<DOC>
[109th Congress House Hearings]
[From the U.S. Government Printing Office via GPO Access]
[DOCID: f:34544.wais]
CAN THE U.S. ELECTRIC GRID TAKE ANOTHER HOT SUMMER?
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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
______
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COMMITTEE ON GOVERNMENT REFORM
TOM DAVIS, Virginia, Chairman
CHRISTOPHER SHAYS, Connecticut HENRY A. WAXMAN, California
DAN BURTON, Indiana TOM LANTOS, California
ILEANA ROS-LEHTINEN, Florida MAJOR R. OWENS, New York
JOHN M. McHUGH, New York EDOLPHUS TOWNS, New York
JOHN L. MICA, Florida PAUL E. KANJORSKI, Pennsylvania
GIL GUTKNECHT, Minnesota CAROLYN B. MALONEY, New York
MARK E. SOUDER, Indiana ELIJAH E. CUMMINGS, Maryland
STEVEN C. LaTOURETTE, Ohio DENNIS J. KUCINICH, Ohio
TODD RUSSELL PLATTS, Pennsylvania DANNY K. DAVIS, Illinois
CHRIS CANNON, Utah WM. LACY CLAY, Missouri
JOHN J. DUNCAN, Jr., Tennessee DIANE E. WATSON, California
CANDICE S. MILLER, Michigan STEPHEN F. LYNCH, Massachusetts
MICHAEL R. TURNER, Ohio CHRIS VAN HOLLEN, Maryland
DARRELL E. ISSA, California LINDA T. SANCHEZ, California
JON C. PORTER, Nevada C.A. DUTCH RUPPERSBERGER, Maryland
KENNY MARCHANT, Texas BRIAN HIGGINS, New York
LYNN A. WESTMORELAND, Georgia ELEANOR HOLMES NORTON, District of
PATRICK T. McHENRY, North Carolina Columbia
CHARLES W. DENT, Pennsylvania ------
VIRGINIA FOXX, North Carolina BERNARD SANDERS, Vermont
JEAN SCHMIDT, Ohio (Independent)
BRIAN P. BILBRAY, California
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 DIANE E. WATSON, California
ILEANA ROS-LEHTINEN, Florida BRIAN HIGGINS, New York
JOHN M. McHUGH, New York TOM LANTOS, California
PATRICK T. McHENRY, North Carolina DENNIS J. KUCINICH, Ohio
KENNY MARCHANT, Texas
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
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
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 well-being 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, supply 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.
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 concern 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 Island 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 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 in-depth
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, 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 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 self-regulating 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.
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.
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 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 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.
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--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.
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
inter-regional 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.
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 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 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 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
far-reaching 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.
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 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 bid-as-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 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 basically 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 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 addition to that, we've added another
1,000 megawatts of repowered 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 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 demand-
response 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 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 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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