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85–092 PDF 2003

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

(II)

COMMITTEE ON ENERGY AND NATURAL RESOURCES

JEFF BINGAMAN, New Mexico, Chairman

DANIEL K. AKAKA, Hawaii

BYRON L. DORGAN, North Dakota

BOB GRAHAM, Florida

RON WYDEN, Oregon

TIM JOHNSON, South Dakota

MARY L. LANDRIEU, Louisiana

EVAN BAYH, Indiana

DIANNE FEINSTEIN, California

CHARLES E. SCHUMER, New York

MARIA CANTWELL, Washington

THOMAS R. CARPER, Delaware

FRANK H. MURKOWSKI, Alaska

PETE V. DOMENICI, New Mexico

DON NICKLES, Oklahoma

LARRY E. CRAIG, Idaho

BEN NIGHTHORSE CAMPBELL, Colorado

CRAIG THOMAS, Wyoming

RICHARD C. SHELBY, Alabama

CONRAD BURNS, Montana

JON KYL, Arizona

CHUCK HAGEL, Nebraska

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

(III)

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

(1)

STANDARD MARKET DESIGN NOPR

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 farreaching 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.

2

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,

3

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

4

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.

5

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.

6

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

7

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

8

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 MidAtlantic 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.

9

* Appendixes A, B, and C have been retained in committee files.

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.

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

10

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.

11

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.

12

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

13

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 indusVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00016 Fmt 6633 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
14

try, 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

15

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?

16

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——

17

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.

18

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

19

1Some 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. 2For 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.

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

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.

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

20

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 interrelated 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.

21

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

22

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 exVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00025 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
23

tended 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

24

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 costbenefit 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 perVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00027 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
25

sonal 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

26

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.

27

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

28

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

29

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.

30

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 hisVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00033 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
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tory 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 21⁄2 years have put a lot of time and

32

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

33

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.

34

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 renewVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00037 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
35

able 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

36

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

37

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 transVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00040 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
38

mission 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.

39

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:]

40

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 viVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00043 Fmt 6633 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
41

tally 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 ‘‘rolledin 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.

42

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

43

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 marketbased 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

44

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

45

1This 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.

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 halfbaked 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

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.

46

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 FERCimposed ‘‘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 loadbalancing 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

47

2FERC 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.

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 leastcost.

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).

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

48

3The 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. 4The 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). 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.

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.

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.

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).

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

49

6Pacific Northwest Electric Power Planning and Conservation Act. PL No. 96-501.

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. 8 New York v. FERC, 535 U.S. ——, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002) (last page of majority opinion) 9Senator 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.

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.

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

The U.S. Supreme Court observed that were FERC to assert such 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

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

50

10The board members are chosen from among stakeholder groups through an elaborate system laid out in the rule. 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.

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.

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

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

51

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. 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 bilateral trades, the less power in the short-term markets and the more potential for an illiquid

market and market manipulation. 14 U.S. Department of Energy. Energy Information Administration. 15See, 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.

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 shortterm, 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

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.

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.

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, bidmarket 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.

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 allocatVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00054 Fmt 6633 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
52

ing 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 freerider 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

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16 ‘‘Presentation to NARUC Committee on Electricity.’’ Mark W. Seetin, Vice President/Government Affairs, New York Mercantile Exchange. July 30, 2002. 17Many 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.

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.

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.

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.

54

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 supVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00057 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
55

porting 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, includVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00058 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
56

ing 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

57

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

58

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 reVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00061 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
59

mains 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 transmissionowning 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 implementaVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00062 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
60

tion 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

61

Organization (RTO) formation in the Midwest. However, despite initial marketopening 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 setasides 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 muchneeded 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

62

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.

63

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

64

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 marketbased 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.

65

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

66

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,

67

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.

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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?

69

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

70

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

71

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?

72

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.

73

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 exVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00076 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
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1 New York v. FERC, 122 S. Ct. 1012 (2002).

cellent 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.

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.

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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.

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

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

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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 muchneeded 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 proVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00079 Fmt 6633 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
77

posal 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

78

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

79

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 investorowned 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 marVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00082 Fmt 6633 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
80

kets—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 ‘‘FERClite.’’ 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 FERClite 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

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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

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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

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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

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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.

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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 shortterm 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.

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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 simultaVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00089 Fmt 6633 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
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* Attachments A and B have been retained in committee files.

neously 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 longterm 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 cooperativelyowned.

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.

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, longterm 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

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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

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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 investorowned 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.

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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.

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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—

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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 govVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00095 Fmt 6633 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
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* Retained in committee files.

erning 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 realtime 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.*

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

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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

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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 bypass problem, but it has rejected this approach in the SMD NOPR. We do not

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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.

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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 governmentowned utilities and electric cooperatives to FERC regulation to the same extent as

shareholder-owned utilities. While EEI commends the Senate for including a socalled ‘‘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

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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 SenVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00101 Fmt 6633 Sfmt 6602 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
99

ate’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, indepth 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.]

(101)

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.

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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 deeppocketed 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 loadserving 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

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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

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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

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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?

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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.

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(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.

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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;

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• 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?

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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 <http:/

/www.nga.org/center/divisions/1,1188,C—ISSUE—BRIEF D—4110,0. html>. MultiState 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

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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

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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 verticallyintegrated 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

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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 longterm 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

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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 enVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00117 Fmt 6601 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
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ergy 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

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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.

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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

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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 planVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00121 Fmt 6601 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
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ning 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 beVerDate 11-SEP-98 08:24 Feb 25, 2003 Jkt 000000 PO 00000 Frm 00122 Fmt 6601 Sfmt 6621 R:\DOCS\85-092 SENERGY3 PsN: SENERGY3
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lieve 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.

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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.

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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 longterm 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 dayahead 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

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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.

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