

where we are.

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This bill gives FERC a lot more responsibility. Now the question

is do we want FERC to do that job and do it well with limited resources, recognizing the budget problems and the difficulty if we’ve

got? If so, then it comes down well what’s really important from a

Federal level in dealing with this transmission issue? And what we

would suggest is it makes a lot more sense for us to truly develop

this, and I’m not suggesting under any circumstances any government money be used on this, keep in mind, but along the lines we

did the interstate highway system.

We’ve got the equivalent today of what was the old two lane system, State highways existed back in the early 1950’s. We reincorporated a lot of State roads, upgraded those with new standards

and made some connections in linking those roads together and developing an interstate highway system. We think that that makes

an awful lot of sense concept wise, and we think that FERC should

have that responsibility. FERC should have the final say so. We

think, just as we did with the State highway system, that you

allow the States or the local folks to have a lot of input as which

roads should be upgraded, what should be incorporated into that

and develop this system in partnership with the States. And I

think they would welcome that. That gives FERC a job they can

do.

If we’re just going to go willie nillie anything that anybody can

define somehow as being transmission of this country, no matter if

it only goes a mile, and we’ve got some that would only go a mile

that could possibly fit into that definition and we’re going to give

FERC jurisdiction on it, FERC’s going to be spread so thin on——

Mr. LARGENT. Can you sum up? I only 5 minutes. Thank you for

your comments.

Mr. ENGLISH. But you’re right.

Mr. LARGENT. One of the things that I wanted to begin my questions with was recalling a committee hearing we had last year with

what were then the sitting FERC Commissioners. And I asked

them the question can any of you give me a definition for just and

reasonable rates. Not one Commissioner could give me a coherent

definition of what constitutes a just and reasonable rate. Not one.

These are the Commissioners that we’re wanting to—some of us

want to give them more authority, some of us want them to give

them less authority. You know, less authority in transmission, but

all of you say we need to give them more authority on reliability

standards.

So I guess I would start there when we deal with transmissions.

Somebody in their testimony, I can’t remember where I saw it, said

that we could need as much as $56 billion worth of investment in

new transmission in this country. $56 billion. Why don’t we have

that? Why are they not out there building transmission lines? Why

are we so far behind the power curve, so to speak, in new transmission?

I think if I asked a panel nodding question, do you all agree we

need more for transmission in this country, all of you would nod

yes we definitely need more transmission. But then a number of

you on the panel said that we don’t want to incentivize by giving

higher rates of return on transmission construction. So we have

sort of a conundrum here in that, you know, Marty, you talk about

83

the fact that the current constraints boost profits. So the people

who could benefit by having new transmission really don’t want to

do transmission, the generators, because they’re actually getting

higher rates of return on their generation asset because there’s no

transmission. And then the people that may be third party, you

know, that want to develop a transco and be independent transmission owners, they’re not really going to do it because the risk

that’s there that Mr. Vesey pointed out, they see as being as higher

than the rate of return that’s currently being granted by FERC.

So, there is the conundrum. We have a huge need for additional

transmission, but we nearly a consensus, at least a majority of the

panel that say but don’t give them any higher rates of return on

their transmission because, you know, it’s a burden on consumers.

So where do you go from there?

Mr. Kanner, I guess I would like to ask for your comments.

Mr. KANNER. Well, I appreciate that, Congressman.

I think in part it’s separating the transportation function, that

highway system, from the merchant function. Having RTOs with

effective planning and construction responsibility is a clear step in

the right direction where they’re not looking at the merchant aspects and whether it boosts generation rates and profits or not.

They also could conceivably say we’re going to bid it out. We’re

going to find whoever is willing and able to build a transmission

link at the cheapest possible rates and not we’re going to just say

whoever will do it, we’ll give them the maximum amount; rather

say whose willing to do it for the least amount.

There’s an independent transmission company in Wisconsin that

is building new facilities. And my understanding is the rating

agencies have said that’s a low risk venture. So it seems like there

is a model that can work, we need to get there.

Mr. LARGENT. Mr. Vesey, I give you just a moment to comment

on that problem.

Mr. VESEY. Thank you. And it a problem. And I think the issue

comes down all rates are incentive rates. I mean, it’s not more or

less the formation of capital and this question about what the right

level is. If we had none of these other risks, if we would resolve

all the siting issues and make the siting clear and expeditious, if

we were to resolve the questions around RTOs and the question of

independence, then you probably would see the current levels of return being appropriate to bring that capital to bear. So there’s two

ways to deal with this. You either can raise the reward or you can

lower the risk; all that’s within the purview of the things we’re

talking about here and should be part of the conversation.

I think the other part is that one has to be cautious that don’t

only think about incenting investment to build new capacity. There

are a lot of ways to provide addition transfer capability in the

transmission system. We have talked not at all about the introduction of new technologies into transmission, because there is no incentive. In current rate of return regulation a utility will not get

the benefits of those efficiencies, only makes money on capital investments, so why would anybody whose in the transmission business make an investment in something that increases the efficiency, therefore lowering costs, when they have no return at all?

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So, one of the points of my testimony is we have to think about

this question of motivating behaviors, not looking to specifically induce capital to build new lines. It’s a much broader conversation

we have to have. And when we restructure the question that way,

I think then you can find a balance because you can the providers

of this new capacity working in tandem with their customers,

which is critical.

Mr. LARGENT. Thank you, Mr. Vesey.

My time’s expired.

I believe Mr. Wynn from Maryland is next.

Mr. WYNN. Thank you, Mr. Chairman.

I would like to begin by thanking our subcommittee chairman

Mr. Barton for his generosity in agreeing to work with me on the

subject of reliability. I sincerely appreciate his offer and look forward to working with him on this issue.

I’d like to begin by asking Mr. Harris, and I don’t think this is

too far afield, Mr. Harris, you can correct me if I’m wrong. I understand that PJM has some concerns regarding a recent FERC directive to join the Northeast RTO. If that is true, would you articulate

your concerns? We’ve heard testimony that there are apparently

some seams in the system that they were attempting to correct via

that directive.

The second question has to do with my concern regarding reliability. And you seem to object to the notion of a self——

Mr. BARTON. Will the gentleman suspend? We want to thank Mr.

Schriber or Chairman Schriber for being—we understand you have

a plane to catch. If there are questions for you, we’ll put them in

a written statement and get them to you. But thank you for your

participation.

Mr. SCHRIBER. Thank you very much, and thanks for having me.

Mr. BARTON. Certainly.

Mr. WYNN. If, in fact, you object to the notion of self-regulating

entity which would have FERC oversight, would you kind of articulate your concerns. And then if the other panel members who have

an opposite view would support a self-regulating entity for this

purpose, I’d certainly welcome that.

So, why don’t we proceed with your, Mr. Harris?

Mr. HARRIS. Thank you, Congressman.

Take on the first issue. PJM is currently the only approved RTO

in the United States that’s operational. With PJM West we’re close

to 70,000 megawatts, seven States, plus the District of Columbia.

We have competition that works. We have a regional planning protocol that works.

There is concern when you talk about enlarging that or merging

that that what we have that works so well may deteriorate if you

try to bring in other areas or other regions too rapidly or too quick.

And that is something that needs to be looked at as the large RTOs

develop. And that was our concern and what we’re discussing with

the State of Maryland, and I think those are valid questions that

need to be answered.

On the issues of where we are going with the standards. Again,

let me just state the 3 or 4 points here.

The electric system must be thought of like an ecological systems; it touches everyone’s life and all elements of it. It isn’t simply

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transmission. Generation and transmission are in competition. In

planning, you can have a generation solution that may be more important than the transmission solution and more viable for the

public good.

What we’re about here to ensure that customers of a value of

competitive price in generation, and transmission is a very meaningful role in that. So the key is having the plan that allows that

to take place so everyone can participate and understand what’s

going on.

The standard setting that needs to take place effects everything.

Ninety-eight percent of the outages on a system are distribution

outages. They are under State control, not FERC control or even

NERC control. So when you talk about a standard in the 21st century, you need to develop a standard that is fully consistent with

retail choice program and the State needs, the bulk needs, the fuel

needs, the generation needs and all of this in a holistic way.

So our concern with the proposal is that it tends to try to carve

out a single element and create some organization around that. We

need to move to the 21st century and look at a holistic solution.

Therefore, we think that the better way to do it is to allow FERC

to issue some sort of rulemaking and through a FERC process create the appropriate body that could look at these things holistically

in a way that you can then provide standards that FERC can approve.

Mr. WYNN. Can I just jump in and say could not a regional entity

such as you describe be a subset of a self-regulating organization

such that the regional entity would purpose to the self-regulating

organization rules appropriate to that region, the SRO could then

approve those and if FERC did not object, proceed and then have

the kind of regional impact or input that you’re describing?

Mr. HARRIS. Yes, sir, that is one of the ways that this could be

done. There are other ways, and that’s when we need, I think, rulemaking way that FERC can come up with what would be appropriate to deal with the issues that we have and be flexible enough

to adapt as technology and the learning curve grows as we develop

this industry of competition.

Mr. WYNN. Are there other members of the panel that want to

comment on that issue?

Mr. ANDERSON. Mr. Wynn, if I could comment very quickly.

I think one of the points that Mr. Harris made, and several others have made, is that increasingly we recognize now that reliability cannot be treated as a stand-alone issue. It’s overlapped

with the commercial practices. It’s absolutely incredible. Every reliability rule has commercial practice implications, just like very

commercial practice rule has reliability implications. They need to

be dealt with together.

One of the big problems with NERC is that NERC deals only

with reliability and the commercial practice implications of it are

second hand, their step-child sort of thing. Now, NERC could solve

that by expanding itself to not be just a reliability organization, but

to be both a reliability and a commercial practice organization, or

on the other hand the Gas Industry Standards Board could expand,

as they say they’re going to do, and create an Energy Industry

Standards Board and deal with both reliability and commercial

86

practices. To me, one or the other, either one of them would be a

good way to start, but neither one of them now are doing it in this

holistic way. You got to take both of them.

We believe very, very strongly that both have to be worked on

together.

Mr. BARTON. The gentleman’s time, unfortunately, is expired.

The Chair would recognize the gentlelady from Missouri for 5

minutes for questions.

Ms. MCCARTHY. Thank you, Mr. Chairman.

And thank you for this very important hearing. And I appreciate

all the input we’re getting today, very valuable input from the panelists. And I’m going to give you full disclosure before I ask my

question.

Before joining the Congress, I served in the Missouri State Legislature for 18 years. And I was President of the National Conference

of State Legislatures before coming to Congress. So, I very much

like what I’m hearing from several of the witnesses about the fact

that we, as Mr. English put it so well, you know, we have an existing system that works, how do we link it to the rest of the country?

What is our real objective here? And I think the objective is to create some sort of dispute resolution that will work.

I’m going to tell you about a company in my State and region,

Ameren, which is working effectively in a bistate way with Illinois.

Everything’s going smoothly. But should they want to put in a new

line or make any other improvements or opportunities, there’s really no place for them to go if Illinois disagrees.

And so I think the question we’re grappling with is how do we

put in place some sort of body that will resolve that for us? And

coming from a State legislative background, I would like to see that

body out there in the States.

So, I was very intrigued by Mr. Schriber’s comments and also

Mr. Harris in your text about some sort of voluntary regional body

that permits the States to work in an interstate way to resolve

this.

And I wonder if any of you on the panel could come up with the

mechanisms that they would need specifically to do that? I would

very much appreciate that.

And also, a second sort of thought for someone to ponder. You

know, Ameren has invested and is investing about $25 to $30 million toward improvements in its efforts in those two States. So

when we talk about incentive rate structures, I worry because

those companies that choose not to invest in their transmission infrastructure seem to me will be rewarded through incentive rates.

And so what does that say to companies that stepped up to the

plate and did it without being told to?

Mr. HARRIS. Yes, ma’am.

First of all, let me go back to the planning process the mid-Atlantic that was developed in a cooperative way with all of the States,

the environmental community and the transmission companies. It

took us 2 years to develop that process. It is a cooperative process

that has been approved by the FERC. It clearly delineates what the

accounting and the cost responsibilities are among the entities. It

is just absolutely crucial to have regional planning protocol.

87

Now, we recognize that we would not have all of the answers to

the world’s problems, so therefore we’ve engaged in a process, we

entered into an arrangement with each of our States. And each of

the States meet periodically and regularly with our independent

board of our RTO and we discuss the issues that are ahead of us

as we move forward to the next levels of evolution. And having an

inner active way to deal with the issues and to move forward is a

way that we address the problem.

What we’ve discovered is that when you really get the details of

the information and allow public input with ubiquity of information, that the common sense of good people can prevail. We are

building construction. Generation is competing. Things are getting

done.

Do we have all the answers? No, but where we stand today is

something that is working. We don’t see a large need for major

transmission in the next 5 to 10 years. We will continue to work

with our States very carefully in this arrangement where the

States have direct input into the independent board as we try to

engage the problems.

So I think seeing it as a holistic thing that effects everyone and

as a process as we move to the future is the wise way to go forward.

Ms. MCCARTHY. Has FERC played any role as you’ve moved forward with this independent board?

Mr. HARRIS. In only two ways. First of all, they approved our regional transmission expanding protocol, which bound all the companies that wanted to play with it. And the second thing when they

approved us an RTO, they also directed that we consider the economic consequences when we evaluate transmission plans instead

of just the load growth and the needs, but we also have to look at

the economic consequences of congestion and other things, and

we’ll integrate that into our plan.

Ms. MCCARTHY. Thank you.

Would anyone else care to comment? Yes?

Mr. VESEY. Very briefly. I think that we shouldn’t leave the impression that no transmission is being built across the United

States. In fact, significant capital is being spent, but it’s mostly in

continued maintenance and upgrade of existing facilities.

The challenge becomes when you’re building a line between

States interregionally, and that’s where the highest risk reside.

I think that we’ve come to the point where we’re actually managing our transmission infrastructure on a just-in-time basis,

which is one of the reasons why the critical points that were made

earlier, why there is such an impact in terms of reliability and

commercial issues. Because we’ve got to the point where that’s how

we run the systems. There’s a clear tradeoff that we’re making in

terms of our ability to put new capacity in the ground versus the

way we’re going to operate these systems to keep the systems up.

So the only points here are that there are—it’s not no transmissions being built, there are some who are building them and in

some instances the risk and the reward is appropriate. In others

it’s not, the balance isn’t right and that happens when people have

to site, obtain new right away and actually site new transmission

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line and are being intrastate or interregion, which is a critical issue

as we’re talking about the bulk wholesale markets.

Ms. MCCARTHY. So you’re thinking that the incentive rate structure is for those opportunities that are not as rewarding and don’t

attract the investors as much as they should?

Mr. VESEY. Again, I think the issue is that all rates are incentive

rates. The points of the issue is in some new project development,

the risks are definitely higher than others. Two of those sources of

risks are the inability of—the difficulty of siting process between

which cross State boundaries or regional boundaries. And the second one is the lack of clarity on how these RTOs, transcos, ISOs

are going to work effectively to produce revenues for their businesses. We don’t have an effective business model yet because that

rules aren’t finished.

In those instances, to make investments that either cross those

lines or involved in one of those forming up forming organizations,

obviously the risk is if you buy the market is being higher than the

return.

Ms. MCCARTHY. I just wouldn’t want to put incentive rates in

place that would discourage investments from companies like

Ameren who stepped up to the plate. Thank you.

Oh, yes, do I have time——

Mr. ANDERSON. Ma’am, one just quick comment on your regional

bodies. As the one consumer group that’s here at the table, although we represent large consumers, we are a consumer group.

Consumer groups, we are very concerned about creating a third

forum or a third entity that we have to participate in. Right now

we have to participate at the State level. We also have to participate at the Federal level. It takes tremendous amounts of resources

to participate in each one. And to add a third layer is a very difficult thing, and I urge you to do that very cautiously.

Ideally, would be to create a regional body which takes over the

State roles then in siting, but the States don’t want to give that

up either. If the States don’t want to give up their siting authorities, which I well understand for a whole lot of different reasons,

I urge you to be very careful in creating a regional body that then

consumes a lot of resources also.

Ms. MCCARTHY. Thank you.

Thank you, Mr. Chairman.

Mr. LARGENT. The gentlelady’s time has expired.

Mr. SAWYER. Mr. Chairman, I would ask unanimous consent, Mr.

English looked like he wanted to make response.

Mr. ENGLISH. Yes, thank you very much Just very quickly.

I think that we’re making a couple of errors here on our assumptions. One is this is a judgment issue. FERC has all the authority.

They can double rates, triple rates, quadruple rates if they find

that to be just and reasonable.

The second thing, is we’re ignoring one big problem, and that is

it is not in the interest of a lot of present transmission holders to

see new transmission built, to see bottlenecks eliminated and roadblocks eliminated. Because it all comes down to the fact that right

now that’s part of the monopoly aspect, that’s where they can make

their money, that’s where they can control the generation, that’s

where they can prevent this competition on wholesale power that

89

I understand that that’s what this committee is about. And unless

you address that to simply increase the rewards, that doesn’t overcome what these people really find to be in their best interest. And

we’ve got to find out some way in which to break those roadblocks.

Mr. SAWYER. Mr. Chairman, Mr. Szwed.

Mr. SZWED. Yes. I just want to take exception to the fact that

there seems to be the allegation that we’re not building transmission because it’s advantaging our generation. And I just want

to remind you all that for the last 5 or 6 years utilities who own

both generation and transmission have been under a code of conduct obligations with regard to Orders 888 and 889, and that’s further promulgated by Order 2000 and the move to RTOs.

I think, you know, just going back, you know, we have been

building transmission. My company alone spent $35 or $35 million

just last year in transmission to connect customers, to facilitate

equipment repairs. I’ve got a request pending to put a large transformer in now that’s $5 million alone.

The issues goes back to what a lot of what Mr. Vesey was talking

about. We’re trying to create a more robust national marketplace

and the transmission system we have today wasn’t built for that.

It was built to serve local load, connect neighbors and provide for

reliability. What we’ve got to do is transform that, and that needs

new investment.

It’s going to take new investors because the rules that we’re operating under require independence for all this today. And we’d

really like to see new investment, new independent investment

come in and be done. And that requires the right kind of rates, the

right kind of pricing, the right kind of returns.

And I’ve heard here today the discussion of transmission is a low

risk situation. I think you got to put it in the context of what it’s

all about. When we separate transmission from the rest of the

vertical integrated utility, it takes on a different risk profile because its sole business is providing transmission service, and it has

risks. And just to say that returns ought to be low because this is

a low risk type proposition, I think we have to think about it. The

risk reward ought to be commiserate with the comparable kinds of

risk opportunities or possible kinds of other industries that have

similar or equal risk, and the returns ought to be that. We haven’t

seen the kind of returns from FERC that recognize that yet, and

that needs to be recognized as we establish the pricing reform that

needs to be done.

Mr. ENGLISH. Focus on reducing the risk, Mr. Chairman.

Mr. LARGENT. We’ll return to the regular order here and recognize the gentleman from Wisconsin, Mr. Barrett for 5 minutes.

Mr. BARRETT. Thank you, Mr. Chairman. And I apologize for not

being here, so some of my questions may be redundant.

I think some of you have mentioned a situation in Wisconsin,

and that’s the State that represent. And earlier this week I was

home and talking to a farmer in the State of Wisconsin. The Wisconsin Public Service Commission has just approved about a 240

mile line from Duluth, Minnesota to Wausau, Wisconsin. And the

concerns that this farmer had was evidenced by a question that

was asked of the current Governor, who was asked whether it was

fair to move this transmission line over a number of farms that

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had been there for many, many years. And the response was we’re

not going to let a couple of farmers stop this transmission of electricity into the State.

The farmer’s argument was I thought an interesting one, in that

he said the power of eminent domain has traditionally been used

for the public good in the sense that you have a company that is

granted the public domain. Generally in the past if it’s been granted, it was either to a regulated industry where the profit was monitored or some other entity where there is interaction between the

government, the State government and the company itself so that

the greater good would be recognized.

His argument was that this is different, that these transmission

companies are essentially simply for-profit companies and why

should the law of eminent domain or whatever laws are going to

be used in this situation allow a for-profit company to take the land

away from a for-profit dairy farmer who is supplying milk to the

people in this country?

If one or two of you can respond to that, as if I were the farmer

sitting there, as to why that should happen?

Mr. English?

Mr. ENGLISH. And that farmer’s probably a coop member, so he’s

probably one of our members. And I think he makes an excellent

point.

The real issue I think you still come down to is this question, you

know, is this something that is necessary for the overall public

good. I think what you categorize as eminent domain and the use

of eminent domain and the overall purpose of it, I think you’re

right, we do have to go back to the heart of that and how do we

use it. And it has to be done very, very selectively, very carefully.

It has to be something that is necessary for the overall good. And

that’s certainly true, I think, whenever you’re providing that on the

Federal level.

The States should be allowed to deal with this issue. It’s only if

it’s absolutely necessary, you know, this is a final—if it can’t be resolved any other way that the Federal Government says it has to

be done for the overall national good. But that should be a last resort. Last, last resort.

Mr. BARRETT. Well, and I think the debate we’re having here,

though, exemplifies that. The discussion, and I understand that the

draft bill has some flexibility allowing the Federal Government to

come in and take this over. But I can tell you, not with this farmer

this week, but with a farmer that I met with in the last 2 months,

walking into his farm—their farm, a man and woman’s farm, I felt

like a character out of an ‘‘Erin Brockovich’’ movie. Someone just

coming in from the Federal Government who didn’t care at all

about this poor farmer in Edgar, Wisconsin whatsoever. And we

were going to use whatever methods we could to put this power

line in.

So, I am concerned about the provisions in here that give the

Federal Government more authority, because there are people who

feel this disenfranchised from State government because the public

service commissioners wouldn’t even come and hold public hearings

in their part of the State of Wisconsin. And now we’re being told

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well those people are too close to you and we’re going to remove

you even further from the decisionmaking power of this democracy.

And I think that’s one of the reasons you’ve got the western Governors—because I think that this is an offshoot of the whole issue

of private rights and people feel as though the Federal Government

is going to come in and just squash them. And I haven’t heard a

compelling reason why that isn’t the case with the provisions in

this draft bill, and I’d be interested to hear someone who can defend those. Someone who wants to defend those. Mr. Szwed?

Mr. SZWED. Just a general comment. I think, as I said in my testimony, I think we are looking toward the States as the primary

vehicle for accommodating that. And, again, the language really

provides for FERC as the backstop. And I think, you know, I sometimes feel like we’re between a rock and a hard place on this,

maybe even more so when Chairman Schriber was here, because

it’s a tough situation between State and Federal. But as we move

toward larger regional marketplace that has an interstate nature

to it, obviously we’d like to see the States resolve the issues of

siting first. But at some point there seems to be the need to have

a backstop and some entity to go to or some authority to go to to

resolve the issue if in fact that is important for the greater good

of the competitive region of the electric marketplace.

Mr. BARRETT. But the legislation we’re talking about, under the

Natural Gas Act, when FERC acts don’t they have to have at a

minimum of certificate of convenience and necessity for the public

good? And I don’t see that here. Here it’s just whatever’s good for

the transmission company and no time at all for the public good

or public necessity.

Mr. SZWED. Yes, I believe that’s the case with the gas side. And

even in the case of Ohio where in Ohio if you take Ohio as a microcosm where years ago we used to do this county-by-county sort of

thing and now it’s rolled into the Ohio Power Siting Board, there’s

still in that cases also a requirement for the need and the benefit

of the facility as well.

Mr. BARRETT. Shouldn’t we need that in this situation?

Mr. SZWED. And I would think that we probably would want to

demonstrate the need for the facility and the reasons, and the benefits that it would provide, right.

Mr. BARRETT. I yield back, Mr. Chairman.

Mr. LARGENT. All right. With that, I think everybody has had a

chance to ask questions.

I want to thank all the panelists for your time. Many of you are

familiar faces that have been contributors in panels in the past. We

want to say thank you to all of you for your participation.

We’ll convene the second panel at 1. Thank you.

[Whereupon, at 12:31 p.m., the subcommittee recessed, to reconvene at 1 p.m., the same day.]

Mr. BARTON. If our panelists and our audience will take their

seats, we’ll start our second hearing of the day.

As soon as we get order, we’re going to let Mr. Norwood make

some introductions and then begin the hearing.

We know that we have witness that’s coming by train, I think

from Baltimore, he may be a little bit late so we’re going to go

ahead and start.

92

The Chair wants to thank this panel for coming back. We also

want to thank you for fastforwarding an additional hour. And we

especially want to thank Mr. Franklin, because I’m told that he’s

been under the weather and is coming in spite of somehow suffering from a cold or the flu, or something like this.

Our second hearing today is Electric Transmission Policy: Regional Transmission Organizations, Open Access, and Federal Jurisdiction.

The hearing will come to order.

The Chair would recognize Mr. Norwood to make a brief introduction, and then we will begin to hear testimony.

Mr. NORWOOD. Thank you very much, Mr. Chairman, and I commend you on your selection of witnesses. Anybody from Texas that

has enough sense to have two people from Georgia on the same

panel, I know I have a great deal of respect for. But I do appreciate

your leadership on these issues and would like to commend you

and the ranking member for the selection of the witnesses.

If I may, I’d like to take this opportunity to recognize and welcome two gentlemen from the great State of Georgia who will be

testifying on this second panel today. Robert Johnson from MEAG

Power and Allen Franklin from Southern Company.

Thank you, gentlemen, for being here.

Robert Johnson is the President, Mr. Chairman, and Chief Executive Officer from MEAG Power headquartered in Atlanta. MEAG

Power is a public generation and transmission corporation, as you

know, that provides power to 48 Georgia communities serving nearly 750,000 Georgians, many of whom are my constituents.

With over 24 years in the electric utility industry, Mr. Johnson

has held several management positions at MEAG at one time or

another, having overseen both engineering and operations. In addition, Bob serves on the Board of Directors for the Energy Authority, one of the largest power marketing joint ventures among public

power organizations that is located in Jacksonville, Florida.

Bob received his bachelor of electrical engineering from Georgia

Tech in 1978 and he’s still a good guy, and his professional engineering license in 1983.

Also testifying before our second panel today is a good friend of

mine, Allen Franklin, Chairman and President and Chief Executive

Officer of Southern Company, also headquartered in Atlanta. Previously Mr. Franklin was President and Chief Operating Officer of

Southern Company, and prior to that served in the same capacity

at Georgia Power Company, Southern Company’s largest subsidiary.

Allen received his bachelor’s degree in electrical engineering from

the University of Alabama, and a master of science from the University of Alabama, Birmingham.

Mr. Chairman, both of these gentlemen are respected leaders

within the electric utility industry and within the Georgia community, as both serve on the Board of Directors for the Georgia Chamber of Commerce.

Bob and Allen, I’m very happy to have you here today before this

committee, and I look forward to hearing each of your testimonies

and perspectives on these critical issues affecting our national energy policy.

93

Thank you, Mr. Chairman.

Mr. BARTON. Thank you, Mr. Norwood.

Does Mr. Boucher wish to make a brief opening statement before

we begin? Okay.

We want to welcome this panel. And, again, thank you for your

attendance. We’re going to start with Mr. Bennett and go right

down the line.

Mr. Bennett is a Commissioner of the New York State Public

Service Commission. We know it’s been a very difficult time for you

the last several weeks because of what happened at the World

Trade Centers. We really appreciate your attendance today. We

know that had to be difficult for you to take away from your duties

in New York to come and testify before this subcommittee.

Your statement’s in the record in its entirety, and we would recognize you for 5 minutes to elaborate on it.

STATEMENTS OF JAMES D. BENNETT, COMMISSIONER, NEW

YORK STATE PUBLIC SERVICE COMMISSION, ON BEHALF OF

NATIONAL ASSOCIATION OF REGULATORY UTILITY COMMISSIONERS; ALLEN H. FRANKLIN, PRESIDENT, CEO & CHAIRMAN, SOUTHERN COMPANY; PETER FLYNN, PRESIDENT,

NEW ENGLAND POWER COMPANY ON BEHALF OF RICHARD

P. SERGEL, NATIONAL GRID USA; ROBERT JOHNSTON,

PRESIDENT AND CEO, MUNICIPAL ELECTRIC AUTHORITY OF

GEORGIA ON BEHALF OF THE LARGE PUBLIC POWER COUNCIL; GLENN ENGLISH, CEO, NATIONAL RURAL ELECTRIC COOPERATIVE ASSOCIATION; MARC S. GERKEN, PRESIDENT,

AMERICAN MUNICIPAL POWER-OHIO ON BEHALF OF TAPS;

PETER G. ESPOSITO, VICE PRESIDENT AND REGULATORY

COUNSEL, DYNEGY, INC. ON BEHALF OF ELECTRIC POWER

SUPPLY ASSOCIATION; CHARLES A. TRABANDT, FORMER

FERC COMMISSIONER; AND MICHAEL J. TRAVIESO, MARYLAND PEOPLE’S COUNSEL

Mr. BENNETT. Very good. Thank you, Mr. Chairman, and thank

you for your comments. It has been a hard time for the State of

New York, but everyone in the State is very grateful for all the

support from the Congress and from all the other areas of this

great country.

Actually I’m not here just as a Commissioner from the State of

New York, but also as a representative of the National Association

of Regulatory Utility Commissioners, otherwise known as NARUC,

which is an organization composed of all of the utility regulatory

commissioners in the country.

The written statement of NARUC has been put into the record,

and I’ll just make a few brief comments and, perhaps, add something from the New York State perspective, and answer any questions you might have.

Three basic issues before us today: Transmission jurisdiction, regional transportation organizations or RTOs and open access.

To be brief insofar as transmission jurisdiction, it’s very clear

that FERC has jurisdiction over wholesale rates. It’s the position

in New York State and also of NARUC that the State retain authority to establish retail jurisdiction, and the jurisdiction to set retail rates including the rates for transmission services. And that

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FERC’s jurisdiction should not be expanded to include unbundled

retail transmission service.

Second, the States should continue to exercise regulatory oversight over retail transmission service. As an alternative to State

oversight, the States could be authorized to form voluntary regional

bodies or RTOs to address regional transmission system issues and

FERC should be required to defer to States acting on a regional

basis.

Insofar as retail jurisdiction, it’s our belief that the jurisdiction

should remain with the States.

I think the two major issues here are reliability and pricing. New

York has something of a unique position right now in that we have

an ISO, an independent system operator, which is like an RTO of

one State. However, we are working very cooperatively with New

England and with PJM. And with experience we see that this region will be able to put together a voluntary RTO working on its

own experience and its own knowledge without having the need for

a direction from FERC as to how it should be done.

We would also believe that Congress, if it so elected, should provide for a State commission advisory role and RTO governance that

allows deference to the State commissioners within a region that

reach consensus concerning governance and operational issues.

NARUC does not support charging local retail customers for new

transmission facilities to move merchant plant energy to a regional

grid.

NARUC also has long supported nondiscriminatory wholesale

open access for transmission services.

In conclusion, in the case of existing transmission facilities, the

local retail consumers have born the vast majority of the costs of

the utility’s transmission facilities. It is the utility’s obligation

under State law or FERC approved contract to provide these consumers reliable and affordable service; they should not bear any

unfair burden due to the transition to an open access transmission

regime.

Thank you.

[The prepared statement of James D. Bennett follows:]

PREPARED STATEMENT OF JAMES BENNETT, COMMISSIONER, NEW YORK STATE

PUBLIC SERVICE COMMISSION

Mr. Chairman and Members of the Subcommittee: Good morning. My name is

James Bennett. I am a Commissioner on the New York State Public Service Commission. I am here today on behalf of the National Association of Regulatory Utility

Commissioners, commonly known as NARUC. I greatly appreciate the opportunity

to appear before the House Energy and Commerce Subcommittee on Energy and Air

Quality and I respectfully request that NARUC’s written statement be included in

today’s hearing record as if fully read.

NARUC is a quasi-governmental, nonprofit organization founded in 1889. Its

membership includes the State public utility commissions for all States and territories. NARUC’s mission is to serve the public interest by improving the quality and

effectiveness of public utility regulation. NARUC’s members regulate the retail rates

and services of electric, gas, water and telephone utilities. We have the obligation

under State law to ensure the establishment and maintenance of such energy utility

services as may be required by the public convenience and necessity, and to ensure

that such services are provided at rates and conditions that are just, reasonable and

nondiscriminatory for all consumers.

States have an important stake in how electric transmission services are provided

to retail consumers. The transmission facilities that serve consumers were approved

by State governmental entities, and importantly are being paid for by these retail

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customers. We are, however, keenly aware of the interstate commerce implications

of transmission service and we believe that the issue of transmission jurisdiction is

now properly before the Supreme Court. Accordingly, NARUC recommends that

Congress follow its prudent practice of allowing the Court to rule on transmission

jurisdiction issues prior to taking any legislative action.

States should retain authority to establish retail rates that include transmission

services, and FERC jurisdiction should not be expanded to include unbundled retail

transmission service. FERC should continue to have ratemaking authority for interstate wholesale transactions and should have jurisdiction over transactions between

suppliers and retail customers located in different States. Prior to the unbundling

of rates to permit consumer retail choice, the States set the full bundled rate—including transmission service. This provided customers not only simplicity but a single source of regulatory redress when problems or complaints arose. Now that retail

rates are becoming unbundled in order to allow customers to choose a generation

supplier, such customers are no less in need of simplicity and regulatory oversight.

NARUC believes that the best way to provide that protection is to allow the States

to continue to exercise regulatory oversight over retail transmission service.

As an alternative to State oversight, States could be authorized to form voluntary

regional bodies to address regional transmission system issues and FERC should be

required to defer to States acting on a regional basis.

NARUC supports legislation leading to voluntary formation of Regional Transmission Organizations (RTOs), with deference given to States in RTO development,

including size, geographic scope and configuration, as well as States acting collectively on a regional basis. Congress should develop a mechanism for States to address ongoing concerns in RTO functions after the initial RTO development period,

including reliability, market monitoring, pricing, congestion management, planning

and interregional coordination. In New York, for example we have established very

high reliability standards—particularly in the highly congested New York City area.

These high standards come at a cost but we believe such a cost is miniscule compared to the consequences of a major outage. We believe that the States, working

in conjunction with their RTO, are best able to develop, monitor, and insure effectiveness of such standards. New York has also worked with its ISO to develop sophisticated market monitoring systems and market price mitigation programs that

help prevent the abuse of market power. Because of the unique electrical configuration in New York City, such programs are essential to protect consumers from price

gouging especially during times of extreme scarcity of supply. As the Northeastern

RTO is being developed, we are working with the parties to ensure that these practices continue.

In order to ensure a cooperative working relationship between the States and the

RTOs , Congress should provide for a State commission advisory role in RTO governance that allows for deference to State commissions within a region that reach

consensus concerning governance and operational issues. In New York, PJM and

New England, State commissions have a good working relationship with their respective Independent System Operators. As RTOs develop and electric systems become larger, we need to continue to find ways to have continued cooperation between the States and the emerging RTOs.

