[Senate Hearing 107-851]
[From the U.S. Government Publishing Office]
S. Hrg. 107-851
STANDARD MARKET DESIGN NOPR
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HEARING
before the
COMMITTEE ON
ENERGY AND NATURAL RESOURCES
UNITED STATES SENATE
ONE HUNDRED SEVENTH CONGRESS
SECOND SESSION
TO RECEIVE TESTIMONY ON THE STANDARD MARKET DESIGN NOPR, AND ON SUCH
RELATED ISSUES AS THE CAPACITY OF LOAD SERVING ENTITIES TO RESERVE
SUFFICIENT TRANSMISSION TO MEET THEIR CONTRACTUAL AND STATUTORY
OBLIGATIONS TO SERVE, TRANSMISSION PRICING AND OTHER MATTERS DEALT WITH
IN THE NOPR
__________
SEPTEMBER 17, 2002
Printed for the use of the
Committee on Energy and Natural Resources
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COMMITTEE ON ENERGY AND NATURAL RESOURCES
JEFF BINGAMAN, New Mexico, Chairman
DANIEL K. AKAKA, Hawaii FRANK H. MURKOWSKI, Alaska
BYRON L. DORGAN, North Dakota PETE V. DOMENICI, New Mexico
BOB GRAHAM, Florida DON NICKLES, Oklahoma
RON WYDEN, Oregon LARRY E. CRAIG, Idaho
TIM JOHNSON, South Dakota BEN NIGHTHORSE CAMPBELL, Colorado
MARY L. LANDRIEU, Louisiana CRAIG THOMAS, Wyoming
EVAN BAYH, Indiana RICHARD C. SHELBY, Alabama
DIANNE FEINSTEIN, California CONRAD BURNS, Montana
CHARLES E. SCHUMER, New York JON KYL, Arizona
MARIA CANTWELL, Washington CHUCK HAGEL, Nebraska
THOMAS R. CARPER, Delaware GORDON SMITH, Oregon
Robert M. Simon, Staff Director
Sam E. Fowler, Chief Counsel
Brian P. Malnak, Republican Staff Director
James P. Beirne, Republican Chief Counsel
C O N T E N T S
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STATEMENTS
Page
Bingaman, Hon. Jeff, U.S. Senator from New Mexico................ 1
Burns, Hon. Conrad, U.S. Senator from Montana.................... 4
Cantwell, Hon. Maria, U.S. Senator from Washington............... 26
Craig, Hon. Larry E., U.S. Senator from Idaho.................... 3
Domenici, Hon. Pete V., U.S. Senator from New Mexico............. 35
Harvill, Terry S., Commissioner, Illinois Commerce Commission.... 58
Hockstetter, Sandra L., Chairman, Arkansas Public Service
Commission, Little Rock, AR.................................... 54
Kyl, Hon. Jon, U.S. Senator from Arizona......................... 25
Moler, Elizabeth A., Senior Vice President, Government Affairs
and Policy, Exelon Corporation, on Behalf of the Electric Power
Supply Association............................................. 72
Patton, Hon. Paul, Governor, Commonwealth of Kentucky............ 37
Popowsky, Sonny, Consumer Advocate of Pennsylvania............... 63
Showalter, Marilyn, Chairwoman, Washington State Utilities and
Transportation Commission...................................... 43
Smith, Hon. Gordon, U.S. Senator from Oregon..................... 30
Sterba, Jeffry E., Chairman, President and CEO, PNM Resources,
Inc., on Behalf of the Edison Electric Institute............... 90
Thilly, Roy, Chairman, Transmission Access Policy Study Group.... 83
Thomas, Hon. Craig, U.S. Senator from Wyoming.................... 2
Tiencken, John, Jr., President and CEO, South Carolina Public
Service Authority, on Behalf of the Large Public Power Council. 77
Western Governors' Association................................... 18
Wood, Pat III, Chairman, Federal Energy Regulatory Commission.... 5
Wyden, Hon. Ron, U.S. Senator from Oregon........................ 2
APPENDIXES
Appendix I
Responses to additional questions................................ 101
Appendix II
Additional material submitted for the record..................... 117
STANDARD MARKET DESIGN NOPR
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TUESDAY, SEPTEMBER 17, 2002
U.S. Senate,
Committee on Energy and Natural Resources,
Washington, DC.
The committee met, pursuant to notice, at 9:36 a.m. in room
SD-106, Dirksen Senate Office Building, Hon. Jeff Bingaman,
chairman, presiding.
OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW
MEXICO
The Chairman. Why don't we start the hearing. This morning
we are conducting a hearing on FERC's proposed rule on standard
market design. I think it is fair to say that this is the most
far-reaching rulemaking that the Commission has ever
undertaken. It comes at a time when we are part-way through a
transition from an electricity industry that depended entirely
on monopoly suppliers whose rates and virtually all decisions
were regulated, to a future where competitive markets can be
depended upon to supply plentiful, low cost and clean electric
power.
It is no accident that the Congress at this time is also
trying to come to terms with this set of issues, at least the
broad issues in a comprehensive energy bill that includes a
far-reaching electricity title. Electricity markets have
clearly not worked well in all respects over the last few
years. We are at a time of seeming price stability right now,
but not long ago we were confronted with spiraling prices for
electricity and natural gas in the West, followed by a period
of discovery that markets had been dysfunctional, and had been
manipulated to produce many of those high prices.
Currently, stock prices are so low for electricity
companies that many predict that needed generation and
transmission will not be built as originally scheduled. It is
clear to me that both Congress and the Commission need to act
to restore stability to the markets, to provide the framework
for a workable electricity industry. This rule is a very major
effort by the Commission to accomplish that.
I have many questions about how it will work. I am not
completely convinced that the Commission has the right answers
to each of the questions that I have heard, but I do believe
that it is headed in the right direction, in that it recognizes
we need to have stable regional market institutions that are
independent from manipulation by market participants. This rule
should, when all the questions are answered, go a long way
toward restoring confidence of both the public and investors in
the markets that we depend upon as the cornerstone of our
economy.
We have a very distinguished group of witnesses today, and
let me call on my colleagues on the Republican side to see if
there is an opening statement there. I wanted to avoid opening
statements by all members at this point, but if one--Senator
Thomas, I know, had intended to do a short statement, and we
will certainly put all other statements in the record.
Senator Craig. Mine is a short one.
The Chairman. Okay, Senator Craig indicated a desire to
make a short statement as well. Why don't we go with Senator
Thomas. You were here first, and make whatever statement you
would like.
STATEMENT OF HON. CRAIG THOMAS, U.S. SENATOR
FROM WYOMING
Senator Thomas. Thank you, Mr. Chairman. Welcome, Chairman
Wood. I think it is important to have this hearing today. The
subject of the hearing, and the subject of some of FERC'S
orders here are useful, but I think the timing is bad, as our
chairman already pointed out. You know we are in the middle of
an energy conference, and I think the time and emphasis ought
to be on that at the moment, and to send that bill to the
President so that we have a good energy bill.
The timing also seems to be an issue--you know, we have
passed a bill with an energy title. We have worked hard there.
I think the FERC's order here and the FERC's issues are
incredibly complex, 600 pages, I think, so it seems to me
frankly the timing is wrong. I agree with the concepts that are
there. I agree we need to do something to change wholesale
transmission, there is no question about that, but I also know
that Wyoming, Utah, and the Northwest have spent millions of
dollars in developing an RTO in response to your Order 2000,
and this is underway.
I think the rulemaking that is being suggested here will
just make it much more difficult, and they will have to start
back over much of what they have already done. As I mentioned,
I agree with the concepts. I think we have to have regional
organizations. I am in favor of a third party operator.
But this is a long term kind of a thing, and we are moving
step by step, and I think we are making some progress over here
in the conference committee, and I guess I just have to say
that I believe it is inappropriate now for us to try and
implement the standard marketing procedures, so I hope that we
can take some of the concepts, we can move forward and have
more time to take a good look at it.
So I look forward to the witnesses, Mr. Chairman. Thank
you.
The Chairman. Thank you very much. Senator Wyden indicated
a desire to make a short statement in addition, so we will
certainly permit that.
STATEMENT OF HON. RON WYDEN, U.S. SENATOR
FROM OREGON
Senator Wyden. Thank you, Mr. Chairman. I will be brief.
Mr. Chairman, the agency proposal, FERC's proposal to have a
national safety net bid cap of $1,000 per megawatt hour is very
troubling to me, because it is potentially devastating to the
Northwest's economy. It would be way above current market rates
in our region, and it would be four times higher than the
current $250 per megawatt hour bid cap that is now in effect
throughout the Northwest. Northwest ratepayers and businesses
are still paying bills from when electricity prices went into
the stratosphere 2 years ago, but to date, the agency still has
not ordered refunds or brought a single enforcement case
against any of the companies that have been responsible for
gouging the west coast consumers. If FERC has not completed
their investigation of west coast market manipulation, how can
the agency possibly know what the problems are and how to fix
them?
Finally, Mr. Chairman and colleagues, judging from FERC's
new standard market design proposal, it seems questionable
whether the agency has learned anything about how west coast
markets work from their inquiry. Basically the agency is trying
to force a huge Western transmission grid to follow a one-size-
fits-all transmission approach that was developed specifically
for geographically small and tight power pools on the east
coast.
Mr. Chairman, we very much appreciate your holding these
hearings. There are of enormous importance to west coast
ratepayers, and I look forward to working with you.
The Chairman. Thank you very much.
Senator Craig, did you wish to make a statement?
STATEMENT OF HON. LARRY E. CRAIG, U.S. SENATOR
FROM IDAHO
Senator Craig. Thank you, Mr. Chairman. I do appreciate an
opportunity. I will be very short.
Chairman Wood, you have heard from one of my colleagues
from the Pacific Northwest and he has echoed a portion of my
concern about what the Commission is trying to do to craft a
market design that works for our region. Now, we have had a
good working relationship, and I assume that we will continue
to have that as you seek to find ways to improve how we market
energy in this country.
So what I am about to say is a good faith offer to work
with you I hope in a very open-minded way to understand the
uniquenesses of the regions of our country, and especially the
Pacific Northwest that the Senator from Oregon and I represent,
but to accommodate those needs you best need to understand what
our consumers, our States, and our neighboring States are
about,and what we intend to fully protect, so what I would like
to hear from you, Pat, is a positive response to an offer to
work cooperatively, because frankly, what I have been hearing
and reading is nothing but negatives about the commission's
proposal for a new standard market design.
My staff, on the other hand, believes there may be a way
out of what I term as a mess, but many serious questions about
the proposals that you have before you I think have to be
brought out. I am willing to work cooperatively with you to do
so.
Now, unless I am persuaded that you and your colleagues
intend to satisfactorily answer the concerns that are reflected
within the regions of our country, and I am going to provide
you with a complete list, or as complete as I can get at the
moment, following this hearing, then I must tell you that I
will work in every way to bring down your effort. I said I
would be brief and to the point, and I am not quite sure I know
how to be anything other than that, but what I see is not what
I like, nor do I believe it fits the needs of our region and
the dynamics that we have worked for decades to create within
that region.
I do not want to create a new design for the country to
deregulate and reregulate in a centralized Federal position
that I think is detrimental to the consumers. The Federal
Energy Regulatory Commission exists to protect, to promote the
interests of consumers in each and every region of the country.
That is your calling. That is your responsibility, The
Chairman. I am not quite sure that I can see that in your
current proposal, so I am anxious to hear your comments today.
Thank you. Thank you, Mr. Chairman.
The Chairman. Thank you very much. Senator Burns, did you
wish to make a statement?
Senator Burns. I'll just enter my statement for the record
and yield to the desires of the chairman.
[The prepared statement of Senator Burns follows:]
Prepared Statement of Hon. Conrad Burns, U.S. Senator From Montana
I have said many times that this country's energy future depends on
our ability to move power from one place to another. Transmission
matters, and I believe the FERC is well-intentioned in its recent
Notice of Proposed Rulemaking. However, I am not yet sure whether the
proposed Standard Market Design (SMD) will serve to add stability to
the electricity markets or not.
We all watched the out of control electricity markets in the summer
of 2000, which affected California most deeply but had a big spillover
effect into the Northwest and into Montana. None of us want to see that
happen again. There are many theories about how to correct our energy
markets, the most primary solution being more generation capacity. In
addition to generation, it is no secret we need more and better
transmission capability to move the newly generated power to the areas
of high demand.
One of the biggest barriers to new transmission has been
unwillingness to finance these large and expensive undertakings with so
much uncertainty in the marketplace.
In my home State of Montana, we have a wide variety of power
customers, producers, and providers. When I ask folks across the state
for their opinions on the SMD I get a lot of different answers. The
only sure thing is how unsure people are about the proposal.
Montana is a large power producing state, primarily hydro and coal-
fired plants. Some of these are privately held, and some of the hydro
is part of public power systems, both BPA and WAPA. The customers of
those facility range from direct service industries, such as Columbia
Falls Aluminum Company, and co-ops who serve families and businesses
from one side of the state to the other.
The question the Montana State Public Service Commission asks is,
how are we assured that a new entity's taking over some of its
responsibilities will result in better policy for Montana? Who does
this ITP which is suddenly and ideally in place report to? Who does it
serve, besides an idealistic view of the perfect market?
I would like to believe that the system for pricing and
distributing transmission rights FERC has proposed will increase
efficiency, market certainty, and market confidence. But I am not sure
that is the case. We need to be sure that the SMD recognizes the
differences between power markets in different parts of the country.
Like it or not, the Northwest is different than the east coast. We have
fewer people, more space, and largely hydro-based systems. The
successful example of PJM that is used as the model for the SMD is none
of these. I understand there are problems to fix, but we need to fix
these problems without creating new ones.
In my mind, it appears we are taking a cookie cutter and imposing
new and uncertain conditions on top of models that work pretty well.
BPA may not be perfect, but as an Administration it has worked well
with local interests and been responsive when I've had concerns. BPA
regularly enters into 20 year contracts with customers who seek a low-
risk strategy . . . what happens to these contracts if SMD is put in
place? We are adding new risk where it didn't exist before to some of
these customers, and that is a big concern to me.
In my mind we need to move forward with a way to improve wholesale
markets and transmission incentives, and I am glad the FERC had
recognized that as a primary goal. But we also need to be realistic
about the timeline for this effort, and recognize the regional
differences in energy markets.
The Chairman. Well, we appreciate that, and we will move
right ahead with our witnesses at this point, and our first
witness, of course, is Hon. Pat Wood, who is the Chairman of
the Federal Energy Regulatory Commission, and we are very
pleased to have you here, and why don't you go ahead with your
testimony and explain to us why this is a good thing to be
doing.
STATEMENT OF PAT WOOD III, CHAIRMAN, FEDERAL ENERGY REGULATORY
COMMISSION
Mr. Wood. Thank you, Mr. Chairman, members of the
committee. My colleagues and I welcome your attention to this
important issue of the Nation's interstate wholesale power
system. It has certainly been at the forefront of this
committee's agenda, and of our Commission's agenda since I came
on the Commission last summer in the aftermath of 18 months of
an unruly and inefficient market that left a lot of customers
harmed.
The current system in the country suffers from a set of
rules and institutions that are inconsistent, gameable, and
inefficient. The Commission has diagnosed this problem not just
in the past 10 months that we have been engaged in this public
effort, but in its analysis of the issue related to California
markets 2 years ago.
Today's range of half-developed markets simply does not
support the policy framework that this Congress adopted in
1992, or reflect the needs of the modern customer. To continue
with the system that produced the catastrophic failure in the
Western markets in 2000 and 2001 would be unconscionable. That
is why, since last summer, my colleagues and I began an effort
to assess the best practices of markets around the world, power
markets and other commodity markets in an attempt to bring some
order to the slow in starting development of our regional power
markets here in the United States.
Following the most public advance consultation in our
agency's history, which continues today, in July our
Commission, two Republicans, two Democrats, acting unanimously,
proposed a rule that encompasses what we have learned. It is a
broad but flexible initiative that will remedy discrimination
on the transmission grid and will serve customers across the
country through efficient and tried market-based processes.
It is a proposal. It is our first synthesis of all that we
have learned in this public process for the last 10 months.
There are people who do not agree with specific aspects of it.
That happens in comprehensive solutions to problems. But our
proposal is out there for comment.
We recently extended the comment period so that people can
provide better ideas, better solutions along the lines Senator
Craig mentioned, a more effective way of synthesizing all these
proposals as they are looked at collectively, and that is what
we plan to spend the forthcoming months doing, and I look
forward to reporting back to the committee at the appropriate
interval to update you on what we are hearing and learning.
Wholesale markets are here today. The fact is that all
Americans depend on wholesale competition for electric power
whether they know it or not. Even with today's flawed markets,
the current national policy of wholesale markets, begun in 1992
by this Congress, has yielded significant savings to customers.
Our job at the Commission, like it was for the natural gas
industry, is to make wholesale energy markets work.
Note that I did not address retail competition. That is a
State decision, and I believe that all customers depend on a
competitive wholesale market to work first, regardless of their
State government's choice as to retail customer choice or not.
The last decade taught us all too clearly that wholesale
power markets will work for customers only if there is
sufficient infrastructure, balanced market rules, and vigilant
oversight of those energy markets. Solving these three main
problems has been the task of our Commission for the past year.
Over that past year, we have spoken to a wide array of experts,
of business people, of customers, of other interested parties
about the most appropriate way to move this agenda forward.
Based on all that we have heard, it is clear to us that the
need to act decisively is imminent, and is now, and we need to
address the problems in the rules and institutions and
oversight capabilities that have plagued the Nation's power
markets.
I believe our proposal will work well in every region of
the country. Importantly, it anticipates significant regional
variation to accommodate different needs in different places.
Regions would determine how to do resource planning, how to
define the associated methods and standards, how to define and
allocate transmission rights, how to plan transmission and
other infrastructure, and how to adopt local marginal pricing
in short-term markets for their specific resource mixes.
State-appointed representatives would be the principal
decisionmakers on these issues for their own regions. I
acknowledged in my testimony that perhaps while the energy bill
is open there is an opportunity to actually codify or empower
that these regionally oriented State-appointed bodies would
have some additional powers that may not exist today.
I have heard that from my State colleagues, that perhaps
there is a promise of advisory commissions, but what does that
mean? I am more than happy to work with States and with the
committee and the conference committee on any language that may
make that important--because in fact these are regional
markets. What began as a very local industry a century ago, and
even in the 1935 act, which is the Federal Power Act that we
implement today, has evolved significantly, principally due to
the 1992 amendments to the act, into a regional type industry.
We can roughly group the regions in different manners, but
there are four to five large regional markets in the United
States, and another couple in Canada, a couple in Mexico, so
there are regional markets on this continent that do not
respect the neat State boundary that we celebrate today on
Constitution Day. These regional entities that are kind of slow
to take form, but are very important to the long-term solutions
of power markets and energy markets are the solution, but
they're not really that clearly codified in the statute, and I
would certainly be glad to work on that issue. I know that time
is imminent.
We are thoroughly evaluating specific proposals from a
number of regions. We anticipate acting on the RTO West filing
tomorrow. It is, as the Senator pointed out, a filing that a
number of parties have been working on together for a couple of
years, and I anticipate that that will, in fact, not start
over, but in fact has advanced the overall solutions for the
country. I think what I have shared with the Northwest Caucus
in fact on the House side a month or two ago is that the RTO
West filing in fact was so comprehensive that it informed what
the commission ought to do for the rest of the country.
There are differences, as Senator Craig pointed out, in the
hydropower-based system. We acknowledge that, look forward to
working that further, but we anticipate that the existing
filings that people have been working on for the past 3 years
in compliance with the FERC's 1999 order encouraging regional
transmission organizations will, in fact, be the laboratories
of learning that we use to understand what regional differences
mean.
These problems that we aim to solve vary by region. In the
Southeast, for example, there have been case after case of
interconnection disputes, of claims of transmission
discrimination against smaller customers, against new
generators, and there is also a phenomenon where some new gas-
fired generators were being built far from load, and there is
no system to fairly assign the costs of that to the people who
caused them.
A regional transmission organization, administering region-
wide rules, would have solved these problems. However, in this
region the voluntary approach to the formation of RTO's has
failed, and has resulted in rules and institutions that are not
suited for today's growing environment. Customers in the
Southeast need an active FERC working closely with the State
commissioners as colleagues to modernize the rules and
institutions.
There is a belief that under our proposal cheap power in
the South and also in the West would flee to other regions, but
in fact, studies show otherwise. With competition, the
opportunities for efficient and new technology bring down the
overall cost for all. Nothing prevents entities anywhere, of
course, from buying and locking in cheap power today.
In the Midwest, by contrast, inconsistent rules, low levels
of transmission investment, and the lack of a congestion
management system to resolve that lack of investment have led
to some reliability near-misses, balkanized markets, and higher
prices than necessary in local regions. There is deep and
strong support for active regional transmission organizations
and standardized rules in the Midwest, and an interest in an
active FERC working with the State commissions and regional
organizations to make their markets work.
In the Northeast, the markets have been organized for the
longest period of time. They have worked quite well, but
require continual evolution to improve their designs. They are
not only enjoying the lower prices brought by competition, they
are beginning to see technological innovation as prices by
location and a transparent market have broken down barriers for
the participation of new energy providers, and demand side
resources.
Regional planning is going on, but as we see across the
country local issues are of overriding concern, particularly in
the State of Connecticut. The Northeast needs an active FERC to
facilitate the continued evolution of the market and to resolve
the issues that exist between the Northeast, Canada, the
Northeast and the Mid-Atlantic and other parts of the country.
In the West, we have all learned what happens when resource
planning is not performed, and what the risks are if market
power is not addressed up front. California's primary problem
was its reliance on the spot market. Our proposed rule relies
on long-term contracts entered into between buyers and sellers,
and is therefore fundamentally different from the California
experience.
There is a different history of how trade was performed and
transmission was planned in the West, and at least some market
design implications for the significant reliance on the
hydropower in the Pacific Northwest. Customers in the West want
clear rules that provide a stable climate for investment.
After-the-fact refunds must be replaced by automatic market
power mitigation rules that are clear and announced up front,
that are focused on times and places when we do not have
sufficient competition. FERC must work with regional
institutions and State officials to develop a seamless market
that is free from manipulation, that fully accommodates any
true physical differences between the West and the East.
Western customers require consistent rules and market power
mitigation that apply up front automatically, rather than the
political and legal in-fighting that we are living through at
the commission today. The pending RTO West and the California
market redesign plans are excellent platforms on which to
build, and they are largely consistent with the commission's
proposal.
In short, the days of FERC sitting on the sideline are
over. We are accountable to you and to customers to make this
work well. We are working much more closely with our colleagues
in the States than we ever have before. We are working through
regional organizations to develop sound rules and institutions
so that they will serve customers in this modern economy. We
will continue our outreach day after day from this point to
keep learning how this proposal can and ought to be improved.
My mind, for example, has been changed by persuasive
argument and evidence put forward by business people and
thoughtful people over the past year. Now that everyone has an
opportunity to look at these concepts all pulled together in
one place, we look forward to working through further workshops
and interaction with the interested parties and the public, and
ultimately to restore confidence to this important sector of
our Nation's economy.
We will argue about details at the commission. I think you
will hear today from the panoply of folks appearing here that
there are varied views on just about every topic, but please
know that our objective is clear, making markets work. Through
more infrastructure investment, through clear, balanced market
rules, and through vigorous market oversight, these markets
will work well for the customer.
Thank you, and I look forward to addressing your questions
at the appropriate time.
[The prepared statement of Mr. Wood follows:]
Prepared Statement Pat Wood, III, Chairman, Federal Energy
Regulatory Commission
Thank you Mr. Chairman, Senator Murkowski, and members of the
Committee for inviting me to testify here today. My colleagues on the
Federal Energy Regulatory Commission and I welcome your focus on the
efficiency of interstate wholesale power markets. We welcome your input
on our July 31, 2002 proposed rule which endeavors to complete the
decade-long transition to stable, efficient electric markets.
In addressing almost every facet of the wholesale electric markets,
our July 31st Notice of Proposed Rulemaking to remedy continuing
discrimination in the Nation's electric power markets and standard
electricity market design has a broad reach. A summary of the proposed
rule is in Appendix C.* Our proposal is built upon the real experience
and best practices of the world's best competitive markets for
electricity and other products. It was written after an extensive ten-
month public outreach process in which we sought input on the breadth
of issues facing the wholesale power markets. Before our unanimous vote
July 31 to propose the rule for public comment FERC Commissioners and
staff held over 25 meetings and technical conferences with experts and
others across the country to hear their concerns, suggestions and
recommendations. A summary of all of our outreach efforts appears in
Appendix B.
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* Appendixes A, B, and C have been retained in committee files.
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I would like to use this opportunity to first explain why my
colleagues at the FERC and I believe that our approach is necessary for
interstate wholesale electric markets and good for our country. I will
follow that with some background on the current state of the evolution
in the nation's power markets. Then I will review some of the major
concerns that people have raised about the proposed rule during our
outreach over the past seven weeks, so we can better understand what
this proposal does and doesn't do and how it will affect customers.
why a more standard approach to electricity markets is good for america
Under the Federal Power Act, the Commission must regulate in the
public interest. That mandate colors every action we take.
The wholesale power market today has many of the worst features of
both regulated and competitive markets, and few of the benefits of
either. There is continuing discrimination against certain buyers and
sellers that harms new market entrants and raises costs to end-use
customers; there are extensive loopholes between state and regional
rules that allow market manipulation to raise prices and compromise
reliability; there is under-investment in transmission that raises
energy costs by billions of dollars across the grid and exacerbates
reliability problems; and the practically-inelastic demand curve means
there is little customer discipline on price and supply.
To serve the public interest, we must look ahead and work to
facilitate the electricity system that Americans in the 21st century
deserve a strong, secure network that is technologically advanced and
capable of delivering the high reliability our society needs at a
reasonable cost. That network will use existing rights-of-way, advanced
materials and electronics to link electricity users and producers more
smartly and more reliably. The generators of the power moving over that
grid will be technologically and environmentally improved, so that we
have a diverse portfolio of generators, using every energy fuel, under
the control of many owners, with plants of every size located across
the nation.
We believe that a clearer focus on getting a firm foundation
established for wholesale electric power markets will accelerate our
evolution to this 21st century system and save Americans billions of
dollars along the way. As with Congress' and the Commission's efforts
in the wholesale natural gas markets in the last decade, these will be
real savings that will lower the costs of America's goods and services,
create and protect more American jobs, and keep more precious dollars
in customers' pockets. How do we know this? Because in England, the
real costs of electricity under wholesale competition dropped
significantly, and in the ERCOT market of my home state of Texas,
wholesale prices under wholesale competition have dropped by 28 percent
in six years. Our Commission's experience with natural gas competition
is telling. Wholesale competition in natural gas has provided, on
average, $6,000 in savings to the average American family over the past
ten years versus charges under continued regulation.
PRESENT PROGRESS TOWARD REGIONAL POWER MARKETS
Following adoption of the Energy Policy Act in 1992, FERC began
working to remove barriers to open, competitive transmission access
with Order Nos. 888 and 2000. Although those made significant progress
toward opening up the grid to new competitors, the biggest obstacle to
full competition remains the fact that grid ownership and operation is
fragmented and access is limited by many owners who have incentives to
discriminate against those seeking transmission service. Order No. 2000
encouraged the establishment of Regional Transmission Operators (RTOs)
to serve as independent grid operators across large regions of the
country, reducing operational costs and making energy flow more
efficiently through smarter operation.
To date we have seen progress toward RTO formation. FERC has
approved an RTO for a large footprint in the Midwest, and has
conditionally accepted RTO proposals elsewhere. See Appendix A for a
map of the existing and proposed regional organizations. FERC's July
31st proposed rule builds upon that progress, answers a number of
questions that have arisen in RTO formation and provides guidance
toward a more uniform and efficient approach toward wholesale power
markets. We will continue to work through these ``real world'' dockets
to better inform ourselves of regional variations that are needed in
the various power markets.
THE COMMISSION'S JULY 31 PROPOSED RULE
Following the most intensive public outreach in Commission history,
on July 31, the Commission issued a proposed rule addressing many of
the crucial details needed to be resolved in order to capture the
benefits of competitive wholesale power markets for customers. Every
aspect of the rule is open to comment and we particularly invite
comment on over 70 specific issues. The proposal followed from ten
months of specific workshops, technical conferences, hearings and
targeted outreach both in Washington and across the country. What we
have heard and learned was publicly disseminated well in advance of the
rule through Commission documents and our web site, and we have
received virtually continuous feedback from all quarters on the various
issues. Our July 31 proposal represents the broad consensus reached
through the process in addition to our ``cuts'' on a handful of non-
consensus issues.
Although the proposed rule represents our best judgment given the
information available, our minds remain open to new views, information
and ideas. Since we issued the proposed rule, we have been actively
meeting with groups and individuals across the country to help them
understand the proposal and understand their concerns. To date, FERC
staff and commissioners have given over two dozen presentations to
groups of state regulators, public officials and conference attendees
and discussed the proposal in every press call and speech. At this
time, we have another 30 outreach presentations scheduled to interest
groups, trade associations, conferences, and others. Appendix B lists
many of the activities and meetings we conducted in developing the
proposal, and many of the formal outreach meetings scheduled since the
July 31 issuance of the proposed rule.
To better ensure that the public and parties have maximum
opportunity to review, consider and comment on the proposed rule, we
have extended the 75-day comment period for another 30 days and we have
also asked for reply comments as well. In our outreach to affected
parties following July 31, we heard this suggestion repeatedly and
responded. We are scheduling additional technical conferences to
explore specific issues in greater depth over the Fall, and have
reserved a week in January for any necessary additional public
discussion after the close of the comment period. Four of which have
been scheduled already relate to market monitoring, software issues,
limitations on liability and Western market concerns. These efforts
will assure that everyone with a stake in this rulemaking has a further
chance to be heard with the goal being a fully fleshed out set of
practical market rules.
CONCERNS RAISED IN AUGUST/SEPTEMBER PUBLIC OUTREACH
We have actively reached out to state utility regulators and
governors, customers, industry members from every sector and region,
academic experts, and other stakeholders from every perspective in
developing our proposed rule. And on a number of key issues we have
been persuaded to adopt a different policy that we began with because
we concluded that it would better serve the public interest.
Let me address some of the key concerns we have heard about the
proposal to date.
How do we know it works?--From the outset, our rulemaking process
has been geared to adoption of the best of the practices that are
working in the world's and America's markets. We have found and
incorporated what is working today in the wholesale markets of the
Eastern U.S., Texas, Canada, Great Britain, New Zealand, and Europe, as
well as features that make markets work better for commodities,
financial instruments, and consumer goods. We are responding to
problems explored and documented by groups from the U.S. Department of
Energy, the National Governors Association, the National Association of
Regulatory Utility Commissioners and academic experts. And the
solutions we propose have been explored and recommended by groups and
authors ranging from President Bush's National Energy Policy to the
Western Governors Association and innumerable blue ribbon panels,
academics and public interest groups. What is new about FERC's proposed
rule is that it is comprehensively pulled together in one place and is
being proposed at a time when it can actually improve the lot of the
nation's energy customers.
There is one provision, the Resource Adequacy Requirement, that is
not currently in operation in other energy markets. This important
provision has already received recommendations for improvement in our
outreach and I expect it will improve through further public
discussion.
Cost-shifting--One of the most widely-voiced concerns about the
proposal is that it could cause cost-shifting between states--that low-
cost states will see electricity prices rise as competition lets high-
cost states buy up the cheap power. We don't believe that will happen
and have made several parts of our proposal clear in this regard. The
proposed rule does not abrogate existing contracts for power or
transmission; it encourages load-serving entities in low-cost states to
keep their existing low-cost power at home under long-term contracts
and/or retail state regulation.
One important issue that I believe needs further work is the
potential mismatch between the duration of ``Congestion Revenue
Rights'' (financial hedges for transmission usage charges) and the
corresponding length of generation supply contracts. We need to assure
wholesale customers that they will have protection against transmission
congestion costs for supply contracts for the life of those contracts,
if they desire it.
Funding for new transmission lines--Our proposed rule encourages
independent transmission providers to charge the cost of new
transmission lines to those who will need them. This prevents local
customers from paying for transmission upgrades to serve other regions
unless those upgrades have benefits at home as well--yet the state
keeps the property tax and employment benefits of new generation and
transmission facilities. But while the proposed rule expresses a
preference for the beneficiary pays approach, it states clearly that it
will be up to the Regional State Advisory Committees (comprised of
state representatives from across the region) to determine the
appropriate cost allocation method for new facilities, so we could see
regional differences in how costs are allocated. This is a departure
from FERC's historical ``rolled in'' transmission pricing policy. But
it is both sensible and fair to ensure that the costs of new
transmission lines are borne by those determined by an independent
operator to be the beneficiaries of their construction, even though it
is not always easy to identify the beneficiaries in an electricity
network where the electrons flow as they choose. Because of these
concerns, there is wide diversity of opinion about this issue
nationwide. Due to this, I expect the various Regional State Advisory
Committees will propose, and we will have, different cost allocation
methods across the country.
Market oversight--Some commenters express fear that the rule will
not avoid a repeat of wholesale market malfunction that the nation saw
in the western energy markets two years ago. The proposed rule is a
direct response to these events. It is clear that many of those
problems were caused by bad market rules within California, mismatched
rules and gaps between California and other states' markets, an over-
dependence upon spot markets, and a shortfall in power supplies
relative to customer demand. We designed our rule with these problems
in mind, and are confident that these rules address and avoid the
problems and loopholes which were exploited, at such great public cost,
in the West. And because a standardized approach to rules is taken, it
will not be possible to exploit gaps between markets with such
strategies as ``Fat Boy'' and ``megawatt laundering''. Unfortunately,
however, no regulatory rule can protect society against those who lie
or deceive, as appears to have happened in the Western market. That is
why it is important to have an independent region-based market
oversight function working on the front line, as the proposed rule
requires.
Our proposed set of rules for market mitigation and oversight are
balanced ones that will protect the market while not impeding
investment. Because these rules and triggers will be known in advance,
and the market monitoring is continuous, this preventive regulation
will serve to keep market participant behavior in check. These measures
have already been tested successfully in market situations, and FERC is
currently imposing them in regional power markets today. They will
prevent the kind of market meltdown and delayed response that occurred
in the West.
I should add that the Commission has already developed and
implemented rules outside the context of this proposal to increase the
clarity and transparency of market transactions. These rules--including
Order 2001, to report discrete information on all electricity sales--
will help market participants and observers (including regulators)
better understand and react to changing prices and conditions in the
marketplace, and increase investor and participant confidence in the
integrity of market transactions.
State Authority--Some objections to our rule proposal have come
from some state energy regulators. This is understandable given our
proposal to treat all transmission uses the same. We don't take this
step lightly, but it is not possible to create a fair and equitable
marketplace without use of a single set of rules for uses of the
transmission grid. In our proposed rule, we explain in detail why we
find that undue discrimination continues to this day, and its negative
effects upon the competitors and customers of the wholesale electric
market.
Electric transmission facilities have evolved in use from support
of local service provision to one of facilitating regional power
reliability and commerce. One of the principal concerns raised by
transmission-owning utilities during our outreach is the uncertainty
created by having two regulatory ``masters'' and the resulting doubt
about being able to recover investments made to benefit the regional
grid. Our proposed rule's cost recovery provisions are an effort to
provide clarity in this regard. We have already heard suggestions about
how this can be made clearer and I expect we will make the necessary
refinements and clarifications.
Regional Market Oversight--The proposed rule only applies to
matters affecting transmission and wholesale power markets. Some states
have opened the retail service franchise to competition; others have
chosen not to. That is a state choice which we respect. Just as with
wholesale natural gas competition, benefits can be achieved by
customers under either regime. The only difference is who allocates the
savings: a state regulator or the marketplace? The national vision that
we have put forward for the wholesale power markets accommodates either
approach. I should add that I think it is unwise for a state to adopt
retail customer choice without a healthy wholesale market operating as
a foundation.
Our proposal recognizes that there are many areas where federal and
state regulators must work together. We cannot build a strong,
competitive and fair market without effective federal and state
cooperation. Three of our four members are former state commissioners,
and we want to continue to maintain strong ties with our colleagues
from state agencies to protect our nation against the ravages of
mismanaged, poorly planned, under-invested, and inefficient energy
markets.
This proposed rule recognizes the critical role that state
regulators play. Consistent with the July 2002 recommendation of the
National Governors Association, we endorse the establishment of
regional, multi-state entities, with representatives appointed by
governors, to collect information and make decisions that reflect
regional values and preferences on key issues including resource
adequacy, system expansion, cost allocation for new investments,
transmission siting, and demand response. Because these issues cross
state boundaries, it is necessary to look for regional solutions to
them. We seek to be a catalyst for making these regional solutions come
to the fore and get implemented.
Unless Congress chooses to give the FERC backstop authority over
transmission siting, this agency will not make decisions about
transmission planning and siting, which is the traditional purview of
the states. We do strongly endorse, however, the empowerment of
regional organizations to do this work, which we believe will result in
better system expansion and resource planning.
We have also heard about this issue in our outreach since July 31.
A number of state authorities are concerned about the relatively vague
role that regional state advisory commissions would have in overseeing
regional power markets. With the energy legislation in conference, I
welcome any action the Congress would make to state that such regional
bodies are specifically empowered to act on these various issues, with
appeal to the Commission where consensus is not reached.
Demand/customer participation in wholesale markets--One of the more
crucial aspects of a successful wholesale power market is enabling
customer demand response and small-scale generation. Timely customer
demand response is crucial to the success of power markets. One of the
best ways to stabilize volatile energy prices and check supplier market
power is to ensure that customers can respond to market signals by
reducing their consumption. Evidence to date indicates that even a
small amount of demand response can have a significant impact in
dampening prices during times of high demand and resource scarcity. All
customers benefit from demand response. And one way for customers to
respond to high electricity prices is turn on their own small
generators, reducing their load on the electric system on the other
side of the customer meter.
Demand response lies squarely at the nexus between wholesale and
retail energy markets and jurisdiction demand response to price is
critically needed in wholesale markets, but it will only occur if
retail customers see a price (or price proxy) and change their load
accordingly. We can lay out market rules that allow demand response and
small-scale generation to participate in wholesale markets, but state
regulators have the ability and authority to enable retail customers to
see the wholesale energy price (or not) and to give them options to
respond to it (or not). We are working closely with state regulators
particularly in a current pilot project in New England and transmission
system and electric market operators to develop and implement a suite
of demand response programs that will satisfy the needs and concerns of
state energy and environmental regulators, create new options for
customers, improve reliability for the electric grid, and help
competitive wholesale markets work better.
Native load--Our national electrical system has generally worked
well for local customers and this should not be jeopardized. We have
crafted the proposed rule with many features that ensure that retail
customers are not harmed by the proposed changes, but benefit. The
major one, of course, is the proposal's reliance on long-term contracts
(not the spot market) to supply the bulk of the customers' needs.
Against strong encouragement to hold initial auctions of Congestion
Revenue Rights (CRRs), we specifically permit regions to allocate CRRs
to native load customers through their current utility providers (load-
serving entities); thus, existing loads would be protected from
congestion costs. When CRRs are auctioned off in later years, it would
be done in a way that holds existing customers financially harmless if
they seek to keep the rights. And in retail customer choice states, we
propose that the CRRs follow the loads, so that if a customer chooses
to move to a new retail provider the CRRs needed to serve that customer
will also move to the new provider.
Specific Regional Issues--Pacific Northwest--The Western region
relies heavily on hydro resources. The operation and dispatch of
hydropower has been negotiated over decades under international
treaties. Market participants in the Pacific Northwest are concerned
over whether the many values and needs of their hydro systems can be
preserved under a market-based system that assumes power will be
dispatched based on price.
There is nothing in the proposed rule, or in a locational marginal
pricing transmission market, that would require the Western hydropower
system to operate any differently than it does today. The operators of
that system will still be able to dispatch power based on the operating
constraints that have been forged through the complex regional and
international arrangements already in place. Our proposed rule would
require that these hydro owners quantify their river basin needs
carefully and specify ``shadow prices'' that reflect the availability
and value of their hydro resources for electric generation. We
anticipate that CRRs can be fashioned to accommodate the special needs
of hydro operators--for example, CRRs could be designed to allow
multiple receipt points for customers purchasing hydropower, so power
can be delivered from any of a number of hydro plants along a single
river system. CRRs could be designed to accommodate seasonal
differences, or multi-year planning. These details will be fully
fleshed out with impacted parties over the next few months both in this
rulemaking docket and in the pending RTO West proceeding.
The West also contains a large proportion of transmission
facilities that are owned and operated by public power entities. Our
proposed rule intends that regional transmission systems be operated by
Regional Transmission Organizations (or Independent Transmission
Providers), and there is concern that if public power or cooperatively
owned utilities opt out of joining an RTO, the proposal cannot work.
This same concern is also expressed over the participation of Canadian
market entities. We believe that the benefits of market participation
and the substantial efficiencies and cost savings offered by large RTO
operation will be attractive and beneficial for non-FERC-jurisdictional
utilities and that most will want to join. To be able to benefit from
the plentiful Canadian energy resources, it is critical to resolve
these issues in the Pacific Northwest.
Infrastructure investment issues--The nation's wholesale electric
markets have been in flux for the last 25 years, first because of
evolving technology and then because of changing regulation. Over the
past decade this uncertainty has led to gross under-investment in
transmission facilities and energy efficiency, but substantial
investment in generation. We need to stabilize the regulatory rules for
the market. Recognizing both the current market situation and future
capital needs of the industry, I follow investor reaction closely. Many
of the investors and analysts I talk with welcome our proposal because
it offers the promise of consistent, dependable market rules that will
apply across the country. Once adopted, the wholesale market rules will
be clear and stable over time. They will open the door for and lower
the risk of new investment opportunities that the nation desperately
needs, by leveling the playing field between incumbent and new players,
traditional and new technologies, and between supply and demand
resources. The power of predictable rules to unleash investment has
been proven in Texas, which has seen $1.2 billion in new transmission
and 65 new power plants built since the wholesale market rules were
adopted in 1996.
I expect to hear in the comments and reply comments about a number
of clarifications or changes that can be made in the rule to further
stabilize investment prospects in this industry. One that has been
raised several times is the seemingly complex nature of regional
planning. Our attempts to include the regional regulators and other
interests ahead of time could perhaps be balanced as effectively in a
different manner. I look forward to working further with my colleagues
and with interested parties on the planning and cost recovery issues.
Environmental Impacts--I have heard a concern that wholesale
competition will lead to more power plant emissions and more
transmission lines across the land. Regulated or competitive, the
country's electric industry is growing just as our overall economy is
growing. However, a more fluid, competitive wholesale marketplace
offers features that should improve rather than compromise the
environment. These include: efficiency-driven retirements of high-
polluting, high-cost power plants; more efficient use of existing
transmission facilities through independent operation; greater use of
demand-side resources, which reduce energy use and air emissions; and
more equitable treatment of intermittent resources (such as wind power)
in wholesale electric markets. The Commission is performing an
environmental assessment as part of the Final Rule.
CONCLUSION
Congress made the critical policy determination in the 1992 Energy
Policy Act that transmission and power markets needed to support
competition. Since that time, the FERC has sought to implement that
policy. It is our expectation that our proposed rule, improved by
further input from the public and affected parties, will complete the
task. Thank you.
The Chairman. Well, thank you very much. We will do 5-
minute rounds of questions, and the two Senators who have come
in, I have been advised that they would like to make an opening
statement. They will be given a couple of extra minutes to do
that when their questions arise.
Let me ask--I will start with a few questions that occur to
me, Mr. Chairman. As I understand your standard market design
proposal, in order to protect the ability of load-serving
entities to meet their obligations, you propose tradable
financial rights to be allocated to those entities but later
auctioned, as I understand.
Since the load-serving entity receives the revenue from the
auction of the rights, they should be guaranteed to be able to
retain the rights in perpetuity. If there is currently
discrimination in retail transmission that needs to be
remedied, how have you remedied it if the same entities who now
have the transmission rights are able to keep those rights
permanently?
Mr. Wood. I think one of the important aspects, and this is
a balance, clearly, Senator Bingaman, is remedying the
discrimination in the most fair manner possible versus the need
for continuity and stability, and it was our view that not so
much--the discrimination is not remedied so much by the
allocation of the congestion revenue rights, which is an
important step, but through the entire panoply of the proposal,
an important part of which is an incentive that is not existing
today for a transmission-owning utility to actually have
sufficient transmission for all the customers, not just the
native load, but for the people who are transmitting power to
the neighboring State, or to a coop embedded within the native
load company.
So certainly the incentive to build more transmission
sufficient to meet everybody's needs, and to have that
administered by an independent body, we think will actually do
as much to remedy the discrimination as the allocation/auction
process. That is not where the real nub of the discrimination
occurs. It occurs in how the system as it exists today is not
being expanded, and how the system as it exists today is being
administered in a way that is not fair to all users.
The Chairman. So as I understand your answer, you are
saying that having these transmission rights, or essentially
the ability to retain these transmission rights on a permanent
basis, or indefinitely, is not a problem because they would be
operated, the transmission system would be operated by an
independent entity, and that resolves the concern. Is that your
basic view?
Mr. Wood. Again, that resolves part of the concern, and you
know, a fundamental concern in increasingly larger and larger
parts of the country is that there is not sufficient
transmission in the first place to meet everybody's needs, both
native loads and load that is adjacent to the region, and for
that reason the important aspect--and I was very intrigued by
the gentleman from New Mexico speaking on EEI and some of the
other transmission owners that the world was not clear enough
to provide the incentives necessary to build additional
transmission where it is needed. We want to fix that. That is
clearly an imperative for us to make sure that not only can we
get the transmission administered fairly, but that it can also
be built where needed, so it is the two, Senator that are
important, administration of what we have got, and the addition
of what is needed to address the growth of the Nation's power
needs.
The Chairman. Let me ask about locational marginal pricing.
How do you intend, or suggest that this concept, locational
marginal pricing, is going to reduce congestion? That is a
significant part of what you are proposing here, as I
understand it, in your order.
Mr. Wood. To be honest, the proposal does not reduce
congestion on its own. It indicates where the congestion is. It
allocates the cost of relieving congestion to the person or
persons who caused it, and one of the issues we saw in
California, I believe we've also seen in the market that I
worked on in Texas last year, was that if the cost can be
shipped off to everybody else on the system, then there is not
a real strong incentive on any party to reduce the congestion,
by either selecting another generator, or by adjusting the
way--his load, or by making some additional construction in new
substations, for example.
So the locational marginal pricing is to actually indicate
what the cost of congestion, i.e., lack of transmission
investment is, so it is a price signal that is sent to a
builder to uncongest the system, but it on its own does not fix
the congestion.
The Chairman. It does create the proper incentive for
relief of the congestion?
Mr. Wood. Yes, sir, rather than uplift the cost of--just
take, for example, southeast Connecticut, or southwestern
Connecticut right now, which is kind of one of our watch areas
because of the need for either new generation or new
transmission to serve the growing power needs there. If a
generator that is inefficient, say an oil-fired generator that
is 40 years old, has to be run every day through the hot
summer, that is not the usual 4 cents per kilowatt hour price,
or 3 cents per kilowatt hour price. It may be an 8 or 9 cent
kilowatt hour price.
Under the protocols which are now being proposed, actually
on tomorrow's docket to be changed by the New England Power
Group, those costs under the current proposal are spread to
everybody in New England for running that inefficient generator
down in southwest Connecticut.
So under a more locational system, the cost would be borne
by the people in that region who choose not to make investment
in sufficient generation, or transmission, to keep the lights
on at a reasonable price, and so it is that philosophy that
locational marginal pricing is directed towards.
The Chairman. All right. Thank you very much.
Senator Thomas.
Senator Thomas. Thank you, Mr. Chairman. You indicated, Mr.
Chairman, how you have worked with the various local entities
and so on, and yet I have statements here, and a number of
statements from Western Governors who indicate, frankly, that
you need to work more closely with the States. Why did you say
that you have been working with them, and then they seem to be
so in opposition to what you put out?
