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CAN THE U.S. ELECTRIC GRID TAKE ANOTHER

HOT SUMMER?

HEARING

BEFORE THE

SUBCOMMITTEE ON ENERGY AND RESOURCES

OF THE

COMMITTEE ON

GOVERNMENT REFORM

HOUSE OF REPRESENTATIVES

ONE HUNDRED NINTH CONGRESS

SECOND SESSION

JULY 12, 2006

Serial No. 109–229

Printed for the use of the Committee on Government Reform

(

Available via the World Wide Web: http://www.gpoaccess.gov/congress/index.html

http://www.house.gov/reform

(II)

COMMITTEE ON GOVERNMENT REFORM

TOM DAVIS, Virginia, Chairman

CHRISTOPHER SHAYS, Connecticut

DAN BURTON, Indiana

ILEANA ROS-LEHTINEN, Florida

JOHN M. MCHUGH, New York

JOHN L. MICA, Florida

GIL GUTKNECHT, Minnesota

MARK E. SOUDER, Indiana

STEVEN C. LATOURETTE, Ohio

TODD RUSSELL PLATTS, Pennsylvania

CHRIS CANNON, Utah

JOHN J. DUNCAN, JR., Tennessee

CANDICE S. MILLER, Michigan

MICHAEL R. TURNER, Ohio

DARRELL E. ISSA, California

JON C. PORTER, Nevada

KENNY MARCHANT, Texas

LYNN A. WESTMORELAND, Georgia

PATRICK T. MCHENRY, North Carolina

CHARLES W. DENT, Pennsylvania

VIRGINIA FOXX, North Carolina

JEAN SCHMIDT, Ohio

BRIAN P. BILBRAY, California

HENRY A. WAXMAN, California

TOM LANTOS, California

MAJOR R. OWENS, New York

EDOLPHUS TOWNS, New York

PAUL E. KANJORSKI, Pennsylvania

CAROLYN B. MALONEY, New York

ELIJAH E. CUMMINGS, Maryland

DENNIS J. KUCINICH, Ohio

DANNY K. DAVIS, Illinois

WM. LACY CLAY, Missouri

DIANE E. WATSON, California

STEPHEN F. LYNCH, Massachusetts

CHRIS VAN HOLLEN, Maryland

LINDA T. SANCHEZ, California

C.A. DUTCH RUPPERSBERGER, Maryland

BRIAN HIGGINS, New York

ELEANOR HOLMES NORTON, District of

Columbia

———

BERNARD SANDERS, Vermont

(Independent)

DAVID MARIN, Staff Director

LAWRENCE HALLORAN, Deputy Staff Director

TERESA AUSTIN, Chief Clerk

PHIL BARNETT, Minority Chief of Staff/Chief Counsel

SUBCOMMITTEE ON ENERGY AND RESOURCES

DARRELL E. ISSA, California, Chairman

LYNN A. WESTMORELAND, Georgia

ILEANA ROS-LEHTINEN, Florida

JOHN M. MCHUGH, New York

PATRICK T. MCHENRY, NORTH CAROLINA

KENNY MARCHANT, Texas

DIANE E. WATSON, California

BRIAN HIGGINS, New York

TOM LANTOS, California

DENNIS J. KUCINICH, Ohio

EX OFFICIO

TOM DAVIS, Virginia HENRY A. WAXMAN, California

LAWRENCE J. BRADY, Staff Director

DAVE SOLAN, Professional Staff Member

LORI GAVAGHAN, Clerk

SHAUN GARRISON, Minority Professional Staff Member

(III)

C O N T E N T S

Page

Hearing held on July 12, 2006 ............................................................................... 1

Statement of:

Kelliher, Joseph T., chairman, Federal Energy Regulatory Commission .... 12

Mansour, Yakout, president and CEO, California Independent System

Operator; Mark S. Lynch, president and CEO, New York Independent

System Operator; Peter Brandien, vice president of system operations,

New England Independent System Operator; and Phyllis E. Currie,

general manager, Pasadena Water and Power ........................................... 35

Brandien, Peter ......................................................................................... 163

Currie, Phyllis E. ....................................................................................... 172

Lynch, Mark S. .......................................................................................... 61

Mansour, Yakout ....................................................................................... 35

Letters, statements, etc., submitted for the record by:

Brandien, Peter, vice president of system operations, New England Independent System Operator, prepared statement of ..................................... 166

Currie, Phyllis E., general manager, Pasadena Water and Power, prepared statement of ........................................................................................ 174

Issa, Hon. Darrell E., a Representative in Congress from the State of

California, prepared statement of ................................................................ 3

Kelliher, Joseph T., chairman, Federal Energy Regulatory Commission,

prepared statement of ................................................................................... 16

Lynch, Mark S., president and CEO, New York Independent System

Operator, prepared statement of ................................................................. 63

Mansour, Yakout, president and CEO, California Independent System

Operator, prepared statement of ................................................................. 39

Watson, Hon. Diane E., a Representative in Congress from the State

of California, prepared statement of ........................................................... 194

(1)

CAN THE U.S. ELECTRIC GRID TAKE

ANOTHER HOT SUMMER?

WEDNESDAY, JULY 12, 2006

HOUSE OF REPRESENTATIVES,

SUBCOMMITTEE ON ENERGY AND RESOURCES,

COMMITTEE ON GOVERNMENT REFORM,

Washington, DC.

The subcommittee met, pursuant to notice, at 2:08 p.m., in room

2154, Rayburn House Office Building, Hon. Darrell E. Issa (chairman of the subcommittee) presiding.

Present: Representatives Issa, Westmoreland, Bilbray, Higgins

and Kucinich.

Staff present: Larry Brady, staff director; Lori Gavaghan, legislative clerk; Tom Alexander, counsel; Dave Solan and Ray Robbins,

professional staff members; Joe Thompson, GAO detailee; Shaun

Garrison, minority professional staff member; and Cecelia Morton,

minority office manager.

Mr. ISSA. Thank you, ladies and gentlemen. I call this meeting

to order, a quorum being present.

This is a hearing of the Government Reform Subcommittee on

Energy and Resources. I ask unanimous consent that the gentleman from California, Mr. Bilbray, be permitted to participate in

this hearing today. Without objection, so ordered.

Good afternoon again. Welcome to the subcommittee.

Today, we will highlight FERC’s recently released Summer Energy Market Assessment of 2006, which identified four major geographic areas of potential critical electrical supply. These areas are

southern California, my home; Long Island, NY; southwestern Connecticut; and the Ontario, Canada, area, which affects the Great

Lakes and clearly has an impact into our country because it is a

source for our power.

Each of these areas is particularly vulnerable in the hot summer.

They are also at risk to unplanned outages by local generators and

disruptions in electricity imports from other regions. Each of the

potential U.S. trouble spots were identified, no surprise, in FERC’s

2004 and 2005 summer assessments.

The issue is of paramount importance not only because I have

constituents in southern California who have previously had the

lights go out but because they are important to the economic wellbeing of the entire Nation.

The potential for rolling blackouts and supply shortages particularly in these regions would have spillover affects and thus greater

implications for the Nation’s electricity system. Furthermore, supVerDate 11-MAY-2000 11:59 Jul 10, 2007 Jkt 000000 PO 00000 Frm 00005 Fmt 6633 Sfmt 6633 C:\DOCS\34544.TXT HGOVREF1 PsN: HGOVREF1
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ply shortages would have a significant negative impact, especially

taking into account the current high price of power.

In addition to hearing today from FERC on its summer assessment, we will hear from regional Independent System Operators

[ISOs] which coordinate electrical transmission and oversee wholesale electricity markets in the U.S. trouble spots.

An important question today for our witnesses is: What are you

doing to address the summer’s challenges—bearing in mind these

trouble spots read like a list of the usual suspects from past assessments—and what are you doing in the long term? I’m particularly

interested, assuming we squeeze by this summer, what are we

doing for the years ahead, assuming a robust and increasing economy?

On our first panel today we are pleased and privileged to have,

I believe for the first time by the new chairman, the Honorable Joseph T. Kelliher, chairman, Federal Energy Regulatory Commission.

Our second panel will be represented by ISOs and a municipal

from southern California. We will be welcoming Mr. Yakout

Mansour, president and CEO of the California ISO; Mr. Mark

Lynch, president and CEO of the New York ISO; Mr. Peter

Brandien, VP of System Operations at the ISO of New England;

and Ms. Phyllis Currie, general manager of Pasadena Water and

Power, a member of the ISO and a public utility.

I look forward to these witnesses.

[The prepared statement of Hon. Darrell E. Issa follows:]

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Mr. ISSA. I ask unanimous consent that the briefing memo prepared by the subcommittee and staff be inserted into the record as

well as all other relevant materials.

I now yield to the ranking member, the gentleman from New

York, for his opening statement.

Mr. HIGGINS. Thank you, Mr. Chairman.

I don’t have an opening statement, but on behalf of ranking

member Diane Watson I would ask that her statement be submitted into the record.

Mr. ISSA. Without objection, so ordered.

Mr. HIGGINS. I want to hear the testimony of the expert panelists.

Mr. ISSA. Mr. Kucinich, would you have an opening remark?

Mr. KUCINICH. I do, thank you, Mr. Chairman.

Today, the Federal Energy Regulatory Commission sits before us

with the 2006 Summer Energy Market Assessment. This Assessment outlines four geographic areas that may be unable to deal

with the surge in electricity demand this summer. Blackouts are

possible in those areas.

I want to thank FERC for identifying these areas before we set

into the hottest days of summer. But I want to point out that this

list is substantially similar to the lists of past years. I hope that

FERC will explain to the committee today why these areas continue to reappear on the list, year after year.

I would also like to note for the record that in the 2003 Summer

Energy Market Assessment, FERC failed to identify Ohio as an

area of concern. Shortly thereafter, in August 2003, the United

States suffered its largest blackout ever. This blackout began in

Ohio, and it spread across much of the northeastern United States

and Canada. I think most people remember it. If we are to believe

FERC’s prediction for 2006, we need to be confident that the Federal Energy Regulatory Commission overcame its past shortcomings that contributed to the 2003 blackout.

Let me remind the subcommittee that deregulation of this energy

market was and still is creating reliability problems. First Energy,

like many power companies, was driven by a motivation to put

profit above the public interest. This culture has led to a lack of

maintenance and deterioration of their infrastructure. These factors played a key role in the 2003 blackout that caused 50 million

people to lose power.

