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