Mr. Wood. Well, I have got to admit I am mystified myself,
but I have learned not to sit there and cry about it but to get
off and work about it. I mean, we are back out on the street. I
will be back out in the West in the coming months to work
through these issues with the States, with the Governors, and
with the affected utilities out there, but we have done,
Senator Thomas, a tremendous amount of outreach. Our staffs
went out on the road the day after we voted the NOPR to start
explaining to folks some of the details, because it is
comprehensive. It is complex.
Senator Thomas. Well, there is a difference between
explaining your point of view and dealing with other people and
including their point of view, which you obviously have not
done.
Mr. Wood. Well, I would respectfully respond, sir, that in
fact we have heard a lot of things over the past 10 months, 11
months, now a year, that have changed our mind. I mean, I
personally changed my mind on a number of significant issues,
and I think in dealing with specific issues, for example, in
the hydropower in the Northwest, there is a lot that we have
learned. I personally have learned a lot about that, and we
have got folks that were in last week from BPA teaching us
about some of the aspects of their hydropower system that we
did not seem to get right in the rule, and I expect that we
will make those changes to make that work better.
But it is a two-way conversation, sir. I mean, certainly
what we did for the last 10 months was listen, and then what we
put out----
Senator Thomas. Well, I understand what you're saying, that
the people who--and you will hear some testimony today which
will not indicate that that is the case, not the feeling of the
people, other than yourself.
What is it that you provide for an incentive for additional
transmission facilities?
Mr. Wood. Well, the first part is that there is clarity of
cost recovery. I mean, how is it--if it is all in one single
tariff, then the rates were looked at one time and they were
covered through a standard mechanism. Today, probably one of
the biggest concerns we heard from utilities through the
outreach is that they're really trapped.
There is what we call the cost trap between the FERC rate,
say, maybe, 20 percent of the total, and then the States all
doing their own rates maybe add up to, you know, 65 or 70
percent of the total. Well, there is 10 percent of the costs
that are just left in the trap, so nobody gets allocated those
costs, and the utility in fact does not get its full revenue
recovery. I think those issues are resolved by a single
transmission tariff, a single way of looking at the total cost
of the system, so one thing I learned in my last job was, given
a clear path of how you are going to get your money back, you
will actually see investment made, so that is one, for example.
The Commission has already indicated in prior orders that
with independent administration of the power grid such as we
now see in a case on our docket tomorrow from the Midwest
regional transitional organization, that the Commission will in
fact adjust the returns on equity granted to those companies to
be higher than they would otherwise be, and that is our first
opportunity to do so, and that is on our docket tomorrow.
Senator Thomas. And your authority under this will go on
down to bundled actually intrastate retail transmission.
Mr. Wood. What we would do, Senator, would be figure out
what FERC needs to set the rates for, and if there is, say,
$200 million for revenue requirement for an RTO, and if $100
million of that is FERC regulated, we will take that, and $100
million goes to State X, then that State commission then would
ascertain how those rates should be allocated to their retail
customers, so at one level, yes, it is an allocation to make
sure that all of the percentages of the total add up to 100,
but as far as the individual bundled rate design, or bundled
rate, that would be done, as it is done today, by the State.
Senator Thomas. However, the authority in your proposition
gives it to FERC. FERC can do whatever they choose to do in
terms of bundled intrastate transmissions.
Mr. Wood. It is actually--we would do, call them the
interstate. I am not aware that there is much intrastate
transmission, perhaps outside of ERCOT, and some would argue
that is not even intrastate.
Senator Thomas. So you are just going to deal with
interstate?
Mr. Wood. Well, that is most everything, sir. I do not want
to mislead you.
Senator Thomas. No, I want to know the answer.
Mr. Wood. Yes, sir.
Senator Thomas. You are just going to deal with interstate.
Mr. Wood. Interstate.
Senator Thomas. Not intrastate.
Mr. Wood. We deal with interstate transmission, which I
would acknowledge to you, sir, is practically all transmission.
Senator Thomas. I do not believe that is true. Obviously,
there is retail transmission, and there is bundled transmission
that does not go interstate, and I think your proposal gives
you authority to deal with that, as opposed to the States,
right?
Mr. Wood. Again, our proposal asserts the jurisdiction, as
we believe the Supreme Court allows, over the interstate part
of transmission.
Senator Thomas. Thank you.
The Chairman. Senator Burns wanted to put his questions in
and make a statement here.
Senator Burns. Thank you, Mr. Chairman, for coming down
this morning. I have got the Interior appropriations bill that
we are going to start here pretty quick. I am going to submit
some written questions to you, and I will give you a heads-up
in the area of wheeling losses, like some of these
transmission, the through and out service areas.
I am concerned about native load and power prices in that
area, I am kind of concerned about the ITP, this new commission
that you proposed, who they are accountable to, how they work
with the PSE's around the country, and also questions with
regard to the cooperatives, and we have some questions in there
especially dealing with hedging and other sophisticated
marketing techniques that concern. They do not have the money
power or the economic power to compete, and I would want to
know how that affects them. Those are the areas that I am
concerned with more in your new proposal.
I appreciate the chairman allowing me to do this, but we
will submit those to you in writing, and you can respond to
those and to the committee if you would, please.
Mr. Wood. I will do that promptly, Senator. Thank you.
Senator Burns. And thank you very much.
Mr. Wood. Thank you.
Senator Thomas. Mr. Chairman, may I submit for the record
this statement from the Western Governors, please?
The Chairman. You certainly may. We will include that in
the record.
[The prepared statement of the Western Governors follows:]
Statement of the Western Governors' Association
Consistent with the policies of the Western Governors' Association,
the following testimony is offered on the Federal Energy Regulatory
Commission's proposed Standard Market Design (SMD) rule. We recommend
that FERC delay the adoption of the SMD rule in the West. FERC has
failed to provide adequate evidence to justify this proposal for the
complex electricity problems of the West.
The West has been diligent in instituting changes needed to protect
the region from a repeat of the ravages of the 2000-2001 Western
electricity crisis--a crisis brought on by the combination of a failed
deregulation scheme in California, most of which was approved by FERC;
robust demand growth and limited growth in generation; a severe drought
limiting hydroelectric production; and delays by FERC in controlling
market abuses. Specifically in the West:
12,000 MW of new generation has come on-line since January
2001 and 26,000 MW are under construction. (This compares with
an installed capacity in the Western Interconnection of 169,000
MW.) Hydro generation has improved significantly since 2001.
Demand is down, particularly in the Northwest and
California;
Significant experience has been gained in the structuring of
demand response programs.
A new reliability management organization, the Western
Electricity Coordinating Council (WECC), has been put in place,
and we urge Congress to do its part by enacting the reliability
provisions passed by the Senate. The regional advisory bodies
authorized in the Senate-passed bill can provide a vehicle for
collective state participation in reliability and, potentially,
related regional market decisions.
A proactive regional transmission planning process has been
initiated. Such proactive planning is a requisite for
successful financing of new transmission.
A protocol on collaborative permitting of interstate
transmission lines has been signed by all the states in the
Western Interconnection and, equally important, by the federal
agencies (DOI, USDA, DOE, CEQ. It is believed that the protocol
will help the West overcome the historic difficulty of securing
necessary federal permits for transmission.
Three Regional Transmission Associations (RTOs) have been
proposed to FERC and are awaiting section review by the
Commission. While these proposals are still in development,
Western governors have supported the voluntary formation of
RTOs where clear benefits to the affected regions are
demonstrated.
We are pleased that FERC is finally paying attention to market
monitoring, although as FERC has acknowledged the Commission lacks the
tools to police the market and penalize market abuses.
FERC's proposed Standard Market Design (SMD) rule proposes
significant changes in the electric power system in the West and a
major effort by the Commission to expand its authority into areas of
traditional state responsibility. Western states have differing views
on the need for changes, but we agree on the following:
1. It is unfortunate that FERC has not developed an empirical
record of abuses in the West that support the changes proposed in the
SMD rule. For example, the proposed SMD rule provides only anecdotal
examples of discrimination in transmission, but not a compilation of
information to demonstrate its case, such as: number of complaints of
discrimination by transmission owners; type of discrimination; number
of megawatthours affected and cost to consumers; results of FERC
investigations of discrimination complaints; and enforcement actions.
The dearth of empirical evidence does not bolster the case for SMD in
the Western Interconnection.\1\
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\1\ Some of the targets for reform in the SMD rule are not
applicable in the Western Interconnection. For example, the SMD
proposal specifically targets the practice of Transmission Loading
Relief (TLR) as detrimental to ensuring nondiscriminatory transmission
and efficient wholesale power markets. However, the SMD rule fails to
note that TLRs are not used in the Western Interconnection.
---------------------------------------------------------------------------
2. FERC has not evaluated the impacts on consumers of the SMD
proposal. While FERC plans to do an EIS on the proposal, it did not
undertake rigorous analysis of the impact of SMD (or for that matter on
any substantively different alternative) before proposing the rule.
Equally disturbing is that analyses FERC has relied on for its policy
decisions have tended to be shallow and do not examine the Western
Interconnection in adequate detail to support proposed policy
changes.\2\ FERC should significantly upgrade the quality of analysis
it uses to make policy decisions and should conduct such analysis for
each interconnection, not assume away important differences between the
interconnections. These efforts should be completed and released for
review and comment prior to any finalization or implementation of the
SMD proposal or rule.
---------------------------------------------------------------------------
\2\ For example, FERC's RTO cost-benefit analysis is not rigorous.
Key inputs to its modeling effort, such as expected improvement in
generation efficiency from RTOs, are merely assumptions not backed-up
by quantitative analysis. In the SMD proposal, FERC cites DOE's
National Transmission Grid Study (NTGS) when concluding that more
transmission is needed. However, the NTGS study says that its model,
POEMS, does not represent physical flows over the transmission system
and ``. . . because it is national in scope, the model does not
consider trade within subregions.'' Thus, POEMS does not even evaluate
Path 15 between northern and southern California. FERC's own December
19, 2001 analysis of transmission constraints provides no detailed
back-up information on the analysis.
---------------------------------------------------------------------------
3. Prior to moving ahead with implementing SMD in the West, FERC,
in cooperation with Western states, needs to study whether SMD is
feasible in the Western Interconnection if non-jurisdictional
utilities, such as municipal utilities, cooperatives, public utility
districts, and federal power marketing administrations, which operate a
large percentage of all transmission in the West, do not participate.
SMD should not be forced on only a limited portion of the transmission
grid in the interconnections.
4. FERC's SMD rule (and perhaps Western RTO proposals) will fail
unless the federal government's power marketing administrations
participate. The PMAs must evaluate how the SMD will affect their
customers and the economics of the regions they serve. The federal
government needs to decide if, and under what conditions, the
Bonneville Power Administration and Western Area Power Administration
will abide by provisions of the SMD rule or a more applicable Western
alternative and join proposed Western RTOs. Because of the major
impacts BPA and WAPA have in the West, the federal government needs to
consult with the states prior to deciding on the PMA's participation in
Western RTOs.
5. FERC should specifically set aside the Western Interconnection
from its SMD rule and concentrate on working with the states to develop
RTOs that address the specific problems in the Western Interconnection.
This process should begin with a well-defined and factually-supported
statement of the problems in the Western Interconnection (which the
western states have already started in the various inter-related
efforts identified above). FERC action on the pending Western RTO
applications could serve as a basis for initiating such discussions
between Western states and FERC.
6. Any FERC action on SMD should be done on a region-by-region
basis. In the West, FERC has not made an adequate demonstration to date
that would justify implementation of its SMD rule.
Western Governors believe these areas of agreement across our
region should form the basis of Congress' direction to FERC on how the
Commission should address Standard Market Design.
Senator Burns. Thank you, Mr. Chairman.
The Chairman. Certainly. Senator Wyden.
Senator Wyden. Thank you, Mr. Chairman.
Mr. Wood, let me go right to why Western ratepayers and
elected officials are so angry about this proposal. Right now,
in the 11 Western States, there is a $250 per megawatt hour bid
cap in place. That is in place now for 11 Western States. You
would in effect lift that bid cap to $1,000 per megawatt hour,
essentially four times higher, and what westerners are so
concerned about is that if you raise the cap in such a dramatic
way, is that not just an open invitation to raise prices
throughout the West?
Mr. Wood. It could be, sir, but let me just clarify that.
In fact, we mentioned that the $1,000 cap is illustrative. It
is the same issue as the $250. The two caps are the same issue.
This proposal does not change the $250 cap, and I was asked
that question by somebody in the press right afterwards. We
noted with interest that----
Senator Wyden. What kind of cap do you envisage then,
because it sure looks to us like it is a $1,000 bid cap. What
kind of bid cap do you envisage?
Mr. Wood. It is $1,000, and in the other markets that were
referenced in the world, current markets in the Northeast and
Texas rely on the $1,000 per megawatt bid hour cap, I would
offer that I think those are healthier markets than the one we
have got out West, and as our order setting it at $250 stated,
this is based on an assessment of the non--I think it was a
question, sir, in fact, you asked us to do, look at the
competitive questions of the West before you go, kind of moving
back to the lowest common denominator market mitigation.
In fact, we did do that, and our staff did a substantial
assessment of the competitive conditions in the West and the
infrastructure shortfalls that we need to make up for before
you do go to a more open marketplace, and we will continue to
assess those as we go forward.
Senator Wyden. I am going to talk about your work to date
in a moment, because I think you know that the General
Accounting Office in June ripped you all pretty good. I mean,
they basically said, and I will quote here, FERC's ambitious
reengineering effort ``achieved little more than superficial
changes.'' It ``served more to educate FERC's staff about new
markets, than to produce effective oversight efforts,'' so if
you are going to cite what you did so far, let us just be clear
that the General Accounting Office, which is the agency we use
for objective evaluations, does not think very highly of your
work.
I want to go back to this ratepayer question, because again
it just seems to me your proposal is going to send our rates,
which already have gone into the stratosphere, even higher, and
that is what happened in California, when you all in effect let
this kind of approach go forward. Every time the cap was
raised, prices went up, they stayed up, and it seems to me that
this is just more of the same, so if you would, explain to me
how this is going to be good for the Western ratepayer. I mean,
there are 11 States on the line, with Senator Cantwell and I,
and a lot of westerners very concerned about it, 11 States,
facing a cap that you have told us this morning is going to
quadruple from the current level.
Mr. Wood. Sir, I did not say that.
Senator Wyden. You just said it would be $1,000.
Mr. Wood. I did not say that, sir. I said that it----
Senator Wyden. Tell us what it would be under what you
envisage.
Mr. Wood. It would stay where it is until we change it with
a specific order in the Western markets. It was set at 250
starting later this month, and that is where it will stay until
the competitive conditions dictate otherwise.
Senator Wyden. So you envisage it is going to stay at $250,
because earlier you said you expected it to be $1,000.
Mr. Wood. I said that this rule said there should be a
safety net bid cap. That was the words that were used.
Senator Wyden. Of $1,000.
Mr. Wood. A safety net bid cap for each market.
Senator Wyden. Right.
Mr. Wood. It did not say a specific number, sir, and----
Senator Wyden. Is it $1,000 or not?
Mr. Wood. It is $250. It is $1,000 in other markets that
are healthier.
Senator Wyden. What is the bid cap under your proposal, so
that westerners understand exactly this morning what you
envisage?
Mr. Wood. The bid cap would be established on a region by
region basis.
Senator Wyden. Could it be $1,000?
Mr. Wood. It could be $1,000.
Senator Wyden. Thank you. That is what we are concerned
about. That is the bottom line. Under your proposal, it could
quadruple, for 11 Western States, and people in our region who
have been clobbered already. Meanwhile, FERC has not taken any
action on refunds. Under what you just said, it could
quadruple, and so you take that potential, plus the very
significant criticism of the General Accounting Office of your
efforts to date, and you can see why westerners, the Governors
and the local officials are so angry.
Like Senator Craig, I am always interested in trying to
find the common ground, and trying to find something that could
work, but you should understand that there is enormous
opposition from the West, and if you persist in something that
could quadruple the cap and allow for what we have seen again
and again, which is rates to go up, you will continue to have
such significant western opposition.
Thank you for the time, Mr. Chairman.
The Chairman. Chairman Wood, did you want to make any
clarifying statement before we move to the next----
Mr. Wood. Yes, sir. In fact, the GAO report, with which I
agreed in total, and the comments that Senator Wyden referred
to, were an engineering effort begun in the prior
administration that rearranged FERC, and I would agree with its
assessment that it did not meet the job.
I have since, with GAO's help, when I came on Chairman a
year ago this month, begun the effort to in fact install a
fully accountable Office of Market Oversight and Investigation.
I look forward to introducing the head of that office, who is a
well-qualified gentleman from the outside who gets it, and he
has hired a number of outside staff and experts who get it, to
work for the Commission and to do this effort on a going-
forward basis.
I appreciate the support that we have gotten from the
committee and the Congress to actually fund this effort. It has
been a very important part of our job. It is a direct response
to what we learned last summer, and we expect to move forward
with very assertive and participatory market oversight
throughout the country both in the organized markets and in the
less-organized markets to make sure that there are no holes in
the web.
The Chairman. Senator Wyden wanted to make a final
statement.
Senator Wyden. Just very quickly, Mr. Chairman, on this
General Accounting Office report, let us just make sure
that the problems that the General Accounting Office have
identified have been corrected before the agency goes forward
with something which I think we have learned this morning has
such devastating potential for the West.
Thank you, Mr. Chairman.
The Chairman. Thank you.
Senator Kyl.
Senator Kyl. Thank you, Mr. Chairman. I want to ask you one
more question about the bid cap in just a moment, but you made
the point that you wanted to work with the Western Governors
and others over the coming months, and you have the statement
that Senator Thomas put in the record from the Western
Governors that raised a series of questions.
My understanding is that the comment period expires
sometime in October. Are you willing to extend the comment
period beyond that time so that those with an interest can
submit their comments to you and you can continue to work with
them?
Mr. Wood. Yes, sir. In fact, last week in response to those
concerns raised from some of our panelists today and others we
extended the comment period a month and then actually added a
response cycle that extends around Christmas, announced that we
would have further workshops on identifying issues that still
remain unresolved, or remain in play in the early part of next
year.
Senator Kyl. I think that is important. Just to note a
couple of things from the submission of the Western Governors,
quoting from their transmittal, FERC needs to work closely with
the States and other participants, and also they note among
other things that the proposed standard market design rule
proposes significant changes in the electric power system in
the West, and a major effort by the Commission to expand its
authority into areas of traditional State responsibility. That
is part of their concern, and some of the words that you used--
and I am just quoting phrases you use. We need an active FERC.
You said that several times. You talked quite a bit about
vigorous oversight. FERC will not sit on the sidelines, and so
on.
Do you appreciate why those who have not had this kind of
aggressive jurisdiction are concerned that there will be a
deeply intrusive regulatory authority into what has been State
jurisdiction in the past, and you can appreciate the concerns
that these people are expressing, I presume?
Mr. Wood. Having been a State regulator, yes, sir, I do.
Senator Kyl. Now, you were from Texas. Texas is excluded
from the FERC proposal, is that correct?
Mr. Wood. About 80 percent of it is intrastate
transmission, so it is not, but the other 20 percent is,
actually.
Senator Kyl. But as you were trying, I think, to point out
to Senator Thomas, in reality it is very difficult to draw a
line and say interstate does not pertain to this particular
transmission, is it not?
Mr. Wood. That is correct, sir.
Senator Kyl. And I know you were trying to make the point,
I appreciate the point, but in a sense it also makes Senator
Thomas' point that there is a deep intrusion into State
regulatory authority here.
With regard to what Senator Wyden was saying, it seems to
me that you are both right, but again we have to get to the
bottom line here. You have temporarily set the bid cap at 250
for the West, but I think I heard you say that you think that
ultimately the market forces will show that a rate of $1,000 is
more realistic. If I missed that, then correct me, but is it
your view that it is likely that that cap of 250 will be
modified, and will be taken up over time?
Mr. Wood. I think two things need to happen, Senator Kyl,
for that to happen. We need to get sufficient amounts of
infrastructure investment in the West. There are in your home
State certainly a lot on powerplants. Transmission lines, gas
pipeline infrastructure, a lot of these things are really
critical to making a competitive market work. That has to be a
precondition for any sort of, I think, deregulation of the
market, and the second is to have some uniform approaches to
how the West and the rules in the West work.
Senator Kyl. Why have you not ruled on the West connect
RTO, and when do you expect you will do that?
Mr. Wood. Well, it is on for tomorrow. I had a lot of
questions about it, quite frankly. I personally asked my
colleagues to move it to our meeting in 2 weeks. It I expect
will be done then. I told you at the last meeting that we were
going to do it after we broke for August, but there were a lot
of issues. We want to get them right. We want to give them firm
feedback, but it will be in a matter of the next couple of
weeks.
Senator Kyl. I am sorry, I want to go back to this question
of the extension of the time. My understanding is that you have
not changed the plan date for the issuance of the final rule
and industry implementation, is that correct? You have extended
the comment period.
Mr. Wood. Right, but I mean, we never established a date
when the rule is actually going to be done.
Senator Kyl. When would you anticipate that that would
occur?
Mr. Wood. Well, I think there is now a--the House
Appropriations Committee asked the Department of Energy to do
the cost-benefit study instead of the Commission, and then to
wait 90 days on that, so I think getting that all done--which
we support. Getting that all done is going to push it probably
until the spring. and that is fine. I think certainly from the
comments we have gotten, and my schedule yesterday was full of
people who had specific issues that they think we did not get
it right on, and we need to continue to get that explored, some
of the issue that were raised here by your colleagues. It is a
work in progress.
Senator Kyl. Well, that is what we are hoping it is, and I
say with all due respect that both Senator Thomas and Senator
Craig before him have expressed a willingness to work, but a
concern that there is not sufficient listening to what is being
said to you by particularly those of us in the West.
I have had several meetings with you, and I have expressed
concerns, and I know you have listened, but it is hard to see
that translated into any of the proposals, and maybe you simply
disagree, and I suppose there is fair room for disagreement,
but given the fact that there is going to be a significant
imposition of Federal jurisdiction in the West, that you have
acknowledged the West in many respects is different than the
East, but you have the Western Governors suggesting that we
slow down and take a look at this in the West to apply it
differently.
The questions have been raised by Senator Wyden and others
that really do require, I think, significant dialogue here. It
is one thing for us to continue to say these things. It is
another for us to find it somehow reflected in what is being
proposed, and quite honestly, our concern is that we see you
hell bent on doing something that you had in mind from the very
outset, modestly tinkering at the margins to try to satisfy
some of the concerns, but not really willing to consider some
of the deep objections and concerns expressed by those of us in
the West, and I associate myself with Senator Craig's comments
that we ought to try to work together on this. If we can create
some time to do this, maybe we can, but at the end of the day,
I think we want to see a little bit more acknowledgement of the
validity of some of these concerns and not lip service alone.
I am going to just put a statement into the record here and
submit some other questions to you in writing, give you plenty
of opportunity to get back to us, and I hope we can continue
the personal dialogue, too, because I hope that can be useful
at the end of the day.
Thank you, Mr. Chairman.
[The prepared statement of Senator Kyl follows:]
Prepared Statement of Hon. Jon Kyl, U.S. Senator From Arizona
I thank the Chairman for holding this hearing. We are facing
tremendous upheaval in the electric industry these days and I believe
that we need to move cautiously to avoid creating greater disruption in
an already fragile state of affairs. The introduction of the Federal
Energy Regulatory Commission or FERC's Notice of Proposed Rulemaking on
Standard Market Design, also known as the SMD NOPR, attempts to address
some of the problems in our current energy markets. However, as a
Senator from a Western state, I have several concerns regarding the
FERC's proposed rulemaking. I am pleased that we will have the
opportunity to examine some of these issues today.
Arizona has watched carefully the trials and tribulations of the
California's failed restructuring experiment. Our State Corporation
Commission recently changed directions on the implementation of retail
competition and now wants to take a more conservative approach largely
due to concerns that consumers will not be adequately protected while
the wholesale markets are in transition. While I support the
development of competitive markets to allocate resources efficiently, I
believe that, with respect to our electric markets, we need to move
with appropriate caution and deliberation to ensure that we do not
create another California type scenario that provides an opportunity
for unscrupulous market participants to game the system at the expense
of consumers. In this regard, I also have strong reservations about
imposing a regulatory scheme that may work well in one part of the
U.S., but fails to recognize the operational and institutional
differences in other parts of the country, such as the West.
Indeed, the West is much different than the East in terms of the
resources and the operations of our electric utilities. I fear that
FERC has missed this fundamental difference in developing the Standard
Market Design proposal. For example, my state has a significant
portfolio of hydroelectric resources. As this Committee is well aware,
hydroelectric facilities present different planning, operating and
economic challenges than the resource mix that dominates the landscape
in the East. It worries me that the Standard Market Design NOPR, while
acknowledging the differences, dismisses them in a rather superficial
manner by simply saying, for example, that FERC ``. . . sees no reason
. . .'' that Standard Market Design would interfere with the operation
of hydro resources. [Note: SMD paragraph 217]
I am also troubled by the apparent intent of the Commission to
extend its reach to areas that have traditionally been within the
purview of the States. For example, in the name of curing alleged
discrimination perpetrated by retail electricity customers against
power marketers of the Enron mold, the Commission proposes to extend
its jurisdiction to bundled retail rates--an area with which the
federal government is ill-equipped to deal. In the name of returning
industry stability, the Commission is claiming a role in establishing
generating reserve requirements for retail service providers another
traditional responsibility of the states. FERC is also usurping state
authority in areas such as demand-side management and transmission
planning. In short, the Commission appears intent on federalizing much
of the electricity system of the United States.
I have concerns that the Commission's approach in implementing the
Standard Market Design will force a costly and unworkable result that
does not squarely address the root causes of industry instability and
does not benefit electricity consumers in Arizona or other Western
states. Given the fact that the proposed rule asks more than one
hundred questions it seems far from certain that the legal authority
and policy basis to develop this rule are iron clad. Recent statements
by the Commission emphasize the importance of bilateral contracts,
regional transmission planning and resource adequacy. Although these
issues are indeed important, the emphasis diverts attention from the
more costly and risky mandates in the SMD NOPR, such as the requirement
to transfer control of transmission to newly-created transmission
operators, or the requirement for transmission providers to create and
operate costly power exchanges, or the requirement that limited
transmission capacity be rationed using financial derivatives called
Congestion Revenue Rights.
I would prefer to see more emphasis in the Standard Market Design
proposal on working cooperatively with stakeholders to develop
solutions rather than the command and control direction in which the
Commission appears to be heading. In fact, the Standard Market Design
rule appears to cut short cooperative efforts to form voluntary
Regional Transmission Organizations in the West. While I understand
that the Commission is trying to foster competitive markets, I am
troubled by a proposal that appears to require a heavy hand from
utility regulators inside the beltway. As a fundamental manner, we need
to make sure that cooperative efforts to coordinate resources in the
West are not compromised by the Standard Market Design proposal.
Finally, I am quite troubled that this proposed rule does not
adequately protect the retail service obligations of jurisdictional and
non-jurisdictional utilities. As the Chairman knows, this has been a
concern of mine for some time, and I am disappointed that FERC has not
fully addressed this in its Standard Market Design proposal. Utilities
that have an obligation to serve retail customers have, largely at the
behest of State regulators, built the physical assets to deliver power.
We need to ensure that these local service obligations are
appropriately preserved.
As I understand it, under the proposed Standard Market Design, FERC
wants utilities to trade the physical access to transmission facilities
for a financial right to the dollars others are willing to pay for the
use of the facilities. These financial derivatives, called Congestion
Revenue Rights, or CRRs, may sound good from an accounting perspective,
but I have concerns about how it will work from an operational
perspective.
When you must depend on electricity to maintain a healthy living
climate, preserve food, and even run life saving medical equipment, it
raises grave concerns that we are trading physical reliability for a
financial benefit. In the case of the Standard Market Design proposal,
we should be careful not to be lulled into thinking that the financial
assurances under standard market design can replace physical access to
the actual facilities that a utility built to serve local retail
customers. This clearly needs to be addressed before this rule is
promulgated in final form.
I thank the Chairman for convening this hearing and look forward to
hearing from our witnesses.
The Chairman. Thank you.
Senator Cantwell.
STATEMENT OF HON. MARIA CANTWELL, U.S. SENATOR
FROM WASHINGTON
Senator Cantwell. Thank you, Mr. Chairman. I think that
many of my colleagues from the West, Mr. Wood, have articulated
our great concerns about this. I think there is a fundamental
question about how a proposal like this gets as far as it has
gotten, given where we have been with all the other issues in
the West.
I want to take an opportunity before I express my comments
to welcome Marilyn Showalter from Washington Sate's Utilities
and Transportation Commission, who is going to be on one of the
later panels this morning.
But I guess, Mr. Chairman, I overheard a statement that I
could take a little more time, since I was not here at the
opening statements, so----
The Chairman. Yes. You will have 7 minutes, 6 minutes and
20 seconds.
Senator Cantwell. I will start talking fast.
Obviously there is great concern, and I guess from an
overriding perspective this is almost mind-boggling for people
in the Northwest. I mean, we still have 50 percent rate
increases in some parts of our State, maybe more, and another
rate increased proposed for this fall coming up. These are
people who are going to be paying a 50-percent rate increase
for the next 5 or 6 years because of the debacle that we have
had in energy, and the fact that--and prior to your taking
over, obviously--I would probably give FERC an F for the way it
handled this situation with California, and not moving quickly
enough to step in.
So we have 50-percent rate increases in some areas of our
State that people are going to live with for the next 5 years.
You have yet to rule on whether prices were unjust and
unreasonable in my State, and we have yet to see any relief for
the Northwest. Now you are coming to us with all of this
unfinished business with all of the things that are going on in
our country and in corporate America, and saying, ``you know,
here is a new market theory that we ought to try.''
Now, I understand efficiencies, and I understand that there
are things that we want to do to better get resources on the
energy grid in more efficient systems, but I have many concerns
with this 630-page report that makes the California model look
simple by comparison. So I am very, very concerned, as are my
colleagues, about how this plays in the West.
And Mr. Chairman, I do have a longer statement about this
that I would like to submit into the record, but I would just
like to say it is unclear to me what the urgent need of this
proposal is. Maybe you can answer a question and tell me that
no, Northwest ratepayers will not see any rate increases from
this. I don't know if you want to make that guarantee today.
But let me point out a few other things. I think that
fundamentally for us, in addition to what some of my colleagues
have said, this proposal completely ignores the unique
relationship of hydropower to the Northwest. Perhaps you are
going to talk about some of these other parts of the world that
this system has been put in place. But I do not know if it has
ever worked in a system so unique as the Northwest's--
particularly given the commitments and constraints that we have
on our system.
Would not the model that FERC proposes here, with an
independent transmission provider controlling the dispatch and
redispatch of hydro-based power based on pure marker signals,
subvert requirements to protect the Endangered Species Act,
meet our treaty obligations with Canada, and operate the
railroad for multiple purposes, including irrigation,
navigation, recreation? It is a complex system. It has other
requirements that it has to meet statutorily.
Would not replacing a competitive model with one based on
pure competition undermine the optimization of the hydro
system, to the detriment of consumers in the Pacific Northwest?
After all, the operators of the dams on one part of the
Columbia are completely dependent upon operations of projects
upstream, which may have different owners and obligations. That
is, the hydro system is operated by a mix of Federal and non-
Federal entities.
So in other words, how does this competitive SMD model work
in systems where 70 percent of the generating capacity is
completely interdependent, and relies on a single fuel source--
the Columbia River. And doesn't FERC's proposal to put an
independent transmission provider in charge of activities such
as long-term generation and transmission planning conflict with
the existing Northwest Power Act? I do not even think it could
be implemented and be consistent with the Northwest Power Act.
So I, like my colleagues, have great concerns and, as I
mentioned, find it mind boggling that we are even here this
morning, given the pain that my State is still facing due to
high energy costs, resulting from what my constituents see as a
failure by FERC to act sooner. So now, we have one more
``trust-us'' market-based proposal that we cannot understand,
that even conflicts with the nature of one energy system and
existing statutes. So I guess my first question is, will you
promise Northwest ratepayers that they will not see a rate
increase as a result of this proposal? And secondly, how can
you argue that it complies with the unique mandates that the
Northwest has, these various other Federal mandates like the
Endangered Species Act and the Northwest Power Act?
Mr. Wood. Well, clearly the other acts have to control. I
mean, this is a Federal regulation, those are statutes, and so
as we----
Senator Cantwell. So then you would not be able to
implement this.
Mr. Wood. It may be difficult, certainly. I think we are
grappling with that in the RTO West's filing that we are
talking about tomorrow at our open meeting, and there are
certainly some obligations that BPA in specific has under their
enabling statutes, and under the Northwest Power Act statutes,
that really kind of create a little bit more complexity, as you
laid out, to this issue.
But to address the core issues, Senator Cantwell, the
reason we are here today talking about this is because of what
happened the last 2 years. We would be absolutely remiss in our
job if we did not try to analyze what went wrong, and we have
done so very thoroughly, what went wrong in that market, and
how to make sure that it does not happen again so that your
customers are not paying 70 percent higher rates.
Senator Cantwell. I am totally baffled by that statement.
We are talking about cost-based rates in the Northwest, and you
are saying now, let us move closer to the hocus-pocus of market
deregulation without FERC doing its job.
I mean, if you want to say, ``here is my proposal, those
rates were not just and reasonable for the Northwest, here is
the relief I am going to give you to help clean up the mess
that has been caused, here is where I am going to make sure
that you get the refunds and get out of the long term contracts
that you deserve. Now, let us talk about moving forward.''
There might be a different discussion under those
circumstances.
But we are stuck with high rates for the next 5 years, and
to most northwesterners it sounds like, ``okay, we are going to
come up with a new market-based proposal, and who knows what
that is going to mean for you.''
Mr. Wood. The issues that you referred to are pending
before the Commission. They are moving forward in their due
process with, I think, as much haste as is possible. It is very
clear that the Commission wants to get these issues and those
of your neighbors to the South resolved as soon as possible. I
wish that did not happen in the 2000-01 time period either, but
I was not here.
Now that I am, we want to make sure this does not happen
again, that we are not stuck in legal and political in-fighting
that is going on now with our Commission for over a year and a
half, in trying to put the pieces back together of what
happened. The market mitigation, which is an important part of
overseeing the market--it is not a free market market, because
there is mitigation there. These tools do not work effectively
if you do not have the whole piece put there, so I mean, we
cannot just put out market mitigation, as we did for the
California market with our kind of, plug-the-dike order last
summer, without trying to take some steps to make sure that in
fact the infrastructure investment comes back into the West,
comes back into the Southwest and the Northwest to continue to
build ahead of when customers need it.
So it is difficult to solve one problem without addressing
what the whole tapestry looks like, and if we got the tapestry
wrong--that is why this is open for comment. It was important
for us to talk about all the issues, to have the outreach that
we had, and I put in my testimony under appendix B the
extensive outreach that we have done to learn from parties,
both commissioners, and commissioners and staff, and some were
staff only, and that outreach continues.
But that is out there for comment. We will certainly hear
back, as we have already begun to hear from folks in the
Northwest. I expect that our discussion tomorrow on RTO West,
which is a live proposal put forth by people in the region who
understand it best, will govern and dictate a lot of what we
have learned, but that does not stop the learning.
So I do think it is important, Senator, to recognize that
this proposal here is a response directly to the debacle that
happened in your part of the country, and our genuine and
thoughtful and practical--not theoretical. These are from
things that have worked, and worked in places around the world
today, that those will be on deck.
Senator Cantwell. I know my time has expired, but I would
love to see where it has worked on a hydro system that has
these other responsibilities. You know, you mentioned that it
may be difficult to implement this given those requirements, so
if it is difficult to implement it, or impossible, given the
Northwest Power Act or the Endangered Species Act, would you
exempt the Northwest?
Mr. Wood. I do not think that would be serving your
constituents well by just carving them out of what we need,
because you asked the first question, is this going to make
rates go up? The point is to make costs and rates go down and
stay down, and if we would say one part of the country is not
deserving of that kind of improvement, then I would not be
doing my job.
If the law itself, the Northwest Power Act, that says
Bonneville cannot make all this work and they have to let it
out, that would be unthinkable.
Senator Cantwell. So you are saying the answer to Northwest
consumers is that rates would go up.
Mr. Wood. Would not go up as a result of this.
Senator Cantwell. You are willing to stand by this proposal
and that Northwest ratepayers would not see an increase in
rates?
Mr. Wood. As a result of this, correct.
The Chairman. I think we will save additional questions for
the next round.
Senator Cantwell. Thank you, Mr. Chairman.
The Chairman. Thank you very much.
Senator Smith.
STATEMENT OF HON. GORDON SMITH, U.S. SENATOR
FROM OREGON
Senator Smith. Thank you, Mr. Chairman. I think it is
apparent that we need this hearing, and I appreciate your
holding it, and Chairman Wood, it is nice to have you here. I
appreciate you coming.
I know you are taking a grilling, but it is very important
that we give you this input from primarily Western Senators and
I must associate myself with my colleagues, both Republican and
Democrat, who are expressing the most earnest kinds of
reservations who are in opposition, and as I have evaluated the
proposal that is the standard market design that is supposed to
get rid of the pricing discrimination, it does seem to me that
it is well-motivated, but it is misdirected, because it assumes
that there is a national energy system that can be regulated by
an active FERC chairman like you.
Not all FERC chairman have been active like you, and I
think we need to make sure that whatever is set up ultimately
can be run by an active or an inactive FERC chairman, and I do
not think that this provides for that at all.
But I think the reason this so misses the mark is because
every part of the country has had its electricity developed
based on its own experience, its own history, its own policies,
its own incentives, and the Pacific Northwest in particular was
the product of the vision of Franklin Roosevelt, when he went
to that area in the middle of the Depression, saw that only 30
percent of the land mass of the Pacific Northwest even had
electricity. He began building all these dams, and electrified
all of the Northwest on the basis of a vision that said, it has
got to be available to everyone.
And from what I understand about reading about your
proposal, and this is a quote, allocating scarce transmission
capacity to those who value it most, in my opinion, that goes
to the heart of what is wrong with this proposal if we are
going to continue serving all of the public, not just those who
value it most.
For example, Senator Cantwell, Senator Wyden and myself
have farms, mills and rural communities that simply cannot
compete monetarily with urban areas for transmission service,
but they nonetheless deserve it. They have got it, and they
want to keep it, and they are already paying much higher rates
now than they used to pay, and it does seem to me that in
addition to a breach of faith with vulnerable rural economies,
we are now going away from the vision of Franklin Roosevelt and
saying that this is just going to be on a market system and a
wholesale out here, but by the way, all you retailers, all the
legal obligations you have to provide service, somehow you have
got to provide that service and rely on this wholesale market
that you have no control over.
So I think this is what my colleagues and I are all saying,
that this national Washington proposal just simply
misunderstands the uniqueness of each energy basin, if you
will, and ours in the Northwest, California certainly had its
own problems because of its own making, but I think it is fair
to say that our Governors and us as elected representatives are
deeply skeptical of this one-size-fits-all approach, well-
motivated, and I do give you credit for that, but I do not
think it fully appreciates the regional concerns and the
history and the effort that is going on with these regional
transmission organizations.
So those are my concerns, Mr. Chairman. I will submit my
full statement to the record, but Pat, I wonder if you can tell
me, I guess tomorrow--you are taking up the RTO West proposal.
What is FERC going to do with RTO West tomorrow as it considers
this national proposal?
[The prepared statement of Senator Smith follows:]
Prepared Statement of Hon. Gordon Smith, U.S. Senator From Oregon
Mr. Chairman, I appreciate your willingness to conduct this hearing
today on the notice of proposed rulemaking on Electricity Market Design
and Structure, issued by the Federal Energy Regulatory Commission on
July 26, 2002.
Let me make my position perfectly clear up front. I am opposed to
this proposed rulemaking, which has raised serious concerns among
utilities in the Northwest and with the Western Governors' Association.
I hope the conferees for the national energy legislation will use the
energy bill to send a strong signal to the Commission not to impose
this 600-page proposal on the nation.
This proposed rulemaking, referred to as Standard Market Design,
is--in my observation--akin to using a sledgehammer to kill a gnat.
FERC is proposing a radical restructuring of the electricity market at
the wholesale level in order to correct supposed undue discrimination
in transmission services. It is not at all clear to me that such
discrimination exists in the Northwest, or that my constituents will
benefit if this proposal is implemented.
The entire West Coast has already suffered through extreme price
volatility in the wholesale electricity market in late 2000 and 2001.
My constituents are still paying for this volatility in rates that have
gone up 45 or 50 percent in the last two years.
What my constituents and the energy-dependent industries in the
Pacific Northwest really want is price stability and universal access
to electricity. In my view, this proposed rulemaking gives them
neither.
It proposes not universal service, but allocating ``scarce
transmission capacity to those who value it the most.'' Let's not kid
ourselves: those who value it the most, and those who can pay the most
for it, are not necessarily the same. We have farms and mills and
struggling rural communities that can't compete monetarily with the
urban areas for transmission services, but who deserve them
nonetheless.
In the 1930s, universal electric service was the public policy goal
of this nation, when only 30 percent of the rural population in the
Northwest had electricity. It was the vision of Franklin Roosevelt, and
the great public works projects on the Columbia River, that electrified
the Northwest. I'm not going to stand by and let regulators unplug the
rural Northwest in the name of competition.
I fail to see how the wholesale transmission system, as it would be
restructured by this proposal--would mesh with highly regulated retail
electricity providers, which have a legal obligation to keep the lights
on in their service areas.
It is also unclear to me how this will affect the regional
transmission organizations that are being developed, such as RTO West.
While there remains significant opposition to RTO West within the
Northwest, all the stakeholders have negotiated in good faith for over
a year to reach the current terms and conditions. Now the message from
FERC is that, once again, the ground rules will change, long-term
agreements won't be honored, and there is no guarantee that retail
providers will have the transmission access they need to keep the
lights on.
I urge the Commission to move slowly on these issues. Regional
transmission organizations should not be established until all the
ground rules are known, until retail providers can be assured they will
have the transmission capacity they need to serve their customers, and
until we know that customers will benefit from these changes.
Mr. Wood. Let me just say as a practical and as a legal
matter I cannot discuss the Commission's anticipated vote
before we actually vote, but let me share my personal thoughts
about the filing there, and these are the same thoughts that I
shared when I was in your home State back in June, and visiting
with the wide panoply of parties who in the past 2\1/2\ years
have put a lot of time and effort into making RTO West work, or
the vision work, because as you point out, it needs to be
regional impact.
I would hope that this system does not predicate on an
active FERC chairman. We intend to be it, because I am
committed to it, my colleagues are, and our staff are, but this
point is to empower the region, and I think certainly your
region more than most has had a history of working together,
certainly the Northwest part. What we found in 2000, 2001 was,
it is not just the Northwest, it is the Canadians, it is the
Californians, it is the desert Southwest, it is the whole
group, and certainly the lack of integration of those three
marketplaces did make it difficult.
But I think it is important to view that what FERC does is
to be the catalyst to make that happen, and the RTO West's
effort is certainly one that I think is setting the mark for
the country. I think a lot of people have, I think,
characterized the proposal as just rubber stamping the Mid-
Atlantic, which is--PJM is the name of the company, or the
group that works here.
I think actually we have been as educated by the efforts
from RTO West and from, interestingly, the California market
redesign efforts, and a lot of the give and take that is going
on there, to really learn what real people do, not what
theoreticians do but what real people do in the marketplace,
and I personally find the RTO West effort significant.
I think it probably--there is not a lot that would need to
be done to comply with the standard market design. I voted on
the rule, and as I look at the proposal--now, my colleagues
might have different feelings. I am not sure they do, but I
will give you a call tomorrow afternoon and let you know how we
came out, but yes, I should say--and I am not saying because it
is what you want to hear, but it is the truth.
I mean, the RTO West filing--we have got another big filing
in the deep Southeast, were filed in compliance with a 1999
order, but they are very good, and there is a lot there. I do
not know that the incremental issues raised by the more
comprehensive approach here are going to require some of these
folks that are at the front of the class to do a whole lot
more, and I think that is probably the good news of the day, is
that the SMD has been largely complied with, or the promises,
or the tariffs laid forth by the parties in these different
parts of the country are pretty much there.
Now, I think they are legitimately concerned that the
efforts that they have put forth so far would be scrapped by
what we do here. I want to just say publicly that is absolutely
the opposite of what we intend. We intend to build upon those
efforts and to use the best lessons of what we have learned in
our 10-month outreach and education session around the world to
find out what, in fact, we are not doing exactly right, and
make sure that we get it better, but you know, tomorrow's news
ought to be pretty good.
Senator Smith. My times is up, I am sorry. I just did want
to ask, Mr. Chairman, if you would respond about the long-term
contracts issue and where you think that is in all of this, and
I will stop.
Mr. Wood. The existing ones? Well, certainly the vision
that we have here, like it is in the gas markets and most other
commodity markets, is predicated upon long-term contracts
between buyers and sellers, that that is really the paradigm
that we build upon, and that the spot market is used to fill in
the voids when it either gets really hot one day or really
cold, or when they are needed to really bring it up to 100
percent of the need, so that is kind of the way that markets
have developed, certainly the way that they are strongly
developed up in your region, the place where they grew up. All
of it is very bilateral contract oriented.
There is more of a centralized power pool market over in
this part of the continent, and that is certainly accommodated
with the rule, but certainly in my mind, to pick a number, 85,
90 percent of the power sold each day would be under some sort
of longer term contract and not off of the spot market, so the
volatility that we saw as a result of California depending 100
percent on its spot market for its needs, that kind of
volatility, where you buy it just an hour ahead of when you
need it, would be gone, and I think that is certainly what has
helped calm those markets down to date, is the fact that
California has moved significantly out of the spot market into
a longer term contract.
Senator Smith. Thank you, Mr. Chairman.
The Chairman. Senator Murkowski.
Senator Murkowski. Thank you very much, Senator Bingaman.
Mr. Wood, let me first of all congratulate you on moving as
rapidly ahead as you have with FERC's revisions, and let me
remind you also that in moving ahead, you have moved a little
bit ahead of the committee, as evidenced by the concern
expressed here. Sometimes it is advantageous to kind of build
up a little interference as you prepare your new proposals.
You know, there are concerns here that are certainly
meritorious, others raise some doubts, and one of the concerns
I have is your decision to assert jurisdiction over retail
transmission, thereby preempting the States, and I can
understand the uniformity, one size fits all, but in reality,
one size does not fit all, because you have two entities. You
have public and private power, and you are not treating them
with the same application.
As I understand your proposal, it applies to investor-owned
utilities, but not public power. Thus, in areas where public
power plays a major role, you have got an inconsistency. It is
my understanding that Bonneville Power in the Northwest, and
TVA in the Southwest, or in Nebraska, which is wholly owned by
public power, or in Georgia, where one half of the transmission
is owned by public power, it is my understanding that FERC does
not have direct jurisdiction over public power transmission, so
I wonder, how can your standard market design work if it does
not apply to public power transmission? Are you going to be
needing authority for public power transmission, or just how
are you going to handle it?
Mr. Wood. A great question. I would say, certainly, the
examples you gave were people who were volunteering to comply,
or volunteering to participate in the market. Both Bonneville
and RTO West, TVA through some announced memorandum of
understanding with all its adjacent utilities, or RTO's, the
integrated municipal Georgia system has filed as part of the
Southeast RTO, Southeast Trans-RTO, a number of the municipals
in Florida are participating there, and throughout the Midwest
a number of smaller public power entities.
Salt River Project, kind of a little bit different approach
in the West Connect, and WAPA, kind of an open question out in
the West as well.
It does make it difficult, Senator Murkowski. I am not one
to go grabbing for jurisdiction lightly, despite any views of
the world that we did so on the retail transmission issue, but
I think we can make the public power issue work. It is the same
issue that we have got with the Canadians, for example, and the
need to have them participating in the U.S. power markets is
pretty evident, both because they are a big potential supplier
of resources to the United States, but because they are just
physically interconnected.
So I do think that both the Canadians and the publics have
got to be more encouraged to be part of the system. They are
not, and I do, based on my own experience in doing this in my
home State, think that if we design it well, and I think we
will, that these folks will want to participate because it
improves the capacity for their customers to get benefits, but
as a direct statutory matter, you are correct, Senator, we do
not have the reach into that part of the industry.
Senator Murkowski. Is it your intention to ask for that?