The U.S.-Canada Power System Outage Task Force Interim Report found that First Energy bears significant responsibility for the

largest blackout in U.S. history. Essentially, First Energy, in its

bid to maximize profit, caused an estimated $6 billion in economic

losses. Reliability is the cornerstone of responsible electricity production, and in a deregulated market the regulator has to step up

and ensure reliability is not sacrificed for greater profits. I hope the

Federal Energy Regulatory Commission understands this.

The excessive electricity rates paid by the American people

should come at least with a guarantee of reliable service. Instead,

deregulation has driven prices higher and made our electricity system more visible to disruption. We are paying more for worse service.

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Thank you very much, Mr. Chairman, for holding this hearing;

and I look forward to the testimony of the witnesses.

Mr. ISSA. Thank you, Mr. Kucinich.

For all Members, there will be 5 legislative days in which to submit their opening remarks.

With that, I would like to ask not only Chairman Kelliher but

all the other witnesses to please rise and take the oath according

to our committee’s rules. Also, anyone who is going to provide access and speak on behalf, please raise your right hand.

[Witnesses sworn.]

Mr. ISSA. The record will show that everyone answered in the affirmative, including a very darling young child.

Mr. Chairman, we normally ask you to stay within 5 minutes. By

unanimous consent, your entire testimony will be in the record, so

you are free go off of that if you dare. Thank you.

STATEMENT OF JOSEPH T. KELLIHER, CHAIRMAN, FEDERAL

ENERGY REGULATORY COMMISSION

Mr. KELLIHER. Thank you, Mr. Chairman.

Mr. Chairman, members of the subcommittee, thank you for this

opportunity to appear before you to discuss the Commission’s Summer Energy Market Assessment and the measures we have taken

to assure adequate electricity supply and enhance the interstate

electric transmission grid. The Energy Policy Act of 2005 gave the

commission important new regulatory tools to address both market

and reliability issues, and I welcome this chance to review current

market issues and to report to you on how we are using the new

authorities you gave us just last year.

Mr. Chairman, first of all, let me start by commending you for

holding this hearing. Six years ago, an electricity crisis began in

California. It quickly extended to the rest of the West and endured

for a year. The reason the California crisis expanded and became

the western power crisis is that California is not a distinct and separate electricity market. It is part of a broader western electricity

market, and I think it is important. That event demonstrates the

nature of wholesale power markets in the United States. Power

markets are not neatly defined by State boundaries, but we also

don’t have a national electricity market. Instead, we have a series

of regional markets, and there is significant differences among

those regions.

Now, wholesale power markets are also international. The

United States is fully interconnected with Canada and with part of

Mexico. So wholesale power markets are actually in some instances

both regional and international. I think that is one reason the

Commission looked at the Ontario market this year, because it

clearly has effects in the United States; and I go through that introduction really to emphasize that problems in southern California

do not remain within southern California and they can extend and

affect other markets. So I want to commend you for the focus of

this hearing today.

Now the Commission staff prepares an assessment of energy

market conditions before each summer electricity cooling season

and each winter natural gas heating season. These reports highlight major changes from years before and areas of potential conVerDate 11-MAY-2000 11:59 Jul 10, 2007 Jkt 000000 PO 00000 Frm 00016 Fmt 6633 Sfmt 6633 C:\DOCS\34544.TXT HGOVREF1 PsN: HGOVREF1
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cern for the upcoming season; and, overall, there has been improvement over the past year.

The Assessment noted four geographic areas in North America

that could face problems this summer: southern California, Long

Island, southwest Connecticut and Ontario, with implications for

adjoining markets in Michigan and New York. Now in all four

areas supplies appear to be adequate to meet normal demands on

the system, but all four regions could be at risk if the demand is

high or key parts of the generation or transmission system have

unplanned outages. Under these conditions, prices could be high

and some load may need to be shed.

Now each of these areas has already been tested by some periods

of early summer heat; and, so far, there have been no major problems. In most regions, however, July and August are the times of

greatest vulnerability to sustained high heat, so we are not out of

the woods yet. Moreover, looking beyond the summer, all four of

these areas that were the focus of the Commission’s Assessment remain at greater risk of electricity supplies tightened in future

years.

Now turning to the four regions identified in the Assessment,

southern California faces another summer of tight supply in an

area of fast-growing demand. The region depends very heavily on

imports from northern California, from the Pacific Northwest and

the Southwest, particularly at peak. In their high-load scenario,

southern California needs to import 10,000 megawatts, fully a third

of its supply. That is a much higher dependence on imports than

we see in most other parts of the country. Since last year, transmission upgrades have helped import capability somewhat, but net

generation growth in southern California barely covered load

growth.

Now, southwest Connecticut in the Northeast, southwest Connecticut again faces a very tight balance between supply and demand. Combined local generation and import capability are not sufficient to meet expected demand and reliability requirements.

Transmission capacity for imports now operates at or near its limit,

while transmission capacity within the region cannot fully support

local generation or the addition of new generation.

The region had not added significant generation or transmission

capacity since 2004. While transmission upgrades are under way,

they will not be complete until late 2009; and until those upgrades

are completed, the infrastructure in southwest Connecticut remains

very fragile.

Now New York City and Long Island pose longstanding challenges for the electric system. The Assessment noted key improvements in New York City as recent generation investments begin to

relieve some reliability concerns. But on Long Island, however, the

balance of supply and demand remains tight. Imports from upstate

New York and New England are still crucial for Long Island, and

the area remains exposed to the risks of heat and unplanned generation and transmission outages.

During last 2 weeks, two of the four major transmission lines

into New York City from upstate New York have failed. The loss

of these two lines means that New York City as well as Long IsVerDate 11-MAY-2000 11:59 Jul 10, 2007 Jkt 000000 PO 00000 Frm 00017 Fmt 6633 Sfmt 6633 C:\DOCS\34544.TXT HGOVREF1 PsN: HGOVREF1
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land will be tested during any periods of sustained hot weather

this summer.

Now, finally, the Assessment touched on the Canadian province

of Ontario, which imports power from adjacent U.S. electricity markets in New York and the Midwest as well as the province of Quebec. The Assessment noted the North American Electric Reliability

Council’s view that Ontario has already lost some of its tight capacity margin since last summer, and our concern is the effects that

Ontario demand and the operation of the Ontario market may have

the U.S. markets. As indicated earlier, wholesale power markets

can be both regional and international, and this is certainly one

case of that.

Part of the problem last summer related to Ontario market rules,

and I want to praise Ontario regulators. Since last summer, they

have changed those rules and adopted day-ahead scheduling earlier

this summer, so I think they should be commended for that action.

The problems in the areas studied in the Seasonal Assessment

have certain common features. At its most basic level, it is clear

that adequate infrastructure is necessary in order to meet demand.

Infrastructure is both generation and transmission, the ability to

generate electricity supply and the ability to transmit it to where

it is needed. It is absolutely necessary that the relationship between adequate infrastructure and prices and reliability be understood and be appreciated. To the extent that infrastructure is inadequate, prices will be higher and reliability will be undermined. It

is the inevitable consequence.

Now the question is how to ensure there is enough transmission

investment to deliver power to the areas that need it and enough

generation to be able to meet demand, especially in highly populated load pockets. And the question is also how do we assure reliability in the bulk power system.

Now we are acting in these areas. One of the Energy Policy Act’s

major goals is to strengthen the U.S. energy infrastructure, especially the transmission grid. And transmission underinvestment is

a national problem. The United States has had a sustained period

of underinvestment in the transmission grid that goes back to the

1970’s. If you look at the transmission grid, the expansion of the

transmission grid last year in terms of circuit miles was 0.5 percent, which is pretty close to zero.

Now recognizing that is a national problem, we are developing a

national solution. We have issued proposed transmission pricing

rules to spur greater investment in transmission, and we are moving to finalize those rules in the near future.

Now in passing and enacting the Energy Policy Act, Congress determined that some Federal transmission siting authority was

needed to lower barriers to adequate investment in the transmission grid. The Commission and the Department of Energy have

been working very closely over the past year to implement the

transmission siting provisions in the new law, and last month the

Commission issued proposed rules to implement the Federal transition siting provisions.

The Commission has also been acting to ensure resource adequacy or adequate electricity supply. This is a complicated area—

as you can see from that protest over there—but it is a complicated

15

area in large part because the Federal and State jurisdiction is imperfect in this area. Neither Federal nor State regulators have perfect jurisdiction to assure resource adequacy. That means that we

must collaborate and work closely with State regulators and, to the

greatest extent possible, since electricity markets are regional in

nature, to develop regional solutions to regional problems.

I’d like to highlight for a moment a recent settlement that we approved that would assure resource adequacy in New England. I

think it is useful to spend a minute or a part of a minute on this

process to show——

Mr. ISSA. Without objection, the gentleman will have another

minute.

Mr. KELLIHER. Thank you—on now necessary and difficult it is

to address regional resource adequacy issues.

As the Summer Assessment noted, part of New England faces

the prospect of electricity supply problems, if not this summer but

very soon. Demand for electricity in this region has been growing

and growing quite fast, and supply is not increasing to meet demand.

Last year, the New England region as a whole added a total of

11 megawatts in new generation and new electricity supply—11

megawatts—while peak demand rose by 2,700 megawatts. That is

exactly the kind of trend we saw in California leading up to the

California electricity crisis, a sustained period of a number of years

where demand far outstripped supply.

Now the New England region faces the real prospect of supply

shortages and high prices in the near future. ISO New England

proposed a locational installed capacity plan, or LICAP, to address

this resource adequacy problem. This proposal generated considerable controversy and was an area of interest to members and senators from the region, and the Commission urged the parties to engage in settlement discussions around an alternative to the LICAP

proposal. We authorized settlement discussions and appointed a

settlement judge; and I am happy to report that, in the end, there

was a very significant settlement. Out of 115 parties, 108 settled.

The region developed a regional solution to this problem, and we

ended up adopting the regional solution.

Finally on electric reliability, the Commission has acted very

quickly to implement the reliability provisions of the Energy Policy

Act. We have issued rules to govern the certification of the electric

reliability organization, and we’re moving ahead to consider and ultimately adopt enforceable mandatory reliability standards and to

ensure that we have a very strong regime of enforcement of reliability standards.

