[Senate Hearing 108-444]
[From the U.S. Government Printing Office]



                                                        S. Hrg. 108-444

                 BLACKOUT IN THE NORTHEAST AND MIDWEST

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

                                HEARING

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                      ONE HUNDRED EIGHTH CONGRESS

                             SECOND SESSION

           ON THE RELIBILITY OF THE NATION'S ELECTRICITY GRID

                               __________

                           FEBRUARY 24, 2004


                       Printed for the use of the
               Committee on Energy and Natural Resources


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               COMMITTEE ON ENERGY AND NATURAL RESOURCES

                 PETE V. DOMENICI, New Mexico, Chairman
DON NICKLES, Oklahoma                JEFF BINGAMAN, New Mexico
LARRY E. CRAIG, Idaho                DANIEL K. AKAKA, Hawaii
BEN NIGHTHORSE CAMPBELL, Colorado    BYRON L. DORGAN, North Dakota
CRAIG THOMAS, Wyoming                BOB GRAHAM, Florida
LAMAR ALEXANDER, Tennessee           RON WYDEN, Oregon
LISA MURKOWSKI, Alaska               TIM JOHNSON, South Dakota
JAMES M. TALENT, Missouri            MARY L. LANDRIEU, Louisiana
CONRAD BURNS, Montana                EVAN BAYH, Indiana
GORDON SMITH, Oregon                 DIANNE FEINSTEIN, California
JIM BUNNING, Kentucky                CHARLES E. SCHUMER, New York
JON KYL, Arizona                     MARIA CANTWELL, Washington

                       Alex Flint, Staff Director
                   Judith K. Pensabene, Chief Counsel
               Robert M. Simon, Democratic Staff Director
                Sam E. Fowler, Democratic Chief Counsel
                         Lisa Epifani, Counsel
           Leon Lowery, Democratic Professional Staff Member


                            C O N T E N T S

                              ----------                              

                               STATEMENTS

                                                                   Page

Bayh, Hon. Evan, U.S. Senator from Indiana.......................     2
Bingaman, Hon. Jeff, U.S. Senator from New Mexico................     5
Campbell, Hon. Ben Nighthorse, U.S. Senator from Colorado........     4
Cantwell, Hon. Maria, U.S. Senator from Washington...............     3
Craig, Hon. Larry E., U.S. Senator from Idaho....................     4
Domenici, Hon. Pete V., U.S. Senator from New Mexico.............     1
Gent, Michehl R., President and CEO, North American Electric 
  Reliability Council............................................     7
Glotfelty, James W., Director, Office of Electric Transmission 
  and Distribution, Department of Energy.........................    14
Harris, Phillip G., President and CEO, PJM Interconnection, 
  L.L.C..........................................................    21
Landrieu, Hon. Mary L., U.S. Senator from Louisiana..............     6
McCarren, Louise, CEO, Western Electricity Coordination Council..    17
Talent, Hon. James M., U.S. Senator from Missouri................    32
Thomas, Hon. Craig, U.S. Senator from Wyoming....................     5
Torgerson, James P., President and CEO, Midwest Independent 
  Transmission System Operator, Inc..............................    25

                                APPENDIX

Responses to additional questions................................    53

 
                 BLACKOUT IN THE NORTHEAST AND MIDWEST

                              ----------                              


                       TUESDAY, FEBRUARY 24, 2004

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                   Washington, D.C.

    The committee met, pursuant to notice, at 10 a.m., in room 
SD-366, Dirksen Senate Office Building, Hon. Pete V. Domenici, 
chairman, presiding.

          OPENING STATEMENT OF HON. PETE V. DOMENICI, 
                  U.S. SENATOR FROM NEW MEXICO

    The Chairman. The hearing will please come to order. I want 
to thank everyone, particularly the witnesses for giving us 
their time today and we assure you that it is not our intent to 
go on forever. We want the hearing to be concise, to the point, 
and as brief as possible, so we will tell you right now that we 
hope you can give your statements and then give a brief summary 
of them and we will take both into account as we move along. 
This is a hearing that pertains itself with the reliability of 
the grid. And the reliability for the nation's grid means the 
assurance that power is flowing safely over our electricity 
lines to consumers and businesses.
    The energy bill provides a section that establishes an 
electric reliability organization, and authorizes that 
organization to create mandatory standards for operating the 
bulk power system and authorizes punishment of those who fail 
to meet those standards.
    I thought maybe since we will just be using those words 
that I would make sure that everybody knows what we are talking 
about. Senator Bingaman, I have a brief opening statement, 
after which I will yield to you. Senator Thomas is the only 
Senator here and if he cares to open, we'll let him do that, 
after which time we'll proceed with all of you unless you have 
an emergency and then we will ask you questions after we are 
finished.
    So today our electric grid is operating voluntarily and the 
rules are voluntary rules and they are set by the American 
Electric Reliability Council. Sometimes known as NERC. And the 
August 14 blackout is our most recent reminder that voluntary 
reliability rules did not work. Perhaps it means that these 
rules are no longer sufficient to ensure the safe, reliable 
operation of our electric grid.
    In the drafting of the energy bill, which is still pending, 
we made that assumption based on the evidence we got, we took, 
that we obtained. The purpose of this hearing is to review the 
solutions NERC has recommended in its February 10, 2004 report 
on how to prevent and mitigate future blackouts.
    This discussion should help focus our attention on issues 
such as the fiscal constraints and requirements of coordinating 
the electricity system to the decision making process for 
developing and enforcing reliability rules. And third, the cost 
of reliability rules, who should bear them and the role of 
technology in improving reliability.
    There is currently a great deal of tension and uncertainty 
in the industry about how we will proceed in improving our 
reliability. Some are concerned that the Federal Energy 
Regulatory Commission, FERC, will try to mandate reliability 
rules despite a clear lack of authority in statutes of our land 
to do that. This could end up tying that industry up in 
wasteful and lengthy litigation.
    Some are concerned that NERC and industry will not act 
efficiently to solve the reliability problems. My answer is the 
best solution is for Congress to pass a comprehensive energy 
bill that indicates mandatory reliability rules. I think those 
mandatory rules are in the current comprehensive bill.
    That is the solution that I'm working to accomplish. There 
are differences of opinion, but the difference of opinion is by 
those who do not think we will pass a comprehensive energy 
bill. That's predominantly wherein the difference lies.
    I believe we have to do that. If we take this part all by 
itself, we have concluded that this is the most important part 
of the energy bill, and I think that's a pretty tough 
conclusion to draw. Some will make it. I think I can refute it 
just by looking at all the other things we ought to be doing.
    The solution that I'm working on is that we owe this 
country a comprehensive energy bill to ensure our domestic 
prosperity and our national security. Senator Bingaman, I 
believe that you agree with my last statement that we need--
that's what we need. I'm not sure that you agree with how we 
get there.
    Having said that, I welcome you to make your opening 
remarks and I have already indicated how we will proceed after 
that. Senator Bingaman.
    [The prepared statements of Senators Bayh, Cantwell, 
Campbell, and Craig follow:]

    Prepared Statement of Hon. Evan Bayh, U.S. Senator from Indiana

    Mr. Chairman, thank you for holding this hearing on the reliability 
of our electric grid. The August 14th blackout signaled that much more 
needs to be done to enhance the reliability of our transmission grid. 
However, I would like to caution my colleagues and others who are quick 
to jump on the reliability bandwagon as a way of hindering the further 
formation of Regional Transmission Organizations (RTOs). While the 
final blackout report from the U.S.-Canada Power System Outage Task 
Force has yet to be released, I read with interest the interim report 
which stated that ``reactive'' power produced by independent power 
operators was not the cause of the massive blackout, which stretched 
from the Great Lakes to the Atlantic Ocean. The Task Force points out 
that lack of coordination seems to be the larger culprit--coordination 
that will only be enhanced with seamless regional transmission 
organizations.
    RTOs were formed to help us move to a more competitive electricity 
market, but as the economy grew, they played an increasingly important 
role in providing coordination of electricity over existing 
transmission lines. RTOs will continue to play an important role in 
ensuring that proper coordination occurs between and among utilities 
and independent providers of electricity. In fact, last week, in my 
home state, the Midwest Independent System Operator (MISO) opened its 
doors to demonstrate upgrades made to the organization since the August 
blackout--upgrades that will help to deter future communication 
failures that certainly played a role in the spread of what otherwise 
may have been smaller blackout. However, if other states intervene to 
prevent American Electric Power (AEP) from integrating into that 
communication system through participation in PJM, its massive presence 
in the Midwest will impede the progress made by MISO to date, creating 
a gaping hole in the coordination in the Midwest.
    Furthermore, states should recognize that if RTOs evolve in a Swiss 
cheese fashion they cannot fulfill the requirement to increase 
reliability as the use of the electricity grid continues to grow. In 
fact, several state public utility commissions recently filed comments 
to FERC supporting FERC's decision to move AEP into the PJM RTO.
    The Indiana Utility Regulatory Commission noted that past rulings 
regarding AEP's existing makeup were dependent on its inclusion in 
these regional organizations. Indiana and the six other commissions 
that joined them in the filing pointed out the compelling economic and 
reliability issues in this matter are regional and multi-regional in 
scope and thus require regional and multi-regional solutions.
    The economic benefits of wholesale electricity markets are real. A 
2001 Department of Energy study of the nation's transmission grid 
confirms that wholesale electricity markets save consumers nearly $13 
billion per year. In testimony filed before FERC on the AEP case, 
Tabors Caramanis & Associates stated that in 2005, AEP integration into 
the PJM market would save consumers in MISO and PJM approximately $214 
million in that year alone.
    I urge my colleagues to recognize the benefits of RTOs, the role 
they play in cost savings and reliability improvements to consumers as 
well as the important role that FERC can play in ensuring that they are 
properly formed.

                                 ______
                                 
Prepared Statement of Hon. Maria Cantwell, U.S. Senator From Washington

    Thank you, Mr. Chairman, for holding this important hearing. I look 
forward to learning more today about this past August's Northeast/
Midwest blackout, which has again sounded the wake up call for federal 
electric reliability legislation.
    As everyone in this room is well aware, devising a comprehensive 
policy that will help this nation achieve its energy independence is a 
task that has divided this Committee, the U.S. Senate and the Congress 
as a whole for three years now. Regardless, I believe that there is one 
thing on which everyone in this room can agree--and that is the need to 
pass legislation giving the Federal Energy Regulatory Commission, 
working closely with regional entities, the statutory authority to put 
in place mandatory and enforceable reliability standards.
    The call for legislation of this kind dates back to at least 1997, 
when both a Task Force established by the Clinton Administration's 
Department of Energy and a North American Electric Reliability Council 
(or NERC) blue ribbon panel independently determined that reliability 
rules for our nation's electric system needed to be mandatory and 
enforceable.
    In response, the Senate passed stand-alone legislation on this 
matter, authored by my predecessor Sen. Gorton, in June 2000. Since 
then, under the leadership of both parties, the Senate has twice passed 
the very provisions included in my bill, the Electric Reliability Act 
of 2004, as part of comprehensive energy legislation--most recently, 
this past July.
    There is no doubt that this nation's consumers and businesses 
cannot afford further delay in improving the reliability of the 
electricity grid. However, I am of the firm belief that we cannot allow 
these crucial provisions to be held hostage to a flawed comprehensive 
energy bill.
    I see Mr. Gent here today, as one of our witnesses. Mr. Gent, I 
read with great interest your January 1 letter to the New York Times, 
in which you wrote that NERC's recent activity to improve the 
reliability of our nation's grid ``does not reduce the need for federal 
legislation that would provide authority to impose and enforce 
mandatory reliability standards. Whether legislation is adopted on a 
stand-alone basis or as part of a comprehensive energy bill, passage is 
essential. If reliability legislation had been enacted when first 
proposed [in 1999], I believe that the blackout would not have 
occurred.''
    Mr. Gent, I could not agree more. And while I know that the 
Chairman has worked to strip one of the most outrageous provisions of 
the H.R. 6 conference report--the MTBE liability protection, which many 
Senators simply cannot abide--from a new energy bill, I am one of the 
many who believe that the bill that remains requires very, very 
substantial revision and thorough debate. With its origins in last 
year's conference report, there are far too many provisions in the new 
bill that this Committee has simply never considered. Moreover, if one 
of our primary policy goals is to improve the reliability of our 
nation's electricity grid, I am hard-pressed to see how many of the 
provisions in that bill are relevant.

   How will weakening the Safe Drinking Water Act help keep the 
        lights on?
   Will providing MTBE producers with $2 billion in taxpayer-
        funded ``transition'' assistance in any way reduce the 
        likelihood of outages?
   How would delaying Clean Air Act implementation in our 
        nation's most polluted cities ensure reliable operation of our 
        electricity grid?
   Can anyone really argue that exempting oil companies from 
        Clean Water Act requirements will make our high-voltage 
        transmission lines more reliable?

    This new bill might not subsidize Hooters, but there remain plenty 
of handouts to the polluters and corporate looters--none of which have 
anything to do with bolstering the reliability of our transmission 
infrastructure. And that's before a non-existent conference with the 
House, the Leadership of which has publicly expressed its complete 
disinterest in revisiting the provisions of H.R. 6 most objectionable 
to the Senate.
    So I am pleased we are having this hearing today, but I have to say 
at the outset I reject the notion that passing comprehensive energy 
legislation--such as it is--is the sole path to improving the 
reliability of our nation's electricity grid. We can pass stand-alone 
reliability legislation. We've done it before. We can--and must--do it 
again. Good energy policy must not be held hostage to the bad, and I 
will look for every opportunity to move this legislation forward.
    Thank you, Mr. Chairman, and I look forward to the testimony of 
today's witnesses.

                                 ______
                                 
          Prepared Statement of Hon. Ben Nighthorse Campbell, 
                       U.S. Senator From Colorado

    Thank you, Mr. Chairman. I would like to thank you for holding this 
hearing and all of the witnesses here to testify. This hearing will 
delve into the problems stemming from last summer's blackout in the 
Northeast. It will be interesting to see how we are going to proceed to 
remedy the problems nation's electricity reliability, especially as we 
have experienced similar problems around the country in the last few 
years.
    While we have been fortunate in our state to escape the power 
outages that have plagued various regions of the country, we also know 
that we are not immune to such crisis. As you all know, many Western 
states are joined together in one huge power grid. We are 
interdependent to the point that the breakdown of a generator in one 
part of the grid will affect power in another part. As well, the entire 
Western grid's electric system is under severe stress. High prices and 
insufficient supplies of energy will no doubt burden many Western 
states for years to come. However, the long-term problem is the supply 
of electricity which is smaller than the demand in the region. Also, 
many states have not built new power generation facilities which would 
help alleviate the increasing demand for electricity, in years.
    The Western power grid is already overworked because of the energy 
needs created by booming economies and population growth.
    As we all know, with the soaring prices of electricity and the 
environmental concerns surrounding coal-fired generation plants, 
natural gas will play a key role in supplying our nation with 
sufficient power. But, my home state of Colorado, along with other 
Western states, has had problems with natural gas as well. In fact, in 
Colorado, we have seen our natural gas prices increase over triple in 
the last several months, resulting in skyrocketing residential utility 
bills.
    I am monitoring the blackout debate carefully so that the best 
interests of my home state are not compromised. I have some questions 
for the witnesses that I would like them to address so that we can 
examine this issue further during the time for questions.
    Thank you, Mr. Chairman.

                                 ______
                                 
   Prepared Statement of Hon. Larry E. Craig, U.S. Senator From Idaho

    Mr. Chairman, thank you for the opportunity to address the state of 
our nation's transmission grid in the wake of the August 14, 2003, 
Northeast-Midwest electricity blackout. The task of fully understanding 
what happened so that we can help ensure nothing like that happens 
again is of critical importance to this Committee.
    It is my hope that today's discussion will focus on the technical 
issues associated with the reliable operation of the electricity grid. 
I do not want the reliability issue to be hijacked by discussions of 
competing agendas on market design and other restructuring issues. Such 
discussions have proved to be, and likely will continue to be, wholly 
unproductive in reaching solutions to growing reliability problems. We 
must get the reliability problems solved.
    Personally, I think that reliability is a straightforward issue--is 
the country investing enough in the grid and how do we ensure that 
necessary investments are made? My concern is whether enough money is 
being spent on maintenance, state-of-the-art equipment, and training--
the nuts and bolts of running the most technologically advanced 
electricity system in the world.
    These questions should not take a back seat to questions of market 
design and other contentious restructuring issues. I believe that if 
you have the proper technology in place along with adequately trained 
personnel that you can operate reliably under either the Regional 
Transmission Organization model or the traditional vertically 
integrated utility model.
    I hope this hearing will stay focused on those issues and avoid 
distractions. Thank you, Mr. Chairman.

         STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR 
                        FROM NEW MEXICO

    Senator Bingaman. Thank you very much, Mr. Chairman, for 
holding the hearing. I think it's a very important hearing. As 
I see it, we are trying to determine two things at this 
hearing. First of all, what caused the blackout to the extent 
that that's known, and second, what actions can we take to 
prevent future blackouts. And obviously the adverse economic 
and personal consequences that resulted from in those 
blackouts.
    I believe it is very important to have a system of rules of 
enforcement to ensure reliability, and that's part of what is 
in the pending legislation and the legislation we earlier 
passed in the Senate.
    I also believe, however, that it's important that the 
organization of the system operators be appropriate. Let me 
just indicate that I'm very pleased that we have the heads of 
two of the ISOs here testifying today. It seems to me that we 
need to understand the ability of those organizations to 
operate and control a system in order to ensure that 
reliability is there. And that I think is part of the solution 
and I'd like to be sure that we hear from them as to that 
aspect of it.
    I think this is a very useful opportunity for us to go back 
and review some of these issues and be sure that whatever 
legislation we pass is constructive, and that whatever can be 
done short of legislation is being done. Thank you very much.
    The Chairman. Thank you very much, Senator. Senator Thomas, 
would you like to make a few remarks and then Senator Landrieu, 
would you like to make a few remarks? Or do you want to go on 
to questioning. All right. Senator.

         STATEMENT OF HON. CRAIG THOMAS, U.S. SENATOR 
                          FROM WYOMING

    Senator Thomas. Just very brief. I remember your brevity 
warning, so that will be good. I thank you for having this, 
this hearing. It was just 5 years ago when I introduced a bill 
that had many of these provisions in it, as a matter of fact, 
and some were in our energy thing.
    Certainly, it talked about having mandatory regulations. It 
talked about the formation of regional RTOs so that we would 
have a way to operate on a regional basis. It also pertained to 
all utilities, which I think has been one of our problems. 
Bonneville Power controls about 75 percent of the transmission 
in one of the particular areas and is uncovered.
    So if we are going to do some things, we probably have to, 
we have to take a long look at that. I'm very much a supporter 
of RTOs. It lets us have some uniqueness in areas but yet 
brings it together with the national grid and I think that's 
very important.
    I guess the thing we really all need to understand is that 
our system is clearly changing and congestion is increasing 
dramatically. We are doing more and more in generation. If we 
want to have the best kind of generation, we have to get out 
into the market. And so I think, I think we are faced with the 
real issue here and we need to move forward to do it, so thank 
you for being here and I appreciate having this hearing.
    The Chairman. Thank you very much. Yes.

       STATEMENT OF HON. MARY L. LANDRIEU, U.S. SENATOR 
                         FROM LOUISIANA

    Senator Landrieu. Just a very brief statement. I thank the 
panelists for participating this morning and the chairman for 
calling this very important timely meeting. But representing 
Louisiana and the Louisiana region in terms of electricity and 
power, we have long enjoyed fairly low market rates for our 
power, robust capacity to generate that power, and have not 
experienced any of the shortages or blackouts associated with 
some of the other regions.
    I have read with interest the summary, and am looking 
forward to working with the chairman on some solutions, but 
recognizing that whatever our region is doing, it's doing it 
pretty well and whatever we move to needs to be fair to those 
regions like ours that produces and generates a lot of energy 
and is a net exporter of energy and electricity. Thank you.
    The Chairman. Thank you very much, Senator. We are going to 
proceed with the witnesses, but I want to go out of line and 
speak for a moment with you, Mr. Glotfelty. What is your title 
in the Department of Energy?
    Mr. Glotfelty. I am currently the Director of the Office of 
Electric Transmission and Distribution.
    The Chairman. I understand that you're currently failing to 
carry out directions included in fiscal year budget of Energy 
and Water regarding the funding of your office. From what I 
understand, you object to some of the specific direction given 
to you in that law. And are instead proposing to reduce funding 
for such items as superconductivity--I should say 
superconductivity research--to make up for what you perceive as 
shortfalls in other areas.
    Now, I want you to know that that will destroy the program 
with a great chance of providing a real huge increase in the 
capacity of transmission lines. We can't ignore that potential 
for solving transmission bottlenecks and replacing existing 
lines, with lines that could carry 100 times the current 
amounts of electricity.
    So I say to you that--let me simply warn you not to shrug 
off the Congress. If you do, I assume that your budget problems 
have just begun. There are a lot of deserving programs at the 
Department of Energy, and I must tell you, you may think so, 
but we think we could use the money that you currently use and 
that fund you, we think we could use it elsewhere in the 
serious demand, especially for basic science and research.
    Now, I am through with that observation. I do not need any 
comment unless you want to make it.
    Mr. Glotfelty. I would like to if I have a moment.
    The Chairman. Please do.
    Mr. Glotfelty. Senator, Mr. Chairman, first I want to say I 
very much appreciate your impassioned support for 
superconductivity. I likewise am a tremendous believer in that 
technology that it is one of the Holy Grails of electricity to 
transmit it without impedance.
    I will work with you and your staff and the budget folks 
within the Department of Energy to try and achieve our common 
goals. I am a believer in superconductivity and its goals on 
the grid, and I just look forward to working with you in your 
role as chairman of this committee, as well as the Energy and 
Water Appropriations Committee to make sure that we can move 
this technology to deployment on the grid, and do not leave it 
as a stagnant technology that the Government works on. So I 
look forward to working with you and your staff in this area.
    The Chairman. I thank you very much. I do not know you at 
all, so it's very strange that you know what I am passionate 
about, what I am not passionate about. You merely said I was 
passionate about this program. You do not know me very well, 
because I'm passionate about a lot of programs in the energy 
bill and a lot of them in the appropriations of Energy and 
Water, so I do not approach this from any passion.
    I approach it that we worked on something for 20 years, 
started in Ronald Reagan's time with a few centers, one of 
which was there. And we went from a little half inch to being 
able to build cables. Now, it would seem to me that nobody 
would want to close an office that has made that much strides, 
and I do not choose to ask every electric executive in the 
country. I just choose to tell you what I have told you. I 
thank you for your remarks and we will now proceed.
    The next witness, the witness will be Michehl Gent. That's 
the president and CEO of the North American Electric 
Reliability Council. It's NERC. And they set voluntary 
standards, they set voluntary standards for the grid and is 
comprised of 10 reliability councils across the United States, 
Canada and a portion of Mexico. Would you please proceed?

       STATEMENT OF MICHEHL R. GENT, PRESIDENT AND CEO, 
          NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL

    Mr. Gent. Yes. Good morning, Mr. Chairman and members of 
the committee.
    Thank you for this opportunity to describe the actions 
taken by our NERC board of trustees on February 10 to ensure 
that a blackout like the one that occurred last August 14 does 
not happen again. I will skip over much of the background 
material that I have presented in my written testimony, and 
hope that you have time to go through that and go directly to 
the resolutions of our board.
    When implemented, these initiatives will move NERC many 
steps closer to being the electric reliability organization 
envisioned by the legislation that you spoke of earlier. The 
board recognizes that we must do everything we can to regain 
the public's trust and to provide reassurance that the 
reliability of the bulk electric system is of paramount 
importance to the electric utility industry.
    Here's what we have to fix. Our investigation found that 
several entities violated NERC operating policies and planning 
standards. We found that the existing process for monitoring 
compliance with reliability standards is inadequate. We found 
that operating entities have adopted different interpretations 
of their functions and responsibilities. We found that problems 
identified in previous blackouts have gone unfixed and 
repeated.
    We found that data being used in models is inaccurate. We 
found that planning studies are not consistently shared and are 
not the subject of adequate peer review. We found that system 
protection technologies are not consistently applied. We found 
that communications between system operators is not always 
effective. The key finding that is of greatest concern to me is 
that the existing NERC reliability standards were violated and 
that this contributed directly to the blackout. I'm also very 
concerned that the problems identified in previous blackouts 
were repeated. We must do better than this.
    The actions that the board has taken fall into three 
categories. Near term actions, where we have asked the parties 
that were directly involved in the blackout to remedy specific 
deficiencies by the summer.
    The second category is what we are calling strategic 
initiatives. These are programs to strengthen compliance with 
existing reliability standards and to track the implementation 
of those recommendations to ensure that they are in fact 
implemented.
    And finally, we have technical initiatives which will 
probably take a very long time. They deal with evaluating 
designs, models, practices and training to prevent future 
cascading blackouts. At full copy, in fact, all 25 pages of the 
board's actions are an attachment to my written testimony.
    These actions are both short and long term, and they are 
both very specific and in some cases general. I'd like to 
specifically mention one of the initiatives that I believe will 
be the most effective of all the initiatives. And that is what 
we are calling the control area and reliability coordinator 
readiness audits.
    A control area is an electrical area bounded with 
electronics that includes generation and demand that's kept in 
balance at all times. A controller is also asked to balance the 
frequency of the network so they contribute to keeping it at 60 
Hertz.
    A reliability coordinator is a step above that. They are 
charged with in many cases several control areas. They have a 
wide area of view of the interconnection and their only job is 
to make sure that reliability is maintained.
    More on the audits. We have currently a program to audit 
new control areas to determine that these candidate control 
areas are ready and suitable to become certified as NERC 
control areas. Existing control areas were grandfathered. No 
more.
    Beginning March 1, we will audit all control areas and 
reliability coordinators. We have expanded the audit criteria 
to include evaluation of reliability plans, procedures, 
processes, tools, personnel qualifications and training with 
immediate attention given to the issues that we uncovered in 
the blackout investigation.
    We have started with the largest control areas first so 
that we will have audited control areas covering over 80 
percent of all the customers in the United States and Canada by 
summer. These readiness audits will not stop there. They will 
be repeated on a cycle of every 3 years.
    The set of recommendations that the NERC board has adopted 
I believe you'll find is aggressive. Right now we are able to 
accomplish much because we have the strong support of all the 
chief executives from all parts of the industry, as well as the 
attention of all the participants. Everyone is now focused on 
reliability but we are still very close to the events of August 
14.
    With the passage of time we are worried that priorities 
will shift, people will move on, other issues will compete for 
our attention and your attention. Having the reliability 
legislation in place will make sure that we can maintain the 
proper focus on reliability on an ongoing sustainable basis.
    Thank you, and I look forward to your questions.
    [The prepared statement of Mr. Gent follows:]

       Prepared Statement of Michehl R. Gent, President and CEO, 
              North American Electric Reliability Council

    Good morning, Mr. Chairman and members of the Committee. My name is 
Michehl Gent and I am President and Chief Executive Officer of the 
North American Electric Reliability Council (NERC). The August 14 
blackout that affected eight states and two Canadian provinces was a 
seminal event for the entire electric industry. Thank you for this 
opportunity to describe recent actions by NERC's independent Board of 
Trustees to ensure such an event does not recur.
    Before doing so, however, I must say that Congress can take one 
very important step to ensure we do not have a repeat of August 14. 
That step is to pass reliability legislation to make reliability rules 
mandatory and enforceable for all owners, operators, and users of the 
bulk power system. Legislation to accomplish that is included in H.R. 
6, the comprehensive energy bill that has already passed the House. 
Senator Domenici included that same language in S. 2095, the slimmed-
down version of a comprehensive energy bill. That language enjoys 
widespread support from all parts of the industry, as well as customers 
and regulators. I believe that if the reliability legislation had been 
passed two years ago, we would not have had the August 14 blackout.
    NERC is a not-for-profit organization formed after the Northeast 
blackout in 1965 to promote the reliability of the bulk electric 
systems that serve North America. NERC's mission is to ensure that the 
bulk electric system in North America is reliable, adequate, and 
secure. NERC works with all segments of the electric industry as well 
as electricity consumers and regulators to set and encourage compliance 
with rules for the planning and operation of reliable electric systems. 
NERC comprises ten regional reliability councils that account for 
virtually all the electricity supplied in the United States, Canada, 
and a portion of Baja California Norte, Mexico.
    NERC has been an integral part of the joint fact-finding 
investigation into the August 14 blackout conducted by the U.S.-Canada 
Power System Outage Task Force. NERC fully supports the task force's 
findings and conclusions, which were laid out in the November 19 
interim report. With respect to what happened on August 14, the key 
findings and conclusions are detailed on page 23 of that report, as 
follows: ``inadequate situational awareness at FirstEnergy 
Corporation,'' ``FirstEnergy failed to manage adequately tree growth in 
its transmission rights-of-way,'' and ``failure of the interconnected 
grid's reliability organizations to provide effective diagnostic 
support.''
    Immediately after the onset of the blackout on August 14, 2003, 
NERC assembled a team of the best technical experts in North America to 
investigate exactly what happened and why. Every human and data 
resource we have requested of the industry was provided, and experts 
covering every aspect of the problem were volunteered from across the 
United States and Canada. In the week following the blackout, NERC and 
representatives of DOE and the Federal Energy Regulatory Commission 
(``FERC'') established a joint fact-finding investigation. All members 
of the team, regardless of their affiliation, have worked side by side 
to help correlate and understand the massive amounts of data that we 
have received. We have had hundreds of volunteers from organizations 
all across North America involved in the investigation. NERC continues 
to provide technical support to the bi-national task force that is 
developing its final report.
    To lead the NERC effort, we established a strong steering group of 
the industry's best, executive-level experts from systems not directly 
involved in the cascading grid failure. The steering group scope and 
members are described in Attachment A.*
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    * All attachments have been retained in committee files.
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    NERC acted to guard against a recurrence of the August 14 outage 
even while our investigation was continuing. Based on preliminary 
information from the investigation, NERC issued a request on October 
15, 2003, to all reliability coordinators and control areas in North 
America. That request begins:

          The reliability of the North American bulk electric systems, 
        including the avoidance of future cascading outages, is of 
        paramount importance to NERC and its stakeholders. Pending the 
        outcome of the final report on the outage, NERC emphasizes to 
        all entities responsible for the reliable operation of bulk 
        electric systems the importance of assuring those systems are 
        operated within their design criteria and within conditions 
        known to be reliable through analytic study. If the power 
        system enters an unanalyzed state, system operators must have 
        the authority and the capability to take emergency actions to 
        return the power system to a safe condition.