Mr. Wood. We have followed closely the deliberations of
this body and of our sister oversight committee in the House,
and I have understood that that did not get the votes to make
it through, so I think our move is to go to plan B and try to
work it maybe the less efficient but perhaps in the long run
the better route.
Senator Murkowski. Well, as shown by the concerns that have
been expressed here--putting FERC in charge of utilities,
planning, meeting future power needs, generation, and
transmission--you have moved from traditional responsibilities
of the States into an overall FERC responsibility. Now, that is
taking on quite a chunk of opposition there, where
traditionally those jurisdictions have been within the States.
What makes you think you can do it better?
Mr. Wood. Sir, in fact the planning issues are ones that we
encourage to be done regionally.
Senator Murkowski. Planning is regional, okay.
Mr. Wood. We do not want that. A lot of this stuff, in
fact, we are trying to empower regional organizations to do
them with regional bodies. For example, the National Governors
Association in July endorsed a process for multi-State
entities--they call them MSEs--to in fact represent each of the
States in the region to do the long range planning for a region
and to work with the RTO's or utilities in that area to get the
transmission built, or to get the generation sited, and we
strongly endorse that process. We just need to see that it
happens.
I mean, 5 years of talking about planning does not get
anything built. We do need some process that will actually lead
to State approvals of siting, and siting and construction of
needed transmission or generation, and we do not envision that
that be done at FERC at all, but we need to make sure that
somebody gets it done, because it is so important to get the
infrastructure on the ground.
Senator Murkowski. I have just got a few seconds left. Let
me go back to public power. It is my understanding that public
power wants to basically be free of FERC jurisdiction as well
as renewable portfolio mandates. How can you have your plan
applicable across the board if public power is exempt?
Mr. Wood. It is going to be difficult, admittedly.
Senator Murkowski. Well, I know, but first of all, do you
agree with public power's position?
Mr. Wood. That they not be jurisdictional? I think it would
work better if they were jurisdictional, but I also am willing
to work with whatever the law you all give me is, and I think
we can make the one that we have got now, that has holes like
Swiss cheese, we can make that work. Admittedly it would be
easier----
Senator Murkowski. I do not know how you can rationalize
uniformity when you have a segment exempt, and it would seem to
me that you would continue to lack the ability to achieve what
you are trying to do, and that is basically consolidate an
application that would apply to both public and private power.
My State of Alaska is not connected to the interstate grid, so
therefore we are exempt from your proposal, so we are going to
sleep well tonight.
[Laughter.]
Senator Murkowski. Thank you, Mr. Wood.
Mr. Wood. Thank you, Senator.
The Chairman. Senator Domenici.
Senator Domenici. Mr. Chairman, I arrived rather late, and
I just would ask that a statement that I made be made a part of
the record.
The Chairman. It will be included.
[The prepared statement of Senator Domenici follows:]
Prepared Statement of Hon. Pete V. Domenici, U.S. Senator
From New Mexico
Mr. Chairman, this hearing addresses an issue of growing importance
in providing reliable electricity supplies across the nation.
I understand that the issue of this hearing, Standard Market
Design, may have implications for the Comprehensive Energy Bill. In
addition, the House Energy and Water Development Appropriations
Subcommittee has inserted language on this issue into their bill and
this will have to be discussed in Conference for that Bill.
I want to especially thank Jeff Sterba, who joins us today from PNM
Resources in New Mexico. Jeff, I appreciate the thoughtful letter and
paper you've provided to me on this issue.
This hearing should help to develop more knowledge on this complex
subject. But from what I know now on this issue, I must express serious
reservations about the approach taken by FERC to date.
A sudden change by FERC to Standard Market Design for the power
industry has immense implications for the entire nation's electrical
supplies. Given the recent turmoil in the industry, this hardly seems
like the time to be rushing toward introducing another gigantic change.
Standard Market Design may have some benefits to the consumers, but
it may also dramatically undercut incentives for private investors to
develop new transmission systems. As a minimum, it changes the ``rules
of the road'' for operations of the entire industry.
I am very concerned that FERC is proceeding on a very rapid time
scale, far too fast for careful study and public comment. There is
insufficient time for markets to consider its implications and
disruptions. It may inject immense financial uncertainty into the
industry as well as compromising the reliability of electrical service.
In my view, Standard Market Design deserves far more careful study
before decisions are made on possible introduction of some of its
features. I look forward to the hearing today to advance everyone's
education on this complex issue.
Senator Domenici. I would just make one observation, or
two, I guess. First, I want to compliment you on the job,
commend the President for putting you there, but that is the
end of my accolades for the day. I have not had a chance to
review what you proposed in depth, but I have reviewed it
enough to feel very strongly that you had better go slow,
rather than fast. I think it is extremely complicated, and
sometimes we end up thinking we know, only to find that after
we have done it, it has ramifications that we did not
anticipate.
I believe, contrary to public opinion at this point, people
think everything is all right on the natural gas side of
America. You know better. It is not all right. In the market,
in the production side it is going all over the place. You are
familiar with that, and clearly there is a great consternation
in a market that was in very good shape and looked like it was
going to be able to say that they could supply us with our
energy needs for an awful long time. They are very concerned,
and when they are concerned, and those who are selling this
product that you are going to regulate, through the regulating
of the delivery system, it is a huge, huge enterprise with
great ramifications, and all I can say to you--I am not sure I
would support it, but if I would, it would certainly be on the
assumption that you will take as long as possible.
The middle of next year is a date being thrown around. that
is far too soon in my opinion, Mr. Wood, and I would be very
careful if I were you, especially if those in the industry are
throwing up legitimate, practical examples, and we have in New
Mexico Mr. Sterba, the chairman of our largest utility, Jeff
Sterba, and although he is the one who produces the product for
the consumer, we listen to the consumer, but on technical
issues we think he has a cadre of people that know what they
are talking about, and when they tell us it will not work on
the schedule you have got it going, it worries me, because if
they say that I would assume there would be plenty of others.
So as I said, because I commend you for taking this job
does not mean we should agree on every issue, and on this one I
certainly do not, and I thank you so much, nonetheless, for
your service.
Mr. Wood. Thank you, sir, and I assure you and the members
of the committee that we are going to work through all these
issues with Mr. Sterba and others to make sure that we do
address the--there are very real problems in these energy
markets, sir, as you point out, sir, and the gas industry is
not immune to that either, and I do think that setting aside as
a potted plant is not what I came here to do, and I think
getting very public and asking the smart people in the world,
as you mentioned, relying on the technical experts, is what we
have done for the last 10 months, and this is what we learned
from this process, and it was very different than where I would
have started had I been a smart boy writing all the answers.
We learned and listened, and my colleagues and I went back
and forth with each other, with a number of parties from across
the spectrum, from traditional utilities to renewable energy
providers and everybody in between, to really understand what
these issues are. There are a lot, and I think you will hear
today there are a lot of varying opinions on some very critical
issues, and somebody has got to make the cut, and that was our
job, is to do, I think ought to do, which is make the hard
decisions and justify them, and I want to use the time ahead to
reexamine if we made the right decisions, but also to take the
ones that we have made that we do feel comfortable about and
explain to you and your colleagues and to others why we came
down the way we did, and why we think it is good for the
country.
So I look forward to any opportunity to do that with you,
Senator Domenici, and any of the committee, and certainly
anyone else.
Senator Domenici. Thank you, Mr. Chairman.
The Chairman. Thank you very much. Chairman Wood, thank you
for your time. We have nine other very distinguished witnesses
here, and we want to get on to them, and we appreciate your
willingness to answer our questions, and we can look forward to
continue working with you.
As I am sure you heard from Senator Domenici and many
people here, there is a great concern about the law of
unintended consequences around here, and I am sure you share
that concern, and that is I am sure what we will hear from some
of our other witnesses as well, but thank you very much for
your testimony.
Mr. Wood. Thank you, Mr. Chairman.
The Chairman. Our next witness is Governor Paul Patton, who
is the Governor of the State of Kentucky, and he is here to
give us the views of his State and other Governors. Thank you
very much for coming, Governor.
STATEMENT OF HON. PAUL PATTON, GOVERNOR,
COMMONWEALTH OF KENTUCKY
Governor Patton: Good morning, and thank you, Mr. Chairman
and other members of the committee, for listening to me, and I
do speak for the State of Kentucky this morning. I am pleased
to have this opportunity to speak about what is obviously one
of the most important energy issues to ever impact the Nation,
this notice of proposed rulemaking recently published by the
Federal Electricity Regulatory Commission to impose a standard
market design for electricity in the United States.
I realize it is its first responsibility and that of the
Congress to support policies that are in the interests of the
entire Nation, and I respectfully submit that FERC's proposed
rules do not meet that criteria. This proposed rule is moving
us toward an energy policy that benefits a few at the expense
of many. Specifically, we are very concerned that this may put
us on a path towards mandated retailed restructuring. FERC
Commissioner Nora Brownell was quoted in last Sunday's press
acknowledging that this rule will primarily benefit States that
have restructured electricity markets. Presently, only 15
States have done so. 35 States have chosen not to remove
jurisdiction from their State regulators at this time, choosing
instead a system that works, and provides safe and reliable
service.
This proposed rule represents a slippery slope that States
like Kentucky fear is heading to mandated deregulation of the
retail electricity market. In my brief comments today, I want
to impress up on you three major points regarding FERC's
standard market design.
The first point is that the FERC rule will have unforeseen
and, as you said, unintended consequences. The second point is
that I am concerned about FERC's policies regarding who pays
for transmission upgrades and expansions. The third and final
point is that we need a cooperative effort that benefits the
entire Nation and takes into account the unique regional
differences in electricity markets, not a mandate from FERC.
The first of the three concerns that I have is that FERC's
proposed rule will have unforeseen and unintended consequences.
This is a policy change that cannot be taken lightly. We think
that Kentucky is a model for cost-based regulation. We have
done it successfully, and our efforts have yielded adequate
generation and transmission capacity for the future.
This rule was written to address perceived discrimination
against certain transmission users, and the rule does not fix
that. If anything, it reverses discrimination, so that Kentucky
and States that have a low cost electricity are penalized to
benefit those who do not. Kentucky consumers will pay more for
their electricity as a result of this rule. Given our lack of
dependence on the wholesale market, our consumers will see
little to no benefit.
Chairman Wood has pointed out that the rule will allow
States to keep their low-cost power through long-term
contracts. Kentucky has two recent experiences which clearly
indicate that suppliers are unwilling to commit to long-term
contracts at the existing cost of service rates if they can
realize greater profits on the wholesale market. FERC itself
left a vast amount of uncertainty in its proposed rule, asking
for comments on at least 100 points.
Even so, this rule is on a fast track. Per our request
along with others, FERC has granted an additional 30 days for
comment, and we appreciate that. Still, the speed with which
FERC wants to move forward and implement these rules is
alarming. We have already seen what happens when markets
undergo dramatic change too quickly. People in California and
the surrounding States are still reeling from the unforeseen
and unintended consequences of the failed California
restructuring effort.
The recent action by the House Appropriations Committee
requiring a cost-benefit analysis of the proposed rule
indicates that other members of Congress share this concern.
Second, I am concerned about FERC's policies regarding who
pays for transmission upgrades and expansions. To States that
have ensured adequate generation and transmission facilities
through responsible planning, the issue of paying for
transmission expansion is of utmost importance. These States do
not believe it is fair to have their consumers pay for
transmission expansions to accommodate the wholesale market.
The Southern Governors passed a resolution opposing
socialization of transmission expansion and upgrades, and
endorse participant funding, meaning, those who benefit from
the expansion pay.
Chairman Wood responded to the media, and by letters to the
Governor, stating that FERC, in fact, agreed that, quote,
``participant funding was the most effective policy for the
future.'' We are pleased that FERC has realized this. We are
saying the words--let us make sure we are talking about the
same thing. The proposed rule does not make participant funding
available for 2 years, and even then, it is only available in a
regional transmission organization. Worse than that, it is
ultimately the RTO who decides who bears the cost.
In Kentucky, where several utilities have joined RTO's, we
still have concerns. We have participated in negotiating
agreements with the RTO. However, we are troubled by the fact
that FERC has rejected at least one such agreement on RTO
costs. This demonstrates that FERC does not respect a
negotiated agreement by a regional body.
Also of concern is a statement in Chairman Woods' letter to
the Southern Governors saying, quote, ``a regional approach to
power markets will benefit all electricity consumers.'' If
those who benefit pay is the policy embraced by FERC, and FERC
believes that all consumers benefit, then it follows that FERC
will find that all consumers must pay for expansions and
upgrades.
Yes, Chairman Wood may have tossed a bone to those of us in
States that do not support rolled-in pricing, where everyone
pays for new transmission. However, the devil is in the
details. How FERC defines benefits of transmission upgrades can
easily turn participant funding into rolled-in pricing.
The third and final point is that we need a cooperative
effort that will benefit the entire Nation, not a mandate
handed down from FERC. FERC continues to say that they want
consistency and certainty in the wholesale electricity market.
In today's economic environment, we fail to understand how this
rule, as proposed, creates the consistency and certainty that
FERC is looking for.
The rule as proposed removes jurisdiction from States like
Kentucky that have regulated successfully for over 65 years.
Rather than issuing national mandates, FERC should be reaching
out in a cooperative effort to ensure that the electricity
market works to the advantage of all. That includes utilities,
marketeers, and please, let us not forget the customers.
This rule will impact all customers, from our large,
energy-intensive industrial customers to our constituents who
pay their electric bills every month. These consumers will find
their needs best served not by FERC policymakers, but by State
regulators who live and work among them. Any effort of this
magnitude must be approached with all the stakeholders at the
table. While FERC has given a nod to the notion that one size
does not fit all, a regional voice is not a substitute for the
ability of a State to do what it does best, protect the
interests of its citizens.
I would like to thank you again for the opportunity to be
here. I hope I have conveyed the message that Kentucky does not
desire to be an obstructionist, but we do want all voices to be
heard. In Kentucky, we have taken a measured and thoughtful
approach to regulating the electric industry. We hope that the
national policymakers will learn from the lessons of the past
and avoid the temptation to adopt a national rule that does not
benefit everyone.
So I urge the Congress to support the actions of the House
Appropriations Committee and evaluate the results of the cost-
benefit studies so that you will know the actual impact on
regions and individual States before implementing this rule.
Thank you very much for your time.
[The prepared statement of Governor Patton follows:]
Prepared Statement of Hon. Paul E. Patton, Governor,
Commonwealth of Kentucky
Good morning, and thank you Chairman Bingaman, Senator Murkowski
and other committee members, for allowing me the opportunity to speak
about one of the most important energy issues to ever impact the
nation; the Notice of Proposed Rulemaking (NOPR) recently published by
the Federal Energy Regulatory Commission (FERC) to impose a standard
market design for electricity in the United States. Let me first state
that I realize it is FERC's responsibility and that of the Congress to
support policies that are in the best interest of the entire nation. I
respectfully submit that FERC's proposed rules do not meet that
criteria.
This proposed rule is moving us toward an energy policy that
benefits a few at the expense of many. While we see potential benefits
to a vibrant wholesale market with clear rules to prevent market power
abuses, our concern is that this rule is too broad and has implications
far beyond the wholesale market.
In Commissioner Brownell's statement quoted in last Sunday's press,
she acknowledges that this rule will primarily benefit states that have
restructured retail electricity markets. Presently, only 15 states have
restructured. Thirty-five states have chosen not to remove jurisdiction
from their state regulators at this time, choosing instead a system
that works, and provides safe and reliable service. This NOPR
represents a slippery slope that states, like Kentucky, fear is heading
to mandated deregulation of the retail electricity market.
In my brief comments today, I want to impress upon you three major
points regarding FERC's standard market design.
The first point is that the FERC rule will have unforeseen and
unintended consequences that will not benefit, but in fact harm many
states.
The second point is that I am concerned about FERC policies
regarding who pays for transmission upgrades and expansions.
The third and final point is that we need a cooperative effort in
developing a healthy wholesale electricity market that benefits the
entire nation, not a mandate to be handed down from FERC. Further, any
final rule must take into account the unique regional differences, and
individual state interests in electricity markets.
First, the Notice of Proposed Rulemaking (NOPR) that FERC has
issued to establish a standard electricity market design will have
unforeseen and unintended consequences. This is a policy change that
cannot be taken lightly. Kentucky is the model for cost-based
regulation. We have created and paid for generation and transmission
systems adequate to meet our need for at least the next ten years. We
have maintained low-cost power through responsible corporate management
and careful regulatory oversight. For states that have a system that is
working well, the negative impact of the proposed rule will be the
greatest.
This proposed rule was fashioned around the presumption that
discrimination exists against certain transmission users. However, the
remedy proposed by FERC greatly exceeds the perceived problem. It does
not cure discrimination. If anything, it reverses discrimination so
that Kentucky and states that have low-cost electricity are penalized
to benefit those that do not.
FERC requires Kentucky ratepayers to fund the development of the
Regional Transmission Organizations (RTO). We're concerned with the
possibility that Kentucky ratepayers may be required to pay additional
costs for services of no benefit to them. Even worse is the possibility
that Kentucky ratepayers might be required to pay for resolution of
unforeseen problems created by FERC's proposal.
At my request, and the request of other state regulators and
governors around the nation, FERC has granted an additional 30 days to
file comments on the rule. We appreciate the additional time. Still, we
are concerned about the many uncertainties, including unforeseen and
unintended consequences. FERC itself left a vast amount of uncertainty
in its NOPR, asking for comments on at least 100 points. Kentucky has
more questions than that regarding the actual impact of this rule. Yet,
even with all of the unanswered questions and uncertainty, FERC is
trying to move this rule forward very quickly. The speed of this
process seems unwarranted and even dangerous.
We have seen first hand the impact of unintended consequences when
we rush to make these kinds of dramatic market changes. The people of
California are still reeling from unintended consequences associated
with a restructured market. Furthermore, the traditionally low-cost
power states surrounding California are likewise still suffering from
the consequences of the failed restructuring initiative. The residual
effects were felt far beyond the borders of California.
It's obvious that others share these concerns. The House
Appropriations Committee passed language requiring the Department of
Energy to do a cost benefit analysis of the proposed rule. We support
the cost benefit analysis and believe it is a vitally important step
before any FERC mandated changes to the nation's electricity market are
allowed to take effect. The concerns of individual states and unique
regional differences must be considered in the analysis as well.
Second, I am concerned about FERC policies regarding who pays for
transmission upgrades and expansions.
To states that have ensured adequate generation and transmission
facilities through responsible planning, the issue of paying for
transmission expansion is of utmost importance. These states have
maintained adequate facilities to accommodate their transmission, and
do not believe it is fair to have their ratepayers pay for transmission
expansion to accommodate the wholesale market.
I received a letter from Chairman Wood regarding the Southern
Governors' Association's (SGA) concerns about this very issue. An SGA
resolution opposed FERC's move toward socializing the costs of
transmission system expansions and upgrades and urged FERC to adopt a
``participant funding'' policy where those who benefit pay. In the
letter, Chairman Wood says that in fact, FERC has made the switch to
``participant funded'' transmission upgrades. We are pleased that FERC
has made this change in its policy but we are concerned that we may be
saying the same words but not talking about the same thing. To clarify,
let me give you some background information.
First, as you know, Congress deregulated the wholesale electricity
market in 1992. Since that time, the FERC policy has been that the
``cost causer'' must pay for any directly caused upgrades or expansions
of the transmission system. Beginning last summer, FERC attempted to
reverse this policy, and move toward ``rolled-in pricing.'' This means
that all ratepayers on the transmission system must bear the cost
whether they directly benefit or not.
Second, while we are pleased that FERC has agreed with us that
participant funding is ``the most effective policy for the future,''
the reality is that in practice, that is not the way this rule will be
implemented. The NOPR does not make participant funding available for
two years, and even then, it's only available to those in an RTO. Worse
than that, it's ultimately the RTO that decides who bears the cost.
For states whose utilities are not members of any RTO, participant
funding is not even available, and customers in those states will be
penalized. In Kentucky, where several utilities have joined RTOs, we
still have concerns. Kentucky is in the Midwest region because of our
utilities' decisions to join the Midwest Independent System Operator
(MISO) and PJM. As a state with very different interests from those of
other states in our region, we cannot attain a comfortable level of
assurance that our ratepayers will be protected in a decision made by
the RTO. Let's be clear, Kentucky ratepayers have already been
penalized by FERC decisions.
MISO filed an agreement to exclude native load from paying an
administrative cost-adder associated with the RTO. However, in Opinion
453, FERC rejected that agreement, and required retail bundled load to
pay the administrative cost-adder. FERC believes native load customers
benefit from the RTO. We strongly disagree. This issue will ultimately
be decided after a lengthy and costly appeal.
FERC's decision demonstrates two things to Kentucky. First, that
FERC does not respect a negotiated agreement made by a regional body
such as the MISO. FERC rejected the agreement in Opinion 453. What
assurance do states have that FERC won't also reject future decisions
made by the RTOs? Second, FERC believes all customers benefit from
enhanced transmission services designed to accommodate a wholesale
market. In fact, in Chairman Wood's letter to the Southern Governors,
he states as much, saying that `` [a] regional approach to power
markets will benefit all electricity customers. . . .''
If ``those who benefit pay'' is the policy embraced by FERC, and
FERC believes that all customers benefit, then it follows that FERC
will find that all customers should pay for expansions and upgrades.
Yes, Chairman Wood may have ``tossed a bone'' to those of us in
states that do not support rolled-in pricing. However, the devil is in
the details. How FERC defines benefits of transmission upgrades can
easily turn participant funding into rolled in pricing. There are still
an awful lot of unanswered questions. Who determines who benefits and
how much? Is it a direct or indirect benefit? What is the timeline
associated with these benefits?
The third and final point is that we need a cooperative effort in
developing a healthy wholesale electricity market that benefits the
entire nation, not a mandate to be handed down from FERC. Any final
rule must take into account unique regional differences, and individual
state interests.
FERC continues to say that they want consistency and certainty in
the wholesale electricity market so that companies can attract
investment for infrastructure building, technological improvements, and
the development of a robust wholesale market. However, this rule
creates anything but certainty.
In today's uncertain economic environment, consumer confidence is
low, investors are leery, and capital for power plant investment has
virtually dried up. In this environment, we fail to understand how the
rule, as proposed, creates the consistency and certainty that FERC is
looking for. FERC has asked for comments on at least 100 points,
creating serious uncertainty for states, industry, and investors. The
rule, as proposed, removes jurisdiction and local oversight from states
like Kentucky that have regulated successfully for over 65 years.
According to Jonathan Raleigh, a top Wall Street analyst with Goldman
Sachs, ``the best performing stocks in the utility industry have been
those with fully regulated (state) service territories . . . in the
mind of investors regulatory change has only hurt companies and
investors.'' Let's be frank, this rule does anything but add more
certainty and consistency in the electricity market.
This NOPR is an unprecedented usurpation of state jurisdiction by
FERC. Instead of issuing national mandates, FERC should instead be
reaching out in a cooperative effort with state officials to figure out
how to make the electricity market work to the advantage of all. That
includes utilities, marketers, and please let us not forget consumers.
This rule will impact all customers, from our large energy intensive
industrial customers, to your constituents who pay their electricity
bills every month. These consumers will find their needs served best
not by FERC policy makers, but by state regulators who live and work
among them.
Any effort of this magnitude must be approached, not through a
federal directive, but with a thoughtful, cooperative effort, with all
of the stakeholders at the table. In this spirit, the National
Governors Association Task Force on Electricity Infrastructure issued a
paper entitled ``Interstate Strategies for Transmission Planning and
Expansion.'' This paper introduced the idea of Multi-State Entities or
MSEs, which would preserve state siting authority. FERC makes reference
to this concept in the rule, but proposes an advisory only committee.
Again, our concern is that our voice would be lost as one voice in a
wide regional group. While FERC has given a nod to the notion that
``one size does not fit all'' by allowing regional differences, a
regional voice is not a substitute for the ability of a state to do
that which it does best, protect the interest of its citizens.
Kentucky seeks to cooperate with FERC to find a solution. We
appreciate Chairman Wood's willingness to work with the states. In the
same spirit of cooperation, I am organizing a national conference to be
held next month in Louisville, Kentucky. The conference is called
``Standard Market Design: A National Discussion with Energy Policy
Decision Makers'' and Chairman Wood has graciously agreed to be one of
our Keynote Speakers. We have also put together a variety of national
speakers to address the impact of the rule on unique regional
electricity markets. It is my hope that by bringing together this
diverse group of people, we can work together to gain a better
understanding of differing viewpoints, and develop policy
recommendations that states can make to FERC in order to ensure that
all interests are addressed and protected.
In conclusion, let me reemphasize the three major points of my
comments. First, that the FERC rule will have unintended consequences;
second, that those who benefit from new transmission lines pay for
them; and finally, that we need a cooperative effort to ensure that
individual states are not harmed by this rule.
I would like to thank you again for the opportunity to be here and
to address you regarding Kentucky's grave concerns with FERC's NOPR. I
hope I have conveyed the message that Kentucky does not desire to be
obstructionist. We have participated in the process, and want to
continue to participate in this process in good faith. We want all the
voices to be heard. One size does not fit all, and a rush to judgment
can only bring unnecessary harm. In Kentucky, we have taken a measured
and thoughtful approach to regulating the electric industry. We hope
that the national policy makers will learn from the lessons of the
past, and avoid the temptation of imposing a national rule that does
not benefit everyone equally, and in fact will harm individual states.
I urge Congress to support the action of the House Appropriations
Committee and evaluate the results of the cost benefit studies so that
you know the actual impact on regions and individual states before
implementing this rule.
Thank you for your time and your attention.
The Chairman. Governor, thank you very much. You have done
an excellent job in articulating specific concerns that your
State has, and I appreciate that. I am not, frankly, expert
enough on the circumstances that you faced to ask you the kinds
of questions that are undoubtedly appropriate at this point. I
gather Senator Cantwell is not here now, so why don't we take
your testimony under advisement, and to the extent we have any
questions, I will submit those to you.
Governor Patton: I appreciate it very much. Thank you very
much.
The Chairman. Thank you very much for coming.
Why don't we bring the panel, the first four witnesses we
had here, Marilyn Showalter, chairwoman of the Washington State
Utilities and Transport Commission, Sandra Hochstetter, who is
the chairwoman of the Arkansas Public Service Commission, Terry
Harvill, who is a commissioner with the Illinois Commerce
Commission, and Sonny Popowsky, who is the consumer advocate
with the Pennsylvania Office of Consumer Advocate.
Let me do this. If each of you could take 5 or 6 minutes
and make the main points that you think we ought to be aware
of, that would be greatly appreciated. Your full statements
will be included in the record, and then we will see if we have
some questions at that time.
Ms. Showalter, why don't you start, please.
STATEMENT OF MARILYN SHOWALTER, CHAIRWOMAN, WASHINGTON STATE
UTILITIES AND TRANSPORTATION COMMISSION
Ms. Showalter. Thank you. I am Marilyn Showalter. I am the
chair of the Washington State Utilities and Transportation
Commission. We urge you to tell FERC to back off of its
standard market design and turn instead to the business of
regulating the wholesale markets, where there is much to do.
At the most general level, this is a clash of paradigms on
how to deliver electricity. In a cost-based model, which is
what most of the West has, utilities are obligated to serve
their customers at cost, and the regulators ensure that that
happens. Competition is a tool if it benefits the competitors,
but only if it does. In a market-based model, competition is
the objective, and it is assumed that that will benefit
consumers.
At a deeper level, this is a debate about political
accountability. This is Constitution Day. You will see in the
Constitution no reference to regional governments, or regional
entities. Ultimately, either the States or the Federal
Government has the authority.
I think of electricity in three dimensions. It is an
economic system, it is a physical system, and it is a political
system, and it is like the game, Paper Scissors Rock, where the
rock beats scissors, scissors beats paper, and paper beats
rock. If you do not get all three dimensions working in sync,
any one can defeat the other. I do not think the standard
market design works on any of those dimensions, economic,
physical, or political, but the most serious problem is with
political accountability.
Let me focus on three phrases that FERC uses in justifying
its rule, and they are, undue discrimination, independence, and
standardization. First of all, undue discrimination. The
promise of the entire rule, the legal linchpin of it, is that
FERC has found undue discrimination, and the rule sets about to
remedy this undue discrimination.
So what is this undue discrimination? It is when a utility
prefers its own customers. The first 50 or 60 pages of the rule
are devoted to a litany of ways that a utility benefits its own
customers. Well, that, to FERC, is undue discrimination because
the utility is preferring its own customers over, for example,
independent power producers. To us, that is the purpose of the
utility. That is the policy set in State law. Utilities are
supposed to benefit their customers.
Nonetheless, FERC, for the first time since the enactment
of the Federal Power Act in 1935, based on that finding of
undue discrimination, asserts jurisdiction expressly over the
transmission component of bundled retail transmission--excuse
me, bundled retail electricity, as well as aspects of resource
planning and demand response. All of these areas are currently
the jurisdiction of the States.
The second word, independence. Well, independence from
what? To FERC, the transmission provider should be independent
from the generators who are using the transmission system. To
us, this independence means independence from political
accountability.
As I mentioned, currently, a utility has an obligation to
serve its customers, and there is a triangle of political
accountability that runs from the ratepayer/voter to the
regulator to the utility, to ensure that the utility fulfills
that obligation to serve. There is also a triangle, or maybe it
is a square of fiscal integrity that runs from the utility that
needs to build the transmission, that is obligated to build the
transmission or generation, to Wall Street, that funds it, to
the regulator that sets the rates to cover those costs, to the
ratepayer who pays the money to cover those costs.
FERC's standard market design would erode these links of
accountability, because it takes these very important functions
out of the hands of public officials and places it in something
called the independent transmission provider, the ITP. The
independent transmission provider is a private corporation with
a private corporate board selected from among stakeholder
groups. It is answerable only to FERC, but only indirectly to
FERC, because what it is supposed to be doing is administering
these market rules that FERC has designed.
This is particularly distressing in the Northwest, because
80 percent of our transmission is owned by the Bonneville Power
Administration, a public entity that operates in the public
interest. In addition, in my State we have 63 utilities. 60 of
them are public utilities owned and run directly by and for the
people they serve, so instead of our current, very public and
publicly accountable model, FERC would have us have a private
model.
The point is that electricity is inherently political,
because electricity is an essential public service, and you
cannot take public out of the public service.
The final word, standardization. This is a one-size-fits-
all approach, but it will not fit all parts of the country.
First of all, just the sheer grandiosity of this proposal, with
its big, broad, complex aspects, means that the error rate, the
risk of error is great, and if there is an error, or a flaw, it
is going to affect the whole country, but in my neck of the
woods it has even more aspects, and some of the Senators have
pointed this out.
I have handed out a chart that is called, Differences that
Make a Difference, and it is all of the ways that the Northwest
power system is different. We do not really have an electricity
system. We have a river system. It serves electricity, barging,
flood control fisheries, and recreation, and you cannot hope to
plunk down a model that essentially arose out of the middle
Atlantic States and expect it to work in our region.
The Chairman. Could you summarize any additional comments?
Ms. Showalter. My final point is that FERC's proposal is a
half-baked idea. There are 130 specific instances in the
proposed rule where FERC expressly admits to a gap, a question,
something it does not know, and we are supposed to provide the
answers to it. It is as if the train is heading West, the
tracks have not been laid, FERC is telling us, well, you figure
out the answers, you lay down the tracks. We do not think we
should have to, since the basic problem that FERC is
addressing, the utilities preferring their own customers, is
not a problem to us.
We urge this committee to tell FERC to slow the train down,
in fact, stop it all together until it is certain there will
not be a train wreck.
[The prepared statement of Ms. Showalter follows:]
Prepared Statement of Marilyn Showalter, Chairwoman, Washington
State Utilities and Transport Commission
Thank you Mr. Chairman and Members of the Committee. I am Marilyn
Showalter, Chairwoman of the Washington Utilities and Transportation
Commission (WUTC). The WUTC is the agency of the State of Washington
that regulates the rates, terms, and conditions of service for the
three investor-owned electric utilities that serve 1.25 million retail
electricity customers in Washington State.
I am pleased to testify this morning on the Federal Energy
Regulatory Commission's (FERC) Notice of Proposed Rulemaking, Remedying
Undue Discrimination through Open Access Transmission Service and
Standard Electricity Market Design. I respectfully request that my
written testimony be included in today's hearing record as if fully
read.
As proposed, FERC's rule would impose the most sweeping and
fundamental changes in nearly 70 years to the structure and
institutions that provide and govern electricity service in my state,
and in the Pacific Northwest region. The rule, and the theories on
which it is based, have profound, and I believe negative, implications
for retail electricity consumers. Likewise, the regulations would put
at risk the coordinated Columbia River hydroelectric system that
provides to the Pacific Northwest not only electricity, but also flood
control, barge transportation, irrigation, fisheries, recreation, and
natural habitats.
Before detailing our specific concerns I want to summarize our
recommendations regarding FERC's proposed rule and regarding actions
that Congress might undertake. The body of my testimony will detail the
reasons for these recommendations.
Regarding its proposed rule, ``Remedying Undue Discrimination through
Open Access Transmission Service and Standard Electricity
Market Design:
1. FERC should not attempt to assert jurisdiction over transmission
used to fulfill statutory service obligations to retail customers
receiving bundled retail service from utilities subject to state
jurisdiction.
2. FERC should work with the regions and states, respecting their
current authorities, to identify real problems in wholesale
transmission and power markets and focus on specific solutions to
demonstrable problems, rather than on standardized solutions to
theoretical problems.
To this Committee and Congress as a whole, I respectfully urge: \1\
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\1\ This recommendation is also made by 48 state utility regulatory
commissioners and other public officials from 17 states. See the
statement attached as Attachment ``A.''
Note: Attachments A, B, and C have been retained in committee
files.
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1. Congress should not include in the pending Omnibus Energy Bill
any provision that expands the authority of the FERC to interfere with
the ability of states and municipalities to preserve their chosen
retail electricity service policies. If any such provision is included,
the Electricity Title should be stripped from the Omnibus Energy Bill.
2. Congress should clarify that the authority of the FERC does not
extend to impairing the ability of state or local government to
regulate any component part of a fully bundled retail sale of
electricity, or the siting of generation and transmission, that is
subject to state or other local government retail regulation.
I turn now to our specific concerns with the new rule FERC is
proposing. There are three phrases that are fundamental to the legal
basis and theory of the proposed rule, but which to me pose three key
questions that you may wish to ponder.
1. ``Undue Discrimination''--Is it undue discrimination, as FERC
asserts, for a vertically integrated, retail utility to use its own
facilities preferentially to serve its own customers in order to meet
its own service obligations under state law? We believe the answer is
NO.
2. ``Independence''--Does FERC's insistence on the ``independence''
of transmission providers provide meaningful public accountability for
key decisions that will vitally affect ratepayer-citizens who depend on
the essential service of electricity? We believe the answer is NO.
3. ``Standardization''--Is it reasonable, practical, and necessary
for the rule to impose a one-size-fits-all theory of market design
across all regions of the country? We believe the answer is NO.
In summary our concerns are as follows:
FERC's singular emphasis on a market-based system disrupts
the ability of states like Washington to preserve a cost-based,
public service model for electricity.
The proposed rule is a grandiose, untested, and risky
solution to undocumented theoretical problems.
The proposed rule represents a sweeping and unprecedented
assertion of federal jurisdiction over matters currently
subject to state authority.
The proposed rule replaces direct public accountability at
the state level with new, weakly-accountable regional
institutions that will manage and govern essential electricity
service.
The proposed rule has practical limitations and real-world
problems.
The proposed rule may actually destabilize the investment
climate for needed new electricity infrastructure.
The proposed rule is incomplete and poorly defined in a
multitude of key areas.
A. FERC's singular emphasis on a market-based system disrupts the
ability of states like Washington to preserve a cost-based,
public service model for electricity.
Washington State shares with FERC the objective of a reliable power
system that can attract needed investment and that works to the benefit
of consumers. However, it is apparent that we seek to achieve that
objective through different paradigms. Ours is a cost-based system that
FERC would disrupt with its market-based system.
My state is among the thirty or more states that have, after
careful deliberation, chosen not to implement a policy of retail
competition for electricity consumers. With the exception of a few very
large industries, consumers in Washington receive electricity as a
fully bundled service (generation, transmission, distribution, and
metering) from state or municipally regulated utilities, many of which
are vertically integrated. Utilities in Washington operate under state
laws that impose on them an obligation to meet the service needs of
their customers. Consumer retail rates are cost-based and set at a
level sufficient to recover the investment and operating costs
necessary for the utility to fulfill its service obligation.
Our system of cost-based, public utility service has worked well
for decades. Consumers in Washington State continue to enjoy reliable
and low-cost electricity service. Our system is not in any way
``broken'' and we see no reason to apply a FERC-imposed ``fix.''
FERC's proposed rule rests on the premise that a vertically
integrated utility, by its very nature, engages in undue
discrimination. That is, when a utility, in order to fulfill its own
obligations under state law, reserves its own transmission and load-
balancing generation facilities to serve its own customers, it is
practicing, according to FERC, undue discrimination. From this premise
that utilities preferring their own customers are engaging in undue
discrimination the rest of the rule flows. If this premise is
misdirected and overbroad (as I believe it is), then the rule loses its
justification.
In states with bundled retail service, utilities build generation
and transmission facilities, or contract for power and transmission, in
order to fulfill their statutory service obligation. The investment and
operating costs of these transmission and generation assets are
recovered in customers' retail rates. Thus, retail customers have
bought and are paying for the facilities that FERC now finds cannot be
used preferentially to serve them. The rulemaking correctly observes
that the majority of capacity on transmission facilities is devoted to
serving bundled retail load. This is not surprising; retail service was
and is the primary purpose of these facilities. It is why the
facilities were built in the first place.
FERC asserts that it must remedy this asserted undue discrimination
so that transmission facilities can be available to all power
competitors in competitive wholesale power markets. Absent any
direction from Congress that state retail service policies should be
preempted, we cannot help but see this as a direct repudiation by a
federal administrative agency of policies expressly adopted by states
to serve the important values they find for their citizens in bundled,
vertically integrated, retail electricity service.
FERC's proposed rule will fundamentally disrupt the ability of
states to maintain a cost-based, public service electricity system
because the rule prohibits a utility from coordinating the operation of
its generating facilities with its transmission facilities for the
purpose of providing service to its retail customers at least cost.
Moreover, the new rule will make it extremely difficult, if not
impossible, for the utility and its state regulator to plan for new
generation and transmission facilities in an integrated manner for the
purpose of meeting future customer loads at least-cost.
FERC argues that its proposed rule accommodates and does not
interfere with state-regulated retail electricity service. It claims
that transmission access rights for native load service will be
preserved through congestion revenue rights (CRRs), and that access to
generation will be preserved through the ability to self-schedule
bilateral energy transactions or owned generation.
FERC's arguments are unpersuasive. Rights to physical transmission
access are not preserved. Rather, these rights are replaced by
financial rights to receive congestion revenues. And these financial
rights are preserved only for historical loads, not for load growth.
From the perspective of native load retail consumers, financial rights
are not a substitute for assured physical capacity. Moreover, after
four years even the financial rights must be competed-for in bid
auctions pitting native load service against all other commercial
interests including the commercial interest of purely speculative
bidders.\2\ The ability to self-schedule bilateral and owned generation
also provides little comfort. The transmission cost for these
transactions will be established through thinly traded locational
energy markets. Prices in such markets are volatile and unpredictable
at best, and at worst can be manipulated for profit without regard to
impact on consumers. Finally, load balancing services are required to
be secured through the ``real-time market,'' rather than through the
utility's own generation flexibility. Consequently, both transmission
and load-balancing generation would no longer be cost-based; they would
be subject to market-determined, clearing prices (i.e., the highest
price established in the centralized markets FERC requires be
established).
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\2\ FERC likes to point out that a utility can ``bid infinity'' for
its own rights and thereby guarantee keeping them. To the extent this
is true, and occurs, the market for these rights becomes thinner and
the price for congestion hedges may be driven ``through the roof'' for
those who need to acquire new hedges. Also, this ``exception'' would
seem to be the very ``discrimination'' FERC finds to be undue, thus
undermining the legal premise for FERC's assertion of jurisdiction over
the transmission component of retail service.
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In sum, FERC's remedy for asserted undue discrimination eliminates
the ability of utilities to use their own facilities to serve their own
customers, and fulfill their own service obligations on a cost-of-
service basis under state and local laws and regulation.
B. The proposed rule is a grandiose, untested, and risky solution to
undocumented theoretical problems.
The NOPR provides no specific evidence that preferential use of
transmission to serve native retail customers has been abused by
utilities in Washington or anywhere else in the Pacific Northwest. The
proposed rule offers only theoretical examples of how vertically
integrated service to native load could disadvantage others. Further,
the NOPR provides no specific evidence that ultimate consumers have
been, or would be, harmed if utilities continue integrated operation of
transmission and generation primarily to serve their customers.
Nevertheless, based on the mere allegation that undue
discrimination could, in theory, occur and that any such discrimination
could, in theory, cause harm to consumers, FERC proposes to absolutely
prohibit vertical integration and preferential use of facilities for
native load service. In its stead, FERC proposes to require that
transmission be operated by newly formed independent institutions so-
called independent transmission providers (ITPs). Going far beyond
basic transmission operations, these new institutions are required to
operate a complex web of short-term markets for energy, ancillary
services, load balancing, and retail demand reductions. Going further
still, these new institutions are to accomplish regional generation and
transmission adequacy studies and requirements, and to monitor the
markets for abusive behavior.
The NOPR provides no estimate of the cost for establishing these
new ITPs, or the cost for operating this complex web of new,
centralized markets for energy and other services.\3\ Against these
unknown costs, the NOPR cites theoretical and unquantified benefits of
improved transaction and system efficiencies. Without any real cost
data showing otherwise, the lesson we learned from California and other
places that have established these kinds of markets suggests that the
expenses to comply with the proposed rule will be great.
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\3\ The NOPR estimates cost for compliance with the new
transmission tariff at approximately $10 million. But it provides no
estimate of the costs to set up and operate all of the proposed day-
ahead and real-time markets for energy and other services.
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Setting the direct expenses aside, the risk associated with
implementing a single market design across all regions of the country
without regard to the specific circumstances and characteristics of the
individual regions is breathtaking. Centralized energy markets of the
type proposed have proved to be extremely volatile, and susceptible to
flaws, manipulation, and runaway prices everywhere they have been
implemented.\4\ FERC argues that it has learned from all of these
errors and failings and that the market design it now proposes will fix
all of the earlier problems. But to impose such a grandiose scheme on
the theory and promise that all of the bugs have now been worked out
puts my region, and the nation, at a terrible risk if FERC's
theoreticians do not prove to be smarter and more prescient than the
experts that designed all of those other imperfect systems.
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\4\ The UK has struggled with market abuses and flaws in its market
design since its inception in the early 1990s. Recent remedies has
focused more on a windfall profits tax than on market design. New
Zealand consumers suffered extraordinary price spikes in mid-2001 (See,
for example, ``Huge Power Bills Force Schools to Cry Help,'' The New
Zealand Herald, August 22, 2001, and ``Blame Low Lakes and Reforms as
the Lights Go Out,'' The New Zealand Herald, July 28, 2001). Australian
electricity markets saw price spikes of 400 percent in mid-2002 without
any real shortage of capacity (See, for example, ``Australian
Electricity Prices Shoot up 400%,'' RiskCenter.com, June 10, 2002).
Both Texas and PJM have experienced market manipulation driving up
prices by as much as 1000 percent (See, for example, ``Texas Might Fine
Enron $7 Million,'' Fort Worth Star-Telegram, June 4, 2002 and
``Pennsylvania Accuses PPL of Gaming Power Market,'' Reuters, June 13,
2002).
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Against these real risks and costs, FERC can provide only
theoretical estimates of benefits. In my state and region we have no
interest in trading a system that is time-tested and that delivers
value to consumers for one that promises to remedy problems we do not
have and promises to deliver benefits we may never see.
There may indeed be problems in need of fixing in both the
wholesale and retail areas of our electricity system. If so, we should
identify those problems clearly and focus regulatory solutions tightly
where solutions are needed. That would serve the public interest far
more efficiently and at less cost and risk than the imposition of a
one-size-fits-all standard market design.
C. The proposed rule represents a sweeping and unprecedented assertion
of federal jurisdiction over matters currently subject to state
authority.
In its proposed rule, FERC asserts ``for the first time its Federal
Power Act jurisdiction over wholesale transmission 'bundled' into
state-regulated retail power rates.'' \5\ It does so because it finds,
despite historical practice since 1935, that a utility preferring its
native load in operation of its own facilities is practicing undue
discrimination. FERC also proposes to intrude into retail demand
response. Moreover, it proposes to require ITPs under its sole
jurisdiction to establish regional resource adequacy requirements. It
also authorizes the ITPs to impose those requirements, and penalties
for non-compliance, on retail load-serving utilities regardless of
whether those utilities are otherwise exempt from FERC's jurisdiction
(e.g., municipal utilities and cooperatives).
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\5\ ``Standard Market Design for State Regulators'' supplied by the
Energy Regulatory Commission to the National Association of Regulatory
Utility Commissioners. July 31, 2002. Page 2.
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All of these areas--bundled retail service, retail demand response,
and generation resource planning and adequacy--fall under state
jurisdiction and have done so without question for three-quarters of a
century. They are matters of state policy determined by state
legislatures and implemented through state regulation. It is true that
these issues often have regional dimensions. Particularly in the
Northwest, where four states rely heavily on a common river system, the
coordination of planning and policies is important. Congress wisely
recognized that need in 1980 and directed that a regional planning
body--the Northwest Power Planning Council--be established to inform
coordinated resource development and regulate the power acquisitions of
the Bonneville Power Administration.\6\ This ``Northwest Solution'' to
regional issues has worked well in coordination with other state and
regional institutions and contractual relationships.
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\6\ Pacific Northwest Electric Power Planning and Conservation Act.
PL No. 96-501.
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The policy argument that federal jurisdiction must be imposed
because states will not or cannot coordinate regional actions simply
does not apply in the Pacific Northwest.
The legal assertion that FERC already has the authority to reach
into state-regulated retail service and resource planning is over-
confident. I believe the Federal Power Act clearly reserves these
matters for the states. The recent U.S. Supreme Court decision in New
York v. FERC does not, contrary to FERC's assertion in its NOPR, find
that FERC has the jurisdiction to reach into bundled retail sales. In
its opinion, the Court makes clear that it is not deciding that
jurisdictional question (as ENRON was urging), because FERC had not
(yet) asserted jurisdiction. Indeed, FERC argued to the Court, in
opposition to ENRON, that:
In light of the Commission's reasonable finding that it lacks
jurisdiction over the transmission component of bundled retail
sales under Section 201, the Commission was not required to
regulate that transmission component under Section 206.\7\
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\7\ ``Brief of the Federal Energy Regulatory Commission'' Supreme
Court of the United States. New York v. Federal Energy Regulatory
Commission, Enron v. Federal Regulatory Commission. Nos. 00-568 and 00-
809. May, 2001. Page 50.
The U.S. Supreme Court observed that were FERC to assert such
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jurisdiction, it would pose complex jurisdictional issues:
It is obvious that a federal order claiming jurisdiction over
all retail transmissions would have even greater implications
for the State's regulation of retail sales--a state regulatory
power recognized by the same statutory provision that
authorizes FERC's transmission jurisdiction. But even if we
assume, for present purposes, that ENRON is correct in its
claim that the FPA gives FERC the authority to regulate the
transmission component of a bundled retail sale, we
nevertheless conclude that the agency had the discretion to
decline to assert such jurisdiction in this proceeding in part
because of the complicated nature of the jurisdictional issues.
[Emphasis in original] \8\
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\8\ New York v. FERC, 535 U.S. ----, 122 S.Ct. 1012, 152 L.Ed.2d 47
(2002) (last page of majority opinion)
In any event, the case FERC cites addressed only transmission
jurisdiction, not jurisdiction over resource planning and adequacy
standards, or retail demand management.
FERC's aggressive and unfounded assertion of new jurisdiction will
inevitably lead to vigorous legal challenges and controversy. Such an
overbearing attitude toward the states and the resulting years of
uncertainty will serve the objectives of neither FERC nor the states,
nor the consumers whose interests government should protect.
