U.S. GOVERNMENT PRINTING OFFICE

WASHINGTON : 

For sale by the Superintendent of Documents, U.S. Government Printing Office

Internet: bookstore.gpo.gov Phone: toll free (866) 512–1800; DC area (202) 512–1800

Fax: (202) 512–2250 Mail: Stop SSOP, Washington, DC 20402–0001

72-516 PS 2002

PACIFIC NORTHWEST DROUGHT

MANAGEMENT AND ENERGY

AVAILABILITY

OVERSIGHT FIELD HEARING

BEFORE THE

SUBCOMMITTEE ON WATER AND POWER

OF THE

COMMITTEE ON RESOURCES

U.S. HOUSE OF REPRESENTATIVES

ONE HUNDRED SEVENTH CONGRESS

FIRST SESSION

May 19, 2001 in Tacoma, Washington

Serial No. 107-29

Printed for the use of the Committee on Resources

(

Available via the World Wide Web: http://www.access.gpo.gov/congress/house

or

Committee address: http://resourcescommittee.house.gov

(II)

COMMITTEE ON RESOURCES

JAMES V. HANSEN, Utah, Chairman

NICK J. RAHALL II, West Virginia, Ranking Democrat Member

Don Young, Alaska,

Vice Chairman

W.J. ‘‘Billy’’ Tauzin, Louisiana

Jim Saxton, New Jersey

Elton Gallegly, California

John J. Duncan, Jr., Tennessee

Joel Hefley, Colorado

Wayne T. Gilchrest, Maryland

Ken Calvert, California

Scott McInnis, Colorado

Richard W. Pombo, California

Barbara Cubin, Wyoming

George Radanovich, California

Walter B. Jones, Jr., North Carolina

Mac Thornberry, Texas

Chris Cannon, Utah

John E. Peterson, Pennsylvania

Bob Schaffer, Colorado

Jim Gibbons, Nevada

Mark E. Souder, Indiana

Greg Walden, Oregon

Michael K. Simpson, Idaho

Thomas G. Tancredo, Colorado

J.D. Hayworth, Arizona

C.L. ‘‘Butch’’ Otter, Idaho

Tom Osborne, Nebraska

Jeff Flake, Arizona

Dennis R. Rehberg, Montana

George Miller, California

Edward J. Markey, Massachusetts

Dale E. Kildee, Michigan

Peter A. DeFazio, Oregon

Eni F.H. Faleomavaega, American Samoa

Neil Abercrombie, Hawaii

Solomon P. Ortiz, Texas

Frank Pallone, Jr., New Jersey

Calvin M. Dooley, California

Robert A. Underwood, Guam

Adam Smith, Washington

Donna M. Christensen, Virgin Islands

Ron Kind, Wisconsin

Jay Inslee, Washington

Grace F. Napolitano, California

Tom Udall, New Mexico

Mark Udall, Colorado

Rush D. Holt, New Jersey

James P. McGovern, Massachusetts

Anibal Acevedo-Vila, Puerto Rico

Hilda L. Solis, California

Brad Carson, Oklahoma

Betty McCollum, Minnesota

Allen D. Freemyer, Chief of Staff

Lisa Pittman, Chief Counsel

Michael S. Twinchek, Chief Clerk

James H. Zoia, Democrat Staff Director

Jeff Petrich, Democrat Chief Counsel

SUBCOMMITTEE ON WATER AND POWER

KEN CALVERT, California, Chairman

ADAM SMITH, Washington, Ranking Democrat Member

Richard W. Pombo, California

George Radanovich, California

Greg Walden, Oregon,

Vice Chairman

Michael K. Simpson, Idaho

J.D. Hayworth, Arizona

C.L. ‘‘Butch’’ Otter, Idaho

Tom Osborne, Nebraska

Jeff Flake, Arizona

George Miller, California

Peter A. DeFazio, Oregon

Calvin M. Dooley, California

Grace F. Napolitano, California

James P. McGovern, Massachusetts

Hilda L. Solis, California

Brad Carson, Oklahoma

(III)

CONTENTS

Page

Hearing held on May 19, 2001 ............................................................................... 1

Statement of Members:

Calvert, Hon. Ken, a Representative in Congress from the State of

California ....................................................................................................... 1

DeFazio, Hon. Peter, a Representative in Congress from the State of

Oregon ............................................................................................................ 3

Larsen, Hon. Rick, a Representative in Congress from the State of

Washington .................................................................................................... 4

Smith, Hon. Adam, a Representative in Congress from the State of

Washington .................................................................................................... 2

Statement of Witnesses:

Anderson, Dr. James, Associate Professor, Fisheries Sciences, University

of Washington ............................................................................................... 81

Prepared statement of ............................................................................... 82

Karier, Dr. Thomas, Power Committee Chairman, Northwest Power

Planning Council ........................................................................................... 38

Prepared statement of ............................................................................... 40

Klein, Stephen J., Superintendent, Tacoma Power ....................................... 23

Prepared statement of ............................................................................... 25

Lepp, Ray, Vice President and General Manager, Western Region,

Birmingham Steel Corporation .................................................................... 78

Prepared statement of ............................................................................... 79

Patton, Sara, Executive Director, NW Energy Coalition .............................. 55

Prepared statement of ............................................................................... 58

Settler, Randy, Secretary, Columbia River Inter-Tribal Fish Commission . 30

Prepared statement of ............................................................................... 32

Walton, Robert G., Assistant Manager, Public Power Council ..................... 90

Prepared statement of ............................................................................... 91

Wilcox, Brett, President and CEO, Golden Northwest Aluminum, Inc. ...... 26

Prepared statement of ............................................................................... 28

Wright, Stephen J., Acting Administrator and Chief Executive Officer,

Bonneville Power Administration ................................................................ 5

Prepared statement of ............................................................................... 7

(1)

OVERSIGHT FIELD HEARING ON PACIFIC

NORTHWEST DROUGHT MANAGEMENT AND

ENERGY AVAILABILITY

Saturday, May 19, 2001

U.S. House of Representatives

Subcommittee on Water and Power

Committee on Resources

Tacoma, Washington

The Subcommittee met, pursuant to call, at 9 a.m., at the City

Council Chambers, 1st Floor of the Tacoma Municipal Building,

747 Market Street, Tacoma, Washington, Hon. Ken Calvert presiding.

STATEMENT OF HON. KEN CALVERT, A REPRESENTATIVE IN

CONGRESS FROM THE STATE OF CALIFORNIA

Mr. CALVERT. Good morning. Thank you for attending this Subcommittee hearing this morning.

First I’d like to thank all of you for having me here in this beautiful area of Tacoma, Washington. I love the Pacific Northwest. It’s

a delightful place to visit. And certainly, my good friend, Adam

Smith, has a wonderful place to represent. This region is a very

special place.

Our Subcommittee is in a unique position in this Congress to

take action on two issues that have dominated media headlines

this year and, I suspect, will continue to dominate headlines

throughout the country. That’s energy and water. Keeping the

lights on this summer and in the future is imperative as is water

for business, homes, crops, and fish. We must carefully plan to

maximize the use of our limited resources. We cannot continue to

talk about managing water resources and power resources as two

separate areas.

The Northwest is suffering from the second-worst drought in its

history. This drought affects all users of water, including businesses, residents, farmers, fish, power users who depend on water

for electricity.

We are here today to accomplish two objectives. First, to evaluate

the impacts of drought in the Pacific Northwest. The second, to explore possible solutions for the current crisis on Northwest utilities

and their customers.

2

As many of you are aware, our jurisdiction includes the Bureau

of Reclamation and the power market administrations, including

the Bonneville Power Administration.

This hearing will focus on issues pertaining to our jurisdiction.

Supposedly, we’re not going to focus on matters outside of our jurisdiction such as price caps, although I think that will probably be

brought up.

I hope our witnesses and members will respect our jurisdiction

and comment on matters that will be forwarded to us later this

year.

I look forward to hearing from the witnesses on why the region

faces the problems before us today. In addition, I would like to

have the witnesses share with us what policies over the next 10

years—over the last 10 years, I should say—have led to the problems that the region is facing today.

Responsible planning for the future means assuring adequate, reliable supplies of both water and power, even in drought years.

We’re here to search out reasonable solutions to the current situation. And I certainly look forward to hearing from the witnesses.

With that, I would like to recognize Mr. Smith, the ranking

democratic member, for any statement he may have.

STATEMENT OF HON. ADAM SMITH, A REPRESENTATIVE IN

CONGRESS FROM THE STATE OF WASHINGTON

Mr. SMITH. Thank you, Mr. Chairman.

First of all, I really want to thank Chairman Calvert for holding

this hearing out—well, not technically in my district—close enough

to my district—and certainly in the Pacific Northwest.

And I think one of the biggest goals I have from this hearing is

to draw attention to the nature of the problem in the Pacific Northwest.

One of my frustrations—and I’m sure it’s a frustration for my

colleagues from the region—nationwide, people don’t really seem to

be aware of the full extent of the problem we’re having with our

electricity and energy crisis in the Pacific Northwest.

To the extent they are aware of it at all, they are aware that it’s

a problem in California. That’s about it. Most of us here know it’s

a huge problem in the Pacific Northwest.

In essence, the pricing of our energy has gone up ten- and twentyfold over the last 18 months, just an incredible increase in expense. And that is combined with the drought situation to really

put us in a situation that could—has already cost us jobs and could

have a major negative impact on our economy.

There are things that we can do to deal with this. And I hope

that out of this hearing, we will get some information on how to

step forward and help to improve the situation.

Just for one example, transmission has become a major issue.

We’re not able to get the power that we have where we need it.

What can we do to improve that situation?

We really need to have a full-scale, 100 percent focus on the energy crisis that is facing the Pacific Northwest as well as the West

Coast in general.

I’m hopeful that out of this hearing, we will learn more about the

situation and draw more attention to it and, hopefully, get policy

3

makers at FERC and in Congress to step up to the problem and

start coming up with solutions. We cannot afford to have power at

the price it is currently at for too much longer. The impact on the

economy would be devastating.

So I’m hoping we will learn a great deal at this hearing and also

get some of the attention we need to push policy makers to make

the decisions that need to be made to help us deal with this crisis.

It is the No. 1 issue.

I—in my career, I have not seen an issue go from being something people weren’t even concerned about to being the top issue

as quickly as this one has. Literally 2 years ago, nobody was talking about it; right now, it’s the No. 1 issue in the region. It affects

jobs; it affects consumers. It dramatically affects the overall economy. So I hope we will focus—give it the focus and attention that

it deserves, which our constituents out here desperately need us to

do.

With that, I will thank Mr. Calvert.

Mr. CALVERT. Thank you.

Gentlemen, any brief open statements before we recognize the

panel?

Mr. DeFazio?

STATEMENT OF HON. PETER A. DeFAZIO, A REPRESENTATIVE

IN CONGRESS FROM THE STATE OF OREGON

Mr. DEFAZIO. Thank you, Mr. Chairman.

Mr. Chairman, I’d say there are two things that bring us here.

One is an act of God, which is the drought—although it may be

human related due to global warming. We don’t really know—but

secondly, an act of Congress.

In the 1992 Energy Act—I was a conferee on that act. I was one

of two conferees to oppose the legislation and one of a very few

members of the House to oppose the legislation which provided the

authorization for deregulation of wholesale generation and transmission and deregulation of state retail electricity. It was a mistake at the time, and I told people it was a mistake; it would never

work; it is nonsensical.

The most reliable, most affordable energy in the entire capitalist,

industrial world, and now we have a system in the West that more

resembles that of India or some other, impoverished, struggling, developing nation, all because of the ’92 act.

The ’92 Act caused BPA to abandon conservation and renewables. The then administrator said he couldn’t afford them because

of coming deregulation. The deregulation is what led to the lack of

investment in generation because of the uncertainties created in

the market. And the deregulation has led to a power crisis that nobody can afford.

So, I’m hopeful that the Committee will exert, substantially, its

jurisdiction in these areas to review deregulation and review the

looming deregulation of transmission because, quite frankly, the

way that the Federal Energy Regulatory Commission is heading

with their mandate for a West-wide RTO or a Northwest RTO will

create a California every day on the transmission system for five

to 7 years until we clean up the 40 congestion points already identified. We don’t need a market to tell us where the choke points

4

are in the transmission system. An engineer can tell us where they

are. We know where they are. And if we deregulate that transmission with a market-based mechanism, which is being advocated

by FERC, with a substantial end of the jurisdiction with this Committee for the Federal components without first upgrading it, we

will be causing worse devastation in the power market than has already been caused.

And I don’t like what I see now, because we’ve set Northwesterners one against another because we’re all trying to get in a lifeboat here, and we don’t need to be getting into a lifeboat.

Yes, the drought is a problem, but if wholesale power were affordable, we could get through it without anywhere near the pain

we’re seeing.

I hope, Mr. Chairman, that we do exert our authority. This is

just a kick-off hearing for further investigation of these matters.

Thank you.

Mr. CALVERT. Thank you.

Mr. Larsen?

STATEMENT OF HON. RICK LARSEN, A REPRESENTATIVE IN

CONGRESS FROM THE STATE OF WASHINGTON

Mr. LARSEN. Mr. Chairman, thank you very much for being willing to hold this field hearing here in the Northwest to talk about

an issue that’s very important to us.

I want to thank the ranking member, Adam Smith, as well for

his efforts, and welcome Mr. DeFazio, as well, to Washington state.

I represent Washington state’s second district, which is in the

Northwest corner of the state. And in many ways, the district is

a microcosm of the—the lifeboat that Mr. DeFazio mentioned.

I have an aluminum company, a DSI; I have the largest public

utility in the state, in my district; a large private utility; and a

rural electrical co-op, all struggling under the crisis that we face

here in the Northwest.

It’s been said that this crisis is sort of our ‘‘perfect storm’’ of energy, seemingly impossible events happening seemingly impossibly

at the same time: the drought, increased demand, and deregulation

efforts in California, all contributing to what we’re facing here in

the Northwest.

And 7 percent of the country’s electricity is generated by hydropower; 75 percent or so of Washington state’s electricity is generated by hydropower, so we are very dependent on what happens

in our skies in terms of rain.

Energy is the basis of our economic engine. So what we face here

now is uncertainty and uncertainty even for our utilities.

This morning in the local paper, there is an article about Snohomish County PUD, which is the largest public utility in the state.

The headline questions cloud—PUD’s planning; the evolving energy

crisis makes it hard for Snohomish County’s utilities to look ahead.

That uncertainty only adds uncertainty to the rate payers and

homeowners in the Northwest. And we certainly need to take a

hard look at what kinds of actions that we can take in Congress

to ensure that we bring certainty back to a very uncertain market.

5

Thank you very much, Chairman Calvert, for holding this field

hearing here in the Northwest. I appreciate the attention that

you’re providing this issue.

Mr. CALVERT. Thank you, gentlemen.

Our first panel member this morning is Mr. Stephen Wright, the

Acting Administrator for the Bonneville Power Administration.

He’s accompanied by Mr. Kenneth Pedde, the Acting Pacific Northwest Regional Director, Bureau of Reclamation; and General Carl

A. Strock, U.S. Army Commander Division Engineer, U.S. Corps of

Engineers.

Welcome, gentlemen.

Mr. Wright, you can begin.

We have a series of lights. We attempt to keep our testimony

down to 5 minutes, so we often have plenty of time for questions.

With that, you may begin your testimony.

STATEMENT OF STEPHEN WRIGHT, ACTING ADMINISTRATOR,

BONNEVILLE POWER ADMINISTRATION, ACCOMPANIED BY

KENNETH PEDDE, ACTING PACIFIC NORTHWEST REGIONAL

DIRECTOR, BUREAU OF RECLAMATION; AND CARL A.

STROCK, GENERAL, U.S. ARMY COMMANDER DIVISION ENGINEER, U.S. CORPS OF ENGINEERS

Mr. WRIGHT. Thank you. I will talk very quickly, to make sure

that I use all of my 5 minutes wisely.

Thank you for the opportunity to appear today, Mr. Chairman.

I appreciate the fact you have taken the time to come out here.

While the nation’s attention has been focused on California, the

Northwest is also facing a severe energy crisis that threatens both

our economy and our environment.

We as a region are heavily dependent on low-cost electricity.

Sixty percent of the electricity in this region is produced by hydropower. The national average is only 15 percent.

So, we depend a great deal on hydropower, and consequently, the

problems that we confront are as a result of that dependence.

We have a lack of supply, due to increasing demand. We have

a near-record drought, the second worst water year in 70 years of

record. And also we have, the troubled transition to deregulation

in California, causing problems for us as well. All of these factors

put together have created a calamity for the Pacific Northwest.

If I could, I would like to describe three time-frames for you: near

term, mid term, and long term.

In the near term, the situation is dominated by issues associated

with the drought. High wholesale prices, along with the secondworst water year on record have created incredible electricity prices

and difficulty in meeting our loads.

Normally, we count on imports from California in a situation like

this. Because of the troubled transition to deregulation in California, we have not had those supplies available to us, or when

they are available, they’re available at incredibly high prices.

In order to deal with this, we have initiated a set of extraordinary measures to make sure that we can keep the lights on in

the Northwest and reduce our costs. We have bought down industrial and agricultural loads. As a result we have reduced loads by

6

more than 2,000 megawatts. In addition, the entire aluminum industry in this region will not operate this summer.

We have also bought out more than 100,000 acres of irrigated

land in the central part of Washington.

In addition we have authority in the biological opinion, to declare

a power emergency and run the hydrosystem harder. I have done

that, four times, in January, February, and again starting on April

3rd.

And we continue to operate in a power system emergency today.

The authority under the biological opinion allows us to increase energy supply, but it does hurt our efforts to recover salmon.

We have, in addition, accelerated conservation programs in the

region. Our belief is that these measures have kept the lights on

in the region. Absent those activities, we don’t believe we could

have met the loads.

We have also created financial stability for the agency so that we

can cover our costs and repay the investments that the U.S. taxpayers have in the Northwest hydro system.

In the mid term, we are confronted with a significant problem:

the size of our rate increase next year. Our current rates end on

September 30th. New rates that go into effect on October 1.

We have new power sales contracts that go into effect on that

day as well, so we cannot just roll over the rates because the new

contracts have new products and services.

The contracts that we signed last year, taking effect on October

1, reflect 11,000 megawatts of load. We have only 8,000 megawatts

of resources.

Under the Northwest Power Act, we have an obligation to serve.

Those who want to place their load on Bonneville have a right to

do so, and we are required to purchase the power to serve that

load.

In today’s market, purchasing that power would cost more than $4 billion. We are a $2.2-billion-dollar-a-year operation. Consequently, what we are looking at is the potential for a 250 percent

rate increase.

We have sought to learn from the problems in California to address our problems. Number one, we’re trying to get out of the

wholesale power market so that we do not have to purchase the $4

billion worth of energy.

If, however, we are unsuccessful with that, our view is that we

must raise the rates. And the reason for that is, because what we

saw in California was when the rates were outrageous, it created

a credit problem. And when you start with a fundamental supplyand-demand problem and then you throw a credit problem on top

of that, what you tend to do is take supply out of the market,

which drives the prices even higher.

So, our view is we are going to do everything we can to get out

of the wholesale market. But if we are unsuccessful, we will then

raise the rates.

We have embarked on a program focused on the following principles. We’ve asked our utility customers to reduce their loads by

10 percent. We’ve asked our direct service industrial customers

who could not operate profitably with a 250 percent rate increase

to shut down for up to 2 years. We would pay the companies to pay

7

their workers, helping to assure that those folks would not be

working would not be harmed by this. Moreover, we sought to lessen the impact on local communities. If workers are paid, they have

money in their pockets to buy gas and groceries. And the secondary

impact to communities should be lessened.

We’re having excellent discussions with all of our customer

groups. We expect this to be difficult, but we expect it to be successful. In that regard, we announced this week our first major

agreement with ALCOA. They have agreed to shut down for up to

2 years at a price where their workers will be paid for the entire

time that they are shut down. In addition, they agreed to continue

to pay their state and local taxes, which should lessen the impact

on the community.

For the long term, again, the fundamental problem is supply and

demand. However, we have a good signal concerning what’s going

on in this region. Bonneville, as the major transmission provider in

the region, is now seeing 28,000 megawatts of potential resources

developed in this region. We will probably need 3,000 to 5,000

megawatts. Not all of that 28,000 megawatts is real, but we are

going in the right direction.

In addition, we have more than 2,000 megawatts on-line next

winter that was not on-line this year. And if our load reduction effort succeeds in taking an additional 2,000 megawatts of demand

away, we have potentially brought supply and demand into greater

balance by 4,000 megawatts.

We have seen some softening in long-term wholesale price markets just in the last couple of weeks. That’s a good signal. We think

it’s a result of what’s going on in the generation and demand markets.

We need infrastructure. We need generation. We need transmission. We need conservation. We need gas pipeline capacity and

storage.

In conclusion, we are faced with enormous problems that will impact both people and fish in this region. We think that by working

together we can reduce the size of those impacts.

I’ve been impressed by the willingness of the people in the Northwest to work together in this time of crisis. We’ve had a tremendous amount of support for the efforts that we have undertaken.

I see light at the end of the tunnel, but unfortunately, it is going

to take some time.

Mr. Chairman, thank you. I also want to make certain it’s understood that we operate the Federal power system in conjunction

with our partners, the Bureau of Reclamation, and the Corps of

Engineers. We’re happy to answer any questions that the panel

may have.

Mr. CALVERT. Thank you.

[The prepared statement of Mr. Wright follows:]

Statement of Stephen J. Wright, Acting Administrator and Chief Executive

Officer, Bonneville Power Administration, U.S. Department of Energy

Mr. Chairman, distinguished members of the Subcommittee, my name is Stephen

J. Wright. I am the Acting Administrator and Chief Executive Officer, Bonneville

Power Administration (Bonneville). We appreciate this opportunity to appear today

and we thank the Subcommittee for its attention to the challenges facing the West

Coast electricity market.

8

Mr. Chairman, the Pacific Northwest is weathering an energy crisis of significant

magnitude. The combination of near-record low streamflows in the Columbia River

Basin, extraordinarily high and volatile wholesale electricity prices and an extremely tight West Coast power supply has severely challenged Bonneville’s ability

to meet its public responsibilities. Bonneville expects to meet demand this summer,

but the persistent drought could affect our ability in the longer term.

More broadly, Bonneville is very concerned about the impact of the West Coast

energy crisis on the Pacific Northwest economy, power system reliability, recovery

of endangered fish and on our own financial health. Virtually all of our focus now

is in managing through this crisis with a set of near-term and longer-term actions

designed to mitigate the impact of the West Coast energy crisis on Northwest citizens and businesses and fish. There are no easy answers here, and tradeoffs must

be made in the near term.

My testimony today will focus on the challenges we are facing and, in particular,

what we are doing to address them. Our belief is that we will be successful in dealing with these challenges to the extent that we anticipate them, address them creatively and address them head-on, and work closely with other regional stakeholders to put solutions into place. Bonneville is in the process of a formal, on-therecord hearing to establish rates, so any comments I may make today concerning

Bonneville’s rates must be very limited and based on the hearing’s evidentiary

record.

• In the near term, through the summer and into this coming winter, our biggest

challenge is preserving power system reliability and Bonneville’s financial

health, while meeting our fish enhancement responsibilities.

• At the same time, we are seeking to reduce the amount of power we must purchase in this expensive wholesale market for the next two years. Bonneville is

facing a significant increase in our load serving obligations beginning October

1, 2001, and purchasing power in this market could lead to a significant Bonneville rate increase.

• Longer term over the next two to four years we support developing new energy

infrastructure, including expanding the transmission system, bringing on new

generation from both conventional and renewable sources, and more conservation. The fundamental driver in the West Coast energy crisis is the gap between

demand and supply. Once the Pacific Northwest has new sources of supply, increased conservation, and much-needed transmission enhancements, Bonneville

believes we can expect relief from these sky-high electricity prices.

NEAR TERM: GETTING THROUGH THE DROUGHT AND PRESERVING RELIABILITY AND

FINANCIAL STABILITY

As members of this Subcommittee, you are familiar with the convergence of conditions that led to the West Coast energy crisis increasing demand, inadequate resource development and transmission infrastructure investment, and California’s restructuring. In addition, the Northwest is experiencing one of the worst droughts

on record, which has severely limited the amount of water available for hydroelectric generation. Hydro resources provide about 60 percent of the power in the

Northwest.

For decades, Bonneville has imported power from California during the winter

months when Northwest electricity demand tends to be highest. But this year, far

from being able to help the Northwest, California came looking for additional power

from us to help it cope with its frequent power emergencies. With a lack of available

supply, Bonneville was forced to declare brief power system emergencies on three

occasions this winter and an extended emergency again this spring.

In one way we were fortunate; the winter was mild, with none of the prolonged

cold snaps that have historically threatened Northwest power system reliability. But

Bonneville still had to take a series of extraordinary actions in order to keep the

lights on.

Reducing Demand and Buying Power: In order to reduce electric load and conserve water, since December Bonneville has purchased or curtailed over 3,600 megawatt-months of energy at a cost of over $500 million. In addition, we netted about

500 megawatt-months of imports from California with two-for-one energy exchanges.

These exchanges were a classic win-win solution because for every megawatt we

sent south during California’s peak-demand hours, they returned two megawatts

(MW) off-peak. Our reservoir levels are actually higher than they would have been

without the exchange. At the same time, California received the energy when it

needed it most’during peak demand hours and was able to return it during ‘‘light

load hours’’ when it actually had excess power.

9

We instituted several major new conservation and renewable energy programs,

and we accelerated the start date for others. Collectively, we expect these initiatives

to yield 215 average megawatts (aMW) of energy savings by 2006.

We are also operating a Demand Exchange program, which makes over 525 aMW

of voluntary load curtailment available to us from our large end-use consumers and

large retail loads of our utility customers during times of high-market power prices

and peak-load demand. Finally working with irrigation districts and the Bureau of

Reclamation (Reclamation), we have arranged irrigation water buybacks that are

leaving over 400,000 acre-feet of precious water back in the river this year, and are

saving or producing over 600 megawatt-months of energy this year.

Emergency Hydropower Operations: Despite poor water conditions, we must manage hydropower operations through the rest of the year to assure we can pay our

bills and maintain system reliability. The National Marine Fisheries Service

(NMFS) 2000 Biological Opinion (BiOp) acknowledges that there may not always be

enough water to meet the normal operation for optimal fish support and still have

enough power generation at the right times. When this occurs, Bonneville is expected to purchase power in the wholesale market to supplement regional supply.

However, the BiOp also anticipated that there could be circumstances when the

power grid would require extraordinary support and acknowledged that at such

times there would be curtailments in flow and spill operations designed to improve

fish survival.

Because this year is turning out to have extended periods of such circumstances,

Bonneville has taken the initiative, along with the other Federal action agencies of

the Federal Columbia River Power System (FCRPS) and with input from the Northwest states and tribes, to craft a set of emergency operating principles and an operating plan. We have agreed with NMFS and the other Federal agencies on reliability and financial criteria for declaring a power emergency.

The financial criteria are important because the Federal hydropower system provides a multitude of long-term benefits to the region. It is one of the economic engines of the region as well as the greatest source of financing for salmon recovery

over the long run. These benefits would be put at risk if we are unable to cover

our costs.

Our goal is to end this fiscal year with cash reserves sufficient to handle an anticipated sharp draw for power purchases in the first quarter of the next fiscal year

(October - December 2001), before the winter rains can replenish stream flows after

a summer drought. The California situation reinforces the importance of staying

current with costs to assure creditworthiness and, ultimately, electric system reliability.

It is important to reaffirm here that Bonneville supports the BiOp. The variations

in this year’s hydro operations are short term. The Federal action agencies are proceeding with development of long-term implementation plans, as the BiOp contemplates. Bonneville has also committed to providing funds to help offset the impacts of this year’s emergency operations. We have issued a solicitation for projects

that will 1) result in more water in the system; 2) remove more power load from

the system; or 3) directly increase returning adult fish or increase juvenile survival.

A California Strategy: Our struggle to meet power and fish needs this summer

will be complicated if California has problems meeting load, as seems more than

likely. Any help we are able to provide California must be carefully managed so as

to not compromise the Northwest situation.

We are working toward getting an agreement with California, before serious problems start, to provide California assistance without impairing Bonneville and Northwest reliability, fish enhancement, or finances. Since the FCRPS is critically short

on water, Bonneville must continue to rely on energy exchanges with California as

we have this past winter.

Regional Emergency Response Team: Last fall, Northwest utilities, agencies, and

states independently formed an Emergency Response Team (ERT). The ERT is

working effectively to anticipate potential power shortages, develop consistent public

messages and alerts, and plan concerted efforts to mitigate and manage shortages

that might occur.

California’s system of calling for voluntary actions by consumers when falling reserve levels trigger a power system emergency has routinely produced a response

of less than a two percent load reduction. In light of this, the ERT has proposed

an organized, informed and pledged curtailment system that might produce a 10–

20 percent voluntary reduction in demand over a few peak hours in a day that

would otherwise see rotating blackouts. The proposal is under active consideration.

10

REDUCE MARKET PURCHASES TO MINIMIZE RATE INCREASE

Bonneville is also facing significantly increased load serving obligations in the

next rate period (fiscal years 2002 though 2006) beginning October 1, 2001. The

price differential between the market and Bonneville power rates led our customers

to increase their purchases from us in the next rate period. When we finalized our

power sales contracts, Bonneville’s contractual obligations added up to approximately 11,000 aMW about 3,000 aMW more than our existing firm resources. Unless these obligations are reduced, we must purchase as much as 3,000 aMW in the

wholesale market.

Bonneville has already made some favorably-priced power purchases to meet this

need for the next rate period. We will also benefit from some of the conservation

efforts I have mentioned that are now going into place or will be in place within

the next couple of years.

The cost of the remaining market purchases, though, could drive Bonneville’s

rates up in the first year of the next rate period by 250 percent or more. An increase

of this magnitude would have widespread negative economic consequences. Already

we are seeing some businesses curtail operations or even close as a result of high

energy prices. With such an increase, we would surely see more businesses close

and more jobs lost. The effect could be devastating for a regional economy that is

already in a slow-down. People with lower incomes would suffer disproportionately.

And, a weak economy frequently translates into less public support for environmental protection.

The most immediate and direct way to decrease the size of Bonneville’s rate increase is quite simply to decrease the amount of power Bonneville has to buy in the

market. And, since we must file our new rates with the Federal Energy Regulatory

Commission (FERC) by the end of June 2001 to have them in effect by October 1,

2001, we have very little time to implement a strategy to accomplish this.

I have asked customers to significantly reduce their demand for power in the upcoming rate period. We are negotiating with our direct service industry (DSI) customers to stay off-line for up to two years. Almost all of the region’s aluminum

smelters are already shut down in the current drought. Bonneville is offering to pay

for the continued curtailment so the companies can cover full wages and benefits

for their employees who would work if the smelters restarted in October with Bonneville power. This is a lot of money, but it is only a tenth of what it would cost

the region’s ratepayers to buy power for these smelters. We are also asking both

our public and investor-owned utility (IOU) customers to reduce demand by up to

10 percent.

It is absolutely critical that the region be successful in this load reduction effort.

Failure would mean the loss of jobs, significant unnecessary rate increases, and a

greater risk of power blackouts this winter.

LONG TERM: DEVELOPING RESOURCES AND TRANSMISSION INFRASTRUCTURE

Bonneville is working to do its part to help meet long-term electric power challenges. We are working with developers to buy the output of planned new facilities

in the region in order to meet our firm obligations in the next rate period. Bonneville has also signed agreements with two of its DSI customers in recent months

that encourage their development of combustion turbines to help serve their aluminum plants.

Bonneville expects to make significant investments in energy-efficiency related activities over the next five years from 2002 to 2006. Our goal is to achieve at least

215 aMW of additional savings from this investment. We have included a discount

in our rate proposal for customer utilities that would accomplish conservation

through their own investment. This funding commitment includes $15 million for

low-income weatherization to be administered through the well-established fourstate/Community Action Program infrastructure. We believe this is an important

component because citizens on fixed or low incomes are hit the hardest by high-energy prices.

We are working with the U.S. Army Corps of Engineers (Corps) and the Bureau

of Reclamation on substantial investments in the efficiency and reliability of the

Federal hydro system to yield more MW and more reliable power from the same

amount of water.

Renewables are very much on our front burner. Since May 1999, we have purchased 35 MW of wind energy and 49 MW of geothermal. We have 560 MW of wind

under development. We have also just received 25 proposals for wind projects totaling 2,600 MW in response to our request for proposals for 1,000 MW of wind power.

We are also collaborating on several solar projects.

11

Building new generation will not solve the region’s power shortage unless the

power can be transmitted from where it is generated to where it is needed. The region is operating at or near its full transmission capacity. In many places, transmission paths are constrained and the transmission lines cannot carry additional

power from generation sites to load centers. The complexity of wholesale power

transactions since open access places more demands on the system. At the same

time, the market has prompted a flurry of generating resource development. Bonneville has received requests for generation integration studies for about 27,000 MW

of new generation in the Pacific Northwest.

Bonneville’s transmission system represents 75 percent of all high-voltage transmission in the Pacific Northwest. Most of this system is over 30 years old. For years,

we have boosted transmission capacity on the existing system through adding shunt

capacitors and new controls. But forecasts are for Northwest winter peak loads to

grow by 12 percent by 2008, and thousands of megawatts of new generation are

planned. Increased electric loads, the complexities of wholesale power transactions

and new generation make it clear that there must be significant investments in the

Northwest system to ensure continued reliability and to address the electric supply/

demand imbalance in the region.

CONCLUSION

Since the West Coast power crisis began to emerge, Bonneville and the other

stakeholders in the Northwest power system have done a heroic job of responding

to the challenges. There is an enormous amount of work left to do, though, and the

light at the end of the tunnel still seems too far away.

The next one or two years will be difficult, but we believe that with the actions

we have outlined, continued effort and regional cooperation can bring us through

this period with the lights on, the economy intact, and on track with the long-term

fish recovery plan.

Mr. Chairman, members of the Subcommittee, thank you for your attention. I am

available to answer any questions you have now about the Northwest drought and

Bonneville’s rate mitigation strategy.

Mr. CALVERT. Mr. Pedde?

Mr. PEDDE. We’re just here.

Mr. CALVERT. You’re just here? You don’t have any additional

testimony?

Okay. I am kind of curious. You mentioned the additional power

that’s coming on-line. You mentioned 28,000 megawatts as being

investigated in this region and you’re about 3- to 5,000 megawatts

short.

What kind of generation is that?

Mr. WRIGHT. It’s almost all natural gas fired and combustion turbine. We have a little bit of wind resource being developed. There

was some discussion about coal resources over in the eastern side

of the region in Montana and a few other things. But this is basically it.

Mr. CALVERT. Is this—are you having the same difficulties here

in the Pacific Northwest as other regions in the country on gas distribution coming into your state?

Mr. WRIGHT. Yes. We are really concerned about that. We’ve

been working with the gas industry on the need for gas pipeline

capacity, in particular.

What the gas industry has told us is that they think that they

can support, with their current pipeline capacity in this region, up

to perhaps 2,000 megawatts of new generation, although that

would compete against other uses of gas as well. We probably need

more than that.

There is some expansion that the gas industry has now committed to just in the last month. Our suspicion is that we may need

more than that.

12

Mr. CALVERT. Is most of your natural gas brought in from the

British Columbia area? Where do you get most of it?

Mr. WRIGHT. Yes, and Alberta.