At the heart of the issues raised at today’s hearing—RTOs, transmission jurisdiction, and open access—is the relatively new development of merchant generating

plants and the question of who pays to get the power produced by these plants to

the markets where the owners of these plants wish to sell their power. These facilities are not owned by utilities and are not necessarily constructed near where they

are needed. These generation units are not being constructed solely for the purpose

of supplying the electricity needs of the State or region in which they are located.

The main purpose for these plants is to sell power to the wholesale market for the

most profitable price, regardless of where the purchaser is located.

This raises the question of who should pay for any new transmission to get this

merchant power to where it has been sold. NARUC does not support charging local

retail ratepayers for new transmission facilities to move the merchant plant energy

to a regional grid. In New York, for example, new generators are responsible for the

costs of transmission lines necessary to connect to the grid. In addition, any grid

improvements made necessary solely related to the new generation are also paid for

by the generator. Any other improvements are paid for by the transmission owner

and passed through to all users of that transmission system.

In the case of existing transmission facilities, the local retail consumers have

borne the vast majority of the costs of the utility’s transmission facilities. Because

the utility’s obligation under State law or FERC-approved contract is to provide

these consumers reliable and affordable service, they should not bear any unfair

burden due to the transition to an open access transmission regime. We clearly exVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00099 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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pect that the new RTOs working with the States will develop sound interconnection

policies that fairly allocate the costs of new transmission facilities between generators and transmission users.

In closing, NARUC has long supported non-discriminatory wholesale open access

for transmission services. State Commissions, however, must retain the authority to

protect retail consumers by ensuring that they are not unfairly burdened by financial and environmental costs that ought to be born by other stakeholders. Further,

States must continue to be deeply involved in RTO development, monitoring, and

price mitigation.

Thank you for giving me the opportunity to appear before you today. I look forward to answering your questions.

Mr. BARTON. Thank you, Mr. Bennett.

We’d now like to hear from Mr. Allen Franklin, who is the CEO

of Southern Company.

And, again, we appreciate you coming since I’ve been told that

you’ve been a little bit under the weather.

Your statement’s in the record, and we’d ask you to elaborate for

5 minutes.

STATEMENT OF ALLEN H. FRANKLIN

Mr. FRANKLIN. Thank you, Mr. Chairman.

Let me say, first of all after hearing Mr. Bennett’s testimony, I

largely agree with the points that he made. Let me add just a moment or state just for the record our corporate situation, which I

think helps explain our position on a lot of these issues.

At this point about 90 percent of all of our net income is regulated by the States. About 10 percent is related to our participation

in the wholesale market. So the big part of our business is still

State regulated related to retail customers, but wholesale is important because it’s a significant part of the growth of our company.

For that reason, because retail is so important, we tend to be

very sensitive to what our State commissions think, and we tend

to be very sensitive to how different changes to the industry effects

our retail customers.

Let me also set the stage for the current state of the electric industry in the southeast. Unlike other parts of the country, there is

plenty of generation in the southeast. There’s massive amounts of

competitive generation under construction. In fact, we expect the

capacity to double in our service area in the next 5 years producing

much more generation than will be needed to serve local load.

A bigger issue with us is not enough generation, there’s plenty,

but the huge amount of transmission that’s going to be required to

move that generation into the market and outside the southeast.

We’re currently projecting that over the next 5 to 6 years we’ll

spend about $6 billion of additional capital for new transmission.

That will triple the amount of investment we have in transmission.

It took 80 years to get to $3 billion, in the next 6 years we’re going to be at $9 billion. That will create a 10 percent rate increase for

our retail customers, which is a concern to us and, obviously,

through our commission.

We intend to build the transmission that’s required, and take

that obligation seriously, but there are some FERC pricing issues

I’m sure that were discussed this morning that make this transmission requirement much more severe than it should be. And the

primary problem is that transmission pricing is not distant-sensitive, which results in generation being located much further from

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load centers than it should be, which increases cost and reduces

the reliability of the system. That’s a problem I hope that can be

addressed.

Now moving to RTOs. In my judgment RTOs are a good idea if

done properly. I think their time has come. And I think FERC

Order 2000 that was issued in late 1999 was very much on the

right track. It laid out standards and expectations, and it left it to

utilities and State commissions to move the process forward.

We were making great progress in the southeast in developing

an RTO structure in the size and the scope along with eight other

public power entities to form a large, what I think would have been

a very effective RTO in the southeast. That was going extremely

well until FERC issued an order in July that in essence stopped

that process in its tracks. Since that time there’s been a great deal

of confusion about the direction RTOs would take in the south.

Where FERC goes next is not clear, but it’s certainly a possibility

that they would mandate not only the size, but the structure of the

RTO. That’s the wrong answer, in my judgment, from our standpoint in the southeast.

First of all, I think they’d take the wrong structure.

Second, it will cause public power to opt out, and in our part of

the country it’s critical that public power participate. There’s been

a severe State backlash, States all the way from North Carolina to

Louisiana have objected to the FERC direction. It makes the nondistant-sensitive pricing worse, simply because an RTO is larger.

Mr. Chairman, I think there is a relatively simple solution to the

current situation. I think if we can get back on the pre-July track

that we’re on in the southeast, and if Congress can help us do that

and FERC can help us do that, that’ll be a plus. If FERC can work

on their pricing and make it distant-sensitive, that will be a big

plus, and I would encourage Congress to do what it can to help

FERC move in that direction.

I want to also discourage Congress at this time from giving any

additional authority to FERC to mandate RTOs, to mandate divestiture of generation or to take additional authority from the States

on bundled transmission rates. If that happens, I can give you reasonable assurance that RTOs will form in the southeast. I think

they will form faster and they will perform better.

Thank you.

[The prepared statement of Allen H. Franklin follows:]

PREPARED STATEMENT OF ALLEN FRANKLIN, CHAIRMAN, PRESIDENT, AND CEO,

SOUTHERN COMPANY

INTRODUCTION

My name is Allen Franklin, and I am Chairman, President, and CEO of Southern

Company. Southern Company is the owner of five operating electric utility companies including Georgia Power and Savannah Electric and Power in Georgia, Alabama Power, Mississippi Power, and Gulf Power in Florida. In our southeastern

service area, we have over 35,000 MW of generating capacity and serve over 3.9 million customers at rates that are 15 percent below the national average. Southern

Company is also the largest wholesale power provider in the Southeast. Our service

territories cover 120,000 square miles and we have over 26,000 miles of transmission lines.

Southern Company supports removal of the remaining barriers to robust competitive wholesale markets through federal legislation. We believe continued, fair competition in wholesale markets can lead to added consumer savings while maintainVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00101 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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ing the high level of reliability that consumers have come to expect. We also support

the development of properly sized and configured regional transmission organizations to help further the goal of non-discriminatory access to the transmission system. Southern Company’s operating subsidiaries have been participating in and

benefiting from competitive wholesale markets by putting our incremental generation needs out to bid. This program has been very successful in helping to ensure

that consumers in our service area pay the lowest possible price for electricity— which should be the main goal of electricity policy initiatives. Just last year,

Southern’s operating companies procured 3,000 megawatts of power via long-term

contracts through competitive bids, and we are seeking another 3,100 megawatts

this year. In response to Georgia and Alabama Power’s most recent requests for proposals, generators bid over 30,000 megawatts for the solicitation of only 3,100

megawatts. Clearly a robust wholesale market already exists in the Southeast. The

objective of Federal legislation and FERC policy should be only to enhance what already exists.

Evidence that the competitive market is functioning well in the Southeast can

also be seen by the incredible amount of new merchant generation seeking to build

in the South. We currently have signed interconnection agreements for about 18,000

MW of new generation and have pending requests for another 34,000 MW, all in

our service area. In fact, we are no longer worried about a shortage in generation

in the region. If all of this generation is built, it would more than double the available generation in our area—clearly much more than is needed to serve consumers

in this area. We are becoming more and more concerned about the feasibility of

siting, building and paying for the additional transmission facilities that may be

needed to satisfy transmission service requests from all of these new generators— in addition to what we must build to serve our retail customers.

We are currently investing significantly in new transmission facilities—both to retain reliable service to our own growing load, and to provide transmission services

for merchant generators building in our service area. We currently have transmission assets with a book value of 3 billion dollars. Over the next five years, we

expect to double that investment to 6 billion dollars, just to keep pace with our load

and the generating projects that have already requested service. If we are ultimately able to site and construct transmission for all currently announced generation projects in the region; our total transmission investment could triple in the next

five to six years—from 3 billion to nine billion dollars. Retail customer rates could

increase by 10 percent if we are required to pick up most of these new transmission

costs, as we are under current FERC policies. It is not clear that savings in generation will ever be sufficient to offset these higher transmission costs.

This gives rise to one of our major concerns, as will be discussed in my testimony

today; that FERC has not paid adequate attention to whether or not its transmission access and pricing policies are leading to rational investment in generation

and transmission to minimize the total costs of electric service. Nor has FERC focused on transmission pricing policies necessary to bring forward the investment in

transmission needed to support competitive markets. For example, the rationale

being used for having just a few very large regional transmission organizations

(RTOs) in the country is that by having a single postage stamp rate for a large region, you can have generation built anywhere to serve load anywhere. But this policy ignores several critical facts. First, building generation closer to load results in

a more reliable system. Second, it is significantly less expensive to build gas pipelines to move gas to generators located near load centers than it is to build generation near the gas fields and build new electric transmission to move power to load

centers. Third, FERC’s postage stamp rate policy for electric transmission juxtaposed against distance sensitive rates for gas pipelines gives generators uneconomic incentives to build closer to the gas source—exacerbated by the fact that generators don’t always have to pay the full cost of new transmission required as a result of their location decisions.

These economic distortions exist today—they are simply made worse by moving

to very large RTOs. Before very large RTOs are considered, appropriate transmission pricing for RTOs, ensuring proper locational decisions by generators must

be developed.

We do not know if the Commission’s stated plan for four large RTOs across the

country will best promote economically efficient, secure and reliable wholesale markets, or what costs and benefits to our customers would result from such a scheme.

The Commission has yet to conduct any analysis to suggest what the optimal size

or configuration for an RTO might be, and what is the most efficient and reliable

market structure within an RTO. We believe such analysis is critical to ensuring

our customers and state regulators that our participation in an RTO is in the best

interest of all electric consumers.

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Thus, we are obviously very concerned about the direction of FERC’s transmission

policies. While it may be true that there is a shortage of generation or transmission

investment in some parts of the country, it is not the case in our service area. We

are continually building new transmission facilities. And as noted, we also have a

tremendous amount of new competitive wholesale generation being built in the region. Our rates are well below the national average and we consistently rate among

the top utilities nationally in customer satisfaction. We are concerned that movement to very large RTOs, without careful forethought regarding implementation

costs and without appropriate transmission pricing and investment policies, could

have disastrous results for our consumers in terms of cost and reliability. We have

been taking a careful, rational approach to the formation of regional transmission

organizations to ensure that the overall goals of a competitive wholesale market are

achieved and that our customers benefit.

SOUTHERN COMPANY’S RTO DEVELOPMENT EFFORTS

When FERC issued Order 2000 at the end of 1999 we immediately began to examine what strategy made sense for us in terms of forming or joining a regional transmission organization. The necessary starting point for us was the Integrated Transmission System in Georgia. The Georgia transmission system has been jointly

owned by four partners since the mid-1970’s. The partners are Southern Company

subsidiary Georgia Power, the Municipal Electric Authority of Georgia (MEAG

Power), the Georgia Transmission Corporation—a cooperative utility—and Dalton

utilities—a municipal system. For an RTO to properly function in our region, it will

require at a bare minimum the participation of these four utilities. That is because

the facilities owned by the ITS partners are inter-mingled—sometimes we might

own different wires on the same poles, or their wires will begin where our wires

end. It would be impossible for an RTO to operate our transmission without also

operating the transmission systems of our partners.

Thus, we began our RTO discussions with the Georgia ITS partners. These discussions continued through 2000 and into 2001. Simultaneous discussions were also

held with many other utilities in the Southeast, including all of our regional investor-owned utilities and TVA, and were broadened to include the Alabama Electric

Cooperative (AEC) and the South Mississippi Electric Power Association (SMEPA).

However, Order 2000 required Southern Company to make a filing by October 15,

2000 either agreeing to participate in an RTO or listing the barriers precluding such

participation. Because we had not yet reached agreement with other utilities on the

exact form of an RTO, Southern Company filed by itself on October 15. Our filing

took the form of a Request for Declaratory Order, seeking FERC’s guidance on

whether our proposed RTO would meet the standards of Order 2000. While it was

never our intention to form a single company RTO, we were limited by time constraints.

On March 14, 2001, FERC issued a response to Southern’s Request for Declaratory Order. The Commission rejected Southern’s October filing on two grounds (1)

Southern Company proposed that only wholesale transmission services would be

subject to the RTO tariff, contrary to FERC policy, and (2) Southern Company proposed some transmission incentives that would flow to transmission owners as opposed to the RTO. FERC determined that this would violate the principles of Order

2000, in which the Commission intended to incent the entity making investment decisions, not the entity building transmission.

Southern believed that we could respond adequately to these FERC concerns.

However, the Commission also noted in its’ March 14th order that as an alternative

to correcting the deficiencies in its October filing, Southern should explore joining

with one or more other utilities to form an RTO in the Southeast. Thus, Southern

continued negotiations with the ITS partners and other utilities in our sub-region

and we also held discussions with GridSouth, GridFlorida, Entergy and TVA.

Around the same time, several non-jurisdictional utilities in the Southeast that had

been somewhat unsuccessful in their attempts to join other RTOs in the region requested to join our discussions to form the SeTrans RTO. These utilities included

Santee Cooper, Jacksonville Electric Authority (JEA), and the City of Tallahassee.

At FERC’s request, Southern filed a status report regarding our efforts to join or

form a larger Southeast region RTO on May 14, 2001 (the status report was supplemented on June 20, 2001). Southern told FERC that since our October filing, Southern had furthered negotiations with the non-jurisdictional transmission owners in

our area. To this end, we included with our status report Memoranda of Understanding with MEAG Power, Dalton Utilities, the City of Tallahassee, Jacksonville

Electric Authority and the South Mississippi Electric Power Association. After the

May 14 filing, Georgia Transmission Corporation, Alabama Electric Cooperative and

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Santee Cooper also signed Memoranda of Understanding. Thus, nine utilities were

now involved in forming the ‘‘SeTrans RTO’’, representing over 39 thousand miles

of transmission, $6 billion dollars in transmission investment, and over 44,000

megawatts of generation that would be within the RTO’s purview. This would place

SeTrans among the largest RTOs in the nation.

Southern Company also reported to the Commission regarding its’ discussions

with Grid South, Grid Florida, TVA and Entergy. Southern decided that joining

with GridSouth, Grid Florida or Entergy was not feasible at that time. These entities were far along in their RTO development. Dealing with the many issues involved with the non-jurisdictional utilities in our area, as well as the jointly owned

transmission system in Georgia would slow the progress that those entities had

made. Southern Company and the municipals and coops with which we are

partnering also have some critical differences over the RTO governance structure of

GridSouth, GridFlorida and the Entergy/Southwest Power Pool RTO. We believe

that smaller RTOs could be implemented much sooner than the larger RTOs favored

by FERC, and if warranted by the market and consumer benefits, merged into a

larger RTO at a later date.

While TVA indicated that it does not wish to join with Southern in an RTO, we

have agreed that most of the benefit of a joint RTO can be gained through coordination agreements (that provide for seamless transmission services and markets

across RTO and utility boundaries). Thus, Southern signed a separate Memorandum

of Understanding with TVA to develop such seams arrangements. GridSouth,

GridFlorida and Entergy have also expressed interest in working on seams issues

with SeTrans. We recently executed a three-way Memorandum of Understanding

with TVA and Entergy to work on these issues.

The goal we expressed in our status report was for SeTrans to make a final filing

with FERC for the establishment of the RTO by December of this year, with an

operational date possibly as early as the fall of 2002. Up until July 12, 2001, Southern Company—in partnership with the eight other transmission owning utilities in

the Southeast—was negotiating and was close to completing a formal agreement to

cover the initial costs of RTO development and establish a decision-making structure. We had also hired an independent facilitator and established working groups

to develop detailed market and operational protocols.

On July 12, 2001, the FERC rejected Southern Company’s Status Report and

issued an order requiring jurisdictional utilities that were in the process of forming

separate RTOs in the Southeast to enter into a 45 day ‘‘mediation’’ process to merge

the separate entities into a single Southeastern RTO. The implementation of this

mediation process was a deviation from FERC’s previous policy direction and applied not only in the Southeast, but in the Northeast as well. Specifically, the parties asked to merge their efforts were SeTrans, GridSouth, and Entergy. In addition,

GridFlorida and the Southwest Power Pool (SPP) were invited to participate, but

they were not required to participate. Also invited (but not required to participate)

were state commissions, non-jurisdictional utilities (municipal utilities and cooperatives,) TVA, the Southeastern Power Administration, and all intervenors in the

dockets related to these RTOs. About 200 people participated in the mediation that

was led by a FERC administrative law judge (ALJ) with consulting assistance.

THE MEDIATION PROCESS

The mediation was subject to a confidentiality rule invoked by the ALJ. We provide here just a broad overview of the issues and a short summary of the mediator’s

report, which was made public on September 10, 2001.

The Southeastern mediation focused on the form of governance, the market model

to be adopted, how congestion pricing should be done, transmission pricing, and

other required functions of RTOs, as laid out by FERC in Order 2000.

While the mediation began with a discussion of four different models (SeTrans,

GridSouth, GridFlorida, and a combined Entergy/SPP proposal), the discussion narrowed down to only two options. These are (1) a Transco (independent transmission

company) type model, and (2) an independent system administrator model (also

know as the independent third-party operator model) that has been supported by

the SeTrans group.

The Transco proposal has an RTO that is managed by a new entity that is formed

via the investment on a passive basis in a limited liability company (LLC) with the

anticipated divestiture of transmission by one or more parties to the LLC. Until actual divestiture of transmission assets, a Board of Directors that is selected through

a fairly complex stakeholder process governs the new Transco Company. Initially,

the Transco Company is owned by the utilities that have invested in it, with the

percentage of ownership being based on the proportion of the amount invested. The

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transmission assets of a utility can be transferred into the LLC with the passive

ownership of the divesting utility’s ownership interest in the LLC increasing proportionately. Eventually, the Transco might be ‘‘sold’’ to investors through an initial

public offering, at which time, the Board of Directors for the Transco would be elected by shareholders.

The SeTrans System Administrator Model, on the other hand, would have a proven, experienced independent third-party transmission operator that would be hired

by the transmission owners to operate an RTO that meets all of the requirements

of FERC Order 2000. The System Administrator would have operating contracts, approved by FERC, with each of the participating transmission owners that would be

similar, but that could contain certain terms and conditions specific to the needs of

individual entities (particularly municipals and coops.)

The System Administrator would not own any transmission, and thus would not

be biased in any way towards its own transmission or against that owned by others.

However, the System Administrator would still be a for-profit company with a balance sheet substantial enough to meet its’ commitments. It would receive a management fee for performing RTO functions, and would have profit incentives (and penalties) to operate reliably and efficiently. We believe the for-profit nature of the System Administrator is essential to making performance incentives work. The System

Administrator would be hired for a five-year term with extension provisions, but

could be fired for cause with FERC’s permission.

Although there may be some surface similarities, there are fundamental differences between the two models. First, the Transco is a start-up company with an

independent stakeholder-selected Board, with the option to turn it into a shareholder elected Board if an IPO occurs. The System Administrator, on the other

hand, is an already existing, proven company, independent from all market participants, that has its own Board of Directors and shareholders already in place, and

has contractual incentives to operate reliably and efficiently.

The second fundamental difference is in asset ownership. The Transco is specifically set up as a repository for divested transmission assets, and earns a return on

those assets. Under the System Administrator model, all transmission assets remain

with others—although independent Transcos would certainly be able to participate

on the same basis as other transmission owners.

The mediator’s final report discussed some of the pros and cons of both models,

but in the end recommended adoption by FERC of the Transco model, with some

modifications that were discussed during the mediation process. The mediator believed that of the two models, the Transco model ‘‘is better developed and more

clearly in compliance with requirements of Order 2000 based on a ‘best practices

analysis’ of other RTOs which have received Commission approval and prior Commission precedent with respect to the current filings.’’ We continue to believe, however, that the System Administrator model offers the greater flexibility, is immediately more efficient, and can accommodate the requirements of all transmission

owners and other stakeholders. We clearly disagree with the judge’s findings.

The Commission has not yet acted on the mediator’s report, but there are indications that it will act within the next several weeks.

SOUTHERN COMPANY POSITION

Southern Company actively participated in the mediation process. We are continuing to support the SeTrans model with the other SeTrans participants. We are

extremely wary about turning over control of our assets and the reliability of our

system to an entity that does not have a Board with direct fiduciary responsibility

to anyone for the assets under its’ control, as would be the case (at least until an

IPO occurs) with the Transco model. We are also concerned about having our assets

managed by a company that also owns transmission assets. Questions arise as to

whether the Transco might favor its own assets. Finally, we are concerned about

turning operation and control of transmission and system reliability over to a new,

unproven entity. We prefer an experienced operator. Thus, we have made it clear

that the Transco model, as currently constituted, is unacceptable to Southern Company. However, we do believe that Transcos can and will develop under the SeTrans

governance model. We are certainly not opposed to for-profit transmission companies (Transcos), and we would like to retain that as an option for ourselves for the

future.

Another reason for support of the SeTrans System Administrator model is that

it is the only model within which public power entities have said they can participate. Participation of public power is critical in our service area because of their significant ownership of transmission. Public power is very wary of turning control of

transmission over to an entity that also owns transmission. In some cases, they beVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00105 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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lieve it violates their charters or other legal requirements. Without their participation, any RTO in our region would be riddled with holes—like Swiss cheese—and

unable to perform all of its intended functions.

In addition to these matters, we have some even more basic concerns. Southern

Company supports the concept of RTOs and believes they can improve the efficiency

and reliability of wholesale power markets. However, we are not yet convinced that

a super-sized, single RTO for the Southeast is in the best interest of the customers

that we serve or our shareholders.

Clearly, as proposed RTO sizes become larger, local control and interest on the

part of the RTO operator will become more diffuse. It is unclear whether a system

operator overseeing the entire Southeast will be able to deal effectively with local

reliability problems. For example, would an operator in North Carolina be able to

assess and deal with a reliability issue in South Florida or Mobile, Alabama, as

would a smaller RTO with more intimate knowledge of local conditions? And a very

large RTO will be expensive. We don’t have any idea, at this time, whether the proclaimed benefits of a very large RTO outweigh the costs. In fact, to our knowledge

no one has yet done any cost-benefit or other analysis on the proper size and scope

of RTOs in the Southeast.

For these reasons and others described below, Southern Company sought rehearing of the July 12 Commission order to negotiate a Southeastern RTO as have many

of the other SeTrans participants and almost all of the state commissions in the

Southeast. We believe that such a rehearing petition will preserve our legal options.

While neither the FERC nor individual commissioners have publicly stated that a

single RTO will be ordered if the parties don’t come to voluntary agreement, that

is certainly a course that industry observers expect FERC to take. Even if there is

not a direct order to participate, there are increasing signals that regulatory pressure may be brought to bear on transmission owners who oppose FERC-prescribed

solutions.

Again, it bears emphasizing that our problem is not with the RTO concept. As

discussed above, Southern Company has planned to join an RTO for over two years

now and has been working diligently towards that goal. Indeed, we have helped lead

an effort that has attracted substantial public power support—something that few

other RTOs in the country have done. Nonetheless, we are opposed to FERC mandates that determine what the RTO should look like, what area it should cover, and

how it should operate. If both FERC and the Congress allow voluntary negotiations

to continue—consistent with FERC objectives—along the path adopted in Order

2000, the nation will end up in a far better place than if RTO mandates come from

Washington. We do not believe that there should be a concern that too many RTOs

will be formed. Even before the July 12th orders, there were a maximum of 14 separate RTOs being formed, and talks were already under way to consolidate several

of them. And to the extent there are ‘‘seams’’ issues regarding differences in markets

within the separate RTOs, those seams issues could be dealt with, as the FERC

Chairman acknowledged in his testimony before this Committee on September 20th,

by FERC rules that would require common market procedures among RTOs.

Our clear preference is to be allowed to continue to negotiate with our public

power partners and neighboring investor-owned utilities to perfect an RTO proposal

that has sufficient scope, meets all of FERC’s Order 2000 requirements, and is acceptable to our state regulators. State commissions throughout the Southeast, including Alabama, Georgia, Mississippi, North Carolina, South Carolina and Louisiana, all filed requests for rehearing or clarification of FERC’s July 12th order.

Three states—North Carolina, Louisiana and Florida—have opened regulatory dockets to examine whether the costs of RTO participation are prudent with respect to

the pros and cons of RTO participation for the retail customers of jurisdictional utilities. All of the state commissions in the Southeast have taken a very strong position that FERC should not mandate a broad regional RTO until the costs and benefits to ultimate consumers have been carefully evaluated. Southeastern state regulators, legislatures, and consumers are all very much opposed to retail consumer

choice at this time, and are concerned that while not directly linked to customer

choice, mandated participation in RTOs will lead to that result. We fear that

FERC’s current path towards mandating very large and broad RTOs will cause irreconcilable differences with state commissions. Clearly if an RTO doesn’t work as

expected or the costs and benefits are out of line, we will be held accountable by

our retail customers via our state regulators.

Southern Company has established a list of principles that are critical with respect to our participation in an RTO. These principles are set forth below:

• The RTO must meet the basic requirements of FERC Order 2000.

• The benefits of RTO participation to our retail customers must exceed the costs.

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• The scope of the RTO must not prevent the RTO from being able to maintain regional and local bulk power system reliability.

• The RTO should be a for-profit entity with incentives (and penalties) to ensure

optimal performance with respect to reliability and cost effectiveness.

• The RTO should have a Board of Directors that is accountable to its shareholders

and has a fiduciary responsibility to the performance of the RTO.

• The RTO should be comprised of a third party operator with actual operating experience, as opposed to a newly created and untested entity.

• The RTO development process and structure must accommodate participation by

all transmission owners, including public power, electric cooperatives, investorowned utilities, and Transcos.

• The Third Party Operator must be independent of all market participants and

transmission owners, thereby avoiding the need for complicated safeguards to

ensure independence.

• The RTO must facilitate entry of other, and perhaps new forms of transmission

owners, including Transcos, to ensure that needed transmission facilities will be

built.

• The RTO must use operating agreements that, although substantially similar, will

accommodate the legal and institutional requirements of all participants.

• The RTO must be acceptable to state regulators.

We continue to believe that the proposed SeTrans RTO will best satisfy these objectives and should be allowed to reach fruition. At this time, there is no need for

a FERC mandate, or for additional authority to be granted to FERC. Indeed, such

action would likely be counter-productive.

Southern Company also supports the tax provisions included in H.R. 4 that would

make it possible for transmission owners to sell or spin off transmission to new corporate organizations without incurring large tax liabilities. While Southern does not

currently plan to divest transmission, it should be retained as an option for the future.

DO VERY LARGE RTOS OR A NATIONAL GRID MAKE SENSE?

The desire to move towards a ‘‘national grid’’ or very large RTOs in this country

must be tempered with economic and technical realities. The term ‘‘national grid’’

itself is a misnomer. Some who use the term use it as a rationale for socializing

interconnection and transmission costs among all consumers, regardless of the benefits they receive. It does not make sense—from either an economic or reliability

standpoint to ‘‘nationalize’’ the transmission grid. Having a centrally controlled grid

is not feasible or desirable form the point of view of system security and reliability

as discussed below. Nor does it make economic sense to remove all bottlenecks and

congestion from the transmission system, because, in most cases, it is much less expensive to locate generation on the unconstrained side of the system, rather than

building transmission to alleviate the constraint. In the Southern Company system

alone, we have estimated that the costs of removing all bottlenecks could be $12 billion, with commensurate rate increases to our customers of over 30%. Thus, to argue

that the cost consequences of a ‘‘national grid’’ are inconsequential, as some have,

clearly stretches the bounds of reason.

Furthermore, not all consumers benefit from transmission system upgrades, and

should not be required to pay for system enhancements for which they receive no

benefit. Only by requiring that cost causation principles be used—i.e., that those

who create costs should pay for them—will true economic efficiency occur. Competitive wholesale markets can benefit consumers—but only if competitors face the true

costs of decisions they make. Markets that are haphazardly designed by bureaucracies, without careful attention to all potential consequences, are doomed to failure.

A primary argument used by proponents of broad regional or national grids is the

notion that the transmission grid is like a lake, where elections are injected into

the grid at one point to form a ‘‘pool’’ of electrons. Under this analogy, users can

take electrons out of the ‘‘lake’’ from any point as needed. Under such a vision (mistaken we believe) there would be no limit to the practical size of a grid, because

there would be no cost of transportation (transmission) of electrons—in fact, electrons would not be transmitted at all—and there would be no added complexities

in grid operations. The ‘‘lake’’ analogy, however, is seriously and dangerously misleading.

The use of the ‘‘lake’’ analogy as support for broad geographic RTOs or a national

grid represents a misunderstanding of how the bulk power system works. The fundamental problem is that a lake by its very nature is a storage medium for water.

Thus, water can be ‘‘injected’’ into the lake when it rains (or when water from river

flows into the lake) and then taken out anywhere from the lake as needs arise. If

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there is more supply than demand, the lake level simply rises. If demand is greater

than supply, the lake level lowers. In either case, the system remains stable.

Electricity, however, cannot be stored. There is not an equivalent ‘‘lake’’ where

power can be injected at one point and taken out at another. Power must be produced at the instant it is needed. Power from specific units is required to meet specific customer needs. While the customer may not use the exact same electrons that

are generated for the customer’s use, generation must be increased to meet a specific customer’s increase in demand, and generation must be decreased when specific

customers reduce demand. If supply and demand is not kept in constant balance,

the system will become unstable and widespread blackouts can result. The specific

generation to be increased in response to a customer’s increase in demand must be

decided by the system operator so that specific transmission lines are not overloaded, consistent voltage is maintained and system stability is achieved. The operator also has to do all this in the least costly manner possible. Thus, it is not the

case that power can be injected (generated) anywhere in the system and taken out

anywhere, at least not without very costly reliability consequences.

An additional complicating factor in the electric system is something called reactive power. Reactive power is a product of the production of alternating current (AC)

power, and must be supplied to run all motors that are connected somewhere in the

grid. Reactive power does no useful work and does not exist as a product that can

be separated from the ‘‘real’’ component of power, but the system can’t operate without it. Operators have to ensure that reactive power is sufficient on a moment-tomoment basis. And unlike the ‘‘real’’ component of power, the reactive component

of power can not be transported over long distances. Again, the ‘‘lake’’ analogy ignores the need for and nature of reactive power.

Power (although not necessarily electrons) does flow from specific generators to

specific customers, over multiple paths (based on the laws of physics, power will

flow from generation to load over the paths of least resistance.) A simplified example may help to explain how this works. Suppose an island utility (to eliminate the

effects of interconnected systems) has a demand of exactly 100 MW at 1:06 PM. The

utility will be generating 100 MW (actually slightly more because of losses) at that

time. Suppose at 1:07 PM a local industrial customer starts up its assembly line and

in an instant the customer’s demand jumps to 110 MW. Generation at the utility

must instantaneously increase to match the increase in demands of 10 MW. The

specific generating units to be ramped up again depends on the condition of the

transmission system at that moment. The utility will be constantly monitoring the

system to determine whether transmission lines can handle additional power. Because power cannot be directed to flow over specific lines, operators can only adjust

flows on transmission lines by adjusting where power is generated. Thus, generation

might actually be ramped up by 15 MW at one unit and ramped down by 5 MW

at another unit to provide the 10 MW.

In this simplified example, nothing else on the system has changed. Thus, the additional 10 MW of power will be injected into the grid to specifically meet the 10

MW of new demand, and the additional 10 MW of power generated will flow directly

to that customer.

The actual system is much more complicated in that demand is constantly changing. Some generators can react to changes on the demand faster than others, and

systems are interconnected so that changes in the utility will affect other utilities

with which that utility is interconnected. Also, most of the matching of supply and

demand is done by computers although human operators can and may have to intervene.

The point of this discussion is to demonstrate the complexity of the grid and associated operational issues. Trying to maintain reliability over a small area is difficult

enough. Trying to operate the system over a whole interconnection would be either

impossible or extraordinarily expensive and complicated. The optimal size for a ‘‘control area’’ (a control area is the geographic area within which a single operator has

control) or an RTO is difficult to determine and can depend on many factors. The

biggest factor is the capability of the interconnections between utilities. If interconnections are weak, there is probably little trade between the utilities and little

economic value to expanding the size of the control area or the RTO. From a technical standpoint, control area or RTO size is also limited by the capability of computers, software, metering and telecommunication among utilities. To change the

control area size arbitrarily and without the knowledge of the control area parameters will likely increase costs to customers.

Taken together, all of these issues—both technical and economic—suggest that

broad geographic RTOs or a ‘‘national grid’’ may create more problems than they

solve. The optimal size for RTOs, while difficult to determine, should be based—as

FERC suggested in Order 2000—on logical market areas and on the strength or

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weakness of interconnections among sub-regions. Optimal size is also a function of

technical limitations and costs. And broad RTOs raise pricing issues that must be

resolved. But perhaps most importantly, the markets themselves should be allowed

to determine appropriate RTO boundaries. As markets develop, RTOs will merge,

break-up and reconfigure, as market needs dictate. Setting RTO boundaries by legislative or regulatory fiat would set in concrete boundaries that may or may not be

the right ones. Furthermore, it has been demonstrated that seams agreements and

reciprocity agreements among RTOs can achieve all of the same objectives as broader RTOs, perhaps at much lower costs. The key is to preserve flexibility as we learn

more about markets and how they are working.

Implementation of very large RTOs or even a ‘‘national grid’’—in particular the

concept of collapsing the whole United States into just a few electrical control

areas—also has reliability and security implications that are particularly critical.

These issues and concerns are not and should not be considered to be a barrier to

RTO formation. They are, however, issues that should be addressed in determining

the proper scope, configuration and market structure for RTOs.

The transmission grid in North America has evolved over many years with one

primary objective in mind—to reliably connect local area generation to serve local

area load. Interconnections with neighboring systems were also developed to provide

limited backup for unplanned contingencies. Market forces today require that the

transmission system be used in ways it was never designed for in support of long

distance energy transactions with flow patterns varying from day to day. These new

uses for the transmission system complicate the jobs of security engineers and operators, and stress the lines and substations designed to serve area loads.

Today, reliability management begins with the transmission planning studies designed to connect existing and forecasted generation to existing and forecasted

loads. Load serving entities such as Southern project forecasted load growth and

transmission planners run contingency studies separately and jointly with neighboring systems to determine the least cost transmission solution required to meet

projected needs. Additionally, any known firm transmission commitments for point

to point service are included in the base transmission plan. For the projected load

and generation plus the set of contingencies modeled, these studies will define the

transmission additions required to avoid thermal, voltage, and stability constraints.