FERC should retreat from its expansive jurisdictional assertions
and focus instead on policing the wholesale transmission and generation
markets. Respecting current authorities, it should work with the states
and regions to identify real problems and customize solutions to fit
those problems.
In any event, Congress has the authority to define FERC's role and
authority.
I urge the Congress, in its deliberations on the Energy Bill
pending in conference committee, not to complicate this matter by
expanding FERC's jurisdictional reach or its authorization to pursue
single-minded market-based policies. We need FERC to do what the
Federal Power Act already requires it to do ensure that charges for
wholesale transmission and generation are just and reasonable.
I do not believe that any Electricity Title is necessary in the
Energy Bill. If such a Title is included, I urge you to include a
provision clarifying that FERC's jurisdiction is limited to use of
facilities for wholesale transactions and does not extend to the use of
facilities to serve state-jurisdictional bundled retail consumers. The
amendment proposed by Senator Kyl could serve this purpose, but only if
it is modified to state clearly that use of facilities to meet a legal
service obligation is not jurisdictional to FERC and does not
constitute undue discrimination.\9\
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\9\ Senator Kyl sponsored SA 3185 to preserve the rights of load-
serving entities with service obligation to continue to use owned or
contracted-for transmission to fulfill those obligation.
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D. The proposed rule replaces direct public accountability at the state
level with new, weakly-accountable regional institutions that
will manage and govern essential electricity service.
Electricity is inherently political because electricity is an
essential public service. Therefore, electricity must be subject to
government oversight that can effectively protect the public interest.
The safety and welfare of the public depend on the availability and
reliable of electricity delivery. State and local governments, the
front-line guarantors of community safety and welfare, ensure that this
basic service is delivered, by providing it directly (as in the case of
municipal or county utilities), or indirectly (as in the case of state-
regulated investor-owned utilities). Moreover, public land, rights of
way, and water resources are devoted to the production of electricity
in order to serve this essential need.
Because the public has a vital interest in maintaining a reliable
and affordable supply of electricity, the institutions engaged in
electricity supply and the regulation of electricity services should be
accountable, as directly and effectively as possible, to the public
that relies on those essential services. Under our current system there
are strong links of accountability that run from the citizen-ratepayer
to the state regulator to the regulated utility. This ``triangle'' of
accountability works to ensure that citizens receive the electricity
they need and utilities receive the revenues they need.
The proposed rule seriously degrades the public accountability of
critical electricity institutions. The proposed rule sets out
``independence'' as a ``bedrock principle'' in order to ensure that all
discrimination in the use of transmission facilities is eliminated. The
implementation of this principle, however, has the practical effect of
making key aspects of electricity service and planning independent from
political and public accountability. Responsibility for transmission
service, generation planning and adequacy, and even aspects of retail
demand, are shifted from state and municipally regulated utilities to
as-yet-to-be-established ITPs, governed by private corporate-style
boards \10\ and regulated solely by FERC in Washington D.C. This
transfer of jurisdiction wrests accountability from local authorities
in municipalities and states and vests it in boards who are
inaccessible and not accountable in any direct way to the ratepayer-
citizens who will be so vitally affected by the ITP's decisions.
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\10\ The board members are chosen from among stakeholder groups
through an elaborate system laid out in the rule.
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In the Pacific Northwest this is particularly distressing because
80 percent of the grid transmission is owned by the public in the form
of the Bonneville Power Administration (BPA). Placing the operation and
management of BPA's transmission under an ITP transfers management of a
public asset from a public agency to a private corporate board.\11\
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\11\ Under the 1980 Pacific Northwest Electric Power Planning and
Conservation Act (PL No. 96-501), BPA is accountable to the Northwest
States through the oversight of the Power Planning Council. The use of
its transmission assets is governed by a series of federal laws going
back nearly 70 years (Bonneville Project Act of 1937, the Flood Control
Act of 1944, the Pacific Northwest Regional Preference Act of 1964, the
Federal Columbia River Transmission System Act of 1974, the
aforementioned Act of 1980, and the National Energy Policy Act of
1992). It may, in fact, be impossible to reconcile the requirements of
these existing statutes with FERC's proposed new requirements. If BPA
were exempt from these new Commission requirements establishment of a
meaningful standard market design in the Pacific Northwest is
impossible--BPA owns the bulk of the transmission and markets the bulk
of the power.
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Ultimately (but indirectly, and mediated through market mechanisms
and the ITP), accountability shifts to FERC whose Hearing Room is 3000
miles away. FERC is not practically accessible to ordinary citizens,
nor, as those of us who suffered the crisis in the Western wholesale
markets last year learned, responsive to a pressing need for action. In
light of FERC's recent record of unwillingness to act to solve crushing
problems in the wholesale sector, where it has both clear jurisdiction
and responsibility, it promises to be neither nimble nor responsive if
it were to preempt states and municipalities in these even broader and
critical retail areas.
FERC argues that the proposed rule provides an important role for
the states as key members of an advisory committee from which the ITPs
are to seek opinions. The opportunity to offer advice to a corporate
board that is not accountable to any state or local institution of
government does not provide accountability to the public. Advisory
committees are just that, advisors. They do not make decisions. The
opportunity to advise is not a substitute for the authority and
responsibility to oversee and regulate accountably to local and state
voters.
The loss of direct public accountability for an essential public
service is a profound flaw of the proposed rule. FERC's argument, that
the advisory role it has reserved for the states is meaningful and
adequate, only serves to demonstrate FERC's failure to grasp the
importance of political accountability to the provision of an essential
public service.
E. The proposed rule has practical limitations and real-world problems.
1. LMP
FERC's rule proposes to use locational marginal pricing (LMP) based
on short-term, bid-market, energy prices to manage congestion in
regional grids. While some form of locational pricing may be possible
in the Pacific Northwest electricity system, its application and
implications for our very distinctive system are problematic.\12\
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\12\ Attachment B describes a number of fundamental differences
between the Pacific Northwest electricity system and systems in the
Eastern United States. These differences, individually and
collectively, mean that a standardized approach based on Eastern
electricity characteristics is highly unlikely to work in the Pacific
Northwest.
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Our regional electricity system is dominated by generation from a
single river system with more than 30 coordinated generating stations
(dams) spread over the 250,000 square miles of the Columbia River
drainage basin. The bulk of the generation is marketed by a single
entity, the Bonneville Power Administration, and the system is
coordinated to meet not only energy production but a host of other
important public purposes: irrigation, flood control, fisheries
management, barge transportation, and recreation. Managing the system
only for the purpose of optimizing the economic efficiency of energy
production would ignore, and jeopardize, these other statutory and
public values of the River.
FERC argues that participation in the location-specific bid-markets
is voluntary, so river operation need not be affected, but that simply
begs the question of whether LMP should be imposed. What use is LMP if
the bulk of the generation does not participate in the bid-markets that
determine transmission prices and system dispatch? The rule is at war
with itself. If LMP does not affect river operations, then it has done
nothing to manage congestion. If LMP does affect river operations, then
it may adversely affect non-power objectives. If the bulk of generation
does not participate in the short-term markets that establish
transmission prices, then those markets will inevitably be thinly
traded, illiquid, and subject to manipulation.\13\ But the clearing
prices determined in those markets will affect all power transmitted,
regardless of whether that power was bid into the markets or not. It is
simply disingenuous to claim that these transmission prices will not
affect river operations.
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\13\ Even outside of a hydropower-dominated system LMP may prove to
be a problem since FERC wants to see most power traded in longer-term
bilateral markets. The more power in bi-lateral trades, the less power
in the short-term markets and the more potential for an illiquid market
and market manipulation.
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At best, applying LMP in our system as FERC has proposed forces a
round peg into a square hole. Comparisons of our complex and inter-
coordinated system to systems in Pennsylvania and New Zealand are
inapt. Less than one percent of the electricity generated in PJM is
hydroelectric.\14\ The majority of this generation comes from only four
(not 30) projects on the Lower Susquehanna River, which affects a
drainage one-tenth the size of the Columbia drainage and an annual flow
one-fifth that of the Columbia River. Unlike the Columbia, the
Susquehanna River is not an important transportation system and is not
principal source of arid-land irrigation.
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\14\ U.S. Department of Energy. Energy Information Administration.
---------------------------------------------------------------------------
The New Zealand electric system has about the same proportion of
hydropower as the Pacific Northwest system--65 percent. However, its
operation is not governed by a complex set of federal statutes,
international treaties, and multiple uses. Nonetheless, it is
interesting to note that one of the predicted benefits of the LMP
market-structure--expansion of needed thermal generation capacity--has
been slow to appear in New Zealand. A combination of illiquid markets,
market concentration, drought, and likely exercise of market power and
generation withholding, led to shortage conditions and significant
price spikes during 2001.\15\ A centralized, bid-market system with
nodal pricing may be in place in New Zealand's hydro-based system, but
it apparently has not served to encourage new infrastructure
investment, or to prevent the exercise of market power and the
appearance of crushing price spikes of 500 or more percent when water
runs short.
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\15\ See, for example, ``New Zealand Electricity: Lessons from the
winter of 2001,'' September 9, 2001. Infratil Company and ``Hedge
Markets for Electric Power in New Zealand. A Report to the Ministry of
economic Development,'' John Small, March 2002.
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2. Transmission Rights
Turning to transmission rights, the new rule proposes to preserve
existing transmission rights and the use of transmission to serve
native load customers by allocating to existing rights-holders the
financial rights to congestion revenues. As I noted earlier, the right
to receive revenue is not the same thing as the right to physical use
the facilities to serve native retail load reliably. Even if it were,
in translating existing physical rights into financial rights, it may
be impossible to retain the value of scheduling flexibility in the
hydropower system. This is another area in which the rule is at war
with itself. If existing rights are preserved and those rights cover
the bulk of the use of the transmission system, then the whole new and
complex system has done little to meet FERC's objective to open up more
access to transmission for non-utility commercial uses.
The proposed rule envisions that transmission congestion hedges
(CRRs) will be tradable in totally unregulated secondary markets. These
hedges are the only means for utilities to insulate themselves from
unpredictable congestion costs if the LMP bid-markets turn out to be
volatile, which, if they are thinly traded, they are almost certain to
be. Allowing these hedges to go to the highest bidder, even if that
bidder is simply a speculator of ``derivative'' instruments, without
any regulatory constraints, is an invitation to gaming and market-
cornering strategies. Simple appeal to a ``market monitoring'' function
is not credible when we recall how little monitoring and regulation
FERC applied to grossly run-away markets during 2000 and 2001.
3. Recovery of Transmission Costs
FERC's proposal for recovery of fixed transmission costs also
presents problems of equity and fairness. The rule proposes that
entities not serving load and simply wheeling power within, through, or
out of a region will pay no access fee. This leaves the retail load
left holding the bag to cover the sunk costs of the transmission system
while other parties use the system for no payment, except congestion
and losses. This will inevitably cause significant cost-shifts to
retail customers. For example, under the rule, PowerEx, a huge Canadian
generator, could wheel power through the Pacific Northwest to the
Southwest without paying a dime toward investment in the Pacific
Northwest transmission facilities it uses. BPA estimates that
currently, charges for such wheeling services account for fully a
quarter of its transmission revenue. Shifting these costs to retail
customers to accommodate free-rider wheeling violates the principles
espoused by FERC, but that would be the result.
4. Capacity Requirement
Finally, FERC proposes a generation-capacity adequacy requirement,
to be imposed by the ITP. In the Pacific Northwest such a requirement
makes little sense. We are an energy-limited system, not a capacity-
limited system (i.e., our system is limited by the amount of annual
stream flow in the Columbia River, not by the capacity of generators to
produce power, so more capacity does not address our primary limiting
factor). FERC acknowledges that energy-limited systems are different,
but the rule proposes a 12 percent capacity reserve requirement unless
we propose another solution that FERC finds to be acceptable. However,
establishing a rigid adequacy standard and authorizing a new
institution (the ITP) to do adequacy planning is redundant in the
Pacific Northwest. Adequacy planning is already performed on a regional
basis by the Northwest Power Planning Council, and each of the retail
utilities also operates under an obligation-to-serve and under a state
requirement to perform least-cost resource plans to fulfill that
obligation.
The proposed new rule appears to be aimed at problems we do not
suffer in the Pacific Northwest and to require solutions that are
either redundant to existing institutions or ill-suite to the Pacific
Northwest electricity system.
F. The proposed rule may actually destabilize the investment climate
for needed new electricity infrastructure.
There is little doubt that the climate for investment in new
generation and transmission in the Pacific Northwest and throughout the
country has been unstable for most of the last decade. New generation
and transmission facilities are needed. That said, FERC's proposal to
radically restructure our electricity system is not a necessary
condition for new facilities to be built. In fact, more than 2000 MW of
new generation plants (both utility and non-utility) are currently
under construction in or contiguous to Washington. BPA has plans to
construct more than 200 miles of new transmission in the next four
years to improve the reliability of the Pacific Northwest grid. I thank
this Committee for its support of the borrowing authority BPA has
requested to accomplish its transmission projects.
New regulatory rules do not cure the confusion, uncertainty, and
instability in investment markets if those rules themselves introduce
new levels of complexity and uncertainty. Much of the need for new
transmission and much of the uncertainty about who is to build it can
be traced directly to FERC's changing regulatory rules since 1992. We
don't need yet more new rules injecting new levels of uncertainty.
Under Washington law there is no ambiguity about who has the
responsibility to arrange for or build the facilities necessary to meet
retail customer load--the utilities bear that responsibility. FERC's
proposed rules will make it extremely difficult for utilities and my
regulatory commission to pursue the long-term investments that will
ensure reliable service in the future. I described earlier (Point A)
how FERC's proposed rules would undermine long-term planning an
investment by the vertically integrated utilities in Washington.
The theory of FERC's proposal rests on the assumption that most new
generation will be built and marketed by non-utility entrepreneurs. We
do not oppose non-utility generation projects. In fact we see them as a
useful and important alternative to, but not a full substitute for,
utility-built facilities.
Putting all of the consumers' eggs in the entrepreneurial basket is
a poor and risky policy. Independent Power Producers and power
marketers are poorly rated as investments and may not be able to
attract the capital necessary to build new generation or transmission.
As an investment sector, merchant power production saw an 86 percent
decline ($222 Billion) in market capitalization between mid-2001 and
mid-2002. Much of the merchant plant capacity in the West is owned by
parties with debt ratings below investment grade.\16\ Recent
cancellations of power plant projects in my region are the result of
poor market conditions and the inability to secure capital, not lack of
transmission access. In short, Wall Street appears to have judged that
the merchant power plant business is failing. FERC appears to be
designing a new and complex market for non-utility power producers in
which no participants will be strong enough to compete.
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\16\ ``Presentation to NARUC Committee on Electricity.'' Mark W.
Seetin, Vice President/Government Affairs, New York Mercantile
Exchange. July 30, 2002.
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In this environment, vertically integrated, state-regulated, retail
utilities may be the key entities able to attract the investment
capital needed for new infrastructure. New rules and new uncertainty
regarding the vertically integrated utilities and their obligations to
meet load requirements may well undermine the major source of new
investment that FERC believes is needed.
G. The proposed rule is incomplete and poorly defined in a multitude of
key areas.
The Notice of Proposed Rulemaking we are talking about today is
more than 600 pages in length. It is a formidable document and
difficult to digest. Yet, on close reading I find that the proposed
rule leaves expressly unresolved more than 100 important issues.\17\
FERC seeks comment on how its regulations should address these issues.
In many cases, these issues represent FERC's acknowledgment that
circumstances, and therefore applications of its theories, will vary
from region to region. It is both arbitrary and unfair for FERC to
dictate that solutions must be found to problems that remain
undocumented and that it is up to those of us who will be affected to
find a solution that will fit into FERC's theory.
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\17\ Many of these unresolved issues are fundamental to how the
proposal will affect customers, states, and regions. Examples include:
the allocation of Congestion Revenue rights to existing rights-holders;
the appropriate functions and roles for an Independent Transmission
Company (Transco) under SMD; whether network resources and loads can be
designated under network access service to allow for continued
integraton of resources and loads; whether load serving entities
holding CRRs have scheduling priority if transmission capacity is over-
subscribed; whether all customers should be charged the same
transmission rate; should the tariff allow for scheduling options for
energy-limited resources; key aspects of real-time energy market are
left undefined; should the tariff include liability provisions and if
so how; key aspects of the market power monitoring and mitigation are
left undefined; what should be the load-serving entities share of the
regional adequacy requirement.
---------------------------------------------------------------------------
My commission and many other parties with whom I have consulted are
struggling to understand the implications and nuances of the proposed
rule. We are frankly discouraged about our ability to protect our
important interests. We appreciate very much the opportunities to meet
with Commission staff in Boise and Las Vegas over the last month to
hear the proposed rule described and to ask questions. It is very
troubling to hear, however, that major components of the proposed
rule--the pro forma tariff, for example--have not been fully developed,
may be internally inconsistent, and cannot be relied upon as
representing FERC's ``real'' proposal. There are so many key issues
left unresolved or ill-defined.
FERC's proposed rule is simply too important and too radical to
proceed without a full opportunity for the public to digest,
understand, and comment on a fully developed and fully defined NOPR
that provides real evidence of the alleged problems and real evidence
of the expected costs and benefits of a clearly defined proposal.
In the Pacific Northwest, and I suspect in other parts of the
country, we hear FERC's message in this NOPR as: ``The (NOPR) train is
leaving the station, heading West, but the tracks haven't been laid,
and it's the West's job to get them laid before the train gets there.''
We say: ``Slow this train down. Better yet, don't let it leave the
station until you know where it is going and that there won't be a
train wreck.''
Thank you again for the opportunity to testify on this important
issue.
The Chairman. Thank you very much.
Ms. Hochstetter, why don't you go ahead.
STATEMENT OF SANDRA L. HOCHSTETTER, CHAIRMAN, ARKANSAS PUBLIC
SERVICE COMMISSION, LITTLE ROCK, AR
Ms. Hochstetter. Thank you, Mr. Chairman and members of the
committee. My name is Sandy Hochstetter, and I am chairman of
the Arkansas Public Service Commission, and I appreciate the
opportunity to appear before you today as a State official that
is responsible for regulating public utilities in the
Southeastern States.
In Arkansas, as in 34 other States across the country,
which is two-thirds of the United States, most electricity
customers depend entirely on vertically integrated utilities
that provide generation, transmission, and distribution service
in one bundled package. State utility regulators have direct
authority over how and how well utility companies provide that
electric service in these 35 States. We assure that retail
rates are reasonable and cost-based, that service is reliable,
and that utility management is responsive to both the
regulators and to its customers.
This direct accountability system between regulators, the
utilities that we regulate, and the customers at a local level
has helped to keep electricity prices low in the Southeast, and
in some other parts of the country as well. The existence of
reasonably priced reliable electric service is, in fact, the
primary reason that most of the Southeastern States have chosen
to retain our current system of fully bundled rate-regulated
electric service. Our markets work. Correspondingly, we
strongly believe that any FERC initiative undertaken to improve
the efficiency of the wholesale markets, which we understand it
is their prerogative to do, should not impair the existing
industry structures that have worked very well in our States.
Unfortunately, the standard market design as currently
written will make it very difficult, if not impossible, for us
to maintain the fully rate-regulated cost-based retail service
models in our States. This proposal would inject market risk
into a currently stable and effective system.
We do recognize that an unregulated wholesale market has
been developing over the last several years, and that it
currently supplies a certain percentage of our power supply
needs. It may well supply an increasing amount of our future
electricity needs, as our existing utilities and fully
regulated States need new electric supplies or need to retire
older plants, most of them will consider options available on
the wholesale market in addition to the option of constructing
needed generating facilities themselves. As a result, we do
want the wholesale market to be successful.
We recognize the appropriateness of policies that provide
adequate access to the transmission systems for the purpose of
supporting an efficient wholesale market, and that FERC has a
lawful obligation to remedy unlawful discrimination in those
markets. However, we feel strongly that FERC must take care to
distinguish what is an impermissible discrimination or abuse of
the system, as opposed to what is a legally required method of
providing bundled retail service, as Chairwoman Showalter just
indicated.
Care must be taken to isolate the specific problems that
are violations of law, so that customized remedies that are
narrowly tailored to address those problems can be fashioned.
In the case of FERC's proposed standard market design, however,
we believe that the evidence and proof of unlawful
discrimination is questionable at best. It is certainly not
sufficient to justify FERC's assertion of authority over
current State regulatory functions in the areas of bundled
transmission service and generation supply adequacy. We do not
believe that there is a basis for FERC to take the allegations
of discrimination in the wholesale market and impose remedies
that displace State jurisdiction and have the potential of
adversely impacting the retail market.
The public interest challenge that we face is how to
balance legitimate needs of the wholesale market with the
legitimate rights of States to choose their own electricity
delivery methods and protect their ratepayers and their local
economies in accordance with the current State laws. The proper
purpose of an efficient wholesale market is to support retail
markets.
We should not adopt any new regulatory frameworks if its
effects will be to jeopardize reliable service and reasonable
rates at the retail level. We need to take more time and more
thoughtful review and analysis than is currently anticipated by
the SMD NOPR, even taking into account FERC's recent decision
to extend the comment period.
I believe that we can reach some common ground, but the
only way that we can do this is to use more issue-specific,
targeted problem resolution processes, as opposed totally
rewriting the book on the way that electricity is currently
delivered. I believe that effective wholesale markets and
effective retail regulation are both necessary, and that they
can coexist, but what we need is a systematic process for
fostering efficient wholesale markets without impairing our
existing retail industry structure.
So in terms of moving forward, I would suggest, because the
NOPR is highly complex, we need a great deal more time and
study to ferret out what might be useful versus what is too
theoretical to attempt, or at least, at best, should be
piloted. We need to peel back the layers one step at a time.
For those proposals that make sense, maybe we can move forward
and implement those, such as participant funding. We can do
that very quickly.
As to other, more difficult issues, we need to move in a
very gradual and incremental fashion, consider what might be
beneficial, what works in some regions and does not work in
others. We are in a solid position in the Southeast in terms of
our adequacy of generation and transmission infrastructure, to
continue to provide reliable and low cost electricity to our
native load customers. We do not need to rush forward hastily.
While there may be room for improvement, we do not suffer from
the ills that are set out as the foundation for SMD. We think
that regional differences, including different retail
regulatory models, must be reflected in both the implementation
substance and the implementation schedule.
Thank you very much for your consideration.
[The prepared statement of Ms. Hochstetter follows:]
Prepared Statement of Sandra L. Hochstetter, Chairman, Arkansas
Public Service Commission, Little Rock, AR
I. INTRODUCTION
Mr. Chairman and Members of the Senate Energy Committee: My name is
Sandra Hochstetter. I am the Chairman of the Arkansas Public Service
Commission. I appreciate the opportunity to appear before you today as
a state official responsible for regulating public utilities in a
Southeastern state, to comment on FERC's Notice of Proposed Rulemaking
regarding Standard Market Design. My remarks come from seventeen years
of experience in both the gas and electricity markets and reflect my
deep concerns about the potential impact of FERC's SMD proposal on the
reliability and cost of electric service in States that have not
abandoned the traditional industry structure.
As a state utility regulator, I recognize that FERC has the
statutory responsibility to regulate wholesale electric markets and to
remedy unduly discriminatory access to the transmission system which
may impair effective competition in those markets. However, I am also
cognizant of my responsibility as a state regulator in a state that has
chosen to retain bundled retail electric service to ensure that
customers have reliable retail service at a reasonable price. Many of
my colleagues in the state regulatory community and I are very
concerned that FERC, in its efforts to fulfill its statutory
responsibilities, is attempting, through various provisions contained
in the SMD NOPR, to inappropriately and unnecessarily extend its
jurisdiction into areas that should remain the province of state
regulators under the dual regulatory regime that, for the most part,
serves our citizens well.
II. STATE DUTY TO ENSURE RELIABLE AND AFFORDABLE ELECTRICITY FOR
CONSUMERS
I would like to first set forth the legal and practical reasons for
the serious concerns many of my fellow regulators, other state
officials and I share about the SMD NOPR. We have the legal and public
interest obligation to ensure reliable electricity service for
consumers at affordable prices. Whatever market structure is in place
must and should serve that end--the customer--and no other. In
Arkansas, and in 34 other states across the country, which is 2/3 of
the United States, most electricity customers depend entirely on
vertically integrated utilities that provide generation, transmission
and distribution service in one bundled package. State utility
regulators have direct authority over how, and how well, utility
companies provide that electric service in these 35 states. To
discharge that obligation, state commissions must assure that:
(1) retail rates are reasonable and cost-based;
(2) service is reliable; and
(3) utility management is responsive both to the regulators
and to its customers.
This direct accountability system between state regulators, the
utilities we regulate, and the customers at a local level has helped to
keep electricity prices low in the Southeast and in other parts of the
country. The existence of reasonably-priced, reliable electric service
is the primary reason that most of the Southeastern states have chosen
to retain the current system of fully bundled, rate regulated electric
service. Although we do not purport to express an opinion as to what
should be done in other States with respect to the issue of electric
restructuring, we do strongly believe that any FERC initiative
undertaken to improve the efficiency of wholesale markets should not
impair the existing industry structures deemed appropriate in each
State.
III. FEDERAL DUTY TO ENSURE EFFECTIVE WHOLESALE COMPETITION AND
NONDISCRIMINATORY TRANSMISSION ACCESS
Even though our current systems of producing, transmitting and
delivering electric service in many parts of the country, including the
Southeastern United States, continue to work well in providing
reliable, low-cost electricity service, we recognize that an
unregulated wholesale market has been developing over the last several
years and that the wholesale market currently supplies a certain
percentage of our power supply needs. The wholesale market may well
supply an increasing amount of our future electricity needs. As
existing utilities in fully regulated states need new electric
supplies, or need to retire older plants, most will consider options
available on the wholesale market in addition to the option of
constructing needed generating facilities themselves. As a result, the
wholesale market is becoming an important supply option for vertically-
integrated utilities in the Southeast. For that reason, we recognize
the appropriateness of policies that provide adequate access to the
transmission systems for the purpose of supporting an efficient
wholesale market, and that FERC has an obligation to properly remedy
unlawful discrimination in the markets properly subject to its
jurisdiction.
However, FERC must take care to distinguish what is an
impermissible discrimination or abuse of the system, as opposed to what
is a legally required method of providing bundled retail service. Care
must be taken to isolate the specific problems that are violations of
law, so that customized remedies that are narrowly tailored to address
those problems can be fashioned. In the case of FERC's proposed SMD,
however, the evidence and proof of unlawful discrimination is
questionable at best. It is certainly not sufficient to justify FERC's
assertion of authority over current state regulatory functions in the
areas of bundled transmission service and generation supply adequacy.
There is simply no basis for FERC to take allegations of discrimination
in the wholesale market, and impose remedies that displace state
jurisdiction and have the potential of adversely impacting the retail
market.
IV. BALANCING ACT--HARMONIZING STATE WITH FEDERAL OBJECTIVES
The difficult question--and our ultimate public interest
challenge--is how to balance the legitimate needs of the wholesale
market with the legitimate right of the states to choose their own
electricity delivery methods and to protect their ratepayers and local
economies in accordance with current state law. The proper purpose of
efficient wholesale markets is to support the retail market. We should
not adopt any new regulatory framework if its effect will be to
jeopardize reliable service and reasonable rates at the retail level,
which is a state and not a federal responsibility. Arriving at a proper
balance between the legitimate needs of the wholesale and retail
markets will take more time and more thoughtful review and analysis
than is currently allowed by the SMD NOPR, even with FERC's decision to
extend the time for filing initial comments and authorize the filing of
reply comments. The simple fact of the matter is that the SMD NOPR
proposes an incredibly complex set of changes to the manner in which
the transmission system is operated that requires careful study and
analysis.
This challenge of coordinating federal wholesale market objectives,
along with the lawful prerogative of the states to preserve effective
retail market designs, will require true and complementary co-
regulation of the type envisioned under the Federal Power Act, rather
than subordination of the retail market to federal control, accompanied
by promises of cooperation or ``advisory input.'' Any vision of co-
regulation, and the process for getting there, must begin with a
recognition that there is nothing about FERC's authority, and nothing
about FERC's desire to promote effective wholesale competition, that
should diminish, much less jeopardize, a state commission's obligation
to assure reasonable rates, reliable service, and appropriate
accountability. Proper regulation is not a matter of one jurisdiction
prevailing over the other, but of ensuring that both jurisdictions act
carefully within their spheres and coordinate their actions. We must
develop a complementary federal-state regulatory regime that allows
both the wholesale and retail market segments to coexist equally on the
same transmission networks, without sacrificing the interests of one to
serve the other in the manner apparently inherent in the SMD NOPR.
Unfortunately, FERC, in attempting to address what it characterizes
as continuing problems of discrimination/barriers to access in the
wholesale market, has proposed in its SMD the implementation of
expansive remedial structures and rules that could have negative
consequences for the retail markets. We do not dispute FERC's
legitimate intention of trying to foster greater competition and
efficiencies in the wholesale market; however, we do take exception to
FERC's proposal of a series of ``remedies'' that are much broader than
necessary to address wholesale market problems, impair our ability to
continue successful retail rate design models that are working well,
and potentially create volatility and higher prices for retail
customers.
V. SUGGESTED PROCESS FOR MOVING FORWARD
I believe that we can reach some common ground between lawful
federal and state responsibilities, and harmonize our respective
interests, but the only way that this can be accomplished is by using a
more issue-specific, targeted problem resolution process, as opposed to
totally re-writing the book on the way that electricity is currently
delivered. Effective wholesale markets and effective retail regulation
are both necessary and can coexist. What we need is a systematic
process for fostering efficient wholesale markets without impairing the
existing retail industry structure. On this subject, I would like to
offer a few thoughts:
1. The SMD NOPR is highly complex. There are a multitude of
different proposals contained within it. Some of these proposals have
been tried, others have not. In moving forward, we need to ``peel
back'' the layers, and take it one step at a time. For those proposals
that make some universal sense and require little debate or analysis,
we can move forward to implement them as a foundation. For instance, it
appears that Chairman Wood and the FERC have endorsed, on a conceptual
basis, the use of Participant Funding for the expansion of the
transmission system. This is a concept that is widely supported within
the Southeast and we should move forward as quickly as possible to
flesh out the details of this policy and to develop a transition plan
for its immediate implementation. After that is in place, we can then
move, in a gradual and incremental fashion, to the consideration of
other elements which might be beneficial, but which need further
analysis, testing, and perhaps trial experimentation or piloting.
2. We need not act hastily. When we act, we must be governed by
where we are starting from in each region of the country. In fashioning
when we should act, policymakers need to recognize that not all regions
of the country are in the same state of utility infrastructure
development. The Southeast is in a solid position in terms of the
adequacy of its generation and transmission infrastructure, to continue
to provide reliable and low-cost electricity to native load customers.
Any necessary further development of efficient wholesale markets in
this region can and should happen on a timely basis. But there are a
number of steps proposed in the SMD NOPR that are not needed to further
develop the wholesale market to benefit consumers.
3. Regional differences should be reflected in the implementation
substance and the implementation schedule. We need to distinguish
between those aspects of SMD that should be common throughout all
regions, and those aspects which can vary among the regions. We need to
calibrate the timing and the substance to the facts within each region.
This type of a regional approach would better accommodate the realities
of regional diversity in geography and fuel sources; differences in
demographic and economic factors; differences in cultural and
governmental institutions; and the existence of different regulatory
approaches ranging from continued bundled rate regulation to unbundled
rates and generation deregulation.
VI. CONCLUSION
In summary, I would like to leave you with several common sense
notions that I believe can be applied to the proposed Standard Market
Design:
Don't fix what isn't broken;
It's our diversity that makes us strong;
Don't kill a gnat with a sledgehammer; and
Haste makes waste.
Thank you for your time and consideration of these comments.
The Chairman. Thank you very much.
Mr. Harvill, why don't you go right ahead.
STATEMENT OF TERRY S. HARVILL, COMMISSIONER, ILLINOIS COMMERCE
COMMISSION
Mr. Harvill. Thank you, Mr. Chairman. I would like to thank
you and other members of the committee for inviting me here
today to discuss the Federal Energy Regulatory Commission's
notice of proposed rulemaking on standard market design. My
name is Terry Harvill, and I am a member of the Illinois
Commerce Commission. The Illinois Commerce Commission is the
State of Illinois' public utility commission, which regulates
several financial and service aspects of investor-owned
electricity, natural gas, water, sewer, and telephone
utilities.
In 1997, Illinois embarked upon retail electricity
restructuring, and 5 years later is still in the midst of this
transition to a competitive retail electricity market. During
this transition, one fact remains clear. Retail competitive
markets cannot exist without underlying competitive wholesale
markets.
In 1996, the FERC set upon a series of orders intended to
open the transmission grid to competing wholesale providers.
The first of these orders, Order 888, and its companion order,
889, dramatically spurred competition in wholesale power
markets by requiring investor-owned utilities to open their
transmission systems to competing power providers on a
nondiscriminatory basis.
The FERC followed that action in December 1999 by issuing
Order 2000, which established rules to encourage transmission-
owning utilities to relinquish control of their high-voltage
power lines to independent entities called regional
transmission organizations, while still maintaining ownership
of their power grid assets and receiving revenues from their
use.
Over time, it has become evident that FERC Orders 888, 889,
and 2000 could propel the wholesale electricity industry only
so far towards robust, workable, competitive power markets. It
became further evident that market reform and standardized
market rules and industry procedures were necessary in order to
eliminate the potential discriminatory business practices and
structural inefficiencies that have allowed market manipulation
and caused the continuation of inefficiencies such as
discouragement of capital investment and transmission.
To this end, the FERC has proposed its standard market
design as a starting point to establish a set of best practices
for sound competitive power market conduct and efficient
transmission operation expansion. As a State commissioner, I
have actively participated in efforts to facilitate the
development not only of retial competitive power markets for
electricity in Illinois, but also competitive wholesale power
markets in the Midwest region.
The ICC has monitored and actively intervened in numerous
FERC proceedings, and I personally have participated in
countless hearings and conferences regarding the regional
transmission organization formation in the Midwest. However,
despite the initial market-opening actions by the FERC,
progress towards competitive wholesale power markets has been
lethargic and, thus, progress in retail competition has even
been more so.
Make no mistake, the potential for discrimination and the
abuse of market power still exists in wholesale power markets.
Beyond the California in 2000, transmission owners still
possess enormous incentives to favor their own generation.
Inconsistent rules governing transmission limit some
transactions while lowering costs for others.
Vertically integrated utilities continue to possess the
opportunity to manipulate transmission availability through
control of strategic matters such as available transfer
capability, calculations, and capacity set-asides for native
load growth projections, and the existence of seams between
regions, and we have one going right through the center of
Illinois, raises cost for interregional power flows.
Simply stated, in Illinois' opinion, standard market design
is long overdue. While I do not agree with all of the details
of the FERC's standard market design proposal, and I note
several aspects of the FERC proposal will require considerable
work before implementation can occur, I believe, overall, the
FERC's SMD proposal represents a tremendous step in the right
direction.
The FERC's SMD proposal will synchronize electricity spot
market operations and rules governing transmission pricing and
transmission system operation. The SMD will also standardize
the rules across geographic regions for operating the
transmission grid. These are all much-needed reforms.
Implementation of these reforms cannot occur soon enough.
A standard market design is long overdue. In order for the
United States to have robust, competitive electricity markets
both at the wholesale and retail levels, a sensible standard
market design is essential. In the coming weeks and months, my
commission, as well as numerous other organizations, will be
working with the FERC to establish these uniform market rules.
I am optimistic that in the end the FERC will be successful in
implementing rules that restore faith to those markets so vital
to every citizen of this Nation.
Thank you.
[The prepared statement of Mr. Harvill follows:]
Prepared Statement of Terry S. Harvill, Commissioner, Illinois
Commerce Commission
Good morning, Mr. Chairman, Ranking Member Murkowski, and other
distinguished Members of the Committee. Thank you for inviting me here
today to discuss the Federal Energy Regulatory Commission's (FERC's)
Notice of Proposed Rulemaking (NOPR), Remedying Undue Discrimination
through Open Access Transmission Service and Standard Electricity
Market Design, which the FERC issued on July 31, 2002. I appreciate the
opportunity to discuss the FERC's efforts to develop a standard market
design (SMD) for wholesale electricity power markets.
My name is Terry Harvill, and I am a member of the Illinois
Commerce Commission (ICC). The Illinois Commerce Commission is the
State of Illinois' Public Utility Commission, which regulates several
financial and service aspects of investor-owned electricity, natural
gas, telephone, water, and sewer utilities. In 1997, Illinois embarked
upon retail electricity restructuring and, five years later, is still
in the midst of the transition to competitive retail electricity
markets. During this transition, one fact remains clear: competitive
retail markets cannot exist without competitive wholesale markets.
In 1996, the FERC set upon a series of Orders intended to open the
transmission grid to competing wholesale power providers. The first of
these Orders, Order 888, and its companion, Order 889, dramatically
spurred competition in wholesale power markets by requiring investor-
owned utilities to open their transmission systems to competing power
providers on a non-discriminatory basis. The FERC followed that action,
in December 1999, by issuing Order 2000, which established rules to
encourage transmission-owning utilities to relinquish operational
control of their high-voltage power lines to independent entities
called Regional Transmission Organizations, while still maintaining
ownership of their power-grid assets and receiving revenues from their
use.
Over time, it has become evident that FERC Orders 888, 889, and
2000 could propel the wholesale electricity industry only so far
towards robust, workable competitive markets. Further market reform and
standardized market rules and industry procedures were necessary in
order to eliminate the potential discriminatory business practices and
structural inefficiencies that have allowed market manipulation and
caused the continuation of inefficiencies, such as the discouragement
of capital investment in transmission. To this end, the FERC has
proposed its Standard Market Design (SMD) as a starting point to
establish a set of best practices for sound competitive power market
conduct and efficient transmission operation and expansion.
As a state commissioner, I have actively participated in efforts to
facilitate the development of not only competitive retail markets for
electricity in Illinois, but also competitive wholesale power markets
in the Midwest region. The ICC has monitored and actively intervened in
numerous FERC proceedings, and I personally have participated in
countless hearings and conferences regarding Regional Transmission
Organization (RTO) formation in the Midwest. However, despite initial
market-opening actions by the FERC, progress toward competitive
wholesale power markets has been lethargic, and thus, progress in
retail market competition has been even more lethargic. Make no
mistake: the potential for discrimination and the abuse of market power
still exist in wholesale power markets. Beyond the California debacle
in 2000, transmission owners still possess enormous incentives to favor
their own generation; inconsistent rules governing transmission limit
some transactions while lowering costs for others; vertically-
integrated utilities continue to possess the opportunity to manipulate
transmission availability through control of strategic matters such as
Available Transfer Capability (ATC) calculations and capacity set-
asides for native load growth projections; and the existence of seams
between regions raises costs for inter-regional power flows. Simply
stated, standard market design is long overdue.
While I do not agree with all details of the FERC's SMD proposal,
and I note that several aspects of the FERC's proposal will require
considerable work before implementation can occur, I believe that,
overall, the FERC's SMD proposal represents a tremendous step in the
right direction. The FERC's SMD proposal will synchronize electricity
spot market operations and the rules governing transmission pricing and
transmission system operation. The SMD also will standardize the rules
across geographic regions for operating the transmission grid. These
are all much-needed reforms. Implementation of these reforms cannot
occur soon enough.
MARKET MONITORING AND MITIGATION
Since the markets envisioned by the Commission in this rulemaking
may not always function properly, it is necessary for the Commission to
adopt strong measures for market monitoring and market power
mitigation. In the SMD rulemaking, the Commission proposes to establish
a process that will lead to the selection of a Market Monitor in each
region that is independent and autonomous of both market participants
and transmission providers. The Market Monitor's purpose is to focus on
identifying factors that may contribute to economic inefficiency such
as market design flaws, inefficient market rules, barriers to entry for
new generation, barriers to demand-side resources, transmission
constraints, and market power. Further, the Market Monitor will be
charged with mitigating the bids of market participants that would
otherwise exercise market power. Finally, the Market Monitor must
provide regular reports regarding the performance of markets, market
manipulation, and factors that impair market efficiency. These market
monitoring structures and policies should provide significantly greater
protection from market power abuse than those that currently exist.
The Commission's intent to endow the Market Monitor with the
authority necessary to prevent market participant behavior that would
result in the manipulation of market prices or the reduction of market
efficiency is well placed. The Commission is also correct in requiring
the Market Monitor to recommend changes in market design and market
structure where flaws exist. Without a proper monitoring and mitigation
plan, there is little reason for market participants to place any faith
in the markets proposed by the Commission.
As the experience of the Western States' has shown, incomplete
market development and poor market structure can lead to severe
consequences. Accordingly, the Commission's decision to not place blind
faith in the immature power markets proposed in the rulemaking and to
establish market monitoring and mitigation measures is appropriate.
However, a major flaw exists in the FERC's Market Monitor proposal
in that the FERC has failed to establish proper procedures to ensure
that the market monitor is truly independent of market participants and
will not be influenced by market participant pressure.
REGIONAL PLANNING
Vertically integrated utilities have incentives and opportunities
to operate the transmission system so as to thwart the actions of their
power market competitors. Such activities include: the calculation and
posting of Available Transfer Capability in a manner favorable to the
transmission provider, standards of conduct violations, calls for
Transmission Loading Relief and other means of congestion management,
and by constructing cumbersome and inefficient OASIS sites. In addition
to subterfuge by vertically integrated utilities, the development of
competitive markets has suffered from other problems such as parallel
path flows, inadequate planning and investing in new transmission
facilities, the pancaking of access charges, the absence of secondary
markets in transmission service, and the possible disincentives created
by the level and structure of transmission rates. Under these
circumstances, wholesale competition cannot succeed.
In spite of the Commission's efforts to address the aforementioned
concerns through Orders 888 and 2000, the corporate tie between
generation and transmission in public utilities and the resulting
problems still exist. In an effort to remedy these problems the SMD
proposal requires the operation of the transmission grid by an
independent operator. This requirement for independent control of the
transmission grid, preferably by a Regional Transmission Organization
or Independent Transmission Provider (ITP), resolves these types of
problems since the RTO or ITP will have no incentive to favor one party
over the other. The SMD rulemaking proposes to require all public
utilities that own, control, or operate transmission facilities to
participate in a regional planning and expansion process overseen by an
ITP. The creation of ITPs, which is probably the next best option to
legal or structural separation of problematic integrated utility
functions, will remove the opportunities for vertically integrated
control area operators to discriminate against competitors or in favor
of their own generating or marketing affiliates. This represents a
significant departure from the historical approach of transmission
planning and expansion where the focus was on a single-control area.
Today, wholesale power markets are more competitive, increasingly
broad, and power is now delivered over great distances. It is necessary
for transmission planning and expansion to focus on regional, rather
than parochial, planning processes.
A regional approach to transmission planning and expansion will
allow the Commission to address documented problems associated with
under-investment in transmission infrastructure. Further, a regional
approach is more efficient as solutions to issues such as parallel path
flows are considered on a market-wide basis instead of for a single
control area. Other benefits include the ability to identify
transmission projects that would benefit a specific area and any
alternatives in an unbiased manner. Lastly, the regional planning
process will rely on market participants to propose and implement
actions to address reliability and other grid problems identified in
regional needs assessments, with ITPs given a backstop role for
situations in which market solutions are not proposed to address
critical grid problems. As such, the SMD proposal will provide an
independent assessment of those projects that are the most cost
effective and/or have the least environmental impact.
DEMAND SIDE RESPONSE BASED ON PRICE
Most electricity customers are unaware of the hourly changes that
occur in the production of electricity. While large industrial
consumers may be more cognizant of their energy costs, electricity is a
relatively small part of their cost of doing business. As a result,
most electricity demand today is unlikely to respond to real-time
fluctuations in electricity prices. This lack of price-responsive
demand is a major structural defect in the electricity market. When a
customer is unable to respond to higher prices, there is no way to
discipline price increases from suppliers. However, under the
Commission's proposed Locational Marginal Pricing, or LMP, approach,
each buyer's bid will indicate the desired amount of power to be
bought, the delivery point, and the time period. In addition, each
buyer will be allowed to specify bid prices that indicate the
quantities it is willing to purchase at alternative prices. Buyers will
also be allowed to submit multi-part bids that indicate the time and
price constraints under which they are willing to purchase energy.
The Commission's LMP approach facilitates demand response programs
by allowing an electricity buyer to indicate in advance the price at
which it is willing to voluntarily reduce its consumption of
electricity. In addition, the proposal results in reduced use of high-
cost power sources when a shortage condition approaches, helps ensure
reliability, prevents a shortage that could produce a curtailment, acts
as a check against market power, and provides a yardstick for the value
that buyers place on supply. These are all sorely needed reforms of the
current arrangement.
LOCATIONAL MARGINAL PRICING AND CONGESTION REVENUE RIGHTS
Locational Marginal Pricing is a market-based method of congestion
management. LMP manages congestion through transparent energy prices
and transmission usage charges that are determined in a bid-based
market. When there is sufficient transmission capacity to obtain power
from the cheapest available generators to all potential buyers (i.e.,
no congestion), there will be only one energy price in the transmission
system. When there is congestion, however, the cheapest generators may
be unable to reach all their potential buyers. Under LMP, the
Independent Transmission Provider will dispatch the system under
congestion in a way that will establish separate energy prices at each
node on the transmission grid and separate prices to transmit energy
between any two receipt and delivery points on the grid. These prices
reflect the real cost of congestion. As a result, LMP efficiently
allocates scarce transmission capacity by allowing those who value it
most to ``buy through the congestion.''
The FERC's SMD proposal also employs a financial instrument called
a Congestion Revenue Right (CRR). A CRR is a financial tool that allows
a customer to protect against the costs of congestion and provide price
certainty for transmission service (i.e., a hedge). A CRR also ensures
that the holder of that right will be protected against congestion
costs for the transmission service covered by that right in the day-
ahead market. In addition, holders of CRRs will also be able to sell
them to others that value the CRR more. Accordingly, CRR buyers will be
able to dispose of them in a secondary market, if necessary.
The LMP system for congestion management is better suited to manage
congestion in a competitive market than the current congestion
management system that relies on pro-rata curtailment (i.e.,
transmission loading relief). This is because LMP allocates scarce
transmission capacity to those who value it most and it relies on an
incentive system (i.e., it assigns congestion costs to the transactions
that cause the congestion) that encourages market participants to buy
and sell power in a manner that is consistent with the reliable
operation of the system. In short, LMP is an efficient economic method
for addressing system congestion as compared with the current arbitrary
physical method of doing so. In addition, LMP and Congestion Revenue
Rights will provide transparent price signals to indicate where new
investment is needed.
Further, under the proposed LMP system, market participants have
greater flexibility in arranging transactions. Market participants also
have the ability to signal whether they are willing to buy their way
through transmission constraints. Under the current system, they are
unable to do so because transmission providers do not have a mechanism
for recovering the cost of economic re-dispatch. Lastly, because market
participants are aware of, and will be responsible for, the full effect
of their decisions on congestion costs, there is an incentive to manage
transactions in a manner consistent with a least-cost dispatch
consistent with reliable system operations.
CONCLUSION
A standard market design is long over due. In order for the United
States to have robust, competitive markets for electricity, both at the
wholesale and retail levels, a sensible standard market design is
essential. In the coming weeks and months, my commission, as well as
numerous other organizations, will be working with the FERC to
establish these uniform market rules. I am optimistic that, in the end,
the FERC will succeed in implementing rules that restore faith to those
markets so vital to every individual of this nation.
Thank you.
The Chairman. Thank you very much.
Mr. Popowsky, why don't you go right ahead.
STATEMENT OF SONNY POPOWSKY, CONSUMER ADVOCATE
OF PENNSYLVANIA
Mr. Popowsky. Thank you, Chairman Bingaman. My name is
Sonny Popowsky. I am the Consumer Advocate of Pennsylvania. It
seems to me there are two principled positions that State and
regional policymakers can take on the broad policy issues that
are reflected in the FERC SMD. The first position is that a
State or region is better served by a cost-based regulatory
framework that relies primarily or exclusively on regulation to
ensure that consumers receive reliable service at just and
reasonable rates.
