1994 MAJORITY STAFF REPORT OF THE TASK 

FORCE ON BONNEVILLE POWER ADMINISTRATION 

OVERSIGHT HEARING 

BEFORE THE 

SUBCOl\LVIITTEE OX 

OVERSIGHT AXD IXVESTIGATIONS 

OF THE 

COMMITTEE ON 

NATURAL RESOURCES 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED THIRD CONGRESS 

SECOND SESSION 

ON 

1994 MAJORITY STAFF REPORT OF THE TASK FORCE ON BONNEVILLE 

POWER ADMINISTRATION, "BPA AT A CROSSROADS" 

84-374 

HEARING HELD IN WASHINGTON, DC 

AUGUST 9, 1994 

Serial No. 103-113 

Printed for the use of the Committee on Natural Resources 

U.S. GOVERNMENT PRlNTING OFFICE 

WASHINGTON : 1994 

For sale by the U.S. Government Printing Office 

Superintendent of Documents, Congressional Sales Office, Washington, DC 20402 

ISBN 0-16 -046201 -0 
COMMI'ITEE ON NATURAL RESOURCES 

GEORGE MILLER, California, Chairman 

PHILIP R. SHARP, Indiana 

EDWARD J. MARKEY, Massachusetts 

AUSTIN J. MURPHY, Pennsylvania 

NICK JOE RAHALL II, West Virginia 

BRUCE F. VENTO, Minnesota 

PAT WILLIAMS, Montana 

RON DE LUGO, Virgin Islands 

SAM GEJDENSON, Connecticut 

RICHARD H. LEHMAN, California 

BILL RICHARDSON, New Mexico 

PETER A. DEFAZIO, Oregon 

ENI F.H. FALEOMAVAEGA, American 

Samoa 

TIM JOHNSON, South Dakota 

LARRY LAROCCO, Idaho 

NEIL ABERCROMBIE, Hawaii 

CALVIN M. DOOLEY, California 

CARLOS ROMERO-BARCELO, Puerto Rico 

KARAN ENGLISH, Arizona 

KAREN SHEPHERD, Utah 

NATHAN DEAL, Georgia 

MAURICE D. HINCHEY, New York 

ROBERT A. UNDERWOOD, Guam 

SAM F ARR, California 

LANE EVANS, Illinois 

PATSY T. MINK, Hawaii 

THOMAS J. BARLOW III, Kentucky 

THOMAS M. BARRETT, Wisconsin 

DON YOUNG, Alaska, 

Ranking Republican Member 

JAMES V. HANSEN, Utah 

BARBARA F. VUCANOVICH, Nevada 

ELTON GALLEGLY, California 

ROBERT F. (BOB) SMITH, Oregon 

CRAIG THOMAS, Wyoming 

JOHN J. DUNCAN, JR., Tennessee 

JOEL HEFLEY, Colorado 

JOHN T. DOOLITTLE, California 

WAYNE ALLARD, Colorado 

RICHARD H. BAKER, Louisiana 

KEN CALVERT, California 

SCOTT MciNNIS, Colorado 

RICHARD W. POMBO, California 

JAY DICKEY, Arkansas 

JOHN LAWRENCE, Staff Director 

STANLEY SCOVILLE, General Counsel 

DANIEL VAL KlsH, Republican Staff Director 

SUBCOMMITTEE ON OVERSIGHT AND INVESTIGATIONS 

GEORGE MILLER, California, Chairman 

SAM GEJDENSON, Connecticut ROBERT F. (BOB) SMITH, Oregon, 

CALVIN M. DOOLEY, California Ranking Republican Member 

NATHAN DEAL, Georgia JAMES V. HANSEN, Utah 

PHILIP R. SHARP, Indiana BARBARA F. VUCANOVICH, Nevada 

BRUCE F. VENTO, Minnesota JOHN J. DUNCAN, JR., Tennessee 

RICHARD H. LEHMAN, California JOHN T. DOOLITTLE, California 

PETER A. DEFAZIO, Oregon WAYNE ALLARD, Colorado 

KARAN ENGLISH, Arizona KEN CALVERT, California 

KAREN SHEPHERD, Utah RICHARD W. POMBO, California 

MAURICE D. HINCHEY, New York JAY DICKEY, Arkansas 

NEIL ABERCROMBIE, Hawaii 

LANE EVANS, Illinois 

THOMAS M. BARRETT, Wisconsin 

JOHN LAWRENCE, Staff Director 

JEFFREY K. STIER, Professional Staff Member 

DANIEL M. ADAMSON, Professional Staff Member 

LINDA GoRDON STEVENS, Clerk 

TED CASE, Republican Consultant on Oversight and Investigations 

(II) 
CONTENTS 

Page 

Hearing held: August 9, 1994 ... oooo•····oo····oo····oooo•oo 0000 oo•••oo ·····oo·····oo·······oo······oo········ 1 

Member statements: 

Hon. Peter A. DeFazio 00 OOOOooOOOOoooo ooOOOOOOOOOOOoOOOOOO 00000000000000000000000000000000000000 OOOOOOOoOOOO 1 

Hon. Robert F. (Bob) Smith oooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooo• 7 

Witness statements: 

Jack S. Robertson, Deputy Administrator, Bonneville Power Administration, Department of Energy, Portland, Oregon 000000000000000000000000000000000000000000 11 

Charts supplied by Mr. Robertson: 

1. Business Plan 00 00 00 00 00 0000 00. 00 00 00 0000. 00 00 00 00 00. 00 00 00 00 00 00 00 00 00 0000 . 00 00 00 00. 00 00 00 00 00 00 00 00 12 

2. Conservation Objectives OOOOOOOOOOOoOOOOOOOOOOOO 0000000000000000000000 0000 000000 000000000000000 13 

3. Rate Comparison 000000000000 oooooooooo. 00000000000 0000 00 0000000000000 00000000 oooo. oooo 00 00000 0000. 14 

4. Avoided Cost of Generation vs. BPA Average Rate 000000000000000000000000000 15 

5. BPA Conservation Acquisitions 1992-2002 oooooooooooooooooooooooooooooooooooooo• 271 

Further statement of Administrator Robertson, accompanied by Walter 

E. Pollock, Assistant Administrator for Power Sales, Bonneville Power 

Administration, Department of Energy 000000 00 0000 .. oooooooooooooooooooooooo 000000 0000000000 199 

Prepared statement of Mr. Robertson 000000000000000000000000 00000000 0000000000000000 00 oooo .. oo... 207 

Bonneville Power Administration's responses to pre-hearing questions 00000 228 

Angus Duncan, Council Member, Northwest Power Planning Council, 

State of Oregon 00 00000000000000000000000000 00 0000000000000 00 000000 0000000000000 0000 oo ..... 00000000 000 00 0000. 17 

Prepared statement of Mr. Duncan .... OOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOoOOOOOOOOOOOOOOOOOOO 20 

Panel consisting of: 

K.C. Golden, executive director, Northwest Conservation Act Coalition, Seattle, Washington ooooooooooooooooooooooooooooooooooooooooooooooooooooooooooOOOOOoOOoOOO 54 

Prepared statement of Mr. Golden OoOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOO 56 

Ken Canon, managing director, Association of Public Agency Customers, Portland, Oregon 0000000000000000000000 000000 OOOOOOOOOOOOOOOOOOOoOOOO 00000000 000000 0000 67 

Prepared statement of Mr. Canon 0000 000000 OOOOOOOOOoOOOOOOOOOOOOOO OOOOOOOoOOOoOOOOOO 69 

Brett Wilcox, president, Northwest Aluminum Company, The Dalles, 

Oregon, accompanied by Ken Peterson, Jr., chief executive office, 

Columbia Aluminum Corporation, Vancouver, Washington .... 00 .. 000000 75 

Prepared statement of Mr. Wilcox 0000 000000000000000000 0000 0000 0000 OOOOOOOOOOOoOOOOOO 77 

Prepared statement of Mr. Peterson 0000000000000000000000 0000 0000 000000000000000000 85 

C. Clark Leone, manager, Public Power Council, Portland, Oregon 00000 90 

Prepared statement of Ms. Leone OoOOOOOoOOOOoo oOOOOOoOOO oooo .... oo .. OOoOOO 0000000000. 92 

Daniel C. Scott, commissioner, Mason County PUD No. 1, on behalf 

of the Aluminum Information Project Utilities, Shelton, Washington ........... oo •• oo •••• oo ................................................ oooo····oo·····oo··················· 99 

Prepared statement of Mr. Scott OOOOOOOOOoOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOO 100 

David E. Piper, general manager, Pacific Northwest Generating Cooperative, Portland, Oregon 00 00000000000000 0000 00000000 OOOOoOOOoOOOoOOOoOoOOO .. oo .. oo .... oo.. 122 

Prepared statement of Mr. Piper 00 00 0000 00000000000000 ...... oo ...... OO .. OOOooOoooo.... 124 

Judy Lamson, policy specialist, Washington Utilities and Transportation Commission, Olympia, Washington oooooooo ...... oo .... oooooooooooooooooooooo 141 

Prepared statement of Ms. Lamson OOOOOOOOOOoOOOOOOOOOOOOOoOOOOOOOOOOOOOOOOOOOOOOOOO 143 

William G. Counsil, managing director, Washington Public Power Supply 

System oooooooooooooooooooo .......... oo.ooooooo•oo·········oo····oo·········oo·····oo······oo····················· 178 

Prepared statement of Mr. Counsil .. oo .. oooooooooooooooooooo Oo oooooooooooo Oo ooooooooooooooo 181 

(III) 
IV 

APPENDIX 

AUGUST 9, 1994 

Additional material supplied for the hearing record from: 

Washington Public Power Supply System (WPPSS): Letter to Chairman 

DeFazio from W.G. Counsil, managing director, dated June 9, 1994 ..... . Subcommittee on Oversight and Investigations, Committee on Natural 

Resources: 

Letter from Chairman Miller to Mr. Counsil, WPPSS, dated September 8, 1994, including follow-up questions ......................................... . WPPSS: Letter from Mr. Counsil to Chairman Miller dated September 

30, 1994, in response to Chairman Miller's letter of September 8 .......... . City of Seattle: Prepared statement of Hon. Norm Rice, Mayor of Seattle, on "BPA at a Crossroads," submitted by Hon. Jim McDermott to Chair- man Miller by cover letter dated September 8, 1994 ................................ . Subcommittee on Oversight and Investigations, Committee on Natural 

Resources: 

1. Comparison of WNP-2 Staff Levels With Industry Averages, prepared by Mark Holt, Congressional Research Service, August 8, 

1994 ········································································································· 2. Committee Print No. 7, "BPA At a Crossroads," May 1994 ............ . 

Page 

275 

277 

284 

292 

298 

300 
1994 MAJORITY STAFF REPORT OF THE TASK 

FORCE ON BONNEVILLE POWER ADMINISTRATION 

TUESDAY, AUGUST 9, 1994 

HOUSE OF REPRESENTATIVES, 

SUBCOMMITTEE ON OVERSIGHT AND INVESTIGATIONS, 

COMMITTEE ON NATURAL RESOURCES, 

Washington, DC. 

The subcommittee met,~pursuant to call, at 9:45 a.m., in room 

1324, Longworth House Office Building, Hon. Peter A. DeFazio presiding. 

STATEMENT OF HON. PETER A. DeFAZIO 

Mr. DEFAZIO. Okay. The committee will come to order. 

There will be a slight change in the order today in that I will 

make an opening statement, and then Congressman Smith will 

have some opening remarks, and then we will hear briefly from Mr. 

Robertson, Deputy Administrator representing Bonneville Power 

Administration for an announcement. And then, because I believe 

that will perhaps be reflected in subsequent testimony, or subsequent testimony we may want to reflect on that, and then we will 

go to the panels as scheduled. 

It is about a year ago, we were in the midst of the Bonneville 

Task Force hearings, a number of which we did in the Pacific 

Northwest. In fact, it would have been my preference to do this 

hearing in the Northwest, but given the exigency of the schedule, 

that wasn't possible and I felt the hearing was very timely and important, given the speed with which BPA is moving to implement 

what would be the most far-reaching changes in the system of distributing Northwest power and in the relationships among the customer groups since the Northwest Power Act of 1980. 

There is some controversy over what the immediate threat is to 

Bonneville regarding their future competitiveness and how they 

might best respond to that. The key to me is that we want to get 

this right. Certainly there are time pressures, and we must look at 

those. 

On the other hand, the last time the region got into a panic over 

time pressures, that being the panic generated by the notices of insufficiency, promulgated by BPA to the region, we put ourselves 

into the largest financial disaster in the history of the Pacific 

Northwest, and we are still paying for it, and we will be paying for 

it, most of us in this room, until the day we die. That episode was 

called WPPSS. 

(1) 
2 

So I want to make certain that in rearranging relationships in 

the Northwest, we do it well. To me, you know, the best public policy is made in the public view. 

Perhaps I am prejudiced as an Oregonian. I was a local official. 

I dealt with the open meetings law and we had to do the most sensitive things always in a public forum. And even if we finally could 

find something like a personnel matter that required a closed session, the reporters could still come in the room and they could challenge whether or not that was truly appropriate as a closed-door 

meeting. 

I am concerned that much of the basis for the Bonneville Power 

Administration's new policies has been formulated essentially behind closed doors. Yes, there have been customer working groups 

and other things, but there has not been broad public involvement, 

in part because of the complexity of the matters, but in part because of the relationships that exist between particular customer 

groups and the Bonneville Power Administration, the ins and the 

outs, the haves and have-nots, the winners, the losers. 

So I think it is entirely appropriate, despite some testimony submitted to this committee, that Congress, the policymakers, shed 

some light on what is going on and attempt to help the region, that 

is the people of the region, every person in the region, determine 

the equities in what is being proposed. We have allegations by 

some customers, an analysis by the non-DSI industrials, that there 

would be a massive shift of burden under this new tiered rate proposal, increasing costs to the public utilities of up to $300 million 

a year. Who wins, who loses? Is that good public policy? Will that 

get us to the energy future we want in the Northwest? Those are 

questions that we need to examine today. 

I am pleased that we have a good slate of witnesses to come before us, and we have a number of issues to develop. The committee 

had a rather extensive series of questions it asked to have addressed. 

I have read the testimony that was submitted as of 5:00 o'clock 

yesterday. As the witnesses testify, I would prefer that they summarize, go to points in response to other testimony, and do as best 

as possible to make their testimony relevant, knowing that what 

you have written has been read and any other written responses 

that you might provide will be read, and will be incorporated into 

the entire record. 

This is an extraordinarily important time for our region. It is a 

time of change, and, as in any time of change, people are jockeying 

for position. I don't expect anybody, no matter what interests they 

represent, to come in and want to give away their interests. 

I don't expect private utilities to want to give big advantage to 

the public or to make some changes that would give big advantage 

to private, or one industrial group to want to give advantage to another. Certainly you should all be strong advocates for the interests 

that you represent. I understand that. I appreciate that. I am an 

advocate myself. 

But I am an advocate for the future of the entire Pacific Northwest and all the ratepayers. I want to balance those interests fairly 

and equitably as we balanced them I think with great wisdom and 

after great controversy in the Northwest Power Act. 
3 

I am concerned that what is being proposed here will unbalance 

that act and in ways that we don't yet understand, and that is 

what this hearing is about. We want to understand it. We want to 

lay it out. We want everybody to have an opportunity to comment 

on it. We want to decide as a region that it is fair and equitable 

and the best way to go forward to a stable energy future for everyone who lives in the Pacific Northwest, particularly for our children. That is why we are here today. 

So I thank everybody for trekking across the country. I do it a 

lot. I know it is not fun or easy. And I look forward to your testimony. [Prepared statement of Mr. DeFazio follows:] 
4 

The Remarks of the Honorable Peter DeFazio 

For a Hearing of 

The Subcommittee on Oversight and Investigations 

August 9, 1994 

Last year at this time, the Task Force on the Bonneville 

Power Administration was in the midst of a series of hearings 

considering the extraordinary challenges facing BPA. We then 

spent many months working on a report containing my conclusions 

after that oversight exercise. The report and its relationship 

to the changes now being proposed by Bonneville in its Draft 

Strategic Business Plan is the subject of this hearing. 

BPA is moving to implement the most far-reaching changes 

considered by the agency since the passage of the Northwest Power 

Act in 1980. I've heard an increasing number of concerns that 

Bonneville is moving too hastily -- that the agency has so many 

processes underway, it is virtually impossible to keep up with 

them all or understand the implications of the sum of the changes 

now underway. 

BPA claims that its haste is driven by the competitive 

threats unleashed by an increasingly deregulated utility 

marketplace and cheap natural gas. We can all agree that 

Bonneville faces unprecedented competitive challenges. But we 

seem to have some disagreement on the immediacy and the magnitude 

of those threats. We'll hear more about that during this 

hearing . 

BPA is first and foremost a public agency with a mandate 

from the public it serves. The public deserves to fully 

understand the implications of the profound changes underway at 

BPA before those changes are set in place. 

That's why I am pleased to be able to share a letter I just 

received from BPA Administrator Randy Hardy. In answer to my 

written request -- and the requests of a growing number of 

Bonneville's customers -- Randy has decided to delay the start of 

a rate case intended to design and implement a tiered wholesale 

electric rate. His revised schedule would commence a rate case on January 9, _jnstead of October 15. · 

That's good news and I congratulate BPA for its flexibility. 

As we will hear later today, BPA's tiered rate proposal could 

cause a huge shift in costs between customer groups, placing as 

much as $300 million a year in new costs on growing public 

utilities like EWEB or the Springfield Utility Board in my 

district, or the utilities serving Tacoma and Seattle in 

Washington State. 

Though I'm pleased that Bonneville has slowed the pace a bit 

on tiered rates, I am dubious about the agency's plans to 

complete the complex task of negotiating new power sales 

contracts within the next four months. The current contracts 
5 

between BPA and its utility and DSI customers expire in 2001. 

Some of the most significant issues facing Bonneville and the 

regions' electric ratepayers will be resolved in the new 

contracts, including the region's relationship to the aluminum 

industry and the nature of the integrated resource planning 

requirement now being negotiated with BPA's public utility 

customers. 

I understand and sympathize with the customers' desire for 

planning certainty. But I am strongly of the opinion that BPA 

must resolve these issues openly and only after consideration of 

a range of alternatives. To that end, I am urging Bonneville to 

prepare an environmental impact statement to guide the 

development of its new long term power sales contracts. An EIS 

will lay out options for BPA and its customers, and analyze the 

likely outcomes. That's the kind of information the region needs 

in order to understand and ultimately endorse BPA's new 

direction. 

Among the changes proposed by Bonneville is the reinvention 

of its conservation programs. It is .far from clear whether BPA's 

reinvention will accomplish the region's energy conservation 

goals. BPA's current conservation programs delivered a record 52 

megawatts of conservation last year at a cost of only 23 mills 

per kilowatt-hour. The burden of proof is on Bonneville to show 

that its new approach will deliver the energy efficiency savings 

called for by the Power Planning Council. I remain unconvinced . 

The tradition of publicly-owned and operated utilities is 

particularly strong in the Pacific Northwest. Public power 

offers its ratepayers economical electric power and responsive 

service. A public utility is, by definition, devoted entirely to 

the interests of its ratepayers. I am a strong believer in 

public power. 

BPA was created to market the power from the federal 

hydroelectric projects on the Columbia River. In its sale of 

power, it is directed by law to give "preference and priority" to 

publicly-owned utilities. BPA's Business Plan seems to violate 

that very basic directive in a number of respects. We'll talk 

about the fut~re of public preference during today's hearing. 

And finally, the Task Force report contained a number of 

proposed cost savings. Some of the most significant are found in 

the management of the Washington Public Power Supply System's 

single operating nuclear reactor. Mr. William Counsil, the 

managing director of WPPSS, took issue with those 

recommendations. He's here today to make his case. 

We will not be considering the changes proposed by BPA in 

its fish and wildlife programs during this hearing, though that 

issue may be the subject of a future hearing . Generally, I share 

BPA's interest in making its fish and wildlife obligations more 

predictable, but am concerned about any proposal that seeks to 
6 

place an arbitrarily defined cap on BPA's fish and wildlife 

obligations. 

As I said, BPA is first and foremost a public agency with a 

public purpose. We all support BPA's goal of maintaining its 

competitive position, of becoming less bureaucratic and more 

efficient. But not at the cost of sacrificing its mandates to 

promote efficient energy use and rebuild the Columbia River's 

salmon runs. Those mandates should not be seen as a drag on 

Bonneville's ability to do business, but as the reason Bonneville 

is in business in the first place. 

The Task Force's report stated: "The Northwest Power Act 

sought to encourage conservation and efficient energy use and 

promote the development of renewable energy resources, thus 

assuring the Northwest an adequate, efficient and economical 

supply of power. The goals of the Act remain sound. In the 

final analysis, these goals are the yardstick by which 

Bonneville's new Marketing and Business Plans should be 

measured ." 

This hearing seeks to measure BPA's Business Plan against 

that yardstick. 
7 

Mr. DEFAZIO. I will defer now to Congressman Smith and then 

we will hear from Mr. Robertson. Bob? 

STATEMENT OF HON. ROBERT F. (BOB) SMITH 

Mr. SMITH. Thank you very much. You are certainly correct. 

This hearing comes at a very crucial time, especially for Bonneville Power Administration. It seems to me exacerbating this whole 

issue has been the idea that for too many people that BPA is a bottomless pit for every social program that comes along. They spend 

$1 billion trying to save fish, currently $1 million a day, and it 

seems as though there is no breakthrough in that issue. 

But I want to compliment what I believe Bonneville Power Administration is doing currently in reorganization and trying to 

bring the agency into a competitive world. There is no question in 

anybody's mind that it wasn't the Government that did it, or it 

wasn't hearings that did it, it was the need to be competitive, and 

Bonneville is reaching out, attempting to reorganize and attempting to compete, and I take my hat off to them for that. I would 

hope in the future that they would not be so soft-headed and softminded as to accept every brainless idea that comes down the road 

about how to correct either the salmon runs or the issues on the 

whole Columbia River. 

But of course many say that it is still not enough, Bonneville 

must do more. Of course these are the same people that have 

bought into the Andy Kerr logic that we must go beyond $1 million 

a day in spending money for fish and of course to save the salmon, 

we must eliminate the real villains. 

Now, who are those real villains? Well, to those that know, the 

real villains are the direct service industries who operate from Bonneville energy, so-called corporate agriculture, quote-underline 

corporate agriculture, and of course included in this is the aluminum industry. These are the people that are responsible for the 

loss of our salmon, and, Mr. Chairman, you probably know-I am 

not sure you do--that there is one huge aluminum company in my 

district. It is called Northwest Aluminum. Brett Wilcox is here. 

This huge corporate structure has a little notch business in the 

aluminum area in the country. They employ 470 people at a decent 

wage in The Dalles, Oregon, and when we talk about the villain, 

make sure we include this huge octopus, this giant industry that 

is housed in The Dalles, orchestrated and engineered by basically 

one person and his employees who are part of the whole program 

and has been tremendously successful. 

Well, I think that we can still support an affordable and environmentally-responsible energy package for Bonneville, and at the 

same time support 40,000 direct and indirect jobs in our area associated with the DSis in the Northwest. While eliminating an industry that pumps about $2 billion annually into the Northwest economy is not going to bring the salmon back, but it could bring us 

a recession to the Pacific Northwest. 

And I mentioned this corporate agriculture that has been 

charged with demonizing the waters of the Columbia River, the 

facts are that on the Washington side about 1.5 percent of the Columbia River water is used for agriculture, and on the Oregon side, 

about 1 percent of the water is used for agriculture. So if we wiped 
8 

out this corporate agriculture, which by the way is not corporate 

at all. These are mom and pop farms. There may be a corporation 

or two along the river, but for the most part, they are just family 

farmers using a very small amount of water and trying to make a 

living and providing the cheapest food in the world to the people 

of America. 

So I suppose we should get rid of them. That would help a lot, 

I know. And then, you know, we go to the whole question of the 

DSis and those who are producing in the Pacific Northwest. 

So I don't have a problem standing up for the people who 

produce, and there is no question that we have made some horrible 

mistakes in the past and BPA has, and is attempting to be the perfect environmental and conservation-oriented organization, and it 

has cost billions of dollars and it hasn't worked. 

So rather than point fingers at each other and eliminate industry 

and agriculture, and aluminum, maybe we better look inside and 

see what we have done wrong on the other side of the ledger, that 

is attempting to be politically perfect environmentally, and in the 

area of conservation. 

I look forward to these hearings, Mr. Chairman, because I think 

there is a defense that can be raised and will be raised today 

against those who believe that we ought to chop out 13 dams and 

therefore the economy of the Northwest to satisfy what some believe is the salvation of the salmon. 

Thank you. 

[The prepared statement of Mr. Smith follows:] 
9 

STATEMENT OF CONGRESSMAN ROBERT F. (BOB) SMITH 

OVERSIGHT AND INVESTIGATIONS SUBCOMMITTEE 

HEARING ON "BPA AT A CROSSROADS" 

AUGUST 9, 1994 

Mr. Chairman, 

This hearing comes at a crucial time for the Bonneville Power 

Administration. This agency that for too long has been the bottomless pit 

for every social program that comes along. They have spent one billion 

dollars on saving fish. But yet some say that's still not enough. 

These are the same people that have bought into Andy Kerr's logic that we 

must go beyond spending one million a day for fish. They say that to save 

the salmon we must eliminate the real villains -- the direct service industries 

and irrigated agriculture. 

I wasn't aware until recently that the 470 people working at the aluminum 

plant in my district were putting Northwest ratepayers at risk. The truth is, 

they are not. Nevertheless, some are trying to exploit this issue even though 

they know it makes absolutely no sense. 

I think you can still support affordable and environmentally responsible 

energy path for Bonneville and still support the 40,000 direct and indirect 

jobs associated with the Direct Service Industries in the Northwest. 

Eliminating an industry that pumps $2 billion annually into the Northwest 

economy is not going to bring back the salmon. But it may bring back a 

recession in the Northwest. 

Or what about irrigated agriculture. We have heard about the so-called 

"corporate irrigators" who want to gut the Northwest Power Act . Who are · 

these people? The irrigators I know are family farmers in places like 

Umatilla and Morrow County. These small operations in these two counties 

inject $400 million into Oregon's economy and they are not the least bit 

interested in gutting the Northwest Power Act. They are too busy trying to 

scratch out a living. 
10 

So I don't have any problem standing up for these people even if some 

others won't. The problem is not the people who create jobs in the 

Northwest, it's the people in the Northwest who think Bonneville is a cash 

register. 

The problem is that some people have confused cutting the fat at Bonneville 

and cutting the heart out of the Northwest economy. 

Mr. Chairman, I look forward to the testimony we will hear today. 
11 

Mr. DEFAZIO. I thank the gentleman. 

Mr. Allard, do you have an opening statement? 

Mr. ALLARD. Mr. Chairman, I don't have an opening statement. 

Thank you. 

Mr. DEFAZIO. Okay. Thank you. 

With that, Mr. Robertson is recognized out of order for some very 

brief remarks. 

STATEMENT OF JACK S. ROBERTSON, DEPUTY ADMINISTRATOR, BONNEVILLE POWER ADMINISTRATION, DEPARTMENT OF ENERGY, PORTLAND, OR 

Mr. ROBERTSON. Thank you, Mr. Chairman. I am Jack Robertson, Deputy Administrator of Bonneville. 

We thought we would at least lead off here with a change of 

schedule which we thought was significant and would perhaps lay 

the context clearer for the hearing. Last month we received from 

you a letter indicating your concern about the fact that we were in 

fact proceeding on a schedule that seemed to you to be too quick 

based on the issues you felt were at stake. You had indicated to 

me personally, I think and to others, that you felt there was a 

growing customer and stakeholder concern in the region that this 

schedule was in fact causing people concern because of the compression of time around it. 

In the wake of that letter, and in conversations with you, we did 

a customer survey and talked to stakeholder groups, as well, to 

verify that in trying to shape our public involvement program to 

be responsive to as many concerns as we could. We look forward 

to congressional reviews like this. We look forward to open debate. 

We think that will definitely result in a better product in the end. 

We take a lot of pride in our public involvement responsiveness. 

What you see here is, quickly, a before and after chart, I think 

you have a copy of this in your packet. If you don't, we can get it 

to you. The chart simply on the top is the before chart. This is before we had a conversation. We were planning on finishing our 

public involvement process at around the end of August with three 

public hearings. We have blowups of this. 

[The charts follows:] 
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=-- ---=! ~ ,.,_.,,., .ro 1oll•.l 
1,500 

1,250 

1,000 

z 

"' 750 0 

3 

i 

500 

250 

Conservation Object

Without 

Business Plan 

1996 1997 1998 1999 2000 2001 2002 

z 

"' 

0 

3 

i 

1,500 

1,250 

1,000 

750 

500 

250 

Bu

I BORROWING C

1996 1997 
40 

38 

36 

.c 34 

:t 

~ 32 

~ 30 ftl 

c::: 

·e 28 

0 

c::: 

26 

24 

22 

20 

Rate Comparison 

. . · . n 

.Rb- '· ·-'-< 

1992 1993 1994 1995 1996 1997 1998 1999 2000 
A voided Cost of G

vs. BPA Avera

100 I NUCLEAR COAL 

80 

60 

mills/kWh 

($1993) 

40 

20 

o~--~~--~~--~~--~

1980 81 82 83 84 85 86 87 

- Avoided Cost of Generation 

NUCLEAR: based on actual cost of Washington P

COAL: based on studies by Kaiser Engineers Powe

GAS: based on studies by Fluor Oaniellncorp
16 

Mr. DEFAZIO. You are dealing with an aging panel here. Mr. RoBERTSON. What you and folks in the region wanted, was 

to put it as simply as possible and as quickly as possible. You needed more time for a discussion about the impact on tiered rates and 

discuss how those tiered rates might effect various customer classes. You needed to get more information from us before we entered 

into that debate more seriously-about the potential impact by customer group. The customers also needed to have more information 

on principles associated with contracts negotiations that are preceding in parallel with the rate case. 

To be brief, what you see in the after arrow is a substantial expansion of the window of discussion, the rates discussion. At the 

top of the after arrow, you can see the window of discussion has 

opened quite large and now extends to January, 1995. At that point 

the darkness takes over, that is when the rate case begins and the 

ex parte window comes down. That was a concern I know of the 

committee as well. 

So, we have tried to push that rates discussion period out. We 

will provide further information through a tiered rates model to the 

committee and to others in the region in the next 30 days. [The information follows:] 

The tiered rates impact model is still under development. Technical work is being 

done by BPA and our customer representatives. We will provide the model to the 

Committee upon completion. 

Mr. ROBERTSON. You can see that the contract discussion which 

was simply a discussion pointed to the top arrow before our conversations with the customers, beginning with contract negotiations in the spring, now involves principal negotiations on the contracts, begins in parallel and ends around January 1, as well. We 

think that will marry up the concerns of the customers for more 

information and begin to make basic principles known in the contracts prior to entering the rate case when a number of principles 

are translated into different rates. 

Fundamentally we have expanded the public involvement process 

into September. I think that is not enough for some folks, but given 

the rate schedules we are on and the need to get done by October 

1 of next year, we are deeply pushing the Bonneville staff, which 

is in a transformation of its own. 

So to make it brief, we tried to respond to our customers. We 

have met with the customers and others. We did a pretty good job 

of moving quickly, and I think we have opened a discussion. There 

will be plenty of opportunity for interactive debate in the course of 

the next two or three months. 

Mr. DEFAZIO. If I could briefly summarize. The immediate concern which I expressed, that is, not fully understanding the potential impact between customers groups, which has been a growing 

concern in the region, and then there are other concerns to be expressed during the hearing, that during this time period, there 

would be latitude for adjustment in the tiering proposal, more analysis on those disparate impact that will be made available to all 

of the customers and the public in the Pacific Northwest so that 

we fully understand what we are entering into. 
17 

Mr. ROBERTSON. Yes. We expect to provide a tiered rate impact 

model which is jointly developed by the customers and us later this 

month. It should begin to be the basis of the information you need. 

Mr. DEFAZIO. You think later this month you can have that. 

Mr. RoBERTSON. That is what our objective is. We will get it done 

in plenty of time. The window now gives us the opportunity to iterate on that. 

Mr. DEFAZIO. Okay. I appreciate that. I think it is a good step 

on the part of BP A. The only unfortunate part of your testimony 

was where you said the darkness takes over on January 1st, but 

we will let that go by. 

Mr. RoBERTSON. Some people see it that way. 

Mr. DEFAZIO. Well, you know, there is a problem when we get 

into the rate setting in terms of the, you know, the restrictions of 

the ex parte contacts, and you know, when people want to raise 

policy concerns, it is very difficult, and I understand you are also 

looking at ways to modify and your attorneys are reviewing ways 

in which you could have a more open process during the rate making; is that correct? 

Mr. ROBERTSON. Yes. 

Mr. DEFAZIO. Okay. Thanks. 

Mr. ROBERTSON. Thank you. 

Mr. DEFAZIO. We will return to the regular order now and have 

the first panel. It is a rather large-oh, wait a minute. Sorry. We 

start with a small panel, but of high quality. I skipped to part two 

there, Angus, sorry. Angus Duncan, council member, Northwest 

Power Planning Council for the State of Oregon. 

STATEMENT OF ANGUS DUNCAN, COUNCIL MEMBER, 

NORTHWEST POWER PLANNING COUNCIL, STATE OF OREGON 

Mr. DUNCAN. Mr. Chairman, thank you. Mr. Smith, good morning, nice to be here in this historic room. Mr. Chairman, my name is Angus Duncan. I am here today rep- resenting the Northwest Power Council to offer the council's testimony on the report of the Task Force on BPA and on Bonneville's 

draft strategic business plan. You have our written testimony and 

I just have a few remarks here to add. 

The council emphatically supports the stated intention of the 

draft business plan, which is to steer Bonneville through the competitive challenges it faces to successfully achieve its fundamental 

legislative plan dates. There is also much within the business plan 

that the council supports, including actions that were called for in 

the council's 1991 power plan. 

There are also elements that the council believes must be developed more fully before they are decided and implemented. I discussed these principally in the written testimony. 

This morning I would like to focus on four challenges for Bonneville that the council perceives in this plan. 

The first has to do with Bonneville's response to the newly competitive energy markets. Bonneville begins with a significant competitive advantage in this region, the Pacific Northwest. The council staff analysis has suggested that Bonneville's wholesale power 

is today between 16 and 30 percent less expensive than power sold 
18 

by other Northwest utilities, Bonneville's initial competitors in the 

emerging wholesale power markets. 

We believe with prudent business choices that Bonneville should 

be able to maintain that edge into the foreseeable future. As it adjusts to the competitive marketplace, Bonneville must be selective 

in choosing the markets where it will compete; it must husband the 

Federal base system, maximize its efficiency and cost advantages. 

Some of the methods that Bonneville proposes for maintaining its 

competitive position, such as tiered rates, are proposals that the 

council set forth in the 1991 power plan. It is gratifying to see 

them emphasized in the business plan, and we are working with 

Bonneville on the process of implementing those ideas. 

Second, Bonneville has a balance beam to walk here between the 

competitive pressures of the marketplace and the agency's identity 

as a public agency with public interest responsibilities. This is 

more than simply compliance with the law, which is the obligation 

of any private company. Bonneville is the steward of a valuable regional power system and of the rivers that underlie that system, 

and these are rivers that have environmental, aesthetic, and cultural as well as economic significance, including most particularly, 

rights reserved by Indian tribes through treaties with the United 

States. 

Bonneville's challenge is to remain a competitive wholesale supplier of power products and services while fully implementing the 

intent of Congress in the Northwest Power Act and the council's regional power plan and regional fish plan; that collective intent, particularly, to acquire all cost-effective conservation, to develop new 

renewable technologies and to protect, mitigate and enhance fish 

and wildlife in the Columbia River basin. 

The biggest unknown affecting Bonneville's competitive position, 

aside from whether it can complete its internal efficiency measures, 

is the impact of fish and wildlife expenditures, particularly the impact of river operations that may be required to protect threatened 

salmon stocks. No one can guarantee that there will not be further 

impact to the hydro system, but the council, working with Bonneville and other parties in the region to look for the most cost-effective ways to use that system while protecting the fish, including, 

for example, more cost-effective and less hazardous means of spillage of fish through the dams. 

The council's third concern is that Bonneville recognizes which 

elements of the business plan are right for implementation, organizational structures. More efficient and delegated decision-making 

are two examples, and which need further work within the region. 

Reinvention of conservation, some aspects of the tiered rate proposal, treatment of fish and wildlife obligations are examples of 

policy choices with far-reaching consequences that should be neither delayed needlessly, nor rushed to fit a predetermined business 

plan schedule. 

Finally, Bonneville must prepare to compete long-term as well as 

near-term. With its present edge in wholesale power costs, Bonneville is better positioned than any other regional facility to invest 

retained earnings in tomorrow's technologies and information systems where this can be done through collaborative efforts, through 

EPRI, through the National Labs, the regional collaboratives. Bon-
19 

neville should exploit such opportunities to make the dollars go further. The same fashion, cost-effective investments in conservation 

today will pay dividends in regional competitiveness down the road. 

But if the cost advantage is applied only to keep rates down today, 

the region will lose an enormous opportunity for the future. 

In conclusion, the council finds much to support in the business 

plan. We are concerned that undertaking changes in haste or with 

only short-term competitiveness foremost in mind would not serve 

the region well. We agree that Bonneville faces competitive challenges, but we believe that through thoughtful management, Bonneville can make these challenges work to its advantage and the 

region's. 

Thank you, Mr. Chairman. I will be happy to answer any questions. 

[Prepared statement of Mr. Duncan follows:] 
c...c ....... t 

w .. IWI,po• 

Dna•• 

.............. ONJell 

20 

NORTHWEST POWER PLANNING COUNCIL 

851 S. W. SIXTH A VENUE, SUITE 1100 

PORTLAND, OREGON 97204-1337 

Phone: 503-222-5161 

Toll Free: 1-800-222-3355 

FAX: 503-795-3370 

August 6, 1994 

Testimony of the 

Northwest Power PlaDDlnl Councn 

before the 

Subcommittee on Oversight and Investigations 

Committee on Natural Resources 

U.S. House of Representatives 

on the report of the 

Task Force on the BonnevDle Power Administration 

"BPA at the Croasroads" 

JAYLWID 

VJaCJIAIUWO 

..... ...... " (IM) santk ..... 

.Je]laN.Etda&n 

--

Good momlng. Mr. Chalnnan and members of the Committee. My name Is 

Angus Dnncan. and I am one of two Oregon members of the Northwest Power 

Planning Connell. I am pleased to be here today to offer the Connell's testimony 

on "Bonnev1lle at the Crossroads.· the report of the Task Force on the Bonnev1lle 

Power Admlnlstration, and on the consistency ofBonnev1lle's Draft Strategic 

Business Plan with the recommendations of Sections II and IV of the Task Force 

report. 

Our comments are organized to address 1) goals of the Business Plan, 2) 

the major policy changes that Bonnev1lle Is proposing to help achieve those goals. 