Mr. CALVERT. Now, one of the key decisions that created the potential for the Bonneville rates to increase as much as 300 percent

after 2001—I guess to that degree—to what extent were the decisions made by Bonneville, and to what extent were they made by

the former Secretary of Energy?

Mr. WRIGHT. We had at least one issue that was extremely difficult for us, and that was how much service can we provide to the

aluminum industry in this region.

We had made a proposal that we would provide them with about

900 megawatts. And, it’s important to understand we have a statutory obligation to serve the public utilities and a statutory obligation to serve the investor owned utilities.

There was a statutory obligation to serve the aluminum industry,

which expires at the end of 2001—the end of this contract period.

And the question was, how much should we provide them? We offered them 900 megawatts. We had a great deal of involvement

from several folks including the Secretary, who ultimately decided

to offer them a greater amount of power. So, there was some involvement there.

Mr. CALVERT. Well, should Bonneville agree to sell 1,500

megawatts to the direct service industry?

Mr. WRIGHT. We agreed to a discussion in the region about that.

At that point in time, we believed that we could do so without

causing a rate increase to other customers. And, it was based on

the market prices at that time.

In hindsight, I would have to say that one could question that

decision, knowing where the market is today, although I don’t

think anyone at that point knew where the market was going.

Mr. CALVERT. But you were not legally compelled to do so?

Mr. WRIGHT. We were not legally compelled to do so. That’s correct.

Mr. CALVERT. Bonneville has also agreed to sell 1,000 megawatts

to investor utilities for the region.

Does Bonneville have a legal obligation to sell power to investor

owned utilities?

Mr. WRIGHT. The law is very clear that we have to give priority

access to our present customers.

There is an obligation to serve any load which the investor

owned utilities choose to place on us. And there is also a program

called the Residential Exchange Program, which provides some

benefits to residential customers and small-farm customers of the

investor owned utility. And our view is that there is an obligation

to serve there for the residential and small-farm customers.

Mr. CALVERT. Mr. Smith?

Mr. SMITH. As we look at the solutions—let’s start with the longterm side—that what we need to do—as part of this hearing and

how we got into this mess—you heard, I think, Mr. DeFazio’s comments about the 1992 Deregulation Act and the effect it did have

on the industry and the price of power.

First, I’d like for you to comment on the ’92 Act and whether or

not that sort of got us off the beam and got us to the point where

13

there was not sufficient supply developed and prices were—you

know, out of control and if we should revisit that.

Mr. WRIGHT. Well, I think we’re in the midst of a transition. Before the ’92 Act, it was fairly clear that there was an obligation to

serve on the part of the utilities and, therefore, an obligation to develop resources.

It’s sort of a combination of the ’92 Energy Policy Act and deregulation that has been occurring in individual states. It has

begun to separate that obligation to serve to make it less clear to

the utilities whether they have that responsibility and, if they don’t

have that responsibility, whether they’re going to be able to recover

their costs when acquiring resources.

As we traveled through the late ’90’s, I would say that there was

a tremendous reliance on the market to provide resources. Look, for

example, at the Bonneville Power Administration. Up until that

time, I think there was a sense that Bonneville had an obligation

to develop resources as well. The Comprehensive Review by the region’s governors and political—.

Mr. SMITH. I’m sorry to interrupt.

Why do you think the market was so pathetically slow to respond, as it turns out, to get us into this situation we’re in right

now?

Mr. WRIGHT. My sense is that we have had a supply-and-demand

problem that has been masked by the fact that we’ve had good

water in this region for the last 5 years. So prices have been relatively low. When marketers looked at this region, and they saw

the prices they didn’t see an economic payback. What they didn’t

see were the underlying fundamentals, which were that there were

real concerns with the loads and not having the resources.

Mr. SMITH. I guess what strikes me—and I’m no economic genius, despite my name—but from eight—it seems like in an incredibly short period of time, we went from the best of all possible

worlds with incredibly cheap power—in fact, as I said, when I first

came to Congress in ’97, the supposed problem Bonneville had was

the market was so low, we were concerned about not using (inaudible).

What Bonneville was concerned about was how they were going

to get people to re-up their contracts. PUD’s were publicly talking

about not wanting to do contracts with PDA’S; the power was

cheaper elsewhere. And then bam. Eighteen months later, it’s off

the charts in the other direction.

I guess as regulators—and that’s what we’re supposed to be in

Congress and what part of the BPA is supposed to be—what can

we do better to make sure we don’t have this sort of incredibly

quick turnaround? How can we regulate the market to make sure

that it’s more responsive?

Mr. WRIGHT. Well, one of the key characteristics of the commodity market is volatility. And what we’re moving from is a regulated market, which provides stability, to a commodity market,

which would be volatile.

The way to deal with volatility is by having hedging instruments

and other instruments to try and protect against volatility and

price swings.

14

And if, in fact, we as a country are going to continue on the path

toward deregulated markets, we are going to have to ensure that

customers have the access to mechanisms that will hedge against

that price volatility.

Mr. SMITH. But should we continue down that path, I guess, is

the ultimate question, given that situation and given how important electricity is, first of all?

Second of all, how difficult is it to build a power plant? I mean,

it’s not like building widgets, if you will. Okay. We need to know

who will crank them out. I mean, it takes a long time, not just for

the power plants, but to build the transmission grids as well.

I guess what I’m asking is, based on your expertise in the area,

is the electricity market one that is going to benefit from the typical free-market competition given those limitations that we talked

about? That’s ultimately—should we continue down that path, or

should we go back?

Mr. WRIGHT. There clearly are some benefits that can be derived

from a competitive, full, subpower supply market. We saw it in

1995 and ’96. When there was excess supply, prices dropped below

Bonneville’s rate. It was an incredible period. In fact, people were

sharpening their pencils, and there was some benefit from that.

We have now seen the opposite side of that equation, which is

when there’s not enough supply, then prices go so high, that more

than offsets the benefits that were derived from the ’95-’96 period.

The challenge here, I believe, and has always been, we have to

make sure that supplies are at least close to, and in some cases,

oversupplying the market. And we have to assure that as we develop these markets, that we can at least get the 15 percent reserve market that we became accustomed to in the overregulated

market, because after that, you have less of a reliability and you

have much higher costs.

But can we craft policies that lead to a 15 percent or better reserve market? That’s how you get to higher reliability and lower

prices for consumers.

Mr. SMITH. We’re almost out of time. I want to ask you one question on the short-term side of the equation.

You are right, from a statutory standpoint, an obligation to serve

the DSIS expires this year. But does have a rather—an impact,

particularly on the aluminum industry—there are a couple of exceptions—in terms of their ability to stay in business. And there

are a lot of concerns that—you know, just paying them for 2 years

to sort of keep that it may not work for all the companies. I know

we just signed an agreement with ALCOA, I believe it is.

I guess the question is, in the short term, what you’re trying to

do is reduce the amount of—of power that’s consumed so that

you’re not as vulnerable in the wholesale market. That’s absolutely

what you have to do. But the consequences of that can be pretty

severe, you will see. You’re negotiating new contracts, and maybe

we can come out of it okay.

But short of simply trying to cut off the amount of power that

is used, in the short term, isn’t the only option that we really have,

to try to go to some cost-based pricing scheme to get that wholesale

market that you have been more exposed to than you would like,

15

given the lack of rain, under control? How else can you do it, and

would there be that big of a negative circumstance?

I mean, you can look at the market right now for wholesale

power. It is not a fair market today. It’s not like price caps are

going to come in here and mess up a perfect market. I mean, it has

been out of whack for quite a while. There is not the sort of free

choice and free competition that the open market contemplated.

Isn’t that something that we have to consider rather than having

you go around trying to cut off as many people as possible to keep

from being exposed to that market?

Mr. WRIGHT. Well, our view is that first of all, the fundamental

problem here is supply and demand. And, by taking these actions,

what we’re doing is reducing demand. I think your key questions

are what does it mean for industry and the region, and are we

headed toward shutting down the aluminum industry long term?

We are trying to be very careful and cautious about the way we do

that so that it does not get us to that position.

Our view is that—the way we are structuring our rates, they will

track the market, and as the market prices come down, we will be

able to take advantage of that. Therefore, we think we would be

able to within a couple of years—offer rates that would allow the

aluminum companies to operate profitably within this region.

In the interim, by paying the workers, we think it allows them

to retain a semblance of a work force so that they will be able to

come back up. There’ll be a work force, a hugely trained work force,

that remains available to them.

In trying to think that through, the actions we need to take to

assure that this is not—as someone once said, ‘‘This is not the execution of the aluminum industry; this is a hibernation period’’—

that it leads to lower costs for all consumers and more jobs in the

Northwest.

Mr. CALVERT. Before I ask Mr. DeFazio—let me ask a quick

question.

The fact—what we were discussing earlier—obviously, this summer, we have a problem. We have a ser-—we have problem. Obviously, in my hometown, when the lights went off yesterday, we had

a problem throughout—throughout—(inaudible)—and—talk about

the market. And I’m going back to the 28,000 megawatts you mentioned that the people talk about building right now.

And I know talk is one thing and actual execution is another.

But if a third of those megawatts came on-line over the next couple

of years—and you can’t predict rain—nobody in this room can—but

if you get back to normal rainfall in a relatively short period of

time, a year to 2 years, you could have a situation where you have

much more than the excess of the 15 percent reserve capacity

you’re talking about; isn’t that correct?

Mr. WRIGHT. I think that is possible. I think there is a good shot

of that happening. Part of the question here, Mr. Chairman, to be

honest, is, what’s going to happen in California? This has been the

great unknown for us. We could get those kinds of reserve margins

for the Northwest, but it could all end up going to California.

And I think one of the great frustrations—to be candid about it—

is the amount of resources that’s off-line in California. This is a

16

confounding factor in trying to figure out what we need to do in

the Northwest.

Mr. CALVERT. And I understand that like—I don’t know if I do

understand the problem.

Mr. DeFazio?

Mr. DEFAZIO. Thank you, Mr. Chairman.

The way the conversation has been going, I think I have to go

to transmission first because of the point that Mr. Wright has

raised about the possibility of the ability to build resources in this

part of the country serving California. I guess it raises two questions.

One is, we might build more than the reserve, but in a market

where you have severed the duty to serve—and the duty is only to

the stockholder or, to maximize profit—it doesn’t mean that that

20 percent margin is—if it was built—is even available on a day

when we need it, or it might be wanting to sell outside the region

when we need it; isn’t that correct?

Mr. WRIGHT. That’s correct.

Mr. DEFAZIO. So basically, we’re headed toward unpredictable reliability and/or price volatility no matter what. The volatility may

be on the down side. There may be a whole bunch of people out

there building a plant today thinking they’re going to get rich.

Looking at the market, they’re going to find out suddenly it’s

tanked; right? I mean, it can go either way?

Mr. WRIGHT. Again, I think price volatility is integral to the commodity market, and there are ways to protect against price volatility.

Mr. DEFAZIO. Well, there’s catches, I’m sure, and all those wonderful things. But then beyond that, the issue also becomes reliability. No matter how much margin we have or excess capacity we

build, if they don’t have to run those plants—which, in a deregulated market, they don’t—it’s my plant. I don’t want to run it. Isn’t

that correct?

I mean, that—we could have 100 percent access, and we could

still have the lights go out because on that day, only 9 percent of

the supply was available because the other 110 percent just didn’t

want to generate. They didn’t think the price was high. Isn’t that

correct?

Mr. WRIGHT. Merchant plant operators have the ability to control

the operation of their plants.

Mr. DEFAZIO. Right. So this is the future. This is great.

Then on the issue of your purchases, you said, ‘‘$4 billion to purchase.’’ what are you assuming per megawatt hour? I mean, if you

come up with $4 billion.

Mr. WRIGHT. It’s in the range of 225.

Mr. DEFAZIO. 225?

Mr. WRIGHT. 225.

Mr. DEFAZIO. And what was—two years ago, what was the—the

price for those sorts of purchases?

Mr. WRIGHT. It would probably be in the range of about 28.

Mr. DEFAZIO. Okay. So basically, eight times the price in the

wholesale market today to replace the power?

Mr. WRIGHT. Yes.

17

Mr. DEFAZIO. So we could safely say if we were in a drought, in

the markets of 2 years ago, we could afford enough energy to meet

all of the BPA’s contractual commitments, including the aluminum

companies, with a modest rate increase?

Mr. WRIGHT. Yes. Actually in May of last year we thought we

could do it with no rate increase.

Mr. DEFAZIO. No rate increase? But that was assuming that you

can buy replacement power cheaper than even 2 years ago?

Mr. WRIGHT. Actually, yes. We thought we could serve all of the

loads that we had at that time. Part of the problem here is that

the price has gone up incredibly. We have a lower amount of load

so that there is an interaction between the amount of load placed

on us and price.

Mr. DEFAZIO. And in fact, in the next 5 years, you might see a

bunch more people coming to BPA?

Mr. WRIGHT. If prices stay as high as they are, I’d expect it.

Mr. DEFAZIO. I had a conversation with a gentleman last night

who told me that the Port of Seattle has formed some sort of public

utility district and will be placing load on the BPA in 5 years?

Mr. WRIGHT. It is my understanding it will.

Mr. DEFAZIO. And so it will end up paying the state of Oregon

for a municipal—overtook PGE, which is for sale—then you would

have some other additional load.

Mr. WRIGHT. Some Members of Congress, I’ve heard, have suggested—yes. Actually, I think that—that is—I mean, if they are a

public utility, they have preference. And so by statute, we are required to serve them.

Mr. DEFAZIO. So given that and given the volatility of the markets and the safe haven the BPA represents, are either the publics

themselves or BPA looking at that 5-year to 10-year rate period in

terms of basically building any generation or increasing capacity

somehow, or are you just going to depend upon and hope that the

market gets better?

Mr. WRIGHT. Is Bonneville planning to?

Mr. DEFAZIO. Well, right. Is Bonneville and/or your public customers. And are there statutory restrictions? Are there things that

you review to determine whether or not, BPA and/or the publics

could construct generation that would be more reliable and that

would run when we wanted it to run and that we could shut it

down when we wanted to shut it down and that we weren’t dependent upon the vicissitudes of the market?

Mr. WRIGHT. Well, the authorities are there for Bonneville to acquire resources if it’s the will of the region to do so. And as you

know, Mr. DeFazio, we’ve had a lot of debate about whether Bonneville ought to be doing those kinds of things.

In fact, I think we agreed in ’95 and ’96 that Bonneville should

not be acquiring resources. There are some good experiences and

some bad experiences with respect to that. So that would be a

question, I think, for the region, is this the right thing to take on?

With respect to our public utilities, they have concerns with respect to the Section 5(b) 9(c) policy.

5(b) 9(c) is a policy that Bonneville has articulated. There are

provisions of law that say Bonneville should not allow people to sell

18

their resources outside the region and then place the load on Bonneville.

It does—in some cases, discourage the re-sale by public utilities.

The way the policy is implemented, we are spending a tremendous

amount of time with our public utilities right now trying to figure

out how we can meet both of our goals.

We want to encourage resource development in the region, but

we also want to make sure that we are not encouraging existing

resources to flee the region and therefore place a greater cost on

the region.

Mr. DEFAZIO. But what if, say, those public entities would enter

into an agreement with you to sell outside the region but devote

all of the profits to constructing a plant which would be dedicated

to serving in-region loads exclusively and at the time after which

they have constructed the plant they would perhaps reach outside

the region?

I mean, this is—I note that my own (inaudible) board is making

millions of dollars in the speculative energy market at the expense

of our California friends, unfortunately, but they’re helping keep

the lights on.

This is an awfully lucrative market to tell public utilities to ignore, and I’m wondering if you enter into agreements with the aluminum industry to curtail load but pay them and have them devote

some of that resource toward building future generation, why

wouldn’t we do something similar with public utilities if we do it

with some of the aluminum plants?

Mr. WRIGHT. Well, in fact, it’s sort of how the 5(b) 9(c) discussion

is going right now, because 5(b) 9(c) would encourage utilities if

they develop a resource to offer the power within the region first

before selling it outside the region.

The difficulty for a public customer, candidly, is that they feel

like they’re exposed to the market and when they make purchases,

they’re making them at market prices and if they’re required to sell

them at cost, then they feel like they’re playing on an unlevel playing field.

So, the problem that you’re identifying, one that we are struggling with right now is, how do you create something that serves

to lower costs for Northwest consumers but doesn’t put an individual utility willing to take risks to develop resources at a competitive disadvantage?

Mr. DEFAZIO. Uh-huh. I mean, what I see potentially happening

here—I just am very pessimistic and—most industries, most people

will not tolerate an unreliable electricity supply. We don’t live in

India. So, I think that’s going to become a higher and higher fact.

I saw someone here in Tacoma, or someone had offered a server

farm in this area 100 percent or 99.99999 percent reliability for a

mere four times their normal going rate.

I don’t think homeowners are going to be willing to pay four

times as much for their bill with a guarantee that their lights won’t

go off—or businesses.

So I’m just thinking there is going to be a big rush among those

who are eligible, and perhaps among some who will become newly

eligible, to BPA in the contract period 5 years out.

19

I’m just saying we should be looking and trying to assess that

5 years out and determining whether or not you’re going to be in

the resource construction business, because you can be in the one

place where people know if you’ve got it, you will run it, and the

lights will stay on, and they can afford it; and everywhere else, it

will be, ‘‘Well, maybe the market will be good today, and I can afford to keep my lights on; maybe it won’t be good; or maybe they

won’t sell into the market because it’s so low and my lights will go

out.’’ That’s where we’re headed here.

Thank you.

Mr. CALVERT. Mr. Larsen?

Mr. LARSEN. Steve, thank you for coming this morning.

You mentioned that in the next couple of years—I don’t want to

put a time line on it—but you’re expecting a softening of the prices,

which—I hear you saying a lowering of the rates out there.

Have you come to the conclusion about what that rate might soften to?

Mr. WRIGHT. Well, Mr. Larsen, I have to say that our ability to

forecast these markets, our track record on that is not that great.

I have to say that anything I say here, you have to take with a

large grain of salt.

But having said that, our hope is that we can get to a rate that

will be attractive to the industry and the Northwest, and that we

can get there within a couple of years.

What we are shooting for is a 100 percent rate increase for this

fall. We see this fall as being the worst period.

Mr. LARSEN. It’s related to my next question, because we are able

to negotiate a—Woods, Woods, and Talco, the ALCOA copper plant

in Ferndale—I think one element of that package was every 6

months, you’ll be reviewing with ALCOA what the rate is out there

and whether or not that rate is going to be economically feasible

for ALCOA to get the plant actually running again.

In other words, half the job is done. There are wages and benefits for the workers. The other half is now getting people back to

work.

And the question I have is, are you—are you specifically looking

at what it would take to address getting the—the aluminum plant

or—and the other plants up and running, or is that just part of the

mix that you’re looking at? You sort of addressed it, I think, in response to—to Adam Smith’s question, but I just want to get a more

specific answer.

Are you specifically looking at that, or again, it’s just part of

the—the general environment you’re looking at?

Mr. WRIGHT. Well, it turns out that it’s not an ‘‘or.’’ it’s an ‘‘and.’’

Our goal is to get the rates as low as we can. It’s our sense that,

from our forecast of the market, that the rates can come down to

a point at which the company would be profitable to operate within

a couple of years.

So, the way I look at it is we should do everything that we can

to try to get the rates as low as we can. And we think that that

can lead to at the aluminum plants in this region operating profitably.

Mr. LARSEN. A question that’s somewhat related but I hear a lot

of, in talking with folks, has to do with the—the must-sell orders

20

that were issued late last year by the Secretary of Energy and then

continued again this administration and then ended up in February.

The concern we—that I hear is, ‘‘Are we going to be sending our

power’’—quote, ‘‘our power’’—‘‘to California this summer?′′ and usually that’s the way it worked.

Mr. WRIGHT. Uh-huh.

Mr. LARSEN. —excess power to California in the summer, excess

power to Washington in the winter. It’s gone off that track last

winter.

Under what circumstances in these criteria would the Secretary

of Energy make a decision to issue must-sell orders this summer

and send power generated to the Northwest south to California, or

anywhere else, for that matter?

Mr. WRIGHT. Well, it’s my understanding that the Secretary had

submitted an order. And our view is that we enter into a mutually

beneficial transaction with California, when it makes sense from

our system’s perspective, and also when it makes sense from their

perspective.

We have had extensive discussions with the Californians about

what types of transactions we would enter into this summer and

tried to describe to them, in fact, that we don’t have a lot of supply.

But there are things that we can do for them. The exchange

agreements that we entered into last year, were highly beneficial

for the Northwest. In fact, they were so beneficial that California

is going to renegotiate them.

Mr. LARSEN. The two for one?

Mr. WRIGHT. Yes. The two for one, actually, was based on historical differences in price between off peak and on peak. That price

differential dissolved this winter. So the two for one turned out to

be hugely beneficial for the Northwest. The Californians had wanted to renegotiate. So we’ve agreed to how we will set up an exchange agreement for the summer.

We also began to talk about what would happen if the lights go

out in California, and we’re still in a situation in the Northwest.

The biological opinion would call for us to interrupt the spill in

order to preserve reliability. And that’s not limited to the Northwest region.

So, we’ve begun to have discussions if that were to occur, concerning what sort of compensation would the Californians provide.

And what we have argued, and Californians have been accepting

of, is that there should be some environmental premium that California would pay us a premium in terms of the return.

Mr. LARSEN. This is just a comment. And it’s heartening to hear

that the secretary of (inaudible)—I’m still hearing you say there

will be some exchange this summer, and I would encourage you to

keep the delegation in the Northwest—and California delegations—

fully apprised of how it’s playing out, because we are very likely

to hear from—from constituents about any exchange that takes

place between the Northwest and any other region of the country.

Mr. WRIGHT. I appreciate that. If I could, just comment on the

exchange. I want to make sure that everyone does know that in the

exchanges we have entered into with California—California has

fully repaid the amounts we have sent down with the two for one.

21

Mr. DEFAZIO. Just on that exchange, if you’re going to exact an

environmental premium on those, if you were in a spill situation

and liability became a problem, you stopped spilling and generated

and transmitted to California, would that money go into some sort

of segregated account?

Mr. WRIGHT. Well, actually, it’s not money. It’s kilowatt hours,

and—.

Mr. DEFAZIO. So it’s kilowatt hours. Could you expand on that

just for a second?

Mr. WRIGHT. Right. It’s an exchange. What we would get is a

premium return, a kilowatt hours return. Our intent is to try to

dedicate that premium back to fish.

Mr. DEFAZIO. You would then use less water at some off-peak

time to generate, therefore conserving some water in the system,

therefore having more water to provide for flows or spill or something later for the fish; is that right?

Mr. WRIGHT. Right. And how we’re going to do the accounting on

that, we haven’t figured out. Things are moving fast.

Mr. DEFAZIO. Thank you.

Mr. CALVERT. Mr. Pedde, I guess, based upon this conversation—

obviously, we’re trying to maximize power this summer as much as

possible for this region. How is that—how is that affecting the contract orders?

Mr. PEDDE. In terms of contract water orders, not directly. Our

contract regulations switch priorities to meet those contracts. We

sell surplus power to Bonneville, provide surplus power on to Bonneville. We don’t sell to them. So in terms of meeting our contract

needs, we’re not affected at all at this time.

Mr. CALVERT. Mr. Smith?

Mr. SMITH. I have to ask this fairly basic question. I know

some—certainly constituents in California (inaudible) up here

would ask as well—it seems that we have sufficient supply capacity

to serve the needs on the western grid. If it were to all be operated,

even with the drought situation—I guess that’s the first question,

is whether or not we do.

You mentioned that there was a steady number of supplies offline in California and serving those areas and—you know, I understand within terms of setting the price, how high the price is.

But if you have a situation where people are, as we are in California right now, in a blackout situation, a situation potentially

that could come to the Northwest this winter, is there anything

that we could do as public policymakers to make sure that that

available supply is used to prevent this, and if so—I mean, why

isn’t that happening in California? Why do you have generators not

operating and the lights are going out? That seems to be a pretty

substantial failure of public policy.

Mr. WRIGHT. Mr. Smith, that is the right question, and I wish

I had a good answer for you. Two things, I’d say.

First of all, there is a supply shortfall. If you look at the peak

loads that are likely to occur on the West Coast this summer relative to the amount of supply, and if everything is running, we do

have a shortfall. So there are periods in which, even with everything running, we come up short.

22

But the shortfalls that we’re seeing this month, when we’re not

at peak loads, are a little difficult to understand. We have sought

to try to understand that there are plants down, some of them for

plant maintenance. That certainly makes sense. The Columbine

Generating Station is going down today for plant maintenance.

But there are other plants down with forced maintenance, and

it seems like a lot of that is out. And some people say it’s because

they ran the resources so hard last summer and fall, that now

we’re paying the piper. I’m trying to figure out how we get past

that problem. I think it is a critical part of trying to resolve this

problem.

Mr. SMITH. Overall—I mean, just—the big difference—since demand has gone up, supply has gone down, how much, truly, in the

western grid has demand gone up over the course of the last two

or 3 years? I’m trying to figure out, you know, where—did demand

go up 10 percent and supply dropped off? What happened? Has

supply not gone up at all? Has it dropped off? My understanding

is demand has gone up, but—2, 3, 4 percent, but not—not obnoxiously high. Can you just give us your input.

Mr. WRIGHT. I don’t have those numbers, as they’re different, on

the tip of my tongue. But I’d like to provide those for the record,

if I could, certainly on the demand side.

On the supply side, I know there has been an increase—and it

has been a substantial amount—in the Northwest, in particular.

But I think a bigger problem is that we, on a net basis, have lost

resources in this region, when we shut down the nuclear plants.

And we operate the system more now for fish, and for good reason.

We’ve added only a couple of small combustion turbines in the last

10 years.

Mr. SMITH. Thank you, Mr. Chairman.

Mr. CALVERT. Thank you.

I will say that the demand in California went up significantly in

the last 3 years, the average in the double digits, as we didn’t have

additional power generation coming on-line. And one of the problems in California is some of the contracts with some of the—some

of the plants were less than the cost of production. So that’s where

the problem is in the market right now, is attempting to get—renegotiate those contracts to get those plants back on-line.

Mr. DEFAZIO. Mr. Chairman, may I have just a moment?

Mr. CALVERT. Certainly.

Mr. DEFAZIO. I’ve quite closely followed the statistics of the California ISO’s, and your peak demand this year is less than 2 years

ago; and your consumption over the time period was up about 4

percent until this year, where it’s dropping rather precipitously;

and your peak demand is below. I’d just like to set the record

straight on that. Your demand is not up in the double digits.

Mr. CALVERT. Well, according to the statistics we have, our demand has increased significantly—a number of years, overall—.

Mr. SMITH. (Inaudible) State of California—. Mr. CALVERT. We’ll move on to—if there are no additional questions for this panel, we’ll move on to the next panel.

The second panel is Mr. Steven Klein, Superintendent of Tacoma

Public Utility; Mr. Brett Wilcox, President and CEO of Golden

Northwest Aluminum; Mr. Randy Settler, Secretary of Columbia

23

River Inter-Tribal Fish Commission; and Mr. Tom Karier, Power

Committee Chairman, Northwest Power Planning Council.

Gentlemen, thank you for attending today. We do have a—a time

light right there. When it gets to yellow, you have 1 minute remaining. You have 5 minutes for your testimony. Please try to stay

within that 5 minutes, and we’ll have time to ask any questions.

With that, Mr. Klein, you may begin.

STATEMENT OF STEVEN J. KLEIN, SUPERINTENDENT,

TACOMA POWER

Mr. KLEIN. Thank you.

Mr. Chairman and members of the Committee, the current crisis—as we’ve talked about already this morning, the situation in

the Northwest is a result of a drought of epic proportions coupled

with the failed industry restriction effort in California that destroyed the opportunity to rely upon the traditional diversity between the winter peak in the Northwest and the summer peak in

Southwest and led to a market failure that drove the price of

wholesale energy into the stratosphere.

Tacoma Power is a municipally-owned electric utility in Washington state, serving approximately 155,000 customers within a

service territory of 180 square miles.

Tacoma Power has a long legacy of conservation and power generation development over its 106-year history. We also have depended upon other contractual resources with various Northwest

entities, including the Bonneville Power Administration. At the end of the year 2000, we had cash reserves of $120 million

and had not had a retail rate increase for 6 years. Prior to that,

from 1989 to 1995, the few rate increases that we did have were

at or below the rate of inflation. We are neither a proponent nor

opponent of electricity industry deregulation. We did not fear competition and choice, because as a consumer-owned utility, we represent the ultimate demonstration of choice. We also follow a strategy that puts our customers first. And we have a legacy of innovation and exceptional cost management. This continues to deliver

high value to a loyal customer base.

But our world began to change last fall. As late as November of

2000, the National Weather Service organizations were still forecasting wet or wetter than normal weather patterns for our area.

By December, the Northwest did not yet see normal precipitation. A cold weather front was forecast and announced publicly to

hit the Northwest beginning Sunday, December 10, 2000, with the

coldest expected to fall upon the following Tuesday.

That Friday before, on December 8, we witnessed an unprecedented surge in the price of wholesale power. Tacoma Power purchased power that day at nearly $3,000 a megawatt hour.

Anticipating the impending cold front and associated high electricity demand, we attempted to buy forward for Sunday through

Wednesday but could not find a willing seller at any price.

Facing the inability to meet the forecasted low, we called upon

our large industrial customers to shut down Sunday and remain

down until further notice.

The cold snap turned out to be milder than predicted. We did

find power available on Monday; however, from that weekend until

24

today, the power market remains highly volatile, and prices are

typically eight to ten times what they were 1 year ago and certainly beyond that in—in spot circumstances.

Tacoma Power has spent over $140 million beyond our normal

level of expenditures to purchase market power. We have depleted

our once robust cash reserves and must now depend on a bank letter of credit to preserve our financial position. This is on top of the

fact that Tacoma Power was the first utility to respond to this first

stage of this crisis by raising our retail rates an average of 50 percent, effective clear back in December of last year.

This system average rate increase sent a strong price signal as

the rate increases range from 43 percent for residential class to up

to 75 percent for commercial/industrial.

Tacoma Power and the community we serve set an aggressive

goal of 20 percent conservation since January of the beginning of

this year. The cumulative conservation attained across our customer base is 13 percent and growing, with April alone at 17 percent.

Tacoma Power has also pursued other strategies to mitigate the

crisis, including temporary diesel generation. We continue to advise

our state and Federal representatives and appreciate the opportunity to testify here today.

Tacoma Power’s customers have felt the sting of the real market

price since December of last year, where some customers in California are only reading about what someday may be coming for

them.

As if a 50 percent system average rate increase were not enough,

the additional hit from a BPA rate increase projected to be as much

as 100 to 250 percent this coming October—why does the Washington, D.C., establishment continue to view the energy crisis as

only impacting California? Our citizens can understand the variability of weather but have a hard time grasping the other aspects

of this crisis.

The California restructuring originally guaranteed rate decreases

and certainty to California consumers. The California electric utilities were able to sell off generation assets for multiples of book

value. Independent power producers were allowed to enter the

wholesale market with no regulation or rules. Northwest rate payers also questioned the actions of an administration that forced the

BPA to commit power it didn’t have to provide even greater benefits to the Northwest direct service industries.

The Energy Policy Act of 1992, supposedly well intentioned—and

represented a response to an expanded global economy and the demand for competition and choice that previously led other industries to deregulation.

However, unique complexities and essential needs that electricity

serves has been greatly misunderstood and underestimated by

market idealists and reformists.

The California experiment sought to establish a ‘‘textbook market’’ and failed miserably. As a result, the citizens of California and

the Northwest will be paying higher rates for years rather than enjoying the supposed benefits of deregulation. In many ways, the

system in the Northwest, whose economy has been built upon reaVerDate 11-MAY-2000 15:39 May 07, 2002 Jkt 000000 PO 00000 Frm 00028 Fmt 6633 Sfmt 6602 J:\DOCS\72516.TXT HRESOUR2 PsN: HRESOUR2
25

sonably priced power, will suffer the most and face a future of uncertainty.

Thank you.

Mr. CALVERT. Thank you, Mr. Klein.

[The prepared statement of Mr. Klein follows:]

Statement of Steven J. Klein, Superintendent, Tacoma Power

The current crisis situation in the Northwest is the result of a drought of epic

proportions coupled with a failed industry restructuring effort in California that destroyed the opportunity to rely upon the tradition diversity between the winter

peaking Northwest and the summer peaking Southwest and also led to a market

failure that drove the price of wholesale energy into the stratosphere.

Tacoma Power is a municipally owned electric utility in Washington State serving

approximately 155,000 customers within a service territory of 180 square miles. Tacoma Power has a long legacy of power generation development over its 106-year

history and we also have depended upon other contractual sources with various

Northwest entities including the Bonneville Power Administration (BPA).

At the end of the year 2000 we had cash reserves of $120 million and had not

had a retail rate increase for six years. From 1989 to 1995, the few rate increases

we did have were at or below the rate of inflation. We were neither a proponent

nor opponent of electric industry deregulation. We did not fear competition and

choice because as a consumer-owned utility we represent the ultimate demonstration of choice. We also follow a strategy that puts our customers first and we have

a legacy of innovation and exceptional cost-management that has continued to deliver high value to a loyal customer base.

Our world began to change last fall. As late as November 2000, the national

weather service organizations were still forecasting ‘‘wet or wetter than normal

weather patterns’’ for our area. By December the Northwest had not yet seen normal precipitation. A cold weather front was forecast and announced publicly to hit

the Northwest beginning Sunday, December 10, 2000, with the coldest point expected to fall on the following Tuesday. On Friday, December 8, 2000, we witnessed

an unprecedented surge in the price of wholesale power. Tacoma Power purchased

power that day at nearly $3,000 per mWH. Anticipating the impending cold front

and associated high electric demand we attempted to buy forward for Sunday

through Wednesday and could not find a willing seller at any price. Facing the inability to meet forecasted load we called upon our large industrial customers to shut

down Sunday and remain down until further notice. The cold snap turned out to

be milder than predicted and we found power available on Monday, however, from

that weekend till today the market remains highly volatile and prices are typically

8 to 10 times what they were just one year ago.

Tacoma Power has spent over $140 million beyond our normal level of expenditures to purchase market power and we have depleted our once robust cash reserves

and must now depend upon a bank letter of credit to preserve our financial position.

This is on top of the fact that Tacoma Power was one of the first utilities to respond

to the first stages of the crisis by raising our retail rates an average of 50 percent

effective December 20, 2000. This system average rate increase sent a strong price

signal as the rate increases ranged from 43 percent for the residential class to 75

percent for commercial/industrial. Tacoma Power and the community we serve set

an aggressive goal of 20 percent conservation and since January 2001, the cumulative conservation attained across our customer base is 13 percent and growing. Tacoma Power also has pursued other strategies to mitigate the crisis including temporary diesel generation and we have advised our State and Federal representatives

and provided testimony at various hearing on the crisis.

Tacoma Power’s customers have felt the sting of the real market price signal since

December of last year, where some customers in California are only reading about

what may someday be coming for them. As if a 50 percent system average rate increase were not enough we, the addition hit from a BPA rate increase projected to

be as much as 100 to 250 percent this coming October. Why does the Washington

D.C. establishment continue to view the energy crisis as only impacting California?