Once the transmission additions are constructed—which may follow a protracted

siting process—operations engineers manage the day to day operation of the system

using load flow programs with contingency analysis. This type analysis is critical

to reliability management by ensuring that the existing system configuration is always operated to withstand the next planning contingency. By measuring actual

flows on transmission lines, the real time load flow includes the effects of loop flows

from other systems and can immediately analyze new configurations as lines and

generators trip or are placed in service. These load flow analysis tools are also used

to calculate total transmission capacity for commercially important points of receipt

and delivery on the transmission system. These values are posted on an electronic

bulletin board (OASIS) and adjusted as transmission capability is sold or added. As

additional transmission capability requests are made, security analysis is performed

to ensure that adequate transmission capability exists to honor the requests.

As transmission constraints appear, the Security Coordinator with responsibility

for that area determines the appropriate action to relieve the constraint. The Security Coordinator may use local procedures, including reconfiguration of the system,

redispatch of generation, or curtailment priorities using contractual agreements to

relieve identified constraints. If local procedures are not sufficient, the NERC line

loading relief program will be implemented to curtail lower priority energy transactions contributing to the constraint. This process has resulted in one of the most

reliable electric power systems in the world.

The implementation of a single RTO in the Southeast or even for the entire eastern interconnection raises a number of reliability management issues. As discussed,

these issues can be addressed with careful organization and delegation. If these

issues are not properly resolved, large area management of reliability will certainly

result in reduced reliability, less than optimum use of the transmission grid, delay

in addressing constraints and potential cascading outages.

Large area reliability management will require that methods be developed to preserve or provide: local knowledge, observability, forecasting, control, and governance

that allows hierarchical decision-making.

No matter how the RTO is structured to manage grid reliability and no matter

how large an area it covers, we can maintain reliability at the lowest overall cost

to consumers through the following actions:

1. Locate generators near loads: Consider two extreme cases. In Case 1, generating

plants are widely distributed across the system to match the distribution of

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load. Generation near each load center is capable of serving the load in that

area and transmission capacity exists to back up local generation (and to import

lower cost power to the area for economic reasons.) In Case 2, generation is located far from load centers near fuel sources and large amounts of power are

moved to major load centers on a routine basis.

In the real world, neither extreme case will exist due to practical constraints

ranging from environmental restrictions on locating plants near major cities, to

the feasibility of siting and constructing transmission to support Case 2. But

clearly the system will be more reliable and less costly if generation is more

widely distributed as described in Case 1. Unfortunately, current FERC policy

will not lead to this preferred result. The reasons will be discussed later in this

testimony.

2. Do not overly centralize control: As more and more control of the electric system

is consolidated for larger and larger geographic areas into one location, the opportunity to have major wide spread control failures becomes more probable. If

the large area RTO implements a single control system for the entire area, a

single point failure (or catastrophic event) that disables this system and any

back-up systems, will leave the entire area with no control options and will certainly reduce reliability. Smaller RTOs (or at a minimum, hierarchical control

areas within a larger RTO) would limit this exposure the same as distributed

generation limits exposure to transmission failures. Clearly, there is a tradeoff

between larger RTOs for market efficiencies and smaller RTOs for local control

and reliability. The proper balance can be found. But it is our judgement that

at least initially, smaller RTOs—with close coordination among RTOs—is a better near-term solution than immediate implementation of the huge RTOs currently being considered by FERC.

FERC should not mandate the boundaries for RTOs, nor should Congress give

FERC such authority. Rather, FERC—as it did in Order 2000—should express its

objectives for RTOs and then let market forces and regional circumstances dictate

the appropriate size, scope and configuration based on natural markets, reliability

and security concerns and trading patterns. It was this direction in which we were

headed—successfully, we believe—before the FERC actions of July 12th.

Another critical component to maintaining reliability, whether in RTOs or otherwise, is to ensure that there are enforceable reliability standards. Congress should

pass legislation that would allow reliability standards to be established and enforced

by a self-regulating reliability organization, with FERC as a back-stop. In this regard, we support the reliability provision in the Chairman’s discussion draft.

MAKING MARKETS WORK—OPEN ACCESS AND PRICING

If we are to rely on a competitive wholesale market for a good part of our future

needs—and Southern plans to do so—we need to focus on how to ensure that such

markets will operate efficiently and reliably. As stated earlier, getting markets to

work efficiently by proper pricing of transmission is critically important to ensuring

low costs and reliable service to consumers. Very large RTOs as suggested by FERC,

without proper attention to how pricing will work, could have severe unintended

consequences from both a cost and reliability standpoint. While transmission pricing

was a specific subject of this Committee’s previous hearing, we believe the relationship of pricing to RTO scope and configuration is critical to the long-term success

of RTOs and worthy of further discussion here.

FERC has indicated that one of its main objectives for very large RTOs is to eliminate pancaking—the charging of multiple transmission rates as you cross transmission owner boundaries. While that may ‘‘sound’’ like a good idea, the truth is

that eliminating pancaked rates and replacing them with a single postage stamp

rate for a large region is exactly the wrong way to go. A postage stamp rate ignores

the fact that it costs more to transmit power over longer distances than it does over

shorter distances. More facilities are used for power transmitted longer distances,

and losses increase as well.

The problem is made more complicated simply because not all areas of the country are created equal in terms of utility size. In the Northeast, for example, you may

have 50 utilities in a single state, meaning that a wheeling transaction could require transmission service agreements with multiple utilities just for short distance

service. In such cases, it may make sense to eliminate pancaking.

In the Southeast, however, we generally have very large utilities, as is certainly

true in our case, which may span several states. If we had a single RTO with postage stamp rates in the Southeast that included Entergy, than the price would be

the same to wheel power from southeast Texas to the Outer Banks of North Carolina as it would be to wheel power from the Atlanta suburbs to Atlanta. That just

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does not make good policy or economic sense, yet FERC appears to be headed in

just that direction.

The fact that under a postage-stamp rate, short-distance services subsidize longdistance services is only a part of the problem. Our greatest concern, and one that

we believe you should share as well, is that it sends the wrong price signals to generators seeking locations for new plants. If it costs generators the same to transmit

power over long and short distances, then it is axiomatic that generators will locate

closer to the fuel source rather than closer to the load in order to save on fuel transportation costs. But locating further from the load means that more transmission

facilities will be used and that new transmission facilities will be needed sooner

than they otherwise might have been—it costs more to transmit over longer distances than it does over shorter distances, even ignoring electrical losses that occur

on the transmission system.

The price signals and location decision-making resulting from FERC’s current

policies are in direct contrast with the historical method of electric system planning,

where generation sites are compared based on total costs—including the trade-off

between pipeline or coal-by-rail transportation costs and incremental transmission

costs. And as discussed above—remember Case 1 and Case 2—the system will be

inherently less reliable.

Proper transmission price signals are also essential to the effective deployment of

distributed generation. If transmission users see the true costs of their use of the

transmission system, then they are more likely to look at distributed generation as

an alternative. Without proper price signals, there is no way to know whether distributed generation is an effective alternative to transmission investment.

FERC’s current pricing policy means that we may will be faced with more demand

for new transmission facilities than would be the case if the true cost of transmission were properly considered in locating new generation. In our region in particular, we are concerned about the feasibility and cost to retail customers of constructing transmission on such a massive scale.

We are already planning to spend about 3 billion dollars (compared to a book

value of current transmission assets of 3 billion dollars) on upgrading the transmission system just to maintain reliability and to accommodate generation now

under construction over the next five years. Having to build new transmission for

even more generating facilities that are locating away from load centers because of

inappropriate price signals will significantly increase these investment levels, not to

mention the problems of siting and constructing this transmission. Network transmission improvements for all the new generation that we believe is probable over

the next five to eight years will cost an additional 3 billion dollars, increasing our

total transmission investment from today’s level of 3 billion dollars to a total of 9

billion dollars. We don’t know how much proper price signals would reduce that

amount, but we can be sure it would have substantial beneficial effect.

Consumers would ultimately pay for this transmission investment. It is not at all

clear to us that added generation efficiencies from an expanded wholesale market

will be sufficient to offset these added costs. We often hear that because transmission is such a small proportion of total costs relative to generation that the savings inherent in large wholesale generation markets will outweigh any potential increased transmission costs or transmission inefficiencies. If we were forced into

building a whole lot of new transmission because of inefficient generation location,

then it is clear that the costs of transmission will no longer be small relative to generation, and in fact may outweigh generation costs at the margin—particularly

when siting costs and reliability issues are factored in.

The problem is exacerbated because FERC’s pricing policies have not been consistent between gas pipelines and electric transmission. Gas pipeline pricing is generally distance sensitive, while electric transmission is not. Thus, electric generators

can locate close to the gas fields and avoid distance sensitive pipeline charges, and

then transmit the electricity to the load over a long distance at a postage stamp

price. Again, the result does not make sense and does not efficiently allocate capital

between these two competing forms of energy infrastructure.

The bottom line is that before FERC revises its RTO policies and sets boundaries,

it ought to spend some time getting transmission pricing right. If large RTOs are

formed under current pricing policies, we may end up over-spending for new transmission facilities and putting generation in the wrong locations. And with FERC’s

policy of rolling in the costs of most incremental transmission facilities, our retail

consumers will bear a large proportion of those costs with little or no benefit.

Another important transmission access issue is the application of open access

rules to all utilities. We believe that all transmission-owning utilities—including

municipals, cooperatives, federal power marketing administrations and TVA should

be subject to the same rules for open access. Our preference would be that all utiliVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00111 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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ties be made subject to the Federal Power Act. However, if the ‘‘FERC Lite’’ con- cept—which only gives FERC the ability to remand open access tariffs back to the

transmission owner is to be adopted—we remain concerned that there is no way for

FERC to ever ensure comparable open access by non-jurisdictional utilities. There

could be an infinite loop, where the non-jurisdictional utility never provides a satisfactory tariff to the Commission. There must be some teeth to the Commission’s en- forcement authority with respect to all utilities.

INTERCONNECTION STANDARDS AND COST ALLOCATION

Another issue that concerns us with very large RTOs is the issue of generation

interconnection. With so much new generation being built in the Southeast, the

question of who gets interconnected, in what order, and who pays for interconnection costs are becoming increasingly important.

The discussion draft of legislation circulated by the Chairman contains interconnection provisions which we can support, mostly because it requires generators

(or their customers) to pay the direct costs of interconnection. We would, however,

also like to see provisions in legislation that would require generators to pay transmission system upgrade costs when such upgrades would not have been required

but for the generation. One proposal that merits attention is ‘‘participant funding’’ of transmission upgrades. Participant funding would allow the generator or transmission service applicant to pay for the costs of new transmission, in exchange for

which they would receive rights to use the transmission system without paying congestion costs. Such rights would have a value equivalent to the transmission investment made by the market participant.

The Chairman of FERC has publicly indicated that he would like to see a change

in FERC’s transmission interconnection policies with respect to cost allocation. In

the past, generators wishing to interconnect with the utility system would themselves be responsible for direct interconnection costs. If network improvements were

also needed, FERC has relied on its ‘‘or’’ pricing policy—i.e., the generator would

pay embedded costs or incremental costs, whichever is greater. More recently, the

Commission indicated in Order 2000 that perhaps in the RTO context, ‘‘and’’ pricing

would be more appropriate, meaning that generators would pay for their use of the

existing transmission system and for any network upgrades they cause.

The FERC Chairman has indicated that he disagrees with these policies, and that

he would like to see both direct interconnection costs and network upgrades rolled

into overall transmission rates and paid for by all load using the transmission system of the interconnecting transmission provider. In other words, even if a generator locates in Georgia to sell to load in Ohio, retail customers in Georgia (and everywhere else in the Southeast) would pick up a share of the interconnection costs.

The implication of this potential change in policy of shifting costs from wholesale

generators to retail customers is clear. The problem is particularly acute with large

RTOs, because customers may have to pick up more of the costs of transmission

than they would have needed locally. Given the very large number of merchant

plants being built in the Southeast, a shift in policy to require all load within an

RTO to pay the interconnection costs of new generators will have a significant cost

impact on our retail customers, and will certainly cause new generators to be less

concerned about the costs they impose on the electric system.

And again, there are inconsistencies with gas pipeline practices at FERC. When

an industrial customer or gas well wants to hook up with the interstate pipeline

system, they are almost always required to pay the cost of the connections. It would

be unthinkable in the gas industry to have an industrial customer tie into the pipeline system for its own use and have all other customers pay for it. But that is no

different than allowing generators to interconnect and having customers who receive

no benefits from that generation pick up the tab. We would urge Congress to make

it clear that those who benefit from interconnections and transmission upgrades

should be the ones who bear the costs.

JURISDICTIONAL ISSUES

The final issue that we’d like to address is the tension between state and federal

jurisdiction. This state/federal jurisdiction issue will not only be a major topic of debate in Congress and at FERC, but also now the Supreme Court has the issue

squarely before it. Southern Company believes that states should continue to have

authority over all aspects of bundled retail sales, including transmission. Some

would go further (as NARUC has) and retain state jurisdiction for unbundled transmission services when the buyer and seller are in the same state. At the other end

of the spectrum, some argue that FERC should have jurisdiction over all transmission, whether it’s used for wholesale or retail, bundled or unbundled.

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This debate is about much more than turf. The real underlying issue is who gets

priority use of the transmission system during periods of constraint or emergency.

And whether utilities can reserve enough capacity on the transmission system to

meet their native load needs before offering capacity to others. Clearly, those advocating federal jurisdiction would like to have all uses of the transmission system on

an equal footing. But this ignores the fact that the transmission system was specifically built to serve our native load customers and we continue to have a legal obligation to serve retail customers in states that have not opened to retail competition.

This issue is at the heart of state commissions’ concerns over giving FERC authority to regulate the transmission portion of bundled retail sales. It is the job of state

regulators to protect the interests of in-state customers. We believe these customer

interests can be served without constraining interstate commerce by leaving jurisdiction over bundled retail sales to the states. We do not believe that more authority

at the federal level, at the expense of the states, is warranted.

A second jurisdictional issue of importance is market power mitigation. Congress

will be considering bills that give FERC broad new authorities for investigating and

mitigating market power, both at the wholesale and retail levels. We believe FERC

and the states already have sufficient authority to prevent and remedy market

power problems. FERC, certainly, can withhold authority of any supplier to sell at

market-based rates. But some believe FERC should also have the authority to order

suppliers to divest generation. Such authority would clearly usurp traditional state

jurisdiction over generation. If given this authority, FERC might try to require divestiture of plants, even where those plants are needed to serve retail customers

in states without customer choice. Furthermore, there is no other federal agency

that has authority to order divestiture of assets by market participants. We believe

such authority is unnecessary, and will again lead to numerous federal/state conflicts.

CONCLUSIONS

The issues currently being considered by this Committee in developing electricity

legislation will have profound effects on the industry for years to come. We believe

that Congress can best ensure the efficient and reliable development of competitive

wholesale electric markets by:

1.Continuing to allow RTOs to develop successfully under FERC Order 2000 in a

manner consistent with market needs and regional circumstances. Congress

should refrain from giving FERC authority to mandate RTOs, and in fact

should encourage FERC to continue along the path it started with Order 2000.

2. Providing guidance to the FERC on transmission pricing, to ensure that federal

pricing policies lead to sufficient investment in transmission and ensure that

pricing signals provided by transmission lead to the efficient development and

location of new generating sources. Congress should also ensure that FERC

pricing policies do not allow for cross-subsidization among electric customers or

groups of electric customers.

3. Ensuring continuation of the proper historical boundaries between state and federal jurisdiction, by leaving with states the ability to regulate all aspects of retail sales, while providing mechanisms for more effective coordination and cooperation between state and federal regulators. If states and FERC are constantly at odds, there will likely be little that gets accomplished, no matter how

much authority FERC has been granted. There are appropriate roles for both

state and federal regulation in the emerging utility markets, and these roles

should be respected.

4. Adopting authority for a self-regulating reliability organization to adopt and enforce reliability standards with appropriate FERC review. It is imperative that

reliability and security of the nation’s electric power supply system should remain our number one priority.

5. Providing that all transmission-owning utilities abide by the same regulatory

rules.

6. Removing federal barriers to effective competition by repealing PUHCA and

PURPA, and removing tax barriers to forming new corporate structures for

transmission ownership and investment.

The greatest concern we have with respect to industry restructuring is of unintended consequences. California is certainly the best example of what can go wrong

when the momentum of a process overtakes good reason and careful forethought.

We need careful thought on all of these industry restructuring issues before we

move forward. It’s the classic case of not being able to unscramble the egg once its

been scrambled. We fear that we are all moving forward on a fast track without

having reviewed the potential unintended consequences. We should move forward

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in restructuring, but in a deliberate, thoughtful manner. And we should always put

consumer interests at the top of our lists. The costs and benefits to consumers of

all restructuring policy options need careful review. And such review should occur

before we make critical structural changes to the electric utility industry that can

not be reversed.

Mr. BARTON. We thank you, Mr. Franklin.

We now want to hear from Mr. Peter Flynn, who is President of

New England Power Company up in Massachusetts. We’ll get a little bit different of a regional perspective, I’m sure.

We welcome you and put your statement in the record, and ask

you to elaborate on it for 5 minutes.

STATEMENT OF PETER FLYNN

Mr. FLYNN. Thank you very much, Mr. Chairman.

New England Power Company is the principal transmission subsidiary of National Grid USA. And I am appearing today in place

of Richard Sergel, President and CEO of National GRID USA. Mr.

Sergel provided the committee with written testimony in advance,

and I’ll be testifying consistent with his prefiled testimony.

Let me begin by explaining that National Grid USA is in the

transmission and the distribution business in the United States

and in the transmission business in other countries. We have no

aspirations to be in the generation or wholesale power sales business. In fact, we’re getting out of that business. So I come to you

today offering the perspective of a company that intends to be and

wants to be in the wires business.

I offer three observations for the committee’s consideration.

First, we believe that time is of the essence to take actions that

will foster the development of workably competitive wholesale markets. We are encouraged by recent statements by the Chair of the

Federal Energy Regulatory Commission that indicates that that

agency is ready to move forward and aggressively pursue the formation of regional transmission organizations, RTOs. And we believe that’s a good thing. However, there were some actions that

only this Congress can take, and key among them would be the removal of existing tax disincentives for the sale of transmission assets.

The single most important thing that Congress can do to foster

the development of independent transmission sector would be to remove that tax disincentive.

Second, the transmission sector is currently evolving. Some believe it will evolve to a structure that will be governed by not for

profit entities. Others believe it will evolve to a structure that in

which transmission will be governed by investor owned transmission companies operating under incentive rates.

Our experience is that the business form will be better able to

attract the investment and provide the innovation that will provide

benefits for customers. We submit, however, that policymakers

today need not choose between those two alternative structures

provided that independent transmission companies operating under

incentive rates have the opportunity to develop, the marketplace

will ultimately choose the structure that best provides benefits to

consumers.

We urge Congress to ensure that independent transmission companies have an opportunity to develop and Congress could do that

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be enacting legislation that urges FERC to adopt incentive rates

that will attract new investment and foster renovation.

My third and final observation is that transmission must be

independent, but not impudent. Independence is critical. Some

argue, however, that independence requires a form where the entity managing the grid takes an almost hands-off approach to new

investment. They argue that investor owned transmission companies will over invest in the grid. We disagree with that argument.

In fact, we believe that the transmission grid is the essential highway that will allow competition in wholesale markets to occur.

The danger is not that the grid will be overbuilt. The danger, we

submit, is that transmission investment will continue to lag. And

we suggest that policymakers should avoid relegating transmission

owners to a passive ownership role only.

Thank you, Mr. Chairman. And I look forward to answering any

questions that the members may have.

[The statement of Richard P. Sergel follows:]

PREPARED STATEMENT OF RICHARD P. SERGEL, PRESIDENT AND CEO, NATIONAL GRID

USA

Thank you for giving me this opportunity to appear here today to discuss transmission issues related to electric restructuring. I am President and CEO of National

Grid USA, the US affiliate of National Grid Group. National Grid Group is the leading provider of independent, for profit transmission in the world.

In the UK, National Grid owns and operates the 4,500 mile high-voltage transmission network in England and Wales, as well as interconnections with France and

Scotland. Since privatization in 1990, National Grid has reduced controllable costs

on the UK grid by over 50% in real terms, and saved a further £ 1 billion by reducing congestion on the system. At the same time, National Grid has consistently improved its record for system availability and reliability, even while demand on the

system has grown to an all time high 50.6 GW in December of 1999. Moreover, in

addition to balancing generation and demand, regulators have recently entrusted

National Grid with the development and implementation of new commercial mechanisms for the bilateral trading of electricity throughout England and Wales, in accordance with recently adopted New Energy Trading Arrangements (NETA).

Worldwide, National Grid also operates Transener, the Argentine transmission

system, through a joint venture with Perez Compac. The system consists of over

5500 route miles of 500 kv transmission lines across an area equivalent to Western

Europe. Transener recently completed construction of an 800 mile transmission line

that connects generation located in the Andes with Buenos Aires. National Grid is

also actively involved in the construction and operation of transmission interconnections between Zambia and the Congo, Tasmania and mainland Australia, the Isle

of Man and the UK, and in the North Sea.

In the United States, National Grid is likewise actively engaged in acquiring or

partnering with US utilities who seek to become or create independent wires or

transmission businesses. As a consequence, Grid has been an active participant in

RTO formation efforts not only in New England and throughout the Northeast, but

also with the Alliance Companies in the Midwest.

By virtue of our worldwide experience and our active participation in RTO formation efforts here, I believe that National Grid is uniquely qualified to offer an informed view not only on the important role that independent transmission plays in

the creation of successful competitive wholesale markets, but on the challenges that

we in the United States face as we attempt to create an independent transmission

sector. I would like to offer three basic observations that cut across all of the subjects under discussion here today.

First, time is of the essence. In the wake of California, we need to accelerate the

creation of successful, competitive wholesale markets for electricity. To put the matter bluntly, electricity restructuring needs a victory. We can hardly expect state regulators in regions that have yet to embrace restructuring to do so unless and until

we demonstrate that competitive wholesale markets not only can function, but can

deliver real value to consumers.

As evidenced by it’s July 12th orders, the FERC recognizes the importance of expediting the RTO formation process as a means of fostering wholesale markets.

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While we understand the concerns of many who argue that the FERC’s action was

somewhat abrupt, we embrace the FERC’s underlying goal. Consequently, we have

redoubled our own efforts to work through the mediation process to expedite the creation of a regional Northeast transmission organization while at the same time

carving out a role for an independent transmission company. The near term creation

of a successful wholesale market throughout the Northeast, a region that by and

large already has embraced both wholesale and retail restructuring, is in our view

critical to the overall success of restructuring, and we will do all within our power

to make it a reality.

The Alliance RTO likewise offers the promise of immediate action. Assuming that

the FERC approves the pending filings, the Alliance could be out of the gate by as

early as December 15th of this year, creating a regional transmission organization

extending over eleven states. This will dramatically hasten the formation of competitive wholesale markets. Indeed, the Alliance RTO, if approved, would serve as

an invaluable platform from which to extend the benefits of wholesale markets and

regional transmission to the larger region. Moreover, if approved the Alliance RTO

will provide policy makers with a laboratory with which to resolve the ongoing debate concerning the future structure of the transmission sector.

Congress also can help expedite the formation of an independent transmission sector and competitive wholesale markets. Congress should enact measured electric restructuring legislation that, at a minimum, ensures the following:

• Open Access. The success of wholesale markets depends first and foremost upon

open access to the transmission grid. Congress should ensure that the nation’s transmission grid, including that owned and operated by public power, is made

accessible to market participants and stakeholders. • Clarified FERC Jurisdiction. Congress should clarify that the FERC has jurisdiction over all transmission, bundled and unbundled, public or private. An appropriate transition period should be considered for bundled rates, and the FERC

need not have authority over rate-setting for publicly owned transmission, but

it must have sufficient authority to ensure and enforce open access. • FERC ‘‘Backstop’’ Siting Authority. Congress should ensure that the FERC has

authority to assist regional transmission organizations in planning, siting and

building new transmission. In the first instance, siting should remain in the

province of the state and local authorities. If the process bogs down, however,

regional transmission organizations should have recourse to the FERC. • Removing Tax Disincentives. The single most important thing that Congress can

do to foster the development of an independent transmission sector is to remove

tax disincentives for the sale of transmission assets. We are convinced, based

upon conversations with many market participants, that they would VOLUNTARILY exit the transmission business if they could defer or otherwise steer

clear of the significant capital gains penalty they face under the existing tax

code. I applaud the House for addressing the issue in HR 4, and urge the Senate and the President to promptly enact the measure into law.

Second, the transmission sector must continue to evolve. The RTO debate has

spawned a far ranging discussion of the true nature of the transmission sector, and

its ultimate organizational structure. Some argue that because of the grid’s vital

role in fostering competitive markets, transmission must be organized as a public

entity, a political collective answerable to its many stakeholders.

In National Grid’s experience, however, transmission is best run as a regulated

business, not unlike other regulated, network businesses, e.g. natural gas pipelines,

telecommunications, etc. Our experience in the UK and elsewhere strongly suggests

that a properly incentivized, independent transmission company can best attract

new investment, best develop and employ new technology, and best apply innovative

management techniques not only to upgrade the grid, but more fundamentally to

extract significant unrealized value from the existing grid, for the benefit of customers.

In reality, however, the debate about the future structure of regional transmission

is probably premature. Transmission will ultimately adopt the form best suited to

meet the needs of the emerging marketplace. It may emerge, as we envision, as a

regulated business with unique regulatory responsibilities, or it may ultimately

emerge as an extension of government regulatory authority with attendant business

responsibilities. Policy makers should resist making premature judgments on which

structure will work best, and allow the natural evolutionary process to continue.

Instead, we believe that policy makers should focus on those issues that will most

directly benefit markets, such as uniform market rules, investment incentives for

new transmission, and innovative rates that encourage the efficient operation of existing transmission assets.

Congress can aid in that process by ensuring the following:

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• Financial Incentives. Congress should urge the FERC to adopt financial incentives

for new transmission investment and innovative rate designs to foster efficient

operation of the existing facilities. • Interconnection Standards and Procedures. Congress should instruct the FERC to

adopt uniform national transmission and distribution interconnection standards

and procedures to expedite bringing new sources of supply to market. • Removing Tax Disincentives, as previously discussed.

Third, Transmission must be Independent, but not Impotent. National Grid’s experience throughout the world has affirmed that the transmission sector must be independent from market participants to assure truly competitive wholesale markets.

We hold that view not merely as a result of a license condition, or business expedient, but as a central tenet of our business plan. We do not engage in the generation business outside of the US, and have already disposed of, or are actively disposing of, our minor generation assets in the US. National Grid has no interest in

being a market participant.

The FERC, of course, has recognized the importance of independence in both Orders 888 and 2000, and is holding the industry as a whole, and National Grid in

particular, to a very high standard of independence.

Independence, however, should not be confused with impotence. True independence assures that the transmission grid will be operated at the highest possible levels of efficiency for the benefit of all customers, including not only generators and

marketers, but also industrial, commercial and residential customers who depend

upon the grid for the reliable delivery of energy from a wide variety of sources.

Recently, however, a few in the ongoing RTO debate have taken the position that

those who own transmission assets can never be truly independent, even if they are

totally divorced from affiliated market participants. They argue that transmission

owners cannot be entrusted to operate their own assets for fear that they will overbuild the transmission grid, and disadvantage generators or other market participants.

In our view, and certainly in recent experience, the danger of under-investment

in transmission is real. The possibility of over-investment is, at best, hypothetical.

In reality, transmission doesn’t compete with generation—the true competitor is the

cheaper and more efficient generation that new transmission can deliver to customers. Could it be that those who purport to worry about too much new transmission are in actuality worried about too much new competition?

We would therefore oppose any Congressional enactment that would relegate

transmission owners to passive ownership.

Mr. Chairman, we believe that policy makers are properly focused on how to revitalize the transmission sector to aid in the development of competitive markets. We

believe that Congress can play a valuable role in that process. I’d be pleased to answer any questions the Committee might have. Thank you.

Mr. BARTON. Thank you, Mr. Flynn.

We now want to hear Mr. Robert Johnston, whose President and

CEO of the Municipal Electric Authority of Georgia. He’s here on

behalf of The Large Public Power Council.

Your statement’s in the record, we would recognize you for 5

minutes to elaborate on it. Welcome.

STATEMENT OF ROBERT JOHNSTON

Mr. JOHNSTON. Well, thank you, Mr. Chairman.

Mr. BARTON. You need to really pull that microphone close to

you.

Mr. JOHNSTON. The LLPC is a collection of 22 of the largest public power systems in the country. We serve 18 million people,

44,000 megawatts of generation and 26,000 miles of transmission.

We’re located in all regions, including many regions represented by

the members of this committee and we have long supported regional transmission entities that facilitate open access. We’ve also

supported comprehensive legislation that promotes wholesale markets.

Addressing some specific issues today, I’d first like to address

bundled retail service issues. We must be allowed to retain capacVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00117 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
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ity, both generation and transmission, to service our native load.

Unlike wholesale energy transactions that they have no relationship to obligation to serve, we must retain this capacity because of

the obligation to serve, an obligation that is imposed on us by State

law.

Any legislation or regulation that requires us to provide capacity

to third parties that would otherwise be used for native load service is simply unacceptable. It will potentially cause to curtail service to native load communities, it may raise the cost or it may do

both. Given that exposure, we cannot do that voluntarily.

In order to fully open the transmission system the Federal legislation must also address private use tax restrictions on private

power assets. Without resolution of this issue, we simply will not

be able to put that 26,000 miles of lines into the system in open

access; we’ll be prevented from putting those resources into RTOs.

And, third, we will be prevented from selling excess generation out

of our system that may, in fact, be created by the open access.

We recognize that the committee does not have jurisdiction over

the tax issue, but we appreciate the chairman’s previous support

for the issue. The chairman’s draft does contain appropriate language which addresses the issues, however I will mention that the

recently passed H.R. 4 legislation has inappropriate language and

would not be adequate.

We supported Chairman Barton’s legislation last year that incorporated the concept of ‘‘FERC-lite.’’ The concept required nonjurisdictional transmission systems such as LLPC systems to provide

nondiscriminatory open access service. The new language, unfortunately, in the draft takes the ‘‘lite’’ out of the FERC-lite proposal.

Rate refund authority given to FERC under the draft language

effectively removed any local jurisdiction over cost recovery associated with publicly owned assets. These are assets that those communities have the responsibility for the debt. The language is unacceptable in our view and should be stricken from the draft.

Regarding RTOs, LLPC supports RTO development, as previously stated. That said, we strongly believe that there is a right

way to evolve to the preferred state so as to do no harm to reliability and low cost to our customers.

We believe the proper approach is to buildupon efforts that are

already working or in development and grow the RTOs in a controlled and logical way. it’s critical that you realize that every region, and in fact every State has unique economic, operational,

legal and regulatory requirements that must be addressed in an

RTO. Because of this, it’s clear that one size and one form for all

regions is not an appropriate approach, as FERC is leaning toward.

It is ill-advised and raises the probability of failure.

In our opinion, you are basically throwing together extremely

large geographic areas that have never operated together, turning

that over to a completely new entity with zero operating experience

and asking it to operate a system that is the life blood of the economy. Like it or not, that is going to raise the complexities and increase the risk.

Now, I’m saying this as a representative of an organization that

believes in and supports development of RTOs, but not in a blind

one size, one form approach.

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Thank you, Mr. Chairman. I’ll be glad to answer any questions.

[The prepared statement of Robert Johnston follows:]

PREPARED STATEMENT OF BOB JOHNSTON ON BEHALF OF THE LARGE PUBLIC POWER

COUNCIL

My name is Bob Johnston and I am the President and Chief Executive Officer of

MEAG Power, located in Atlanta, Georgia. I am testifying today on behalf of the

Large Public Power Council (LPPC). The LPPC is an association of 22 of the largest

public power systems in the United States. LPPC members directly or indirectly

provide reliable, affordably-priced electricity to approximately 18 million customers

and we own and operate over 44,000 megawatts of generation and approximately

26,000 circuit miles of transmission lines. LPPC members are located in states and

territories representing every region of the country, including several states represented by members of this Committee—such as Tennessee, Texas, California, New

York, and Arizona—and include several state public power agencies as well.

The majority of LPPC members perform the same functions as traditional

vertically-integrated utilities. However, LPPC members are publicly-owned, not investor-owned. As a result, LPPC member systems are not profit seeking entities. We

are, instead, service-focused and committed to the residents and communities we

serve. Therefore, the benefits resulting from the reliable and cost-effective provision

of generation, transmission, and distribution service flow directly to public power

customers and communities.

Mr. Chairman and members of the Subcommittee, the LPPC appreciates your efforts to develop comprehensive electricity legislation. The LPPC supports the enactment of comprehensive legislation that promotes a competitive, efficient wholesale

power market of benefit to all consumers. The LPPC has long taken an active and

progressive role in supporting the development of a competitive electricity market.

The LPPC was the first group of transmission owning utilities to express support

for open transmission access in the debates preceding the Energy Policy Act of 1992.

More recently, we have led the way in developing and promoting regional transmission entities as a mechanism to manage and operate the transmission system

in an open access environment and were one of the first organizations to promote

the formation and implementation of Regional Transmission Groups.

The LPPC supports competitive wholesale power markets and open access, nondiscriminatory transmission service. Public power systems are oftentimes net buyers

in the market and greater access to competitive wholesale power markets will benefit our customers and communities. Public power also sells any excess power, when

available, in the wholesale market. However, our systems are built specifically to

serve our native load customers. We do not overbuild our systems or speculate on

future energy needs.

Our first obligation is to our local customers and communities. Therefore, we support comprehensive energy and electricity legislation that will provide greater access

to competitive wholesale power markets, that ensures open access, non-discriminatory transmission service, that improves reliability and increases efficiencies in the

management and operation of the transmission grid, and that ensures delivery of

services to consumers at the lowest reasonable rates. We oppose any changes in law

that would undermine the use of our transmission assets to deliver reasonablypriced power to our retail customers.

We appreciate the efforts this Subcommittee has made to advance the debate on

how to achieve benefits for electricity consumers and we would like to offer the

Large Public Power Council’s continued assistance in crafting legislation. During the

debate on these issues in the last Congress, the LPPC provided our input to the

Committee and contributed our views to the debate. We appreciate this opportunity

to continue our involvement. We have reviewed the Discussion Draft dated September 21, 2001, issued by Chairman Barton, and, while we will not comment extensively on the Discussion Draft, we highlight a few of our specific concerns in this

testimony. As noted above, we have been active in this debate for some time and

have long supported Chairman Barton in his efforts to enact comprehensive energy

legislation. However, we have serious concerns with the Discussion Draft in its

present form, particularly with respect to (1) provisions of the draft that subject

public power to virtually all of FERC’s ratemaking authority and (2) the draft’s repeal of FERC’s authority to review mergers and asset sales. We understand that

this is a discussion draft and that it is intended to foster significant discussion

among the affected parties and the Committee members. The LPPC would like to

continue this dialogue. We must, however, stress again that there are legal constraints—such as private use tax restrictions, bond indenture requirements, and

state statutory obligations—that are unique to public power, which must be adVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00119 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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dressed before full open access can be provided or participation in RTOs can be contemplated.