    NERC requested that each reliability coordinator and control area 
in North America review a list of reliability practices that the 
investigation associated with the blackout to ensure their 
organizations are within NERC and regional reliability council 
standards and established good utility practices. NERC further 
requested that within 60 days, each entity report in writing to their 
respective regional reliability council, with a copy to NERC, that such 
a review has been completed and the status of any necessary corrective 
actions. That list included things such as voltage and reactive 
management, reliability communications, failures of system monitoring 
and control functions, emergency action plans, training for 
emergencies, and vegetation management. (The October 15 letter is 
attachment B to this testimony.)
    NERC received responses from 166 of the 168 reliability 
coordinators and control areas. Almost all entities considered 
themselves to be in compliance with NERC reliability rules. A number of 
entities identified areas where they could make improvements and 
described the measures they were taking.
    NERC's Board of Trustees has now reviewed the findings of the 
August 14 blackout investigation. Based upon that review, the board 
ordered NERC to implement a set of recommendations prepared by the 
steering group that directed NERC's blackout investigation. The board 
recognizes that we must do everything within our power to regain the 
public's trust and provide reassurance that preserving the reliability 
of the bulk electric system is of paramount importance to NERC and to 
the electric industry as a whole.
    NERC's investigation concludes that:

   Several entities violated NERC operating policies and 
        planning standards, and those violations contributed directly 
        to the start of the cascading blackout.
   The existing process for monitoring and ensuring compliance 
        with NERC and regional reliability standards was inadequate to 
        identify and resolve specific compliance violations before 
        those violations led to a cascading blackout.
   Reliability coordinators and control areas have adopted 
        differing interpretations of the functions, responsibilities, 
        authorities, and capabilities needed to operate a reliable 
        power system.
   Problems identified in studies of prior large-scale 
        blackouts were repeated, including deficiencies in vegetation 
        management, operator training, and tools to help operators 
        properly visualize system conditions.
   In some regions, data used to model loads and generators 
        were inaccurate due to a lack of verification with actual 
        system data and field-testing.
   Planning studies, design assumptions, and facilities ratings 
        were not consistently shared and were not subject to adequate 
        peer review.
   Available system protection technologies were not 
        consistently applied to optimize the ability to slow or stop an 
        uncontrolled cascading failure of the power system.
   Communications between system operators were not effective 
        and hampered their ability to recognize the developing system 
        emergency.

    A key finding of NERC's investigation, and of greatest concern to 
me, was that existing NERC reliability standards were violated, and 
that this contributed directly to the blackout. I am also very 
concerned that problems identified in studies of prior large-scale 
blackouts were repeated. We must do better than this.
    Despite the absence of the reliability legislation we have been 
seeking, the board has determined that NERC must use all available 
means to obtain full compliance with its reliability standards. We have 
also committed to ensure that there is greater visibility given to 
those who violate NERC reliability standards. Specifically, the board 
resolved to:

   Receive detailed information on all violations of NERC 
        reliability standards;
   Act to improve compliance with NERC reliability standards;
   Provide greater transparency to violations of reliability 
        standards, while respecting the confidential nature of some 
        information and the need for due process; and
   Work closely with the Federal Energy Regulatory Commission 
        and other applicable federal, state, and provincial regulatory 
        authorities in North America to ensure that the public interest 
        is met with respect to compliance with our reliability 
        standards.

    To address the deficiencies found in the investigation, NERC's 
recommendations fall into three categories: near-term actions parties 
must take to remedy specific deficiencies before this summer; strategic 
initiatives to strengthen compliance with existing reliability 
standards and to track the implementation of recommendations from this 
and other outage investigations; and technical initiatives to prevent 
or mitigate the impact of future cascading blackouts. (A full copy of 
the board's actions is Attachment C.)
Near-term Actions
    1. Correct the Direct Causes of the August 14, 2003, Blackout.

   The companies implicated in the blackout are directed to 
        complete specified remedial actions and certify that these 
        actions have been completed.
   NERC will assign experts to help these companies develop 
        plans that adequately address the issues identified in this 
        report, and for any other remedial actions for which they 
        require technical assistance.
Strategic Initiatives
    2. Strengthen NERC's Compliance Enforcement Program.

   Each Region will report all violations of NERC operating 
        policies, planning standards, and regional standards, whether 
        verified or pending investigation.
   If presented with evidence of a significant violation, the 
        offending organization must correct the violation within a 
        specified time. If an organization is determined to be non-
        responsive and presents a reliability risk, NERC will request 
        assistance of the appropriate regulatory authorities.
   NERC will review and update all compliance templates 
        applicable to current NERC reliability standards.
   NERC and ECAR will evaluate violations of NERC and regional 
        standards and develop recommendations to improve compliance 
        with reliability standards.

    3. Initiate Control Area and Reliability Coordinator Reliability 
Readiness Audits.

   NERC and the Regions will establish a program to audit all 
        reliability coordinators and control areas, with immediate 
        attention given to addressing the deficiencies identified in 
        the blackout investigation. These audits shall be completed 
        within three years, with the 20 highest priority audits to be 
        completed by June 30, 2004.
   NERC will establish a set of baseline audit criteria that 
        will include evaluation of reliability plans, procedures, 
        processes, tools, personnel qualifications, and training.
   The Regions, with input from NERC, will audit each control 
        area's and reliability coordinator's readiness to meet these 
        audit criteria.

    4. Evaluate Vegetation Management Procedures and Results.

   NERC and the Regions will initiate a program to report all 
        transmission line trips resulting from vegetation contact.
   Each transmission operator will submit an annual report of 
        all vegetation-related high voltage line trips to its Region.
   Each transmission owner shall make its vegetation management 
        procedures and documentation of work completed available for 
        review and verification.

    5. Establish a Program to Track Implementation of Recommendations.

   NERC and the Regions will establish a program to document 
        the completion of recommendations resulting from the August 14 
        blackout investigation and investigations of other historical 
        outages, reports of violations of reliability standards, 
        results of compliance audits, and lessons learned from system 
        disturbances.
   NERC will establish a program to evaluate and report on bulk 
        electric system reliability performance.
Technical Initiatives
    6. Improve Operator and Reliability Coordinator Training.

   All reliability coordinators, control areas, and 
        transmission operators shall provide at least five days per 
        year of training and drills in system emergencies for each 
        staff person with responsibility for the real-time operation or 
        reliability monitoring of the bulk electric system.

    7. Evaluate Reactive Power and Voltage Control Practices.

   NERC will reevaluate the effectiveness of the existing 
        reactive power and voltage control standards and how they are 
        being implemented in practice, and develop recommendations to 
        ensure voltage control and stability issues are adequately 
        addressed.
   ECAR will review its reactive power and voltage criteria and 
        procedures and verify that its criteria and procedures are 
        being fully implemented in regional and member studies and 
        operations.

    8. Improve System Protection to Slow or Limit the Spread of Future 
Cascading Outages.

   All transmission owners will evaluate the zone 3 relay 
        settings on all transmission lines operating at 230 kV and 
        above for the purpose of verifying that each zone 3 relay is 
        not set to trip on load under extreme emergency conditions. 
        NERC will review any proposed exceptions to ensure they do not 
        increase the risk of widening a cascading failure of the power 
        system.
   Each Region will evaluate the feasibility and benefits of 
        installing under-voltage load shedding capability in load 
        centers that could become unstable as a result of being 
        deficient in reactive power following multiple-contingency 
        events. The Regions are to promote the installation of under-
        voltage load shedding capabilities within critical areas that 
        would help to prevent an uncontrolled cascade of the power 
        system.
   Evaluate ``Planning Standard III--System Protection and 
        Control'' and propose revisions to adequately address the issue 
        of slowing or limiting the propagation of a cascading failure. 
        Evaluate the lessons from August 14 regarding relay protection 
        design and application and offer additional recommendations for 
        improvement.

    9. Clarify Reliability Coordinator and Control Area Functions, 
Responsibilities, Capabilities and Authorities.

   More clearly define the characteristics and capabilities 
        necessary to enable prompt recognition and effective response 
        to system emergencies.
   Ensure the accurate and timely sharing of outage data 
        necessary to support real-time operating tools such as state 
        estimators, real-time contingency analysis, and other system 
        monitoring tools.
   Establish the consistent application of effective 
        communications protocols, particularly during emergencies.
   The operating policies must be clarified to remove 
        ambiguities concerning the responsibilities and actions 
        appropriate to reliability coordinators and control areas.

    10. Establish Guidelines for Real-Time Operating Tools.

   Evaluate the real-time operating tools necessary for 
        reliable operation and reliability coordination, including 
        backup capabilities and report both minimum acceptable 
        capabilities for critical reliability functions and a guide of 
        best practices.

    11. Evaluate Lessons Learned During System Restoration.

   Evaluate the blackstart and system restoration performance 
        following the outage of August 14 and develop recommendations 
        for improvement.
   All Regions will reevaluate their procedures and plans to 
        assure an effective blackstart and restoration capability 
        within their Region.

    12. Install Additional Time-Synchronized Recording Devices as 
Needed.

   Define regional criteria for the application of synchronized 
        recording devices in power plants and substations and 
        facilitate the installation of the devices to allow accurate 
        recording of system disturbances and to facilitate benchmarking 
        of simulation studies.
   Facility owners will upgrade existing dynamic recorders to 
        include GPS time synchronization and, as necessary, install 
        additional dynamic recorders.

    13. Reevaluate System Design, Planning and Operating Criteria.

   Evaluate operations planning and operating criteria and 
        recommend revisions.
   ECAR will reevaluate its planning and study procedures and 
        practices to ensure they are in compliance with NERC standards, 
        ECAR Document No. 1, and other relevant criteria; and that ECAR 
        and its members' studies are being implemented as required.
   Reevaluate the criteria, methods and practices used for 
        system design, planning and analysis. This review shall include 
        an evaluation of transmission facility ratings methods and 
        practices, and the sharing of consistent ratings information.

    14. Improve System Modeling Data and Data Exchange Practices.

   Establish and implement criteria and procedures for 
        validating data used in power flow models and dynamic 
        simulations by benchmarking model data with actual system 
        performance. Validated modeling data shall be exchanged on an 
        interregional basis to support reliable system planning and 
        operation.

    NERC's investigation will continue for some time. Although we 
believe that we understand what happened and why for most aspects of 
the outage, we are continuing to conduct detailed analysis in several 
areas, notably dynamic simulations of the transient or high speed 
phases of the cascade, and a final verification of the full scope of 
all violations of NERC and regional reliability standards that led to 
the outage.
    To complete the technical investigation of what happened, regional 
modeling teams working with NERC have constructed electrical models to 
simulate the exact conditions of August 14 and are in the process of 
subjecting those models to the events that occurred during the time 
preceding the outage to understand better its causes. These simulations 
will examine the electrical stability of the grid--that is, how 
strongly the generators were synchronized to one another--and whether 
there was a voltage collapse of the transmission system. We will also 
focus on why operating procedures that should have detected problems 
that developed on the grid and kept them from spreading did not prevent 
the cascading outage across such a wide area. We expect to issue a 
detailed technical report on these issues later in the year.
    I will conclude my testimony where I began, with an urgent request 
that Congress enact the reliability legislation this year. The set of 
recommendations the NERC board has adopted is an aggressive one. Right 
now we are able to accomplish much, because we have the strong support 
of the chief executives from all parts of the industry, as well as the 
attention of all participants. Everyone is now focused on reliability. 
But we are still very close to the events of August 14. With the 
passage of time, priorities will shift; people will move on; other 
issues will compete for attention. Having the reliability legislation 
in place will make sure that we can maintain the proper focus on 
reliability on an ongoing, sustainable basis.
    NERC is fully committed to working with all sectors of the 
electricity industry, with the Federal Energy Regulatory Commission and 
other regulatory agencies, and with customers to ensure the reliability 
of the bulk electric system in North America. Our principal focus in 
the next several months will be to implement the recommendations the 
NERC board has now adopted. But the most important step for assuring 
the long-term reliability of the bulk electric system remains passage 
of legislation to make the rules mandatory and enforceable for all 
system owners, operators and users.
    Thank you.

    The Chairman. Thank you very much.
    Mr. Glotfelty, same rules, 5 minutes.

 STATEMENT OF JAMES W. GLOTFELTY, DIRECTOR, OFFICE OF ELECTRIC 
      TRANSMISSION AND DISTRIBUTION, DEPARTMENT OF ENERGY

    Mr. Glotfelty. Yes, sir. Mr. Chairman, Senator Bingaman and 
other Senators and members of the committee, I appreciate the 
opportunity to participate in this hearing today.
    As you know, the Power System Outage Task Force released 
its interim report in November 2003. The task force found that 
the August 14 blackout was caused by specific practice 
failures, rule violations, equipment and software failures and 
human decision, human decisions that are strikingly similar to 
other large blackouts that have impacted the United States.
    After each of these major blackouts, since 1965, an expert 
team of investigators have probed the causes of the blackout, 
written detailed technical reports, and issued a list of 
recommendations to prevent or minimize the scope of future 
blackouts. The task force, our task force found the 
recommendations from prior reports have not been sufficiently 
implemented, sustained or enforced. And this is a dire 
consequence that we move forward with this.
    Despite the problems with our reliability institutions and 
practices that we have found as a result of the latest 
blackout, there are a number of specific actions that we 
believe will make our system more reliable. These are actions 
that have been taken already.
    NERC's letter to control areas and reliability coordinators 
in October 2003, directing short, near-term actions that must 
be taken to ensure reliability.
    FERC's December 2003 order directing First Energy to 
implement a series of remedial actions. Initiatives undertaken 
by the Midwest ISO to ensure that their equipment is--their 
monitoring equipment is doing what is intended, as well as 
their joint operating agreement with PJM.
    Finally, a heightened state of awareness among all of our 
transmission system operators could perhaps provide the most 
reliable action for the summer. Nobody wants to be the cause of 
the next blackout.
    There are reliability issues that may still need to be 
addressed. These include the need to make compliance with the 
reliability standards mandatory. Obviously, the Congress has 
legislation pending before it and we urge them to pass this 
legislation, comprehensive legislation that includes mandatory 
reliability.
    Additional issues. We need to establish a funding mechanism 
for NERC or a successor organization that is independent of the 
entities that they oversee. You need to clarify the prudent 
expenditures and investments to improve reliability in the 
transmission system are recoverable through transmission 
rights. The need to develop accountability metrics for NERC or 
a successor and its board. And finally, the need to ensure that 
the highest levels of corporate governance support and sign off 
on reliability plans and audits.
    Many of these issues will be addressed in further detail 
when the task force issues its final report in March. What Mr. 
Gent went through were submitted to the task force as part of 
their public and open process. They were submitted to us 
through the United States and Canadian websites, they were 
posted on our websites when they were received so that 
everybody who wanted to have a role in our process was able to 
see the recommendations that were submitted by NERC, and 
everybody else.
    Many members of our task force have already expressed 
support for these recommendations that NERC has undertaken. 
Nevertheless, the task force may conclude that certain elements 
in NERC's package should be expanded or strengthened. And if 
so, it will suggest appropriate changes in our final report 
which we expect to be released in March.
    In closing, Mr. Chairman, I want to emphasize that although 
there is a wide range of actions that need to be taken to 
ensure reliability, there is one action that is absolutely 
essential. Congress must enact comprehensive energy legislation 
with mandatory reliability provisions. That's a critical 
component.
    I'd be happy to take questions. Thank you.
    [The prepared statement of Mr. Glotfelty follows:]

Prepared Statement of James W. Glotfelty, Director, Office of Electric 
          Transmission and Distribution, Department of Energy

    Good morning, Mr. Chairman, Senator Bingaman, and other members of 
the Committee. My name is Jimmy Glotfelty. I am Director of the Office 
of Electric Transmission and Distribution (OETD), and currently serve 
as the U.S. Director of the Power System Outage Task Force. I 
appreciate the opportunity to participate in this hearing and to 
express the Department of Energy's (DOE) views on several matters 
related to the reliability of the bulk electric systems in North 
America.
    Let me begin by noting that the Interim report of the Task Force 
released in November, 2003, found that the blackout on August 14, 2003 
had several direct causes and contributing factors, including:

   Inadequate vegetation management
   Failure to ensure operation within secure limits
   Failure to identify emergency conditions and communicate 
        that status to neighboring systems
   Inadequate operator training
   Inadequate regional-scale visibility over the bulk power 
        system.

    Although the initiation of the August 14, 2003, blackout was caused 
by the identified deficiencies in specific practices, equipment, and 
human decisions that coincided that afternoon, the Task Force also 
noted that many of the causes are strikingly similar to causes of 
earlier blackouts in the U.S.
    The Task Force's Interim Report also noted that after each major 
blackout in North America since 1965, an expert team of investigators 
had probed the causes of the blackout, has written a detailed technical 
report, and issued a list of recommendations to prevent or minimize the 
scope of future blackouts. The report clearly found that 
recommendations from prior reports have not been sufficiently 
implemented, sustained, or enforced.
    Despite the problems in our reliability institutions and practices 
that have been identified to date in the Task Force's investigation of 
the August 14 blackout--with invaluable support and cooperation from 
NERC and other industry experts across the U.S. and Canada--I believe 
that our electric system is being operated more conservatively today 
than it was on, say, August 13, and this could mean greater 
reliability. This is due to a combination of actions and factors, 
including:

   The letter from NERC's Board of Trustees on October 10, 
        2003, directing the heads of all control area and reliability 
        coordinator organizations to take a series of near-term actions 
        to protect reliability.
   The Federal Energy Regulatory Commission's (FERC) order of 
        December 24, 2003 to FirstEnergy, directing the company to 
        implement a series of remedial actions by June 30, 2004.
   Initiatives undertaken by the Midwest Independent System 
        Operator (MISO) to address the deficiencies in its tools and 
        procedures identified in the Task Force's Interim Report as 
        well as their new joint operating agreement with PJM.
   A general heightening of awareness since August 14, 
        particularly due to the issuance of the Interim Report, of the 
        importance of reliability. One of the challenges we face now, 
        and which the Task Force will address in its recommendations, 
        is how to sustain that awareness for the long term.

    In addition, the Department of Energy strongly supports the more 
recent action by NERC's Board on February 10 when it issued fourteen 
very clear and forceful directives to NERC's regional councils, 
committees, and members concerning near-term and long-term actions to 
be taken to correct problems identified in the course of the Task 
Force's investigation. I am pleased to add that FERC, Regional 
Transmission Organization and Independent System Operator presidents, 
and appropriate authorities in Canada have also indicated their strong 
support for these actions.
    Important though NERC's directives are, it is also important to 
note that they cover only part of the spectrum of issues relevant to 
maintaining reliability for the long term. That is, they cover the 
things that NERC is able to do now, on its own, given its current legal 
status as a voluntary organization funded by its members. There is 
another set of reliability concerns that have been raised that would 
need to be addressed by government actors, including the Congress, 
federal agencies such as FERC, DOE, state legislatures and regulatory 
agencies, and appropriate authorities in Canada. These include:

   The need to make compliance with reliability standards 
        mandatory and enforceable by enacting comprehensive energy 
        legislation.
   The need to establish a mechanism for funding NERC or a 
        future reliability organization and the regional reliability 
        councils that is independent of the entities they oversee.
   The need to clarify that prudent expenditures and 
        investments to maintain or improve reliability will be 
        recoverable through transmission rates.
   The need to require all entities operating as part of the 
        bulk power system to be members of the regional reliability 
        council (or councils) for the regions in which they operate.
   The need to develop accountability metrics for NERC and its 
        Board. And finally,
   The need to ensure that the highest levels of corporate 
        governance support and sign off on reliability plans and 
        audits.

    Many of these issues will be addressed in further detail when the 
Task Force issues its Final Report in March.
    Mr. Chairman, as you know, the Task Force sponsored a series of 
public meetings at several U.S. and Canadian sites to hear the 
suggestions of the public, industry, and a wide variety of other 
organizations concerning what should be done to prevent future 
blackouts and minimize the scope of any that nonetheless occur.
    Interested parties have also submitted a large body of written 
comments and material to the Task Force, all of which is publicly 
available at U.S. and Canadian websites (www.electricity.doe.gov).
    NERC's initiatives of February 10 were submitted to us and made 
publicly available in both draft and final form as part of this 
process. The Task Force will draw on these inputs and the findings of 
its investigation in preparing its recommendations for its Final 
Report. Members of the Task Force, such as FERC Chairman Pat Wood, have 
already expressed strong support for NERC's actions of February 10. 
Nevertheless, the Task Force may conclude that certain elements in 
NERC's package should be expanded, and if so it will suggest 
appropriate changes.
    In closing, Mr. Chairman, I want to emphasize that although there 
is a wide range of actions that many parties need to take to maintain 
reliability, there is one action that is absolutely essential. The 
Congress must enact comprehensive energy legislation with mandatory 
reliability provisions as a critical component. If that were done, many 
of the other needed actions could be accomplished readily in the course 
of implementing the legislation. Without the solid legal foundation 
legislation would provide, our institutional infrastructure for 
maintaining reliability will continue to have significant weaknesses.
    Thank you very much. I will be happy to answer your questions.

    The Chairman. Thank you. Thank you very much. Louise 
McCarren, CEO of the Western Energy Coordinating Council, WECC, 
covers the Western Interconnect, Interconnection, all States 
west of the Rockies from Montana to New Mexico, is that 
correct?
    Ms. McCarren. Yes. Thank you.
    The Chairman. Five minutes and we put your statement in the 
record.

              STATEMENT OF LOUISE McCARREN, CEO, 
            WESTERN ELECTRICITY COORDINATING COUNCIL

    Ms. McCarren. Thank you, sir. Thank you Chairman and 
Senators. I appreciate very much the opportunity to speak to 
you.
    I have four points I'd like to make. The first is that the 
WECC and all of its members wholeheartedly support the 
reliability legislation. And the three key components for us 
are the delegation of authority, the deference clause and the 
regional advisory bodies, all of which we support. The key 
underpinning, of course, is the need for mandatory reliability 
criteria, and the ability to enforce such criteria.
    Second point I want to make is we support NERC's 
recommendations as outlined by Mr. Gent and are working 
actively with NERC, particularly on supplying help for the 
readiness audits.
    The third and major point I want to make this morning is 
that as a result of two very serious outages in the Western 
Interconnect in 1996, the WECC and its members implemented a 
voluntary reliability management system which is a contractual 
relationship--relation among the transmission owners and 
generators. And it has in it adherence to a number of criteria 
which are contained in an appendix to my testimony, and a 
series of penalties, including potential financial penalties 
for noncompliance to those criteria.
    This has been an evolving process in the West, and it works 
well. It certainly can be improved, but we have it in place. 
And the key point is right now there is a contractual voluntary 
relationship.
    And finally, my last point, we believe strongly that the 
NERC and the Regional Reliability Council should be the primary 
organization to establish and implement reliability standards 
with a strong FERC back stop for compliance. Thank you very 
much.
    [The prepared statement of Ms. McCarren follows:]

    Prepared Statement of Louise McCarren, CEO, Western Electricity 
                          Coordinating Council

    Chairman Domenici, Senator Bingaman and Members of the Committee. 
Thank you very much for this opportunity to testify before you today on 
the very important issues of transmission grid reliability, the role of 
reliability standards and ensuring compliance with reliability 
standards. I welcome the opportunity to explain how reliability is 
addressed in the West, and to offer some perspectives on what Congress 
needs to do to enhance grid reliability on a national basis.
    The Western Electricity Coordinating Council, or WECC, is the 
largest and most diverse of the ten regional electric reliability 
council members of the North American Electric Reliability Council, 
covering the entire Western Interconnection (see Attachment 1).* WECC 
is a voluntary organization whose mission is to promote a reliable 
electric power system in the Western Interconnection, support efficient 
competitive power markets, assure open and non-discriminatory 
transmission access among members, provide a forum for resolving 
transmission access disputes, and provide an environment for 
coordinating the operating and planning activities of its members as 
set forth in the WECC Bylaws.\1\
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    * Attachments 1 and 2 have been retained in committee files.
    \1\ The WECC was formed on April 18, 2002, by the merger of the 
Western Systems Coordinating Council (``WSCC''), the Southwest Regional 
Transmission Association, and the Western Regional Transmission 
Association. The WSCC was formed with the signing of the WSCC Agreement 
on August 14, 1967 by 40 electric power systems. Those ``charter 
members'' represented the electric power systems engaged in bulk power 
generation and/or transmission serving all or part of the 14 western 
states and British Columbia, Canada.
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    The WECC region encompasses a vast area of nearly 1.8 million 
square miles, extending from Canada to Mexico. It includes the Canadian 
Provinces of Alberta and British Columbia, the northern portion of Baja 
California, Mexico, and all or portions of the 14 western states in 
between. Due to the vastness and diverse characteristics of the region, 
WECC's members face unique challenges in coordinating the day-to-day 
interconnected system operation and the long-range planning needed to 
provide reliable and affordable electric service to more than 71 
million people in WECC's service territory.
    Today, over 35 years after the founding of our predecessor, the 
Western Systems Coordinating Council or WSCC, the WECC continues to be 
responsible for coordinating and promoting electric system reliability 
throughout the Western Interconnection, as well as providing the forum 
for its members to enhance communication, coordination, and 
cooperation--all vital ingredients in planning and operating a reliable 
interconnected electric system. A central focus of this effort in 
recent years has been the development and implementation of the 
Reliability Management System, a contract-based system to protect the 
reliability of the Western grid.