Our citizens can understand the variability of weather but have a hard time

grasping the other aspects of this crisis. The California restructuring originally

guaranteed rate decreases and certainty to California consumers, the California

electric utilities were able to sell off generation assets for multiples of book value,

the independent power producers were allowed to enter the wholesale market with

no regulation or rules. Northwest ratepayers also question the actions of the adminVerDate 11-MAY-2000 15:39 May 07, 2002 Jkt 000000 PO 00000 Frm 00029 Fmt 6633 Sfmt 6621 J:\DOCS\72516.TXT HRESOUR2 PsN: HRESOUR2
26

istration that forced BPA to commit power it didn’t have to provide even greater

benefits to the northwest direct service industries.

The Energy Policy Act of 1992 was well intentioned and represented a response

to an expanded global economy and the demand for competition and choice that had

previously led other industries through deregulation. However, the unique complexities and the essential needs that electricity serves have been greatly misunderstood

and underestimated by market idealists and reformers. The California experiment

sought to establish a ‘‘text book’’ market and failed miserably. As a result, the citizens of California and the Northwest will be paying higher rates for years to come

rather than enjoying the supposed benefits of deregulation. In many ways the citizens of the northwest, whose economy has been built upon reasonably priced power

will suffer the most and face a future of uncertainty.

Mr. CALVERT. Mr. Wilcox?

STATEMENT OF BRETT WILCOX, PRESIDENT AND CEO,

GOLDEN NORTHWEST ALUMINUM, INC.

Mr. WILCOX. Thank you, Mr. Chairman.

My name is Brett Wilcox. I’m President of Golden Northwest

Aluminum Company. Golden Northwest owns and operates aluminum smelters at Goldendale, Washington, and the Dalles, Oregon. Normally, we employ 1,225 people and are one of the largest

employers in Eastern Washington and Eastern Oregon. We are

committed to saving these family wage jobs and continuing to anchor the economy of our distressed rural communities.

Our production and employment currently are curtailed. The

Bonneville Power Administration is remarketing the power we had

under our contract. Each DSI’s contract rights and marketing

agreements are different.

Under our company’s particular agreement, our employees receive full wages and benefits. Bonneville received over 100—we’ve

received $100 million in cash to invest with other customers. In a

pact with Bonneville United Steel Workers Union, we’ve committed

our remaining marketing proceeds to help save our smelter operations by developing new Northwest power projects, including a

very significant amount of wind power generation.

Mr. Chairman, your invitation asks that I testify about tiered

rates. This is a rate form I proposed to Bonneville to reduce demand during the current power supply crisis. Tiered rates reflect

the reality of the market. The buying of the next increment of additional power costs a lot, and reducing consumption of the margin

saves a lot. If power consumers receive this ‘‘price signal’’ in their

rates, then less power will be used; less will be needed; less will

be purchased at higher prices.

Consumers do not have to reduce their consumption—consumers

do not have to reduce their consumption by the full amount of the

higher-priced tier to receive the benefits of tiered rates.

Experience in Great Britain indicates when the power reserves

are critical, the reduction and consumption by only at one and a

half percent can reduce market prices by up to 25 percent.

Tiered rates are one of the best ways to lower high power prices.

All consumers benefit, whether or not they can reduce their own

demand.

I still believe that, objectively speaking, tiered rates are the single-most appropriate ‘‘demand-side’’ policy to encourage conservation and efficiency and help reduce power prices.

27

Realistically, however, I recognize that politics and confusion and

fears have made it virtually impossible, as a practical matter, for

Bonneville to adopt tiered rates for its DSI customers.

I won’t waste the Subcommittee’s time by beating a dead horse.

Please note, however, that leaving aside the DSI’s, tiered rates still

make sense for Bonneville’s other customers.

If the utilities pay tiered rates, their customers will soon pay

some variant at the retail level. Conservation and efficiency will

improve, and consumption and power prices will be lower.

Without DSI’s as an issue, I hope Bonneville, its utility customers, the region, and Congress will recognize that appropriate

price signals for changes in demand are critical to managing the

demand side of the supply-demand equation.

Rather than reduce the demand with price signals, Bonneville’s

trying to reduce demand among its aluminum—and some nonaluminum—companies by asking them to extend their curtailments

for up to 2 years beyond the curtailments now scheduled to end in

September.

While our loads have not grown and have not contributed to the

current energy shortage, our company would like to be part of the

solution to the power crisis.

We are willing to agree to some extent of curtailment but only

under terms that are fair to our workers and our company that

give us a reasonable assurance we will be able to resume operations when the current crisis ends.

Different aluminum companies are so differently situated that

fairness cannot result if Bonneville pursues a ‘‘one size fits all’’ approach to extended curtailments. For example, our company shared

its power marketing proceeds with its employees and Bonneville

and is using the remaining funds for new power plants to save its

smelters and their jobs. No other aluminum company agreed to do

that.

Second, each company’s cost of ‘‘hibernating’’ for an extended period is different. In addition to continued employee costs, we have

other continuing fixed costs from not operating. These costs vary

widely from company to company.

We have, and will share, our cost information with Bonneville

and allow Bonneville to verify our actual ‘‘hibernation’’ costs. We do

object, however, to Bonneville paying us less than anything but the

full amount of our company’s actual costs. We are willing to help

in this crisis, but we can’t do so in a way that doesn’t cover our

costs and therefore threatens our survival.

My company’s smelters were built with Federal encouragement

at the sites of two dams, neither of which would have been built

without these smelter loads to use the power. In a few years, the

ever-growing loads of Northwest utilities will push us off the Federal system entirely.

The bell does not toll only for aluminum smelters. Over half of

all electric power in the Northwest is used by industry and agriculture. Low power prices have traditionally been the significant

competitive advantage of the Northwest industry.

Without abundant and reasonably priced electric power, the

lights of factories and of farms will go out all over the Northwest.

We face a crisis of paying taxes, not just utility bills. There is a

28

very real threat that the current power crisis will deindustrialize

the Pacific Northwest.

If Bonneville, the traditional economic provider of the region, is

now going to confine its power supply to relatively few customers,

then Federal power will no longer keep the region’s economy

healthy.

The ample, reasonably priced power will have to come from new,

nonFederal projects. Bonneville has the tools to support those nonFederal projects. We encourage them to use them.

Thank you very much.

Mr. CALVERT. Thank you.

[The prepared statement of Mr. Wilcox follows:]

Statement of Brett Wilcox on Behalf of Golden Northwest Aluminum, Inc.

and Northwest Energy Development, LLC

A. Introduction

My name is Brett Wilcox. I am President and CEO of Golden Northwest Aluminum, Inc. (‘‘Golden Northwest’’). Golden Northwest owns and operates primary

aluminum smelters at Goldendale, Washington, and The Dalles, Oregon. Normally,

we employ 1,225 people. We are the largest employer in Klickitat and Wasco Counties, and among the largest employers in Eastern Washington and Eastern Oregon.

We are committed to saving these family wage jobs and continuing to anchor the

economy of our distressed rural communities.

Our production and employment are currently curtailed for lack of affordable

power. The Bonneville Power Administration is remarketing the power we had

under contract. Each direct service industry’s (‘‘DSI’’) contract rights and remarketing agreement is different. Under my company’s particular agreements, our employees receive full wages and benefits, Bonneville receives one hundred million dollars in cash that benefit its other customers, and—in pact with Bonneville and the

United Steelworkers of America—we’ve committed our remaining remarketing proceeds to help save our smelter operations by developing new Northwest power

projects, including a very significant amount of wind power.

As a result, I am testifying today not only for Golden Northwest and our employees, but also for our new power project development company, Northwest Energy

Development, LLC (‘‘Northwest Energy’’), which is developing three proposed power

projects, including our wind projects. Our motto is ‘‘Northwest power for Northwest

jobs.’’ It’s a motto we hope will become that of Bonneville and the entire Pacific

Northwest, working and cooperating together as a region.

B. Tiered Rates

The Chairman asked that I testify about ‘‘tiered rates.’’ This is a rate form I proposed to Bonneville to reduce demand during the current power supply crisis. Tiered

rates reflect the reality of the market: that buying the next increment of additional

power costs a lot; and reducing consumption at the margin saves a lot. If power consumers receive this ‘‘price signal’’ in their rates, then less power will be used, less

will be needed, less will be purchased at high prices, and average power costs will

be lower.

Consumers do not have to reduce their consumption by the full amount of the

higher priced tier of power to benefit from tiered rates. Experience in Great Britain

indicates that, when power reserves are critical, a reduction in consumption by

11⁄2% can reduce market prices by up to 25%. A recent study for the Electric Power

Research Institute suggests that the top 10% of demand is responsible for 50% of

price peaks. Tiered rates are the best way to lower high power prices. All consumers

benefit, whether or not they can reduce their own demand.

I still believe that, objectively speaking, tiered rates are the single most appropriate ‘‘demand-side’’ policy to encourage conservation and efficiency, and help reduce power prices and rates during the current crisis. Realistically, however, I recognize that politics, confusion and fears (perhaps the politics of confusion and fears)

have now made it virtually impossible, as a practical matter, for Bonneville to adopt

tiered rates for its DSI customers. I won’t waste the Subcommittee’s time beating

a dead horse. Something different must be done regarding the DSIs and Golden

Northwest.

Please note, however, that leaving aside the DSIs, tiered rates still make sense

for Bonneville’s utility customers. If utilities pay tiered rates, their customers will

29

soon pay some variant at the retail level. Conservation and efficiency will improve,

and consumption and power prices will be lower as a result. Without DSIs as an

issue, I hope Bonneville, its utility customers, the region, and Congress will recognize that appropriate price signals for changes in demand are critical to managing

the demand side of the supply-demand equation.

C. Extended Curtailments of Aluminum Smelters

Rather than reduce demand with price signals, Bonneville is trying to ‘‘pick off’’

specific aluminum and non-aluminum loads and keep them shut down for a twoyear extension beyond the curtailments now scheduled to end in September.

While our loads have not grown and have not contributed to the current energy

shortage, our company would like to be part of the solution to the power crisis. We

are willing to agree to some extended curtailment, but only under terms and conditions that are fair to our workers and our company, and that give us a reasonable

assurance of being able to resume operations when the current crisis ends.

Different aluminum producers are so differently situated that fairness cannot result if Bonneville pursues a ‘‘one size fits all’’ approach to extended curtailments.

For example, Golden Northwest shared its power remarketing proceeds with its employees and Bonneville, and is using the remaining funds for new power plants to

save its smelters and their jobs. No other aluminum producer agreed to this or does

it. Second, each company’s costs of ‘‘hibernating’’ for an extended period are different. In addition to continued employee costs, we have other continuing fixed costs

from not operating. These costs vary widely from company to company.

We have and will share our cost information with Bonneville and allow BPA to

verify our actual ‘‘hibernation’’ costs. We do object, strenuously, to Bonneville paying

us anything less than the full amount of our company’s ‘‘hibernation’’ costs. We’re

willing to help in the current crisis, but we can’t do so in a way that doesn’t cover

our costs, and therefore threatens our survival.

It must be remembered, here as in the tiered rates discussion, that each

kilowatthour our smelters don’t use, and that Bonneville doesn’t have to buy, is currently very expensive. After September, my company could and would operate, and

our employees would be at work, but for our willingness to extend our curtailment

at BPA’s request. That extension will save Bonneville and its other ratepayers a

huge amount of money.

It would be fair to share the savings of extending our curtailment after October,

as we shared the benefits with BPA for remarketing before October. But we do not

ask for even that. We do insist, however, on receiving at least enough of those savings to cover our costs of producing the savings for others. That is only fair. And

it’s essential for us to remain viable during the extended curtailment.

Finally, a two-year extension of the current curtailments beyond September is

simply too long. There is no clear need for it: the forward price curve for electric

power is not a high plateau, but a line that plunges beginning next spring. In addition, a total of three years is simply too long for a smelter to be shut down. Our

employees will move on, our communities will wither, our company will die. We

should treat the current power crisis for what it is: a severe emergency of uncertain

duration, but not a permanent one.

D. Bonneville Assistance to Non–Federal Resources that Aid Northwest Jobs

My company’s smelters were built with Federal encouragement at the sites of two

Federal dams, neither of which would have been economical to build without these

smelter loads. Yet in a few years, the ever-growing loads of Northwest utilities will

have pushed us off the Federal system entirely.

The bell does not toll only for the aluminum smelters. Over half of all electric

power in the Northwest is used by industry and agriculture. Low power costs have

traditionally been the only significant competitive advantage Northwest industry

and agriculture enjoy. Wage rates are high here. Transportation costs are high.

Taxes are high. Without abundant and reasonably priced electric power, the lights

of factories and of farms will go out all over the Northwest, perhaps never to be

lit again. We face a crisis of paychecks, not just utility bills. This is a very real

threat that the current power crisis will ‘‘de-industrialize’’ the Pacific Northwest.

If Bonneville, the traditional economic driver of the region, is now going to confine

its power supplies to a relatively few favored customers, then Federal power will

no longer keep the regional economy healthy. The ample, reasonably priced power

will have to come from new, non–Federal power projects. Bonneville has the tools

to help support these new, non–Federal projects. We ask that Congress and the Administration urge Bonneville to use them.

In particular, we urge emphasis on Northwest power for Northwest jobs. Every

new power plant uses up some portion of the available infrastructure: transmission

30

capacity, pipeline capacity, water, air. It makes a huge difference to the Northwest

whether the power, or at least the financial benefits of the power, from the new

project are, or are not, dedicated to saving regional employers and employment. You

can’t tell, just by looking at a new plant, whether its power and financial benefits

flow to Northwest jobs. But you can tell by looking at its books and sales arrangements.

Bonneville’s statutory mandate under the Northwest Power Act is to ‘‘assure the

Pacific Northwest an adequate, economical, efficient, and reliable power supply.’’ The Act gives Bonneville many specific as well as broad powers to assist, stimulate,

support, provide transmission and other services to, and help finance non–Federal

power plants. Bonneville should do so. In particular, BPA can and should help customers develop new resource by providing credit support through agreements like

the Cowlitz Falls payment backup or a ‘‘financial sleeve’’ under which BPA buys

power from a new project for up to five years and agrees to resell it to the same

customer at the same cost.

BPA should support resource development particularly by traditional customers,

such as Golden Northwest, whose Bonneville power is being taken away so that it

can be sold instead to utility customers whose loads are growing and who are not

building their own new resources to meet that growth. And it should do so with an

unequivocal and unapologetic priority for those who, like Northwest Energy Development, are willing to sign on the dotted line and commit to use the power or financial benefits from the new non–Federal projects to save Northwest employers and

Northwest jobs. By actively supporting such resource development, BPA can help

turn the current power crisis into a win-win opportunity for the future of the entire

Pacific Northwest.

Thank you.

Mr. CALVERT. Mr. Settler, go ahead.

STATEMENT OF RANDY SETTLER, SECRETARY, COLUMBIA

RIVER INTER-TRIBAL FISH COMMISSION

Mr. SETTLER. Good morning, Mr. Chairman, esteemed members

of the Committee. My name is Randy Settler. I’m Secretary of the

Columbia River Inter-Tribal Fish Commission. I’m a member of the

Tribal Council of the Confederated Tribes and Bands of the

Yakama Nation and the Chairman of the Yakama Nation’s Fish

and Wildlife Committee.

I want to thank you both for the opportunity to testify before you

today and for your desire to look into this critical situation.

It is not the current water conditions standing alone that are affecting tribal resources in the Columbia River Basin. The real problem is the management decisions made and actions taken by the

Federal and state agencies in reaction to the drought. It is these

unilateral decisions and actions that are putting the long-term viability of the salmon resource in jeopardy.

The true crisis with long-term implications has been declared in

the Columbia River, as well as here in the Puget Sound, where numerous salmon populations are in danger of being lost to this and

future generations.

As a region, as sovereigns, we must distinguish between managing for short-term inconveniences and preventing long-term

losses. Due to state and Federal reactions to current water conditions, a heightened state of emergency has been created for our

shared salmon resources.

Under treaties negotiated with the United States in 1855, the

tribes reserved to themselves several rights as sovereigns, among

these the right to take fish at all usual and accustomed fishing

places. Our people have exercised this right since time immemorial.

Our peoples fished during times of drought and during times of

31

floods, during times of great runs of salmon and during times of

low runs of salmon.

As they do now, our chiefs and elders watched over the harvest

to ensure that the people cherished and protected the gift of salmon from the Creator. It is our expectation now that the United

States will honor the treaties and take the steps necessary to protect our trusted resources.

The extremely low water year does not lower the standard by

which the United States must strive to meet to honor those obligations held within the treaties. To honor its commitment, the United

States must ensure that there is water in sufficient quantity and

quality in the Columbia River and to ensure the safe passage of

out-migrating juveniles, as well as for adult salmon returning

upriver to spawn.

Under treaties with the Columbia River treaty tribes and with

Canada and under its domestic laws and agreements, the United

States is obligated to give primacy to the salmon emergency. In

order to deal with this ongoing emergency, the tribes believe that— I’d like to point these out. These are, for the record, documents

that—we have interacted with the various Federal agencies—that

we’d like recognized.

Mr. CALVERT. Those will be submitted for the record, without objection.

[The information referred to is retained in the Committee’s files]

Mr. SETTLER. Right. And the Federal agencies, at a minimum,

must provide the flow and spill levels for out-migrating juveniles

and the returning adults as identified in the tribe’s 2001 River Operations Plan, initially presented to the Federal Government in

February 2001, with updates in March, April, and May of 2001.

Mr. Wright has promised us a written response for these. We

have not received any written response back yet.

Because of the 2001 low-flow conditions, in combination with the

Columbia River dams, and the absence of fish protection measures

in 2001—these factors will result in very high levels of salmon mortality, whose effects will last for several generations, ten or more

years. The Federal Government must develop a mitigation program

that addresses the overwhelming impacts the hydropower system

will impose in 2001.

To the extent irrigation withdrawals must be limited to meet the

flow and spill standards, the Federal Government should mitigate

for that impact and explore the potential for reducing irrigation

withdrawals in the long term, using a willing buyer and willing

seller standard.

The Federal Government must honor its commitments under the

1996 MOA. Unexpended fish restoration monies held in Bonneville

Power Administration’s financial reserves must be released to the

tribes and to the region’s fish and wildlife agencies.

The Federal Government must commit to providing the financial

resources to implement the 2000 BiOp and ‘‘All-H’’ paper.

The states must maintain their minimum in-stream flow standards and ensure that water quality standards continue to be met.

And in order to reduce the burden of river uses on the backs of

salmon, we ask that you support and facilitate the sustainable development of energy resources by the tribes.

32

I will focus on the flow and spill issues this morning. Flow and

spill proposals: Tribal representatives met with Federal agency representatives on several occasions in January and through December 2000, but a meaningful dialogue was never developed on a government-to-government basis.

A list of meeting dates in the BiOp is the only indication that

the Federal Government attempted to consult with the tribes. None

of our substantial concerns were addressed in the BiOp.

The tribes continue to believe that the four dams in the lower

Snake River must be breached to ensure the restoration of salmon

in that basin. It is clear from the scientific data collected over years

of study that breaching is the only sure course to salmon restoration. If we don’t breach the dams, then a very aggressive program

of increased flows through the reservoirs and spills at the dams

must be pursued by the Federal agencies to increase the survival

of juvenile out-migration.

Based on the overwhelming amount of information available

from research conducted over the last 30 years, transporting fish

only harms; it does not provide any long-term benefits.

I have two more pages. Would you like me to—.

Mr. CALVERT. If you would summarize that, we would certainly

appreciate that.

Mr. SETTLER. This year, by declaring an emergency, the Federal

agencies are banning the flow and spill proposals they outlined in

the BiOp. For the spring, still, the Federal agencies identified 3,600

megawatt months’ worth of water as needed to prevent jeopardy to

these fish.

Now they have decided to spill less than 10 percent of that level.

There’s a hitch. They will spill this meager amount of water they

promise for fish if they are given the option of taking away spill

from the mid Columbia salmon stocks.

In an effort to compromise, the tribes and others have forwarded

a proposal of 800 megawatts of spill. The 800-megawatt months of

spill in the tribal proposal will provide a more biologically sound

‘‘spread the risk’’ approach.

Mr. Chairman, I have a couple more pages I’d—.

Mr. CALVERT. We’d be happy to accept those for the record. And

if you have any closing remark, we would appreciate that so we can

move on to the next person.

Mr. SETTLER. I’ll reserve my remarks. I hope I get some questions.

Mr. CALVERT. Mr. Settler, we’ll get back to you with some questions.

[The prepared statement of Mr. Settler follows:]

Statement of Randy Settler, Secretary, Columbia River Inter–Tribal Fish

Commision

Good morning Mr. Chairman, esteemed members of the committee. My name is

Randy Settler; I am the Secretary of the Columbia River Inter–Tribal Fish Commission. I am also a member of the Tribal Council of the Confederated Tribes and

Bands of the Yakama Nation and the Chairman of the Yakama Nation’s Fish and

Wildlife Committee. I want to thank you both for the opportunity to testify before

you today and for your desire to look into this critical situation.

The Commission was formed by resolution of the Nez Perce Tribe, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the

Warm Springs Reservation of Oregon and the Confederated Tribes and Bands of the

33

Yakama Nation for the purpose of coordinating fishery management policy and providing technical expertise essential for the protection of the tribes’ treaty-protected

fish resources. Since 1979, the CRITFC has contracted with the BIA under the Indian Self–Determination Act (P.L. 93–638) to provide this technical support. The

Commission’s primary mission is to provide coordination and technical assistance to

the member tribes to ensure that outstanding treaty fishing rights issues are resolved in a way that guarantees the continuation and restoration of our tribal fisheries into perpetuity. My testimony today is provided on behalf of the tribes.

Treaties of 1855

Under treaties negotiated with the United States in 1855’, the tribes reserved to

themselves several rights as sovereigns, among these the right to take fish at all

usual and accustomed fishing places. Our peoples have exercised this right since

time immemorial. Our peoples fished during times of drought and during times of

floods, during times of great runs of salmon and during times of low runs of salmon.

As they do now, our chiefs and elders watched over the harvest to ensure that the

people cherished and protected the gift of salmon from the Creator. It was the expectation of our treaty negotiators then that the tribes would always have access

to abundant runs of salmon; it is our expectation now that the United States will

honor that commitment and take the steps necessary to protect our trust resource.

This reserved right has not been diminished by time and its full exercise has been

upheld and affirmed in several U.S. Supreme Court decisions. Yet, our ability to

fully exercise this right has been compromised by a combination of state and Federal decisions and management actions focused on the short term.

The fact that we now find ourselves in an extremely low water year does not

lower the standard by which the U.S. must strive to meet to honor those obligations;

in fact, the drought increases the burden of the U.S. and its agencies to ensure that

the salmon resource is protected from further injury and loss. To honor its commitment now means that the United States must ensure that there is water in sufficient quantity and quality in the Columbia River to ensure the safe passage of

outmigrating juveniles as well as for adult salmon returning upriver to spawn.

We do not propose this standard in a vacuum, it is a standard we have lived by

and under which we manage our fisheries, to ensure this resource will be here for

our greatgrandchildren’s children. In times of scarcity our peoples have sacrificed

to ensure the survival of the salmon: for example, we have not fished commercially

for summer Chinook since 1964 and our harvest of those stocks for ceremonial and

subsistence purposes has been negligible.

I want to take this opportunity to note that the tribes, working through the Commission, have developed a framework restoration plan, Wy–Kan–Ush–Mi Wa–Kish–

Wit or Spirit of the Salmon. This plan documents the threats to our fisheries, identifies hypotheses based upon adaptive management principles for addressing these

threats, and provides specific recommendations and practices that must be adopted

by natural resource managers to guarantee their trust responsibilities and meet

their treaty obligations. In this plan, the tribes have identified the need to insure

that the burden of conserving these salmon stocks is allocated fairly across those

land and water uses responsible for, their decline. Consistent with this need, we

have identified changes that hatchery programs, forestry, hydroelectric development, irrigation, mining and other development activities must make in their operations to ensure the recovery of salmon stocks and fisheries. The tribes’ ultimate

goal is to restore a sustainable resource for the benefit of all peoples in the Pacific

Northwest. Consistent with meeting this goal, each and every beneficiary of the

river must make sacrifices in times of shortage, much as the tribes have voluntarily

sacrificed fully exercising their right to fish over the last several decades. The tribes

now call upon those who would generate electricity and those who would withdraw

water from the rivers to now make that sacrifice, or to provide equivalent mitigation

when it is demonstrated that such sacrifice is impossible.

At the outset, let me clearly state that it is not the current water conditions

standing alone that are affecting tribal resources in the Columbia River basin. The

real problem is the management decisions made and actions taken by the Federal

and state agencies in reaction to the drought. It is these unilateral decisions and

actions that are putting the long-term viability of the salmon resource in jeopardy.

In the tribes’ view, too much is being made of there being an ‘‘energy crisis’’ or a

‘‘water crisis’’ in the basin; these are real problems but they are short-term in nature. The true crisis, with long-term implications, has already been declared in the

Columbia River, as well as here in the Puget Sound, where numerous salmon populations are in danger of being lost to this and future generations. As a region - as

sovereigns - we must distinguish between managing for these short-term inconveniences and preventing the realization of the true potential for long-term losses. Due

34

to state and Federal reactions to current water conditions, a heightened state of

emergency has been created for our shared salmon resource.

Under treaties with the tribes, with Canada, and under its domestic laws and

agreements, the United States is obligated to give primacy to the salmon emergency. In order to deal with this on-going emergency, the tribes’ believe that:

• the Federal agencies, at a minimum, must provide the flow and spill levels for

out migrating juveniles and returning adults as identified in the tribes’ 2001

river operations plan, initially presented to the Federal Government in February 2001, with updates in March, April, and May of 2001;

• because the 2001 low flow conditions in combination with the Columbia River

dams and the absence of fish protection measures in 2001 will result in very

high levels of salmon mortality whose effects will last for several generations

(ten or more years), the Federal Government must develop a mitigation program

that addresses the overwhelming impacts the hydropower system will impose in

2001; 2

• to the extent irrigation withdrawals must be limited to meet the flow and spill

standards, the Federal Government should mitigate for that impact and explore

the potential for reducing irrigation withdrawals in the long-term, using a willing buyer and willing seller standard;

• the Federal Government must honor its commitments under the 1996 MOA, unexpended fish restoration monies held in Bonneville Power Administrations financial reserves must be released to the tribes and the region’s fish and wildlife

agencies;

• the Federal Government must commit to providing the financial resources to implement the 2000 BiOp and ‘‘All–H’’ paper;

• the states must maintain their minimum instream flow standards and ensure

that water quality standards continue to be met; and,

• in order to reduce the burden of river uses on the backs of salmon, we ask that

you support and facilitate the sustainable development of energy resources by

the tribes.

I will address each of these issues in turn.

Flow and Spill Proposals

During the development of the BiOp, the tribes attempted to engage the Federal

agencies in government-to-government consultations in order to ensure that our

treaty reserved rights were protected. And while tribal representatives did meet

with Federal agency representatives on several occasions from January, through December 2000, expending considerable time and resources, a meaningful dialogue was

never developed on a government-to-government basis. In reviewing the BiOp, a list

of meeting dates is the only indication that the Federal Government attempted to

consult with the tribes. We believe that none of our substantive concerns were addressed in the BiOp.

With regard to the hydroelectric power system, the tribes continue to believe that

the four dams in the lower Snake River must be breached to ensure the restoration

of salmon in that basin. It is clear from the scientific data collected over years of

study that breaching is the only sure course to salmon restoration. In lieu of dam

breaching, a very aggressive program of increased flows through the reservoirs and

spills at the dams must be pursued by the Federal agencies to increase the survival

of juvenile out migrants. Based on the overwhelming amount of information available from research conducted over the last 30 years, the tribes do not believe that

transporting fish provides benefits anywhere near the equivalent of adequate flows

and spill.

We advocate flow and spill not because we believe they are the answer to salmon

recovery, but because they are the only two management actions at our disposal.

They will lessen what promise to be unusually lethal impacts of the hydropower system at a time when salmon stocks in the Snake and upper Columbia River are at

dangerously low levels. This cannot be considered enhancement but, at best, damage

control.

We have been told that, instead of dam breaching, we will use the next eight

years for adaptive management. Yet there is a growing reluctance to use the information and knowledge we have already gathered about the survival of salmon,. let

alone utilizing additional information we may learn by conducting additional studies

to improve their survival.

Previous Drought Years

This year, the amount of available water for instream flows in the Columbia River

basin is expected to be lower than that of 1977, recognized as the worst water year

on record. This year, by declaring an energy emergency, the Federal agencies intend

35

to circumvent the flow and spill proposals they outlined in the Biological Opinion

(BiOp) on the Federal Columbia River Power System (FCRPS). This spring, the Federal agencies have proposed to limit spill to less than 10% of that identified in the

BiOp as necessary to avoid jeopardizing listed salmon populations. And even this

limited action will only be taken if they are granted the option of stealing spill that

was to be provided for other salmon populations during the summer. In 1977, even

with some flow and spill provided, the National Marine Fisheries Service estimated

in river survival of only 2–3% for out migrating Snake River juveniles.

To ‘‘alleviate’’ what everyone recognizes as a disastrous situation for out-migrating

juvenile salmon, the Federal agencies propose ‘‘transporting’’ these fish by barge or

truck for release below the dams.

Virtually no transported fish returned as adults from the 1977 out migration. In

fact, even though fish transportation, as a technical solution, has been in use since

1968, several salmon populations have either disappeared or been listed for protection under the ESA. The tribes believe that the research is in, transportation does

not work; the best way to ensure the survival of these populations is by either

breaching dams or providing sufficient spill and flow levels.

In 2001; we know how poorly Snake River spring Chinook survived in 1977. We

know that during years with favorable river conditions (high flow and spill rates),

smolt-to adult returns (SARs) for upriver stocks that must navigate the several

dams on the river compare most favorably with SARs for downriver control stocks,

those that have no dams blocking their path to the ocean. We know that flow augmentation lessens the impacts of reservoirs and that spill lessens the impacts of

dams.

We now know that we would need many millions of acre-feet to approach flow levels even close to the historic hydrograph. Yet, getting back to the historic

hydrograph isn’t enough. Because the reservoirs behind the Dams Act to slow water

velocity several fold, for flow, we would need to increase average precipitation several fold to compensate for the presence of reservoirs. Even in normal years, this

would be impossible.

Clearly the flow augmentation targets proposed by the Federal agencies in the

BiOp are inadequate. Yet, this year the Federal agencies refuse to provide even

those levels, as a result, flows are now half of the BiOp targets. And the safest avenue for fish, providing for spill over the dams, is now subjected to drastic curtailment or complete elimination in order to provide water for power generation.

Spring Spill

While we should at the very least be able to count upon the Federal agencies to

meet the goals and objectives they set for river management in the BiOp, it appears

as though neither the tribes nor the salmon can count on them making any effort

to restore salmon. The legally mandated spill at Federal dams in the Columbia and

Snake rivers as described in the BiOp have been abandoned, plunging already

weakened salmon runs through the most lethal routes in the river system. Without

spill, the salmon resource is left to turbine passage, mechanical bypass and transportation with all of their uncertainties.

For the spring out migration, the BiOp called for 3600-megawatt (mw) months

worth of spill as a reasonable and prudent alternative (RPA) that would help to preclude jeopardy to the listed salmon populations. Declaring an emergency, the Federal agencies initially claimed that the best they can now offer at this critical time

for the salmon is 300 mw months of spill, or less than 10% of the RPA. Even this

drastically reduced level of spill is contingent upon compromising spill regimes later

in year, with the potential for putting other salmon stocks at risk.

In an effort to compromise, the tribes and others have forwarded a proposal for

800 mw months of spill. The 800 megawatt months of spill in the tribal proposal

provides a more biologically sound, ‘‘spread the risk’’ approach for migrants reaching

the lower Columbia. The tribal proposal calls for a fraction of the spill - approximately 8 days versus 62 days- required in the 2000 Federal Biological Opinion. The

tribal ‘‘spread the risk’’ strategy would provide salmon several passage routes in the

face of the uncertainties surrounding this year’s river conditions.

The tribes continue to reject the Federal proposal to swap summer spill at mid–

Columbia dams for spring spill in the lower river - an inappropriate and irresponsible trading of risk from one stock to another. The Federal proposal would force

parties to walk away from a historical spill settlement agreement that took a decade

to negotiate and finalize.

State Management Actions and Obligations

Water is an extremely limited resource and the rivers throughout the region are

already over-allocated due to poor management by the states. While these waters

36

serve other important uses and users, they are fundamental habitat for salmon.

Salmon need these waters for instream flows. Our treaties, and the Federal and

State trust responsibility to the tribes under our treaties, as well as the Endangered

Species Act and the Clean Water Act, are there to protect these resources.

A sufficient level of water is simply not available for all the uses being proposed

by the various user groups, especially during these times. States should consider

providing, and the Federal Government should consider supporting, funding incentives for setting or amending instream flows to levels higher than the current flows

where necessary to ensure that these flows are adequate to meet the needs of fish.

The States should provide more funding to allow responsible agencies to follow

through on the states’ legal responsibility to establish instream flows. Sufficient

funding should also be provided to ensure that the agency could enforce these flows

each and every year, especially in drought years. Current state funding levels fall

woefully short of the amount needed to fulfill these responsibilities in a legitimate,

scientific manner.

While these issues are shared by each state, in light of the location for this hearing, I will highlight as an example an issue in the State of Washington.

In 1980, the State of Washington had the foresight to reserve instream water

rights to protect fish habitat and public health. But, under the same law, the State

is allowed to reduce these flows in cases of ‘‘overriding public interest.’’ On April 5,

2001 the Washington Department of Ecology (WDOE) exercised this discretion and

authorized a critical flow adjustment, reducing designated instream water flow levels by 23% in the Columbia River. This action was apparently taken in order to

avoid cutting off the access of junior appropriators, permitting even irrigators with

rights secured after 1980 to withdraw water in this drought year. The tribes do not

believe that decision was taken in full consideration of the public interest. By law,

water conservation is a public interest, and the burden of further conservation

should be ‘‘shared by the various users to the greatest extent practicable.’’ By reducing instream flows, however, Washington is not allocating the burden between

users. Rather, the State of Washington is benefiting private economic interests over

public interests.

The tribes are concerned that, by taking this action that favors irrigation needs

exclusively over the needs of fish, the State of Washington is not honoring its obligations to rebuild naturally spawning stocks of anadromous fish as required under US

v. Oregon, the Chinook rebuilding program of the U.S.–Canada Pacific Salmon Treaty, and the Northwest Power Act. Obviously, the State’s action in reducing instream

flow levels will not benefit salmon. Every cubic second foot of water available for

instream purposes is more valuable in a drought year than in a year of normal runoff.

In this specific instance, under the terms of their permits, the junior water right

holders were aware that their rights could be curtailed at least once in every 20

years for instream flow purposes. These rights were conditioned upon volume runoff

forecasts, subsequent water development occurred based upon that condition. This

year was the first time that junior rights holders faced that potential since Washington established instream rights in 1980. The junior permits were specifically

made conditional upon volume runoff forecasts and subsequent water development

occurred based on that condition. This would be an appropriate year to restrict these

diversions to protect instream uses. Yet the State chose to let them withdraw water

this year anyway.

In addition, this decision has a cumulative impact: further reducing instream

flows reduces the volume of water available for hydroelectric production and for spill

for salmon and will adversely affect the region’s interest in both these instream

uses.

The State of Washington must take affirmative actions to rebuild salmon runs,

even during low flow years, to protect the treaty fishing rights of the tribes. The

State has not demonstrated that it has a plan to restore salmon to meet the tribes’

fishing needs or that it can mitigate for reducing instream flows this year.