I would now like to comment more fully on the issues that are the focus of the

Committee’s attention today.

TRANSMISSION POLICIES AND THE LEGAL CONSTRAINTS ON PUBLIC POWER

The LPPC believes that a competitive energy market should include open access

to the transmission grid on a non-discriminatory basis and that the reliability of

electric service must be preserved and preferably enhanced, through competition.

For a competitive market to be viable, LPPC member systems must be able to continue to meet the needs of our customers and must be able to provide a reliable and

cost-effective delivery system. We must be able to serve our native load at the lowest reasonable cost while meeting reliability standards. As locally-owned and operated entities, LPPC members’ first obligation is to the communities that we serve.

Our commitment to these communities is to continue to provide reliable and reasonably priced electric power.

It is important to emphasize that two things make us different than others in the

electric industry. We are governed and supervised locally—and our performance directly affects our ratepayers rather than shareholders. We are therefore very protective of our ratepayers and our public policy positions tend to emphasize consumers

rather than institutions. As a result, we believe that any transmission policy must

recognize these obligations and allow us to continue to serve our native load.

In addition, since public power systems have retained the legal responsibility to

meet the energy needs of their native load customers, they must maintain and retain resources to ensure the capability to supply such energy. Sufficient generation

assets and assured transmission access are required to assure that the energy needs

of customer-owners are met in a reliable and cost effective manner. State and local

laws place requirements on public power systems that must be addressed. For example, my utility, MEAG Power, has an obligation under our state statute to serve

our customers. Unlike an energy marketer who wants firm transmission rights to

support a sales contract, we must preserve the capacity to supply our customers due

to an obligation to serve imposed by state law.

In order to create fully open access transmission, federal legislation must resolve

the ‘‘private use’’ tax issue and should recognize the distinct nature of public power

and its contribution to the electricity industry. The LPPC has testified extensively

on this issue, both before this Committee and the House Ways and Means Committee. Without resolution of current tax restrictions relating to private use, restrictions on tax-exempt bonds (1) will prevent public power from fully opening up its

transmission and distribution systems for use by investor-owned utilities and marketers, (2) will prevent our full participation in Regional Transmission Organizations (RTOs), and (3) will constrain our ability to make long-term sales of surplus

power. Absent adequate reform of private use, one of the key problems—how to

move electric power from generation to load—will continue to plague the system,

and the objectives of comprehensive legislation, the development of a robust, competitive, and fair market, will not be achieved.

While we appreciate the efforts of the House on this issue and recognize that this

Committee does not have direct jurisdiction over this matter, we cannot stress our

position on this issue with more conviction. We appreciate the efforts of the subcommittee and the inclusions of our agreement on private use in the Discussion

Draft. Earlier this session, the House passed H.R. 4, the Securing America’s Future

Energy (SAFE) Act. H.R. 4, as passed by the House, addresses private use issues,

but contains a number of changes to the private use provisions as introduced in the

Hayworth bill [H.R. 1459] that frustrate the aim of opening up and expanding the

transmission grid. The Hayworth bill represented a landmark agreement between

public power and investor-owned utilities forged at the request of Congress, and all

parties believe it strikes an appropriate balance with respect to removing restructuring-related tax impediments. However, the private use provisions in H.R. 4 were

modified in significant ways and these changes make H.R. 4’s private use provisions

unworkable—and in some respects, worse than current law—for public power. The

Chairman’s Discussion Draft contains the language as included in H.R. 1459 and

we ask the Committee’s assistance in ensuring that these key private use relief provisions are revised and modified so the original objectives sought by this agreement

are achieved.

The LPPC supports proposals to ensure that all market participants have access

to the transmission system on a fair and open basis. ‘‘FERC-lite,’’ as included in the

subcommittee’s bill in the last Congress, is part of such an open access policy. It

would require public power entities to provide transmission services at rates that

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are not unduly discriminatory and require non-rate terms and conditions to be comparable to those required of the investor-owned utilities. We believe that open transmission access, including the FERC-lite provision, will encourage a robust and competitive market. However, as noted above, absent adequate private use reform, public power will be unable to provide open access transmission service due to the existing legal constraints. For this reason, our support for the ‘‘FERC-lite’’ concept is

predicated on the removal of these legal constraints.

In addition, due to ‘‘private use’’ tax restrictions, our transmission-owning members have sized their transmission systems to supply their own native loads. At this

time, we have limited transmission capacity available for other entities. To the extent we have such capacity, we are willing to make it available to all comers on a

non-discriminatory basis, as FERC-lite would require. But, a rule that required us

to make available to others transmission capacity we need to serve our native load

will result in power curtailments or higher prices to our own customers. Any expansion of FERC transmission jurisdiction must respect the interests of the customers

for whom the transmission facilities were built.

The LPPC supported Chairman Barton’s legislation introduced last Congress. The

bill incorporated the ‘‘FERC-lite’’ concept and required large non-jurisdictional

transmission providers to provide non-discriminatory open access. However, that bill

did not apply to the transmission component of a bundled retail sale, thereby allowing public power transmission owners to continue to serve our native load. Similarly, the Administration in its ‘‘Comments on Draft Electricity Restructuring Act

of 2001’’ (Senator Bingaman’s Discussion Draft), has recommended that the provision on federal jurisdiction over the transmission component of the retail sale be

eliminated from the draft. The LPPC believes that this is appropriate. Some current

proposals would expand transmission jurisdiction in a way that would jeopardize the

ability of public power systems to serve their own resident, retail customers. The

LPPC cannot support extending FERC jurisdiction in this manner as it may interfere with our fundamental obligation to provide reliable power to our ratepayers and

owners.

In addition, the LPPC has very serious concerns regarding the provisions contained in Section 702 of the Discussion Draft, which would amend Section 206 of

the Federal Power Act. When combined with the amendments in Section 201, the

effect is to take the ‘‘lite’’ out of FERC-lite. The ‘‘Uniform Refund Authority’’ provisions would allow FERC to set just and reasonable rates (and order limited refunds)

for: (a) public power transmission to jurisdictional public utilities; and (b) public

power wholesale sales to jurisdictional public utilities. This would largely negate the

limitations on the Commission’s ratemaking authority over public power transmission that are an integral part of FERC-lite. The Uniform Refund Authority provision would subject public power wholesale sales and transmission rates to review

by FERC when and if such rates are challenged under Section 206. While public

power systems would be able to set their own rates in the first instance, these rates

could, at any time, be reset by FERC. If so reset, the public power system could

then be required to pay retroactive refunds. In our view, the ‘‘Uniform Refund Authority’’ provision, as drafted, cancels out FERC-lite and imposes unworkable,

‘‘after-the-fact’’ rate regulation on public power entities.

RTO POLICIES SHOULD RESPECT UNIQUE AND REGIONAL CHARACTERISTICS

As noted earlier, the LPPC strongly believes that the nation’s transmission grid

should be organized in a manner that first and foremost ‘‘does no harm’’ to existing

transmission and related delivery systems that are performing properly and as designed. Any proposed changes should be thoroughly studied to ensure that benefits

exceed costs and that unintended consequences are minimized. Necessary and timely upgrades to and expansion of the transmission grid are needed. This will most

likely be accomplished if transmission assets are managed through a not-for-profit

regional transmission organization (RTO). Under this model, such upgrades would

not need to meet the higher rate of return requirements necessary for a for-profit

entity. Native load customers of one state should not be forced to bear the cost of

massive grid upgrades that are to benefit marketers or customers or another state.

The costs of upgrades are more appropriately borne by those who benefit from them.

The LPPC believes that RTOs should be created to foster wholesale competition.

RTOs should have an appropriate geographic scope, preferably be not-for-profit, and,

in all cases, be fully independent of market participants. While LPPC believes that

this type of organization will operate more cost-effectively and will more likely result in the open transmission necessary for a fully functioning market, our members

are open to consideration of other types of models. The LPPC opposes granting

FERC broad new authority to compel transmitting utilities to join RTOs. Similarly,

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the Administration in its ‘‘Comments on Draft Electricity Restructuring Act of 2001’’

(Senator Bingaman’s Discussion Draft), did not endorse expansion of FERC’s authority in this area and recommended that provisions providing FERC with additional authority be deleted. The LPPC does, however, support confirming the authority that FERC asserted in Order 2000 to order jurisdictional utilities into an

RTO on a case-by-case basis in order to remedy undue discrimination or anticompetitive conduct.

The LPPC has significant concerns about provisions that mandate public power

membership in RTOs. The LPPC believes that an evolutionary—and not revolutionary—approach is needed to ensure the continued delivery of reliable, affordable

electricity to consumers. The LPPC does support the voluntary formation of RTOs.

Many LPPC member systems are already participating voluntarily in RTOs or ISOs

while others are working hard to establish RTOs in their regions. We have long endorsed the basic notion that coordination of transmission can have positive benefits

for consumers. However, we understand that every region may have very different

needs and problems. As such, we would strongly urge that the formation of RTOs

proceed carefully, and without a ‘‘one-size-fits-all’’ approach.

Regional efforts to form RTOs and ISOs underway at this time should be recognized and the efforts made should be built upon. While the LPPC is not necessarily

opposed to the concept of four large RTOs currently being advocated by FERC, this

should not be the first step. We should not let the perfect be the enemy of the good.

Creating RTOs over large geographic areas multiplies the complexities and has the

real potential of slowing progress. We believe that the advances made on a smaller

scale should be recognized and those efforts continued. It may be possible, at some

later time, to build upon these efforts and create larger scale transmission systems.

The LPPC believes that regional modeling should be done to assess the impacts of

the creation and development of RTOs on the transmission grid. As the transmission grid is regionalized, an evaluation of the lessons learned should be done so

that reliability is ensured and the potential benefits are maximized.

As our members participate in the development of RTOs and ISOs, our unique

constraints have come into play. For example, my company, MEAG Power has participated in the discussions on a southeast RTO—‘‘SeTrans.’’ Since we have an obligation under state statute to serve our native load, our participation in SeTrans was

predicated on an ability to preserve the capacity necessary to provide power to these

customers. Through negotiations, we believe we will be able to grandfather in our

native load obligations and obtain recognition of our pre-existing transmission

rights. In addition, under proposed SeTrans policies, we would not be required to

curtail our native load unless all other mitigation measures have been attempted.

This will allow us to fulfill our obligations to our customers imposed by state law.

However, the same solution would not work for all public power entities. Unfortunately, recent actions at FERC may undercut the voluntary efforts underway in

many regions, e.g., the SeTrans RTO proposal in the southeast, that are designed

to accommodate public power.

In addition, public power systems face difficult issues in participating in RTOs.

These must be addressed before a national system of RTOs can be put into place.

As noted earlier, private use restrictions present a barrier for participation by public

power systems. Furthermore, many public power entities operate under additional

legal and operational requirements that affect their ability to participate in the ownership of an RTO or to transfer ownership or operations of their transmission facilities to an RTO. These requirements include provisions in state constitutions, state

and local laws, and bond covenants that vary from system to system. For these reasons, the LPPC believes that the voluntary regional efforts undertaken by the industry should be used and built upon, since through these negotiations efforts have

been made to accommodate the unique characteristics and legal requirements of

public power.

The legal restrictions on public power and its participation in RTOs varies from

state to state. Some states, such as Georgia, restrict the use of public funds while

others limit the ability of public entities to associate with for-profit entities. Still

other states specifically authorize public power entities to join with other public entities in the ownership and operation of electric transmission facilities. Attached to

my testimony is a matrix that highlights some of the state and local requirements

applicable to LPPC member systems which might affect their ability to participate

in an RTO. What this illustrates is that a one-size-fits-all approach cannot feasibly

address the myriad of issues that confront public power and its participation in

RTOs.

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CONCLUSION

As the Subcommittee continues to move forward with electricity legislation, the

LPPC offers our continued assistance. We would be happy to work with the Subcommittee and its staff to properly tailor FERC transmission jurisdiction to the

unique structures and responsibilities of public power systems, ensure market

power and merger protections for consumers, and retain the appropriate level of

flexibility for FERC as it approves new RTOs. However, I must again stress that

any comprehensive electricity legislation must meaningful private use relief—either

in the same bill or in companion legislation from the tax committee—in order to be

workable.

We look forward to working with the Committee to develop comprehensive electricity legislation that addresses our concerns, garners wide support and can ultimately be enacted. I will be happy to answer any questions you have.

Examples of State and Local Legal Requirements for Public Power Participation in Ownership of an RTO

Chelan County, Public Utilities

District No. 1.

Wash. Const. art. VIII, § 7 provides that no county, city, town, or other municipal corporation shall give any money or property, or loan its money or credit to or in aid of any individual, association, company or corporation, or become directly or indirectly the owner

of any stock in or bonds of any association, company or corporation.

Wash. Rev. Code § 54.16.040 allows a PUD to purchase, maintain, conduct, and operate

transmission lines within or without its limits, for the purpose of furnishing the district’s inhabitants and any other persons, including public and private corporations,

within or without its limits, with electric current for all uses.

Wash. Rev. Code § 54.16.090 allows a PUD to enter into any contract or agreement with

the U.S., or any state, municipality, or other utility district; or with any cooperative, mutual, consumer-owned utility; or with any investor-owned utility; or with an association

of any such utilities, for carrying out any of the powers authorized by Wash. Rev. Code

Title 54.

Wash. Rev. Code 54.12.010 prohibits unlawful delegation of Commission authority; case

law requires needs of local ratepayers to be addressed.

Colorado Springs Utilities ....... Colo. Const. art. XI, § 1 forbids a city to lend or pledge its credit or faith, directly or indirectly, in any manner to any person, company, or corporation, public or private, for any

purpose whatever; or become responsible for any debt, contract, or liability of any person, company, or corporation, public or private, in or out of the state.

Colo. Const. art. XI, § 2 prohibits a city from becoming a shareholder in any corporation or

company or joint owner with any person, company, or corporation, public or private, in

or out of state; but a city is not prohibited from becoming such a shareholder or joint

owner to effect the transmission of energy in whole or in part for the benefit of the inhabitants of such city.

Colo. Rev. Stat. § 31-15-707(1) allows a city to acquire electric light and power works and

distribution systems and all appurtenances necessary to any of said works or systems,

or to authorize the erection, ownership, operation, and maintenance of such works and

systems by others, subject to voter approval, municipal bond and financing requirements, and a condition that allows the city to purchase and condemn such works or

systems.

CS Charter 6-70 restricts participation unless in the ordinary course of business.

CS Bond Ord. 8-14 restricts participation unless in the normal course of business.

JEA ........................................... Fla. Const. art. VII § 10 generally prohibits a municipality, county, special district, or agency of any of them to become a joint owner with, or stockholder of, or give, lend or use

its taxing power or credit to aid any corporation, association, partnership or person; but

it does not prohibit laws authorizing such entities from becoming a joint owner of, giving, or lending or using its taxing power or credit for the joint ownership, construction

and operation of electrical energy generating or transmission facilities with any corporation, association, partnership, or person.

Fla. Stat. Chap. 163 & 361 authorize joint power projects among utilities, public and private, domestic and foreign, subject to restrictions that the right to full possession and

to all of the use, services, output, and capacity of any such project during the estimated useful life thereof be vested, subject to creditors’ rights, in the entity created

pursuant to Chapter 163 or 361. Under local law and charter, may need City Council

approval.

Bond covenants prohibit adverse effect on revenues.

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Examples of State and Local Legal Requirements for Public Power Participation in Ownership of an RTO—

Continued

Los Angeles Department of

Water and Power.

Cal. Const. art. 16, § 6 prohibits any political subdivision of the state to give or lend credit in aid of or to any person, association or corporation, whether municipal or otherwise,

in any manner whatever, for the payment of the liabilities of any individual, association,

municipal or other corporation whatever; it also prohibits the legislature from authorizing the state or any political subdivision thereof to subscribe for stock or become a

stockholder in any corporation whatever.

L.A. City Admin. Code §§ 23.129 & 23.132 require City Council approval.

L.A. City Charter §§ 219.4 & 390 require City Council approval.

Lower Colorado River Authority Texas Const. art. 3 prohibits a public utility from owning or acquiring stock in a corporation or from owning an interest in a partnership or joint venture (except with respect to

electric generating facilities with other utilities).

Bond covenants require LCRA Board of Directors to retain authority to adjust rates to assure that LCRA can meet its debt service and coverage requirements; no prejudice to

bondholder rights.

Municipal Electric Authority of

Georgia.

Ga. Const. art. IX, § II, ¶ VIII prohibits any county, municipality, or other political subdivision of Georgia, through taxation, contribution, or otherwise, to appropriate money for or

to lend its credit to any person or to any nonpublic corporation or association except for

purely charitable purposes.

Ga. Code Ann. § 46-3-126(5) authorizes MEAG to acquire electric transmission lines by

purchase or otherwise, either as owner of all or of any part in common with others or

as agent, and to purchase or construct part of the capacity of transmission projects

sponsored and owned by or in common with others, and to transmit power both for

itself and on behalf of others.

Ga. Code Ann. § 46-3-126(7) authorizes MEAG to exercise any one or more of the powers,

rights, and privileges conferred in the section either alone or jointly or in common with

one or more other parties or utilities, whether public or private. MEAG is authorized to

own an undivided interest in transmission facilities with any other parties, whether

public or private, and to enter into agreements with the other parties regarding the

construction, operation and maintenance of such transmission facilities by any one or

more of the parties to the agreement acting as agent for the others.

Ga. Code Ann. § 46-3-127 prohibits MEAG from constructing or operating any project for

profit except insofar as such profit will inure to the benefit of the public.

Nebraska Public Power District Neb. Const. art. XI § 1 prohibits a city, county, town, precinct, municipality or other subdivision of the state from ever becoming a subscriber to the capital stock, or owner of

such stock, or any portion or interest therein, of any private corporation or association.

Neb. Const. art. XIII § 3 prohibits the credit of the state’s political subdivisions from ever

being given or loaned in aid of any private individual, association, or corporation.

Affirmative and restrictive bond covenants covering, among other things, rate setting and

compensation, revenue requirements, standards for contract or property transfer approval based on interests of NPPD and bondholders, use of proceeds or payments, and

preserving the bonds’ income tax exemption.

Cannot delegate or surrender statutory authority to FERC or submit to its jurisdiction voluntarily.

Can participate in a public RTO but only by agreement authorized under Nebraska

Interlocal Cooperation Act (Neb. Rev. Stat. § 13-801 et seq.) or Joint Exercise of Powers

statutes (Neb. Rev. Stat. § 70-628.01-628.04). Cannot delegate or surrender statutory

duties and elected governing board powers to governing board of public RTO controlled

by private persons.

New York Power Authority ....... N.Y. Pub. Auth. Law § 1005(11) requires that participation in an RTO be necessary or convenient for carrying on the Authority’s business; possible restrictions in bond covenants

based on permissible investment criteria.

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Examples of State and Local Legal Requirements for Public Power Participation in Ownership of an RTO—

Continued

Omaha Public Power District .. Neb. Const. art. XI § 1 prohibits a city, county, town, precinct, municipality or other subdivision of the state from ever becoming a subscriber to the capital stock, or owner of

such stock, or any portion or interest therein, of any private corporation or association.

Neb. Const. art. XIII § 3 prohibits the credit of the state from ever being given or loaned in

aid of any individual, association, or corporation.

Neb. Rev. Stat. § 70-601(1) defines ‘‘district’’ to be public entities organized within Nebraska.

Neb. Rev. Stat. § 70-649 allows any public power district to sell to any public power district, public power and irrigation district, irrigation district, city or village, any power

plant, electric generating plant, electric distribution system, or any parts thereof, for

such sums and under such terms as its board of directors may deem fair and reasonable.

Neb. Rev. Stat. § 70-628.01 allows any district that is interested in the operation of power

plants, distribution systems, or transmission lines of ethanol production or distribution

facilities, either alone or in association with another district or districts, may sell,

lease, combine, merge, or consolidate all or a part of its property with the property of

any other district or districts with the approval of a majority of the board of directors of

each district involved.

Neb. Rev. Stat. §§ 70-625 gives a public power district all the usual powers of a corporation for public purposes and authorizes it to purchase, hold, sell, and lease personal

property and real property reasonably necessary for the conduct of its business, subject

to any limitations in the petition for its creation.

Neb. Rev. Stat. §§ 70-628.01-.03 authorizes a public power district to exercise its powers

either alone or jointly with other districts, municipalities and public agencies, and electric cooperatives and electric membership corporations within or outside the state.

Neb. Rev. Stat. § 70-628.04 authorizes any public power district participating jointly and

in cooperation with others in an electric transmission facility to enter into agreements

with the other participants, including provisions for the construction, operation, and

maintenance of such facility and allocation of resulting costs among the participants.

Orlando Utilities Commission Fla. Const. art. VII § 10 generally prohibits a municipality, county, special district, or agency of any of them to become a joint owner with, or stockholder of, or give, lend or use

its taxing power or credit to aid any corporation, association, partnership or person; but

it does not prohibit laws authorizing such entities from becoming a joint owner of, giving, or lending or using its taxing power or credit for the joint ownership, construction

and operation of electrical energy generating or transmission facilities with any corporation, association, partnership, or person.

Fla. Stat. Chap. 163 & 361 authorize joint power projects among utilities, public and private, domestic and foreign, subject to restrictions that the right to full possession and

to all of the use, services, output, and capacity of any such project during the estimated useful life thereof be vested, subject to creditors’ rights, in the entity created

pursuant to Chapter 163 or 361. Under charter, may need City Council approval.

Bond covenants prohibit adverse effect on revenues.

Sacramento Municipal Utility

District.

Cal. Const. art 16, § 6 prohibits a political subdivision of the state from lending or pledging its credit, in any manner, for the payment of the liabilities of any individual, association, municipal or other corporation, or from making a gift of any public money or

thing of value to any individual, municipal, or other corporation.

Cal. Const. art 16, § 6 prohibits a political subdivision of the state from subscribing for

stock, or becoming a stockholder in any corporation.

Cal. Pub. Util. Code § 12801 allows a municipal utility district to acquire, construct, own,

operate, control or use, within or without the district, works or parts of works for supplying the inhabitants of the district and public agencies therein, or some of them, with

light, water, power, and heat.

Seattle City Light .................... Wash. Const. art. VIII, § 7 provides that no county, city, town, or other municipal corporation shall give any money or property, or loan its money or credit to or in aid of any individual, association, company or corporation, or become directly or indirectly the owner

of any stock in or bonds of any association, company or corporation.

Wash. Rev. Code 35.92.052 provides cities owning their own electric utilities to enter into

agreements with investor-owned utilities, cooperatives, public utility districts, other cities, and agencies of the United States for the undivided ownership of transmission and

generation facilities, so long as the city is not severally liable for actions of the other

participants and so long as the city assumes no larger share of the responsibility and

expenses than its proportionate ownership share.

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Examples of State and Local Legal Requirements for Public Power Participation in Ownership of an RTO—

Continued

Snohomish County, Public

Utilities District No. 1.

Wash. Const. art. VIII, § 7 provides that no county, city, town, or other municipal corporation shall give any money or property, or loan its money or credit to or in aid of any individual, association, company or corporation, or become directly or indirectly the owner

of any stock in or bonds of any association, company or corporation.

Wash. Rev. Code § 54.16.040 allows a PUD to purchase, maintain, conduct, and operate

transmission lines within or without its limits, for the purpose of furnishing the district’s inhabitants and any other persons, including public and private corporations,

within or without its limits, with electric current for all uses.

Wash. Rev. Code § 54.16.090 allows a PUD to enter into any contract or agreement with

the U.S., or any state, municipality, or other utility district; or with any cooperative, mutual, consumer-owned utility; or with any investor-owned utility; or with an association

of any such utilities, for carrying out any of the powers authorized by Wash. Rev. Code

Title 54.

Wash. Rev. Code § 54.12.010 prohibits unlawful delegation of Commission authority; case

law requires needs of local ratepayers to be addressed.

Santee Cooper ......................... S.C. Const., art. X, § 11 prohibits the state or any of its political subdivisions from becoming a joint owner of or stockholder in any company, association or corporation; but the

General Assembly can authorize Santee Cooper to become a joint owner with privately

owned electric utilities, including electric cooperatives of electric generation or transmission facilities, or both, and to enter into and carry out agreements with respect to

such jointly owned facilities.

S.C. Const. art VIII, § 13 permits the sharing of lawful cost, responsibility and administration of functions with one or more governments whether within or without the state.

Tacoma Public Utilities: Light

Division.

Wash. Const. art. VIII, § 7 provides that no county, city, town, or other municipal corporation shall give any money or property, or loan its money or credit to or in aid of any individual, association, company or corporation, or become directly or indirectly the owner

of any stock in or bonds of any association, company or corporation.

Tacoma City Charter § 4.1 allows the city to possess all powers granted to cities by state

law to construct, purchase, acquire, add to, maintain, and operate, either within or outside its corporate limits, public utilities for supplying power to the municipality’s inhabitants and to sell and deliver any of these utility services outside its corporate limits to

the extent permitted by state law.

Tacoma City Charter § 4.5 prohibits the use of revenues for purposes other than the necessary operating expenses of the utility, including interest on and redemption of the

outstanding debt thereof, and making additions and betterments thereto and extensions

thereof. The funds of any utility shall not be used to make loans to or purchase the

bonds of any utility, department, or agency of the city.

This document reflects preliminary analysis for discussion purposes only and is not intended to be a legal opinion with respect to any

matter nor to indicate that all or part of the facilities of LPPC members are transmission facilities for purposes of FERC jurisdiction. Sub- mitted with LPPC Comments on RTO Notice of Proposed Rulemaking, Docket No. RM99-2-000 (August 20, 1999).

Mr. BARTON. Thank you.

We have a series of two votes pending on the floor, and those are

the only two votes for the day. We’re going to hear from Mr.

English, then we’re going to recess to go vote, and then we will

come back at approximately 2 p.m. to finish Mr. Gerken and Mr.

Esposito and Mr. Trabandt and Mr. Travieso.

So, Mr. English, we’re going to give you the last word for this

session of the panel. And then we’ll go vote and we’ll come back

and will start with Mr. Gerken.

STATEMENT OF GLENN ENGLISH

Mr. ENGLISH. Thank you very much, Mr. Chairman. I appreciate

that.

As I think the members of this panel are well aware, the National Rural Electric Cooperative Association represents a 1,000 cooperatives, 46 States and 35 million consumers in those States. It

is owned by those consumers.

Mr. Chairman, the National Rural Electric Cooperative Association supports the formation of large independent regional transVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00126 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
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mission organizations if they’re fully independent and properly designed and operated, minimizes market power and maximizes efficiencies. That’s what we think the objectives of RTO should be.

Electric cooperatives expect and intend to be a part of RTOs that

are established across this country. Of course, that would mean

that the transmission that is a part of those RTOs would be under

the FERC jurisdiction. And we have no objection to that.

Mr. Chairman, for that reason, NRECA see little reason for—to

subject electrical cooperatives to additional Federal regulatory commission authority if, in fact, those cooperatives are a part of RTO.

We recognize that this would have a very heavy financial burden

on those electric cooperatives and, of course, that would be on those

consumer owners themselves.

As far as legislation is concerned, we appreciate the carry forward of the recognition of the importance of the relationship between the consumer and his duly elected board, and the ability of

that board to carry out the intent of those consumers.

We are, however, somewhat puzzled by the insertion of section

206 of the Federal Power Act in applying that to the electric cooperatives. That seems to us to, in effect, take away what was

given under the so-called FERC-lite provisions.

We’re also extremely concerned about the fact that it appears

we’d find ourselves with dual jurisdiction, two different Federal

agencies directly us as to what we should do. First is the Rural

Utility Service, and of course anyone that has a loan through Rural

Utility Service, they have their own rules, regulations, mandates as

to what must be done. Second would be any FERC jurisdiction,

which could in the very likelihood at least on some occasion be contradictory to what we’re being told with those agencies.

We think that if anything is done in this area, particularly as it

applies to our assets and resources that may very well be under

loan, that there should be something in the legislation that addresses that dual jurisdiction and requiring those two Federal

agencies to work together to make sure that we don’t find ourselves

in that kind of a conflict.

Also, we believe that the States should retain their traditional jurisdiction over retail sales and electric distribution systems should

not be subject to FERC jurisdiction. Particularly whenever you consider the fact that FERC does not have the resources nor does it

have the experience to be able to address a number of these issues,

many of which are engineer related.

So, we would strongly urge that careful consideration be given to

the fact that any kind of retail sales, anything addressing the retail

sales should remain with the States and should not be subject to

FERC jurisdiction.

And also I would again make the point, Mr. Chairman, as I did

earlier today, that unless the FERC is specifically targeted as to

what their objectives are, that will do nothing except dilute the

very limited resources that FERC already has and make them incapable of carrying out the responsibilities that are to be assigned

to them.

We think the RTO’s are extremely important. We think they

need to be run right. We believe that everyone should have an

equal chance to participate in those RTOs, and that’s going to deVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00127 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
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pend on a very vigorous and very alert FERC, one that has the resources to do that job.

Thank you very much, Mr. Chairman.

[The prepared statement of Glenn English follows:]

PREPARED STATEMENT OF GLENN ENGLISH, CHIEF EXECUTIVE OFFICER, NATIONAL

RURAL ELECTRIC COOPERATIVE ASSOCIATION

INTRODUCTION

Chairman Barton and Members of the Subcommittee, I appreciate this opportunity to continue our dialogue on the restructuring of the electric utility industry.

For the record, I am Glenn English, CEO of the National Rural Electric Cooperative

Association, the Washington-based association of the nation’s nearly 1,000 consumer-owned, not for profit electric cooperatives.

These cooperatives are locally governed by boards elected by their consumer owners, are based in the communities they serve and provide electric service in 46

states. The 35 million consumers served by these community-based systems continue to have a strong interest in the Committee’s activities with regard to restructuring of the industry.

Electric cooperatives comprise a unique component of the industry. Consumerowned, consumer-directed electric cooperatives provide their member-consumers the

opportunity to exercise control over their own energy destiny. As the electric utility

industry restructures, the electric cooperative will be an increasingly important option for consumers seeking to protect themselves from the uncertainties and risks

of the market. I would like to thank you, Mr. Chairman, and Members of the Committee for your receptiveness to the concerns and viewpoints of electric cooperatives.

REGIONAL TRANSMISSION ORGANIZATIONS

NRECA supports the formation of large, independent Regional Transmission Organizations or RTOs for all transmission owners.

RTOs, if fully independent and properly designed and operated, can substantially

mitigate the ability of transmission owners that also own generation to influence the

market for electric energy and to potentially discriminate against competitors. Because an effective RTO can operate the transmission system on a regional basis to

maximize efficiencies, it can also significantly improve reliability and reduce the potential for power market instability that can lead to price spikes.

NRECA has supported the formation of RTOs in a number of ways. NRECA submitted comments to the FERC in the rulemaking that resulted in Order No. 2000,

and, in fact, FERC adopted several of NRECA’s recommendations. NRECA representatives attended each of the Commission’s five regional collaborative meetings

during 2000 and facilitated presentations made by individual cooperatives at those

meetings. NRECA also successfully facilitated voluntary RTO informational filings

by cooperatives even though the Commission’s regulations did not require most cooperatives to make such filings. Finally, NRECA and cooperatives in the southeastern United States have been very active in the ongoing FERC mediation that

is seeking to establish a single, large Southeast RTO.

For cooperatives to fully participate in RTOs as they clearly wish to do, and in

order for properly formed RTOs to develop, the following issues are of critical importance:

Full Recovery of Transmission Revenue Requirements. Transmission-owning cooperatives must obtain full, immediate recovery of their revenue requirements from

an RTO if they agree to commit their facilities to the functional control of that RTO,

as contemplated by Order No. 2000.

Comparable Inclusion of Transmission Facilities. Some transmission-owning cooperatives have had difficulty getting their transmission facilities accepted for operation/cost recovery by a future RTO on the same basis as investor-owned utilities

during the RTO formation process. Those IOUs opposing inclusion of cooperative

transmission facilities point to the radial, load serving nature of these facilities as

a reason for excluding them, overlooking the fact that they own comparable facilities

that are included in their FERC-regulated transmission revenue requirements. Cooperatives therefore favor the use of a single, consistent standard to govern the

RTO’s functional control of all transmission facilities, regardless of the owner.

Grandfathered Contracts. Many cooperatives have substantial contractual arrangements with neighboring transmission providers. These contracts take many

forms: some are among joint transmission owners, others deal with provision of both

generation and transmission, and some are transmission-only agreements (both preVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00128 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
125

and post-Order No. 888). Whatever their content and form, these contracts are vital

to sustaining the cooperative’s ability to provide on-going service to their own member-owners. Transmission-owning cooperatives will not be able to join an RTO unless they have assurances that such contractual rights will not be severed without

their consent. Similarly, transmission-dependent cooperatives cannot lose access to

the transmission facilities needed to serve their member loads.

Regulation by the Rural Utilities Service. Many cooperatives have substantial

loans from, and, as a result, are substantially regulated by the Rural Utilities Service (RUS) of the U.S. Department of Agriculture. The Commission must take RUS

regulation into account and coordinate with RUS to ensure that when cooperatives

seek to join RTOs, inconsistent, inefficient regulation of cooperatives by these two

federal agencies does not occur.

85-15 Revenue Test. Cooperatives lose their tax-exempt status when more than 15

percent of their revenue is received from nonmembers. The Internal Revenue Service (IRS) has not clarified that, when a cooperative joins an RTO, the revenues received by the cooperative from the RTO will not be deemed to be nonmember income

for purposes of the 85-15 revenue test. Congress must ensure that cooperatives can

join RTOs without unintentionally violating their current not-for-profit tax status.

NRECA appreciates the Chairman’s effort to address the 85-15 issue in the September 21 discussion draft. That language, however, is inadequate to solve the problem and permit cooperatives to participate in RTOs. Since the September 21 discussion draft addresses tax issues, it should incorporate the provisions in H.R. 1601.

Cost Shifting. RTO transmission rates and tariffs should (a) mitigate cost shifting

and take into account the specific needs and characteristics of each affected region,

including costs of operation, debt, and other expenses; (b) use the same effective return-on-investment to all participating transmission owners; and (c) recognize the

goal of establishing a single non-pancaked rate structure applicable to all customers.

RTO Market Power. As transmission service remains a monopoly, and as individual RTOs assume control of larger transmission systems than individual transmitting utility owners, RTOs will possess unprecedented market power. In this context, a badly governed and operated RTO may be worse than no RTO at all. Thus,

the monopoly status of an independent RTO must be acknowledged at the outset,

and the RTO’s transmission rate structure and associated cost-of-service should be

developed using traditional cost-of-service ratemaking principles. RTOs should not

be eligible for ‘‘incentive ratemaking,’’ ‘‘performance-based ratemaking’’ or ‘‘lighthanded regulation’’ that would have the effect of increasing rates to transmission

customers without concomitant benefits or reducing independent regulatory oversight of such an RTO’s activities.