So we’re taking actions to address, as you highlighted in your

opening statement, these problems in the long term. So thank you

for your attention.

Mr. ISSA. Thank you, Mr. Chairman.

[The prepared statement of Mr. Kelliher follows:]

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Mr. ISSA. I’m going to waive my opening round of questions so

that we can get to each of the Members here because of the likelihood that some of them will have to go in and out.

Suffice to say only one thing, which is we have had discussions

about how to deal with pump storage and how to price it as advanced transmission; and I recognize that it is a process question,

in addition to a pricing question. I also recognize that there are

current matters you won’t be able to speak to. What I would like

to do is give you more time throughout this, and if there is time

remaining we will talk on the record about it. Then, if there is not,

I would like to submit for the record so that we can have an indepth discussion of how we are going to progress to promoting this

advanced transmission system in every place appropriate around

the country. Is that agreeable?

Mr. KELLIHER. Yes, sir.

Mr. ISSA. I thought it would be. Thank you.

With that, vice chairman, Mr. Westmoreland, please start the

opening round of questions.

Mr. WESTMORELAND. Thank you, Chairman Issa.

Mr. Chairman, thank you for being here.

Mr. KELLIHER. Thank you.

Mr. WESTMORELAND. Some people have stated in the not-so-distant future reserve margins in certain areas will be at a critical

level. I know that transmission has been cited as a solution to this

problem, but I feel there needs to be greater emphasis placed on

increasing our total energy supplies. What do you see being done

to increase new generation?

Mr. KELLIHER. Well, there have been different approaches taken

in different regions. One fact that isn’t really commonly understood

is that the United States, over the past 10 years, have we added

electricity supplies? How have we met demands for the past 10

years? Most of that electricity supply over that period has been

built by independent power producers. Something like 74 percent

of the electricity supply built over that year has been built my nonutilities.

That trend has changed recently. Right now, if you look at most

power plants under construction, I believe the majorities right now

are being built by utilities, vertically integrated utilities. The

United States has met electricity supply in different ways over

time. If you were to go back 40 years, how did we build electricity?

It was built completely by vertically integrated companies without

exception.

In the 1980’s, it started being built largely by independent power

producers backed by long-term purchase contracts signed by the

utility as the buyer and then resold to retail consumers. Five years

ago, it was built by nonutilities who were building completely at

risk, building multibillion dollar facilities without any contract to

sell any of the output. Now that means of building power plants,

perhaps that one is not going to be tried again. The risk ended up

being much higher than I think the generators anticipated.

Now we are in a period where the balance has shifted back to

the utilities building. The question really is, is that a temporary

shift? I think probably the right answer is we have different kinds

of wholesale power markets. In some wholesale power markets,

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there is not much left of vertical integration. For example, New

England. In New England, by virtue of State action, not FERC action or Federal action, most generation was divested by the utilities. So, in New England, the vast majority of supply is met by

independent power producers, and I think it would be very difficult

to undo that.

But in other regions of the country vertical integration remains

the norm. So I think, probably the correct answer, there is very significant differences among the wholesale power markets in this

country. In one region, the solution to meeting supply needs would

probably be the independent power producer and in another it

might be the vertically integrated incumbent utilities. In others, it

will probably be both under some State competitive bidding process. If the utility ends up being the low bidder, perhaps it is perfectly reasonable for them to be the builder, but they may not be.

Mr. WESTMORELAND. Thank you.

One followup question, if I could, Mr. Chairman.

The FERC recent study explained that, in areas of this country,

who are in danger of potentially critical supply. Who is responsible

for addressing reliability? I know you mentioned the reliability factor versus the cost and the transmission. Is it FERC’s job to address the reliability? Is it a State issue? Is it a regional issue? And

should it be passed along to that ratepayer such as—I live in Georgia, and we have a great power company there, but should that increase of somebody else’s reliability service be passed on to that

ratepayer?

Mr. KELLIHER. Well, there are different senses of reliability. In

terms of reliability, if you mean in the Energy Policy Act of 2005

sense, the reliability of the bulk power system, those we will set

standards at FERC, and those standards will assure reliability of

the bulk power system, and the cost of those standards will be recovered and be passed through.

If you are talking about reliability in a broader sense in terms

of supply reliability, that’s the area that I pointed out it was very

complicated, where State and Federal jurisdiction is imperfect. We

don’t have jurisdiction over power plants. We don’t have jurisdiction—except when they are sold. We review a sale from a market

power point of view.

But in terms of building a power plant, it is sited by States

under State law. The States have that jurisdiction. States have jurisdiction over the utilities, the State-regulated utilities; and they

would be responsible for making sure the State-regulated utility

has adequate supply.

We have jurisdiction over wholesale power sales and wholesale

power rates. Now there is certainly a relationship between the two,

but we, by and large, we don’t have jurisdiction over the State-regulated utility and the decisions it makes on how to meet supply.

That’s typically something that’s overseen by the State commissions, the State regulators. We would regulate the wholesale market.

Mr. WESTMORELAND. So you don’t have control over the whole

grid system?

Mr. KELLIHER. We have jurisdiction over the interstate transmission system, and we have jurisdiction over the wholesale power

31

sales, not wholesale power purchases. The lines—a lawyer can

draw the lines neatly. An economist would probably blanch at the

notion of some of these distinctions.

States have jurisdiction over retail sales and retail consumers.

We have jurisdiction over wholesale power sales and utilities when

they are selling power for resale. Any sale that is not to an ultimate consumer, like an industrial or residential consumer, we

would have jurisdiction over because that is a wholesale sale or a

sale for resale. But you have two markets, retail and wholesale

market. One is federally regulated and one is State regulated, but

they clearly have effects on one other.

Mr. WESTMORELAND. I was going to say that.

Thank you, Mr. Chairman.

Mr. ISSA. Thank you, good round of questioning.

Mr. Kucinich.

Mr. KUCINICH. Thank you very much, Mr. Chairman.

Mr. Kelliher, does the FERC monitor utility efforts to ensure reliability of the transmission system?

Mr. KELLIHER. We are currently in the process under EPAct—before the Energy Policy Act was enacted, FERC had no authority to

enforce reliability standards, let alone penalize anybody for violating reliability standards. I think that is one of the effects of the August, 2003, blackout. Congress gave us that authority.

We are in the process of reviewing 102 proposed reliability standards, and we will soon propose adopting certain aspects of those

standards. We are also in the process of certifying an electric reliability organization. We are really faithfully executing the model

that Congress set up where what Congress wanted was to be a selfregulating organization, an industry organization. We would certify

them if they had the expertise and independence to develop the reliability standards. We would review and approve them, make

them enforceable. But the first responder on enforcement would be

regional entities and the electric reliability organization. We would

be the ultimate enforcer.

Mr. KUCINICH. Well, in connection with that, then how do you

ensure utility maintenance? Are you monitoring utility maintenance? And, if not, who is?

Mr. KELLIHER. Maintenance that is necessary to comply with reliability standard, we would ultimately ensure—we would ultimately enforce those requirements. We would do so through audits.

We would do so through the prospect of civil penalties of a million

dollars per day per violation.

Mr. KUCINICH. What degree of granularity do you have here? For

example, going back to our experience of 2003 which made many

of us in Ohio experts on utility blackouts, we know that the utility

in question, First Energy, was not properly maintaining their

transmission system.

Mr. KELLIHER. Yes, sir.

Mr. KUCINICH. So my remarks earlier about how—you know,

what are we doing in 2006 that we didn’t do in 2003? How specific

is the monitoring of the utility performance on a critical issue of

maintenance?

Mr. KELLIHER. Maintenance in terms of tree trimming?

Mr. KUCINICH. Maintenance in terms of transmission.

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Mr. KELLIHER. Well, the principal maintenance—let’s hypothesize the principal maintenance with respect to a transmission facility is vegetation management. Vegetation management has been

a common cause to all the regional blackouts that have occurred in

this country going back to the 1960’s, so it is going to be——

Mr. KUCINICH. I am not talking about vegetation management.

I am talking about vegetating management. I’m talking about management which is not hiring enough people to do the maintenance.

That was one of the issues in Ohio, by the way. You can have

a great plan for managing trees interfering with transmission lines

or distribution lines, but if you don’t have enough people—this is

the fundamental question. What I saw in Ohio is that First Energy

was actually laying off people who would be used to be able to keep

the transmission lines clear.

My question again to you is, how specific would be your monitoring of utility maintenance of the transmission systems?

Mr. KELLIHER. The way the law was structured was most enforcement would be done at the regional level with regional entities—we would approve a delegation of enforcement authority from

the North American body, the electric reliability organization, to

regional entities. We would in turn oversee both the electric reliability organization and the regional entities.

It is critical that the regional entities’ enforcement be strong and

credible and consistent. Ultimately, I think what would ensure that

a company subject to reliability standards complies with those

standards was a million dollars a day multiplied over a year ends

up being a pretty substantial amount of money. And that kind of

violation—let’s assume somebody violates the vegetation management standards. That would be a continuing violation every day for

a sustained period of time, and a million dollars a day times 365

starts becoming significant. And I think it gives—you were concerned about financial incentives. I think it gives them a financial

incentive to have a strong maintenance program.

Mr. KUCINICH. Thank you.

I have just one quick final question. I see in your report you say,

with respect to Ontario, our concern is the effects that Ontario demand may have on U.S. markets, and you go on to say that demands for emergency energy could make balancing supply and demand in New York and in the Midwest more difficult and more

costly.

Are you then saying that if Ontario has a need for emergency energy it could have a negative effect on the supply in New York and

the Midwest, thus increasing the price of power to consumers in

these regions? And if you are saying that, how much of a price increase could people be looking at?

Mr. KELLIHER. I couldn’t estimate what a possible price effect

might be.

But, as you pointed out earlier, on August 14, 2003, an event in

Ohio led to blackouts in Canada and then through Canada into

New York. These markets, they are physically interconnected; and

there is also significant transactions throughout the interconnected

markets. So there can be price effects. As we saw in the West, incidents in California extend across not just 11 States but two Canadian provinces. So it can happen.

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Mr. KUCINICH. Thank you, Mr. Chairman.