3) some observations and concerns regarding the adequacy and rnatunty of some 

of the policies proposed In the Business Plan to achieve the goals of the Northwest 

Power Act, 4) some observations about the hnplications of the proposals In the 

Business Plan for the dlstrtbution of costs and risks In region, and 5) some 

observations regarding the rationale for the changes being proposed by Bonnev1lle 

and Bonnev1lle's characterization of that rationale. The good news Is that the 

Connell believes that Bonnev1lle Is now a competitive power supplier and can, 

with sk:Ulful management, remain so In the future. We briefly address fish and 

wUdllfe Issues raised In the Business Plan. We look forward to future 

opportunities to comment further. 

We note at the outset that many of the features of the Business Plan are 

features that the Connell has supported for some time. For example, the ·connell 

called for examination of multi-tiered wholesale rates In the 1991 Power Plan. We 

have been encouraging greater decentralization of conservation Implementation. 
21 

The Council has also been actively encouraging approaches to conservation 

Implementation that reduce the cost to the utlllty system. We are pleased to see 

these Initiatives reflected tn the Business Plan. 

There Is one overrtdtng conunent. The goal we all have Is that Bonneville 

remain competitive and fulfill it obligations under the Power Act today and In the 

future. To accomplish this, Bonneville must remain clear about Its fundamental 

purpose and nature. It Is a public agency with broad and long-term public 

purposes as well as narrower and shorter-term conunerclal purposes. Bonneville 

will Inevitably face pressures to sacrifice Investment for the long tenn. such as 

conservation. tn favor of short run rate advantages. The Intent of the Business 

Plan must be to make Bonneville business-like tn the execution of both Its public 

and private purposes. It must not be to make Bonneville Into a business for 

which public purposes are secondary to Its conunerclal purposes. It Is not yet 

clear that the Business Plan has fully succeeded tn walking this fine but essential 

line. The Council and others tn the region are prepared to continue to work with 

Bonneville In this important task. 

Goals of the Draft Strategic Buslneu Plan 

The Council clearly supports the stated Intention of the Draft Business 

Plan, which Is "to steer BPA through the competitiVe challenges It faces to 

successfully achieve Its fundamental legislative mandates .• , A Bonneville that Is 

more effective, more efficient and more responsive to Its customers and the 

citizens of the region will be a better Bonneville. It will be a Bonneville better able 

to fulfill the goals of the Northwest Power Act and Bonneville's other organic 

legislation. The Council believes that Bonneville IS sincere tn thiS aim. and many 

aspects of the Business Plan should move Bonneville tn those directions. 

Proposals tn the Business Plan alSo should contribute to reducing the "hassle 

factor" many experience tn doing business with Bonneville. For example, It Is a 

very positive step to organize marketing efforts along customer-segment lines and 

direct account executives to learn about and represent wlthtn Bonneville the 

problems factng lndivtdual customers. 

Much of the Business Plan IS aimed at Instituting the organizational 

structures, management objectives and accountabllltles and changes tn Internal 

culture that are necessary for a more effective, efficient and responsive 

organization. Bonneville should move ahead quickly to Implement these aspects 

of the Business Plan. However, there are other aspeciS that cause the Council 

some concern, such as certain aspects of the agency's proposed reinvention of 

conservation, certain aspects of the tiered-rates proposal and the treatment of 

fish and wildlife obligations. The Council believes these need further development 

before Implementation. and I will diScuss them tn more detaU later tn my 

testimony. 

1 Bonnevflle Power Admlntstratlon Drqft Strategtc Business Plan. June 1994. p . 32 

2 
22 

Major policy changes 

In attempting to respond to Bonneville's competitive challenges, the 

Business Plan proposes several key changes in the way Bonneville offers and 

prtces its products and services. Primary among these is tiered wholesale rates, 

unbundling of products and charging market prtces for some of those products. 

Tirrough these mechanisms, and others, Bonneville proposes to both increase 

revenues and cut costs. These changes are essential to Bonneville's effort to close 

the "revenue gap" -- the projected gap between planned revenue requirements 

and an assumed goal for rates. Tiered rates, for example, are a rationale for 

Bonneville moving to direct customer financing of conservation and thus reducing 

Bonneville's costs and borrowing requirements. Charging market prtces for some 

unbundled products is intended to raise more revenue than was possible when 

sold as part of a package. 

There are aspects of these changes that the Council supports, such as the 

economic efficiency signal Bonneville would send to its customers by adopting 

tiered rates. Tiered rates should provide a better economic signal to customers of 

the cost of new resources. They will reduce, but not eliminate, the lost margin 

expertenced by utilities as the result of investments in energy conservation.2 

Tiered rates will also subject Bonneville to the discipline of the competitive 

wholesale markets in their acquisition of new resources. Tiered rates should 

contrtbute to greater economic efficiency of the regional power system. This is 

why the Council's 1991 Power Plan called for Bonneville and its customers to 

investigate and implement wholesale rate designs if necessary to achieve the 

conservation goals of the plan, that give individual wholesale customers prtce 

signals based on avoided costs. A multi-tiered wholesale rate, with the last tier 

set at avoided cost. could be approprtate. 

Bonneville also would give its customers a clear view of the value of its 

service if some of its products are unbundled and ifBonneville charges market 

prtces for them. This also should result in greater economic efficiency in tl1e use 

of these products. From that standpoint, the Council supports these changes. 

However, if the goals of economic efficiency are to be met, it will be essential 

that Bonneville be consistent in its application of market prtnciples in prtcing its 

products. For example, the second tier must be prtced at the market level or it 

would not provide an accurate signal, and it would undercut the incentive for 

customer development of conservation. There are at least two ways in which the 

second tier might not be market-prtced. The first is that Bonneville would use the 

low cost of some of the federal base system resources to hold down the prtce of 

tier 2. The second could occur if, as we expect, new resources added to the 

second tier are more expensive than the resources already in that tier. If the 

costs of these resources are just averaged in with those of the resources already 

2 By "lost margin" we mean the dlfference between revenues lost and the power costs avoided. 

3 
23 

In the second tier, the resulting melded price would be less than the cost of new 

resources. Thus, tiered rates no longer would send the appropriate market 

signal. Both of these conditions should be avoided. 

Pricing of other products must follow the same principles. For example. 

unless the pricing of transmission services sends customers a signal about the 

Incremental costs associated With serving Incremental loads, customers will not 

be seeing the true benefits or costs of their decisions to implement or not 

implement conservation or other new resources. It will not be easy to implement 

Incremental pricing In transmission. However, if Bonneville is to be true to 

market principles, 1t must price transmission In way that sends a clear signal of 

the Incremental cost, whether It is wheeling Its own power or that of competitors. 

wm the policy changes be sufficient to fu1flll Bonneville's responslbWties? 

As noted above, the Business Plan proposes relying on market mechanisms 

to a large extent to achieve Its commercial and public purposes. While the 

Council supports many of these means from the standpoint of economic 

efficiency, there is reason to question whether they are adequate to achieve all of 

Bonneville's public purposes. In at least one Instance, conservation, the Business 

Plan proposes a mechanism to give assurances that those public purposes will be 

met. Unfortunately, It 1s not clear that the proposed mechanism is or can be 

sufficiently developed In the time frame of the Business Plan. In other areas, no 

backup mechanism is considered. The Council seriously questions whether 

Bonneville can move forward on all issues in the Business Plan at this time. 

Some, such as internal efficiency and orgaruzationallmprovements. should 

proceed Immediately. Others need more time for development. The Business 

Plan should recognize this fact and proVide place holders for these issues. Three 

of these are particularly Important to the Council. They are conservation 

reinvention: enVIronmental considerations of power resources and development of 

renewable resources: and fish and Wildlife reinvention. Although not actually a 

part of the Business Plan, we believe the government corporation legislation is In 

the same category. Here 1s a brief discussion of each: 

Conseryatlon Reinvention -- Conservation is the foremost area where the 

Council is concerned about the adequacy of the means proposed In the Business 

Plan. The existing system of Bonneville-funded, locally implemented conservation 

Is on track to meet Bonneville's share of the regional goal of 1,500 average 

megawatts by the beginning of the next decade. In 1993, this system delivered 

approximately 52 average megawatts at a cost to the utlllty system of 23 mills per 

kilowatt hour. This far exceeded Bonneville's target for the fiscal year of 39 

average megawatts, and It was nearly double the amount of conservation the 

agency acqUired the previous year. The life-cycle cost of this conservation was 

significantly less than the cost of new generating resources. 

Nonetheless, there are concerns about the current conservation system. 

For example, there are concerns about the impacts on Bonneville's rates, fixed 

4 
24 

costs and borroWing requtrements. 3 Many believe there are significant 

inefficiencies in Bonneville's administration of conservation. There are also 

perceptions of inequities in the distribution of conservation costs and benefits --

primarily that customers whose loads are not growing are contributing to the 

conservation of those whose loads are. As a consequence, Bonneville is proposing 

to ·reinvent" conservation delivery. 

The reinvented conservation proposed in the Business Plan consists of: 

• Tiered wholesale rates to encourage customer utillty funding of 

conservation: 

• Elimination of regional conservation funding to the utillties: 

• Offering capital to utillties that choose not to raise capital for conservation. 

That capital, interest and possibly a Bonneville service fee would be 

recovered through a Bonneville ·energy service charge· to the utillty: 

• Sale of demand-side management services by Bonneville to utillties and 

possibly others: and 

• Some level of regionally funded support for "market transformation 

ventures" -- activities intended to change the standard practice in a market 

for electricity-using facilities and equipment, thereby reducing the cost of 

efficiency improvements. 4 

There are several reasons why the Business Plan's model of reinvented 

conservation may not be successful in meeting the cost-effective conservation 

targets in the Council's plan. 

First. all else being equal, most of Bonneville's customer utilities will see 

greater rate impacts from conservation with the reinvented model than with the 

current model. This is largely because the reinvented model does not share the 

costs of conservation with all of Bonneville's customers as is currently the case. 

The rate increase for many utillties will be small-- 1 to 3 percent. Some utilities 

could see rate increases of as much as 5 to 6 percent under the reinvented 

conservation proposal. s In their concern about retail competition -- undoubtedly 

heightened by Bonneville's focus on competition -- some utillties may be reluctant 

to commit to greater rate impacts. There are mechanisms available to mitigate 

3 Bonneville's draft analysiS indicates that continued Bonneville funding of consetvatlon would 

add approximately 1.5 mills per kilowatt hour to Bonnevtlle's rates between 1996 and 2003. 4 An example would be activities llke manufacturer Incentives, that create a large market for 

efficient equipment. bring down Its cost and ultimately make It possible to establish or Improve 

energy efficiency standards for that equipment. Another would be training for an:hJtects and 

engineers· to promote energy-efficient design, construction and operation practices. Research 

and demonstration actltles are also Important to transforming markets. 5 Draft analysiS by Bonneville Power Administration. 

5 
25 

those Impacts, such as greater use of municipal financing for conservation and 

alternative Incentive structures. However, these mechanisms are also avallable 

under the current system of conservation financing. 

The second reason that the Business Plan's model of reinvented 

conservation acquisition may not be successful is that the tiered rate system will 

not provide a mechanism to give conservation credit for Its environmental benefits 

compared to conventional generation technologies. Unless Bonneville's potential 

wholesale competitors give consideration to environmental effects. Bonneville will 

be forced to price second-tier power at a rate that does not reflect environmental 

considerations. The Power Act's 10-percent credit for conservation finds no place 

In the tiered rate system. 

Third, unless Bonneville Incorporates Incremental pricing for transmission 

products, the benefits of avoided transmission Investment attributable to 

conservation will not be captured. 

Fourth, the reinvented model also assumes sJ.gnlflcant savings from utility 

adoption of tiered retail rates and resulting retail customer conservation and fuel 

sWitching. The Council believes this price response will be quite modest. 

Moreover, if utilities do have a greater concern about their retail rates, there 

seems to be little reason to believe they are Interested In sending a higher rate 

signal to their customers. 

Fifth, the reinvented model proposes using Bonneville's bonoWing authority 

to provide loans to utility customers for their Implementation of conservation. It 

may be Important to have such a source of capital avallable. It is not clear, 

however, that Bonneville has the legal authority to use Its bonowtng authority In 

that way and Its bonoWing authority is limited. 

Flnally, Bonneville proposes to selllts demand-side management services to 

utilities. It is unclear how successful Bonneville can or should be 1n this 

enterprise. By selling demand-side services, Bonneville would compete directly 

With private businesses that offer the same services. It is probably worth noting 

that energy service companies like these have not been particularly successful In 

the Paclflc Northwest. 

Conservation Reinvention Principles -- Reinventing conservation Is a challenging 

and possibly risky proposition. Clearly, the current system of acqulrlng 

conservation must be considered successful if Bonneville doubled Its acquisition 

from Fiscal Year 1992 to Fiscal Year 1993 and did so at extremely competitive 

costs. Moving away from this successful system should be done cautiously. To 

Bonneville's credit, It has consistently maintained Its commitment to achieving 

the Council's conservation goals. However, for many of the reasons noted above, 

there are many who have concerns about whether the reinvented conservation 

model Is adequate to meet the cost-effective conservation goals of the Power Act. 

6 
26 

For this reason, Bonneville included principles in the Business Plan 

intended to assure that the conservation would, in fact, be achieved. Those 

principles are: 

• Overall goal-- meeting the Council's regional target for all cost-effective 

conservation savings. 

• Strot.egies 

• Regionally supported market transformation activities. Programs and 

funding levels determined through a collaborative process. 

• Customer-funded efficiency programs consistent with: 

• An Integrated resource planning (IRP) commitment In power sales 

contracts. Integrated resource plans are to be developed by 

Bonneville's customers using Mexistlng IRP criteria confirmed by a 

consultative process: 

• A collaboratively developed mechanism to track and provide 

confidence In conservation accomplishments: and 

• A perlormance accountability mechanism to be developed 

collaboratively to reward good perlormance and/or penalize poor 

perlormance. 

• BPA demand-side products and services with: 

• Transition to reinvented conservation on mutually (Bonneville and 

customers) acceptable schedule and tenns: and 

• Bonneville commitment to a "mld-course correction" if necessary, for 

example, to take steps to ensure that the conservation goals are met. 

There are many positive aspects to these principles. Integrated resource 

planning is good business planning. Done well, Integrated resource planning 

should result In better resource decisions and should help utilities avoid or 

mitigate risks. This Is the r..;ason the Council is working to develop a utility-scale 

planning model. This would make It relatively easy for Individual utilities and 

utility consortia to use the data and analytical techniques the Council develops In 

its' planning process In doing their own Integrated resource plans. 

Similarly, tracking requirements are essential if utilities are to know 

whether they are spending their customers' dollars effectively. Accountability 

should be valued by all customers to assure that no one is attempting to secure 

short-run advantage to the detrtment of Its neighbors and the region's long-term 

interests. For example, some are concerned that one utility mlght forego 

7 
investment in conservation to secure a temporary rate advantage over Its 

neighbors. 

These integrated resource planning, tracking and accountability 

mechanisms will be successful, however, only to the extent that Bonneville's 

customers are willing to accept responsibility for the wise use of the region's 

federal resources along with the benefits of those resources. In addition, 

Bonneville must be willing to hold customers accountable when they fail to live 

up to that responsibility. Sharing in the benefits of the federal Columbia River 

Power System should also mean sharing in meeting the goals of the Northwest 

Power Act. 

S1mllarly, market transformation actlvities hold promise of delivering 

conservation resources at lower cost to the delivery system. However, these must 

be more than token efforts. If there are efficiencies to be gained from coordinated, 

centralized action, Bonneville and tts customers must be willing to commit to 

making them happen. And, if there 1s the possibility that a mid-course correction 

will be required, the region must be assured that there 1s a plan in place and the 

capability to carry 1t out exists. 

Bonneville and Its customers, the Councll and others. have been working 

hard to further develop the conservation reinvention principles in ways that are 

effective and not burdensome to those involved. At this point, however, there 1s 

not consensus. 'Ib1s Issue must be resolved before the Councll can fully support 

this part of the Business Plan. The Business Plan schedule must not be allowed 

to override resolution of these Issues. 

Alternattye Ways of Reinventing Conserva.Uon -- The Business Plan offers only one 

option for reinventing conservation. It may be a good option if the reinvention 

principles can be made to work. However, the Councll believes there are also 

other options that could achieve most of the same ends with perhaps greater 

certainty. Given the challenge and the risks of conservation reinvention, the 

region deserves a more thorough exploration of the options. One alternative that 

deserves analysts includes: 

• Continued regional funding of conservation at a sl.gnlficant level but with 

utilities paying directly a higher portion of the cost. This would reduce 

Bonneville's costs and borrowing requirements and reduce the perceived 

inequities in the distribution of conservation costs and benefits. 

• A cost-sharing formula that varies the customer's contribution as a 

function of load growth and the share of the customer's load served by 

Bonneville. Utilities with high load growth and/or partial reliance on 

Bonneville would support more of the conservation cost directly. Till.s 

would further reduce the perceived inequities. 

8 
28 

• Increased reliance on the utillties' municipal bonding capability to finance 

conservation with Bonnevtlle payment of the regional share of the debt 

service. Tills would reduce both the cost of conservation and the pressure 

on Bonnevtlle's borrowing. 

• Increased Oextbillty for utll1ty implementation. Many utll1ties can do an 

excellent Job of destgntng and operating programs for their service 

territories and may be able to be more cost -effective in their conservation 

deltvery. 

• A signtftcant focus on market transformation opportunities. Bonnevtlle can 

be the catalyst for securing low cost savings. 

• Vigorous efforts to reduce Bonnevtlle's overhead. This must be pursued 

with any alternative. 

Such a model would stgntftcantly reduce the rate impacts and the perceived 

inequities in the current conservation model. It also would reduce Bonnevtlle's 

share of the cost of conservation as well as the pressure on Bonnevtlle's fixed 

costs and borrowing authority. At the. same time, it would preserve much of the 

benefit of regionally shared costs of conservation development. It should be 

analyzed. 

Environmental Considerations and Renewa.ble Resource Deyelo.pment --

The Business Plan includes very ltttle regarding consideration of environmental 

costs and benefits and less on the development of renewable resources. These 

two Issues are linked because It Is essentlal to gtve renewable resources and 

conservation credit for their environmental benefits 1f they are to compete fairly 

with conventional generating alternatives. It Is worth noting that the Draft 

Environmental Impact Statement for the Business Plan concludes that the 

"market drtven" Bonneville has smaller environmental effects than the status 

quo. 6 This conclusion rests on assumptions about price-induced conservation 

and fuel switching. Bonnevtlle load loss and customer development of generating resources. These assumptions are clearly open to question. Bonnevtlle's 

approach to the envirorunent must be more than simply m1nlrnlzlng the rtsk that 

Bonnevtlle someday might face regulation of an envirorunentalimpact not 

regulated today. The Business Plan must address this Issue 1f 1t Is to be effective 

in carrytng out the goals of the Power Act. 

Ftsh and WlldUfe ReinvenUon -- Although not a topic of this heartng, It ts 

important that you know that there Is not consensus about the proposals for fish 

and wtldltfe reinvention contained in the Business Plan. As in the case of 

conservation reinvention, Bonnev1lle should move ahead with other portions of 

the Business Plan whtle working to resolve the issues associated with fish and 

wtldltfe reinvention. 

6 Bonneville Power Adm1niStration, Op Cit. pp 219-224. 

9 
29 

Government Corporation -- The question of the government corporation 

legislation was not addressed in the business plan. The Council clearly supports 

the goals of administrative efficiency that the legislation is intended to produce. 

At present, however. there is not consensus in the region regarding other aspects 

of this legislation. Bonneville should try to achieve the administrative efficiencies 

it can without legislation while working to achieve regional consensus about this 

legislation. 

Issues Not Developed in the Business Plan 

The Business Plan is relatively silent on a number of issues that are at least 

as critical to Bonneville's business success as conservation reinvention. These 

include the nature of Bonneville's business relationship with the Direct Service 

Industries. including the variable rate and the quality and value of the reserves 

provided by the DSis; the irrigation discount; and the costs of the Washington 

Public Power Supply System. The Business Plan proposes a formula for 

application of tiered rates to the DSis but provides no details. The question of 

irrigation rates is not raised at all, nor is the issue of oversight of the Washington 

Public Power Supply System. Because these issues are critical to Bonneville's 

business success, we believe the Business Plan should at least lay out a process 

through which they will be addressed. 

Distribution of Cost and Risk 

The proposals in the Business Plan will have signtflcant effects on the 

distribution of costs and risks between customers. Such distribution effects are 

typically not the Council's concern. The Council believes it is essential, however, 

that the region fully understand those effects. 

The primary distribution effect is from the introduction of tiered rates. 

Tiered rates largely abandon the concept of regional sharing in the cost and risk 

of new resource development. Instead, tiered rates imply that costs and risks are 

born entirely by those requiring new resources. The beneficiaries of this policy 

change are primarily those whose loads are not growing. This includes some utilities and the direct service industries. There has been one estimate that the 

cost of that shift to the preference customers is as much as $200 million annually 

by the year 2004.1 

As noted earlier, principles of economic efficiency support a move in this 

direction. At the same time, however. this represents a signtftcant departure from 

the principles that have guided regional development in the past. One can argue 

that today's new resources-- natural gas-fired combustion turbines-- are much 

less costly and rtsky than those contemplated when the concept of regional 

sharing of costs and risks was adopted. They are not risk-free, however. If the 

7 Association of Public Agency Customers. April 20. 1994. 

10 

84-374 0 - 94 - 2 
30 

region is going to move away from this principle, tt should do so consciously. We 

do not believe the Business Plan is as clear about this change as tt needs to be. 

Unbundling Bonnevtlle's products and charging market prices for some of 

them will also affect distribution of costs among customers. Perhaps the prtmaiy 

example is the unbundling and market pricing of power shaping services. Because most customer loads are not constant. most require shaping services to 

match resources to loads. Because Bonnevtlle controls much of the region's 

hydropower generating capacity, Bonnevtlle is in the best position to provide 

shaping services. Shaping services are currently part of the bundled Priority Firm 

service. In the proposed system. those havtng greater need for shaping services 

would pay more. Those wtth relatively Oat loads would pay less. 

Moves toward unbundling and charging market prices for products like 

shaping services are consistent wtth principles of economic efficiency. However. 

Bonnevtlle has not indicated what lt would charge for these services or how lt 

would set rates for the direct service industries, whose loads are essent1ally Oat. 

in relation to the rates charged to the industrtal customers ofBonnevtlle's public 

utllity customers. As a result. 1t is lmposstble to calculate the distribution effects 

of these changes. Without more information from Bonnevtlle, the regton is not in 

position to support or reject this element of the Business Plan. 

Finally, we should be clear about the intergenerational effects of the 

changes being proposed in the Business Plan. The Business Plan portrays a shift 

to almost total reliance on market mechanisms. Market mechanisms do some 

things extremely well. They requtre efficient operation and spur Innovation in 

meeting customer needs. These are positive elements, and the regton should 

make appropriate use of market mechanisms to foster efficiency and Innovation. 

Markets typically do not. however, take a long-term vtew. Markets typically do 

not account for environmental Impacts unless forced by regulation or tax policies. 

The Power Act, in contrast, intended that the region invest for the future as 

well as for the present. The Act intended that we consider the environment in 

more than purely a business risk-management sense. The Business Plan, as 

currently constructed, may well have the effect of shlfting costs to future 

generations -- avoiding near-term investment in conservation and renewables 

while incurring future fuel costs. It may also have the effect of shlfting costs to 

the environment. The Council believes these effects need to be explored further 

before the Business Plan is tlnalized. Bonnevtlle is arguably in the best position 

of any utllity in the Northwest to be competitive in the short run and to make the 

necessary investments -- in conservation, renewables, the transmission system. 

information systems and people -- that will insure that lt ls competitive in the 

long run as well. 

11 
31 

BoDDeville's Competitiveness - Is the Glass Half Empty or More than Half 

Full? 

Mr. Chairman, I will conclude by addressing a subject I mentioned at the 

beginn1ng of my testimony-- the question of Bonneville's competitiveness. 

Bonneville's concern about competitiveness motivates most of the changes 

proposed in the Business Plan. I want to emphasize that the Council believes 

Bonneville is subject to competition at the wholesale level. The Council further 

believes that Bonneville needs to recognize these competitive pressures and 

respond to them. Some signillcant changes in the way Bonneville does business 

are necessary. 

The Council also recognizes the difficulty of leveraging change in a large 

organization in the face of internal and external inertia and outright opposition. 

The degree of support for change seems to vary in proportion to the size of the 

perceived threat. For Bonneville, the threat is competition. Unfortunately, the 

Council believes that Bonneville may have overstated this competitive threat in 

the Interest of bolstering arguments in favor of changes called for in the Business 

Plan. 

The Council believes that Bonneville's glass is not half-empty and draining 

fast. as the introduction to the Business Plan would have us believe. Rather, the 

Council thinks Bonneville's glass is more than half-full. Bonneville's competitive 

advantage has been eroded and it does face signillcant risks. It is, however, still 

in a good competitive position, and careful management can maintain and bulld 

on that position. 

The Council is somewhat concerned that Bonneville may have been so 

successful at telling the bad news in its Business Plan that It may undercut its 

competitive position -- in essence. creating a self-fulfllling prophecy of 

uncompetitiveness. Candor with customers and the public can help Bonneville. 

Overreaction can hurt. 

I will briefly discuss three key issues that Bonneville raises as evidence of 

Its eroding competitive position. These are competition from natural gas-fired 

turbines, certain risks and the possibility ofload losses. 

Competition from Gas-fired Combustion Turbines -- Bonneville has 

compared the cost of Its power to that from a natural gas-fired combustion 

turbine to indicate how perilous Its competitive position has become. There Is no 

denying that increases in Bonneville's rates and continued low gas prices have 

seriously eroded the agency's competitive position. Bonneville's rate increases are 

primarily the legacy of ill-advised investments in nuclear power in the 1970s. 

Bonneville continues to finance nuclear plants that were never completed. Those 

are sunk costs that cannot be avoided. They are, however, perhaps illustrative of 

the need for caution when you think you know what the future will be like. 

12 
32 

The other side of the equation has been driven by low gas prices and 

Improved combustion turbine technology. To assess how much erosion has 

occurred, the Council staff analyzed public information on bids received by 

Snohomish County Public Utllity District (Everett Washington) in response to its 

recent request for proposals. In this analysis, the costs of proposed gas-fired 

combined cycle combustion turbine projects were adjusted for consistency and 

compared with projections of Bonneville's rates from the 1993 rate case. 

For this analysis, staff considered 20-year bid energy price streams for 15 

proposals. All but one would be placed in seiVice in 1998. The selection of bids 

was limited to plants proposed to be financed using municipal bonding. This type 

of financing is available to many of Bonneville's customers and would likely 

provide the least costly financing for this type of project. 

Bonneville Priority Firm (PF) rates currently provide a full seiVtce power 

product, delivered to the customer utllity. To fairly compare bid prices with 

forecast Bonneville PF rates. the bid prices were adjusted to account for 

interconnection, shaping. capacity and other seiVices included in the PF rate. 

Because the market prices for these seiVices are not available at present 

Bonneville system cost adjustments from the 1993 B1lling Credits program were 

used to estimate the shaping and capacity prices that would be incurred by a 

utllity seeking to integrate power from a gas turbine into its system. Depending 

on what Bonneville eventually charges for these seiVices, the results might be 

somewhat different. The sample of bids analyzed was limited to plants that would 

be located within the utllity's seiVice territory or that clearly included 

transmission costs in the bid price. Representative substation interconnection 

costs were added to each bid price. In total. these adjustments added an average 

of approximately 7 m1l1s per kilowatt-hour to the 20 year levelized nominal bid 

prtces. 

Some of the Snohomish bids appear not be based on actual natural gas 

prices. However. several bids, falling within the average to high price range, 

appear to be credible proposals. These bids have levelized nominal prices that are 

16 to 34 percent higher than the November 1993 medium forecast of Bonneville's 

PF rate. The adjusted first year (1998) prices of the proposed projects are from 6 

to 28 percent higher than the 1998 medium forecast PF rate. 

The low end of the credible proposals beat Bonneville's highest rate 

forecast, but not until about the year 2008. Bonneville's high rate forecast 

includes a number of very substantial risk assumptions: 

• A $200 m1llion increase in costs due to risks, which are not specified; 

• Increased costs for new resources; 

• Medium-high load growth; and 

• A loss of 250 additional megawatts of firm energy lost as the result of 

fish mitigation requirements. 

13 
33 

Any of Bonneville's competitors will face its own set of risks as well. 

Snohomish did receive bids that might pose a competitive threat today. 

However, we cannot assess the quality of those bids with the information 

available -- what kinds of gas supply terms these bids contain or the quality of 

the gas supply contracts. Depending on what happens in the gas market, they 

might turn out to be very good deals or very bad ones. In general, staff believes 

this demonstrates that Bonneville remains a very competitive wholesale supplier. 

While clearly the gap has narrowed, Bonneville is likely to still be the best deal in 

town. 

Bonneville Risks -- Bonneville is uniquely subject to a number of risks that 

could drive up its rates. One is the risk of unilateral changes in the terms of 

Bonneville's debt repayment to the U.S. Treasury. Legislation to contain that risk 

recently has been introduced by Congressman DeFazio and Senator Hatfield. The 

Council supports that legislation in concept. 

The other major risk facing Bonneville is the potential cost of salmon 

recovery measures. There is the very real potential of additional salmon recovery 

costs, and the Council by no means wishes to understate those risks. The 

Council is committed to fulftlllng the fish and wildlife obligations of the Power Act 

and the Endangered Species Act as cost-effectively as possible. 

We would take issue with the way in which Bonneville portrays fish and 

wildlife costs. On page 15, the Business Plan presents a plot of fish and wildlife 

costs. including foregone power revenues and replacement power costs. e The 

chart appears to portray exponential growth in the costs but at no point suggests 

that a signiftcant part of the costs in 1993 and 1994is related to drought 

conditions and would not be experienced in normal or wet years. Portraying 

these costs in this way has the effect of falsely conftrming the worst fears of 

Bonneville's customers. Bonneville's risks of increased fish and wildlife costs are 

real, but the risk of falling to rebuild declining populations of fish and wildlife in 

the Columbia Basin are as great or greater. It is unlikely that costs would 

increase exponentially year to year. It is incumbent upon Bonneville and the 

Council to provide the customers with realistic estimates of the bounds on future 

fish and wild-life related rate impacts. 

We think it is important to take a broad view in salmon rebuilding efforts in 

the Columbia River Basin and not focus narrowly on stocks that are being 

prot~ted under the Endangered Species Act. Yet the region's response to fish 

and wildlife problems sometime seem to be driven by that one law. The ESA 

imposes a recovery planning process that is something like emergency surgery. 

To attack a problem that is so wide-ranging, the region needs a broad approach -- a holistic health care plan rather than emergency surgery to aid specific stocks. 

8 Bonneville Power Admlnlstration. Op Cit. 

14 
34 

Bonneville's fish and wildlife activtties respond to at least four important 

legal mandates. The first is the Northwest Power Act. which requires Bonneville 

to protect, mitigate and enhance fish and wildlife of the Columbia River Basin 

impacted by hydroelectric dams -- all fish and wildlife, not just those being 

protected under the Endangered Species Act. The second, of course. is the 

Endangered Species Act. The third is our nation's responsibility to Columbia 

Basin Indian tribes under the treaties of 1855. The fourth is our nation's 

obligations to rebuild naturally spawning salmon runs under the U.S./Canada 

Pacific Salmon Treaty of 1985. 

Efforts on all these fronts can and should proceed simultaneously and in a 

coordinated way. None of these mandates is less important than any other. They 

all aim to protect and enhance fish and wildlife populations in the Columbia River 

Basin, albeit to different levels. The Council and Bonneville must discharge these 

obligations: the Council in developing the region's fish and wildlife program; and 

Bonneville in implementing the actions assigned in a full and timely fashion. 

Probabilitv of Loss of Load -- It is important to distinguish between losing 

existing load and losing load growth. With tiered rates, Bonneville is putting itself 

in a competitive market for load growth. There is every reason to expect that 

some or many customers may choose to meet all or part of their load growth from 

sources other than Bonneville. This should not pose a particular problem to 

Bonneville. 

There are· several scenarios in which Bonneville could lose existing load. A 

customer, whether utility or industry, may choose to develop or purchase 

resources to offset its Bonneville purchases. A direct servtce industry or a large 

customer of one of Bonneville's utility customers may go out of business or leave 

the region. Or, retail competition may result in retail customers of Bonneville 

losing load to a competitor -- other electricity suppliers or suppliers of other fuels. 

While all of these are possible or even likely to some degree, it is highly unlikely 

that the cumulative loss of load would reach anything like Mdeath spiral" 

proportions. The first tier of a tiered rate system will be protected from some of 

the costs that drive up rates. That should help maintain Bonneville's 

competitiveness for a large portion of its existing load. Counteracting the effects 

of loss of load is the over 200 average megawatts per year of load growth the 

region is expeliencing as well as a competitive but vtgorous West Coast market for 

power. 

Some Bonneville customers will choose to acquire resources to displace 

power from Bonneville. In the past. some utilities chose to limit their dependence 

on Bonneville when the economics of doing so were much less favorable than they 

are today. As the earlier analysis shows, the Council thinks that, particularly 

with tiered rates, the economics will continue to favor serving existing load with 

purchases from Bonneville, we expect some utilities or DSis will choose to 

displace some of their Bonneville load. We do not expect rampant defection. 

15 
35 

Similarly, it is likely that some of Bonneville's direct service customers and 

large industries that buy power from Bonneville customer utilities may cease or 

significantly decrease operations, for a variety of reasons. These industries are 

engaged in competitive world markets. and their margins are slim. Clearly, 

Bonneville and its customers should try to maintain these loads as long as it is 

economically advantageous to do so. But it may not be possible or even desirable 

to maintain all those loads no matter what. 

Retail wheeling might have an impact on Bonneville's load. In theory. some 

Bonneville customer utilities could lose load to retail competitors if their 

distribution lines were opened to all. However, we will have the opportunity to 

see whether this happens first in California and elsewhere in nation where retail 

power rates are significantly above the cost of new resources. It is not at all clear 

that California and others will act affirmatively on retail wheeling. Conditions 

favoring retail wheeling do not exist currently in most of the Northwest. Our 

region's embedded costs are low. There will be some niches where retail 

competition will be present, most likely in the form of competition from other 

Northwest suppliers. But it will be niches not whole markets. Retail wheeling in 

the Northwest would require affirmative action by state legislatures, regulatory 

commissions or local utility commissions. Given that it will be hard to find a 

significant overall economic benefit in this region from retail wheeling, the 

Council does not expect a large impact. 9 

With respect to competition from other fuels. particularly natural gas, most 

of that competition is in the residential sector. A benefit of tiered wholesale rates 

is that Bonneville's customers will see more directly the costs of trying to retain 

loads that would be more economically served by other fuels. Utilities can e.'qlect 

to see continued space and water heating load lost to natural gas. However, this 

will lead to greater fuel efficiency overall and in most instances will be more than 

offset by other load growth. 

Overall, the Council sees the possibility of possible of load losses totaling as 

much as several hundred megawatts. We believe wholesale load losses in the 

thousands of megawatts are unlikely. If there is load loss in reasonable amounts, 

the Council believes Bonneville could sell the power at rates very similar to those 

it would have charged prior to the load loss. Markets for this power are both 

inside and outside the region. If callback provisions relating to public and 

regional preference prevent Bonneville from entering into contract sales that 

recover adequate revenues, congressional action should be considered to modifY 

those requirements. This would be in the best interest of customers inside and 

outside the region. 

9 For a critique of the savings associated With retail competition see. Kahn. Alfred E .. "Lets Play 

Fair With Utility Rates." Wall Street Journal. July_, 1994. 

16 
36 

Conclusion 

In conclusion, the Council finds much to support in the Business Plan. We 

applaud the emphasis on greater efficiency, effectiveness and responsiveness to 

customers and other constituencies. Similarly, in principle the Council supports 

aspects of the move toward greater use of market mechanisms -- tiered rates. 

unbundled products and market pricing. These moves. 1f applied consistently. 

should lead to greater econom1c efficiency. 

However, the Council is concerned that. for a number of reasons, these 

market mechanisms will not be sufficient to insure the development of all costeffective conservation. Conservation reinvention principles outlined in the 

Business Plan could provide the necessary assurances, 1f they can be 

satisfactorily implemented. At present there remain slgntficant disagreements 

among the various parties. These disagreements must be satisfactorily resolved 

before the Council can support this aspect of the Business Plan. The same can 

be said about fish and wildltfe reinvention. 

The Council is also concerned that environmental considerations and 

Bonneville's role in fostering the development of renewable resources are not 

adequately dealt with in the Business Plan. The issues here Ue largely outside 

market considerations and must be dealt with in other ways. 

The Council notes that there are signtficant distribution issues inherent in 

the proposals in the Business Plan. Tiered rates, while positive from the 

standpoint of econom1c efficiency, result in a signtficant departure from the 

concept of regional sharing of costs and risks of growth. The net effect is that 

customers with growing loads bear all the costs of that growth. Similarly, 

unbundled products and market pricing for some of those products will result in 

a redistribution of costs from the current system. However. without knowledge of 

what Bonneville will charge for these products and precisely how the products 

will be defined, it is not possible to assess the magnitude of the redistribution. 

More fundamentally, the increased reliance on market mechanisms 

described in the Business Plan has the potential for transfers of costs and risks to 

future generations and to the environment. TI1is is a result of the generally shortterm perspective of competitive markets and the fact that environmental 

considerations are typically external to the market. In part. the Power Act was 

enacted to overcome such market flaws. The Business Plan needs to tell the 

region how Bonneville intends to deal with the potential for such market flaws in 

the future. 

The Business ?Ian is relatively silent on a number of issues that are at least 

as critical to Bonneville's business success as conservation reinvention. These 

include the nature of Bonneville's business relationship with the Direct Service 

Industries, including the variable rate and the quality and value of the reserves 

provided by the DSls; the irrigation discount; and the costs of the Washington 
37 

Public Power Supply System. Because these issues are critical to Bonneville's 

business construct, we believe the Business Plan should at least lay out a process 

through which they will be addressed. 

Finally, With respect to Bonneville's competitive position. the Council 

believes Bonneville faces competitive threats, but that these threats can be 

managed. Overall, while Bonneville's competitive position certainly has worsened. 

lt is still strong. Bonneville will experience some load loss but is unlikely to 

experience load losses that would lead to a death spiral. If the call-back 

provisions of public and regional preference prove to be significant Impediments 

to marketing any surplus power at competitive rates, congressional action to 

modifY those provisions should be considered. 

Thank you again for the opportunity to testifY here today. I would be happy 

to answer any questions. 

Q:\DW\WW\RSTR\DBPDI"ZZ'5.DOC 

18 
38 

Mr. DEFAZIO. I thank the gentleman for staying within his allotted time. We are going to do an agreement with Representative 

Smith. We are going to take 10-minute question rounds, so if you 

can give us the light on 10 minutes, since there is only the two of 

us at the moment. 

There is obviously a question, which I couldn't have submitted to 

you in writing, which would be to respond to BPA's new schedule, 

and I guess generally and if we can keep your answers as brief as 

possible, sort of respond to it generally in terms of addressing some 

of the concerns you have raised. Secondly, do you believe in particular, you know, when they are 

now talking about having the contracts negotiated by the first of 

the year before we enter into the rate-making, my understanding 

is there are two cases which have been brought previously against 

BPA in terms of contracts where it was found that an EIS was necessary. Do you think an EIS would be necessary, and few think it 

would be necessary, do you think that the so-called EIS that accompanied the business plan would be adequate or could be modified to meet those requirements? 