Again, my intent is not to single out the State of Washington: in the State of

Idaho, the Nez Perce Tribe is involved in the lengthy water allocation negotiations

in the Snake River Basin Adjudication. The State of Oregon faces some of the same

problems as Washington in ensuring adequate instream flows for fish, as well as

ensuring that water quality standards are met each year. The tribes are willing to

work with each one of these States to find ways to assist the junior appropriators,

so long as any mitigation will not reduce instream flows. The tribes also believe that

the States can mitigate for some of these impacts by working with the tribes to reform artificial propagation policies. We continue to believe that such reforms will

help to assure rebuilding Columbia River salmon runs to sustainable, harvestable

levels for tribal and non-tribal fishers.

37

Tribal Management Proposals

The tribes have long recognized that co-management in harvest arenas alone will

not address one of the most significant problems facing Pacific salmon: the loss and

degradation of their ecosystems. To address this major problem, the tribes have developed Wy–Kan–Ush–Mi Wa–Kish- Wit, or The Spirit of the Salmon, a salmon restoration program focused not on a single salmon stock or species, but instead on the

integrated habitat characteristics that make up a healthy watershed. The tribes believe that implementation of their plan will result in healthy, sustainable salmon

fisheries from Southeast Alaska to the headwaters of the Snake River Basin. To protect and recover tributary habitat, the plan proposes that land and water managers

meet a series of habitat conditions associated with survival rates. The use of this

‘‘Coarse Screening Process,’’ where applicable will define allowable levels of watershed impacts consistent with salmon restoration.

The tribes’ salmon plan calls for baseline surveys of watershed and in-channel

conditions as well as trend monitoring to document watershed recovery, test assumptions and validate models used in land management. Monitoring needs include

egg-to-smolt survival, total smolt production, and production per spawning pair in

salmon-bearing watersheds. Physical monitoring needs in all salmon-bearing watersheds include measuring substrate sediment loads, large woody debris, pool frequency, and volume, bank stability, and water temperature.

Adaptive management is a hallmark of the tribes’ salmon plan, which takes a

gravel-to-gravel approach to achieve improvements in survival throughout the salmon life-cycle. The tribes’ science-based approach to land management is supported

by independent scientific peer review. To halt salmon declines and rebuild healthy

runs, the USFS and BLM must likewise implement science-based adaptive approaches that integrate biological and physical monitoring with land management

actions that protect and restore salmon habitat.

The tribes’ plan calls for an expedited program of watershed restoration actions

for the Columbia Basin. The tribes are working in partnership with state, Federal,

and local governments as well as private landowners to establish a comprehensive

program for implementing actions that will restore functioning ecosystems in our

watersheds. We have developed watershed restoration action plans for the 23 salmon bearing watersheds above Bonneville Dam in the Columbia Basin. Many of these

actions will be carried out on private lands.

State and Federal hatchery management programs contribute to the extirpation

of naturally spawning salmon stocks in the basin. The tribal goal to put fish back

in the river means literally putting the fish back. Young salmon, if released at the

proper time, will return as adults to spawn in the same area they were released

as juveniles. Consistent with this concept, the tribes, working with the state and

Federal fishery agencies, developed a supplementation protocol so as to reform

hatcheries to rebuild naturally spawning salmon populations in the basin. Utilizing

this protocol, the tribes developed integrated production plans that can be implemented as research projects to restore naturally spawning populations using carefully monitored supplementation practices. Under tribal management, hatcheries

would be used for the restoration of naturally spawning Chinook stocks throughout

the Basin.

The tribes and the Commission, working with the state and Federal fishery agencies, developed a flow program at the dams that would help restore salmon by providing sufficient river flows for migration. This flow program enhances and ensures

the benefits from protecting and restoring watershed systems and reforming hatchery programs. In this way can we rebuild salmon populations to harvestable production levels rather than continue the status quo and preside over their demise.

The tribes’ plan covers all the areas that must be addressed in order to protect

salmon stocks and insure their restoration to levels consistent with the international obligations of the United States and with its trust obligation to the tribes;

but that will be the easy part: the most difficult obstacle facing the restoration of

the salmon runs is the lack of political will to tackle the issues head on. We will

do everything necessary to insure that these runs will be rebuilt.

Conclusion

The salmon resource, and with it, tribal rights reserved under treaties with the

United States must not be the last priority of the list of considerations reviewed by

the state and Federal Governments when river management decisions are being

made. To alleviate this burden, the tribes ask that you ensure that other river users

are bearing their fair share of the conservation burden. We would also ask for your

support of a National Tribal Energy Bill, which will foster expedited energy resource

development on tribal lands and provide the Northwest tribes the opportunity to

38

help alleviate the burden of energy reliance on the Columbia and Snake rivers by

the rapid development of new cost effective power supplies to serve Northwest loads.

1 Treaty with the Yakama Tribe, June 9, 1855, 12 Stat. 951; Treaty with the

Tribes of Middle Oregon, June 25, 1855, 12 Stat. 963; Treaty with the Umatilla

Tribe, June 9, 1855, 12 Stat. 945; Treaty with the Nez Perce Tribe, June 11, 1855,

12 Stat. 957.

2 The Bonneville Power Administrations 2001 Action Plan project solicitation is

limited to actions that have already received necessary state and Federal permitting

and can be implemented ‘‘on the ground’’ by September 30, 2001. While we do not

object to this solicitation, we recognize and BPA recognizes that the terms of this

solicitation so limit the projects BPA can consider, that these projects cannot possibly offset the impacts of the 2001 hydro operations on Columbia Salmon runs.

Looking at this issue from a different perspective, BPA will avoid nearly $2 billion

in costs by foregoing salmon operations in 2001, whereas the 2001 Action Plan solicitation is likely to result in $10 to $20 million in mitigation project funding. To further place this solicitation in perspective, to implement the FCRPS Bilogical Opinion and NPPC Fish and Wildlife Program, we estimated that over $200 million in

new BPA funding would be needed in 2001.

Mr. CALVERT. Dr. Karier, you may begin your testimony.

STATEMENT OF DR. THOMAS KARIER, CHAIRMAN, POWER

COMMITTEE, NORTHWEST POWER PLANNING COUNCIL

Mr. KARIER. Thank you, Mr. Chairman, and members of the Subcommittee.

My name is Tom Karier, and I’m one of two members of the

Washington delegation of the Northwest Power Planning Council,

and I also serve as chairman of the council’s power Committee.

Thank you for the opportunity to speak here on behalf of the

council. We are an agency of the states of Idaho, Montana, Oregon,

and Washington. Under the Northwest Power Act of 1980, the

council conducts long-range electric energy planning and analysis

and also prepares a program to protect, mitigate, and enhance fish

and wildlife for the Columbia River basin that have been affected

by the hydropower dams.

The council has been conducting an ongoing analysis of the West

Coast electricity crisis, and from our analysis, it appears the crisis

has five key causes, causes that have been characterized as comprising that perfect storm.

First, the competitive wholesale power market has been characterized by excess capacity and an abundant hydroelectric power for

most of the—of the mid to late 1990’s. And it did not provide a

price signal sufficient to encourage new investments in new generating and conservation resources.

Peak summer loads grew by almost 12,000 megawatts in the

West between 1995 and 1999, while generation capacity increased

by only 4,500 megawatts.

Second, below-average rainfall and snowpack in 2000 and 2001

have dramatically reduced our recent hydropower supply by almost

5,000 megawatts. That’s equivalent to the power needed for four

cities the size of Seattle. We are facing the second-worst drought

on record.

Third, the price of natural gas, the primary fuel for thermal

power plants in the Northwest, has more than doubled in the last

year, largely as a result of supply and demand, including increased

competition with the Midwest for existing natural gas supplies.

39

Fourth, planned and unplanned maintenance of thermal power

plants in the Northwest, but especially in California, have reduced

the power supply.

And fifth, production from the hydroelectric system has been affected by efforts to recover salmon and steelhead listed under the

Endangered Species Act, although emergency operations this year

are returning much of that power.

Obviously, a lack of rainfall is having the largest and most immediate impact. Based on our analysis, we offer the following observations and recommendations: Bonneville should continue the

emergency hydropower operations it began in February. This

means drafting reservoirs below biological opinion target levels for

this time of year in order to generate more power.

New power facilities are coming on-line in the near future, and

these will help ease the crisis. More than 700 new megawatts are

scheduled to come on-line in July alone.

We are also encouraged that renewable resources—particularly

wind power—are being developed aggressively in the region. The

regional utilities and industries also are installing temporary generation to help them through the summer and fall, when we expect

prices will continue to be high.

At the same time, we see encouraging developments in energy

conservation, demand exchanges between utilities and the customers, and economic incentives. But we still anticipate high current prices that will continue for us for another year, at least, perhaps longer.

But when prices moderate and supply increases, we must not

lose sight of the need for a longer-term policy that helps us deal

with future crises.

For example, state utility regulators should explore power pricing changes to reflect market prices and risks. If consumers saw

realtime prices, they would have much more incentive to reduce

conservation and invest in energy efficiency measures.

Consistent with our responsibilities to the Northwest Power Act,

the council is concerned about the impact of the drought on fish

and wildlife in the Columbia Basin, as well as the impact on the

nation’s power supplies.

The critical issue this spring is whether to spill water over dams

to help juvenile salmon and steelhead migrate to the ocean. Spill

is required, by the biological opinion, on hydropower operations

issued by the National Marine Fishery Service, but water that is

spilled cannot be used to generate power.

The council has advocated for hydropower operations that ensure

energy reliability in the Northwest and to use any additional water

storage to provide the best benefit for Columbia Basin fish.

In April, we addressed the spill issue with our own recommendations for dam operations this spring and summer. In short, we recommended that the spill be eliminated at the four dams where fish

can be collected and put in barges. We recommended that limited

spill be provided at Bonneville, the Dalles, and John Day Dams to

help fish migrate once energy adequacy is assured.

We believe these operations would provide the best balance of

power generation and fish protection in this difficult drought year.

40

Mr. Chairman, we have an opportunity to fix the current problem while also investing in the future.

Thank you, again, for the invitation to address the Committee

today. Thank you.

Mr. CALVERT. Thank you, Tom.

[The prepared statement of Dr. Karier follows:]

Statement of Dr. Thomas Karier, Washington Member,

Northwest Power Planning Council

Good morning Mr. Chairman, and members of the Subcommittee. Thank you for

the opportunity to testify today on behalf of the Northwest Power Planning Council.

My name is Tom Karier, and I am one of Governor Gary Locke’s two appointees

to the Council. I also chair the Council’s Power Committee, which includes one

member from each of the four Northwest states that are represented on the Council.

The Council is an agency of the states of Idaho, Montana, Oregon and Washington. Under the Northwest Power Act of 1980, the Council conducts long-range

electric energy planning and analysis, and also prepares a program to protect, mitigate and enhance fish and wildlife of the Columbia River Basin that have been affected by hydropower dams.

For nearly two years, we have been conducting periodic reviews of the West Coast

power crisis and the high wholesale market prices, an effort we began in 1999 as

the signs of an impending power problem began to make themselves evident. Today

I will share with you the conclusions of our latest analysis and our recommendations for alleviating the crisis.

To begin with some background, we believe five key events are contributing to the

current crisis.

First, as the result of the nationwide wholesale electricity deregulation authorized

by the National Energy Policy Act of 1992, the risk associated with the development

of new generation resources was placed on independent developers. These independent developers must believe they can recover their costs and earn a reasonable

return before they will invest. The excess capacity and abundant hydroelectric

power that characterized Western power markets through most of the mid to late

’90s did not provide price signals sufficient to encourage investments in new generating and conservation resources—at least not until prices jumped up last year. As

a result, construction of new power plants and new conservation and renewable resources during the last decade did not keep pace with growing demand for electricity. Throughout the entire Western Systems Coordinating Council area peak

summer loads grew by almost 12,000 megawatts between 1995 and 1999 while generation capacity increased by only 4,500 megawatts.

California’s experiences with its own deregulation law have exacerbated the supply and demand problems and helped to drive up wholesale power prices throughout

the West to levels never seen before.

Second, below-average rainfall and snowpack in 2000 and 2001 have dramatically

reduced our region’s hydropower supply. So far, 2001 is the second-driest year on

record in the Northwest, and with normal operations our region’s hydropower generating capacity is reduced by about 5,000 megawatts—enough power for more than

four cities the size of Seattle. Runoff in the Columbia River Basin is predicted to

be 56.5 million acre-feet, just 53 percent of normal. There also is bad news from

north of the border, where the Canadian Columbia River Basin is experiencing rain

and snowfall far below normal. This reduces the amount of power that can be generated both in British Columbia and downstream at dams in the United States.

Third, the price of natural gas, the fuel of choice for thermal power plants in the

Northwest, has more than doubled in the last year, largely as the result of supply

and demand issues, and also competition with the Midwest.

Fourth, planned and unplanned maintenance of thermal power plants, both in the

Northwest and in California, reduced the power supply, as did plant shutdowns to

comply with air quality requirements.

Fifth, the loss of flexibility in the operation of the hydroelectric system due to Endangered Species Act requirements has derated the system by more than 1,000

megawatts.

We are most concerned about the present condition of the Federal Columbia River

Power System, which provides about 40 percent of the electricity in the Northwest.

It is a system that runs on water, of course. And right now the water supply in the

Columbia River Basin is low. I want to make it clear that for us in the Northwest,

the crisis is not just about a failure to build new power plants. It is a crisis of fuel

supply, and for us, fuel means water.

41

The Northwest is a hydropower-dependent region. In an average year, approximately 75 percent of the electricity generated in the region comes from hydroelectric

dams. Frequently in the fall and winter we import power from California to help

meet our load. These power imports during the low-flow winter months help us

store water in reservoirs for spring fish flows. Storing water also helps us meet our

demand for power in the spring and summer and make surplus power available to

California.

Good hydropower conditions during the last several years masked the growing imbalance between supply and demand. Last winter and this spring, poor hydropower

conditions in the region combined with California’s ongoing supply crisis are exacerbating the imbalance between supply and demand and making our dependence on

hydropower all the more clear. Not only are we concerned about having enough electricity if the remainder of the spring and summer are warmer and drier than usual,

but we also are concerned about the impact of low flows and reduced water spills

at dams on juvenile salmon and steelhead migrating to the ocean.

The power crisis is affecting Northwest electric utilities and ratepayers, as well

as those in California, and particularly businesses and industries. Utilities are raising their rates, dramatically in some cases. The Bonneville Power Administration

may have to buy power on the spot market next fall if expected new contractual

obligations increase its load by as much as 3,000 megawatts. Earlier this year, Bonneville proposed rate increases to cover the additional cost averaging 60 percent

and, for some customer classes, exceeding 90 percent. With the situation further deteriorating, Bonneville is working to keep the rate increases in double figures, a goal

that would have sounded absurd a year ago.

Businesses and industries are shutting down or cutting back. In many instances,

the cost of power exceeds the value of the product produced. The aluminum industry

and some irrigated agriculture are prime examples. In these instances, the power

has been purchased back from the consumer or, in some cases, the consumer has

been able to remarket the power.

What can be done?

Based on our ongoing analysis of the power supply and market prices, we developed the following observations and recommendations:

First, Bonneville should continue the emergency hydropower operations it began

in February. This means drafting reservoirs below Biological Opinion target levels

for this time of year in order to generate more power. The emergency hydropower

could be augmented with imports, if possible, and also by reducing spill. This would

keep reservoir elevations a little higher, and that is an important consideration for

our power supply later this year.

Second, new power plants are under construction in the Northwest, and these will

help ease the crisis. More than 1,100 megawatts of new generating facilities will

begin producing electricity by July, and about 700 megawatts more will be operating

by the end of this year. In 2002, some 1,700 additional megawatts of new generation

is expected to begin operating. Meanwhile, natural gas usage in the Northwest, both

for homes and businesses and as a fuel for power plants, continues to increase. But

supply has not kept pace with demand and, like wholesale electricity, prices for natural gas have continued to increase—although recently prices fell back to $5–$6 per

million Btu. That is still about three times as expensive as a year ago. The Council

estimates that demand for natural gas will continue to grow at about 2.3 percent

per year. Gas companies are working to increase the supply, and pipeline companies

and their customers are working to increase capacity.

Third, we are encouraged that renewable resources, particularly wind power, are

being developed aggressively in the region. Two new wind power developments will

yield 325 megawatts of capacity in the next year or so, and planned hydropower upgrades in the Northwest will yield an additional 80 megawatts of capacity. Of the

anticipated 1,800 megawatts of new power expected this year, 200 is wind power

from a site in southeastern Washington.

Fourth, temporary new thermal generation is being installed by utilities and industries that use large amounts of power to help get through the anticipated high

prices this year and next. About 500 megawatts of temporary, peaking thermal

plants will come online this year. We recommend that permits be issued for these

plants if they 1) meet minimum environmental-protection criteria, and 2) are authorized only for limited time, after which the plants could continue only if approved

through normal siting process.

Fifth, efforts to improve energy-use efficiency must accelerate. The Council always

has defined conservation as improved energy-use efficiency—not as an exercise in

personal sacrifice such as living in a colder house or taking luke-warm showers. To

the Council, conservation means using energy more efficiently to do the same

amount of work. Our staff has identified a number of promising efficiency efforts,

42

including the following: 1) replace incandescent bulbs with compact fluorescents; 2)

upgrade commercial lighting; 3) ‘‘tune up’’ heating/air conditioning systems in commercial buildings; 4) replace inefficient industrial electric motors; 5) retire second

refrigerators in homes (20 percent of Northwest homes have two; old ones use twice

as much electricity as ‘‘Energy Star’’ models); and 6) accelerate replacement of existing clothes washers (‘‘Energy Star’’ models use 35 percent less electricity and 35– 45 percent less water).

Sixth, pursue industrial/commercial demand reduction. This is a separate area of

efforts to improve energy-use efficiency, and it has huge potential. Our staff has

identified the following methods: 1) utilities should negotiate interruptible powersupply contracts with their largest customers, where this is possible; 2) utilities

should investigate new contractual mechanisms like demand-exchange programs;

and 3) utilities should investigate buying back power from these customers for short

periods of time. There is good progress to report in this area. Northwest industries

have agreed to reduce their demand for power by about 1,000 megawatts. This will

be accomplished through short-term contractual arrangements that include power

buybacks by utilities, industrial shutdowns and remarketing of power supplies by

industries. Utilities also have arranged an additional 800–900 megawatts of demand

reduction agreements, primarily with industries, in which the power customers

agree to reduce their power usage in return for a payment or credit.

Seventh, and for the longer term, state utility regulators should explore power

pricing changes to reflect market prices and risk. Most consumers don’t see realtime (marginal cost) prices. If they did, they would have more incentive to reduce

consumption and invest in energy efficiency measures. Most consumers do not want

to be exposed to the volatility and risk of real-time prices. However, creative rate

design and new metering technologies can promote greater price response without

punishing the consumer.

Eighth, new energy policies also should be explored. But these can be controversial. For example, price caps on wholesale power have been proposed. The Council

has not taken a position on price caps because the governors of the Northwest states

do not agree on the issue. Two governors believe that temporary price caps are

needed to address the severe economic impacts of high power prices. The other two

governors believe that price caps will create uncertainty in the market and serve

as a disincentive to the development of new generation and conservation.

Ninth and finally, we all must continue to inform the public about the problem.

The public needs to understand the problem is real and that efforts at home will

help ease the crisis.

Now Mr. Chairman and members of the committee, I would like to discuss the

impact of the energy crisis on fish and wildlife of the Columbia River Basin. While

the Council has a statutory responsibility to assure the Pacific Northwest an adequate, efficient, economical and reliable power supply, our planning also must protect, mitigate and enhance fish and wildlife affected by hydropower dams in the Columbia River Basin. The near-record low snowpack runoff this year has the potential to have adverse effects on fish as well as power, and particularly juvenile salmon and steelhead that migrate to the ocean during the spring and summer.

The Council’s planning responsibility under the Northwest Power Act, and also

the responsibility of the Federal agencies that operate dams in the Columbia River

Basin and sell the power, is to provide equitable treatment to fish and wildlife with

other purposes of the dams. Those other purposes include navigation, irrigation,

recreation and flood control.

In April, the Council recommended operating strategies for Columbia and Snake

river dams that would eliminate water spills at most dams this spring and summer

in order to make more water—and, therefore, more power—available later in the

year. This policy would be adjusted as water conditions or the power situation

evolve.

This is controversial, to say the least.

The 2000 Biological Opinion on the operation of Columbia and Snake river hydropower dams, issued by the National Marine Fisheries Service on behalf of threatened and endangered species of salmon and steelhead, calls for spilling water over

the dams this spring and summer to help juvenile fish migrate to the ocean. Spill

is an effective method of moving juvenile fish past dams, but water that is spilled

cannot be run through turbines to make electricity.

The Council’s technical analysis of the impact of drought on the power supply in

2001 suggests that reducing spring spill at some dams and eliminating it at others

would 1) help reservoirs refill by the end of summer to levels specified in the Biological Opinion; 2) potentially reduce summer power prices if surplus power can be

generated; 3) reduce the risk of power supply problems next winter; and 4) help ensure adequate water storage to aid juvenile fish migration next spring.

43

Based on the analysis, the Council made the following recommendations:

• Barge juvenile salmon and steelhead this spring and summer.

• Do not spill water at the four dams where fish can be collected and put in

barges. These dams are Lower Granite, Little Goose and Lower Monumental on

the Snake and McNary on the Columbia.

• Spill a limited amount of water at John Day, The Dalles, and Bonneville dams,

where fish cannot be collected for barging.

• If spill is reduced or eliminated, Bonneville should set aside a portion of the income from the sale of additional power to pay for projects that mitigate the impact of this year’s drought on fish.

• Place a high priority on refilling storage reservoirs to Biological Opinion target

levels by August 31 in order to protect the winter power supply and ensure

enough water for the fish migration in 2002.

• Purchase power and water from irrigators who are willing to sell, in order to

leave more water in the rivers for fish.

In conclusion, Mr. Chairman and members of the subcommittee, where do we go

from here?

First, this crisis will end, but not right away. During the next two years, new generating plants, new conservation and new renewable energy will be coming online

in the Northwest. Creative demand-reduction agreements are being implemented by

utilities and their largest customers. Utilities are installing temporary generating

plants to help them through the summer, at least, and maybe through next winter

as well. The Council does not oppose these plants, but believes they should be temporary. These will produce power at a lower cost than power on the volatile wholesale market.

Conservation efforts including replacing incandescent light bulbs with compact

fluorescent bulbs, replacing inefficient industrial motors, and the other things I

mentioned could save the region more than 240 megawatts, according to our analysis.

The Council’s recommendations amount to a call for the West to fix the current

problems while investing in the future. We must ensure that utilities and consumers remain financially solvent until new sources of generation and demand reduction moderate prices.

Perhaps the only good thing that can be said for the current crisis is that it offers

the West an opportunity to think carefully about our future power supplies and take

steps to ensure adequate investments in new thermal generation, and also in new

conservation and renewable energy. These developments would be aided by a coordinated effort to streamline siting processes throughout the West so that we retain

the essential environmental and community safeguards while avoiding unnecessary

delays.

Mr. Chairman, that completes my testimony, and I would be pleased to answer

any questions.

Mr. CALVERT. Mr. Klein, do you believe that Bonneville should

have overprescribed when they were making their power project?

Mr. KLEIN. I understand the circumstances they were in, but--.

Mr. CALVERT. Then why did they do it, in your opinion?

Mr. KLEIN. Well, I think lobbying and political pressure.

Mr. CALVERT. Lobbying by whom?

Mr. KLEIN. A number of different entities that felt that they were

entitled, based on the benefits to those industries, to help the economy.

I think I agree with Steve Wright that probably, at the time, the

belief was that expanding of the pie can be done without damage.

Specifically, looking back, if we gave away far more of the pie,

then—.

Mr. CALVERT. Obviously, that had an impact on your customers?

Mr. KLEIN. Certainly, and will continue to have.

Mr. CALVERT. And obviously—Mr. Wilcox, I sympathize. I’ve been

in business most of my life. I can understand that—probably that

it’s not—even though someone is paying your—your employees, it’s

difficult to shut a business down for a couple of years. I imagine

44

you’re very concerned about your customers, where they’re buying

product at the present time, how you rebuild that customer relationship again, what kind of—what do you do in this interim period

of time while you’re basically down?

Mr. WILCOX. Yeah. Our particular company’s problem is that we

have a contractual obligation to operate, a supply of customers. We

have a holding arrangement for our raw materials, alumina. We’re

supposed to take some of the alumina, smelt it into aluminum, and

provide a factory aluminum.

So I’m contractually obligated to operate for this 9-month period.

I was able basically to buy my way out of that obligation.

And our concern is that we can’t do that if the curtailment gets

extended further. And that’s one of the costs we have.

Mr. CALVERT. Yeah. Part of that is you could not do that beyond

2 years.

Mr. WILCOX. Right now we did an agreement to buy ourselves

out of that supply obligation (inaudible) for 9 months to extend our

curtailment beyond October, after we negotiated that. We haven’t

been able to do that yet.

Mr. CALVERT. What’s happening, like, for instance, with your raw

resources, on that end of it?

Mr. WILCOX. We basically have to buy it and resell it at a depressed market price.

Mr. CALVERT. Mr. Settler, talking about, obviously, breaching

dams in the Snake River, what type of solution would you have to

make up for the lost hydroelectric power that we lose in a situation

such as that? Do you have any solution for that?

Mr. SETTLER. Well, I think you have people here better able to

answer that question. They have the responsibility to answer that

question. My obligation—I uphold the treaty of 1855 to protect

those resources. Certainly, we had these conditions that have existed in the past, and it shows, and it reflects, the record of the

people that are responsible, that they did perform the duties that

they were supposed to perform.

Mr. CALVERT. Now—.

Mr. SETTLER. And so my responsibility is to protect these resources and rebuild them to meet our treaty obligations. And so if

we don’t breach these dams, then we have to provide the needed

flows from the added spill to ensure their survival. It’s not happening.

Mr. CALVERT. Now, you don’t believe that the technology and the

methodology that’s been used in barging smolt salmon is a proper

solution? Of the reports that I’ve read—that—that a significant

amount of juvenile salmon are, in effect, being able to be put up,

and factually, they do not damage a larger population, especially

in a year like this.

Doesn’t the biological opinion allow for that to occur and to stop

the spilling in the—in some (inaudible) in order—for emergencies

such as this in this region, where the power can be turned on, and

allow this region to—to continue to operate?

Mr. SETTLER. Sir, most of the collection facilities are at the

Snake River, and they barged a lot of those smolts. In 1977, when

they started this program, it was a similar drought condition.

45

Mr. CALVERT. Hasn’t the technology improved significantly since

1977?

Mr. SETTLER. Well, I think there’s been some improvements, but

there is still no indication that it’s brought back an increased number of fish. There’s no scientific evidence that supports that, sure,

they can collect more smolts.

When the dams—when the smolts go out, they’re trapped in the

facility. They don’t experience natural conditions. Right now we’re

looking at smolts trapped behind these dams. We just met with the

Columbia Basin Fish and Wildlife Authority, and people were saying, ‘‘We’re going to barge every smolt we can on the Snake River.’’. The Idaho state manager got up and said, ‘‘Great. How are you

going to get them to the collection facility, because there is no

water going through the system? They can’t even make it to the

collection facility.’’. So yeah. You can say—you can barge every smolt that you get

to the collection facility, but they can’t make it. It’s the same way

with the upper Columbia River stocks right now. They’re not making it through the system. We’ve got estimates of 30 percent

through the system. 50 percent of the smolts should have went out

by now.

The smolts that we’re talking about are from last year’s—about

200,000 run of spring chinook. That was a very good run. Millions

and millions and millions of dollars have been spent on trying to

rebuild these runs.

The Yakama Nation—we’ve got 30-—30,000 wild chinook coming

back from the Yakima River, where we manage. That’s--.

Mr. CALVERT. My time has expired.

We have an extraordinary year, here. We’re trying to find a reasonable solution to this. I know Mr. Karier probably will have a

comment on how we may be able to work out a solution. And I will

come back to that.

In the meantime, Mr. Smith—. Mr. SMITH. Thank you, Mr. Chairman.

Actually, (inaudible) example of the problem that we have. Because the wholesale power market is so expensive right now, we’d

like to be able to generate as much hydropower as humanly possible so that both of you can stay in business, frankly.

The problem with generating that amount of hydropower is that,

A, we don’t have the water; and B, we have salmon concerns, as

Mr. Settler pointed out: The more of that water you spill over the

dams, the barging, at best, has had a mixed record. No matter how

you look at it, it’s not as good as the natural way of the salmon

going up and down the flows; and we have legal and—obligations

involved—legal obligations.

So I guess what—in the long term, in the next year or two, it

makes a lot of sense to build as much more generation as we can

get. I don’t think that all has to be natural gas power plants. There

are other ways to go. Short-term gas is (inaudible).

I want to ask Mr. Wilcox—my understanding is your plan is to

make the aluminum company sort of energy independent in the

next two or 3 years.

Can you tell us a little bit about the—by ‘‘energy independent,’’

I mean not dependent on Bonneville anymore.

46

Can you tell us a little bit about that?

Mr. WILCOX. Yes. When we entered into our new marketing

agreement last December, where we sold our power for the 9

months, until October, we agreed that we’d invest the proceeds

back into building new power projects to suit our needs.

We also agreed that we would co-op the Bonneville system altogether in 2006. So basically, we have a window of opportunity between now and 2006 to build power projects to (inaudible) we won’t

directly get any power from Bonneville.

So we are independently pursuing three resources. We’re putting

in a project, a gas fire project, at the Golden Dalles smelter site

that would be in operation February 2002, very fast track.

We are very actively developing a large amount of wind generation in the eastern end of the Columbia Gorge. I’ve become a believer in wind generation. And given the high price of natural gas,

you have to have a diversified portfolio to have reasonable power

costs.

And third, we’re just at the very early stage of a siting on another large natural gas spot (inaudible) Oregon. And if we could get

those three projects done, we will have an economical supply of

power long term. Given our natural gas crisis, it won’t solve all our

problems, but it will—should make the future a lot better than

having no Bonneville power after 2006.

Mr. SMITH. And it’s just a matter of getting you there, basically.

That’s a big--.

Mr. WILCOX. Yeah. You know, what we plan to do basically is use

this 5-year period between 2001 and 2006 as a bridge where you

could buy—and have half of your power needs met by Bonneville

while you built the power projects, so come 2006, you don’t have— the problem we face now is if we curtail for 2 years, we have to

use our marketing proceeds to cover our losses during the curtailment. We wouldn’t have any resources for any power projects,

which would kill us in the long term. So we have to still have— as a bridge—so we can build our power projects to get off the—the

Bonneville system so that the power is available for—.

Mr. SMITH. How much of your power do you get from Bonneville,

and how much of it do you have to get from the open market right

now?

Mr. KLEIN. Currently, under the existing contract, we get 12 percent of our needs met by Bonneville Power Administration.

Mr. SMITH. Yeah. That’s a—fairly—quite a lower number than I

would have expected. I thought, as a public utility, you had priority. Why such a low number?

Mr. KLEIN. Back in the mid 1990’s, Tacoma Power voluntarily—

one of the first utilities in the nation to voluntarily allow our large

industrial customers open access to go to the market. And part of

that was making an arrangement with Bonneville to allow them to

go. So they went. The marketing, as you know, did quite well the

first 2 years and then has been hammered very hard for the last

year.

Mr. SMITH. So you have large exposure to the wholesale market?

I guess that what all this is, two, 3 years from now, when they get

there—and I think there are certainly some broader energy questions—I think we need to be careful about totally relying on our

47

natural gas generating plants and that there are some broader

issues that are in the jurisdiction of the Committee.

But the real question is, for all of us, how do we get through the

next year or 2 years? And it seems to me that all of this argues

rather strongly that FERC,the regulatory agency that has the authority to step in and try to help out, needs to do something or, you

know, you run the risk of either, you know, charging customers an

incredible amount or to have significant increases and going bankrupt.

Northwest—I mean, your company stares in the face of the possibility of not being able to be around anymore if we can’t get ahold

of the power for the next couple of years. And the damage to the

fish is overwhelming. And it all comes back, to a certain extent, to

the exposure to the wholesale market and also to the fact that we

are not maximizing our current supply.

Now, I don’t know what FERC’s authority is to come in and tell

people to generate power, but they certainly have authority to control the prices if they see fit. If they don’t do it—. I think you three gentlemen now sort of described a lot of the

very negative consequences that are going to happen. I guess for

any future panelists or anybody in the audience and anybody up

here, if they have a different solution, if they have some way, other

than getting costs under control and maximizing short-term supply

or some sort of regulatory effort, something that’s going to get us

through the next 2 years, I am very anxious to hear it.

But I think that is the stark realities that we’re facing. And

thank all of you for explaining—my time is up, so...

Mr. CALVERT. Thank you, gentlemen.

Even though I’ll remind the panel that FERC is not under our

jurisdiction, I’ll ask the question, that—maybe to Dr. Karier.

What percentage of power does FERC have authority over the

administrative--.

Mr. KARIER. I don’t—. Mr. CALVERT. An estimate of power, approximately.

Mr. KARIER. Well, that’s something I probably have to research

and give you the exact answer. But certainly FERC has jurisdiction

over the investor owned utilities, and in the Northwest, we rely primarily on Bonneville as one large public entity, for about 40 percent of our power. BPA doesn’t have the same oversight by FERC

as the—. Mr. CALVERT. I’m sorry to interrupt. But Bonneville is not charging 2- 3-, $400, $3,000 a megawatt hour? I mean, we don’t need to

regulate.

Mr. KARIER. Right. In many cases, Bonneville has said that they

would follow any sort of direction from FERC—and so there’s always a voluntary participation.

Mr. CALVERT. I just wondered, for the record, is it approximately

about 50 percent of the market amount regulated—approximately?

Mr. KARIER. It’s in that range.

Mr. CALVERT. Thank you.

Mr. DeFazio?

Mr. DEFAZIO. Thank you, Mr. Chairman.

Mr. Chairman, I’ve observed that the—the Pacific Northwest—as

a result of the California deregulation and market manipulation by

48

a number of large energy companies and the failure of FERC to

act—is paying higher average prices in the wholesale market than

are California utilities.

Our problem is not in the Northwest. We don’t need FERC to

regulate the prices up here. We’re not gouging anybody. We have

a problem with the power we traditionally buy from California

being at extortionate rates. And we are paying—and this is a fact

which I can substantiate. We are paying higher average prices in

the wholesale market than are California utilities when we purchase.

Mr. Klein, if you—if you would, the Chairman seemed critical of

Bonneville’s decision in investigating the role of the last administration in signing contracts with the aluminum companies. Mr.

Wright said that at the time when he signed those contracts, that

he believed—and under the market conditions at that time—that

he could have provided the power to the aluminum companies

without raising everybody else’s rates.

Do you think that was an accurate assessment?

Well, he didn’t sign the contracts, and he was an administrator.

But he was at BPA at that time in entering into those contracts.

Mr. KLEIN. I have no reason to disbelieve his understanding of

the circumstance.

Mr. DEFAZIO. So if wholesale rates today were the same as

wholesale rates 2 years ago, we wouldn’t be sitting here trying to

figure out how to curtail the aluminum industry and looking at

rate increases of 100, 200 percent for your customers?

Mr. KLEIN. I believe that’s correct.

Mr. DEFAZIO. Thank you.