Collaborative Process. The Commission has sought to encourage RTO forming

public utilities to actively collaborate with cooperatives in order to accommodate

their needs as consumer-owned entities. Unfortunately, in numerous instances collaboration has been nothing more than a thinly disguised effort of saying, ‘‘take it

or leave it.’’ For cooperatives to effectively join RTOs, public utilities must be required to meaningfully collaborate with cooperatives beginning with the earliest

stages of RTO formation efforts. The Commission should not fail to act when informed of RTO formation efforts that exclude cooperative participation.

An NRECA member-approved resolution stating its conditional-support for RTO

formation is attached hereto for the Committee’s convenience and reference.

OPEN ACCESS AND FEDERAL JURISDICTION

NRECA opposes efforts to subject electric cooperatives to the jurisdiction of FERC.

That expansion of jurisdiction would unnecessarily impose heavy financial burdens

on electric cooperatives and their consumer-owners.

NRECA also opposes efforts to move jurisdiction over retail sales and the distribution system from the states, where that jurisdiction properly lies, to FERC. FERC

lacks the experience and resources to regulate retail service and the distribution

system, as well as the capacity to address the important state and local interests

that are inherent in retail electric service.

NRECA, however, sincerely appreciates the Chairman’s efforts in the 106th Congress to limit the expansion of FERC jurisdiction over electric cooperatives. NRECA

looks forward to working further with the Chairman and the Committee to resolve

any concerns they may have about FERC’s role in a manner that minimizes the adverse impacts on cooperatives and their consumer-owners.

Expansion of FERC Jurisdiction over Cooperatives with Transmission Is Unnecessary

Proponents of expanded FERC jurisdiction argue that all transmission owners, including cooperatives, must be subject to the same regulatory scheme if they are to

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1FERC Stats. & Regs. ¶ 31,036, at 31,897 (citing to the Small Business Administration definition of a small utility that is a utility that sells 4 million megawatt hours or less per year). 2Transmission-owning cooperatives that have RUS loans and loan guarantees.

move power efficiently across the grid. In fact, however, sellers of electric energy can

move power across electric cooperative lines.

In the Energy Policy Act of 1992 (EPAct), Congress amended § 211 of the Federal

Power Act to require electric cooperatives and other transmitting utilities to provide

non-discriminatory transmission service to any eligible entity that requests service.

In the event the eligible entity is unsatisfied with the service or price offered, § 211

allows that entity to petition FERC for an order requiring the transmitting utility

to provide service.

Moreover, FERC’s Order No. 888 requires all public utilities to provide transmission service under a pro forma tariff that includes a ‘‘reciprocity’’ provision. That

provision permits a public utility to deny a transmitting utility open access transmission service unless the transmitting utility offers to provide the public utility

equivalent transmission services in return.

EPAct and FERC’s Order 888 reciprocity requirements have proven extremely effective in opening up the entire transmission grid. Any eligible entity can obtain

transmission service from electric cooperatives as easily as they can from any public

utility, under comparable terms.

Moreover, cooperatives simply are not large enough in most instances to pose a

barrier to open markets. Whereas only 19 of the 166 independently-owned public

utilities subject to Order 888 qualify as small utilities,1 all but 26 of the nearly 1000

rural electric systems qualify as small utilities under that definition. Of those 26,

four own no transmission lines at all.

To put it in perspective, FERC logically should have a more significant role regulating larger electric utilities such as Entergy—whose subsidiaries own and operate

more than 14,000 miles of transmission line and sell more than 97,000,000 MWH

to more than 2,400,000 metered accounts—than it should have regulating HickmanFulton Counties Rural Electric Cooperative— which owns 1 mile of transmission

line, and sells less than 120,000 MWH per year to fewer than 4,000 member-owners.

Congress Should Not Subject Electric Cooperatives to Expanded FERC Jurisdiction

Under § 206 of the Federal Power Act

Until recently, proposals to expand FERC jurisdiction over cooperatives were intended to subject all transmission facilities to the same rules. Those proposals would

ensure that cooperatives provided open access to their transmission facilities at

rates that were comparable to what they charged themselves.

§ 702 of the September 21 discussion draft goes far beyond that baseline. § 702

would subject all transmission service and all wholesale sales made to public utilities to FERC review and regulation under § 206 of the Federal Power Act.

H.R. 2944, the Electricity Competition and Reliability Act, as passed by the Energy and Power Subcommittee in the 106th Congress, included language to expand

FERC’s jurisdiction over transmission-owning cooperatives 2 based on a comparability standard. Specifically, the language would have authorized FERC to review the rates a transmission-owning cooperative charges its members against those

it charges to non-cooperative members to ensure the rates are comparable. If the

rates are not comparable, they would be remanded to the transmission-owning cooperative for revision. In this manner, the transmission-owning cooperative is allowed

to maintain control of the ratesetting function, which is key to our consumer-members. The comparability standard along with the small electric utility exemption is

know as ‘‘FERC lite’’.

Unfortunately, the September 21 discussion draft emasculates FERC lite. § 201

creates the veneer of establishing the comparability standard as the basis for expanding FERC jurisdiction over transmission-owning utilities. Upon close analysis,

however, § 702 of the discussion draft nullifies the comparability concept that was

incorporated in § 201 of the discussion draft. Under this section, rather than review

cooperative transmission rates under a comparability standard, FERC would subject

cooperative transmission rates to a full review under the just and reasonable standard. Rather than remand rates to boards of directors elected by cooperatives member-consumers, FERC would set the rates itself at whatever level FERC considers

appropriate.

In addition to emasculating FERC lite, § 702 would also, for the first time, subject

cooperatives’ wholesale rates to FERC review and regulation. At a time when Congress and FERC are seeking to move towards a competitive wholesale market for

electric energy, § 702 would move in the opposite direction, increasing the regulatory

burden on electric cooperatives that seek to sell power in the wholesale market.

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NRECA recognizes that some entities have abused those markets. They have exercised their market power to raise the cost of electricity. § 702 does not address

those abuses.

Electric cooperatives have not been part of the problem. Not-for-profit electric cooperatives have not gamed markets, they have not abused consumers, and they

have not exercised market power. It would be impossible for them to have done so.

Cooperatives do not own enough generation and are not large enough players in

electric markets to exercise market power. All together, electric cooperatives generate only about 5% of the electric power in the country, which is less than half of

the power they need to serve their own consumers. All combined, electric cooperatives’ sales to public utilities represent less than 1% of all sales in the wholesale

market.

H.R. 2944 recognized the substantial differences between not-for-profit consumerowned electric cooperatives and investor-owned utilities, and made an effort to accommodate those differences; § 702 ignores those differences.

Expansion of FERC Jurisdiction to Cooperatives with Transmission Would Subject

Cooperatives to Expensive Duplicative Regulation

If FERC jurisdiction were expanded, electric cooperatives would be subject to unnecessary, duplicative, and possibly contradictory regulatory obligations.

First, all electric cooperatives are regulated by their customers. Cooperatives are

not-for-profit and are owned by the consumers they serve. They are governed by

boards of directors composed solely of consumer-owners, who are themselves chosen

by the consumer-owners of the cooperative in open elections. The tradition of local

ownership and control and democratic governance runs deep. And, because cooperatives are not-for-profit companies that are directly responsible to their consumers,

all but fourteen States have delegated their power to set and regulate rates to the

cooperatives’ boards of directors.

Second, even those electric cooperatives that have outstanding RUS loans or loan

guarantees are subject to significant regulation by FERC. As explained above, RUS

borrowers with transmission facilities are subject to § 211 of the FPA. RUS borrowers must provide non-discriminatory transmission service on request, and are

subject to FERC wheeling orders where disputes arise. RUS borrowers are also subject to the reciprocity requirements in FERC’s Order No. 888 and 889.

Third, RUS borrowers are subject to pervasive regulation by RUS, pursuant either

to RUS regulations or to the loan document that RUS borrowers must sign to obtain

loans or loan guarantees. RUS regulation ranges the gamut: restrictions on depreciation rates, standards and specifications for electric system construction, uniform

system of accounts, required standard contract forms, mandated competitive procurement procedures, merger review, credit management, and a myriad of additional topics—even intervention in the choice of senior managers for borrowers in

financial difficulty. In all, RUS regulations cover more than 800 pages in the Code

of Federal Regulations. Moreover, other RUS mandates are contained in hundreds

of extant ‘‘REA Bulletins’’ covering most categories of electric system construction

and daily operation.

If FERC’s full Federal Power Act (FPA) jurisdiction were expanded over transmitting utilities, RUS borrowers would be subject to several more levels of regulation

than any investor-owned utilities. RUS borrowers could also be subject to conflicting

requirements from different agencies. For example, both RUS and FERC would have

the authority over cooperatives’ transmission rates, accounting systems, and record

keeping methods. Depending on how broadly FERC’s jurisdiction was expanded,

both agencies could also have authority over cooperatives’ mergers and asset transfers, transmission maintenance procedures, and investments in new transmission

facilities.

That duplicative authority would raise costs and increase regulatory uncertainty

for cooperatives, make it more difficult for cooperatives to react quickly to changes

in the competitive market, and handicap cooperatives compared to public utilities,

which do not face duplicative regulatory obligations.

FERC Lacks the Resources to Address Expanded Jurisdiction over Cooperatives

FERC has insufficient resources today effectively to meet its current regulatory

obligations. In light of the limits on its resources, it is hard to imagine how FERC

could effectively handle an expansion of its jurisdiction and authority. According to

the last FERC Annual Report containing such numbers (1996 report), FERC regulates about 370 public utilities. Depending on the manner in which FERC defines

‘‘transmission’’, extending FERC jurisdiction over transmitting entities could add

more than 450 cooperatives and many municipal systems. The number of FERC-regulated entities could more than double.

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In other words, FERC would become stretched even thinner. Under such circumstances, the amount of abuse in the market would be certain to increase dramatically. The holes in the regulatory net would become so large that utilities could

conclude the chance of getting caught in wrongdoing would be so remote as to pose

no barrier. Thus, instead of enhancing the competitive market, expansion of FERC

jurisdiction could severely handicap it, putting consumers at substantial risk.

FERC Lacks the Capacity to Regulate the Distribution System and Retail Services

Several proposals for electric legislation would: (a) grant FERC the responsibility

for establishing standards for the interconnection of distributed generation to the

distribution system; (b) mandate net metering for some consumer-owned generation;

(c) establish principles for setting rates for retail energy service to consumers with

distributed generation; and (d) grant consumers, subject to FERC regulation, the

right to sell power they choose not to use (‘‘negawatts’’) to third parties.

NRECA opposes the federalization of these issues for several reasons. First, electric cooperatives own 44% of the nation’s distribution system. Much of these distribution systems are located in rural areas where the population density is low,

averaging less than 6 consumers per mile. As a result, the revenue generated in

these areas is extremely low, averaging approximately $7,000 per mile. Net metering and distributed generation interconnection programs, for instance, if formulated

and implemented without a strong sensitivity and appreciation for local conditions

would lead to increased electricity costs for consumers in rural areas that could

least afford to pay them. Second, electric cooperatives have obtained $36.4 billion in RUS financing. As a

result of this financing, RUS must approve the rates and practices of distribution

cooperatives and cooperatives that own generation and transmission. Negawatt and

net metering programs and distributed generation interconnection standards have

a direct impact on these rates and practices; however, they are being federalized

without any role for RUS. This will create significant problems for cooperatives.

Third, these issues have traditionally been the responsibility of states and local

regulatory bodies. Moving these issues to the federal level makes it more difficult,

or in some cases impossible, for states and local regulators to protect the public interest.

Policy decisions with respect to retail electric and distribution services can have

tremendous impact on local standards of living and economies. It is important,

therefore, for state and local regulators to be able carefully to balance local interests

and to craft tightly focussed regulations of retail electric and distribution services

that meet local needs. Moving responsibility over these issues away from the local

community to the federal level makes it less likely that regulatory decisions will reflect local needs or protect local interests. Moving responsibility over these issues

away from the local community to the federal level also makes it harder for utilities

to provide reliable, universal electric service at a reasonable cost.

The ‘‘negawatts’’ proposal embedded in § 104 of the September 21 discussion draft

is a perfect example of the risks of federalization. At the federal level, the proposal

is attractive because it appears that it would create a more liquid regional wholesale

market. At the local level, however, it is clear that the proposal could cause significant price increases for retail consumers served by the same utility as a few very

large industrial consumers who resell their power. It could also cause significant

economic disruption in that community when industries choose to sell power and

lay-off the workers no longer needed to work on idled production lines. State and

local regulators are more likely to be sensitive to those kinds of concerns than federal regulators.

Moreover, NRECA does not believe that FERC has the experience or the resources

to regulate effectively matters relating to retail electric or distribution services. Over

more than 65 years, FERC and its predecessor, the Federal Power Commission

(FPC), regulated wholesale sales and transmission service. FERC has never established technical standards for the interconnection of generation at the transmission

level, and it has never had any experience whatsoever regulating retail services or

distribution systems. FERC does not employ today a single distribution engineer.

Further, as discussed above, FERC is experiencing difficulty meeting its existing responsibilities today with its limited resources. Multiplying FERC’s responsibilities

by giving it new jurisdiction over retail and distribution services would spread

FERC’s limited resources even more thinly to the detriment of both wholesale and

retail consumers.

Mr. BARTON. We thank you. When we come back, we’ll start with

Mr. Gerken. We’re in recess until approximately 2 p.m.

[Brief recess.]

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Mr. BARTON. The subcommittee will come to order.

The pending business before us is the hearing on RTOs and

transmission policy for the electricity industry. We had heard from

Mr. English, we now want to hear from Mr. Gerken as soon as everybody gets settled. it looks like they’re about settled.

Your statement’s in the record. You’re recognized for 5 minutes.

STATEMENT OF MARC S. GERKEN

Mr. GERKEN. Good afternoon, Mr. Chairman and members of the

subcommittee. I am Marc Gerken, President of American Municipal

Power-Ohio in Columbus, Ohio. I am testify today on behalf of

AMP-Ohio and TAPS.

AMP-Ohio is a wholesale power supplier and service provider for

84 municipal power systems throughout Ohio, Pennsylvania and

West Virginia.

TAPS is an association of transmission dependent utilities and

other supporters of nondiscriminatory transmission access and vigorously competitive wholesale electric markets. For more than 16

years AMP-Ohio has been involved in a competitive purchase and

delivery of wholesale power as an aggregator for municipal electric

systems. As an active participant in the Midwest wholesale market,

AMP-Ohio has experienced both benefits of competition and the

limitations of the current market structure.

The topic of today’s hearings, RTOs, open access and transmission jurisdictions are key to achieving an effective wholesale

competition and its intended purpose meeting consumer benefits.

And I stress the consumer benefit part. Compromise on these

issues will do far more harm than good.

AMP-Ohio operates in five different transmission control areas

today that will be part of RTOs, the Alliance RTO, the Midwest

ISO and the PJM RTO, that’ll be PJM West. Not only are there

competing RTO proposals, but transmission owners are playing

RTO musical chairs, hoping from one RTO into another created a

checkerboard system with potential holes and inconsistencies.

These kinds of behaviors do not advance the development of large

independent rationally scoped RTOs, which TAPS believes are essential to a competitive market.

TAPS applauds FERC Chairman Pat Wood’s recent statements

and efforts to ensure proper RTO formation. Despite this important

development, Federal legislation is still needed to clarify and affirm

FERC’s authority to move forward with this new organized scheme.

Absent congressional affirmation, more aggressive FERC action

is likely to get mired in litigation, therefore with regards to RTOs

TAP would urge Congress to do three things.

Affirm FERC’s authority to require jurisdictional utilities to participate in an RTO to remedy undue discrimination, and as Chairman Woods also proposes, generic condition for market based authority and merger approval.

Second, authorize FERC to require transmission owning Federal

utilities to participate in an RTO if needed to remedy undue discrimination.

And last, authorize FERC to order RTO participation by municipal and cooperative utilities upon finding that the transmitting

utility has engaged in undue discrimination in the provisions of

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transmission, and that open access tariffs are unlikely to remedy

this problem.

On the question of FERC jurisdiction over transmission, TAPS

believes that for the electricity competition to be successful it is essential that FERC have authority to establish one set of rules for

the use and operation of the Nation’s interstate transmission system. Somewhat like Mr. Flynn mentioned, think what pandemonium would occur if the interstate highways posted two different

speeding limits for passenger cars. A higher limit for interstate instate cars and a lower rate for out of State cars. Go on farther and

think how many crashes or congestions would occur if the State established a different regime for instate cars to switch lanes, maybe

you don’t have to turn your turn signal on, versus the out of State

cars. Or think what would happen if a State would mandate that

out of State vehicles pull over to the shoulder during rush hours

so that in-state vehicles could pass. You cannot have multiple inconsistent systems for use of an interstate transportation system,

it won’t work; yet this is precisely what the divided transmission

authority allows.

Some have suggested that the current split jurisdiction assures

reliability to the transmission owner’s native load. Our view is that

it has the potential to subject native load customers of other utilities to less reliable and more expensive service. We do not see this

as the State versus Federal issue, rather it is a State versus State,

consumer versus consumer issue. And FERC is the only entity that

can ensure open fair nondiscriminatory and reliable service to all.

TAPS urges Congress to recognize in the legislation that there

can be only one set of rules for all users of the transmission network, and those rules need to be set by FERC. And subsequently,

TAPS support FERC jurisdiction over transmission use for bundled

as well unbundled retail sales and also FERC jurisdiction over the

terms and conditions of service over municipal cooperative system

transmission systems subject to the FERC-lite provisions.

TAPS looks forward to working with the subcommittee. And I appreciate it, and I look forward to your questions.

[The prepared statement of Marc S. Gerken follows:]

PREPARED STATEMENT OF MARC S. GERKEN ON BEHALF OF THE TRANSMISSION

ACCESS POLICY STUDY GROUP

Good afternoon, Mr. Chairman and Members of the Subcommittee. My name is

Marc Gerken. I am President of American Municipal Power-Ohio in Columbus,

Ohio.

AMP-Ohio is a nonprofit wholesale power supplier and services provider for municipal electric utility systems, including 79 of Ohio’s 85 community-owned electric

utilities, three in Pennsylvania and two in West Virginia. Ohio municipal electric

systems account for approximately six percent of the retail electric sales in Ohio,

serving about 360,000 meters statewide. Our organization has 186 employees, and

operating revenues of more than $228 million. Our members receive their power

supply from a diversified resource mix, including: wholesale power purchases

through AMP-Ohio and on the open market; energy produced at the 213-megawatt,

coal-fired Richard H. Gorsuch Generating Station owned and operated by AMPOhio; individual community-owned generation facilities; and municipal generation

joint ventures such as the 42-megawatt Belleville Hydroelectric Project and the 157-

megawatt OMEGA JV2 distributed generation.

Ohio’s municipal electric systems do not own significant transmission facilities,

and therefore are transmission dependent. In 2000, the non-coincidental peak for

AMP-Ohio member communities was 1,793 megawatts. We operate in five different

transmission control areas today that will be part of the Alliance RTO, Midwest ISO

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and PJM RTO. Our energy control center has handled arrangements to move power

across as many as 18 different transmission systems in one year.

I am here today to testify on behalf of the Transmission Access Policy Study

Group (TAPS). TAPS is an association of transmission-dependent utilities and other

supporters of equal, non-discriminatory transmission access to the nation’s transmission grids and vigorously competitive wholesale electric markets. TAPS members

are located in more than 30 states. (Let’s attach list of members and map.) AMPOhio, and the other municipal, cooperative and investor-owned utilities and municipal joint action agencies that are members of TAPS, are transmission dependent

utilities (TDUs). We must depend on the use of transmission systems of large

vertically-integrated utilities in order to reach alternative sources of power supply

for our consumers. TAPS members have been active in wholesale markets for some

20 years, and have been on the ‘‘bleeding edge’’ of efforts to obtain transmission

service, open access, and RTOs. AMP-Ohio’s 20-year involvement in the competitive

purchase and delivery of wholesale power as an aggregator for our members gives

us a full appreciation of the central role of open and non-discriminatory access to

transmission in ensuring all consumers access to reliable service and for wholesale

and retail competition to be a success.

TAPS has concluded that the only way to get to a competitive electricity industry

is by restructuring the industry to provide the transmission and market structure

needed to allow competitive forces to work. We believe federal legislation is needed

to achieve this critical objective, but it must be the right legislation. To promote

electricity competition and ensure reliable service to all consumers, we must all

work together to get the basic infrastructure right. The subjects of today’s hearing—

RTOs, open access, and transmission jurisdiction—are key to achieving these important objectives. Compromise on the critical issues of industry structure will do far

more harm than good.

Specifically, we believe that Congress should enact legislation to:

• Clarify FERC’s authority to require participation in large, truly independent and

rationally configured regional transmission organizations (RTOs), with full authority to operate the regional grid as well as to plan and expand it, or cause

its expansion.

• Place regulatory responsibility for all transmission service—wholesale and retail,

bundled and unbundled—clearly in FERC’s hands (subject to ‘‘FERC lite’’ jurisdiction over the transmission owned by municipal and cooperative utilities).

1. FERC NEEDS AUTHORITY TO REQUIRE STRONG, INDEPENDENT, BROAD REGIONAL RTOS

Large, rationally configured, independent and robust regional transmission organizations, with exclusive authority to operate, plan and cause expansion of the grid,

are key to getting the transmission infrastructure right. The current regimen of control of transmission by individual vertically-integrated utilities must change to be

compatible with and support competitive markets. Regional transmission organizations are the structure needed in a competitive electric industry. As FERC correctly

found in Order 2000, RTOs are required (1) to eliminate the continued opportunity

(that exists notwithstanding Order 888’s requirement of open access tariffs) for discriminatory transmission practices; and (2) to achieve efficient management of the

grid and improve reliability.

Today, the grid remains largely in the hands of one set of market participants

(vertically-integrated utilities or utilities with transmission subsidiaries) that can

use that control—in ways often difficult to detect—to favor themselves. Even if the

owner is not discriminating, that potential chills the market, as FERC has found.

When curtailments are called or transmission service requests are denied, a doubt

arises as to whether competitive considerations came into play.

AMP-Ohio has experienced denials of service and interruptions that are frankly

inexplicable except as the result of the transmission owner’s manipulation of the

transmission system to advantage its own generation and sales and disadvantage

a competitor. For example, on June 30, 1999, AMP-Ohio’s request to transmit 20

MW from a member city was denied based on a claimed lack of available transmission capacity (ATC). A check of the ATC across the interconnection in the opposite direction showed no capacity in that direction either, in apparent defiance of

the laws of physics. We were amazed that an interface could be fully loaded in both

directions at the same time—one would think that some unloading would occur,

even be encouraged, as opposing reservations or uses are made. Our skepticism

about the accuracy of the transmission providers’ claimed lack of ATC in both directions was increased by the fact that we had to replace the power we had sought

to transmit with a $4,000 per megawatt hour purchase—about 40 times the cost of

generating our own power—from one of the transmission providers.

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As a defense against such discriminatory interruptions and service denials that

are both costly and threaten reliability, AMP-Ohio has undertaken an aggressive

campaign to place 157 megawatts of small, distributed generation resources in our

member communities. But this defensive action only highlights the need to get operation of the transmission system out of the hands of market participants. Only truly

independent RTOs, with no stake in the market, can achieve the trust required to

create a marketplace—a competitively neutral platform—on which competition can

thrive, with enhanced reliability and efficient use of generation resources.

Regionalization of transmission planning under the control of an independent

RTO, with authority to expand or cause expansion of the grid, is also critical to a

robust transmission system capable of reliably handling the competitive market’s increased traffic. Single system regional planning will be a dramatic improvement

over a grid planned by numerous owners with different competitive agendas.

Vertically-integrated utilities who now control planning and expansion often have

a competitive interest in not improving their transmission system. Many risk losing

substantial amounts of money if they construct new transmission that opens their

generation up to competition. Even hefty incentives, paid by captive transmission

customers, may be insufficient to overcome this competitive disincentive. No such

hurdle would impede construction if independent RTOs had full responsibility to

plan and build, or cause construction of, transmission facilities necessary to create

and sustain competitive wholesale markets and provide a high degree of regional

reliability for end use customers. Federal legislation should confirm that RTOs must

perform this critical function.

As was stated this morning by the American Public Power Association’s witness,

Roger Fontes, legislating new forms of incentive pricing for transmission services is

NOT the right tack to take to encourage grid expansion and improvements; we

should not accept transmission owner efforts to retain exclusive rights to construct

while seeking rate incentives as an inducement to do so. Rather than granting existing owners an exclusive right to build for RTOs and giving in to their incentive demands, we should enable RTOs to put competitive pressure on the cost of capital.

Therefore, Congress should 1)authorize RTOs to cause expansion of the regional grid

by constructing transmission themselves or by bidding out construction and passive

ownership; and 2) allow and encourage public power utilities to share in the ownership of the new transmission facilities.

As FERC has also recognized, RTOs can facilitate competition by ending the current balkanized markets, where an additional ‘‘pancaked’’ rate (or toll) must be paid

whenever a transaction crosses the corporate boundaries separating one transmission owner from the next. In contrast, RTOs that eliminate rate ‘‘pancaking,’’ as FERC Order 2000 requires, would permit competitors to sell their electricity goods

throughout a broad regional market by payment of a single charge. By expanding

the market, RTOs can increase the number of buyers and sellers that can transact

with each other, enhancing competition and reducing market power.

FERC Order 2000 gets the minimum functions and characteristics of RTOs right.

However, it relies on voluntary action to get RTOs formed. But lethal to competition

are gerrymandered RTOs designed by a group of vertically-integrated utilities to enhance their market power by creating barriers to competitors. Also crippling to efforts to expand the grid, and to invest in the baseload generation necessary to serve

growing customer needs, is the uncertainty created by the ‘‘RTO-hopping’’ spawned

by reliance on voluntarism.

‘‘Musical chair’’ RTOs have plagued my region, the Midwest. We have two RTOs

forming—the Midwest ISO (MISO) and the Alliance RTO—where there should be

one, and their configurations keep changing. This past year, three major utilities—

Illinois Power, Exelon (ComEd), and Ameren—sought to exercise what they claimed

were their ‘‘rights’’ to pull out of MISO and switch to Alliance. The result (effectuated through a settlement that FERC approved) creates a hole in the Midwest

ISO. Even more recently, on August 31, DTE Energy Co.’s transmission subsidiary

filed with FERC to join the MISO and withdraw from the Alliance, despite the fact

that DTE is not directly connected with any MISO member. Revolving door RTOs

will never achieve their purposes. Nor will checkerboard RTOs.

In February 2001, the Alliance and MISO reached an agreement through FERC

mediation efforts that, in principle, calls for the continuation of the two RTOs, while

establishing a single pricing structure for certain transactions, and an inter-RTO coordination agreement. However, the effectiveness of this arrangement remains to be

seen.

Recent FERC orders and statements by FERC’s new Chairman Pat Wood indicate

a greater willingness to require RTO participation and ensure that RTOs have a

large, rational scope. In orders issued July 11, FERC expressed a preference for four

RTOs (aside from the ERCOT portion of Texas)—one in the West, one in the SouthVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00136 Fmt 6633 Sfmt 6621 E:\HEARINGS\75759 pfrm04 PsN: 75759
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east, one in the Midwest and one in the Northeast, and initiated a 45-day mediation

as step one in forming a single RTO for the Southeast and Northeast, respectively.

At FERC’s September 26 meeting, Chairman Wood issued a memo in which he

made clear his willingness to employ ‘‘sticks’’ instead of just ‘‘carrots’’ to ensure RTO

formation:

What to do about the December 15, 2001 date in Order No. 2000? I recommend that this be changed to be the date by which all jurisdictional utilities

must either elect to join an approved RTO organization or have all market

based rate privileges by any corporate affiliate be prospectively revoked, following a Section 206 investigation. I would also recommend that no mergers be

approved relating to entities who do not become part of an operational RTO.

And for an public utility that chooses not to be part of an RTO, I believe we

would need to take a hard look at the transmission rates they are permitted

to charge to ensure that they are just and reasonable and recognize the interdependence of the power grid.

While we applaud Chairman Wood’s statement, federal legislation is still needed

to clarify FERC’s authority to move forward on this newly energized course. Absent

Congressional guidance, more aggressive FERC actions are likely to get mired in

litigation. In fact, legal challenges to the flexible directives included in Order 2000

will be argued before the D.C. Circuit next week. TAPS therefore urges Congress

to adopt in legislation the RTO participation position that was developed and is supported by APPA’s transmission owning and TDU members:

• Confirm FERC’s authority to require FERC-jurisdictional (as of the date of enactment) utilities to participate in an RTO as a generic condition for continued or

requested market-based rate authorizations or as a standard requirement for

merger approval or to remedy undue discrimination.

• Authorize FERC to require transmission-owning Federal utilities to participate in

an RTO to remedy undue discrimination.

• Authorize FERC to order RTO participation by municipal and cooperative utilities

based on a finding that the utility has engaged in undue discrimination in the

provision of transmission service, or abused its control over transmission so as

to disadvantage competitors, and open access transmission tariffs are not likely

to remedy the problem. Any such orders must accommodate tax code restrictions and/or bond covenants.

2. FERC MUST BE RESPONSIBLE FOR REGULATING ALL INTERSTATE TRANSMISSION.

For electricity competition to be successful, it is essential that FERC have authority to establish one set of rules for the use and operation of the nation’s interstate

transmission system. For this reason, TAPS supports extension of FERC jurisdiction

over the terms and conditions of service over municipal and cooperative transmission systems, subject to ‘‘FERC Lite’’ provisions. In addition, TAPS supports

FERC jurisdiction over the transmission used for bundled as well as unbundled retail sales. In fact, TAPS believes the Federal Power Act as currently enacted encompasses such jurisdiction, as we made clear in our brief to the Supreme Court. However, we urge Congress to clarify FERC’s authority to reflect today’s policy objective

of promoting competitive markets and ensuring reliable service for all consumers.

The Supreme Court case pertains to Order 888, in which FERC asserted jurisdiction over transmission for unbundled retail service (where states have adopted retail

competition), but not transmission used for bundled retail sales (traditional retail

sales where the price for power is ‘‘bundled’’ with the price of transmission and distribution services). The D.C. Circuit upheld FERC’s assertion of jurisdiction over

unbundled retail transmission as compelled by binding Supreme Court precedent as

well as by deference to FERC’s interpretation. Although the Court of Appeal’s decision strongly suggests that FERC could exercise jurisdiction over the transmission

component of bundled retail electric sales, it upheld FERC’s decision not to do so

as ‘‘a statutorily permissible policy choice.’’ At the Supreme Court, a number of

states are challenging FERC’s assertion of jurisdiction over unbundled retail transmission; Enron is challenging FERC’s failure to assert jurisdiction over the transmission used for bundled retail transactions. TAPS has stated its support of Enron,

and filed a brief opposing the states’ challenge. The case was argued on October 3.

Good public policy in 2001 and beyond should not depend on whether and how

the Supreme Court interprets the 1935 Federal Power Act, as amended. Rather, for

competitive markets to work, Congress must clarify FERC’s jurisdiction over all

uses of interstate transmission.

To access competitive markets, all users must rely on the same integrated transmission grid. Perhaps no other industry stands more in need of a single set of interstate rules, and a single traffic cop, to ensure the coordinated, non-discriminatory,

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and efficient use of the transmission required to support competitive electricity markets.

Think what pandemonium would occur if the interstate highways posted two sets

of speed limits for passenger cars, one for in-state cars and the other for cars going

out of state. Think how many crashes would occur if the state established a different

regime for preferred in-state cars to switch lanes—they need not look or signal, because they are to be accorded ‘‘priority.’’ It would also be inconceivable for Virginia

to establish a rule that during rush hours, out-of-state vehicles on Interstate 95

must pull over to the shoulder so Virginia vehicles may pass.

Yet, that is precisely what divided transmission authority would allow, as determined by the Eighth Circuit. That court ruled that states could set their own rules

for the transmission of bundled retail sales and favor these in-state users when

there is insufficient transmission capacity. Northern States Power v. FERC, 176

F.3d. 1090 (8th Cir. 1999). Under NSP, each state can set its own rules for transmission of bundled retail sales within that state, without regard to what other

states do, and without regard to FERC’s rules, while FERC is limited to setting

rules for wholesale and unbundled (choice) retail uses. No regulatory body would

have authority to ensure a coherent scheme for the use and allocation, among all

users, of what is necessarily the single transmission network.

Such a system will not work. You cannot have multiple, inconsistent systems for

reserving, allocating and scheduling transmission over the unitary transmission network. Reliability, efficiency, and competitive markets will all suffer in the name of

preserving service to a favored subset of retail consumers.

For example, AMP-Ohio and its members serve the bundled retail customers of

those member cities by paying to use the transmission of other utilities. In August,

AMP-Ohio’s transmission service that permits its members to serve these retail customers under network service was curtailed, increasing costs and threatening reliability. Should these retail customers, who have long paid and continue to pay their

fair share of the costs of the transmission system, be more exposed to curtailments

than the bundled retail customers of transmission owners? And should retail customers that dare to exercise their retail choice options (where available under state

law) be treated as second-class citizens if they receive power transmitted through

a state that gives priority service to its own bundled retail customers?

As an active participant in the Midwest wholesale power market, AMP-Ohio has

experienced threats to system reliability and prices spikes in recent years. While

there are constrained transmission interfaces and a need for generation and transmission additions, in our opinion the root cause of these problems is market manipulation and market structure. Based on our 20 years of practical experience in the

market, we can attest to the fact that the market has become increasingly dysfunctional and has taken steps backward, not forward.

Retail competition will not be successful if power supplied through the market,

using FERC-jurisdictional unbundled transmission service, is less reliable than

power supplied to bundled customers. Consumers will not switch suppliers if they

cannot count on reliable delivery of power from their new supplier. Nor can competitive wholesale markets thrive where states retain authority to accord transmission

owners serving their bundled retail customers access rights superior to those of

other users.

While some will suggest that the current split jurisdiction assures reliability to

the transmission owners’ ‘‘native load’’ customers, our view is that it creates a black

box that prevents the open markets that are needed to benefit all equally ‘‘native

load’’ consumers. If a utility says it has no transmission capacity available to others

because it is needed for its own bundled retail use, can we be sure that this isn’t

market manipulation in the name of reliability? Utilities have been known to reserve all of the transmission import capacity in the unlikely event that every single

generation plant in the control area simultaneously shuts down. Removing such actions from FERC scrutiny by placing them behind a state-jurisdictional curtain invites discrimination and destroys any pretense of non-discriminatory open access.

And they subject equally ‘‘native load’’ customers of other utilities to less reliable

and more expensive service. Every utility, those that own transmission and those

that do not, have native load customers that deserve and must have equal reliability. As was said by former FERC Chairman Martin Allday, everybody is somebody’s native load customer.