Mr. DUNCAN. Mr. Chairman, I am going to pass a little bit on 

the question of the EIS, just taking these in reverse order. But I 

would be happy to have our general counsel review that issue and 

give you a response back. 

Mr. DEFAZIO. I would appreciate that. 

Mr. DUNCAN. I certainly expect that if there are significant 

changes that are still to be made in the business plan and the 

schedule permits those changes, that an EIS has to be comprehensive enough to include those, and there are still substantial 

uncompleted portions of this business plan in our estimation. We 

have some aspirations for completing some of that unfinished business, and the Bonneville's proposed extended review period may 

allow us some additional margin of time for doing that, particularly 

the discussions on conservation reinvention which we participated 

in intensely over the summer still have a ways to go, but it is not 

impossible for those to be concluded satisfactorily within the schedule that Jack described today. And if that happened, then we would 

hope that that agreement, and those understandings, could be reflected in the business plan and in the EIS, but we are not there 

yet. 

Mr. DEFAZIO. Okay. 

Mr. DUNCAN. We would also, I think, appreciate the additional 

time for public review. We are trying to squeeze our oversight responsibilities over the business plan in with a major, main-stem 

rulemaking and a new power plan, and we are, frankly, having difficulty making those time ends meet. So this is going to be of assistance to us, too. Mr. DEFAZIO. Was the time line on the new plan from the council? 

Mr. DUNCAN. The power plan will be adopted sometime next 

year. Mr. DEFAZIO. Okay. In your testimony, page 5, the bottom of the 

page you refer to the reinvented model of conservation and talk 

about the fact that since we would no longer be sharing conservation costs among all customers, that there would be a rate increase 
39 

for some. You discuss a small rate increase, one at 3 percent and 

some utilities could see rate increases at 5 to 6 percent under the 

reinvented conservation proposal. You refer to a draft analysis by 

the BPA. They didn't see fit to provide that to me or to the committee or to make us aware of that despite repeated contacts. So perhaps you could-is that a 5 to 6 percent retail or wholesale rate 

increase? 

Mr. DUNCAN. That would have been a-the analysis led to aretail rate impact. That is the rate impact that affects those retail 

utilities competitiveness, and so the analysis was done on the basis 

of retail impacts. 

Mr. DEFAZIO. Okay. Do you think it is a-I mean do you think 

the analysis is adequate? Do you think the impact might be greater, or do you have any way of commenting-it was a draft analysis, 

I guess? 

Mr. DUNCAN. Yes. It is a first cut-well, it is more than a first 

cut, but it is certainly far from complete, because a lot of pieces of 

the business plan and of conservation reinvention and the allocation of distribution of cost and benefits is incomplete. So it is an 

interim indication. 

But what it suggests is that in order to accomplish the kind of 

conservation that the power plan envisions, some utilities under 

the decentralized model that Bonneville is describing are going to 

be dealing with retail rate increases, and that is not a reason that 

they will not do conservation, but it certainly will be a disincentive 

that is going to be weighed in the process. The more retail competitiveness pressure they feel, the more visible that rate impact is 

going to be. We have to weigh that. 

Mr. DEFAZIO. I understand that. And particularly if we are looking at retail. 

Mr. DUNCAN. Yes. 

Mr. DEFAZIO. Retail tiered rates, which BPA seems to assume in 

its analysis. We had a very unfortunate experience with that in 

Springfield in 1982, in fact. We had riots in the streets or a demonstration at least and burning of electric bills. But let's go beyond 

that. 

Also, you are saying here there is no 10 percent credit for conservation. Well, before I get to that, one thing that has concerned 

me all along, and a question I put to BPA that has never been satisfactorily answered, is if we send this message through the tiering 

down to the individual utilities and if the rate impact would be in 

this 5 to 6 percent range, and if the threat to BPA is that there 

is going to be all this wholesale power out there basically unlimited, because of it being provided by new producers, independent 

power producers with long-term, stable extraordinarily cheap contracts, wouldn't my option as a local utility be to say, hey, why do 

I want to mess around with this conservation stuff and induce a 

rate increase when I can go out and get this really spiffy firm, 

cheap IPP power for less? 

Isn't that a concern? BPA tells me they will control that through 

the transmission system; on the other hand, they tell me that they 

are losing control of the transmission system. 

Mr. DuNCAN. I don't think the transmission system is going to 

be an element of control, a tool of control in this case. I guess if 
40 

I can step back from your question a little bit, Mr. Chairman, it 

is my perspective, and this is from spending 10 years on the private side in the utility business, as well as my time on the council, 

that in this competitive marketplace, utilities are going to have to 

figure out how to compete, not just on the basis of a kilowatt hour, 

because a kilowatt hour is a pretty undifferentiated product. Anyone can sell you one. 

And if that is all you are selling, then you are going to compete 

just on the basis of the cost of it, and some utilities are going to 

find it very difficult, especially smaller ones, to compete in that respect. Utilities which are smart about positioning themselves for a 

competitive retail marketplace are going to have to think about 

ways to add value to that kilowatt hour, and in only a limited number of ways I guess that I can see right now. This is reliability, that 

that is kind of a negative value added. It is only when that doesn't 

appear that that becomes a significant marketplace factor and you 

lose on it. 

What is a positive, highly visible marketplace value added factor 

is if you can help your customer use the power more efficiently. 

And it is my belief that utilities which are going to compete successfully are ones that do figure out how to add that value to their 

kilowatt hour that they sell to their customer. 

The problem is that near term there is an enormous amount of 

psychology that says, no, we just have to compete on rates. And the 

concern I think that the council broadly has is the potential for sacrificing long-term competitiveness, which is what we will evolve to 

with utilities competing on the basis of service and value added, 

not just rates; sacrificing that for short-term competitiveness, 

where they may well be at a disadvantage unless they start cutting 

costs which are front loaded, capital-intensive. What are those? 

Well, those are conservation and renewable technologies. And 

they are also investments in environmental protection, investments 

that don't pay off until substantially down the road. So the concern 

is that the long-range competitiveness of the region broadly, the 

economic viability of the region, and the competitiveness of individual utilities is going to be adversely affected by this emphasis on 

being short-term rate competitive. 

Mr. DEFAZIO. Okay. And certainly if we are looking at the free 

market which many espouse here, there are other things that are 

going to come into effect now. I mean in some cases you can build 

customer loyalty for your local utility. I mean all of the things that 

play into private market. 

Not everybody has rushed to one of these new alternate phone 

providers because many say they know AT&T or they know this or 

that, they will stick with it, even if there is a marginal cost saving. 

I mean there are going to be a whole host of factors. BPA does recognize that in terms of their customer service reps for the utilities 

and then obviously utilities are going to have to somehow recognize 

that more with their individual customers, if we ever get to retail 

wheeling. 

We only have a minute left in this round, so I will try and phrase 

a brief question that you can answer briefly. 
41 

Well, why don't I-at this point I am going to save until the next 

round. I am going to defer now to Congressman Smith for his 

round and then I will get back to you. 

Mr. SMITH. Good morning, Mr. Duncan. How is your daddy? 

Mr. DUNCAN. Pretty good, what we see of him. 

Mr. SMITH. Good. Slip him the grip for me, will you? 

Mr. DUNCAN. I will. 

Mr. SMITH. Thank you. I understand you have been a proponent 

of drawdowns, even though the core draft system's configuration 

study says there is no biological benefit to drawing down these reservoirs unless you draw them all the way down to the mud at a 

cost of $5 billion. It is my understanding that the Power Council 

paid Hersa Engineering to shadow the Corps' work; they came up 

with the same findings. How can you continue to push this plan on 

the face of the evidence that it does salmon no good biologically? 

Mr. DUNCAN. Congressman, to be fair, I think you would also 

have to characterize me as a proponent of transportation, since the 

language in the Council's rule, which I wrote substantial portions 

of, said that there are a number of tools we have to reserve for 

salmon recovery. One is drawdown, another is transportation, a 

third I would add would be spill, and that those ought to be analyzed technically and objectively and not as, you know, ideological 

issues that you support or oppose. 

So as far as I am concerned, all of those measures are still on 

the table; they continue to be analyzed. We have also had reported-we have also had a recent report from National Marine 

Fisheries that raises some major questions about the efficacy of 

transportation, and the Council is going to do its own analysis on 

all of those measures in our current main-stem rulemaking. The Corps' analysis, in particular, relies heavily on their com- puted benefits of transporting fish in barges to argue that there is 

no biological benefit to allowing the fish to go down the river 

through a drawdown procedure. I think we have some serious questions about the accuracy of those assumptions of transportation 

benefits for fish, which the HARS report incidentally also raised 

and supported. 

So I wish there were an easy answer to your question that said 

drawdown is good or drawdown is bad. I think even the Corps will 

acknowledge, as they did when I asked them about it, that their 

conclusion with respect to biological benefits was based on their assumptions about transportation benefits, and if you call those into 

question, then you get a different conclusion from their analysis. 

Mr. SMITH. So you want to continue to use drawdown as one of 

the alternatives to work on as well as spill and conservation, even 

though you have two authorities that say d:rawdown doesn't work? 

Mr. DUNCAN. Well, let me clarify, Congressman. What we are 

going to do is to continue to have those as alternatives in our rulemaking, and the Council will conclude, I expect, by November or 

December of this year, you know, which of those or which combination of those, and which configuration of them, you know, ought to 

be in the Council's salmon recovery plan. So we have not specified 

that, for example, lower granite should be drawn down and it 

should be drawn down to thus and such a level. That is on the 

table and it is open for discussion in the Council's rulemaking. 
42 

Mr. SMITH. Well, I am not going to ask about the spill experience, because that was a catastrophe, I understand. So maybe you 

are back to your only one left, transportation, which you support, 

I hear. 

Let me ask you about, in your testimony I couldn't determine 

your position on the variable rate and the irrigation discount. What 

is your position? 

Mr. DUNCAN. Congressman, the Council hasn't specifically considered those and taken a Council position, so I have to differentiate between a Council position and my answer to your question. 

I have been a supporter-supporter is not the right word, but I 

have argued that the variable rate made economic sense when Bonneville and the direct service industrial customers negotiated it and 

agreed to it in the 1980s, and I still feel like that was a correct decision and one that was on balance good for the region. 

Mr. SMITH. In 1980? 

Mr. DUNCAN. In the 1980s, that is correct. That was a time in 

which we had a substantial surplus of power in the region, and this 

was a reasonable way to make sure that we could continue to use 

that and have a means of amortizing the cost. We don't have that 

surplus in the region any more, and I have considerable difficulty 

in justifying continuing that variable rate in the 1990s. But it 

made sense at the time. 

Mr. SMITH. You mean if you don't continue the variable rate, 

then you are going to put somebody out of business, so we are 

going to have more energy? 

Mr. DUNCAN. No, I am not proposing putting anybody out of 

business. What I am proposing to do actually is to, what I propose 

to do would be to let the market work with respect to the DSI's 

purchasing power from Bonneville, and with respect to the region 

purchasing interruptible benefits and system flexibility from the 

DSis. If it turns out we can work an arrangement where both the 

region and the DSis benefit from new contracts, that is what we 

ought to execute. 

If it turns out that we can, for example, buy reserves or flexibility less expensively somewhere else, then I see no reason for paying more for that flexibility and those reserves by buying them 

from the DSis. So my proposition would be to let the DSis, the 

other customers of Bonneville and other parties, compete to provide 

those kinds of benefits to the region. 

Mr. SMITH. What about the irrigation discount? 

Mr. DUNCAN. I think that ought to be on the table, as well. 

Mr. SMITH. In other words, you, in both of these situations, you 

want to change what has been historically the case since the agreement in 1980? 

Mr. DUNCAN. Yes. 

Mr. SMITH. And the reason is because we don't have enoughwe don't have a surplus of energy; is that the reason? 

Mr. DUNCAN. That is the beginning of the reason. The other part 

of the reason is that we are in a much more competitive marketplace, and customers of Bonneville, you know, by executing special 

deals, can thereby render Bonneville less competitive in the marketplace. 
43 

Mr. SMITH. I asked Mr. Hardy about these issues during our last 

hearing, and I want to reiterate for the record his answers. I was 

asking him about what the impact was with respect to irrigation 

discounting, and his answer was about half of 1 percent. 

Then on the question of the variable rate, I asked him if they 

had lost any money, and I am reading from his quote to me. He 

said, quote, "I guess the point I would make, Congressman Smith, 

is that in five or six years, since the variable rate was initiated, 

we have about broken even." 

Then he went on to say that when aluminum prices were high, 

they received more money, $1 per pound, and basically we have 

lost that. The aluminum price has plunged and he says we are 

about even. However, quote, the rate has probably kept on line 

some plants that otherwise would have gone off line. In that sense, 

we are probably in a net sense ahead for having instituted the rate 

and the quote. 

Do you have any concern about aluminum plants going off line? 

Mr. DUNCAN. I do have some concern about aluminum plants 

going off line, particularly if they went off line precipitously and 

left us with a big chunk of power, we would then have to sell at 

dumb prices, yes, absolutely. And I find nothing to disagree with 

in Mr. Hardy's statement about the variable rate, retrospectively. 

Mr. SMITH. And the question of impact from the irrigation rate, 

one-half of 1 percent probably is going to change the world in your 

view? 

Mr. DUNCAN. I am reminded of Senator Dirkson's comment about 

100 million here and 100 million there and pretty soon it adds up. Mr. SMITH. I never thought you would ever mention that. Mr. DUNCAN. I am not above a mercenary comment. 

Mr. SMITH. Well, let me ask you about what you think-do you 

believe that DSis are subsidized? 

Mr. DUNCAN. No. !-well, I think that gets back to my answer 

about the variable rate. A lot of people will point to that and call 

that a subsidy for the DSis. I don't regard it as that. I regarded 

it at the time and do still as a reasonable business deal between 

a willing buyer and a willing seller. 

Mr. SMITH. Thank you. 

Mr. DEFAZIO. Okay. I thank the gentleman. We are being so good 

here about staying within our time. Mr. SMITH. Yes. I was on yellow. 

Mr. DEFAZIO. Yes. That is great. Unusual in a congressional 

hearing. Since we are in this area, let me just-! am a little puzzled by something, which is the 7(c)(2) process that BPA goes 

through, and I am not sure whether you are going to be able to totally explain it or not; Jack certainly can, he is an expert on it. 

Mr. DUNCAN. He probably has a chart. 

Mr. DEFAZIO. But you know, just from the last rate case docu- ment, they come up with what they say is a cost of service total 

for the aluminum companies, and they say it is 1.324414 million. 

No, those are thousands. Even in Washington we have trouble with 

numbers that big. And then after we go through all of the exercise 

and the adjustments, we come out with a 7(c)(2) delta or that is 

a theoretical loss of $357,999,000. 
44 

Now, I guess I don't know what that all means, because if-why 

BPA goes through this exercise, why we come up with a number 

and we say that this is the division between cost of service and revenues received. You referred to or alluded to the proprietary study, 

the secret study that was done that shows the net benefit, which 

I assume included some of the assumptions about aluminum plants 

going off line, which I am not allowed to see, no one in the public 

is allowed to see, no one except the aluminum companies and BPA 

is allowed to see; I assume the Council has not been privy to that 

study; is that correct? 

Mr. DUNCAN. I haven't been privy to that study, I am not aware 

that our staff has. 

Mr. DEFAZIO. That was a two-year total, I am sorry, on the 

7(c)(2). So some of the staff has seen the proprietary study? 

Mr. DUNCAN. I don't know. I am unaware of it. Mr. DEFAZIO. Because it is hard t~we will hear it referred to 

in subsequent testimony; it is just difficult for me to have a group 

representing strongly their own interests and their own profits 

come in and say to me we have a study that shows that we are 

a net benefit to the region and to have BPA who has always had 

a very close relationship with a number of companies come in and 

say we have a study that shows a net benefit to the region, but you 

can't see it. It is hard for a public policymaker. 

Mr. DUNCAN. Again, my way of testing that would be to allow the 

market to test it by seeing whether we could attract those same 

benefits from other providers at the same or a lower cost. 

Mr. DEFAZIO. So you are referring in particular to say values of 

reserve. Mr. DUNCAN. Values of reserve, exactly. 

Mr. DEFAZIO. I understand that some of the industrial customers 

would like to bid on providing reserves to BPA-has the Council 

been contacted by other customers that would like to be included 

in that process? 

Mr. DUNCAN. I think some industrial customers might well be interested in bidding on it. I think some of the utilities might be interested in and willing to bid on it. 

Mr. DEFAZIO. I think-! mean since we are getting so free-market oriented here, I think that is a great idea and I would assume 

that we would open that process up fully. 

Mr. DUNCAN. And that would be the best possible way I think 

to test this benefit, rather than either restore the aluminum companies or Bonneville, my, of the three of us, having to take that on 

faith. 

Mr. DEFAZIO. Well, and the good thing about that is we no longer 

have to argue over the assumptions which I can go into at great 

length, you know, the 1982 assumptions and the, you know, the 

turbines and the interest rates, but we could put all of that argument aside and just say, fine, we are going to do a free market 

process here, anybody who wants to provide this sort of 

interruptability can bid. The aluminum companies could do it individually. Some aluminum companies might, rather than acting as 

a cartel and bidding as a group, which generally defies, you know, 

my sense of law and free competition in the United States, they 

could do it individually. 
45 

Mr. DUNCAN. I would expect some would be able to make considerably more competitive bids than others, and that would be just 

fine. 

Mr. DEFAZIO. And I assume then the ratepayers would probably 

come out ahead, or other ratepayers, as good. 

Mr. DUNCAN. Yes. 

Mr. DEFAZIO. Well, let's get to a couple of other points here. And 

this is--I don't want to go into this too long, but I share this concern with the Council and I just would like you to-where you talk 

about the threat of competition and you say the Council believes 

that Bonneville may have overstated this competitive threat in the 

interest of bolstering arguments in favor of changes called for in 

the business plan. Now, is that a position of the Council or is that 

you? 

Mr. DUNCAN. Council staff has done the analysis that is reflected 

in our written testimony. And I think that there is a general feeling on the Council, although I can't say that we have taken a vote 

on this or taken a Council position on it, that while it is important 

for Bonneville to signify, you know, to its own-to its customers 

and its own employees, that times have changed and the company 

has--the agency has to be more efficient and competitive, there 

comes a point at which you start overstating the potential for you 

to become noncompetitive. 

In the business plan, for example, and in a number of the other 

documents Bonneville has provided to the region, there is a chart 

in there that shows fish and wildlife costs. And it basically shows 

those costs shooting through the roof. And in fact, there is nothing 

technically wrong with that chart, because fish costs have gone up, 

and in the last two or three drought years, it has been a very expensive proposition. But the inference you draw from the chart is 

that those costs are going to increase exponentially. 

Well, if you have customers who already are concerned about 

dealing with you and impose a, say, 2 or 3 percent discount on 

their willingness to deal with you, and you start undermining your 

competitive position even further by stating that you do have fish 

and wildlife costs and they are uncontrolled and they are shooting 

out of site exponentially, chances are that customer's discount is 

going to go up from 2 or 3 percent to 4 or 5 or 6 percent, and is 

not going to end up making Bonneville more competitive. 

Mr. DEFAZIO. Sure. So basically we are talking about a free market lesson for BPA here, which is you want to get customer confidence, I think that is something that BPA has to pay some attention to. My understanding is there have been some rather extraordinary presentations by BPA on this issue, particularly to Mr. 

Lovelin's group which seem to engender a great deal of fear. 

I guess I would like to just underline the point you made about 

drought. You know, if we are in a cycle-this is a permanent cycle, 

we have really big problems in the Northwest beyond just our hydroelectric system, I mean with the potential for our forests or 

rangelands or anything else. I mean if we don't get back to more 

than what we consider normal meteorological conditions, we've got 

some real adjusting to do. But that is the key in terms of the last 

couple of years. 
46 

Mr. DUNCAN. But even if we continue, even if worst case were 

concluded and we would continue in this kind of serious drought 

situation, the line doesn't keep going up, you know. It levels off at 

a very difficult and high level, and we have got to do everything 

we can to bring it down. 

Mr. DEFAZIO. Right. There is a limit to the system, no matter 

how much you want to tweak it, no matter how much you are an 

advocate of drawdown or anything else, there is a limit to the system, a realistic limit, particularly when you have to figure there is 

another year coming. 

Mr. DUNCAN. Yes. One of the reasons, for example, that we could 

continue to examine drawdown as an option is that at some point 

that extra acre foot of water does become exponentially more expensive and starts to impact refill for both fish and power, and you 

have to look at ways of using the same water more efficiently, because there isn't more. 

Mr. DEFAZIO. Right. On page 10, issues not developed in the 

business plan, you raised three major points and you might expand 

on those briefly. That is, the business plan proposes a formula for 

application of tiered rates but the question of irrigation rates, is 

not raised at all. 

I might disagree with you somewhat. It seems to me with either 

the DEIS or the business plan they mention something about summer rates, which is a vague reference to me for irrigators, but it 

would be a change in the system. So I believe it was referenced. 

And these issues are critical to Bonneville's business success and 

business plan process. Do you want to expand on that any? 

Mr. DUNCAN. I think the point we were trying to make there is 

that there are a lot of issues out there that have to be addressed 

in a-an early and deliberate way. We are not going to be able to 

squeeze all of them into the business plan, given the schedule that 

it is-that it is on. It was a way, if anything, of underlying the fact 

that important issues have to be given the time to work themselves 

out. 

Some of them are not in the business plan because they are 

going to take longer to work out. One of them is not in the business 

plan because it is going to rely on the Congress to move on it or 

not, and that is the issue of incorporation. And the point to describing those is that those are also issues that Bonneville is going to 

have to take up if it is going to thoroughly examine its competitiveness and render itself as competitive as possible. 

But they're not going-not going to be addressed in this current 

business plan, as far as we can tell. 

Mr. DEFAZIO. Let me get one more question in quickly before this 

round ends. I will have a couple more questions the next time. 

How much of BPA's projected load loss, according to the Council, 

is due to customers choosing to meet load growth independent of 

BPA? For instance, they talk about Clark, 250 megawatt cogent 

project. I keep asking BPA, have you received a notice from Clark 

yet? Have you received a notice from Clark or Snohomish that they 

no longer wish to purchase that power? Because I understand you 

have to give a two-year notice. There has been no notice. 
47 

Are they anticipating load growth or are they actually, do you 

think, going to say to BPA, No, we will take 250 megawatts less 

two years hence? 

Mr. DuNCAN. I think that the Council's staff analysis and judgment, which I share, is that, as in the past, some utilities have chosen to meet their own load growth partially, and they will continue 

to do so for a variety of reasons that have to do with diversity of 

supply, reliability, not just price. I would not necessarily expect 

Clark and Snohomish would or wouldn't conclude these negotiations. But I am not under any illusions about some utilities choosing to meet some of their load growth and conceivably some of their 

load through their own resources. Historically, they always have. 

EWEB has its own resources, Seattle has its own resources. A lot 

of utilities are partially reliant customers of Bonneville. 

So I think the point the Council was trying to make there is that 

will continue, but that is not the origin of a death spiral for Bonneville. And that the potential loss of future load for Bonneville, if 

that is how one wants to characterize it, is in the hundreds of 

megawatts, not the thousands of megawatts; and that there are a 

variety of other reasons than just wholesale rates why that is going 

to take place. 

Mr. DEFAZIO. Okay. Thank you, gentlemen. 

Mr. Smith. 

Mr. SMITH. Your statement here regarding the intent of the business plan, you say, must be to make Bonneville businesslike in the 

execution of both its public and private purposes. Must not be 

made--it must not be to make Bonneville into a business for which 

public purposes are secondary to its commercial purposes. 

Question-are 4 70 jobs in The Dalles a social concern to Bonneville? 

Mr. DUNCAN. Jack is going to have to answer that directly. Do 

I think they should be a social concern for Bonneville? Yes. 

Mr. SMITH. Good. So do I. You and Mr. DeFazio were agreeing 

with each other to go to a strictly bidding kind of a program and 

allowing people to bid on extra energy, wherever they might get it, 

and it sounded like the Adam Smith purity. 

Mr. DUNCAN. No. That was--

Mr. DEFAZIO. It was specifically in connection, if I can interrupt, 

with the value of reserves and not all new resources. It is one particular benefit that is provided for one industry or company. 

Mr. SMITH. Thank you for the clarification, Mr. Smith. 

Mr. DeFazio. 

Mr. DEFAZIO. Even if he is a relative, I am not that much of an 

advocate. 

Mr. SMITH. I am sure you are not an advocate. The question that 

I have is simply that in that decision-making process and in the 

business plan, do you or do you not believe there ought to be a cost 

benefit kind of analysis with respect to how you handle those kinds 

of reserves? The point again being that pure--pure competition is 

one question. 

Another question, if Bonneville Power Administration has to 

have a social half of its body, it can't be so competitive that it 

drives an aluminum plant out of production in The Dalles just to 

maintain the competitiveness of Bonneville. 
48 

Mr. DUNCAN. Well, Congressman, I also don't want to be in the 

position of-of advocating a pure rate competitiveness test in the 

instance of DSis when I am arguing that that shouldn't be the beginning and end of wisdom in Bonneville's dealings elsewhere in its 

business world. So, yes, I think there are other considerations, and 

ought to be, besides simply which-which supplier can provide the 

least expensive reserves to Bonneville. And considerations, for example, such as building and maintaining a long-term business relationship and, therefore, for a long-term reliability of those reserves 

is a consideration-ought to be in any business dealing. It was in 

contract negotiations that I had when I was on the private side. 

So if your question is, should this be entirely driven in some abstract world of who can undercut the next competitor by one dollar, 

no, I am not advocating that at all. But I am advocating opening 

this up to competition with multiple issues, not just the ultimate 

dollar cost being a part of that competition. 

Mr. SMITH. I think I should not retreat. We are beginning to 

agree, and that is dangerous. 

Thank you. 

Mr. DEFAZIO. I thought you agreed with his dad on a lot of 

things. 

Mr. SMITH. His dad had a heavy gavel. I was never asked whether I agreed or not. 

Mr. DEFAZIO. And--

Mr. DUNCAN. And I paid for those sins. 

Mr. DEFAZIO. Actually, I just saw him. He was here a couple of 

weeks ago for his class reunion. There are three people, I think, or 

four left that were in his class. It is fun to see him. He always 

starts by introducing himself to me as if I don't remember him. I 

always remember him. 

On page 16 of your testimony, second paragraph, at the end of 

the paragraph, you talk about retail wheeling. There is a lot of 

hysteria about retail wheeling; there have been a lot of questions 

about what the legislation adopted by Congress and what Congress 

intends in terms of wheeling. The California PUC has seemed to 

back down after threats of litigation from some of their major utilities. 

BPA made some assumptions about load losses due to retail 

wheeling. Do you want to briefly address that? 

Mr. DUNCAN. Yes. I think it was appropriate for Bonneville to do 

an analysis that bounded its likely future with best and worst 

cases. And, here, I am speaking again for myself, not the Council, 

because they haven't spoken to the issue of retail wheeling. 

But at least what I see of the bold start and pretty immediate 

slowdown at the California PUC is-is that while retail competition 

is certainly coming to the utility industry, it is probably not going 

to arrive the day after tomorrow in all of its form and substance, 

and that there is time for both utilities to adjust their competitive 

strategies and, more important from our perspec--our institutional 

perspective, time for the Congress and State legislatures, public 

utility commissions and the Council to try to figure out how we 

protect some of those long-term values that were embedded in the 

Northwest Power Act, and at the same time, reap the benefits. And 
49 

I think, on balance, there will be benefits of a more competitive energy and utility marketplace. 

So the short answer to your question is now, retail wheeling is 

not going to be here in full form immediately; and I guess it is my 

belief that utilities need to be expeditious but deliberate in figuring 

out how they are going to respond to it. 

The impulse is to respond to it by being able to compete on rates, 

and that impulse tends to be fed by, particularly, gas companies 

and IPPs that want to open up and do business in the Northwest 

and will put a lot of pressure on Northwest utilities to think in 

those short-term-that short-term frame of reference. 

Mr. DEFAZIO. Sure. 

Mr. DUNCAN. I think we have a longer period of time to make 

those adjustments until then. 

Mr. DEFAZIO. You made a good case early in the day about the 

alternate providers. So I subscribed to some Podunk alternate provider, and what I got when I tried to dial long distance was, there 

was no availability. So one would want to be a little cautious about 

signing up with an IPP, lest you turn on your heat one day in the 

winter and they say, sorry, we are out. 

It is-there are going to be some really major questions. Is Oregon, Washington, Idaho or Montana, the service territory of BPA, 

are any of them currently considering rules regarding retail wheeling? 

Mr. DUNCAN. I am not aware of any that are. I think, Congressman, that what we will find over the next 10, 15 years is a sharp 

differentiation in the marketplace and that there will be some customers whose business operations lend themselves to buying big 

chunks of cheap power that will be looking for those. But there will 

be a lot of smaller ones. 

Mr. DEFAZIO. I understand that. In fact, that has been, at times, 

one of the unfortunate impacts on the telephone. 

Mr. DUNCAN. Right. 

Mr. DEFAZIO. When you cherry-pick and pick off the big cost centers, but then who wants to provide the rural electric? That is always the case and that is something that is going to have to be 

looked at as a package by the regulatory commissions. We will 

have later testimony basically questioning one of the suggestions 

made by the task force which had to do with the issue of regional 

preference. 

One scenario BPA has spun out is that we are going to be left 

with this power and we won't have anybody who wants to buy it 

at a decent rate. And, in particular, we can't market it outside the 

region because we have to have the call-back provisions. And the 

response of the task force was, well, if you could come into a permanent surplus power situation, and given the new marketplace, 

there is a good rate which can be obtained-in fact, SMUD was in 

here testifying on another issue; their avoided cost is 37 mills, so 

they'd be thrilled to be able to bid at about, you know, somewhere 

in the 30 mill range, I am sure, to buy some long-term power from 

BPA. 

So the task force suggested if there is not a-a firm market in 

the region, or market at a good price, that we should look outside 
50 

the region. And apparently either you or the Council-and if you 

could clarify that, agreed that there might be some benefits to this. 

Mr. DUNCAN. Yes. The Council hasn't taken a position on it, but 

certainly if Bonneville is sitting on surplus power that it can't market internally and can't market externally because of constraints, 

removing those constraints pretty much has to be on the table. And 

I think that the Council would support removing them. I found it instructive, Mr. Chairman, to sit in a-an advisory 

committee meeting over at Bonneville a few months ago when one 

of Bonneville's public customers was complaining about the lack of 

competitiveness, and that he was just thinking of taking his business elsewhere. And a major private utility representative, who 

was also sitting in the room, offered out of hand to take his consignment of Bonneville power at his price, straight across, no questions asked. No regional preference problems there, either. But the deal was not consummated. 

Mr. DEFAZIO. Okay. And we will hear from Judy Lamson later, 

in her testimony on page 5, she refers to Puget Sound Power and 

Light recently purchasing 500 megawatts of power from new resources at 42 mills. So again, there may be markets within the region. It will be interesting to explore that question in a little more 

depth. Two other quick things. Integrated Resource Plans-would you 

care--I mean, there has been some controversy over how we should 

do IRPs. There now seems to be agreement in the public power 

community that it would be desirable to develop them. The question then becomes enforceability. 

Mr. DUNCAN. And it is a question that we are still discussing 

within this energy conservation group that is meeting at Bonneville, between public interest groups, the Council and others. I expect that most of Bonneville's customers, you know, will do some 

kind of an IRP because it only makes business sense. 

I think there is some concern about the assumptions that customers will select, in doing their IRPs, and whether those will reflect the goals of the regional act. And all of that is obviously still 

under discussion. Where, at least, I am coming down right now is 

a willingness to focus on the region's contribution, rather than proposing a structure that involves policing every single customer of 

Bonneville. I don't think that is especially productive. I don't think 

that is required by the Act. 

But what is, I think, essential and productive is that there be a 

tracking mechanism so that-so that we know whether those IRPs 

are in fact producing the conservation returns that are consistent 

with the regional act. And, as yet, we don't have agreement on 

some sort of credible structure for tracking conservation contributions, utility by utility, and being able to accumulate those and report them to the region. 

Mr. DEFAZIO. Okay. The Act, as I recall, gives some price preference or difference for conservation, 10 percent. 

Mr. DUNCAN. Yes. 

Mr. DEFAZIO. Do you think we should be tracking that as we do 

all IRPs, or do you think the IRPs should be free-market-cost 

based? 
51 

Mr. DUNCAN. 1-1 guess the fundamental rule that I think ought 

to be observed is that those who are partaking of this public value, 

the river and the electricity that it generates, have reciprocal obli- gations back to the region. That river doesn't belong to any one economic user group; it belongs to all of us. And there is an obligation 

to use its production as efficiently as possible. 

Mr. DEFAZIO. Okay. In applying the-well, no. Mr. DUNCAN. And the Power Act sets the terms for its use. It includes a 10 percent benefit for conservation. 

Mr. DEFAZIO. Sure. Okay. I think-I will see if Mr. Smith has 

more questions, now that he has found something he can disagree 

with you over. I will defer back to Bob. 

Mr. SMITH. I think I found something. 

Mr. DUNCAN. It is a relief to me, too. 

Mr. SMITH. Should utilities who get the benefit of conservation 

savings bear their cost? 

Mr. DUNCAN. Yes. And they do now. 

Mr. SMITH. That means that-that means that you believe all 

that the utilities are bearing equitably the cost of conservation? 

Mr. DUNCAN. Well, equity is a hard thing, and 1--

Mr. SMITH. Evenly. Mr. DUNCAN. What? 

Mr. SMITH. Try evenly. 

Mr. DUNCAN. No. 

Mr. SMITH. Let me give you an example. 

Seattle City Light pays Bonneville $40 million a year and gets 

four million back. That is not true of many other utilities in the 

Northwest; is that correct? 

Mr. DUNCAN. That is correct, yes. 

Mr. SMITH. So which utilities benefit and which do not? 

Mr. DUNCAN. Well, Congressman, certainly Seattle benefits and 

EWEB benefits. Mr. SMITH. An urban area, right? 

Mr. DuNCAN. It is an urban area with substantial load growth. 

Mr. SMITH. I assume EWEB benefits. 

Mr. DUNCAN. Yes. Mr. SMITH. What about Pacific Power and Light? 

Mr. DUNCAN. Pacific Power and Light, probably fits under theregional exchange. 

Mr. SMITH. Would you agree that-therefore, that in the new 

business plan, whoever receives conservation benefits ought to pay 

for them? 

Mr. DUNCAN. Well, Congressman, if we are to continue to be a 

region and distribute costs and benefits of the system on a regional 

basis, then there will inevitably be some inequities. Some areas 

will grow faster and some slower. If we simply decide to divide up 

the hydro production of the Columbia River and allocate a chunk 

to each utility, I am sure some would perceive that as a more equitable solution. I don't. Mr. SMITH. I think the point is, you are pressing Bonneville towards conservation. 

Mr. DUNCAN. Yes. 

Mr. SMITH. That may be a bona fide public response from your 

point of view. 
52 

My question is, should one utility benefit over another when you 

are stressing conservation? If one utility does a terrific job of putting forth conservation, why shouldn't they benefit from it? 

Mr. DUNCAN. Well, they do benefit from it. 

Mr. SMITH. I'm talking in terms of region. 

Mr. DUNCAN. And so does the region. 

Mr. SMITH. But you just admitted to me that there were some 

inequities. 

Mr. DUNCAN. There are. I admitted there is unevenness. 

Mr. SMITH. Pardon? 

Mr. DuNCAN. Unevenness. There are lots of inequities in theregion. 

Mr. SMITH. Unevenness? 

Mr. DUNCAN. Yes. 

Mr. SMITH. So you are saying that utilities that are primarily in 

residential areas benefit and those utilities which probably have 

more commercial activity don't. Is that a fair statement? 

Mr. DUNCAN. No, because we have--we have substantial commercial and industrial conservation programs, and those will also 

have benefits. 

Mr. SMITH. I think I will leave you with that ambiguity. But I 

think I am right, and I will go into this in more depth. And I think 

we will have some testimony about which utilities benefit from conservation and which do not and why. And maybe the Pacific Northwest Council ought to take a look at that unevenness. 

Mr. DUNCAN. Yes. I hope we will, and we are. And one of the reasons that I have supported decentralizing conservation programs 

and some costs of conservation is to try to get a closer match between costs and benefits. But I still believe that we--and the law 

describes us as a region where those costs and benefits have to be 

construed regionally, as well as utility by utility. 

Mr. SMITH. Well, somebody makes a decision, obviously. And you 

are in a position of advisory over Bonneville Power Administration. 

Somebody makes the decision where to transfer these credits. 

Mr. DUNCAN. Yes. And I have made--some of my staff are really 

uneasy, but I have been supporting a movement toward more closely aligning those costs and benefits at the utility leveL 

Mr. SMITH. I yield back to Mr. DeFazio. 

Mr. DEFAZIO. One quick point on that. My understanding is, we 

had a record year for regional acquisition of conservation. Last 

year, was it 53 megawatts? 

Mr. DUNCAN. Yes. 

Mr. DEFAZIO. 23 mills? 

Mr. DUNCAN. Pretty cheap. 

Mr. DEFAZIO. Is there any other resource out there we could buy 

for 23 mills? 

Mr. DUNCAN. Not that I am aware of. 

Mr. DEFAZIO. So BPA avoided having to acquire 53 megawatts 

of something that would have cost considerably more than 23 mills. 

I haven't questioned them recently; a year ago during the February-March time period, my recollection is they were purchasing 

power close to 30 mills. 

Mr. DUNCAN. Somewhere between 30 and 40. 
53 

Mr. DEFAZIO. Right. So right now, the way we are acquiring conservation benefits, everybody in the region, because we are acquiring a resource that is so cheap that, you know, it far outstrips anything anybody could require individually and BPA doesn't have to 

acquire something more expensive and crank it into the rate base 

and charge everybody more. 

Mr. DUNCAN. That is right. The disadvantage and the reason it 

is an issue in the first place, that two--2.3 cents is a life-cycle cost, 

but most of those costs are front-loaded and so they put near-term 

upper pressure on rates, long-term downward pressure on rates. And that is the dichotomy that we are trying to resolve. 

Mr. DEFAZIO. Yes. You avoid transmission. 

Mr. DUNCAN. Yes. Mr. DEFAZIO. I mean, there are a number of immediate savings. 

Mr. DUNCAN. Yes. 

Mr. DEFAZIO. If transmission is going to become a great new 

functional commodity that BPA is marketing to everybody, then we 

want to free up as much of it as possible so we can market as many 

of those parts as possible because we are making so much money 

doing it? 

Mr. DUNCAN. Yes. 

Mr. DEFAZIO. Thank you. Call the next panel. Thank you for 

your excellent testimony. The next panel will come up. As they are getting arranged, I am 

going to step out. We will-why don't we take about two minutes 

here, right? There are certain things that don't-yes, two minutes 

for the next panel. You don't have to sit down right now. You can 

stretch, whatever. I am serious. [Recess.] 