The second position is that a State or region would benefit
by opening the generation portion of the electric industry to
competition within the framework of a properly designed market
structure in which competition among generation providers is
relied upon to produce reliable service at just and reasonable
market-based prices.
A third position, which I think is neither principled nor
acceptable, is to permit the deregulation of generation and
then allow the use of market-based prices in the absence of
real competition and in the absence of a market structure that
actually produces reasonable service at reasonable prices. In
my view, you cannot simply assume competition and then let
generation prices be determined either by owners of bottleneck
transmission resources who can use those resources to prevent
those consumers from receiving lower cost generation, or by
sophisticated marketers who devise ways to manipulate poorly
designed markets and then invent childish nicknames for the
methods they use to cripple a region's economy.
I think the current FERC commissioners recognize that there
is a fundamental difference between competition and mere
deregulation, and that deregulation in the absence of full and
fair competition is the worst of all worlds for consumers. I
believe FERC has properly changed its focus to developing a
truly competitive market structure and then police and monitor
those markets.
Also, I think FERC has correctly recognized that if the
Nation wishes to rely on market forces at the wholesale level
to provide adequate supplies of generation at just and
reasonable prices, that there are certain common structural
requirements that need to be addressed in order for those
benefits to flow across State and regional lines.
Now, most electric consumers in my State, Pennsylvania, are
served by utilities that are part of what many people consider
to be the most successful regional electricity market in the
United States, PJM. One of the advantages we have had in
developing a regional model in PJM is that we have had a 75-
year head start. That is, the PJM utilities actually first
joined to work together on a coordinated basis in 1927. The
evolution of PJM into a more competitive wholesale market and
independent system operator has been just that, an evolution.
When I look at the PJM market as it has performed since it
became an independent system operator with substantially
market-based pricing, I have seen a continuation of reliable
service at energy prices that are generally consistent with
what one would expect in a competitive energy market. There has
not been room for market manipulation in PJM, but because PJM
is operated on a truly independent basis with a very strong and
effective market monitoring unit, I believe that efforts to
improperly exercise market power are more readily detectable
and remedied in PJM. I would therefore agree that a PJM-type
model is a reasonable starting point for developing principles
for a successful common market design.
The question, of course, is whether a market design that
works in a densely populated region like PJM that has long been
served primarily by investor-owned utilities utilizing thermal
generating plants and operating in a tight power pool would be
the best design, for example, in a sparsely populated area, or
in an area served primarily by hydropower.
Personally, I would like to see more consistency among the
regions surrounding PJM. This could improve reliability,
moderate prices, and most directly prevent gaming by market
participants between regions with different rules. I would
rather see generators competing with each other under a
consistent set of rules, than looking for angles in the seams
between markets that allow them to increase profits through
gaming.
Having said that, I would certainly defer to my
counterparts in other States and regions to advise FERC as to
whether they believe the PJM or SMD model would work in those
regions, or whether, in fact, any attempt to move towards
competitive wholesale markets create more problems than it
solves.
Now, regarding the specific elements of the SMD proposal
itself, my own greatest concern is the resource adequacy
provision. I agree with FERC that the PJM method of assuring
resource adequacy through an installed capacity market is
subject to manipulation, and needs to be substantially improved
or replaced. I also agree with FERC that the energy market
alone is not adequate to ensure long-term resource adequacy.
As I describe in my written testimony, however, I believe
that the FERC long-term adequacy proposal is not a viable
replacement to the installed capacity mechanism in place in
PJM, and just with two other issues briefly, regarding the
issues of governance and market monitoring, I agree fully with
FERC that it is essential that the board and staff of an
independent transmission provider be truly independent of any
market participants, and that they operate the system in the
public interest, not in the narrow interest of any partial set
of market players,and I also think it is absolutely necessary
to have an effective market monitoring unit within the
independent transmission provider in order to prevent market
manipulation, and take steps to remedy such problems when they
arise.
With that, I conclude my testimony. I would be happy to
answer any questions you have. Thank you.
[The prepared statement of Mr. Popowsky follows:]
Prepared Statement of Sonny Popowsky, Consumer Advocate
of Pennsylvania
Thank you for inviting me to testify today with regard to the
Federal Energy Regulatory Commission Notice of Proposed Rulemaking on
Standard Market Design.
My name is Sonny Popowsky. I have been the Consumer Advocate of
Pennsylvania since 1990 and I have worked at the Office of Consumer
Advocate since 1979. I have also previously served, and appeared before
this Committee, as the President of the National Association of State
Utility Consumer Advocates (NASUCA). Today, I wish to make it clear
that I am speaking only on behalf of my own Office. Members of NASUCA
are currently reviewing the massive FERC NOPR, and I expect that, like
other national associations that address public policy issues in the
electric industry, the ultimate views expressed by NASUCA members on
this topic will almost certainly reflect regional differences. I am
aware, for example, that some NASUCA member offices in the West have
very strong reservations about the FERC proposal as a poor fit for that
region.
It seems to me that there are two principled positions that state
and regional policy-makers can take on the broad policy issues that are
reflected in the FERC SMD. The first position is that a state or region
is better served by a cost-based regulatory framework that relies
primarily or exclusively on regulation to ensure that consumers receive
reliable service at just and reasonable rates. The second position is
that a state or region would benefit by opening the generation portion
of the electric industry to competition within the framework of a
properly designed market structure in which competition among
generation providers is relied upon to produce reliable service at just
and reasonable market-based prices.
A third position--which I think is neither principled, nor
acceptable is to permit the deregulation of generation and then allow
the use of market-based prices in the absence of real competition and
in the absence of a market structure that actually produces reasonable
service at reasonable prices. In my view, one cannot ``assume''
competition and then let generation prices be determined either by
owners of bottleneck transmission resources who can use those resources
to prevent consumers from receiving lower cost generation, or by
sophisticated marketers who easily devise ways to manipulate poorly
designed markets and then invent childish nicknames for the methods
they use to cripple a region's economy.
I think the current FERC Commissioners recognize the flaws in that
third position and understand that there is a fundamental difference
between competition and mere deregulation, and that deregulation in the
absence of full and fair competition is the worst of all worlds for
consumers. I think the current FERC Commissioners recognized that it
was not enough to say in the face of the Western state power
catastrophe to ``let the markets work,'' when in fact those markets
appeared to be subject to grotesque levels of manipulation. FERC has
properly changed its focus to monitoring and policing markets, through
such efforts as the creation of the new FERC Office of Market Oversight
and Investigation. Finally, I think FERC has correctly recognized
through the SMD NOPR that, if the Nation wishes to rely on market
forces at the wholesale level to provide adequate supplies of
generation at just and reasonable prices, that there are certain common
structural requirements that need to be addressed in order for those
benefits to flow across state and regional lines.
Again, I think that there are strong principled arguments
supporting the view that a cost-based regulatory system of vertically
integrated electricity providers is preferable to a more market-based
system. I also have heard many principled arguments that a market
design that works in the mid-Atlantic states may be totally
inappropriate in other regions such as the Pacific Northwest. But I
think FERC has done a service to the Nation by taking a proactive
approach and setting forth a proposal for comments that at least
attempts to take a ``best practices,'' rather than a ``lowest common
denominator,'' approach to developing a standard market design for the
Nation as a whole. The reliance on best practices is important for
states that have already had some success in developing regional
wholesale markets. Standardized rules that preserve or improve the most
successful existing market design functions are desirable; market rules
that are watered down and weakened just in order to get other regions
``on board'' are of no value, or would indeed be counterproductive.
Most electric consumers in my state, Pennsylvania, have the good
fortune of being served by utilities that are part of what many people
consider to be the most successful regional electricity market in the
United States, PJM. It is obviously not a coincidence that many
features of the FERC SMD are taken from the PJM model. One of the
advantages we have had in developing a regional model in PJM is that we
have a 75 year headstart. That is, the PJM utilities first joined to
work together on a coordinated basis in 1927. The evolution of PJM into
a more competitive wholesale market and independent system operator has
been just that an evolution. When I look at the PJM market as it has
performed since it became an independent system operator with
substantially market-based pricing, I have seen a continuation of
reliable service at energy prices that are generally consistent with
what one would expect in a competitive energy market. The average spot
energy price in PJM was below $50 per megawatt hour (or 5 cents per
kilowatt hour) in more than 86% of the hours in both the years 2000 and
2001. Even when energy prices go up sharply in PJM, as they did at
various times this past summer, they seem to do so in response to
forces of supply and demand. We have not been immune from market
manipulation in PJM as I believe was evidenced in the energy market in
July 1999 and the capacity market in the winter of 2001 but, because
PJM is operated on a truly independent basis with a very strong and
effective market monitoring unit, I believe that efforts to improperly
exercise market power are more readily detectable and remedied in PJM.
There are certainly still problems in PJM, particularly in the
capacity market. Indeed, this problem is recognized in the FERC SMD,
which rejects PJM's Installed Capacity (or ICAP) market structure as a
way of assuring resource adequacy. Unfortunately, I think the FERC-
proposed replacement method for assuring resource adequacy creates its
own set of problems, and would be unworkable in a region like PJM that
has retail choice.
Nevertheless, I would agree with FERC that the PJM model--which is
not really unique to PJM in many respects either at the national or
international level--is a reasonable starting point for developing
principles for a successful common market design. The question, of
course, is whether a market design that works in a densely populated
region that has long been served primarily by investor-owned utilities
utilizing thermal generating plants and operating in a tight power
pool, will be the best design, for example, in a sparsely populated
area or in an area served primarily by hydro power.
Personally, I would like to see more consistency among the regions
surrounding PJM. This could improve reliability, moderate prices, and,
most directly, prevent gaming by market participants between regions
with different rules. For example, under prior PJM rules, it was in the
interest of some generators operating in PJM, who were subject to an
energy price cap but received installed capacity (ICAP) credits, to
move their power out of PJM during periods of shortage into neighboring
regions that did not have a capacity requirement but where they could
charge higher uncapped energy prices. While I believe that this
particular practice was substantially remedied by a subsequent change
in the PJM rules, my point is that I would rather see generators
competing with each other under a consistent set of rules, than looking
for angles in the seams between markets that allow them to increase
profits through gaming.
Having said that, I would certainly defer to my counterparts in
other states and regions to advise FERC as to whether they believe the
PJM or SMD model would work in those areas or whether in fact, any
attempt to move toward more competitive wholesale markets creates more
problems than it solves.
Regarding the specific elements of the SMD proposal itself, my own
greatest concern is the resource adequacy provision that I alluded to
earlier. No matter how the electric industry in this Nation changes at
either the wholesale or retail level, it is essential, in my view, to
maintain the adequacy and reliability of electricity service. In the
SMD, FERC makes it clear that it rejects the use of the PJM Installed
Capacity (ICAP) market as a means of assuring that adequate generation
reserves are in place to ensure service to customers throughout the
year. We have learned through hard experience in Pennsylvania that the
PJM ICAP market is subject to manipulation and needs to be
substantially improved or replaced. I also agree with FERC that the
energy market alone is not adequate to ensure long term resource
adequacy. I am concerned, however, that the FERC's long term adequacy
proposal is not a viable replacement to the ICAP mechanism now in place
in PJM.
I think that FERC is correct in seeking a longer-term (three year)
adequacy planning horizon and in requiring the Independent Transmission
Provider (ITP) to develop a load forecast to cover that period. I do
not agree that FERC should establish a specific minimum reserve level
such as 12%. A reserve margin is an output of a reliability analysis,
not a goal in itself. The relevant reliability standard, I think, is
the one day in ten year loss of load probability (LOLP) analysis that
has been used for many years by PJM and many other planning entities.
The reserve margin that is required to meet the one day in ten year
LOLP is a function of many factors, including the size, type and outage
history of the generation in a particular region.
The biggest problem with the FERC proposal, however, is that it
calls on all load serving entities (LSEs) to develop a plan to meet
their share of the reliability requirement three years hence. It is
only necessary to look at the list of LSEs who were serving retail
customers in Pennsylvania in 1999 and compare that to the list of such
LSEs in 2002 in order to recognize the flaw in this proposal. Many of
the competitive LSEs from 1999 have left the Pennsylvania market or
gone out of business. Others have remained in the market but their
current loads are drastically different from the loads they were
serving two or three years ago. In my opinion, FERC's proposal might
work in a region that has no retail competition and where a single
provider is responsible for meeting all future load requirements. I do
not think it will work, however, in a state or region where individual
utilities and competitive marketers have no real way of knowing the
amount of retail load that they will be serving three years from now.
In my opinion, the cost of reliability over and above the level
that the market provides is a social cost that should be borne by all
those who benefit from a reliable electric system, that is, everyone
who uses electricity. In other words, if society concludes that the
costs of unreliable service are intolerable--and I agree that they are
intolerable--and if the competitive market alone does not produce the
level of reliability that society believes is necessary, then we should
put our collective thumb down on the scale on the side of reliability
and take steps to ensure such reliability at a reasonable societal
cost.
One possible way to address this issue under the FERC SMD would be
for the Independent Transmission Provider (ITP) itself, such as PJM, to
serve as the backstop ensurer of resource adequacy in the event that
the competitive wholesale markets do not produce adequate resources to
ensure reliable service. That is, if the ITP determines in its forward
resource planning role that the market will fail to deliver needed
resources in a timely manner, the ITP should have the authority and
capability to meet those needs. Preferably, the ITP should meet those
needs through some type of competitive procurement process, such as an
auction, that should be open to not just capacity from new central
power plants, but also to distributed generation, demand side
resources, and transmission improvements. But ultimately, the cost of
meeting this reliability requirement--over and above the level of
reliability produced by market forces--should be shared by all
electricity consumers.
Finally, I would like to touch on two other issues that are
addressed in the SMD and that I believe are extremely important to any
successful competitive wholesale market design. Those issues are
independent governance and market monitoring.
With respect to governance, I would submit that the independence of
the PJM Board of Managers and Staff has been critical to the
credibility and success of the PJM ISO. I am encouraged by the clear
recognition in the SMD of not only the need for Board independence from
market participants, but also of fully independent ITP operations as
well.
In addition, I think it is necessary to have an effective Market
Monitoring Unit within the ITP in order to prevent market manipulation
and take steps to remedy such problems when they arise. Again, this is
an area where I believe that PJM has excelled. The market monitor also
must have complete independence and freedom from interference by market
participants. I do not think it is either necessary or appropriate,
however, to have the market monitoring unit be physically separate from
the ITP market operations. On the contrary, I think it is preferable
for the market monitor to be closely integrated into ITP operations, as
is currently the case in PJM.
With respect to data, I would give the market monitor the greatest
possible access to all cost, price, and other market information that
could in any way assist the market monitor in reviewing market
transactions on both a real-time and long-term basis. Those market
participants who wish to shield data from the market monitor should, in
my opinion, bear an extremely heavy burden. Certainly, confidentiality
and market concerns come in to play to the extent that requests for
information extend beyond the market monitoring unit. There should be
strong, effective confidentiality protections, such as those contained
in the PJM Operating Agreement and Market Monitoring Plan. However,
these should not interfere with the ability of the market monitor to
obtain the information in the first place. Nor should this be allowed
to interfere with the ability of the market monitor to report the
results of his or her analysis to the ITP Board, FERC, and state
regulators in the event that evidence of potential or actual market
abuse is found.
It is my view that after the disgraceful and shocking revelations
of the last year regarding the operations of the wholesale electricity
market in parts of the Nation, the entire national effort to
restructure the electric industry is at risk. It is in the interest of
all market participants, not just consumers and regulators, to ensure
that these markets are vigorously and effectively monitored. This must
be done in a manner that prevents even an opportunity for market
manipulation or other abuses that have called into question the
benefits of any attempt to bring greater competitive forces into the
wholesale electricity market.
I want to thank Chairman Bingaman and the Committee again for
permitting me to share my views on these important issues. I would be
happy to answer any questions you may have at this time.
The Chairman. Thank you very much. Let me just ask a very
general question, similar to what Senator Cantwell asked
earlier of Chairman Wood.
The long-term, or the goal which I think FERC is intending
to serve with this standard market design proposal is to
increase the reliability of the power throughout the country,
and ensure the lowest possible cost. I gather from your
testimony, Ms. Showalter, you believe that it will not do that
in the case of Washington, that your State will be adversely
affected, the costs will be higher, the reliability will be
less secure if this standard market design is adopted, is that
correct?
Ms. Showalter. That is essentially correct, yes. I would
put it that the risks of the prices going higher, or
reliability being eroded, or political accountability being
eroded are much greater in the FERC's proposal than we have
today. We have a pretty good system today.
The Chairman. I would ask Ms. Hochstetter the same
question. Do you believe that this standard market design
proposal will either interfere with reliability as you now
enjoy it in Arkansas, or raise the price of power to your
consumers?
Ms. Hochstetter. Yes, sir. As drafted, there are several
provisions that would operate to reduce the certainty of
reliability that we have today and also increase costs both on
the transmission side and potentially on the generation side,
So those are both two adverse consequences that at this point
in time we do not see how they could be mitigated or offset by
any corresponding benefits on the other side.
The Chairman. Maybe you could be a little more specific as
to the problems that you see this standard market design
causing with the continued reliability of power in your State.
Ms. Hochstetter. Well, for one thing the capacity that is
currently dedicated to native load customers would not be
assured as going to them for future growth purposes. While
there is a provision in standard market design that they could
have some capacity rights for their existing needs, there is
nothing to guarantee that in the future, and so everyone would
be competing on an auction basis, or a bid basis, for
infrastructure for the future, and we would not have any
control over any of that, either the addition of incremental
transmission or the pricing of it, or any of the aspects to
guarantee reliability.
The Chairman. Well, Mr. Harvill, how about from your
perspective? I gather from your testimony you do believe that
this standard market design proposal will increase the
reliability of power and will ensure the lowest possible cost,
or will do better than current law does. Is that an accurate
interpretation?
Mr. Harvill. I think that is an accurate statement, and I
agree that at least in my opinion the standard market design
can do everything to improve reliability and very little to
decrease reliability going forward. This is something that we
have been looking for for a number of years in the State of
Illinois, having gone to retail competition. We understand that
since we no longer regulate generation and the construction of
new generation in the State of Illinois, we are going to rely
on generation on a more region-wide basis, and it needs to be
interconnected, and it needs to be overseen by, as Mr. Popowsky
acknowledged, a market monitor to assure that things are done
above-board.
The one example that I would give, going back to 1999 with
a weather-related problem when one transmission line was taken
out going east from Illinois, it created serious problems with
regard to actual generation coming into the State of Illinois.
Taking that to a logical argument, that if that transmission
line could be manipulated in an economic sense rather than in a
physical sense, we could face those same problems, so what we
are looking for here is really standard market design to
increase our reliability, to increase the power flows among the
States, to make sure the power flows freely and without the
potential for market abuse.
The Chairman. Mr. Popowsky, let me ask you the same
question. Do you see this proposal as in a general way
increasing reliability, and reducing prices in your area of the
country, or do you believe you have pretty much done everything
that this proposal would contemplate should be done in your
area?
Mr. Popowsky. No, we certainly have not done everything,
but I do think that generally, for our region, given the
features of our region, and particularly Pennsylvania, the PJM
model I think works well. I think in terms of generation, which
is the biggest cost in a retail customer's bill, the price of
the generation that now are produced by the PJM market are
certainly lower than the embedded costs, the embedded rates for
generation that some of our high cost utilities in Pennsylvania
were charging. Unfortunately, we are still paying stranded
costs right now, but that is a result of the former system
rather than the current system.
In terms of reliability, I think that PJM has for many,
many years recognized that operating on a regional basis and
doing the reliability planning on a regional basis, I think
provides benefits for all utilities and all consumers, and I
think they have recognized in the last few years that doing
transmission planning on a regional basis also provides benefit
for consumers, particularly in an area like ours, so yes, I
think for the most part our PJM model has worked, at least in
Pennsylvania and I think in PJM.
The Chairman. Thank you very much.
Senator Cantwell.
Senator Cantwell. Thank you, Mr. Chairman, and thank you,
Chairwoman Showalter for this list of issues that are, if you
will, the important critical things in this multipage report,
or rulemaking, that we need to understand.
I guess on that, the first question is in trying to grapple
with these wholesale versus retail regulation. Didn't the U.S.
Supreme Court recently address the issue of Federal versus
State jurisdiction over transmission use for bundled retail
sales, and how would that--I mean, they have been pretty clear
about where the authority lies, have they not?
Ms. Showalter. Well, our commission was a party in that
suit, and I attended the Supreme Court argument, so I followed
it pretty carefully. There were two questions before the Court:
Does FERC have jurisdiction over transmission if a State has
unbundled, that is, a deregulated transmission from
generation--that would be a State like New York--and does FERC
have jurisdiction over transmission, or the transmission
component of bundled retail services in States that have not
deregulated, like Washington?
At the time, Enron was arguing in the Court that yes, the
Supreme Court was required to say, and FERC was required to
assert that it had jurisdiction over the transmission component
of bundled retail service. FERC's position in the U.S. Supreme
Court was that no, FERC does not have jurisdiction, and in its
brief to the Court FERC said, in light of the commission,
meaning FERC, in light of the commission's reasonable finding
that it lacks jurisdiction over the transmission component of
bundled retail service sales under section 201, it is not
required to regulate the transmission component under 206, as
Enron was arguing.
The position of FERC changed with the new chair, so now
FERC is asserting jurisdiction over that component, over retail
sales, as Enron had urged. FERC in its rulemaking says that the
U.S. Supreme Court has made clear that it does have
jurisdiction, and I flatly disagree. If you read the last three
paragraphs of the U.S. Supreme Court opinion it clearly says
that it is not reaching that question. It did not reach that
question because FERC did not assert jurisdiction. In fact, the
Court said that were FERC to assert such jurisdiction it would
raise, and I am quoting, the complicated nature of the
jurisdictional issues.
So it is an unanswered question. What is being interpreted
here is the Federal Power Act, which gives FERC jurisdiction
over the wholesale business of electricity and transmission, so
the question is, is transmission limited only by wholesale, or
does it reach into retail?
There is no doubt at all that when the act was passed in
1935, all of the States had bundled retail service, and the
States had jurisdiction over the transmission component of
bundled retail service. Now that some States have deregulated,
the question arises, but it seems to me the legal question is
unanswered, but that in any event FERC should not assert
jurisdiction over our States and, in any event, it is Congress'
role to define that, so we say we would rather you not have an
electricity title in the energy bill, but if there is going to
be one, clarify that FERC does not have jurisdiction over
retail service.
Senator Cantwell. Which they argued before the Supreme
Court and said so.
Ms. Showalter. In the case, FERC asserted it did not have
jurisdiction.
Senator Cantwell. Thank you.
Another issue on which it is obviously critically important
that we get clarification is this issue of congestion revenue
rights, and whether, in this proposal, after a 4-year period,
utilities would have to give up these congestion revenue rights
and, in fact, become part of a bidding process. My sense is in
the rulemaking that this is pretty clear. I am not sure, from
what has been said this morning, whether people agree that that
is what happens. What is your impression of what is going to
happen here on existing contracts on transmission, the long-
term contracts?
Ms. Showalter. Well, it is not terribly clear in the
proposed rule itself, but under the rule, utilities have the
right to the money from an auction of their transmission
rights, and so if you want to imagine nickels coming out of the
electrical socket, the issue is that the right of physical
access to the transmission system is not the same as the
financial benefits from it. What consumers need is electricity,
not dollars.
But even given that, first there is no provision for
growth. In other words, FERC would assert that utilities have
the financial rights, not the physical rights, to their current
contracts but not the future. Utilities are built to grow. We
know in the Northwest that dams were built in 1930 and we are
still benefiting from it, but more importantly, it is very
difficult to know what those contractual rights actually are.
Because we have a different system today, the contracts for
power and transmission assume that the utilities will have the
benefit. A utility does not contract with itself for
transmission, for example. If a utility owns transmission, it
does not have a contract that looks like that. FERC would have
it turn over the transmission to an independent power provider
where it is unclear what these rights mean, but it is only the
financial right.
Senator Cantwell. Mr. Chairman, could I ask one more?
The Chairman. Why don't you ask a final question, then we
will go to another panel.
Senator Cantwell. In looking at it, it seems to me FERC is
saying, ``yes, after 4 years, basically the long-term
transmission contracts that you currently have are not going to
be valid and you are going to have to rebid.'' You know, it is
a very interesting question. We cannot get FERC to basically
get rid of our unjust and unreasonable Enron contracts, but yet
FERC wants to get rid of our 20 and 30-year transmission
contracts, if that is what I interpret, reading the current
proposed rule.
If this is not the case, it seems to me that a new proposed
rulemaking that clarifies that, where people in the Northwest
could comment, or comment on that impact, would be a helpful
thing in clarifying exactly what is the intent under this
proposed rule.
Ms. Showalter. And I assume there will be a lot of comments
to FERC about that question, and FERC will try to clarify it.
The deeper question to me, though, is the jurisdictional one.
It does not matter so much what this rule says, as who gets to
say it, who gets to set the rules. If FERC has jurisdiction
over retail service, it has jurisdiction. If it has
jurisdiction in any State in the country, it has jurisdiction
over every State in the country, and today's rule, problematic
as it is, is not necessarily tomorrow's rule. That is why the
jurisdictional issue is so important, and it is so important
that Congress clarify FERC does not have jurisdiction over
retail service, bundled retail service.
Senator Cantwell. Thank you very much. Thank you, Mr.
Chairman.
The Chairman. Thank you very much. Let me thank all four
witnesses for your excellent testimony. We appreciate it.
We will go ahead with the final panel at this point. Jeff
Sterba, the chairman of PNM Resources, Roy Thilly, chairman of
the Transmission Access Policy Study group, John Tiencken, who
is president and CEO of South Carolina Public Service
Authority, and Betsy Moler, who is the senior vice president
for Government Affairs for Exelon Corporation.
Why don't we start--we will just do the same way here we
did before. Betsy, why don't we start with you, and each of you
take 5 or 6 minutes. Your entire statement will be included in
the record, but if you could make the main points that you
think we need to be aware of, we would appreciate it.
STATEMENT OF ELIZABETH A. MOLER, SENIOR VICE PRESIDENT,
GOVERNMENT AFFAIRS AND POLICY, EXELON CORPORATION, ON BEHALF OF
THE ELECTRIC POWER SUPPLY ASSOCIATION
Ms. Moler. Thank you, Mr. Chairman. I appreciate the
invitation to be here today. My name is Betsy Moler. I am
senior vice president of Exelon Corporation. Exelon is a public
utility holding company. Our two utility subsidiaries,
Commonwealth Edison and Picot Energy, serve 5 million customers
in Chicago and Philadelphia. We have more retail customers than
any other utility. We also have 40,000 megawatts of generation
that we either own or have under long term contracts, the
second largest generation fleet in the country.
I am appearing today on behalf of EPSA, the Electric Power
Supply Association. EPSA is the trade association representing
competitive power suppliers, including independent power
producers, merchant generators, and power marketers.
I do have a somewhat unique perspective on today's
rulemaking proposal. As an alum of this committee staff and as
the chair of the Federal Energy Regulatory Commission when FERC
issued Order 888, I was there at the beginning of the
transition to competition, and I am happily participating as we
work our way through the difficult issues that this industry
faces.
I want to make four points today. First, the present system
simply is not working. The fact that Western price caps are
working and electricity issues are no longer on page 1 of every
newspaper in the country should not lull us into complacency.
Wholesale competition is not working as efficiently as it needs
to. The current system is balkanized, inefficient, and results
in rates that are simply too high. Markets are susceptible to
manipulation. We have clearly seen that in the West, we have
seen it in Texas, and the current system is not sustainable.
Second, the standard market design notice of proposed
rulemaking is based on best practices from energy markets
around the world. The essential features are not some radical
theory that FERC dreamed up. They work. They are practical,
they are workable, and they are economically sound.
The Commission in the rulemaking proposal does recognize
that it has additional work that needs to be done before they
get to a final rule. I want to focus in particular on
locational marginal pricing, which is one of the hearts of the
rulemaking proposal.
LMP works better than any other model in the world for
managing congestion. The Department of Energy Transmission
Advisory Subcommittee of the DOE's Electricity Advisory Board
which it is my privilege to chair has just endorsed LMP, and
that board is composed of a broad array of public, private
entities, consumers, large producers and the like, and we all
agreed that LMP is the best practice in this area.
Third, we need a standard market design. All wholesale
transactions need to be under a single tariff, with clear
pricing rules, transparent pricing rules, clear planning
policies to be done on a regional basis, consumer protection
through mitigation and oversight. It will work if we give it a
chance, and it needs to happen.
Fourth, the transmission issues are serious. The FERC has
worked through them successfully in PJM. PJM initially
allocated financial transmission rights based on utilities
load. They successfully preserved our ability, and in this
sense I am speaking as Picot Energy, the largest load-serving
entity in PJM, to serve native load. It can be done under LMP.
It can be done properly under the notice of proposed
rulemaking.
The 2004 effective date provides sufficient time to allow
an orderly transition to the new marketplace. EPSA and Exelon
will file supportive comments on the NOPR. We will include
specific suggestions designed to make it even more workable and
respond to FERC's numerous questions. The fact that they are
going through this normal notice and comment rulemaking process
to me is an excellent sign, and it is obvious that they are
listening to those who have specific suggestions to make.
Frankly, I am puzzled by the idea that the NOPR goes too
far too fast. Without a standard market design, our Nation's
electricity markets will continue to be erratic and subject to
market power abuse. State regulators will see a change in their
role once SMD is implemented, to be sure, but, as the Supreme
Court recognized in its review of Orders 888 and 889, the
Nation's electric supply system epitomizes interstate commerce
and cannot be effectively regulated by individual States.
A thoughtful standard market design proposal for the
wholesale electricity markets is imperative to the future
health not only of the electric supply industry, but to the
Nation's economy.
Thank you, and I will be pleased to answer any questions
you may have.
[The prepared statement of Ms. Moler follows:]
Prepared Statement of Elizabeth A. Moler, Senior Vice President,
Government Affairs and Policy, Exelon Corp.
Mr. Chairman and Members of the Committee, thank you for the
opportunity to testify today. I am Elizabeth A. (Betsy) Moler, Senior
Vice President, Government Affairs and Policy for Exelon Corporation.
Exelon is a registered utility holding company. Our two utilities,
Commonwealth Edison (ComEd) of Chicago, and PECO Energy of
Philadelphia, serve over 5 million electric customers, the largest
electric customer base in the United States. We have more than 40,000
MW of generating capacity, the second largest portfolio in the United
States. Our wholesale power marketing division, known as the Power
Team, markets the output of our generation portfolio throughout the
lower 48 States and Canada with a perfect delivery record.
I am here today representing the Electric Power Supply
Association's (EPSA) member companies. EPSA is the national trade
association representing competitive power suppliers, including
independent power producers, merchant generators and power marketers.
These suppliers, which account for more than a third of the nation's
installed generating capacity, provide reliable and competitively
priced electricity from environmentally responsible facilities serving
global power markets. EPSA seeks to bring the benefits of competition
to all power customers. On behalf of the competitive power industry, I
thank you for this opportunity to comment on the Federal Energy
Regulatory Commission's Standard Market Design (SMD) rulemaking
proposal.
I have a unique perspective on the FERC's initiative. I served as a
Member of the Commission from 1988-1992, and then as the Chair of the
Commission from 1993-1997. I was at the Commission's helm in 1996 when
we issued Order Nos. 888 and 889, the landmark rules that required
utilities to provide ``open access'' to their transmission lines and to
develop transparent systems to provide information about available
capacity on their transmission lines. Those rules implemented Congress'
mandate in the 1992 Energy Policy Act to enhance competition in
wholesale electricity markets. Order No. 888, which was recently upheld
by the United States Supreme Court,\1\ made great strides toward the
restructuring of wholesale electricity markets. However, recent events
in wholesale electricity markets, including dislocations in California,
have made it abundantly clear that more work needs to be done to make
wholesale competition work better in order to benefit all consumers.
Simply put, Order No. 888 did not go far enough. I believe that FERC's
Standard Market Design initiative is the next, essential step towards
efficient competitive wholesale markets that will bring real benefit to
consumers.
---------------------------------------------------------------------------
\1\ New York v. FERC, 122 S. Ct. 1012 (2002).
---------------------------------------------------------------------------
The competitive power supply industry supports the direction that
FERC has taken and wholeheartedly endorses the idea of standard market
rules and a single transmission tariff. The rule incorporates best
practices from energy markets throughout the world: FERC has learned
from both successful and failed markets what should and should not be
incorporated into a standardized market. By contrast with the
unsuccessful California wholesale market design, the essential features
of FERC's standard market design have already been shown to work.
Studies have repeatedly shown that efficient competitive wholesale
markets bring real benefits to consumers. Regional transmission
organizations--a crucial part of SMD--could save consumers as much as
$60 billion by 2021.\2\ Wholesale competition--incomplete as it is--has
already benefited consumers; the average price of electricity has gone
down as much as 35 percent since the introduction of wholesale
competition in the 1980s.\3\
---------------------------------------------------------------------------
\2\ ``Economic Assessment of RTO Policy'' prepared for FERC by ICF
Consulting on February 26, 2002.
\3\ ``2000 Data Update: Assessing the `Good Old Days' of Cost-Plus
Regulation'' study prepared for EPSA by the Boston Pacific Company.
---------------------------------------------------------------------------
There have been a number of efforts during the past decade to open
wholesale power markets to competition. Notwithstanding these efforts,
the Nation's electricity markets remain inefficiently disjointed. The
solution is a thoughtful, cohesive and standardized design for the
Nation's wholesale electricity markets. A standard design will benefit
all interests by reducing transaction costs and connecting buyers and
sellers across greatly expanded market areas. Adoption of a standard
wholesale market design with nationally integrated rules is imperative
to avoid more California-style crises.
FERC's bold proposal, which was developed with the benefit of a
significant outreach program to solicit the views of various sections
of the industry, the government and consumers, is broad and far-
reaching. The SMD principles are practical, workable, and economically
sound. SMD would apply the same set of rules for all users. It includes
clear pricing and planning policies, consumer protection through
mitigation and oversight, market rules that protect against
manipulation, and regulations that enhance reliability. All told, it
clearly will lead to a more efficient, effectively functioning
marketplace.
STANDARDIZED MARKET AND A SINGLE TRANSMISSION TARIFF
For the competitive electricity supply industry to function
efficiently and deliver electricity where and when consumers need it,
electricity markets within the contiguous States must operate
seamlessly. Supply must be allowed to seek out demand without
encountering local roadblocks and tollbooths at every state line. Our
current balkanized transmission system makes it difficult to transmit
power from region to region, drives up costs, and harms reliability.
Standardized market design will solve these problems by creating
uniform rules and allowing all transmission customers to operate under
the same procedures and pricing structure. SMD will allow all
transmission users to schedule power deliveries using multiple receipt
and delivery points, putting them on a fair footing with transmission
owners and preventing manipulation of the transmission system.
Congestion on the grid will be managed through an efficient locational
marginal pricing (``LMP'') system. For regional markets to be fully
coordinated, data systems, software, user interfaces and business
processes will have to be standardized to the fullest extent possible.
Exelon has extensive experience operating in the Pennsylvania-New
Jersey-Maryland Interconnection (``PJM'') marketplace, long recognized
as the Nation's most successful regional wholesale market. Indeed, our
subsidiary PECO Energy was one of the founding members of PJM, and we
are proud of the fact that PJM has pioneered many successful practices
that FERC proposes to apply across the country. In marked contrast to
California's flawed system, PJM's LMP market design has proven to be
the Nation's most reliable and efficient market design.
Many industry experts recognize that LMP works. For example, the
Transmission Grid Solutions Subcommittee (which I have the privilege of
chairing) of Secretary of Energy Spencer Abraham's Electricity Advisory
Board, recently endorsed LMP. The Subcommittee, which includes
representatives from public power, state regulatory commissions,
investor-owned utilities, independent system operators and independent
power producers, applauded FERC's effort to continue to implement LMP
and the initiative to require RTOs to adopt such a system.
SMD would solve a number of the transmission concerns that were
raised during the Senate's debate on the National Energy Policy Act.
When PJM implemented LMP, it successfully addressed a number of
transition issues. PECO's historic capacity rights formed the basis for
the initial allocation of financial transmission rights, or FTRs. Based
upon our experience, we can state unequivocally that LMP does not
interfere with, or harm, a utility's ability to serve its native load
customers. The same is true for the FERC SMD rulemaking proposal.
Because SMD addresses transition issues and reservation of transmission
capacity for existing customers, there is no need for Congress to make
special provisions to enable load-serving entities to meet their
service obligations. That amendment would have created two classes of
transmission customers, deterred entry by new competitors, and required
FERC to micromanage transmission planning and capacity reservation.
MARKET MONITORING AND OVERSIGHT
States provide a vital role in consumer protection, but they cannot
be individually responsible for protecting their citizens from
dysfunctional markets. Simply put, attempting to build electricity
islands, as defined by State borders, ignores the truly interstate
nature of wholesale electricity markets and the reality of the way
electricity markets work. The State of California designed a flawed
system that drove up prices in the entire West. Through the creation of
a standardized market, with rational market rules that encourage risk
management and enhance transparency, can consumers benefit and escape
undue discrimination. Wholesale electric markets are regional; the
rules that govern them cannot be decided on a state-by-state basis.
Electricity does not and should not stop at the state line-regional
markets promote reliability and lower costs.
Standardized rules for operation of the transmission system will
prevent the exploitation of ``seams'' between regions and help lower
costs for all consumers by thwarting the efforts of some transmission
owners to favor their own generation over lower cost options. SMD will
increase price transparency and oversight of the markets, and
standardized rules will prohibit much of the gaming that Enron was
accused of inflicting on the California market. The FERC has provided
extensive analysis of how the SMD will eliminate exposure to such
practices in Appendix E of the NOPR.
regulatory certainty will calm capital markets and encourage investment
The regulatory certainty provided by SMD will enhance needed
investment in transmission and generation and stabilize the industry.
Delaying or preventing its implementation would not only harm
electricity consumers, it would also be deeply harmful to our national
economy and energy supply. The financial markets have welcomed the SMD.
A Schwab Capital Markets Washington Research Group report said that the
SMD NOPR could ``provide more certainty sooner and rebuild confidence
with investors.'' They went on to state that risk exists only if
Congress decides to intervene on behalf of some PUC's and incumbent
utilities thus stalling implementation of SMD. The best thing that
Congress can do to improve wholesale electricity markets would be to
urge FERC to ``get on with it'' in implementing SMD.
One of the major reasons that companies have been reluctant to
invest in much-needed transmission expansion is current uncertainty
about the rules under which transmission will operate. Electricity
generators and transmission owners alike recognize that transmission
owners must be able to recover their investments, plus a fair return on
those investments. The President's National Energy Policy Report
predicted that demand for electricity would increase by about 25
percent over the next ten years, while electric transmission capacity
would only increase by four percent. SMD implementation would clarify
the importance of adding transmission infrastructure and promote
investment in the grid. A system of congestion revenue rights will
provide the appropriate economic signals to encourage investment in and
efficient use of the transmission system. This provides real incentives
for investment in much needed infrastructure.
SMD IS A PROPOSED RULEMAKING, NOT A FINAL RULE
Standard Market Design is a step in the ongoing evolution of the
electric industry--it is neither the first word on the subject nor the
final chapter. This is a move to strengthen the markets that developed
after FERC's Orders No. 888, 889 and 2000. The SMD is critical to
completing Congress' vision and FERC's of genuine wholesale
competition, efficient transmission systems, the right pricing signals
and more options for consumers. As circumstances shift overtime, I am
sure that there will be proceedings to calibrate the SMD rule and
propose enhancements to the wholesale electricity market.
Comments are due on November 15, with reply comments due on
December 20. FERC does not anticipate final implementation of the rule
until 2004. I believe this is sufficient time to allow an orderly
transition to the new marketplace. EPSA, Exelon and other stakeholders
will file comments on this rulemaking, urging changes, fine-tuning and
clarification. We agree with the destination of the SMD, but have
suggestions that will help make it better when we get there. We believe
that SMD is an excellent move towards promoting nondiscriminatory
competitive markets, and we support going forward with the rulemaking
process. Everyone involved in the process, including the Commission,
recognizes that the current proposal needs refinement; that is what the
rulemaking process is all about. But I am confident that the
Commission, and its fine staff, will get the job done.
Frankly I am puzzled by the attitude of some that SMD goes ``too
far, too fast.'' Without SMD our Nation's electricity markets will
continue to be erratic and subject to market power abuse. State
regulators will see a change in their role once SMD is implemented, to
be sure. As the Supreme Court recognized in its review of Order Nos.
888 and 889, the Nation's electric supply system epitomizes interstate
commerce and cannot be effectively regulated by individual states. A
thoughtful, standard market design for wholesale electricity markets is
imperative to the future health not only of the electricity supply
industry, but also to the Nation's economic recovery.
Thank you again for the opportunity to testify. EPSA, and Exelon,
look forward to continuing to work with you to promote effective
competitive electricity markets.
The Chairman. Thank you very much.
Mr. Tiencken, why don't you go right ahead.
STATEMENT OF JOHN TIENCKEN, JR., PRESIDENT AND CEO, SOUTH
CAROLINA PUBLIC SERVICE AUTHORITY, ON BEHALF OF THE LARGE
PUBLIC POWER COUNCIL
Mr. Tiencken. Thank you, Mr. Chairman. My name is John
Tiencken, and I am president and CEO of the South Carolina
Public Service Authority, also known as Santee Cooper. I am
testifying here today on behalf of the Large Public Power
Council, LPPC, an association of 24 of the largest public power
systems in the United States.
The LPPC members directly or indirectly provide reliable,
affordably priced electricity to most of the 40 million
customers served by public power. Collectively, we own and
operate over 44,000 megawatts of generation and approximately
26,000 circuit miles of transmission lines. LPPC members are
located in States and territories representing every region of
the country, including States represented by members of this
committee such as Washington, Arizona, Florida, California, and
Nebraska.
While the SMD NOPR would not be directly applicable to
public power systems if enacted in its present form, it would
significantly affect us. The LPP member systems have
relationships with investor-owned utilities who will be
directly subject to these regulations. In some instances, we
are so effectively integrated with the systems of our investor-
owned counterparts that we will also need to accommodate the
constraints of SMD. Also, the facilities of many of the LPP
systems are within the footprint of existing and proposed
regional transmission organizations, or tight power markets,
which may significantly be changed as a result of SMD.
These existing relationships will mean that we will
effectively be living within an SMD regime. The Large Public
Power Council and my company individually will file comments
with FERC and have some significant concerns about the SMD
NOPR. We agree with FERC that it is important to have clear
rules to guide participants and to ensure that markets function
properly. However, the establishment of such rules must be and
should be approached with caution. Any misstep could lead to
serious market dysfunction, and our overriding concern
continues to be the protection of customers and the obligations
that we have to serve those customers.
Let me state that we are in favor of open access
transmission. The LPPC has long supported policies that ensure
that all market participants have access to the transmission
system on a fair and nondiscriminatory basis. Presently, we
provide open access to our available transmission on terms
comparable to those that we charge ourselves.
My company, Santee Cooper, was the first public power
system to submit an open access safe harbor tariff with the
FERC, and we operate our system consistent with the
requirements of Order 888 and 889. Over 3 years ago, the LPPC
agreed to a compromise proposal known as FERC Light. The intent
of FERC Light was to agree to extend limited FERC jurisdiction
to public power systems and cooperatives in order to ensure
that open access transmission service would be provided to all
market participants.
The LPPC continues to support this limited expansion of
FERC transmission jurisdiction. LPPC believes, and as many of
the committee members expressed today, that regional
differences need to be respected in any legislative or
regulatory framework. As an association of 24 members from all
over the country, we are very well aware of the distinctions
that exist in markets around the country, and genuine diversity
does exist among our members. This leads to an awareness on our
part that one size simply does not fit all.
The final issue I am going to address with you today
concerns our ability of public power systems to serve our local
communities. This is an issue of paramount concern to LPPC
member systems. Just let me reiterate, we support open access
transmission policies. However, we do not want to risk the
reliable, reasonably priced power that our customers expect and
are entitled to.
Our members' facilities were built for the benefit of their
customers and our communities. Let me talk about my company in
particular. Santee Cooper was created back in the thirties for
the primary purpose of lighting up previously unserved rural
areas of South Carolina. Today, we have more than 4,000 miles
of transmission lines, mostly low voltage, spread all over the
State, reaching out to the least populated areas of our State.
By virtue of our statute, we are charged with the
responsibility of serving the electric cooperatives who are
serving customers in every county of our State. This statutory
obligation to serve is also embodied in a contract that we have
with the cooperatives to provide generation and transmission
service. This contract began in 1950, and has more than 20
years remaining, and may be extended beyond that.
The bottom line is that we have a very clear, very binding
obligation to provide the cooperatives, who reach more than 1.6
million South Carolinians, with electric service, including
transmission. Since our relationship with our customers is
cost-based pricing, and transmission is bundled into the cost,
our customers have a grave concern that the transmission system
which they paid for, and which provides them the electric power
at reasonable rates, will continue to be available to them
first, with any excess to be made available to others who are
not customers. This is what we do at Santee Cooper.
Public power operates as it does because our communities
have chosen this system. We are located in and operate in the
communities we serve, and those communities direct all of our
decisions. Local control has made us responsive to the
community's need, be that increased generation, or upgraded and
expanded transmission lines. Our customers have paid for the
transmission systems in their communities and, in many
instances, continue to pay for them. There is no reason they
should have to pay twice, first to build it, and then to use it
when it is congested.
Although the SMD NOPR seeks comment on a proposal that
offers limited protection against this outcome, we think that
direction from Congress is needed. For that reason, we support
the service obligations amendments that Senator Kyl and others
have put forward.
I appreciate the opportunity to testify, and look forward
to questions.
[The prepared statement of Mr. Tiencken follows:]
Prepared Statement of John Tiencken, Jr., President and CEO, South
Carolina Public Service Authority, on Behalf of the Large Public Power
Council
My name is John Tiencken, Jr., and I am President and CEO of the
South Carolina Public Service Authority (known as ``Santee Cooper''). I
am testifying today on behalf of the Large Public Power Council (LPPC),
an association of 24 of the largest public power systems in the United
States. LPPC members directly or indirectly provide reliable,
affordably-priced electricity to most of the 40 million customers
served by public power. We own and operate over 44,000 megawatts of
generation and approximately 26,000 circuit miles of transmission
lines. LPPC members are located in states and territories representing
every region of the country, including states represented by members of
this Committee, such as Washington, Arizona, Florida, California, and
Nebraska.
Mr. Chairman and members of the Committee, the LPPC has played an
active role in supporting a competitive, wholesale power market to
benefit consumers. We are here today to take stock of where we are.
First and foremost, LPPC wants to ensure that the customers we serve
and to whom we must answer continue to receive reliable and reasonably
priced power. I am here today to discuss the SMD and the issue of
service obligation, and to urge the Senate and Chairman Wood to
consider these important issues.
PUBLIC POWER SYSTEMS ARE UNIQUE
What does it mean to be a public power system? As a threshold
matter, a public power system is owned by the communities it serves,
not by private investors. We are not-for-profit entities. My company,
the South Carolina Public Service Authority (known as ``Santee
Cooper'') was created by the South Carolina legislature in 1934 ``for
the benefit of all the people of South Carolina and for the
improvements of their health, welfare and material prosperity.''
Specifically, it was chartered because the state needed to build a dam
on the Santee River, for flood and malaria control as well as
electricity production. Since that time, Santee Cooper has functioned
as an independent state agency, providing reliable electric services to
the citizens of South Carolina at rates which among the lowest in the
Southeast. Based on generation, Santee Cooper is the nation's third
largest publicly owned electric utility among state, municipal and
district systems. Our system serves 132,000 retail customers in
Berkley, Georgetown and Harry counties, and is the source of power for
the state's electric cooperatives. Santee Cooper also serves 32 large
industrial customers in 11 counties and provides power to the
municipalities of Georgetown and Bamburg and the Charleston Air Force
Base. Santee Cooper has 4,300 miles of transmission facilities covering
75 percent of South Carolina's geographic area.
STANDARD MARKET DESIGN PROPOSED RULEMAKING
Last month, the Federal Energy Regulatory Commission issued a
notice of proposed rulemaking (NOPR) on Standard Market Design (SMD).