As we move toward competition on a state-by-state basis, it is essential that

FERC be authorized to establish a single scheme for use of the grid that does not

relegate wholesale uses or retail choice programs to second-class status. The absence

of a clear, unified set of rules would enable one state to cripple choice programs in

a neighboring state by according in-state bundled sales a higher priority than

unbundled deliveries to its neighbors. This is not a state versus federal issue. Rather,

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it is a state versus state, consumer versus consumer issue. And only FERC is in a

position to ensure open, fair, nondiscriminatory, and reliable service to all.

TAPS urges Congress to recognize in legislation that there can be only one set

of rules for all users of the interstate transmission network, and that those rules

need to be set by FERC.

TAPS appreciates this opportunity to present its views to the Subcommittee.

Mr. BARTON. Thank you, Mr. Gerken.

We want to now hear from Mr. Peter Esposito, who is Vice President and Regulatory Counsel for Dynegy, Inc.

Your statement’s in the record and we welcome to have you

elaborate on it for 5 minutes.

STATEMENT OF PETER G. ESPOSITO

Mr. ESPOSITO. Thank you, Mr. Chairman and members of the

committee for allowing me to speak here today on behalf of the

Electric Power Supply Association and my company, Dynegy.

Those that are familiar with the energy situation last year in

California, I know you all are, might logically ask why should I

touch power? Isn’t it the third rail of energy here? The simple answer is just because California didn’t get it right doesn’t mean the

Nation as a whole can’t afford to do it. Power’s the life blood of the

American economy. Growth and demand must be met by growth

and supply and improvements in an aging infrastructure.

Today some regions are on the edge of a supply/demand imbalance, as California was. This imbalance will only get worse unless

we change today’s regulatory paradigm of a patchwork of ever

changing rules being issued under the aging statute. Simply put,

those who supply and transmit power need rules they can rely on

and consumers simply want power that is reasonably priced and

reliable. Consumers don’t want to be surprised by price spikes or

blackouts, especially given the increased threats we now face.

In this regard, incumbent monopolies have a legal obligation to

provide service often at any price. New entrants are aligned with

consumers because they know they will not be successful in the

market unless they actually provide consumers reliable power at a

reasonable price.

How do we satisfy your constituents and our customers? We satisfy their desire for reliability at reasonable prices through competitive markets that allow customers to choose from a variety of

suppliers and products that reflect the balance of price and reliability risk those customers choose to assume.

It is amazing in this United States what a profit incentive can

do to assure the products are on the shelves in ample supply. Mr.

Radanovich was here, I’d point out, to whine.

Establishing competitive markets requires some common sense

and a big picture view. There are three perspectives that are involved in any market and are involved in the electric market: That

of those who produce, in this case the generators; those who deliver, the transmission owners; and, those consume, consumers.

This isn’t rocket science. We need to assure that the raw material, energy, can be produced in large quantities and transported

flexibly to the points where consumers want to use it. Much as the

space program gave us a great political and technology benefits,

forging flexible markets gives us double benefits. It trains us to reconfigure systems to make economic sense on an hourly basis alVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00139 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
136

lowing markets to help mitigate the impacts of nefarious attacks on

our infrastructure. Flexibility works very well in the gas industry

to bring consumers great benefit, it’ll work here in the electric industry.

More specifically, from the production side we must assure easy

entry to markets. We can do that by establishing uniform interconnection rules applicable to all, as you all have proposed. But

that is not all we have to do. We have to assure that wire owners

do not restrict access to wires in order to favor their own generation, and to do that we need to separate control as we talk about

this morning.

FERC plans to do this through RTOs and Congress should affirm

FERC’s authority to compel memberships in RTOs by all transmission providers, or at a minimum not interfere with the FERC’s

current policy of saying you’re either in the old world or the new

world. That policy, if implemented, will work.

The mere formation of RTOs, however, is not enough to ensure

that markets can do their job effectively. We must assure that each

has an open access tariff that is flexible to allow the aggregation

of supply and the aggregation of customers, not just to take a static

system and use it in a static manner.

We need to deal with the seams issues between transmission providers. Today’s transmission system is all too often characterized

by numerous relatively small franchise service areas shaped in

ways that would make the best congressional redistricters proud.

To move power between regions one must contract with each of

these franchisees for transmission service.

Imagine changing trucking companies at each county line when

trying to truck tangerines from Tampa to Trenton or oranges from

Orlando to Oswego. The farmers and consumers had to pay the cost

of this inefficiency, Congress would have acted decades ago to fix

this problem and, in fact, it did by creating a national highway system. Yet this is how we transmit power in most regions today.

This structure of the early part of the last century has stayed in

place in large part due to structural and political inertia, if not outright existence. The time is right to fix this and reducing the sheer

number of transmission providers by forming RTOs is, in part, the

answer. So too is making the RTOs large enough to limit the burdens associated with changing trucks at every county line. This

doesn’t, however, require uniform markets, just consistent business

practices between the RTOs.

One problem with RTOs is that they will become big monopolies.

We need to get consumer inputs through stakeholder advisor

boards. Another thing is to incent them correctly. We talked about

incentive rates this morning. We ought to be thinking about volumetric rates. You provide more service, you make more money. It’s

a pretty simple concept, works in the gas industry.

We can remove artificial barriers including PURPA and PUHCA.

We can empower FERC to require consistent business practices.

From a transmission owner’s perspective we need a regulatory

and tax climate in which capital formation can occur. That involves

regulatory certainty, changes in tax laws and the right to make a

profit commiserate with risk.

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Second, they need the ability to expand their service to expanded

access. We talked about siting this morning.

And finally, there are other ways to expand transmission including use of existing rights of way and new technology.

Finally, consumers need to be empowered. They need to see price

signals so they know how much it’s going to cost when they consume power. California they predicted 260 hours of blackouts last

year where this past summer we had none, zero. Why? Because the

consumers got the price signal.

Finally, we need a means of consumer choice. And I know you’re

not going to go to mandating retail access, but you can set up a

paradigm in the wholesale market where retail access can work,

and I encourage you to do that.

Your bill is going in the right direction, but the devil is in the

details. I’d encourage you to take a look at those details, some of

them sort of reverse direction, and we look forward to working with

you on those details.

Thank you.

[The prepared statement of Peter G. Esposito follows:]

PREPARED STATEMENT OF PETER G. ESPOSITO ON BEHALF OF ELECTRIC POWER

SUPPLY ASSOCIATION AND DYNEGY INC.

Mr. Chairman and members of the Committee. Thank you for allowing me to

speak here today on behalf of the Electric Power Supply Association. EPSA is comprised of generators and marketers of electric power. I also speak on behalf of

Dynegy, a marketer and generation owner, and a member of EPSA.

Those familiar with the energy situation that developed in California over the last

year will agree that incorrectly restructuring the power industry can have dire consequences. Armed with this knowledge, you may quite naturally ask: ‘‘why should

I touch power; it could be just another political third rail?’’

The simple answer is that just because California didn’t do it right doesn’t mean

the Nation as a whole can afford not to do it at all. Now more than ever, power

is the lifeblood of the American economy. Growth in demand must be matched by

growth in supply and improvements in an aging delivery infrastructure. Today,

some regions are on the edge of a supply demand imbalance. This imbalance will

only get worse unless we change today’s regulatory paradigm of a patchwork of

ever-changing rules being issued under an aging statute.

While those who supply and transmit power need modern rules they can rely on,

consumers simply want power that is reasonably priced and reliable. They don’t

want to be surprised by price spikes or blackouts, especially given the increased

threats we now face.

Incumbent monopolies have a legal obligation to provide reliable service at any

price. New entrants are aligned with consumers because they know that they will

not be successful unless they actually provide consumers reliable power at a reasonable price.

How do we achieve these reliability and price objectives simultaneously? Everyone

seems to have an idea,

• Do we have the government build power plants to create a reserve? That would

be folly unless we want the government to build all the plants. Otherwise the

private sector would simply back off its new construction until equilibrium of

supply and demand was created. No one is going to build power plants in a

glutted market if they are not going to get back their investment and some return on that investment.

• Do we require public utilities to build more generation? Go back to the ‘‘good old

days?’’ Remember what got us here was overbuilding during the rate-based

‘‘nothing’s too good for the ratepayers’’ construct, where the ratepayers are on

the hook to pay for virtually anything and everything the utilities build, whether it is economic or not. Can our economy afford to pay large premiums on

power year after year under the old regulated regime while our competitors in

the rest of the world adopts the new deregulated regime? Of course not!

And how do we satisfy your constituents and our customers? We can satisfy their

desire for reliability at reasonable prices through competitive markets that allow

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customers to choose from a variety of suppliers and products that reflect the balance

of price and reliability risk those customers choose to assume. It is amazing in this

United States what the profit incentive can do to assure that products are on

shelves in abundant supply.

Establishing competitive markets does not involve nuclear physics. It does, however, require some common sense and a big-picture view.

There are three perspectives this Committee must consider when addressing electric restructuring. These are the perspectives of:

1. Generators: those who produce the product and who need easy entry to markets,

signified by access to the grid

2. Transmission owners: those who deliver the power, who need roadblocks to

grid expansion removed, and

3. Consumers: those who purchase and consume power, and who deserve power

that is reasonably priced and reliable.

These are the three basic players in any market. Each needs to be empowered.

This is not rocket science. We need to assure that the raw material—energy—can be produced in large quantities and transported flexibly to the points where con- sumers want to use it. Much as the space program gave us great political and technological benefits, forging flexible markets gives us a double benefit: By training us

to reconfigure systems to make economic sense on an hourly basis, vibrant, flexible

markets also help mitigate the impacts of nefarious attacks on our infrastructure.

More specifically:

First, from the production side, you must assure generators easy entry to

markets. In power industry parlance, this means assuring that new generation can

get interconnected to the grid and that, once connected, it is able to reach many

consuming markets under reasonable contractual terms and at a price that is reasonable and determinable in advance.

Bearing in mind that transmission is presently a monopoly and will be for some

time, this means:

• establishing base-line interconnection rules for all markets, in all states, that require transmission owners to provide new generators with open access to their

delivery systems, even when those new generators compete with generation

owned by those who control the wires.

One means of assuring that wires owners do not restrict access to wires in order

to favor their own generation is to separate the control of wires from control of competing generation. FERC plans to do this through the formation of large Regional

Transmission Organizations (RTOs), in effect pooling the transmission assets of

many utilities under one independent operator. Congress should affirm FERC’s authority to compel membership in RTOs by all transmission providers.

The mere formation of RTOs, however, is not enough to assure that markets can

do their job effectively. We must:

• Assure that each RTO has open access tariffs that facilitate the movement of

power from many generators to many consumers. These tariffs must apply fairly and across the board to all users of the transmission system so as to assure

each a chance to compete, both in the sale and purchase of energy.

• Deal with ‘‘seams’’ issues between transmission providers. Today’s transmission system is all too often characterized by numerous relatively small franchised service areas shaped in ways that would make the best Congressional

redistricters proud. To move power between regions, one must contract with

each of these franchisees for transmission service. Imagine changing trucking

companies at each county line when trying to truck tangerines from Tampa to

Trenton. If the farmers and consumers had to pay the costs of this inefficiency,

Congress would have acted decades ago to fix the problem, indeed it did by creating a national highway system with characteristics like minimum bridge

heights. Yet this is how we transport power in most regions of the country

today. This vestige of the early part of the last century has stayed in place in

large part due to structural and political inertia, if not outright resistance. The

time is ripe to fix this, and reducing the sheer number of transmission providers

by forming RTOs is, in part, the answer. So too is making RTOs large enough

so that the burdens associated, for example, with moving power from Florida

to the PJM are not overwhelming.

• One problem with RTOs is that they will, by definition, become giant monopolies.

Giant monopolies generally have no incentive to act like a competitive

business and their service tends to become ‘‘bureaucratic,’’ to be kind. Because

customers will not have another RTO to go to for service if they don’t like their

regional RTO, we must create incentives for RTOs to treat customers as customers. There are two ways to address this.

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• First, there must be some recognized means of assuring customer input is taken

seriously, for example through stakeholder advisory boards to the the RTO.

• The second is to make RTO cost and profit recovery dependent on providing valuable service, e.g., by setting up rate designs that are based on throughput, not merely on ownership of wires. When the RTO does a good job,

it should be rewarded; when it does not, it should not.

• Economies of scale must be achievable:

• Congress should remove artificial barriers, including ownership restrictions

included in PURPA and PUHCA.

• FERC must be empowered to require consistent transmission business

practices across the country.

Second, from the transmission provider perspective, you must give the

RTOs the tools to do their job and the ability to make a profit. This entails providing:

• A regulatory and tax climate in which capital formation can occur.

• Regulatory certainty: Change is inevitable, but constantly changing rules

need not be. Just as generators are asking for some certainty in environmental requirements and market rules, transmission owners have a right to

know what is expected of them; when they will be rewarded and when they

will be punished by regulators.

• When change is required, there should be adjustments made to facilitate

change. Here, tax laws changes are necessary to assure that taxable events

do not occur simply because transmission assets are transferred under government request to RTO control.

• Transmission owners must have the right to make a profit commensurate

with risk.

• The ability to provide better service with expanded assets. The surest way

to eliminate any semblance of generator market power is to remove all congestion from the system, so that many sellers can reach many buyers and viceversa. This will require that something be done to facilitate siting of new transmission facilities, in what could be a very painful political process. This could

occur through regional compacts, or through RTO processes, with a federal eminent domain backstop. Again, consumers all over the nation will benefit from

better markets and increased infrastructure security if we come together as a

Nation to deal with critical siting issues. Whatever method of dealing with

these issues is chosen, landowners must feel they got a fair shake.

• Let us not forget in this quest that there are many ways to expand transmission,

through the use of existing rights of way and with new technology. New wires

in new rights of way are not the only way to expand and enhance the transmission system.

Third, consumers need to be empowered.

• Price signals: Consumers need to be charged power they consume, so they know

how much they will be billed if they consume more or less of it. Contrary to

lore, demand for power in the aggregate is elastic, as has been proven so forcefully in California this summer:

• where the NERC predicted 260 hours of blackout and none, repeat none, occurred, and

• where wholesale prices came down before West-wide wholesale price caps went

into effect, once retail prices rose.

• Choice: Getting wholesale markets right means establishing the foundation for

customer choice. In California, had customers been able to choose the 5 to 6

cent power being offered by generators last year they would not now be shouldering the burden of much more expensive power that was purchased last winter, before demand dropped off. We realize that the Congress is not likely to

force choice on the states, but it should at least give the states wholesale markets that allow choice to go forward should the states so choose.

Finally, but most importantly, we all need market rules that set up sustainable

markets, that is, markets that are fair both to consumers and suppliers of power.

Just as price caps will stifle the addition of needed generation, so too will very high

prices stifle the economic growth and prosperity of our country.

Both FERC and Congress have a role in assuring we meet these goals. Congress

can best help consumers receive the most reliable and reasonably priced power by

reaffirming FERC’s authority and providing it with policy direction and appropriate

flexibility to achieve these goals. The time to do this is now.

Mr. BARTON. Thank you.

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We now want to hear from Mr. Charles Trabandt, former FERC

Commissioner, former general counsel to this committee, former

general counsel, I think, to the Senate Energy Power Committee

and until August the CEO of a company that was located, I believe,

in one of the towers at the World Trade Center.

So, we really, really appreciate you being here and appreciate

your expertise, and thank you for your prior service to the country.

And I’m sure that you have many services yet to provide for the

country. Welcome to the committee.

Your testimony is in the record and we would ask you to summarize it in 5 minutes.

STATEMENT OF CHARLES A. TRABANDT

Mr. TRABANDT. Thank you, Mr. Chairman. It’s a privilege to be

with the committee again.

As this morning’s hearing demonstrated, there’s a critical need

for capital investment in the Nation’s electric transmission infrastructure and I would suggest that isn’t just for new interregional

lines. The country is quite a bit behind in terms of sustaining capital investment for the existing system, as well as for new transmission lines. And I encourage you to think of that.

Pat Wood last week also informed the country as well as you, as

I understand it, that the needs that we had prior to September 11

probably are going to increase as a result of the attacks and the

requirements of the new homeland defense infrastructure requirements, which both you and the Senate are considering right now.

FERC in Order 2000 sought to address that need by providing

structural and regulatory flexibility for independent for-profit

transmission companies or transcos as an alternative business

model for the regional transmission organizations. That flexibility,

in fact, have worked and I’m sure you’re well informed of this, but

we have across the country in every region a large number of investor owned utilities and public power entities which have joined

transcos.

Just last week a group of six southwest utilities acted to create

the newest transco that would serve Arizona and New Mexico.

Today it is clear from a business and financial perspective that

the for-profit business model is a viable and, I believe, preferred

option for RTOs. Furthermore, I am convinced a properly structured transco will be able to access the capital markets for equity

and debt financing to provide timely funding for the improvement

and expansion of the transmission infrastructure, which was the

nature of my responsibilities as a managing director at Merrill

Lynch.

The Alliance Transco RTO with National Grid USA as the proposed managing member I suggest is one example of the transco

RTO model which provides important precedence for further

transco development. In that model National Grid, as you may

know, has committed to a billion dollars of investment in the Alliance company’s systems as part of the deal that was struck in August.

I couldn’t agree more with Mr. Vesey who spoke to you this

morning about the new RTO transmission business under your bill

as well as under Order 2000. I think it’s a mistake to think of the

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new transmission business that these RTOs will be running as the

same thing as transmission services that have been provided in the

past. This is a new business model, it involves different risks and

it certainly, in my judgment, is worthy of consideration of incentives to ensure the availability of capital to meet all the responsibilities that the RTOs will have that the utilities did not have in

providing transmission services.

FERC in July, however, took actions to require mediation negotiations in the northeast and the southeast intended to support an

immediate drive toward a single RTO in each region. The actions

signaled a major policy change to establish four RTOs, one each in

the northeast, southeast, midwest and the west and to do so without the incentives and the flexibility provided by Order 2000, which

as I just indicated has been successful from the model that I support.

I would counsel caution with regards to such an immediate policy

change because of the potential risk that it will materially disadvantage the transco alternative, and thereby inhibit the availability of capital for existing systems and new systems.

Also such a policy change could have a negative impact on FERC

actions already taken such as the alliance, Midwest ISO settlement

arrangements which will support initial operations in the midwest

in the very near future.

Finally, I would recommend that the subcommittee in any legislation consider measures to preserve the structural and regulatory

flexibility of Order 2000 for the RTOs, particularly in the transco

business model. Such measures I believe should ensure the

transcos can be a vital segment of the future electric transmission

system and provide the needed capital for investment.

In addition, I would recommend that the subcommittee consider

appropriate procedures to protect investments already made and

approved in operating transcos, and to provide for an orderly transition to any new policy direction which, Mr. Chairman, I think

you’ve laid out in your discussion draft which, hopefully, would continue to support a viable transco alternative and financing for the

infrastructure needs of the industry.

Thank you, Mr. Chairman.

[The prepared statement of Charles A. Trabandt follows:]

PREPARED STATEMENT OF CHARLES A. TRABANDT

Thank you, Mr. Chairman, for the opportunity to testify before the Subcommittee

on the subject of ‘‘Electric Transmission Policy: Regional Transmission Organizations, Open Access, and Federal Jurisdiction.’’ At the outset, I want to commend the

Subcommittee for its decision to proceed with these hearings. While we can never

forget the horrific and tragic events of September 11th, we also cannot allow the

perpetrators of those acts of war to paralyze our great nation. So, it is appropriate

that important business such as these hearings go forward to address critical energy

issues of the future.

On the morning of September 11th, I was at the Institute of Nuclear Power Operations (INPO) in Atlanta for a regularly scheduled meeting of the INPO Advisory

Council and a dinner to honor Dr. Jim Rhodes, the retiring INPO CEO. As the terrible events of that morning unfolded, the meeting was canceled and INPO immediately joined nuclear utilities across the country in tightening security and implementing emergency preparedness plans with impressive professionalism. From all

reports, the nuclear industry performed superbly throughout those early days of national crisis and continues to do so.

That same morning, my former colleagues in the Global Energy and Power Group

of Merrill Lynch’s Investment Banking Division had just arrived at their offices in

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the North Tower of the World Financial Center, across from the World Trade Center. They were evacuated immediately after watching in horror as the second hijacked aircraft hit the twin towers. I am thankful to report that they all escaped

without serious injury. However, it now appears that those offices could be closed

for an extended period, so my old group will be relocated elsewhere in the New York

City area.

I have been asked to provide testimony on FERC’s Order No. 2000 RTO policy

from a financial perspective, with particular emphasis on the independent transmission company or transco alternative and the incentives for transco’s. My testimony reflects my eight years of experience as a Managing Director in the Global

Energy and Power Group of Merrill Lynch’s Investment Banking Division, from

which I retired in August. As a Managing Director, I had responsibility for strategic

advisory assignments for electric utility and energy company clients around the

world. Among other assignments, I have advised electric utilities on specific transmission transactions, including the establishment, financing and strategy of Hydro

One in Ontario and the establishment and financing of U.S. RTO’s. My testimony

is also informed by my prior service as a FERC Commissioner and as a Committee

Counsel in the House of Representatives and the Senate.

Other witnesses in this and prior hearings have testified about the increasingly

urgent need for investment in the nation’s electric transmission infrastructure. Investment by any measure has fallen just as the wholesale electricity market under

open access policies has grown dramatically. And, just as the electricity system

moves toward Regional Transmission Organizations, the stress and strain on the

transmission infrastructure is going to increase at an accelerating rate for several

reasons. Electricity demand nationwide has continued to grow and is projected to do so at

a steady rate. Construction of new generation plants is underway at a record pace,

requiring new interconnections and upgrades and increasing the demand for transmission services. Wholesale electric transactions for existing generation, with associated transmission service requirements, have increased several fold in recent years.

Additionally, the system already is experiencing increased congestion with growing

costs and fast rising transmission curtailments or TLR’s. And probably not yet well

understood nor fully appreciated, the existence of a new RTO can significantly

change the wholesale transaction structures and transmission service requirements

to execute newly economic trades. In short, there is a critical need to provide investment to maintain the national grid, which undoubtedly will increase in the aftermath of the September 11th attacks and in the new context of homeland defense.

These relatively inevitable pressures on the electric transmission system in the

context of the drive to RTO’s under FERC Order No. 2000 support a flexible approach to financing and structuring RTO’s. FERC acted prudently to provide the

electric industry with the opportunity to structure RTO’s as independent for-profit

transmission companies (transco’s), as Independent System Operators (ISO’s) or as

hybrid ISO-transco organizations. Hybrid organizations could include an RTO structured as an ISO with one or more transco’s as members, who also may provide various services to the RTO.

FERC also developed a transmission rate-making policy for RTO’s which was intended to remove pricing disincentives for transmission owners to join RTO’s and

to help transmission companies become viable businesses. Under that rubric, FERC

endorsed Performance-Based Rate Regulation (PBR) for RTO’s to create incentives

to make efficient operating and investment decisions, share benefits between customers and the RTO, protect system reliability, and prescribe rewards and penalties

in advance based on benchmarks. PBR has been implemented for transmission services in Canada and the United Kingdom, in Federal regulation of telecommunications in the U.S., and by State PUC’s for retail electric, gas, and telecommunications service.

Consequently, while a novel concept at FERC thus far, the PBR approach is well

established in regulatory circles. What is less apparent, however, is that it will take

some time to collect the required data for the benchmarks for a new, non-power pool

RTO. Nonetheless, the PBR has substantial financial and regulatory appeal as an

alternative to FERC’s traditional transmission ratemaking policy.

In addition, FERC decided to consider innovative pricing proposals for RTO’s, on

a case-by-case basis, in response to its concern about continued under-investment

in the transmission grid. The possible innovative pricing proposals include a formula rate of return, levelized rates, accelerated depreciation and incremental pricing for new transmission facilities. FERC also encouraged market approaches to

congestion management as early as feasible. An RTO also can propose a rate moratorium for the period through January 1, 2005, and capture cost-saving benefits or

increase leverage to increase earnings. Additionally, FERC will consider acquisition

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adjustments on a case-specific basis where there are measurable benefits to customers.

FERC also recognized that the IRS Code created a substantial disincentive for

transmission owners to divest substantially depreciated transmission systems. As a

result, passive ownership rules provide specific protections and rights for those owners who transfer control to the RTO (transco). Of course, the House-passed energy

legislation would address the problem and mitigate or remove that tax disincentive.

Another disincentive exists in the context of registration requirements under

PUHCA with the SEC. The multi-state nature of the larger proposed RTO’s could

trigger a registration requirement for the owner of a small active ownership interest, with relatively severe limitations and approval requirements for other business

and financial activity. Several potential strategic partners and equity financial investors have indicated that they would be unwilling to accept registration as a condition of a strategic partnership or an active equity investment in an RTO. Legislative action by the Congress or administrative action by the SEC may serve to remove this financial disincentive at some point.

Not surprisingly, many possible strategic partners and equity financial investors

are themselves directly, or are affiliated with, market participants, as defined by

Order No. 2000. As such, those potential investors are limited by the FERC rules

to a 5% ownership stake for 5 years, in order to ensure RTO independence, although

they could make qualified passive investments. Thus, the market participant limitations do constrain the investment opportunity for many potential (and knowledgeable) investors and limit the universe for marketing transco private equity. But, it

does not appear that FERC will amend Order No. 2000 to address this issue.

FERC also adopted a policy of ‘‘open architecture’’ and required that RTO’s be designed so that they can evolve over time. The purpose of open architecture is to

allow RTO’s to improve, evolve and accommodate technical change, albeit subject to

FERC review. The open architecture policy is particularly important for transco’s,

given the likely substantial changes between Day 1 operations and later requirements, such as congestion management and new investment policies, which have

major financial implications.

This overall regulatory flexibility has spawned transco proposals across the country, which could create the proper conditions for the nascent independent transmission industry. Transco’s could support further development of the competitive

wholesale electricity market by accessing capital markets to secure the much needed

financing for sustaining capital expenditures, upgrades and expansion of the transmission infrastructure. As a general financial matter, transco’s should become attractive as an equity investment to strategic partners, financial (private equity) investors, and the public market.

Strategic partners will be attracted by the opportunity to manage a significant

asset base, share in the value creation potential (‘‘gain sharing’’), have specified

rights with regards to the assets, and an acceptable projected return on the equity

investment. There are indications that there are a number of potential strategic

partners, however the probable requirement to register under PUHCA with the SEC

is an impediment today. Financial investors will require a well-defined and meaningful investment as a private placement with a subscription agreement, appropriate limitations on liability, an acceptable return and exit strategy, board representation, and other typical features. There are definitely financial investors interested in the transco opportunity, provided that the specific transco structure can be

formulated to satisfy their individual requirements.

Transco’s also may become attractive to the public equity markets in the form of

an IPO, a spin-off, or a tracking stock, each of which has differing characteristics

and conditions. The IPO alternative probably will require, among other factors, a

solid management track record of a couple of years, a good business plan and marketing story, sufficient size for liquidity, adequate projected growth and total return,

well developed valuation, reasonable regulatory stability, and of course, a positive

stock market environment. As a result, it is not likely that the new transco’s under

Order No. 2000 will be positioned for an IPO in the first or second year of operations. That factor suggests the importance of a strategic partner and/or financial

investors in the initial transco financial plan.

Additionally, transco’s should be capable of obtaining strong investment grade

credit ratings, which will support financing by access to debt markets. Credit rating

agencies have become more experienced with the transco concept and have developed a series of quantitative metrics and qualitative factors to assess the credit

quality of a transco. A transco with transmission system assets should be able to

achieve a solid investment grade rating with a capital structure having debt in the

range of 60% to 70%, under reasonably favorable regulatory treatment.

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The electric utility industry is moving with reasonable dispatch to capture the opportunity provided by the FERC regulatory flexibility. For example, the Alliance

Companies (nine Midwestern utilities and Dominion Energy), Grid South (three investor-owned utilities serving the bulk of customers in North Carolina and South

Carolina), Southern Company and public power groups in Georgia, Alabama, and

Mississippi, Grid Florida (three investor owned utilities serving the bulk of customers in Florida), Entergy in Arkansas, Louisiana and Mississippi, and

TransConnect (five investor-owned utilities in the Pacific Northwest) have proposed

and committed resources in varying degrees to a for-profit Limited Liability Company (LLC) structure for their RTO. Utilities, such as First Energy, DTE and Consumers Energy, have created independent transmission subsidiaries to facilitate options for their systems. In addition, the American Transmission Company with investor-owned and public-owned transmission systems in Wisconsin already has, and

the TRANSLink group, including NSP, Mid-American, Alliant, NPPD and OPPD, is

in the process of, forming independent transmission companies in the hybrid structure under the Midwest ISO-proposed RTO. And, last week, Arizona Public Service,

Salt River Project, El Paso Electric, Public Service of New Mexico, Tucson Electric

and Texas-New Mexico Power announced that they were abandoning the non-profit

DesertSTAR ISO proposal in favor of a new for-profit transco RTO, WestConnect,

for the southwest region. Each of these initiatives will create the opportunity in one

form or another to access capital markets for financing purposes.

Two recent developments highlight the opportunity for for-profit transco’s. First,

a new consortium, in July 2001, won a structured auction in Alberta and signed an

agreement to acquire the TransAlta transmission system which supplies 60% of the

Province’s transmission requirements. The consortium is 50% owned by SNCLavalin, one of the leading engineering and construction firms in the world, 25%

owned by the Ontario Teacher’s Pension Plan Board, a large institutional investor

in Canada (OTPP), 15% owned by Macquarie Financial Group of Australia, and 10%

owned by Trans-Elect of the U.S. The consortium paid a premium for the TransAlta

assets in a competition which reportedly included several other international strategic and financial investors.

SNC-Lavalin made the investment to capitalize on its international engineering

and financing expertise, which when combined with the strengths of the TransAlta

team, would support high quality transmission services and much needed expansion

of Alberta’s interconnections with surrounding jurisdictions. OTPP concluded that

Alberta wanted to make it attractive for investors to expand the electricity system,

such that the TransAlta transmission business was a good asset to finance pensions.

And, Macquarie also saw the acquisition as a good investment and its first of many

infrastructure investments in Canada. While not directly on point in the context of

U.S. RTO’s, this consortium demonstrates that there are strategic investors, such

as SNC-Lavalin, and financial investors, such as OTPP and Macquarie, who are prepared to make financial commitments in the transmission infrastructure under favorable financial conditions.

More recently, on August 28, 2001, eight of the Alliance Companies, announced

that they had signed a Letter of Intent (LOI) with National Grid USA, by which

National Grid USA would become the Managing Member of the Alliance Transco

LLC. The transaction is subject to the negotiation of definitive documents pursuant

to a detailed Term Sheet attached to the LOI and to a FERC determination that

National Grid USA is qualified to be Managing Member. The eight Alliance Companies and National Grid USA made filings at FERC on August 28 seeking the requisite approvals of the joint Alliance Transco LLC. The Alliance RTO has already

been substantially approved by FERC under Order No. 2000.

The Alliance-National Grid USA transaction is highly significant and well reflects

the potential business, commercial and financial benefits of FERC’s regulatory flexibility with regard to RTO structure under Order No. 2000. A key element of the

transaction as filed at FERC is a non-binding declaration of intent by Commonwealth Edison to divest transmission facilities with a gross book value exceeding $1

billion. Such a declaration of intent satisfies a critical pre-condition for establishing

Alliance Transco LLC as the Alliance RTO. The resulting RTO would be structured

as a for-profit transmission LLC, the first of its kind to become operational under

Order No. 2000.

The Term Sheet attached to the LOI lays out the key elements of a strategic partnership which would be beneficial to the Alliance Companies, National Grid USA

and the customers of the Alliance Transco RTO. National Grid USA’s parent company has an excellent track record in the United Kingdom for managing transmission assets effectively and ensuring reliable delivery of electricity. The Term

Sheet commits National Grid to making $1 billion in specified investments in the

Alliance RTO in exchange for a seven-year management contract and associated

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compensation. At the same time, the Alliance Companies are provided with significant incentives to divest their assets in the form of cash and attractive passive investments with financial benefits and assured liquidity in several forms.

For those companies which do not divest immediately, there will be various protections to ensure that National Grid USA as Managing Member fulfills it obligations in its functional control of their systems. Both divesting and non-divesting Alliance Companies will have FERC-approved approval rights over certain National

Grid USA actions, while National Grid will have a right of first negotiation on any

transmission asset sales by an Alliance Company to another party. In my judgment,

the Alliance-National Grid USA LOI and Term Sheet is an excellent example of the

types of commercially-based business and financial transactions which are possible

under FERC’s transco-RTO structure.

The FERC transco-RTO structure can also be beneficial in creating a businessoriented approach and commercial culture for providing RTO services. In that regard, the Alliance Companies created a special purpose LLC structure for the startup activities required to support initial operations of Alliance RTO. The special purpose LLC, with the nickname ‘‘Bridge Co’’, is a classic model of a lean but effective

commercial organization in modern business terms.

Bridge Co has a CEO as the only full time employee and a staff of seconded employees, supported by consultants and contractors with tightly negotiated contract

arrangements. Bridge Co is coordinating all of the start-up arrangements for Alliance RTO, but without making any market design-related business decisions. In

order to minimize initial operating costs and maximize open architecture design

flexibility in the future, Bridge Co has negotiated favorable contracts for virtually

all RTO-required functions and has avoided any significant investment in functional

assets.

All back office functions, employee benefits packages, information technology requirements, subordinate security coordination and supporting activities have been

outsourced and procured by competitive bid from non-affiliated vendors. Additionally, Bridge Co has optimized organizational centralization and decentralized operations, such that staffing levels are adequate and cost-effective. The combination of

these forward looking commercial approaches should support an initial RTO operation and organization that will have minimized costs on day one, while ensuring

operational reliability, system security and high quality services for Alliance RTO

transmission customers.

Bridge Co currently is completing RTO system tests with vendors, conducting customer training programs and beginning operational tests with the Alliance Companies and then Alliance customers. Bridge Co is now hiring the operational staff required for 24/7 transmission operations. Total cost for the Bridge Co start-up effort

and payment of Alliance Companies’ expenses is approximately $75 million, which

would be reimbursed by National Grid USA pursuant to the LOI. The existing Alliance master schedule contemplates that all necessary preparations will be completed and all required approvals will be received for initial operations, assuming

timely FERC and state PUC actions. That result also could be another tangible benefit of the FERC transco-RTO policy, recalling that the Alliance companies operate

in eleven states, stretching from Missouri to Virginia, with approximately 57,000

miles of transmission lines, 115 Gwe of generation capacity, and serving approximately 40 million customers.

The fact that the Alliance for-profit transco RTO has reached the stage of operational testing for initial operations, while at the same time negotiating the definitive documents for a strategic partnership with National Grid USA as the Managing

Member of Alliance Transco LLC, is itself a testament to FERC’s flexible RTO policy. Quite importantly, FERC in January 2001, ordered that the Alliance Companies

and MISO participate in a settlement conference associated with the requests of

Ameren, Commonwealth Edison and Illinois Power to withdraw from MISO and join

the Alliance. Chief Administrative Law Judge Wagner presided over a two-month

negotiation which culminated in a settlement approved by FERC.