Mr. ISSA. With that, we go to the lightning round in order to get

the chairman out of here when we leave for our votes.

Mr. Bilbray.

Mr. BILBRAY. Mr. Chairman, both the Los Angeles and San Diego

region is a nonattainment area under the Clean Air Act. Over the

last 20, 30 years, there has been no new facilities produced in those

areas for good reason. As a former member of the Air Resources

Board, I have seen the numbers on reducing emissions, not increasing them. How do we develop the type of reliable sources? Strictly

by bringing in outside sources? Or can we do it internally?

Mr. KELLIHER. Well, that’s one of the challenges. Southern California does rely very highly on imports. And if you look at another

area that was addressed in the Summer Assessment, New York

City, New York City has a rule, an 80/20 rule that they have had

since the late 1970’s or early 1980’s. Their general rule is 80 percent of the generation of the supply needed to meet New York City

demand has to come from inside New York City, and they want to

limit their dependence on imports to 20 percent. I think that’s

something that is fairly unique to New York.

A load pocket—southern California has a load pocket, New York

City and Long Island have load pockets, load pockets where there

is high demand, very thin margin between supply and demand, difficulty in adding generation within the load pocket for various reasons but environmental considerations being one of them.

In some of the load pockets, if you see that tight balance, generation can be a solution. Transmission can be a solution. Sometimes

you need both. Sometimes you need to lean more on one area than

another.

Now in California they do recognize the problem, and they seem

to have an interest in leaning more on a transmission solution than

perhaps a generation solution in southern California. Perhaps Mr.

Mansour can address that in the second panel. But they are significantly expanding transmission in California. They are making significant investments. In some respects perhaps they are catching

up to—in those investments in areas where there has not been

much in recent years. It really will vary from region to region.

It is an issue that we have to deal with because we’re looking at

the mid Atlantic States where New Jersey regulators, our colleagues in the State, argue that there is a very tight supply and

demand in balancing northern New Jersey, but it is very difficult

to build generation in northern New Jersey and they think a transmission solution is necessary more than a generation solution. So

it really will vary. It is difficult to build generation in some parts

of this country.

Mr. BILBRAY. The perception that transmission is the environmental option has kind of run into problems in southern California,

too, where you have a transmission proposal going through State

parks.

Has anybody talked about the fact that in local utilities we tap

into general purpose governments to do siting, but when it comes

to transmission capabilities we don’t draw on the Council of Governments [COGs]? We almost leave it up to the project proponent

to find these alignments and sort of like it is their problem, not our

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problem, in government to be able to find the best economic and

environmental opportunity to be able to site these things. Has anybody talked about including that as the responsibility of the Council of Governments?

Mr. KELLIHER. I’m not aware of that.

A lot of utility executives say the reason they don’t build much

transmission—they don’t spend more, they haven’t in the past, it

is the hardest thing to get done. It is easier to build generation

than transmission is what you hear frequently. I think that is one

reason that Congress changed the law and provided for some Federal siting jurisdiction.

Mr. BILBRAY. As somebody who comes from local government, it

is always easier to say no and how terrible the proposal is to either

put the facility or the transmission capabilities in. But local government and regional government have never been given the responsibility to be proactive and say, OK, you don’t like this proposal. Where is the best proposal, as you see it, and be proactive

about siting that ahead of time. We site the subdivision, but we

never want to site the transmission lines.

Mr. KELLIHER. Yes.

Mr. ISSA. Thank you. You stayed well within the time. I appreciate that.

As promised, we are running out of time because of the vote.

Mr. Chairman, I am going to give you a very few questions and

ask you, if they are yes-nos—which they are not—to answer them.

Otherwise, we will take the rest in writing to allow you not to wait

25, 30 minutes for us to return.

Mr. KELLIHER. Thank you.

Mr. ISSA. And my apologies to the ISOs, that it is impossible to

not ask to you please be patient.

In your testimony, you talked about the failure of the two lines

in upstate New York into New York City. It didn’t actually get into

the details of what caused the failures, and I would appreciate if

you would make the record complete by, when available, giving us

more information on the specifics of those failures. Particularly, we

have one—the ranking member has left——

Mr. KELLIHER. I will provide that for the record.

Mr. ISSA. I appreciate that.

Obviously, one of the questions is one that may be more difficult

and beyond the Assessment. Since these trouble spots have been on

the record 2004, 2005 and now 2006, what is it going to take to

have them removed from X-year? I think we all realize that some

of them are going to be back on in 2007, and the ISOs particularly

today will talk to us a little bit about their regions and how they

are getting out of it.

But to the extent that the FERC believes they know the minimums necessary to take them off the list, that would be helpful

that you give us your vision of it, which would be hopefully similar

to the ISOs.

The growth of renewables in California and the mandating of renewables—obviously, we are thrilled to have as much clean renewable energy as we can, but I would appreciate it if you would give

your feeling on how it makes reliability more difficult. In California

specifically, where we have a lot of wind, it is reliable that we have

35

wind. But that we don’t have it when we need it is also reliability

predictable.

So to the extent you can show the impacts—obviously, that is

going to impact advanced transmission and pump storage and how

the two relate. You don’t have to be exhaustive. I don’t want you

to go beyond what you would give reasonably here today.

Last but not least, in my opening statement or in my opening

sort of question, I said I am extremely interested in how the FERC

is going to, from a process and time line basis, get to valuing pump

storage in order to define what advanced transmission is and why

it can be incorporated at X-price by our ISOs. Because today it appears as though we have a great relief valve for some of these peak

needs. Unfortunately, if you have a mountain and you have a siting

of a transmission line but you don’t know what the value of that

pump storage is, those projects are not going to go forward.

I know that we will hear from the ISOs, and they will give us

some insight. But to the extent you can show us a process and time

line, that would be very helpful. If you have any responses before

you throw me out of here.

Mr. KELLIHER. Could I respond to those questions for the record

in writing?

Mr. ISSA. Absolutely.

With that, I would like to thank all of you for your patience in

advance for about a 20 minute delay, and then we will convene the

second panel. We stand in recess.

[Recess.]

Mr. ISSA. This meeting of the subcommittee will come back to

order. I appreciate your patience as we went through our obligation—the thing that we use as an excuse for rudeness so often

here.

With that, you have already been sworn in.

Your opening statements, as I said earlier, by unanimous consent

will included in the record.

I appreciate you using roughly 5 minutes.

With that, Mr. Mansour, I guess you get the leadoff; and all you

have to do in your opening statement, of course, is respond to everything that the FERC had to say earlier. You get that responsibility. Thank you.

Mr. MANSOUR. Do I get the time allowance as well, Mr. Chairman?

Mr. ISSA. By unanimous consent, so ordered.

STATEMENTS OF YAKOUT MANSOUR, PRESIDENT AND CEO,

CALIFORNIA INDEPENDENT SYSTEM OPERATOR; MARK S.

LYNCH, PRESIDENT AND CEO, NEW YORK INDEPENDENT

SYSTEM OPERATOR; PETER BRANDIEN, VICE PRESIDENT OF

SYSTEM OPERATIONS, NEW ENGLAND INDEPENDENT SYSTEM OPERATOR; AND PHYLLIS E. CURRIE, GENERAL MANAGER, PASADENA WATER AND POWER

STATEMENT OF YAKOUT MANSOUR

Mr. MANSOUR. Thank you very much; and good afternoon, Mr.

Chairman, committee members and honored representatives.

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My name is Yakout Mansour, and I am the president and chief

executive officer of the California Independent System Operator

Corp., that I will refer to as ISOs as I go. I joined the ISO in March

2005, so it has been over a year, but I have been intimately involved with the western electricity market for many years.

It is a pleasure and honor to be here today to discuss the electricity outlook in southern California for the summer of 2006, our

efforts to overcome the challenges we are facing, and the steps that

have been taken to address the long-term needs of California.

Just in case I lose my time allowance, Mr. Chairman, in a nutshell, California, since restructuring and actually since the time of

the crisis, has added 14,000 megawatts of new generation. We retired over 6,000 megawatt of inefficient and socially unfriendly resources, old resources already. So the net is 8,500 or so, but the effect remains that we have 14,000 megawatt of new generation in

California.

$3.5 billion of transmission have already been in the ground and $4.5 billion have been approved in total, including that $3.5 billion.

In the process as we speak, between the utilities of southern California, Edison and San Diego, there is about $6 to $7 billion of

transmission projects.

But that is not enough. This is California. That is growing fast.

We are firing on four cylinders at the same time. We are catching

up on a period where investment was not enough.

As was mentioned, there was a lack of investment for a long time

before restructuring, and that is actually what drove restructuring.

We are retiring the old fleet. We are accommodating one of the

most aggressive renewable programs in the country, if not the

most. The fourth one is accommodating one of the strongest economic growths.

Compared to a year ago, which is last summer, now this summer

we are about at the same level as we were last summer in terms

of our stress of the grid. From last summer until today, we have

1,900 megawatt of new generation. They are both in the south,

which makes up for more than the retired old, which is about 1,500

megawatt. That is including Mojave in the south and Hunter’s

Point. Both were publicly opposed projects.

Now the net is modest, yes, 300 or 400 megawatts between the

1,900 which is significant and what we have retired. But the fact

remains from last summer until this summer we have 1,900

megawatts of more efficient and reliable generation.

The grid import capability has been increased by about 800

megawatts. Our grid reliability cost, what we call the congestion

cost, have decreased by over 40 percent. In 2004, it was over $1 billion. Last year, it was around $600 million.

We have a very pleasant increase in the subscriptions to the demand response and interruptible programs, especially those in the

south and those in the north. All are very active and all the participants are very active in promoting conservation. There are more intensive efforts to promote conservation; and the Governor never

misses a chance to promote conservation, whether at a private

meeting with us or public meetings.

Last year, the State consumers were credited with about 800

megawatt due to conservation. So what does the picture I refer—

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I think someone is operating a computer slide for me. If you could

press the first slide. Next one.

For California overall, the total control area supply is about—

close to 52,000 megawatts, and that is after excluding 4,000

megawatts of outages, possible outages. The most likely demand for

California is just over 46,000 megawatts; and, Mr. Chairman and

members of the committee, we are—I think we may achieve this,

actually, that forecast, by the end of this week.