                  WECC'S RELIABILITY MANAGEMENT SYSTEM

    As the electric industry moved toward competitive markets, and 
following two widespread outages in 1996 in the Western 
Interconnection, the WSCC recognized the need to place a greater 
emphasis on operating the transmission system in accordance with 
established reliability criteria. Recognizing that it might take a 
number of years to pass federal reliability legislation, the WSCC Board 
of Trustees established a policy group and three task forces to 
develop, through an open process, the Reliability Management System 
(RMS).
    Under the RMS, 23 WECC member control areas \2\ and seven other 
transmission operators \3\ have agreed, through contracts with the 
WECC, to comply with WECC reliability criteria. These organizations are 
defined as Participating Transmission Operators in the RMS Agreements. 
The contractual obligations to comply with WECC RMS Reliability 
Criteria also extend to 16 contracts entered into between Participating 
Transmission Operators and interconnected generators. In addition, two 
control areas have incorporated the RMS Agreements into their electric 
rate tariffs, thereby obligating another 117 generator owners to comply 
with RMS Reliability Criteria.
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    \2\ Control area as used here means an electric system or systems, 
bounded by interconnection metering and telemetry, capable of 
controlling generation to maintain its interchange schedule with other 
control areas and contributing to frequency regulation of the Western 
Interconnection.
    \3\ Other transmission operators here are organizations that own 
and operate major transmission facilities in the Western 
Interconnection that are not control areas.
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    Under the RMS, non-complying entities are subject to sanctions 
(ranging from letters indicating noncompliance to monetary sanctions). 
Initial determinations of noncompliance are made by the WECC staff. All 
determinations by the WECC staff can be appealed by the sanctioned 
party to a ``Reliability Compliance Committee'' with representation of 
multiple market participants. Challenges to sanction determinations by 
the Reliability Compliance Committee can be made through alternative 
dispute resolution procedures.
    Contracts between the WECC and all Participating Transmission 
Operators not subject to Federal Energy Regulatory Commission (FERC or 
Commission) jurisdiction, such as public power systems, are based on 
the same contract used by FERC-jurisdictional Participants, with 
necessary modifications to the provisions regarding filings with the 
Commission. To ensure that the requirements of the RMS remain uniform 
throughout the Western Interconnection, the transmission operators not 
subject to FERC jurisdiction have agreed to amend their contracts to 
reflect all changes to the contracts required by the FERC for 
transmission operators subject to FERC jurisdiction. In addition, the 
contracts with Canadian entities are subject to review by provincial 
authorities in Canada.
    In establishing the RMS, the RMS policy group and task forces 
reviewed all NERC and WECC (WSCC) reliability criteria and identified 
specific criteria that are critical for reliability management, and for 
which compliance could be measured. The addition of criteria to the RMS 
contracts in a phased approach has, in each phase, been preceded by an 
evaluation period during which data were collected, but no sanctions 
were enforced. The evaluation period permitted WECC members to provide 
comments, recommend refinements, and determine if the criteria were 
suitable for a mandatory compliance program. From the evaluation 
process, criteria were incorporated in three phases into the RMS 
Reliability Criteria. The RMS criteria are listed in Attachment 2.
    WECC is carefully reviewing the findings of the August 14, 2003, 
blackout to learn from the experience and improve our operation even 
though the outage did not occur in our area. We are treating the 
findings as if the outage did occur in the Western Interconnection. The 
RMS Reliability Criteria can be refined if the review recommends any 
revisions.
    During the RMS development process, the confidential treatment of 
RMS compliance data by the WECC staff emerged as a critical issue. 
Section 5.2(a) of the RMS Criteria Agreement requires that ``the WECC 
Staff (1) shall treat as confidential all data and information 
submitted to the WECC Staff by a Participant under this Reliability 
Agreement, (2) shall not, without the providing Participant's prior 
written consent, disclose to any third party confidential data or 
information provided by a Participant under this Reliability Agreement, 
and (3) shall make good faith efforts to protect each Participant's 
confidential data and information from inadvertent disclosure.'' 
However, Section II of Annex A to the RMS Criteria Agreement requires 
that notices of noncompliance be sent to: (1) corporate officers of 
Participants determined to be in noncompliance: (2) state or provincial 
regulatory agencies with jurisdiction over such Participants; and, (3) 
in the case of U.S. entities, FERC and the Department of Energy, if the 
government entities request this information.
    On April 14, 1999, the FERC granted the WSCC's request for a 
declaratory order asserting jurisdiction over the RMS. Western Systems 
Coordinating Council, 87 FERC para. 61,060 (1999).\4\ The Commission 
explained that:

    \4\ In addition, the Department of Justice has provided a Business 
Review Letter regarding the RMS covering antitrust concerns.
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          The RMS . . . requires participants to adhere to reliability 
        criteria and contains sanctions for failure to comply with 
        those criteria. As such, we agree at this time with WSCC that 
        the RMS significantly `affects or pertains to' rates and 
        charges by public utilities subject to this Commission's 
        regulation. Accordingly, on these specific facts, our `rule of 
        reason' will allow us to accept for filing the RMS and RMS 
        contracts with Commission-jurisdictional public utilities.

    As such, all of the RMS agreements with FERC-jurisdictional 
entities, and all amendments thereto, have been filed with, and 
accepted by, the Commission under Section 205 of the Federal Power Act.
    As explained above, the RMS is being implemented in a phased 
approach, with new criteria added only after a period of evaluation 
during which the effectiveness and enforceability of the criteria are 
assessed by the WECC and its members. The third phase was accepted by 
the FERC by letter order issued December 17, 2003, in Docket No. ER04-
27-000 and went into effect on January 1, 2004. This process ensures 
that the criteria included in the RMS set clear, objective standards 
and that compliance with such criteria is readily measurable.
    Twenty-three of thirty-three WECC control areas are voluntary RMS 
Participants, accounting for approximately 88 percent of the load and 
81 percent of the generation in the WECC region. The WECC staff 
continues to work with control areas and others who are not RMS 
Participants to encourage their participation.\5\
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    \5\ Ten WECC control areas are not RMS signatories. They are Avista 
Corp., Comision Federal de Electricidad, Portland General Electric 
Company, PUD No. 1 of Chelan County, PUD No. 1 of Douglas County, PUD 
No. 2 of Grant County, Puget Sound Energy, Seattle City Light, 
Sacramento Municipal Utility District, and Tacoma Power.
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    The WECC strongly supports the passage of federal legislation 
authorizing mandatory reliability standards, such as Section 1211 of S. 
2095. As discussed in greater detail below, this legislation authorizes 
delegation from the national Electric Reliability Organization to 
regional entities, such as the WECC, for the purpose of proposing and 
enforcing reliability standards. Indeed, in the case of a regional 
entity organized on an Interconnection-wide basis, like the WECC, the 
legislation presumes that such delegation is appropriate. These 
delegation and deference provisions are important to protect the 
success of the RMS program, and prevent any disruption of it. While the 
WECC RMS program takes careful account of current NERC standards, and 
is often based on them, the RMS program has been carefully tailored to 
address the specific needs and concerns of system users in the Western 
Interconnection. Moreover, development of the RMS took several years, 
and the RMS has undergone significant refinement in the years since it 
first went into effect.
    With respect to compliance with reliability standards, WECC 
believes the accountability through RMS data reporting has been a 
constant reinforcement to member organizations to comply with operating 
reliability requirements. Though financial sanctions are not the only 
means of enforcement, they have worked quite well for the Western 
Interconnection.
    The RMS also has a significant advantage in that it includes two 
Canadian Provinces and a Northern Mexican State that are not subject to 
FERC jurisdiction (in addition to numerous non-jurisdictional US 
entities). This provides great value to the Western Interconnection for 
reliability that is very important in the absence of the passage of 
legislation, and with respect to the Canadian Provinces, important even 
with the passage of legislation.
    The WECC supports mandatory reliability standards and reasonable 
enforcement of such standards. However, it is essential that any such 
standards be designed and developed to maximize system reliability. 
That process has been one of the WECC's core missions, through the RMS, 
during the past few years. The RMS criteria, specifically tailored for 
the unique characteristics of the Western Interconnection, are 
carefully designed to enhance and maintain the reliability of the 
entire Western region.

                    NEED FOR RELIABILITY LEGISLATION

    As mentioned above, the WECC fully supports passage of the proposed 
reliability legislation. The WECC and its predecessor, WSCC, have 
participated over the past several years in the development of this 
legislation to ensure that it properly reflects the reliability 
challenges and accomplishments of the West. The following provisions of 
the legislation are particularly important to the WECC:

          1. Delegated authority to a regional entity under Section 
        215(e)(4). This section requires the Commission to issue 
        regulations authorizing the Electric Reliability Organization 
        (``ERO'') to enter into an agreement to delegate to a 
        conforming regional entity authority for proposing and 
        enforcing reliability standards. This language would enable 
        delegation to a regional entity with an established reliability 
        system such as the WECC.
          2. ``Deference clause'' in Section 215(d)(3). Under this 
        provision, the ERO must presume, subject to rebuttal, that a 
        proposal from a regional entity that is organized on an 
        Interconnection-wide basis encompassing its entire 
        Interconnection is just, reasonable, and not unduly 
        discriminatory or preferential and in the public interest.
          3. The creation of Regional Advisory Bodies under Section 
        215(j). This provision will ensure an appropriate role for 
        states in the reliability assurance process.

    The WECC strongly supports the pending legislation and believes 
that it strikes the appropriate balance between the development of 
mandatory and enforceable reliability requirements throughout the 
nation and the need for regional flexibility and deference. That 
deference is appropriate where a solution that makes sense in one 
Interconnection, and does not adversely affect systems in a neighboring 
Interconnection is, for some reason, not appropriate as a uniform 
continent-wide standard.
    Though the goal of common continent-wide standards is laudable, the 
Western Interconnection is distinct from the Eastern Interconnection 
and Texas. As such, the pending legislation correctly recognizes that 
the Western Interconnection must have an important role in the 
development of reliability standards for the West.

                               CONCLUSION

    Thank you, Mr. Chairman, and Senators for the opportunity to 
present to you the WECC's perspectives on the important subject of 
ensuring the reliability of our transmission system. I hope that this 
perspective has been useful to you, and I welcome your questions.

    The Chairman. Thank you very much, ma'am. Mr. Phil Harris, 
President and CEO of PJM Interconnection. And PJM covers 
Pennsylvania, New Jersey and Maryland, is that correct?
    Mr. Harris. No, Mr. Chairman. It's Pennsylvania, New 
Jersey, Maryland, Delaware, Washington, D.C., Virginia, and we 
are merging into the States of Ohio, Kentucky, West Virginia, 
Indiana, and Illinois.
    The Chairman. I apologize.
    Mr. Harris. Indeed, Mr. Chairman, with the expansion of 
PJM, it's interesting that PJM will be larger than the entire 
Western Interconnection combined.
    The Chairman. Proceed.

    STATEMENT OF PHILLIP G. HARRIS, PRESIDENT AND CEO, PJM 
                    INTERCONNECTION, L.L.C.

    Mr. Harris. All right. It is a pleasure to be here, Mr. 
Chairman, particularly thinking back to my New Mexico roots. I 
operated a power system for a long time in New Mexico, I also 
operated a power system for nearly a decade in Louisiana.
    In the course of these events, I have worked for utilities 
and cooperatives. So in the past 10 years I have been the 
president and CEO of PJM in the Northeast. So I think I have a 
fairly well understanding of the electrical dynamic across this 
nation.
    I think the biggest problem we have right now and I 
appreciate the chairman and the Congress for jumping on this is 
the fact that there is a lack of confidence. We need to get the 
confidence back in our industry. We need to get the trust back.
    If you look at the electric industry as we sit today and as 
it's evolved over the past 100 years, we have 4,000 different 
entities involved with the generation, transmission and 
distribution of power. And this is regulated and governed by 50 
different States.
    You heard Mr. Gent comment earlier, there is over 155 
control areas all trying to control this single synchronous 
motor that is running. And that's all electricity is, it's 
really a single motor. Some of those entities are regulated by 
the Federal Energy Regulatory Commission, some aren't regulated 
at all. Some report to the President of the United States. 
There are many different structures involved, and we found that 
that particular gaggle of construct is not sufficient to meet 
the needs of the 21st century.
    I'm very pleased, Mr. Chairman, when you brought the issues 
of technology, superconductors and what technology has done. We 
have been operating competitive power markets for the past 6 
years and technology has been the key to be able to operate 
these things in a very, very large size and to do it 
successfully.
    We have added over 11,000 megawatts in new generation. We 
currently have over 3,600 megawatts in generation under 
construction to service areas. We have 10,000 megawatts that 
are also in the planning queue to be built and constructed. We 
have had over $700 million of transmission in this area with 65 
percent of it participant funded. So where do we stand and 
where do we think----
    The Chairman. What kind of funding?
    Mr. Harris. Participant funding, where the generator is 
paid for.
    The Chairman. All those growth numbers you are using, are 
those in any way related to acquiring areas, or are they all 
natural growth?
    Mr. Harris. It's growth from the competitive markets and 
the structure we have to enable wholesale competitive markets 
to deliver increased reliability for the customer.
    I think there are three essential elements that need to 
take place in the legislation, and they are all combined and I 
think they are all in there.
    First of all, we do need mandatory national standards. But 
these standards need to be developed and approved and see due 
process because of the different kinds of entities. Some areas 
of the country have markets, some do not. You need a healthy, 
derived process to determine what the standards should be and 
shouldn't be.
    Second of all, just as NERC itself is auditing the control 
areas, the NERC organization needs to be auditable. No 
organization can be beyond public oversight. It's absolutely 
crucial that FERC have the authority to provide public 
oversight of this institution, do the auditing and the controls 
necessary and also to allow appellate processes to develop.
    With the country split, there is about 60 percent of each 
interconnection now is covered by RTOs, about 50 percent 
nationally. Some areas have moved to wholesale markets, some 
haven't, so there is going to be some disconnects and disputes, 
and only FERC can resolve the issues between commercial 
products and reliability standards because they are 
intertwined.
    And thirdly, there needs to be FERC oversight over 
wholesale transmission for all entities, and I believe all of 
that is in the legislation. With these three elements, I think 
we can move forward to a much more healthy and robust industry 
and I certainly encourage the passage of those.
    One final comment I would like to bring back and again the 
rule of technology in improving reliability. What large RTOs do 
is it takes these 4,000 entities, and were able to bring them 
together in ways to optimize the real time balance. We have 
demand side programs now that have tremendous value because we 
have been able to optimize that and use that technology in 
dispatch.
    We are using artificial intelligence. We are using 
neurologic networks and some of these technologies to handle 
tens of thousands of buses. We are actually looking at 3,000 
different contingencies every 30 seconds to make sure the 
system will always be stable and reliable.
    You can get the economies of scale, you can get the 
reliability, you can get the efficiencies, you can increase the 
capacity, you can have the planning and it will work and be a 
healthy industry as we move the Nation forward. Thank you, Mr. 
Chairman.
    [The prepared statement of Mr. Harris follows:]

      Prepared Statement of Phillip G. Harris, President and CEO, 
                      PJM Interconnection, L.L.C.

    Mr. Chairman and Members of the Committee:
    I am Phillip Harris, President & CEO of PJM Interconnection, L.L.C. 
PJM is the Regional Transmission Organization dedicated to the 
enhancement of reliability and the operation of competitive wholesale 
electricity markets in a seven-state region spanning from Ohio to 
Delaware and from Virginia to New Jersey. In fact, the electricity 
serving this very building here in the District of Columbia flows 
reliably and at a reasonable price, in part, as a result of the 
competitive market structure operated by PJM.
    The events of August 14, 2003 represent as much a crisis in 
confidence in this industry as it does a failure of the electric power 
grid. As one who has worked in this industry my whole life operating 
power plants, as well as transmission and distribution systems, my 
message is simple: we must redouble our efforts to restore the public's 
confidence. To do so, we need to remain focused like a laser on the end 
goal and identify, with specificity, what is working and what needs 
repair in this fast moving environment. We can only do this by avoiding 
sound bites when specifics are needed or painting with a broad brush 
when a felt tip pen is needed. I will try to provide some of those 
needed specifics today.
    The ``bottom line'' is that there is no silver bullet, be it 
legislation or trimming trees that represents ``the'' single answer. 
Rather, we are in the middle of a long and difficult transition. We are 
dealing with a speed of light product that does not respect state or 
even international borders. Yet, this industry was built, financed and 
operated for over 80 years as a gaggle of over 4000 different entities 
providing varying aspects of the service of generation and delivery of 
electricity.
    We need to develop comprehensive solutions to meet the public's 
21st century demand for this product. The events of August 14 show what 
happens when we try to harness this speed of light product using a 
``mix and match'' of 20th century balkanized command and control 
solutions to meet 21st century needs.
    Although my testimony will address the August 14 event, I want to 
lead with what I think is the far more pressing issue: How do we 
address the critical crossroads we find ourselves in today? How does 
Congress and the Federal Energy Regulatory Commission, as our nation's 
policymakers, move this industry forward through clear and coherent 
policies and institutions? How do we avoid the pitfalls of unclear or 
internally contradictory policies slowing industry growth and 
discouraging investment? I am here to outline the specific answers that 
I believe are needed given where we are and where we need to be.

Answer #1--Instituting Transparent and Independent Regional Planning
    Much of the mid-Atlantic region's ability in real time to withstand 
the disturbance of August 14 was the result, not of human intervention, 
but of hardware working as it should hardware that was designed to 
protect each of our systems from outside faults, voltage drops and 
other system disturbances that threaten system reliability. Although 
the hardware generally worked as it should, the hardware didn't just 
come into being magically. Rather, the hardware was planned and sited 
as a result of a transparent planning process undertaken by PJM with 
the involvement of all stakeholders, from state commissions to 
landowners to large utility companies. I underscore the word 
``transparency''. In the past, each utility planned its system 
essentially as an island. Each utility designed and operated its 
systems to meet that particular system's needs. Although 
interconnections were acknowledged, the concept that one can find a 
better alternative by taking an action on an adjoining system was the 
exception rather than the norm. An independent entity, with a ``big 
picture'' look at the entire grid, can, through such a transparent 
process, ensure that the appropriate hardware is in place and that 
reliability is maintained proactively and at prudent cost to the 
consumer.
    Let me be more specific. The fully and provisionally approved ISOs 
and RTOs in the eastern interconnection along with the Tennessee Valley 
Authority, are currently committed to developing an overall transparent 
regional plan. The development of that extensive a comprehensive plan, 
which, in this case will cover nearly 60% of the Eastern 
Interconnection and over 100 million Americans, is unprecedented for 
this industry. As a result of transparency, independence and sheer 
size, these entities are able to come together to develop a regional 
plan that will address comprehensively the needs of this very large 
portion of America's interconnected grid. Only independent entities 
such as RTO's can undertake these solutions in a manner which will not 
be seen by the marketplace as favoring one provider over another or 
sacrificing one entity's ``native load'' at the expense of another's 
``native load.''

Answer #2--Ensuring Appropriate Reliability Jurisdiction With 
        Regulatory Oversight
    We agree with the proponents of the energy legislation that one 
must ensure that all market participants are subject to the same set of 
reliability rules. This includes those entities that are not, today, 
subject to FERC jurisdiction. The Senate Energy bill would do that and 
PJM had always been and remains a proponent of this vital part of the 
legislative reliability proposal. Notably, in areas of the country 
covered by RTOs, this is not as significant an issue--for example, in 
PJM our existing tariff already reaches non-jurisdictional entities to 
ensure compliance with NERC and regional council reliability standards.
    Today, nearly 50% of peak load and installed generation, covering 
all or parts of 29 states, is managed by fully approved or 
provisionally approved RTOs and ISOs. So at least in RTO areas, there 
exist structural solutions that address the need for reliability 
authority over all entities not just traditional-FERC regulated 
companies. That being said, a legislative solution would enshrine such 
a rule throughout the nation.
    On a larger plain, we need to get the role of the regulator right. 
It is critical that FERC, already the regulator of the wholesale market 
and the overseer of wholesale prices, also has a strong oversight role 
in the adoption and enforcement of reliability standards. FERC's 
oversight over reliability must not be a passive one--simply rubber 
stamping proposals that come before it. Rather, reliability and market 
issues are so inextricably intertwined that the regulator must have the 
tools and authority to fully and swiftly address the intertwined 
relationship of markets and reliability. This can best be accomplished 
through strong regulatory oversight over both sides of the coin--the 
market and reliability.

Answer #3--Need for Regional Coordination
    Some have suggested that RTOs were one of the causes of the 
problems of August 14. I would suggest just the opposite. Fully-
functioning RTOs are the present and future solution that solve the 
balkanized network problems which arose on August 14. In the PJM 
region, our regional oversight has lead to a marked improvement in 
reliability. For example, since inception of our markets, we have seen 
a dramatic increase in the efficiency of generating plants. Since 1998, 
the forced outage rate (defined as the number and duration of episodes 
of generating units not operating as planned) has declined more than 
20%.
    In its February 10, 2004 report on the August 14 outage, NERC 
requests one specific action of PJM: namely, reevaluation and 
improvement of communication protocols between neighboring reliability 
coordinators and neighboring control areas. It is worth noting that we 
were actually working on improving these protocols even before the 
August 14 outage occurred let alone before the NERC report. As of 
August 14, 2003, we had reached agreement with the MISO and had 
submitted for stakeholder review a proposed Joint Operating Agreement 
that addressed these communication protocols and more as they affected 
our two systems. We have subsequently further enhanced this protocol in 
response to the recommendations of the DOE/Canadian task force and in 
our discussions with NERC.
    This operating protocol moves reliability in the Midwest to the 
next level by providing for disciplined and detailed coordination 
between our two systems in a manner that is unprecedented today between 
neighboring control areas. The Joint Operating Agreement between MISO 
and PJM not only ensures real time data communication and modeling of 
each other's systems, but in addition details specific protocols as to 
what each system is to do proactively to address system conditions on 
the neighboring system. Among other things, the two RTOs will honor 
each other's key flowgates. PJM will operate its system to respect and 
relieve congestion on the Midwest ISO system with a similar level of 
support from the Midwest ISO back to PJM once the MISO's markets are 
functional. This agreement remains a flexible document designed to 
address additional recommendations coming out of NERC or the DOE/
Canadian reports. We believe that this agreement represents a new level 
of regional coordination that can be utilized as a model throughout the 
nation. I want to thank the MISO and its staff for their excellent 
working relationship with us and look forward to prompt NERC and FERC 
approval of this important protocol. A brief description of the Joint 
Operating agreement is attached.*
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    * All attachments have been retained in committee files.
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    Despite not having the agreement actually in place, on August 14 
PJM proactively went beyond a control area operator's existing 
obligations in order to communicate both with First Energy and the MISO 
to let them know of system disturbances we were seeing on the First 
Energy system. In short, we went beyond the existing NERC standards by 
alerting neighboring systems of problems. Although better communication 
is always appropriate (and a critical component of the MISO/PJM Joint 
Operating Agreement), let us not use this to mask the underlying 
problem. At the root cause, the First Energy system did not follow 
established reliability procedures to proactively address deteriorating 
system conditions such as occurred on August 14 and did not have the 
necessary situational awareness of what was happening on their system 
that day. Had the Midwest ISO have in place the tools that it is now 
working with us to put in place, the root causes of the August 14 
outage might have been avoided. I am attaching to this testimony the 
ISO/RTO Council's as well as PJM's response to NERC's outage report 
which details our concerns. I am also attaching an article from two 
academicians outlining how the PJM market rules, had they been in 
effect in the Midwest on August 14, would address congestion on the 
transmission system

Answer #4--Support FERC's Efforts to Place AEP Into PJM
    I discussed above the need for large regional transmission 
organizations with the functional control and oversight over very large 
areas so they can ``see the big picture'' and utilize tools to spot and 
correct reliability issues before they become problems. MISO, with its 
control of 122,000 MW of generation, and PJM, with its control of 
76,000 MW of generation, can perform those critical tasks and end the 
balkanized system we have in the Midwest currently. That being said, we 
have an immediate problem on our hands, one which can only be solved by 
prompt and comprehensive regulatory action. Specifically, the American 
Electric Power system, representing over 42,000 MW of generation 
remains outside of any Regional Transmission Organization. Although PJM 
serves as the reliability coordinator for AEP and took steps on August 
14, working with AEP, to protect its customers and the surrounding 
region, without the market-based operational control that PJM brings, 
the Midwest is faced with a giant ``hole in the donut'' when it comes 
to the voluntary coordination of utilities in the region.
    AEP's voluntary decision to join PJM is forestalled by certain 
regulatory action and inaction within certain states. We face an 
unfortunate but perhaps inevitable problem where the states of 
Illinois, Indiana, Michigan, Pennsylvania, New Jersey and the District 
of Columbia have all weighed in urging FERC to integrate AEP into PJM 
as rapidly as possible. By contrast, the states of Virginia and 
Kentucky today are holding up such integration. Absent a timely 
resolution of this matter by FERC, the Midwest remains exposed. 
Although today we have a well-run reliable AEP system that PJM is 
overseeing as AEP's Reliability Coordinator, there are dollars and 
benefits that are delayed while this state vs. state gridlock 
continues. We note that FERC Chairman Wood indicated in a recent letter 
to Georgia Governor Sonny Perdue that this matter involves ``a dispute 
among states involving transmission and wholesale power in interstate 
commerce'' and that over $61 to $80 million in annual net benefits for 
retail service providers in AEP's territory and approximately $932 
million in benefits for retail service providers in PJM, AEP and 
Dominion are at stake.
    This Congress has given the power to the FERC to resolve such 
impediments when they interfere with the voluntary coordination by 
utilities such as AEP seeking to join PJM. We urge this Congress to 
allow the regulatory process to move forward, to recognize that this is 
a unique fact-specific case where one state's actions are interfering 
with another state's action and allow FERC to work through this 
process. Although some have used sound bites to characterize this 
matter, this is not an issue of federal preemption of the states but, 
as FERC Chairman Wood indicated to Governor Perdue, a dispute that the 
FERC ``seeks to oversee in a way that brings about the best result for 
customers.'' Resolving divisions among states on matters of interstate 
commerce is nothing new. The need for a federal authority to resolve 
such disputes was one of the bedrock principles that caused our 
founding fathers to abandon the loosely knit Articles of Confederation 
and adopt the interstate commerce provisions of the U.S. Constitution.

                              ------------

    I began this discussion by noting that we need to reaffirm all that 
has worked well and focus, like a laser, on those aspects of our 
industry that need improvement. As I indicated above, through regional 
planning, strong regulatory oversight over reliability, enhancement of 
fully functioning regional transmission organizations and regulatory 
action to solve the lack of AEP in an RTO, we can begin to build the 
structural base that will begin to restore consumer confidence in this 
vital industry. Mr. Chairman and Committee members, we at PJM stand 
ready to work with you and all stakeholders to ensure that our electric 
system meets the 21st century needs of this great country.

    The Chairman. Thank you very much. James P. Torgerson, 
president and CEO of the Midwest Independent Transmission 
System. MISO covers 15 central States and one Canadian 
province, is that correct?
    Mr. Torgerson. That is correct, sir.
    The Chairman. Please proceed.

  STATEMENT OF JAMES P. TORGERSON, PRESIDENT AND CEO, MIDWEST 
         INDEPENDENT TRANSMISSION SYSTEM OPERATOR, INC.