While the SMD NOPR would not be directly applicable to public power
systems, if enacted in its present form, it would significantly affect
us. LPPC member systems have relationships with investor-owned
utilities, who will be directly subject to these regulations. In some
instances, we are so effectively integrated with the systems of our
investor-owned counterparts that we will also need to accommodate the
constraints of the SMD. Also, the facilities of many of LPPC systems
are within the footprint of existing and proposed regional transmission
organizations (RTOs) or tight power markets--which may be significantly
changed as a result of SMD. These existing relationships will mean that
we will effectively be living with an SMD regime.
The Large Public Power Council, and my company individually, will
file comments with FERC and have some significant concerns about the
SMD NOPR. We agree with FERC that it is important to have clear rules
to guide participants and ensure that markets function properly.
However, the establishment of such rules should be approached with
caution. Any misstep could lead to serious market dysfunction. Our
overriding concern continues to be the protection of our customers and
our obligations to serve them. LPPC has maintained a cooperative and
active relationship with FERC. We intend to continue to work with FERC
on this massive rulemaking and will be filing initial comments on the
NOPR with the Commission in November.
Open Access
Let me first state that we are in favor of open access
transmission. LPPC has long supported policies that ensure that all
market participants have access to the transmission system on a fair
and non-discriminatory basis. Presently, we provide open and non-
discriminatory access to our available transmission on terms comparable
to those we charge ourselves. In fact, my company, Santee Cooper, was
the first public power system to submit an open access, safe harbor
tariff with the FERC. We operate our system consistent with the
requirements of Orders 888 and 889.
Over three years ago, LPPC agreed to a compromise proposal known as
``FERC-lite.'' The intent of FERC-lite was to agree to extend limited
FERC jurisdiction to public power systems and cooperatives in order to
ensure that open access transmission service would be provided to all
market participants. LPPC will continue to support this limited
expansion of FERC transmission jurisdiction--but no more than what was
agreed to in our original compromise. The SMD NOPR and recent Supreme
Court decisions, combined with several contemplated legislative
proposals, have raised concerns among our members that the language of
the current FERC-lite provision could be expanded beyond its original
intent, possibly to impose de facto full FERC jurisdiction over public
power systems and cooperatives. LPPC is gravely concerned about this
potential interpretation. Therefore, while we continue to agree to
provide open access on non-discriminatory terms, LPPC cannot continue
to support FERC-lite unless the current language is modified to restore
its original intent.
Reciprocity
One provision in the SMD NOPR that directly impacts non-
jurisdictional utilities is the reciprocity provision. Order 888
provided that a non-public utility that takes service under a public
utility's open access transmission tariff must ``offer comparable (not
unduly discriminatory) services in return.'' Public power systems have
operated successfully within this framework for several years.
In the SMD NOPR, FERC has proposed to continue this approach to
reciprocity and we believe that the SMD NOPR contains an acceptable
reciprocity standard. Under the SMD, non-jurisdictional entities must
provide service comparable to what they provide themselves in order to
obtain SMD service from a jurisdictional utility. It is our
understanding that the proposed reciprocity standard does not require a
non-jurisdictional entity to adopt an SMD tariff, a reading which we
believe is supported by FERC.
Regional diversity
LPPC continues to believe that regional differences need to be
respected in any legislative or regulatory framework. As an
organization of 24 member systems from all over the country, we are
very well aware of the distinctions that exist in the markets around
the country. We have member systems located in New York State that are
fully participating in the NY ISO. Other member systems are located in
ERCOT. Still other systems are in the Pacific Northwest, the Southeast,
Midwest, and the West. Genuine diversity exists among our members. This
leads to an awareness on the part of LPPC that ``one size doesn't fit
all.''
While all of our members have accepted open access requirements,
not all of our members believe that the detailed market structure
imposed by SMD will work for them. In the Southeast, for example, I am
seriously concerned that if the SMD NOPR is enacted in its present
form, that the SeTrans development process will come to an abrupt and
premature end. That would be tragic since this unique process has
brought seven FERC non-jurisdictional transmission owners together with
three investor-owned transmission owners in an effort to find and
develop a regional transmission organization that best meets the needs
of our region.
In addition, several LPPC members are located in the Northwest,
where most power is produced through the coordinated operation of a
hydroelectric system. Our Northwest members have concerns that SMD
concepts such as LMP may not be workable and may pose risks to the
stability of this regional market.
We strongly urge the Congress and the Commission to recognize that
the needs of communities in different regions will vary and the means
of meeting those needs must also be distinct. While it may be desirable
to have regions and their markets be compatible, they do not have to be
identical.
Service Obligation
The final issue I am going to address today relates to the ability
of public power systems to serve our local communities. This is an
issue of paramount concern to LPPC member systems. Let me just
reiterate--we support open access transmission policies. However, we do
not want to risk the reliable reasonably-priced power that our
customers expect and are entitled to.
Public power systems are established by state law and are
obligated, generally by state law, to provide electric service to their
customers. We need to maintain and preserve the ability to fulfill this
obligation. For example, one of LPPC's Midwest members, Nebraska Public
Power District (NPPD), must own its own transmission--under state law,
ownership by any entity other than a public power system is not
permitted. NPPD must also, under state law, retain functional
responsibility to provide service to its customers. It is possible that
FERC will recognize these obligations and we hope FERC will work with
us to allow us to continue to meet our obligations.
Other LPPC members have entered into long term bilateral contracts
in making their long-term generation and transmission decisions. These
firm commitments allow for a stable and secure economy. They provide
for certainty in the market and allow the parties to make operational
and investment decisions over the long-term, decisions that are
necessary for the continued expansion of a functioning electric
generation and transmission system. Without some certainty as to the
future, obtaining approval from public governing bodies for generation
and transmission investments will be difficult, if not impossible.
As noted earlier, our facilities were built for the benefit of our
customers and communities. Let me talk about my company in particular.
Santee Cooper was created back in the 1930s for the primary purpose of
lighting up previously unserved rural areas of South Carolina. Today we
have more than 4000 miles of transmission lines extending over most of
the state, reaching out to the less populated sections of our state. By
virtue of our statute we are charged with the responsibility of serving
the electric cooperatives around the state, located in all 46 counties
of the state. This statutory obligation to serve is also embodied in a
contract that we have with the cooperatives to provide generation--and
transmission--service. This contract began in 1950 and has more than 20
years remaining and may be extended beyond that. The bottom line is
that we have a very clear and binding obligation to provide the
cooperatives--who reach more than 1.6 million South Carolinians--with
electric service, including transmission.
Our system was not built for the purpose of making bulk transfers
through our territory to points outside, but for the moving of
electricity from our generating stations to our customers. As a result
of our obligation to serve these customers, in particular the
cooperatives, the vast majority of our transmission lines are routed
through rural areas to reach equally rural areas. Most of the
transmission is at low voltages (69kv and 130kv and some 230kv). We do
not have any 345kv or 500 kv lines on our system. Since our
relationship with our customers is cost-based pricing, and transmission
is bundled into the cost, our customers have a grave concern that the
transmission system which they paid for and which provides them their
electric power at reasonable rates, will continue to be available to
them first--with any excess to be made available to others who are not
customers. That is what we currently do at Santee Cooper.
Public power operates as it does because our communities have
chosen this system. We are located in and operate in the communities we
serve and those communities direct all of our decisions. Local control
has made us responsive to our communities' needs--be that for increased
generation or upgraded and expanded transmission systems. Our customers
have paid for the transmission systems in their communities and, in
many instances, continue to pay for them. For example, several years
ago, the Sacramento Municipal Utility District (SMUD) contributed
approximately $100 million to an effort coordinated with other public
agencies to build a 500 KV line from the Sacramento area to the Oregon
border. The financing was done through bonds that will be repaid with
revenue collected from SMUD customer rates. The line is used to meet
the service needs of the Sacramento area, with any surplus made
available on a non-discriminatory basis. This line was built to respond
to the needs of the local community served by SMUD. This is an example
of how public power continues to invest in transmission assets
necessary to serve its customers and demonstrates how those customers
continue to pay for these transmission upgrades and expansions.
In other instances, our customers not only pay for the transmission
assets, they are obligated and responsible for the debt. For example,
MEAG Power, an LPPC member located in Georgia, is the all-requirements
wholesale electricity provider to 49 Georgia municipalities. These
cities formed MEAG Power and issued over $4 billion in municipal bonds
for the purchase of generation and transmission facilities in order to
ensure reliable, economical electric service. These customers actually
issued the bonds and serve as guarantors for the debt incurred. They
deserve to have continued use of the transmission assets they have paid
for and continue to pay for.
In summary, the key point for us is that our customers should not
have to pay twice for their transmissions system--first to build it and
then to use it when it is congested. Our customers have paid for the
critical transmission lines necessary to move power from distant
generation sources to meet service obligations to our communities. If
we are required to pay congestion charges whenever our use and the
demands of others exceed the capacity of the line, our customers would,
in effect, be ``double billed'' for the same transmission capacity. As
noted above, we need access to our own facilities and those to which we
have contractual rights in order to serve our communities. We are
concerned that our customers not lose the economic benefits that they
have created through investment and planning during times of
transmission congestion. Although the SMD NOPR seeks comment on a
proposal that offers limited protection against this outcome, we think
that direction from Congress is needed. For that reason, we support the
service obligation amendments that Senator Kyle and others have put
forward.
THE NEED FOR STATUTORY RECOGNITION OF SERVICE OBLIGATION
FERC recognizes our need to serve our customers and communities.
The issue is partially addressed in the SMD NOPR, however, the
provision does not sufficiently resolve our concerns. In addition, the
SMD NOPR is merely a proposal and we are very concerned about how and
when these issues will get resolved, therefore, we feel it is
appropriate to seek statutory recognition of our obligation to serve.
We supported the Kyl amendment--SA 3184--offered during the Senate
debate on S. 517. We believe that the amendment is good energy policy
and good public policy. It protects our consumers and helps ensure the
reliable delivery of electricity to our customers. Under the amendment,
a utility that has firm transmission rights (by ownership or under
contract) can retain those rights to meet its state law service
obligation. The amendment makes it clear that customers don't have to
pay twice for transmission: once to build it and then a second time to
use it if congestion occurs. The amendment is consistent with FERC
policy objectives and has wide support from industry--both transmission
owners and transmission dependent utilities.
Some have argued that recognizing this obligation to serve and
providing us with the transmission rights to fulfill this obligation
could be an impediment to competition. However, most LPPC member
systems would greatly benefit from a truly competitive wholesale
market. This is because we are generally price takers, not price
makers. We buy power on the wholesale market to fulfill the needs of
our customers and only sell power into the market when it is in excess
of our community's immediate need. In fact, most LPPC member systems
are net buyers of electricity. Moreover, we have no interest in or
motivation for favoring our own generation. Since we are not-for-profit
entities, we look for the lowest priced generation--wherever that is--
and provide that to our communities. In this way, our customers pay the
lowest price we can provide for their electricity.
Transmission investment
Many LPPC members have built transmission systems to accommodate
load growth. To the extent permissible under the private use rules, any
excess is made available to the market to the extent it is not needed
by the system to serve its customers. It is in the entity's best
interest to both build for load growth and to make excess transmission
capacity available to the market place. Load serving entities and their
customers who prudently built transmission to accommodate future load
growth should not be deprived of the benefit of that investment by
having their future right to use that transmission taken away. FERC can
develop oversight rules that will preclude hoarding or other potential
abuses that might occur. Elimination of load-serving entities ability
to guarantee service to its customers is not the solution.
In addition, under current rules, there are mechanisms in place by
which an RTO/ISO can assure that transmission upgrades are made when
transmission customers are willing to bear the cost of those upgrades.
The allocation of transmission rights to meet service obligations will
not operate as an impediment to transmission investment. Any concern
that transmission rights holders may have a disincentive to expand
transmission can be addressed by requiring that RTOs or RTO
participants make transmission upgrades when transmission customers are
willing to bear the cost of those upgrades
This Committee and the Commission have both expressed an interest
in how best to encourage investment in transmission facilities. This
then is the problem we are attempting to solve. In this respect, public
power is part of the solution, not the problem. We continue to invest
in transmission, in particular at SMUD, the Lower Colorado River
Authority (LCRA), and the Salt River Project (SRP). We are very active
in constructing needed transmission. It is our understanding that the
Commission is looking for a mechanism that makes sense, allows for
planning, and facilitates reliable expansion. We will be happy to work
with the FERC on this and demonstrate how public power is helping to
build needed new transmission today.
Private Use
It bears remembering that public power systems continue to be
constrained by IRS ``private use rules'' from providing open access
transmission service using facilities financed with tax exempt bonds.
We appreciate that the Senate understands that the ability of public
power to make its transmission facilities available to all users
depends on a solution to the private use problem. The Senate bill
reflects that understanding. The private use laws remain an impediment
to this day. While we continue to receive assurances that reforms in
this law are forthcoming, this has not yet occurred. Until such time as
adequate private use is provided, public power will remain restricted
in our ability to provide open access transmission service.
CONCLUSION
I appreciate the opportunity to testify before this Committee and
provide the views of the LPPC on these important issues. Our first
obligation is to our customers and communities. We believe that we must
be able to continue to fulfill our obligation to serve those customers
and communities and provide them with reasonably priced, reliable
electric service. We ask that statutory recognition of this obligation
be provided. I will be happy to answer any questions you have.
The Chairman. Thank you very much.
Mr. Thilly, why don't you go right ahead.
STATEMENT OF ROY THILLY, CHAIRMAN, TRANSMISSION ACCESS POLICY
STUDY GROUP
Mr. Thilly. Thank you, Mr. Chairman, members of the
committee. I will summarize quickly some points from my
testimony.
First, I am the president and CEO of Wisconsin Public
Power, Inc., which is an electric utility owned by 37 Wisconsin
communities. We own gas and coal-fired generation. We serve all
the requirements of those cities.
I am also a member of the board of directors of the
American Transmission Company, which is a for-profit
transmission company that owns most of the facilities in
Wisconsin. Transmission is unbundled in Wisconsin, but rates
are not deregulated.
I appear on behalf of TAPS, which is an association of
utilities like WPPI in 34 States. We are generally small
systems. We have an obligation to serve our customers on a
long-term basis. Our primary concern is getting our generation
to our load. We do not own the transmission that we rely on,
and so we are very concerned that bundled and unbundled service
for load-serving entities be comparable and equal.
We are strong supporters of regional transmission
organizations and FERC's efforts to create competitive
wholesale markets, and we commend the FERC for moving forward
with the SMD. It is a huge undertaking. FERC's objectives are
correct. Getting it right is going to be difficult, and we,
like many others, are concerned with the details, and we are
very committed to working with FERC on those details.
We are also concerned that there are major obstacles the
success of FERC's objectives which are beyond FERC's control,
and that Congress needs to be aware of those. The first is
generation concentration. We start with an industry that is
already very concentrated, and it is becoming more
concentrated.
With the big shake-out that is occurring in the IPP
merchant sector, there are less choices and less competitors
every day in our market. If Congress decides to repeal the
Public Utility Holding Company Act, I am convinced we will see
many more mergers, and therefore the possibility of even
further concentration. The House is proposing to take away
FERC's merger authority. If Congress and FERC are not committed
to limiting concentration, SMD and any competitive wholesale
market will fail.
The second major problem is inadequate infrastructure.
Wholesale competition depends on a robust transmission grid,
and that grid is becoming more and more congested. We have to
get new facilities built for the system to work, and if the
objective is competitive wholesale markets, there should be an
obligation within the RTO's to cause construction of
transmission needed to give all customers reasonable access to
those competitive markets.
We are concerned that the SMD proposal favors a concept
called participant funding. That concept is undefined and
untested today. We understand the concern that rates should
assign costs on the basis of cost causation and benefits
received, but we fear that a strict participant funding system
will delay the construction of new infrastructure, and will
result in more and more congestion. There is no perfect
solution to incentives for construction of transmission or to
rate design. It is a difficult area, and it would be a major
mistake for Congress to mandate a particular funding mechanism
in legislation or rate design. You have already given
sufficient authority to FERC to do it, and through sections
205, 206, and 212(a).
Just for example, provision of funding would undermine the
concept of stand-alone transmission only companies that can
only grow by building and funding their own facilities. It
would create vested interest in maintaining congestion, because
the guy who builds the first line would become the opponent of
the second line that is going to decrease the value of his
congestion rights. Also, there is a big free rider problem.
Most transmission is very difficult to build. It has to built
for multiple purposes with multiple beneficiaries, so we would
urge you not to legislate in that area.
The other key issue for us is the same one that John
Tiencken mentioned, and that is being able to continue to meet
our obligation to serve. My utility bought a share of a large
coal-fired powerplant in 1990, and when we did that, we had to
secure long-term transmission to deliver it to our load. We had
to litigate over that for 3 or 4 years. It was a very bloody
situation. We had to agree to buy that transmission for 35
years, come hell or high water, on a take or pay basis even if
the plant was not operable. We could not have financed that
unit without securing the transmission, and it would not have
been prudent for us to go forward without having secured that
transmission.
To wipe that away at this point would be fundamentally
unfair, so we have also supported the concept of the Kyl
amendment in a limited way to protect existing transmission
rights dedicated to resources that are necessary to meet our
legal obligation to serve, and it is essential that the
protection extend not only to transmission owners, but to those
who secure their transmission by contract because they are not
owners.
My final point is, I agree with the last panel that the SMD
needs more clarification on the ability to secure new
transmission for new resources. We have to build. I have a
wonderful contract with a merchant we entered into last year
which is suitable framing because the plant will not get built.
We have to build new generation, and to do that we have to
secure long-term transmission rights, and the SMD is not clear
on that at all.
Thank you.
[The prepared statement of Mr. Thilly follows:]
Prepared Statement of Roy Thilly, Chairman, Transmission Access
Policy Study Group
I would like to thank Chairman Bingaman and members of the
Committee for the opportunity to testify today on the Standard Market
Design (SMD) Notice of Proposed Rulemaking (NOPR or ``SMD rulemaking'')
issued by the Federal Energy Regulatory Commission (FERC or ``the
Commission'') on July 31, 2002.
I am the Chief Executive Officer of Wisconsin Public Power Inc., a
municipal joint action agency serving 37 municipal members in
Wisconsin. I appear on behalf of the TAPS group, which is an informal
association of transmission-dependent electric utilities located in 34
states. TAPS members own generation and purchase a substantial amount
of power and energy under a variety of wholesale contracts. They serve
their member utilities and retail customers under long-term contracts
and state law obligations to provide reliable service at reasonable
cost. Some TAPS members own transmission, but all members depend
substantially on transmission owned and controlled by others in order
to deliver their power on a reliable and economic basis to their
customers.
Since its inception in 1989, TAPS has been an ardent advocate of
the development of vigorously competitive wholesale electric markets.
We have actively supported the creation of strong, independent regional
transmission organizations (RTOs). TAPS commends the FERC for its
resolve, since the passage of the Energy Power Act of 1992 (EPAct), to
achieve competitively neutral regional transmission systems that
provide open, non-discriminatory access to all users. We particularly
applaud FERC's decision in the SMD rulemaking to eliminate the
pervasive discrimination that exists between bundled and unbundled
transmission service.
A competitively neutral transmission grid is an essential condition
for the creation and maintenance of competitive wholesale markets.
FERC's efforts to move the industry into RTOs have run into many
obstacles. This should surprise no one, since RTOs are specifically
designed to take away the substantial competitive advantages that have
been enjoyed by incumbent, vertically-integrated systems for years.
TAPS further commends the Commission and, in particular, the
leadership of Chairman Pat Wood, for issuing the SMD rulemaking, and
for the Commission's commitment to the clear objectives underlying this
rulemaking. FERC's goal is to once and for all eliminate undue
discrimination in the provision of transmission service for all
purposes, and to achieve vigorously competitive, transparent short-term
energy markets for the benefit of consumers. The Commission's
objectives are admirable and its dedication to consumer interests is
clear. However, we believe that the challenge of achieving these
objectives is monumental and we greatly fear the consequences of
failure.
Like many others, TAPS has significant concerns about the important
details of the SMD proposal. We will be commenting on these concerns to
the Commission. I will highlight several in this testimony and suggest
what Congress should and should not do in fashioning a final energy
bill in light of this important rulemaking.
Recent experience has taught us all how very difficult it will be
to achieve and sustain truly competitive electric markets. We know
today that it is a far more complex undertaking than the economists and
others anticipated five years ago. We also know that the consequences
of error can be disastrous.
Therefore, TAPS will be urging FERC to take the time necessary to
get it right. The SMD proposal is massive. FERC needs to move both
cautiously and deliberately to finalize the rule, taking into account
the legitimate concerns of many parties. Also, it is essential that
FERC not waiver or compromise on fundamental principles such as RTO
independence, rational RTO boundaries, and complete comparability of
service. The ultimate objective must be just and reasonable electric
rates for all wholesale purchasers, not deregulated prices simply for
the sake of less regulation. If the result of restructuring markets is
not lower prices and better service than the traditional cost-of-
service model, restructuring is not worth the effort.
Despite the obvious obstacles and the extremely disheartening and
unethical, if not illegal, behavior of a number of significant market
participants that has become evident in the last year, TAPS continues
to believe that the introduction of more competition into the industry
will benefit consumers. However, we believe that it will take
tremendous regulatory resolve, vigilance, and courage to achieve and
sustain competitive markets. We also caution that major problems will
develop in the implementation of SMD if details are driven by a short-
term market focus, without respecting the fundamental principle that
the ability of load-serving entities, large and small, to meet their
obligations to customers with existing resources and future resources
must be protected.
TAPS members are very concerned that two developments in our
industry will end up defeating FERC's pro-competitive objectives,
despite the best of intentions. It is very important for FERC and
Congress to step back and recognize the realities of our changing
industry.
First, in many places, our nation's transmission infrastructure is
clearly inadequate to support competitive markets. Transmission
construction is extremely difficult. It has been neglected by many
utilities because a weak transmission system protects their local
generation investments. Transmission congestion is increasing, and with
congestion, opportunities to manipulate markets grow exponentially.
Second, concentration in the ownership and control of generation is
increasing. Although the highly concentrated structure of many electric
markets today is to a great degree attributable to the industry's roots
as vertically-integrated franchised monopolists, the recent increase in
concentration is primarily a result of the major shakeout occurring in
the merchant sector. There are fewer and fewer, not more, competitors,
and the beneficiaries of the shakeout will be the largest incumbent
utilities whose market dominance can only grow as new market entrants
fail or sell off assets. This means less sellers, less choice, and less
competition. In addition, if Congress repeals the Public Utility
Holding Company Act, we can expect a deluge of merger proposals that,
if approved, will dramatically increase concentration.
SMD will not benefit consumers if the transmission system becomes
increasingly congested, so that region-wide ``non-pancaked'' access
exists on paper only, while in reality, a customer's only choice is
generation close to its load. SMD also will fail if, as a result of
increasing concentration, very few supplier choices exist in fact. The
combination of increased congestion and concentration is frightening. A
very large market participant with generation located in a variety of
places on a congested regional grid will be able to dispatch its
resources to create congestion, and thereby increase its competitors'
costs and create new opportunities for profits for itself. This is an
invitation for manipulation that is hard to detect, and which can
significantly harm consumers.
For these reasons, FERC's SMD rule must be carefully constructed to
(i) ensure that needed new transmission infrastructure will be built in
a timely fashion to give all customers reasonable access to competitive
regional markets; and (ii) provide for comprehensive market monitoring
and market power mitigation measures that will prevent manipulation of
the market in new and inventive ways and, especially in areas where
effective competitive will not exist any time soon, protect customers
before, not after, they are harmed. Congress must provide FERC with the
tools and a mandate to prevent harmful concentration and the exercise
of market power.
There are, of course, many issues related to the details of the SMD
rulemaking. I would like to highlight three crucial elements that
require clarification or change.
1. Protection of Existing Transmission Rights
The SMD NOPR states that it is FERC's intention to provide market
participants that have firm transmission rights today through ownership
of facilities or by contract, with new, equivalent transmission rights
under SMD. This is essential so that entities like TAPS members can
continue to deliver power from their resources to their loads without a
material change in reliability or cost.
TAPS members have long-term, load-serving obligations. To meet
these obligations, they have made major investments in generation, and
significant power purchase commitments, that never could or would have
been made without simultaneously obtaining transmission rights, or
constructing transmission facilities, to be able to deliver these
resources to their customers. For instance, my utility, WPPI, bought
107 MW share of a large coal-fired plant in Minnesota in 1990. To be
able to make this purchase and finance the unit, we had to secure long-
term transmission rights for the life of the unit through Minnesota to
Wisconsin, across a major transmission constraint. Obtaining those
transmission rights was not easy. It involved years of negotiation and
protracted litigation before FERC, and brought us very close to
antitrust litigation. Ultimately, we had to sign a long-term contract
agreeing to pay for the needed transmission service come hell or high
water ? that is ? even if the service became no longer needed because
our generating unit is no longer operable. The resulting hard fought
transmission rights are very valuable today. They are essential to the
economic viability of our investment and to our continued ability to
provide reliable service to our members and their customers. Our
municipal members' 140,000 retail customers will suffer severely if we
do not receive rights under SMD that are, in fact, equivalent to our
transmission rights today. This same issue exists for every TAPS member
and for many other utilities, private, public and cooperative, that
have invested in generation and made long-term purchase commitments to
reliably serve customers, dependent upon related transmission delivery
rights and investments.
The SMD NOPR states an intention to protect existing transmission
rights. But we are very troubled by the fine print, which in many
places suggests that we may end up with rights that are significantly
less secure, less valuable, and shorter term. I will not go into the
details here, but suffice it to say, while we applaud FERC's stated
principle, we are very concerned about its implementation.
Because meeting our obligations to serve and the related need to
preserve existing transmission rights is such a fundamental consumer
protection and small system survival issue, TAPS supported an amendment
submitted by Senator Kyl of Arizona for consideration on the floor of
the Senate when the energy bill was considered last spring. We have
worked on improving the Kyl language in consultation with
representatives of large public power systems and others. I have
attached to my testimony the language that we believe should be added
to the energy bill on this issue. The TAPS language will benefit the
customers of all utilities with a legal obligation to serve, whether
they are owners of transmission or obtain their transmission by
contract (including service agreements under FERC's open access
tariffs), and whether these utilities are investor-owned, municipally-
owned, or cooperatively-owned.
Existing rights to transmit existing generation commitments to load
must be honored, and would be preserved by the narrowly-tailored
language that TAPS supports. We urge Chairman Bingaman and the other
members of the Energy Conference to support adding the attached
language (Attachment A)* to the final energy bill. TAPS will also be
urging FERC to craft its final SMD rule, and the associated
implementation details, to fully protect these existing transmission
rights.
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* Attachments A and B have been retained in committee files.
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2. Securing Long-Term Transmission Rights for New Resources
A second, very important priority is modifying the SMD proposal to
clearly enable load-serving entities to obtain new, long-term
transmission rights that will allow assured delivery of new resources
to our loads without significant risk of congestion costs. My utility
must build new generation. This is true for many other public power,
cooperative, and investor-owned systems across the country. The simple
fact is that we must meet our loads reliably, which requires long-term
investments, long-term contract commitments, and long-term planning.
Recent experience has shown that we cannot rely on the merchant sector
and short-term markets for needed capacity. Last year, WPPI negotiated
a very attractive long-term contract with a major merchant for rights
to the output of a new power plant for which a certificate to construct
has been granted by the state. Our contract is now suitable for
framing, but not much else. The plant will not be built because the
merchant cannot finance. We must build it ourselves. In order to
finance new generation and make prudent commitments for future supply,
we must be able to obtain long-term transmission rights that match the
new resources.
Unfortunately, the SMD proposal speaks in terms of securing future
rights of one week, one month, one year, or perhaps, longer in
duration. ``Perhaps longer'' is not enough. TAPS members are not
speculators. We cannot build plants with 30-35-year lives and issue
debt that is amortized over 30 years, with only short-term delivery
rights and congestion protection. We are willing to pay our fair share
of the costs of the transmission needed to integrate new resources into
the network and to deliver power from those resources to our loads on a
reliable basis. But we are not willing to rely on outbidding all other
market participants in annual auctions for the transmission rights to
secure delivery of long-term generation investments or power contracts.
The service obligation language attached to this testimony
addresses this problem in part by requiring FERC to exercise its
authority to facilitate planning and expansion of the grid to meet the
reasonable needs of load-serving entities to meet their service
obligations. In addition, TAPS will be urging FERC to modify its SMD
proposal to clearly provide that load-serving entities can designate
new network resources dedicated to serving their loads and can obtain
new, long-term transmission rights that match the life of those
resources.
3. Getting New Transmission Built
If the objectives of SMD are to be realized, it is essential that
new transmission be built in a timely fashion. Congestion must become
the exception, not the rule. We have a lot of catch up to do and it
will not be easy. Transmission is a natural monopoly characterized by
network economies and, in many cases, can be built only with the use of
the public's power of eminent domain. Sitting can be extremely
difficult and delays are common. Sitting authority rests in the states,
rather than in FERC, which creates further difficulties in planning on
a regional basis and meeting regional needs. For these reasons, simply
relying on market signals to drive needed new transmission construction
is not likely to work. Utilities in Wisconsin have been trying to get a
new 345 kV line built to Minnesota for many years. We have only one
major 345 kV line linking us to the west and are in significant
jeopardy when that line goes out of service. The existing line is fully
loaded almost all of the time and interruptions are common. In fact, in
our state, no transmission import capacity is available on a firm basis
from any direction! The proposed new line has been approved, but
multiple lawsuits have been filed to stop construction. If the line is
actually built, the process could easily take more than 10 years from
application to completion.
Unfortunately, FERC's SMD proposal states a strong preference for a
``participant funding'' mechanism for getting new transmission built.
Participant funding is an undefined and untested concept. It apparently
presumes that individual market participants--generators and load-
serving entities--will step up and pay for the construction of new
lines in advance, despite long construction lead times and the changing
nature of grid flows over time, in exchange for the rights to
congestion revenues. There is substantial political pressure on
Congress from at least two very large vertically-integrated systems to
hardwire this untested funding mechanism into law. Perhaps
coincidentally, this proposal would provide existing generation with a
significant competitive advantage over new generation.
TAPS will seek to convince the FERC in the SMD proceeding not to
place primary reliance on participant funding in order to achieve a
robust grid. We strongly urge Congress not to mandate, or create a
preference for, participant funding or to legislate on transmission
pricing or rate design. Transmission funding and pricing present
difficult and complex issues. There are no easy or perfect solutions.
Transmission owners will always plead for more investment incentives,
despite the fact that a dependable 11-12% return on investment year
after year would be very attractive to others. Ratemaking and funding
issues are exactly the sort of matters that should be the
responsibility of an expert regulatory agency that can test new
proposals and modify methodologies over time to meet changed
circumstances.
The Federal Power Act already contains the standards needed to
guide FERC to the right result. Sections 205 and 206 require
transmission rates to be just, reasonable, and not unduly
discriminatory or preferential. To this fundamental pricing principle,
EPAct added Section 212(a) to address the pricing of transmission
service ordered under Section 211. Section 212(a), which the Commission
has read into Sections 205 and 206, requires that transmission charges
``promote the economically efficient transmission and generation of
electricity.'' It also mandates that, ``to the extent practicable,
costs incurred in providing the wholesale transmission services, and
properly allocable to the provision of such services, are recovered
from the applicant for such order and not from a transmitting utility's
existing wholesale, retail, and transmission customers.'' No new
transmission pricing legislation is needed.
TAPS members recognize that state commissions have legitimate
concerns about transmission construction driven by new generation built
in one state to sell output into another state. Obviously, the
customers where the generation is built should not be saddled with high
transmission costs to subsidize long-distance deliveries elsewhere.
This problem can be dealt with effectively by the FERC with a rate
design that assigns costs to both loads and generators based on cost
causation and benefits received. Charges for transmission do not have
to be borne solely by the load where the transmission facilities are
located. TAPS generally supports an innovative rate design proposal
recently made by the proposed TRANSLink Transmission Company in the
Midwest. Under this concept, the costs of high voltage highway
facilities would be shared among all load within a region and not be
shouldered solely by loads in the particular state where a facility is
located, and the costs of lower voltage local transmission facilities
would be shared by loads and generation (including exporting
generation) within the local area. This proposal is currently pending
at FERC.
It is most important that new transmission be built promptly.
Relying on participant funding is likely to lead to significant delays
for a number of reasons. Most transmission lines have multiple purposes
and provide simultaneous benefits to diverse parties, rather than to a
single party or set of parties. In fact, to get approval of a new
transmission line, it is often necessary to demonstrate multiple
benefits and that the proposed line is the least-cost solution to
meeting a variety of needs, including local voltage support,
reliability under various contingencies, as well as improving access to
economic sources of power. The multiple purposes of lines will create
significant free rider problems: parties may be encouraged to wait and
see if someone else will pay for a line, which will end up benefiting
many. In addition, the beneficiaries of a network upgrade will change
over time with changes in load, generation, and grid topography.
Efficiency and cost-effectiveness will often require upgrades to be
sized larger than is required for discreet, immediate needs of the
particular market participant that would fund an upgrade. As a result,
under a participant funding regime, optimal improvements from a
regional, long-term planning perspective may not be made. Finally, we
need to be very careful not to create new incentives to maintain
congestion and oppose new construction. Where a market participant
funds a new line in exchange for rights to associated congestion
revenues, that market participant may very well become an opponent of
the next new line that would lessen congestion and therefore the value
of the congestion revenue rights received by the first participant
funder.
These problems strongly suggest that we need a regional
transmission planning regime that includes a clear obligation on the
part of RTOs to build or cause construction of the transmission
necessary to ensure reliable service for customers and reasonable
access to competitive regional markets. TAPS believes that RTOs should
be obligated to construct, or cause the construction of, new facilities
needed to maintain reliability, accommodate load growth (as utilities
have in the past), enable RTOs to honor existing transmission rights,
and provide all loads with reasonable access to the competitive market.
RTOs also should be required to build, or cause construction of, major
new inter-regional highway facilities and to integrate new generation
into the regional grid. Assignment of costs of this integration should
track cost causation and benefits.
Finally, we would point out that a participant funding model will
totally gut the business model of for-profit, transmission-only
companies. Transcos will not be created and survive if they are not
allowed to grow their business by building and owning needed new
facilities, and including the costs in their rate base, on which they
are entitled to earn a reasonable return. We believe that transmission-
only companies are the best vehicle for getting the grid fixed.
In Wisconsin, we have tested this model. Most of the utilities in
the state have divested their transmission to a new, for-profit,
transmission-only company ? the American Transmission Company (ATC).
Munis and co-ops, as well as investor-owned utilities, have divested
their facilities to this entity. ATC is dedicated to improving our weak
transmission system and adding to its asset base. ATC's construction
budget is more than double the individual transmission construction
budgets of the vertically-integrated systems prior to divestiture. We
expect ATC to more than double its rate base in four years. There is no
competition for capital within ATC between transmission investments and
power plants in Brazil or China and other diversification
opportunities. Participant funding would totally undermine this
important experiment.
Thus, there are many reasons why TAPS believes that Congress should
resist legislating market participant funding of new transmission
facilities. And TAPS is not alone in this effort. We are part of a
broad-based coalition that includes public and private power, rural
electric cooperatives, independent transmission companies, consumer
advocates, and large industrial consumers. The coalition strongly
opposes legislating participant funding of transmission. I have
attached to this testimony recent letters (Attachment B) to the Senate
from this coalition.
Thank you again for inviting me to testify on behalf of TAPS. I
would be pleased to answer any questions you have.
The Chairman. Thank you very much.
Jeff Sterba, we are very pleased to have you as the cleanup
hitter here today. Please give us your views.
STATEMENT OF JEFFRY E. STERBA, CHAIRMAN, PRESIDENT AND CEO, PNM
RESOURCES, INC., ON BEHALF OF THE EDISON ELECTRIC INSTITUTE
Mr. Sterba. Thank you, Chairman Bingaman, and I will also
try to be brief. I want to thank you for calling these hearings
and allowing me to testify. I must admit that I am a bit
humbled and maybe a bit anxious by Senator Domenici's reference
to me as an expert. I will try to live up to that, but probably
will stumble.
I am the chairman, president, and CEO of PNM Resources, and
appear here today on behalf of Edison Electric Institute, which
is an association of shareholder-owned utilities operating in
the country.
First, let me state that we really do believe that the
objectives of the standard market design are sound. We want to
have a robust wholesale competitive market. We know that that
requires price transparency. We know that that also requires
comparable access to the system, which must be administered by
an independent third party, and we know that that cannot happen
without adequate incentives to build the infrastructure,
particularly transmission, as has been mentioned by many of the
players now that appear before you today, so in many ways the
end state that is desired by the SMD is right. The question is
how we get there.
Any time that you try to create significant structural
change in markets, for example, you always have a couple of
options about how you make that happen. You can approach it
from an evolutionary perspective, or you can approach it from a
revolutionary perspective, and I think one of the factors that
needs to be taken into account in determining which approach
one takes is to think about the environment that we are in
today, and this is what really gives me pause.
Today, and I will primarily speak about the Western
marketplace because that is what I am most familiar with, we
have what I would call a destabilized marketplace. It has poor
liquidity, it has significant credit concerns, it has
uncertainty over regulatory rules and political interests that,
frankly, standard market design does not fix.
There are many issues that remain outstanding from the
California kerfuffle, for example, that the SMD does not
address, and so what gives me pause is, the question is, is now
the time for a big bang change to a system that has worked, I
think, very well in one area of the country, but only after
going through a very extensive 75-year process? Hopefully, the
rest of the country can do it in less than 75 years, but the
ability to do it within one, I question, and I also question
whether or not a better approach is to think about this
regionally, that recognizes some of the regional distinctions.
Let me raise, briefly, four concerns and also attempt to
propose what could be solutions for them. The first one we have
touched on. I am one of those, unlike my friend Betsy Moler,
that believes this is too much, too fast, but it is because of
the area of the country that I come from.
There is a skepticism about the applicability of the PJM
model in radial systems as opposed to network systems, in
hydro-dominated systems as opposed to those systems that have
small amounts of hydro. There are substantial differences in
the physical infrastructure of the systems, but there is also
substantial political and process distinctions.
While the Northwest has had regional planning for sometime,
and there has been regional collaboration and cooperation in
other parts of the West, it has certainly not developed in the
same way that it has within PJM, so I think the solution in
this point is to go slower and to consider regional phasing.
The second concern I would raise is that my reading, and it
is very clear to me in listening to the testimony today that
everybody's reading of the SMD does not come to the same
interpretations of what is intended, my reading is that there
are increased risks placed on transmission owners without
compensating opportunities.
Much of this is of a technical nature that should not
consume the Senate's time. It is appropriately addressed in
comments to the FERC in terms of how their pricing methodology
will work, how it may create holes that costs will slip
through, that the transmission owner may ultimately then be
responsible for, and not necessarily be able to be compensated
for, and also issues associated with having the right to build
transmission within your own footprint, so I think the
solutions there are changes to the pricing approach, or at
least clarity.
The third concern is that this obviously dramatically
alters States' roles in transmission pricing, priority of
native load use, reserves, and demand side planning. Any time
one goes through this kind of fundamental change there is a
value of greater communications, also a clarity of
responsibility of these regional groups that are proposed. It
is not clear to me what authority they would have, and as a
person trying to operate a utility, I would have to be
concerned that the imposition of new regional groups that have
no authority effectively does nothing but add additional
bureaucracy and cost to the process, and lack of clarity about
where responsibility really lies.
The last item that I would mention, and I know this is
politically sensitive, but it is one that in the West is very
crucial, is that the SMD does not apply to all transmission
operators. Chairman Wood mentioned that, while it may be
preferable, we believe we can make this Swiss cheese work. I
would have to respectfully disagree.
In the West, over 40 percent of all transmission is owned
by nonjurisdictional utilities. If you exclude the State of
California, over 60 percent is owned by nonjurisdictional
utilities. There is very little transmission that is owned by
public power within the State of California. I do not see how
one can create a system that imposes a set of burdens and
operating practices on 50 percent of an interconnected grid,
but does not impose it on the other 50 percent.
I certainly understand public power's preference for that
not to happen, but I would have to surmise that efforts to put
this kind of a system in place in the Western United States are
doomed to failure unless this issue is closed. This is not baby
Swiss cheese with small holes. These are craters, and there are
participants--let me give you one brief example. I know I am
pushing my time limit, Mr. Chairman.
But we have participated for about 4 years in a
collaborative stakeholder process to create the West Connect
RTO, trying to fulfill the objectives that the FERC had laid
out sometime ago. It is not perfect, but it is the best we
could come up with trying to gain voluntary cooperation from
the 50 percent of the transmission owners that are not FERC-
regulated. It is clear to me that what we have created through
West Connect, which was filed with the FERC in October of last
year--we have yet to receive an order. I understand we will get
one in the next couple of weeks--but it is clear to me that it
does not comply with the provisions or the intentions of the
standard market design.
But at the same time, there are still entities that own
more transmission than my company does who would not subscribe
to West Connect because they did not have to, so I find it very
difficult to believe that we will be able to make progress on
implementing SMD on an interconnected basis without addressing
this issue of jurisdictional transmission.
And I believe the timing, relative to the energy debate
that is hopefully on track, I know it is a very tough issue,
but I do believe it has to be addressed. There are many other
issues that also need to be addressed, but I am very concerned
that we could face a period of debilitating litigation if the
SMD, as currently configured, goes forward on the time line
that is currently proposed.
I am very appreciative of Chairman Wood's slipping of the
schedule for comments, and for allowing reply comments, but I
think it is going to take more than that.
Thank you.
[The prepared statement of Mr. Sterba follows:]
Prepared Statement of Jeffry E. Sterba, Chairman, President and CEO,
PNM Resources Inc., on Behalf of the Edison Electric Institute
Good morning, Chairman Bingaman and Members of the Committee. I am
Jeffry E. Sterba, Chairman, President and Chief Executive Officer of
PNM Resources, Inc. Public Service Company of New Mexico, which is the
principal subsidiary of PNM Resources, Inc., is a public utility
primarily engaged in the generation, transmission, distribution, sale
and trading of electricity, and in the transmission, distribution and
sale of natural gas within the State of New Mexico.
I am appearing before the Committee today on behalf of the Edison
Electric Institute (EEI). EEI is the association of U.S. shareholder-
owned electric utilities and affiliates and associates worldwide. I
would like to commend Chairman Bingaman and all the Members of this
Committee for your attention to important electricity issues. I am
pleased to have the opportunity to present EEI's views on the Federal
Energy Regulatory Commission's (FERC's) Notice of Proposed Rulemaking
on Standard Electricity Market Design, known as the ``SMD NOPR.'' I
would like to discuss our initial views on the NOPR and identify those
elements of the NOPR that affect the energy legislation pending before
Congress.
1. OVERVIEW
The goal of market-oriented restructuring of the electric industry
is to provide benefits to consumers. This goal requires clear market
rules and a favorable investment climate to ensure the development of
the strong energy infrastructure, particularly transmission, needed to
support robustly competitive wholesale electricity markets. We must
work together to make competitive markets work.
We commend FERC for moving forward with the development of a
standard market design (SMD). The objective of a standard market design
is a sound one. EEI supports the Commission's goal of developing a
standard market design that sets the rules of the road for all market
participants. Standardization of the rules governing power markets on a
regional basis will provide price transparency and comparable open
access to transmission, while facilitating the development of robust
regional wholesale electricity markets. EEI also supports the
Commission's move to standardized day-ahead and real-time regional
electricity markets with financial transmission rights and locational
marginal pricing (LMP) and the NOPR's approach to demand response, as
long as regional differences and state responsibilities over issues
such as planning and resource adequacy are respected. EEI wants to help
make standard market design work.
We believe it is important to move to this goal at a firm, steady
pace. But we are concerned with some aspects of the FERC NOPR and
believe that in some respects it will not work, in practice, as FERC
intends. California's electricity experience clearly demonstrated that
inflexible, rapid and radical change can have unintended consequences,
harming customers and markets. Obviously, none of us want to repeat
that experience on a broader, national scale. To accomplish the goals
we share, EEI is committed to working constructively with FERC and the
states to address these concerns.
Thus, while we support the Commission's approach to the
standardization of real-time and hourly markets, its adoption of
locational marginal pricing and its approach to demand response, we do
have substantial concerns about some other elements of the SMD NOPR.
First, we are concerned that every region cannot practicably accomplish
all that the SMD NOPR proposes within FERC's extremely ambitious
timeframes. Second, the SMD NOPR will undermine our nation's urgent
need for new transmission infrastructure. Third, it affects important
state interests, but appears to provide an insufficient framework to
foster essential state cooperation needed for regional institutions to
work effectively. For example, it raises for the first time important
issues on how to address longer-term generation adequacy needs without
developing appropriate regional consensus. Finally, it does not apply
to government and cooperatively owned utilities, which operate one-
fourth of the nation's transmission and generation. Years of litigation
over these issues may delay needed investment and improvements in our
energy infrastructure.
Constructive solutions are readily available. Greater cooperation
with the states and a stronger role for transmission owners will
accomplish the goals we share with FERC. We believe FERC should focus
first on getting day-ahead and real-time regional energy markets up and
running. It should clarify its transmission pricing and transition
rules, eliminate the barriers to transmission enhancements and take
affirmative measures to encourage needed transmission construction.
Since planning and resource adequacy issues have traditionally been
addressed at the state level, not at FERC, states must have a greater
opportunity and more time to participate in fashioning regional
approaches. In addition, government and cooperatively owned utilities
must be required to participate in a standard market design, so that
the goals of a standard market design are achieved, although we
recognize that legitimate transition issues should be addressed.
Congress can help by affirming FERC jurisdiction over all utilities
and, where existing approaches for siting critical transmission do not
work, providing FERC backstop authority for siting of transmission. I
address each of these issues in detail below.
2. EEI'S PRINCIPLES FOR STANDARD MARKET DESIGN
Prior to the issuance of the SMD NOPR, EEI adopted principles on
standard market design to serve as the benchmark against which we would
evaluate the then upcoming NOPR and guide EEI's response to it. A copy
of our principles is attached to my written testimony.*
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* Retained in committee files.
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We believe the goal of standard market design is to establish an
efficient and robustly competitive wholesale electricity marketplace
for the benefit of consumers. This can be accomplished through the
development of consistent market mechanisms and efficient price signals
to induce efficient investment in productive transmission facilities
and demand response activities, combined with the assurance of fair and
open access to the transmission system. Important elements include:
The continued development of regional transmission
organizations (RTOs);
Transmission pricing that promotes access to all potential
users, reliability and adequate infrastructure development;
A consistent set of standards to constrain market power
abuse;
A planning process that has appropriate support and
cooperation from state public utility commissions, identifies
needed upgrades and expansions of the transmission system and
affords transmission owners responsible for planning within
their footprint the first opportunity to build;
Acknowledgement of the role of state utility commissions and
regional reliability authorities in ensuring long-term supply
adequacy and RTO coordination with these entities in
implementing a market approach; and
Demand response programs that coordinate wholesale market
activities with state and utility programs.
FERC's SMD proposal includes much that is consistent with our
principles and that we support. EEI supports the overall framework for
competitive markets set forth in the NOPR, including the use of day-
ahead and real-time energy markets and the use of a financial, rather
than a physical, priority means to mitigate transmission congestion. We
also commend FERC's market-based approach to demand response. This
approach has been used in markets in PJM and the Northeast, where
states and market participants have worked cooperatively over decades.
However, the proposed SMD rule will not meet our nation's current
urgent need for transmission infrastructure enhancement and energy
market stability. Let me elaborate.
3. SMD NOPR WILL DETER NEEDED TRANSMISSION EXPANSION
As testimony before this Committee in the past has demonstrated,
investment in transmission has lagged, due in large part to regulatory
uncertainty, insufficient rates of return and inability to site
transmission. The current transmission system is inadequate to support
the vision of robust competitive markets that both the Commission and
EEI support. Certain parts of the country are desperately in need of
new transmission to assure that electricity can be delivered to
customers when and where they need it.
Substantial new investment in transmission is needed to meet the
needs of customers and the marketplace. Investment in transmission has
been declining at an average rate of about $100 million a year during
the past two decades. Transmission investments in 1999 were less than
half of what they had been in 1979. Billions of dollars for investment
are needed. A recent study shows that maintaining transmission capacity
at its current level might require an investment of about $56 billion
during the current decade. Unless these trends are changed, the SMD
proposal puts continued access to transmission to serve native load
customers at risk in congested areas.