PANEL CONSISTING OF K.C. GOLDEN, EXEClJTIVE DIRECTOR, 

NORTHWEST CONSERVATION ACT COALI'fiON, SEATTLE, WA; 

KEN CANON, MANAGING DIRECTOR, ASSOCIATION OF PUBLIC AGENCY CUSTOMERS, PORTLAND, OR; BRETT WILCOX, 

PRESIDENT, NORTHWEST ALUMINUM CO., THE DALLES, OR, 

ACCOMPANIED BY KEN PETERSON, JR., CHIEF EXECUTIVE 

OFFICER, COLUMBIA ALUMINUM CORP., VANCOUVER, WA; C. 

CLARK LEONE, MANAGER, PUBLIC POWER COUNCIL, PORTLAND, OR; DANIEL C. SCOTT, COMMISSIONER, MASON COUNTY PUD NO. 1, ON BEHALF OF THE ALUMINUM INFORMATION PROJECT UTILITIES, SHELTON, WA; DAVID E. PIPER, 

GENERAL MANAGER, PAC~IC NORTHWEST GENERATING 

COOPERATIVE, PORTLAND, OF; AND, JUDY LAMSON, POLICY 

SPECIALIST, WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION, OLYMPIA, WA 

Mr. DEFAZIO. Okay. I thank the panel for their indulgence. I got 

ambushed on the way to the corner of the building there and had 

to answer a few questions. 

The next panel, rather extensive panel-I apologize for the 

crowded conditions. This is not the Ways and Means Committee, 

but you each have a microphone and some water. What I would 

like you to do is watch the lights and stick to your five minutes. 

And as I said earlier, any departure from prepared remarks or prepared testimony is always welcomed because I have read the testi-
54 

mony but it is your five minutes. We will go in the order provided 

for on the sheet. Mr. Golden will be first. 

STATEMENT OF K.C. GOLDEN 

Mr. GOLDEN. Thank you, Mr. Chairman, Mr. Smith, for inviting 

our comments on your excellent report. 

I first wanted to reaffirm that the Earth is not flat. Those of us 

who have looked at the evidence and concluded, like the task force 

concluded and as the power planning council indicated this morning, that Bonneville is not in imminent danger of massive load loss, 

have been accused by some of burying our heads in the sand and 

ignoring the new competitive realities of the electric utility industry. I am here to say we are acutely aware of those realities. We 

stand ready, willing and able to help Bonneville accommodate and 

adapt to those realities and fulfill its mission in view of those realities. 

Having said that, you still have seen no credible case made for 

an imminent massive load loss or a death spiral. I think the task 

force's conclusion on that subject was correct, and I think the testimony today of the Washington Utilities and Transportation Commission will put to rest any fear that there is any present or foreseeable lack of demand for the output of the Columbia River system. The Earth is not flat but the sky is not falling. 

Second, I wanted to indicate that the draft business plan's conservation reinvention departs quite markedly under Congress's direction, under the regional act and this task force's recommendation to acquire all cost-effective conservation. Quite apart from the 

reinvented conservation program will meet its goals, it starts by 

aiming to deliver annual savings in every year after 1996, significantly lower than the Power Planning Council's annual targets and 

Bonneville's own 1992 targets from its conservation implementation plans. 

That is what happens if it works. And I think that the task 

force's grave concerns about whether it will in fact work are very 

well placed. I want to reaffirm that we are ready and able to help 

Bonneville adapt to new realities. Tier grades was, after all, I suppose it is time to admit it, our initiative. We have worked very 

hard to help Bonneville develop a conservation approach that conforms to this task force's recommendations and the Senate appropriations language. As the Council indicated, Mr. Duncan indicated, we have a long way to go. 

In the effort to move that discussion forward, I have included in 

my written statement a discussion paper called Rethinking Conservation, Reinvention Revisited that I think incorporates much is 

what is useful, insightful information in the conservation 

reinvention proposal, while preserving the essential features of a 

successful existing system, a system that is producing the only 

cost-effective resource that Bonneville has ever delivered in significant quantities. I hope that that proposal addresses some of the 

concerns that Mr. Smith raised this morning about equity. 

I guess I want to conclude by just thanking you all for 

redirecting Bonneville toward the crucial mission, the central mission of Bonneville, which is defined in the purposes of the regional 

act. BPA assertions to the contrary notwithstanding, this discus-
55 

sion is about ends, not just means. The business plan treats commercial success as Bonneville's primary goal and the Act's purposes 

as the statutory constraints among which Bonneville must now 

begin on its way to that Holy Grail of commercial success. I think the business plan treats the regional act and its purposes 

as a cost of doing business. We think it is the reason for doing business. It is not a penalty that handicaps Bonneville relative to its 

competitors. It is the prize that sets Bonneville above its competitors as an uniquely valuable regional institution that provides a lot 

more than kilowatt hours. We think the regional act was a promotion from the role of simply commodity broker to the role of 

steward of the Columbia River's bounty and advocate for a brighter 

energy future for Bonneville. I think it is time for Bonneville to ac- c~pt that promotion. I think Bonneville is eminently capable of rising to the occasion 

and accepting that promotion, but not if it keeps thinking of itself 

as a competitively challenged business. I would urge Bonneville 

leaders and this task force to think of it instead as a public service 

organization with the unique ability and the enormous resources to 

provide affordable energy service, environmental integrity and sustainable economic development opportunities to the nine million 

citizens in the Northwest. 

Thank you again for your continuing, persistent and very insightful oversight. 

Mr. DEFAZIO. I thank the gentleman for being so brief. 

[Prepared statement of Mr. Golden follows:] 
56 

Statement of K.C. Golden 

on behalf of the 

Northwest Conservation Act Coalition 

before the 

House Committee on Natural Resources 

Task Force on the Bonneville Power Administration 

August 9, 1994 
57 

Thank you Mr. Chairman and members of the Task Force for soliciting our 

comments on your report. On behalf of the Northwest Conservation Act 

Coalition and its 70 member organizations, I want to extend our sincere 

appreciation for both the quality and the persistence of this Task Force's 

oversight activities. Your continued diligence is the region's greatest hope for 

realizing the bright promise of an economically and environmentally sound 

energy future that Congress articulated in the Northwest Conservation Act of 

1980. 

Let me begin by congratulating you for the thorough and insightful analysis 

you provided in "BPA at a Crossroads." We particularly appreciate its clear 

focus on the enormous public policy implications of BPA's "competitiveness 

project" and its unwavering insistence on putting the public interest first. 

The analysis and recommendations in Section II are particularly compelling, 

and we support them wholeheartedly. 

We particularly support your proposition at the beginning of 

recommendation 9: 'Those who benefit from the power provided by the 

Columbia River hydroelectric system bear a responsibility to further the 

efficiency goals of the Act." We believe integrated resource planning will 

result in more sensible resource acquisitions, but we wish to emphasize that 

130 individual IRPs do not sum into a plan for the prudent management of 

the Federal Base System. That plan can only be developed regionally, by the 

Council. We are still a region; we'll still be a region with tiered rates; and 

we're better off because we are a region. Since the Council's Plan is the best 

hope for coordinated management that maximizes the benefits of the FBS, all 

who share those benefits should be required to implement the Plan - and in 

particular, to achieve its conservation targets - as a condition of service. The 

relative ease with which BPA and the region's utilities surpassed the 

Council's targets last year - notwithstanding severe budget constraints -

should put to rest any fear that the Council's goals are unreasonably 

ambitious. 

Section II of the Report reaffirms the region's priorities and begins to 

straighten the record on BPA's competitive prospects. Section IV offers an 

impressive list of costs incurred for reasons having little to do with BPA's 

core mission - costs that should be eliminated before BP A even contemplates 

curtailing the efficiency and fish recovery programs that lie at the heart of its 

statutory mission. We note that these costs are significantly understated, 

because they rely on conservative WPPSS estimates of mothballing costs, and 

because they do not take account of the full range of subsidies to the DSis. 

The miscalculation of the value of reserves provided by the DSis 

(approximately $40 million annually) represents less than a quarter of the 

annual difference between the cost that BP A incurs to serve DSl loads and the 

revenues collected from them during the last two-year rate period. We find it 

conspicuous that BPA makes frequent (and often inflated) reference to the 
58 

costs of fish and conservation programs as principle drivers behind its alleged 

loss of competitiveness, yet almost never publicly reveals (let alone bemoans) 

the unproductive nuclear costs and industrial subsidies that clearly represent 

the agency's most serious financial liabilities. 

BPA's Draft Business Plan is patently inconsistent with the Task Force's 

recommendations. It uses different assumptions, arrives at diametrically 

opposed prescriptions, and only grudgingly acknowledges the report's clear 

admonition to fulfill the mission that Congress articulated in the Regional 

Act. Two inconsistencies are particularly noteworthy. 

First, despite the Report's well-founded conclusion that BP A is not in 

imminent danger of massive load loss, the draft business plan is crafted in 

large part as a response to the specter of the death spiral. To the extent that 

BPA's actual competitive prospects are analyzed in the draft business plan 

and accompanying environmental impact statement, the evidence suggests 

that significant load losses are exceedingly unlikely. BPA's rates remain 

substantially lower than the cost of alternative resources. The hypothetical 

"30 mill combustion turbine" to which some observers compare BPA rates is 

not an appropriate comparison, for at least four reasons: 

1) Cost estimates as low as 30 mills/ kwh assume full base load 

operation, while purchases from BP A are seasonal and diurnal in 

nature. Typical utilities have annual load factors on BPA of around 

50%. If the fixed costs of a combustion turbine costing 30 mills/ kwh at 

full baseload operation are spread over a 50% annual load factor, the 

cost of energy produced rises to over 40 mills/ kwh, over a third higher 

than the comparable BPA rate. 

2) Line losses incurred during generation and distribution generally 

add about 5 mills/ kwh to the cost of power from a combustion turbine. 

3) The Northwest Conservation Act requires BPA to give a 10% 

preference to energy efficiency, in part to reflect the environmental 

impacts of generating resources. Substituting the quantified estimates 

of the air impacts associated with burning gas (and occasionally oil) in 

combustion turbines used by most states which quantify these impacts 

would probably yield an estimate higher than 10%. 

4) The economic and environmental risks of the existing system are 

now well-known and captured in BP A rates. The economic and 

environmental risks associated with combustion turbines are only 

beginning to emerge. 

Taken together, these factors drive the cost of a "30 mill" combustion turbine 

to near 50 mills, or almost twice the current BPA preference rate. 

2 
59 

The testimony of the Washington Utilities ar.d Transportation Commission, 

which regulates Washington's investor-owned utilities, clearly shows that 

the market value of BPA's power is significantly greater than the revenues 

BPA collects from many of its customers. There is not now, nor will there be 

in the foreseeable future, any shortage in demand for the output of the 

Columbia River System. 

Furthermore, BPA's proposed "market-driven" alternative will not 

significantly reduce projected load losses. Given the extraordinary lengths to 

which BPA proposes to go to protect its competitiveness, we find it 

remarkable that BPA has not documented a significant problem, and that its 

proposed solution has very little effect. In concurrence with preliminary 

Power Council analysis, the Task Force concluded that BPA is wise to 

undertake cost control measures, but that it faces no imminent threat to its 

competitiveness. We hope that the Task Force will work with the Council to 

develop a more definitive analysis of this important issue. 

Second, the draft business plan departs radically from the Task Force's 

recommendations on energy conservation. The draft and accompanying 

DEIS directly and disingenuously link BPA's investments in cost-effective 

energy efficiency with its hypothetical Joss of competitiveness. Based on this 

spurious link, BPA proposes to replace its successful conservation investment 

program with an alternative that even Randy Hardy describes as "a high risk" 

strategy. 

Conservation is the most economical energy resource available to the region, 

but it is not free. BPA cannot fulfill the Regional Act's and this Task Force's 

directive to "acquire" conservation while pursuing the draft business plan's 

goal of making conservation a net revenue producer. Even if BPA's 

proposed conservation reinvention worked, it would, by BPA's own 

estimates, produce annual conservation savings significantly lower than the 

Council's targets and the planned savings under BPA's 1992 Conservation 

Implementation Plan. The draft business plan aims for underachievement. 

We have been working with BPA and its customers to devise a program 

under which the customers would assume much of the responsibility for 

making the efficiency investments that BPA proposes to drop. The Senate 

Appropriations language that stipulates the terms under which this transfer 

of responsibility would be acceptable form the framework for these 

discussions. Although we remain gravely concerned about the implications 

of dramatic reductions in regional conservation investment, we are working 

in good faith to develop a system which meets the standard set forth in the 

Senate Appropriations language. Independent verification of energy 

efficiency achievements and a meaningful, performance-based accountability 

mechanism are, as the Senate language suggests, critical features of any 

credible alternative to a system that is presently performing well. They are, 

3 
60 

in fact, crucial features of illl)C effective regional conservation effort, 

"reinvented" or otherwise. 

While BP A's proposed conservation "reinvention" is in many respects 

antithetical to the Task Force's findings and recommendations, it contains 

one crucially important initiative. BPA has accurately concluded that if the 

region's energy efficiency goals are going to be reached, all who share in the 

benefits of the Federal Base System must assume responsibility for reaching 

them. To his credit, Randy Hardy has endorsed this concept vocally. It 

remains for BPA to develop a system which accurately aligns the allocation of 

Federal Base System benefits with beneficiaries' performance in maximizing 

the value of those benefits to the present and future citizens of the region. In 

negotiating new Power Sales Contracts, BP A has a golden opportunity to 

develop such a system. The renegotiation of these contracts represents the 

unique moment at which BPA can ensure that those who enjoy the fruits of 

the federal investment in the Columbia River System bear the responsibility 

for maximizing the system's productivity. These contracts allocate what is 

arguably the region's most valuable public resource. Therefore, they must 

contain provisions which allow third parties to pursue and protect the vital 

public interest in efficient use of the FBS as a condition of service. 

The attached discussion paper, "Conservation Reinvention Revisited," is an 

effort to incorporate the useful insights of BPA's proposal into a more 

comprehensive system that preserves most of what is working in the existing 

model. While we are pleased with results of last year's conservation effort, 

we are by no means complacent. We offer "Conservation Reinvention 

Revisited" in the spirit of building on BPA's singular success in delivering 

cost-effective energy savings to the regional grid. 

In many crucial and substantive respects, the draft business plan departs from 

this Task Force's direction. These inconsistencies represent more than a 

disagreement about strategy. Contrary to BPA's assertions, the draft business 

plan is not merely about means. While it nods dutifully to the Regional Act's 

directives, it does not embrace them as BPA's core mission. It treats Congress' 

direction as a series of statutory constraints through which BPA must 

navigate, not, as the Task Force report recommends, as "the yardstick by 

which Bonneville's new Marketing and Business Plans should be measured." 

The most disturbing part of BPA's "reinvention" to those of us who believe 

passionately in BPA's public service mission is that when BPA leaders talk 

about what separates the agency from a business, they talk as if their public 

service mission makes them somehow ~than a business, a business with a 

competitive albatross around its neck. 

The draft business plan treats the Regional Act as a bothersome cost of doing 

business. We're saying that the Act is the reason for doing business. The 

draft business plan focuses primarily on commercial success and looks at the 

4 
61 

Regional Act's mission as an impediment to that success. We're saying that 

the Regional Act's mission is the definition of success. The Act is not a 

penalty that handicaps BPA relative to its competitors, it's the prize that sets 

BPA above its competitors as a uniquely valuable institution that serves the 

region with a great deal more than kilowatt hours. 

We've heard Bonneville leaders say recently that what's at stake in the 

reinvention is BPA's very survival , as if that was the most important goal we 

can imagine. It is not. 

An economically and environmentally affordable energy future; healthy 

Northwest ecosystems; democratic control of the region's energy and natural 

resource decisions; efficient use of our precious endowment of inexpensive 

hydropower; affordable basic energy service for all; far-sighted stewardship of 

the Columbia River's bounty: these goals are far more important to the 

people of the region than BPA's commercial fortunes. 

BP A appropriately maintains that these goals are intertwined - that without 

commercial success, BPA won't be able to accomplish any of the Regional 

Act's purposes. We agree that they are related, but we would describe the 

relationship somewhat differently: Unless BPA devotes itself as passionately 

to these goals as it has to "competitiveness," there is no reason for it to exist as 

a public entity. 

The Regional Act defined a crucial job for BPA to do and this Task Force has 

compellingly reaffirmed the importance of that job. The Act wasn't a 

punishment; it was a promotion from the role of a commodity broker to the 

role of steward of the Columbia River's bounty and advocate for a brighter 

energy future. BPA can and must accept the promotion that Congress gave it 

in 1980 and that you have offered once again in "BPA at a crossroads." 

Bonneville is capable of rising to the occasion, but not if it keeps thinking of 

itself as a competitively-challenged business. Instead of looking of BPA as a 

business with a monkey on its back, we'd urge you to think of it as a public 

interest organization, like NCAC, with an ambitious mission, and unlike 

NCAC, with an enormous revenue-producing endowment. 

Think of it, not as a business, not as a government agency, but as a committed 

team of public interest advocates with the unique ability and enormous 

resources to provide affordable energy service, environmental integrity, 

healthy fisheries, and sustainable economic development opportunities for 9 

million people. 

We plan to submit more detailed written responses to your pre-hearing 

questions in the near future. Thank you for your continuing deliberations 

and oversight, and for the opportunity to participate. 

5 

84-374 0 - 94 - 3 
62 

A IT ACHMENT TO TESTIMONY OF K.C. GOLDEN 

House Natural Resources Committee, BPA Task Force 

August 9, 1994 

NCAC Discussion Draft 

RETHINKING CONSERVATION "REINVENTION" 

BPA's proposed conservation "reinvention" begins from the premise that regional 

acquisition of saved energy is a failed model. Citing competitive threats and customers' 

unwillingness to "embrace conservation as a resource," BPA proposes to induce 

conservation through a combination of a modest short-term marginal cost signal at the 

wholesale level, targeted marketed transformation activities, and a DSM product line that 

BPA would sell to customers. 

Many of us who have been instrumental in building the Northwest's succe~>sful energy 

efficiency programs see the situation somewhat differently. Last year's conservation 

performance ( 135 megawatts saved regionally, and over 50 megawatts saved on the BPA 

system) clearly reaffirmed the proposition that energy efficiency can be acguired as a resource on a large scale. Conservation is, in fact, the ruJh resource that BPA has ever acquired cost-effectively in significant quantities. Last year's success prompted the U.S. 

Senate to observe, in its FY 95 Energy and Water Appropriations report (103-291), "[The] 

combination of regional funding and locally tailored programs achieved impressive savings 

at a modest cost in 1993." The recently-completed work of the House Natural Resource 

Committee's BPA Task Force confirms that conservation is not exerting significant upward 

pressure on BPA rates, and that BPA can remain competitive without reducing its 

conservation investments. 

Based on the dramatic recent success of the region's conservation effort, the region and 

BPA have much to be proud of, but no reason to be complacent Continuing efforts to 

improve the efficiency and effectiveness with which we deliver saved energy to the regional grid are clearly in order. However, effective reform should build on success, rather 

than scrapping a highly successful approach and starting over. NCAC embraces 

innovation, but we are wary of "reinvention" that dismantles first and reinvents later. In 

the spirit of building on success, we offer the following thoughts on how to improve the 

region's conservation performance. 

Premises and principles 

While we believe that BPA's conservation "reinvention" approach is founded on some unsound premises, we acknowledge and support BPA's effort to rise to the enormous 

challenges posed by industry restructuring. In view of those challenges, and in view of the 

urgent necessity to make the most of the Columbia River's increasingly constrained output, we begin from the following premises: 

·We are still a region; we'll still be a region after tiered rates; and we're 

better off because we're a region. Sound management of the Columbia River 

System is fundamentally a regional enterprise. It cannot be accomplished as the sum of the 

independent activities of BPA's more than 130 wholesale customers. Tiered wholesale 

rates will help to communicate the economic consequences of action or inaction at the 

margin, but it will not eliminate regional interdependence. Our ability to manage the system 
63 

autonomously on behalf of the region's citizens depends on our performance in managing 

the system wisely. Maximizing the productivity of the federal investment in the region's 

power system is our collective challenge. It is also an enormous opportunity, an opportunity that the Regional Act urged us to seize in its first purpose: 

"to encourage, through the unique opportunity provided by the Federal Columbia River 

Power System - conservation and efficiency in the use of electric power, and the 

development of renewable resources within the Pacific Northwest." (PL 96-501, Section 2.( 1)) 

We begin from the premise that as the operator of the world's largest coordinated 

hydropower system and transmission grid, BPA has an unparalleled capacity to make 

efficiency investments, offset lost revenues by marketing saved energy, and increase the 

value of the FBS by maximizing the energy services it produces. 

• The primary goal is to minimize the total. life-cycle cost of providing 

energy services. while avoiding unacceptable rate impacts. The region's 

considerable experience in developing conservation suggests that the resource can be 

acquired effectively with only modest rate impacts. BPA's estimates of the impact of 

continued conservation investment on wholesale rates (approximately 1.2 mills over the 10 

year period) is well within any reasonable assessment of what is possible and acceptable in an increasingly competitive wholesale power market. Furthermore, because of its considerable marketing advantages, BPA is in the best position to minimize rate impacts by 

marketing the conserved product. We strongly support BPA's efforts to eliminate 

unnecessary costs and subsidies. As the BPA Task Force report concluded, Bonneville 

can maintain its status as the wholesale power provider of choice while sustaining necessary levels of energy efficiency investment. 

• Marginal cost pricing is good economic policy. not a panacea. Regional and 

national experience demonstrates conclusively that economically efficient pricing increases 

the effectiveness of conservation programs, but in no way eliminates the need for them. As 

the BPA Task Force concluded, "(A] tiered rate- by itself- is not likely to provide an incentive sufficient to cause utilities to make substantial direct investments in 

conservation ... " Persistent market barriers remain, leading to chronic failure to capture 

cost-effective energy savings even in places where retail rates are two or three times higher 

than they are in the Northwest. Energy efficiency is the cheapest resource available, but it 

isn't free. There is no substitute for investment. The 20 mill difference between the likely 

Tier 2 rate and the Council's estimate of the regional avoided cost is a partial measure of the 

opportunities to reduce the region's energy bill that will not be captured by individual 

utilities responding to a tiered wholesale rate. 

• BPA and electric utilities generally will continue to play a uniquely 

valuable role in the increasingly competitive power industry. Unlike any of 

their emerging competitors, electric utilities are singularly equipped to provide customer 

services that are likely to become more valuable as the market diversifies. Electric utilities 

have a pronounced competitive edge in providing increasingly important products such as energy portfolio management, risk mitigation, and efficient energy service. Because it 

manages one of the region's most important economic and environmental assets, Bonneville has an especially crucial role in maximizing the value of those assets to the 

region as a whole- a role that no other existing entity or combination of entities can play. 

• BPA is wise to get in front of industry changes. but it should not panic. 

BPA remains, by a significant margin, the lowest cost wholesale power supplier in the 

West. Competitive challenges are real, but BPA is not in imminent danger of massive load 

2 
64 

loss. BPA can and should reduce costs in many areas where it is now either inefficient or where it is incurring large costs that are not directly related to its core mission, as defined in 

the purposes of the Regional Act It can do this deliberately and soberly, without reducing 

conservation investments. The earth is not flat, but the sky is not falling. 

11 Reinvention 11 insiehts 

We start from somewhat different premises, but we applaud some of the key insights of 

BPA's conservation "reinvention" effort 

·Long-term conservation success requires local initiative. Energy efficiency 

efforts must respond not only to regional needs, but to the challenges and opportunities of 

local communities and the utilities that serve them. Without sacrificing regional 

conservation performance, local utilities should have greater discretion to implement 

efficiency efforts in the manner that responds best to unique local circumstances. And 

while the region should encourage creative adaptations to local needs, local utilities should 

accept responsibility for delivering the regionally cost-effective conservation that is 

available in their service territories. As a region, we need to be fiTlTlly accountable -- not to some arbitrary outside authority, but to each other- for the wise management of our most 

valuable collective asset: the Columbia River System. 

• Real and perceived inequities in the distribution of conservation 

expenditures need to be addressed. We note that, compared to other resource acquisition payments, conservation payments are distributed ~ evenly throughout 

the region. We would not expect those payments to be distributed perfectly evenly unless the~ were distributed perfectly evenly. Nevertheless, with the introduction of tiered 

rates, we should reexamine the distribution of conservation funding, both among retail 

utilities and between retail utilities and BPA. 

• BPA and its customers can and should reduce conservation overhead BPA 

and the region's utilities are presently delivering conservation cost-effectively, but we can 

do better. Efficiency programs are still saddled with some unnecessary costs and 

administrative burdens. Some overhead is of course necessary to ensure solid evaluation 

and performance. But duplication, second-guessing, and overprocessing can be 

significantly reduced. 

• We should focus on uerformance and reward it. Our ability to manage the 

Columbia River System autonomously and keep its benefits in the region depends on our performance in managing the system prudently and efficiently. Therefore, distribution of 

the system's benefits ~ the region should be at least in part performance-based rather 

than entirely entitlement-based. 

3 
65 

From here to there: steps toward improved conservation 

performance 

Starting from somewhat different premises and sharing many of the same goals, we would 

like to sketch out some of the features of an improved approach to regional conservation. 

Our intent is to preserve the best of what we have built over the last decade, while 

incorporating some of the key insights of BPA's conservation "reinvention." Again, these 

features assume that we are better off building on success rather than starting over. 

1) Adjust conservation cost-sharing to more closely reflect utilities' resource needs and reliance on BPA. This will address equity concerns and adjust 

for growth while more closely approximating actual costs and benefits of conservation for 

the regional system. 

2) Increase retail utilities' proportion of overall conservation investment 

relative to BPA's to reflect the increased local value of conservation in a 

tiered rates environment. Do not diminish aggregate conservation 

investment as long as cost-effective conservation opportunities remain. 

This preserves BPA's indispensable role as the primary regional conservation investor, 

while bringing more of the costs and rewards to the local level. Safeguards will be 

necessary to ensure that aggregate conservation investment is sufficient to capture all costeffective savings. 

3) Reduce the total cost of energy efficiency programs by capitalizing on the customers' access to favorable tax-exempt financing. Third party financing 

agreements- in which BPA backs locally-issued debt- have been successfully pioneered 

by a few utilities. These agreements reduce pressure on BPA's financial relationship with 

the federal government and reduce the cost of conservation by lowering financing costs. 

This approach should be used more widely. 

4) Reduce the unit cost of saved energy and ensure that conservation 

targets do not become caps by preserving the budget flexibility to take 

advantage of unanticipated opportunities between rate cases. While exceeding 

annual targets, the region missed significant opportunities to capture cost-effective 

conservation this year due to budget constraints. The cost per unit of saved energy can be 

reduced significantly by ensuring that fully operational programs reach all willing 

participants. Reducing backlogs and reducing the waiting period for successful programs 

will lower unit costs by allowing fixed costs to be spread over a larger number of kilowatt 

hours and by encouraging greater participation. 

5) Continue the trend toward providing increased local flexibility in 

program implementation. Energy Smart Design is a good working example of a regional program that offers enormous local discretion in implementation. We should 

continue to investigate approaches in which the utility delivers an agreed-upon quantity of 

savings and is free to achieve that level with maximum local discretion. 

6) Forge a clear, contractual link between efficiency performance and 

allocation of FBS benefits to wholesale customers. Current tiered rates 

proposals allocate FBS benefits exclusively on an entitlement basis. However, our ability 

to control the benefits of the regional system will be based on our collective performance, 

and the size of those benefits is in part a function of efficiency achievement. Therefore, our allocation of those benefits should be based, at least in part, on customers' indeoendently 

evaluated efficiency performance. BPA has a statutory responsibility to achieve regional 

4 
66 

conservation goals, but the implementing agencies must share that responsibility. To 

maximize the total value of the system to the region, a significant portion of its value should 

be reserved for allocation to those customers who enhance the system's value by delivering 

saved energy. 

7) Develop and implement an ambitious market transformation program that 

uses BPA's formidable market leverage to institutionalize efficiency in 

technology development, construction practices, building operations, and 

industrial processes. BPA has appropriately recognized its ability to "push" efficient 

products through the distribution chain, as well as "pull" them through from the end-user. 

The full range of methods to capture efficiencies at lower cost by intervening earlier in the 

research, development, production and distribution phases should be employed. This 

should both el''land the total conservation resource (by bringing in measures that would not 

have been cost-effective if they had been acquired through end-use incentives), and lower 

the cost of acquiring the resource overall (by intervening earlier, when smaller investments 

can have a bigger impact). 

8) Identify and remove barriers that constrain BPA's ability to reap the full 

market value of its efficiency investments on behalf of the region's 

consumers. Lost revenue remains one of the principal deterrents to utility-sponsored 

energy efficiency initiatives. BPA's formidable marketing advantages should allow it to 

offset lost revenue by marketing saved energy at or near its full market value. Legal and 

institutional barriers to such marketing should be re-examined and, if possible, removed. 

Bonneville's capacity to eliminate or substantially mitigate lost revenue impacts is vastly 

superior to that of its customers. 

We offer this alternative approach in the spirit of regional cooperation, a spirit that has 

enabled us to deliver impressive energy efficiency results in recent years. We offer it with 

a keen recognition that the industry is changing rapidly and in ways that challenge us to 

improve conservation delivery systems. 

However, we are also deeply concerned about the rapid erosion of a conservation 

infrastructure that took a decade to build and delivered admirable results last year. This 

infrastructure has already begun to contract significantly, because of a widespread 

perception that BPA's "reinvention" will entail significant and rapid net reductions in 

energy efficiency investment. Virtually all of the energy service leaders in the private sector 

have significantly reduced their workforces or left the region altogether in the last year. 

Only a year ago, the Regional Conservation Acquisition Task Force and others were 

working feverishly to ensure that private firms and educational institutions would quickly 

develop a qualified work force to meet the healthy demand for energy efficiency services. 

One of the principal obstacles to that effort was the perception that utility investment 

commitments are unreliable, and that BPA could suddenly ramp down its programs, as it 

did in 1984. Now, BPA is proposing to do just that. Ironically, Bonneville also proposes 

to pick up much of the slack by developing its own energy service marketing apparatus. 

That apparatus exists now in the private sector. BPA should utilize it, not supplant it. 

We remain eager to explore even better ways of delivering the enormous benefits of energy 

efficiency to Northwest consumers. But we believe firmly that a credible effort to do a 

better job begins from a strong appreciation of how much we have accomplished, as well 

as a keen awareness of how much remains to be done. 

5 
67 

Mr. DEFAZIO. Mr. Canon. 

STATEMENT OF KEN CANON 

Mr. CANON. Thank you, Mr. Chainnan, Mr. Smith. I represent 

a group called the Association of Public Agency Customers. It is a 

group of large industries that buy their full requirements essentially from public agencies. 

I guess our view is that competition does exist for Bonneville, regardless of the current number, as far as rates. I think the question is of a competitive Bonneville future. 

We believe that utility customers aren't waiting for Bonneville 

potentially to become uncompetitive. I know that my industrial 

members certainly aren't waiting. They are moving to diversify, 

and we expect that to happen and continue to put pressure on Bonneville, as well. 

For many, Bonneville's uncertainties are viewed as larger or at 

least equal to new resource uncertainties, those new resource uncertainties being mostly gas costs and supply. Those are issues that 

industries are very familiar with, and utilities are becoming more 

familiar with, and they feel like they can deal with those contractually. 

We believe that Bonneville is properly concerned about loss of 

revenues and the ability to fund their responsibilities into the future. Our analysis shows that Bonneville is likely to become in the 

realm of uncompetitive by the end of this decade. What that 

shows-again, our rate analysis shows a series of double-digit rate 

increases facing Bonneville if it continues on the status quo. 

Obviously, Bonneville has undertaken a number of steps--cutting costs, unbundling products and services, transmission access, 

program retooling and tiered rates; we support some of those. I 

think for many of them it is much too early to tell. 

We do have a number of concerns. First of all is adequate information and evaluation, as we go through this process, making sure 

that we have the time to respond to that. We are mindful of Bonneville's schedule and are willing to work within that schedule, but 

I think it behooves everyone to make sure that there are no surprises; and we need to be better in asking Bonneville-making our 

requests to Bonneville on information. 

Bonneville needs to be very good about responding. We want to 

see real, overall cost improvements, not just a shift of costs from 

Bonneville to the utilities or from the DSis to the utilities. I think 

the measure that we are looking at is Bonneville's costs plus utilities costs are lower than what you would imagine a Bonneville status quo cost to be. And unbundled products and services, as mentioned earlier, I think that there will be a number of my member 

industrial customers who are interested in potentially offering reserves to Bonneville, as well as the DSis and the utilities. 

I think fundamentally, as we go through this process, the question is a question of Bonneville's continued role in the region and 

whether or not this region is in fact a region anymore. Regardless 

of the assumptions that went into the regional act, it seems it is 

going to be a great challenge for all of us to determine whether, 

as we go through this process, we don't actually set up a situation 
68 

which pits one group against another group in a way that literally 

tears the region apart. 

We do give credit to Bonneville, a large Federal agency, for recognizing that its position today does not guarantee its future and 

for taking bold steps, both internally and externally, to improve its 

chances in the future. We certainly don't agree with everything in 

the business plan, and we will have many intense discussions with 

all of the parties sitting here at the table today on these subjects. 

However, now that we have a draft business plan, we at least have 

a target to shoot at, and we believe it as an important first step. 

Thank you. 

Mr. DEFAZIO. I thank the gentleman. 

[Prepared statement of Mr. Canon follows:] 
Managing Director 

Ken Canon 

69 

Association of Public Agency Customers 700 N.E. Multnomah, Suite 1000 

Portland, Oregon 97232 

(503) 239-9169 

Testimony of Ken Canon, Managing Director of the 

Association of Public Agency Customers 

To 

The Subcommittee on oversight and Investigation of the 

House Committee on Natural Resources 

August 9, 1994 

The Association of Public Agency Customers (APAC) is a group 

of large Northwest industries who purchase electric energy from 

Northwest public agencies (municipals, rural electric 

cooperatives, and public or peoples utility districts). Since its 

formation in 1981, APAC has represented its membership in every 

BPA rate proceeding. APAC was formed out of the recognition that 

BPA rates have a profound impact on the rates charged by the 

local public agency. APAC's industrial members need an adequate, 

reliable and competitive power supply in order to survive in an increasingly competitive global economy. 

The Regional Act was based on the assumption that BPA would 

operate as the center of a coordinated, regional power system. 

Events since the passage of the Regional Act have forced BPA and 

the region to question that assumption. Changes in technology, 

institutional relationships, business organization, and future 

assumptions have combined to place BPA's centralized role at risk. Without significant changes, BPA is likely to become just one of many participants in a vastly more open and fluid regional 

power system. BPA's new role may be focused more on coordination 

through its operation of the regional high voltage transmission 

grid, rather than its current position as a primary funding 

source. If, however, BPA is to continue as the central focus of 

regional electric energy policy and activity, it must be strive to improve its competitive position. 

Achievement of the purposes of the Regional Act (cost 

effective resource development) is closely intertwined with the 

need for BPA to keep rates - both short term and long term - at competitive levels. As a high fixed cost utility system, BPA 

risks losing more than it might gain by raising rates in the 

short term on the promise of lower rates in some distant future. 

The challenge facing BPA is to strike an acceptable balance. 
70 

Load loss only serves to deprive BPA of the very revenues needed 

to fund its responsibilities. 

We are concerned that BPA is on a path that will place it 

(and those that rely on it) in an uncompetitive position in the 

near future. Two countervailing factors support this concern. First, under the status quo, BPA is projected to need a series o f 

double digit rate increases in orde r to meet an increasing 

revenue requirement. Second, other utilities and independent 

power producers are aggressively moving forward to lower costs and limit rate increases. Our view is that the competitive 

crossover point for BPA will occur near the end of this decade. 

However, APAC members, andj or the utilities that serve them, are not waiting for this to occur. They are actively exploring means 

to reduce their reliance on BPA through their own resource 

acquisitions or through power purchase arrangements. 

Establishing a more diverse power supply is viewed as a prudent 

option given the challenges facing BPA. At the same time, we are 

working closely with our utilities, BPA and others in an effort 

to help transform BPA into a competitive, customer-responsive 

organization. 

In its draft Business Plan, BPA seeks to address its 

competitive position by designing a tiered wholesale rate 

structure, by unbundling its products and services and by 

reinventing conservation and fish and wildlife programs. In 

addition, BPA is restructuring its workforce in order to be more market and customer oriented. We support BPA's intent to 

unbundle its products and services, to provide greater 

transmission access, to seek more cost effective means to acquire 

conservation and to achieve more measurable results from its 

considerable fish and wildlife annual investments. However, we 

are not convinced that tiered rates are necessary to achieve 

these laudable goals. We are concerned that tiered rates as 

proposed in BPA's draft Business Plan only formalize the split 

between BPA customers that are expecting growth and those that 

are expecting little or no growth. This may have unintended 

negative consequences for future regional action. Regional 

action is not aided by a system that pits growing public agency customers versus nan growing public agency customers and Direct ~ 

Service Industries in an ongoing regional battle over the ~ 

diminishing capability of the Columbia River hydro power system. 

We have only begun to understand the nuances involved in 

establishing a workable and fair tiered rate system. We believe 

that it is much too early to either endorse or oppose a tiered 

rate structure. The question that we continue to try to sort out 

is, "How are we better off with a tiered rate system as compared to some other non status quo system?" That determination can 

only be made following a much clearer definition of what a tiered 

rate system actually involves, how it specifically affects the 

2 
71 

different customer groups, and whether it actually provides a 

more competitive electric utility system as opposed to simply 

shifting costs from BPA to its utility customers. 

Never the less, we do have two concerns regarding tiered rates as proposed by BPA. The first regards the treatment of the 

Direct Service Industries. We understand the competitive plight 

confronting the DSis. We face the same competitive pressures but 

without the safety net of a rate that varies with the price of 

the commodities produced by the APAC membership. High load 

factor industries (whether DSis or APAC members) provide real 

benefits to the efficient u se of a power system. However, any 

tiered rate proposal adopted by BPA must treat the DSis in the manner contemplated under the Regional Act. Even though there 

are limits to DSI growth, the DSis (in exchange for long term 

contracts) committed to paying for a share of BPA's load growth. 

This commitment must be reflected in any tiered rate system 

adopted by BPA. In addition, it must be recognized that the DSis 

are not the only industries in the region that may be willing to 

provide reserves for the power system. An examination of the 

need for reserves, the options to provide the reserves and the 

pricing of reserves may reveal other entities willing to provide 

reserves at a competitive price. 

our other concern with the tiered rate proposal involves the 

treatment of industries that have "Contracted For, Committed To" 

(CFCT) amounts under the New Large Single Load (NLSL) provisions 

of the Regional Act. In the Regional Act, only one tiered rate provision was adopted, the New Large Single Load provision. This 

growth penalty could be avoided if the industry could demonstrate 

that it had a contract or commitment from its utility for an 

amount of power in excess of its current usage. A number of 

industries in the region have documented their CFCT amounts and 

their utilities have entered those as an exhibit to their Power 

Sales contract. We believe that BPA must continue to recognize 

these CFCT amounts in any Tier 1 allocation. 

Answer to the specific questions posed by the Subcommittee : 

Questions 1. 2 and 3 

over the past decade BPA's competitive position has eroded 

sharply due to other competitive power supply options and BPA's 

own cost pressures. we continue to support BPA's efforts to gain 

Government Corporation status as one means to implement greater 

internal efficiencies. However, assumptions of ever-increasing 

fish, wildlife and other nonrevenue producing investments, 

continued internal cost increases, uncertainty caused by BPA's 

political nature and significant customer dissatisfaction are leading BPA's customers to examine other resource options. 