    Mr. Torgerson. Good morning, Mr. Chairman and members of 
the committee. Thank you for the opportunity to appear before 
this committee to address recommendations made by NERC as a 
result of its investigation of the August 14 blackout.
    At the outset, I would like to say that the Midwest ISO has 
fully cooperated with the various investigations into the 
events of the August 14. We have found that working with the 
investigators of the international task force and NERC has been 
a valuable experience.
    Meeting the recommendations allows us to confidently 
operate a grid that has been thoroughly reviewed for compliance 
with best reliability practices. Mr. Chairman, I'm pleased to 
inform the committee that the Midwest ISO will meet or exceed 
the NERC recommendations that is the subject of today's 
hearings.
    The Midwest ISO was formed in 1998. It is the first entity 
found by FERC to be an RTO. The Midwest ISO region covers 
portions of 15 States and the Canadian province of Manitoba. Of 
relevance to your inquiry here, we act as reliability 
coordinator for two sets of companies, one who are members, and 
a second set in the mid-continent area power pool region that 
have not transferred control of their transmission systems to 
the Midwest ISO.
    As reliability coordinator, the Midwest ISO monitors, 
plans, conducts analyses regarding the high voltage grid and 
communicates with the control areas in our region who have 
primary control capabilities to open and close transmission 
circuits and to redispatch generation.
    Three of the more than 30 companies within our reliability 
coordinator territory suffered outages in the blackout of 
August 14. Mr. Chairman, your letter of invitation to this 
hearing asked us to respond to the recommendations contained in 
the NERC's February 10 report. The recommendations which most 
directly apply to the Midwest ISO are found in attachment A, 
section B to the recommendation 1 of the NERC report.
    I'd like to briefly summarize the Midwest ISO's responses 
to NERC's recommendations. The more detailed response is 
contained in my full testimony previously submitted to the 
committee.
    As to NERC recommendation number 1 that the Midwest ISO 
improve its reliability tools, we have put our State estimator 
into production and as of December 31, 2003, it has served as 
our main reliability tool. This comprehensive tool allows us to 
gather real-time information on the status of our system and 
our neighboring systems. The State estimators run every 90 
seconds and solves in less than 30 seconds using over 88,000 
data points.
    We also have expanded our capabilities to run contingencies 
on our systems so that we have already modelled impacts on the 
grid if certain problems arise.
    This analysis tool is run after every third State estimator 
solution and it's completed in less than 10-minute standard of 
NERC, while evaluating over 5,000 contingencies. We have also 
implemented software updates that allow us to sort the data we 
receive with more emphasis on the information with the greatest 
potential for negative impact on the grid. Finally, in a case 
of a problem within any of our systems, we have developed a 
redundant backup.
    As to NERC recommendation 2, that we improve our tool 
that's designed to allow visualization of the grid status by 
our employees, we have more than doubled our video display 
areas, we have increased our ability to see the grid on a wider 
basis and we have increased our ability to see in greater 
detail any identified problems.
    As to NERC recommendation number 3, that we improve 
operator training criteria, we have participated in emergency 
drills and are instituting a series of additional drills and 
training that will be in place by June 30. In addition, we will 
train individual operators on a simulator.
    As to NERC recommendation number 4, that we improve our 
communications, we have worked with our members to clearly 
identify communication protocols in times of a system 
emergency. We have also increased communication of detailed 
information with non-Midwest ISO members, and now we are also 
fully utilizing NERC systems.
    As to NERC recommendation number 5, that we verify 
reliability authority, we have developed a reliability charter 
with our members to specifically delineate roles and 
responsibilities. We have developed a detailed joint operating 
with PJM.
    And Mr. Chairman, we also support the remaining NERC 
recommendations contained in the February 10 report that are 
not specifically directed to the Midwest ISO.
    If I may now turn to energy legislation pending before the 
Congress, I think that we all agree that reliability provisions 
in H.R. 6 and S. 2095 will enhance system reliability. But I'd 
like to take this opportunity to suggest that there are other 
issues addressed in the electricity title of the energy bill 
that would benefit grid reliability.
    By acting on issues that bring certainty to investments and 
grid upgrades, Congress can help get needed infrastructure 
built. We believe that the infusion of capital needed to 
enhance the electricity infrastructure will not occur while 
legislation that may change the assumption of such investments 
is a possibility. Anything that can be done to remove that 
uncertainty would help facilitate investment in the grid and I 
would be happy to answer any questions.
    [The prepared statement of Mr. Torgerson follows:]

 Prepared Statement of James P. Torgerson, President and CEO, Midwest 
             Independent Transmission System Operator, Inc.

    Good morning, Mr. Chairman and members of the Committee. My name is 
James P. Torgerson. I am the President and Chief Executive Officer of 
the Midwest Independent Transmission System Operator, Inc. (``Midwest 
ISO''). The Midwest ISO was formed in 1998. It is the first entity 
found by the Federal Energy Regulatory Commission (``FERC'') to be a 
Regional Transmission Organization (``RTO''). The Midwest ISO did not 
originate from a legislative mandate or against the backdrop of a tight 
power pool, but from voluntary action.
    The Midwest ISO's region covers portions of fifteen states and the 
Canadian province of Manitoba. Of relevance to your inquiry here, we 
act as a Reliability Coordinator for two sets of companies: one who are 
our members and a second set in the Mid-Continent Area Power Pool 
(MAPP) region that have not transferred control of their transmission 
systems to the Midwest ISO. As Reliability Coordinator, the Midwest ISO 
monitors, plans, conducts analyses regarding the high voltage grid and 
communicates with the Control Areas in our region who have the primary 
control capabilities to open and close transmission circuits and to 
redispatch generation. Three of the more than 30 companies within our 
reliability coordinator territory suffered outages in the blackout of 
August 14, 2003.
    Mr. Chairman, as you know your letter of invitation to this hearing 
asked us to respond to the recommendations contained in North American 
Electric Reliability Council's (``NERC'') February 10th Report on the 
August 14th blackout. The recommendations which most directly apply to 
the Midwest ISO are found at Attachment A Section (B) to Recommendation 
1 of the NERC Report which is included at the end of my testimony. I 
would like to specifically address each one of the NERC recommendations 
as they apply to the Midwest ISO.

                CORRECTIVE ACTION #1--RELIABILITY TOOLS

    In order to meet and exceed our duties as a Reliability 
Coordinator, the Midwest ISO utilizes a variety of tools, which we 
continue to upgrade and enhance as new capabilities become available. 
Those tools were already in the process of being upgraded prior to the 
August 14th events, but those events have prompted the acceleration and 
further expansion of those enhancements.
    In August 2003, the Midwest ISO was using two primary tools for 
reliability coordination: a status change alarm log and a flowgate 
monitoring tool with a static contingency analysis tool. While this 
tool set was substantial, it left us highly dependent on information 
from Control Areas within our region for the most accurate assessment 
of the status of the grid. When incorrect, incomplete or no information 
was provided, we were at risk of being unaware of significant operating 
events. Our systems also lacked extensive visibility into our 
neighboring systems, and as with our own region, were dependent on 
others for some of the data that was used to run the tools.
    Prior to August 2003, the Midwest ISO was already working to 
improve its capabilities. We were developing a State Estimator to model 
the current status of the transmission network and to use as a basis 
for contingency analysis and other real-time monitoring tools. At that 
point in time, we had already modeled over 60,000 data measurement 
points, but the model was not stable enough to be used as a primary 
reliability-monitoring tool. Since that time, we have added an 
additional 28,000 measurement points and stabilized the model. On 
December 31, 2003 this tool was promoted to be the primary tool for 
monitoring the real-time status of the transmission system. This 
reliability tool is a comprehensive model of the transmission network. 
It monitors and measures the status of all transmission lines and 
transformers over 230 kV (as well as all others identified as being 
critical to system operations) and the status of all generating units 
in our region. Our model also includes the first control area adjacent 
to the Midwest ISO area for most of our neighboring systems, and we are 
working to finish the modeling into all of the other neighboring 
control areas. The State Estimator runs every 90 seconds and provides a 
detailed updated view of the entire system.
    We also have a contingency analysis tool that runs on every third 
run of the State Estimator. This tool analyzes approximately 5,000 
different potential contingencies identifying potential problems on the 
system. Our modeling personnel continue to work to improve these tools 
by working with Control Areas both within our region and in our 
neighboring systems to improve the information and integration of the 
system. We are also working to improve the speed of these tools. Our 
goal is to significantly improve the solution rate while we also 
increase the number of points being monitored.
    The identification and management of transmission and generation 
outages is a critical part of any reliability coordination effort. 
Within the Midwest ISO region, all outage information is received from 
the equipment owner via a real-time data exchange. This information is 
automatically incorporated into the State Estimator model. The Midwest 
ISO is continuing to work to increase the availability of real-time 
outage information from neighboring systems. In August 2003, data from 
neighboring systems was all received via an industry standard interface 
that is not a real-time exchange tool. Through the joint operating 
agreement recently executed with PJM, our neighboring RTO, our two 
companies have worked to create the infrastructure for the real-time 
exchange of operating data, including outage data between regions. We 
expect to be exchanging real-time outage information with PJM by May of 
this year. We are attempting to negotiate the same real-time exchange 
of outage information with our other neighbors.
    In order to better utilize the vast amounts of data available to 
our reliability coordinators, a great deal of effort has gone into 
developing tools to sort out the most critical data and provide alarms 
properly identifying the significance of that data. Since August 2003, 
the Midwest ISO has substantially upgraded its alarming systems. We 
have increased the identification and integration of information 
through increased alarming levels for change of status Megawatt, 
MegaVar and kV limit measurements. We have also improved the 
presentation of the alarms through the use of increased alarm grouping, 
color-coding and limit threshold adjustments. The Midwest ISO is 
continuing to explore and evaluate additional improvements to our 
alarming capabilities.
    We have taken considerable efforts to provide redundancy and backup 
for our reliability tools. These efforts have several dimensions. 
First, all our reliability tools have at least one other tool that can 
provide similar information. For example, if our State Estimator became 
unavailable for any reason, we would use our flowgate-monitoring tool 
as an alternate means of monitoring the system in real time. And if our 
contingency analyzer was unavailable, we could also use our flowgate-
monitoring tool as the backup.
    Also, each of our computerized reliability tools has a redundant 
version (software and hardware) on site and in the event of a failure 
of the primary system; the redundant system would automatically take 
over its operation. Our building and computer room electrical supply 
and communication systems have built in redundancy as well. Finally, in 
the event of the complete loss of either our Carmel, Indiana or our St. 
Paul, Minnesota facility, they are backed up at an alternate location. 
The Carmel facility has a permanent back-up site near downtown 
Indianapolis, and the Carmel facility provides backup for the St. Paul 
facility.
    We believe the steps necessary to implement this NERC 
recommendation have been completed.

               CORRECTIVE ACTION #2--VISUALIZATION TOOLS

    In order to rapidly analyze and respond to system anomalies, it is 
critical to provide our reliability coordinators with tools to quickly 
visualize the portions of the system where the anomaly exists. Prior to 
August 2003, the Midwest ISO was highly dependent on input from the 
Control Areas in our region in order to visualize problems. Evaluation 
of the blackout events made it clear that this dependency raised 
concerns. The Midwest ISO has taken steps to eliminate that dependency 
and provide our operators with the tools to rapidly visualize system 
problems. Since August 2003, we have developed and implemented 
visualization tools that allow our operators to monitor the system in 
greater detail and on a wider geographic basis. As operating situations 
dictate, the operator can then narrow his view to see smaller and 
smaller segments of the system down to and including one-line 
electrical schematic diagrams of individual substations to better 
identify specific problems.
    The reliability coordinators now have an overview tool that allows 
them to monitor the Midwest ISO transmission system and surrounding 
areas on a real-time basis. This includes all 230 kV and higher 
transmission facilities along with all critical underlying facilities 
of 100 kV and above. The real-time overview includes information on 
real-time megawatt and reactive power values, voltage profiles and 
outage indications. As the operator needs additional detailed 
information, he can automatically access more detailed information on a 
specific area. This information can be displayed in a simple one-line 
electrical schematic diagram.
    As part of this visibility tool enhancement project, the Midwest 
ISO also upgraded the video projection system in our Carmel, Indiana 
facility. The video projection system provides the ability for a large 
amount of real-time, dynamic, visual information to be displayed and 
viewed by several people in the control center simultaneously. The 
upgrade program included the addition of over 20 new video projection 
units more than doubling the display area in the control room.
    We believe these enhancements go beyond the recommendations made in 
the NERC report.

                     CORRECTIVE ACTION #3--TRAINING

    We believe that training is as important to providing reliable 
services as adequate tools. Prior to August 2003, the Midwest ISO had 
focused on recruiting experienced and skilled operators to staff our 
control room. The blackout event highlighted the need to increase our 
training efforts. The Midwest ISO has developed a comprehensive 
training plan that we are currently implementing. By June 30th, each of 
our reliability coordinators will have completed at least five days of 
system emergency training as recommended. That requirement will 
continue on an annual basis and will also be developed to include 
performance assessments of each reliability coordinator in a training 
mode. This training will consist of a combination of activities 
including the following:

   Regional Emergency Response Drills--The Midwest ISO will 
        participate in regional drills with MAPP, Mid-America 
        Interconnected Network, Inc. (``MAIN'') and East Central Area 
        Reliability Council (``ECAR''). These drills will also involve 
        member control area operators and in some instances other 
        reliability coordinators such as PJM. The Midwest ISO will 
        assess our reliability coordinators participation in the drills 
        through observations and in debriefing sessions following the 
        drills.
   Table Top Emergency Drills--The Midwest ISO will use a 
        series of one-day tabletop drills that will involve varying 
        combinations of Midwest ISO staff and control area operators 
        from our membership. These drills will be fact specific and 
        scenario driven to test staff's performance in response to 
        hypothetical problems. The Midwest ISO staff's performance will 
        be evaluated and appropriate actions taken.
   Emergency Training on a Training Simulator--The Midwest ISO 
        is developing training scenarios for use with our training 
        simulator. The initial scenarios will involve two-day sessions 
        where individual operator performance can be assessed and 
        compared to other operators working on the same simulations. 
        This training will occur during the 2nd quarter of 2004.
   Operating from Back-Up Control Center Drills--The Midwest 
        ISO will train our operators on a range of emergency conditions 
        including those that involve the loss of our primary control 
        center with the accompanying need to transfer operations to our 
        back-up facilities in a rapid manner.
   Training on Emergency Operating Guides--All Midwest ISO 
        reliability coordinators are required to review and understand 
        all standing, temporary and emergency operating procedures 
        applicable to their jobs. This self-study is reviewed with the 
        operators by their supervisors on a regular basis.
   Emergency Communications and System Restoration--This is a 
        three-day training course that focuses on communication skills, 
        critical thinking (including the application of those skills to 
        system operations) and restoration activities. Participants in 
        this training will be assessed through an exam provided at the 
        end of the course.

    This recommendation will be met by the June 30, 2004 deadline.

                  CORRECTIVE ACTION #4--COMMUNICATIONS

    Following the events of August 14th, the Midwest ISO reevaluated 
our communications protocols and procedures and implemented significant 
improvements, including:

   Working jointly with our membership to develop and implement 
        an Emergency Response Procedure directive that clearly states 
        the definition of a system emergency, the criteria for a system 
        emergency and the emergency actions that will be taken to 
        resolve such an emergency.
   We also implemented our Conservative System Operating 
        Procedures that defines events and conditions that warrant 
        implementing more conservative system operating procedures and 
        lists the procedures, and communications needed to implement 
        those procedures. In addition, our joint operating agreement 
        with PJM obligates both parties to operate to the most 
        conservative limit on all jointly monitored flowgates and 
        equipment. This condition allows both companies to assure 
        reliable operation of our systems.
   Midwest ISO reliability coordinators are obligated to post 
        critical outage information to the NERC communication systems 
        to update neighboring Reliability Coordinators. We believe the 
        steps necessary to implement this recommendation have been 
        completed.

               CORRECTIVE ACTION #5--OPERATING AGREEMENTS

    Transmission system reliability depends on the ability of the 
Reliability Authority to not only identify problems and rapidly design 
solutions, but also on the authority to order users of the grid to 
implement corrective measures. As recommended, we have also reviewed 
our authority to direct corrective action over those parties to whom we 
provide reliability coordination services. These entities fall into 
five categories summarized below:

    Transmission owning members of the Midwest ISO--Our authority over 
this segment is clear and reinforced by several sources. First, FERC 
Order Nos. 888 \1\ and 2000 \2\ make clear the role of the ISO/RTO in 
providing reliability (security) coordination to its members. 
Additional FERC regulations on the operational authority and short-term 
reliability authority of RTOs further reinforce that authority.\3\ In 
addition, the Midwest ISO Transmission Owners Agreement and the Midwest 
ISO Open Access Transmission Tariff also both provide explicit 
authority for reliability coordination.
---------------------------------------------------------------------------
    \1\ Order No. 888, 61 Fed. Reg. 21,540, FERC Stats. & Regs. para. 
31,036 (1996).
    \2\ Regional Transmission Organizations, Order No. 2000, 65 Fed. 
Reg. 809 (January 6, 2000), FERC Stats. & Regs. para. 31,089 (1999) 
(Order No. 2000), order on reh'g, Order No. 2000-A, 65 Fed. Reg. 12,088 
(March 8, 2000), FERC Stats. & Regs. para. 31,092 (2000) (Order No. 
2000-A).
    \3\ 18 CFR Sec. 35.34 (b)(3) and (4) (2003).

   Independent Transmission Companies (ITCs) who are members of 
        the Midwest ISO--Our sources of authority over this category is 
        very similar to that shown above, and is addressed in Appendix 
        I to the Transmission Owners Agreement that deals specifically 
        with ITCs.
   Non-transmission owning users of the transmission system, 
        including non-member generators--Our primary source of 
        authority in this instance is the FERC approved Open Access 
        Transmission Tariff, which contains specific requirements to 
        follow the direction of the Midwest ISO to relieve loading 
        problems, and provides for monetary penalties in the event of 
        failure to comply.
   Companies not members of the Midwest ISO, to whom the 
        Midwest ISO provides reliability services under contract. This 
        category currently includes members of MAPP that are not 
        members of the Midwest ISO. Under this category, we have a 
        contractual arrangement with the MAPP reliability region of 
        NERC (and prior to October, 2003 with the ECAR reliability 
        region) to fulfill their contractual obligations with their 
        members. We do not have a direct contractual relationship with 
        the Control Areas themselves and we obtain our authority 
        through MAPP's relationship with its membership.
   Canadian Province--The Midwest ISO has a coordination 
        agreement with Manitoba Hydro under which we act as Reliability 
        Coordinator for their transmission facilities. The agreement 
        specifically lists the responsibilities of the Midwest ISO as 
        Reliability Coordinator. However, it does not obligate Manitoba 
        Hydro to follow the directions of the Midwest ISO. Due to the 
        unique international relationships involved in this contract 
        and the nature of Manitoba Hydro as a Canadian Crown 
        corporation, they are unable to make this contractual 
        commitment. However, this agreement is the most comprehensive 
        of its type between Canadian and U.S. companies within the 
        industry. The working relationship between the companies has 
        been outstanding and Manitoba Hydro has always voluntarily 
        complied with our directions as their Reliability Coordinator.

    In addition, the Midwest ISO will soon file with the FERC a 
``Reliability Charter'' with many Midwest entities that identifies in 
specific detail the roles and responsibilities of each entity to 
maintain system reliability. We are also planning to work with the NERC 
Operating Committee in its efforts to revise the operating policies and 
procedures to ensure reliability coordinator and control area 
functions, responsibilities, and authorities are completely and 
unambiguously defined, as described in NERC recommendation 9.
    We believe the steps necessary to implement this recommendation 
have been completed.
    Mr. Chairman, the Midwest ISO fully supports the remaining NERC 
recommendations contained in the Blackout Report. I would like to 
comment on some of the other specific recommendations. Recommendation 3 
addresses an improved audit process so that all Control Areas and 
Reliability Coordinators will be reviewed on a three year cycle. While 
the recommendation proposes to audit only 20 of the highest priority 
entities by June 30, the Midwest ISO would support increasing the 
number of first year audits. We would also support NERC adopting a 
policy stating that an entity that commits a significant or repeated 
violations of reliability standards will be placed on an annual audit 
cycle until NERC is satisfied that the problems have been corrected.
    The Midwest ISO believes that Recommendation 4 concerning 
vegetation management should not merely rely on reporting vegetation 
related outages but should establish minimum line clearance standards 
to avoid contacts in the first place. This is an area where Reliability 
Coordinators like the Midwest ISO must continue to rely on local 
Control Areas to maintain the integrity of the system.
    In general terms we would recommend that NERC operating policies 
should be issued in the form of specific standards and efforts should 
be made to eliminate vague or ambiguous language.
    Mr. Chairman, to look beyond the recommendations in the NERC 
Blackout Report, we believe increased reliability can also be achieved 
through agreements between interested parties. The Midwest ISO is 
actively exploring additional agreements to ensure greater reliability. 
It has recently executed a joint operating agreement with its 
neighboring RTO--PJM--that allows for greater management of the 
intertwined seams in the Midwest. In the joint operating agreement, we 
have committed to data exchange and other features that will allow each 
to be assured of the others performance of tasks to protect the 
reliability of the regional grid. By having that agreement on file with 
the FERC, FERC can also serve as a forum for resolution of any future 
dispute on performance that the parties themselves cannot resolve. 
Likewise within the Midwest ISO's own region, the terms of the Midwest 
ISO's tariff are contractually binding on customers and users. These 
are measures in place today that can be expanded.
    Mr. Chairman, you also asked for our views on the reliability 
provisions contained in the Conference Report on H.R. 6 and the 
identical language found in S. 2095 which you recently introduced. The 
Midwest ISO strongly supports this legislation. We believe that 
establishing an Electric Reliability Organization reporting to the FERC 
that develops clear reliability standards and providing that 
Organization with the authority to impose penalties for violations of 
the reliability standards would be effective in ensuring a more 
reliable bulk power system. Thank you for your time and I would be 
happy to answer any questions you may have.

               CORRECTIVE ACTIONS TO BE COMPLETED BY MISO

    MISO shall complete the following corrective actions no later than 
June 30, 2004.

          1. Reliability Tools. MISO shall fully implement and test its 
        topology processor to provide its operating personnel real-time 
        view of the system status for all transmission lines operating 
        and all generating units within its system, and all critical 
        transmission lines and generating units in neighboring systems. 
        Alarms should be provided for operators for all critical 
        transmission line outages. MISO shall establish a means of 
        exchanging outage information with its members and neighboring 
        systems such that the MISO state estimation has accurate and 
        timely information to perform as designed. MISO shall fully 
        implement and test its state estimation and real-time 
        contingency analysis tools to ensure they can operate reliably 
        no less than every ten minutes. MISO shall provide backup 
        capability for all functions critical to reliability.
          2. Visualization Tools. MISO shall provide its operating 
        personnel tools to quickly visualize system status and failures 
        of key lines, generators or equipment. The visualization shall 
        include a high level voltage profile of the systems at least 
        within the MISO footprint.
          3. Training. Prior to June 30, 2004 MISO shall meet the 
        operator training criteria stated in NERC Recommendation 6.
          4. Communications. MISO shall reevaluate and improve its 
        communications protocols and procedures with operational 
        support personnel within MISO, its operating members, and its 
        neighboring control areas and reliability coordinators.
          5. Operating Agreements. MISO shall reevaluate its operating 
        agreements with member entities to verify its authority to 
        address operating issues, including voltage and reactive 
        management, voltage scheduling, the deployment and redispatch 
        of real and reactive reserves for emergency response, and the 
        authority to direct actions during system emergencies, 
        including shedding load.

    The Chairman. Your statement is in the record.
    Mr. Torgerson. Yes, sir.
    The Chairman. Thank you very much. I noted that Senator 
Talent arrived after the four of us and I wanted to just put 
you in the same position. We asked each Senator if they wanted 
to make a few comments briefly before we started questioning, 
and I would ask you that now, Senator?