Under the settlement, Alliance and MISO were authorized to pursue their separate RTO models, the three withdrawing companies made total payments of $60

million to MISO, and Alliance and MISO were required to implement an Inter-Regional Coordination Agreement and develop a super-regional rate. The thrust of the

latter requirement was to create a seamless market for transmission services to support a competitive wholesale electricity market across the Midwest region. Alliance

and MISO have pursued that objective aggressively in so-called ‘‘seams’’ negotiations

and in Open Access Transmission Tariff filings made at the end of August to support initial operations of both systems. Similarly, Alliance and MISO have participated in a stakeholder process to address the key market design issues associated

with congestion management in their respective systems.

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Of course, there is opposition to the flexibility which has resulted in the AllianceMISO settlement agreement and the Alliance-National Grid USA LOI. Opponents

generally prefer the ISO structure for a Midwest RTO and/or are anxious to put in

place a single, fully integrated electricity market in the Midwest supported by one

RTO, and I respect those views. FERC on July 12, 2001, signaled that the majority

was in favor of four large RTO’s in the Northeast, Southeast, Midwest, and West,

and ordered jurisdictional transmission owners in the Northeast (PJM ISO, N.Y.

ISO and N.E. ISO) and the Southeast into ‘‘mediation’’ negotiations facilitated by

FERC ALJ’s. Various parties have petitioned FERC to convene Midwest ‘‘mediation’’ negotiations intended to reverse the Alliance-MISO settlement and broker some

form of direct merger to form a single Midwest RTO.

FERC has provided some additional detail in the past few weeks regarding its

new RTO policy. Chairman Wood testified before the Subcommittee that large RTO’s were not only required for competitive markets, but were now imperative for a reliable national power grid. He testified that the cost of planning and executing the

necessary level of security and infrastructure protection will be significant and will

require expertise that only large region-wide organizations can provide. To that end,

FERC plans to make decisions in the Northeast and Southwest mediation cases in

the next month or so, based on mediation reports from the assigned ALJ’s. FERC

has scheduled technical conferences next week on the key RTO market structure

issues, including congestion management, cost recovery, market monitoring, transmission planning, business and reliability standards and the nature of transmission

rights. The conferences will form the basis for a rulemaking to establish a significant amount of standardization nationwide in uniform market structure regulations.

FERC also will review the status of the Alliance-MISO seams agreement and possibly consider requiring mediation for a merger, while encouraging RTO West and

DesertSTAR to initiate merger discussions for a west-wide RTO which eventually

would include California.

Other witnesses have testified about the legal and policy considerations in opposition to and support of the FERC-ordered mediation in the Northeast and Southeast

and the concept of four RTO’s nationwide. From a business and financial perspective, I would counsel caution in this immediate policy direction. Policy makers and

regulators may wish to consider the potential risk that the transco RTO alternative

will be materially disadvantaged by such a significant and immediate change in the

FERC RTO policy.

In the area of infrastructure and transmission grid security, the Congress, the Administration and industry have responded in quick order to the heightened threat

of terrorism. The Subcommittee provided leadership with the hearing on September

20th with Administration witnesses and related activities. The Department of Energy was scheduled to make legislative recommendations on security on October 9th

with immediate Committee mark-up of emergency legislation in the Senate this

week. NERC has been in a readiness state of high alert and an EEI task force has

been working with NERC, NEI, other energy trade groups and DOE on enhanced

security measures.

All of these initiatives, and undoubtedly many more in the context of homeland

defense, will parallel the preparations for Desert Storm a decade ago. Government

and industry worked in close cooperation then to ensure adequate protection of our

vital energy sector. And, I ’m confident that today’s efforts ultimately will be just

as successful in the face of the new terrorist threat. At the same time, I support

action by the Subcommittee to pursue its legislative agenda in the area of electricity

policy. The nation now will probably require even more capital investment in the

electric transmission grid and there needs to be some resolution of the major policy

issues to support that result.

In conclusion, the structural and regulatory flexibility provided by FERC under

Order NO. 2000 has spawned a new generation of independent for-profit transmission companies and RTO’s. Those transco’s will be operated on a commercial

business-like basis and should have access to the capital markets. Transco’s should

have the financial capability if properly incentivized to fund the critical transmission infrastructure improvements and expansion required to maintain system reliability and to support a competitive wholesale market. I would recommend that

the Subcommittee in any Federal transmission policy legislation consider measures

to preserve that flexibility, so that transco’s can continue to be a viable and growing

segment of the future electric transmission system. In addition, I would recommend

that the Subcommittee consider appropriate procedures to protect investments already made in approved and operating transco’s and to provide for an orderly transition to any new policy direction, which hopefully would continue to support a viable transco alternative.

Thank you, Mr. Chairman. I would be pleased to answer any questions.

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Mr. BARTON. Thank you.

We now want to hear from Mr. Michael Travieso, who is with

Maryland People’s Council.

We do appreciate your expediting your schedule to get here. Your

testimony’s in the record, and we would welcome you to elaborate

on it for 5 minutes.

STATEMENT OF MICHAEL J. TRAVIESO

Mr. TRAVIESO. Thank you very much, Mr. Chairman.

It’s not easy, I guess, but it’s Travieso, it’s apropos here. I guess

it’s like the oil company used to be.

Mr. BARTON. Well, I apologize for mispronouncing it.

Mr. TRAVIESO. That’s okay.

I am the Maryland People’s Counsel. I was appointed to that position by Governor William Donald Schaeffer in 1994, and serve at

the pleasure of the current Governor. I run a small State agency

which has the responsibility for representing residential customers

in the energy and telecommunications industries.

My office has been very active in the past in PJM and the formation of the PJM policies, and is currently very active in the Northeast RTO process. We’ve been involved in the 45 day mediation

process and continue to be involved.

I would like to commend you, Chairman Barton and the members of the committee and your staff for continuing efforts to seek

out and include the views of consumers or consumer representative

as you proceed with your inquiry into the development of effective

competitive wholesale markets. My testimony, however, is not intended as an endorsement of the deregulation and restructuring of

the electric industry everywhere. While Maryland has restructured,

I share the concerns of many about the ability of residential and

small business customers to benefit unless wholesale markets can

be made to function efficiently. Without a workably and competitive and efficient wholesale market, retail prices will be higher and

perhaps much higher than necessary.

I also believe that individual States who have restructured

should be able to determine their own fate and determine, if they

wish, that utilities with the obligation to serve under just and reasonable rates should remain in place.

This testimony will focus on the basic principles necessary to establish a proper framework for a competitive wholesale market.

I believe that the existing transmission systems were not

planned or built to serve regional markets, and therefore must be

redesigned. I believe that RTOs should have the authority to conduct transmission planning, studies and have the authority backed

by FERC to order the construction of new transmission.

I do not favor for-profit transmission companies. I believe that it

will raise the cost of capital for transmission organizations and

companies just as they have done for generators. Regulated transmission companies have not had difficulty attracting capital because under the cost of service regulation they are guaranteed a return. In fact, utility’s cost of capital has traditionally been among

the lowest of any businesses in the United States.

Larger regional transmission organizations are better than

smaller ones because of the reduction in administrative and transVerDate 11-MAY-2000 09:30 Apr 11, 2002 Jkt 010199 PO 00000 Frm 00151 Fmt 6633 Sfmt 6602 E:\HEARINGS\75759 pfrm04 PsN: 75759
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action costs and the increase in generating capacity and diversity.

I think the 40,000 megawatts which is in the bill is too small. I

think that when you have transmission RTOs of that size, there’s

a significant risk of the exercise of market power. And my office favors the creation of the northeast RTO, although we have lots of

concerns. That would create an RTO of over 120,000 megawatts,

which would have the effect of reducing the opportunity for generators, generator owners to strategically bid their generation and to

raise the price.

I would say the principle difficulty in ensuring a truly competitive wholesale market would be creating one of sufficient size and

scope to create uncertainly on the part of owners of generation that

their bids to sell power will be accepted. I’m not talking about regulatory uncertainty. I’m talking about a situation in which there are

enough sellers that the bids that these sellers are going to submit

will have to be at or near marginal costs in order for them to actually sell their power. and when we redesign the electric system and

returned, that’s what the rhetoric was; the bids were going to be

at or near marginal costs. That can only happen if there is a sufficient number of sellers, sufficient liquidity in the market, both the

energy and the capacity market.

I favor fewer and larger RTOs as long as they are properly structured, cost benefit analysis are performed prior to their formation

and costs are not shifted from one set of customers to another or

from customers of high cost transmission owners to those of low

cost transmission owners.

I oppose incentive rate making and actually NASUCA, the organization that my office is a member of, opposes incentive rate making as well for the recovery of transmission costs as unnecessary

and not cost effective. It could lead to excessive earnings, higher

consumer costs. There’s no evidence of need. I believe that RTO

planning will be sufficient to lead to the development of a transmission system that can do the job.

I believe that the FERC currently has the legal authority to do

what it is now doing regarding the creation of four large RTOs,

market power mitigation and the imposition of customer refunds on

entities that have used market power. However, FERC needs to exercise its power more to ensure that markets work efficiently and

consumers are protected.

FERC does need additional authority over transmission planning

and in certain other areas. We are—I am against the FERC exercise of jurisdiction over retail transmission where in States that

have not restructured, where they still have bundled rates. I believe that jurisdiction belongs to the States.

RTO markets must design and encourage the utilization of demand side peak load reduction programs. And I note that’s in the

draft without much greater demand elasticity than currently exists.

In PJM and elsewhere peak load prices will easily be subject to the

exercise of market power.

I believe that individual States must continue to play a prominent role in assuring reliability and in helping with the design of

wholesale markets. However, the success or failure in obtaining

workably competitive markets will ultimately depend on the FERC

and on the RTO structure and authority.

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1See Cooper, Mark N., Electricity Deregulation And Consumers: Lessons From a Hot Spring

And A Cool Summer, (Consumer Federation of America, August, 2001), and sources cited therein).

Thank you very much, and I’ll be happy to answer questions.

[The prepared statement of Michael J. Travieso follows:]

PREPARED STATEMENT OF MICHAEL J. TRAVIESO, MARYLAND PEOPLE’S COUNSEL

INTRODUCTION

My name is Michael Travieso and I am the People’s Counsel for the State of

Maryland. I have been in that position since 1994. The Office of People’s Counsel

is an independent state agency that represents the interests of residential utility

consumers of electricity, natural gas, telephone and water services before the Maryland Public Service Commission, federal agencies, state and federal legislatures, and

the courts. Created in 1924, the Maryland People’s Counsel is the oldest consumer

advocate agency of its kind in the United States.

My office is a member of the National Association of State Utility Consumer Advocates (NASUCA). NASUCA represents 42 state utility consumer offices from 40

states and the District of Columbia. While I am speaking on behalf of the Office

of the Maryland People’s Counsel today, NASUCA members have extensive experience with electric utility restructuring at the federal and the state level. NASUCA

has issued a series of resolutions concerning electric deregulation and the formation

of regional transmission organizations that indicate the views of consumer advocates across the country. Many of my comments here today rely on those resolutions

which are available on the NASUCA website.

I would like to start by commending Chairman Barton, the members of the committee and your staff for your continuing efforts to seek out and include the views

of consumers and consumer representatives as you proceed with your inquiry into

the development of effective, competitive wholesale power markets.

My testimony is not intended as an endorsement of the deregulation and restructuring of the electric industry. I share the concerns being raised by many about the

ability of residential and small business customers to benefit unless wholesale markets can be made to function efficiently.1 This testimony will focus of my views on

the basic principles necessary to establish a proper framework for a competitive

wholesale market.

My points in summary form are the following:

1. Without a workably competitive and efficient wholesale market, retail prices will

be higher than, and perhaps much higher than necessary.

2. The principal difficulty in ensuring a truly competitive wholesale market will be

creating one of sufficient size and scope to create uncertainty on the part of the

owners of generation that their bids to sell power will be accepted.

3. Both for reliability and market design purposes, RTOs must continue or establish

installed or deliverable capacity requirements and concomitant capacity markets in addition to energy and ancillary services markets.

4. Generally speaking, larger regional transmission organizations are better than

smaller ones because of the reduction in administrative and transactions costs

and the increase in generation capacity and diversity.

5. Generally speaking, the existing transmission systems were not planned or built

primarily to serve regional markets and, therefore, must be redesigned and enhanced to do so.

6. RTO market design must encourage the utilization of demand-side peak load reduction programs. Without much greater demand elasticity than currently exists in PJM and elsewhere, peak load prices will be easily subject to the exercise

of market power.

I believe that individual states must continue to play a prominent role in assuring

reliability and in helping with the design of wholesale markets. However, the success or failure in obtaining workably competitive markets will ultimately depend on

the FERC and on RTO structure and authority. FERC should have clear authority

and jurisdiction to:

a. Determine the appropriate size of RTOs;

b. Require transmission owners to join particular RTOs;

c. Return generators to cost-of-service prices if necessary;

d. Provide regulatory oversight to RTOs in order to monitor regional wholesale markets and impose appropriate behavior modifying penalties on parties or entities

shown to have abused their market power;

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e. Regulate the long-range planning and cost recovery of transmission owners in

order to foster the efficient sale and delivery of electricity and capacity across

large regional wholesale markets;

f. Ensure the competitive neutrality of transmission systems by assuring that transmission owners will provide for open access and use of the transmission system

at just and reasonable rate without any discrimination in favor of generation

owning affiliates;

g. Ensure the provision of transmission service at the lowest cost possible;

h. Require that RTOs meet strict standards of economic operation and investment;

i. Require that RTOs have independent non-stakeholder boards which guarantee

input from consumer advocates and state public service commissions;

j. Provide a regulatory forum for the resolution of complaints by market participants

of tariff or RTO protocol violations, violations of relevant federal law and the

use and abuse of market power;

k. Require RTOs to enforce compliance with rules and protocols promulgated by the

North American Reliability Council, (NERC).

An RTO must exhibit the following characteristics and be able to perform the following functions:

• it must be independent from market participants;

• it must serve a region of sufficient scope and configuration to perform effectively

and support efficient and non-discriminatory power markets;

• it must have operational responsibility for all transmission facilities under its control;

• it must have authority for maintaining the short-term reliability of the grid.

• it must administer its own transmission tariff and use a transmission pricing system that promotes efficient use and expansion of transmission and generation

facilities;

• it must ensure the development and operation of efficient and fair mechanisms

to manage transmission congestion;

• it must develop and implement procedures to address parallel path flow issues

both within its own region and with other regions;

• it must provide for a supplier of last resort for all ancillary services that cannot

otherwise by supplied efficiently by market mechanisms;

• it must be the single OASIS—the Open Access Same-Time Information System—

site administrator for all transmission facilities under its control and independently calculate total transmission capacity (TTC) and available transmission capacity (ATC);

• it must monitor markets for transmission services, ancillary services and bulk

power to identify design flaws and potential market power problems and propose appropriate remedial actions; and

• it must be responsible for planning necessary transmission additions and upgrades in coordination with appropriate state authorities.

I favor fewer and larger RTOs so long as they are properly structured; cost benefit

analyses are performed prior to their formation; and costs are not shifted from one

set of customers to another or from customers of high cost transmission owners to

those of low-cost transmission owners. I oppose incentive ratemaking for transmission owners as unnecessary and not cost-effective. This country’s transmission

system should be regulated as the monopoly it is and should be operated in the public interest.

I believe that the FERC currently has the legal authority to do what it is now

doing regarding the creation of four large RTOs and regarding market power mitigation and the imposition of customer refunds on entities that abuse market power.

In my view, FERC needs to exercise its power to ensure that markets work efficiently and consumers are protected. FERC does need additional authority over

transmission planning and in certain other areas.

If the FERC has any concerns about its authority, I urge this Subcommittee and

Congress to give FERC the specific tools it asks for, including:

—specific authority to order the formation of RTOs and to order utilities to join

them;

—authority to ensure the adoption of uniform interconnection standards;

—authority to award customer refunds for past periods if the FERC determines the

rates charged to be unjust and unreasonable;

—authority to assess civil penalties for market power violations;

—enhanced authority to review and scrutinize mergers;

—clear authority to remedy market power abuse

—authority to mandate reliability standards for bulk power markets and to work

with the states to ensure the reliability of electric supply;

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—authority to require the development and implementation of demand response/

peak sharing programs.

That concludes my prepared remarks. I want again to thank the Sub-committee

for this opportunity to appear and to speak on behalf of the residential consumers

of Maryland and to express what I believe are the concerns of consumers in general.

Mr. BARTON. Thank you.

The Chair recognizes himself for questions. Just as an aside, the

House has finished its business on the floor for the day, so that

when this hearing is adjourned, members can go home if they wish.

Just put that as a suggestion.

I have a general question. We put out at the staff level a draft

RTO proposal late yesterday afternoon. Have any of your groups

had a chance to see that and study it? Okay. I don’t see.

Mr. ESPOSITO. We’ve had a chance to see it, but not study it.

Mr. BARTON. Okay.

Mr. TRAVIESO. We’ve seen it, we haven’t studied it yet.

Mr. BARTON. Okay. Well, I would encourage you to study it and

get your written comments to the committee staff and the minority

staff, and any specific members.

We’ve had a lot of testimony, a lot of discussion about the number of RTOs. FERC was moving toward four RTOs plus ERCOT.

What’s the general position of you gentlemen? Is there a magic

number and is that magic No. 4 plus one or should we let the market operate and see what seems to make most sense based on the

geographic considerations?

Mr. Franklin?

Mr. FRANKLIN. Mr. Chairman, there’s certainly not a magic number. I don’t think anyone could know what the proper—what the

optimum ultimate size should be and what it will be 10 years from

now. To my knowledge, no studies have been done.

There are some natural markets that have formed around the

country, there’s some in the southeast. I think the natural markets

that have formed that have some reasonable transmission capability within that region so you can move significant amounts of

power within that region is a good start.

Our thought is that forming RTOs that can be formed relatively

quickly that meet the needs of a specific region that can get concurrence of State commissions in that region, even if it’s somewhat

smaller, getting those done quickly but putting them together in a

way that they could be merged with larger RTOs later makes a lot

of sense.

I think over time if an RTO is too small, it’ll become obvious.

There’ll be demands for lots of transmission between that RTO and

the next one and lots of power movements. And over time you can

go from smaller RTOs to larger RTOs, but I think the other process

is irreversible. I don’t see how you form a huge RTO that covers

20 States and later decide that was too big, you can’t manage the

bureaucracy is out of control. It seems to me it’s almost impossible

to go in the other direction.

Mr. Bennett, do you have a comment on that since you’re representing the NARUC group, plus your State?

Mr. BENNETT. Yes, I would say it’s sort of a geographic evolutionary process. As I said in my opening remarks, we see the benefit

of a voluntary approach where a region puts something together.

But as a practical example, New England, New York and PJM are

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working together. And logic dictates that if and when RTOs become

the way to go, that would be a region that seems to work together,

has worked together and is doing it now.

Mr. BARTON. Okay. You all haven’t had a chance to study the

RTO draft that we released yesterday afternoon, but it has as a

minimum size requirement for an RTO 40,000 megawatts. Would

any of you care on the record to comment on the minimum size requirement? Is 40,000 reasonably good or should it be higher, should

it be lower, or should there be no minimum requirement in terms

of the number of the size of the megawatts in the RTO?

Mr. Esposito?

Mr. ESPOSITO. Mr. Chairman, 40,000 would allow California to

remain a single State RTO, and I think we’ve seen the experience

of single State RTOs not being pleasurable, to say the least. So you

might want to look at a bigger number.

I think at the end of the day what you really want to look at is

where our market’s developing, and that’s where the physics, not

the politics work together. And, you know, 40,000 might be fine

somewhere and not good somewhere else. So, it’s difficult to just

set a number in stone.

Mr. BARTON. Okay. Mr. Gerken?

Mr. GERKEN. What I think is important, I think I commented a

little earlier on the first question. I think 4 or 5. The larger the

RTOs to us, the better. I think what’s more important is——

Mr. BARTON. The larger the size?

Mr. GERKEN. The larger the size of the RTO, less seams issues,

but also importantly is that all these are run under one set of rules

and guidelines. I think that is the biggest issue right now.

We’re stressed to a little point. We happen to fall within the Midwest ISO and the Alliance RTO, and that was formed as a merger,

but it’s still questionable whether that formation’s going to work as

what I call, I guess, a subset of one large RTO.

Mr. BARTON. Okay.

Mr. TRAVIESO. Just to follow up, I did say in my testimony that

I thought 40,000 was too small.

Mr. BARTON. As a minimal?

Mr. TRAVIESO. As a minimum. Even as a minimum. It seems to

me that once you’re down to that size, in order for that size of an

RTO to work, you’d have to have very vigorous FERC oversight and

enforcement against market power abuse.

Mr. BARTON. Okay. My time has expired, but I’m going to ask

one more question. Should the FERC be given the authority to

force a private entity into a specific RTO? Now the draft mandates

that you join an RTO, but it gives the time period and flexibility

about creation, but there are those that say we should give the

FERC the authority to mandate participation in a specific RTO.

Mr. Franklin?

Mr. FRANKLIN. I’d like to answer that, Mr. Chairman, being a

private entity. The answer is no.

Mr. BARTON. I am surprised. Shocked, amazed and stunned.

Mr. FRANKLIN. FERC doesn’t know any better than any of the

rest of us ultimately what size RTOs are going to be best or in

which RTO in particular—transmission system should be. I think

what needs to be in place is a national policy, which there is, that

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RTOs be formed. And I think there needs to encouragement to get

them formed, but the heavy hand of simply dictating arbitrarily not

based on cost studies, market studies or anything else that company A needs to be in RTO B without questioning or asking the

question of State commissions, utilities, customers or anyone else

just seems to me to be arbitrary and will lead to a bad result.

Mr. BARTON. Okay. Mr. Flynn?

Mr. FLYNN. Mr. Chairman, my response to your question would

be no, I would be concerned if FERC were in a position where it

could dictate join a particular RTO, because I don’t think all RTO

structures are necessarily equal. I think different structures have

the potential for offering different degrees of benefits to market

participants, to generators in the region as well as to consumers in

the region.

Based on our experience, we believe that there’s greater potential

for providing consumer benefits from an RTO that has as part of

it an investor-owned for-profit independent transmission company.

And if one gives FERC the authority to dictate a particular form

of RTO, our concern would be that FERC, based on the information

that’s available, might pick wrong up front and we may be forced

into a form of RTO that could be suboptimal.

So we would rather see the flexibility for different structures to

develop and then let the market choose which one is providing the

highest level of consumer benefits.

Mr. BARTON. Okay. Mr. Johnston, and then Mr. Esposito, and

then we’re going to go to Mr. Boucher for his questions.

Mr. JOHNSTON. I would agree that—let me say the only time that

FERC should be given the authority to force an entity into an RTO

is to relieve market abuse as a mechanism of relief of that. Otherwise, I agree with some of the other comments that I don’t think

there is a perfect size. I think you have to look at markets, you

have to look at operational issues in the regions, you have to look

at cost benefits; all those play into the RTOs and which is best for

me to join or for some other entity to join. But other than the relief

of market abuse, I would not agree that FERC should have that

authority.

Mr. BARTON. Mr. Esposito?

Mr. ESPOSITO. I agree a lot of points Mr. Flynn made, but at a

certain point you can’t just have a big hole in the middle of a region. And somebody’s got to say you got to be part of the one that

surrounds you. And the only entity I can think of to say that is

FERC.

Mr. BARTON. Are you aware of a particular company or small

group of companies in a particular region that would try to create

a hole in the middle of the donut, so to speak?

Mr. ESPOSITO. There’s a lot of that going on in the midwest. You

can see the maps that are just Swiss cheese, because it does exist.

Mr. BARTON. Mr. Boucher?

Mr. BOUCHER. Well, thank you, Mr. Chairman. Let’s continue the

discussion with regard to RTOs and, Mr. Franklin, let me begin

with you.

I know that when the FERC issued Order 2000 your company expressed support for the basic theory of that order, which is that

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utilities would be encouraged to join RTOs, but not required to do

so.

This July the FERC has made a somewhat more affirmative

statement and has gone beyond Order 2000 by suggesting that if

investor owned utilities do not join RTOs, the FERC perhaps would

withhold merge authority and might withhold the authority for

market based rates. So there’s something of a greater encouragement, shall we say, for IOUs to join RTOs than was existent in

Order 2000.

So my first question to you is how do you feel about the new

order, what is your reaction to that as compared to Order 2000.

And if you find that the July order imposes problems for you, what

are those problems, if you could precise? Is it higher rates that

would be imposed upon transmission sales or is it the inability to

reserve sufficient capacity for your native load? I mean, what are

the kinds of precise problems that you see stemming from this July

order?

Mr. FRANKLIN. Thank you. A very good question, and I’ll try to

give a fairly short answer.

First of all, the FERC order in July was not helpful. In the

southeast, every investor owned utility that I have knowledge of

and most all public power groups were working in good faith to

form RTOs. So we didn’t really need a bigger hammer. We already

felt the need to move in that direction.

What FERC has done, in my judgment, first of all has not only

expressed an interest in moving faster and more deliberately to

RTOs, they’re beginning to express a very firm position on the

structure for the RTO in the southeast and the size. Well, unfortunately, that was not the structure and the size being pursued

throughout the southeast, so it has pretty much thrown those negotiations into turmoil and I think slowed down the process.

No. 2, the States in the southeast are not at all convinced about

the direction that RTOs should take. I think FERC generally was

going in the right direction with Order 2000, and we were in the

process of trying to convince our States that that was a good move.

I think the recent approach by FERC has tended to dissuade or increase the concern that the States have about where FERC is ultimately going.

And we can’t move into an RTO. With 90 percent of our income

regulated by States we cannot move into an RTO structure or size

that our State strongly oppose. It would be financial suicide for us.

So it’s awfully important for us to bring the States along, and I

think FERC action has hurt that.

The other point, the very large RTOs I think long term may

make sense. I doubt there needs to be four, maybe there needs to

be six, maybe there needs to be eight. I don’t know. I think time

will tell. But with current FERC pricing where you can move within an RTO, where you can move power any distance for the same

price you move it one mile, we’re going to get huge distortions related to location of generation. And FERC has not been willing to

address that.

One of my greatest concerns related to large RTOs is the distortion that we see in the location of generation because of inadequate

distance-sensitive pricing.

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Let me just mention one other thing since I’ve got the floor. The

chairman’s probably about to cut me off.

But a big issue from a corporate standpoint for us is there is not

inadequate generation in the southeast. I heard one of the panelists say there was imbalance. There is imbalance; there is way too

much generation being built in the southeast. That’s probably good

for consumers long term, but it’s going to require a huge amount

of transmission. Ultimately we’re going to have to build that transmission and collect the cost of that transmission from our retail

customers. Regardless of FERC State jurisdiction the ultimate consumer in our region has to pay for that transmission. And we want

to be sure that only the right transmission is built and that our

State commissions are willing to allow us to recover that cost.

That’s a huge financial issue for us.

Mr. BOUCHER. You have mentioned a couple of times in your testimony today this notion of distance-sensitive pricing, and I think

it might helpful for us if you were a little more specific about what

the problem that you perceive is and how distance-sensitive pricing

should properly be structured to address that problem.

Mr. FRANKLIN. Okay. Thank you for this opportunity.

In most any other form of transportation that I’m aware of, the

further you move a product the more it cost to move it. So if you’re

going to build a manufacturing plant, all things equal, you build

it closer to the market not a 1,000 miles away.

In electric transmission within a region, within an RTO that’s

not true. You can build a power plant a mile from the load or 500

miles; the cost to move the power is the same. So there’s no incentive to build the generation close to the load. That exacerbates the

transmission problem. It’s resulting in generation being build by

the boatloads down along the Gulf Coast where natural gas is located and shipped to Atlanta, and Charlotte and up the east coast

when in fact it should be built close to those load centers, all other

things equal.

That causes two problems. It increases the investment in transmission and the ultimate cost to consumers. And No. 2, it makes

the system less reliable because you have these massive power

flows; the greater the power flow the more bottlenecks are created

and the more reliability problems are created.

Mr. BARTON. Will the gentleman yield?

Mr. BOUCHER. Before I yield, Mr. Chairman, ask you one additional question.

You’ve really defined well, I think, the problem. But what’s the

answer? I mean, how do we achieve distance-sensitive pricing so as

to result in generation being built in a way that is proximate to

where electricity is consumed?

Mr. FRANKLIN. It actually is pretty simple. It’s been done in the

natural gas industry. If you move gas from the Gulf Coast to Atlanta, it cost a whole lot more than moving it just 10 miles inshore

from the Gulf Coast. So FERC is very familiar with distance-sensitive pricing.

There can be lots of debates about the exact method where there

is zonal. In other words, you have a megawatt mile approach,

which offends a lot of people, and I’m not sure it’s a great idea either, or do you say you can move power for a price for 100 miles

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and when you go the second 100 miles there’s another increment?

There are lots of methodologies; I think a methodology that can be

found that’s fair.

I think the problem is the mentality has been at FERC, and our

industry too to a degree, that transmission is such a low cost in the

total cost of electricity compared to generation that it doesn’t matter; that it doesn’t matter if you overbuild. It doesn’t matter if you

build too far from the load center. Well, that’s changing.

What we’re looking at is tripling our investment in transmission.

It’s only about 10 percent of our total investment to date. Transmission is about 10 percent. Within the next 5 years it’ll go to 20

percent. So investment in transmission does matter and making efficient transmission decisions is just as important as making efficient generation decisions.

Mr. BOUCHER. Well, that’s excellent food for thought, and I thank

you.

I’d be happy to yield to the chairman with the admonition that

I have one additional question I’d like to ask.

Mr. BARTON. I was just going to ask what he answered if there’s

a way to do distance-sensitive pricing that the industry thinks

makes sense, that’s all.

Mr. BOUCHER. Mr. Chairman, let me suggest, if I might, Mr.

Chairman, that maybe we ask Mr. Franklin and his very excellent

staff to enlighten us a little bit further with some written recommendations.

Mr. BARTON. Could the gentleman suspend just a second?

Mr. BOUCHER. I’d be happy to.

Mr. NORWOOD. Are we going to have more than one round?

Mr. BARTON. We’re going to have a long one round.

Mr. NORWOOD. I see. So the light’s not nearly as important?

Okay. No problem.

Mr. BARTON. You’ll be on Georgia time when we——

Mr. BOUCHER. And, Mr. Franklin, if you could perhaps send us

some written suggestions in the fairly near timeframe about how

distance-sensitive pricing might actually work. What kind of formulas would make sense to achieve it?

Mr. FRANKLIN. We will absolutely do that. Thank you.

Mr. BOUCHER. That would be helpful.

Mr. Chairman, the other question I have is this: The Supreme

Court had arguments last week in the consolidated cases arising

out of the FERC’s Order 888. No sooner had the FERC issued

Order 888 than it was sued from both directions. Marketers filed

suit saying the FERC had not gone far enough to assert jurisdiction over transmission and the States, on the other hand, sued

FERC saying that they had done too much and that Order 888 asserting authority over unbundled transactions in States that were

open to competition was more than FERC could have done, and

that FERC was not empowered to do it. And the Supreme Court

heard the arguments on both of those positions last week.

This set of arguments, that case, really goes to the fundamental

issues that we have to address in terms of the balance of State and

Federal authority over transmission. And I’m wondering if anybody

here thinks that this subcommittee ought to wait until the Supreme Court renders its decision, which we could probably expect

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in the near term, anywhere from 2 months to 6 months depending

on what they get to first, before we legislate on this complex and

very difficult subject?

I am agnostic. I’m open to suggestions. I haven’t made up my

mind about whether it makes sense for us to go forward at this

point and begin to tackle these thorny issues, but I would welcome

your advise. And so let me offer the opportunity to suggest to us

whether it’s better to wait or whether it’s better to move.

Mr. BARTON. That will have to be the last question.

Mr. BENNETT. I have an easy answer on that, since the State of

New York was one of those arguing against the FERC extension of

jurisdiction, we think it would be wise to wait.

Mr. BOUCHER. Okay. Anybody disagree? Did I see a hand over

here?

Mr. Esposito?

Mr. ESPOSITO. I would just say you might think about somehow

encouraging the Supreme Court to act quickly. I don’t know what

kind of vehicle you have to do that.

Mr. BOUCHER. That’s above our pay grade, Mr. Esposito.

Well, maybe if we actually report a bill, that might a signal of

some sort.

Well, thank you, Mr. Chairman. And I want to thank these panel

members for their helpful testimony.

Mr. BARTON. We do encourage all members to put their written

comments in on this distance-sensitive pricing. We understand that

Mr. Franklin’s position is probably not unanimously accepted by

the other members of the panel.

The gentleman from Georgia, Mr. Norwood’s recognize for 10 seconds—5 minutes.

Mr. NORWOOD. This is going to be a loud hearing, I can see.

Thank you, Mr. Chairman. And I do thank the panel members.

I find it interesting the ranking member and the chairman, I believe, got right at the heart of the issue and I want to stay on this

thing of RTOs just for a little while. And I’m particularly interested, Mr. Johnston and Mr. Mr. Franklin, hearing from you as all

panel members, but I want us to say what you said before maybe

in maybe some different ways so that it sits very well with this

committee and we all have an understanding of it.

It’s pretty clear, I think, to all of us that FERC has been moving

rapidly trying to get everybody into RTOs. It seems that they like

the magic number of four. It seems that they like the thought of

large RTOs. And I’m interested in hearing again, first, is this a

possibility? Is it technologically possible? Again, how do you feel

about that? What if the FERC gets this wrong? What will it do to

your customers and my constituents? Have there been studies done

so that we can understand, perhaps, if we get it wrong what it

might do to our customers?

What’s the consequences of us moving too quickly right now?

What will it do to your customers and my constituents if we go too

fast? Are there ways that the FERC can speed the process along

without mandating to our utilities a certain predetermined configuration that you have to sit in stone right now or that perhaps we’ll

try to sit in stone?

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And I’m willing to give up a great deal of time to hear you two

gentlemen to discuss that.

Mr. JOHNSTON. We believe that it’s a fairly hard sell in a low cost

State for RTOs generally, even though I’m speaking here as LPPC

and we support the development of RTOs, but reasonable thought

out RTOs that we’ve taken a look at operational issues, we’ve taken

a look at natural markets, we’ve taken a look at cost benefits.

Frankly, I have not seen—I don’t believe there is any cost benefit, comprehensive cost benefit analysis for the southeast United

States on the value of RTOs. And I’m not saying that there isn’t

value, I’m saying there has not been comprehensive studies done

or got out.

Mr. NORWOOD. Well, could they be ongoing and we don’t know

about it? Is somebody looking at that?

Mr. JOHNSTON. Well, maybe they are, but I am not aware of

them. But they need to be done and we’ve stressed that they need

to be done, because it’s very difficult for us to go to our communities and sell the cost of RTO development, which could be hundreds of millions of dollars, and I have seen very few people say

that you’re going to lower transmission costs by the creation of

RTOs. I think most of us believe you’re going to raise the transmission costs. So where’s the value going to come from? It’s going

to come from the generation side.