If BPA were to continue the status quo, we believe they will 

3 
72 

become uncompetitive by the end of the decade. However, BPA's 

customers will not wait to take alternative actions. If BPA is 

unable to convince its customers in the next several years that 

it can significantly change the way it does business, then BPA 

could face the beginning of a death spiral . Even moderate load 

loss could impact BPA's financial viability. Significant BPA 

change would include controlling its c osts, limiting the scope of 

its activities to those that are at the core of its business and 

those that it does best, and utilizing the flexibility of the 

hydro sys tem in partnership with its customers in order to 

provide resources economically. 

Question 4. 

It is much too early to determine the effectiveness of BPA's 

attempt to restructure its operations in an effort to be more 

customer oriented. However, we certainly support BPA's efforts. 

Recognition of the "hassle factor" problem is an important first 

step in c orrecting the problem. 

Question 5. 

Unde r the tiered rates struc ture propos ed in BPA's draft 

Busine ss Plan, it appears that approximately $200 million to $300 

million in costs will be shifted to preference customers. These 

costs will be shifted from the DSis, from a residential exchange 

buyout on the order of $200 million a year and from contracts 

that have rates based on BPA's Average System Costs. These cost 

shifts c ome primarily from shifted responsibilities for resource 

deve lopme nt and the loss of the DSI top-quartile market. 

Question 6. 

We believe that most utilities, and certainly the larger 

ones, will continue conservation efforts with or without tiered 

rates. Tiered rates may reduce some efforts at some of the 

slower growing utilities. Freed of the limitations and 

requirements imposed with many BPA conservation programs, we believe that utilities are in the best position to develop 

locale-specific conservation activities. To the extent utilities are investing their own customer funds, we believe they will be 

motivated to develop innovative means to achieve more 

conservation at a lower cost. 

Question 7. 

None at this time. To the extent that BPA proposes to act as a backstop from the very beginning of the conservation 

reinvention, what motivation would exist for utilities to go 

forward on their own? Just delay and the entire program would 

revert back to the existing status quo with all the utilities 

sending money to BPA, BPA processing the money and skimming off a 

4 
73 

not inconsequential amount for as overheads and program 

administration, and then disproportionately reallocating the 

remaining money back to the very utilities that sent it in 

originally. 

Question 8. 

No. 

Question 9. 

BFA and the region's utilities need to focus on treating 

conservation as a resource, not as a social program. As a 

resource, BFA and the region's utilities should have spent the 

past 13 years focused on acquiring the least costly, most 

effective conservation first. This would minimize rate impacts, 

reduce the need for new BFA Treasury borrowing authority, while 

still meeting the region's conservation goals. The same approach 

should be used now . 

Question 10. 

Based on what we have seen to date, we do not support this 

concept. The advantage of public power is local control over the 

local consumer owned utility. To agree to this principle could 

possibly mean removing much of a utility's discretion to respond 

to unique local needs and situations. It would also mean 

assuming that all utilities would act in bad faith and therefore 

all need an affirmative requirement in their power sales 

contracts. We are unwilling to make that assumption. our 

reaction to this principle is highly depenctent on the specifics 

of the proposal. 

Question 11. 

Renewable resources will continue to compete with natural 

gas-fired resources. BFA's unbundling of products and services, 

and greater transmission access could allow more utilities to 

diversify their resource portfolio through the integration of 

renewable resources. 

Question 12 

Establish the DSI price equal to what an all-requirements 

industrial customer would pay by adjusting the weights of the 

DSI's Tier 1 and Tier 2 prices to accomplish that goal. 

Question 14 

BFA has recently revised its schedule to accommodate a 

greater focus on the power sales contracts to initiate this 

process. The customers must be more e~plicit regarding their 

5 
74 

specific information and data needs and BPA must be more 

responsive to developing this information in a timely fashion. 

BPA cannot keep the endpoint of its schedule fixed while pushing 

back the front end of the schedule. Each BPA customer must go 

into the tiered rates process with their eyes open regarding the 

specific financial impacts of each proposal. We are concerned 

that the current schedule compresses the process, but we are 

willing to try to work within these constraints. 

Question 15 

The DSI's load pattern is beneficial to the power system. 

So, also, are the loads of some retail customers in the region. 

Opportunities extended to the DSis in recognition of their 

beneficial load patterns should also be offered to other retail 

customers that can provide the same beneficial load patterns. 

Question 16 

Congress should make no changes to regional preference. 

6 
75 

Mr. DEFAZIO. I notice a couple of reople are standing in the 

back. The committee has no objection i they want to take a couple 

of the seats over here at the end of the dais. But if they like standing, they can do that, too. I thought this was interesting enough 

that you could sit down and stay awake, but maybe other people 

don't, so-yes, I know. 

I am wondering when-the House has just gone out. Just listening to the bells. 

Okay, Mr. Wilcox is next. 

STATEMENT OF BRETI' WILCOX 

Mr. WILCOX. Thank you. I am Brett Wilcox, President of Northwest Aluminum Company in The Dalles. With me is Ken Peterson, 

CEO of Columbia Aluminum Corporation. 

Bonneville faces a real and immediate challenge. This problem is 

both cyclical and structural. BPA is going through a cycle when its 

own costs have risen dramatically and may make it uncompetitive 

unless future increases are controlled. 

In contrast, BPA's competitors, especially gas-fired generators, 

face historically low fuel and other costs. While BPA's still have 

some cost advantage, it clearly would be imprudent to bet the agency on the hope that BPA's costs will come down and that natural 

gas prices will go up. It is essential that BPA take action now so 

it can remain competitive, regardless of uncontrollable future cycles. 

It would be a mistake for anyone to believe that BPA's problem 

is just cyclically low natural gas prices. The fundamental problem 

is the way BPA's business is structured. BPA's historic practice of 

selling highly bundled power products has resulted in many customers paying for services they do not use, while other customers 

pay less than the cost they impose on the system. 

For example, bundled rates give customers an artificial incentive 

to develop their own combustion turbines because they can operate 

their own resources at minimum cost and shift the costly shaping 

and load falling services to BPA. The current structure places BPA 

at the inherent disadvantage of providing an entire fruit basket of 

services while competitors just have to provide basic apples. The 

proposed business plan fosters apples-to-apples competition. 

A second structural problem is BPA's ability to respond to rapidly changing markets as quickly and economically as its competitors. BPA simply cannot afford to be outmaneuvered by competitors 

who are more and more market focussed and customer oriented. 

The proposed business plan streamlines BPA and reduces the 

hassle factor dealing with the government bureaucracy. While the 

draft business plan provides a good map, it can only be implemented through into contracts and rates. We support BPA's ambitious but necessary schedule which was announced today to resolve 

these issues by October, 1995. These contract and rate issues can 

and should be resolved by compromise within the region. None of 

these issues requires a change in Bonneville's existing statutory 

guidance. 

One key issue is conservation reinvention. We support tiered 

rates because price signals can be a more effective and economical 

way to meet the region's conservation goals than bureaucratic pro-
76 

grams and cash incentives. Contrary to some claims, BPA is not 

risking regional conservation goals by trying an unproven approach. BPA will maintain its strong conservation effort but replace grants with loans recovered through energy service charges. 

This approach follows the proven and highly successful energy finance conservation program pioneered by Pacific Power. 

The last issue I want to put to rest is the assertion that the DSis 

are subsidized through the value reserve credit and valuable reserve rate. Neither is a subsidy. Both hold down other customers' 

rates. I would personally support your idea to seek reserves from 

anyone through competitive bids. 

BPA enjoys substantial rights to restrict service to the DSis 

when necessary to protect service to its other firm power customers 

in the region. These rights range from stability reserves, which 

allow BPA to interrupt 100 percent of the load for brief periods, to 

top quartile reserves under which BPA restricted 25 percent of 

each DSI load almost continuously over the last two years, principally to avoid purchasing high-cost energy. While DSI rates are 

adjusted, provides some compensation for these restrictional rights, 

bottom line, BPA charges the DSis higher rates for interruptable service than it charges utilities for firm service. In my book, that 

is not a subsidy. 

The variable rate paid by BPA's aluminum smelters links the 

power cost to the price of aluminum. If prices fall, the rate is discounted, but only to a point that is still above the price BPA can 

obtain in other markets. If aluminum prices rise, smelters pay a 

premium. 

The claim by NCAC that variable rates could cost regional ratepayers more than $300 million is just plain wrong. BPA has calculated that as of March, the variable rate has improved revenues 

by $52 million. The DSis estimate that over its entire life, the rate 

will add about $50 million to BPA's revenues. My written testimony contains a more detailed explanation of these and other issues. 

Thank you for the opportunity to testify and respond. 

Mr. DEFAZIO. Thank you, gentlemen. 

[Prepared statement of Messrs. Wilcox and Peterson follow:] 
77 

TESTIMONY OF BRETT WILCOX 

PRESIDENT OF 

NORTHWEST ALUMINUM COMPANY 

BEFORE THE HOUSE NATURAL RESOURCES COMMIITEE 

My name is Brett Wilcox. I am the President of Northwest Aluminum Company, 

located in The Dalles, Oregon, which is a direct service customer of the Bonneville Power 

Administration. My company, and my employees, want BPA to remain a competitive 

supplier of power. For this reason, Northwest Aluminum and BPA's other direct service 

industrial customers support the proposal in BPA's Strategic Business Plan to restructure and 

streamline its business so it can meet the challenges of the new competitive marketplace for 

electricity. The electric power business is undergoing rapid and accelerating change towards 

increased competition, particularly in the wholesale power and transmission markets. BPA 

must be allowed to respond to this new competitive market if it is to maintain its position as 

the power supplier of choice in the Pacific Northwest. 

Today I would like to malce several important points in response to your Task Force's 

Report. 

First, BPA does not need two years to reposition itself in the market, nor does it have 

the luxury. Competitive forces are driving BPA's customers into the arms of competitors 

even as we convene here. 

Second, utilities are prepared and motivated to pursue conservation vigorously under 

tiered rates -- and without BPA's heavy overhead costs. 

Third, the DSis should be treated no differently under new contracts and rates than 

other customer groups, as provided by the Northwest Power Act. 

Fourth, the Task Force's Report concludes erroneously that the DSis enjoy subsidies. 

To the contrary, the DSis are paying more than the costs of serving them, and I'll explain 

how. 

Fifth, the Variable Rate is one of the most successful sales implements ever adopted 

by BPA. It has produced great benefits for BPA and its customers, and has been emulated by 

other utilities that serve such loads elsewhere. 

And finally, I will address the real subsidies in BPA's rates and explain why disposing 

of Regional Preference is a bad idea and, in any case, futile. 

0027046.01 
78 

The Competitive Environment 

I have closely followed, and participated in, the development of BPA's Strategic 

Marketing Plan and its Strategic Business Plan. BPA accurately identifies many of the factors 

which have created a more competitive market for electricity, including open transmission 

access, the falling cost of gas fired generation, increases in BPA's costs and uncertainty about 

future increases in these costs, and the large number of well-financed new entrants into 

wholesale power generation markets. 

All of these factors have eroded the competitive advantage that BPA enjoyed for 

decades due to its low-cost federal hydropower base. In my judgment, however, none of 

these factors represents the single largest threat to BPA's ability to perform in the 

marketplace. The federal hydro system is still capable of producing low cost energy products 

which customers will need as power markets evolve. 

The real threat to BPA lies in potential barriers, imposed from outside the marketplace, 

on BPA's ability to respond to the market by changing as quickly and economically as its 

competitors. BPA's historic cost advantage over alternative suppliers has been significantly 

reduced such that BPA has little, if any, margin for error. If BPA's competitors react more 

quickly to occupy product niches which are opened as markets evolve and to move out of 

product niches that become unprofitable, then BPA will steadily loose market share. As a 

utility with fixed costs making up most of its total costs, BPA cannot afford to be 

outmaneuvered systematically by more market-responsive competitors. Therefore, BPA must 

have the capability to change rapidly in response to market forces. 

Northwest Aluminum supports BPA's Business Plan because it represents reasonabl e 

change where change is clearly needed. Without these changes, the inexorable upward 

pressure on BPA's overall costs, and its customers' perception that this pressure will continue, 

would seriously impair BPA's competitive position. In the eyes of its customers, BPA's 

Business Plan is an important first step to address and slow these pressures. Further, 

implementation of the Business Plan will streamline BPA and by more clearly defining 

responsibilities will reduce the bureaucratic "hassle factor" that has characterized BPA's past. 

The Business Plan must be implemented without delay because the competitive pressures 

BP A faces are real, and delay in reacting to them would, in itself, send BPA's customers a 

signal that BPA has become an inflexible and unreliable supplier in a changing market 

I recognize that BPA has unique responsibilities arising from its use of the Columbia 

River System and its status as a federal agency. But the fulfillment of these public 

responsibilities depends on BPA's ability to meet the basic commercial needs of its customers. 

If BPA fails in that enterprise, then there will be no funds for the discharge of its public 

responsibilities. 

2 002JQ46 0 \ 
79 

Contracts and Rates 

Many of BPA's initiatives will require new contracts with its customers and revised 

rates. BPA recognizes that timing is the key issue to the success of its Business Plan and 

proposes an ambitious, but necessary, schedule to address and resolve these contract and rate 

issues by October 1995. I also believe that the success of BPA's Business Plan requires that 

this deadline be met. 

These contract and rate issues can and should be resolved by negotiation and 

compromise within the region. A regional solution will balance the many interests affected 

by BPA and it will be sufficiently flexible to allow for future changes as they are needed. 

None of the outstanding issues requires any additional statutory guidance for BPA. Excessive 

Congressional oversight could detract from the ability and willingness of regional parties to 

act in a timely fashion. Instead of compromising their differences through good faith 

negotiations in the region, parties would be encouraged continually to return to Washington 

for political solutions to their business problems. BPA must be free to pursue market-based 

solutions to market problems. BPA cannot possibly respond to rapidly changing market 

conditions if it must negotiate with its customers and potential competitors before Congress. 

Tiered Rates 

BPA has identified the adoption of tiered rates as a key element in reinventing 

conservation. In fact, the initial impetus for tiered rates came from the conservation 

community. I support tiered rates because the price signals provided by tiered rates can be 

effective and economical means to reach the region's conservation goals when coupled with 

strong utility support for achieving all cost effective conservation. I do not agree that tiered 

rates should be coupled with continued cash incentives to utilities sponsoring conservation. 

One important reason for substituting tiered rates for cash incentives is the high cost and 

hassle factor inherent in policing the use of incentives. Tiered rates allow customers to reap 

directly, through lower power bills from BPA, the rewards of conservation without the 

bureaucratic overlay of the current system. 

I will not propose any alternatives for the implementation of BPA's tiered rate 

principles because those changes are currently being worked out among interested parties in 

the region in BPA's tiered rates workshops. I expect a consensus to develop in that process. 

I do not expect the consensus proposal to treat the DSis any differently than other BPA 

customer groups. The DSis should have the same incentives to conserve as other customers 

and should not suffer discrimination regarding the adequacy of their power supply. 

The DSis Are Not Subsidized by Other Customers 

The Task Force's Report contends that the DSis are subsidized by other customers due 

to the value of reserve (VOR) credit in their Industrial Power rate and due to the Variable 

Rate for aluminum smelters. Neither of these provisions is a subsidy -- to the contrary, both 

provisions benefit BPA's customers generally and serve to hold down other customers' rates 

002704601 
80 

The BPA rates .applicable to the DSis, including the VOR credit and the VI rate, recover the 

full cost of serving the DSis' loads. 

VOR Credit. BPA enjoys substantial contractual rights to restrict service to the DSis 

when necessary to protect service to its other firm power customers in the region. These 

restriction rights range from the "stability reserves" by which BPA can interrupt up to I 00% 

of a DSI's load for brief periods in the event of equipment outages (~. several DSis were 

restricted this spring when the L.A. earthquake disrupted transmission of power sales from 

California to the Northwest), to top quartile restrictions which BPA has used for economic 

reasons (Uu BPA has restricted 25% of each DSI's load almost continuously since August 

1992 for economic reasons while it is purchasing to serve its other firm loads). Even though 

the DSis' rates are adjusted to provide some compensation to the DSis for these interruption 

rights, BPA charges the DSis higher rates for interruptible service than it charges utilities for 

firm service. In my book, that is not a subsidy. 

The VOR credit is part of a comprehensive rate package known as the Industrial 

Power ("IP") - Priority Firm ("PF") Rate Link. This link was established in 1987, based on 

BPA's 1985 rate case results, to quantify the net of adjustments required under the Regional 

Act to BPA's PF rate to derive the IP rate. The individual adjustments are a "typical retail 

margin," a "character of service adjustment" for top quartile interruptions, and the VOR 

credit. The sum of these adjustments produced a surcharge of approximately 1. 5% to be 

added to the firm power rate applicable to BP A's public utility customers to develop the DS!s' 

interruptible power rate. After the 1985 rate case, parties requested BPA to extend the 1985 

methodology through 1990, and later through 1996. BPA adopted the link after expressly 

finding that the link would in aggregate track the net of the individual components if they 

were recalculated in each future rate case. The Federal Energy Regulatory Commission 

approved the methodology twice. The link has been used by BPA in each subsequent rate 

case by escalating the 1985 net mark-up by the rate of inflation. 

NCAC now argues that one element of the link -- the portion of the VOR credit 

associated with forced outage reserves -- would be substantially lower if it were recalculated 

today . NCAC is mistaken about the amount of the VOR credit. The VOR forced outage 

component of the VOR credtt compensates the DS!s for the value of certain contractual 

restriction rights that were negotiated in 1981. By virtue of BPA's forced outage restriction 

rights, BPA was able to avoid in 1981 purchasing over 1200 megawatts of combustion 

turbines to back up its system. The primary savings to BPA was the carrying costs on long 

term debt BPA would have had to incur in 1981 to acquire the turbines. Therefore, it was 

appropriate for BPA to base the VOR credit on those savings. The DSis receive only onehalf of the savings and BPA's other customers receive the remaining savings through lower 

rates. Moreover, NCAC is simply incorrect about the amount of reserves the DSis prov1de. 

BPA negotiated the amount and duration of its rights to restrict 1600 megawatts of DSI load 

to provide the 1288 megawatts of capacity reserves it concluded were needed to back up all 

of BP A's operating resources. 

4 002704601 
81 

NCAC is also incorrect about the effect of recalculation of the VOR credit, which 

would require r'epeal of the comprehensive IP-PF Link. Most elements of the IP-PF Link 

would be more favorable to the DSis if recalculated today 14fed on current circumstances. 

First, the VOR credit gave the DS!s only token compensation for stability reserves, which are 

provided by an automatic load shedding device at DSI plants, and which save BPA hundreds 

of millions of dollars in transmission system upgrades that BPA would otherwise need to 

obtain the same level of transmission reliability. Second, the character of service adjustment 

for top quartile restrictions was based on conditions in 1986 and 1987 during which BPA's 

surplus of firm power made top quartile restriction highly improbable. If applied to the 

current deficit condition, the downward adjustment to the DSI rates would be twice as large. 

Finally, by escalating the net mark-up, the IP-PF Link overstates the actual increases in retail 

margins. If all elements of the IP-PF Link were recalculated using the 1985 methodology, I 

would expect the DSis' rate to be reduced by a modest amount. NCAC's anempt to criticize a 

single component of the link in isolation is self-serving and inappropriate. 

The Variable Rate. The Variable Industrial ("VI") rate paid by BPA's aluminum 

smelter customers links the DS!s' power cost to the worldwide price of aluminum. BPA 

adopted this rate in 1986 to enhance its overall net revenues and thereby keep rates to other 

customers lower than they would be without the VI rate. If aluminum prices fall, the 

smelters' power price is discounted; but even the low end of the VI rate is designed to remain 

above the price BPA could obtain for the power in other markets or the value of reducing 

BPA's power purchases. When aluminum prices rise, the smelters pay a premium on their 

power price and BPA gets more revenues from sales to the DSis than it would at the standard 

IP rate. As a secondary goal, BPA designed the VI rate to produce an average rate equal to 

the IP rate, if possible. 

The claim by NCAC that the VI rate "could cost regional ratepayellll more than 

$300 million by June 1996" is just wrong. This number represents the difference between 

charging the DSis the IP rate and the VI rate for the same amount of power over a I 0-year 

period assuming that aluminum prices had stayed at extremely depressed levels for the 

remainder of that period. The very reason BPA adopted the VI rate was its well-supported 

conclusion that the DSis would ll21 buy the same amount of power at the IP rate when 

aluminum prices were depressed. With the VI rate, the DS!s will buy ~ power, at prices 

above what BPA <:ould otherwise sell the power for, and this extra revenue is the benefit of 

the VI rate to BP A and its other customers. 

In March 1994, BPA calculated that, as of that time, the VI rate had improved BPA's 

overall revenues by $52 million. The DS!s estimate that, o.ver its life, the VI rate will add 

about $SO million to BPA's revenues. Our estimate uses BPA's method of comparing its 

overall revenues with and without the Variable Rate, and it uses more current aluminum 

prices than were available to BPA in March. In retrospect, the VI rate has operated as 

planned to benefit all of BPA's customers. The DS!s benefited from more stable operations. 

Other customers benefited from higher revenues. In fact, at the top of the aluminum price 

cycle, the VI rate allowed BPA to cancel one of its scheduled rate increases. 
82 

Cost Shifting Under The Business Plan 

Currently, costs and benefits of BPA's programs and products are not closely tracked 

by rates. BPA's historic practice of selling highly bundled power products has resulted in 

many customers paying for services they do not use while other customers pay less than the 

cost they impose on the system. This is the true cross-customer subsidy in BPA rates. As a 

result, SPA's prices are not competitive for some products while other products are overutilized because they are underpriced. 

The graph attached to my testimony illustrates this point. Natural flows and associated 

power generation capability of the Columbia River system are low in winter and very high in 

spring and early summer. Power needs of northwest utilities, in contrast, peak in winter and 

are low when water is abundant and power would naturally be produced. A very large part of 

SPA's costs were incurred to shift water and associated power from the time when it naturally 

occurs to when it is most needed. 

While SPA's current rates do differentiate somewhat between seasons and time of use, 

the "one size fits all" approach in SPA's current marketing program means that particular 

customers may pay more or less than the costs their loads impose upon the system. 

Unbundling of products in the new Marketing and Business Plans allows BPA to correct this 

problem. It also helps make SPA's marketing complementary to rather than in conflict with 

its expanded fish and wildlife responsibilities. 

BPA's current competitiveness problem in large part is caused by its current bundled 

rates. If a utility develops its own combustion turbine, for example, it can run its own 

resource at an extremely efficient 100% baseload operation to meet the cheapest to serve part 

of its load. This leaves BPA to provide the costly services above the line of the utility's own 

resources. 

Under the new Business Plan, BPA provides "baseload" power "below the line" 

(through each customer's share of Tier I power) and each customer is responsible for meeting 

variations in its own loads (through either their own resources or by buying unbundled or 

"rebundled" BPA power and services). This insures "apples-to-apples" competition rather 

than leaving BPA with an inherent competitive disadvantage because it delivers an entire fruit 

basket with each apple it sells. Unbundling will sh1ft costs towards those customers who 

place higher costs on BPA and away from customers that have been systematically 

overcharged for what they get from BPA. This movement to more cost-based rates and real 

competition is a positive and appropriate development. It is one of the reasons I think tt is 

important for BPA to implement the Business Plan by October 1995. 

Regional Preference 

The Task Force report suggests that BPA might be less vulnerable in a competitive 

power market if the Regional Preference Act were amended to facilitate power sales to 

California. I disagree. The only possible reason to amend the Regional Preference Act would 

6 0021046 0 1 
83 

be if the hydro .system were so badly mismanaged that BPA's rates forced the closure of much 

of the region's industry. Rather than planning for such failures, this Committee should 

encourage BPA's effort to change the way it does business to succeed in the competitive 

future. Moreover, the days when it was possible to sell bulk power to California at a profit 

appear to be gone; to the contrary, BPA's analysis shows that currently BPA can most 

economically meet its own resource needs through power imports. 

BPA's Strategic Business Plan is a reasonable blueprint to address very real and very 

pressing problems. I hope you can join to support prompt adoption of the plan and 

implementation of its rates and contract elements by October 1995. 

The assertions made by some parties that the DSis pay subsidized rates are incorrect. 

Rates to the DSis recover the cost of serving the DSis. Rather than criticize BPA's 

contractual restriction rights and the Variable Rate, customers should applaud them as creative 

and successful responses to market conditions and urge BPA to use similar creativity in the 

future. 

7 0027046 Ol 
84 

Hydro Resource Capability and Utility Loads 

Natural Streamflow 

Baseload Resource 

Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul 
85 

TESTIMONY OF KEN PETERSON, JR. 

CHIEF EXECUTIVE OFFICER OF 

COLUMBIA ALUMINUM CORPORATION 

BEFORE THE HOUSE NATURAL RESOURCES COMMITTEEAUGUST 9, 1994 

My name is Ken Peterson. I am the Chief Executive Officer of 

Columbia Aluminum Corporation. My company owns an aluminum 

smelter near Goldendale, Washington, which is a direct service 

customer of the Bonneville Power Administration (BPA). Columbia 

Aluminum Corporation is owned 30% by all of its employees through 

an Employee Stock Ownership Plan, and the remainder is owned 

mostly by myself as well as some other employees. In short, we are 

100% employee-owned. 

Like Mr. Wilcox, my co-owners and employees are deeply 

concerned about BPA remaining a competitive source of power into 

the future. We want this because we live and work in the great 

Pacific Northwest and we know that the aluminum industry is like 

the proverbial canary in a mine shaft. That is, our business is more 

sensitive than most to uncompetitive power rates. For example, we 

cannot switch to natural gas or fuel oil or coal as a substitute for 

electricity. We require electricity truly as a raw material, as many 

people learned in the BTU tax debate. Moreover, the cost of 

electricity can typically make up 30% of our total production costs. 

Therefore, problems will show up for our business as a kind of early 

warning system for more pervasive systemic problems. This helps to 

explain why my company is deeply concerned as we see BPA 

struggling to retain its relevance into the· 21st century. 

My objective today is to make two points: 

Number 1. This Task Force's May 1994 report entitled "BPA at a 

Crossroads" erroneously states at page 9 that "the low price the 

DSis pay for power [because of the variable rate] ... impose an 

economic cost on the region by increasing the electricity rates paid 

by all other BPA customers." 

Number 2. On the other hand, the Majority Staff Report's 

conclusion on page 12--"BPA should implement tiered wholesale 

power rates and offer certain unbundled services to better serve 

customer needi:""--is exactly correct and should be affirmed at every 

opportunity. 

Now let me address these points at more length. 
86 

I. The idea that the Variable Rate is some sort of regional 

subsidy to the aluminum industry is a myth. The Majority Staff has 

done a profound disservice to the region by repeating this falsehood. 

In fact, the direct opposite is true. That is, the Variable Rate is an 

outstanding example of a public policy which achieved its objectives 

pretty much exactly as planned. The Majority Staffs analysis of this 

issue was shallow and apparently substituted a simple, but wrong, 

answer for a more complex, but accurate, one. Let me explain. 

Apparently the Majority Staff simply took the actual amount of 

direct service energy sold pursuant to the Variable Rate from the 

time of its implementation, multiplied this by the relevant plateau 

rate (the otherwise "normal" rate) in effect over time and compared 

this to the actual revenue produced under the variable rate to date. 

Using this simplistic approach it is mathematically true that more 

money would be generated if that amount of power had been sold 

under the standard Industrial Rate. 

Unfortunately, this represents a completely static analysis of 

a policy whose purpose it was to change what behavior would 

otherwise be. It also completely disregards the present value of 

money which must be included in any comprehensive analysis. 

I can personally testify, however, to the effective use of this 

policy in influencing behavior. In 1987, after the Variable Rate had 

been implemented, Commonwealth Aluminum, the prior owner of the 

Goldendale smelter, completely shutdown the smelter and went out 

of the smelting business in North America. During the preceeding 

three months, and the succeeding six months, I along with many 

others worked very hard to buy this closed plant with the intention 

of restarting it. We negotiated an unprecedented labor contract with 

the United Steelworkers of America. We negotiated a multi-year 

sale of most of the output of the plant to a foreign company. We also 

worked with BPA on transferring the power contract. In spite of all 

these efforts I was unable to finance this multi-million dollar 

transaction with American bank capital. By mid-1987 aluminum 

prices were considerably stronger than at the end of 1986. 

Nonetheless, American banks refused to back the transaction 

because of a fear that prices would soften again. 

The consortium of foreign banks that eventually supported us 

were intensely interested in the Variable Rate and I remember BPA 

sent an employee to thoroughly brief them on how it worked. I can 

say categorically and unequivocally that without the Variable Rate 

we would have been unable to buy the smelter and restart it in 1987. 

Perhaps someone else could have come along in· 1988 or 1989, but 
87 

that would be shear speculation. The fact is that insofar as my 

smelter's power usage is concerned there would have been zero used 

during at least 1987 and 1988 but for the Variable Rate. 

I also want to emphasize that when the power contract was 

transferred to Columbia Aluminum Corporation in mid-1987 we were 

given the opportunity to choose either the Variable Rate of the 

standard Industrial Rate. We chose the Variable Rate even though we 

knew before one kilowatt-hour had been used that we would start 

off paying a higher rate than if we chose the standard rate. The 

downside potential was simply too great under the circumstances. 

know that my experience was similar to others' and taken together 

the Variable Rate was a key element in returning or maintaining 

literally thousands of jobs in the Pacific Northwest. But it also 

provided BPA with millions of dollars of revenues at a critical time 

which it otherwise would not have had. In short, the entire region 

was a winner. 

The simplistic analysis that assumes mistakenly that my 

smelter's power use in 1987 and 1988 (and maybe longer) would 

have been the same whether or not there was a Variable Rate 

conspicuously proclaims its complete Jack of understanding of the 

Variable Rate and what was happening in the region in the mid1980's. Compounding this mistake is the total failure to appreciate 

that a dollar paid in the present is more valuable than a dollar paid · 

in the future. The Variable Rate resulted in huge "overpayments" in 

its early life and only later did the rate fall below the standard 

Industrial Rate level. The Majority Staff apparently ignored this. 

2. A major reason for the drastic erosion of BPA's 

competitiveness lies in the debacle involving the Washington Public 

Power Supply System's construction of five nuclear power stations. 

Only one was completed. The other four were multi-billion dollar 

"dry holes." The completed one is a high cost source of power itself. 

While I was in Jaw school in Oregon and then as I practiced law in 

Eastern Oregon I was a critic of WPPSS. 

I mention this because as I see it the fundamental policy 

problem with these ill-fated nuclear plants was that there was then 

no tiered rates. If we would have had tiered rates I cannot imagine 

that the region would have spent the billions of dollars it did with 

nearly nothing to show for it. Tiered rates d~ not make much sense 

when the incremental cost of power is going down, as it was during 

much of BPA's earlier years. But it makes a great ,deal of sense when 

the incremental cost is rising. Not only does it place the cost of 

meeting demand growth on those who are growing, which is only 
88 

fair, but it also provides more appropriate economic signals 

concerning the cost of such additional power. 

I believe strongly in the capitalist, free market economic 

system that has evolved in America. Its genious lies in the ability to 

transmit signals to consumers and producers so as to stimulate or 

suppress demand or supply at any particular time. Thus, when price 

signals from BPA said that power only had a 2 mill cost it was 

reasonable that demand projections would look rather rosy. Power at 

25 mills, however, had a completely different demand curve, as 

should be expected. Not surprisingly people became more aware of 

uninsulated walls and ceilings and the disadvantages of baseboard 

electric heating. 

Thus, I believe part of the reason for the WPPSS tragedy was 

the lack of tiered rates. Consequently, the idea that BPA is finally 

serious about them is good news, although it is 20 years too late for 

my tastes. 

I also believe strongly that "unbundling" is the only reasonable 

and fair way to conduct business in these circumstances. There is no 

doubt that in the "one size fits all" world that has been BPA there 

are products and services that have been provided to all when only 

some find the particular feature of value. If I am right then this 

means that some customers have been paying more than they 

otherwise should because they have picked up part of the tab for 

those using the more expensive features. Conversely, this has given 

some customers the idea that certain features are "free", thereby 

encouraging excess use, since the true cost has been shifted to 

others. 

I understand the concept of "unbundling" to mean matching the 

proper costs with the particular products and thereby sending the 

appropriate economic signals to customers. This is completely fair 

and equitable and, in the final analysis, is the only way I know of for 

BPA to honestly meet its statutory objective of providing the 

"lowest possible rates to consumers consistent with sound business 

principles. " 

Finally let me say a word about speed. There is no doubt that 

some of the things BPA has announced it wants to do represent 

significant changes in the way it has done business during the last 

50 years. Change is always threatening. It is always upsetting. This 

is part of the human condition. But change is also fundamental to 

remaining . alive and viable. 

1 kno'w that the Task Force report raises the issue of whether 

BPA is pushing these changes too rapidly or not. I do not believe they 

are. Earlier I pointed out that certain changes made decades ago 
89 

could. have saved tremendous grief for the region. If, as some have 

suggested, BPA waits any further to implement significant changes 

and only does so when it is literally forced to at the precipice of a 

utility death spiral it will be too late. I can tell you that in the 

dynamic and real world of competition it is almost never the 

superior strategy to be the last to respond to changing customer 

demands, which we loosely call the business enyironment. The cases 

of International Business Machines and Digital Equipment would 

seem to provide .ample proof of this statement. 

Because change is so hard to truly accomplish, and I suspect 

this is doubly hard in a government bureaucracy, it is imperative to 

begin when the signs are clear that trouble is brewing on the 

horizon. The signs are clear now, even if the exact magnitude and 

proportions are not known in exquisite detail yet. The changes BPA 

proposes should increase fairness and equity. There is no valid 

reason to put off for tomorrow what can be done today in this 

regard. This committee should be urging such changes and I add my 

voice to the support you have given to things such as tiered rates 

and unbundling. On the other hand, this Task Force's credibility is 

undermined by superficial and simplistic analysis which wrongly 

supports myths about our regional electric system. As President 

Clinton says, "We can do better than that. • 

Thank you for this opportunity to provide some input on this 

matter of urgent import!lnce to our region. 
90 

Mr. DEFAZIO. We go now to Ms. C. Clark Leone. 

STATEMENT OF C. CLARK LEONE 

Ms. LEONE. I am manager of the Public Power Council, a service 

organization representing 114 of Bonneville's municipal, cooperative and PUD customers and the primary organization representing 

our members before Bonneville in rate cases, contract negotiations 

and other Bonneville policy matters. 

While we don't agree with all the features in the business plan, 

we support Bonneville's general direction to increase its efficiency, 

improve customer service and retain its position as the supplier of 

choice in the Northwest. The issue of competitiveness has served 

as the backdrop for much of BPA's reinvention efforts. While I 

share the concern that BPA's rates could rapidly become uncompetitive, I think that a review of the rate level alone is too simplistic. Equally important is rate stability. 

Many brokers, marketers and independent power producers are 

offering long-term contracts at fixed rates. In contrast, BPA faces 

a murky future of ESA compliance costs, vagaries of the weather, 

fluctuating surplus power prices, potential repayment, reform initiatives and nuclear decommissioning costs. 

Predictions of BPA rates are more an issue now for mystics and 

seers than rate analysts and utility managers. I applaud the steps 

that Congress has taken to minimize some of these uncertainties, 

for example, legislation recently introduced by Senator Hatfield 

and you, Mr. Chairman, to refinance Bonneville's outstanding appropriated debt. 

Second, the administration's agreement to credit Bonneville for 

the cost of recent emergency fish protection measures is also welcome, and we hope this is not an one-shot affair. It represents a 

sharing of extraordinary costs into the future. 

And third, of course, the cost saving proposals contained in the 

majority staff report outline important steps to reduce revenue requirements and increase certainty. There are some folks that look 

at the scope of change proposed in the draft business plan and urge 

caution and slowdown. 

I feel that the concerns prompting calls for delays can be allayed 

if BPA proceeds in a sensible and deliberate fashion. The first critical matter that PPC sees is the business arrangement, which is the 

contract renewal terms, and then rate case issues followed on by 

that. 

I was just reviewing Mr. Robertson's chart, business plan before 

and after. I hope I am not to be disappointed in it. The agreement 

that PPC and BPA entered into is that intensive contract negotiations will begin now with a target finish date in mid-December. If 

and only if, core contract issues are resolved and set in concretenot just negotiation and discussion, but set in concrete-then a rate 

case with the unbundled products, tiered rates, et cetera, will follow on in January. And then, of course, the target would be October 1, 1995 as the new date that rates would become effective. 

My written testimony outlines PPC's responses to the specific 

questions raised in our letter of invitation. Let me just quickly 

summarize our key points. 
91 

Tiered rates are a useful tool to send a price signal on the cost 

of new resource acquisitions. We do not object to tiered rates provided that they comport with PPC's tiered rate principles. We believe, though, that the tiers should reflect specific resources and 

their costs, specifically the Federal-based system, including conservation resources achieved to date. The second tier should be new 

resources, including purchase power. We think the draft plan inappropriately spreads existing resources across both tiers. 

Next, Bonneville must adhere to the cornerstone Federal policy 

of preference. PPC's concerned that the draft plan proposes treating new preference customers as second-class citizens in that they 

will have less call to Tier 1 rates than will existing customers. 

Finally, we support the conservation reinvention efforts. We believe local utility controlled and directed conservation programs can 

achieve the conservation targets contained in the power plan of the 

Council at costs lower than those under the current system. 

Before concocting a Rube Goldberg compliance mechanism, the 

parties-those parties who doubt us should give us a chance to 

prove them wrong. I believe this committee provides the ultimate 

accountability mechanism. Our members' failure to achieve commonly held conservation objectives will result in a mandatory imposition of highly restrictive conservation mandates. 

We want conservation reinvention to work. I simply ask that we 

be allowed to succeed. Thank you. 

Mr. DEFAZIO. Thank you. 

[Prepared statement of Ms. Leone follows:] 
92 

Testimony 

of 

C. Clark Leone 

Manager 

Public Power Council 

before the 

House Natural Resources Committee 

Subcommittee on Oversight and Investigations 

Bonneville Power Administration's Draft Business Plan 

August 9, 1994 

General Comments on Recommendations Contained in the 

Majority Staff Report, "BPA at the Crossroads" 

The Majority Staff Report provides an important and up-to-date review of Bonneville Power 

Administration (BPA) and some of the options available to the agency in its attempts to lower its 

costs and remain competitive. As you know, BPA's public utility customers have suggested areas 

where they also believe savings can be realized. (For example, for the FY 1993-1994 rate period, 

customers identified approximately $70 million dollars of expense and capital reductions that BPA 

could make in the conservation program that would have had relatively minimal effect on program 

success.) RPA appears to be seriously considering all suggestions as it goes about reinventing its 

entire operation from the bottom up. 

The Majority Staff Report lists specific and detailed actions that the Administrator can take to 

bring costs down. The BPA Draft Strategic Business Plan (Draft Plan), on the other hand, deals 

with ways to provide guidance to employees, to improve its relationships with its customers, and to 

structure the agency's operations to keep its costs down over the long-term. The difference between 

the Majority Staff Report and the Draft Plan appears to be one of emphasis rather than of substance. 