So that leaves us about 12 percent margin. By the way, we need

about close to 7 percent margin for operating reserve. If we account

for the response of interruptible programs which we only use in

emergencies, that would be 24 percent.

But this is the interesting thing. Those programs, people are paid

actually in advance to be ready to be interrupted if we need them

to. But to do that we have to say it is an emergency so we make

the news, and we have to interrupt, and they make the news again.

It is called then something we lost load, but, actually, they are paid

to do it, and they are part of the program. We would like to see

more of that.

Next slide.

For southern California, the load forecast is about 30,000

megawatts—sorry, 27,000 megawatts; and the resources available

are 30,000 megawatts, as we mentioned earlier, about 10,000

megawatts, 30 percent of that on import. But California and the

West have invested over the years billions of dollars on the transmission grid to make that possible. This is a good thing, because

it capitalizes on the regional diversity both in resources and weather. So that leaves us in southern California 10 percent.

You see the margin between 10 percent and what is needed for

operation is 7 percent is only 3 percent, and that is what we call

tight. If we include the demand response and interruptible programs, that would be about 20 percent.

The next slide, please.

That is a pictorial that, when we say tight, how tight are we and

what do we mean? The numbers that I’ve just presented to you represent the middle part of this graph, the middle bar in this bar

chart. And you can see under the most likely condition the green

line, even with accounting of up to 2,000 megawatt loss of import

capability, we have slightly more than what we need to have. If

you account for the interruptibles, you can almost be close to the

extreme 1 in 10 in terms of load. That is based on additional 1,500

megawatt outage.

Now if you go to the left, things get really extreme. If you have

very high load and you have higher outages on generation and you

have a 2,000 megawatt loss of import, you get closer to the possibility of tripping firm load. Now how far you go to the left to say we’re

comfortable, this is a measure of public policy, how much the public

is willing to spend and the cost to make more available to California in those extreme conditions.

So as operators, of course, regardless of how slim the chance of

the slim conditions is, we prepared for the worst. So what do we

do for the short term?

Next one.

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For the short term, we’re conducting operator workshops. We

have so far trained over 300 operators nationwide, promoting conservation together with all the agencies and the Governor’s office.

We are engaging all the suppliers and the power plants, coordinating maintenance. We are completing all the upgrades in the grid,

improving communications with LADWP and Bonneville, implementing new market rules, and we are improving the forecast.

For the long term—this is my last piece. Next slide, please.

For the long term, 2007 is likely to be as tight or even a bit tighter than we have today, because we don’t have as many generation

plants from last year to now. But we have a break of the deadlock.

The utilities would not go long term because they were not assured

cost recovery, and the market rules that we have today—the original market design that we have today before we get to the new

market design doesn’t give them really comfort to invest. So there

is a new proposed ruling from the PUC that will get close to 4,000

megawatts by 2009.

So, hopefully, 2009 for sure, that we are going to be OK. We hope

that we can get some by 2008; 2007 for sure is going to be tighter.

We are going to get the first two.

After that, the transmission development—we don’t call it transmission planning; we call it transmission development—is streamlined. We are currently identifying and studying major projects:

Sunrise, Greenpath, Tehachapi and Lake Elsinore. We’re talking

about $5 billion, as I said; and the last is the market tools which

is the market redesign and technology upgrade.

In this respect, yes, we’re tight under extreme conditions, but we

have plans to minimize the impact and hopefully squeeze by. In

this respect, I am confident we have the ingredients that we need.

The long debates about let us do more studies or, you know, give

us more time to do new things, I think we should be past that.

Overall, I can say, yes, we’re tight, but not to the point where

the lights will be off all the time. It is going to be maybe sometimes. Last year, we were as tight. We had one of our best operations ever. Are we going to have some lights off? Hopefully not,

but we’re prepared to minimize that impact.

Thank you, Mr. Chairman and members of the committee.

Mr. ISSA. Thank you.

[The prepared statement of Mr. Mansour follows:]

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Mr. ISSA. Mr. Lynch,

STATEMENT OF MARK S. LYNCH

Mr. LYNCH. Thank you, Mr. Chairman.

My name is Mark Lynch; and I am president and chief executive

officer of the New York Independent System Operator [NYISO].

The NYISO’s mission is to ensure the reliable, safe and efficient

operation of the State’s major transmission system and to administer an open, competitive and nondiscriminatory wholesale market

for electricity in New York State.

The fundamental importance of system reliability is highlighted

in New York State as home to one of the world’s most important

financial and communication centers. After reviewing the FERC’s

Summer Assessment, we generally agree with the Office of Enforcement’s findings as they pertain to New York and the potential

risk to be addressed this summer.

It is important to note that New York has a long history of interregional coordination and mutual assistance with our neighboring

control areas, which include ISO New England, PJM, and the Canadian provinces of Ontario and Quebec. These arrangements are

fundamental to the overall reliability of the region and have proven

very effective in allowing control area operators to manage system

contingencies and respond to system emergencies.

New York State’s generation resources currently meet all applicable standards, including the locational requirements that apply

to New York City and Long Island. The outlook for both New York

City and Long Island has improved for this summer as compared

to last year, though high fuel cost and demand could still yield high

prices there this summer. Long Island has benefited from the operation of its submarine cable interconnection with New England.

Additional benefits will be achieved when the planned Neptune

cable between PJM and New York is completed.

Notwithstanding an overall positive outlook for the summer, it is

important to note that recent unplanned outages on two transmission cables into New York City occurred following the issuance

of the Summer Assessment. These outages are expected to continue

until early to mid-August and have added to the challenges of dealing with the summer demand in New York City.

The New York ISO has worked with Con Edison to implement

plans to address the situation, and the city continues to meet all

applicable reliability criteria. However, the possibility for voltage

reductions or controlled, localized load shedding remains somewhat

elevated under extreme weather conditions or in the event in the

loss of additional facilities.

In addition to ensuring day-to-day reliability, the New York ISO

is concerned with providing market signals to attract the infrastructure and investment needed to meet the future demand in

electricity. In 2005, the NYISO conducted the first in a series of annual studies as part of its comprehensive reliability planning process. The first draft report recently issued by the NYISO identifies

future reliability needs and finds that resources needed to address

them are either planned or under development. The draft report

also identifies issues and potential risks and provides an action

plan to address those issues.

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Of course, it is important to ask whether the wholesale electric

markets in New York State support and encourage investment in

new generation facilities where they are needed. The answer so far

is a resounding yes.

The location-based approach to pricing energy and capacity provides detailed price signals about where additional generation is

needed and the likely economic value of that generation. Nearly

5,000 megawatts of new capacity have been added to the system

since NYISO began operation. Generator availability rates have

improved by over 10 percent, which is largely the result of the

NYISO’s capacity market rules that reward high unit availability.

In addition, the NYISO’s demand-side programs, which include

over 1,800 megawatts of resources, have been very successful.

Notwithstanding the success of the NYISO markets in sending

economic signals to incent development, longstanding institutional

barriers continue to impact the development of needed infrastructure. For example, New York State’s generating siting law, referred

to as ‘‘Article X,’’ expired in 2003 and has not yet been replaced.

The longer-term reliability and economic needs cannot be met

with new generation alone. Further growth of the NYISO’s demand-side programs and improved transmission facilities are also

very important to satisfying continued load growth.

While some transmission capacity has been added in recent

years, overall investment in transmission in New York has been

modest. The difficulty of licensing transmission has long been a

challenging impediment to transmission investment. The backstop

provisions provided by Congress included in last year’s Energy Policy Act will help alleviate that uncertainty.

In conclusion, the paramount responsibility of the New York ISO

is to ensure reliability of the New York State’s bulk electric system.

Since it began operation in 1999, the New York ISO has fulfilled

this mission without compromise. The markets administered by the

New York ISO have proven not only to be compatible with system

reliability but, in fact, have enhanced system reliability in New

York State by providing the price signals necessary to attract additional generating capacity, by providing financial incentives for

generating units to maintain a high rate of unit availability, and

by introducing innovative demand-side programs that increase reliability and market efficiency.

As we move forward to address the important challenges that

I’ve touched upon today, I am confident in the New York ISO’s

ability to meet the reliability needs of New York State while administering fair and open and competitive markets.

Thank you.

Mr. ISSA. Thank you.

[The prepared statement of Mr. Lynch follows:]

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Mr. ISSA. Mr. Brandien.

STATEMENT OF PETER BRANDIEN

Mr. BRANDIEN. Thank you, Mr. Chairman and members of the

Subcommittee on Energy and Resources. I think I have a number

of positive points to report to you today about southwest Connecticut and whether or not it is going to continue to be on the list as

we move forward.

For the record, my name is Peter Brandien. I’m the vice president of system operations at ISO New England. My remarks will

address the challenges facing New England and southwest Connecticut in particular and the actions taken by the ISO and the

stakeholders to address the long-term concerns.

First off, I want to emphasize that the ISO plans and operates

the bulk power system in New England, including southwest Connecticut, to meet reliability standards and the criteria established

by ISO New England, the North America Electric Reliability Council and the Northeast Power Coordinating Council.

I agree in general with the FERC observation that there is inadequate capacity in southwest Connecticut and that no significant

capacity has been added since 2004 and that the transmission system is operating to its limit.

The ISO forecasts possible recordbreaking demand for electricity

in New England this summer. On average, summer peak demand

is growing at 2 percent per year in New England, which equates

to about 500 megawatts or one combined cycle generating plant.

The summer peak in southwest Connecticut is also growing at the

same 2 percent per year.

We expect the region will have adequate resources this summer.

However, the region or local areas could experience tight supply

conditions if generation is constrained or if hot, humid weather increases demand. In these cases, the ISO has longstanding procedures to maintain reliability. These include the activation of demand-response resources, purchasing power from neighboring control areas and implementing voltage reductions. These procedures

also include public appeals for conservation through the media;

and, in the past, we have had very good relations with the media

getting the word out and the response that we have had from our

customers.

As a last resort, after all operating procedures have been exhausted, the ISO may be required to institute controlled power outages to maintain reliability in the bulk power system if the regional demand for electricity exceeds the supply.

The ISO has developed a communication protocol to inform the

public officials throughout New England of the actions taken by

ISO New England to manage the bulk power system under these

type of circumstances. We keep them informed as the system gets

tighter and tighter so they are not caught unaware at the end. We

have a communication protocol with a caution, watch, warning type

thing so that people are aware and we get the information out to

the media.