EEI is concerned that the SMD proposal would further dampen both
the incentive and the ability to construct new transmission in many
important respects.
First, the SMD proposal radically changes the role of transmission
owner in several critical respects. It requires a stakeholder-selected
board to oversee all regional transmission operations, even for an
entity that is totally independent of electricity buyers and sellers.
Transmission investors would have no control over the management of
their assets. Thus, it essentially precludes the option to form a for-
profit transmission company.
It also drastically diminishes the role of the transmission owner
in building the transmission system. Transmission owners and
independent transmission companies should have the first opportunity to
expand or improve their systems. Others should have the opportunity to
build if system owners do not. While all options for building
transmission--including current transmission owners, independent
transmission companies, and merchant transmission--must be preserved,
the NOPR would make transmission owners, which usually have a state
statutory obligation to serve, own existing facilities, rights-of-way
and have eminent domain authority, the builders of last resort. We
believe this is a recipe for gridlock.
If transmission capacity is not enhanced within four years, assured
access of native load customers to transmission would be reduced. This
occurs because the SMD proposal would effectively ``grandfather''
native load customers by assigning congestion revenue rights to native
load for just four years. After that time, native load would have to
compete with others for congestion rights. Additionally, the SMD NOPR
removes the ability of the transmission owners to set aside
transmission for the forecasted growth of their native load.
Second, FERC's pricing, liability and operational proposals impose
many new risks without comparable incentives. The proposed transmission
tariff fails to provide the types of liability limitations that the
states have traditionally applied. Instead, the tariff imposes
significant new outage liabilities when compared to most state tariffs.
Since FERC has asserted jurisdiction over all transmission, it needs to
provide the types of liability limitations that states have applied to
transmission service previously under their jurisdiction. Such
liability protection is necessary to ensure that transmission providers
are able to procure insurance, which is essential to procuring capital
for investment. FERC's proposed pricing rules also do not compensate
for these risks or provide incentives for new investment.
Third, the transmission planning process, which currently involves
the states and requires state approval before new facilities can be
sited, would very quickly be transferred to new and untested regional
entities. We are concerned that without greater state acceptance and
participation, such regional efforts will not facilitate the important
energy infrastructure improvements we need in the next few years.
Instead, we would become embroiled in litigation or siting disapprovals
or both. And the process FERC envisions looks unnecessarily cumbersome,
duplicating, rather than building upon, existing efforts. The role of
the states in regional planning needs to be enhanced.
We fear all these changes would make it extremely difficult to
attract investment in new transmission. FERC can fix many of these
problems. FERC should:
Articulate clear cost causation principles that impose the
responsibility for the cost of new facilities on those who
cause such costs,
Apply the same liability provisions to transmission service
as the states,
Remove unnecessary restrictions (such as the governance
rules) on transmission owners which are independent of market
participants,
Allow transmission owners first option to enhance their own
facilities, and
Work cooperatively with the states to develop effective
regional planning and siting solutions that allow flexibility
for regional differences.
As stated elsewhere in my testimony, Congress can help by granting
FERC backstop siting authority where state processes do not work.
4. SMD NOPR PREEMPTS STATE INVOLVEMENT WHEN STATE COOPERATION AND
COORDINATION IS REQUIRED
If regional markets are to work efficiently, there must be greater
coordination with the states, which have important responsibilities
regarding distribution, retail electric service, resource adequacy,
planning and siting. Getting ``buy-in'' by the states is, as a
practical matter, critical to the success of a standard market design.
If state concerns are not accommodated, they may effectively block
needed actions, since states retain the authority to issue permits to
site new generating and transmission facilities. Moreover, lengthy
litigation may follow, creating further regulatory uncertainty and
slowing the process even more.
Under the SMD NOPR, FERC ``federalizes'' the transmission component
of bundled retail sales, transmission planning and resource adequacy.
States currently determine the transmission component of rates to
retail consumers and approve the prudence of electricity purchases in
closed states. All states approve transmission and generation plans.
The SMD NOPR would change these aspects of the current federal-state
regulatory regime.
Foremost among these changes is FERC's assertion of jurisdiction
over what was previously state-regulated retail transmission. This
proposal will trigger significant, practical changes in prices and cost
recovery among customers in different states, but important transition
details are not clear in the NOPR. The aggressive schedule set out in
the NOPR does not accommodate the time needed to make necessary changes
to state laws or regulations, implement changes to rate structures, or
allow sufficient time to develop the necessary ``comfort zone'' that is
needed before such a dramatic restructuring of the way in which
electric utilities are regulated can be implemented.
The SMD NOPR also transfers state authority over planning and
resource adequacy to untested regional organizations, and does so at
the same time those regional organizations will be busy trying to set
up real-time and day-ahead markets. EEI agrees that regional approaches
to these matters make sense. But, since FERC has no explicit statutory
authority over planning or resource adequacy, the regional approach
requires state involvement, acceptance and cooperation, not federal
mandates.
FERC must explicitly recognize a decisional role for states and
regions in planning and resource adequacy matters. States are active
participants in the Northeast areas where regional markets work best,
and we would like to see other states actively participating in
developing regional markets elsewhere. However, a FERC proposal simply
allowing states to advise an Independent Transmission Provider
(``ITP'') controlled by a stakeholder-selected board will not suffice
to convince states that have traditionally been reluctant to
participate in regional processes.
Finally, the SMD NOPR appears to allow ``bypass'' of state
laws and decisions that provide for the recovery of public
benefit charges, including utility transition costs. In Order
No. 888, FERC issued a simple rule to eliminate this by-pass
problem, but it has rejected this approach in the SMD NOPR. We
do not understand the basis for this. Providing for the
continuation of state public purpose charges will help assure
state cooperation.
EEI and its members have been working hard to help coordinate the
state and federal roles in regional activities by working with FERC,
NARUC, the Western Governors Association, the National Governors
Association and its Center for Best Practices and the Western
Interstate Energy Board and will continue our efforts on this critical
task.
5. REGIONAL DIFFERENCES ALSO MUST BE RECOGNIZED
FERC's standardization effort needs greater flexibility to adjust
to regional differences. For example, while we support the locational
marginal pricing and market design features of the PJM ISO that the SMD
NOPR adopts, they cannot be quickly or easily transplanted to every
region as the NOPR contemplates. The West, in particular, has a very
different resource mix, large reliance on hydropower and a different
transmission configuration.
PJM has been in existence for over 60 years, and its market system
was the first to develop after Order No. 888 was issued in 1996. While
major elements of its market structure may be the ultimate goal toward
which other regions of the country should work, the regulatory,
technical and commercial infrastructure to support these markets does
not yet exist in many regions. Even participants in the PJM market
point out features in the SMD NOPR that should be improved. While the
Commission has stated that it will be somewhat flexible in setting
deadlines for various regions to meet the SMD requirements, its
timeframes are extremely ambitious and simply not realistic.
6. PLANNING AND RESOURCE ADEQUACY ISSUES REQUIRE MORE REGIONAL
FLEXIBILITY AND STATE INPUT
One of the SMD proposals that raises some of our greatest concerns
is the resource adequacy requirement. Effectively, the SMD requires the
Independent Transmission Provider to establish minimum reserve margins
(a margin of spare electricity capacity in case electricity demand
exceeds projections or existing generating capacity unexpectedly fails)
and longer-term electricity purchase obligations on the suppliers
serving retail customers within its region. While a mechanism is needed
to assure that there is adequate capacity to serve customers, we
believe that important issues need to be addressed on the resource
adequacy requirement in the NOPR. First, the NOPR imposes an
unrealistic time frame of July 2003 on getting this process up and
running. The Independent Transmission Provider will have enough to do
to get LMP and day-ahead and real-time markets in place quickly.
Second, the proposal needs greater regional flexibility to allow for
thoughtful consideration of regional differences.
Third, since many states have statutory and regulatory planning and
resource adequacy requirements (resulting from their enforcement of the
``duty to serve''), state cooperation is essential. The SMD NOPR
requires the ITP to develop a plan for all states in a region. States
will have an advisory role (through the Regional State Advisory
Committee or ``RSAC'') but no longer would be the key decision-makers
on adequacy and the implementation of resource plans. The SMD NOPR also
relies upon an untested and yet to be defined market-based approach for
investment, which appears to deny a transmission owner the first option
to enhance its own facilities. This radical departure from current
practice could jeopardize state issuance of needed permits and support
for cost recovery. States must be in accord with transmission and
resource adequacy plans or utilities will face resistance on permitting
and siting needed infrastructure and on cost recovery.
Transmission planning requires state buy-in because states control
siting decisions. While the NOPR correctly recognizes the importance of
moving to a regional approach quickly, the simple fact is that, under
current law, it will not work without state cooperation. States have
been slow to include regional benefits as a criterion for transmission
siting approval. Congress can break this impasse by providing FERC with
backstop siting authority for transmission in those instances where
existing state approval processes for transmission expansion do not
work. This approach would give states a reasonable opportunity to site
needed transmission facilities, but would permit FERC to authorize such
siting if a state does not act or fails to act within a reasonable
time. Such federal authority is particularly justified now that FERC
asserts federal jurisdiction over all transmission and the emphasis on
broad regional electricity markets and regional grid operations. This
limited authority is still not as far reaching as FERC's authority to
site natural gas pipelines. We urge Congress to include federal
backstop siting authority in the comprehensive energy legislation now
in conference.
7. SMD MUST APPLY TO GOVERNMENT AND COOPERATIVELY OWNED UTILITIES
Government-owned utilities and electric cooperatives should be
subject to the same regulations as jurisdictional utilities if
competitive markets are to work efficiently. Any standard market design
would unavoidably exacerbate the regulatory imbalance between
government-owned and cooperative utilities (``non-jurisdictional
utilities'') and shareholder-owned utilities subject to FERC's
jurisdiction, if FERC does not have statutory authority to treat them
the same way. While FERC-jurisdictional utilities must comply with all
aspects of the SMD NOPR, including turning over control of their
transmission systems to an independent transmission provider, non-
jurisdictional utilities need provide only the limited open access
required under the reciprocity provisions of FERC Order 888 issued in
1996. As Members of this Committee are well aware, in some areas of the
country, non-jurisdictional utilities own the major portion of the
transmission grid. This is particularly true in the Pacific Northwest.
In the U.S. portion of the entire western interconnection, non-
jurisdictional utilities own 41 percent of the transmission grid.
The SMD NOPR does little to cover these entities, even as a
requirement to provide ``reciprocal'' service. As a result, we believe
they are likely to avoid joining regional organizations, through which
they would likely become subject to SMD to a greater, if not, full
extent. Indeed, it seems that the approach taken in the NOPR is an
incentive for non-jurisdictional utilities not to join an RTO, a result
that is contrary to the Commission's goals. We believe that this
proposal allows discrimination against jurisdictional utilities and
gives government-owned utilities and cooperative utilities a
competitive advantage. We also question how the resource adequacy
requirement, among other provisions in the NOPR, can be implemented in
regions of the country where a substantial portion of the load-serving
entities are not subject to the Commission's jurisdiction.
Only Congress can ultimately remedy the inequitable differences in
regulation between jurisdictional and non-jurisdictional utilities that
are highlighted in the SMD proposal. EEI urges Congress to correct this
problem by subjecting government-owned utilities and electric
cooperatives to FERC regulation to the same extent as shareholder-owned
utilities. While EEI commends the Senate for including a so-called
``FERC-lite'' provision in its version of H.R. 4, even that proposal is
undermined by large loopholes that would allow all but the very largest
non-jurisdictional utilities to escape even open-access requirements.
8. CONCLUSION
While we agree with the objective of transparent, robust,
competitive electricity markets, EEI believes that a more evolutionary
approach should be taken in the SMD NOPR. This is particularly
important in view of the current uncertainty in the capital markets
that provide the needed investment for our industry.
We urge the Commission to focus first on establishing regional day-
ahead and real-time energy markets and on encouraging needed
transmission improvements through pricing and other reforms, including
encouragement of independent transmission companies.
We urge Congress to bring government-owned utilities and electric
cooperatives under FERC jurisdiction and to enact FERC backstop
transmission siting authority. This will make it much easier to address
the remaining resource adequacy and planning issues raised in the NOPR
in cooperation with the states.
Thank you very much.
The Chairman. Thank you very much. Let me just ask a very
few questions, and then we will end the hearing here.
Let me ask Betsy Moler, obviously, as I understood your
testimony at any rate, your view is that the differences that
Mr. Sterba just described between the configuration of the
different systems in different parts of the country, some areas
in the Northwest, hydropower-dominated systems, this radial
systems versus network systems, your view is that a standard
market design along the lines of what is being proposed here
does work in all those different contexts, as I understand it.
Ms. Moler. I believe that standard market design can be
made to work. I agree with several of the comments that have
been made today that there are many nitty gritty details that
need to be addressed before you get to the final rule stage.
One of them may be dispatch of hydro where it is the
predominant resource in the region. We dispatched--Exelon owns
hydro in Pennsylvania. It is dispatched under the PJM rules. It
is not, however, the predominant resource, and we recognize
that, but as Chairman Wood said this morning, this is a
proposal.
It is the nature of the notice and comment rulemaking
process that you work through issues of this sort before you
issue a final binding rule, and perhaps I have more confidence
than others at this table and who have testified today that the
commission will address those nitty gritty issues before they
get to the final rule stage. The process is in place for them
to do that.
The one question I have, though, is on the
nonjurisdictional entities.
The Chairman. Do any of the rest of you want to make
additional comments on that?
Let me ask about an issue that Mr. Thilly raised in his
testimony, that is, this whole issue of generation
concentration. How do we limit the concentration? As I
understood, your concern there is that if we go forward with a
repeal of PUHCA you will find more and more of this generation
concentrated in very few hands. What is the solution to that in
your view? Is it not to repeal PUHCA, or is it to go forward
and be sure that FERC takes responsibility for dealing with
undue concentration in a very real way, or what is the
solution?
Mr. Thilly. I think it is essential, if you repeal PUHCA,
that the Senate stand firm on the merger provisions that you
adopted enhancing FERC's merger authority in the Senate bill
that is in conference. If that does not stand, then I would say
you should not repeal PUHCA.
In our area, the merchant plants were all canceled.
Utilities are building. Concentration is increasing without
mergers, and I am absolutely certain that we will see more
merger applications if PUHCA is repealed, so there has to be a
strong standard at FERC. There is an inherent conflict between
concentration and seeking a competitive market with many
sellers and many buyers, and so I guess my--I think what the
Senate did was excellent, and I certainly hope it stands.
The Chairman. Mr. Sterba.
Mr. Sterba. Mr. Chairman, I guess I would have a slightly
different, or maybe a significantly different point of view.
Concentration is an issue that is addressed in the merger of
any two companies by other bodies of the Federal Government.
There is a standard process of merger review in which it goes
through a number of steps, and concentration, and the old
Herfendahl Index, is one of the fundamental features of that
review. I am not convinced that layering on additional review
is necessary, because of the already engaged process for merger
review.
The Chairman. Anybody else? Betsy.
Ms. Moler. I believe that if you look at the actual
experience of mergers and assets, exchanges, swaps, sales,
whatever, in the last 5 years that they have deconcentrated
generation rather than increased concentration. Most of the
sales have been to new entities, utilities have sold generating
capacity, and I believe that the Senate's merger review
provision is really a solution in search of a problem.
I also believe, however, that in addition, under standard
market design, where you have bid-based markets, and a utility
having turned over its transmission assets to the control of an
ITP, you will not have the ability to manipulate the markets in
favor of your generation, which is currently the case today.
The Chairman. Mr. Tiencken, did you have a comment?
Mr. Tiencken. Mr. Chairman, we, of course, favor the
retention of PUHCA unless there is a safety net which is
adequate to protect consumers, and we think that the presence
of the review that is currently in the Senate bill would be the
right answer for that.
The Chairman. I see that my colleague, Senator Carper, has
just arrived here. We have just concluded about 3 hours of
excellent, in-depth testimony, Senator Carper. Did you have any
question?
[Laughter.]
Senator Carper. I sure do. Can we just go through this one
more time?
[Laughter.]
Senator Carper. May we will have lunch together and I can
come up to speed, but thank you. I appreciate you being here.
Thank you.
The Chairman. Let me thank all of these witnesses as well.
I think this has been good testimony. Let me particularly thank
Chairman Wood for not only his testimony, which I did thank him
for before, but also remaining to hear the other witnesses. I
do appreciate that, and I am sure the witnesses themselves did.
Thank you all very much.
[Whereupon, at 12:26 p.m., the hearing was adjourned.]
APPENDIXES
----------
Appendix I
Responses to Additional Questions
----------
Federal Energy Regulatory Commission,
Washington, DC, October 23, 2002.
Hon. Jeff Bingaman,
Chairman, Committee on Energy and Natural Resources U.S. Senate,
Washington, DC.
Dear Mr. Chairman: Thank you for your letter of September 23, 2002,
enclosing questions for the record of your Committee's September 17
hearing on the Federal Energy Regulatory Commission's Standard Market
Design Proposed Rule.
I have enclosed my responses to the questions from Senators Gordon
Smith, Jon Kyl, Mary Landrieu, Byron Dorgan, Conrad Burns and Bob
Graham.
If you need additional information, please do not hesitate to let
me know.
Best regards,
Pat Wood, III,
Chairman.
[Enclosure].
Chairman Wood's Responses to Questions Submitted by Senator Smith
Question 1. Your rule's underlying assumption is that those who
``value transmission the most'' will get it. That's a radical departure
from the open access, common carrier type of transmission system we've
had since Order 888. How does this mesh with universal access to
electric service and a utility obligation to serve?
Answer. Our proposal is consistent with a utility obligation to
serve and universal access. Load-serving entities with an obligation to
serve would continue to receive transmission service necessary to meet
their load. All customers who pay an access charge to use the grid
would have full access to the grid. Existing contracts would not be
abrogated.
While protecting these existing arrangements, Standard Market
Design provides new opportunities for existing rights holders and those
seeking new service. Existing users can turn over usage to others, and
receive the benefits of this more efficient allocation. SMD also
provides incentives for transmission users to more efficiently plan
their future uses, since the strains on the grid are being exacerbated
by inefficient siting decisions. Finally, SMD provides a new option to
any customer to ``buy through'' congested interfaces such that they can
physically deliver power if they are willing to pay the price (and
there are customers who voluntarily give up their usage in return for
this price).
Question 2. What would be wrong with the regional approach offered
by BPA in its comments to FERC on the scope of the environmental work
associated with the SMD NOPR?
Answer. Bonneville Power Administration suggests implementing the
rulemaking ``in only those regions where there are market problems.''
All regions will benefit from more efficient and competitive wholesale
markets. All regions including the Northwest need a framework to meet
the future demands from these markets because hydro supply will remain
fixed as load grows. We recognize that the specific form of the
wholesale market structure and design will vary by region and we
believe the RTO West order provides a solid foundation for the
Northwest and the Western Interconnection. It is critical that market
systems within the West are compatible with each other.
The need for such compatibility is clear from experience in the
West itself. A drought in the Northwest inevitably affects California
and the Southwest. A market failure in California could not be
contained within the state but had devastating effects throughout the
West. Different bid caps in neighboring areas have created inefficient
arbitrage opportunities in the East as well as West. Efforts to resolve
inefficiency and opportunities for manipulation due to ``seams'' have
stalled due to incompatible designs within an interconnect. The West
needs compatible market structures throughout the region to prevent
such problems in the future. The Commission seeks to ensure that market
structures are compatible, without changing the ability to accommodate
statutory and Treaty obligations of Northwestern utilities and operate
the particular resource mix and transmission topology of the region.
Question 3. What happens to utilities when they do not get the
Congestion Revenue Rights (CRR) needed to serve their load? Let's say
they were outbid by a deep-pocketed player. What are the short-term,
and long-tern results? What happens once these CRRs are no longer
available?
Answer. The proposed rule envisions that such utilities would keep
their rights if they choose not to turn them over. Their physical and
financial position would be unchanged. The proposed rule suggests a
four-year allocation of CRRs to all load-serving entities based on
their current uses of the system to ensure that existing load is
shielded from congestion costs, and suggests that regions can propose
to extend the allocation for a longer time period. Moreover, if there
were an auction after four years, the particular mechanism that was
proposed was intended to allow entities to hold on to their rights and
avoid financial harm. The proposed mechanism was based on a best
practice identified in FERC's Northeast RTO mediation hearings.
However, this particular piece of the SMD proposal has not been
supported by a broad consensus of parties in other regions. As a result
of the significant amount of concerns we have heard on this feature,
the Commission will explore the issue further beginning with a
technical conference on December 3, 2002. The Commission's policy
through gas industry restructuring, Order No. 888 and Order No. 2000,
was to preserve existing contracts but to create better opportunities
for open access transportation going forward.
Importantly, this issue is being addressed in RTO orders. The
SeTrans, West Connect, and RTO West orders issued over the last month
provide means through which contracts can be voluntarily converted to
the new services. We expect that RTO orders will be the primary forum
for contract allocation and conversion issues.
More generally, the Commission has made clear that its rulings on
these and other issues in pending RTO applications will not be
superseded by the SMD final rule, except for issues on which the
Commission's RTO orders specifically indicated differently.
Specifically, in this month's orders on West Connect and SeTrans, the
Commission stated:
. . . it is not this Commission's intent to overturn, in the
final SMD rule, decisions that are made in this docket. In
other words, unless the Commission has specifically indicated
in this order that an element of the RTO proposal is
inconsistent with the SMD proposal or needs further work in
light of the SMD proposal, we do not intend, in the final SMD
rule, to revisit prior approvals or acceptances of RTO
provisions because of possible inconsistencies with the details
of the final rule. This Commission intends to take all
appropriate steps at the final rule stage of the SMD rulemaking
to ensure that, to the extent we have already approved or
conditionally approved RTO elements, these approvals would
remain intact.
Question 4. Your Resource Adequacy Requirement requires every load
serving entity in the U.S. to show it can meet its peak loads plus 12%
on a planning basis. Won't that lead to a surplus of generation and
destroy the spot markets?
Answer. No electrical system can meet its day-to-day load with
total generation that just equals expected peak load. All systems need
a ``planning'' reserve that accounts for forced plant outages, longer
term normal plant maintenance outages, and load forecast error.
Traditionally, this responsibility was met by integrated utilities
under state oversight. Because most utilities draw upon regional
markets, a reserve requirement for one state would be difficult to
enforce because out-of-state entities with fewer reserves could ``lean
on'' the in-state company's reserves. Our proposed rule emphasized the
role of the states in this area by providing a placeholder for them to
choose a state standard or, preferably, work on a regional standard.
After the experience of California, we do not believe we can let
planning reserves fall below a minimum level, however, because we have
an obligation to ensure reliable transmission service and wholesale
power sales at just and reasonable rates.
Planning reserves strengthen rather than destroy spot markets.
Liquid and deep spot markets coexist with primary reliance on long-term
contracts. Most customers will wind up with power to buy or sell on any
given day even when they contract in advance for their expected needs,
due to supply and demand variability.
Question 5. FERC has just given approval to RTO West, subject to
certain changes. If RTO West's provisions are inconsistent with the
final rule-making on SMD, which one will prevail? Would RTO West be
required to modify key provisions, such as protecting existing long-
term transmission contracts?
Answer. The SMD proposed rule suggested that many areas could be
worked out on a regional basis. As you say, the Commission approved RTO
West's proposal for long term transmission contracts. There is no need
to abrogate existing long-term contracts to achieve region-wide
compatibility, standardized service, and increased opportunities for
efficiency that we seek in SMD. We do not expect the RTO West
provisions and the final rule on SMD to be inconsistent. In its
September 18, 2002 declaratory order on RTO West, the Commission said
it viewed the RTO West proposal as both informing and being informed by
the proposed SMD Rule. In addition to meeting the requirements of Order
No. 2000, the RTO West proposal had many elements that could serve as a
basic framework for a standard market design for the West. The order
recognized the need for regional variation to reflect the unique
characteristics of the region. We will hold technical conferences and
further stakeholder discussions to further understand those differences
and to foster-development of an RTO West proposal that reflects both
Western needs and a standard market design.
More generally, the Commission has made clear that its rulings on
these and other issues in pending RTO applications will not be
superseded by the SMD final rule, except for issues on which the
Commission's RTO orders specifically indicated differently.
Specifically, in this month's orders on West Connect and SeTrans, the
Commission stated:
. . . it is not this Commission's intent to overturn, in the
final SMD rule, decisions that are made in this docket. In
other words, unless the Commission has specifically indicated
in this order that an element of the RTO proposal is
inconsistent with the SMD proposal or needs further work in
light of the SMD proposal, we do not intend, in the final SMD
rule, to revisit prior approvals or acceptances of RTO
provisions because of possible inconsistencies with the details
of the final rule. This Commission intends to take all
appropriate steps at the final rule stage of the SMD rulemaking
to ensure that, to the extent we have already approved or
conditionally approved RTO elements, these approvals would
remain intact.
I intend to clarify on rehearing that the same approach would apply
to the recent RTO West order.
Question 6. Is this the last major rule-making on transmission we
are going to see from FERC? You claim that no one is investing in
transmission. Isn't that really the result of regulatory uncertainty
since the passage of the 1992 Energy Policy Act? Isn't this proposed
rule-making just going to extend this uncertainty?
Answer. The uncertainty in the electric industry has lasted for
over a decade, as the wholesale market has gradually opened in
different ways in different regions, beginning with the passage of the
Energy Policy Act of 1992. I agree that regulatory uncertainty has
contributed to the lack of needed infrastructure investment. That is
one reason we proposed the SMD framework to seek consensus on the
processes and rewards for investment going forward. The framework
allows for alternative forms of state regulation but provides a
framework that is compatible across different states in a region so
that users of the regional grid do not continue to suffer from
inefficiency, market manipulation, and a lack of investment. Our goal
is to use SMD and the companion RTO cases to end the decade of
uncertainty by establishing clear, consistent, comprehensive long-term
rules and practices for efficient, competitive wholesale markets.
The rules we are proposing complement the other two parts of the
wholesale market restructuring trilogy from the Commission beginning
with Order No. 888 and Order No. 2000. These two rules along with the
proposed Standard Market Design rule would provide a complete set of
rules and institutions that meet today's needs while providing
sufficient flexibility to evolve to meet changing circumstances.
Question 7. You say you have learned much about hydro-power.
However, I am hearing from my constituents that many of their concerns
about this rule's failure to recognize some of the unique features of a
hydro-based system were known to FERC's staff before the rule came out,
and that the rule just dismisses these concerns. How can I assure my
constituents that these concerns will be address in the final rule?
Answer. The RTO West order approved what stakeholders in the
Northwest worked out to accommodate any special features of the hydro-
based system. The three RTO orders in the Western Interconnection have
encouraged parties to develop compatible market designs to allow for
seamless trading and eliminate opportunities for manipulation of the
seams. In the SMD NOPR the Commission does not intend that anything in
the proposal, or in a Locational Marginal Pricing market design, would
require the Western hydropower system to operate any differently than
it does today. We have recently announced further workshops and
meetings regarding issues such as this that are important to the West.
We understand that it is difficult to design and allocate transmission
rights that accommodate hydro scheduling issues, especially when the
system is over-subscribed (with or without SMD), and we addressed
processes for resolving these issues on a regional basis in both the
NOPR and the RTO West order. On October 2, 2002, we issued a notice
extending the time for NOPR comments on certain issues and announcing a
number of additional workshops including two specific meetings to
obtain further understanding of Western concerns and discuss how best
to address such concerns. On October 22, 2002 senior Commission staff
met with technical staff from the industry to discuss operational
concerns by Western operators, including the unique characteristics of
the Western hydro and public power systems. On November 4, 2002 a
policy meeting on Western issues will be held in Portland, Oregon to
address policy issues related to the West, proposals for flexibility in
certain areas of the NOPR, and differences in market design within the
Western Interconnection. The November 4th meeting will be open to the
public and attended by FERC commissioners and staff.
I would clarify that the intent of our proposed rule is that the
operators of the Western hydropower system would still be able to
dispatch power based on the operating constraints that have been forged
through the complex regional and international arrangements already in
place. Other elements of the rule would accommodate hydropower
resources. For example, we anticipate that Congestion Revenue Rights
can be fashioned to allow multiple receipt points along a single river
system to accommodate the special operational needs of run of river
hydropower. Congestion Revenue Rights could also be designed to
accommodate seasonal differences or multi-year planning. Further, we
considered hydropower resources in developing the market monitoring and
mitigation plan.
The Commission takes seriously the concerns raised by Western
interests in response to our proposal. As discussed above, we intend to
work with Western interests and experts to address their concerns and
to ensure that a final rule will work to the benefit of all regions of
the country.
Chairman Wood's Responses to Questions Submitted by Senator Kyl
Question 1. The fundamental basis of the Commission's SMD proposal
seems to be to have a single set of rules for wholesale electric
markets, and to have all transmission owners be subject to the SMD
transmission tariff.
(a) In the West, significant transmission is owned and operated by
entities that are regulated at the state and local level. Is SMD able
to accommodate these entities without resorting to expansion of federal
jurisdiction? What has the Commission done or what will it do to
facilitate participation by non jurisdictional entities? Does the
Commission intend to assert authority over non jurisdictional entities?
Answer. The Commission has not proposed to require compliance with
SMD by non-public utilities, e.g., municipals, RUS-financed
cooperatives and federal power entities. In Order No. 888, which was
affirmed by the U.S. Supreme Court, the Commission included a
reciprocity provision in its open access transmission tariff. Under
this provision, all customers (and their affiliates), including non-
public utilities, that own, control or operate interstate transmission
facilities and that take service under a public utility's open access
transmission tariff, must offer comparable (not unduly discriminatory)
transmission services in return. In the SMD rulemaking, the Commission
proposes to continue this approach to reciprocity and to grandfather
all reciprocity tariffs that the Commission previously found met the
comparability standards of Order No. 888.
However, in many areas of the country, because of the significant
transmission owned by non-public utilities, it is important that non-
public utilities be strongly encouraged to participate in RTOs. RTO
scope and configuration that encompasses all transmission systems in a
region increases the reliability and efficiency for all users. We have
attempted to encourage non-public utilities to join RTOs and believe
that SMD and RTOs will prove to be as advantageous to their customers
as it will be to customers of jurisdictional entities.
(b) The Commission's SMD proposal does not seem to recognize
regional differences. Why not? Why does the West have to be exactly
like the East? If Texas can have a separate market design, why can't
the West, especially if that will ensure broader participation.
Answer. Throughout the SMD NOPR the Commission recognizes the need
for regional flexibility. For example, the Commission recognized that
regional variation may be needed in the following circumstances: (1)
term, type and allocation of Congestion Revenue Requirements; (2)
resource adequacy standards and methods; (3) transmission pricing,
including pricing of transmission expansions; (4) calculation of
Available Transfer Capability; (5) market power monitoring and
mitigation; (6) rules for locational marginal pricing; (7) procurement
of certain ancillary services; and (8) action to preserve system
reliability. Moreover, the Commission on October 9th, 2002 issued a
third RTO order in the West on WestConnect that accommodates a variety
of regional concerns.
With respect to the West, there are now three Commission-approved
plans for independent transmission operation that cover almost all of
the Western grid. These entities are working together to eliminate
seams problems through the Seams Steering Group for the Western
Interconnection process. A common market design across the West is more
critical than having an identical market design for both the East and
West. The SMD proposal reflects the lessons we have learned from the
experiences of a number of markets, including California and the West,
and seeks to apply the best practices from all of these markets.
Regional differences are appropriate so long as they benefit customers
as much as we believe our proposal will.
(c) FERC's SMD timetable is very tight and seemingly inflexible. Is
it realistic to expect areas that historically have not been subject to
central dispatch, to adopt an LMP system on the timetable FERC
suggests? Does FERC understand the reluctance of States to adopt new
and drastically different regulatory and market mechanisms, given the
problems encountered in California and elsewhere?
Answer. SMD is a direct response to the problems of California and
the West. SMD will reduce the risk of such problems happening again;
continuing with the status quo unduly risks a repetition of those
problems. That said, I understand the desire to preserve well-
functioning features of the existing system including the allocation of
transmission rights, determination of transmission rates, ongoing
planning processes, and existing resource adequacy methods. I believe
these existing processes can be compatible with SMD. We will be paying
close attention to the Western RTO development including implementation
timelines, prioritization of tasks, and costs of various market design
features in the future. The Commission recently approved an
implementation schedule for RTO West.
The Commission recently extended the comment periods and announced
a number of additional workshops including two specific meetings to
obtain further understanding of Western concerns and discuss how best
to address such concerns. On October 22, 2002, a staff-to-staff meeting
on Western Operations was held in Denver, Colorado where senior
Commission staff with technical staff from the industry identified
major operational concerns by Western operators, including the unique
characteristics of the Western hydro and public power systems. On
November 4, 2002 a policy meeting on Western issues will be held in
Portland, Oregon to address policy issues related to the West,
proposals for flexibility in certain areas of the NOPR, and differences
in market design within the Western Interconnection. The November 4th
meeting will be open to the public and attended by FERC commissioners
and staff.
While the Commission continues to work on its SMD proposal, the
Commission also has made clear that its recent rulings on RTO
applications such as West Connect and RTO West will not be superseded
by the SMD final rule, except for issues on which the Commission's RTO
orders specifically indicate differently. Specifically, in this month's
orders on West Connect and SeTrans, the Commission stated:
. . . it is not this Commission's intent to overturn, in the
final SMD rule, decisions that are made in this docket. In
other words, unless the Commission has specifically indicated
in this order that an element of the RTO proposal is
inconsistent with the SMD proposal or needs further work in
light of the SMD proposal, we do not intend, in the final SMD
rule, to revisit prior approvals or acceptances of RTO
provisions because of possible inconsistencies with the details
of the final rule. This Commission intends to take all
appropriate steps at the final rule stage of the SMD rulemaking
to ensure that, to the extent we have already approved or
conditionally approved RTO elements, these approvals would
remain intact.
Question 2. FERC is proposing to get into areas that traditionally
have been the province of State regulators, such as resource adequacy
and planning.
(a) What is the statutory authority relied on by FERC for this
expansion of its areas of responsibility?
Answer. The SMD proposed rule recognizes that resource adequacy and
planning are primarily under the jurisdiction of states, and does not
propose to change that. However, the Commission is concerned that,
without some minimum level of resource adequacy, the Commission cannot
assure just and reasonable rates in wholesale power markets. In this
regard, the Commission expressed concern in the proposed rule that
``inadequate resources could lead to poor market liquidity and even
shortages with sustained high wholesale power prices.'' (Paragraph
493). The proposed minimum level of resource adequacy protects against
extreme shortages and serves as a placeholder for states to continue
their traditional role in overseeing resource planning by specifying
the methods and standards of adequacy. The method proposed by the
Commission gives states and load-serving entities choices as to what
the appropriate level of resource adequacy should be, and how to meet
the requirement (e.g., new generation or demand response, and with
resources under an obligation to serve retail native load or with
merchant resources). Thus, it can be tailored to meet the needs of a
particular region.
Moreover, the proposed rule does not seek to overturn existing
regional planning entities, but rather to build off of their efforts.
For instance, the CREPC/SSG-WI process in the West serves as a model of
the benefits of cooperation to meet regional supply and transmission
needs, and could satisfy the requirements of the proposed rule.
(b) What happens if FERC and the States differ in their views on
planning and resource adequacy?
Answer. I expect that FERC and state plans will be compatible. Our
resource adequacy proposal is a minimum standard designed to support
and supplement, not supplant state policies. The proposal provides a
placeholder for states and utilities to develop resource planning
methods and standards, preferably on a regional basis. A conflict would
only arise if there was an extreme imbalance of supply and demand due
to poor planning by a utility, state, or group of states. Since region-
wide reliability is a public good, we believe we have an obligation to
ensure that customers do not suffer from the lack of planning by
others.
(c) Does FERC believe that States are not fulfilling their
responsibilities on planning and resource adequacy? If so, what is the
basis for that conclusion?
Answer. In regional power systems, a regional approach to planning
is needed. No single state acting alone can ensure adequate resources
across a whole region. I think states have generally fulfilled their
responsibilities satisfactorily through a variety of means. However, no
continental state is immune from reliability effects elsewhere in the
interconnected grid. The California experience is the type of situation
we believe we need to protect against, where a shortage in one area
affects customers across the interconnected regional grid.
Question 3. In what appears to be yet another change in direction,
the Commission now emphasizes ITPs, as opposed to RTOs, ISOs, RTGs, and
other earlier proposals.
(a) If the Commission is still interested in RTOs, why the delay in
acting on RTO proposals such as WestConnect? WestConnect is the
culmination of years of work by Southwest electric utilities, and
reflects considerable compromise among investor owned and non
jurisdictional entities. It offers a real opportunity for the regional
structure the Commission says it wants. Yet, WestConnect has been
pending before the Commission for almost a year, with no action
whatsoever; just this week, it again has been taken off the Commission
agenda. So instead of acting on a concrete proposal that has the
support of jurisdictional and non jurisdictional players in the
Southwest, the Commission spends its time on SMD, ignoring regional
difference, concerns of State Commissions, and the need to have
participation by all regional entities.
Answer. In light of developments in the industry since 1999, it is
important for the Commission to review what practices actually work in
power markets. The process leading up to our July 31st proposed rule
was a broad, inclusive attempt to learn about all of these best
practices in all areas of wholesale power market development. As we
move forward with specific regional proposals for RTOs, it is crucial
that the Commission have a clear sense of what proposals are likely to
succeed based on actual experience.
As noted in the proposed rule, RTGs can serve as Independent
Transmission Providers. As of October 9th, 2002 the Commission has
approved independent entities to manage all of the jurisdictional
transmission systems in the West and much of the non-jurisdictional
systems. We do not expect that SMD would change these RTO decisions. We
delayed action on the WestConnect proposal from July 31 until October
9th in order to ensure that we had thoroughly analyzed the proposal and
responded to all the comments that were filed.
(b) When will the Commission act on WestConnect and other pending
RTO proposals?
Answer. As of October 9th, 2002, almost every region of the country
has some form of independent entity that has been approved by the
Commission to manage the transmission system. The Commission approved
over the last month RTO West and WestConnect which, along with the
California ISO cover most of the Western grid. Almost all of the
Eastern grid is now covered after October 9th, 2002 approval of SeTrans
for much of the Southeast. If RTOs are approved and in place in a given
region then there is no need for any other Independent Transmission
Provider.
Question 4. As I understand the Standard Market Design proposal,
transmission owners will turn over operation of their facilities to
Independent Transmission Providers who will subsequently schedule
necessary transmission service. For a limited period of time, existing
owners of transmission facilities will be entitled to a financial right
called a congestion revenue right to recognize prior transmission use.
This congestion revenue right will reportedly protect local service
obligations. However, I am concerned that trading physical access to
transmission facilities does not rise to the same level of protection.
The congestion revenue rights raise several questions:
(a) How does the creation of a financial right provide equivalent
value to transmission owners who have made the capital investment,
negotiated with local landowners, and secured the appropriate
regulatory approvals for the construction of these facilities?
Answer. All existing transmission customers, including transmission
owners, would have full physical access to the entire transmission
grid. This basic access is better than what generally exists today.
Moreover, the proposed rule's Congestion Revenue Rights (CRRs) will be
allocated to existing customers such that they would pay no congestion
charges if they continue to schedule service consistent with their
current arrangements. I realize that confusion over these complicated
issues remains, and the Commission must better explain how financial
rights protect customers.
The proposed rule does not propose to change the basic cost
recovery mechanism (the load ratio share charge) that utilities rely on
to recover the costs of their transmission investment. Thus,
transmission owners will have the same opportunity to recover the costs
associated with their transmission facilities as they do now.
(b) How will a utility that experiences load growth receive the
necessary access to transmission facilities?
Answer. As its load grows, the utility would acquire access to
transmission service in the same way as all customers on its system.
The utility would pay the access charge and schedule the needed
service. To the extent the requested service causes congestion, the
utility would have the choice of obtaining the necessary CRRs to
protect itself against congestion, paying the congestion charge, or
expanding the transmission grid to alleviate the congestion. If the
utility expands the transmission network, it would retain the CRRs
created by the expansion for the useful life of the new facilities.
(c) What happen[s] when the congestion revenue rights expire? Will
retail customers pay uncapped rates? How will a retail customer be able
to mitigate the prices that will flow front the auctioning of
transmission rights?
Answer. The proposed rule envisions that utilities and other
transmission customers would keep their rights if they choose not to
turn them over. Their physical and financial position would be
unchanged. The proposed rule suggests a four-year allocation of CRRs to
all load-serving entities based on their current uses of the system to
ensure that existing load is shielded from congestion costs, and
suggests that regions can propose to extend the allocation for a longer
time period. Moreover, if there were an auction after four years, the
particular mechanism that was proposed was intended to allow entities
to hold on to their rights and avoid financial harm. The proposed
mechanism was based on an identified best practice by market
participants in the Northeast RTO mediation hearings here. However,
this particular piece of the SMD proposal has not been supported by a
broad consensus of parties in other regions. As a result of the
significant amount of concerns we have heard on this feature, the
Commission decided to engage in further dialogue beginning with a
technical conference on December 3, 2002. The Commission's policy
through gas industry restructuring, Order No. 888 and Order No. 2000
was to preserve existing contracts but to create better opportunities
for open access transportation going forward.
Importantly, this issue is being addressed in RTO orders. The
SeTrans, West Connect, and RTO West orders issued over the last month
provide means through which contracts can be voluntarily converted to
the new services. We expect that RTO orders will be the primary forum
for contract allocation and conversion issues.
Chairman Wood's Responses to Questions Submitted by Senator Landrieu
Question 1. Clearly stated in the SMD NOPR is the position of the
Federal Energy Regulatory Commission that participant funding is the
preferred method of transmission pricing for grid expansion. While I
strongly agree with the concepts encompassed in participant funding,
the SMD NOPR omits the details and specifics, which I am very
interested. Please provide the details and specifics of your view of
the implementation and application of the concepts of participant
funding, including but not limited to the principles of approval of the
participant funding method for transmission pricing, FERC natural gas
pipeline and incremental pricing precedent to be used in the
implementation and application of participant funding, FERC natural gas
pipeline and incremental pricing precedent which the FERC intends to
deviate from in the implementation and application of participant
funding, and any and all other types of incentives in your view needed
to create a robust program of electric transmission grid expansion
(return on equity, accelerated depreciation, etc.).
Answer. In the SMD NOPR the Commission expressed a preference for
participant funding and noted that it would consider participant
funding for proposed transmission facilities that are included in a
regional planning process conducted by an independent entity. The
Commission issued an order on October 9th, 2002 that approves the
general framework of the SeTrans proposed participant funding
framework. Neither the SMD NOPR nor the SeTrans proposal attempted to
clearly define the types of investments that would fall into each
pricing category, including voluntary participant funding, obligatory
participant funding, or obligatory rolled-in pricing. Since no party
advocates participant funding for all investments, it will require
technical and policy work in each region to define these categories.
The Commission announced a technical conference on participant funding
to be held on November 6, 2002 and will be holding on-going discussions
with state and industry officials in each region to discuss their views
on these pricing policies.
While the Commission continues to work on its SMD proposal, the
Commission also has made clear that its rulings on RTO applications
such as SeTrans will not be superseded by the SMD final rule, except
for issues on which the Commission's RTO orders specifically indicate
differently. For example, in the SeTrans order, the Commission stated
that we would allow the use of participant funding in SeTrans as part
of a general framework for transmission expansion. It is not the
Commission's intention to revisit this determination after issuance of
a final rule on SMD, and I would oppose any such effort.
Question 2. There seems to be a widening rift between the States
and FERC on the FERC's plans for energy markets. If we continue this
path, we could be headed for years of litigation and no progress. Does
FERC have any plans to attempt to resolve the concerns of the states?
Answer. We are working closely with all the regions to make
wholesale markets work and to synchronize wholesale markets with
various state regulatory approaches. We believe states retain control
of the issues that are important to their ability to fulfill their
public interest responsibilities. For example, states will continue to
set retail rates, maintain primary responsibility for resource
planning, protect any low cost power they wish to keep, choose the
level of vertical integration, and make siting decisions.
To better understand states' concerns, we have held six SMD
discussions exclusively for state commissioners and staffs, three other
discussions with state commissioners and industry at large, and ten
additional meetings with various sectors and interests, such as public
power, environmental groups, consumer advocates and large industry
groups as well. Moreover, we have participated in dozens of meetings on
market design. And this is just the beginning. We are learning from the
states what regional differences need to be accommodated in wholesale
market design and states hear from us how standard market design can
improve interstate markets nationwide and benefit customers in all
regions. FERC's recent RTO orders in SETrans, WestConnect, and RTO West
address many state concerns and reflect our flexibility in response to
regional needs.
Question 3. While I do not expect FERC to be able to predict
everything about the impacts and results of the SMD, please provide me
with the positive impacts and results that you can guarantee concerning
the SMD NOPR? More specifically, provide me with the positive impacts
and results to low cost states, such as Louisiana, that you can
guarantee concerning the SMD NOPR?
Answer. The proposed rule would save customers money because
effective wholesale markets would:
achieve more efficient use of current electric system;
get more new, efficient, clean generators built, which drive
down electricity prices;
treat everyone fairly;
protect existing contracts and service quality for native
load, and ensures transmission for future load growth;
prevent opportunities and incentives for market manipulation
including transmission manipulation;
prevent California-type melt-downs through resource
planning, market oversight and market power mitigation; and
reduce price volatility.
In addition, the proposed rule would improve reliability and
security of the nation's infrastructure because effective wholesale
power markets would:
use stable market rules to encourage investment in new
generation, transmission and demand reduction;
make technologically smarter use of existing transmission
grid;
encourage investment in new technologies that offer greater
efficiencies and better environmental solutions, thus reducing
use of scarce fossil resources;
adopt cyber-security standards that reduce grid
vulnerability to terrorism;
make more new resources available due to long-term planning
and adequacy requirements, reducing short-term scarcity and
outages; and
provide incentives for locating resources closer to
customers, making the grid more reliable and secure.
Lastly, our proposal would:
minimize inefficient and gameable ``seams'' through
standardized rules;
require the transmission grid and short-tern markets to be
operated by a fair, independent organization (RTO or ITP);
establish procedures to monitor market operations and
effectiveness and mitigate market power and manipulation;
preserve and expand the role of states in regional planning,
resource adequacy, and cost allocation for new resources and
facilities;
supplement long-tern bilateral contracts with real-time
energy markets that reveal the true costs of electric
congestion and value over location and time;
manage congestion on the electric grid by price instead of
service denial, creating economic signals for new investments
in infrastructure and technology;
set procedures for minimum long-tern regional resource
adequacy using generation, transmission and demand-side
resources, with details set by regional state committees;
permit customers under existing contracts to keep the same
level and quality of transmission service if they choose to do
so;
allow flexible transmission pricing, including participant
funding;
rationalize and improve power plant transmitting siting with
better signals, participant funding and regional resource
planning; and
create stability and certainty for customers and investors.
In sum, we believe these measures will make every American
electricity customer better off even those in lower cost states-with
lower wholesale electricity costs, better grid reliability and more
stable electricity markets.
Chairman Wood's Responses to Questions Submitted by Senator Dorgan
Question 1. It appears that this Notice of Proposed Rulemaking
(NOPR) would alleviate rate pancaking, which is important. It also
seems that most Regional Transmission Organizations (RTOs) will
initially move to a license plate rate structure. Do you envision RTOs
ultimately moving toward a postage stamp rate structure in the longer-
term? Why or why not?
Answer. We proposed to permit the use of license plate rates and
sought comment on whether regions should eventually be required to move
to postage stamp rates, or whether that should be a regional decision
up to the committee of state representatives. It is difficult to say at
this time whether RTOs will move toward a postage stamp rate structure
in the future. Several entities have proposed transition periods for
moving away from license plate rates in their RTO filings. The
Commission accepted MISO RTO's six-year transition period and the RTO
West's eight-year transition period. SeTrans asked for an eight-year
transition period, while WestConnect proposed a transition period that
will terminate January 1, 2009. The Commission is interested in
creating more efficiency without creating unnecessary cost shifts,
which a shift from license plate rates can do.