(I) Please discuss your view of BPA's competitive position at present and over the next ten 

years. What are the competitive threats? What are BPA's competitive advantages? 

BPA's competitive position is still good. The Federal Base System (FBS) remains valuable. 

Evidence of this value to BPA's preference customers is found in the extensive effort and 

commitment they are making to •nsure that BPA's reinvention efforts are successful. We believe 

that BPA is moving in the direction of improving its long-term competitive position, although many 

significant issues remain. 

The costs of new wholesale generation are coming close to BPA's wholesale rate and recent 

experience indicates that non-federal power is being offered contractually at specific or formula 

- PPC Testimony - PUBLIC POWER COUNCIL 500 N.E. Munnomah, Suite 729 Pol"'llnCI, OR 97232 

(503)232-2427 
93 

prices at or near BPA's Priority Firm rate, which applies to purchases by preference customers in 

the Northwest. These kinds of contract offers tend to minimize, allocate and control the 

uncertainties faced by utilities in the wholesale electricity markets. BPA's continued 

competitiveness depends on its ability to control its costs. If unable to do so, BPA's prices will 

increase and its customers will protect their competitive position by exploring alternatives to BPA. 

Some disagree with this view of BPA' s competitive situation and argue that BPA is 

overreacting to a threat that is perceived, not real. Yet Snohomish County PUD in Washington state 

was recently offered approximately 8000 megawatts in response to its request for resources 

proposal. We understand that the offers are not all less expensive than BPA's price, but they are 

more predictable and stable because the offers generally contain firm prices for fixed amounts of 

power over definite time periods. 

(2) How likely is it that BPA's rates will be uncompetitive when compared to alternate 

generation sources in the 2002-2003 rate period? 

The costs of new generation are dropping, retail wheeling services are being requested by 

industrial customers, and BPA's costs are rising. If BPA is able to reduce its costs, thereby keeping 

its prices to its preference customers down, the agency should be able to retain its competitive 

advantage. If not, it will be difficult for BPA to remain competitive in the near-term, making it 

difficult to be competitive in the long-term. 

Price alone, though, is not the only challenge for BPA. Equally important is rate stability, 

for competitors are even now offering long-term contracts at fixed prices. 

(3) BPA's Business Plan asserts that BPA will lose at least 1400 aMW of load if the actions 

proposed in the plan are not implemented, though the analysis contained in the Business 

Plan DEIS concludes that under the status quo only 599 aMW of finn load will he lost. 

How likely is it that the BPA Business Plan's "death spiral" scenario, in which BPA 

loses more than 7000 aMW out of its present load, will actually take place? 

PPC is working on gaining a better understanding of all the numbers in the Draft Plan and 

DEIS. Loss of BPA's entire load seems highly unlikely, but 1000-1400 aMW loss within tbe next 

five years is possible. We know that many of BPA's preference customers are planning to develop 

resources that will insulate them, at least partially, from uncertainties about BPA's future power 

supply and prices. We very much want BPA to succeed in its reinvention and to retain as much 

load as possible. 

(4) The Task Force report discussed what it called the BPA "hassle factor." Has BPA 

moved to correct its deficiencies in the area of customer service and satisfaction? 

PPC believes that BPA is moving toward correcting deficiencies in the area of customer 

satisfaction. The Draft Plan identifies " ... high and continually improving customer satisfaction" 

as its first Strategic Business Objective (SBO). This SBO contains four specific measurements that 

BPA plans to use to measure its success with its customers and to hold specific organizational 

components accountable. This SBO, when combined with the appointment of Account Executives 

charged with assisting specific customers, should help the customers feel confident that BPA is 

sincere in its desire to reduce the "hassle factor" . 

- PPC Testimony -

84-374 0 - 94 - 4 

2 PUBLIC POWER COUNCIL 500 N.E. r,lh,lllnom•h. Suite 7'29 Portland. OR 97232 

!503) 232·2<t2'7 
94 

(5) Actions proposed in BPA's Business Plan, such as tiered rates, unbundled services and 

conservation reinvention, taken together are likely to shift costs between customer 

categories. For example, all customers now bear part of the costs of regional 

conservation investment, but many will see those costs decline under the actions 

proposed in tht Business Plan. Others will likely see their overall costs increase. What 

cost shifts do you anticipate as a result of the proposed actions in the Business Plan 

DE IS? 

It is certain that the changes that BPA is undertaking will alter the current cost relationships 

among BP A's customers. We at PPC are very concerned that these issues are addressed fairly, 

prior to the implementation of tiered wholesale rates and unbundled products and services. We are 

concerned, for example, that the rate paid by the DS!s could differ significantly from that paid by 

the industrial consumers of the region's preference customers, a result we believe to be contrary to 

the intent of the Northwest Power Act. We are troubled that the application of tiered rates to the 

residential exchange program could result in inequities between the region's preference customers 

and the residential ratepayers of the IOUs. At this point, the complexities associated with tiered 

rates, unbundling, changes in subtransmission cost allocations, the low density discount, and other 

components of rate design leave all observers without a clear picture of the impacts on their 

individual utilities. Consequently, we are working to develop the necessary analytical tools to allow 

utility-specific analysis of the impacts of alternate approaches to tiered rates. 

(6) The Business Plan DEIS estimates that, compared to the status quo, the market-driven 

alternative will yield about 40 aMW of utility-sponsored conservation as a result of a 

tiered rate's price signal, 22 aMW as a result of fuel switching, and 130 aMW as a 

result of independent utility programs. How likely is it that BPA's customers will 

acquire the cost effective conservation in their service areas in the absence of BPA 

programs and financing? Will the application of the Business Plan's conservation 

reinvention principles ensure that the region will acquire the conservation called for in 

the Power Planning Council's plan? 

PPC's members are committed to independent development of conservation resources. We 

believe that our members will, in the near-term, continue to operate most of the core conservation 

programs developed by BPA because they are technically sound and they provide benefits to 

consumers. We expect changes to occur in the nature, structure and amount of financial incentives 

offered by the sponsoring utility in conjunction with these types of programs. PPC expects to see 

payment and incentive structures that more closely mirror local conditions instead of the uniform 

regional approach of the current BPA programs. 

BPA's conservation program is at a crossroads: We can continue the centrally designed 

programs of the last 14 years with all their attendant shortcomings (40% overheads, inflexibility, 

and cross-subsidies), or we can pursue a decentralized, locally-initiated and -controlled approach to 

conservation. Neither approach is without risks. The centrally-designed programs of the past have 

demonstrated that, if money is no object, we can deliver all the conservation that has been targeted. 

In a decentralized, locally-initiated approach to conservation, we will be challenged to deliver 

conservation more creatively and less expensively. 

In any event, if we continue on the current course, BPA's available borrowing authority for 

directly-funded conservation programs will expire in three or four years. At that point, BPA will 

- PPC Testimony PUBLIC POWER COUNCIL 500 N.E Muttnomah, SUite m Portland, OR 97232 

(503}232-2427 
95 

have borrowed the remaining $700 million for conservation, further exacerbating the upward 

pressure on its rates and worsening its competitive position. This situation could drive customers 

off the BPA system, thereby jeopardizing the agency's ability to repay its federal debt and fulfill its 

fish and wildlife responsibilities. 

The Draft Plan proposes a reinvention of BPA's conservation program. In doing so it relies 

upon three key elements: "market transformation"; customer-initiated energy efficiency programs 

based upon integrated resource plans (IRPs); and demand-side products and services. PPC has been 

working with BPA, the Northwest Power Planning Council (Council), the Northwest Conservation 

Act Coalition and others to define these activities. We are approaching a consensus and expect to 

finalize regional IRP guidelines soon. PPC expects to recommend principles designed to gain 

regional consensus about approaches to "market transformation". 

Despite PPC's optimism about the success of conservation reinvention in the region, we do 

have some concerns. As with any new system, the approach outlined in the Draft Plan may need 

fine-tuning. For example, we are troubled that the Draft Plan discussion about midcourse 

corrections may be read to permit a return to BPA centralized funding of all conservation. We do 

agree that if problems arise in the reinvented conservation world, some sort of corrective action may 

be needed. But centralized funding is not the answer. 

The potential benefit of the reinvention lies in capturing the imagination and creativity of 

BPA' s customers who are working on developing guidelines for IRPs with provisions for tracking 

and accountability. We believe that centralized programs should be limited to "market 

transformation" activities which are appropriately conducted at the regional level but that the 

creative efforts needed to make conservation reinvention work reside with the local utility boards 

and commissions. That creativity could be thwarted through intrusive directives and limitations on 

the self-governing authority of consumer-owned utilities. 

We understand that there are those who doubt the conservation commitment of the region's 

public power systems. We intend to prove the doubters wrong. 

(7) What steps should BPA be prepared to take if the Draft Plan's expected conservation 

achievements are not fulfilled? 

BP A should be prepared to offer products and services designed to assist utilities to meet the 

targets, and Energy Service Charges (ESC) should be available to preference customers who wish to 

use this vehicle. Customer IRPs should help us to know whether utilities are on track to accomplish 

the conservation goals outlined in their IRPs. We do not believe that there should be any 

backsliding from the conservation reinvention goals. All signals to BPA and the customers should 

be to make reinvention work at the local level. 

(8) Does BPA need new legislath·e authority or any changes in existing authorities to 

implement its conservation reinvention plans? 

In order to implement the ESC, which is one of the cornerstones of BPA's conservation 

reinvention, we believe that Congress may need to take steps to authorize BPA to offer an ESC. 

PPC intends to initiate discussions with BPA to define ESC vehicles that may be tailored for easy 

utility use, and we expect to support any needed congressional action. 

- PPC Testimony - 4 PUBLIC POWER COUNCIL $00 N.E. Mullnotnllh, Suite 729 Pbnland. OA 11232 

(503)232-2427 
96 

(9) What alternatives would you propose that would better achieve the region's conservation 

goals, while reducing the need for new BPA Treasury borrowing authority? 

The best approach to achieve the region's conservation goals, without new Treasury 

borrowing authority, is to place the responsibility for conservation resource development at the local 

utility level. This is appropriate because conservation involves working with end-use consumers and 

is thus an inherently retail activity. 

(10) One key element in BPA's conservation reinvention is a requirement that its utility 

customers agree to a contractual requirement for integrated resource planning and 

efficiency action plans intended to acquire all cost effective conservation in each 

customer's service territory. Do you support such a requirement in principle? Do you 

believe it will have the effect of reaching the conservation goals set by the Northwest 

Power Planning Council? 

PPC supports the notion of contractually requiring integrated resource planning 

commitments. We have been working collaboratively to define guidelines that will assist customers 

in developing their IRPs. We believe that the Council's conservation goals will be met through the 

local utility IRP mechanism. The Council's goal, however, is regional and not utility-specific, 

while IRPs are very customer-specific and are intentionally designed to capture the details of local 

situations and opportunities. It will thus not be a simple matter to draw direct comparisons between 

local IRPs and a regional conservation plan. 

(11) What are the implications of the Business Plan for the development of renewable energy 

resources? 

We are unsure about the implications of the Draft Plan for renewab1e resources, though in 

and of itself, it could have negligible effect. In the future, renewable resources will compete to 

serve markets transformed by competition, but affected as well by tax incentives, conditions of 

transmission access and new technologies. It is too early to tell how these will interact. 

(12) What alternatives would you propose for treatment of the DSis in a tiered wholesale 

electric power rate? 

Please refer to the answer to question 15. 

(13) What other changes to BPA's tiered rate proposal would you suggest? 

PPC has adopted detailed positions with respect to tiered rates. Last winter, BPA's 

customers developed a set of principles for the implementation of tiered wholesale rates. Based on 

discussions with BPA, the customers modified the principles which were then incorporated into the 

agency's Draft Plan. The customers' goal is to assure a commercial foundation for a basic 

relationship with BPA that covers the purchase of power from the federal system. This commercial 

foundation is necessary for the customers to be able to make well-informed business decisions 

regarding the purchase of federal and non-federal power in the future. 

The customers' approach to tiered rates is driven by the emerging characteristics of the 

changing wholesale market, which emphasize a contractual approach that balances the interests of 

- PPC Testimony 5 PUBLIC POWER COUNCIL 500 N.E. ~ultnomah, Suite 729 Portland, OR 97232 

(503)<!32·2427 
97 

both buyer and seller in any long-term arrangement. Recent examples of the long-term approach 

include wholesale contracts with specific prices, as well as rates that are based on a specified pool 

of generating resources. These contracts support the significant financial investments necessary on 

both sides of any long-term arrangement, by minimizing, allocating and controlling the sources of 

uncertainty that face both buyers and sellers. The success of any long-term relationship between 

BPA and its wholesale customers in the Northwest depends on wholesale contractual arrangements 

that provide acceptable levels of certainty about rates and other terms and conditions of the sale. 

We have been working with BPA on tiered rates, specifically on the details of 

implementation of the principles listed in the Draft Plan. Through this process, we have discovered 

that many of the principles are subject to various interpretations, and there remain significant 

differences of opinion between BPA and the customers on how tiered rates should be put into place. 

For example, the customers had proposed, and thought that BPA had agreed, that Tier 1 be 

defined as a fixed set of resources, with the costs of those resources determining the Tier 1 rate. In 

our minds, a list of specific federal resources should be included in Tier 1, with short-term 

purchased power forming the basis of BPA's expected service to Tier 2 loads. On this issue, we 

even seem to have agreement from the environmental community. BPA, on the other hand, 

disagrees, apparently out of concern that the "cost basis" of Tier 2 would end up exceeding the 

market price, and thus will interfere with BPA's goal of using Tier 2 sales to build up fmancial 

reserves. We have offered several mechanisms to protect against risks in BPA's Tier 2 business 

line, and await BPA's response to our proposals. 

In other areas, BPA's approach differs from that proposed by the preference customers. For 

example, PPC advocates that newly-formed preference utilities be offered the same rights to power 

from the federal system as are offered to preference customers at the time of the original 

determination of rights to purchase Tier I power, even though this would mean that all Tier 1 

customers would give up some Tier 1 rights in this situation. BPA's approach would create in 

effect a "second class" of preference customers, those formed in the future, whose rights to the FBS 

would be more restricted than the rights of those preference utilities in existence today. 

The bottom line here is a simple one: the preference customers are concerned that BPA's 

approach to tiered rates will not provide the basis for a long-term purchase relationship with BPA or 

protection of preference rights. 

(14) Has BPA allowed enough time for public comment and participation in its. tiered rate 

implementation schedule? Are you satisfied with the process to date? 

Given the pace, complexity and number of changes called for in the Draft Plan, some have 

recently sought a slow-down of BPA's entire reinvention processes. At the same time, many 

preference customers are anxious to reach closure on issues that have been pending for months. A 

balance is therefore needed between timeliness and thoroughness. We believe we have reached such 

a delicate balance and now have an opportunity to meet the needs of the customers and of BPA. 

Specifically, PPC and BPA have agreed to a sequencing of events for the next 14 months. 

The basic structure is this: Intensive contract negotiations will begin in early September with a 

target finish date in mid-December. A BPA general rate case is planned to commence after the first 

of the new year, with a target of October 1, 1995, as the date new rates become effective. Core 

- PPC Testimony - 6 PUBLIC POWER COUNCIL 500 N.E. Mu"nornah. Suite 72!1 Porrt.nd. OR 87232 

(503)232-2427 
98 

contract issues will be resolved and set in concrete by the December target date. If they are not, 

contingency arrangements will be necessary. 

(15) In the longer term, what relationship should BPA seek with its DSI customers? What 

changes would you suggest be made in new DSI power sales contracts? 

PPC advocates that no more than 75 percent of the DSis' historical loads on BPA be used to 

determine their access to Tier I power, but BPA has concluded that several hundred average 

megawatts more should be used. We also believe that preference customers should have the option 

to recall service at Tier 1 to the DSis in the event that further reductions in the capability of the 

FBS are required to assist migrating anadromous fish. In the new long-term business relationship 

with the DSis, preference customers wish the variable industrial rate discontinued and a value of 

reserves payment based on competitive bidding. At the same time , we believe that the DSis should 

have access to the transmission system on the same terms and conditions as other BPA customers. 

(16) What opportunities exist for BPA to expand its sales of power outside the region and the 

profits from those sales? Should Congress consider providing any new authorities that 

would allow BPA to maximize its returns on the sale of power surplus to regional needs? 

BPA already has significant, albeit statutorily limited, authorities to sell power outside of the 

region. PPC believes it premature to discuss amending these authorities until basic regional 

relationships are structured by means of new wholesale power sales contracts. 

Thank you for the opportunity to testify before this Subcommittee. 

- PPC Testimony - 7 PUBLIC POWER COUNCIL S00 N.E. Mu1tnom•h. SuiUI m Potttl rld. OA 97232 

(503) 232·2427 
99 

Mr. DEFAZIO. Mr. Scott. 

STATEMENT OF DANIEL C. SCOTT 

Mr. ScOTT. I am Dan Scott. I am a commissioner from Mason 

County PUD No. 1 in Shelton, Washington. 

I want to thank you for the opportunity to come back here and 

give my testimony about the BPA business plan and your committee's work on the subject. I would like to commend the committee 

for an excellent report. I think I am in whole-hearted agreement 

with it. 

I represent both Mason PUDs and a group of utilities called the 

Aluminum Information Project. They include Mason 1; Mason PUD 

3, also in Mason County, Washington; and five utilities from Oregon, which are the Canby Utility Board, Central Lincoln People's 

Utility District, Emerald People's Utility District, Salem Electric 

and the City of Cascade Locks. 

The first thing I want to talk about a little bit is the business 

plan, and I want to emphasize that our utility is not unlike most 

utilities in the region. It seems to me that there are about 10,000 

utilities that signed the agreements to build the WPPSS plant and 

that is kind of a good mark of what utilities are. Half a dozen of 

them fall into the Clark and Snohomish ilk, and probably 60 or 70 

or even 80 are fairly closely paralleled to Mason 1. 

We have 4,200 customers. We have absolutely no industrial load. We have a very small commercial load. We have a total of 17 employees; that includes meter readers to managers. So when they 

come out with a business plan that asks us to unbundle our services and possibly look elsewhere for our power, it makes me nervous because we simply don't have the ability to buy smart. We 

don't have the staff or the resources. 

I think that Bonneville's business plan looks too heavily to the 

revenue enhancement side and not enough to the cost containment 

side. It is my experience from being in business that you can talk 

about revenue enhancement all you want, but you need to be competitive within. That is really what determines your competitiveness. 

I'd like to talk about the DSis and Bonneville's approach to serving them. We believe that they do get a subsidy. The 7C2 Delta indicates 300 and almost 60 million dollars per biennium. That is 

money that my ratepayers and all the ratepayers in the region pay 

to subsidize the DSis. I think the DSis provide an important service for Bonneville. They provide important jobs for the region, but 

those jobs are no more important than five jobs in a cabinet shop 

in Shelton or 50 jobs in a mill, in Omak, or jobs anywhere else in 

the region. I can't understand the idea of subsidizing them. 

We should have an orderly approach to DSis. We should offer 

them a contract that makes sense, both to them and to the region. 

And we should not eliminate preference in the process. Thank you 

very much. 

Mr. DEFAZIO. Thank you. [Prepared statement of Mr. Scott follows:] 
100 

PUBLIC UTILITY DISTRICT NO. 1 

OF MASON COUNTY 

N. 21971 Hwy. 101 

Sheltoo. Wosh1ngtoo Q8584 

BOARD OF COIWVIISSIONEAS 

DANIEL ( SCOTT Pres1dent 

RKK BUE<HEL. V1ce Pres.de'"'t 

KAIS 80lENOEA Se<re1orv 

HOUSE COIOIITTBB 011' II'ATORAL IU!SOilRCBS 

Subcoamittee on oversight and Investigations 

The Honorable Peter DeFazio 

Washington, D.C. 

TI!S'l'~ OP DAIIIEL C. SC0'1"1' 

co .. issioner 

Mason County Public Utility District lfo. 1 

Shelton, Washington 

011 BBIIALP OF: 

The Aluainua Inforaation Project utilities 

August 9, 1994 

(206) 877.5249 • 1-801).544-4223 !In Wosn.ngton Only) • FAX (206) 877-9274 
101 

SUMMARY OF TESTIMONY 

My name is Dan Scott. I am a commissioner of Mason County 

Public Utility District No. 1 in Shelton, Washington. 

Thank you for inviting us to appear before you today. 

In your invitation, you asked us whether the Bonneville 

Power Administration's draft Business Plan is consistent with 

this committee's BPA Task Force Report. 

The short answer is no. The Task Force Report contains a 

series of forceful recommendations, including calls for 

Bonneville to reevaluate its long-standing relationship with the 

region's aluminum smelters. Unfortunately, Bonneville's draft 

Business Plan ignores those recommendations. 

Furthermore, Bonneville's schedule for drafting new power 

sales agreements, unveiled only last week, is unrealistic. The 

schedule calls for drafting these contracts in only three months. 

Bonneville says it does not need to prepare a separate 

environmental impact statement (EIS) on its contracts because the 

draft Business Plan covers the subject. But the Business Plan 

does not discuss contract options for the aluminum smelters at 

all, an issue which was addressed in prior federal court 

decisions holding that Bonneville must prepare an EIS for power 

sales agreements. (See pages 13-14 of this testimony for 

details.) 

we fear that Bonneville's rushed effort will almost 

certainly fail or produce results that over time will harm the 

long-term interests of both Bonneville and the region's publiclyowned utilities. 
102 

The schedule also precludes this committee from conducting 

oversight hearings and continuing its valuable work. That ought 

to be as untenable to you as it is to us. 

We see the need for change. We understand that the federal 

power system is facing significant problems, and we remain 

committed to working with Bonneville and other customers to 

address these challenges. But we need time to evaluate proposals 

and alternatives, and Bonneville's schedule does not allow us to 

do that. 

The Aluainua Information Project 

In the last year, Mason PUD No. 1 has been working with a 

group of other utilities on issues relating to the region's 

aluminum smelters and other Direct Service Industries (DSis). 

Our group is informally known as the Aluminum Information 

Project. In addition to Mason PUD No. 1, participants include 

Mason PUD No. 3 in Washington and five utilities in Oregon: 

the Canby Utility Board; Central Lincoln People's Utility 

District in Newport; Emerald People's Utility District in Eugene; 

Salem Electric and the City of Cascade Locks. 

The purpose of our group is to analyze the existing 

Bonneville-DSI relationship and to press Bonneville to undertake 

the necessary analysis to ensure that future rates and contracts 

between the DSis and Bonneville provide a net benefit to the 

region. 

I am appearing today on behalf of the Aluminum Information 

Project utilities, and my comments reflect their concerns. 

2 
103 

Why Mason County PUD cares about the DSis 

Mason PUD No. 1 serves approximately 4,200 customers, most 

of them residential. We have a very small commercial customer 

base and no industrial customers. our utility was established in 

1934 -- it was the first PUD in Washington State, and we recently 

celebrated our 60th anniversary. 

Since 1959, Mason PUD No . 1 has been a full requirements 

Bonneville customer. We wish to remain so in the future. 

Bonneville, however, appears to be "reinventing" itself in a 

way that is damaging to its long-term relationship with publiclyowned utilities. For example, Bonneville appears to have devoted 

more attention in recent months to ensuring the survival of the 

region's aluminum smelters than in ensuring that ~ survive. 

Bonneville has concluded in the EIS for the draft Business 

Plan that: 

In contrast to BPA's preference customers and IOU 

[investor-owned utility] customers, BPA has no statutory obligation to provide power to the DSis 

beyond the term of their existing contracts [in 2001]. 

Page B-5. 

But elsewhere in the EIS, Bonneville asserts that its new 

proposed pricing policies, compared with the status quo, will 

increase Bonneville's DSI firm load by 422 average megawatts (by 

making Bonneville power more attractive) and ~ the load of 

publicly-owned utilities by 140 average megawatts . • 

• See page 4-63 of the EIS. Public agency loads are reduced 

"primarily because of price-induced conservation and fuelswitching." 

3 
104 

That seems backwards. If publicly-owned utilities are 

indeed Bonneville's preference customers, then its pricing 

changes and other policies ought to address our needs, as core 

customers. 

Finally, the draft Business Plan raises so many questions 

about what Bonneville will actually charge for power that many 

utilities now question whether Bonneville can in fact remain a 

low-cost provider. 

Although the Plan outlines a general approach to "tiered 

rates" and "unbundling," it contains few hard facts by which 

utility commissioners or general managers can evaluate 

Bonneville's proposals. 

As a result, the Plan leaves the overall impression of being 

poorly thought out. If implemented, it may encourage publiclyowned utilities to leave the federal system. 

Mason PUD No. 1 does nQt want to leave the federal system. 

Our load is only six average megawatts. We have 17 employees, 

and we have little ability and resources to "go it alone . " Like 

many small and medium-sized utilities around the Pacific 

Northwest, we have no plans to build our own generating resources 

or buy power from independent producers. 

4 
105 

The BPA Task Force Report 

Mason PUD No. 1 and other Aluminum Information Project 

utilities endorse the House Committee on Natural Resources' BPA 

Task Force recommendations regarding the DSis.' 

We are pleased to see that the Task Force called on 

Bonneville to conduct a comprehensive analysis of the economic 

costs and benefits of continuing to serve the DSis.' 

Unfortunately, Bonneville has not responded to this 

recommendation nor has it agreed to undertake a request from the 

Aluminum Information Project to conduct a similar study of the 

DSis. 

' The DSis consume approximately 3,200 average megawatts of 

electricity every year. Last year, the 10 smelters paid Bonneville 

about $356 million for power. The smelters currently purchase 

electricity under a special variable industrial rate that 

fluctuates with the price of aluminum. The rate was implemented in 

1986 and expires in 1996. Because the price of aluminum has been 

low in the last several years, Bonneville • s revenue from the 

smelters is also down. The difference between Bonneville's 

projected cost of service and its revenue from the smelters is 

known as the "7(c)(2) delta." In fiscal year 1994, the projected 

delta is $178 million. Most of those costs are shifted to publicly-owned utilities and to the residential and small farm 

customers of investor-owned utili ties which buy power under the 

"priority firm" rate. 

' The Task Force report, "BPA at a Crossroads," page vi, 

concluded: 

"BPA needs to conduct a comprehensive analysis of the economic 

costs and benefits to the Northwest of the region's aluminum 

industry, known as the direct service industries or DSis. Based 

upon this analysis, a new rate structure should be designed for the 

DSis that equitably balances the interests of the DSIS and all 

other regional ratepayers. Furthermore, Bonneville must prepare 

for the very real possibility that some of the individual DSis may 

not survive the competitive challenges facing the industry in the 

near term." 

5 
100 

In April 1994, we wrote Bonneville with suggestions for a 

study that would examine options for continued DSI service. We 

had meetings with Bonneville staff and followed up with letters 

to Administrator Randall Hardy, but no action was taken. That is 

where things stand today. 

We are llQt suggesting that Bonneville decline to offer new 

agreements to the DSis when the existing ones expire in 2001. We 

recognize that the DSis provide certain benefits, such as 

reserves, to the federal system. 

But we believe Bonneville has a legal responsibility to 

carefully examine future service to the DSis. 

Bonneville's reluctance to study the costs and benefits of 

continued DSI service is perplexing in light of the agency's 

purported new business approach. 

Conclusion 

The Aluminum Information Project utilities believe 

Bonneville is rushing to sign long-term power purchase contracts 

with the DSis before first examining alternatives. 

We fear that if Bonneville proceeds with its current 

approach, we will continue to subsidize the smelters and assume 

significant risks for continuing to serve them for years to come. 

6 
107 

In the draft Business Plan, Bonneville ~ that any loss 

of DSI service is bad for the system (no matter when it occurs). 

It ~ that the DSis should get a large assignment of cheap 

federal hydropower. And it assumes that DSI rates will remain 

lower than ·the rates of publicly-owned utilities. 

We challenge those assumptions and request that Bonneville 

look at other options. 

If Bonneville is to become more business like, then it ought 

to act more like a business. That means evaluating its 

relationship with the DSis, placing more emphasis on cost 

containment and doing a better job of consulting with its 

customers. 

To achieve those goals, we have two specific requests: 

1. Congress needs to pressure Bonneville to examine its 

relationship with the DSis as part of the overall Bonneville 

"reinvention." That means looking at new DSI contract options 

and alternatives, including more interruptibility, shorter-term 

agreements and other options identified in your Task Force 

report. 

2. This committee should, as soon as possible, hold an 

oversight hearing in the region on the future of preference and 

Bonneville's continuing assault on the basic tenets of the 

Bonneville Project Act of 1937. The Act states that the 

Bonneville administrator shall "give preference and priority to 

public bodies and cooperatives" in disposing of power from 

federal dams. 

7 
108 

We are alarmed at the present direction . A federal agency, 

bound in theory by statute, appears to have taken upon itself the 

reinvention of its priorities and duties. In so doing, it is 

whittling away its historical and legal responsibilities to core 

customers, the public bodies and cooperatives. 

The bottom line, Mr . Chairman, is that the federal system 

was built for publicly-owned utilities and their customers. As 

preference customers, we deserve the best Bonneville has to 

offer, not the leftovers. 

Thank you for asking us to testify. 

8 
109 

SUPPLEMENTAL TESTIMONY 

Part A contains a general discussion of Bonneville's draft 

Business Plan. 

Part B contains answers to specific questions relating to the 

DSis. 

PART A: BONNEVILLE'S DRAFT BUSINESS PLAH 

Bonneville released its draft Business Plan on June 29. 

Under the Plan, Bonneville proposes to adopt a "market approach" 

to selling power from the federal dams on the Columbia River 

system and other sources. 

Those proposals are the most significant for the Pacific 

Northwest federal power system since Bonneville was first 

established 57 years ago. 

The Business Plan, however, outlines only the general 

direction in which Bonneville wants to proceed. It contains 

little analysis of how these proposed changes will affect the 

power bills of utilities around the region. 

1. Rate i~cts for publicly-owned utilities 

Bonneville insists it will examine rate impacts later --

during formal rate proceedings. 

9 
110 

But how are utilities supposed to evaluate the Plan i f they have 

no numbers and no basis by which to compare the alternati ves ? ' 

That's the chief problem with Bonneville's draft Business 

Plan . It proposes to launch major new changes but has not 

provided the information by which publicly-owned utilities can 

evaluate if they will be better or worse off under the new 

regime . • 

At the heart of the Plan is this principle: Bonneville will 

treat all its customers alike by offering them equal access to a 

range of products and services. 

Unfortunately, the thrust of the principle seri ously weakens 

the rights of 121 publicly-owned utilities that rely on 

Bonneville for their supply of power. And it elevates the DSis 

to a status traditionally accorded to publicly-owned utilities. 

• To understand how important these numbers are , imagine you 

rent a fully-furnished apartment for $850 per month, including utili t i esa The landlord c omes to you with an "offer" that will 

supposedly improve your situation. He proposes to rent the same 

apartment to you for $500 per month but charge you separately for 

utilities, furniture, elevator, swimming pool and underground 

parking . But he won't tell you what these "unbundled" extras cost. 

How do you make your decision? 

• Larger publicly-owned utilities, investor-owned utilities 

and DSis have the resources to move off the federal system. 

Typically, they do not need or want a "full meal" from Bonneville. 

Many sma l l and medium-sized utilities, however, are interested in 

remaining full requirements customers of Bonneville. 

10 
111 

At a time when the federal system is under a huge amount of 

stress and many publicly-owned utilities need more power, 

Bonneville proposes to continue selling large quantities of power 

to the DSis -- even if it means encouraging utility customers to 

look elsewhere for their supply. 

This problem is best illustrated by contrasting Bonneville's 

commitment in the Business Plan and related documents to maintain 

DSI load, no matter what. 

Bonneville's preferred alternative -- its proposed action --

will use price signals to encourage some utility load growth to 

move off the federal system, and will similarly entice the DSis 

to stay as Bonneville customers.• 

If publicly-owned utilities are indeed Bonneville's 

preferred customers, then Bonneville must find ways of meeting 

their loads first, and if necessary, reducing DSI loads over 

time. 

• Total DSI firm load is projected to stay about the same, 

approximately 1,850 ave~age megawatts, under either the status quo or market-based scenar1o. The issue is whether the DSis buy 

Bonneville power or acquire their own resources. 

11 
112 

2. DSI rates and contracts 

Another problem is that the Plan and environmental impact 

statement (EIS) do not mention DSI rates. Why did Bonneville 

neglect to mention smelter rates? 

Because Bonneville ~ that DSI rates would continue to 

be about 4 or 5 percent ~ than preference rates in the 

future. 7 

But if Bonneville plans to develop new products and 

services, why would it not examine DSI revenues to assess whether 

the DSis would, or should, pay more for Bonneville services? 

The answer is that Bonneville apparently wants DSI rates to 

remain low because it wants to keep DSI loads on the system, no 

matter what.• 

This discrepancy between the way Bonneville treats the 

publicly-owned utilities and the way it proposes to serve DSI 

load needs to be addressed. 

7 This information was obtained from Bonneville staff but is not in the Plan itself. 

' The Draft Business Plan in Brief asserts: "Now more than ever there is considerable risk that some of the Northwest's 

aluminum plants may permanently close or operate 

intermittently .... If our rates were to rise to around 35 mills, it 

is possible half of the aluminum smelters in the Northwest could go 

out of business. This would mean a huge loss of load to BPA --

around 1,450 average megawatts (aMW)." Page 5. 

The Plan describes this as a "dire scenario" but does not 

analyze whether DSI load would gradually move off the federal 

system, thus alleviating any potential impact. 

12 
113 

The Plan ought to look at other options for DSI service. 

Your Task Force Report identified some of those options, 

including greater interruptibility, seasonal power sales, shorter 

term contracts and other alternatives. 

Bonneville has not examined those alternatives. 

Despite those omissions, Bonneville says it intends to rely 

on the Business Plan and EIS to guide it in developing new power 

sales contracts with the DSis and utility customers. It 

apparently believes that this EIS -- which contains no discussion 

of contract options is adequate to cover the contracts when 

they are drafted later this year. 

Bonneville has lost two Ninth Circuit court of Appeals 

decisions on the subject and ought to know better than to proceed 

with contracts before preparing an EIS that carefully examines 

contract alternatives. 

In Port of Astoria Oregon v. Hodel, 595 F.2d 467 (1979), 

the court ordered Bonneville to prepare an EIS for a new power 

sales contract with a proposed aluminum smelter in Warrenton, 

Oregon. Bonneville had argued that an EIS was unnecessary. 

In Forelaws on Board y. Johnson, 743 F.2d 677 (1984), the 

issue was raised again. Bonneville claimed that Congress had 

intended to exempt it from the preparation of the EIS on new 

contracts when it passed the Northwest Power Act. The court 

ordered Bonneville to prepare an EIS on its power sales 

agreements. Bonneville took eight years to prepare the EIS, 

which was only released in January 1992. 

13 
114 

The argument that Bonneville makes today is similar to the 

losing propositions in those cases. Here, unlike Port of Astoria 

or Forelaws, there is an existing EIS, done in preparation of 

Bonneville's draft Business Plan. 

The problem is that the EIS contains no discussion of 

contract options, particularly for the DSis. Topics, such as 

increased interruption of DSI service, which were covered in the 

1992 EIS, have been ignored in the current impact statement. 

Bonneville appears to have taken the position that the 

preparation of the EIS, never mind its contents, is suffici ent . 

We question whether this is a sound interpretation of federal 

statute and court decisions, and we ask your assistance in making 

sure that Bonneville analyzes DSI contract options ~ it 

offers new long-term agreements to the aluminum smelters. 

14 
115 

PART B: ANSWERS TO SPECIFIC QUESTIONS 

Question 12: What alternatives would you propose for treatment 

of the OSis in a tiered wholesale electric power rate? 

Answer: Bonneville appears to be locked into a single approach 

to serving the OSis in tiered rates: providing them with an 

assignment of 85 percent of historical loads in Tier 1, the cheap 

resource pool. 

It is easy to understand why the DSis want more Tier 1 power 

and less of the expensive Tier 2 power. The more cheap federal 

power they buy, the better off they are. 

But if Bonneville removes the DSis from paying for load 

growth and regional conservation, those costs are shifted to 

other customers. 

Bonneville has not looked at alternative assignments, and 

has not evaluated whether a smaller assignment (e.g., 50 or 75 

percent) would lower rates for publicly-owned utilities. 

In sum, Bonneville needs to use the next three months 

(before the rate case) to consider alternatives to DSI service 

other than the 85 percent assignment. 

It is difficult, if not impossible, to design tiered rates 

for the DSis without first considering larger contract issues: 

What are Bonneville's legal obligation to the smelters? How are 

new preference customers treated under tiered rates? 

15 
116 

Will new preference customers be allowed to obtain the same 

rights for Tier 1 power as existing preference customers? What 

happens to power that is assigned to a smelter which subsequently 

closes? Is it resold at market rates as part of the Tier 2 pool 

or returned to Tier 1 for use by existing and new preference 

customers? 

Unless and until Bonneville confronts these issues, we 

believe it should not proceed with a tiered rate assignment for 

the DSis. 

Question 14: Has BPA allowed enough ti•e for public co.-ent and 

participation in its tiered rate i•ple•entation schedule? Are 

you satisfied with the process to date? 

Answer: No. Although Bonneville's new schedule for tiered 

rates removes some of the frantic pressure on utilities and other 

interested parties, it still is inadequate. 

Bonneville unveiled its draft tiered rate methodology only 

on July 14. Participants -- customers and other interested 

parties -- in its Tiered Rate Work Group offered comment on July 

28. 

Most of the publicly-owned utilities, including Mason PUD 

No. 1 and other Aluminum Information Project Utilities, said they 

did not have sufficient information by which to evaluate 

Bonneville's draft methodology. 

16 
117 

In part because of comments from numerous customers around 

the region, Bonneville announced last week that it would postpone 

the beginning of the new rate case by three months. Instead of 

beginning October 1, the rate case will now begin January 1. 

Furthermore, Bonneville has abandoned its "bifurcated" 

approach, in which it intended to deal with methodology first and 

specific rates second. The revised Bonneville proposal calls for 

a "single track" approach. 

Although we are pleased that Bonneville has postponed the 

rate case for three months, we fear that Bonneville will not 

reevaluate any of its assumptions in the intervening period. 

The critical issue is not time, but Bonneville's commitment 

to consult the Work Group and ask it for a recommendation. 

Our assessment is that Bonneville refuses to acknowledge its 

legal obligation to the Work Group, which_was established as part 

of a settlement agreement in the 1993 rate case. 

The hearing officer's (administrative law judge) order 

establishing the Work Group specifically said: 

BPA shall co .. ence a process to consider and 

possibly develop a tiered rate methodology, 

beginning in the Summer of 1993 and 

concluding prior to the start of BPA's next 

general rate case. The tiered rate process 

shall consist of two phases. The purpose of 

the process shall be to provide parties and 

interested persons an opportunity to engage 

in a cooperative effort to reach consensus on (a) a tiered rate aethodology ••• and (b) 

whether or not tiered rates should be 

iapleaented. 

17 
118 

See Administrator's Record of Decision, 1993 Final Rate Proposal, 

pages 136-137, and Appendix D for the complete order. 

WP-93-A-02, page D-4. 