        STATEMENT OF HON. JAMES M. TALENT, U.S. SENATOR 
                         FROM MISSOURI

    Senator Talent. Mr. Chairman, I will just say that I'm 
deeply concerned that unless we take the kind of steps that 
these witnesses have recommended and that we had in the bill, 
that we are going to be looking at another blackout and it's 
just a matter of time.
    The Chairman. While the Senator makes that statement, let 
me just state for the record for those who are listening and of 
concern, we have three, is that correct, what we would call 
major blackouts, including this last one as I understand it. 
And in 1965, we had the Northeast and they lost 20,000 
megawatts, 30 million customers. In 1996, Western blackout, 
28,000 megawatts, 8 million customers. I do not see anybody 
disagreeing. And then 2003, on August 14, the blackout was 
62,000 megawatts, affected 50 million customers and cost 
ultimately about $5 billion.
    As you recall it as experts, is that a pretty good summary 
of major ones? Well, Senator Talent, I just thought that 
following your remarks and knowing that we have not underloaded 
since these, if anything, they are loaded more because there 
has not been great investment for one reason or another. And 
they are loaded more and more because people want what they 
sell. That's your prediction? You better try to find out a way 
to fix it or we are going to be sitting here with Americans 
seeing us and saying that what good were they.
    Now, having said that, I have a lot of questions, but I'm 
going to just change a bit and let you go first, Senator 
Bingaman, and I will go--or one of the other senators. We are 
going to try to get out of here, everyone, by 12, so if you can 
keep your answers short, we'll all keep our questions short.
    Senator Bingaman. Mr. Harris, let me start with you. It 
appears to me we have got, although both are considered ISOs, a 
big difference between the way that PJM is organized and the 
way that MISO is organized. You have much more central control 
of PJM. As I understand it, there are 23 different control 
areas in MISO, is that correct?
    Mr. Harris. Yes. There are 23 that are transmission owning 
members. We actually have reliability coordination over 35.
    Senator Bingaman. Well, when this blackout occurred last 
year, my impression is that it cascaded until it got to the 
boundaries of PJM, and then it stopped. And that would lead me 
to conclude that you were doing something there that they 
should have been doing in MISO at the time, am I right about 
that? Is there some way that you organize your requirements on 
reliability there at PJM that we need to try to replicate 
across the country?
    Mr. Harris. I think there is a dual answer there. In the 
first place, once the cascade starts, it rips, basically at the 
weakest links. And so the question is why it ripped where it 
did is up to a lot of study. But it seems to me there are 
certain things that are being done.
    One of these is the fact that we do precontingency 
planning. We dispatch looking at the thousands of things that 
could possibly be a worst case event and those things that were 
analyzed that we are always in a state that we can deal with 
that.
    Secondly, we price in a way that the generations can 
respond based upon the price signal when you have congestion 
and a problem. So the precontingency dispatch and the price are 
two tools that are tremendously valuable.
    The third thing is authority. We have the sole authority to 
declare emergency, to direct emergency and to declare the end 
of the emergency and everyone has to abide by authority.
    Senator Bingaman. So those are three ways in which you try 
to head this off, and you think those served you well in this 
circumstance?
    Mr. Harris. Correct.
    Senator Bingaman. Mr. Torgerson, do you have anything like 
those same provisions in place there in your ISO?
    Mr. Torgerson. As of right now, we do not do dispatch of 
the generation from the market as Mr. Harris does. We will. We 
have plans to do that starting December 1 of this year when 
we'll initiate the market in the Midwest which then we will be 
sending the price signals to all the generators. So that will 
be added and that's--we'll have the market.
    To be able to have the same authority, we do have the 
authority to tell people to redispatch, to shed load, to do the 
same activities Mr. Harris does, but we do not have the ability 
right now to direct generators like he does because he runs the 
control area, which we will have in the future. So there are 
some differences right now. They should narrow quite a bit by 
the end of this year.
    Senator Bingaman. Would you agree that the centralized 
control that they have been able to develop or acquire there at 
PJM would be a help in heading off these kinds of blackouts in 
your area in the future?
    Mr. Torgerson. I think between the tools we have 
implemented already that I mentioned in my remarks and in my 
prepared testimony, and couple that with having the market like 
Mr. Harris has, I think would be very beneficial in heading off 
blackouts in the future.
    Senator Bingaman. Ms. McCarren, let me ask you in the West, 
as I understand it, a number of operators in your region have 
not joined in signing the contracts that make your rules 
enforceable, is that right?
    Ms. McCarren. Yes, Senator, and that list appears in my 
testimony.
    Senator Bingaman. You might push that button. I don't think 
you are being heard.
    Ms. McCarren. Apologize. Yes, there are a number. They 
appear on page 6 of my testimony at a footnote. We are working 
very actively with several of them to convince them of the 
value of being in the RMS, our contractual reliability plans. 
And I think we will be making some headway, but there are some 
significant outliers, Senator.
    Senator Bingaman. This is something we need to get a 
resolution of, it would seem to me, if we are going to head off 
blackouts in the future, would you agree with that?
    Ms. McCarren. I do. The FERC has been very helpful to us 
and very tuned into this issue of entities that are not 
signatories. And so we are hoping to have some help from them 
as well.
    Senator Bingaman. And do they have the authority at this 
point to order, to order these utilities to participate?
    Ms. McCarren. No. They do not. But we certainly have the 
power of persuasion.
    Senator Bingaman. And they are beginning to use that?
    Ms. McCarren. Yes, Senator.
    Senator Bingaman. Okay. It seems to me that having strong 
RTOs or ISOs is an essential part of dealing with this problem. 
It's not just that we need a better set of reliability rules or 
a better backup mechanism to enforce them. They are sort of on 
the ground responsibility for avoiding these kinds of blackout 
problems in the future. It comes down to the RTO or the ISO. Is 
that a correct view of things or incorrect in your opinion, Mr. 
Harris?
    Mr. Harris. Yes, Senator. I think it's exactly correct. I 
think the other value that a large RTO brings is in the 
regional planning. All entities come together in our area and 
participate in the planning from environmental groups to the 
various States to the citing authorities. They all participate 
and we are able to look at the entire region as it's seen and 
operated, how it's growing and the needs of new generation, 
including the green generation coming on and make sure those 
needs are met in a least cost efficient way is another 
tremendous value of RTOs.
    Senator Bingaman. Thank you very much. I think that this 
light here means I have used my time, so I will quit.
    Senator Thomas. Okay, thank you. The chairman had to step 
out for a moment. He will be back very shortly. Mr. Glotfelty, 
do you--2 years ago, a national transmission grid study was 
called for a designation of national interest transmission 
bottlenecks. Are you finished with that? Are you doing that? 
What has the Department done on that?
    Mr. Glotfelty. We have, we have begun the process. We have 
completed a draft Federal Register notice to submit to the 
Federal Register to bring parties in to give their views of 
what a national interest transmission bottleneck is.
    As you know, provisions or something similar to a national 
interest transmission bottleneck designation was included in 
the energy bill conference report. And we were trying to 
proceed as much as we could on our own free will before we 
understood what the Congress wanted us to do.
    So since the Congress--the Congress has not completed their 
energy bill, we feel it's important that we continue to go, 
continue to move forward on national interest transmission 
bottleneck designations, figure out the criteria by which we 
will designate those in the future and hope that Congress will 
pass the energy bill and give us a little bit more direction as 
we go through our process.
    Senator Thomas. I just mention it's 2 years and going on, 
that's quite a while. It looks like perhaps we could have done 
something by now. Mr. Gent, what do you think we have to have, 
can you have mandatory or enforcement reliability without 
legislation?
    Mr. Gent. Senator, it's very difficult as I stated in my 
written testimony. Today everybody is dedicated to having a 
reliable system. As time marches on, I'm afraid that we'll have 
what I call a reliability or risk creep. The only tool we have 
right now is to have disclosure of violations and that's the 
tool that we are going to use. We are working hard to come up 
with a uniform way of disclosing violations to the rules and 
we'll have that in place or have that decided within a month.
    Senator Thomas. You mentioned in your statement a number of 
times that you point out violations some, but you have no way 
of enforcing it, is that right?
    Mr. Gent. That's correct.
    Senator Thomas. Mr. Harris, in your statement you sound as 
if you do not need any authority. That everything's great.
    Mr. Harris. Well, from the operation of PJM as an RTO, 
that's correct. You know, we are actually operating day-to-
day----
    Senator Thomas. But you are not an RTO.
    Mr. Harris. Yes, sir, we are.
    Senator Thomas. No. It depends on how you define it.
    Mr. Harris. Well, we are FERC approved as a regional 
transmission organization.
    Senator Thomas. What about the State's role as individual 
States? Do they have any input?
    Mr. Harris. Absolutely. We have a separate agreement with 
our States. We have a memorandum of understanding where the 
States come in, they participate with the board, they give 
advice to our board, we meet with the States in our regional 
planning context and it's a very healthy relationship that we 
have with our States.
    Senator Thomas. But you do not have them all involved?
    Mr. Harris. Well, all of the States that are currently 
under operational construct are. We are in the process now of 
integrating AEP Dayton, Dominion out of Virginia and 
Commonwealth Edison. Of those States, five of those States plus 
the District of Columbia are supporting moves to get AEP into 
PJM as soon as practicable.
    The States of Virginia and Kentucky are asking questions 
and hearings are still going on there.
    Senator Thomas. That's not really how we'd like to see it, 
though, is it? Wouldn't we like to see RTOs that are, that are 
coming together because the States decided to do that, and then 
the companies in those States would be part of it?
    Mr. Harris. Yes. When we look at the genesis of how PJM was 
formed, it was because we spent the years of doing the due 
diligence and the analysis and review as to what is the most 
beneficial good for the public. How does the consumer benefit 
over what the status quo is?
    And I think those kind of questions need to be asked and 
need to be addressed in a public forum, but also need to be 
done in a timely way because the value proposition as we are 
seeing is huge.
    Senator Thomas. In the West also, we do not really have an 
RTO, do we?
    Ms. McCarren. No. In the Western Interconnect, no RTO has 
been effectively formed. Thank you. And in response to the 
question from Senator Bingaman, I believe very strongly that in 
the absence of those RTOs, there is even a bigger role for 
mandatory reliability standards and the role of the three 
reliability coordinators we have in the West. So no, there are 
no RTOs at this time.
    Senator Thomas. One of the reasons we do not have an energy 
bill and one of the reasons we aren't able to do this is 
because the States want some State authority here. And they--
that's why I think regional RTOs that are put in by States and 
not by other ways are what we have to do if we are going to get 
something done, and particularly in the West. We had States 
that did not want to participate and Federal--Federal like 
Bonneville. Do you have any involvement or control over the 
Government agencies?
    Ms. McCarren. We have--Bonneville is a signator to the RMS 
and almost all of the State, the public entities are members of 
WECC. And yes, they do participate. And it's voluntary, as you 
said.
    And in addition, we have the two Canadian provinces which 
of course are completely non-jurisdictional.
    Senator Thomas. I see. Just one final, I guess. Do you--do 
you think, Mr. Gent, that the transmission system is--has 
investment to keep up with the demand?
    Mr. Gent. I think the evidence is rather obvious that it 
has not. It's a sad commentary that we put in all sorts of 
generation over the last decade and we have not put in the 
companion transmission to get that generation to market.
    Senator Thomas. Actually, we have not put in enough 
generation to meet demand either, for that matter.
    Mr. Gent. Some of the generation that we put in is locked 
in by the transmission.
    Senator Thomas. Yes. Do you give any thought to third party 
operators for transmission?
    Mr. Gent. To NERC and the Regional Reliability Council's 
third party operators make no difference. It's just a matter of 
ownership. What we care about is whether they play by the rules 
or not. And it's quite likely that new entities that have lots 
of transmission are going to be very concerned with playing by 
the rules.
    Senator Thomas. Playing by the rules is sometimes a little 
difficult to get different operations to be able to participate 
in the transmission. They just get much less, isn't it?
    Mr. Gent. Currently, we do not have trouble with the 
transmission operators. I think the problem here is the 
transparency, even though they may be audited or they may 
undergo compliance audits, nobody knows what the results of 
those audits are. So we are taking steps to make sure that NERC 
and the general community is aware of what the results of the 
audits are.
    Senator Thomas. Again, if you paid any attention at all to 
what we were doing with our energy bill, you would discover 
that some of the places this whole idea of availability of 
space on transmission is part of the problem.
    Mr. Gent. Yes.
    Senator Thomas. That's part of the reason we did not get it 
finished and we have to do something about that in the future. 
Thank you.
    The Chairman. Thank you, Senator. Senator from Louisiana.
    Senator Landrieu. Thank you very much. And I really 
appreciate all the comments made, and Mr. Harris, yours in 
particular, for the way you not only described your involvement 
in the industry, but generally how complicated this is, which 
is why it's been extremely difficult for us to try to put 
together a comprehensive piece of legislation of which 
electricity is only one part.
    We have thousands of entities that have developed with 
different rules and regulations, but we are clear on this 
committee that while we believe that competition and efficiency 
could work to reduce prices and establish a greater, more 
positive outlook in the future, without the reliability section 
being done, we could really create some serious havoc and 
problems.
    That's the struggle that our committee is moving through to 
try to figure out the different views of the different States 
and constituencies, whether to have voluntary or mandatory RTOs 
and checkpoints for reliability.
    One of the issues that I have been focused on is this 
participant funding issue, which I have argued as representing 
a region and that seems from what I know to be able to produce 
more electricity than we consume. We are a fairly large 
consumer of electricity. We have a lot of industries, a lot of 
power, you know, powerplants, cogeneration, et cetera.
    But we are not opposed to being part of a national system 
if it was done in a fair manner, and I have argued that not 
sufficiently to get votes of everyone up here, but participant 
funding is a fair way to go about allocating costs associated 
with having to invest more in the transmission line.
    In other words, if generators, once it sells, think they 
have a market for their electricity, then they should be 
willing to pick up part of the cost of that and not have it on 
the ratepayers of States like Louisiana when we are already 
producing and consuming as much electricity as we need and 
shipping it everywhere else.
    I keep saying ``why should the ratepayers in Louisiana pay 
additional rates so that Illinois can turn their lights on, and 
New York can turn their lights on?'' I mean, I want to help 
them turn their lights on but I'm not willing to pay for them 
to turn their lights on. So I've argued about participant 
funding being maybe a fair way, not for them to pick up the 
total cost, but for them to pick up the costs associated with 
their need.
    You indicated that that's what you all do so could you 
explain maybe to the other members and maybe make a comment 
about how that system in your mind is fair because some people 
aren't for that system up here.
    Mr. Harris. Certainly I'd be happy to, and also there is 
something that Senator Thomas said earlier on planning. Let me 
try to connect the dots on how it works and how it works very 
well. The electrical system is like an ecology system. One 
thing affects everything else.
    So when you are planning and changing, okay, that has to be 
studied in the whole. That's where an RTO comes in because you 
have got an independent staff to do total, complete planning.
    Now, we need generation. We need to have transmission. The 
variables that affect that are your load growth, any 
operational bottlenecks like we talked about with reliability. 
And then ultimately deciding decisions for a different 
generating plant.
    Every time a generation plant comes on, they choose where 
they want to locate, the size they are and the kind of 
generation mix you are going to have, whether it be a coal, 
gas, nuclear or whatever that plant may be.
    So what you do through participant funding is we have a 
requirement and, Senator Thomas, it's actually a requirement 
our States insisted that we put in there. And that is, that 
when a new generation plant comes on, we do what is called a 
simultaneous feasibility deliverability test.
    Now, all that means is that when you come on line you have 
to move your power anywhere without any constraints happening. 
So we analyze the system, looking at these other variables, 
okay, and any build that needs to be made to be able to allow 
that plant to come on and move their power without constraints, 
they have to pay for it, okay?
    And that is very valuable, because what happens in our 
area, for example, we have had over 11,000 megawatts of 
generation, and every time we add, we are building 
transmission, support it, and you are adding to the reliability 
of the grid, and it's able to move without congestion. Okay. 
That's the beauty of participant funding.
    Now, it doesn't cover 100 percent of the cost because you 
have to look at the other variables. Now, about 65 percent of 
our $700 million was funded that way, and you really do not 
need legislation. The Federal Regulatory Commission approved 
this for us in 1998 and we have been utilizing that process 
ever since.
    Senator Landrieu. So in other words, when a generator comes 
on, when a generator wants to site into a State, they basically 
have to pick up according to the model that you've used about 
65 percent of that cost?
    Mr. Harris. Whatever the planning study says they need to 
do. It takes an analysis to determine what you need to. The 
important thing is you say that power has to be moved 
throughout the region and then whatever that transmission is 
necessary to enable them to do that, otherwise you are 
degrading the system and you are forcing, like you say, others 
to pay for it.
    And what we found is when you can do the analysis and when 
you have the competitive wholesale markets, people are willing 
to pay those costs in order to get on line and you are adding 
to the reliability of the grid. It works.
    Senator Landrieu. Mr. Chairman, I'd really like us, you 
know, to pursue more, maybe not at this time, this particular 
model. It might help us to get through one of the more 
contentious arguments about the piece of our bill on which we 
have gone back and forth, some want participant funding, some 
do not. Maybe this model, with some adjustments to it, could 
help us get over that barrier and get over that hurdle because 
it's very, very important.
    That's generally what I wanted to say. I will hold my other 
questions until later.
    The Chairman. Thank you very much. Let us see, Senator, if 
you are ready.
    Senator Talent. Thank you, Mr. Chairman. Well, Senator 
Landrieu and Senator Thomas have gotten into the issue that 
interested me in particular because it seems to me we have got 
a lot of agreement on the committee about the importance of 
mandatory reliability type organizations and regulations.
    But then the other issue is less enforcement on existing 
lines, but investment so that we can get new lines as needed. 
Mr. Gent, you said it's kind of an offhand comment, something 
Mr. Thomas was asking at the end. You mentioned that it's a 
matter of ownership. Would you go into that a little bit more? 
Did I hear you correctly?
    Mr. Gent. I was referring to transmission organizations 
that take ownership and operate transmission. I think DTE 
Energy, Detroit Edison is a good example. I think they sold 
their system to ITC, so it's a different ownership, but the 
operation continues to be proper and in line with the 
reliability rules.
    Senator Talent. Right. Now, were you suggesting that 
ownership might matter in terms of incentives to invest in the 
grid or in your opinion, is that unimportant, given--assuming 
that we have RTOs that are adequately empowered the way Mr. 
Harris was talking about?
    Mr. Gent. Senator, it's probably very important to someone, 
but to me I'm interested in how the grid operates so the 
ownership doesn't come into that picture.
    Senator Talent. Okay. I'm kind of--when I mention things 
like that, I know I'm sort of throwing the hagus in the fire a 
little bit on a very difficult issue. But let me address that 
more generally.
    If we empower NERC or the RTOs or both in terms of 
enforcing reliability on existing lines, or insisting on 
investments either through participant funding or in some other 
way in new lines where necessary, do we need at some point to 
go into ownership issues in the judgment of those here at the 
panel or can we ensure adequate investment, notwithstanding 
differing incentives that might depend on who owns what, if 
somebody owns the lines or not. Would anybody like to offer a 
comment on that? Yes.
    Mr. Harris. Yes. Senator, I think one thing to keep in mind 
is that the investment that's necessary is what is necessary to 
make sure you have a reliable grid. And over the past 6 years, 
what we have discovered in a highly congested area here in the 
Northeast and the Mid-Atlantic, up and down the Atlantic 
Seaboard, is that most of the value you get for transmission 
reliability and upgrades is in the components, not the lines.
    Once you do the studies and you look at the generation 
coming in, the demand side response that want to come on, it's 
by operating substations, putting in smarter technology for 
control systems, better transformation. And the lines that you 
do have to build are actually coming out to be short segment 
lines, as opposed to having to build a long----
    Senator Talent. Interesting. And you had full--I'm sorry, 
and you have full authority in your RTO to order such 
investments as you think are necessary to protect the 
reliability of the grid? Is that true?
    Mr. Harris. That's correct, we do, yes, sir.
    Senator Talent. That's not always true, though, for RTOs 
around the country, is it?
    Mr. Harris. No. I think under FERC Order 2000 there is the 
requirement once you become fully functional that the RTO would 
have that authority, but I'm not, I don't think everyone but 
PJM has that right now.
    Senator Talent. Well, let me just hone in then and ask 
generally, I mean, if--when we talk about investment issues and 
we talk about RTOs or mandatory reliability, if we take care of 
the latter, can we have confidence that we are taking care of 
the former?
    In other words, if we adequately empower RTOs or NERC, can 
we just let the system work then and assume that there will be 
adequate investment, as well as operation of the existing 
assets?
    Mr. Harris. It takes both. You have a standard which NERC 
does to make sure that people are operating at a certain 
plateau, but once you get there, then you have to actually have 
a process to take the different and multiple competing entities 
to allow them to allocate the resources that would be in the 
best public good. And that's the day-to-day operations of an 
RTO, reasonable planning, State coordination, all of that comes 
into actual running of the grid, so it's a partnership.
    Senator Talent. So NERC and the RTOs together will do that 
if they are adequately empowered without any other changes, is 
that your opinion, Mr. Gent? Do you want to offer an opinion on 
that?
    Mr. Gent. Yes. I think Mr. Harris has stated it exactly 
right. We can operate the existing system reliably whether it 
has an adequate amount of transmission or not. To be able to 
conduct commerce and business the way RTOs are meant to conduct 
business, we need more transmission. So we can operate the 
system whether we have more or less.
    Senator Talent. But just empowering you all isn't 
necessarily going to produce that more transmission, right?
    Mr. Gent. That's right. Mandatory standards will make 
everybody on an equal plane, but it won't provide us with 
additional transmission.
    Senator Talent. Although Mr. Harris said that you can 
require additional transmission capabilities as new plants come 
on line, so there--to some extent you can, right?
    Mr. Gent. That's correct.
    Senator Talent. One other thing then, Mr. Chairman, I 
appreciate your indulgence. The uncertainty surrounding all 
this is itself a problem, isn't it? In other words, I certainly 
can understand, if I'm a company that owns generating and 
transmission facilities and I'm not sure how much ownership or 
control I'm going to have over the transmission facilities in a 
year, 2 years or 5 years because, you know, FERC is here and 
Congress is there, and that's not exactly a great incentive for 
me to make a big investment in those transmission facilities, 
is it?
    I mean, it probably would be good if one way or another we 
cleared up some uncertainty. Mr. Torgerson, you look like you 
are stirring yourself to make a comment?
    Mr. Torgerson. Oh, no. I fully agree with that, sir. The 
investment in the transmission system needs some certainty from 
the FERC and from Congress as to what the rules of the road are 
going to be. The dollars from investment I have heard from 
people are pretty much sitting on the side lines until the 
rules of the road are set.
    So it may very well be, and Mr. Gent, I blame you for 
bringing up this whole ownership thing. But it may very well be 
that regardless of exactly where we go on the ownership issues, 
that if we just settle that and then sort of regulate in light 
of that context, that we can make maybe any kind of system in 
that regard work from a reliability standpoint once we know 
what it is, and you all can regulate around it. Is that fair? 
You are all nodding your head. Okay. Thank you, Mr. Chairman, I 
appreciate it.
    The Chairman. A little while ago you thanked me for what?
    Senator Talent. For indulging me. Because I think I went 
over my time.
    The Chairman. Yes, you did. And my indulgence was running 
thin, but you did very nicely.
    Senator Cantwell.
    Senator Cantwell. Thank you, Mr. Chairman. Mr. Gent, your 
testimony couldn't be more clear in that basically you say that 
had the legislation been passed on reliability, we would not 
have had the August 14 blackout and that you request that 
Congress enact this reliability legislation this year.
    Do we need to enact any other legislation or just--by that 
I mean, do you need to enact any other legislation than the 
reliability legislation to make reliability work?
    Mr. Gent. Senator, there are a number of other things that 
would help reliability work. More transmission would help. 
Certainly would help. But from my own perspective as the CEO of 
NERC, we need the reliability legislation and I understand that 
there is, there is a context for the vehicle in which that 
happens.
    I have to leave that up to Congress to decide how you are 
going to go about doing this. But we do need the legislation.
    Senator Cantwell. But don't you think it's somewhat 
irresponsible for us not to pass a reliability standard if in 
fact that's the only legislation we can pass?
    Let me preface it by this. My predecessor, after a similar 
blackout in the Northwest, Senator Gorton, proposed this 
legislation and it did pass one body, not the other. That was 
the warning call. What happened in the Northwest was the 
warning call and people dropped the legislation, we passed it 
out of Senate and it was held up in the House.
    Now we have had a worse crisis happen on the east coast and 
the same thing is happening. People are holding this 
reliability bill hostage to get other legislation. And I think 
it's irresponsible for us not to pass reliability standard 
legislation even if it's stand-alone legislation.
    We can all agree, can't we, that this is actually needed 
legislation?
    Mr. Gent. I agree.
    Senator Cantwell. Thank you.
    The Chairman. Thank you very much. I think it's my turn for 
a few minutes. Let me just say, Mr. Gent, that may very well be 
the case that this is important. I think everybody says it is. 
But a lot of people would say that there are five, six, maybe 
10 provisions in the energy bill that are very important also, 
and we are going to try our very best to get more than this. We 
are not trying to get--as implied, to kill this.
    Quite to the contrary. It's already passed both bodies in 
conference and so we don't have the hangup that we had before. 
The hangup is whether we get a bill or not. And I do not think 
this is the hangup. So I just wanted to make sure you know that 
there are some other things. And sooner or later, we are going 
to get to the point where we move with the other bill or we 
start considering pieces.
    I think that's still a ways off and I'm sorry to tell you 
that. Let me move to something that everybody in America, every 
time we have a problem in an area, be it six subdivisions in a 
part of Virginia or whether it's a blackout, what they see on 
their television sets for a week afterward or two weeks is the 
vegetation issue. The trees are falling down all over the 
lines, and you are borrowing crews right from all over.
    Last time we had one they borrowed them from hundreds of 
miles away. I couldn't believe there were such good feelings 
that people would do that. But I guess I'm going to ask anyone 
that knows about this, I have not heard anybody come up with 
things we ought to do to minimize these tree falling or 
hangover trees issue.
    Does anybody have a suggestion for the record and for our 
people on what we ought to do about that? Mr. Harris?
    Mr. Harris. Yes. Mr. Chairman, I think the thing to realize 
is that something is always failing on the electrical grid. It 
is an electromechanical system that we are talking about. It's 
a machine. It's what is running. We don't put electricity in 
our hands and say look at my electricity. You have a machine 
that's running. And something is always breaking and failing.
    Therefore, the operations of that grid is crucial, and 
that's get into the things we are talking about with the 
contingency analysis, the State estimator tools that Mr. 
Torgerson and I have put in. So that you are always looking at 
the system as what is going to fail next, so you are always in 
a position to handle failure, not to prevent it, because these 
things are going to happen. People are going to run into a 
power line----
    The Chairman. Yes, I understand.
    Mr. Harris. Hurricanes hit and so forth.
    The Chairman. But ultimately, some people are casting about 
the idea that we get rid of all of that, that the lines no 
longer be in proximity to trees. I would assume that's an 
enormous undertaking from the standpoint of cost and whether it 
can be done or not, is that a fair statement?
    Mr. Harris. That's a fair statement, and there are just a 
lot of maintenance from vegetation to just how often you do 
breaker maintenance. All that needs to be done in some good 
practice, but things are going to fail because it's an 
electromechanical system. We need to plan for it.
    Senator Cantwell. Briefly----
    Senator Landrieu. Could I follow up on that point?
    Senator Cantwell. Okay.
    Senator Landrieu. If I could follow up on that point, how 
expensive is it to bury these lines? Is that a problem with the 
expense of it because burying lines in places and coordinating 
the cable system, to me, you avoid hurricanes, you avoid the 
trees? And, just to follow up with the chairman, is that even 
remotely possible in terms of the costs associated?
    Mr. Harris. It's just cost prohibitive for your long lines 
and your long haul today. I mean, you are looking at 10 to 50 
times the cost of putting them overhead and that's just 
extraordinary.
    Senator Landrieu. But in the cities when you are digging up 
the streets anyway, like to lay telephone cable, is it not 
efficient to maybe also lay your electric cable while you are 
doing that? You are not adding much cost?
    Mr. Harris. It's done considerably for new developments. 
Yes, ma'am.
    Senator Landrieu. I would like to pursue that, Mr. 
Chairman, and I don't mean to take your time, but I'm glad you 
brought that up.
    The Chairman. Well, all right. Senator, there is a major 
study and it says if you were to adopt it as a national policy, 
the costs are, you know, incredible. And I think somebody said 
that when they used the ratio a hundred times as much. Edison 
Electric establishes the cost and I myself was wondering 
whether we could in some way promote it.
    But the first thing that will be said is the Government pay 
for it and obviously we are not going to do that. We would 
never get anything passed, $300 or $400 billion to correct this 
problem.
    Senator Landrieu. But you could grandfather some provisions 
and then new development could potentially as the grid grows 
and expands----
    The Chairman. You could pursue, you know, something 
coercive with reference to doing the things together any time 
that new undergrounds are being built that would have the 
capacity to carry, we ought to be encouraging that you do them 
together. You are probably saying you do some of that already, 
is that correct?
    Mr. Harris. Yes, sir.
    The Chairman. Okay. Let me just move on to just a few. Mr. 
Glotfelty, Senator Cantwell before she left was recommending, I 
think was the only one today, that said that we ought to do a 
stand-alone reliability bill. I don't know whether your job or 
your expertise provides you with any observations, thoughts on 
that, but what do you think about that proposal?
    Mr. Glotfelty. Thank you, Mr. Chairman. A few thoughts. 
First, as you know, it's been the administration's position for 
years now that we need a comprehensive energy bill, one that 
addresses more than just stand-alone reliability, one that 
addresses a wide array of the issues that are necessary to 
ensure that markets work and that we have a reliable 
transmission system.
    We believe that those today are included in the conference 
report that the House and the Senate passed that is pending 
before the Senate. And we feel that it's absolutely essential 
that a comprehensive solution to this problem resolve the 
issues that are facing this country.
    Specifically, about the stand-alone legislation, I know 
that there are a number of different varieties of stand-alone 
reliability legislation. We think the most critical or a few 
pieces that are very important are provisions that allow 
deference to the regions. Provisions that allow us the most 
flexibility to work in an international fashion with our 
partners in Mexico and in Canada, and others that will ensure 
that we have a streamline approach to ensuring reliability 
rules are mandatory.
    The Chairman. I thank you very much. Let me take a couple 
more, but I would ask prior to that, two gentlemen on this 
side, you have been asked questions about investment, and so 
have you.
    We have in the bill, you know, eliminated PUCA, which 
people like you and two generations of people that run the 
plants and operations have recommended that. And I just wanted 
to say, in addition to what our Senator from Missouri said, I 
would assume that something like the elimination of PUCA would 
be helpful in terms of getting the industry to have more 
resources. Is that a fair statement?
    Mr. Gent. Senator, I serve a constituency that is all over 
the map on that, so NERC has no official position on that.
    Mr. Glotfelty. Mr. Chairman, I just got back from spending 
2 days in New York City meeting with investment banks with the 
Undersecretary of Energy. And time and time again, we heard 
that call, that the repeal of PUCA is necessary to provide 
certainty for more investment in the transmission sector.
    The Chairman. Mr. Harris.
    Mr. Harris. As president and CEO of PJM, I'm kind of 
neutral to the question, but as a person professionally in the 
business for a long, long time, I do think it would be helpful.
    The Chairman. Yes. Mr. Torgerson?
    Mr. Torgerson. Mr. Chairman, the Midwest ISO doesn't really 
have a position on it either, but as a former finance person, I 
understand that eliminating it would be helpful.
    The Chairman. All right. Some say that what Congress has to 
do to protect reliability is to establish a national 
reliability organization, pass mandatory reliability standards. 
Do you think that that is needed to improve reliability? Do you 
think that that's the only thing that's needed to improve 
reliability? You have already kind of answered that question. 
You kind of favor that. You don't. How much?
    Ms. McCarren. I agree with that statement that we need to 
get that legislation passed.
    The Chairman. Alone?
    Ms. McCarren. If that's the only way it can be moved then 
yes, alone.
    The Chairman. Mr. Harris.
    Mr. Harris. Well, I think what I have known specifically 
what is in the legislation, I think the points we are talking 
about with public oversight that is necessary with FERC 
authority to audit, with FERC authority over wholesale 
transmission throughout the nation. It's a broad, complete 
package and it would have to be looked at to make sure that it 
was total and complete.
    The Chairman. Mr. Torgerson.
    Mr. Torgerson. Actually, I believe that the comprehensive 
legislation is important to be passed. I think having a 
transmission office in DOE is important. I think the sense of 
the Congress related to the RTOs is very important and also the 
clarification on the States to protect native load is 
important, along with reliability. And I think reliability is 
clearly something very important, too.
    The Chairman. Okay. American electric power, I'm going to 
turn to that situation where they--American Electric Power's 
participation in PJM-RTO, what is the current status of the AEP 
and the PJM-RTO members, and is it important to the grid 
reliability that AEP join in this PJM-RTO. Who wants to take a 
shot at that? Mr. Harris?
    Mr. Harris. Yes, sir, it's extraordinarily important from 
three particular perspectives. Number one, there was an 
agreement with AEP and the merger condition that had to do with 
joining an RTO. That was a public policy question and a 
decision after lengthy hearings. As was mentioned, there are 
five States that support AEP getting in right now to complete 
the merger conditions. In two States they are having hearings 
on it. That needs to be completed.
    Secondly, the economics are huge. You look at close to a 
billion dollars savings from having AEP as part of a large 
regional market.
    And then thirdly, if you look at the Eastern 
Interconnection and how the Eastern Interconnection operates. 
AEP is huge, it's the largest transmission company. It's in the 
middle of the Eastern Interconnection and having that part of a 
functioning RTO will abate and help the overall--moving the 
electrical grid forward in the 21st century.
    We are working at making arrangements with TVA so that they 
can participate without abridging the TVA Act. All of that is 
integral to AEP being a functional part of the RTO. So we are 
almost at a stand still until this moves forward and it's very 
important.
    The Chairman. Thank you very much. All right. I may follow 
up with one or two, but I doubt that. I yield now to Senator 
Bingaman.
    Senator Bingaman. Thank you very much, Mr. Chairman. As I 
understand it, NERC has a requirement that utilities file 
reports of failure to comply with NERC reliability rules. And 
that with--file those reports with NERC. And now FERC has come 
along and said they want copies of those reports as well. Am I 
right about that?
    Mr. Gent. That's broadly correct.
    Senator Bingaman. Okay. Do you want to refine it for me?
    Mr. Gent. Each Regional Council, each has their own 
compliance programs and when they uncover violations, it goes 
into a regional report. And then it's generalized back to the 
NERC board.
    What we are going to do in these resolutions is to make 
sure that every single violation gets reported in its full 
glory to the NERC board. We are working now to come up with a 
way to disclose that to the FERC in its proper context. I think 
you can see that if they just received every violation they 
wouldn't know how to put the significance on one versus 
another.
    So we are--we hope to have within a month and a half a 
written policy that FERC can agree to as well that will allow 
us to pass that information on.
    Senator Bingaman. FERC has taken some action, has it not, 
to require that these reports be filed with them?
    Mr. Gent. They have only suggested that that would be a 
rule making, but to date, they have not done that.
    Senator Bingaman. Let me ask Mr. Glotfelty. Do you agree 
that it makes sense that those reports, reports of failures in 
some form need to be filed with FERC?
    Mr. Glotfelty. I think the most important thing is that 
they be made public at the right point in time. The companies 
that have violations ought to have the ability to go and 
discuss and determine if there really is a violation and then 
compare its magnitude to another's. But at some point in time 
if FERC is the appropriate entity where they would be filed so 
that there is some sort of public access, then that would be 
fine.
    Senator Bingaman. I guess what has always concerned me 
about this whole issue of blackouts is when a blackout occurs, 
those of us who are supposed to be exercising some kind of 
oversight role of the Federal agencies, we need to know, who do 
you call in to a committee hearing and say why did this 
blackout occur and how are you going to get it fixed?
    I have always thought FERC was the appropriate agency for 
us, at some stage at least, to be able to call in and say why 
did we have a blackout here. That's your job to head this off.
    They have a pretty good answer right now, which is it's not 
their job. They don't have the authority. NERC has got a pretty 
good answer, because NERC has no authority to enforce its 
rules. Everyone has got a pretty good answer as to why it's not 
their problem except the ISO operators, I guess.
    I guess, Mr. Torgerson, you are the one guy who sort of, 
the buck stops with you when a blackout occurs in your, in your 
region, your area, and you are the one that we need to look to 
to explain why the problem happened and how you are going to 
avoid it in the future. Is that the way you see the structure 
right now?
    Mr. Torgerson. I think--yes. The way we see the structure 
it's now become our responsibility to make sure we have the 
tools in place, follow the NERC standards, follow the rules 
that FERC has for us, and to monitor the system. And in the 
event that there are potentials for outages that could occur, 
we need to make sure we step in and stop, try to stop those 
before they expand.
    And the idea behind it is to run these contingency analyses 
that Mr. Harris talked about that allows us to look at things 
ahead of time.
    Senator Bingaman. So you see the ultimate responsibility 
for avoiding blackouts in your area as being yours?
    Mr. Torgerson. We will work to do it. Keep in mind we don't 
switch the breakers. We are not the ones trimming the trees, 
taking care of the vegetation management. That's still within 
the control areas of the utilities. We oversee the flows on the 
system. NERC has the standards on those tree trimmings and they 
are trying to expand that. We don't go out and actually 
physically do those things. We monitor and make sure the system 
is in a stable state.
    Senator Bingaman. Let me ask Mr. Harris if you see your 
role as also that sort of limited or conditioned, or your 
responsibility as conditioned in that same way, or do you think 
that as head of the PJM operation, you really do have the 
responsibility to be sure the trees are trimmed?
    Mr. Harris. Well, the overall reliability stops with us. We 
have an independent board. A fiduciary obligation of the board 
of PJM is to ensure we operate a safe and reliable electrical 
grid. And if we see maintenance practices, we see things that 
are affected the operations of the market, we would be 
obligated to move on that.
    Senator Bingaman. Ms. McCarren, let me ask you the same 
thing. You have a much more loose arrangement in the West. Does 
your Western Energy Coordinating Council feel that the buck 
stops with you if there is a blackout in your region?
    Ms. McCarren. I think we have to step forward and take 
responsibility. And we have to, under the current tools we 
have, do the best we can with enforcement. We have a 
contractual arrangement in place.
    With respect to vegetation management, we can certainly 
make improvements. We are working on those. With respect to our 
reliability coordinators which oversee or are above those 
control areas, we've got a lot of work to do. And it's a wakeup 
call what happened in the East. And yes, we have to step 
forward and take this responsibility. But it is a shared 
responsibility at this point with the control areas and the 
transmission owners and operators.
    Senator Bingaman. There is, in the bill that we have 
pending in the Senate calendar now, language that casts great 
doubt on FERC's authority to require the participation of 
utilities and RTOs. From what I'm hearing, that would be ill-
advised for us to limit FERC's authority to require that 
participation. Is that your view, Mr. Harris?
    Mr. Harris. Yes, sir, it is. Let me just say, you know, I 
have operated all over this Nation, out West, South for over 30 
years. And I have seen the value brought in through large 
regional organizations. You have got 4,000 different entities. 
Local needs to be met, regional differences need to be met, and 
umbrella organizations that have the responsibility and 
authority for reliability can do that. And it will add value.
    Senator Bingaman. All right. I will stop with that.
    Senator Thompson. Senator Schumer, you came a little late. 
Would you like to ask a question?
    Senator Schumer. Yes. Thank you. I thank you, Mr. Chairman. 
I appreciate it. I just have one question of the panel, and 
it's for Mr. Glotfelty. It follows up on what the chairman, 
Chairman Domenici, had asked.
    This is about superconductivity. You know, when I look at 
my area in New York City, our biggest problem is probably not 
new powerplants being built in upstate New York and the Hudson 
Valley, hydropower in Canada because we are going to need more 
power and I have been supportive of trying to do that, but it's 
rather transmission, getting the lines here, it's very crowded, 
it's hard to do. It holds things up.
    Superconductivity seemed to be our manna from heaven. To 
produce lines that allow three times, eight times, even 10 
times the amount of electricity to go through the same line is 
just a godsend, not only for New York but for any other crowded 
area that needs power.
    So I had worked actually with Senator Domenici, he 
representing Los Alamos, I representing one of the companies, 
IGC in Schenectady that is interested in this. Energy, and you, 
frankly, have been very supportive of these roles. Now because 
of earmarking the amount of money allowed to superconductivity 
has gone way down--and I am told by the people at both Los 
Alamos and IGC, this is not just going to slow this down, but 
you know, they are on the verge of many different important 
breakthroughs in terms of research. This could end it. So it's 
really penny-wise and pound-foolish to slow this.
    I spoke with Secretary Abraham. I don't know if he informed 
you of that, and said we have to find the money elsewhere and I 
was heartened to hear Senator Domenici say, ``Go find the 
money.'' Can you elaborate on what we can do? I mean, to say 
your hands are tied, none of these earmarks came out of this. I 
realize it wasn't Energy's doing, but Congress', they weren't 
from me. To say that there is nothing to do here because other 
things not related to superconductivity were earmarked out of 
this fund just doesn't answer the question in terms of our 
large, large energy needs down the road when we have a 
breakthrough technology that could work.
    So, could you elaborate a little more after hearing Senator 
Domenici say, I was told what he said. I was at another 
hearing, you know, that, ``go find the money.'' Your handcuffs 
are off, or go do--what can we do to help make that happen? 
What can the Energy Department do to find it? I'm sure in the 
huge budget you have, this is, I think we are only looking for 
something, you know, in the range of 15 or $20 million to 
restore that total fund back up to the $48 million that it was 
last year.
    What can we do here? Can you give us some ideas? We won't 
pin you down, but I just want to make sure that you are going 
to turn over every rock.
    Mr. Glotfelty. Let me assure you that we will. We in the 
administration are huge believers in the applicability, in the 
promise that superconductivity shows, not only in terms of 
transmission lines but other types of devices, motors, 
generators and other things that will save electricity, reduce 
environmental effects of producing electricity for decades to 
come.
    This has been a challenging year with the discretion that 
we have been afforded in terms of our budget. The actual real 
reduction in terms of dollars from last year to this year is 
only about $6 or $7 million. It is a much greater decrease from 
the President's request, which was $47 million, to the $32 
million that they have actually been allocated this year.
    I assure you as I have the chairman that we are trying to 
turn over every rock to put more dollars into this program. 
Your State is the beneficiary of two of the first deployments 
in Albany, as well as in Long Island.
    Senator Schumer. Right.
    Mr. Glotfelty. Where we would take superconducting tables 
and actually deploy them in the grid, and we do not want to 
delay those. We want those to go on as planned. I think this 
year we are going to have to get through, but I think in the 
future, it is incumbent upon Congress and the industry to help 
us achieve our success. Minimizing earmarks will allow to us 
get there.
    Senator Schumer. Right. Let me just say in response to what 
you said, with the Chair's indulgence, that I am told if we 
don't get some money this year, finding it some way or other, 
it's really going to slow progress dramatically in terms of the 
amount of money. Yes, it's $6 to $10 million, but that's in the 
total budget of about $12 or $13 million. And it really just, 
you know, you hire scientists. You hire workers. You fire them. 
You are not sure you are going to be able to get them back 
again.
    Mr. Glotfelty. I agree with you. The effects delay 
implementation of many of the technologies.
    Senator Schumer. All right. So are we going to try and look 
and find some money this year so maybe working with the 
chairman we can replenish you next year. You know, there must 
be some little pools of money that are not all going to be 
spent this year that were allocated?
    Mr. Glotfelty. I would like to work with you and our budget 
staff and the Appropriations staff to see if we can do that.
    Senator Schumer. Okay. I thank you. I appreciate that. 
Thank you, Mr. Chairman.
    Senator Thomas. Thank you, Senator. Let me ask one. You, I 
believe, led the investigation on the blackout and you are 
going to have a report soon.
    Did the interim report or will the final report have any 
legal conclusions about the cause of the blackout?
    Mr. Glotfelty. It will not. That is not our responsibility. 
That is a court's responsibility to draw legal conclusions.
    Senator Thomas. And I know it's hard to answer, but I guess 
I'd like to have some reaction. Do we have any agency, any 
group that you know of that's talking about the future for 
electric generation and transmission, talking about the 
capacity of transmission, whether it's new or increasing 
capacity, talking about the investment, who is going to be able 
to do that and how we do it, the best power source, are we 
going to continue to use gas, can we use coal, which requires 
more transmission.
    Are we going to have regional RTOs tied together with an 
interstate national theme. About the ownership of transmission, 
the benefit--those who benefit ought to pay and avoids regional 
monopolies which we have a little bit of right now.
    If those are some of the issues, do we have anyone dealing 
with those and where are we going to be in 10 or 15 years? Just 
anybody who feels like it. Let us have a little reaction.
    Mr. Harris. Senator, your observation is correct. There is 
tremendous asymmetry. In my initial comments, I mentioned 4,000 
different entities involved in generation, transmission and 
distribution of power in this nation. And it's huge and 
eclectic, and tremendous asymmetry between different parts of 
the regions that are moving at different paces.
    And in the Mid-Atlantic region, we have a planning protocol 
but the States insist to address all of those questions, but 
it's only for the ones that are underneath our footprint. 
However, we do have a council among all of the RTOs which 
covers about 60 percent of the interconnection, Eastern 
Interconnection. And in that we are putting together a regional 
planning protocol to look at everything underneath our 
footprint collectively, and to be able to address these long 
run issues as an RTO collective planning process.
    Senator Thomas. So you would do it more on a regional 
basis?
    Mr. Harris. And through our coordination with the other 
RTOs, we can share the data and come up with a plan to do it in 
that respect.
    Senator Thomas. I'm not aware of much coordination among 
the RTOs.
    Mr. Harris. As I mentioned, Senator, there is a lot of 
asymmetry in the development. It is--let's take time to get 
everything operational.
    Senator Thomas. Yes.
    Ms. McCarren. Senator, in the West, we are undertaking--
undertaking to develop a very close relationship among three 
key players in terms of planning and looking at all the issues 
you have raised.
    There is, as you may know, a group that was put together to 
look at the commercial side of all of these issues and that has 
an acronym. We also have a State regulator's group and we have 
the Western Governor's Association and we have the WECC.
    We are undertaking right now a detailed analysis of how we 
can work a lot more effectively together to address exactly the 
issues that you've described.
    Senator Thomas. Okay. Thank you. Yes, sir.
    Mr. Torgerson. Senator, we have in the Midwest ISO the 
organization of MISO States which are the State commissioners 
from every State that's in the Midwest ISO that have formed a 
group that we work with on planning issues, particularly. But 
not only planning but resource adequacy, generation adequacy 
within all--the entire area.
    And we've worked directly with them now where they provide 
not only input but help us come to decisions on things like--
beyond participant funding, or how do we define who the 
beneficiaries are and what cost mechanism could be put in place 
and this is being done in conjunction with all these State 
commissioners.
    We also have a joint operating agreement with Mr. Harris' 
firm, PJM. And part of that requires a joint planning activity 
between the two of them, our stakeholders from both our groups 
so we can start planning a longer term not just within our own 
areas but across the Midwest ISO and PJM.
    Senator Thomas. Good. Yes, sir.
    Mr. Glotfelty. Senator, my comments surround a process that 
we undertook as we were creating DOE's Office of Transmission 
and Distribution. We had two meetings that were attended by 
about 300 to 350 folks from the industry from consumers, 
consumer groups, environmental groups, municipals and co-ops as 
well.
    And we undertook an exercise to try to see what the grid 
and create a vision for what the grid might look like in 2030. 
And we created a document called Grid 2030, a subsequent 
document was a road map which systematically addressed the 
barriers that need to be broken down to achieve that vision. 
And I will be happy to get it to you and your staff if----
    Senator Thomas. Thank you very much.
    Mr. Gent.
    Mr. Gent. Senator Thomas, it sounds like you are forming 
the scope of the Department of Energy or one of the charges 
that I would hope that our U.S. Government would undertake. All 
of these issues are vital to the Nation and I think that Mr. 
Glotfelty has many of these issues on his platter.
    I would look for there to be a national solution first, and 
then a regional solution.
    Senator Thomas. I agree. And then I do think probably the 
Department has the responsibility to bring it together, but I 
don't want to be based on governmental decisions only. This 
ought to have private sector, both consumer/provider input and 
I'm sure that it will.
    Well, thank you all very much for being here. I hope that 
we can result in an energy bill that will help on this so much. 
If anyone has further questions on the committee within the 
next 24 hours, you may get some questions. So very well. 
Committee is adjourned. Thank you.
    [Whereupon, at 11:45 a.m., the hearing was adjourned.]