But on the other hand, I also—Mr. Wilcox, in the past, has been

a great advocate of deregulation. In fact, I remember when he was

going to take his company into the private market and do better

than BPA. And he’s advocating that—a pure rate, which he said is

a dead horse. I’m glad to hear him admit it’s a dead horse, because

of the extraordinary negative effect that it would have on every

other rate payer who isn’t able to curtail 25 percent.

Could you comment a little bit on what the impact on your other

customers, all your other businesses, small businesses, and residential rate payers would be of a tiered rate that was proposed.

Mr. KLEIN. Public power has great concern for that and hope

that folks that look at this issue really look through to it, because,

as we talked about, the DSI’s lobby would receive substantially

more than their statutory entitlement. They’re a manufacturing operation that can, in fact, wrap up the production, depending upon

the market conditions, and can, in fact—they’ve given 75 percent

of their need at extremely below-market rate—however, can certainly continue to make profits as good or better than they’ve made

in the past.

As you referenced, public utilities’ customers of Bonneville, particularly those that have aggressively participated in conservation—what happens is the more you conserve, the more your load

is down, the less you’re entitled from Bonneville.

So if suddenly 75 percent of your customer base is provided adequately by Bonneville but you have this 25 percent exposure that

never goes away, you can never get there from here. The more you

49

conserve to try to make up that 25, then the 75 percent price—that

portion of your entitlement continues to shrink.

So the way this is proposed, a public utility would always have

75 percent of its customer base, whatever it is, served at one level

and have the other 25—and unlike a business, you can’t make 25

percent go away.

So basically it’s a cost shift mechanism that shifts substantial

costs to the citizens and consumers of the Northwest.

Mr. DEFAZIO. And how about as a conservation mechanism? He

said it gets a 25 percent reduction in Great Britain. Well, of course,

according toMr. Wright’s figures, a 25 percent reduction in the current wholesale market rates being charged due to the market manipulations in California would lower us to a 210 percent rate increase if we provided it to everybody who has a contract. I assume

that still wouldn’t be an acceptable level of rate increase.

Mr. KLEIN. Right.

Mr. DEFAZIO. Just to further pursue this—because I’m bitterly

opposed to tiered rates—in fact, I’m probably in Congress because

of tiered rates, because my local utility put in place tiered rates

during the WPPSS and was driving people out of their homes; and,

I became a leader of a rate payer movement.

Just to examine it a little bit more, you’re talking about for the

utility. What about for an individual customer? What if you have

an all-electric home and you’ve been given this 25 percent tiered

rate; you’ve invested in insulation; you’ve got a heat pump; you’ve

installed some fluorescent bulbs? Where do you get that 25 percent? What’s the message the market is sending you here? What

are you going to do?

Mr. KLEIN. That’s a good question. And as—as I talked about, as

those individuals—as the utility struggles to send the right signal

to those consumers, the goal should be, is everybody conserves to

the best degree they can. But ultimately, it doesn’t help the utility

in this kind of tiered rate arrangement. So you continue to mix and

match price signals and confuse the consumer along with putting

the utility in a position—.

So I guess in general, I agree with everything you’ve said.

Mr. DEFAZIO. Just one last question: Did we have any trouble

getting conservation investments before Bonneville abandoned

them in the mid ’90’s because of deregulation? The former administrator, who now works for Enron as a consultant, was, at the time,

totally panicked, and he said he wasn’t going to be able to sell his

power at 2.3 cents a kilowatt hour, and he abandoned all conservation and renewable measures in the early, mid ’90’s.

But weren’t we out there? Wasn’t there an incredible amount

available that we didn’t buy?

Mr. KLEIN. Yeah. It’s my understanding that the Northwest has

been the most successful in the nation and has had the most aggressive conservation programs, which is amazing, because people

say we have the lowest rates in the country and couldn’t possibly

have a conservation ethic. And we’ve put our conservation ethic up

to any other area of the country.

Mr. DEFAZIO. So we don’t need to screw people with higher rates

in order to get them to conserve?

Mr. KLEIN. Right.

50

Mr. DEFAZIO. Thank you.

Mr. CALVERT. Mr. Larsen?

Mr. LARSEN. Thank you, Mr. Chairman.

Mr. Wilcox, the approach that—that Golden Northwest—I want

to give a title to it—has distributed generation, and it’s the idea

that there are two chickens in every pot and two cars in every garage and two turbines in every backyard and basically building

your own power supply. We’re seeing that up in Bellingham and

Georgia Pacific Paper Mill.

To address the issue that they’re trying to address—that is, to

keep the paper mill alive—they had to shut down the pulp mill. To

keep the paper mill alive, they’re looking at building two 10-megawatt generators on site.

Can you list—if there are obstacles—any regulatory or legislative

obstacles that you’re coming across or lessons that you’re learning

in going through this that—that we can possibly address?

Mr. WILCOX. I—actually, in terms of siding, I would say that the

regulators of both Washington and Oregon have been very responsive. They understand that there’s an energy crisis and are trying

to move things expeditiously. So I have no complaints at all there.

I would say right now the one technical bottleneck is at the Bonneville transmission level, because Bonneville has a queue of who

applies for transmission and kind of goes through them in order.

And some of those may be small things that may never get done.

And I think one thing Bonneville could do is give out a different

kind of sense of urgency to projects that are real and large and essential for a particular industry to stay in business—as an example, just kind of taking the one-megawatt emergency generator in

the order in which it was filed.

Mr. LARSEN. The Boeing company—which we still like to remind

folks still has 78,000 jobs here in the Northwest—related to Boeing—it’s just the headquarters that’s leaving—the Boeing company saw its electricity bill jump $1.6 million. And I know there’s some

discussion between Boeing and Snohomish County PUD’s about

doing something along the lines of what we’re looking at.

So I want to just ask Dr. Karier, has the planning council looked

at the policy implications, distributed generation, equity issues, access to power issues? Have you taken a look at that at all?

Mr. KARIER. What we are doing is trying to track all the new

generation as closely as possible, including projects like Brett

Wilcox’s. There are a number of projects that have broken ground

and are under construction, and we anticipate there will be about

1,800 new megawatts available by the end of this year in the

Northwest. 200 of that is wind power. And there’s another wave— probably equal to that amount—that will come on within the next

year after that.

So the council originally identified that we needed about 3,000

new megawatts in the Northwest to reestablish a reasonable reserve level. And at least over the next two or 3 years, the projects

that are under construction look like they will hit that target. That

is assuming that all the projects are completed that are under construction or planned.

Mr. LARSEN. Are those all for the entire system or some of those

projects for specific companies like Golden Northwest?

51

Mr. KARIER. These are projects in the Northwest, and it is allinclusive. And if a project is designed for a specific industry, that

may displace power from another utility.

So what we’re looking at is the total supply-and-demand picture

to make sure that we have enough reserves in the Northwest.

Mr. LARSEN. Mr. Chairman, I appreciate the opportunity to be up

here today.

As you know, I’m not on the Resources Committee. I am on the

Transportation and Infrastructure Committee. So there is an issue

about high-financing the structure. If you don’t mind, I would like

to ask because in my district, there was a—in Bellingham, Washington—there was an explosion, a rupture, a pipeline explosion,

that killed three young men. And the issue of pipeline safety is

very important to the people I represent, but also recognizing that,

that we do have to—there have to be some investments in the pipeline infrastructure to move natural gas to the areas where we need

it to run the power plants.

Has—has the Northwest Power Planning Council looked at what

percentage of this 38,000-or-so miles that the present energy report

says we’re going to need in terms of a new pipeline—has it looked

at what kind of pipeline infrastructure we’re going to need in the

Northwest region to meet our needs?

Mr. KARIER. We are starting to look very closely at natural gas

because so much of the new generation is going to be natural gas

fired. And because prices have been volatile in natural gas, there

is a lot of uncertainty there of how much—how much that power

will cost.

Prices did rise significantly. They are about twice as high as they

were two or 3 years ago. They’ve been very volatile. Our analysis

of the gas industry is that there’s a lot of effort being put into new

supplies and to expansion of the pipeline. All of this seems to be

on track to keep pace with—with the new demands, but it’s an extraordinary new demand coming on with these plants.

So I think it’s an area we need to keep monitoring and to look

for potential bottlenecks. And there may be price spikes in the gas

industry.

Mr. LARSEN. Are we going to do another round?

Mr. CALVERT. We’re going to look at this chart rather than (inaudible) the last panel here pretty soon. But I have a couple questions I’d be happy to entertain (inaudible).

Dr. Karier, on the issue that Mr. Larsen just brought up on natural gas, would your primary source of natural gas be from Canada?

Mr. KARIER. That’s right. For the Northwest, the primary sources

are from Canada, from Alberta, and British Columbia.

Mr. CALVERT. Do you know the percentage of how much natural

gas—in the Washington area, for instance, or the Pacific Northwest—comes from Canada rather than some other location?

Mr. KARIER. The other location is, I think, from the Rocky Mountain area from Colorado, and I don’t know the exact percentage. I

can find out. I think the majority of it is coming from Canada,

though.

52

Mr. CALVERT. Is there any price differential at the present time

between the gas that you’re getting from Canada versus the—the

Rocky region?

Mr. KARIER. I don’t believe so, but again, I would have to check

that.

Mr. CALVERT. The—the other issue on the amount of power

that’s coming on-line—you mentioned that you believe that—how

many megawatts are coming on-line within the next year?

Mr. KARIER. 1,800 megawatts in the next year.

Mr. CALVERT. In the next 2 years?

Mr. KARIER. I believe it is an additional 1,700 megawatts in the

second and third years.

Mr. CALVERT. And you believe that you’ll be exceeding the 15

percent reserve capacity within two to 3 years? Do you believe that

once you get to that, that—that there still will be market manipulation that can potentially have that type of activity going on, or

do you believe that prices will start going down andstabilizing?

Mr. KARIER. In—well, in terms of the reliability that will provide,

all these projects must be finished. The way that the council calculates it is we want a 5 percent or less chance of an outage due

to inadequacy. Right now it’s running at about a 20 percent possibility of inadequacy this coming winter, which is far too high.

So if all those projects are finished, we believe we’ll be down in

that range of a reasonable probability of an outage.

Certainly, I think the best pressure, to keep prices down in the

long run, is to have an adequate supply available. And in this market, we can hope that all these projects will be finished, that adequate supply will be there, and prices will come down, and that

will go a long way to producing stability for the market.

Mr. CALVERT. Thank you. Any additional questions?

Mr. DEFAZIO. Thank you, Mr. Chairman. Just to follow up on

that line of questioning...

So in a deregulated market where utilities and generators no

longer have a duty to run their system—let me just give you a

statement that was made by the—I was in a debate with a fellow

named Phil Romero, who is apparently a former staff member for

Pete Wilson at the (inaudible) talking about his authorship of the

California (inaudible) and a chair of the (inaudible) Electric Board

last Monday night in Eugene.

And in response to a question—similar to what you just asked—

about how much generation and supply is available in the Northwest now and how much of a shortage we have, Mr. Bergman, who

is quite sophisticated in this matter, said, ‘‘I can’t answer that

question. No one can answer that question, because in the current

market, nobody is telling anybody what they’ve got under contract

and what they can generate because they’re too vulnerable to the

market and market manipulation.’’.

Was that a fair statement?

Mr. KARIER. Well, we found that it’s difficult to get all the information that we require from the utilities. And certainly, I think

that’s a problem that needs to be looked into.

We—we do have a pretty good idea of the capacity that’s existing

out there in the Northwest and also--.

53

Mr. DEFAZIO. Right. But, if I could, in a deregulated market, nobody has to operate to their capacity; is that correct?

Mr. KARIER. That’s true.

Mr. DEFAZIO. So if you’re calculating that to get to this 5 percent

margin, you just need a certain amount of installed capacity; and

you are then assuming that those people will run those plants, the

prices will be affordable, and the energy will be sold in the Northwest. Are those the assumptions you’re making?

Mr. KARIER. I think the assumption is that there will also be an

adequate number of producers that will be competing with each

other. And if there is some sort of violation of—of competitive

standards and rules, then certainly that could happen.

Mr. DEFAZIO. Well, what’s happened in California is a few large

energy companies dominate the market, and they can make more

money sometimes by not running part of their supply and running

the other part at extortionate prices.

What’s to prevent that from happening here? What’s going to

overcome the market manipulation forces? There is this idea that,

‘‘Gee, maybe if we build enough, we’ll get there.’’.

But if people can still merge and they can be dominated and people can exert market power, what is ever going to solve that problem and get us back to the reliability we had when it was a regulated, cost-based, affordable system?

Mr. KARIER. I certainly agree with some of the sentiments that

you’re expressing. In terms of the way the market has evolved, it’s

much more of a boom-bust type of market than I think anyone anticipated. And the fact that it took so long to get this new generation under construction, I think, is a significant problem.

Under a well-functioning market, you would hope that the producers would have anticipated that there was an impending shortage and they would have started this construction two or 3 years

ago. That didn’t happen. They started after the prices spiked. And

so we have to wait two or 3 years until enough capacity comes online.

Mr. DEFAZIO. 28,000 megawatts is applied to BPA for transmission rights is what Mr. Wright says, at least preliminarily. If

all that 28,000 got built, we would have a surplus of power potentially here in the Pacific Northwest.

So the other side of the market that we might see—which might

be just this huge, quick downturn, to a point where it dropped to

the prices of 2 years ago. Wouldn’t that be below the imbedded cost

of these new plants, let alone their marginal costs? Would they

even operate the damn thing?

Mr. KARIER. Our experience so far has been underproduction.

And we’re experiencing a price spike associated with that.

Mr. DEFAZIO. Well, we had overproduction and now underproduction. I mean—you know, what we’re talking about is extraordinary volatility here. Is volatility in price and in reliability a desirable characteristic for electricity? Is there a substitute that I’m

not aware of?

Mr. KARIER. Well, prior to this, we had a regulated market,

which basically forecasted energy needs and then regulated construction. And it was—it was obviously more stable—the prices

54

were not volatile. We did not have these kinds of shortages that

we’re experiencing now.

Mr. DEFAZIO. What’s stopping us from going back to regulation?

Mr. KARIER. You may know the answer.

Mr. DEFAZIO. You just appointed us, Congress. Thank you.

Mr. CALVERT. Mr. Larsen--.

Mr. LARSEN. Mr. Chairman, thank you.

I have a few questions, one for Dr. Karier.

You talked about natural gas and the—the resources that need

to be developed. The question I was trying to get at—that was,

have you done—has the council done calculation on how many

miles of pipelines we need to build in the Northwest, or is that

someone else’s job? Should I go to someone else to look at that?

Mr. KARIER. That’s something that’s tangential to what we’re

doing. We’re simply monitoring what the gas industry is doing to

see if there are potential bottlenecks that may arise. The industry

at this point is trying to expand capacity within existing physical

structures—and they seem to have some ability to do that before

they start building expanded physical structures.

Mr. LARSEN. Thanks.

Mr. Klein, this is related to this issue of volatility. And in the

market, we have—deregulation seemed to have been based on at

least one premise that electricity was a commodity and had the

characteristics of a commodity.

But can you, from your perspective, explain or provide some criteria about what you think a commodity is and how electricity is

different from that and the impact that it’s had on volatility in the

market.

Mr. KLEIN. The first way, I’ll answer that in a more humorous

vein, and that is, it’s an invisible commodity. So that makes it

much different than some of the others.

But I—it’s possible, I guess, that you could, if you spend enough

time on it, maybe accomplish a restructuring that would allow it

to be a commodity.

But I think the difficulty comes—is in order to—with electricity

being such a necessity—I mean, you don’t have to—like coffee

beans or something like that, I suppose—but since it’s such a necessity of life—.

Mr. LARSEN. In the Northwest, you’re talking about?

Mr. KLEIN. That’s true.

-- you really have to ensure there is a robust and vibrant market.

You can’t follow other typical commodity environments where you

just believe the market will take care of itself and entities can

enter and sell their apples today, or decide not to sell their apples

today, on the market. People will just not buy apples if they’re too

costly.

In this case, where these are lighting and heating our schools

and providing energy for needed surgeries and operations, this is

an essential commodity. So if someone wants to turn it into a deregulated environment, you’re going to have to do something unusual, and that puts some goalposts, puts some regulation around

that market. And I guess no one’s ever done that before, created

a—a—a free market that—that is so constrained so you can assure

55

it remains robust. Then you’re back to starting again. Then why

are we doing this?

That’s not to say that there aren’t some things that we can do

as a nation to promote so that we don’t—we don’t fall into that

complacency and we don’t look at new technologies in the energy

industry, distributed generation, or things like this.

There are other ways, I think, that our legislative leadership can

look to enhancing or providing incentives so that the electric industry doesn’t see itself as a protected monopoly and doesn’t look at

new innovations. So I think there’s a balance there.

Mr. DEFAZIO. If I could interrupt for just a second on the commodities aspect—I think it’s useful to note that it is the only commodity that is traded on the Commodities Futures Exchange Commission—Trading Commission, which is not regulated by that commission. It is unique. It was exempted in the early ’90’s.

In fact, actually, one of the key votes was from the wife of a senator from Texas who serves on the board of Enron. It is now the

only unregulated, deregulated commodity in the world, in the

United States, that’s traded.

Mr. LARSEN. Thank you, Mr. Chairman.

Mr. CALVERT. I thank this panel for your testimony and answering our questions.

And we will invite our third and final panel.

Ms. Sara Patton, the Coalition Director for the Northwest Energy

Coalition; Mr. Ray—I believe it’s Lepp—Vice President/General

Manager, Birmingham Steel; Dr. James Anderson, Associate Professor of Fisheries Sciences at the University of Washington; and

Mr. Rob Walton, the Assistant Manager, Public Power Council.

I thank the witnesses for attending today’s hearing. We have

some lights there. We attempt to try to keep the testimony to 5

minutes, where we’ll have time for questions.

With that, Ms. Patton, you may begin your testimony.

STATEMENT OF SARA PATTON, COALITION DIRECTOR,

NORTHWEST ENERGY COALITION

Ms. PATTON. Thank you.

Mr. Chairman, members of the Committee, my name is Sara Patton. I’m the Executive Director of the Northwest Energy Coalition.

The Coalition is in alliance with almost 100 organizations that

advocate policies to provide clean and affordable energy for the

residents of Washington, Oregon, Idaho, Montana, and British Columbia.

Our member organization includes consumer and environmental

groups, community action agencies, progressive utilities, businesses, and others. A full list of our members is appended to my

testimony.

Before I came to the Coalition, I worked for 15 years at Seattle

City Light, designing and implementing the utility’s award-winning

conservation programs.

You’ve asked me to address the role conservation renewables can

play in the current water and energy situation affecting the Pacific

Northwest.

I will start with an assessment of the potential for cost-effective,

clean, new renewable energy resources in the region and then move

56

to the demand side of the equation—on the contribution that energy efficiency and load management can make in the current situation.

On Clean, Renewable Energy: The excellent news about cost-effective, clean, renewable energy for the Northwest is perhaps best

demonstrated in the excellent response to the Bonneville Power Administration’s request for proposal for wind power. BPA asked for

a thousand megawatts of wind power, at a competitive price, capable of commercial operation by late 2003.

In fact, BPA received a proposal for 2,532 megawatts of quick,

clean, cost-effective wind projects in the region. BPA’s press release

on the subject, which begins with the exclamation, ‘‘The response

blew us away,’’ is appended to this testimony, along with a chart

of the locations and sizes of projects.

And the good news about wind power’s role in the current energy

situation is not limited to potential for quick, new projects. There

are over 90 megawatts of wind plants operating now in the region

and over 400 megawatts of wind and geothermal energy under development to serve the region right now. A map and chart of these

projects is also appended to my testimony.

Wind is estimated to cost between 3 and a half and 6 cents a kilowatt hour. The full potential of wind power in the region is enormous, at 133,000 average megawatts. And as BPA’s experience

bears out, the construction lead time is quite low, usually between

one and 3 years.

The region also has a geothermal and solar potential—that I

have detailed in my written testimony, but I won’t talk about them

right now, because I want to move to the Efficiency and Load Management. I want to make three points, one on the decline of energy

efficiency investments that we’ve seen in the last 10 years; today’s

conservation opportunities; and, third, the load management opportunities. And I’ll expand on each of these points in turn, but first

I want to get a couple of important definitions.

The first definition is of ‘‘energy conservation.’’ during this

drought and financial crisis, we’ve asked people to turn down their

thermostats, to turn off their lights, and to cut their hours of operation.

That’s not energy conservation. That’s curtailment or, more familiarly, shivering in the dark. The current situation demands this

kind of sacrifice, and we thank the residences and businesses of

our region for their very generous response.

The reduction in consumption is good for all of our pocketbooks

but especially for low-income households and small businesses. And

any water we can leave in the rivers is a blessing for the salmon

struggling through this drought.

The energy conservation I will be talking about today, however,

is not curtailment. It is not doing without but, rather, doing more

with less. It’s more efficient lighting, well-insulated homes, and

high-efficiency motors in the industry.

This increased efficiency gives us comfortable homes, a competitive business, with the very least harm to our air, water, and climate.

The second definition—‘‘load manage’’—the term is used to cover

a range of efforts to reduce consumption during peak periods. The

57

efforts include installing devices on residential water hatcheries to

allow a utility to turn them off remotely when peak demand threatens blackouts or forces the utility to purchase outrageously priced

power.

Similar opportunities are available in businesses and in industry.

Typically the utility pays the customer for the willingness to reduce

the consumption and agrees to a specified limit on the number and

duration of those reductions.

These load amendment programs serve as a very cost-effective

way to avoid the purchase of expensive power and/or blackouts in

the short term without painful reduction in the quality of service.

Back to my three points after my definitions.

First, the Decline in Energy Efficiency Investments: In my written testimony, the Pacific Northwest largely abandoned the most

successful and cost-effective energy conservation for the nation

starting in 1994. We’ve achieved 1,500 megawatts—average

megawatts, at a savings, at a cost 2 to 2 and a half cents a kilowatt

hour, with a retail value of between 2- and $2.5 billion.

In Washington, investment has declined by 75 percent from 1993

to 1998. The BPA’s investment dropped 80 percent between 1993

and 1999. There’s lots of room for improvement. And the good news

is that we have great opportunity today.

In its 1998 Conservation and Power Plan—that the Power Council projected over 1,500 average megawatts of cost-effective conservation at an average cost of 1.7 cents a kilowatt hour.

Given a much higher forecast of the cost of new generating between now—the council’s staff confidently predicts that there are

2,400 average megawatts of energy conservation which are cheaper

than new power.

The third point is we must take advantage of load management

opportunities. In the very near term, utilities and the BPA can provide significant emergency insurance against blackouts and financially deduct the power purchases for load management.

Most high-rise, commercial buildings in this region already have

energy measurements—computer sensors capable right now of

shedding inessential (inaudible) loads on a moment’s notice.

Less sophisticated devices are relatively easy to install and allow

utilities to turn off water heaters, for example, instantaneously.

Now is the time to get these options in the field. An entire year’s

class of salmon smolt are facing a massacre with the migration to

the sea.

And we’re risking human life with a high possibility of blackouts

or condemning children with asthma and people with emphysema

to the emergency rooms from all the new diesel generation we’re

firing up right now.

It’s time to deliver clean and efficient—clean energy from efficiency and renewables and to take full advantage of load management opportunities.

My written testimony ends with a list of things Congress can do

to help the region meet this precious, clean, and affordable energy.

Thanks, once again, for the opportunity.

Mr. CALVERT. Thank you.

[The prepared statement of Ms. Patton follows:]

58

Statement of Sara Patton, Executive Director, NW Energy Coalition

Introduction

Mr. Chairman, Members of the Committee, my name is Sara Patton. I am the

Executive Director of the NW Energy Coalition. The Coalition is an alliance of almost 100 organizations advocating policies to provide clean and affordable energy

for the residents of Washington, Oregon, Idaho, Montana and British Columbia. Our

member organizations include consumer and environmental groups, community action agencies, progressive utilities, businesses and others. A full list of our members

is appended to my testimony (Attachment A). Prior to coming to the Coalition, I

worked for fifteen years at Seattle City Light, designing and implementing the utility’s award-winning conservation programs.

We appreciate the opportunity to testify at this very timely hearing. Energy policy

is on the public agenda today in a way that it has not been in many a year.

This hearing is focused particularly on the electric energy situation in the Pacific

Northwest. While our region has its own particular situation, much of today’s discussion can help inform our understanding of these issues at a national level as

well.

The Committee is well aware of the Pacific Northwest region’s supply situation

and the implications for our region of recent developments in California energy markets. This situation makes it clear that inaction is not an option. You have asked

me to address the role conservation and renewables can play in the current water

and energy situation affecting the Pacific Northwest. The Northwest has a proud

record of development of renewable energy and energy efficiency resources and the

opportunity to build on that foundation is clear and compelling.

I will start with an assessment of the potential for cost-effective, clean, new renewable energy resources in the region and then move to the demand side of the

equation - on the contribution that energy efficiency and load management can

make in the current situation.

CLEAN RENEWABLE ENERGY

The excellent news about cost-effective clean renewable energy for the Northwest

is perhaps best demonstrated in the excellent response to the Bonneville Power Administration’s (BPA) Request for Proposals for wind power. BPA asked for 1000

megawatts (MW) of wind power at a competitive price and capable of commercial

operation by late 2003. In fact, BPA received proposals for 2,532 MW of quick. clean.

cost-effective wind projects in the region. BPA’s press release on the subject, which

begins with the exclamation, ‘‘The response blew us away . . .’’ is appended to this

testimony along with a chart of the locations and sizes of the projects (Attachments

B & C).

And the good news about wind power’s role in the current energy situation is not

limited to potential for quick new projects. There are over 90 MW of wind plants

operating in the region and over 400 MW of wind and geothermal energy under development to serve the region right now. A map and chart of these projects are appended to this testimony (Attachment D). Wind is estimated to cost from 3.5 to

6 cents per kilowatt-hour (kWh). The full potential for wind power in the region is

enormous at 133,000 average MW. I have been quoting MW rather than average

MW above. Since wind is an intermittent resource, its average megawatts of production are usually about a third of its megawatts of capacity depending on the site.

So 133,000 aMW is a very sizable potential. And as BPA’s experience bears out, the

construction lead-time is quite low, usually between 1–3 years.

The region also has significant geothermal power potential: between 7,000 and

11.000 MW at a cost of between 4.5 and 7 cents per kWh. The region has 45 aMW

of geothermal under development and another 45 aMW in process.

Finally, we have sunshine in the region, if not on the I–5 corridor. There are more

than 200,000 aMW of solar potential in the region from a combination of direct thermal and photovoltaic production. The costs for direct thermal vary from 2 to

13 cents per kWh and for photovoltaics from 17 to 21 cents per kWh. Even though

photovoltaic power is still expensive to produce, it is frequently a cost-effective option for remote locations. which would require expensive line extensions in order to

buy power from central station plants on the grid.

Fact sheets on wind, geothermal and solar power from the Renewable Northwest

Project are appended to my testimony (Attachment E) and also available on RNP’s

web site at www.mp.org. The Renewable Northwest Project is an alliance of environmental and consumer groups with renewable energy developers, which promotes

clean, renewable energy for the region.

59

ENERGY EFFICIENCY AND LOAD MANAGEMENT

I want to make three key points:

• While the Northwest has a record of innovation and leadership on energy efficiency, recent years have seen a distressing lapse of attention to conservation

by BPA and too many Pacific Northwest utilities.

• There remain large opportunities to save energy, money and the environment

through investments in energy efficiency in our region.

• While past conservation efforts have focused largely on reducing overall usage,

today’s situation also requires a focus on reducing peak demand.

I will expand on each of those points in turn but first a couple of important definitions. The use of the term ‘‘conservation’’ during the current crisis has caused my

colleagues and me a great deal of distress. We have been used to using the terms

‘‘energy conservation’’ and ‘‘energy efficiency’’ synonymously. During this drought

and financial crisis, many spokespeople and the media have called for homes and

businesses to reduce their consumption by turning off lights, turning down (or up)

thermostats and cutting hours of operation. They have called that behavior ‘‘con- servation.’’ We would call it curtailment or more familiarly, ‘‘shivering in the dark.’’ The current situation demands exactly this kind of sacrifice, and we support our

elected officials and other leaders in calling for it. We thank the residents and businesses of the region for their generous response. The reduction in consumption is

good for all of our pocketbooks, but especially for low-income households and small

businesses, and any water we can leave in the rivers is a blessing for the salmon

and other fish and wildlife struggling through this drought.

The energy conservation I will be talking about today, however, is NOT curtailment. It is not doing without, but rather doing more with less. It is more efficient

lighting, wellinsulated homes, and high efficiency motors. This increaesd efficiency

gives us.,. comfortable homes and competitive business and industry with the very

least harm to our air, water and climate.

Second ‘‘load management’’ is a term used by utilities to cover a range of efforts

to reduce consumption during peak demand. Usually the peaks have been measured

for generation capacity, but the region is now also considering peak demand on

transmission and even distribution capacity as well. The efforts include installing

devices on residential water heaters to allow the utility to turn them off remotely

when peak demand threatens a blackout or forces the utility. to purchase outrageously priced power. Similar opportunities are available in businesses and industry to reduce or curtail non-essential electrical consumption temporarily in response

to system peaks. Typically the utility pays the customer for the willingness to reduce consumption and agrees to specified limits on number and duration of the reductions.

These load management programs do not necessarily result in less energy consumption overall and they are not strictly speaking improvements in efficiency.

They can. however, serve as very cost-effective ways to avoid purchase of expensive

peaking resources in the long term and purchase of expensive power and/or blackouts in the short term without a painful reduction in quality of service.

The Decline in Energy Efficiency Investments

According to the Northwest Power Planning Council, Pacific Northwest utilities

acquired about 1327 average megawatts of cumulative conservation savings from

1978 to 2000. Federal, state and local efficiency codes and standards have saved

more than 200 megawatts. For perspective, the grand total of 1,500 average

megawatts is more than enough to serve the entire load of Seattle City Light. Utility funded conservation savings in those years were acquired at a cost between 2

and 2.5 cents per kilowatt-hour and had a retail value to consumers of $2.5 billion.

But starting in 1994, the region saw a steep decline in utility investments in energy efficiency. The most detailed study of this trend came in Washington State.

The State’s Department of Community Trade and Economic Development published

a detailed survey of conservation investment trends in 1998 based on information

from utilities serving 86% of the state’s electric consumers.

That study found that total utility investments in conservation peaked in 1993 at

$ 169 million (constant 1997 dollars) and then declined in each year thereafter. By

1998 utility conservation investments were down to only $42.5 million, a 75% reduction. No other state made a comparably detailed assessment, but there is little reason to doubt that the Washington experience was representative of the region as a

whole. This is particularly likely given that the Bonneville Power Administration’s

financial support for public utility conservation programs was, between 1993 and

1999, cut by more than 80%.

Why did this happen? There are two major causes. First, estimates of the cost of

new generation declined, driven by the advent of highly efficient combined-cycle

60

combustion turbines and projections of low future gas prices. In order to be costeffective, of course. conservation investments must save energy at a cost lower than

the price of new supply. When that ‘‘avoided cost’’ dropped, so did the supply of costeffective efficiency investments, though the avoided costs used by almost all utilities

included no accounting for environmental costs of various resources.

Some reduction in conservation effort was, thus, economically, if not environmentally. justified. But the scale of the conservation cutbacks far exceeded any reasonable estimate of the reduction in the pool of cost-effective savings. We need to

search further for a complete explanation of these developments.

A second explanation for a reduction in utility conservation spending was the possibility of deregulation. The prospect of competition at the retail level created great

uncertainties for utilities. Who would their customers be in the future? What would

be the size of the load they would have to serve? Could the costs of conservation

investments in the facilities of customers who defected to another supplier be recovered? In the absence of clear answers to these questions, utilities were reluctant to

make new investments in either supply-side or demand-side resources.

Whatever the relative weight of these causes, the end result is clear. The Northwest experienced a drastic decline in investments in conservation, even in highly

cost-effective conservation.

Today’s Conservation Opportunities

With combined-cycle combustion turbines today’s new generation resource-ofchoice. recent dramatic increases in gas prices have significantly raised the avoided

cost against which conservation investments must compete. The pool of cost-effective

conservation opportunities has substantially expanded.

In its 1998 ‘‘Northwest Conservation and Electric Power Plan,’’ the Northwest

Power Planning Council evaluated the twenty-year supply of cost-effective conservation across a range of scenarios for future electricity demand, alternative resource

costs, and water conditions. The Council concluded that, ‘‘The average amount of regionally costeffective conservation that the Council has identified is approximately

1,535 average megawatts.’’ This number did not include any savings in the aluminum industry, although the Council believed that ‘‘there is undoubtedly some additional potential in that sector, as well.’’ The average levelized cost of these 1,535

average megawatts of savings was approximately 1.7 cents per kilowatt-hour. Yes,

this is an additional 1500 aMW on top of the 1500 aMW the region has already

saved.

The 1998 Plan’s mid-range forecast assumed that average real gas prices would

escalate by about 1% per year. Obviously events have overtaken this forecast and,

in so doing. have increased the amount of conservation that is cost-effective compared to new generation alternatives. The Council’s new plan is not expected to be

completed until late 2002, but Council staff has confidently predicted that the new

long term gas, price forecasts will result in at least 2400 aMW of cost-effective energy efficiency potential in the region.

A study completed in June of this year by Council and Seattle City Light staff

reinforces the message that there’s a lot of highly cost-effective conservation out

there. The study attempted to estimate the twenty-year conservation potential in

Seattle’s service territory.

With a 50 mill avoided cost threshold, the study found that 211 to 257 aMW of

cost-effective conservation could be acquired over twenty years. The average cost of

this conservation resource was estimated to be between 1.8 and 2.1 cents per kilowatt-hour. With this information, Seattle has decided to ramp up towards a doubling of its annual conservation targets. Over the next decade the utility plans to

meet half of all load growth with conservation. And remember that this potential

exists in a city that has. over twenty years, already implemented the most aggressive conservation effort in the region.

Cost-effective conservation remains a plentiful and highly affordable resource for

the Northwest.

Load Management Opportunities

Historically Northwest conservation programs have focused on reducing the total

number of kilowatt hours used, without much regard to when, in the year or the

day, those savings occurred. In our hydro-dominated system this made sense. We

were, in the jargon of the industry, ‘‘energyconstrained,’’ not ‘‘peak-constrained.’’

That is, the hydroelectric system has enormous peak capacity - Grand Coulee alone

has a capacity of almost 10,000 megawatts - but the amount of water in the system

limits the total number of kilowatt hours that can actually be generated over a year.

It is important to recognize that this situation has changed. Even our hydroelectric system is no longer big enough to buffer us against the high marginal costs

61

of peak energy usage. The unacceptably large probabilities of being unable to meet

demand that the Northwest Power Planning Council has warned of are concentrated

in the winter months (December–February) and on a limited number of peak hours

in those months.

As the entire West Coast has seen this year, the costs of serving peak loads can

be enormous. The cost of transmission capacity that is very rarely used can, all by

itself, be larger than the ordinary cost of delivered power. If transmission capacity

is priced at $24 per kilowatt year, then capacity that is used for only 400 hours per

year costs 6 cents per kilowatt-hour actually delivered. The same economics apply

to distribution capacity that is very rarely actually used. Finally, of course, system

peaks - often driven by extreme cold-weather events in the Northwest -commonly

strike many utilities at once. This coincident demand for energy can, and does, drive

the cost of energy itself to remarkable heights. Add it all up and the value of reducing Pacific Northwest peak loads can be very substantial.