The purpose of Phase 1 was to identify problems and concerns 

with tiered rates, establish potential tiered rate principles and 

develop tiered rate alternatives. Phase 2 was to evaluate 

various tiered rate options. 

The order also said Phase 2 was to end no later than July 1, 

1994, "with a BPA determination, based on recommendations from 

the work group (1) for a preferred methodology or methodologies, 

or (2) not to proceed with tiered rates." 

The July deadline was not met in large part because 

Bonneville had not completed its work. It did not present its 

methodology to the Work Group until July 14, two weeks after the 

deadline. 

Bonneville's postponement of the rate case until January 1 

therefore gives the Work Group more time to review alternatives 

and fulfil its responsibilities. 

But Bonneville has said it intends to proceed, no matter 

what the Work Group decides. In comments before the Public Power 

Council in Portland on Wednesday, August 3, Bonneville staff said 

the agency would proceed without a Work Group recommendation. 

The order does not require the Work Group to reach consensus, 

they said. 

18 
119 

We concur that the Work Group is not required to reach 

consensus. But we disagree strenuously with Bonneville's 

statement that it is not required to ask the Work Group for a 

recommendation nor bound to accept its conclusions on whether to 

proceed with tiered rates. 

Bonneville's interpretation renders the Work Group purely 

advisory. Under this approach, Bonneville could and would do 

whatever it wished. That is not what the order and the formal 

Administrator's Record of Decision state. 

Question 15: In the longer term, what relationship should BPA 

seek with its DSI customers? What changes would you suggest be 

made in new DSI power sales contracts? 

Answer: Bonneville needs to revaluate and assess its entire 

relationship with the DSis. Its draft Business Plan and 

accompanying documents have concluded that it has no statutory 

obligation to serve DSI load after 2001, when the existing 

contracts expire. 

We therefore believe Bonneville has a "clean slate" by which 

it can draft new agreements. These agreements should recognize 

the vulnerability of some aluminum smelters, which are old and 

face competition from within the industry. 

19 
1~ 

Specifically, we believe new DSI contracts should carefully 

examine the following general contract options: 

1. Shorter-term contracts. Bonneville ought to offer a 

menu of possible contract options to the DSis, including shorter 

agreements for companies that intend to close all or part of 

their operations in the next decade. 

There is no reason that Bonneville should offer standard, 

20-year agreements to all the smelters and commit itself to 

acquire power to meet the loads of companies with varying degrees 

of economic stability and efficiency. 

2. Take or pay provisions. Bonneville ought to consider 

including some sort of provision that requires the DSis to pay 

for the amount of power reserved for them during the contract 

term, whether used or not. If properly structured, these 

payments could discourage the DSis from signing long-term 

agreements and then reducing or halting power purchases during 

the contract period. (At present, the DSI are required to give 

only one year's notice if they want to reduce operating demand.) 

Take or pay provisions would help make the DSis •ore accountable. 

3. Increased interruptihility. Make one or •ore quarters 

(quartiles) of DSI load interruptible. At present, only one 

quartile of DSI load is interruptible. The other three 

quarters approximately 2,400 average megawatts -- is 

considered firm. 

20 
121 

What are the costs and benefits of alternatives, such as 

supplying the DSis with one quartile of firm power and three 

quartiles of interruptible power? 

4. Seasonal sales. Bonneville should consider selling firm 

power to the DSis only during certain seasons. Instead of 

offering firm power year around, Bonneville could sell more firm 

power to the DSis in spring and summer (when surplus) and less in 

winter (when needed by utilities). 

DSI load is valuable to Bonneville in spring and summer . 

The reason is that Bonnevi lle can sell f i rm power to the DSis and 

receive revenue when the energy has little value to its utility 

customers. Furthermore, Bonneville also needs the water to run 

through the dams at this time for "fish flush" (migration of 

juvenile salmon downstream.) 

Any one or combination of these alternatives could protect 

public preference and ensure that publicly-owned utilities do not 

subsidize the smelters or assume the risks of their continued 

operation in the Pacific Northwest. 

21 
122 

Mr. DEFAZIO. Mr. David E. Piper. 

STATEMENT OF DAVID E. PIPER 

Mr. PIPER. Thank you, Mr. Chairman. Good morning, Mr. Smith. 

I appreciate being with you this morning. 

I am Dave Piper, the General Manager of the Pacific Northwest 

Generating Cooperative. We are a cooperative generation transmission system; we have 29 rural electric distribution systems in 

Oregon, Washington and Idaho, and we serve as the power manager for those systems. 

Our focus today is on competition, of course, and when we talk 

about competition, we worry about the retail level; we need to be 

competitive at the retail level, and from a rural cooperative perspective, our concern is not maybe the traditional one, because we 

have very few industries. We have primarily residential and agriculture communities. 

We don't worry about alternative fuels because there really 

aren't alternative fuels in the rural area. What we worry about, 

from a competitive standpoint, is to be able to keep the rural economy viable, to keep rural jobs, to keep people from migrating to the 

cities. 

This is important to us because cooperatives are traditionally 

lean. They do not have extensive staffs or resources. They have 

roughly 50 to 70 percent of their total costs represented by their 

power bills to BPA. So what Bonneville does will pretty much dictate what happens at the retail level. 

We want Bonneville to be competitive and we want to be able to 

control our future in power supply. So with Bonneville in danger 

of being noncompetitive or uncompetitive at the wholesale level, absolutely. We believe in fact that Bonneville's predictions for the future on future rates are too low for their rates and they are too 

high as far as other resources are concerned. So basically, Bonneville is underestimating the problems that it has in the competitive 

sense for the future. 

As an example, today, our organization is building a relatively 

small methane landfill project near Corvallis called Cofbin Buke, 

and that resource is projected to be competitive with today's Bonneville rate, not the tier 2, but today's PF over the long haul. 

That is a resource that we are going ahead with, and we have 

given notice to Bonneville that that will be part of our take. We 

are also looking at purchase systems for other investor utilities in 

the region, and we are also participating in what is called the 

Northwest Resource Project. So resources are a fact of life. What 

we don't have is the certainty to be able to move ahead on some 

of them. I know that Bonneville is in competitive danger because 

in fact we intend to provide that at the wholesale level, provided 

it is cost-effective to do so. 

Should the process at Bonneville be slowed down? I don't think 

so. Otherwise, we are looking as customers at a rate increase in 

October of 1995 that could be as high as 15 percent. The priority 

firm rate will provide a less competitive Bonneville if that occurs. 

Fifteen percent on top of what presently exists puts Bonneville into 

that uncompetitive fact situation very soon. 
123 

The real problem we have is how do we plan in this period of uncertainty, this state of flux that we are in right now. How do we 

decide what resources we need to purchase? We are doing an IRP 

right now; we are in the middle of it. When we get the results of 

that and as we go along, we need to know what resources to purchase; we need to know what conservation that we can effectively 

accomplish. 

We need to develop the pools that will put all of this together 

economically. Until this rate case, until the contracts first get resolved and then the rate case, we don't know how we are going to 

do this. The competitive factors at the retail level aren't waiting for 

these resolutions, and we need to get ahead with this project. 

I agree with the new direction that Bonneville is projecting here 

this morning with the schedule; I haven't seen it to know the details, but certainly the concepts are agreeable to me. 

Our concerns with the business plan are outlined I think pretty 

well in the written testimony. I concur with Ms. Leone on the 

tiered rate comments. We in the rural areas are significantly exposed from a transmission perspective from what is called the 

fringe or the actual delivery to our member systems, and from 

transfer agreements. So we are concerned about transmission. 

We need pooling; we need to be able to develop the economies of 

scale that are available to large systems, mitigate the risks that 

are available to it-that are facing us, and to be able to have the 

ability to buy and sell on a long-term basis. 

Conservation is on the right track. It provides the right incentives. We are doing the IRPs; we are not going to do anything that 

isn't in the best interests of our member consumers. We have no 

purpose other than that. We are going to do cost-effective conservation. 

We are worried about the present plan where the equity does not 

exist. Our members are PNGC, pay Bonneville $150 million a year 

for conservation, get back about $10 million of that in terms of benefits, as compared to Seattle City Light. 

We are treading water right now until this is resolved, and our 

members are treading water. They are trying to stay competitive, 

the industry and the economics are changing rapidly and we need 

a resolution as fast as possible. 

I appreciate your time. 

Mr. DEFAZIO. Thank you. 

[Prepared statement of Mr. Piper follows:] 
124 

Pattners in Power Management 

David E. Piper 

Testimony Before the 

oversight and Investigations Subcommittee 

of the 

Mr. Chairman, 

House Natural Resources Committee 

August 9, 1994 

Good morning. My name is Dave Piper and I am the General Manager 

of the Pacific Northwest Generating Cooperative (PNGC), a 

generation and transmission company located in Portland, oregon. 

PNGC is made up of twenty-nine rural electric cooperatives which 

serve over 500,000 customers in eight Western states. We continue 

to appreciate the Committee's help in exploring key changes 

affecting the energy future of the Northwest. I would also like to 

thank you and Congressman Smith for the opportunity to testify 

today. 

The central question before the Committee today is a crucial one --

to what degree and how fast should change occur in the way Federal 

power is delivered in the Northwest. PNGC, as the power manager 

for its member systems, is vitally interested in the answer. 

Competitiveness 

We all have heard the word competitiveness a lot lately . While it 

has primarily been used in reference to The Bonneville Power 

Administration's (BPA) competitive position, we believe that the 

real focus should be on the competitiveness of Bonneville's 

customers. The farms, businesses and communities that depend on 

PNGC-member utility cooperatives do not operate in a vacuum. They 

increasingly operate in a global economy and have competitive 

problems of their ow., -- which we have a responsibility to help 

solve. Our goal is to position them well, not to serve some 

internal need to change the way Bonneville looks. 

With that said, I do believe that BPA is heading in the right 

direction . If you look at the baggage that Bonneville is saddled 

with, you understand that they have no choice. Exponentially 

rising fish and wildlife costs, rock bottom world aluminum prices, 

continued drought, coupled with the emergence of low-cost 

generating alternatives such as gas combustion turbine projects 

presents the possibility that Bonneville customers will seek their 

power elsewhere. 

Pacific Northwest Generating Coopentitle 

711 N.E. Halsey 

Surte 200 

Portland. OR 97232·1288 

(503) 288·1234 

Fax (503) 288·2334 
125 

PNGC provides a good example of customer response to increasingly 

competitive energy markets. We have been very active in searching 

out alternative power suppliers and have a good understanding of 

what the market looks like. That search has been predicated on several factors. First, we believe that Bonneville's forecasts for 

future rate increases are too low and that the price of alternative 

resources will be even more competitive than now anticipated. In 

addition, uncertainty over future fish and wildlife and 

regionalized conservation costs make it easier to look at 

alternatives to Bonneville that do not have large unknowns attached 

to their cost structures. 

Just last month, we broke ground on PNGC's Coffin Butte project. 

Located North of Corvallis, the project will run on methane gas 

recovered from a reg ional landfill, displacing several megawatts 

of Bonneville power. In addition to being a source of 

env ironmentally f riend l y renewable energy, we believe that Coffin 

Butte will operate at a levelized cost that is l owe r over the longterm than Bonnevi lle's projected priority firm rate. There are 

other projects like it out there, and, coupled with low cost 

natural gas projects, we believe that Bonneville is in for some 

real competition. 

Bonneville's reaction to this competitive pressure has been 

constructive. We applaud Randy Hardy for helping to build momentum 

to achieve structural change at Bonneville that will upgrade their 

customer service -- in terms of both rates and responsiveness. We 

do not want in any way to stall that momentum. Without it, we will 

not achieve the broadscale change necessary to keep Bonneville, and 

our customers, competitive. 

Process for Change 

The key question at this point is whether we have the information 

necessary to endorse the changes envisioned in Bonneville's Draft 

Business Plan. Unfortunately, the answer is that we do not have a 

good idea of what specific impacts they will have. The way to gain 

some certainty of what those impacts are, however, is not to stall 

the process, but to modify it. 

PNGC strongly believes that Bonneville must make substantial 

progress in negotiating new customer contracts before proceeding 

with a new rate case. Again, we do not advocate a delay in the 

projected October, 1995 rate case completion date. We do believe, 

however, that in order to have that rate case make sense, it needs 

to be based on firm contractual commitments. 

To that end, I have attached an outline produced by a review group 

of Bonneville customers for sequencing the business plan with the 

contract negotiation process. By timing the offering of new contracts with the issuance of a Record of Decision on the new rate 

case, we hope to be able to mesh the numbers with the proposed 

policy changes. In this way, we can make reasonable decisions 

based on real world considerations. 

84-374 0 - 94 - 5 
126 

I am under no illusion that to get all of this work done by 

October, 1995 will be easy. That is the point. We need to keep 

the pressure on Bonneville to make meaningful changes and to lock 

those changes into contracts. If we can start contract 

negotiations now, it should be possible to have contract language 

to consider along with the rate case in January. We believe that 

linking up the contract negotiation and rate case processes will 

provide the customers timely information with which to view 

Bonneville's reinvention proposals while maintaining a meaningful 

deadline for moving forward. 

In order to make good resource decisions for PNGC's future, we need 

to have some degree of certainty over Bonneville's future rate 

structure. Having the reinvention principles locked into customer 

contracts provides that certainty. Resource acquisition decisions 

at the utility level are long-term decisions -- taking into account 

a twenty or thirty year time frame. We need to have some assurance 

that, two years down the road, Bonneville will not use a new rate 

case to change its mind on the basic mechanics of its business 

plan. Without that certainty, PNGC and other utility players will 

be far less likely to commit to new resources -- whether they are 

conservation or generating resources. 

Draft Business Plan 

PNGC has reviewed the Draft Business Plan and has submitted 

comments to Bonneville (attached). In general, we are concerned 

that the plan is too preoccupied with finding new revenues rather 

than with controlling costs. In particular, it is vital that BPA 

institute an accounting system that can separate costs and revenues 

by its different business lines. We need to be assured that the 

services that BPA is offering its preference customers are costbased. On the other major items, we have the following comments: 

Tiered Rates -- The Draft Plan's implementation of tiered rates has 

substantial shortcomings. Consistent with the PPC tiered rate 

principles, which we endorse, the entire existing Federal Base 

System must be the only source of power and costs for Tier 1 

service and rates. Individual customers will be less likely to 

invest in conservation programs to meet load growth if they are 

having to foot the bill for regionalized conservation measures funded out of tier 1. Subsidizing tier 2 power rates to keep them 

artificially low provides less incentive for Bonneville to acquire 

low-cost resources and provides less of a conservation incentive 

for utilities seeking to meet new loads. 

In an increasingly competitive energy market, it is also important 

to remember that, by keeping the price of tier l low, a properly 

structured tiered rate system helps guarantee continued 

participation. This, in turn, guarantees ongoing debt repayment 

and fish and wildlife mitigation funding. 

Transmission and Unbundling PNGC is vitally concerned that 

Bonneville will inhibit competition by retaining the ability to 
127 

manipulate non-power factors like access to transmission. For 

utility systems to truly have the ability to make independent 

resource decisions, Bonneville must provide access to transmission 

service that is cost-based. In addition, we believe that postage 

stamp rates based on the entire BPA transmission system, including 

so-called "fringe" and transfer agreements, should be included in 

"rolled in" average pricing for both existing and new resources. 

It is increasingly important that we make sure we are comparing 

apples to apples as we discuss the impacts of unbundled services. 

BPA's stated goal of providing no increase in the tier 1 price over 

the current Priority Firm rate is misleading because tier 1 service 

will not include load shaping and other necessary products. 

Pooling -- As part of the business plan implementation, BPA should 

enter into contracts directly with pooling organizations for tier 

1 power, tier 2 power, and other products and services. Small 

utilities need to be able to take advantage of the economies of 

scale, risk mitigation, and efficiencies in resource operation 

available with pooling. 

Conservation -- PNGC supports Bonneville's conservation program 

reinvention. We believe that the costs of the current conservation 

program are not borne equitably. Those utilities who get the 

benefit of conservation savings should bear their costs. A lack of 

commercial and industrial customers virtually guarantees that PNGCmember utilities will never get back what they put into the current 

program and will continue subsidizing larger urban systems. For 

instance, as the present system is configured, PNGC members 

annually contribute roughly $150 million in revenues to Bonneville 

and get back roughly $10 million in support of conservation 

programs. At the same time, Seattle City light pays Bonneville 

about $40 million a year and gets that same $40 million back. 

A proper price signal, through implementation of a well structured 

tiered rate system, will provide ample incentive for us to acquire 

all cost-effective conservation and renewable resources. You must 

remember, cooperatives are locally controlled and operate without 

a profit motive. Our sole concern is providing the lowest-cost 

power to our members over the long-term. If that means acquiring 

additional conservation, then that is the path we will follow. The 

key is providing adequate planning information and the flexibility 

to permit an independent choice. PNGC is currently in the middle 

of preparing an Integrated Resource Plan. While we are required to 

do one as a condition of REA financing, we view it as an important 

tool in providing the lowest-cost resource acquisition possible. 

We have been alarmed by calls for a strict "command and control" 

style approach to conservation acquisition complete with penalties 

and surcharges for not meeting preestablished conservation goals. 

We believe that these efforts would put BPA in a regulatory role 

that violates the principle of local control inherent to memberowned utility systems. It is a heavy-handed reaction that ignores 

the key point -- we want to acquire all cost-effective conservation 
128 

and are obtaining the information to determine what that is. We 

want Bonneville to help us to succeed in meeting the Regional Act's 

conservation goals rather than to engage in practices that 

interfere with our local decision-making prerogatives. 

Conclus ion 

How far and how fast Bonneville should travel in the course of its 

reinvention is a complicated question. We believe the underlying 

competitive reasons for moving forward are sufficient to justify 

the effort to make Bonneville more cost conscious and more customer 

oriented. Implementation of a true tiered rate system remains the 

single most important component of a new competitive arena where 

customers have resource acquisition choices. While some may 

ultimately leave Bonneville, the competition alone will continue to 

drive the agency to become more efficient. A low-cost tier l will 

insure Federal d e bt repayment and fish and wildlife mitigation 

fund i ng. 

While muc h constructive work has g o ne into c harting a new path f o r 

Bonneville, customers must know the long-term implications before 

choosing to support or oppose the new policies included in the 

Draft Business Plan. Key to that knowledge is making progress 

toward signing new long-term power supply contracts. By sequencing 

the next rate case with the offering of new contracts, Bonneville 

customers will hav e a much better basis on which to judge the 

application of the principles included in the Draft Business Plan. 

PNGC has appreciated Bonneville's willingness to work together to 

define the road ahead and believes that delaying the process will 

hamper our ability to become more competitive -- as an industry and 

as a region. We do not support pushing back the rate case. Any 

such delay will also delay the day when we can adequately plan for 

our resource future. Without s ome s ense of certainty, the industry 

will sit on its hands -- choosing to forestall decision making and 

del a ying the ability t o benefi t from a more c ompetitive energy 

market. 

Again, thank you for the opportunity to testify today. We view 

this as a useful process and appreciate being included. I would be 

happy to answer any questions that you may have. 
129 

Propalld Outllat Jor llftblililin1 

Ntw Ba1iaeu Rllatioasbip 

A. Basic: Sequmc:e &lid Sc:hedule. 

I. Auaust 1 • D~eember IS, 1994- Negotiate eomplete eonncts (to be offemi 

after rate we). 

l . Ocmbor 10, 1994 •• BPA issues non-official "Preliminary Dl"'ft" me deslan 

that looks as muc:h lilce 1ft Initial propo~&l u possible. 

3. O~ber 10 • Dt.:ember 23, 1994 ··be issue workshops. 

4. January 9, lSISIS •• BPA publishes sin&le track rare c:as11 Initial Proposal. and a 

Ftdel"'l .P.taister Notice on tht proposed new. eontracts. 

S. J&II.IW'f 9 • July l, 19SI5 •• Ponnal rate .:aso. 

6. A11gust 1. 1995 •• Rl%t ROD iuued, SPA otTers new eontracts. 

7. October 1. 199S -New rates and new eontracts (for customers that accept 

shcm) become effective. 

1. Belin bilateral Mp1iationa imm8diately betw..n repraentatives of all 

cus1Dmers and BP A seament m~nt;trs in a ;ustomer driven process modtltd 

lftor Clk Tiered Rates and Products and Pricin& tuk forct diJcuuiotts. 

Tarstt- c:omplmd contra.ets by Dtctmbet lS, 19~. 

2. Initially, the discussions should encompus all tlemlllts or the business 

reluicmship in order of imponanct without lttwllptinc to dis'linauish betwllln 

c:oatract llld rlt! issues. Section C lists the key issues in !he order to INi 

rnolveci. 

L As ntptiacion progresRS, rat• issues will be idwlifitd (but will nmain 

wilhin dle negoti.tion discussions until lhe lnitial Proposal issutt). 

b. IssutS commaa to all c:ustomcrs will be tddrenecl md resolved first. 

c. Separate disciiiSions with eustomtr clautt 111d individual customers on 

unique issues may oc;ur in pll"'llel with main neaotiations .. 

d. Non-customtrs are free to initim their own informal discussio1111 with 

BPA. 
130 

3. BPA's October IH-4 "Preliminary Draft" proposal on Rate Deaign, Tiered 

Jlms, Mlllinal Coat, Service Cblrpa. Tr~~~smiaion and Cost of Setvice 

iS11111 will kick off dauilld intormaaal worbllops but will not be an initial 

propoul uad will not Aqllire beaiMinB of •• ..,.,.... nde. 

4. Tht fonDal rUI cue (llld "ex-pane• Nit) stanJ an Januuy 9, l99S. After 

customa IIICi BPA have COIIIJIIIted COIItract n•ao1ialions, any rue rela!ed 

conUKl imaa requirin1 7(i) approval btcome Plft ot rate ea.sc. 

5. Somt chiDIU 10 7(i) proc111 lhollld bt implemtntecl for upcoming rate cue 

INI mon fundamental chanac:s must be d.vclopad for all futura CISIIS. 

L Allow for direcc prennlltion co deciaionnMk•• on more thU1 one 

oceuion. 

b. Allow for CODtKtl between panies ad BPA staff' (subje~ tD notice, 

etc:.) without tile attd for trantcripa. Pll1i11 tec~uatin& opportunity for 

such contact will set the qenda and control input from other parties. 

Minutes of distii$Sion to bo kept and served on all parties. 

c.. Ellplor• IDIIM 10 allow p&rti11 ta respond to mattert raised in sutr 

britfinp to dccisiorunuen (U.. if dif!'erent from stafftmimony). 

6. Afhr Rate ItOD ·-· previously ntiiOiilttd contrects art fint•tllllecl {t.J., if 

neaotiatod uranatmtnt chanat dut 10 7(i) or to IICCOIIImodate bow BPA 

raolvtd punly rall iauas) and offl:l'od to all Cllltomen. 

C. Contract Issues. 

No ~mpt will bt made tu aartatte contract from ratt iauM initially ~ tha pani .. to 

the wntrKts should bt tl'et to nqotiue all elements of 1ha business IITI!\Eement. 

After Ill• fact, HYtral inuu may tum out 10 be sus.:eplible only to a 7(i) process (a..&.. 

IICU!al numeric:al rate schedlllt eban11es); others may need 7(i) approval {U.., cost 

allac:ation fonnula .lhe puties ml)' acree 10 ). 

Negotiations should swt with eorc: issues important to all parties and proceed to aonCoOTt or customer WJique iuu11. 

1. .Prapoted Core htuu in very ro11gh order of imporLam:11. 

a.. Defme Tier I riahts md obligt~ions. 

b. Define 1 couple Gf buic options for Tier 2 servic:e. 

;. D.tint flexibility riJhts. 

cl. Dtftl\t key shaping servic:c&. 
131 

e. Define baic: tru111niaion riahtt. 

f. Dofine purdlue relllionship (full, partial) ud rules for switchina. 

g. Define tennin&Don rightl. 

h. Define billina detmninulls. 

i. Dlfine buic pooling ri;hl& 

j. Create procedures for dispull resolutions 111d contract intfrprahdion. 

Jr.. Improve r&te ca. procedures. 

2. Non-Core 

L Schedwina procedun:s. 

b. Billing pRK:edures. 

c. Force majeure 

d. shar .. thl-lhortqo ri&ills llld obligi.Dollll __ ...• 

e. Plannina insufficiancy rights and obligarion1. 

f. Inu.rruptinn riahts. 

i· Stancluds for service. 

h. :Exdlanp of pl111ning and oper&tion informltion. 

i. Exhibits md rules for revising. 

j. R.alationahip to otMr documenu. 

Hga: Di~pule Resolution, Contra=t Interpretation and Rate Case Procedures ate listed 

at the end of the care issues. However, the development of a mutually satisfacwry and lair 

method to r1110lve diiPutes md dt~:ide i511ue1 mu must necessarily be left parti&lly open. to 

adjust &:QDtracts for future events md assure timely performance is critical to a succetsful 

buSiness arrm&emtnt. In addilion, how partl11 decide to resolve failure disputes will ha.ve a 

signifi~t eft'ec:t on how much dawl need be spelled uut in th• contracts at this rime. 

07flM4 . 1 ~ua,. . oc:zt7ft .01 
PertltflfS in Po-r Mana~nt 

BPA Public Involvement 

P.O.Box 12999 

Portland, OR 97212 

Subject: BPA Draft Business Plan 

Dear Sir or Madam, 

INTRODUCTION 

132 

August 3, 1994 

PNGC and its Member Rural Electric Cooperatives consider the BPA Business Plan and the 

fundamental changes that it envisions the most important policy development affecting BPA and 

its Customers in the last ten years. Allowing for changes in scale between BPA and 

Cooperatives, the many competitive challenges that BPA describes in the Business Plan are 

exceptionally real to your cooperative Customers. Therefore, we appreciate this opportunity to 

comment. 

As stated above, we strongly agree with BPA in its description of the competitive challenges that 

we must confront over the next few years. Further, we believe that our businesses' continued 

success depends on BPA's success. We therefore support BPA's decision to vigorously pursue 

a restructuring of its business and the reinvention of its various business lines. 

However, the Draft Business Plan narrative' has a fundamental shortcoming. It fails to 

adequately recognize the reverse of our competitiveness equation; that BPA 's competitiveness 

js integrally deoendcnt on jts Customers' competitiveness. Throughout the document solutions 

to BPA 's perceived problems are proposed and considered without adequate regard to the effects 

on, particularly, Cooperative Customers and our consumers. The discussion below on tiered 

rates is the most important example of this situation. If the implementation of the Business Plan 

is to be successful over the long term, BPA must more fully recognize this interrelationship and 

take a substantial portion of responsibility for its Cooperative Customers' competitiveness. 

'In the months leading up to publication of the Draft and in the weeks since, we have had 

many discussions with BPA staff that have assured us that BPA has not forgotten the 

interrelationship between BPA 's and its Customers' competitiveness. However, the marked 

failure of the narrative to reflect these assurances and to describe a mutually satisfactory business 

relationship has been most disappointing. 

Pacific North-t Oeneratlng Coope,..tlwl 

711 N.E. Halsey 

Suite 200 

Portland, OR 97232·1288 

(503) 288-1234 

Fax (503) 288·2334 
133 

Page2 

August 3, 1994 

This shortcoming directly leads to the Draft's preoccupation with finding new revenues (from 

both existing and new customers) rather than with controlling costs. We recognize the cost 

control efforts in the Draft; but find them inadequate2• These limited efforts seem more 

interested in apportioning pain rather than putting BPA and our industry on a sound and 

business-like path. 

NEW RESOURCES & TIERED RATES 

The primary source of increasing costs for our industry is the cost of new resources, both 

generation and conservation. BPA's Business Plan must provide a competitive environment to 

control these costs and must help remove both economic and political impediments for customer 

acquisition of resources. The Draft Plan's implementation of tiered rates and the reinvention 

of conservation have substantial shortcomings with respect to these goals. 

I. The entire existing FBS' must be the only source of power and costs for Tier 1 service and 

rates. All new resources including short term power purchases, other generation and all new 

conservation must be the only source of power and costs for Tier 2 service and rates. If the 

fmal Business Plan fails to make this clear separation between Tier 1 and Tier 2 then the 

competitive market and Customer acquisition of both generation and conservation resources will 

be short circuited. 

Consider the negative effect on a Customer's conservation program from BPA 's failure to keep 

all new conservation costs out of Tier l rates. A given customer could be paying for all of its 

2PNGC and its Members recognize the many political pressures to continue excessive 

spending in a number of areas. We are committed to helping BPA with our Members of 

Congress to impress upon them the importance of making sound business decisions for BPA 

rather than continuing what is often perceived as "federal largesse". 

'Here, the term FBS is used broadly. It may include some existing resources such as Idaho 

Falls, short term power purchases for the purpose of maintaining FBS capability in below critical 

water years, and possibly Tenaska. 
134 

Page 3 

August 3, 1994 

own new conservation costs with its own money; that is a "Customer-Tier 2" cost in their rates. 

At the same time BPA will be funding at the same Customer's Tier I expense another 

Customer's new conservation. The obvious unfairness of this situation could inhibit the (first) 

Customer from investing in its own conservation'. 

A similar situation arises for generation . Consider the first Customer above investing in new 

generation at its own cost; that is as a Tier 2 cost. If BPA subsidizes a new BPA resource by 

placing some of its costs in Tier l , this customer will end up paying some of another customer's 

Tier 2 cost. Again, independent resource acquisitions will be inhibited . There is another 

potential way for this inhibition to occur. The customer who wants to acquire its own generation 

could be concerned that BPA will subsidize its Tier 2 power sufficiently to keep the BPA Tier 

2 rates below the customers costs. Just the possibility of this occurring could prevent Customers 

from their own independent resource acquisitions. 

Ultimately, BPA can not give itself the flexibility to include uncompetitive, or simply higher, 

tier 2 resource costs (conservation or generation) in Tier I power costs or our mutual goals for 

a competitive market and Customer acquisition of new resources won't work. 

As to BPA 's concern that at least ten percent of FY 1996 loads should be subject to the second 

tier, we note that according to BP A data on the December through March loads and resources 

of the federal system, at least fifteen percent of loads would be in Tier 2 under our approach 

during these winter months (based on the monthly average megawatts of power purchases). 

Since this is the load period that will strongly determine our new resource requirements, 

certainly BPA's concern is satisfied . 

2. We see the issues of BPA's resource integration services, including transmission services, in 

the framework of providing a competitive environment for resource acquisitions. BPA should 

price these services at the same price for BPA resources as for Customer owned resources. 

BPA should not use these services to make its Tier 2 resources look more competitive than they 

are. 

4

Specifically, items Ia and 3b in the Conservation Reinvention Principles need work. First, 

market transformation funds must be limited; certainly, no more than $10 million per year. And 

two, there can be no "forgiveness" of energy service charges. All new resource costs are Tier 

2 costs; they must not be put in Tier I at any time. 
135 

Page 4 

August 3, 1994 

Specifically with respect to transmission, we believe that postage stamp rates based on the entire 

BPA regional transmission system, including so-called "fringe" and transfer agreements, should 

be included in "rolled-in" average pricing for both existing and new resources. 

The ability to deliver federal and non-federal power at the same rate to an existing BPA power 

requirements customer's system is essential to the development of a competitive power market. 

lfBPA can reach a utility for delivery of federal power, it should retain the responsibility to put 

in the arrangements necessary to reach such a system for wheeling purposes. Without this 

leveling of the playing field, the competitive power market will remain economically out of 

reach for all of BPA 's requirements customers who are currently served via transfer 

arrangements. Because of the highly integrated nature of the transmission system, and the 

multiple uses and benefits of new and existing transmission facilities, identifying separate lines 

and facilities as the basis for transmission rates is difficult and contentious. BPA should offer 

transmission rates to both federal and non-federal users based on rolled-in , embedded costs. As 

facilities which were previously classified as "fringe facilities" come into wheeling use, the cost 

of these should be included in the "network segment" revenue requirement; preference customers 

should then be granted points of delivery at their systems (the same points where Federal power 

is delivered) under IR or other network transmission contracts. 

The "single utility" principle should continue to guide BPA 's transmission planning so as to 

avoid redundant investment. Costs associated with transferring power over third party systems 

may arise because the best plan of service requires use of facilities other than BPA's. These 

should be treated the same as BPA's transmission system costs and included, as appropriate, in 

either the BPA 's wheeling or federal power revenue requirement. If new costs to transfer across 

non-federal systems are incurred as a result of a preference customer requesting wheeling 

service, these new costs should be treated in the same manner as if BPA had made an investment 

in new transmission plant to meet such request. 

3. The ability to pool all loads and resources within a pooling organization is critical if small 

utilities are to be competitive with BPA and other organizations in resource acquisitions. BPA 

should enter into contracts directly with the pooling organization (including wholesale power 

utilities - e.g. G&Ts) for Tier l power, BPA Tier 2 power (if purchased by the pooling 

organization) and all integration services. 

Small utilities need to be able to take advantage of economies of scale and efficiencies in 

resource operations and acquisitions the same as large systems. In order to do this, co-ops must 
136 

Page 5 

August J, 1994 

be able to do real-time scheduling and marketing of power to minimize costs and take advantage 

of load diversity. Advantages to BPA include administrative benefits of working with fewer 

organizations and the very important competitive yardstick that pooling organizations will 

provide for BPA's own new resource activities. 

Without pooling, take-or-pay obligations for power would be unfair to small utilities. Some 

small utility loads are much more volatile than for the generally more diverse loads of large 

utilities. One large industrial load can go away overnight for a small utility. Some small 

utilities have large proportions of their loads in one rate class that have homogeneous reactions 

to economics or weather. The small utility will find it virtually impossible to effectively 

mitigate the financial risk of take-or-pay provisions in the manner of large utilities or pools. 

BPA insists on being able to operate its system on an integrated basis, but is dragging its feet 

on letting small systems pool together to operate their combined system on an integrated basis. 

PNGC's proposed tiered rate implementation does not preclude BPA from operating as it wants. 

We only require a reasonable accounting of costs. 

4. In order to acquire resources, Cooperatives will need to do Integrated Resource Plans (IRPs). 

It is important to us that BPA should not include any provisions in our power sales contracts that 

would constrain us from meeting our social goals with respect to generation or conservation. 

The authorities of BPA and the Council should not be expanded beyond what was required by 

the Act. Local control remains important for Cooperatives and an effective way for us to stay 

competitive at the retail level. Additionally, it is important that BPA not interfere in the IRP 

requirements from the Rural Electric Administration (REA). 

CONTROLLING COSTS 

Controlling costs must become a way of life for the restructured BPA; it must become part of 

the corporate culture. This must be accomplished if BPA and its Customers are to be 

competitive. Market forces and non-market measures must be brought to bear. 

1. We suggest, as others have, that BPA should institute an accounting system that can separate 

costs and revenues by its different business lines. Your Customers must be satisfied that they 

are not paying for other entities' services. The various business lines (transmission, Tier I 

power, Tier 2 power --including purchases, specific resources and load growth services--, 

resource integration services and conservation --DSM--) must sink or swim on their own. If one 

is found to be uncompetitive, costs will be cut, or the business line will close up shop. 
137 

Page 6 

August 3, 1994 

2. Another suggestion for controlling costs is to develop measures of effectiveness where market 

forces do not exist. Specifically in the Fish & Wildlife arena, BPA must prove to itself as well 

as to its Customers and the public at large, that its expenditures are cost effective. We believe 

that some measures for fish have actually been counter-productive; for example the recent 

additional spill program. We believe that other programs have not been cost effective when 

compared to alternative measures; for example flows versus transportation. As your customer 

survey revealed, BPA has been slow to take this type of Customer advice. We recommend that 

your final Business Plan remedy this situation. 

REALLOCATION OF COSTS 

The draft Business Plan is notable for what it includes as well as what is left out. If the aim of 

this process is to put both Bonneville and its customers on a more competitive footing, the 

agency should not overlook major opportunities to mitigate increased rate pressure. 

Section 4 (h) (10) (C) of the Northwest Power Act directs BPA to treat expenditures in excess 

of the power share of a hydroelectric project's cost "as payments for other project costs for 

which BPA is responsible under the law." This provision provides clear direction to the 

Administrator to allocate a share of the fish and wildlife expenses of multipurpose facilities to 

project purposes other than power production. Those expenses are to be borne by the taxpayers 

rather than the ratepayers and should offset a portion of BPA 's annual Treasury payment. 

Section 4 (h) (10) (C) is applicable to past, present and future expenditures and adds up to a 

significant dollar amount. Since passage of the Northwest Power Act, Bonneville has reportedly 

spent $270-$325 million on fish and wildlife mitigation that is attributable to non-power project 

purposes. In addition, it continues to add to that total by at least $50 million a year. 

As part of Bonneville's reinvention or by separate action, PNGC urges the Administrator to 

exercise his responsibility under Section 4 (h) (10) (C). While BPA has ignored this requirement 

in the past, exponentially rising fish and wildlife costs pose a significant threat to the future of 

competitiveness of the agency and its customers. 
138 

Page 7 

August 3, 1994 

OTHER ISSUES 

A variety of other issues concern us in our desire to see that we and BPA are competitive. 

!. Exchanging IOUs could receive a windfall from the implementation of Tiered Rates. We 

believe that reform of the Residential Exchange is mandatory to prevent this. 

2. The Low Density Discount, mandated by the Regional Power Act, is also an essential element 

of our competitiveness. Any changes contemplated in the LDD should not hurt our 

competitiveness, should take into account the purposes of the Act and should be done in 

consultation with your Cooperative Customers. 

3. The DS!s may also receive a windfall from the implementation of tiered rates; that is they 

may escape sharing in some of the costs of load growth. We believe that BPA should neither 

discriminate in favor, nor against, the DS!s relative to Public Utility industrial consumers. BPA 

should institute whatever reforms are necessary to put the DSis on a par with other industrial 

consumers in consultation with your other Customers. 

4. Finally, it is our strongly held opinion that the complexity and risks of the BPA restructuring 

and the implementation of tiered rates requires that we negotiate new power sales contracts 

before the next rate case. We simply must have contractual guarantees as to our business 

relationship and pricing methodologies. A genuine partnership between BPA and its Customers 

can permit nothing less. 

CONCLUSION 

The Business Plan, the restructuring of BPA and the challenging new environment in which we 

find ourselves are all terribly complex. It is not possible in one letter to fully communicate our 

concerns or our ideas. Particularly in the area of tiered rates implementation, we have additional 

thoughts that may be helpful. We look forward to the additional opportunities to exchange 

information to which the BPA staff have committed. The PNGC staff and the undersigned are 

eager to answer your questions or continue discussions at your convenience. Again, thank you 

for this opportunity to comment on the Draft Business Plan. 
Page 8 

August 3, 1994 

Sincerely, 

() -ng~, Da~per ~fl&L Executive Vice President Ctera1 M 

139 

MM""' C"P~p f2.r 

Raf9seyer, Manager 

lachly Lane Co-op 

J~~ 

_]5:;~ Dave Sabala, Manger -..__ 

Douglas Electric Co-op 
140 

Page 9 

August 3, 1994 

~ Lincoln Electric Co-oP. 

c;;;2/-&c 

Lew Greene, Manager Peter Cook, Director 

a;?~ Lower Valley Power & Light 

Cliff Stewart, Manger 

Orego il Electric Co-op 

mer Sarns, Man ger 

Tann_er El~tric Co-op~ _ 

~e /44..-----

a:veseuss:Manger 

West Oregon Electric Co-op 
141 

STATEMENT OF JUDY LAMSON 

Mr. DEFAZIO. And finally, Ms. Lamson. 