                                APPENDIX

                   Responses to Additional Questions

                              ----------                              

    Midwest Independent Transmission System Operator, Inc.,
                                        Carmel, IN, March 11, 2004.
Hon. Pete V. Domenici,
Chairman, Senate Committee on Energy and Natural Resources, Dirksen 
        Senate Office Building, Washington, DC.
    Dear Chairman Domenici: Thank you for the opportunity to testify 
before your committee at its February 24, 2004 hearing concerning the 
recommendations made by the North American Electric Reliability Council 
(``NERC'') in its report on the August 14, 2003 blackout. Set out below 
please find my responses to the follow-up questions contained in your 
letter to me of February 27, 2004.
              Responses to Questions From Senator Domenici
    Question 1. What steps has MISO taken after August 14 to ensure 
greater grid reliability?
    Answer. Prior to August 14, the Midwest ISO was in the process of 
upgrading and enhancing a variety of tools used to insure reliability. 
The blackout prompted an acceleration and expansion of these efforts. 
As described in more detail in the written testimony already submitted 
to the Committee, these steps include the following:

   Reliability Tools. As of December 31, 2003 our State 
        Estimator has served as our main reliability tool. This 
        comprehensive state-of-the-art computer system allows us to 
        gather real time information on the status of our system and 
        our neighboring systems. We have also expanded our capabilities 
        to run contingencies on our system so that we have already 
        modeled impacts on the grid if certain problems arise. We have 
        implemented software updates that allow us to sort the data 
        that we receive with more emphasis on the information with the 
        greatest potential for negative impact on the grid. Finally, we 
        have developed a backup system in case of problems with any of 
        our primary systems.
   Visualization Tools. We have improved our capacity to allow 
        visualization of the status of the grid by employees of the 
        Midwest ISO. We have more than doubled our video display areas 
        and have increased our ability to see the grid on a wider basis 
        and to visualize in great detail any identified problems.
   Training. We have participated in Emergency Drills and are 
        instituting a series of additional drills and training that 
        will be in place by June 30, 2004.
   Communications. We have worked with our members to clearly 
        identify communication protocols in time of system emergencies. 
        We have also increased communication of detailed information 
        with entities not members of the Midwest ISO and we utilize the 
        NERC system to communicate with other Reliability Coordinators.
   Operating Agreements. The Midwest ISO has developed a 
        Reliability Charter with our members to specifically delineate 
        roles and responsibilities. We have also developed a detailed 
        joint operating agreement with PJM to specifically delineate 
        the necessary coordination at our intertwined seam in the 
        Midwest.

    I should also point out that the Midwest ISO will meet or exceed 
all of the recommendations concerning our organization contained in 
NERC's report on the August 14 blackout.
    Question 2. How do you think the companies in your region will 
react to NERC's data collection? What will you do to ensure full 
cooperation?
    Answer. All of the companies in our region continue to hold 
reliability as the highest priority. As such, I believe that the 
companies in our region will fully comply with NERC's new data 
collection requests and the Midwest ISO will provide the necessary 
information and assistance to encourage them to do so.
    Question 3. The East Central Area Coordination Agreement contains a 
large number of control areas, most of them rather small compared to 
other regions of the country. Do you think this contributed to the 
communication failures of the August 14 blackout? Should reliability 
coordinators be more centralized--that is big, not small--so they can 
be well-equipped to deal with the coordination of the grid?
    Answer. The Midwest ISO believes that greater coordination among 
fewer areas will allow for more effective communications. On August 14, 
we believe the inability to accurately confirm the status of the grid, 
rather than the number of control areas in the East Central Area, most 
contributed to communication failures.
    The Midwest ISO has developed a Reliability Charter for all 
entities in our organization including those that participate in the 
East Central Area Coordination Agreement to clearly delineate specific 
roles and responsibilities in meeting our reliability goals. We will 
continue to work to insure the proper configuration of Control Areas. 
As noted in more detail in my testimony previously presented to the 
Committee, the Midwest ISO is now well equipped to deal with the 
coordination of the grid.
    Question 4. What are your thoughts on the application of a 
contractual compliance model in your regions?
    Answer. The Midwest ISO has not pursued a contractual compliance 
model with our members and I do not know if they would be willing to 
enter into such contracts. We believe the steps taken to improve 
reliability, as outlined in my testimony and in the answer to Question 
1 set out above, are the preferred methods to achieve this goal. As I 
also stated in my testimony, I believe the enactment of the enforceable 
reliability provisions contained in the Conference Report on H.R. 6 and 
in S. 2095 would go a long way to provide a more reliable bulk power 
system.
    Question 5. Do you think that companies in your region like First 
Energy were disproportionately blamed for the August 14 blackout?
    Answer. There is a legitimate public interest in determining the 
causes of the blackout of August 14 which resulted in disruptions and 
inconveniences for so many people. The event started in Northeast Ohio 
and the exact reasons why it spread so rapidly are still unknown. On 
the afternoon of August 14, the Midwest ISO was providing real time 
information to the Federal Government. It is possible that in giving 
the Government correct real time information that highlighted problems 
in First Energy's territory, we attracted scrutiny to their operations.

              Responses to Questions From Senator Campbell

    Question 1. Is another catastrophe such as we saw last summer 
likely to happen again without the intervention of Congress? And, if 
so, what is needed from Congress legislatively to ensure that the 
blackout that struck the Northeast and Midwest last summer is not 
repeated in other areas of the country?
    Answer. It is not realistic to totally eliminate any possibility of 
future blackouts but I believe the steps various Regional Transmission 
Organizations, NERC, individual companies along with Federal and State 
governments have undertaken will significantly reduce the likelihood of 
a reoccurrence and limit the extent of the problems caused by any 
reoccurrence. In terms of steps Congress could take to help avoid a 
recurrence of a large scale blackout, I would reiterate from my 
testimony already submitted to the Committee that the enactment of the 
electricity title of the pending energy bill would be a major step 
forward in providing a more updated and reliable transmission grid.
    Question 2. I certainly don't want my home state of Colorado's 
resources and consumers hit by these problems. Are certain regions of 
the country just more susceptible to blackouts, or do you think this 
sort of scenario is possible anywhere in the United Slates?
    Answer. Blackouts have occurred in different sets of circumstances 
since the 1960s, usually for different reasons each time, so it is 
difficult to say whether blackouts are more likely in any particular 
part of the country. However, the outages in the Western interconnect 
in the 1990s and the outage last summer each involved transmission 
lines coming into contact with trees. Vegetation management reviews 
across the country have been recommended by NERC to address this 
potential cause.
    Question 3. What specific authorities does NERC (North American 
Reliability Council) lack that contributed to the collapse of the 
Eastern power grid?
    Answer. The adoption of binding reliability standards by an 
electric reliability organization supervised by the FERC would fill an 
important gap in NERC's current authority. Mandatory reliability rules 
if adopted, and consistently interpreted and enforced will decrease the 
likelihood of another outage.
    Question 4. What costs, particularly to private consumers, might be 
associated with your proposed changes?
    Answer. The Midwest ISO has not quantified the costs of 
implementing the suggestions in the answer to question 3. However, the 
suggestions made would involve incremental work for NERC and the FERC. 
They would not require the creation of new institutions.

              Responses to Questions From Senator Landrieu

    Question 1. Since your respective organizations are responsible for 
short-term reliability and interregional coordination,what have your 
organizations done to date to prevent similar events that occurred on 
August 14 from re-occurring?
    Answer. The Midwest ISO has taken actions unique to itself and 
worked jointly with PJM on other arrangements as explained below. Prior 
to August 14, the Midwest ISO was in the process of upgrading and 
enhancing a variety of tools used to insure reliability. The blackout 
prompted an acceleration and expansion of these efforts. As described 
in more detail in the written testimony already submitted to the 
Committee, these steps include the following:

   Reliability. As of December 31, 2003 our State Estimator has 
        served as our main reliability tool. This comprehensive state-
        of-the-art computer system allows us to gather real time 
        information on the status of our system and our neighboring 
        systems. We have also expanded our capabilities to run 
        contingencies on our system so that we have already modeled 
        impacts on the grid if certain problems arise. We have 
        implemented software updates that allow us to sort the data 
        that we receive with more emphasis on the information with the 
        greatest potential for negative impact on the grid. Finally, we 
        have developed a backup system in case of problems with any of 
        our primary systems.
   Visualization Tools. We have improved our capacity to allow 
        visualization of the status of the grid by employees of the 
        Midwest ISO. We have more than doubled our video display areas 
        and have increased our ability to see the grid on a wider basis 
        and to visualize in great detail any identified problems.
   Training. We have participated in Emergency Drills and are 
        instituting a series of additional drills and training that 
        will be in place by June 30, 2004.
   Communications. We have worked with our members to clearly 
        identify communication protocols in time of system emergencies. 
        We have also increased communication of detailed information 
        with entities not members of the Midwest ISO and we utilize the 
        NERC system to communicate with other Reliability Coordinators.
   Operating Agreements. The Midwest ISO has developed a 
        Reliability Charter with our members to specifically delineate 
        roles and responsibilities. We have also developed a detailed 
        joint operating agreement with PJM to specifically delineate 
        the necessary coordination at our intertwined seam in the 
        Midwest.