ISO has identified a lack of resources to ensure reliability in

southwest Connecticut and in 2004 secured emergency demand-response resources for that area through a competitive bid. The RFP

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resulted in additional quick-start capacity for the summer peak period for 2004 through 2007. Although resources haven’t been added

since 2004, that RFP did take into consideration the requirements

that we would need through 2007, recognizing that the transmission upgrades would not be there. The RFP was designed to

bridge these gaps until these transmission reinforcements were put

in place.

The ISO has worked with the New England stakeholders to develop long-term solutions for southwest Connecticut.

The State of Connecticut has approved major transmission reinforcements in southwest Connecticut. The Southwest Connecticut

Reliability Project will extend the 345 network, which is the backbone of the transmission system, in New England into southwest

Connecticut. This will be done in two phases. The first phase will

be in service by the end of this year, December 2006; and the second phase is expected to be in service by the end of 2009. While

these projects will not be in place for this summer, they are critical

to ensure the reliability in southwest Connecticut for the long term.

There is a significant reliability benefit to get that first phase in

2006, and we will see these benefits even though the second phase

will not be in service until 2009.

One of the responsibilities delegated to the ISO by the FERC is

to develop a regional system plan for an open stakeholder process

that identifies a need for additional infrastructure and provides solutions to ensure reliability for New England. We take that responsibility very seriously, and the ISO identified the need for transmission reinforcements in southwest Connecticut in our 2001 regional system plan, which was the first year that ISO published a

regional system plan.

On June 15, 2006, the FERC approved the settlement agreement

for a new Forward Capacity Market in New England under which

the ISO will conduct auctions beginning in 2008 for capacity resources to be developed beginning in 2010. The new capacity market is the result of a lengthy stakeholder process, subsequent litigation and, ultimately, settlement discussions surrounding the best

approach to meet New England’s growing need for capacity.

On May 12, 2006, the FERC approved the ISO and NEPOOL’s

proposal, known as Phase II of the Ancillary Services Model

Project, to develop much-needed fast-start resources to provide reserves, particularly in the low pockets throughout New England.

ISO is scheduled to implement this new market October of this

year.

In conclusion, while there are significant challenges in southwest

Connecticut that will persist until the planned infrastructure improvements are complete, ISO New England has procedures in

place to operate the system reliably in New England and southwest

Connecticut should emergency actions be required this summer.

For the long term, a combination of transmission projects and

wholesale market improvements are intended to provide additional

capacity in southwest Connecticut to meet the area’s growing demand for electricity.

I would also like to say that we have transmission projects into

our other load center, the Boston area, significant transmission system upgrade as well as transmission projects that are approved

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and under construction to reinforce our ties with New Brunswick

and also improve the reliability in Northwest Vermont. So through

this regional system planning process we have sited and have a

number of transmission projects throughout New England that will

improve the overall reliability.

Thank you.

Mr. ISSA. Thank you.

[The prepared statement of Mr. Brandien follows:]

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Mr. ISSA. Mrs. Currie.

STATEMENT OF PHYLLIS E. CURRIE

Ms. CURRIE. Good afternoon.

Mr. ISSA. The thing that is scary is that Peter said he provides

it, but you say wait a second if he is going, ‘‘What is that button?’’

That is not something you want to hear in switching power, is it?

Ms. CURRIE. That is true.

Good afternoon. I am Phyllis Currie, general manager of the

Pasadena Water and Power Department of the city of Pasadena,

CA. My comments this afternoon speak to conditions in southern

California, which were also the subject of Mr. Mansour’s comments.

Pasadena is a municipal electric utility that is located geographically in the Los Angeles basin, and electrically we are within the

control area of the CAISO.

Pasadena distributes electricity to approximately 61,000 retail

customers. We buy power from and sell power to participants in

California and the regional wholesale power markets; and we also

are both a transmission customer of the CAISO and also a participant and transmission owner, which means we have turned over

operational control of our transmission assets to the CAISO.

I also serve as the president of the Southern California Public

Power Authority; and that consists of 11 utilities and 1 irrigation

district, all public power. Collectively, we serve over 2 million people in southern California.

SCPPA was formed in 1980, and the purpose was to facilitate

joint investment of generation and transmission projects which our

members would not have been able to finance alone. We have included a map in my written testimony that shows you all the

projects that we are a part of.

In my written testimony, I describe in detail the recent investments by both Pasadena and SCPPA; and these include generation,

transmission, and natural gas reserves which we believe will give

our customers the adequate reliability and deliverable power that

they deserve. These investments are also available to help the region overall meet the summer peak demand.

I want to emphasize the need for the continued close coordination among the CAISO load-serving entities like Pasadena and the

other SCPPA utilities and regulators during the summer to assure

that the expectation of our customers for reliable power are met.

Finally, I want to voice concern about the market redesign and

technology upgrade proposal that Mr. Mansour referred to, and this

is something that the CAISO has filed with FERC.

In my role at Pasadena and at SCPPA and in my former life as

CFO of the L.A. Department of Water and Power, I have had a lot

of experience in financing generation and transmission projects;

and our concern is that what attracts capital investment are clear,

simple, and stable rules that allow investors to understand the risk

that they will incur and to reduce those risks.

Pasadena and the SCPPA members were very concerned that the

market rule changes that are being proposed will discourage development of much-needed generation and transmission and will inhibit efficient use of all available resources on a regional basis. The

MRTU finding, which is over 5,000 pages, is 180 degrees away

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from the direction that investors want and need. The proposed

rules are not clear, they’re not simple, and they’re not stable.

To give you an example, the MRTU proposal does not provide a

mechanism to ensure that load-serving entities like Pasadena are

able to obtain the long-term transmission rights as directed by

Congress in the Energy Policy Act of 2005. Such rights were one

of the biggest issues in the electricity title of that act, and the

MRTU proposal is not only inconsistent with Congress’ intent, but

it also does not conform to the very constructive rule on long-term

rights that FERC issued in 2006.

In order to invest in long-term-generation load serving, entities

like Pasadena need to know that they are able to have transmission over the long term so that they have certainty about the

deliberate cost of energy to consumers.

Another example, the MRTU adopts a complex series of scheduling processes that differ from prevailing practices in the rest of the

western interconnection. This has the effect of discouraging transactions among participants in the western market and increase the

cost of those transactions that do occur.

Bottom line is that the MRTU proposal at this point does not

permit a reasonable degree of cost predictability and in our opinion

will not facilitate market transactions or interoperability in the

western interconnection.

Twelve western senators also voiced their concern by writing to

FERC noting these concerns and urging that the Commission

should, ‘‘proceed cautiously and provide a thorough vetting of the

issues raised.’’ A copy of the Senate letter is included in my written

testimony.

However, I want to assure you that the public power community

is committed to working with all parties including the CAISO to

ensure that this summer all of our customers have the energy that

they need. I took the opportunity during your break to give Mr.

Mansour a very detailed idea of what our issues are.

In conclusion, I thank you for this opportunity and look forward

to answering your questions.

Mr. ISSA. Thank you.

[The prepared statement of Ms. Currie follows:]

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Mr. ISSA. I want to thank all of you for making every effort to

stay as close as you could to the 5 minutes.

Ms. Currie, I would like to hear more about, you know, the simplicity and the strategy, but I think what I’m probably going to do

is ask Mr. Mansour to answer your questions in a moment, and I

think that may be better to have somebody that can respond.

Before I do that, I want to ask all of you, in your individual

areas, the ISOs and obviously within the Pasadena umbrella, if the

worst case occurs, as in your chart, Mr. Mansour, but in all of

yours, if the worst case occurs this year, that the highest likely outages occur somewhere in California, New York, New England, will

we have power outages? Does your worst-case scenario assume

that, unless everyone runs home and turns off their air conditioners, that we will have power outages if the worst occurs?

Mr. MANSOUR. Mr. Chairman, my definition of worst-case scenario is not just that everyone turns off their air conditioner. It is

also high level of outages of generators more than the average we

get. It is also outages of major transmission elements, as I said,

one of the major entities with the West like 2,000 megawatts.

Mr. ISSA. I appreciate that. But if all of that happens——

Mr. MANSOUR. If all of that happens, if you have major transmission outages, a lot of generation out, more than normal, and extreme hot temperature, we will have outages. Some of them—hopefully, the majority of them will be the planned outages which is the

one that is contracted for interruption. The amount that would be

forced to be out, our role is to minimize that amount in terms of

magnitude and duration.

But all of those scenarios are trained on. The operators are

trained on how to respond to it, how to prepare in advance so that

they do not propagate to the rest of the West and what is the recovery process so we can minimize the duration.

Mr. ISSA. Mr. Lynch. By the way, I’m mostly talking about, for

all of us that are sort of my age, it is like the biorhythm charts

where you have the ups and downs. I’m just talking about the likely high end of your range occurring at the likely high end of your

range between transmission outage, production outages and, obviously, a hot day. I’m not talking about the earthquake. But it appears as though that is the answer, is, if those coincide, we will

have either forced or nonforced outages predictably if all three line

up.

Mr. MANSOUR. That is correct, sir. For example, the transmission

outages, we had transmission outages over the last few weeks on

major transmission lines because of eagle nesting and eagle activities and forest fires but not earthquakes.

Mr. ISSA. We should trim those eagles, I guess.

Mr. Lynch.

Mr. LYNCH. Your question I think takes on sort of a very farreaching or a worst-case scenario as you put it. Within our planning and within the system that we have available, we do look at

various contingencies and the N minus one contingency of losing

the single worst—or I guess resource that you have out there, be

it a transmission or a generating facility. The way our system is

set up it can absorb that.

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Actually, looking at New York City, because of the previous

blackouts in and around the city, we go into thunderstorm alert at

certain times in the summer and actually look at an N minus 2 criteria. Essentially, with the cables that we have out, we are almost

in that right now, where we could still withstand a single loss of

a major contingency, a resource being out or another transmission

line.

After that, we get thin, and we go into emergency procedures,

and I think Mr. Brandien outlined very similarly what we would

do. You would look to your other control areas. You would curtail

basic transactions across your borders. You would look for emergency power to come in. You would then look to some type of a notice and actually initiation of our demand-response programs.