WHAT CONGRESS CAN DO

Let me close with a list of things Congress can do to assure that these renewable

energy. conservation and load management opportunities do not escape our grasp

and that the exciting potential of renewable resources does not remain mainly potential.

• Support tax credits for energy efficient new construction of buildings and homes.

• Support a ten year extension of the production tax credit for wind generating

resources.

• Support stronger appliance efficiency standards and tax credits for early adopters.

• Provide matching funds for utility-run conservation programs, e.g., rebates for

energy efficient appliances, weatherization and high efficiency industrial motors.

• Increase funding for low-income weatherization and energy assistance programs.

• Provide tax credits and other incentives for pollution control equipment to retrofit older generating plants.

• Establish a temporary federal price cap, i.e., Federal Energy Regulatory Commission implemented cost-plus pricing. Exempt new generation to get plants on

line quickly.

• Provide financial support for BPA to invest in energy conservation and purchase

more power, so it doesn’t have to rely on harming salmon to ensure this October’s Treasury payment.

• Support the use of energy efficiency and distributed renewable resources to relieve transmission congestion.

Thank you for the opportunity to present this testimony. The region does not have

to overbuild fossil fuel power plants to meet the present crisis. We have plentiful,

quick and cost-effective solutions from energy efficiency, wind and load management.

62

63

64

65

66

67

68

69

70

71

72

73

74

75

76

77

78

Mr. CALVERT. Mr. Lepp, do you—

STATEMENT OF RAY LEPP, VICE PRESIDENT AND GENERAL

MANAGER, WESTERN REGION, BIRMINGHAM STEEL CORPORATION

Mr. LEPP. Thank you, Mr. Chairman.

My name is Ray Lepp. I’m Vice President/General Manager of

the Seattle division of Birmingham Steel. The steel plant is located

in West Seattle, just minutes outside of downtown.

The plant has been in its current location on Elliot Bay since

1905. It is a permanent fixture in the city’s landscape. In fact, virtually every school, hospital, skyscraper, stadium, bridge, airport in

the Puget Sound area is made in part by the steel manufacturing

plant, and thus it helps to create Seattle’s landscape. We’ve also

provided the steel for the Bonneville power dams in the past.

Before I address the two energy-related questions, I’d like to

share a few things about our plant. Birmingham is a big recycler.

All of our feed scrap is recycled material. More than 16,000 junk

cars are recycled each month at the plant. Firearms from over 50

Puget Sound law enforcement agencies are melted down. We make

new steel from cans, discarded appliances, and other scrap metal;

thus we reduce solid waste destined for landfills and save energy

for natural resources.

Birmingham employs up to 300 skilled workers at the plant, several of whom are third-generation employees who provide great living-wage jobs to people who may not fit the high tech mold of today’s economy. Our employee turnover is less than 1 percent. We’re

an old industry but one that many people depend on. Birmingham has invested over $145 million in the plant to acquire this facility in 1991. We’ve invested in pollution control

equipment to reduce emissions, invested in noise reduction abatement, and improved the landscaping.

The plan is one of the most efficient fuel manufacturing plants

in North America. Our environmental, community service, and employee safety programs have all been recognized with awards in the

last year.

Electricity is an integral part of our process. As such, Birmingham requires a significant amount of electric energy to melt

scrap metal to produce rebar, angle bar, and other merchant bar

products that are used in construction.

Electricity is our number two cost at the plant; scrap metal is

our number one. So why do I share this information? It’s because

I feel you need to know that this plant is at risk of shutting down.

I need you to know that the steel industry is highly competitive.

With electricity being our second highest cost at the plant, these

costs can make or break us. Many of our competitors around the

country continue to have an advantage over us in this area. They

get their electricity at a lower cost, whether it be imports from

Utah or imports from China or Japan. The West Coast energy crisis is threatening our economic competitiveness.

So the questions you’ve raised are indeed timely, especially in

light of Bonneville’s projected rate increases.

Birmingham’s electric facility, Seattle City Light, receives power

from Bonneville. And those costs are passed on to us from other

79

rate payers. Seattle City Light has already increased our rates by

53 percent with an additional 47 percent projected increase coming

this July.

The lower rainfall, the low snowpack, and ESA restrictions have

hurt the region. But that’s one of the risks that one assumes, being

somewhat dependent on hydropower.

Bonneville is a great benefit to this region and one I’d fight to

preserve. I know that the latest rate filing is controversial, given

that it requires the aluminum companies to shut down for 2 years.

That doesn’t really seem right to me, but neither does the twotiered rate proposal of the aluminum companies.

In fact, Seattle City Light estimated that the two-tiered rate

would result in a cost increase to Birmingham Steel of roughly 6-

to $10 million a year. Such a shift, when added to the 53 percent

rate increases we’ve already had and the 47 percent July 1st,

would place Birmingham in a hopeless situation.

I’m not sure what the answer is, but as plant manager of the facility, it’s my responsibility and my duty to fight for and protect my

300-plus employees and 300 indirect employees.

What happens to your business if rates increase significantly?

Simply stated, Birmingham will close its doors, and 300-plus

employees will lose their jobs. A facility that employs several

second-, third- and fourth-generation employees simply will go

away.

No operator could sustain the type of increases with the rate incurred and operate this plant competitively among competitors who

aren’t faced with the same cost increases.

The only way we’ve survived this long is that several years ago,

before the current energy crisis, Birmingham faced its own crisis.

Our utility’s electric rates were threatening our competitiveness

and our viability.

We initiated discussions with our utilities to identify conservation strategies to reduce our load. Since that time, we’ve conserved

more than 10 percent by replacing equipment, reducing lighting,

and implementing other conservation strategies.

We believe we may be able to conserve an additional couple percent, but beyond that, we can’t reduce demand without threatening

our process.

We compete with imports and facilities that aren’t affected, and

we remain competitive on the strength of our award-winning energy conservation and 35 percent water conservation over the past

18 months.

To conclude, I’m here to tell you, the members of the U.S. Subcommittee on Water and Power, that this energy crisis is real, and

our clients cannot sustain these increases and stay in business.

Thank you for your time.

Mr. CALVERT. Thank you.

[The prepared statement of Mr. Lepp follows:]

Statement of Ray Lepp, Vice President and General Manager, Western

Region, Birmingham Steel Corporation

Good morning members of the U.S. Committee on Resources, Subcommittee on

Water and Power. My name is Ray Lepp, Vice President and General Manager of

the Seattle division of Birmingham Steel. The steel plant is located in West Seattle,

just minutes outside of downtown. The plant has been in its current location since

80

1905 and is a permanent fixture in the city’s landscape. In fact, virtually every

school, hospital, skyscraper, stadium, bridge and airport in the Puget Sound area

is made in part by the steel we manufacture at the plant, and thus, we’ve helped

create Seattle’s landscape.

Before I address the two energy-related questions you asked of me, I’d like to

share just a few things about the steel plant: • Birmingham is a big recycler. All of our feed scrap is recycled material—more than 16,000 junk cars are recycled each month at the plant, firearms from over

50 Puget Sound law enforcement agencies are melted down at the plant—we make new steel from cans, discarded appliances and other scrap metal. Thus,

we reduce solid waste destined for landfills, and save energy and natural resources.

• Birmingham employs over 300 skilled workers at the plant, several of whom are

third-generation employees, and we provide great living-wage jobs to people who

may not ‘‘fit’’ into the high-tech mold of today’s economy. Our employee turnover

is less than 1%. We’re an old industry, but one that many people depend on. • Birmingham has invested over $145 million in the plant since acquiring the facility in 1991—we’ve invested in pollution control equipment to reduce emissions, invested in noise reduction abatements and improved landscaping—the

plant is one of the most efficient steel manufacturing plants in North America.

Our environmental, community service and employee safety programs have all

been recognized with awards in the last year.

• Electricity is an integral part of the steel manufacturing process. As such, Birmingham requires a significant amount of electric energy to melt scrap metal

to produce rebar, angle bar and other merchant bar products that are used in

the construction of roads and buildings. Electricity is our number two cost at

the plant—scrap metal is our number one cost.

So why do I share this information with you? I share this information with you

because I need you to know that this plant is at risk of shutting down. I need you

to know that the steel industry is a highly competitive industry, and with electricity

being our second highest cost at the plant, electricity costs can make or break us.

Many of our competitors around the country continue to have an advantage over us

in this arena—they get their electricity at a lower cost. Whether it be Nucor in

Plymouth Utah or imports from China . . . the West Coast energy crisis is threatening our economic competitiveness.

So, the questions you’ve raised are indeed timely, especially in light of BPA’s projected rate increases. Birmingham’s electric utility, Seattle City Light, receives

power from BPA, so those costs are passed on to us and other ratepayers. Seattle

City Light has already increased our rates by 53% with an additional 47% increase

coming this July. The lower rainfall, low snowpack and ESA restrictions have hurt

this region, but that is one of the risks one assumes being somewhat dependent on

hydropower. BPA is a great benefit to this region and one that I’d fight to preserve.

I know that the latest rate filing is controversial given that it requires the aluminum companies to shut down for two years. That doesn’t really seem right to me,

but neither does the ‘‘two-tiered rate’’ proposed by the aluminum companies. In fact,

Seattle City Light estimates that the ‘‘two-tiered rate’’ would result in a cost increase to Birmingham of roughly $6–10 million a year. Such a shift, when added

to the 53% rate increases we’ve already incurred and 47% rate increases proposed

for July 1st, would place Birmingham in a hopeless situation. I’m not sure what the

answer is, but as plant manager of this facility, it is my responsibility and my duty

to fight for and protect my 300 plus employees and 300 indirect contract employees.

What happens to your business if rates increase significantly? Simply stated, Birmingham will close its doors and the 300 plus employees will lose their jobs; a facility that employs several second, third and fourth generation employees will simply

go away. No operator could sustain the type of increases we’ve already incurred—

a 53% rate increase already imposed and an additional 47% rate increase proposed

for July 1st—and operate this plant competitively when its competitors aren’t facing

the same cost increases. Add the latest increases to the estimated $6–10 million

‘‘two-tiered rate’’ shift and there is no question that we would go out of business.

The only way we’ve survived this long is that several years ago, before the current

energy crisis, Birmingham faced a crisis of its own—our utility’s electricity rates

were threatening our competitiveness and economic viability. We initiated discussions with our utility, Seattle City Light, to identify conservation strategies to reduce our load. Since that time, we’ve conserved more than 10% by replacing equipment, reducing lighting and implementing other conservation strategies. We believe

we may be able to conserve an additional 2–3%, but beyond that, we cannot reduce

demand without threatening our manufacturing process. We compete with imports

and facilities that are not impacted by the West Coast energy crisis. We have reVerDate 11-MAY-2000 15:39 May 07, 2002 Jkt 000000 PO 00000 Frm 00084 Fmt 6633 Sfmt 6621 J:\DOCS\72516.TXT HRESOUR2 PsN: HRESOUR2
81

mained competitive on the strength of our award-winning energy conservation and

35% water conservation efforts over the past 18 months.

How does it affect your employee’s production and your competitiveness? I believe

that I’ve already answered this—simply stated, production will decrease because we

can’t compete with competitors who aren’t experiencing the same cost increases.

To conclude, I’m here today to tell the members of the U.S. Subcommittee on

Water and Power, that this energy crisis is real and that this plant cannot sustain

these increases and stay in business.

Thank you for your time. I’m available to answer questions.

Mr. CALVERT. Dr. Anderson?

STATEMENT OF JAMES J. ANDERSON, ASSOCIATE PROFESSOR,

SCHOOL OF AQUATIC AND FISHERY SCIENCES, UNIVERSITY

OF WASHINGTON

Dr. ANDERSON. Thank you, Mr. Chairman.

I’m Associate Professor in the School of Aquatic and Fishery

Sciences at the University of Washington.

I’ve been working on Columbia River salmon and power issues

for two decades. They went by quickly.

I—the first time I presented before this Committee was in 1995.

At that time, the fish runs going up the Columbia were the lowest

on record. There were 10,000 fish that came back in the spring of

that year.

This year, we have 350-—370,000 fish that returned to the river,

plus the drought. That was a tremendous number of fish. In fact,

it’s a record since the time we’ve been keeping records, going back

to the ’30’s. We have more fish that have gone up the river this

year than ever before.

In my testimony, I show a couple of graphs that give you a visual

impact of what this is. This is completely unexpected, particularly

since in 1995, we were talking about taking out the dams. We

thought fish were going to be extinct in a very short period of time.

Why are these runs coming back right now? Well, what I was

saying back then—as many scientists who were believing and finding through their data—there were great variations in the ocean

which are driving—is a major driving factor for the productivity of

these stocks.

So what I want to do is give you a little characterization of what

that variability is and then how the different actions we are taking

in the hydrosystem affect the survival of these stocks relative to

that variability in the ocean.

I present in my testimony a number of figures which show the—

the daily return of runs over 40 years of the major stocks into the

major regions of the—of the—of the basin. If you look at those,

what you find is there is a variability, a scale change. In the ’60’s

and ’80’s, the stocks were fairly high. In the ’70’s, in the ’90’s, they

were—they were low. And it appears again that the stocks are increasing. Certainly this year and the last year, we’ve had some better runs into the system, in general. And this year, we have a spectacular run.

So we have a little reprieve from extinction, at the very—at the

very least. And what we need to do is, in short, to begin to use the

information that we have on the system so we can take a little load

82

off demand off the hydrosystem and still be able to—to recover the

fish, still be able to generate electricity.

What this means is we have to use the information we have

available, and we have to use it in a rational manner. I don’t believe that we are doing—clearly, we are not doing as well as we

could with that.

Six years ago, we thought what we needed to do was take out

the dams. Now we realize that there is a multitude of factors.

What I want to do now is discuss the basic things that we do in

the hydrosystem: flow augmentation, spill, and transportation, in

fairness to the ocean, to give you kind of an idea of how this all

needs balance with each other.

There’s been a lot of studies looking at the relationship between

flow and survival. We find that survival—to plot the year-to-year

survival with the year-to-year flow, there is a relationship.

The higher—the wetter the water year, the more survival you

have going through the river; the more fish come back. If you look

within a season, if you see how the flow changes from the beginning of the migration through the end, there is no relationship

we’ve been able to find in the hydrosystem between flow and survival.

We’ve talked about water augmentation. This does not affect

flow. It’s not a significant factor that we can show any impact. In

fact, it could be—in some situations, water augmentation warms

the system, and it could be detrimental to the fish.

The point on ‘‘spill’’ is spill has a very small impact. It has a theoretical impact. But compared to other measures we can take, it’s

very expensive and very ineffective. Transportation is the most effective way that we have to get fish through the river.

This year, we have—for every one fish—for every ten fish that

come back through in-river routes, we have 15 fish that come back

through transportation. The river transport studies show that this

is a good way to move fish; we should continue to do this.

Now, the final point I want to make is that the ocean is a factor.

It’s a big factor. In 1995, we had a quarter percent of the fish come

back. This year we have on the order of 2 to 3 percent. This is a—

a tenfold factor, in a relative sense, a thousand percent increase in

survival because of the ocean. Our hydrosystem factors, in a relative sense, might give us a 1 to 10 percent increase.

Now, my final point, then, if we understand and factor in what

the ocean does, we have some flexibility in how we operate the

hydrosystem. We don’t—I believe we do not have to make draconian measures in the hydrosystem when ocean systems exist.

And I’ll conclude my testimony with that.

Mr. CALVERT. Thank you, Doctor.

[The prepared statement of Mr. Anderson follows:]

Statement of James J. Anderson, Associate Professor, School of Aquatic

and Fishery Sciences, University of Washington

My name is James Anderson; I am an Associate Professor in the School of Aquatic

and Fishery Sciences at the University of Washington. My research over the past

two decades has involved Columbia River salmon and the influence of the

hydrosystem and climate on the survival and productivity of the stocks. I wish to

thank the Power Water Subcommittee for this opportunity to testify on the current

science and status of fish populations in the Columbia River system.

83

Background

I first appeared before this committee in June of 1995 and testified on the state

of Columbia River salmon (Anderson 1995). That spring the salmon run in the Columbia River was the lowest ever recorded. In my testimony I explained how scientists were finding that throughout the North Pacific marine populations were correlated with decadal-scale patterns of ocean temperatures and currents. I suggested

that the very low salmon populations were in part due to climate change. The young

salmon smolts were entering a warm ocean in which food was scarce and warmwater predators were abundant. I concluded that the fate of the endangered salmon

was strongly determined by what happened in the ocean (See Anderson 2000 for

summary). At that hearing the committee also heard from witnesses claiming that

the fish were doomed to extinction unless the Snake River dams were removed. The

hearing encapsulated an ensuing scientific debate, reduced to whether the salmon’s

decline was nature’s fault or the dam’s fault.

Now, six years later the region is face with a near record drought, the value of

the water has raised the cost of salmon recovery to billions of dollars, and the largest spring chinook run in 40 yrs has just returned to the Columbia. The question

is no longer whether the ocean is major contributor to population variations. The

question now is what is the real value of recovery measures in terms of fish survival. In my testimony I review the status of the stocks and the scientific information on the effectiveness of current hydrosystem actions to aid fish survival.

Salmon population status

Returns of wild salmon are not yet available for this year, but the counts at dams,

which include both hatchery and wild fish, indicate a good year for 2001 following

on the good returns from 2000. Over 360,000 spring chinook passed Bonneville dam

this spring. On the peak day, twenty seven thousand fish passed Bonneville, which

is nearly three times the entire spring run in 1995. illustrates how incredible the

difference was between the two years. This year the run is five times larger than

the ten-year average. Last year 177,000 spring chinook returned, which was one the

largest run in 20 years.

Figures 2 through 8 show the daily counts of adult salmon returning to the Snake

and the mid–Columbia and put the recent runs in a historical context spanning 40

years. The Snake River chinook population was low in the early 1980s and throughout the1990s. It increased in 2000, and this year the run was the largest on record.

84

The Snake River sockeye exhibited a decline in the early 1980s and reached near

extinction levels in the 1990s. However, the captive brood program and improved

ocean conditions are likely factors attributable to the small increase in 2000 ().

Snake River steelhead population was low in the 1970s and has increased largely

through a hatchery program. Currently, the wild run is about 10% of the hatchery

run ().

In the Mid–Columbia, the chinook were also low in the 1970s, but have improved

over the last two years presumably because of improving ocean conditions ().

85

Mid-Columbia sockeye returns were low in the1990s but improved in 2000 ().

The mid–Columbia steelhead run has been small for 40 years. It was especially

low in the mid 1990s and increased in 2000. The run is essentially maintained as

a hatchery program ().

The passage of chinook at McNary Dam characterizes the total Snake and Columbia River runs. Note the double peak each year. The first peak represents the Snake

River spring chinook and the second peak is mostly composed of Hanford Reach fall

chinook. The total run was low in the 1970s and the 1990s. Again, this year’s return

is the highest in the record ().

86

Finally, to put the 2001 drought into perspective, the daily flow at McNary Dams

between 1962 and 2001 is illustrated in . Three significant droughts have occurred:

1973, 1977 and 2001. In these years the spring runoff peak is essentially missing

from the daily record.

Several general characteristics are noteworthy in these records. First, the returns

represent both hatchery and wild stocks with wild fish dominating the runs in the

early part of the record and hatchery fish dominating in the recent years. Second,

the records demonstrate that salmon populations vary on decadal scales and between years. Stocks were generally higher in the 1960s and 1980s and lower in the

1970s and 1990s. Year-to-year variations in all stocks are considerable. It is not uncommon for a stock to increase or decrease by a factor of two to three from one year

to the next.

Status of Salmon Science

In my testimony six years ago I presented information that the ocean was a significant factor in determining the survival of salmon populations. This hypothesis

was not controversial to many ecologists, but it was largely ignored by Columbia

River fishery managers, who attributed the decline of the stocks to the hydrosystem.

Today, with six additional years of research coupled with a significant change in the

ocean there is acceptance that the year-to-year and decadal scale variations typified

in the figures above cannot be attributed to any single factor; be it the ocean currents, sea surface temperatures, coastal winds, river flows, or dam operations. Because many factors are beyond our control, fishery managers have focused on

hydrosystem operations as primary recovery measures: flow regulations, river temperature regulation, and dam operations. The strategy assumes that managing the

hydrosystem within specified physical standards will improve fish survival and facilitate fish recovery.

87

However, because of the increasing value of the water and concerns as to the effectiveness of control measures, the strategy of operating the hydrosystem according

to physical standards alone is not sufficient. Managers need to base the physical actions in terms of the resulting biological impacts on the salmon and especially in

terms of survival. The effectiveness of actions needs to be put in the perspective of

their contribution to the overall life history of the fish. I will briefly discussion the

major hydrosystem actions and their effectiveness.

FLOW AUGMENTATION

A significant question during this drought concerns the effectiveness of flow augmentation in improving fish survival. To address this question it is important to

first realize that a relationship of seasonal flow and smolt survival within a year,

or a relationship of flow and survival between years, does not imply flow augmentation will increase survival. Flow augmentation is produced by scheduled releases

from storage reservoirs and by limiting municipal and agricultural withdrawals.

Flow augmentation does not change the yearly averaged flow; it only reshapes the

runoff over the season. Flow augmentation has a small and variable impact on the

natural seasonal flow, temperature and turbidity, because the natural patterns are

driven by the unregulated tributary runoff while flow augmentation is mostly from

storage reservoirs.

Based on flow and smolt survival research, a relationship has been found between

yearly-averaged flows and the survival of chinook and steelhead passing through the

hydrosystem. However, the same research demonstrates that seasonal flows are not

correlated with hydrosystem survival. Because flow augmentation makes up a small

portion of the seasonal flow, it too is not correlated with smolt hydrosystem survival.

A relationship between seasonal flow and survival of fall chinook migrating from

Hells Canyon to Lower Granite Dam has been observed in studies. Here again, the

contribution of flow augmentation to this seasonal flow is small and the potential

impact on survival is not measurable. Furthermore, there is a reasonable possibility

that flow augmentation from the Hells Canyon dam complex may in some years decrease fish survival (Anderson, Hinrichsen and Van Holmes 2000). The research indicates that the natural seasonal patterns of flow, temperature and turbidity are

correlated, so simple correlations any of these variables with smolt survival does not

identify which one may affect survival. Based on fish bioenergetics, increased temperature will increase smolt mortality and since water releases from Hells Canyon

can increase the Snake River temperature, augmentation can increase mortality.

Furthermore, in these studies fish travel time was uncorrelated with flow, so it has

no effect in reducing smolt exposure time to predators.

Simply put, flow survival studies conducted over 8 years indicate that the impacts

of flow augmentation on smolt survival are not measurable at best, may be neutral,

and in some situations may decrease survival. Potential impacts of flow augmentation on survival can be estimated with models. However, the benefits were not estimated in the NMFS Biological Opinion.

DAM PASSAGE AND SPILL

Studies on smolt dam passage indicate benefits for smolts passing dams in spill

water compared to passing through bypass systems and turbines. However, recent

model analyses show the benefits of spill are small. Not spilling at Columbia River

dams this year decreases the total passage survival of Snake River smolts from

about 50% to 49%; a difference of 1%. The net change for Mid Columbia smolts is

about 10% and for lower Columbia River smolts is about 3% (NWPPC 2001).

Considerable progress has been made on identifying the impacts of hydrosystem

operations on the upstream migration of adult salmon (Bjorn et al 2000). Of concern

is the effect of spill. Periods of high spill appear to delay salmon passage and increase fall-back across the dams.

TRANSPORTATION

The vast majority (80 to 98%) of salmon smolts from the Snake River reach Bonneville tailrace in barges. Ninety-eight percent of the fish survive the barge trip, but

after release the fish die at a higher rate than smolts that have arrive at Bonneville

tailrace via in-river migration. If this differential mortality of transported fish relative is equal to the mortality of smolts passing through the river, then barging has

no benefit over in-river passage. In normal and low water years it is believed that

barging is better for Snake River salmon and this is the preferred strategy for this

year. Barging mid–Columbia salmon is less effective because the fish must migrate

88

through several of dams before they reach McNary Dam, from which can be transported.

Ultimately the efficacy of transportation depends on the level of differential mortality. Few reliable estimates are available and it appears to vary between species,

over the season, and from year-to-year. Furthermore, the reason why transported

fish die at a greater rate than fish that have passed through the hydrosystem is

unclear. Hypotheses, focusing on stress in transportation, suggest it may be possible

to improve the transportation system, making it the preferred passage route.

OCEAN EFFECTS

Over the past six years a number of studies have correlated ocean variables and

marine populations. For example, Alaskan and west coast salmon have an inverse

relationship with decadal scale cycles in ocean currents and temperatures (Hare,

Mantua and Francis 1999). Between 1977 and 1998 ocean conditions, characterized

by the Pacific Decadal Oscillation (PDO), favored Alaskan salmon and were detrimental to west coast salmon. In 1998, the PDO reversed and correspondingly west

coast salmon stocks increased while many Alaskan stocks declined. Studies in the

Oregon coastal waters confirm a recent and significant increase in the abundance

of salmon food (Peterson 2000). An article in the Seattle Times noted ‘‘This is the

third spring in a row that scientists working out of Newport have encountered a

fertile Pacific, a trend that began in one of the wettest Northwest years on record

and has continued even as onshore weather patterns this year set the stage for a

severe drought (H. Bernton, Seattle Times staff reporter, May 09, 2001)

COMBINED EFFECTS OF OCEAN AND HYDRO OPERATIONS ON SALMON

An important step in setting hydrosystem performance standards and selecting

recovery actions is to recognize and adjust for the considerable influence that ocean

and climate cycles have on salmon populations. The improved ocean conditions over

the past three years have benefited both wild and hatchery stocks and are a major

factor in the record returns of spring chinook. The data suggest ocean factors outweigh the effect of hydrosystem operations. Comparing smolt to adult survival from

the 1995 outmigration to the 1998 and 1999 outmigrations, the survival has increased from 0.25% in 1995 up to about 2% in 1998–1999 period. This 1000% increase in relative survival can creditably be attributed to the increased productivity

in the ocean. In comparison, the relative change in survival with spill and flow augmentation have been estimated to be on the order 1 to 10%. This comparison to the

poor conditions in the mid 1990s is relevant because virtually all estimates of salmon extinction and recovery probabilities assume the ocean remains in the extreme

poor state of the 1990s.

A recent paper on recovery options concluded that even dam breaching would not

recover the stocks under the conditions that existed for brood years 1990–1994

(Kareiva, Marvier, McClure 2000). However, the paper did not mention that the

years used in the analysis represented some of the warmest years on record (See

89

the PDO in ). If the analysis were revisited, including both good and bad ocean conditions, the conclusions would be significantly different. In fact, an analysis in the

Plan for Analyzing and Testing Hypotheses (PATH) demonstrated that with a regime shift back to cool ocean conditions, the stocks would recover without changes

to the hydrosystem (Marmorek, Peters, Parnell 1998). The majority of PATH participants rejected this hypothesis as unrealistic, with little chance that the smolt-toadult survival could rise above 1%. However, the recent shift in the ocean follows

the analysis assumptions, and if the ocean survival persists through this decade, the

PATH analysis suggests the stocks would recover without aggressive the

hydrosystem operations. However, most analyses on salmon recovery to date consider scenarios that require draconian measures to save the stocks from extinction.

Conspicuously absent are analyses that include ocean cycles.

I am not suggesting that salmon will recover irrespective of societal efforts. Such

a stance would be irresponsible. But to implement performance measures without

regard to their benefits in relationship to the status of the ocean is equally irresponsible. Science, in service of salmon recovery and management, must assess the impacts of physical actions in terms of their biological effects on the stocks. The

science must quantify biological performance through monitoring, and where the

data is insufficient, through biologically realistic models. Furthermore, the science

must seek to understand the mechanisms by which the environment affects salmon

survival.

The improved ocean conditions give salmon a temporary reprieve from extinction.

But, eventually the ocean will warm again and with or without a drought, the competing demands for the water will be great. If we continue to increase our understanding of salmon ecology and if we begin to realistically assess the benefits of recovery actions, we may be able to meet the coming challenge. However, if we forgo

learning and disregard quantified analyses in making decisions, salmon management could face a failure of public trust and salmon recovery would be jeopardized.

References and Notes

Anderson, J. J. 2000. Decadal climate cycles and declining Columbia River salmon. In Sustainable Fisheries Management: Pacific Salmon. Edited by E. Knudsen et.

CRC Lewis Publishers, Boca Raton. p. 467–484. (www.cbr.washington.edu/papers/

jim/victoria.html)

Anderson, J. J., Testimony presented before the Subcommittee on Water and

Power of the US House of Representatives Committee on Resources. June 1995

Washington D.C.

Anderson, J. J., R. A. Hinrichsen and C. Van Holmes. 2000. Effects of Flow Augmentation on Snake River Fall Chinook. In Comments on Idaho Water Users on the

draft All–H paper by the Federal Caucus: Conservation of Columbia Basin Fish–

Building a conceptual recovery plan. Submitted on behalf of the Committee of Nine

and the Idaho Water Users Association. March 16 2000.

Bjorn et al 2000, Migration of adult spring and summer chinook salmon past Columbia and Snake River dams, through reservoirs and distribution into tributaries,

1996

DART. 2000. Data Access in Real Time. (http://www.cbr.washington.edu/dart/

dart.html)

Hare, S. R., N. J. Mantua and R. C. Francis. 1999. Inverse production regimes:

Alaskan and West Coast Salmon. Fisheries 24(1):6–14. (www.iphc.washington.edu/

Staff/hare/html/papers/inverse/abst—inv.html).

Kareiva, P. M. Marvier, M. McClure 2000, Recovery and Management options for

spring/summer chinook salmon in the Columbia River Basins, Science 290(3) 977–

979.

Marmorek, D.R., C.N. Peters and I. Parnell (eds.) 1998. Plan for Analyzing and

Testing Hypotheses (PATH): Final Report for Fiscal Year 1998 (ESSA Technologies,

Vancouver, Canada, 1998

Peterson, W. T. 2000. RECENT SHIFTS IN ZOOPLANKTON ABUNDANCE AND

SPECIES COMPOSITION OFF CENTRAL OREGON. Beyond El Nino. PICES conference (North Pacific Marine Science Organization). (pices.ios.bc.ca/elnino/abstracts.htm)

Mr. CALVERT. Mr. Rob Walton.

90

STATEMENT OF ROBERT G. WALTON, ASSISTANT MANAGER,

PUBLIC POWER COUNCIL

Mr. WALTON. Thank you, Mr. Chairman, members of the Subcommittee.

Thank you very much for this opportunity to testify about job

management and energy availability in the Pacific Northwest.

My name is Robert Walton. I’m the Assistant Manager of the

Public Power Council, a regional association representing the consumer-owned utility customers of BPA.

Our members include municipal and cooperative utilities and

PUD’s in five states. You’ve mentioned Snohomish PUD, Tacoma

City Light, Eugene Water and Electric Board. Those are some of

our members.

I submitted written testimony to you, including analysis by the

Northwest Power Planning Council staff on the power supply situation and the biological impact of reduced spill.

I’d like to depart from those written comments in my 5 minutes

and summarize my perspective on the short- and long-term issues

that we face.

In the short term, as many of the speakers have described, the

drought has put tremendous pressures on the Federal agencies in

the region. I see a tug-of-war, which is pretty clear, over the issue

dozzer, which is how to use the water in the Columbia River this

year.

Pulling in one direction are the fish advocates. And you’ve heard

from the Yakima tribal leader, Randy Settler, today. And there are

others who argue that we should support the out-migrating smolt

by spilling water—spill—spill water, to implement the Endangered

Species Act, the Federal trust and treaty responsibilities, and nontribal harvest.

Pulling in the other direction are members of the power community and many members of the—the economic sector in the region.

Mr. DeFazio said earlier that the public won’t tolerate an unreliable power system; this isn’t India. That’s exactly why we’re arguing against spill this year. Many people consider the water in this

drought, in this energy crisis too valuable to spill.

And some of the evidence suggests that the biological benefits

from spilling this year are not sufficient to warrant the high cost.

As Dr. Anderson suggested, we have a record run this year of

spring chinook. And it’s interesting to note that the harvest rate

on the salmon in the river—which includes the nonlisted and the

listed species—has gone up this year from 9 to 15 percent.

So in our written comments, PPC supports the declaration of

emergency—the—operating the Federal system to meet load supporting—supports the criteria to maintain a reliable system and

would support the extraordinary measures that Mr. Wright described.

We certainly support the responsibility of the power system to

mitigate the impacts that the dams have on fish and wildlife.

In the longer term, I’d like to offer my perspective on some failures that I see interestingly in common between energy policy and

salmon management policy. I think both can be described as being

stuck in the middle between alternative courses of action.

91

The result in both salmon and energy policy is irrational decisions that are being made that take us in neither direction.

I’d like to quote from—from my written testimony from a passage

that was published in May 1994 by the first National Marine Fisheries Service Recovery Team, the so-called ‘‘Debbon’’ (phonetic)

team—quote, ‘‘There is no directed authority or accountability to

ensure effective management of the overall system.’’.

By the way, they’re talking about fisheries’ management, but I’d

like you to think in terms of both fish and power.

The bottom line is a classic situation. Among a myriad of agencies and interests, no one, really, is in charge. Institutional, jurisdictional, state, and Federal boundaries make rational overall fisheries management decisions impossible. Each agency has its own

area of designated authority and responsibility and gets its own

funding and sets its own goals, leading to its own special projects

and agenda, all of which are budget-dependent.

It seems to me in the fish arena, we have a—we’re stuck in the

middle between two potential salmon management strategies. One,

as advocated by National Marine Fisheries Service, would have us

manage their tiny populations of naturally spawning native wild

fish. If so, it seems to me that there’s a very difficult opportunity—

chance that the Federal agencies will be able to meet their—their

obligations to provide harvest to the tribal and nontribal fishermen.

If this continues to be our salmon policy, it’s hard to justify killing these salmon for fun and profit. As an alternative, they could

manage for the state-of-the-art use of artificial production hatcheries to produce the kind of fish that can spawn naturally or in

hatcheries to try to build the fish runs that are capable of harvest.

On the energy side, I don’t think I need to tell members of the

Subcommittee—you’ve already stated it very eloquently today—

we’re stuck in the middle between a regulated system that had a

clear assignment of responsibility, a clear obligation to serve, a

clear obligation to maintain reserves, a clear obligation to keep the

rates down and, on the other side, as some people have described

it, the genius of the marketplace, with a deregulated system. We’re

stuck in between the combination of both the—the—the power and

the fish policies—is that the regional execs are being asked to

make decisions right now in the short term—spill or not spill—

when, in fact, the long-term policies behind both fish and power

strategies, in my mind, are not clear enough to lead us to long-term

success.

Thank you.

Mr. CALVERT. Thank you.

[The prepared statement of Mr. Walton follows:]

Statement of Robert G. Walton, Assistant Manager, Public Power Council

Mr. Chairman, Members of the Subcommittee: thank you very much for this opportunity to testify about Drought Management and Energy Availability in the Pacific Northwest. These are very timely and important subjects for the Subcommittee

to consider and I appreciate your interest and attention.

My name is Robert Walton. I am the Assistant Manager of the Public Power

Council (PPC), a regional association representing the consumer-owned utility customers of the Bonneville Power Administration (BPA). PPC’s members include municipal and cooperative utilities and public utility districts (PUDs) in 5 states. These

consumer-owned utilities purchase power and/or transmission from BPA and proVerDate 11-MAY-2000 15:39 May 07, 2002 Jkt 000000 PO 00000 Frm 00095 Fmt 6633 Sfmt 6621 J:\DOCS\72516.TXT HRESOUR2 PsN: HRESOUR2
92

vide the largest share of BPA’s income, which is used to fund BPA’s treasury payments and the fish and wildlife program, along with other programs and obligations.