    I should also point out that the Midwest ISO will meet or exceed 
all of the recommendations concerning our organization contained in 
NERC's report on the August 14 blackout.
    Question 2. Mr. Torgerson, can you provide a rough estimate for the 
following: (1) to date, total administrative costs for MISO; (2) the 
number of committees that have been formed under the organization, 
including stakeholder committees; (3) the number of ongoing FERC 
proceedings that the MISO is engaged in, and (4) the number of 
different technical systems required to operate the MISO on a daily 
basis?
    Answer. (1) MISO Administrative Costs--The Midwest ISO's costs of 
operations have sometimes been referred to in shorthand as the MISO's 
``administrative costs.'' The MISO provides reliability services, 
transmission tariff services, system planning and billing, settlements 
and revenue distribution services as its core functions. It performs 
certain services as a contractor to MAPPCOR for companies that are not 
MISO members located in the MAPP region. Those services are paid for at 
cost. The MISO's reliability coordinator coverage and its tariff area 
cover parts of 15 states and the province of Manitoba. The Midwest ISO 
provides transmission service to 164 tariff transmission customers. The 
Midwest ISO's costs for providing these services are recovered pursuant 
to a component of its tariff on file with the FERC, Schedule 10. 
Pursuant to this Schedule 10, the MISO has charged to and recovered 
from its customers approximately $74 million in 2002 (at an average 
rate of $0.130 per MWh), and $68 million in 2003 (at an average rate of 
$0.113 per MWh).
    A greater level of detail about MISO's financial position, 
including its costs of operation, is included in the Company's audited 
financial statements, copies of which accompany my response.* I would 
note that the Midwest ISO agreed as part of a settlement agreement with 
its transmission owning members to defer recovery of $25 million of 
costs incurred in 2003 until 2008. The other major cost we are not 
recovering currently is the expense of preparing to initiate the day 2 
congestion management, energy markets and financial transmission rights 
program.
---------------------------------------------------------------------------
    * The financial statements have been retained in committee files.
---------------------------------------------------------------------------
    (2) MISO Committees--When MISO was formed through the voluntary 
action of certain transmission owners in the Midwest, the founding 
members submitted a governance structure that had been developed with 
stakeholder input that insured the Midwest ISO would be independent of 
the transmission owners and likewise of any market participant. Mindful 
that the new organization could benefit from the views of the 
transmission owners and other stakeholders who contributed to the 
development of the MISO, five different committees were called for in 
the Company's organic documents. They are as follows:

                   The Advisory Committee
                   The Transmission Owners Committee
                   The Planning Advisory Committee
                   The Alternate Dispute Resolution Committee
                   The Nominating Committee

    The duties of each of these organizations appears in the Midwest 
ISO Agreement and the Company's By-laws. In their respective spheres 
these Committees provide a regular, formal manner for the MISO and its 
Board of Directors to get the considered advice of its members and 
stakeholders on issues important to the MISO's development and customer 
service.
    The Board of Directors has four committees, three of which have 
only Board members as participants and the fourth, the Nominating 
Committee, has two representatives from the Advisory Committee along 
with three Directors of the Board. The other committees are: the 
Finance and Audit Committee, the Human Resources Committee and the 
Markets Committee.
    The Advisory Committee has four subcommittees underneath it and 
more than 25 working groups or task forces. The Transmission Owners 
committee has three working groups that report to it. These groups 
cover technical issues as well as policy developments.
    (3) FERC Proceedings--The MISO is a party to 53 proceedings at the 
FERC that are still ongoing. I have left in the ongoing category any 
docket that a final order has not been issued in or where the time for 
rehearing has not yet run, or if requested has not been acted on by the 
Commission. These include 44 ``ER'' or Electric Rate Dockets and 
various ``EL'' or Electric Litigation dockets and one ``EC'' or 
Electric-corporate docket. As of March 2, 2004, the Midwest ISO had 
made 17 individual filings to FERC so far this calendar year.
    (4) MISO Technical Systems--The MISO depends on about 69 different 
technical systems to conduct its business on a daily basis. While, I am 
sure my engineers could subdivide each of them further, I think 
grouping the systems upon which the MISO depends into four areas might 
help in understanding them.
    The Midwest ISO relies on three major technical systems to operate 
on a daily basis: the ``EMS"; the billing and settlements system, and 
its communications system. Each has components or subsystems as well.
    The ``EMS'' or Energy Management System is the focus for MISO's 
basic core operations. It includes eight tools or computer programs 
systems that address the state of the grid. The systems that the 
reliability coordinators use to perform their functions are in this 
group and include: the State Estimator, which has an accompanying 
contingency analysis tool, the alarming tool, load forecasting, outage 
coordination and unit commitment. There are also three systems that the 
engineers use off-line for planning studies that relate to both the 
commercial uses of the system and reliability matters. To let our 
customers interact with us to purchase, reserve and schedule 
transmission service, the MISO operates an Open Access Same Time 
Information System (``OASIS'') site. The processes are then grouped in 
technical systems for OASIS automation, and electronic and physical 
scheduling. These systems are relied upon on a daily basis. Two 
additional technical systems archive the data generated from the 
applications I have just listed.
    The settlements system (for billing, invoicing and disbursement of 
revenue to the transmission owners) runs from three technical systems. 
This is a key part of our business; however, it is relied upon mostly 
at specific times of the month, e.g., 2 days after month end, 5 days 
after month end.
    Portions of the MISO's communications system link the MISO to the 
outside world, MISO operations to one another and MISO employees to one 
another and the outside world. Eleven technical systems are involved in 
performing these functions.
    The remainder of the technical systems are often remote from or 
even hidden from external view. They allow for development of WEB 
applications, corporate financial systems, basic desktop functions, 
computer network tools and applications, data base systems, server 
platforms and the cyber security systems related to virus protection, 
intrusion detection and digital certification.
    These systems are mirrored, duplicated for redundancy purposes or 
have alternative capabilities in our back-up center.
    Once again, thank you for the opportunity to provide this 
information to the Committee. If I can do anything to assist you in 
your tireless efforts to enact comprehensive energy legislation, please 
feel free to contact me.
    Sincerely,
                                        James P. Torgerson,
                                                 President and CEO.
                                 ______
                                 
                  Western Electricity Coordinating Council,
                                 Salt Lake City, UT, March 5, 2004.
Hon. Pete V. Domenici,
Chair, Senate Committee on Energy and Natural Resources, Hart Office 
        Building, Washington, DC.
    Dear Senator Domenici: Attached are WECC's responses to questions 
submitted by you and Senator Campbell after the February 24, 2004 
Senate hearing. Thank you for the opportunity to clarify these issues.
    Please feel free to call me if you have any additional questions.
    Sincerely,
                                           Louise McCarren,
                                           Chief Executive Officer.
[Attachments]

              Responses to Questions From Senator Domenici

    Question 1. Your testimony has indicated that the Western 
Interconnection should be treated almost as its own Electric 
Reliability Organization and the legislation provides for such 
delegation and deference. Why is this structure essential for the 
Western Interconnection?
    Answer. The Western Electricity Coordinating Council (``WECC'') has 
advocated, and continues to support, three important provisions in 
federal legislation.

          1.1.1. Electric Reliability Organization (``ERO'') delegation 
        authority to a conforming regional entity for proposing and 
        enforcing reliability standards.
          1.1.2. A ``Deference clause'' under which the ERO must 
        presume, subject to rebuttal, that a proposal from a regional 
        entity that is organized on an Interconnection-wide basis 
        encompassing its entire Interconnection is just, reasonable, 
        and not unduly discriminatory or preferential and in the public 
        interest.
          1.1.3. The creation of Regional Advisory Bodies to ensure an 
        appropriate role for states and provinces in the reliability 
        assurance process.

    This structure is essential because it provides for continent-wide 
standards to ensure appropriate outcomes, while recognizing individual 
differences to achieve those outcomes. It provides appropriate federal 
oversight while allowing management, implementation, and administration 
at a more local level. Significant regional differences should preclude 
a ``one-size-fits-all'' approach. Standards that are achievable by all 
entities within the nation may be less stringent than could be applied 
to, and are appropriate for, smaller regions. Further, the intent for 
regional flexibility and deference is to ensure that existing criteria 
that meet or exceed these national standards are preserved. For 
example: some Canadian entities have signed the WECC Reliability 
Management System Agreements, obligating them to pay sanctions for 
noncompliance if it occurs. National legislation, without similar 
Canadian and Provincial actions, will not provide similar results for 
these entities. However, as part of the Western Interconnection, these 
entities have a dramatic affect on its performance. Therefore, WECC is 
advocating for a structure that will preserve these benefits, while 
providing for national standards that must be met or exceeded.
    Further, providing this flexibility for an Interconnection poses 
little risk. The lack of alternating current connections with other 
regions, which defines regions such as the Western Interconnection and 
the Electric Reliability Council of Texas (``ERCOT''), virtually 
eliminates the ability for problems in one region to propagate into 
another. As previously mentioned, each Interconnection may have 
specific circumstances that require special criteria or consideration. 
For example: the Western Interconnection must recognize the special 
concerns associated with large load centers connected by limited 
transmission and supplied by generation located at great distance from 
this load. This situation is unlike that found in much of the Eastern 
Interconnection and requires special consideration to ensure reliable 
operation. Therefore, WECC must maintain the ability to develop 
criteria that meets or exceeds national standards while addressing 
legitimate differences found here.
    As a member of the North American Electric Reliability Council 
(``NERC''), WECC has contributed to the laudable goal of common 
continent-wide standards. However, the Western Interconnection is 
distinct from the Eastern Interconnection and ERCOT, and our peer 
reliability organizations have recognized this, and accepted 
modifications to some standards and procedures. As such, the pending 
legislation correctly recognizes that the Western Interconnection must 
have an important role in the development of reliability standards for 
the West.
    Question 2. I am interested in the contractual compliance aspects 
of the WECC. How detailed are the requirements in these contracts and 
how closely do they match NERC's rules? What kinds of penalties exist?
    Answer. The WECC's Reliability Management System (``RMS'') derives 
its sanctioning authority from the Western Electricity Coordinating 
Council Reliability Criteria Agreement (RMS Agreement). This is a 
contractual agreement among participants, signed by all participating 
in the RMS program. The document is available from the WECC website 
(www.wecc.biz) at the following link: http://www.wecc.biz/
committeeslJGC/CPTF/RMS/documents/index. html.
    Annex A of the RMS Agreement describes in detail each compliance 
criterion, and what is required for compliance. Development of the RMS 
criteria began with NERC policies and WECC criteria. Refinements were 
made to the RMS criteria during an evaluation process to verify that 
each criterion is clear, measurable, and enhances reliability. Some RMS 
criteria match NERC's standards (e.g. control performance standards 1 
and 2) very closely. Other standards (e.g. operating reserve) are not 
in the NERC standards, but closely match WECC criteria. All RMS 
criteria are as restrictive as or more restrictive than the NERC 
standards. Compliance with RMS criteria demonstrates that an entity has 
complied with similar NERC standards.
    Sanctions for violating RMS criteria range from a letter to the 
Chief Executive Officer for the least severe violation to a letter and 
monetary sanctions for the most severe incidents. Monetary sanctions 
are increased for repeat incidents of noncompliance during a particular 
compliance period (e.g. a month or quarter) and for repeat periods of 
noncompliance. The sanction for noncompliance with the disturbance 
control standard includes an increase in operating reserves rather than 
a monetary sanction. The amount of a sanction varies depending on the 
size of the entity that violated the criterion and the type of 
violation. Monetary sanctions have ranged from a thousand dollars to 
more than several hundred thousand dollars. However, this range does 
not represent the maximum dollar sanction that could occur.
    Question 3. Your written testimony indicates that a high percentage 
of the WECC control areas are members of Reliability Management System. 
Are there any large transmission owners that are not members and how do 
you deal with the lack of participation of all non-members?
    Answer. WECC members that are in the generation, transmission, 
distribution, or trading of electricity or the provision of elated 
energy services in the Western Interconnection must belong to member 
class 1, 2, or 3. Class 1 members own, control or operate more than 
1,000 circuit miles of transmission lines of 115 kV and higher within 
the Western Interconnection. Class 2 members own, control, or operate 
transmission or distribution lines, but not more than 1,000 circuit 
miles of transmission lines of 115 kV or greater, within the Western 
Interconnection. Class 3 members do not own, control or operate 
transmission or distribution lines in the Western Interconnection. This 
class includes power marketers, independent power producers, load-
serving entities and any other Entity whose primary business is the 
provision of energy services. WECC offers the following response within 
this context.
    There are six of WECC's 27 Class 1 members that are not signatories 
to the RMS Agreement. Three of these Class 1 members are control areas. 
In addition, while twenty-three of thirty-three WECC control areas are 
voluntary RMS participants, accounting for approximately 88 percent of 
the load and 81 percent of the generation in the WECC region, one 
control area operator is not a WECC member and is not an RMS signatory. 
However, the WECC staff continues to work with control areas and others 
who are not RMS participants to encourage their participation.
    Regardless, all entities that are not RMS signatories submit RMS 
data in accordance with a Board policy adopted in August 1999. The 
Board took the following actions with respect to the RMS and members 
that have not signed the RMS agreements.

   WECC will continue the collection of RMS data from those 
        members that have not signed the RMS agreements.
   WECC will continue to send late-data notices on a routine 
        basis to those members that have not provided the requested RMS 
        data within the requested time.
   WECC will continue sending noncompliance notification 
        letters to member organizations that experienced noncompliance 
        with respect to one or more of the RMS requirements. The 
        noncompliance notifications include a summary of the number and 
        severity of noncompliant events, and provide the dollar amount 
        of sanctions that would have been assessed if the RMS were 
        officially in place and the noncompliant organization had 
        signed the RMS agreements.

    The Board policy permits an entity to request that the RMS 
noncompliance notification letters be discontinued when those 
noncompliant members that have not signed the RMS agreements and have 
requested in writing that they not receive the noncompliance 
notifications. To date, four Control Areas and two other entities have 
exercised this option and requested discontinuance of RMS noncompliance 
notification letters.
    When considering the RMS it is critically important to involve and 
include generators and marketers as well. Further, while achieving 
these RMS contractual commitments is difficult, the RMS agreements are 
enforceable in both Canada and Mexico, once signed.
    Question 4. Please describe your vegetation management program and 
do you believe it can serve as a nationwide model?
    Answer. WECC has three different processes in place to monitor an 
organization's vegetation management program. The processes are:

          4.1.1. Annual certification through the RMS that owners of 
        transmission facilities are performing vegetation management 
        for the 40 major transmission paths (transmission paths which 
        are identified as being most significant for reliability in the 
        Western Interconnection). Each path owner(s) certifies that:

                   It has a vegetation management program in 
                its Transmission Maintenance and Inspection Plan 
                (``TMIP'');
                   It performs vegetation management in 
                accordance with its TMIP; and
                   It has records of its vegetation management 
                maintenance activities.

                  The WECC staff audits the RMS Participant's TMIP, 
                maintenance and inspection practices, and maintenance 
                records for the reasons listed below.

                   A disturbance report identifies maintenance 
                and inspection activities as a contributing factor in 
                the disturbance;
                   A recommendation by a Compliance Monitoring 
                Work Group (``CMWG'') team;
                   Incomplete annual certification; and
                   Random audit.

                  Failure to comply with the RMS criterion results in a 
                letter sanction and possibly monetary sanctions.

          4.1.2. A survey is conducted after each calendar quarter that 
        requires each owner of transmission lines 230 kV and above to 
        report the number of outages caused by vegetation. This survey 
        brings visibility that vegetation management is important. 
        Transmission owners are expected to improve their vegetation 
        management program when the number of vegetation management 
        related outages increase.
          4.1.3. CMWG teams review the operating practices for each 
        member including vegetation management. Control area operators 
        are reviewed once every three years. Other WECC members are 
        reviewed once every five years. If compliance with vegetation 
        management criteria is identified as a problem, the review team 
        can recommend that the WECC staff perform an RMS audit to 
        determine if the RMS transmission maintenance criterion has 
        been violated.

    The WECC program may serve as a template for a nationwide model. 
However, WECC intends to evaluate current efforts after thoroughly 
reviewing the August 14 event, with the intent of improving our current 
processes.
    Question 5. If Congress continues to be unable to pass 
comprehensive energy legislation that includes mandatory reliability 
rules, do you think that control areas in other parts of the country 
should follow the WECC contractual compliance model?
    Answer. The WECC RMS is a significant achievement and it works well 
when ``most''` or all entities within an interconnection participate. 
It has the advantage of being enforceable with entities operating 
outside the United States. However, it can be difficult to implement 
contracts because there are limited incentives for entities to 
participate. The lack of 100% participation by entities within the 
Western Interconnection, considering the considerable efforts of the 
WECC and its predecessor the Western Systems Coordinating Council, 
underscores this issue. However, these limitations notwithstanding, the 
RMS is an unprecedented success. It could be used in other regions with 
appropriate modifications to meet regional circumstances, presuming 
entities are willing to sign appropriate agreements.

              Responses to Questions From Senator Campbell

    Question 1. Is another catastrophe such as we saw last summer 
likely to happen again without the intervention of Congress? And, if 
so, what is needed from Congress legislatively to ensure that the 
blackout that struck the Northeast and Midwest last summer is not 
repeated in other areas of the country?
    Answer. Outages affecting the electric system are inevitable and we 
cannot ensure that outages will not be repeated in other areas of the 
country. Human error, equipment failure, and system operating 
conditions aggravated by adverse weather conditions are factors that 
can collectively result in widespread electric system outages. 
Operating policies and procedures are in place to reduce the likelihood 
of such occurrences and when they do occur, limit the geographic area 
affected and the duration of the outages. Compliance with reliability 
standards in planning, maintaining, and operating the electric system 
will significantly reduce the likelihood of outages like the one that 
occurred on August 14, 2003. Enactment of reliability legislation will 
provide needed support in enforcing compliance with reliability 
standards, (e.g. vegetation management, operator training and 
certification, analysis tools, etc.) further reducing the likelihood of 
such outages.
    However, such legislation does not address fundamental physical 
infrastructure problems such as the extreme difficulty in getting 
transmission additions permitted and sited, financial incentives for 
the construction of transmission additions, difficulties with State and 
Federal land management agencies concerning vegetation management and 
difficulties siting new facilities, etc. The current emphasis in the 
U.S. for competitive wholesale markets requires long distance energy 
transactions. Increases in these transactions, plus normal load growth, 
cannot be accommodated without transmission system expansion.
    Question 2. I certainly don't want my home state of Colorado's 
resources and consumers hit by these problems. Are certain regions of 
the country just more susceptible to blackouts, or do you think this 
sort of scenario is possible anywhere in the United States?
    Answer. Electric system outages are possible anywhere in the United 
States, and as the previous response suggests, this risk cannot be 
eliminated entirely. However, the enactment of reliability legislation 
will enhance enforcement of compliance with reliability standards, 
which can significantly reduce the likelihood, and geographic scope, of 
these outages. Considering the differences within the Western 
Interconnection compared to other interconnections that were previously 
mentioned, it is vitally important for this legislation to include the 
three important provisions currently in the proposed federal 
legislation of: delegation, deference, and a role for states and 
provinces.
    Question 3. What specific authorities does NERC (North American 
Electric Reliability Council) lack that contributed to the collapse of 
the Eastern power grid?
    Answer. WECC notes the following from NERC's testimony to the 
Senate:
    ``Congress can take one very important step to ensure we do not 
have a repeat of August 14. That step is to pass reliability 
legislation to make reliability rules mandatory and enforceable for all 
owners, operators, and users of the bulk power system.''
    Question 4. What costs, particularly to private consumers might be 
associated with your proposed changes?
    Answer. As your question suggests, operating the electric system 
reliably requires entities to incur costs. However, as the August 14, 
2003, event demonstrated, the costs of not operating reliably, are 
significant as well. WECC believes that compliance with existing 
standards is presently reflected in charges to consumers to the extent 
that entities have been successful in getting rates approved. A 
quantitative analysis of costs associated with modified criteria has 
not been performed, and cannot be performed before specific proposals 
are known, if then.
    However, new standards that may be identified from the August 14, 
2003, event analysis, must follow existing processes for development by 
WECC or NERC, respectively. In general terms, both the WECC and NERC 
standards development processes provide open and meaningful 
consideration of costs and benefits by all affected parties, including 
consumer representatives. Said differently; new Policies, Procedures, 
Standards, etc. that may be proposed must show benefit exceeding costs, 
and consider concerns expressed by consumer representatives. Therefore, 
while these cost impacts have not been quantified, the development 
process being followed should allow for a full assessment and 
consideration of these costs.
    Costs related to the addition of new facilities are even more 
difficult to estimate without specific proposals. Again, the processes 
that must be followed to receive approval to make these additions 
provides for identifying costs and allocating them using public 
processes, and in most cases, governmental oversight. These processes 
identify costs and provide discussion forums regarding those costs.
                                 ______
                                 
    [The following are responses of Michehl R. Gent, president 
and CEO, North American Electric Reliability Council.]

              Responses to Questions From Senator Domenici

    Question 1. A number of the recommendations recently approved by 
the NERC Board involve compliance audits. How does NERC plan to improve 
the audit process to ensure reliability readiness?
    Answer. NERC will institute a new readiness audit program for the 
reliability coordinators and control areas in North America. Previously 
such audits were done only for new control areas. Working with the 
regional reliability councils, NERC will audit all reliability 
coordinators and control areas in North America on a three-year cycle. 
Audits will include evaluation of reliability plans, procedures, 
processes, tools, personnel, and training. Audits will examine both 
written documentation and actual practices. Particular attention will 
be given to the deficiencies identified in the investigations of the 
August 14, 2003, blackout. The highest priority audits--of the largest 
control areas--will be completed by June 30, 2004. The reliability 
readiness audit process has already begun, with the completion of the 
first three site visits; other audits are scheduled on a regular basis. 
NERC will make the final audit reports available to regulators and the 
public to provide assurance that all responsible entities are capable 
of reliably operating the bulk electric system and that remediation 
plans are being implemented to address any deficiencies that are 
identified. FERC and other relevant regulatory agencies will be invited 
to participate in these audits.
    Question 2. Under S. 2095's reliability provisions, FERC will play 
an important oversight role in assuring reliability. What is FERC's 
role today in NERC's efforts to strengthen the current voluntary 
reliability regime?
    Answer. NERC will work closely with the Federal Energy Regulatory 
Commission to ensure compliance with reliability standards. FERC 
Chairman Patrick Wood attended the NERC Board of Trustees meeting on 
February 10, 2004, at which recommendations for strengthening the 
reliability of the bulk power grid were approved. The Chairman 
expressed his full support for NERC's actions to ensure that the 
existing system of voluntary compliance with reliability standards 
provides necessary protections for American electricity consumers. FERC 
has also announced its intention to provide vigilant oversight of 
NFRC's efforts to implement the blackout recommendations. FERC 
representatives will participate in the reliability readiness audits 
already initiated by NERC and the regional reliability councils and 
will also participate in the effort to strengthen NERC's compliance 
templates, which are used by the NERC compliance program to measure the 
performance of operating entities under the reliability rules.
    Question 3. NERC has said that it will be collecting information on 
violations of the voluntary rules. What will NERC do with this 
information and will FERC, or any other government agencies like the 
Department of Homeland Security, be involved in this data collection?
    Answer. NERC is implementing a new system that will require each 
regional reliability council to report to the NERC Compliance 
Enforcement Program within one month of the occurrence all significant 
violations of NERC operating policies and planning standards and 
regional standards. These confidential reports will contain details 
regarding the nature and potential reliability impacts of alleged 
violations and the identities of involved parties. Once the results of 
the investigation of a significant violation are received, NERC will 
require an offending organization to correct the violation within a 
specified period of time. If an offending organization is non-
responsive and continues to cause a risk to reliability, NERC may seek 
to remedy the violation by requesting the assistance of appropriate 
regulatory authorities.
    NERC will also receive from the regional reliability councils 
quarterly reports of all violations of NERC and regional reliability 
rules on a non-public basis.
    NERC intends to make the final results of investigations of 
significant compliance violations available to regulators and the 
public. NERC will also periodically provide aggregated reports of all 
violations to regulators and the public, with an indication of the 
nature and seriousness of the violations.
    Much of the data that NERC will have access to is subject to 
confidentiality agreements. Some of the data contains market-sensitive 
information. Some of the data relates to critical energy 
infrastructure, and as such, cannot be made public without placing the 
system at greater risk. Notwithstanding these constraints, NERC 
recognizes the need to make appropriate information about the level of 
compliance available to regulators and the public, in order to regain 
the public's trust and provide assurance that preserving the 
reliability of the bulk electric system is of paramount importance to 
NERC and to the electric industry as a whole. NERC has convened a task 
force to develop disclosure guidelines. I would be happy to provide the 
results of that task force work to the committee. NERC is working 
directly with FERC to address how reported information on violations is 
to be shared with the Commission.
    NERC works separately with the Department of Homeland Security 
(DHS) on critical infrastructure matters and serves as the electric 
sector coordinator and Information Sharing and Analysis Center. DHS 
will have access to information on violations where it is relevant to 
the protection of the electricity infrastructure.
    Question 4. How does NERC plan on assuring implementation of its 
recommendations to enhance the reliability of the bulk power system 
that were recently approved by the NERC Board?
    Answer. NERC is already in the process of implementing the board's 
recommendations that call for specific actions by NERC and the regional 
reliability councils. With respect to the near-term actions that 
FirstEnergy, PJM, and the Midwest Independent System Operator must take 
to remedy specific deficiencies before this summer, we have required 
the involved entities to certify to the board by no later than June 30, 
2004, that the required remedial actions have been completed. Each 
organization is further required to present a detailed plan for 
completing the identified actions to the NERC committees for technical 
review on March 23-24, and to the NERC-board for approval--no later 
than April 2, 2004. NERC has assigned experts to help these companies 
develop plans that adequately address the issues identified in the 
recommendations, and for any other remedial actions for which they 
require technical assistance.
    One NERC action item is to develop a tracking system to ensure that 
recommendations from investigation reports and audits are fully 
implemented. That system will include a regular reporting function to 
the board, the NERC stakeholder community, regulators, and the public 
on the progress being made to implement each of the recommendations.
    Question 5. The systems affected by the August 14, 2003 blackout 
were members of one of three Regional Reliability Councils--the East 
Central Area Coordination Agreement, the Mid-Atlantic Area Council and 
the Northeast Power Coordinating Council. Is it correct that each of 
these councils has their own reliability standards? Are such individual 
reliability council rules generally more or less stringent than NERC 
rules? Whose rules take precedent--the council's or NERC's?
    Answer. The East Central Area Coordination Agreement, the Mid-
Atlantic Area Council, and the Northeast Power Coordinating Council 
have reliability standards that complement and implement the NERC 
standards, as do the other regional reliability councils. A region may 
also have a standard on a subject not covered by a NERC standard. 
Regional standards may be more stringent than, but may not be 
inconsistent with or less stringent than, the NERC standards. Both sets 
of rules apply, and operators must comply with the more stringent one.
    Question 6. How does NERC interact with the states and with the 
regional transmission organizations?
    Answer. NERC interacts with the states and with regional 
transmission organizations in a variety of ways. Representatives of 
states and the RTOs are active participants in the various committees 
that carry out NERC's work. Both states and RTOs have representation on 
the NERC Stakeholders Committee, which elects the Board of Trustees and 
provides advice to the board on policy matters. State representatives 
make up one of the nine voting segments in the NERC procedure for 
voting on new reliability rules. RTOs participate in another of the 
nine voting segments.
    Question 7. The Congressional Budget Office estimates that spending 
by the electric reliability organization would total roughly $1.1 
billion between 2004-2013 and net revenues collected by the reliability 
organization would total $820 million over the same period. Do you 
agree with CBO's argument that the reliability organization's spending 
and revenues should be included in the federal budget?
    Answer. No. First, Section 1211(b) of S. 2095 specifies that the 
electric reliability organization certified by FERC and any regional 
entity that is delegated enforcement authority are not ``departments, 
agencies, or instrumentalities of the United States Government.'' Thus, 
it is unclear why any costs or revenues of the reliability 
organizations authorized by this legislation should be ``scored'' as 
revenues and costs of the federal government.
    Second, these reliability organizations are funded by electric 
industry participants and ultimately by customers and users of 
electricity. The ERO will have the authority to assess its members for 
all of its costs, and it will not be seeking any money from Congress. 
Under proposed new Federal Power Act section 215(c)(2)(B), the ERO must 
``allocate equitably reasonable dues, fees, and other charges among end 
users for all activities under this section.'' Therefore, the ERO's 
revenues should fully cover the amounts spent by the organization.
    As we understand it, it is only because the Congressional Budget 
Office uses a ``lost taxes'' methodology that there is any difference 
assumed for budgetary purposes between spending by the EERO and 
revenues received by the ERO. (As it has been explained to us, the 
``lost taxes'' methodology assumes that the collection annually of the 
fees to fund the reliability organizations will reduce economic 
activity, resulting in a 25% ``lost tax receipts'' cost to the Federal 
government because of the collection of such fees.) While we are not in 
a position to effectively challenge the budget scorekeeping rules, 
their application in this instance appears to produce a result that is 
inconsistent with how the non-profit ERO actually will operate, and 
that fails to account for the benefits that will result to the economy 
from assuring the greatest possible reliability of the electric grid. 
Avoiding a cascading outage of the magnitude of the August 14 outage 
and the economic dislocation it caused (estimated to be between $4 and 
$10 billion for that single event) is surely a substantial benefit that 
must be weighed against any costs of maintaining the reliability 
organizations.
    Question 8. What is NERC doing to involve these countries in 
implementing its recommendations to strengthen grid reliability?
    Answer. As you are aware, the interconnected grid does not take 
account of international boundaries. The United States has extensive 
interconnections with Canada, and a significant amount of trade in 
electricity goes on between the two countries. The physical grid 
operates to a common set of rules, and Canadian and U.S. interests 
participate together in all of NERC's activities. Our interconnections 
with Mexico are much more limited (confined to Baja California Norte, 
Mexico and isolated connections along the Texas/Mexican border), but we 
expect that activity to grow over the years, and Mexican participation 
in NERC's activities to grow commensurately.
    Three of the regional reliability councils--WECC, MAPP, and NPCC--
include systems in both the United States and Canada. The NERC board 
recommendations stemming from the August blackout are equally 
applicable on both sides of the international border, and will be 
implemented throughout the NERC regions. The full integration of 
Canadian participation into NERC and the regional councils makes this 
possible.
    Question 9. How will the ERO ensure that it will be an independent 
body that can act efficiently to deal with grid needs and potential 
violations?
    Answer. The reliability legislation requires that the entity that 
is certified by FERC as the electric reliability organization must have 
the ability to develop and enforce reliability standards that provide 
for an adequate level of reliability of the bulk power system. Another 
requirement for certification is that the entity must have established 
rules that ensure its independence from the users, owners, and 
operators of the bulk power system, while also assuring fair 
stakeholder representation in the selection of the directors of the ERO 
and balanced decisionmaking in any ERO committee or subordinate 
organizational structure. The legislation also contemplates that the 
ERO will have a secure funding base to support its activities. These 
provisions have been carefully crafted to assure both that the ERO will 
be independent, and also that it will be able to carry out its 
specialized reliability functions efficiently through the use of 
established industry expertise.