Question 2. Given the complexity of this NOPR, can you please
explain how you envision transmission system upgrades/expansions would
actually occur, and who would build more transmission?
Answer. A number of parties could identify transmission upgrades
including existing vertically integrated transmission owners,
independent transmission companies, and merchant transmission
companies. The proposed rule reinforces the process of Order No. 2000
where these projects would be coordinated to ensure no investment
degrades other parts of the grid. Voluntary investments could be made
in return for the Congestion Revenue Rights created. Investments could
also be made in return for regulated returns, if the project is deemed
beneficial and if the market alone would not make the investment. Each
RTO has a process to govern specific mechanisms, and the Commission
will be holding further dialogue in the SMD proceeding to clarify the
rules and rewards of investment. While regional planning is very
important, it is not my intention to hold up good investments in a slow
centralized process. I would expect that the majority of new
transmission that is constructed will be upgrades to existing lines
rather than the siting and construction of new lines through new rights
of way, but there is a need to bolster the regional grid through multi-
state lines.
Question 3. Could you please clarify what aspects of this proposal
would apply to cooperatives, municipal and federal utilities.
Answer. The Commission has not proposed to require compliance with
SMD by non-public utilities, e.g., municipals, RUS-financed
cooperatives and federal power entities. In Order No. 888, which was
affirmed by the U.S. Supreme Court, the Commission included a
reciprocity provision in its open access transmission tariff. Under
this provision, all customers (and their affiliates), including non-
public utilities, that own, control or operate interstate transmission
facilities and that take service under a public utility's open access
transmission tariff, must offer comparable (not unduly discriminatory)
transmission services in return. In the SMD rulemaking, the Commission
proposes to continue this approach to reciprocity and to grandfather
all reciprocity tariffs that the Commission previously found met the
comparability standards of Order No. 888. Non-public utilities would
not have to meet the requirements of SMD in order to provide reciprocal
comparable transmission services.
However, in many areas of the country, because of the significant
transmission owned by non-public utilities, it is important that non-
public utilities be strongly encouraged to participate if SMD is to be
effective. Efficient regional power markets benefit customers of non-
public utilities. We have attempted to encourage non-public utilities
to join RTOs and believe that SMD and RTOs will prove advantageous to
non-public utilities and to the reliability and efficiency of the
regional grid.
Question 4. What would happen if an RTO told a utility to build a
transmission line in North Dakota, for example, and then the State
Public Utility Commission (PUC) said the costs couldn't be recovered in
the rate structure? How would the transmission line ever get built?
Answer. As you suggest, if a utility were required to build a
transmission line but knew it would not recover its costs (for whatever
reason), the utility likely would resist the requirement to build.
However, if the line is needed for local or regional reliability and
the line limits load-serving entities' ability to obtain low-cost
power, then that state's customers will pay the price for not building
the line as they pay for unnecessarily high-priced electricity and
reduced reliability.
The Commission's NOPR acknowledged that states have exclusive
jurisdiction over transmission siting. However, to avoid conflicts or
delays in building transmission lines, we are encouraging a regional
process with involvement of the states. The NOPR essentially adopts the
recommendation of a recent National Governors' Association report on
using Multi-State Entities to facilitate regional transmission planning
decisions. See Interstate Strategies for Transmission Planning and
Expansion, National Governors' Association, posted on July 18, 2002,
available in . Multi-State Entities, along with an open
regional planning process, would preserve the states' role in siting
decisions, while promoting regional solutions. The need for additional
transmission capacity is reaching critical proportions. Our proposal to
address these needs regionally is an effort to break the logjam that is
preventing construction of such capacity.
Question 5. Would a for-profit transmission company model, such as
the one that some Midwestern cooperatives and utilities are involved
in, be feasible under the market design that you are proposing?
Answer. Yes. The Commission has long recognized that the
independent transmission company (ITC) business model can bring
significant benefits to the industry. Their for-profit nature with a
focus on the transmission business is ideally suited to bring about:
(1) improved asset management, including increased investment; (2)
improved access to capital markets, given a more focused business model
than that of vertically integrated utilities; (3) development of
innovative services; and (4) additional independence from market
participants, which reduces market power.
We recently approved TRANSLink Transmission Company, L.L.C.'s
application to operate within the Midwest ISO, an approved RTO.
TRANSLink is a for-profit ITC made up of three members of the Midwest
ISO RTO and three other transmission companies. It will share some of
the characteristics and functions of an RTO with Midwest ISO, including
the operation of part of Midwest ISO's transmission grid.
Question 6. With this proposal, the FERC seems to be pushing the
industry in the direction of a national marketplace and toward a market
in which transmission is separated from distribution and generation.
Yet Wall Street seems to be rewarding the old-fashioned vertically
integrated companies. Please comment.
Answer. With most of the country under some form of Commission-
approved independent entity managing transmission, the separation of
the transmission that began more than five years ago is well under way.
From my experience, this will encourage new entry in each region. Many
vertically integrated utilities actually have generation assets
dispersed across the country, so competitive entry continues despite
the temporary credit problems of the merchant sector. I believe that
the stability provided by regulatory certainty regarding market design
and structure will help bring back capital to the market sector.
Question 7. In turning over operational control of transmission to
RTOs, would utilities still be liable for mismanagement that is the
fault of the RTO?
Answer. The tariffs proposed under the NOPR contain the same force
majeure provision and indemnification provision as contained in the
Order No. 888 pro forma tariff. Under those tariffs, the Commission has
shown flexibility on how transmission owners and operators choose to
allocate liability between themselves, but has otherwise said the
determination of liability should be made in state fora. In particular,
the Commission has said that state law should decide the applicable
standard for liability (such as negligence or gross negligence).
Several entities, including Midwest ISO RTO and RTO West, have sought
to revise the liability provisions by arguing, among other things, that
no current Federal forum exists for entities that are now subject to
Commission jurisdiction only and can no longer seek relief at the state
level. In the NOPR, we seek comments on multiple issues, including
whether there is a need to include liability provisions in the
Commission's pro forma tariff; under what circumstances liability
protection should be provided in a Commission open access transmission
tariff (e.g, should we provide such protection only where it is not
available through state tariffs); whether liability provisions should
be generic or adopted on a regional basis; whether the standards
adopted in a Commission pro forma tariff should reflect what was
previously provided under state law; and how we should resolve the
issue in the multi-state context of an ISO or RTO. The Commission will
review the comments filed and has planned a staff technical conference
on December 11, 2002 to further discuss liability issues.
Question 8. Could the resource adequacy requirements that FERC is
envisioning result in FERC telling RTOs, and in turn utilities, what
fuel mix they have to use? Wouldn't this be an unintended consequence
of the NOPR?
Answer. No. The SMD NOPR's proposals regarding resource adequacy do
not address fuel mix at all. The Commission wants to ensure that each
region has a sufficient level of generation resources available, not
that those resources be of any particular type. Certification of
resource expansion plans would be within the states' purview.
Question 9. The Western Governors' Association and others have
indicated that this proposal would create more uncertainty, rather than
less. How do you respond to this?
Answer. Establishing common rules for transmission service and
electric power markets will remove much uncertainty from the industry.
Market participants would face a stable regulatory environment with
consistent rules. With three approved institutions in the West and a
constructive process underway to resolve seams problems in the West,
the region should have some certainty now on how the Western market
will look in the future. Moreover, the proposed market monitoring and
market power mitigation, including long-term resource adequacy
requirements, would stabilize prices and ensure adequate generation
will be available when needed. Lastly, the proposed rule and subsequent
RTO orders should ensure that the economic bargains of existing
contracts will be maintained and protected.
Question 10. Are there adequate safeguards under this proposal to
ensure that we do not have a repeat of the California crisis?
Answer. Yes. In fact, the proposed rule addresses the market design
flaws that caused the California crisis. In contrast to the practices
that contributed to California's problems, Standard Market Design would
stabilize energy costs and prices by relying predominantly on long-term
bilateral contracts, rather than requiring all power to be bought or
sold in spot markets. It would reduce resource scarcity and improve
reliability by requiring load-serving entities to bring adequate long-
term resources to the market to ensure that supply is always available
when needed. Standard Market Design proposes strong market mitigation
measures to prevent withholding, and proven market rules that prevent
the gaming that occurred in California. (See a description of how the
gaming is prevented in Appendix E of the proposed rule). In addition,
locational marginal pricing on a nodal basis (i.e., at many points on a
system) rather than just for a few zones would allocate the cost of
congestion to the entity causing the congestion, which would remove the
incentive to artificially cause congestion. The RTO West is developing
a regional variation of LMP, i.e. Locational Pricing which would
reflect the lowest bid price for the next increment of energy delivered
to a particular location, but would not rely on the marginal cost of
production.
Question 11. Would this NOPR increase or decrease costs to
consumers?
Answer. We believe that the proposed rule would decrease costs to
customers. Competitive markets have worked well to lower costs and
(often) to improve service in many industries where they have been
tried. This includes natural gas, long distance telecommunications, and
electric power in regions such as PJM, Texas, and the United Kingdom.
The SMD proposal would specifically and comprehensively address the
risks inherent in the second lesson through a detailed plan of market
mitigation. SMD also proposes resource adequacy. The key problem that
makes electric markets vulnerable to price spikes is supply shortage,
real or contrived. By proposing resource adequacy, SMD seeks to ensure
that enough capacity is built ahead of time so that there will not be
absolute shortages in regional markets. It also would mitigate market
power in load pockets--localities where power supplies are short and
power suppliers are few. Generators in such areas would be required to
enter must-run agreements (to prevent contrived shortages) and would
have caps on what they can bid (preventing them from arbitrarily
raising prices). SMD would require a safety net price cap to prevent
prices from rising above a certain level, regardless of market
conditions. This cap would prevent customers from ever seeing prices
higher than the cap. It also would allow markets that are under stress
to institute more stringent mitigation, modeled on systems already in
use in, for example, New York. Finally, SMD would provide for ongoing
market monitoring at both the regional and national level. This market
monitoring would detect and respond to urgent market problems rapidly
and provide a way of identifying and addressing longer term problems
before they become serious. This would provide indispensable feedback,
allowing us to improve market rules and operations over time without
waiting for emergencies to develop.
Together, these measures form a comprehensive customer protection
program to prevent any recurrences of recent market failures and
manipulations. Given those protections, market forces can act as they
normally have to lower costs and maintain reliability to customers.
A competitive model, coupled with regulatory certainty and
appropriate incentives, such as what is proposed through SMD, would
provide greater incentives for long-run transmission, generation, and
demand response investment. It also would foster the creation and
installation of new technology to maximize the capabilities of existing
infrastructure. Further, regulatory certainty would prevent the
incurrence of stranded costs.
To the extent states choose retail competition, customers would not
be restricted to buying from the vertically integrated utility, but
would have the opportunity to contract with the lowest cost suppliers
in the region to meet their power needs. This includes the ability to
purchase any excess supply on neighboring systems without paying an
additional transmission charge to reach it.
Moreover, to the extent states do not choose retail competition but
their vertically-integrated utilities have excess power for sale, these
utilities would be better able to sell this excess power in more
distant and perhaps higher-priced markets. The state commissions would
usually credit back the revenues from those sales to retail customers,
who would then reap the benefit from those sales. Likewise, better
markets mean better access to lower cost power to meet utilities' needs
during periods of local shortages.
The Commission's stated preference to permit participant funding
for transmission expansions would insulate bundled retail customers
from paying increased transmission costs for transmission upgrades to
serve other regions, while allowing the state to enjoy the tax and
employment benefits of new generation and transmission facilities.
Participant funding would rely on an independent entity, the ITP or
RTO, to determine the beneficiaries of a particular transmission
upgrade and to allocate costs of the project to the beneficiaries.
These decisions would be made in consultation with the Regional State
Advisory Committees and are subject to Commission approval.
Lastly, the proposed rule anticipates that Congestion Revenue
Rights will be allocated to current users of the system in order to
protect them from any congestion costs on the system. Congestion
Revenue Rights would ensure continued access to the generators from
which retail customers are currently served. This is an advantage over
other potential buyers, who may be subject to congestion costs to reach
a particular low-cost generator. Thus, Congestion Revenue Rights
coupled with long-term contracts and/or direct sales by vertically
integrated utilities would insulate retail customers from any changes
in the marketplace.
Chairman Wood's Responses to Questions Submitted by Senator Burns
Question 1. Several cost benefit studies were released earlier this
year concerning the impact on utility customer rates of forming
Regional Transmission Organizations (RTOs). The studies showed no net
benefit and indeed potential rate increases for residents of Montana.
What assurance can you give me that the implementation of the FERC's
Standard Market Design rulemaking will result in lower rates for the
citizens of Montana?
Answer. While we expect SMD to lower wholesale prices on average,
there are a few states where there could be a slight increase. When
Montana restructured, it did not require long-term contracts for the
sale of power from its inexpensive generation to its load. As a result,
the generation could be exported and sold elsewhere in the Western
grid, thus lowering prices in other states. Because of these exports,
the Commission's cost-benefit analysis of RTOs projected that more open
markets would lead to slightly higher wholesale power prices in most of
Montana than would otherwise occur (about 3 percent). It also projected
a subsequent reduction of prices in the years after markets opened.
However, Montana's wholesale prices would remain among the lowest in
the West. Moreover, this analysis assumed no long-term contracts, which
has the result of increasing the estimated prices to Montana customers.
If customers voluntarily signed long-term contracts, their prices could
be lower than this estimate.
Question 2. Electricity in my pail of the country often travels
great distances from where it is generated to the customer. The FERC's
Standard Market Design rulemaking sets up a new process for securing
electricity transmission. What assurance can you give me that:
First, the citizens and power companies of Montana will have long-
term access to the power grid they have relied upon to get them
electric power and;
Second, the rates the power companies and citizens of Montana will
pay to have their power transmitted will decrease, or at least not
increase, if the Standard Market Design rule is implemented.
Answer. I expect that significant benefits will be brought to
Montana through the existence of RTO West. The underlying assumption
for transmission service under the proposed rule is universal access--
all customers that pay the access charge would have full physical
access to the grid. The proposal addresses one of the problems facing
transmission service today--indiscriminate transmission service
interruptions when there is insufficient capacity to meet all requests
for service. Under the proposed rule, customers causing congestion
would be required to pay for it. However, the proposed rule also would
require that existing customers receive protection against congestion
costs through ``Congestion Revenue Rights.'' The combination of
universal access and congestion cost protection means that customers
can receive the service they need without financial disruption. In
other words, the citizens and power companies of Montana would have
long-term access to the power grid they have relied upon to get them
electric power at no additional cost if the Standard Market Design
proposed rule is implemented.
Question 3. I am concerned about the potential impact the Standard
Market Design rulemaking could have on ratepayers in Montana.
Transmission owning utilities get significant revenues from the
transmission services they provide. The Standard Market Design
rulemaking appears to suggest that they would not get any revenue for
electricity wheeled ``through and out'' of their service area.
--is this correct?
--if yes, wouldn't this result in higher rates to native load
customers? Stated differently, how does the Standard Market Design
rulemaking propose that companies make up the revenue they may lose
from the ``through and out'' rate design the FERC proposes in the
rulemaking?
Answer. It is not correct that a transmission-owning utility would
not get any revenue for electricity wheeled through and out of the
service area. The SMD NOPR and RTO West order ensure that a
transmission owner would be able to continue to collect 100 percent of
its revenue requirement. They allow transmission owning utilities to
collect revenue for electricity wheeled ``through and out'' of their
service area. The Commission recognized that eliminating a specific
transmission charge for through-and-out service would facilitate
efficient inter-regional transactions and increase savings for buyers
and sellers, but would result in cost-shifting and may stifle new
transmission investment. Accordingly, the Commission proposed to create
a mechanism for ensuring that the cost of interregional transmission
services is allocated fairly among the regions. The Commission
specifically sought continent on alternative methods under which: (1)
the source ITP would allocate a portion of its revenue requirement to
the sink ITP's transmission customers; or, (2) a revenue crediting
approach, under which inter-regional transfers could be priced at the
load ratio share charge and the inter-regional transaction charges
would be netted out over some time period.
The Commission recently approved an export fee for RTO West as part
of its transition to a new rate design. The Commission generally said
that its rulings on RTO West were informed by but also would inform the
SMD rulemaking. More recently, the Commission has made clear that its
rulings on these and other issues in pending RTO applications will not
be superseded by the SMD final rule, except for issues on which the
Commission's RTO orders specifically indicated differently. In this
month's orders on West Connect and SeTrans, the Commission stated:
. . . it is not this Commission's intent to overturn, in the
final SMD rule, decisions that are made in this docket. In
other words, unless the Commission has specifically indicated
in this order that an element of the RTO proposal is
inconsistent with the SMD proposal or needs further work in
light of the SMD proposal, we do not intend, in the final SMD
rule, to revisit prior approvals or acceptances of RTO
provisions because of possible inconsistencies with the details
of the final rule.
I intend to apply the same approach to RTO West.
Question 4. State public utilities commissions like the Montana
Public Service Commission have traditionally been responsible for
assuring adequate generation and transmission resources exist to supply
the needs of state residents. The Standard Market Design rulemaking
appears to give this responsibility to new organizations called
Independent Transmission Providers (ITP's). We're proud of the job the
Montana Public Service Commission has done protecting the citizens of
my state. Part of the reason the Montana PSC is so responsive to
ratepayers and utilities is that those members are elected.
What assurance can you give me that the interests and concerns of
Montana residents will be addressed by this new organization (i.e.,
Independent Transmission Provider)? How will the ITP members be
selected and to whom will the ITP be accountable?
Answer. The SMD NOPR envisions that states would retain their
primary roles in resource adequacy planning. State officials could rely
on regional agreements as they always have in most regions to set the
regional policy guidelines. Once policy guidelines are set based on
state and regional agreements by entities with public accountability,
it is important that implementation is conducted on a regional basis,
by an entity that is independent, professional, and competent. RTOs
like RTO West would be able to achieve such independence and
competence. RTO board members would selected in a way to achieve
competence and independence. We also envision a significant amount of
local and regional oversight through committees of state
representatives that would be involved in RTO oversight.
Question 5. The Standard Market Design rulemaking mandates the
formation of Independent Transmission Providers. In this regard, on a
number of occasions, the FERC has pointed to the PJM Interconnect as an
example of a successful Regional Transmission Organization. The PJM
region, and many other regions of the country, rely heavily on gas and
coal generated power; so called thermal energy. As you know, the
Northwest region of the country has a heavy reliance on hydroelectric
power. There are critical, distinct differences between how thermal
based and hydroelectric based regions must operate. How does the
Commission plan to address these differences in the Standard Market
Design rulemaking?
Answer. Through its outreach and its RTO West order, the Commission
considered extensive comments of the states and other entities in the
Northwest. We note that NorthWestern Energy, L.L.C. previously Montana
Power Company is a participant in the RTO West proposal. The RTO West
market design, based on locational prices and financial transmission
rights, is generally consistent with the SMD design, and it also
addresses difficult contractual and other issues that can be worked out
on a regional basis. In the SMD NOPR process the Commission sought to
accommodate hydropower resources while standardizing transmission
service and energy markets. In this regard, the Commission did not
intend that anything in the proposed rule, or in a Locational Marginal
Pricing market design, would require the Western hydropower system to
operate any differently than it does today. While no entity has pointed
out to us any features of our proposal that would prevent the Western
hydropower system from operating as it generally does today, we have
recently announced further workshops and meetings regarding issues such
as this that are important to the West. On October 2, 2002, we issued a
notice further extending the time for NOPR comments and announcing a
number of additional workshops including two specific meetings to
obtain further understanding of Western conceals and discuss how best
to address such concerns. On October 22, 2002, a technical meeting on
Western Operations was held in Denver, Colorado to identify major
operational concerns by Western operators, including the unique
characteristics of the Western hydro and public power systems. On
November 4, 2002, a policy meeting on Western issues will be held in
Portland, Oregon to address policy issues related to tire West,
proposals for flexibility in certain areas of the NOPR, and differences
in market design within the Western Interconnection. The November 4th
meeting will be open to the public and attended by FERC commissioners
and staff.
I would clarify that the intent of our proposed rule is that the
operators of the Western hydropower system would still be able to
dispatch power based on the operating constraints that have been forged
through the complex regional and international arrangements already in
place. We also discussed other elements of the rule and how these
elements would accommodate hydropower resources. For example, we
anticipate that Congestion Revenue Rights can be fashioned to allow
multiple receipt points along a single river system to accommodate the
special operational needs of run of river hydropower. The Commission
intends to contribute internal staff and external consulting resources
to help us work on this issue collaboratively with the Northwest.
Congestion Revenue Rights could also be designed to accommodate
seasonal differences or multi-year planning. Further, we considered
hydropower resources in developing the market monitoring and mitigation
plan. Finally, we proposed to accommodate existing contracts and
scheduling practices for hydropower resources.
The Commission takes seriously the concerns raised by Western
interests in response to our proposal. As discussed above, we are
working with Western interests to address their concerns and to ensure
that a final rule will work to the benefit of all regions of the
country.
Question 6. The Standard Market Design rulemaking suggests that
hedging and other sophisticated market techniques may allow utilities
to take advantage of the congestion revenue rights (CRR) established by
the rule. This may be true and may be feasible for many of the larger
utilities in the county. However, in Montana and other parts of the
county, we have many small Cooperatives with limited staffs, budgets
and resources. These crucial differences may result in companies in
states like mine not being able to take advantage of any opportunities
this new approach may offer. How does the Commission plan to address
this concern in the Standard Market Design rulemaking?
Answer. CRRs would be allocated to all existing customers for four
years to ensure that their current service is essentially unchanged.
Thus, any customer that merely wishes to maintain its current
transmission access to generators and avoid any cost of congestion
could simply schedule its transmission service consistent with the CRRs
it receives.
Chairman Wood's Responses to Questions Submitted by Senator Graham
Question 1. In your experience have public power entities refused
to cooperate with the Commission's open access transmission program?
Answer. No. To the contrary, a number of such entities have chosen
to offer open access transmission.
The Commission lacks jurisdiction to require most public power
entities (those that are not public utilities) to comply with our open
access regulations. Under Order No. 888, which was affirmed by the U.S.
Supreme Court, the Commission required only that a utility taking open
access transmission service from a public utility must offer comparable
service reciprocally to the public utility. The Commission has proposed
a similar reciprocity provision as part of the SMD NOPR. However, I
believe it will be to the benefit of public power entities to
participate in other aspects of Standard Market Design as long as they
are able to continue to meet their statutory and contractual
obligations.
The Commission will be as flexible as it can be to ensure
participation of public power in RTOs. Under Order No. 888, almost two
dozen public power entities have filed reciprocity tariffs (see answer
to question 2). The Commission proposes to grandfather all reciprocity
tariffs that the Commission previously found met the comparability
standards of Order No. 888. As stated in the proposed rule, the
Commission seeks comments on this proposal.
Question 2. Roughly how many public power entities have filed
voluntary open access transmission tariffs with you? Does this
represent the minority or the majority?
Answer. We have received approximately two dozen filings from
public power entities. We have accepted virtually all of these tariffs,
including those submitted by Bonneville Power Administration, Salt
River Agricultural Improvement and Power District, Southwestern Power
Administration and Western Area Power Administration. Two tariff
filings are still pending before the Commission and one was dismissed
as unnecessary.
While most of the largest public power entities have filed
reciprocity tariffs with the Commission, they represent only a minority
of the total number of public power entities in the nation.
Question 3. It is my understanding that the major public power
transmission systems in the Eastern Interconnection are either members
of ISOs, members of proposed RTOs, or negotiating to join RTOs. Is this
accurate?
Answer. With the exception of the Tennessee Valley Authority (TVA),
your statement is accurate. And TVA, the nation's largest public power
provider, has signed a memorandum of understanding (MOU) with Midwest
Independent Transmission System Operator, Southern Company and Entergy.
These four transmission providers own or operate about 150,000 miles of
transmission lines serving an area totaling more than one million
square miles. The MOU establishes a framework for the transmission
providers to develop formal regional coordination agreements that would
ensure seamless transmission services. The regional coordination
agreements would complement any additional transmission coordination
efforts in which TVA, MISO, Southern Company, and Entergy are involved.
These efforts include the existing MISO membership, as well as the
proposed SeTrans RTO involving Southern, Entergy, and several other
Southeastern utilities.
Appendix II
Additional Material Submitted for the Record
----------
Statement of Braulio L. Baez, Commissioner, Florida Public
Service Commission
This testimony is being filed for the purpose of commenting on the
progress that is being made to develop a regional transmission
organization in Florida and the potential impact of the new Federal
Energy Regulatory Commission's rulemaking. As you know, on July 31st,
the FERC issued what is being called its Standard Market Design (SMD)
Notice of Proposed Rulemaking, or in FERC speak what we call a NOPR.
This rulemaking addresses business practices with respect to the
wholesale energy market. The Standard Market Design is the third major
rule process undertaken by the FERC addressing issues of access to the
transmission system. The Florida Public Service Commission has actively
been involved in this process since the issuance of Order 888 back in
1996, continuing with Order 2000 two years ago.
These comments address Florida's experience with this process and
give our perspective on where the Florida Commission and FERC have
similar objectives and areas where we may not always agree with our
friends at the FERC. These comments reflect my own opinions since the
Florida Public Service Commission has not yet voted on our formal
comments to be filed with the FERC in this SMD rulemaking. These
official comments will be considered by the Florida Commission at an
upcoming meeting.
My comments reflect two different themes. The first is to express
our continued support for the movement toward standardized market
design and practices to encourage the development of robust wholesale
markets. The other theme is to express concern about the over-reaching
and inappropriate assertion of FERC jurisdiction into areas of utility
regulation which are solely the purview of state utility commissions.
We continue to believe that the end goal of more competitive wholesale
markets can be achieved without the jurisdictional transgressions and
preemption engendered by some parts of this NOPR. In fact, we are
concerned that the resolution of jurisdictional disputes created by
this NOPR may actually delay the timely start up of regional
transmission organizations.
The Florida Commission has supported the overall policy direction
initiated by the FERC in its recent RTO orders. While we certainly had
jurisdictional concerns with Order 888 and Order 888-A, we did not
dispute the objectives contained therein. We concur that robust,
competitive wholesale markets are beneficial to customers throughout
the electric industry. We agreed with FERC for only asserting its
jurisdiction over the ``unbundled'' aspect of transmission access that
occurred through either voluntary actions on the part of utilities or
through the mandate of retail access by state authorities. We also
accepted the veracity of FERC's assertion in Order 2000 that
participation in RTOs by jurisdictional utilities would be voluntary.
The FERC initially stated that all jurisdictional utilities would
be expected to join several, geographically large, RTOs (or as FERC
calls them in the current NOPR, Independent Transmission Providers or
ITPs). This was of great concern to Florida as we are a peninsular
state with limited electrical interconnections with the rest of the
Southeast. We are almost entirely dependent on indigenous power
generation to meet our rapid load growth and to support our reliability
standards. In fact, the Florida statutes give the Florida Commission
very strong regulation over the adequacy and operation of the Florida
grid. Fortunately, the FERC has more recently shown flexibility with
respect to geographic scope and size of RTOs.
Based on these three precedential conditions--voluntary
participation in RTOs, FERC's recognition of appropriate state/federal
jurisdictional boundaries, and the recognition of Florida's somewhat
unique electric configuration--Florida has been very supportive in
promoting the development of a peninsular Florida regional transmission
organization which we call GridFlorida. Last December, the FPSC gave
initial approval for peninsular Florida utilities to participate in a
Florida specific RTO. We did this based on a finding that economic
benefits were likely to accrue to the citizens of Florida.
Finally, on September 3, 2002, we gave final approval to most
issues associated with governance, structure, operations, and planning
of GridFlorida. Because the utility applicants recently submitted a
revised market design proposal that dramatically differed from the one
originally filed with the FPSC and tentatively approved by this
Commission, we plan to conduct an expedited hearing to take testimony
on this last aspect of GridFlorida. We note that the Applicants'
proposed market design has many of the features specified in FERC's
current rulemaking including locational marginal pricing, financial
transmission rights, day ahead energy markets, and the elimination of
pancaked rates.
The point of this short historical recitation is to illustrate both
the progress we are making and the general concurrent, regulatory
direction that the FPSC and the FERC have been taking. However, we are
concerned that this positive, regulatory partnership maybe harmed with
the adoption by the FERC of some components of the current rulemaking.
The following are a few of the key areas that give me concern.
PLACING BUNDLED RETAIL TRANSMISSION SERVICE UNDER FERC AUTHORITY
In both Order 888 and 2000, FERC recognized Florida and twenty-six
other states had not elected to implement retail choice. Based on this
fact, the FERC made a clear distinction between transmission service
provided in ``bundled'' versus ``unbundled'' states where transmission
service was just another component of wholesale markets. In its filing
with the U.S. District Court of Appeals, the FERC acknowledged a legal
distinction between these two types of services and admitted that while
it probably had jurisdiction over both types of transmission service,
Order 888 was directed toward remedying undue discrimination over
wholesale transmission service. It chose at that time not to assert
authority over retail, bundled transmission service.
The Florida legislature has not undertaken any legislative steps to
open up Florida to retail choice. Morever, the Florida legislature
elected not to implement recommendations of the blue ribbon 2020 Study
Commission to initiate steps to permit the separation of existing
generation into affiliates for the purpose of furthering wholesale
competition in Florida. Yet, the very existence of state regulated
vertical utilities has led the FERC in its current proposal to assert
exclusive jurisdiction over retail transmission service and to decide
on what terms and conditions retail customers will have access to the
transmission system.
I personally believe that in bundled states where franchised
utilities have a statutory obligation to serve retail load, that this
native load (along with firm contracted wholesale customers) should, in
some cases, have preferential access to the transmission system that
was built to serve that load and was paid for by these native load
customers. FERC has clearly decided to ignore the historically and
contemporary utility industry as it exists in Florida and in the
majority of other states today. Most transmission was built to connect
retail regulated generators with incumbent, franchised load areas. Even
transmission that was interconnected to other franchised utilities was
constructed first and foremost to serve native load reliably and
economically. It was not designed as an open access transmission system
to facilitate wholesale transactions. This is not an argument to allow
``undue'' discrimination on the part of vertically integrated
utilities, but a recognition of appropriate levels of priority access
to the existing grid with respect to obligations to serve, system
reliability, and allocation of system resources. These are vital areas
of state jurisdiction and are essential elements for the provision of
bundled, retail electric service.
GENERATION RESOURCE STANDARDS
Section 201(b)(1) of the Federal Power Act gives the FERC authority
over transmission facilities and wholesale sales, but specifically
excludes authority over ``facilities used for the generation of
electric energy or over facilities used in local distribution. . . .''
However, in this NOPR the FERC attempts to extend its authority to
generation resource adequacy by specifying minimum reserve margins that
must be maintained by load serving utilities and margins that will be
administered by the independent transmission provider or ITP.
While we support FERC's goal to ensure that adequate generation
resources are available in the wholesale market and recognize that
multi-state ITPs add a complexity to properly establishing such
standards, state commissions in states with integrated utilities have
had for decades the responsibility for ensuring adequate planning
reserves be maintained. In retail access states, where generation has
often been unbundled, these same commissions or other appropriate
entities such as reliability councils can set reserve requirements for
the load-serving entities that participate in regional power pools or
ITPs. There is simply no need nor authority for FERC to venture into
this area.
DEMAND RESPONSE STANDARD
The NOPR gives considerable authority to the independent
transmission provider to decide what is the appropriate treatment of
demand responsive load. Demand responsive load is load that can be
removed from the grid during periods of high prices or high demands
where generation reserves are very tight.
Florida is unique in that it has very large amounts of demand
responsive load. Due to our aggressive deployment of residential load
control devices and the use of interruptible rate tariffs for
commercial and industrial customers, some 2,700 megawatts of summer
demand and 3,634 megawatts of winter demand are used as demand side
resources in Florida. These represent 6.7 percent and 8.4 percent of
our projected 2002 summer and 2002/2003 winter total demand
respectively. These are fully dispatchable resources which are under
the control of the utility's dispatch center. All dispatchable load is
deployed under rates, terms, and conditions approved by the Florida
commission such as the duration of the interruption, the frequency, and
the time of interruption. The utilization of demand side resources such
as these must comply with all the customer tariffs and the operation of
such rates, terms, and conditions can not be legally delegated to the
ITP without the consent of the utility that offers the tariffs and the
FPSC that approves them. This does not mean that in some jurisdictions
such control may not be ceded or contracted to the ITP by utilities,
but the FERC does not have authority to order such arrangements. In
addition, I do not believe there is a good policy reason to move
authority over generation adequacy to the FERC.
The Florida commission believes that the Federal Power Act does not
convey any authority to the FERC to determine how such resources shall
be used in determining generation adequacy, how such resources shall be
used in determining operational reliability, and what is the
appropriate treatment of such resources in the operation of either day
ahead or real time energy markets.
FORMATION OF REGIONAL STATE ADVISORY COMMITTEES
We are sympathetic to the challenges confronting FERC in designing
transmission planning processes when multi-state utilities,
commissions, and other siting authorities are involved. We admit that
determining the need for, timing of, and cost responsibility for
regional system improvements under an ITP type model is a most
formidable problem. We endorse FERC's concept that some type of
regional state advisory committee should be involved. However, we
believe the processes for developing participation mechanisms for
states has not been fleshed out and a number of confounding issues must
be resolved before a formal mechanism is instituted.
We have given extensive thought to various multi-state concepts and
are mindful of the legal and administrative complications that are
associated with such entities. For example, while a formal role for
state entities is appropriate, who this will be and what specific
decision making authority they will be granted is yet to be determined.
In some areas, the multi-state regional entity may have a decisional
role instead of an advisory one. For example, FERC clearly has no
authority over the siting process for new transmission facilities, yet
in many cases such facilities may involve multiple states and multiple
state agencies who have input in the location and conditions for siting
transmission lines. In this case, then some kind of decisional process
with the attendant administrative due process safeguards would be
required.
Moreover, in the case of Florida our ability to participate in
multi-state forums may be restricted without specific statutory changes
from the Florida legislature authorizing this commission to
participate. As an alternative to establishing these new entities as
described in the rulemaking, the FERC could use its existing authority
under Section 209 of the Federal Power Act to establish a Federal/State
Joint Board similar to the joint boards instituted by the Federal
Communications Commission. These boards have proven to be an effective
vehicle to establish a collaborative process for the state commissions
with respect to the telecommunications industry.
CONCLUSION
In conclusion, the Florida Commission is in a unique situation. We
have moved to approve a peninsular Florida RTO, yet we have not
deregulated electric service and transmission remains bundled as part
of the customer's electric service. We believe our work in
collaboration with the FERC is a positive step toward creating a robust
wholesale competitive market. However, we do have major concerns that
the reach of this current FERC rulemaking jeopardizes the progress we
have made and treads on the statutory obligations of state commissions.
Thank you for this opportunity to share my thoughts with you.
______
Statement of Frederick E. John, Senior Vice President, External
Affairs, Sempra Energy
Members of the Committee, thank you for allowing Sempra Energy to
submit comments for the record of the September 17th hearing regarding
the Federal Energy Regulatory Commission's (FERC) Standard Market
Design (SMD) Notice of Proposed Rulemaking (NOPR). Sempra Energy is a
Fortune 500 energy services holding company whose subsidiaries provide
electricity and natural gas services. Sempra Energy's two California-
regulated subsidiaries are San Diego Gas & Electric Co. and Southern
California Gas Company. Together, these utilities serve a population of
nearly 21 million in southern California. Sempra Energy also owns
subsidiaries that build and own generation facilities, trade energy,
and provide energy services to end-use customers.
We commend the Committee for examining the potential impact of the
SMD NOPR upon our nation's energy markets and appreciate your
consideration of our interest in this important public policy issue. In
commenting on FERC's SMD proposal, our primary focus is on establishing
the best means of meeting the needs and expectations of end-use
customers--reliable, reasonably priced energy--and, second, on avoiding
past mistakes.
As a California-based corporation, it is particularly appropriate
that we provide comments as you consider FERC's SMD proposal to
redesign our nation's electric market. Our customers have been in the
unenviable position of being in the eye of the storm of energy
restructuring gone awry. We know what can and will happen when market
rules are unclear and poorly designed, and when infrastructure is
inadequate to meet increased and growing energy needs. Beginning in
2000, many of our customers experienced extremely volatile and
skyrocketing wholesale electric commodity prices that were the
culmination of serious supply and demand imbalances and flaws in the
market structure.
The chaos that occurred in California's energy market and
throughout the western United States during 2000 and 2001 resulted from
an inadequate infrastructure as well as market flaws and possibly some
market manipulation. The result today is a flawed and partially
deregulated market, as well as extensive market and regulatory
uncertainty that prevents and/or delays the construction of the very
infrastructure that may be necessary to prevent a future energy crisis.
Under these circumstances, our California customers are facing
potential shortages. Until clear and predictable rules are in place,
the potential for market disruption and abuse remains a significant
concern. Without clear and standardized rules, market participants can
play, unimpeded, a kind of ``regulatory arbitrage'' that compromises
market integrity and consumer confidence. To ensure workably
competitive markets and proper consumer protections--to protect
customers from extreme future price volatility, excessive prices,
potential market abuse, and threatened reliability--the balkanized
market rules that currently exist must be eliminated. The SMD proposal
offers a vital step toward achieving these important goals.
We recognize that some policymakers from our state have expressed
concern regarding FERC's proposal. Our support for SMD is not based
upon a lack of trust in their judgment or ability to regulate state
jurisdictional aspects of the electricity industry. In fact, since the
energy crisis, California has removed several restrictions that
exacerbated the flaws in the new market, including limits on the
ability of utilities to enter into long term contracts by requiring the
utilities to bid for power exclusively through the Power Exchange. The
state has also attempted to take steps to expedite siting for new
electric generation and natural gas transmission facilities. To some
extent, these efforts have helped to improve supply availability.
Nevertheless, California is not an island and, as a recent GAO Report
concludes, California historically imports about 20% of its electricity
needs from other states; the fact is that California and its energy
consumers are part of, and dependent on, a market that is far larger
than California. Despite California's reliance on imported power, and
the recognition among most who have studied the energy crisis that
infrastructure inadequacy was a primary cause of the energy crisis,
increased market and regulatory uncertainty in California has resulted
in many delays and cancellations of previously announced projects.
Without clear and uniform national energy market rules, investor
uncertainty about the energy marketplace will continue, and will result
in the absence of investment both in California and nationwide. Until
market rules are established, there is no reason to expect investor
confidence; in addition, there is a threat that this trend will
continue, and that as a nation we will slip further behind in
developing the infrastructure needed to support growing market demands.
California has learned through trial and tribulation that for
markets to work properly, competition must be fair, and all market
participants must be subject to the same rules. For a variety of
reasons, including difficulty in rationalizing the risks associated
with utility investment in new generation against the backdrop of
regulatory prudence reviews and the danger of stranded investment, loss
of choice for retail customers, and poor incentives for improvements in
the efficiency of utility-owned generation, re-regulation will not
benefit energy consumers. Competition in the nation's wholesale power
markets, under properly designed standardized rules, will improve
reliability and put downward pressure on prices because:
1. Incentives will exist to continually seek less expensive and
more efficient means of meeting the country's electricity needs,
without the artificial constraints that can result from inconsistent
rules among states;
2. The focus of market participants will not be on seeking market
opportunities based on inconsistencies among the rules of various
states, but on competing based on the effectiveness of reducing costs
through increased reliability.
The federal government has a critical role to play in helping to
create a truly competitive wholesale power market. In fact, the FERC
and Congress are the only entities that can remedy the confusing and
irregular patchwork nature of our nation's electric grid, with its
myriad rules and regulations.
At the height of the energy crisis, many (including Sempra Energy)
argued that FERC needed to intervene in the energy market to ensure
stability, reliability, and fair prices. FERC eventually stepped in and
put in place emergency measures to control the skyrocketing energy
prices in the western markets. The call for FERC intervention presented
a stark and sobering reality: while California's market rules were set
by one state, the electric grid's regional nature prevented any state
regulator from implementing a solution that would affect change from
all market participants. Ultimately, FERC was the only entity that
could address the problem.
FERC recognized, however, that its interim market mitigation
measures were not the solution to problems in California and the
western United States, but were at best stopgap measures. Consequently,
FERC mandated that the emergency measures end on September 30, 2002 and
be replaced with an improved market structure. FERC ordered the
California Independent System Operator (Cal-ISO) to propose how to
restructure itself to correct the state's market failures that caused
the energy crisis. The Cal-ISO filed its reform proposal in May 2002.
As a result of the energy crisis in California and the fate of
restructuring in other states, FERC has determined that it is now
necessary to prescribe a national policy for restructuring to ensure
fair, open and stable electric markets across the United States. We
agree. The result will be a set of rules that apply equally to all who
use the national electricity transmission ``highway'' system, increased
market certainty, increased infrastructure investment, more efficient
consumption and production decisions, and significant improvements in
deciding which power plants and additional transmission projects should
be built, and when such facilities should be placed in service. In
short, end-use customers can expect to see increased reliability and
reduced costs in a post-SMD environment.
KEYS POINTS OF THE SMD NOPR
The SMD NOPR is designed to remove the remaining impediments to
competitive electric markets begun by FERC's issuance of Orders 888 and
2000 while ensuring the existence of consumer protection measures and
promoting infrastructure investments where they will provide the
greatest benefit for consumers. Orders 888 and 2000 were designed to
create competitive wholesale electric markets and build regional
transmission structures. The SMD NOPR is intended to remove remaining
barriers to the creation of competitive wholesale power markets,
including lack of standardized tariffs and service provisions and
rules. The NOPR also includes market monitoring and market power
mitigation provisions.
The SMD NOPR will provide a standard market design for wholesale
electric markets. To ensure that all users of the national transmission
``highway'' have to play by the same set of rules, the SMD NOPR
proposes to assert jurisdiction over the transmission component of
bundled retail transactions, and modify the transmission tariff to
offer a single set of flexible transmission service rules to all
transmission customers.
From Sempra Energy's perspective, it is extremely important to
adopt a set of uniform rules across the country to provide customers
with increased reliability at reasonable prices. Not only will this
promote economic efficiency, but market certainty, where it is greatly
needed. In its proposal, FERC has appropriately focused on promoting
infrastructure adequacy; market power mitigation and market monitoring;
integrated day ahead and real time markets; a workable congestion
management model; and a single, common electric transmission structure
across the country. The beneficiaries will be electricity consumers
across the country.
Infrastructure Adequacy
Robust competition and reliability require sufficient generation
and transmission capacity. When reserves run short, the ability to keep
the lights on is compromised, and the prime objective of a utility
cannot be met. Without competition in the energy market, just and
reasonable prices cannot be ensured. In order to achieve these goals
under a market design that also includes proposed market mitigation
measures such as bid caps, the SMD NOPR focuses on the need to create
incentives for financial commitments that will support additional
construction. While FERC has demonstrated its flexibility by inviting
comments on how to develop the best long-term resource adequacy
mechanism, it is significant that FERC has initiated discussion of how
to best accomplish this goal.
A key cause of California's electric crisis was a shortage of
infrastructure, both generation and transmission. Because of problems
with siting and the uncertainty of the restructuring process in the
1990s, little generation or transmission was added in California. This
factor, combined with a severe drought in the Pacific Northwest, a
significant decrease in the availability of hydro-electric generation,
and unusually hot weather throughout much of the west, led to a
shortage of generating capacity. Even after the hot weather ended, the
shortage continued because of increased forced outage rates caused by
older, inefficient power plants that had run harder than usual and were
in desperate need of repair. Insufficient transmission capacity
exacerbated the problem. A viable reserve adequacy mechanism will go a
long way towards correcting this problem.
Recent fires in southern California demonstrate all too clearly the
critical need for additional transmission infrastructure. The fires
jeopardized electric service to that entire portion of the state,
demonstrating how razor thin the margin is between having adequate
generation and delivering it where it is needed. Many restrictions now
exist that limit the ability of utilities to site new transmission
infrastructure. To ensure that competitive markets can serve growing
demand, unnecessary impediments to the siting of new transmission
infrastructure must be eliminated.
Market Monitoring
Electricity markets are not immune from attempts at market
manipulation. FERC's SMD NOPR appropriately focuses on the need for
sufficient market monitoring mechanisms to detect when market power and
related issues arise and to resolve them before they destroy markets
and harm consumers. In addition, the combination of various elements of
FERC's proposal, including locational marginal pricing, security
constrained dispatch, congestion revenue rights, and integrated day-
ahead and real-time markets, taken together with market monitoring and
appropriate market mitigation measures, should prevent the types of
gaming described in the now infamous Enron memos.
Integrated Day Ahead and Real Time Markets
One of the key problems with California's energy markets after
restructuring was the separation within and between the day ahead and
real-time markets. For example, the Cal-ISO was prohibited from
arranging economic trades between different market participants when
there was congestion in the forward energy markets. Prior to the energy
crisis, problems were visible when prices for various ancillary
services rose higher than the energy costs. The Cal-ISO was at times
paying more for standby reserves than for spinning reserves. The Enron
memos make clear that many of its ``strategies'' were designed to take
advantage of the fact that the day-ahead market run by the Cal-PX did
not take into account transmission constraints. Enron could create
congestion within the Cal-PX market, and then get paid for relieving it
in the Cal-ISO's real time market.
The SMD NOPR makes clear that all day ahead and real time markets
need to be integrated and security constrained. This must be an
essential element of any successful market design. Under the old
structure of a vertically integrated utility in control of its own
control area, these principles were largely irrelevant because the
utility ensured that all schedules were feasible and decisions about
which units to use for what purpose were integrated, at least within
the utility's own supply portfolio. As we transition to a new market
structure, the FERC's SMD NOPR requires similar integration.
Congestion Management
Sempra Energy has long supported Locational Marginal Pricing (LMP)
as the best congestion management system that ensures all schedules are
feasible and avoids the need for subsidies. We strongly supports FERC's
adoption of LMP as an essential element of its SMD. The networks in the
northeast United States that use LMP are the success stories of
electric restructuring, while California provides a glaring example of
what can occur if a congestion management system attempts to take a
short-cut by adopting only a zonal type of congestion management. LMP
provides the best signal for identifying what types of additional
infrastructure are most needed and where it should be added, as well as
what additional infrastructure will provide the greatest benefit to
consumers. As infrastructure needs are met in the future, customers
will benefit greatly if investments are made in an optimal manner. The
Cal-ISO is trying to implement an LMP system as part of its Market
Design 2002 process. At the same time PJM, a system that uses LMP, is
finding that many utilities want to join its market.
Single National Electric Transmission Structure
During California's energy crisis, our customers saw firsthand what
occurs when pricing structures differ among regions. The problems that
California consumers experienced during the energy crisis were
exacerbated by the generators' ability to sell electricity outside of
California at a rate far exceeding the state's wholesale price cap, to
then sell the electricity back to California at a higher rate and avoid
price caps.
The FERC's SMD NOPR requires one electric transmission market
structure for all market participants. Treating all transmission
customers equally removes discrimination within markets. As long as
bundled retail customers remain a separate category of users, it is
impossible to ensure that they are not favored by integrated utilities,
who serve them and wholesale customers. By creating similar markets in
different regions, inter-regional transactions will be simplified and a
national energy market will develop, thus maximizing efficiencies for
all electric customers.
CONCLUSION
FERC is charged with ensuring that wholesale energy prices are just
and reasonable. The Commission's policies have been the subject of
debate and criticism by some state commissions, Members of Congress,
and others for failing to provide appropriate consumer protection. Now,
FERC is taking a forceful step to correct flaws in restructuring that
inadvertently harmed consumers in California and the western United
States, and to ensure that the future electric industry restructuring
protects consumers. Under the leadership of its new Chair, FERC is
taking an appropriate and much needed step to address the patchwork
nature of our nation's electric markets by issuing the SMD NOPR.
We applaud FERC's proactive effort and believe that the SMD NOPR is
a critical first step toward repairing our nation's electric market.
FERC is the appropriate entity to assume responsibility to repair the
current market design flaws and to establish a market structure that
will ensure just and reasonable electric rates. Workable competition is
ultimately the best protection for all market participants. The SMD
NOPR takes a critical step toward ensuring a workably competitive
electric marketplace. We urge Congress to support the Commission in
this endeavor.