In New York, we have two types, not only the emergency demand

response but we contract ahead for demand response that we know

that we can count on. We would basically call on those programs,

and you would have to look at some type of voltage reduction. As

the very last resort, I think you would be looking at some very localized types of load shedding or load management control. But you

would have to get into a pretty dire situation.

That is not to say that the stars can’t align and the biorhythm

chart can’t put all three lines crossing at the same time. Anything

is possible. We saw that in 2003. But I think, overall, when you

look at the system this summer, we run about an 18 percent reserve margin on the system. We actually have a little bit more

than that. We do have the capability of imports and feel pretty

comfortable, other than going to that extreme, extreme condition,

that we should be good this summer.

Mr. ISSA. Mr. Brandien, I am making this more complicated perhaps in the question, I am just making the assumption that your

goal is to be able to have the statistical inevitably that you will

have transmission problems along unexpected outages on a hot day

at some point. It is numerically—statistically, it is going to be and

your goal is to be able to either have no outage or only dip in that

situation to those that have been paid for that relief because that

is part of the realignment plan. If that happens today—and you already have transmission problems, so I’m very confident the other

two line up—you are going to be looking at keeping hospitals lit

while turning off other people in the worst case.

Mr. Brandien, how would you be in that situation today.

Mr. BRANDIEN. I tend to be an optimist in these situations. I

think the probability is low. We do a lot of things to ensure that

the probability stays low: the maintenance we do on the infrastructure in the springtime; the maintenance that we do on the generators; looking at the various scenarios, high loads, high outages; get

the word out to our constituents throughout New England, keeping

them informed as we experience, say, the first outage and that the

system is getting closer and hopefully the public responds and voluntarily reduces the load——

Mr. ISSA. Out of respect of the other Members’ time, I’m going

to cut short. I’m going to paraphrase what you said earlier, which

was basically you have a plan to beg people to shut down things

as part of your survival. So I’m going to make the assumption at

this time you don’t have the ability to do it by ordinary means, nor

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do you have advanced load shedding beyond industrial customers,

and that is one of the concerns of this committee, that we apparently don’t have that.

Ms. Currie, I’m assuming that you are going to say that, since

you depend on other people, in your testimony you don’t have a

high confidence if those line up you are not going to have your customers denied power.

Ms. CURRIE. I think, to the contrary, as a municipal utility operator, we have adequate reserves to cover our customers. In fact, we

have more than what is required.

We are, however, supportive of entire State; and so if the CAISO

says there is a system-wide emergency, we will shut down our customers, even though we have adequate reserves for them, in order

to support the rest of the State. That has happened in the past. It

could happen in the future. Based on the CAISO’s predictions,

we’re hopeful that we won’t do that this summer.

Mr. ISSA. Thank you.

And, again, I’m going to respect the other Members and alternate

and come back for a second round if there is time.

Mr. Higgins.

Mr. HIGGINS. Thank you, Mr. Chairman.

My questions are specific to the New York Independent System

Operator. As I understand it, New York is a deregulated market.

The process works in a way whereby the Independent System Operator establishes what the demand for the day is and then the

producers—kind of like a reverse auction, if you will—the producers respond to that; and once the daily demand is met, that is the

price paid to all of those who have submitted proposals.

Mr. LYNCH. It is not exactly like that. We actually run two markets a day ahead. Commitment market, which is a financial market, it is based on bids and offers. Generators will provide offers;

and we will make commitments in a day-ahead scenario so that we

feel, based on projections from the load-serving entities, that we

have sufficient capacity met.

When we get into the real-time markets, you are correct, we are

a balancing market. And if there are transmission constraints or

generation outages, there is locational pricing. As a rule, there is

a locational pricing, a current price that is out there. And what I

think you are referring to is the uniform pricing, as opposed to bidas-pay pricing where you would get whatever was bid in. But we

actually look at a clearing price across the State.

The important point there is that it is a locational pricing; and,

historically, prices upstate in the northern and western part of

New York State have actually been lower than downstate in New

York City and the Long Island area, specifically because of the constraints. In other times, when there are no constraints, you may

have a unit setting the marginal cost or the lowest production price

available across the State.

The way we run our markets, though, we do look at the lowest

production cost. We do drive the system to the marginal cost, and

I think that is one of the true benefits of what we do.

Overall, as I said, there would be very few instances when there

are no constraints in the system, that a unit downstate would be

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setting the price for the entire State with the locational zones that

we have in place.

Mr. HIGGINS. Statewide capacity supply, 40,000 megawatts?

Mr. LYNCH. Yes, we have about—I would say about—well, I will

tell you exactly. We have a little over 39,642 megawatts of in-State

supply. Our projected peak demand this year is a little over 33,000

megawatts. We look at about an 18 percent reserve. That is not

counting our demand-side program. I mentioned that we have contracted forward for demand-side management, which we call special case resources, about 1,000 megawatts.

We also, since we run a capacity market in New York, we actually contract ahead for import capacity; and we have the capability

to import about another 2,700 megawatts. So we have fairly good,

sufficient capacity.

One of the things—and I think it goes back, Mr. Chairman, to

your question on concerns about loss of contingency. We also have

locational requirements for New York City where physically what

we do is we project the peak demand for New York City and we

require, physical, on the ground, of 80 percent of that peak capacity

be located within the city. For Long Island, it is actually 95 to 99

percent of the physical capacity that is needed to meet their peak

demand to be located within that boundary so that they are not depending on imports from transmission but actually have robust

generation facilities within their geographical boundaries to meet

those loads.

Mr. HIGGINS. What you are saying is a 39,000 megawatt capacity

or supply and a peak demand of approximately 33,000 megawatts.

Mr. LYNCH. That is correct.

Mr. HIGGINS. It seems those margins are pretty tight.

Mr. LYNCH. It is 18 percent; and that is actually dictated through

the NPCC, the Northeast Power Coordinating Council. They give

us a criteria to look at our installed reserve margin, and it is different in different regions. Taking that criteria, we have come up

with—and it has been pretty consistent over the last 5 to 10

years—of carrying about an 18 percent reserve margin.

Mr. HIGGINS. Right. But I’ve also read statements where you

have encouraged the State legislature to site more plants presumably for the purpose of increasing supply capacity. If you are comfortable with that 18 percent margin, what is the basis for making

or encouraging the siting of more plants to build in new supply capacity?

Mr. LYNCH. Well, from a market standpoint, when you look at a

locational pricing—as I mentioned, we ask for a certain amount of

capacity to be within New York City and also Long Island in running a market that is supply and demand and price is set by tighter supply. So the more supply that you have, obviously there is

price alleviation both on the energy sides and the capacity side. So

having more capacity available will actually provide a better mix,

a better reliability.

Mr. HIGGINS. I’m sorry, but that also provides the cost-cutting

stimulus that is promised from more competition.

Mr. LYNCH. Well, when you say cost-cutting stimulus, I think

what you are looking at is competitive forces to come in and basiVerDate 11-MAY-2000 11:59 Jul 10, 2007 Jkt 000000 PO 00000 Frm 00191 Fmt 6633 Sfmt 6633 C:\DOCS\34544.TXT HGOVREF1 PsN: HGOVREF1
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cally alleviate price pressures and actually reduce overall consumer

prices.

Mr. HIGGINS. Isn’t that the effect of more capacity?

Mr. LYNCH. More capacity will help.

I would say, though, that I don’t agree with the statements that

some entities have made that deregulation, especially in New York

State, has resulted in higher prices. What you see is a phenomenon

of gas prices and oil prices, especially over the last 3 or 4 years,

just exponentially increasing over what anyone predicted.

When we do an analysis from 2000 to 2004 of fuel-adjusted prices

we actually find that consumers have benefited, 5 percent reduction in overall prices. That is on a fuel-adjusted basis. I believe

that the New York Public Service Commission came out with a

study that basically replicated the same type of analysis and indicated that on a fuel-adjusted basis you had a reduction in pricing.

Mr. ISSA. Thank you. Thank you for your line of questioning.

The Chair will take a prerogative and perhaps agree with the

gentleman in reverse. I think on both sides of the aisle here on all

energy issues, including gas, oil, natural gas and electricity, a

shortage in a free market will always lead to significantly higher

prices. We may not be sure if an excess will give us lower prices,

but I don’t think there is any question today as we fill up at the

pump that a shortage of refining or a shortage of capacity anywhere along the system inevitably leads to artificially higher

prices, and it is something that this committee has been dedicated

to on a bipartisan basis.

With that, Mr. Bilbray.

Mr. BILBRAY. Mr. Chairman, I just would like to point out in the

California experience—Ms. Currie probably wasn’t there—where

we did have the shortage was actually public utilities that were

wheeling and actually ending up making more off the situation

than the private sector was at that time.

First of all, Mr. Lynch, 80 percent to 90, that is a pretty impressive number. What technologies are you using to generate within

an urban area? Are you using natural gas or what combination are

you using?

Mr. LYNCH. You are specifically talking about New York City and

Long Island?

Mr. BILBRAY. Yes.

Mr. LYNCH. There are some older oil-fired-type plants there, but

predominantly the new generation that comes in has been gas. It

has been either combined cycle or what we call simple cycle, a combustion turbine. Predominantly, the new generation that I mentioned before has all been gas.

Mr. BILBRAY. Ms. Currie can you tell about the days we could

burn oil, right, Ms. Currie?

Ms. CURRIE. Mr. Bilbray, if I might comment on your first comment, the public power utilities made investments that benefited

the entire State and didn’t get paid for them. Furthermore, FERC

did a very exhaustive investigation as to whether or not we manipulated the market; and we were found not to have done that.

Mr. BILBRAY. There was no out-of-State sales?

Ms. CURRIE. There were out-of-State sales, but we were not market manipulators. We bought power and then turned it over to the

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State to benefit the entire State. So we think we did the right thing

during the last energy crisis, and we are prepared to continue to

do that.

Mr. BILBRAY. I appreciate that information. The last we saw was

that there was wheeling out to Arizona and some wheeling coming

back between Arizona and Utah.

Ms. CURRIE. I think those things were thoroughly investigated by

FERC, and we were exonerated.

Mr. BILBRAY. My question to you, if you were over at—in Los Angeles, we just decommissioned or—wasn’t the Laughlin facility a

joint project with Edison that the utility had for major generation

for a while?