              Responses to Questions From Senator Campbell

    Question 1. Is another catastrophe such as we saw last summer 
likely to happen again without the intervention of Congress? And, if 
so, what is needed from Congress legislatively to ensure that the 
blackout that struck the Northeast and Midwest last summer is not 
repeated in other areas of the country?
    Answer. Large-scale blackouts are possible when operators of the 
system do not follow the established rules. The most effective means to 
reduce the chances of another widespread outage like the August 2003 
blackout is action by Congress to make reliability rules established by 
an ERO mandatory and enforceable for all users, owners, and operators 
of the bulk power grid. I believe that if the reliability legislation 
had been passed two years ago, we would not have had the August 14 
blackout. The reliability language included in the conference version 
of H.R. 6, and also in S. 2095, enjoys widespread support from all 
parts of the industry, as well as customers and regulators. The August 
blackout underscores the urgent need for Congress to enact reliability 
legislation this year.
    Question 2. I certainly don't want my home state of Colorado's 
resources and consumers hit by these problems. Are certain regions of 
the country just more susceptible to blackouts, or do you think this 
sort of scenario is possible anywhere in the United States?
    Answer. The potential for disruptions to the bulk power grid exists 
in all regions of the country. Widespread grid outages are rare, but 
are possible if there are multiple failures in the system of 
reliability safeguards.
    Both the current NERC reliability system and the reliability 
legislation acknowledge that regional differences may be reflected in 
reliability rules applicable within a given region. Under the current 
voluntary system, for example, the Western Electricity Coordinating 
Council (WECC) has established a voluntary, contract-based Reliability 
Management System, through which 23 control areas and 7 other 
transmission operators are contractually committed to comply with 
specific reliability criteria. The WECC Reliability Management System 
is designed specifically to address the needs and concerns of 
transmission users in the Western Interconnection. The system takes 
account of, and is often based on, NERC reliability criteria.
    Recognizing that there may be unique regional needs, the 
reliability legislation provides for delegation and deference to 
regional entities organized on an Interconnection-wide basis. 
Specifically, the legislation provides that, in reviewing reliability 
standards, the Federal Energy Regulatory Commission shall give due 
weight to the technical expertise of a regional entity organized on an 
Interconnection-wide basis with respect to a reliability standard to be 
applicable within that Interconnection. The legislation further creates 
a rebuttable presumption that a proposal to the ERO from a regional 
entity organized on an Interconnection-wide basis for a reliability 
standard that would be applicable on an Interconnection-wide basis is 
just, reasonable, and not unduly discriminatory or preferential, and in 
the public interest. Under the legislation, the ERC would be authorized 
to delegate authority to a regional entity for the purpose of proposing 
reliability standards to the ERO and enforcing reliability standards if 
the entity satisfies certain requirements set forth in the legislation 
for its governance, ability, and organization.
    Question 3. What specific authorities does NERC (North American 
Electric Reliability Council) lack that contributed to the collapse of 
the Eastern power grid?
    Answer. NERC has conducted a comprehensive investigation of the 
August 14 blackout, and has contributed to the U.S.-Canada Power System 
Outage Task Force's November 19, 2003, Interim Report identifying the 
root causes of the outage. From our investigation, we have concluded 
that some entities violated NERC operating policies and planning 
standards. The lack of NERC authority to enforce compliance with the 
reliability rules meant that there was no effective deterrent to these 
violations that ultimately contributed directly to the start of the 
cascading blackout.
    In addition to deterring violations through the possibility of 
sanctions, enforcement authority also is necessary to assure that the 
system is managed properly on a day-to-day basis. The blackout 
investigation revealed numerous failures in operations and 
communications practices. The existing process for monitoring and 
assuring compliance with NERC and regional reliability standards proved 
inadequate to identify and resolve specific compliance violations 
before those violations led to a cascading blackout. Deficiencies 
identified in investigations of prior large-scale blackouts in the 
areas of vegetation management, operator training, and use of tools to 
help operators better visualize system conditions were repeated. These 
are areas in which mandatory and enforceable rules could have made a 
substantial difference and where an enhanced enforcement process might 
have prevented the blackout from occurring.
    Question 4. What costs, particularly to private consumers might be 
associated with your proposed changes?
    Answer. The current voluntary reliability system is already funded 
by consumers, who pay approximately $50 million annually for 
reliability to NERC and its regional council members. In contrast, 
estimates of the cost of the August 14 blackout range from $4-$10 
billion. Put in this perspective, reasonable additional costs to 
consumers for supplying a more robust and mandatory reliability system 
would be a far wiser investment than leaving the system vulnerable to 
the unexpected and often excessive costs associated with a major power 
disruption.
               Response to Question From Senator Bingaman
    Question. There are a number of class action suits against 
companies involved in the blackout. Does the report draw any 
conclusions as to the legal liability of the defendants in these 
actions?
    Answer. Neither the interim report of the U.S.-Canada Task Force 
nor reports issued as the result of investigation of the blackout by 
NERC draw any conclusions regarding the legal liability of defendants 
in class action suits stemming from the August blackout. I would expect 
that conclusions as to legal liability would be the province of the 
court system.

              Responses to Questions From Senator Landrieu

    Question 1. It appears from your study that the deficiencies 
identified were not caused by insufficient transmission capacity in the 
affected areas, is that correct?
    Answer. That is correct. Insufficient transmission capacity was not 
identified as a specific cause of the August 14 blackout. NERC 
identified the following failures as leading to the August blackout: 1) 
some entities violated NERC operating procedures and planning 
standards, and those violations contributed directly to the start of 
the cascading blackout; 2) the existing process for monitoring and 
assuring compliance with NERC and regional reliability standards was 
inadequate to identify and resolve specific compliance violations 
before those violations led to a cascading blackout; 3) reliability 
coordinators and control areas have adopted differing interpretations 
of the functions, responsibilities, authorities, and capabilities 
needed to operate a reliable power system; 4) problems identified in 
studies of prior large-scale blackouts were repeated, including 
deficiencies in vegetation management, operator training, and tools to 
help operators better visualize system conditions; 5) in some regions, 
data used to model loads and generators were inaccurate due to a lack 
of verification through benchmarking with actual system data and field 
testing; 6) planning studies, design assumptions, and facilities 
ratings were not consistently shared and were not subject to adequate 
peer review among operating entities and regions; and 7) available 
system protection technologies were not consistently applied to 
optimize the ability to slow or stop an uncontrolled cascading failure 
of the power system.
    Question 2. Of the 530 plants that were involved in last summers 
blackout how many had ``black start'' capabilities? What ``black 
start'' technologies are available to help plants get back online more 
quickly after a blackout? If some of the plants had ``black start'' 
capabilities to get them up and running would there have been a benefit 
for the other plants?
    Answer. Restoring a system from a blackout is not just a question 
of restarting generating units. Restoration requires a very careful 
choreography of re-energizing transmission lines from generators that 
were still on-line inside the blacked-out area as well as from systems 
from outside the blacked-out area, restoring station power to the off-
line generating units so that they can be restarted, synchronizing 
those generators to the Interconnection, and then constantly balancing 
generation and demand as additional units and additional customers are 
restored to service.
    NERC requires that each operating entity have a black start plan 
along with a system restoration plan. The ability of the system 
operators to restore the grid and service to customer load was enhanced 
because the backbone 345 kV system in New York State remained energized 
and served by hydroelectric generation that remained on-line near the 
New York-Ontario border at Niagara Falls and St. Lawrence. The system 
operators used these generators plus the power that continued flowing 
from Hydro-Quebec to keep a part of the transmission system energized 
in northern New York, which provided the power needed to black start 
the off-line generators. This was a key to the overall restoration. Had 
that system not remained energized, operators would have called on the 
black start units that exist around the system.
    There are several hundred diesel-generating units installed in the 
SCAR, MAAC, and NPCC regions. Most of these units range from fractions 
of a megawatt to several megawatts in size. Many, but not all, of these 
units are located at plants involved in last summer's blackout. 
Hydroelectric generating units also provide black start capability, as 
do many combustion turbines.
    Question 3. If some of the plants had ``black start'' capabilities 
could other plants have been brought online more quickly because they 
could be powered up and more easily synchronized back into the grid?
    Answer. The restoration process following the August 14, 2003, 
blackout went very well, and NERC and its regions are completing a 
detailed investigation of the restoration process. That investigation 
will include the procedures used to black start off-line generators, 
and should provide valuable information to help us determine if 
additional black start generation is needed.
    Question 4. The black out caused the loss of tens of billions of 
dollars because manufacturing ceased. In addition, safety was 
endangered when sewage plants shut down and overflowed into rivers and 
gas ran low because refineries couldn't operate. Should these areas of 
critical infrastructure have there own capabilities to generate 
emergency power?
    Answer. NERC's responsibility is to develop and enforce standards 
to provide for the reliable operation of the bulk electric system. 
While public health and safety are of vital concern, NERC does not 
address black start capability for manufacturing facilities, sewage 
facilities, refineries, or other customers. Such facilities are served 
from local distribution systems and will have service restored in 
conjunction with overall system restoration priorities. Critical 
facilities such as hospitals commonly have emergency generators for 
when they lose power from the grid. Other asset owners would be in the 
best position to judge the relative costs and benefits of installing or 
increasing their own capabilities to generate emergency power.
    Question 5. Has NERC studied the idea of supplementing certain 
plants with mobile power generators that can by quickly moved from a 
plant where it supplies ``black start'' capabilities to the scene of 
natural disaster or terrorist attack to keep critical infrastructure 
running?
    Answer. NERC has not studied that issue. The results of the study 
described in answer to question 3 above may provide some insight on 
this question.
                                 ______
                                 
                              Department of Energy,
               Congressional and Intergovernmental Affairs,
                                    Washington, DC, April 23, 2004.
Hon. Pete V. Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate, 
        Washington, DC.
    Dear Mr. Chairman: On February 24, 2004, Jimmy Glotfelty, Director, 
Office of Electric Transmission and Distribution, testified regarding 
the reliability of the Nation's electricity grid.
    Enclosed are the answers to 22 questions that were submitted by 
you, Senators Campbell, Bingaman, Wyden and Landrieu to complete the 
hearing record.
    If we can be of further assistance, please have your staff contact 
our Congressional Hearing Coordinator, Lillian Owen, at (202) 586-2031.
            Sincerely,
                                          Rick A. Dearborn,
                                               Assistant Secretary.
[Enclosures]

              Responses to Questions From Senator Domenici

    Question 1. Do you think that NERC's compliance audit plan is 
sufficient and will it be effective?
    Answer. The compliance audit program is critical to effective 
monitoring and enforcement of reliability standards. It should be 
effective if the industry's funding for the North American Electric 
Reliability Council (NERC) and the regional councils is not dependent 
upon the companies subject to audit, if NERC and the regional councils 
make compliance audits a high priority, if NERC and the regions commit 
sufficient resources to the program, and if the teams are made up of 
experts from both within the industry and outside the industry.
    Question 2. What is DOE's role in strengthening the reliability of 
the grid and what has been accomplished so far in making the grid more 
reliable?
    Answer. DOE conducts R&D programs in critical areas related to grid 
reliability, provides analytic assistance to the Federal Energy 
Regulatory Commission (FERC), the States, and other organizations with 
an interest in reliability issues, and represents the Administration on 
grid-related questions. More specifically:

   We are developing a portfolio of technologies to enhance the 
        reliability and efficiency of the grid. High temperature 
        superconductivity, advanced conductors, electric storage, 
        distributed intelligence/smart controls, and power electronics 
        will form the building blocks of a modernized grid. This will 
        be complemented by projects in demand response and distributed 
        generation.
   We published the National Transmission Grid Study in May 
        2002, which identified a number of key transmission 
        bottlenecks.
   We have provided assistance to the states in the West, the 
        Midwest, and the Northeast in the development of regional 
        organizations to facilitate regional solutions to transmission-
        related policy problems.
   We have played a critical role in the activities of the 
        U.S.--Canada Power System Outage Task Force, and we will be 
        actively involved in responding to the Task Force's 
        recommendations for preventing future blackouts and minimizing 
        the scope of any that nonetheless occur.
   We have responded to the recommendations of the National 
        Energy Policy that direct the Secretary of Energy ``to work 
        with the Federal Energy Regulatory Commission (FERC) to improve 
        the reliability of the interstate transmission system and to 
        develop legislation providing for enforcement by a self-
        regulatory organization subject to FERC oversight'', and also 
        ``to authorize the Western Area Power Administration to explore 
        relieving the ``Path 15'' bottleneck through transmission 
        expansion financed by non-federal contributions.'' In these 
        areas, we supported the enactment of legislation to make 
        compliance with reliability standards mandatory and 
        enforceable, and we also coordinated arrangements for a project 
        to ease the Path 15 problem in California.
    Question 3. Do you think that restructuring in the electricity 
industry contributed to the August 14 Blackout?
    Answer. To date, the U.S.-Canada Power System Outage Task Force's 
investigation, which DOE has coordinated on behalf of the 
Administration, has found no particular linkage between the 
restructuring of the industry and the blackout. The Task Force 
concluded in the interim Report it issued in November 2003 that the 
August 14, 2003, blackout was caused by:

   An insufficiency of reactive power resources in the 
        Cleveland-Akron area;
   Inadequate situational awareness in FirstEnergy's control 
        room after its energy management system lost some critical 
        functions;
   Inadequate management by FirstEnergy of electrical 
        clearances for transmission lines in its right-of-way areas;
   Inadequate diagnostic assistance of FirstEnergy's problems 
        on August 14 by the Midwest Independent System Operator (MISO) 
        and PJM Interconnection (PJM).

    Question 4. The reliability provisions in the comprehensive energy 
bill obviously are critical to improving the reliability of the grid. 
The comprehensive energy bill also encourages greater investment in the 
transmission system through siting reform and pricing incentives. How 
important are these provisions to improving long-term grid reliability 
and you think there will be sufficient transmission capacity to meet 
demand?
    Answer. The provisions relating to transmission siting and grid-
related investments are extremely important for both the near term and 
the long term.
    As for the sufficiency of transmission capacity to meet demand, the 
first impact of limited transmission capacity will be higher retail 
electricity prices, due to reduced capacity of wholesale electricity 
buyers to reach distant low-cost suppliers. In other words, reliability 
would still be maintained but consumers would see higher prices. 
Eventually, of course, it could become difficult to meet demand 
reliably even using all nearby and high cost suppliers. The current 
reliability problems in southeast Connecticut are a good example.
    Question 5. I understand that grid reliability does not recognize 
international boundaries since both Canada and Mexico have transmission 
systems that are interconnected with our country's grid. How would you 
describe the current efforts by the DOE, FERC, and NERC to deal with 
this international aspect of reliability?
    Answer. The reliability of the North American electricity grid can 
be enhanced further through closer coordination and compatible 
regulatory and jurisdictional approaches. Each country needs to develop 
a mechanism for enforcing compliance with the standards by entities 
under its jurisdiction. Each country also needs to be confident that 
entities that are subject to the jurisdiction of a neighboring country 
will also be subject to compliance and enforcement requirements. NERC 
is a North American organization, and the reliability standards it 
develops are North American standards.
    If the Electricity Reliability Organization (ERO) is created with 
the passing of the comprehensive energy legislation currently before 
Congress, then the ERO will be capable of dealing with the 
international aspect of reliability. The ERO will be the international 
organization that will address cross-border electricity flows and 
reliability.

              Responses to Questions From Senator Campbell

    Question 1. Is another catastrophe such as we saw last summer 
likely to happen again without the intervention of Congress? And, if so 
what is needed from Congress legislatively to ensure that the blackout 
that struck the Northeast and Midwest last summer is not repeated in 
other areas of the country?
    Answer. The Task Force's Interim Report noted that many of the 
causes of the August 14, 2003, blackout are strikingly similar to 
causes of earlier blackouts in the U.S. We have reliability standards, 
but compliance with them needs to be mandatory and enforceable. It is 
critical that Congress make compliance with reliability standards 
mandatory and enforceable by passing comprehensive energy legislation 
that includes such reliability provisions.
    Question 2. I certainly don't want my home state of Colorado's 
resources and consumers hit by these problems. Are certain regions of 
the country just more susceptible to blackouts, or do you think this 
sort of scenario is possible anywhere in the United States?
    Answer. The U.S.-Canada Power System Outage Task Force Interim 
Report determined that the initiation of the August 14, 2003, blackout 
was caused by deficiencies in specific practices, equipment, and human 
decisions that coincided that afternoon. These factors include 
inadequate vegetation management; failure to ensure operation within 
secure limits; failure to identify emergency conditions and communicate 
that status to neighboring systems; inadequate operator training; and 
inadequate regional-scale visibility over the bulk power system. 
Although regions with frequent transmission congestion such as the 
Northeast may be at greater risk, this scenario is possible anywhere in 
the United States.
    Question 3. What specific authorities does NERC (North American 
Reliability Council) lack that contributed to the collapse of the 
Eastern power grid?
    Answer. NERC has no authority to enforce the standards that it 
presently develops or to assess penalties. Further, NERC is limited by 
its current legal status as a voluntary organization funded by its 
members. There is a need to establish a mechanism for funding NERC (or 
a future reliability Organization) and the regional reliability 
councils that is independent of the entities they oversee. Finally, 
NERC lacks authority to require all entities operating as part of the 
bulk power system to be members of the regional reliability council (or 
councils) for the regions in which they operate.
    Question 4. What costs, particularly to private consumers might be 
associated with your proposed changes?
    Answer. Prudent expenditures and investments to maintain or improve 
reliability would be recoverable through transmission rates, as they 
are today. The incremental expenditures and investments would be small 
in comparison to the cost of chronic or widespread blackouts.

               Response to Question From Senator Bingaman

    Question. There are a number of class action suits against 
companies involved in the blackout. Does the report draw any 
conclusions as to the legal liability of the defendants in these 
actions?
    Answer. The U.S.-Canada Power System Outage Task Force's mandate 
did not include reaching conclusions regarding legal liability of 
parties involved in the August 14, 2003, blackout.

               Responses to Questions From Senator Wyden

    Question 1. Are you familiar with the experiment of eliminating 
skilled operators at the ``Flat Iron'' facility in the Pacific 
Northwest region? Are you aware that there was a system failure which 
might have been prevented if full time operators had been present?
    Answer. I am not familiar with this matter; the Office of Electric 
Transmission and Distribution does not monitor the operation of 
hydroelectric power facilities.
    Question 2. Given this past experience, both on the East Coast and 
at the Flat Iron plant, wouldn't you agree that in many cases it pays 
to maintain trained operators on-site in the operation of electric 
power facilities?
    Answer. ``Trained'' operators were involved during the August 14, 
2003, blackout. However, the training was not adequate. Deficiencies in 
specific practices and human decisions contributed to the escalation of 
the problem. On-the-job training during daily operations is not 
sufficient to ensure reliability; emergency preparedness requires 
experience under realistic simulated emergency conditions. NERC 
recently recommended modifying personnel certification criteria to 
include emergency response training requirements and other 
qualifications necessary to assure reliable operations. While having 
trained operators on-site is usually good, BPA and other organizations 
believe that remote operation can be consistent with sound business 
practices.
    Question 3. If that is the case, then can you tell me why the Army 
Corps of Engineers and the Bureau of Reclamation have been pushing 
forward with proposals to ``remote operate'' many of the hydroelectric 
dams in the West?
    Answer. Since neither the Task Force nor the Office of Electric 
Transmission and Distribution address the operation of the 
hydroelectric dams in the West, I am unable to comment on the rationale 
behind the Army Corps of Engineers (Corps) and Bureau of Reclamation's 
(Reclamation) proposals. Questions regarding specific operational 
issues should be directed to the Corps and Reclamation directly since 
they are responsible for operating their respective hydroelectric 
projects in the West. However, I am informed by officials at the 
Bonneville Power Administration (Bonneville) who work jointly with the 
Corps and Reclamation in setting operating practices and performance 
expectations that several of the hydroelectric plants in the Northwest 
that Bonneville markets from are currently operated remotely and others 
are being considered for remote operation. I understand that Bonneville 
and its partners, the Corps and Reclamation, expect remote operation to 
be done in a manner that is consistent with industry practice and is 
compatible with contractual requirements as well as operational and 
reliability standards.
    Question 4. Wouldn't these proposals seem to directly ignore the 
lessons learned from the East Coast blackout and the Flat Iron 
incident?
    Answer. The August 2003, blackout focused attention on the 
vulnerabilities of our Nation's existing energy infrastructure. This 
and other events are proof that our increasingly complex and integrated 
world calls for a more responsive energy system. While maintaining 
reliability requires properly trained and skilled operators, it is also 
clear that the integration of advanced communications, control methods, 
and information technology is necessary to enable more effective use of 
electric system assets, optimized grid operations, and cost-effective 
economics.
    Question 5. I understand that the Army Corps is considering a 
proposal to ``remotely operate'' the John Day Dam from The Dalles Dam. 
The plan includes using microwave communications towers, which require 
a continuous ``line of sight''. If communications were interrupted for 
any reason, how long would it take for a senior operator to make it 
from the Dalles Dam to the John Day Dam to correct whatever operations 
errors might have occurred?
    Answer. I am informed by Bonneville that the Corps' John Day-The 
Dalles microwave system, scheduled to be operational later this fiscal 
year, will increase generation reliability with improved communication, 
greater redundancy and more operator flexibility. While either The 
Dalles powerhouse or John Day powerhouse will be able to provide 
supervision of the other powerhouse, on-site operators will staff both 
continuously. Microwave communications are routinely used for command 
and control of electric power systems. State-of-the-art of microwave 
communications is a highly reliable mechanism for interconnecting and 
controlling geographically distributed power facilities.
    Question 6. Do you understand the key role that the generation at 
John Day plays in maintaining the transfer capability and reliability 
of the transmission system? Due to John Day's proximity to the 
California-Oregon Intertie, a loss of generation at John Day would 
affect both exports and imports of electricity. In the case of failure 
at John Day, energy would have to be transmitted over greater 
distances. The further energy is transferred, the harder it is to 
maintain constant voltage on the transmission system, thus causing the 
system to be unstable and the higher the energy losses. Wouldn't you 
agree that this loss in revenue over a very short period of time would 
more than cover the added cost for retaining trained operators at the 
John Day on a 24-hour basis?
    Answer. The Office of Electric Transmission and Distribution's 
mission is to modernize and expand the electricity delivery system, 
with a focus on reliability. OETD is not involved in decisions 
affecting operation of specific generation facilities such as the John 
Day facility.
    Control area operators have primary responsibility for grid 
reliability. NERC policy mandates that all control areas shall operate 
so that instability, uncontrolled separation, or cascading outages do 
not occur. OETD assumes that, under any scenarios for John Day, the 
contractual and operational requirements for grid reliability would 
need to be met.
    I am informed by Bonneville that the value of any capital 
investment, including remote operation capability, is determined by 
analyzing the expected savings over time versus the cost to implement. 
Bonneville informs me that if remote operation is implemented 
consistent with the control area operator's reliability requirements, 
then no degradation of plant availability should occur, and the 
benefits should exceed the costs. In the case of John Day, I am further 
informed that the plant will have trained staff on-site even when the 
plant is remotely operated. The cost savings is achieved through the 
increased staffing flexibility associated with plants that have remote 
control capability.
    Question 7. Are you aware that experts within the Corps believe 
that there are structural problems at the John Day Dam and that some 
believe that the Dam may be at risk, and that the navigation locks 
themselves may be in danger? I understand that the Corps is already 
amending $8 million to address some of these concerns. Is that correct?
    Answer. Since neither the U.S.-Canada Power System Outage Task 
Force nor the Office of Electric Transmission and Distribution address 
the details of the operation of the hydroelectric dams in the West, I 
am unable to comment directly on the Army Corps of Engineers activities 
at the John Day Dam. However, I am informed by Bonneville that the 
Corps of Engineers has programmed $11.3 million to address structural 
problems on the navigation lock during FY 2004. I am told that the 
Corps, in briefings of Bonneville management, has assured Bonneville 
that independent reviews have found no evidence that the dam and 
powerhouse are at risk.
    Question 8. Isn't it true that the ``first response'' in the event 
of a crisis or structural incident at the Dam would be the 
responsibility of an experienced, trained and senior operator?
    Answer. I am informed by Bonneville that a Corps operator would 
provide a first response, whether on-site or remote. Again, I am told 
that both The Dalles and John Day powerhouses will continue to be 
staffed by trained and qualified operators.
    Question 9. Wouldn't you agree that remote operation of the John 
Day Dam isn't in the best interest of the region or the nation?
    Answer. I am informed by Bonneville that it is the Corps' intent 
that remote operation of any Corps facility will be done consistent 
with contractual and operational requirements for electric grid 
reliability. Additionally, I am told that the Corps, Reclamation and 
Bonneville expect to explore ways to deliver on these and other 
requirements in the most cost effective manner for the benefit of the 
electric ratepayer and the public.
    Question 10. Can you assure me that this proposal or a variation of 
it which will have this critical point of the Northwest power grid 
dependent upon remote control operation will not be pursued further?
    Answer. I am informed by Bonneville that this Corps-managed, John 
Day-The Dalles remote operation capability investment is scheduled to 
be operational by the end of July 2004. Bonneville informs me that this 
investment, when completed, will enhance system reliability and 
operational flexibility since it will provide for operation of either 
plant from the other (e.g. Corps operators could leave the control room 
at one project to attend to emergencies at the navigation lock or 
elsewhere in the powerhouse).

              Responses to Questions From Senator Landrieu

    Question 1. As you know, my region of the country has long enjoyed 
reliable and affordable electricity. Given what has happened to FERC 
approved PJM and MISO why should the Southeast embrace a totally 
deregulation market concept at this juncture?
    Answer. The U.S.-Canada Power System Outage Task Force's 
investigation has found no particular linkage between the restructuring 
of the industry and the blackout. The August 14 blackout was caused by:

   An insufficiency of reactive power resources in the 
        Cleveland-Akron area;
   Inadequate situational awareness in FirstEnergy's control 
        room after its energy management system lost some critical 
        functions;
   Inadequate management by FirstEnergy of electrical 
        clearances for transmission lines in its right-of-way areas;
   Inadequate diagnostic assistance of FirstEnergy's problems 
        on August 14, 2003, by MISO and PJM.

    The identified deficiencies in specific practices, equipment, and 
human decisions could have occurred anywhere in the United States, and 
are not indicative of any problems with a particular regulatory 
structure. Further, many of the causes of the August 14, 2003, blackout 
were similar to the causes of blackouts preceding restructuring of the 
electricity industry.
    Question 2. Does the Administration have a consistent position on 
the time-frame for implementation of the Standard Market Design?
    Answer. The incomplete transition to a restructured industry poses 
one of the greatest challenges facing the electricity system today. The 
transmission infrastructure is too vital to our Nation to leave in an 
extended state of uncertainty. Some components of the Standard Market 
Design are a high priority. For instance, the formation of regional 
transmission organizations (RTOs) offers tremendous benefits, and must 
be completed soon to meet regional challenges and maintain reliability. 
However, the Administration also acknowledges the need to be flexible 
to accommodate regional needs and differences. Therefore, it is very 
difficult to give an exact time-frame for implementation since 
timelines will vary region by region.