As the entities that pay the bills, we have a direct interest in scrutinizing BPA’s operations and expenses regarding power generation and fish and wildlife mitigation. But as consumer-owned utilities, we do not merely seek to keep the lights on

and reduce costs. We also reflect our customers’ interest in a healthy environment

with thriving fish and wildlife populations. What we seek is cost-effectiveness, program accountability and demonstrable results.

My testimony today addresses two issues.

• How will Federal agencies operate the Federal Columbia River Power System

(FCRPS) this year: spill water over dams to increase survival of salmon or use

that water to maintain a reliable electrical power system?

• General concerns about a lack of accountability in the management of salmon

and electrical reliability.

PPC’s Recommendation to the Federal Agencies Regarding Operation of the

Columbia River

PPC commends the Federal agencies for assigning top priority to maintaining

power system reliability and public safety. We recommend the agencies continue to

utilize the provisions in the Biological Opinion that allow for emergency operations

of the Federal Columbia River Power System.

In particular, PPC supports the declaration of a power emergency and continued

implementation of the April 13 draft operating plan for the Federal Columbia River

Power System (FCRPS). (See letter to BPA Acting Administrator Steve Wright on

May 10, Attachment A.) Although the Biological Opinion calls for extensive ‘‘spill’’ to aid salmon migration, the draft operations plan determines the amount of water

spilled for fish based on the volume forecast for water runoff in the system. Due

to the extremely low runoff forecasts to date, the Federal agencies would not spill

any water this year under the current criteria.

Top Priority for Water Stored in the FCRPS Should Go to Maintaining the

Reliability of the Pacific Northwest Power System

The Federal agencies have established criteria to ensure the region can meet

power demand in the near term and next winter. For example, criterion 2 in the

Federal agencies’ operating plan established a goal of maintaining a 5% loss of load

probability in future months. PPC supports this criterion, but is troubled that the

drought and West Coast energy situation may make it impossible for the agencies

to maintain that level of reliability. In fact, the region is working hard to maintain

a reliability in the 20% to 26% range. To PPC, a 20% chance that the region would

fail to meet load this winter is not consistent with a reliable power system.

Faced with a goal of 5% loss of load probability and analyses that indicate a 20%

or higher loss of load probability, PPC concludes that the prudent course of action

for the Federal agencies is to store as much water as possible in the FCRPS to meet

future load.

Without the declaration of a power emergency and implementation of the current

operating plan, the Federal agencies would be forced (under the 2000 Biological

Opinion) to spill water over the dams instead of running it through the generators.

The Northwest Power Planning Council has estimated (see Attachment B) that this

water, if run through the generators, would produce over 6600 mw-months of energy

in the Federal system. PPC supports the conclusion reached by Council and BPA

staff that the loss of this amount of energy would do serious harm to the region’s energy supply, increasing the risk of blackouts in the Northwest.

PPC’s member utilities are participating, along with Investor–Owned Utilities, the

Governors and many others in the region, in a widespread effort to reduce electrical

load and increase electrical generation. There are some signs of progress in these

efforts. The potential consequences of a power system failure in the middle of winter, however, are so onerous that PPC urges the Federal agencies to err on the side

of ensuring the reliability of the power system.

The Impact that Spilling Water would have on the Economy of the Pacific Northwest

In addition to reducing power system reliability, spilling large amounts of water

would cost the region a lot of money. The Council estimated the value of power that

could be generated if spill were eliminated to be more than $ 1 billion (see Attachment B). These are costs that would ultimately be borne by the region’s ratepayers.

BPA’s utility customers face the prospect of a wholesale rate increase this October

estimated to be between 80% and 250% over current levels. The impact of such an

increase could have devastating impacts on the region’s economy, resulting in the

loss of thousands of jobs and economic harm to the region’s residential customers.

If Federal agencies were forced to spill water for fish, the additional costs would add

93

to the size of the rate increase, resulting in additional economic displacement in the

region.

The Impact that Elimination of the Spill Program this Year would have on Salmon

BPA’s customers understand and support the obligation to mitigate for the impact

of the dams on fish and wildlife in the Columbia Basin. However, we haven’t always

supported the specific measures that have been implemented. The power industry

has been skeptical about the biological benefits of flow augmentation and spill for

years. In times of high energy prices, the cost-effectiveness of spilling water to increase survival of juvenile salmon has been particularly suspect.

PPC’s decision to support elimination of spill this year is based in large part on

recent preliminary analyses by the Power Planning Council Staff (see Attachment

C). Using a National Marine Fisheries Service (NMFS) model and data, the Council

analyses suggested that relatively few adult salmon would be lost as a consequence

of eliminating the 2001 spill program. One of the major reasons for this is the fact

that NMFS has decided to put most of the fish in barges, not left in the river this

year. The analyses suggested that elimination of spill would cause a modest decrease in survival of the juvenile fish in the river, but the impact on the entire outmigration was only a few percent. After considering the low ocean survival of these

fish, the analyses suggests the impact of eliminated spill would result in the loss

of a relatively small number of adult salmon.

A number of scientists for fisheries agencies and tribes have criticized the Council

staff’s preliminary analysis. Some of their criticisms may have merit, but even if the

preliminary analyses are off by an order of magnitude or more, point seems to be

the same: we could significantly reduce the reliability of the region’s power supply

and increase the cost of electricity in the current situation, but save a relatively

small number of salmon in the process. From a power system perspective, it would

be imprudent to spill water this year, given the apparent ranking of costs and benefits.

Who is in Charge of Keeping the Lights on and Managing the Salmon?

In May, 1994, seven experts appointed by NMFS released their report entitled:

‘‘Snake River Salmon Recovery Team: Final Recommendations to National Marine

Fisheries Service.’’ In the report (page III–1), they stated:

There is no directed authority or accountability to ensure effective management of the overall system. The bottom line is a classic situation: among

myriad agencies and interests, no one really is in charge. Institutional, jurisdictional, state and Federal boundaries make rational overall fisheries

management decisions impossible. Each agency has its own area of designated authority and responsibility, gets its own funding, and sets its own

goals—leading it to its own special projects and agenda, all of which are

budget dependent. For example, in the early 1980s, the NPC developed a

water budget with hopes that rigorous data would be collected to test and

enhance its effectiveness. For more than a decade, the critical data have not

been collected.

Unfortunately, this six year-old quote still rings true in 2001, but now it also

seems to make an important point regarding the management of electrical power

as well as salmon resources.

As the Pacific Northwest and the West Coast face increasing challenges to maintain electrical power system reliability, the quote from the recovery team applies:

no one is in charge of keeping the lights on. That is, no single entity or person is

has the responsibility to ensure that the lights stay on in the region and along the

West Coast. BPA, NMFS and other Federal agencies are making decisions to generate or spill on the Columbia River, but they don’t have responsibility for all the

electrical power control areas in the region. Neither FERC nor the Department of

Energy appears to have clear responsibility to maintain a reliable power system. Individual utilities may have an obligation to serve, but not beyond their service territories. Certainly the independent power producers don’t have a responsibility to

keep the lights on.

Regarding the management of salmon, the Endangered Species and Northwest

Power Acts, trust and treaty relationships to tribes, international treaties and other

statutes all apply to the Federal agencies. As the recovery team stated in May,

1994, no one entity has taken charge of managing the salmon resource. One result

of this situation is a failure to establish clear goals or a definition of success in

terms of salmon recovery.

We would like to offer one example of the current situation. It is a fact that the

number of salmon and steelhead species listed under the Endangered Species Act

in the Northwest is increasing, and some of those species are in serious decline.

94

However, a significant portion of ratepayer money directed at salmon recovery over

the last 20 years has been spent on developing a huge hatchery program. The result? This year’s return of spring chinook above Bonneville Dam is the largest in

over 60 years, but most of the fish are of hatchery origin. As the following graph

shows, this year’s return is about five times higher than the ten-year average.

This large number of salmon ought to be good news, but it isn’t exactly a success

story, because there is no way to harvest the hatchery fish without killing fish protected by the Endangered Species Act. As a result, salmon managers are faced with

the choice of either killing the hatchery salmon to keep them from spawning (assuming they can identify the hatchery salmon) or having them spawn in the same

waters as the protected salmon and thereby changing the genetic makeup of the

protected salmon. This is one of several consequences of a failure to establish clear

lines of responsibility.

PPC would like to participate in and support a reliable and affordable electrical

power system as well as a successful salmon rebuilding effort. Without clear lines

of responsibility and accountability, however, success is much harder to achieve.

Thank you for this opportunity to testify before your Subcommittee.

ATTACHMENT A

May 10, 2001

Mr. Stephen J. Wright, Acting Administrator

Bonneville Power Administration

905 N.E. 11th Avenue

Portland, OR 97232

RE: To Spill or Not to Spill

Dear Steve:

The choice of whether to spill at Federal dams in May forces the Federal agencies

to manage competing risks. PPC believes the agencies should continue to assign top

priority to maintaining power system reliability and public safety.

Specifically, PPC believes that the agencies should continue to operate the Federal Columbia Power System pursuant to the declared power emergency and implement the criteria in the April 13 Draft Plan. The criteria in the plan are objective

and reasonable, especially in light of the substantial risk that BPA will not be able

to meet its power obligations.

Grant PUD recently asked FERC to approve a temporary emergency variance of

the interim spill requirements at Grant’s projects. Specifically, Grant makes this request so that the District can make that generation available for critical regional

energy needs, for the purpose of displacing generation at other hydro projects where

spill may be more effective in passing fish this year than at the District’s Priest

Rapids Project and/or for the purpose of facilitating other power and fishery measures in this unusual low water year.

95

At this point, PPC sees the Grant proposal as the only compromise available to

the Federal agencies in their attempt to balance in-river survival with power system

reliability. Therefore, PPC supports the proposal—if it is approved by FERC.

We appreciate your efforts to implement the criteria in the April 13 Draft Plan

while looking for ways to minimize costs and risks to ratepayers.

Sincerely,

C. Clark Leone

Manager

ATTACHMENT B

EXECUTIVE SUMMARY

The ongoing drought has focused concerns about the adequacy of the region’s power supply for the coming summer, fall and winter. Operational strategies for the

Columbia/Snake river hydropower system are a key component of managing through

this year with the objectives of: • Satisfying electricity demand through this spring and summer;

• Achieving reasonable summer flows for salmon migration;

• Not significantly worsening fall and winter reliability and the ability to meet

Biological Opinion (BiOp) reservoir target elevations in 2002; and

• Limiting the impacts of wholesale power purchase costs on the region’s economy

and the financial condition of the region’s utilities.

To assess the options available to the region, the Council has analyzed several alternatives for the operation of the power system over the coming year. The analysis

was done in two stages. The first focused on this spring and summer for two water

scenarios—1977 water and 1944 water. These years bracket the current runoff volume forecast for 2001. For each of these water years, several operating strategies

were evaluated. They include: running the hydropower system to the Biological

Opinion constraints for spill and flows; maintaining spill while drafting the system

deeper to meet loads; and three strategies that involve significant reductions in spill

combined with limited use of deeper drafts, with the objective of achieving BiOp reservoir elevations by the end of August. The analysis looked at such metrics as the

amount of curtailment that could be experienced, the cost of purchased power to address any curtailment, end-of–August reservoir elevations, and spring and summer

flows.

The second stage of the analysis focused on the operation of the system through

the fall and winter with the starting elevation of the reservoirs in September being

the primary variable. This analysis was done probabilistically with uncertainty

about fall and winter water conditions, temperatures and forced outages of thermal

units. The analysis looked at the probability and magnitude of load loss during the

winter period and April 2002 reservoir elevations.

The conclusions drawn from this analysis are:

• Operating the hydropower system to the BiOp targets for spill and flows would

lead to either significant curtailments and/or very large purchased power costs

this summer.

• Operations this spring and summer that leave reservoirs at the end of August

at elevations significantly below BiOp elevations expose the region to significantly increased probability of power supply inadequacy next winter. In addition, such operations would result in a significant probability that April 2002

reservoir elevations will be well below BiOp elevations, thereby reducing spring

flows for salmon.

• The only alternatives we see that both avoid curtailments and/or large purchased power costs this summer AND return reservoirs to BiOp elevations by

the end of August involve substantial reduction in spill and limited drafting of

reservoirs beyond BiOp elevations. Reductions in spill can be restored by purchases, reductions in load and additional generation. Alternatives that significantly reduce spill have the additional advantage of reducing market prices this

summer and bringing additional income into the region in the form of dollars,

returned energy next fall and winter, or both.

• Decisions need to be made now, but they can be revisited periodically as the

spring and summer unfold. The spill season begins in April. By that time, we

will have relatively little additional information about how the rest of the spring

and summer are going to unfold. From the power supply standpoint, a prudent

approach would be to significantly reduce spring spill. If conditions improve

through the spring, it may be possible to restore some spill. If, instead, we were

to opt to maintain spill or reduce it only slightly in the spring and if conditions

96

1The April ‘‘early bird’’ forecast has come in at 55.7 MAF.

do not improve, that spill energy would be lost to the system and would necessitate more stringent and potentially very expensive measures later on.

• The potential for power supply problems this summer and next winter and the

probable high cost of power call for continued and increased attention to implementing load reduction, conservation and new generation.

INTRODUCTION

The runoff forecast for 2001 continues to degrade. The January-through–July forecast released March 15th is 57.6 million acre feet (MAF) at The Dalles Dam. 1 The

mid–March forecast for runoff volume at The Dalles compared with the eight lowest

years in the 60-year historic record is shown in Figure 1. The most often quoted

forecast assumes 75 percent of normal precipitation for the last two weeks of March

and 100 percent of normal precipitation from April 1st on. However, alternative

forecasts are made for higher and lower percentages of normal April–July precipitation. As Figure 1 shows, if the April through July precipitation is 75 percent of normal, the runoff volume would be less than the 1977 volume, the lowest on record.

While National Weather Service personnel to whom we have talked do not believe

April through July precipitation that is 50 percent of normal is very likely, the possibility of runoff as low or somewhat lower than 1977 is quite possible.

These conditions raise obvious concerns about whether the Northwest power system can meet loads through this summer and next winter and satisfy the other demands placed on it.

Objectives

In view of the very poor water conditions facing the region and the continuing

power crisis in California, the Council has undertaken an analysis with the objective

of identifying strategies that:

• Satisfy electricity demand through this spring and summer;

• Achieve reasonable spring and summer conditions for salmon migration, given

the circumstances;

• Do not significantly worsen fall and winter reliability and the ability to meet

Biological Opinion reservoir target elevations in 2002; and

• Limit the impacts of wholesale power purchase costs on the region’s economy

and the financial condition of the region’s utilities.

97

2Most smolts in the Snake River will be barged this year, but some remain in-river. There

is no barging in the Columbia main stem upstream of McNary. 3Power Supply Adequacy

Tools

The tools that the region has at its disposal to meet these objectives are:

• Use of ‘‘emergency’’ hydro. Emergency hydro is defined as additional energy that

can be generated by drafting reservoirs below elevations intended to increase

the likelihood of meeting spring and summer BiOp flows for salmon. The risk

in using emergency hydro is that we may take reservoirs so low that summer

flows are affected and end-of–August elevations have a significant adverse effect

on fall and winter reliability.

• Reducing spill. Spill is water that is passed over the dams, not passed through

turbines. Consequently, spilled water produces no energy. Spill is an element of

the BiOp and is also an element of the FERC-sanctioned agreements governing

the operation of non-Federal projects on the Columbia. The risk in reducing spill

is the possible impact on survival of in-river downstream juvenile migrants. 2

• Purchase of imported power. To the extent that we can purchase power, potential deficits can be reduced or eliminated and water can be retained in the reservoirs. The availability and price of imports is problematic this year. Physically, there ought to be imports available in off-peak periods. However, this

year the price may be prohibitive. The costs of purchased power work their way

into retail rates with adverse impacts on the regional economy. In addition, Bonneville’s financial position is particularly vulnerable this year. High purchase

power costs could imperil Bonneville’s ability to make its Treasury payment and

maintain necessary operating reserves through the fall.

• Additional in-region ‘‘emergency generation.’’ Several utilities in the region have

or are in the process of installing emergency generation. These are typically

groups of diesel fuel or natural gas-fired reciprocating engines—‘‘Diesel Farms.’’

Others have turned to small, single cycle gas turbines, some older used units,

others new. In addition there is some ability to utilize existing industrial and

large commercial backup generation. These are relatively small in utility terms,

but can add up in aggregate. To the extent these units can be acquired and operated at costs less than the cost of purchased power, they can offset expensive

purchases or use of the other alternatives. The downside is the potential air

quality impacts associated with these typically comparatively high emissions

units.

• Voluntary or purchased load reduction. This can take several forms. One is investment in traditional conservation—the more efficient use of electricity. This

has the advantage of reducing electricity use while not impacting productivity

or lifestyle. Certainly a lesson of the past year is that sustained investment in

conservation is important. However, there is relatively little that can be implemented by this summer. The other approach is curtailment—reducing or eliminating some uses of electricity. This can be voluntary, such as elimination of unnecessary decorative lighting and signage; turning off lights and appliances

when not is use, and so on. Or it can be purchased curtailment. The most prominent example of this has been the aluminum industry, where most plants are

now being paid not to operate. The amount of the payment is less than the cost

of the power to serve them. This approach has other applications as in irrigated

agriculture and other industries.

ANALYTICAL APPROACH

In this analysis, the Council used its GENESYS model of the Northwest power

system. That model is described in detail in the Council’s March 2000 power supply

adequacy study. 3 GENESYS treats the region as a whole, but does simulate the

transmission constraints into the region and between the Eastern and Western

parts of the Northwest. Individual utilities or control areas are not modeled. The

region modeled included all of Montana, Oregon, Idaho, and Washington so that results could be directly compared with information from the Northwest Power Pool.

Regional loads were reduced to account for the recent reductions in direct service

industrial (DSI) load. It was assumed that there was approximately 500 megawatts

of DSI load still operating. Further reductions in DSI load are possible. In addition,

there are some additional industrial closures that may not be reflected in the analysis. The model also incorporates known ‘‘emergency’’ generation such as the ‘‘diesel

farm’’ installations that several regional utilities have undertaken. The potential for

imports from outside the region—British Columbia, California and the Desert

98

4The monthly output of thermal units was discounted by their forced outage rates.

Southwest—is represented by seasonal supply curves that are estimated from available data and consultations with informed persons in the affected regions.

Stage 1 -- March through August 2001

The analysis was approached in two stages. The first concentrated on the Marchthrough–August period. The analysis began with the reservoirs at their actual

March 1st elevations. Typically in analyses of this sort, important variables like

hydro conditions, temperatures and, therefore, electricity loads, and forced outages

of power plants are treated probabilistically. Several hundred simulations or

‘‘games’’ are run where the water conditions, temperatures and forced outages are

sampled according to their probability of occurrence. By analyzing the results of

these hundreds of games we can estimate the probabilities of load-resource imbalances and meeting reservoir elevation and river flow targets. However, because

there are so few years in the 60-year record of hydro conditions with runoff volumes

like the current forecast and only one with a lower runoff, we have chosen to do

scenario analysis using 1944 and 1977 water conditions. The analysis is limited to

monthly energy analysis due to difficulties in modeling sub-daily operations with

this year’s reservoir and water conditions. Average temperatures and expected operation of thermal units were used. 4 The actual maintenance schedules of thermal

generating units are now commercially sensitive information and not easily obtained. For this analysis, planned maintenance of thermal units was scheduled into

May, June and early July as has historically been the case.

The first stage looked at various operating strategies for the spring and summer

primarily involving emergency hydropower and reductions in spill. Purchases were

not evaluated explicitly because of the uncertainty of the availability of purchases

this spring and summer (California is experiencing rolling blackouts as this is being

written, a time when peak loads in the state are approximately 60 percent of what

can be expected this summer) and their expected extremely high cost. However, depending on availability, purchases could substitute for spill reduction or could be

used to restore reservoir levels after emergency hydro operations. Council staff is

attempting to get information regarding aggregate firm import commitments that

Northwest utilities may have. The analysis will be updated if this information becomes available. The analysis focused on the level of potential curtailment, the effect

on spring and summer flows, and the end-of–August reservoir elevations.

Stage 2 -- September 2001 through February 2002

The second stage of the analysis focused on the ability of the region to meet loads

through the ensuing fall and winter for different reservoir elevations at the beginning of September. For this part of the analysis, a set of hydro conditions corresponding to the lower two thirds of the water years (runoff volumes less than 114

MAF) were used. This is because there appears to be a correlation, albeit very weak,

between the January-through–July streamflow volumes and the volumes in the ensuing August-through–December period. This correlation is shown on Figure 2.

99

The model was run in its full stochastic mode, i.e., multiple games with water

conditions, temperatures and, therefore, loads, and forced outages on thermal units

determined randomly. In addition, a limited amount of imports was assumed to be

available during off-peak periods.

RESULTS

Stage 1 -- March through August 2001

Operation of the system for the March-through–August period was analyzed for

several different scenarios for 1944 and 1977 water conditions. For each year, a

‘‘Base Case’’ was run that corresponds to operation of the system according to the

BiOp. In addition, a ‘‘Maximum Emergency Hydro’’ case was run that maintains

spill and drafts reservoirs as necessary to meet load, using up to 10,000 megawattmonths of emergency hydro. Finally, three different spill reduction cases were run

with a limited amount of emergency hydro (up to 1,000 megawatt-months) used as

necessary to meet load while at the same time maintaining end-of–August reservoir

contents very close to BiOp elevations (within 1 or 2 percent).

The spill reduction cases were:

• Spill reduction 4—No spill at Federal projects;

• Targeted spill—Morning and evening spill at John Day and Bonneville, no spill

at other projects, Federal or non-Federal;

• Spill reduction 5—No spill at any projects.

The amount of energy involved in spill is quite large. Figure 3 shows the availability of spill energy across the spill season for the spill reduction 4 and 5 cases.

100

SUMMER SUMMARY

For each of these cases several measures were evaluated:

• The total curtailment across the period;

• The cost of imports IF the curtailment could be offset by purchases, assuming

a $250/MW-hr price;

• The approximate amount of spill energy used;

• The August 31 system content below BiOp elevations; and

• The amount of ‘‘retained’’ energy. The retained energy is the amount of spill energy available over and above that needed to meet load and restore system contents to BiOp elevations at the end of August.

This information is summarized in Table 1. Also shown is a result from the second stage of the analysis: the probability of unserved demand at some level across

the 2001–2002 winter months. This will be discussed in a later section.

101

Several things are readily apparent from Table 1. The first is that operating the

system to the BiOp to spill and meet flow targets is not an option. To do so would

102

5The degree to which this water can be used to increase reservoir levels is limited because

of limited inflows to reservoirs high in the system late in the summer. 6Those like Bonneville who could have spill energy to sell would still have increased revenues,

just not as great as current market prices might suggest.

leave very large unserved load (curtailments) with either 1944 or 1977 water. If it

were possible to purchase imported energy to meet those deficits, the cost could easily exceed $1 billion, and it is not at all clear that purchases of this magnitude

would be available.

A second observation is that by using maximum emergency hydro—drafting the

reservoirs deeper—while maintaining spill could, with 1944 water, avoid summer

curtailments. With 1977 water, there would be some remaining curtailment, but of

a magnitude that might be managed with additional load reduction and some purchases. However, in this instance the curtailment occurs in August when imports

might be especially hard to acquire. In both cases, the August 31st reservoir content

is well below BiOp elevations. This has implications for reliability later in the fall

and winter, as indicated by the higher loss-of-load-probability in the last column of

Table 1. This question is examined in Stage 2 of the analysis.

The final observation is that with the combination of significant reductions in spill

and some use of emergency hydro, it is possible to effectively eliminate curtailment

in the 1944 water case and return reservoirs to their BiOp elevations by the end

of August. In addition, there is an appreciable amount of retained energy in the system. For 1977 water, the combination of significantly reduced spill and limited use

of emergency hydro does not eliminate curtailments but reduces them to much more

manageable levels while returning reservoirs to BiOp elevations. The curtailments

largely occur in May and June, coinciding with the period during which most

planned maintenance on thermal units is assumed to be occurring. If water conditions this year approach 1977 conditions, the region could need to look to further

steps to avoid curtailment. As in the 1944 water case, there is some energy retained

in the system, although much less. We have looked at additional scenarios that do

not reduce spill quite as much and compensate by using additional emergency

hydro. However, unless we are willing to accept August 31 reservoir contents that

are well below BiOp, the amount of reduction in spill has to be significant.

This retained energy could be used to restore some spill, fill reservoirs somewhat

higher at the end of the summer or to generate additional power. 5 If this retained

energy were used to generate electricity it could generate additional revenue to offset high power prices. Alternatively, it might be exchanged with California on an

X Megawatt-hours-for-one basis, with much of the returned energy coming the following winter when it could help address potential power supply problems. In either

event, some of the benefit could be set aside to fund fish mitigation measures that

might offset some or all of the effects of a one-time reduction in spill.

It should also be recognized that introducing the amount of additional energy associated with spill into the market will have the effect of reducing market prices.

To analyze the potential effect, two short-term price studies were done using the

AURORA model. One run used the hydro generation associated with full spill, the

other used the hydro generation associated with no spill, both for 1944 water. The

average market price differential between the two runs was $56/megawatt-hour.

This would reduce the revenues that Bonneville and other Northwest utilities might

receive from reducing spill and selling additional energy. But purchasers of power

on markets throughout the West would benefit from lower prices. 6 If we assume

that 10 percent of the electricity consumed during the April-through–August period

is secured through short-term markets as opposed to long-term contracts, the value

of this reduction in price would be $1.2 billion.

SPRING AND SUMMER FLOWS

Also of concern is the effect of the operational strategies on spring and summer

flows. Figures 4 and 5 show the percent change in flows from the BiOp operation

for spring and summer at McNary and Lower Granite for 1944 and 1977 water respectively.

103

Spring flows are generally increased from BiOp levels for the operating strategies

modeled because each involves some emergency drafting. Summer is a different

story. The system is trying to refill reservoirs that provided emergency energy earlier in the summer, thus reducing summer flows. This is particularly so for the

‘‘maximum emergency hydro’’ example. Generally, summer flows in the Snake are

most at risk. In the reduced spill cases, some of the summer flows could be restored

by generating with the retained spill energy or by spilling.

Stage 2 -- September 2001 through February 2002

This part of the analysis was focused on reliability concerns through the fall and

coming winter. Of particular interest was to assess the effect of lower end-of–August

reservoir elevations on the ability to meet load. Three cases were examined:

• Reservoirs at BiOp elevations at the end of August;

104

• Reservoirs starting at the elevations corresponding to the use of emergency

hydro only for 1944 water conditions (79 percent of BiOp elevation); and,

• Reservoirs starting at the elevations corresponding to the use of emergency

hydro only for 1977 water conditions (72 percent of BiOp elevation).

It should be pointed out that the last two cases are essentially surrogates for

starting the reservoirs at elevations significantly below BiOp levels. For example,

additional drafting for higher summer flows could have the same effect.

As noted earlier, this part of the analysis was carried out probabilistically using

random draws of water conditions, forced outages of thermal units and temperatures which, in turn, are used to determine loads. A reduced set of water years was

used to reflect the fact that there appears to be a weak correlation between the unregulated volumes in the fall and winter and the unregulated volumes in the preceding eight months. For this analysis, it was assumed that a very limited amount

of imports was available beginning in October, primarily during off-peak periods.

This reflects the experience of this past winter. We would hope that with additional

generation scheduled to come online in the Southwest this summer, more imports

might be available at an affordable price. Faced with curtailment, the simulation

uses emergency hydro up to a total of 10,000 megawatt-months, limited by physical

and operational constraints. In the absence of imports, the emergency hydro is restored to the extent possible by running in-region thermal units harder and purchasing imports.

WINTER 2001–2002 POWER SYSTEM ADEQUACY

The first question was the probability of curtailment occuring at some time during

the winter season, the months of December 2001 and January and February 2002.

This is shown in Figure 6.

When starting at BiOp reservoir elevations, in 20 percent of the 300 winters modeled, there was some level of unserved load, with the maxiumum seasonal unserved

load being over 3,000 Megawatt-months. This is not indicative of a reliable system

and is consistent with the results of the Council’s March 2000 study, which found

a 24 percent probability of unserved load in 2003. In this year’s analysis we have

lower loads and some additional resources, both of which should improve reliability.

However, this is conteracted by also having reduced import capability and lower average hydro capability because we are drawing from the lower two-thirds of the set

of water years.

105

The amount of power needed to bring the loss of load probability down to 5 percent was found to be approximately 2,500 megawatts. This could achieved through

of some combination of additional generation, imports, conservation and/or voluntary or purchased load reduction.

For the lower reservoir starting elevations, 39 to 45 percent of the winters experience some unserved load with average unserved loads of 800–900 Megawatt–Months

in those winters and maximums reaching over 5000 Megawatt-months.

January is the worst of the winter months. To get a better sense of the magnitude

of shortfalls that could be experienced, we looked at the average daily unserved load

for that month. This is shown in Figure 7.

For the case with reservoirs starting at BiOp elevations, approximately 7 percent

of the 9,300 January days simulated (300 games times 31 days), had some level of

unserved load, with the maximum daily average reaching about 8,000 Megawattdays. Starting the reservoirs at the lower elevations increases the percentage of

days to 13 and 15 percent with the maximums reaching 10,000 to 11,000

Megawatts-days.

SPRING 2002 RESERVOIR ELEVATIONS

The other effect of lower reservoir starting elevations is on April 2002 reservoir

elevations. These elevations are established to ensure being able to provide spring

flows for downstream salmon and steelhead migrants. In the BiOp, approximately

12 MAF of water by April 15th is targeted for providing spring flows. On average,

starting reservoirs in the fall at the lower elevations results in approximately 2

MAF less water in storage by April than when the reservoirs begin the fall at BiOp

elevations. In the worst case with the lower starting reservoir elevations, April storage volumes are over 6 MAF lower. The duration curves of reservoir content (shown

as difference from BiOp contents) is shown on Figure 8 for the case where reservoirs

are started in September at their low 1977 water elevations.

106

CONCLUSIONS

Several conclusions can be drawn from the results of this analysis.:

• Operating the hydropower system to the BiOp targets for spill and flows would

lead to either significant curtailments and/or very large purchased power costs

this summer.

• Operations this spring and summer that leave reservoirs at the end of August

at elevations significantly below BiOp elevations expose the region to significantly increased probability of power supply adequacy problems next winter. In

addition, such operations would result in a significant probability that April

2002 reservoir elevations will be well below BiOp elevations, thereby reducing

spring flows for salmon.

• The only alternatives we see that both avoid curtailments and/or large purchased power costs AND return reservoirs to BiOp elevations by the end of August involve substantial reduction in spill this spring and summer and limited

drafting of reservoirs beyond BiOp elevations. Reductions in spill can be restored by purchases, reductions in load and additional generation. Alternatives

that significantly reduce spill have the additional advantage of reducing market

prices this summer and bringing additional income into the region, either in the

form of dollars or returned energy next fall and winter.

• Decisions need to be made now, but they can be revisited periodically as the

spring and summer unfold. The spill season begins in April. By that time, we

will have relatively little additional information about how the rest of the spring

and summer are going to unfold. From the power standpoint, a prudent apVerDate 11-MAY-2000 15:39 May 07, 2002 Jkt 000000 PO 00000 Frm 00110 Fmt 6633 Sfmt 6621 J:\DOCS\72516.TXT HRESOUR2 PsN: HRESOUR2
107

proach would be to significantly reduce spring spill. If conditions improve

through the spring, it may be possible to restore spill. If, instead, we were to

opt to maintain spill or reduce it only slightly in the spring and conditions do

not improve, that spill energy would be lost to the system and would necessitate

more stringent and potentially very costly measures later on.

• The potential for power supply problems this summer and next winter and the

probable high cost of power call for continued and increased attention to implementing load reduction, conservation and new generation.

ATTACHMENT C

MARCH 30, 2001

DRAFT

ISSUE PAPER:

ANALYSIS OF 2001 FEDERAL COLUMBIA RIVER POWER SYSTEM OPERATIONS

ON FISH SURVIVAL

INTRODUCTION

The Columbia River Basin is now facing a severe drought. The current forecasts

predict that this will be at least the second worst water year in the 72-year historical record, and there is a possibility that this year may in fact set a new record

for low flow conditions.

The poor water conditions, a growing BPA financial problem, and looming energy

concerns are causing the region to look for alternatives to meet anticipated energy

needs. Changes to the operations of the Federal Columbia River Power System

(FCRPS) will most likely be needed to optimize power production and help offset the

growing Northwest and West Coast power crisis.

Reductions in spill designated for juvenile fish passage have been considered as

one way to help meet energy demand. While spill reductions may help ease the difficult power situation, it is unclear how these reductions may affect juvenile fish

survival. To help answer this question, Council staff examined the possible relative

biological effects of various spill and transportation alternatives on Columbia basin

fish survivals. While there are many unlisted hatchery and naturally spawning populations in the Columbia Basin, the Council analysis focuses solely on ESA-listed

stocks.

The 2000 Federal Columbia River Power System Biological Opinion (2000 Biological Opinion) uses a combination of strategies to help juvenile salmon and steelhead

migrating out to the ocean pass through or around each hydroelectric dam. There

are four possible routes: (1) through a juvenile bypass system, which intercepts fish

with screens and routes them through a specially designed passage in the dam; (2)

by opening the spill gates, which routes the fish over the spillway but decreases the

water available for generating electric power; (3) through the turbines, which is not

a preferred route due to reduced survival; and (4) by intercepting fish and transporting them in barges to a release point below the hydroelectric system.

This Issue Paper focuses on three questions:

• Given full implementation the 2000 Biological Opinion for 2001 water conditions, how will additional spill reductions at FCRPS dams change the total system survival of migrating ESA-listed juveniles?

• How will juvenile transportation at McNary Dam affect the survival of the

Upper Columbia ESA-listed stocks?

• How will adult returns be affected by changes in spill and fish transportation

operations?

The analysis that follows is a preliminary staff analysis of these questions. The

Council seeks comment on this analysis and will consider these issues further at

its April 24, 25, and 26 meeting in Spokane, Washington. Those wishing to comment

may submit written comments to Mark Walker, Director, Public Affairs Division,

Northwest Power Planning Council, 851 SW Sixth Avenue, Suite 1100, Portland, OR

97204 or mwalker@nwppc.org through April 20, 2001.

SUMMARY OF RESULTS

In analysis included in the 2000 Biological Opinion, the National Marine Fisheries Service (NMFS) used its spreadsheet model to project the survival of salmon

passing through the hydrosystem. This model, known as SIMPAS, is used in this

analysis to estimate the relative effects of various spill and transportation alternatives on juvenile salmon survival.

108

The following are the results of this analysis.

When compared to full implementation of the 2000 Biological Opinion under 2001

water conditions, spill reductions at FCRPS dams:

• Have little to no effect on the total system survival of Snake River spring/summer chinook, Snake River steelhead or Snake River fall chinook.

• Decrease total system survival for Upper Columbia spring chinook, Upper Columbia steelhead and Middle Columbia steelhead to the highest extent compared to other ESU’s. These stocks are not transported and pass through several dams.

• Have less effect on the total system survival for Lower Columbia chinook and

Lower Columbia steelhead because 1) most of the these listed populations are

geographically situated below Bonneville Dam and 2) the Lower Columbia chinook and steelhead only pass one FCRPS dam (Bonneville Dam).