Ms. CURRIE. Well, that may be a little bit after my time. I retired

from L.A. in 1999.

Mr. BILBRAY. They have decommissioned it since, but at the time

it was a pretty big generator. I was just wondering—you have left

there. If I can ask the representative from California, we just decommissioned a major facility that was generating for the Los Angeles air basin and has there been any replacement for that generation facility at Laughlin?

Mr. MANSOUR. If it is the Los Angeles Water and Power facility,

it is not in the ISO control area. L.A.—it is a separate controlled

area, and they are separate from the ISO. If you are talking

about——

Mr. BILBRAY. Actually, it was a joint project between the utility

and Edison in Laughlin. It was a slurry coal mixture operation that

has been decommissioned. I was wondering, as it is going to be

down, how to you replace that generation?

Ms. CURRIE. You may be thinking of the Navajo project. L.A. has

over 7,000 megawatts of capacity right now, and their peaks are in

the mid-5,000’s. So even with the loss of that capacity they would

still be well in excess of what they need to serve their customers

and support the rest of the State.

Mr. MANSOUR. I can tell you, as I said in my testimony, Mr.

Bilbray, there was 14,000 megawatts of new generation and retirement of 6,500 megawatts total. So the net is about 8,500 since the

crisis time. It is not necessarily growing in pace with the faster

growth, but there was a net of 8,500 megawatts in total.

Mr. BILBRAY. Thank you very much.

No further questions, Mr. Chairman. I yield back.

Mr. ISSA. Thank you.

On the Navajo, that generation shut down, as I understand it,

not just because of, if you will, air quality. It shut down, as I understand, because of water—inability to get a source of water.

Ms. CURRIE. Yes.

Mr. ISSA. And eventuality that even if they got that they only

had so many years. It was more complex shutting down of a facility

than just air quality.

Ms. CURRIE. Yes, it was; and I think it is important to point out

that, over the last 5 years, the municipal community of California

has added 2,800 megawatts of capacity. If you look at the total

amount of demand that we represent, that’s about 20 percent. In

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ered generation, which not only gives you more efficient generation

but it also cuts down on air quality issues.

Mr. ISSA. Just a brief answer, if possible, relative to California.

We took off, you know, 8,500—we have 6,000 megawatts lost, 14

brought in, 8.5 net. Excluding the Navajo facility, much of the rest

of that power, except for air quality rules, as I understand, could

have been kept for peak. But, in fact, it was taken off to get credits,

when in fact the facility is going to cost money to dismantle and

a relatively low cost to keep it as peak.

Is that your assessment? California’s air quality rules—I am not

disagreeing with them—but do encourage the dismantling of what

would otherwise be fully depreciated older facilities that could be

used in times of shortage?

Mr. MANSOUR. I can tell you, Mr. Chairman, that at least in the

last two—since I have been on the job—were shut down based on

public pressure. Mojave is—you know, Edison tried to make the

point to keep it; and they still for a while tried to even repower unsuccessfully. So they had to shut it down.

Hunter’s Point in the San Francisco area has been a point of dispute for a long, long time. Every politician in California I think lobbied to shut it down, and finally it did shut down. It is a combination of quality, neighborhood kind of uneasy about generation close

to the load center. Which really makes the point, when people talk

about generation and new transmission, I am yet to see a neighborhood that is willing to accept a generation plant rather than a

transmission. It is part of the difficulty between the two, so it is

a combination.

Mr. ISSA. Going back to advanced transmission, and I think all

of you—well, let me rephrase that. Certainly those of us with

mountains are particularly eligible to use the pump-storage-type

technology which New York has some, New England has some capability. California has two sets of ridge lines that run up and

down the State. We’re probably the wealthiest, other than the sort

of Rocky Mountain States, in the ability to put those in.

Assuming that the FERC works diligently and relatively quickly,

and can give us a formula to fairly analyze that, when we are looking not at the LEAPS project, which is one particular project, happens to be in my district, but when we are looking at the future

of relatively low cap cost compared to equal facilities of conventional generation and we are looking at putting in that 8 hours of

peak in the worst case, does this type of technology have the potential where you have the large drops, either water or the ability to

put in artificial water—does this represent what should be a substantial portion of our peak power? Obviously, we have the ‘‘what

ifs,’’ but, in concept, does it?

Mr. MANSOUR. I will start, Mr. Chairman; and I agree fully with

you.

I would even add to it that the more development and more aggressive development of renewable wind power, together with

pump storage facilities, is I think a marriage made in heaven. You

are talking about wind that blows at the time that you don’t need,

and it doesn’t blow when you need it, and you are talking about

major regulation issues. If we can marry the two whenever possible

it will increase the value of wind from a capacity point of view. So

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whenever it is possible and whenever within reason the cost is justified this is a technology that definitely should be on the map.

Mr. ISSA. Thank you.

Any of the other ISOs?

Mr. LYNCH. We do have pump storage in New York, and it works

pretty much off of our locational pricing, and it is compensated as

such. I am not familiar enough with the hydrology or the physical

terrain around where we have the run-of-the-river hydros and

whether we can actually facilitate that, but it is something we can

look at. As FERC basically crafts the rules, we would respond accordingly; and I think the market would, also.

Mr. BRANDIEN. We have about 1,600 megawatts of pump storage

in New England, and from an operating perspective they’re great.

When you look at trying to develop resources like wind, where potentially the output of those units can be going up and down significantly, integrating them into the grid, marrying them up exactly like it was said with a quick moving hydro unit makes a lot

of sense.

Ms. CURRIE. I think the only thing I would add is, if you have

the opportunity to develop such a project close to the load center,

that really is an additional advantage.

Mr. ISSA. Pasadena mountains come to mind?

Ms. CURRIE. We’re working on it, but I think that is going to be

a challenge.

Mr. ISSA. Obviously, these are challenges that remain.

I have one closing question, other than the ones that I would like

to submit for the record and ask you to answer at your reasonable

leisure. We are going to keep the record open for 7 legislative days

so we will submit additional questions.

But I do have one that is a technology question. The conventional

load shedding historically has been to go to large users and get

them to shut down, industrial users and so on. The technology obviously exists today to go in and turn off the air conditioners or

re—turn up the temperature, for example, on the air conditioners

of most homes in each of your areas; and yet that is virtually not

distributed at all.

I know, and from what we went through in the California crisis,

that at the exact time that we were having huge power outages,

had we been able to get every home to turn their temperature up

to 78 or 80 degrees—we are talking about homes in many cases

that had nobody in them but had been left at a comfortable 72 or

74, whatever the homeowner wanted. Had we been able to ramp

that up, we would have shaved far more than enough power to prevent virtually every blackout that occurred in California.

What are your ISOs and public utilities doing to roll out or to

encourage or to look at putting in the kind of advanced load shedding that would allow for those kinds of individual homes to participate in their own best interest?

Mr. BRANDIEN. In New England, we have a number of demandresponse programs, price-sensitive programs as well as 30-minute

response programs that we count on for operating reserve to respond exactly like you said.

We do have a number of people that have responded to that gap

RFP I talked about in Connecticut, where they actually do shut

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down or actually raise the temperature or cycle air conditioner

compressors. And I believe it is somewhere around 20 megawatts

in Connecticut that is in that 260, 270 megawatt gap RFP. I believe it is an untapped resource that is available out there to us.

Especially when you take a look—the summer peak demands are

really driven by air conditioning.

Mr. ISSA. Thank you.

Any of the other ISOs? Ms. Currie.

Mr. LYNCH. Well, I can just quickly—we administer the wholesale electric market. Therefore, we’re not really involved in the retail side that you are specifically talking about. But I will note that

the New York PFC is actively involved in looking at retail programs, especially on the demand side as well as the load-serving

entities in the large transmission centers. So there are programs

that I think people, as you indicate, recognize the benefit and the

capability of these programs to reduce and shape peaks. So there

is a lot of effort ongoing, but right now it is outside of our area of

influence.

Mr. ISSA. But you either get to calculate that if they implement

it or not if they don’t.

Mr. LYNCH. Yes, we would be very supportive and provide any

studies they would need to substantiate what they have done.

Mr. ISSA. Ms. Currie.

Ms. CURRIE. As a retail provider——

Mr. ISSA. We wondered why you were here. Now we know for

sure. It is this question.

Ms. CURRIE. The Southern California Public Power Authority has

engaged in an experimental project called the Ice Bear, and we’re

putting this technology into a number of our service territory installations. Basically, you buildup ice over night; and it can provide

the cooling for a facility during the daytime when the peaks are

higher. As I said, almost all of the SCPPA members now are putting these installations in commercial facilities; and we are going

to be exploring what we can do to roll it out on a residential basis.

Mr. ISSA. Excellent.

Mr. Brandien.

Mr. BRANDIEN. If I can add just one more thing, as we move forward in all the rules that we are implementing like with our forward capacity market, we’re developing those such that the demand response can play the same game as the generators, which

opens up a revenue stream for people to go out and sign up customers where they can cycle off their air conditioning compressors

and things. So we are trying to make the rules such that people

can take advantage of that.

Mr. MANSOUR. Mr. Chairman, first of all, the technology exists.

Advanced metering and signals to the customers in a lot of ways—

it does exist in a lot of ways. What is left is the education of the

consumers as to how to use the information, how to interpret the

information and how to use it.

All the utilities in California, including of course the municipals,

they have major programs on advanced metering and using those

kind of signals for the consumers to actually do their part for the

benefit of both the consumer and the system. The involvement of

the ISO would be there would be a signal at the ISO that we have

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an issue that would go to the utility, and the utility translates that

into the signals to the consumers according to the arrangement.

We are very interested in it because, as I said, really as much

as we would try to beef up the infrastructure of transmission, there

is a lot of room out there for conservation and demand response.

Mr. ISSA. Thank you, and thank you for closing with Governor

Schwarzenegger’s No. 1 statement when he meets with you.

With that, I would like to thank all of you for your attendance

and your patience through our votes. We will hold the record open,

according to my script here, for 2 weeks from this date for those

who may want to forward submissions and possible inclusions. I

would also ask unanimous consent that all Members be able to submit additional questions to our panel.

With that, we stand adjourned.

[Whereupon, at 4:35 p.m., the subcommittee was adjourned.]

[The prepared statement of Hon. Diane E. Watson and additional

information submitted for the hearing record follow:]

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