[Senate Hearing 107-851]
[From the U.S. Government Printing Office]



                                                        S. Hrg. 107-851

                      STANDARD MARKET DESIGN NOPR

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

                                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

                              ----------                              

                               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.
---------------------------------------------------------------------------
    * Appendixes A, B, and C have been retained in committee files.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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).
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    \6\ Pacific Northwest Electric Power Planning and Conservation Act. 
PL No. 96-501.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \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\
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    \16\ ``Presentation to NARUC Committee on Electricity.'' Mark W. 
Seetin, Vice President/Government Affairs, New York Mercantile 
Exchange. July 30, 2002.
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \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.