When compared to full implementation of the 2000 Biological Opinion under 2001

water conditions, full transportation at McNary Dam with no spill at FCRPS dams:

• Increases Upper Columbia spring chinook total system survival under all alternatives.

• Increases Upper Columbia steelhead total system survival under most conditions.

For the alternatives examined, estimated adult losses for listed fish range from:

• Zero adults lost for Snake River steelhead (0.0 percent of total return) to

• 53 to 2,535 Upper Columbia spring chinook adults lost with no transport at

McNary Dam (12.7 percent of total return).

CAVEATS

Staff believes that this analysis focuses on the attributes most important to this

year’s decision. While not all the relevant factors have been measured or identified,

this analysis focuses on the relative effect of various alternatives. Parameters that

are assumed to be the same among various alternatives effectively ‘‘cancel out’’ in

a relative analysis. Nevertheless, the reader should be aware that:

(1) This analysis focuses primarily on juvenile fish survival through the dams. It

does not include any consideration of the potential effect of migration delays resulting from fish holding at dams before entering the juvenile bypass system. While this

behavior has been observed in some circumstances, the Council is not aware of any

empirical measurements demonstrating the effect this behavior has on the survival

of juvenile fish to maturity.

(2) This analysis also does not include any consideration of the benefit to adult

fish migration resulting from reduced spill. While it has been observed that the

number of adult fish entering the ladders at a dam often increases when spill is

terminated, the Council is not aware of any empirical measurements demonstrating

the effect of this behavior on the survival or fitness of adult fish migrating upriver.

(3) This analysis does not consider the effects of reducing spill at the non-Federal

dams located in the mid–Columbia region. The SIMPAS model does not include information on the survival of juvenile fish through those dams.

(4) The survival estimates shown in this issue paper are survivals through the

hydrosystem. These estimates include all mortalities that occur to juvenile fish during this phase of their migration, even mortalities that would occur naturally in the

absence of the hydrosystem. No attempt has been made in these estimates to differentiate mortalities that result from the hydrosystem from mortalities that result

from other sources.

SUMMARY OF RECOMMENDATIONS

This issue paper does not attempt to weigh the value of additional electrical

power generation versus the value of increasing the survival of juvenile fish through

spill. However, in the event that it is determined that spill should be decreased, the

staff offers the following recommendations for the 2001 juvenile migration season:

• Stop spill at Ice Harbor and McNary dams.

• Maximize transportation at all FCRPS collector dams, including McNary.

• Utilize surface sluiceway spill at dams to pass juveniles wherever possible and

beneficial.

• If water is available for spill, focus spill to optimize benefits to Middle Columbia

steelhead and to a lesser extent remaining inriver Upper Columbia spring chinook and steelhead.

• Although major changes in the fish passage structures at the dams are unlikely

to be accomplished this year, the U.S. Army Corps of Engineers should immediately accelerate development of surface-oriented bypass systems which, in efVerDate 11-MAY-2000 15:39 May 07, 2002 Jkt 000000 PO 00000 Frm 00112 Fmt 6633 Sfmt 6621 J:\DOCS\72516.TXT HRESOUR2 PsN: HRESOUR2
109

7 A description of SIMPAS and model documentation can be found in Appendix D of the 2000

Biological Opinion.

fect, allow juvenile fish to have the advantages of spill without the large impact

on power generation.

SIMULATED PASSAGE MODEL (SIMPAS)

Council staff used the SIMPAS model to analyze the relative effects of various

spill and transportation alternatives on fish survival in the Snake River and upper

Columbia River basins. 7 SIMPAS is a spreadsheet model developed by the NMFS

Hydro Program staff that uses empirical fish passage data to estimate relative juvenile survival through the hydrosystem for various alternatives. The model was used

by the Federal Biological Effects Team to help develop the 2000 Biological Opinion

and is currently used to analyze the relative consequences of hydropower operational changes on the survival of listed stocks.

Question 1. Given full implementation the 2000 Biological Opinion for 2001 water

conditions, how will additional spill reductions at FCRPS dams change the total system survival of migrating ESA-listed juveniles?

To address Question 1 the staff analyzed four different spill alternatives:

Base Case -- Full implementation of the 2000 Biological Opinion at all Federal

dams based on projected 2001 water conditions. This includes:

• No spill at Lower Granite, Little Goose and Lower Monumental dams

• Full transport of juveniles at Snake River collector dams

• No summer spill at McNary Dam with full transportation

Alternative 1 -- Base Case plus:

• No spill at Ice Harbor Dam

• No spill at McNary Dam

Alternative 2 -- Alternative 1 plus:

• 24 hour spill reduction to 20percent of total flow at The Dalles Dam.

• 24 hour spill reduction at Bonneville Dam to 50 kcfs.

No Spill Alternative

• No spill at FPRPS dams

Average of Low Flows -- Projected 2001 spring and summer river flows were estimated using a weighted average of the 8 lowest water years (1929, 1930, 1931,

1937, 1941, 1944, 1973 and 1977) of a 61-year historical record. In the event that

2001 is even lower than these averages, it is possible that inriver survival may decline further and thus the relative benefit of transporting fish, where possible, may

increase. Table 1 shows average river flows used in the analysis.

Delayed mortality of transported juveniles- The 2000 Biological Opinion estimates

differential post–Bonneville Dam mortality (D value) of transported fish. The D

value is defined as the ratio of the post–Bonneville survival of transported fish to

the post–Bonneville survival of fish that remain inriver. If the D value is greater

than 1.0 then transported fish have a post–Bonneville survival rate that is higher

than inriver fish. If the D value is less than 1.0, then transported fish have a post–

Bonneville survival rate that is lower than inriver fish. A D value of less than 1.0

may be caused by a variety of causes including the delayed effects of the transportation and collection process.

To more accurately reflect the total system survival and the delayed mortality

that may occur after transport, the Council staff adjusted transported fish survivals

using the D values contained in the 2000 Biological Opinion. The D values used are

summarized in Table 2.

110

RESULTS

Using SIMPAS, the Council staff estimated total system survival to below Bonneville Dam for each ESA stock using the various alternatives. Staff chose to use total

system survival over inriver survival because it better reflects the effects of spill reductions given the number of stocks being transported. Total system survival to

below Bonneville Dam is calculated by summing the percent survival of transported

fish with the percent survival of fish remaining inriver. In the spill analysis, only

Snake River fish are transported. Where fish are not transported, inriver survival

equals total system survival.

Table 3 summarizes total system survival to below Bonneville Dam for the various stocks and alternatives. Starting with 1,000 juveniles, the table shows how

many fish survive to below Bonneville Dam. Total system survivals for Snake River

stocks represent survival from Lower Granite pool to below Bonneville Dam. System

survival for Upper Columbia stocks represent survivals from McNary pool to below

Bonneville Dam. Middle Columbia survivals represent survival from John Day pool

to below Bonneville. Finally, Lower Columbia survivals indicate survival from Bonneville pool to below Bonneville Dam.

111

To understand and encompass the range of effects that reducing spill has on total

system survival, the Council staff compared the Base Case to the No Spill alternative. Table 4 shows the change in number of juveniles surviving to below Bonneville Dam.

112

RESULTS

• Stopping spill at Ice Harbor and McNary dams has little effect on the total system survival of any listed stock. The only stocks that are slightly affected are

the Upper Columbia spring chinook and steelhead, which have a 0.4 percent decrease in survival.

• Because most Snake River listed stocks are transported, decreasing or eliminating spill at FCRPS dams has little to no effect on Snake River stocks. Total

system survival of Snake River spring/summer chinook decreases by 0.2 perVerDate 11-MAY-2000 15:39 May 07, 2002 Jkt 000000 PO 00000 Frm 00116 Fmt 6633 Sfmt 6621 J:\DOCS\72516.TXT HRESOUR2 PsN: HRESOUR2
113

8 It should also be noted that because most of the Lower Columbia ESUs are geographically

located below Bonneville Dam, fewer Lower Columbia listed fish are affected by dam passage.

Furthermore, NMFS has not determined which, if any, Lower Columbia chinook or steelhead

stocks that are found above Bonneville Dam qualify as ESA-listed populations. The 2000 Biological Opinion states that causes for the decline of these two ESUs are primarily related to habitat

and hatchery impacts.

cent, Snake River fall chinook decrease by 1.0 percent, and there is no decrease

in Snake River steelhead.

• Lower Columbia chinook and steelhead survivals are less affected by eliminating

spill at all dams (decreases of 2.8 percent for chinook and 2.8 percent for

steelhead) because these stocks only pass one hydro project, Bonneville Dam. 8

• Elimination of spill at all dams has the greatest impact on the survivals of

Upper Columbia spring chinook and steelhead (decreases of 11.3 percent and

10.5 percent respectively) and Middle Columbia steelhead (a decrease of 10.3

percent). These stocks are not transported and pass through several dams.

Question 2. How will juvenile transportation at McNary Dam affect the survival

of the Upper Columbia ESA-listed stocks?

Upper Columbia spring chinook and steelhead survivals are affected the most by

eliminating spill at the lower river FCRPS dams. Because McNary Dam has fish

transport facilities, a possible way to increase Upper Columbia fish survivals is to

collect juveniles at McNary and transport them to below Bonneville Dam. To help

determine the usefulness of this approach, staff looked at total system survival from

McNary pool to below Bonneville Dam for the base case 2000 Biological Opinion alternative and the no spill alternative with full transport at McNary Dam. High and

low transportation effects (D values) were used from Table 2 to estimate total system survival. Table 5 summarizes the findings.

RESULTS

• Under full transportation at McNary Dam, total system survival for Upper Columbia spring chinook increases using both low and high D values. Increases

in total system survival range from 10.4 percent to 67.0 percent.

• Transportation at McNary appears to benefit Upper Columbia steelhead under

most but not all conditions. Transportation at McNary does not benefit

steelhead for lower D values. Total system survival changes for Upper Columbia

steelhead range from ‘‘13.7 percent to 58.8 percent.

Question 3. How will adult returns be affected by changes in spill and fish transportation operations?

Council staff estimated the number of adults lost or gained from the changes in

operations by listed stock. The alternatives studied assumed no transportation and

full transportation at McNary Dam under spill and no spill conditions. High and low

D values from Table 2 were used for transportation benefits. The number of juveniles arriving at the various dams was obtained from the 2001 NMFS juvenile outVerDate 11-MAY-2000 15:39 May 07, 2002 Jkt 000000 PO 00000 Frm 00117 Fmt 6633 Sfmt 6621 J:\DOCS\72516.TXT HRESOUR2 PsN: HRESOUR2
114

9Memo from Michael Schiewe to Donald Knowles, ‘‘Estimation of Percentages for Listed Pacific Salmon and Steelhead Smolts Arriving at Various Locations in the Columbia River Basin

in 2001.’’ March 22, 2001. 10 NMFS. ‘‘Summary of Research related to Transportation of Juvenile Anadromous Salmonids

Around Snake and Columbia River Dams.’’ April 2000.

migration memo. 9 A summary of the number of listed juveniles arriving at various

locations is shown in Table 6.

The adult estimates were calculated by multiplying the number of juveniles lost

or gained by an estimated smolt to adult ratio (SAR) for each stock. A general range

of SARs was estimated by taking upriver SARs contained in the April 2000 NMFS

white paper on transportation 10 and back calculating adult survival to below Bonneville Dam. Tables 7 through 9 include the range of SARs used and summarize the

results.

115

116

117

RESULTS

Under the given assumptions, when comparing the surviving number of adults

under base case 2000 Biological Opinion operations to the no spill alternative:

• For all transportation and spill scenarios, very few adults are lost for Snake

River stocks. A range of only two to 22 spring chinook, zero steelhead and five

to 47 fall chinook adults are estimated to be lost. The number of adults lost are

0.2 percent, 0.0 percent and 0.9 percent respectively of the total number of surviving adults.

• For all transportation and spill scenarios, Middle Columbia steelhead may lose

as many as 705 adults or 11.5 percent the total number of surviving adults.

• Upper Columbia spring chinook with no transportation at McNary lose as many

as 2,535 adults or 12.7 percent of the total returning adults. With transportation

at McNary, there is actually an increase of up to 1,722 (6.9 percent, low D

value) to 14,394 (38.4 percent, high D value) spring chinook adults.

• Upper Columbia steelhead with no transportation at McNary lose up to 1,179

adults or 11.8 percent of the total number of returns. With transportation at

McNary, Upper Columbia steelhead lose up to 358 adults (3.7 percent) with low

D values and gain 6,610 adults (37.5 percent) with high D values.

118

11 Rock Peters, Corps of Engineers, Personal Communication.

RECOMMENDATIONS

Based on the results of the analysis the Staff makes the following recommendations: • Do not spill at Lower Granite, Little Goose, Lower Monumental, Ice Harbor or

McNary dams. Spill at Lower Granite, Little Goose and Lower Monumental is

eliminated under full implementation of the 2000 Biological Opinion. Spill at Ice

Harbor Dam is of little value because most Snake River juveniles have been

transported so few fish remain in the river. McNary spill is of lesser importance

because its juvenile bypass system is fairly effective in routing juveniles away

from turbines.

• Maximize transportation at all FCRPS collector dams, including McNary. Maximum transport of juveniles at the Lower Snake dams is already called for

under full implementation of the 2000 Biological Opinion. Transporting juveniles at McNary makes sense because it increases Upper Columbia spring chinook survival under all conditions and Upper Columbia steelhead survival

under most conditions. McNary transport also makes sense because of the potential in 2001 for poorer inriver migrating conditions. If transportation takes

place it should be fully evaluated for its benefits. The information gained will

be useful for guidance in future years, particularly under poor water conditions.

• Utilize surface spill at dams to pass juveniles wherever possible and when benefits are likely. In general, surface spill at dams is effective in passing juveniles

with much less water than via the spillway. For example, studies at The Dalles

sluiceway (which uses low flow surface spill) indicate that approximately 43 percent of inriver fish pass via the sluiceway when there is no spillway spill. 11

• If water is available for additional spill, focus spill to optimize benefits to Middle

Columbia steelhead and to a lesser extent remaining inriver Upper Columbia

spring chinook and steelhead. If spill takes place at all, it should be employed

at Bonneville, The Dalles and John Day, to benefit the Middle Columbia

steelhead. For the most part, this listed stock will not be transported and must

pass the lower three mainstem dams. Spill could take place during dusk and in

the early morning to optimize fish passage.

• Although major changes in the fish passage structures at the dams are unlikely

to be accomplished this year, the Corps should immediately accelerate development of surface-oriented bypass systems which, in effect, allow juvenile fish to

have the advantages of spill without the large impact on power generation. It

is evident that the current method of producing spill by opening a gate 40–50

feet below the surface of the reservoir is a relatively inefficient way to provide

passage to juvenile salmon and steelhead, which are near the surface.

Mr. CALVERT. I’ll ask Dr. Anderson a question, because maybe

this has all been related to the entire panel here.

Obviously, it’s a concern that we all share, that—that the salmon

population has increased and that we don’t consciously do anything

that would irreparably harm that resource.

However, your testimony is interesting in that you believe that

we can possibly have additional electricity this summer without irreparably harming the fish population by utilizing the technologies

that have been operating here for the last number of years, large

technology.

Is that—is that correct, when I say that?

Mr. ANDERSON. Particularly for the spring runs, the ones that,

unfortunately, have come up through the river already—have gone

down through the river—barging work is tremendous. We have

good data for that, for the summer run. The fall chinook come

through later on. We really don’t have good information on how

well that’s going to work. Unfortunately, as a scientist, I can give

you a mixed answer. We have a tendency to do that.

With barging, we have the capacity to improve it for some of the

runs. So I think that it is something that needs to be considered.

119

We need to continue to look at the data, that yes, we have more

flexibility.

Mr. CALVERT. I’m a believer in science rather than—you know,

outcome-produced science rather than real science to make sure

that we are doing the right thing.

Ms. Patton, I congratulate you on the work on wind and solar.

I used to be Chairman of the Energy Environment Committee.

We’ve done a lot on renewable energy. I will say that—you know,

I know that people like to make fun of California right now, but

we have a significant amount of renewable energy in California.

People will be surprised to know that the largest amount of wind

is in California. It happens to be in my home county, Riverside

County. The largest utilization of solar in the United States is in

California. The largest utilization of geothermal in the United

States is in California. But obviously, that’s—that’s not enough to

make up for the shortfall that we’re experiencing.

But what’s important in the interrelationship that Dr. Anderson

is describing—even with the additional 400 megawatts we have online, that only makes up about half of the loss—from the biological

opinions, as I understand it—in the shortfall of water.

And in fact, it’s not assisting the salmon population. That—that

has a direct effect on Mr. Lepp, because if, in fact, we’re spilling

water for no good purpose—in effect to increase salmon population—.

Your company—and I don’t know how you’ll get through this

summer—I hope you do—you know, I—we need a strong steel industry in this country, and your increased power rates—$6 million,

I think you mentioned--.

Mr. LEPP. I said it was just the last increment. It’s already gone

up over 12 million.

Mr. CALVERT. Obviously, you can’t keep your doors open with

that type of situation.

So it’s important that we get the science together to—to make

sure this, in fact, is—is the case and we can continue to maintain

fish population—and actually increase fish population, as we experienced this year. And let’s not do something that has this—unintended consequences as losing an industry such as yours. And obviously, that is something we certainly don’t want to do.

Yes, Ms. Patton.

Ms. PATTON. I just wanted to respond briefly, that right now,

the—there is no spill for salmon, and--.

Mr. CALVERT. Has there been some spill—.

Mr. SMITH. Just this week.

Ms. PATTON. Just this week. There have been some arrangements for a very small amount of smolt, but there is no spill for

salmon.

I would also mention—and in another capacity, I’m the Vice

President of the Board of Save our World Salmon—that it’s—the

peer-reviewed science coming out of the Army Corps of Engineers’

past study showed that, in fact, the—the—the barging was not the

best way to save salmon, quite clearly, and that we will need a

more natural river in order to make the salmon come back.

Mr. CALVERT. Obviously, there is a disagreement with that.

120

Ms. PATTON. There is. I’m not a scientist, so I can’t review that

credential. I just want to refer you to the Army Corps of Engineers’

science, the—the past analysis.

Mr. CALVERT. I guess in conclusion—and my time has come up—

is that we do have more fish this year. That’s the happy news.

Ms. PATTON. And there was more spilled when those fish went

to sea. It wasn’t just ocean conditions.

Mr. CALVERT. More fish is good, then.

So that’s—I’ll give it to Mr. Smith.

Mr. SMITH. Thanks.

I think I just have two questions, one for Ms. Patton and one for

Mr. Walton.

On the—I’m very encouraged by your remarks on renewables and

focusing on engineer efficiency, not just, you know, doing less with

less—I mean doing more with less—and the opportunities that are

out there. And the more I read about it, it’s really quite exciting.

The technology, I mean, not—obviously, this isn’t my field of expertise, so I’m sure that there is more than I know about.

But just from what I know about, from biomass fuel cell and a

variety of energy efficiency plans, there is a massive amount of

things that we can do.

And the primary reason why we haven’t done them to the degree

that we have is because—well, fossil fuels are cheaper, if you look

at it from just the standpoint of buying it; that—they used to be

cheaper. They, in some cases, still are.

But I think the issue is really sort of getting us to look at the

full cost of a fossil-fuel based energy system.

Now, if you look at it, it’s simply what you’re paying at the pump

or what you’re paying on your electricity bill. You’re not looking at

the impacts on the environment and the full impacts that—not to

mention the fact that we are dependent on fossil fuels. We will be

dependent on foreign sources. That’s where they are. Certainly,

that’s where oil is, at any rate.

So shifting to renewables and shifting to these alternative

sources is absolutely critical. But a lot of people will look at it and

say, ‘‘Well, yeah. Yeah. We can do a little bit here and a little bit

there, but it’s never really going to amount to much.’’.

I wonder if you can just comment briefly on it. If we made the

investment in REE, in tax credits, in setting standards—like cafe

standards or standards for air conditioners—if we really committed

ourselves to it, what—how dramatic a shift can we have in what

we use for energy?

Ms. PATTON. I think there is no question that we could meet all

of our electricity demand with clean renewables and energy efficiency. 133,000 average megawatts of wind supply is enough and

is way more than we’re using now and way more than our—and

you would never want to—to do that, you know, monolithic. You

would want to have a diverse supply, obviously.

But there is no question that the kinds of things you’re talking

about—biomass fuel cells coming on board and the ability to have

a more resilient system with that kind of distributed generation

and clean renewables means that we have a way to have a clean,

affordable energy future that’s based on renewable energy.

121

And as some people have said, with regard to the age of petroleum, the Stone Age didn’t end because we ran out of rocks. And

we’re not—the Petroleum Age is not going to end because we ran

out of oil. It’s going to end because we have much better alternatives.

Mr. SMITH. Mr. Walton commented on the deregulation situation,

and it’s sort of popular, accepted fact right now that the energy

problems that we have cannot really be the fault of deregulation

because we haven’t really deregulated. We just sort of regulated in

a different way. And there is a certain amount of truth to that, particularly if you look at the retail side of it.

Certainly in California, one of the reasons that the crisis got

worse and became a credit crisis was because the prices were not

passed on to the consumers for the longest time. Retail consumers

had no incentive, really, to decrease their demand because that was

still regulated.

But on the wholesale side of the equation, isn’t it fairly—wholesale and also in generation—isn’t it somewhat fair to say that we

have pretty much a deregulated power system in terms of—you

know, no one’s required to generate power, no one’s required to

build new generation, and they can charge pretty much whatever

they want on the wholesale market? I could be wrong here. So I’m

just asking.

But isn’t it fairly—you know, isn’t it fair to say that we do have

a deregulated wholesale system, and aren’t we really sort of seeing

the limitations of taking that approach?

As someone who has to do with the public utilities and being

very involved in it—and I’m just kind of curious about your comments on that.

Mr. WALTON. Steve Klein said earlier that Tacoma didn’t take a

stand either way, and neither did PPC. But I think you’re right,

that—particularly with the advent of the interdependent power

producers, there was a large sector of unregulated generation in

the system.

As Congressman DeFazio has pointed out numerous times, however, one of the things that troubles me is the loss of the obligation

to serve. And I think taken, for instance, as a West Coast system,

it’s—it’s very troubling that nobody is in charge of West Coast reliability, no one entity. Not FERC, not the Secretary of Energy, not

Bonneville has—has the job of trying to keep the lights on everywhere.

The fact that some of the generators can sit back and wait for

higher prices and don’t have an obligation to serve puts the utilities in an extremely uncomfortable position.

So I think that we may be part of the way toward deregulation,

but that’s why I refer to it as being kind of high-centered in the

middle. You’re not getting the, quote, ‘‘genius of the marketplace’’

as advocates of deregulation would have us.’’

Mr. SMITH. Well, why not—if I could explore that for just a moment—on the wholesale situation? I mean, if there is no obligation

to serve, you can charge whatever you want to charge in the wholesale market, why aren’t we getting the genius of the market? I

mean, why isn’t it working?

122

Mr. WALTON. Congressman, I’m far from an expert on this, and

there are people in the room—and probably members of your Subcommittee—better to answer that question than I.

But it certainly seems to me that the California experiment

failed to connect the different parts of the market together. It was

far from—from free.

PGE—PG&E and Southern California Edison, as I understand it,

were both forced to buy high and sell low. That’s not a free market.

I’m worried that Bonneville can be put in the same position if we

don’t watch out up here. And certainly, the transmission system,

as you’ve also pointed out, isn’t far enough along to allow the free

exchange.

Other speakers today have also pointed out that what used to

work well on the West Coast—where California could send us

power when we needed it and vice versa—has been severely curtailed due to the California experience and the drought.

So there are a number of things that have combined, as Dr.

Karier mention—the ‘‘perfect storm’’ analogy—has all come together at once.

Mr. SMITH. Thank you.

Mr. CALVERT. Mr. DeFazio?

Mr. DEFAZIO. Thank you, Mr. Chairman.

Ms. Patton, I didn’t quite catch you. You said—you captured

1,500 megawatts of conservation back in the early ’90’s before

Randy Harvey panicked and cut off all the funding of BPA.

Now, was that 1,500 megawatts caused by coercion, or was it— what were the techniques used? Was it sky-high prices so people

were desperate?

Ms. PATTON. No. It was, in fact, a combination, a small amount

that came from good energy codes based on cost-effective—. Mr. DEFAZIO. Mandates?

Ms. PATTON. 200 megawatts of that.

Mr. DEFAZIO. That was a mandate.

Ms. PATTON. That was a mandate.

But they were also set at what was (inaudible) at the market

price. They were not set at the marginal cost of energy. Most of

that 1,500 megawatts came in as a result of utilities joining with

their customers. The customers paid some of the costs of a new efficiency improvement, and the utilities paid another part of it to

make it cost-effective to everybody so that you had zero-interest

loans for residential organizations, rebates on an efficient (inaudible) industrial motors, you know, the kinds of heating ventilation

and air-conditioning design (inaudible) new commercial buildings

so that we had a sharing of the cost. And it made it a good deal

for everybody. But they were not coercions. They were voluntary.

And they were-- and there was opposition.

Mr. DEFAZIO. And it was at 2 to 2 and a half cents?

Ms. PATTON. That’s right.

Mr. DEFAZIO. Which, in today’s market, would be--.

Ms. PATTON. A dream.

Mr. DEFAZIO. —a dream?

What’s your price on the 2,400 average megawatts you predicted?

Ms. PATTON. I have to conduct a full analysis of that from the

Power Council. What they looked at with their 1,500 megawatts,

123

which they did the full analysis on, was an average of 1.7 cents a

kilowatt hour.

Mr. DEFAZIO. Is that 1,500 available now?

Ms. PATTON. Yeah. I mean—.

Mr. DEFAZIO. At 1.7 cents a kilowatt hour?

Ms. PATTON. Exactly. And the whole reason is lost by not investing over this last period of time—is enormous, especially given the

current—Seattle City Light continued to invest in conservation

and—as did PG&E Water and Electric.

Mr. DEFAZIO. And wouldn’t that be a bit of a problem with a

tiered rate structure—to take those utilities which raised private

funds in the private markets, bonded, and vested—if we were suddenly to say to them, ‘‘Well, you, like everybody else, those who

have done nothing’’—which some utilities have done—‘‘will see a 25

percent penalty rate on your consumption’’?

Ms. PATTON. Not support those tiered rates. Right.

Mr. DEFAZIO. And so you’re saying there’s 2,400 megawatts out

there? Could you give a price? I’d be interested in a price.

Ms. PATTON. Again, a specific one (inaudible) Seattle and looked

at—any energy jurisdiction which is done with regard to conservation of energy stock saw another 250 average megawatts at 1.8 to

2.1 cents a kilowatt hour.

So I think we’re in the range of (inaudible) cents a kilowatt hour

for even that 2,400—.

Mr. DEFAZIO. Okay. And today, in the wholesale market and energy—I have trouble always coming up with my conversions—but

it’s selling at about 50 cents a kilowatt hour?

Ms. PATTON. Yeah. You just--.

Mr. DEFAZIO. Right. So you substitute 2 cents conservation for

a 50-cent purchase? The conservation provides a permanent benefit? The 50-cent purchase keeps the lights on for the next millisecond?

Ms. PATTON. Yeah, as well as more homes and businesses.

Mr. DEFAZIO. It doesn’t sound like it’s too tough of an equation.

Mr. Lepp, this—the two-tiered rate—you gave a number, but I

don’t know how that related to a percentage increase. You said you

had a 53 percent rate increase, and you said a tiered rate would

cost you 6- to $10 million. What would it be? Another doubling of

your rate or—.

Mr. LEPP. It would be another 50 percent.

Mr. DEFAZIO. Another 50 percent on your rate.

And would it be similar for every other industrial customer,

every other business except for DSI’s—is that correct?—that tiered

rate?

Mr. LEPP. In Seattle City Light’s area, it depends on the proportion of the power that they pull from Bonneville. And in the past—

Mr. DEFAZIO. Right.

But any BPA customer who is a business would see those sorts

of rate increases under the tired rate?

Mr. LEPP. Right.

Mr. DEFAZIO. And then finally, to Mr. Walton.

That was great testimony. A lot of witnesses comment on what

people have said before. But you comment on what other witnesses

124

said before you. It makes for a much more interesting sort of discussion.

You were put to the—the question by Mr. Smith on the issue of

deregulating one side and not the other.

Are you familiar with Montana’s situation? In Montana, they did

deregulate both sides for business; isn’t that correct?

Mr. WALTON. Yes.

Mr. DEFAZIO. And as I understand it now, all of their heavy industry—or virtually all of their heavy industry—is closed or closing, and many of the small businesses are threatened with closure,

and the State is desperately trying to find power because they deregulated both sides, unlike California.

And so what happens in the case of Montana, as I understand

it—and correct me if I’m wrong—is PP&L of Pennsylvania—Pennsylvania Power and Light—bought all of the generation from Montana Power, and they are now able to get higher prices outside the

state of Montana; so Montana, which had the sixth lowest rate in

the United States of America and 150 percent surplus in terms of

power generation, now has a point at which its businesses cannot

afford to buy power and is saying that they’re deficient in power

because the power is being sold for a higher price elsewhere. Is

that essentially an encapsulation of that situation?

Mr. WALTON. Mr. DeFazio, I believe it is, with the exception that

the cooperatively owned utilities in Western Montana, the Bonneville customers—some of them had the extreme foresight to purchase presubscription contracts. So they’re looking pretty good.

I think your description of what happened to Montana Power

was accurate, as I understand it. And I also followed, from a distance, the fact that the legislature had a special session. And the

question for them was would they give the Public Services Commission the authority to oversee the sale, by Montana Power, of their

assets.

And it’s my understanding that they didn’t have much authority.

So Montana Power essentially got to pick the purchaser. And so

this thing has kind of snowballed. And I think that’s turned into

an example—another example of how not to proceed with energy

costs.

Mr. DEFAZIO. And that in the one area the people most frequently say is the outstanding success of deregulation—Pennsylvania—are you familiar with the fact that, Pennsylvania has

capped rates in a deregulated—so-called ‘‘deregulated environment’’—that less than 10 percent of the customers have chosen the

thing that we were all told they wanted—which no one in California wanted either—which was customer choice—and that, in

fact, of course, Pennsylvania is also blessed with the fact that the

part of PJM which has mandatory scheduling authority as a regional transmission organization—and finally, of course, that their

economy is depressed, so they have a little bit of a surplus of power

right now?

But everybody is kind of worried about what happens when the

rate caps come off in 4 years. But right now it’s a success. Deregulation of the rate caps is a success in Pennsylvania, sort of.

Thank you very much.

Mr. CALVERT. Mr. Larsen?

125

Mr. LARSEN. Thank you, Mr. Chairman.

Ms. Patton, I’m glad you’re here today. (Inaudible) a reminder

that the impacts that were seen from the energy crisis in the

Northwest has a direct impact on consumers and homeowners and

(inaudible) folks on your list, all the opportunity council members,

Puget Sound Council of Senior Citizens, the Washington State Association of Community Action Agencies. These are groups that are

serving low-income, moderate-income people throughout the Northwest.

So I’m glad that you’re here. And I wanted to give you a very

brief opportunity—not to cover all the recommendations—but—in

the ‘‘what Congress can do’’ section—but do you have three or four

that you think would have the best, most immediate impact on lowincome, moderate-income individuals?

Ms. PATTON. Well, the first one is the continued Congressional

support, Federal support for low-income organizations. That’s incredibly important. We’ve been working on this in this region really

hard, and I will have to commend Bonneville for the one thing that

Bonneville continued to do when it was cutting its conservation (inaudible).

One of the major things they continue to do is more slashing of

conservation by 80 percent—was to fund low-income organizations.

It’s incredibly important for low-income households to have more

efficient trailers and more efficient homes to live in—and so strong

support for that, strong support also for energy assistance, because

low-income households are being hit, of course, much harder by the

entire rate even though utilities are working—the utilities in this

region are doing a good job. I think they’re trying to work with that

situation, but Federal support is critical.

Mr. LARSEN. Dr. Anderson, did you talk a little bit earlier about

how you would factor (inaudible) oscillation into drought management and, therefore, it hurts availability?

Mr. ANDERSON. That’s a good question. There are efforts now to

understand how we want to predict that. Looking back in the hundred-year record, we do see these clear, distinct signals of ecosystems throughout the Pacific, throughout the (inaudible).

So one of the things we could factor in—to state that these cycles

are going to continue with global warming, I guess that’s—that’s

not a good scientific approach, of course.

The other more scientific way to do this—there’s some work

that’s going on right now showing that a number of factors added

together give the ability to predict over the short term a couple of

years.

Also, we have scientists—scientists are out studying the plankton

off the coast. What we’re finding is when the ocean is fertile, the

fish survive well. So a monitoring scheme that is going on right

now can give us information that’s going to say, ‘‘Things are good

this year. Let’s give ourselves a little bit of slack somewhere else

in the system.’’.

I think that as research goes on, we will increase our ability to

predict, maybe in a couple months, maybe in a year or two. But

right now we’re not using any of this information. We’re not factoring in the ocean at all. Any information we do have, we’ll probably make decisions on the hydrosystem.

126

Mr. LARSEN. I think it’s like anything else. We need to be careful,

as well, about saying, ‘‘It’s only PDO,’’ and—and looking at that as

only one factor. And it’s quite a myriad of factors.

Mr. ANDERSON. Right. And they’re beginning to—they—they

have a four-factor analysis right now that—that’s—is looking encouraging. They are doing something like this for hurricanes—a fellow named Robert Gray—who has done very well predicting hurricanes. But—. Mr. LARSEN. Mr. Lepp, good to see you again. And I just shudder

when I read headlines like I read in the Seattle PI today because

my—in Bellingham, I see headlines like that day in and day out,

with companies shutting down, possibly, and Birmingham Steel

possibly being up for sale—which, you know, you just—provides

uncertainty in the community here.

I don’t know if there is a question in there, but more just to say

that it’s another clear example of the impacts the energy crisis is

having on the Northwest.

And if you have anything to add to that, feel free.

Mr. LEPP. Well, you know, there are 19 North American steel

companies that have gone bankrupt in the last 18 months. And

part of it, I know, from my standpoint of the products we sell—our

price today is the same as it was in 1972. So we have survived our

ability to—to maintain efficiency and keep looking for that—that

edge.

And you know, this—this circumstance here is really—is really

(inaudible). We were nicely profitable going into it, and this thing

just—just wiped us out—well, this plus the gas. Our gas price has

tripled since October of last year. That’s another part of this.

And we—we export a third of our products, which is probably— I would say probably the only American steel plant that does that.

There’s not many exports of steel other than what we do. We do

a commodity product, so we’ve got to be really, really efficient. And

we are. We are really proud of our efficiency. But I just can’t—it

creates a hurdle we just can’t clear, as much as we’d like to.

And we’re not going to compromise our environmental programs;

our safety programs; and those things that are near and dear to

us, to our employees. So those stay intact, and we keep doing what

we can do to survive.

Mr. LARSEN. Thanks for your comments, sir. Thank you.

Thank you, Mr. Chairman.

Mr. CALVERT. I want to thank this panel for your testimony and

answering our questions.

I want to thank Mr. Smith, his hospitality here in Tacoma—.

And to the audience for your willingness to come on this Saturday and sacrifice part of your weekend.

With that, this hearing is adjourned.

[Whereupon, at 11:50 a.m., the Subcommittee was adjourned.]

Æ