[House Hearing, 109 Congress]
[From the U.S. Government Publishing Office]




 
          CAN THE U.S. ELECTRIC GRID TAKE ANOTHER HOT SUMMER?

=======================================================================

                                HEARING

                               before the

                  SUBCOMMITTEE ON ENERGY AND RESOURCES

                                 of the

                              COMMITTEE ON
                           GOVERNMENT REFORM

                        HOUSE OF REPRESENTATIVES

                       ONE HUNDRED NINTH CONGRESS

                             SECOND SESSION

                               __________

                             JULY 12, 2006

                               __________

                           Serial No. 109-229

                               __________

       Printed for the use of the Committee on Government Reform


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