Well, if it comes from the generation side, and you’re already in

a low cost State, that’s a difficult cost benefit analysis because the

chances are what’s going to happen to your generation is it’s going

to get exported, you’re not going to import cheaper generation.

So, I’m not saying it can’t be done. I’m saying it’s a very tough

sell in a low cost State. But it needs to be done or it’s dead on arrival in my communities when I try to sell the cost of developing

an RTO.

So comprehensive cost benefit studies, operational studies. As

some have said, these systems that we’ve built over the last 100

years were never built to be put together, so there has not been an

operational study on what happens when you do put them together.

And there will be issues, operational issues that come out of that

that have not even been studied.

Mr. BARTON. Would the gentleman yield?

Mr. NORWOOD. Yes, sir.

Mr. BARTON. And I’ll give you as much time as you need.

Well, I’m a little puzzled. Basically the transmission assets already exist and there are already people operating them. What is

the additional cost of creating an RTO if the infrastructure is in

place and the personnel’s in place, and all we’re really doing is setting the ground rules and requiring that there be, for lack of a better word, cooperation and communication? Where is the additional

cost in that?

Mr. FRANKLIN. That’s a good question, but there’s also a very

good answer.

Mr. BARTON. Thank you.

Mr. FRANKLIN. An RTO, the primary cost is setting up one very

large centralized control system with staff that actually—it’s not

just a coordination in cooperation. It is replacing a number of

smaller control centers and smaller staffs that may be scattered

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around several States with one large control center; lots of electronics, lots of computers, lots of screens, lots of telecommunication

equipment. The thing in California, as I recall, for the power exchange and the ISO was like $600 million to set up.

Now, that is an extreme. A lot of things in California was an extreme. It won’t cost anywhere near that, but our best estimate for

the smaller RTO that we were talking about with the coops in municipals is probably $100 million.

Mr. BARTON. But over time if you’re going from many to fewer,

you know, and from older to newer in terms of equipment it will

save money, wouldn’t it?

Mr. FRANKLIN. Well, it’s a case if somebody would buy those old

control centers from you, but you still have the investment in those

control centers plus you build a new one.

Now, long term, I think—let me—if I could address maybe both

questions sort of.

We haven’t done a cost benefit study. We’ve done a cost study,

a rough, very rough cost estimate of what the RTO would cost.

Maybe $100 million, maybe a little more initially to set up.

I’ve been involved in the industry 30 something years. I’ve been

planning transmission for a big part of that. My gut feeling is that

over time with that kind of investment, the size we’re talking

about, it probably will pay for itself. I couldn’t prove it today, but

I think it probably would. But when you talk about a much bigger

RTO, it’s the typical centralization, decentralization question.

You can prove on paper centralizing every decision in a company

that the CEO will make it run better, but it doesn’t. The same is

true in trying to centralize the operation of a huge transmission

system in one place as opposed to having maybe 3 or 4 operating

centers. Theoretically you get more efficiencies, you have fewer control centers, but what you end up with is more bureaucracy and decisions being made further from consumers and further from the

frontlines.

When you say how centralized should a company be, there is no

exact answer. How big should an RTO be, there’s no exact answer.

The bigger it is the more bureaucratic it becomes, the further reliability decisions are made from where the real reliability problems

are, but theoretically the more efficient it is. And we think the balance is what’s being proposed in the southeast for the SETRANS

model.

And let add one other point to Mr. Norwood’s question. Another

big issue, Congressman, and I’m very concerned about this because

we’re the most regulated industry in the world and we’re one of the

most regulated companies in the world.

We’re regulated by four State commissions. And if we go into a

big RTO and it doesn’t work, and we don’t have our State commissions on board, it’s going to be a disaster just like it’s been a disaster in California.

And I don’t mean a disaster from a reliability standpoint, I mean

a disaster for us. We’re going to be punished financially just like

the companies in California have been punished.

It’s critically important for us to get the States comfortable and

onboard with where we’re taking RTOs. I think that can be done,

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but it can’t be done with a heavy hammer mandate from Washington. It’s just not going to work.

Mr. BARTON. Of course, I could say you could help in getting the

States onboard.

Mr. FRANKLIN. And I will.

Mr. BARTON. Poor little old struggling southern company might

have some influence.

Mr. NORWOOD. Reclaiming my time.

Mr. FRANKLIN. I tell you what, if we had had——

Mr. BARTON. It still is Mr. Norwood’s time.

Mr. FRANKLIN. If we had had the influence with the State commissions that the chairman gives us credit for, our stock would be

selling for 50 bucks a share, not 25.

Mr. NORWOOD. You’ve made it clear, I think, to the chairman

that if we have that RTO there are X amount of new dollars that

are going to be spent. And then you said well, we think we can pay

for that. Well, I don’t have any doubt you’re going to pay for that.

My question is it’s my constituents who are going to pay for that,

because that’s who you have to pass that on to.

Mr. FRANKLIN. Right.

Mr. NORWOOD. And so the question has to be if we’re going to

do this, what is that going to do to rates in Georgia?

Mr. FRANKLIN. Congressman, I think initially it’s going to raise

rates. I don’t think there’s any question for two reasons. We’re

going to have an incremental cost of forming the RTO, that’s new

dollars. We’re going to have to build a lot of new transmission; that

could be helped if we had FERC transmission pricing right. So I

don’t think there’s any doubt near term the rates are going to go

up.

Longer term if these markets operate more efficiently, the generation markets; in other words having a larger region, more efficient generation markets what you would hope is the lower generating costs would offset the higher cost of setting up the RTO. Now,

that’s a gamble, but I think it’s a pretty good gamble for the RTO

our size.

Now, if it’s start costing $200 million or $300 million, I’d be hard

pressed to make that representation.

Mr. NORWOOD. Mr. Chairman, I’ve only got eight more questions,

and I’ll be brief. But I do have two other little quick things.

And, Mr. Franklin, while we’re talking let’s finish this.

Mr. SAWYER. With unanimous consent.

Mr. NORWOOD. I didn’t notice Mr. Boucher needed it.

I keep hearing over and over again at these hearings this analogy that compares our transmission system to a reservoir. And I

can visualize that pretty well where you can put electrons in anywhere along the system and you can take them out anywhere else.

As someone who is regulated by FERC, I’ve heard the discussion

about FERC authority in establishing transmission ratemaking

standards. Now, I’d like to hear your view on that situation.

Mr. FRANKLIN. Let me talk about the lake analogy first.

Mr. NORWOOD. Well, tell me about that reservoir.

Mr. FRANKLIN. There is no legitimate analogy between a lake

and a transmission system. It’s like comparing an airplane to a

tugboat. I mean, there is no analogy at all.

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In an electric system you have to be very, very careful where you

inject power. You can burn the system down if you inject it in the

wrong place. You have to be very, very careful where you add demand. And you have to add transmission based on the pattern of

growth of generation and demand. So the lake analogy is useless.

The highway analogy I would also add is useless.

You can’t take shortcuts and pretend the electric system is a lake

or a river, or a highway system. It’s not. It’s an electrical system

and it’s very much more complicated than static systems like highways or lakes. And, again, I think a little more thought going into

that before the California experiment was implemented might have

saved a lot of grief.

Mr. NORWOOD. How does this relate to transmission investment

and getting a return on the risk associated with that investment?

I mean, is this something that FERC has sufficient authority over

already or is this something that Congress needs to act on?

Mr. FRANKLIN. I think as far as authority to set wholesale rates

for transmission, FERC has authority. What I would like to see

FERC do, and they have indicated in the past they would but it

doesn’t seem to be a priority, is to really focus on transmission pricing to make sure that transmission investment is done efficiently;

that is generating plants are located in the right place, and that

there is some incentives for building this huge amount of transmission.

I am flabbergasted that people, they believe in competition,

somehow don’t believe that incentives work in a regulated business. It’s just like in a competitive business.

I’m also flabbergasted that utilities and State commissions that

offer incentive rates for demand side products to use less energy,

to use energy differently, they believe incentive rates for those kind

of products, somehow that won’t work for transmission investment.

I think it’s a very short-sighted approach to simply continue to

try to divide up the same amount of transmission among more

users as opposed to focusing on getting the right amount of transmission built, and incentives will help that.

Mr. NORWOOD. Mr. Johnston, we probably need to answer quickly here. You know, I realize that the municipals and coops are not

regulated by FERC, however, folks around here are talking about

changing that. What is your feeling on this and the FERC having

jurisdictional control over transmission associated with bundled

services to our communities?

Mr. JOHNSTON. Well, we would strongly oppose FERC jurisdiction over bundled retail service to our communities. You know,

frankly, it goes back to our obligation to serve and our State mandates. If you take away the tools that we use to carry out that obligation, how can we be expected to accomplish it? Because if you

give FERC control over priority and use of that facilities, you in effect are tying our hands and our ability to carry out that obligation

to serve. You know, it’s kind of a silly statement, but maybe you

have to transfer the obligation to serve to FERC, but I’m not sure

they care to have it.

Mr. NORWOOD. Well, what happens if we were to do that? I

mean, I don’t understand what happens back home if FERC were

to have that jurisdictional control.

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Mr. JOHNSTON. Well, in a plain simple example, if I am moving

electrons across the grid in Georgia in order to deliver it to my

communities and a constraint occurs in that system and FERC is

in control of that system or somebody under FERC’s control is in

control of that system and they direct the priorities such that they

remove my native load to relieve the constraint, that’s stripping me

of my ability to deliver that obligation to serve that native load.

Mr. BARTON. We’re going to have to discourage the gentleman

from any further questions.

Mr. NORWOOD. I bow to the chairman.

Mr. BARTON. And we want to announce for the other members

about to ask questions, it is acceptable to ask questions of the

panel members who are not from the great State of Georgia.

Mr. NORWOOD. But not desirable. Mr. Chairman, I apologize to

the other panel members. It’s sort of natural for me to ask——

Mr. BARTON. I understand. I understand.

The gentleman from Ohio is recognized for such time as he may

consume.

Mr. SAWYER. Thank you, Mr. Chairman.

I just have to observe that there are—I can think of at least a

couple of transportation systems that are distant-sensitive. I’m not

sure that we want to emulate them in this case, but one is the

Postal Service.

Mr. BARTON. Very good point.

Mr. SAWYER. And the other may have some distance-sensitive

pricing, but most of us can’t discern it, and that’s the airlines.

There are an awful lot of fees that have no bearing on distance and

there are an awful lot of people who are unhappy with that.

I would also suggest that centralized command and control of the

kind that you suggested as a hypothetical seems to have been tried

in the Soviet Union and fell apart. And my submission is that it

would not be useful.

Let me ask one more question of the gentleman from Georgia,

and anybody else who would like to answer, and that is the end

of year deadline, it seems to me, creates some enormous pressures.

Can you tell us your reaction to the feasibility and the result if in

fact that’s adhered to?

Mr. FRANKLIN. Well, I think the end of your deadline goes back

to Order 2000.

Mr. SAWYER. Okay.

Mr. FRANKLIN. We were on a course along with the people from

the municipals in Georgia represented by Mr. Johnston and others

to move in that direction. I think the recent developments starting

back in May and then concluding or being further exacerbated by

the FERC order in July have knocked these negotiations off track.

I think the end of year deadline does not seem feasible to me at

all anymore.

Mr. JOHNSTON. Could I add something there?

Mr. SAWYER. Sure. Sure.

Mr. JOHNSTON. It’s important to also recognize that the form of

RTO that FERC is leaning toward, which is away from what we’ve

been negotiating, essentially will alienate the vast majority of public power in the southeast, meaning public power is going to walk

away from that RTO and has told FERC that. It’s not just MEAG,

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it’s virtually all the major transmission holders, public power

transmission holders in the region. You’re going to have a huge

potholed RTO if FERC does what they have indicated they’re going

to do, and it will not work very well.

Mr. SAWYER. The whole struggle for competition in your arena

for the last 85 years it seems to me, has been a competition for capital. That’s been where the real competition has been, and that’s

where the price advantages have resulted.

Mr. Trabandt, you mentioned that a properly structured transco

will be able to access capital markets adequately. Can you give us

briefly a sense of what you think is a properly structured transco

and if the current access to financing is continued in the future,

what will be the prospects for transmission capitalization?

Mr. SAWYER. Congressman, I appreciate the question because I

think it’s very important for the subcommittee to focus on the notion that these are new business operations. The RTO responsibilities which have been established by FERC in which the various

RTOs around the country have been trying to satisfy would require

this new business entity to be operating in a circumstance somewhat different from what had been previously contemplated, I

think.

When I talk about properly structured, I’m talking about a capitalization that perhaps would be 60 to 70 percent debt with the

increment of equity that would go with that, perhaps some preferred that would be structured in a way such that the coverage

ratios would ensure that it’s investment grade and will stay investment grade, which means it has to be credit worthy itself and it

must have credit worthy counterparties for its contracts. That the

investment that it’s required to make—in many of these RTOs the

negotiations have been along the lines of if a new generator—and

in fact the chairman’s proposed bill addresses this interconnections.

We actually looked at all the proposed interconnections of the companies associated with the Alliance RTO. And there are numerous

proposed power plants around the country, as you know. Perhaps

the slow in the economic will change that, perhaps the uncertainty

in regulations as a result of California will change that. But nonetheless, there are lots of proposed power plants, all of those plants

have to be interconnected and all of those interconnections are

going to have to be paid for. And every new interconnection, as you

heard from Mr. Johnston and also from Mr. Franklin, change the

flows on the system. And those have to be accommodated as well.

And that’s going to require substantial upgrade of the existing infrastructure to be able to support the competitive market. That’s

the reason, I think, that some formulation of an incentive, and as

Mr. Vesey testified this morning, whether it’s a somewhat higher

rate of return because of the increased risk associated with it or

whether it’s in the form of other features that FERC has already

adopted in Order 2000, is appropriate to ensure that in fact we can

get the kind of capital to go in assuming the structure, and I described it in my testimony as well.

Mr. SAWYER. Is the traditional notion of ‘‘just and reasonable’’

rate as reflected in comparable kinds of risks in the marketplace,

the same risk profile, will that apply effectively in the environment

that we’re talking about?

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Mr. TRABANDT. I’m glad you raised that, because I was interested

in Congressman Largent’s comment about the FERC Commissioners being here last year and none of them could define ‘‘just

and reasonable.’’

The definition of just and reasonable was established by the Supreme Court in a famous case some years ago, and there’s not a

whole lot of question about that. And I don’t think anything that’s

being discussed in the way of incentives, and I read the chairman’s

proposal to make this clear, is to suggest anything that’s not just

and reasonable. But there is a range of reasonableness that’s established under the applicable law with regards to what rates can be

to take into account, for example, public policy associated with this

very specific issue, infrastructure of commitments, to take into account greater risk, to take into account circumstances where the

regulators have concluded that their benefits to the public and the

consumers from having a different formulation of rate.

It’s interesting to my experience, you all are more knowledgeable

than I, but the FCC’s been doing this for quite some time in telecommunications. When I was at FERC we worked with them when

they adopted an incentive rate formulation which you all have long

since approved. Most States have incentive rates of one kind or another. They’ve been wildly successful in reducing congestion in the

United Kingdom where there’s an incentive that’s shared between

the customers and between the company in terms of formulating

new approaches to the business, which I think Mr. Vesey’s testimony clearly looks at.

All of that can be built into a business model with a structure

which I think could be highly successful in addressing these issues.

I think the question before you is FERC, as I understand it and

all I know is what I’ve read, has indicated that it doesn’t believe

that with its new approach, it’s new policy, that incentives will any

longer be required. And while I don’t question for a minute they

have the authority, I helped write the incentive policy of FERC in

1991 and believe they did then and believe they did under Order

2000; I think the question is are those going to be available to support these new business structures, which you’ve heard from others

are going to be very, very challenging businesses.

Mr. SAWYER. Are there others who would care to comment? Mr.

Flynn?

Mr. FLYNN. Mr. Sawyer, I think the notion of ‘‘just and reasonable’’ certainly accommodates a return on rate base, the traditional

rate making that we’ve had in the industry in the past. And whether the return that FERC sets is just and reasonable, the market

will tell us by whether or not investment is forthcoming to go into

assets. But I think the notion of just and reasonable can accommodate more than just traditional return on rate bases, as Mr.

Trabandt alluded to a minute ago.

National Grid has pending before FERC today what I think is

the first incentive rate for transmission that’s been proposed in the

United States. And it was a joint filing with the New England

Power Pool which consists of generators, municipal utilities, marketers as well as transmission companies. Really the cross section

of the industry. And the proposal that’s before FERC, as I recall,

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had over 90 percent approval and it was supported by ISO New

England.

What was it? It was an incentive proposal that said we, National

Grid, need to do some maintenance on our system. A good utility

does maintenance on its transmission system. But to do maintenance the traditional way of working, at least in the northeast, is

to take that transmission line out of service while you’re doing the

work. When you take the line out of service, that path is no longer

available for power to get from generation to load. And what you

end up doing is adding congestion on the rest of the transmission

system.

And we know in New England today congestion costs the consumers are paying are more than $100 million a year. And doing

some studies and working with ISO New England, we did forecasts

that taking this line out of service was going to create the potential

for significant congestion that consumers would pay.

Well, the first thing we did is move the time of the outage to the

fall, so it wasn’t during the summer peak. But beyond that, we

solved the potential of doing this work live, working the line live,

keeping it in service so the power continue to flows to customers

while we’re doing the required maintenance.

And it appeared to us from our forecasts, and the work with ISO

New England, that the savings to customers in terms of lower

power costs because of the savings in congestion would more than

offset the additional costs of doing the work live.

And so this was a proposal we brought to the New England

Power Pool, and it really was a share the savings type of incentive

where everybody wins. And the customers who used the system,

the generators that used the system all looked at this and said

‘‘Yes, this is a good idea.’’ This is the type of thinking we would

like to see investor owned transmission companies bring to the

management of the grid.

Now, this proposal is pending before the Commission. The work

is going on. We’re doing it live whether or not we get incentive

from FERC. But nonetheless, it took a fair amount of work and

study to come up with the idea to do the thinking of how you could

save consumers money on the system. And we’re really looking at

this as a signal from the Commission will this sort of—approval of

the incentive will give the signal to the industry that, yes, if you

come forward with innovative ways of creating savings for customers, there’ll be something in it for shareholders. And I think the

concept of just and reasonable rates can accommodate that sort of

incentive ratemaking as well as traditional return on rate base.

Mr. BARTON. If the Chair would interrupt. The gentleman from

Ohio has had 11, 12, 13 minutes. Now, I said such time as you may

consumer, because I gave Mr. Norwood 15 minutes, but—— Mr. SAWYER. Or such time as they may consume?

Mr. BARTON. Yes. But if you could wrap it up in the next 2 minutes, because we need to let Mr. Shimkus and the vice chairman

of the full committee, Mr. Burr, have some time. Mr. English has

to leave at 3:30, I believe.

Mr. SAWYER. I can wrap it up in the next 2 seconds, Mr. Chairman. I yield back the balance of my time.

Mr. BARTON. Well, if you have another—okay.

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Mr. SAWYER. Thank you very much. Appreciate your latitude.

Mr. BARTON. And we’re going to go to the gentleman from Illinois, Mr. Shimkus for such time as he may consume, but hopefully

shorter road than longer.

Mr. SHIMKUS. As you wish, Mr. Chairman. Thank you for the

time.

I’ll tell you what I’m struggling with, and we’ve been in this debate now for 5 years that I’ve been a Member of Congress. But we

do have a new environment today than we had a month ago, and

I’m going to give you some examples, and I think we would be remiss if we did not add into this debate the new shift in the world

based upon terrorism.

So some of this debate on how we’re going to arrange our transmission grid should probably start addressing things like security,

redundancy, capital available for repair, which I don’t know if

we’ve discussed very much today, and I missed the first panel, and

I apologize for that.

The other thing I learned—I’ve been struggling with is the business model with what we have done, one, as we’ve addressed the

airline industry. There was a time when you went to business

classes on developing small business, what did you tell someone

who wanted to develop a small business, you’d better have the capital to allow you to survive for 3 years without turning an actual

profit in that business. But as we have become leaner and meaner,

just in time inventories and stretching the price so thin because we

all wanted lower prices in every good and service, we have diminished our ability for the capital reserve to respond to emergencies.

I’m really struggling with this. I see that that has happened in

the airline industry and it’s costing us a lot of dollars, a lot of tax

dollars to keep these industries solvent, which is important for our

whole Nation.

The other thing that I’m personally struggling with is, and it

does kind of relate to the industry, the—I was at the Verizon headquarters down right across from the World Trade Center on the

Telecommunications Subcommittee, Mr. Chairman. I think it’s—

and it fits into this whole debate about competition. Because here

we have a regional Bell company that’s supposed to be the big, in

essence, regional monopoly that helps put down the competitive

local exchanges, but it was big enough to bring a lot of capital to

bear to get the connections up rapidly, and their story is monumental what they did at the switching station to get the economy

back forward. The little competitors would say, you know, they

can’t compete but would the little competitors combined be able to

provide the response, the emergency response that a regional monopoly, in essence—they don’t like that terminology, but in essence

the regional Bell was able to bring to the table?

So in this whole debate on addressing the transmission grid, my

concern is what about this new environment of having the capital

available to respond in case of tragedies and disasters, and the

like? And I just want to throw that out. I don’t want responses yet,

but that’s what I’m personally addressing right now, and I think

it needs to be part of the debate, Mr. Chairman, especially as we

talk about capital available, the redundancy issue and the repair

issue and how do we fund the expansion of the transmission grid.

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So that’s an intro, but I want to ask Mr. Flynn, because you’ve

had some expertise, can you tell me about the National Grid’s business operations in Great Britain and are there any lessons that we

can learn from the restructuring of England’s power industry and

things that we should do or things that we should not do?

Mr. FLYNN. I think there are some lessons to be learned. Obviously, you cannot go from one system and just map it to the United

States point for point and say well what worked there will work

here. But just to set the stage a little bit, back a decade ago all

of the industry in the U.K. was government owned. And 11 years

ago the U.K. privatized the system and it created an independent

transmission company, that is a company that was for-profit investor owned, to manage the transmission grid that had no interest

in the generation of power sales business. And that’s National

Grid. So that’s the genesis of our company.

What has occurred in the U.K. over the period of a decade is that

National Grid has reduced the controllable costs of operating the

transmission system by about 50 percent. And it has reduced congestion costs on the transmission system by about 1 billion pounds.

Both of those occurred under a system of incentive rates that the

regulator in the U.K. established.

In essence, the regulator said ‘‘Look, we want you to manage the

system as a business and what we’re going to do is work with you

up front to set targets with regard to what we think is the right

level of costs that a company that’s prudently operating the system

would incur, and then we’re going to set your rates based on those

target revenues. You have the incentive and to try to operate the

system more efficiently. And to the extent that you do, there will

be sayings that your shareholders get to share in. On the other

hand, if you’re less efficient than we think you should be, then

there’ll be some shareholder pain and your profits will be less.’’

They also established an incentive with regard to congestion costs

on the system. And congestion costs are essentially costs that customers pay for power because generators that bid low, that are low

cost, cannot run. They’re constrained off by the system operator because there isn’t enough transmission capacity to get the power

from the low cost generators to the load centers. And because these

low cost generators are constrained off, higher cost generators have

to run and the difference is called congestion costs.

And when the markets opened in the U.K. congestion costs increased steadily the first few years, the same thing we’ve seen,

quite frankly, when the markets opened in New England. And

what the regulator said is we want to give you an incentive to

begin to manage the system to control these congestion costs, and

to the extent you’re able to bring the cost down, your shareholders

will be able to share in that.

I think the broad lesson is if you create a rate system with the

right financial incentives, then the regulated transmission company

will respond. And if you align incentives for shareholders with

what’s in the interest of customers, then you have a happy situation with the management of the transmission company is trying

to create customer benefits and at the same time is adding to

shareholder value.

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With the right incentive rate structure, you also have a viable

business that (a) that’s able to raise the capital that’s necessary to

invest in the system. And, indeed, National Grid has engaged in

considerable investment in the U.K. system, most of it not in new

transmission lines on virgin right-of-way. Most of it is upgrading

the existing system to improve the efficiency of the system, but

under a business model a viable business is able to go to the capital markets and get that capital to make the necessary investment.

Mr. SHIMKUS. Thank you. And I know that using that U.K.

model is difficult comparing it to the United States with the size

and distance and stuff, but I did want to have that answered. And

I’m going to finish up with a local general—Illinois has three

RTOs. And I’d like to have Mr. Esposito, he talked the seams issue,

what are the difficulties you face in a State in which there is actually three different RTOs?

Mr. ESPOSITO. The easy answer, Congressman, is that you know

for three RTOs you have at least three seams, and you have to deal

with things like scheduling times, being consistent when you go to

put your power on the system, and you’re going to go across these

seams, that everything links up.

You have issues with what they call ramp rates. Some RTOs will

look at different ramp rates and some might start at the beginning

of the hour, some might start 15 minutes before the hour. These

are problems that they’ve experienced in other places, particularly

New England, New York, PJM. And you have to get some entity

to say this is going to be the rule. And in the case of natural gas,

that became the Gas Industry Standards Boards. It looks like we

may have the Electric Industry Standards Board there to do that.

Being able to deal with those important issues that are day-today, hour-to-hour issues is critical.

Conversely, three isn’t all that bad because you have a situation

where you will develop best practices. Now, one of the things we

had in the New York/New England PJM area was a situation

where one of them required you to schedule your power an hour

and a half ahead and the other allowed you to schedule the exact

same type of transaction a half hour ahead. So we were able to say

‘‘well, they could do it in a half hour, why do you take an hour and

a half.’’ And you develop best practices over time.

So I think looking at resolving seams, we shouldn’t jump all the

way to saying we’re going to have a uniform set of rules across the

country or a uniform market, because that could be a uniform mistake.

Mr. SHIMKUS. I’ll just two bits worth and yield back, Mr. Chairman.

It does tie into my previous comments and the effect, although

you may eventually get to best practices there may be some deficiencies initially in the system by which you may not be able to get

the return on the investment which addresses the repair and the

maintenance and the possible development of redundancies and the

things I think, the new environment—in this new environment

that we’d better start talking about and considering.

And with that, Mr. Chairman, thank you and I yield back my

time.

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Mr. BARTON. For our last questions, the gentleman from North

Carolina.

Mr. NORWOOD. Could the gentleman respond to that, Mr.

Esposito?

Mr. BARTON. I didn’t think that was a question. I thought that

was a statement. But, sure if he wants to respond.

Mr. ESPOSITO. Yes. I would just respond when you go to a competitive market, you’ve got people like us who make money finding

efficiencies in the system. When people say no, we say why not and

try to work around. And I think you end up with the work arounds

by having competitors enter the market. These aren’t people who

make money unless they find a solution.

Mr. GERKEN. Can I answer, add to that? I’ve got three RTOs.

One of the things that we’ve got three RTOs and we don’t see a

real issue of working within those. My issue from a small perspective is being able to move my power on an hour-to-hour basis.

Let’s say I’m trying to, for layman’s terms, I’m moving from one

IOU, IOU-A to IOU-B, and I’m moving 100 megawatts. What happens is during the hour I get a TLR, or transmission line relief that

says I have no capacity through that interface. That’s physically

impossible, but what happens is all the IOUs have reserved all of

their native load or all their generation to that capacity that says

zero. Well, my problem is if it was an independent system operator,

if I said ‘‘Okay, I will turn 50 megawatts of peaking generation on

in B to unload you 50 megawatts, will you allow me 50 megawatts

in,’’ I don’t get any justification or satisfaction because they control

the rules today.

If an RTO was there independently looking at it, watching the

flows, I would actually be giving them benefit as well as my asset

benefit. That’s all we see is the trouble area right now.

Mr. SHIMKUS. I should ask Mr. Norwood, is that fine? Do you

yield back your time?

Mr. NORWOOD. I didn’t have to.

Mr. BARTON. All right. Mr. Burr, the last questioner.

Mr. BURR. I thank the chairman. I’ve enjoyed listening to Mr.

Shimkus.

If I cover ground that you’ve already plowed before me, I apologize.

Mr. BARTON. I would encourage you to plow it quickly.

Mr. BURR. I will plow it extremely quickly.

Mr. BARTON. We’ve already had one crop harvested today.

Mr. BURR. I won’t even plant a second one.

Mr. Franklin, let me ask you, because I think you’ve covered in

some detail in your testimony some concerns that you have about

RTO formation specifically how quickly FERC’s trying to move.

Which speed should they move if they should?

Mr. FRANKLIN. Congressman, my concern is not so much how

quickly, it’s more a case of how prescriptive FERC apparently intends to be on the size and scope of the RTOs.

I think that, first of all, the RTOs that are formed we’re going

to be stuck with for a long, long time. And whether it takes 18

months or 21⁄2 years in the long term doesn’t make any difference.

I mean, it’s much better to get it right.

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At the same time, I think before this latest order coming out of

FERC, we were getting close to a broad agreement in the southeast

to form an RTO. Now, once we had the broad agreement to form

it, it probably takes a year to 18 months to actually put it in place

and have it working. So I don’t think under any circumstances

we’re talking about a long period. The issue is more how prescriptive FERC will be as opposed to letting RTOs evolve in different

regions.

Mr. BURR. What experience do we have within FERC today and

RTOs at their ability to evaluate the assets?

Mr. FRANKLIN. When you say ‘‘evaluate the assets,’’ you

mean——

Mr. BURR. Value the assets.

Mr. FRANKLIN. Oh, the value of the assets in an RTO? I first of

all wouldn’t profess to know what expertise is in——

Mr. BURR. But is the only example that we have up to this time

what we did in California? Was it FERC that valued the assets

that went into the——

Mr. FRANKLIN. No. No. I don’t think so.

Mr. BURR. All right.

Mr. FRANKLIN. Being from Georgia I’m in a perfect position to

evaluate and be an expert on California.

Mr. BURR. That’s why I asked you.

Mr. FRANKLIN. So take what I say with a grain of salt.

I think the high cost, and I’m going to say this very generally because I don’t want to overstate what I really know. The high cost

of forming the power exchange and the ISO in California was more

a case of the design, how elaborate the computer systems were, the

time it took to do it, how many people were involved. It seemed to

me it was sort of a design by committee. But it doesn’t seem to me

that the cost of buying those computer systems, putting the software together, hiring the staff; it doesn’t seem to me that that

should be related to be the FERC.

Mr. BURR. You, a southern company, to join an RTO would be

asked to turn over your transmission grid, correct?

Mr. FRANKLIN. We’d be asked to turn over the control and operation of our transmission grid, not the ownership.

Mr. BURR. The reimbursement that you might receive for the use

of that grid would have a significant factor on whether you participate in the upgrade of that grid, would be that be correct?

Mr. FRANKLIN. First of all, we have a—it would have a big factor

in whether we were smiling or frowning when we did it.

We have some legal obligations to provide services, Mr. Johnston

said about the municipals. So we have an obligation to build transmission. We have an obligation to expand the system as demand

grows. But it’s awfully hard to build transmission. You got to get

siting, you’ve got to deal with local landowners. It’s a very unpopular thing to do locally. And you can do it with a whole lot more enthusiasm and a whole lot more courage in dealing with local problems if you’re getting a decent return on that future investment.

Mr. BURR. Is there anybody that believes that we do not need to

upgrade our transmission grid in this country?

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Mr. Bennett, let me ask you, is it the position of the public utility

commissions that FERC has the authority to take a closed State

and to require them to open up, to participate in a——

Mr. BENNETT. I’m sorry, what were the last two words?

Mr. BURR. Does FERC have the authority in your estimation to

go into a closed State and require them to join an RTO?

Mr. BENNETT. I think that’s part of the litigation before the Supreme Court now, I would say it’s the position of NARUC and the

position of New York State that FERC does not have that authority.

Mr. BURR. I was just trying to get you to stay that.

Mr. BENNETT. And they should proceed on a voluntary basis.

Just a comment. One of the greatest problems, aside from the

economic part of it, one of the great problems is how do you get

the transmission lines built from one State to another.

I happen to live on Long Island, which is known as a load pocket.

We have a need for 5,000 megawatts and we can produce about

5,010 megawatts, so we’re right on the line. And we had a plan to

bring power across the Sound from Connecticut which was going

very well, and then at the last minute we derailed. Now, I’m sure

we can work things out with our friends in Connecticut, but it is

very, very difficult to get these transmission lines built even within

one’s State. And if you’re going to go from one State to another, the

difficulty becomes compounded. But I think that it works—we’re

going to do a lot better in that situation working with Connecticut

than if someone tried to mandate it.

Mr. BURR. It may have been your testimony, Mr. Franklin, and

I think we’ve had it before and I certainly understand it, that the

ability to site generation might overcome some of the bottlenecks

in transmission grids. And I would also add to that, and I’ll be

happy for you to comment, that there are many places in the country where, for whatever reasons, we won’t build generation facilities where there’s a need for power. And the ability to upgrade a

transmission grid and put a generation facility in the desert, as advantageous as it is, for somebody else to put a generation facility

right next to a high growth area where we can deliver power.

Under the scenario, shouldn’t we as a national interest make

sure that whatever we do is something that creates the type of incentive that does upgrade our transmission grid where it’s needed?

Mr. FRANKLIN. Yes, sir. I think there are two points.

When deciding where to build generation, for example, we don’t

need to let the cost of transmission or the cost of generation alone

dominate that discussion. We need to look at the total cost of both.

The real incremental cost; how much more is it going to cost to

build a generating plant in location A versus B, and how much new

transmission is going to be required. And add the cost up and

whichever one is the lowest cost, that’s where the generation

should be built. And if we get transmission pricing right, that’s exactly, in my judgment, that will happen.

So the first issue is to get the pricing right so generation is built

where it needs to be built. I think the second component you referenced is to be sure it is a reasonable financial investment to put

money in transmission so that the capital is coming into the transmission business.

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If we do those two things, I think the market demand will over

time make sure we have the right amount of transmission and

we’ll have generation located in the right place.

Mr. BURR. Is there anybody that would disagree with the statement that Wall Street will be a good indicator as whether we’ve

found the right balance as to how to write a transmission bill? I

show that as all yeses.

Thank you, Mr. Chairman. I yield back.

Mr. BARTON. Thank you, gentlemen.

I want to thank this panel. This concludes our series of hearings

on the electricity industry. The next step is to put out a second

draft after appropriate consideration of the comments on the first

draft. I would encourage you to look at our RTO proposal that I authorized the release of yesterday afternoon. Get those comments in

writing to us as quickly as possible.

The Senate is attempting to move some sort of energy legislation.

If and when that occurs, I would like to be able to go to markup

with an electricity bill so I could have the option with Mr. Dingell

and Mr. Boucher, and Mr. Tauzin to put it into the comprehensive

energy conference if that occurs.

Thank you, gentlemen, for your testimony today.

This hearing is adjourned.

[Whereupon, at 3:45 p.m., the subcommittee was adjourned.]