Mr. LAMSON. Good morning, Mr. Chairman and Mr. Smith. My 

name is Judy Lamson, and I am a policy specialist with the Washington Utilities and Transportation Commission. 

We very much appreciate the opportunity to present the Commission's views this morning. In the Commission's role as regulators 

of IOUs, we are very concerned with BPA's treatment of the residential and small farm customers of these IOUs. Both the business 

plan and the proposed tier-rate methodology would impose an arbitrary limit on the rights of these customers to the Federal-based 

system. 

Let's look at the history of the Power Act, its original intent and 

the facts as they are today. Prior to the passage of the act, regional 

interests were competing for access to BPA's limited, low-cost energy resources. 

Because at that time BPA was not authorized to acquire new resources, BPA was forced to notify its customers that it had insufficient power to meet their needs. BPA initiated a process to allocate 

that limited Federal power to cover a fraction of each customer's 

load. 

At the same time, customers of IOUs were using indirect methods to gain the same access to the low-cost Federal resources as 

their neighbors served by public utilities. I think many of you in 

the room today are familiar with the State of Oregon's creation of 

the Domestic and Rural Power Authority and the City of Portland's 

litigation in this area. 

The act was designed to resolve these problems, to provide equal 

access to the Federal base system and to allow BPA to acquire new 

resources. The act specifically gave residential customers of all regional utilities, both public and IOUs, direct access to low-cost Federal power through a priority firm rate. 

Unlike the other public utilities, the IOUs are required to offer 

something in return for this access: An adequate power supply at 

the reasonable cost. The IOUs must offer to sell BPA an equivalent 

amount of power at their average system cost, well below what it 

would have cost BPA to acquire new resources. 

The Direct Service Industries, or DSis recognized at that time 

that their contracts to the existing Federal system were about to 

expire and traded planning certainty in the long run for quote, 

"dramatically higher rates and substantially lower power quality," 

close quote. That was a statement made by a DSI witness testifying on the Power Act before the Subcommittee on Energy and 

Power back in 1979. 

Using the projections prepared by BPA in 1979, attached to the 

Senate committee report on the Power Act from that same year, 

the Commission has estimated the rate distortion that has transpired since the passage of the Power Act. The results are startling. 

The IOU customers are receiving less than one-third the benefits 

intended to be achieved by the act. 

In 1986, BPA offered the aluminum smelters a special variable 

rate which is currently 21 mills per kilowatt. BPA argues that 

without that special rate, it might have lost up to 1000 megawatts 

of industrial load. Meanwhile, one of our IOUs, Puget Sound Power 
142 

and Light Company, is purchasing 500 megawatts of power from 

new resources at twice the price of the current variable rate, about 

42 mills per kilowatt hour. We recognize that maintaining the viability of the DSis is an important public policy issue. We are urging, however, that as we 

consider the future of BPA, we look at the entire economic picture, 

and balance the interests of all of the stakeholders in the region. 

Let's look at what might have transpired if BPA had not chosen 

to offer a variable rate to the DSis and see how much money BPA 

could have saved. If BPA had offered 500 megawatts of power to 

Puget at the current nonvariable industrial rate of 27 mills per kilowatt hour, instead of selling it to the DSis at the variable rate of 

21 mills per kilowatt hour, BPA would have received an additional 

$28 million per year in revenue. Without the variable rate, BPA 

would be serving the remaining aluminum load and others at the 

regular industrial rate, receiving an additional $114 million per 

year in revenue. That is not all. 

Puget would be buying that BPA power for about 15 mills per 

kilowatt hour less than Puget is now paying other suppliers, and 

Puget would be saving about $72 million per year. This would 

lower Puget's average system cost to an approximately $35 million 

reduction in BP A's annual purchased power expense through the 

residential exchange. In total, BPA could have saved about $178 

million in 1994. In summary, I would like to make the following points: first, we 

expect BPA to recognize the IOU residential and small farm customers of IOUs have the same rights to the Federal base system 

as do the customers of public utilities. BPA's sale of power to IOUs 

is at cost-based rates. It is not a subsidy. 

Second, we expect BPA to recognize the exchange power purchase for what it is, a lowest cost, highest quality of any major resource acquisition BPA has made since passage of the act. 

Third, we expect BPA to cease treating the difference between its 

power sales revenue and its purchased power expense related to 

the exchange as a net cost subject to management control in the 

same manner as overhead. Fourth, if BPA proposes to provide the DSis with low-cost power, 

they should be prepared to consider low-service quality, such as 

through more interruptible power or other options to ensure that 

all customer classes cover their cost of service. This matching of 

service quality with costs to serve should be done before the new 

contracts are executed. 

We appreciate the efforts of this oversight committee and Congressman DeFazio's task force in ensuring the continued accountability of the Bonneville Power Administration, and we thank you 

again for the opportunity to present our views. 

Mr. DEFAZIO. Thank you. 

[Prepared statement of Judy Lamson follows:] 
143 

TESTIMONY OF 

JUDY LAMSON, POLICY SPECIALIST 

WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION 

before the 

U.S. HOUSE OF REPRESENTATIVES 

COMMITTEE ON NATURAL RESOURCES 

SUBCOMMITTEE ON OVERSIGHT AND INVESTIGATIONS 

"BPA at a Crossroads" 

August 9, 1994 

Thank you for the opportunity to present the views of the Washington Utilities 

Transportation Commission at such a timely hearing on issues that are of critical importance 

to the citizens of the Northwest. 

The Washington Utilities and Transportation Commission, or WUTC, regulates the 

investor-owned utilities in Washington. These utilities serve about 55% of the population of 

the state, or about 2 1/2 million people. The remaining population is served by municipal 

utilities, public utility districts, electric cooperatives, and mutual power companies. In our 

role as regulators of investor-owned utilities, or IOUs, we are very concerned with BPA's 

treatment of the residential and small farm customers of these "IOUs." 

Under the Pacific Northwest Electric Power Planning and Conservation Act (the 

Power Act), these customers are provided equal access to the benefits of the federal 

hydropower system through an "exchange" program. This exchange will be the focus of our 

testimony. We will leave detailed comments on BPA's conservation programs and fish and 

wildlife obligations to others. The WUTC and other state agencies are continuing to review 

BPA's business plan and will have additional comments in the future which we will share 

with the Committee. 

We are becoming increasingly concerned that the Bonneville Power Administration 

has lost sight of the charges that Congress imparted it in 1980 under the Power Act. The 

Power Act's primary purposes are to encourage conservation and renewable resources, to 

protect anadromous fisheries, to provide for an adequate regional power supply, to ensure 

public participation in energy decisionmaking, and to provide equal access to the benefits of 
144 

the federal hydropower system to ALL citizens of the region for their domestic and small 

farm needs. 

BPA' s draft business plan contains many desirable elements, such as efficiency 

improvements, a streamlined bureaucratic process, unbundling and repricing of certain 

products and services, and offering of additional and more specialized products and services. 

While proposing to implement these improvements, however, BPA has lost sight of the 

origins of the residential exchange program, how it benefits BPA, and what the alternatives 

to this program were at the time the exchange program was created by Congress. 

I would like to focus at this point on the history of the Power Act, its original intent, 

and the facts as they are today. 

THE REGIONAL ENERGY PICTURE PRIOR TO THE ACT 

Prior to the passage of the Act, the regional interests were competing for the right to 

BPA's limited low-cost energy resources. At that time, Bonneville was not authorized to 

acquire new resources to meet increasing demands. Bonneville would have been forced to 

allocate each utility's share of federal power to a fraction of its load. In fact, BPA initiated 

such an allocation process in 1979 to do just that. The public utilities and the Direct 

Services Industries (DSis) opposed such an allocation and supported Bonneville's efforts to 

obtain authority from Congress to acquire additional resources, thus avoiding allocation. 

Without the Act, BPA may well have been obligated to serve the residential customers 

of the IOUs through indirect methods. The state of Oregon had created a new public utility, 

the Domestic and Rural Power Authority, to purchase power from BPA to serve residential 

customers in Oregon. The city of Portland had filed suit seeking the right to acquire lowcost resources from BPA for its residents and municipal facilities. In both of those cases, 

BPA would have been required to serve additional customers at the same rate it served the 

public utilities, but without the benefits of the lower-priced exchange power. Furthermore, 

either of these would have meant less cheap power for the public utilities. 

At the same time, BPA had notified its customers that it had insufficient resources to 

meet their requirements, and BPA's contracts with the direct service industries were about to 

expire. The DSis were concerned enough that BP A would not have enough power to serve 

them that they had contracted to buy a portion of the output of the now-terminated WPPSS 

nuclear plants 4 and 5. 

THE POWER ACT WAS PASSED- SOLVING THE PROBLEMS 

The Act was designed to resolve these problems. It gave the residential customers of 

ALL regional utilities access to low-cost federal power. The Act allowed BPA to purchase 

additional resources needed to serve load growth, and it created the residential exchange 

program to provide BPA with a large and assured low-cost resource. The DSis gave up their 

2 
145 

contractual rights, which were about to expire, to the existing federal system, in exchange 

for new, long-term contracts at higher rates. The DSis specifically recognized that planning 

certainty in the long-run was worth "dramatically higher rates and substantially lower power 

quality." That was a statement made by a DSI witness testifying on the Power Act before 

the Subcommittee on Energy and Power in 1979. BPA appears to be forgetting these very 

important facts. 

The legislative history of the Act is replete with members' statements on how the 

resource allocation and rate construct of the Act were designed to assure residential 

customers lower cost power and to provide the industrial customers with higher cost power. 

Senators Hatfield, Packwood, Jackson, and McClure, and Representatives Ullman, Duncan, 

Moorhead, Kazen, and Dingell all spoke specifically about how the Act was to result in 

lower rates for residential customers, including those of the IOUs, and higher rates for 

industrial customers. Attachment I includes excerpts of these comments. 

The residential exchange program was a part of the process to assure BPA an 

adequate power supply and to avoid allocating limited resources. The investor-owned 

utilities did not seek the exchange -- they would have preferred to be customers of BPA just 

like the public utilities, simply purchasing power for the IOU residential and small farm 

loads. That would have allowed the IOUs to avoid high-cost new resources planned at that 

time, such as Colstrip 3 and 4, Valmy, Boardman, Skagit, Pebble Springs, Creston, and so 

forth, all of which were expected to cost much more than the "average system cost" rate at 

which the exchange program requires the IOUs to sell power to BPA. 

Under the Act, the "priority firm" rate clas~ was established, consisting of the 

"general requirements" of the public utilities and federal agencies, plus the residential and 

small farm loads of the IOUs. This class of customers is entitled to be served with BPA's 

lowest-cost power resources. First, this customer class is entitled to 100 percent of the 

"federal base system" resources, BPA's cheapest. When the first source is exhausted, this 

customer class then receives service from the power BP A buys under the residential 

exchange agreements. Only if these sources are insufficient will the public utilities and 

residential customers be served with new, higher-cost resources. 

Under the residential exchange program, BPA sells power to the investor-owned 

utilities in an amount sufficient to serve the IOU residential loads at the Priority Firm rate, 

the same rate schedule available to public utilities under section 7(b) of the Power Act. 

Unlike the public utilities, however, the investor-owned utilities must offer something in 

return: they must offer to sell BPA an equivalent amount of power at their average system 

cost. (Section S(c)(l) of the Power Act.) BPA has the option-- but not the obligation-- to 

purchase this energy. (Section 5(c)(5) of the Power Act.) 

3 
146 

RESOURCE ALLOCATIONS UNDER THE ACT 

BPA currently meets its priority firm load with about 8000 megawatts of power from 

the federal base system, plus about 2000 megawatts from exchange purchases. Without the 

power which BPA purchases under the exchange agreements, BPA would have faced a 

massive power deficit beginning in 1981 and probably would have been forced to complete 

high-cost resources, such as WPPSS nuclear plants I and 3. The result would have been 

much higher rates for the public utilities, the DSis, and all other BPA customers. The 

exchange is saving BPA customers hundreds of millions of dollars per year compared with 

the higher-cost resources BPA would otherwise have acquired. 

Under the Act, BPA's non-priority customers, including DSis, are served with 

resources not assigned to the priority-firm pool. These resources include the exchange, 

surplus, and new resources. Currently, the DSis receive one fourth of their power on an 

interruptible basis from surplus hydro when available. The remaining three-quarters is 

served 86% with BPA purchases from the residential exchange, and 14 % with new resources 

BPA has acquired from various sources. The cost of providing these resources, plus 

transmission and conservation costs allocated to the DSis, adds up to about $700 million per 

year. (BPA 1993 Wholesale Power Rate Development Study, Table 14.) However, the 

DSls pay only about $500 million per year to BPA for this power. This is largely due to the 

fact that the variable rate which the DSis pay is tied to the world aluminum market price, 

which has remained depressed. Thus, the cost to provide DSI service is forecast to cost 

nearly $200 million more than the DSis will pay for power. 

EXPECTATIONS UNDER THE ACT-- AND REALITY 

We've reviewed the projections prepared by BPA and attached to the Senate 

Committee Report on the Power Act (Report No. 96-272, July 30, 1979, Appendix B), and 

we've made some simple calculations based on those projections. The General Accounting 

Office report "Impacts and Implications of the Northwest Power Bill" (1979) includes a 

graphic depiction of the expected rates for each class of Bonneville customers. A copy of 

that graph is included in Attachment 2. 

When Congress passed the Power Act, residential customers of private, or investorowned , utilities were expected to receive some $650 million per year in benefits from the 

exchange program as of 1994. Instead, the current benefits are less than $200 million per 

year. Even adjusted for the lower-than-forecast loads, the exchange benefit would have been 

$450 million for 1994. 

In BPA's 1979 forecast, the cost of power purchases projected from the residential 

exchange for 1994 were expected to average about 34 mills/kwh, and the priority firm rate 

was expected to average about 22 mills/kwh, so that residential customers were expected to 

receive an approximate 12 mill/kwh benefit under the exchange. Instead , BPA is paying 

only on the order of 32 mills for the exchange power, and today's priority firm rate is about 

4 
147 

28 mills, so that the residential customers receive only a 4 mill/kwh benefit under the 

exchange. 

On the other hand, for 1994, it was expected that the DSis would pay 10 mills/kwh 

more than the expected priority firm rate paid by public utilities and residential customers, or 

$400 million per year more than the priority firm rate. Adjusted for the lower loads which 

actually materialized, the DSis would have paid $240 million over and above the priority 

firm rate. Instead, the DSis today are paying much less than the priority firm rate -- by 

more than $100 million. Today's priority firm rate of 28 mills/kwh is 7 mills more than the 

DSI rate of 21 mills/kwh. 

Today, the residential ratepayers are paying a lot more than was intended when the 

Power Act was passed, and the DSis are paying a lot Jess than intended. The residential 

customers are receiving less than one-third of the financial benefits intended by Congress. 

The DSis are the only customer group paying Jess than intended. EPA's proposal to limit 

the exchange included in its Business Plan, would only exacerbate this distortion. 

WHY ARE THINGS SO DISTORTED? 

The origin of the current rate distortion is in a 1984 amendment to the Average 

System Cost methodology approved by BPA without engaging in the consultative process 

with the state Commissions or the Northwest Power Planning Council as directed by 

Congress in section 5(c)(7) of the Power Act. In that decision, BPA removed the equity 

return and federal income tax from the price it pays to the IOU s for power. In effect, BPA 

now requires the IOUs to offer BPA power below the IOUs' cost as a precondition to 

purchase power from BPA at EPA's cost to serve the IOUs' residential customers. If 

anything, the residential exchange is a subsidy of Bonneville by the residential customers of 

the IOUs, who must pay not only the full cost of BPA power in rates, but also the equity 

return and federal income taxes associated with the IOUs' power resources. 

Not only is BPA buying power from the IOUs below cost, but BPA is receiving far 

less from the DSis than projected, largely due to the Variable Industrial rate paid by the 

DSis, as discussed above. 

BPA COULD El\'HANCE REVENUES WITH SALES TO INVESTOR OWNED 

UTILITIES 

In 1986, BPA offered the aluminum smelters a special "variable" rate, tied to the 

world price of aluminum. BPA has argued that, without the special rate, it might have lost 

up to 1000 mw of industrial load. Currently, the DSis are paying about 21 mills/kwh for 

power under this rate. Meanwhile, Puget Sound Power & Light Company is purchasing over 

500 megawatts of power from new resources at prices of around 42 mills/kwh . We 

recognize that maintaining the viability of the DSis is an important public policy issue. We 

are urging , however, that as. we consider the future of BPA rates, we look at the entire 

5 
148 

economic picture and protect the interests of exchange customers. Let's look at what might 

have transpired if BPA had not chosen to offer a variable rate to the DSis. 

If, instead of offering the DSis a variable rate, BPA had offered power to Puget and 

others at the regular, non-variable DSI rate, and Puget and other utilities had purchased that 

power instead of purchasing contracts for gas-fired power, both Puget and BPA would be 

better off. 

BPA would now be selling Puget about 500 megawatts of power at the current nonvariable Industrial Power (1P) rate of 27 mills/ k'Wh, instead of the Variable Industrial (VI) 

rate of 21 mills/kwh, and would therefore be receiving an additional $28 million year in 

revenue. But that's not all. Since BPA would not have offered the variable rate, BPA also 

would be serving the remaining aluminum load and selling power to others at the regular 

Industrial Power rate, rather than the Variable Industrial rate. BPA would be receiving an 

additional $114 million per year in revenue from those sales. That's still not all. 

Puget would be buying that BPA power for about 15 mills/kwh less than Puget is now 

paying other suppliers, and Puget would be saving about $72 million per year. Since about 

half of Puget's load is residential, Puget sells about half of its power to BPA, so the $72 

million reduction in Puget's power cost would result in a $35 million reduction in BPA 's 

purchased power expense through the residential exchange. 

Altogether BPA would have been much better off had it sold power to Puget at the 

regular industrial power rate rather than selling to the DSis at the lower variable rate. BPA 

would be receiving $28 million in extra revenue from power sales to Puget, $114 million in 

extra revenue from higher-priced sales to aluminum smelters and $35 million in savings in 

purchased power costs through the exchange. Altogether, offering power to Puget at the 

regular DSI rate instead of offering the variable rate to the DSls could have saved BPA about 

$178 million for 1994. 

WHERE DO WE GO FROM HERE? 

In view of this serious shonfall in benefits to the residential customers of the region 

compared with what Congress expected and intended, one would hope that BPA's new 

"reinvention" activities would include restoring the residential exchange to expected levels in 

a manner mutually beneficial to both BPA and the IOUs. One would expect BPA to be 

looking for ways to bring its cost of service into balance with the rates it charges all 

customers. In fact, we are finding exactly the contrary. BPA 's Business Plan and its 

preliminary tiered rates methodology appear directed at exactly the opposite result. 

First, the draft Business Plan carries an explicit goal of holding s12w the residential 

exchange benefits to $200 million per year, less than a third of what BPA forecast at the time 

Congress was considering the Power Act. There is absolutely no logic or methodology to 

the proposed target, and it bears no relationship to any change in either BPA power supply 

6 
149 

costs or exchange utility power supply cost. BPA's own recent forecast of exchange benefits 

over the next seven years is in the $285 - $350 million per year range, and we expect those 

benefits to be received. A copy of that forecast is included in Attachment 3. 

Second, BPA's July 1994 Preliminary Draft Tiered Rates Methodology proposal 

utterly fails to recognize the residential customers as a legitimate component of BPA's 

obligation to provide service from the existing federal system. This is in direct conflict with 

sections 5(b)(l) and 7(b) of the Act. BPA's Tiered Rates proposal would allocate the 

"existing system" among the public utilities and the DSis. The exchange customers would 

only be given access to power at undefined tier one rates, with no specific link to the federal 

base resources. The residential customers of the IOUs are entitled under the Power Act 

to the same service from the federal system as the public utilities. The DSis do not 

share this entitlement. This must be acknowledged by BPA. 

CONCLUSION 

We recognize that many of the historical circumstances under which the Act was 

drafted have changed, and we certainly do not expect BPA to follow blindly along a 

previously selected route which has evolved in other ways in the past decade and a half. We 

do, however, expect BPA to adhere to the primary directives and intent of the Act. We 

welcome any assistance the Subcommittee can provide in this regard. 

First, with respect to the residential exchange sales, we expect BPA to recognize the 

IOU residential customers as a legitimate load which BPA is obligated to serve. Residential 

and small farm customers of IOUs are entitled to pay the same rates and are entitled to the 

same service and recognition that other Priority Firm customers receive. BPA's sale of 

power to IOUs is at cost-based rates. It is not a "subsidy." 

Second, with respect to the power BPA purchases from the investor-owned utilities 

under the exchange, we expect BPA to recognize this power purchase for what it is: the 

lowest cost, most reliable, best shaped power -- both seasonally and by time of day -- of any 

major resource acquisition BPA has made since passage of the Act. This IOU power costs 

BPA less than half of the cost of power from WPPSS 2 and significantly less than the power 

from the proposed Tenaska project. Furthermore, IOU power comes complete with capacity 

reserves and other valuable attributes. It is a purchased power opportunity at a price 

favorable to BPA. Moreover, if at some point BPA can find a cheaper source of power, 

section 5(c)(5) of the Power Act provides for that flexibility. 

Third, we insist that BPA recognize its residential exchange sales to the IOUs as a 

legitimate component of BPA's priority firm obligation, to be treated exactly the same as the 

general requirements of public bodies and cooperatives for tiered rates allocation and other 

purposes. 

7 
150 

Fourth, with respect to the level of exchange benefits, we expect BPA to cease 

treating the difference between its power sales revenue and its purchased power expense as a 

"net cost" subject to management control in the same manner as copy paper, overhead, or 

aluminum wire. It makes more sense for BPA to measure its savings from having the lowcost exchange power available to it, rather than having to contract with new resource 

developers for power from new power plants, which would be considerably more expensive 

than the average system cost rate. 

Fifth, with respect to the difference between the cost of service to the DSis and the 

revenue they provide, we believe that if BPA proposes to provide the DSis with below-cost 

power, they should be prepared to consider lower service quality, such as through more 

interruptible power quality or other options, to ensure that all customer classes cover their 

costs of service. This matching of service quality with costs to serve should be done before 

new contracts are executed. We have experienced a reluctance on BPA's part in the past to 

perform necessary quantitative analyses of rate options, such as in the tiered rates 

discussions. We hope this is not repeated in other contexts, such as the negotiation of new 

contracts. 

Sixth, BPA should fully meet its conservation obligations under the Act. We have 

required the utilities we regulate to include conservation as a resource in their integrated 

resource plans and to include conservation in their competitive bidding resource acquisition 

programs. We have also allowed them to recover conservation costs in rates. If BPA does 

not do the same, it becomes more difficult for the regulated utilities to compete with the 

other utilities in the region. 

Finally, BPA 's proposed change of "corporate" direction to become "market driven" 

and "customer focused" must not be given priority over and above BPA's statutory 

obligations. These include using the federal Columbia River Power System to give priority 

to conservation and renewable resources, to provide equal access to that system for 

residential customers of IOUs, to protect, mitigate, and enhance anadromous fisheries, and to 

ensure that its processes are public and that the agency is responsive to the needs of the 

entire region. BPA is first and foremost a federal agency with broad responsibilities under 

the law; it is not a commodity marketeer and should not behave like one. 

We urge the Committee to take steps to ensure that BPA adheres to its directives 

under law. These steps can and should include the following: 

o Do not accept any proposed legislation making BPA a federal corporation unless 

and until BPA can demonstrate that it is moving fundamentally in the right direction; 

o Do not accept any proposed legislation making BPA a federal corporation unless 

BPA is subject to adequate regional accountability. This can be accomplished through 

regulation or by appointing a Board of Directors (possibly the Northwest Power Planning 

Council) to oversee Bonneville; 

8 
151 

o Ensure through your oversight capabilities that BPA recognize that the residential 

and small farm customers of investor-owned utilities have the same rights to the federal base 

system as do the customers of public utilities. 

We appreciate the efforts of this Oversight Subcommittee and Congressman DeFazio's 

Task Force in ensuring the continued accountability of the Bonneville Power Administration, 

and we look forward to working with you and others as we enter into a new era in the 

electricity industry. 

Thank you. 

9 
152 

CONGRESSIONAL RECORD CITATIONS REGARDING EQUAL 

ACCESS TO THE FBS FOR IOU DOMESTIC AND RURAL CONSUMERS 

Jackson, S 14691, 11/19/80 

The rate provisions of the bill make it possible to immediately extend the economic benefits of lowcost Federal power to consumers served by investor-owned utilities; this is accomplished by raising 

rates to the aluminum companies_ At the same time, preference customers rates are limited by a 

"rate ceiling" to no greater than what they would have been without the bill Preference customers 

and residential users of electric power arc always entitled to the lowest available BP A rate while 

commercial and industrial consumers generally pay higher rates reflecting new resource costs. 

Hatfield, S 14695, 11/19/80 

For many years the people of Oregon have been discriminated against in the rate structure because 

of our system of distributioiL This bill sets a uniform rate structure for BPA power sold to any 

utility for its rural and residential customers. This bill will mean, in effect, a saving of $1 billion in 

the next 10 years for the ratepayers of Oregon, with the revenue slack being made up by the directservice industrial customers who will get renewed long-term contracts in return for the higher rates 

that they will pay. 

McClure, S 11596, 8/3/79 

This exchange power will also be sold at the Administrator's lowest rate ... 

Packwood, S 11601, 8/3/79 

Residents served by private electric utility companies will again have access to much cheaper 

hydroelectric power generated at Federal installations. 

Ullman, H 9843 (9/ 29/80) 

And, importantly, S. 885 would provide much-needed rate relief for the residential and small farm 

customers of private utilities. These ratepayers, now disproportionately burdened by the enormous 

costs incurred in adding new generating capability over the past decade, would be able to share 

equally with public utility customers in the benefits of the Northwest's low-cost Federal power 

system. 

Dingell, H 9848, 9/29/80 

The rate provisions of this bill are fair and equitable. They protect the rights of preference 

customers to lower cost Federal-based resources. They provide that the Administrator's direct 

service industrial customers will pay substantially higher rates. These rates permit the residential 

customers of investor-owned utilities to share in the economic benefits of the Federal-based resource 

system. 

Moorhead, H 9849, 9/29/80 

Because the residential rates of public agencies arc 50 percent of those of the private utilities in 

Oregon, there is a movement toward creating a new public agency for the State of Oregon. While 

this may bring some temporary relief to the residential consumers of Oregon's private utilities, it 

would create such a huge strain on Bonneville's resources that the entire region's power supply 

would be thrown out of balance and into coun. 

Duncan, H 9863, 9/29/80 

The bill corrects the rate disparities between public and private utilities. 

Kazen, H 10674, 11/ 17/ 80 

S. 885 will ... provide low-cost power to residential and small farm customers of the region's investorowned utilities. 

Attachment 1 
153 

APPENDIX III APPENDIX III 

w 

.... 

<( 

a: 

w 

<.:l 

<( 

a: 

w 

> 

<( 

35.0 

30.0 

25.0 

FIGURE Ill · 1 

AVERAGE REVENUE REQUIREMENTS FROM BPA 

PNUCC LOADS · BASE CASE 

DSI RiJ~ Under the Bill......_ 

24.2 

19.3 19.3 19.3 

~---+--------- ,, 

YEAR 

...,_ WholesMe Ril~ ro Public 

Agenc1~s Urldt'!f tiM 81ft 

35.1 

22.0 

1) AfrPr 1984·85. the,.,,. w•ll ~ ser ilt il ll!"f'l no leu tr1iln rt'lilt set lor the vr•r 1984.S5 ¥Jd rhilt tS #QUttlblr m rrtiltiQn to 

the rrtiltl filrt!S ch.,~d by me oubllc bodv ilnd coo~r•t•vr cusromers to thr•r •ndnor:Wilf cunomers. 

Source: Bonneville Power Administration 

III .9 

Attachment 2 
154 

RESIDENTrAL EXCHANGE 

COST STABll.JZATION STRATEGIES 

One goal ofBPA's Business Plan is to limit the net cost of the Residential Exchange Program. 

Bec11use of the interaction between the Residential Exchange and the PF Rate, Business Plan 

success in holding BPA's costs and rates down results in increased exchange net costs. Original 

estimates of the gaps between Residential Exchange costs and the Marketing Plan, were as 

follows: 

EY...l22§_ FY 1997 FY 1998 FY 1999 EY..1QQQ FY 200 I 

71 Marketing Plan Target") $220.1 $282.9 $314.5 $344.3 $346.4 $346.9 

l... Exch. Program Es't. ~ $152.0 . $214.4 $167.8 $186.4 $159.1 $170.0 

~~=~~:~:§~'E.~~~6s :r ~~ ::;r&...:s1:4t> .;::~ 7$I5?/ ;B~'";j§[f87 .' ~~~116' 9: 

Current estimates of the gaps, using lat~:st Business Plan assessment rate estimates and revised 

ASC estimates, show smaller gaps than originally estimated. The gaps between projected 

Residential Exchange costs and the Business Plan goal of$200 million, arc as follows: 

FY 1996 EY 1997 EY.J..22.!i FY 1999 EY..l.QQQ EY2QQl 

Exch. Program Est. $180.8 $240.8 $256.6 $283.5 $261.6 $285 .1 

_Q9 M)II il) :r~ .••. ~~2.~ 20 . 0 ___ !2 ~-~ -- --- g99 () .. . . E£9.:.~--- ·- -~~()0:.0. n&P?."?.E:-:==:_:. ,;,;;"' tsl 9. 'i E:;:;:::::s'4o :: ::"~ss6 :~~: :: :: :ssJ:57~.;;:;e;l ~: lf5 :~ 

Attachment 3 
155 

Mr. DEFAZIO. I want to thank all of the witnesses for providing 

thoughtful testimony within the prescribed time and will now go to 

a series of questions. Again, we will do it in the same manner as 

last time, 10-minute blocks for myself and for Congressman Smith. 

I will pretty much sort of go across the panel, and then I will 

have some questions that others may want to respond to. 

With Mr. Golden, I guess I would like you to expand a little bit. 

You have heard the earlier testimony on the rate increase that 

might follow with the conservation reinvention. You heard some of 

the other concerns I expressed about what some utilities might do 

when confronted with that rate increase as opposed to the options 

that are out there to basically acquire additional power. 

Do you think that is a realistic fear, and would you like to talk 

about that, that cost increase analysis BPA provided to some people? I don't know if you have seen it; I haven't seen it, but I guess 

perhaps the council saw a draft of it. 

Mr. GoLDEN. I have seen some charts that I think contain some 

of the analyses that you are describing. I do think that it is not 

at all surprising that the proposed conservation retention would entail retail rate increases. The point of the conservation reinvention. 

Mr. DEFAZIO. What about the testimony we heard on this side 

by Mr. Piper that his customers are paying $150 million for conservation on an annual basis and not getting anything back? Would 

this address those inequities that he has professed? 

Mr. GoLDEN. I would like to address that by challenging whether 

there are inequities. Conservation is not a revenue distribution 

mechanism, it is a resource acquisition. If you want a lot of hydropower, you build a dam at Grand Coulee. If you want a lot of saved 

energy, you have to go where the buildings are. Relative to other 

energy resource acquisitions, conservation expenditures are spread 

relatively evenly throughout the region, but you wouldn't expect 

them to be spread perfectly evenly unless the resources were distributed. 

Mr. DEFAZIO. How are they spread evenly, on a per capita basis? 

I mean is conservation, are conservation benefits unavailable to 

smaller utilities? I mean they can't participate in the program, only 

the bigs can participate? 

Mr. GoLDEN. No. And that distinguishes them sharply from generating resources. I did not hear Mr. Piper or PNGC making any 

objection to the fact that Bonneville develops generating resources, 

and therefore, all the benefits of Tenasca are going to Tacoma. Of 

course that is not an issue. Tenasca is a resource, the benefits go 

to the region. The region bought it because presumably they 

thought it was the best resource deal available. 

The same is true of conservation. It is different from generating 

resources in the sense that at least some of it is available to all 

service territories. With a generating resource, it all goes to one 

place. And the notion that it should somehow be distributed evenly 

at all or on a per capita basis simply is a failure to recognize that 

it is a resource and if you want the resource, you have to go to 

where it is. 

Mr. DEFAZIO. So this goes to the earlier point that Mr. Duncan 

made about the 58 megawatts at 23 mills, and there was nothing 
156 

cheaper available, and it was a whole region cost and the whole region benefited; is that the point you are making? 

Mr. GoLDEN. Right. Indeed there are beneficiaries in the buildings where the efficiency measures were installed, and that is a 

good thing. That is one of the reasons that we prefer energy efficiency. But that is not why Bonneville did it. They did it because 

it needed energy resources and that was the best deal. 

Mr. DEFAZIO. The council made some recommendations on ways 

to reinvent or modify conservation to deal with the massive 

overheads and some of the other problems, but without going quite 

as far as has been proposed in the business plan. 

Have you reviewed those? Do you support any of those as options 

for a way to reduce some of the costs and burdens to the region 

and the inefficiencies of the system decentralizing it, getting away 

from the Soviet-type bureaucracy we have at BPA? 

Mr. GoLDEN. I do think that Bonneville has experimented successfully in the last couple of years with decentralizing program 

implementation and we support that very strongly. 

Would I make a sharp distinction between providing maximum 

local flexibility for program design, program implementation, and 

running the programs in the way that best fits the needs and goals 

of the local communities, and what Bonneville has at least initially 

proposed to do, which is shifting the lion's share of the responsibility for collecting revenues to pay for the programs to the local level. 

Mr. DEFAZIO. What if there were some more burden placed upon 

local utilities? I mean right now it is mostly BPA-funded. What if 

there was a cost-sharing? 

Mr. GoLDEN. Right. There is some cost-sharing. 

Mr. DEFAZIO. But what if it were enhanced? The Federal Government used to give 85 percent for sewers. Now we are down to 50, 

and we don't give it to very many people. I mean something along 

those lines. 

Mr. GoLDEN. The proposal that we provided you in your written 

testimony suggestion that the cost-sharing formula should be more 

closely aligned with the differing growth patterns of different utilities and the different proportion of their load that they do put on 

Bonneville, and that that could make the system more equitable, 

that will still not result in every utility getting back exactly the 

number of dollars that they put into conservation from Bonneville 

in the form of conservation programs, because Bonneville couldn't 

acquire the resource that way. 

Mr. DEFAZIO. Okay. Mr. Canon, you raised a number of points. 

I thought that there were a couple of key points where you said 

you need information, you need time to evaluate that information, 

and time to respond. And I got sort of the drift of your remarks 

that perhaps you felt that thus far, you know, we hadn't had that, 

or under the previous time line. 

Do you think the new time line will meet those concerns? 

Mr. CANON. I think it is going to be tight, but I think it is doable 

if all of the parties to this process act responsibly, and that, as I 

mentioned before, means that we as parties and the other folks sitting up here who are customers have to raise as many issues, and 

there are many issues. 
157 

I think there are many issues that we don't even know yet as we 

get into the new answers of tiered rates. We have to raise those 

issues, ask Bonneville what is your thinking on this, and then Bonneville needs to be able to get back to us and say, well, this is the 

evaluation that we have done, or this is our thinking, so we can 

go through this process. It is going to be a challenge on the time. 

And I wouldn't want to dissuade you from that, but I think that 

it is important to have a schedule and it is important to try and 

stay on that schedule. 

Mr. DEFAZIO. One of the concerns I have expressed personally 

and I know customer groups and others have had this same concern is the lack of that kind of analysis, and I share your opinion 

there. But one analysis I have seen was created under contract for your 

group by Mr. Wolverton, and my understanding is that his analysis-! have read it, I can't say I fully understand it; but he says 

that-predicts there could be a $200 million to $300 million costshift, and I think it was on an annual basis, not biannual, from the 

DSis to growing public utilities. I mean do you stand behind that 

analysis? 

I mean if the growth-! mean the growth is occurring in these 

public utilities. He said by definition growing public utilities. My 

concern is what were the implications for growth if we are seeing 

a large cost shift from a constant consumer of electricity to areas 

that are undergoing growth in the region? 

Mr. CANON. Let me summarize our concern on this issue. Line's 

paper was done at a single point in time; we didn't know what Bonneville's tiered-rate proposal was looking like at that point in time. 

Our concern is that essentially the Regional Act was a regional 

deal. Everyone had to give up something to get something, hopefully. One of the obligations that the DSis took on is the fact that 

they weren't going to be able to grow, but because they wanted 

long-term contracts, they would still continue to participate in regional load-growth cost through essentially the rate directives. 

Things have changed in this region, but the Regional Act still 

hasn't changed. And we want to ensure that not only the DSis, but 

others who have essentially been party to the Regional Act fulfill 

those commitments until and unless the Regional Act is changed. 

We are concerned that depending on the way that the tiered rate 

is structured, the DSis, because they are limited in growth, perhaps would not be exposed and fulfill their commitment to participate in regional load growth. The numbers may change over time, 

depending on how the tiered rate is structured. 

But the philosophy is that the DSis are paid for 20 to 30 percent 

of regional load growth up to this point in time, and they may very 

appropriately feel like that is unfair. I would if I were a DSI. But 

that is the deal that was struck in the Regional Act, and that is 

what we are going to be vigilant on. Mr. DEFAZIO. Are the customers you represent growing? 

Mr. CANON. I am trying to think of any that are. The customers 

that I represent are not that different from the aluminum smelters, 

the chemical companies. 

Mr. DEFAZIO. How many people are employed in the industries 

you represent? 

84-374 0 - 94 - 6 
158 

Mr. CANON. Probably a couple hundred thousand. 

Mr. DEFAZIO. Is that direct employment? 

Mr. CANON. Direct employment. You have Boeing as a member. 

Mr. DEFAZIO. You have a couple hundred thousand, and the DSls 

have got 40,000 direct and indirect, so what iR your direct and indirect? What do you think? I mean they are using a multiplier of 3.5 

or 4, so you want to use the same ones? 

Mr. CANON. Sure. 

Mr. DEFAZIO. So you represent 800,000 to 1 million customers. 

Now, what rates are your people receiving? Are they getting a preferred rate? 

Mr. CANON. They range in rates probably from Tacoma right 

now, which is 26 mills up to Seattle, which is 32, 33 mills. Most 

of them are in the 30-mill range, and of course we don't have a 

variable rate. 

I think I want to be very clear that on many issues the DSis and 

my members obviously are like kind. We are both industries. And 

we essentially do the paper as a shot across the bow, you know, 

establishing kind of the precept upon which we are going to operate. You know, I literally have lost a member because a facility 

closed down. The Atochem facility in Tacoma. 

Mr. DEFAZIO. And what did they produce? 

Mr. CANON. Chloroalkalide, and others, Bolton Paper Industries 

have taken significant downtime. Obviously one in your district, 

International Paper, has had a number of week-long and monthlong type of shutdowns. 

Mr. DEFAZIO. Having to do mostly with the prices they can obtain for their product, given the increase in inputs and their fixed 

costs of operating. Mr. CANON. Right. 

Mr. DEFAZIO. They could benefit with a variable rate; it would 

attract pulp, right? 

Mr. CANON. Oh, they would love that. 

Mr. DEFAZIO. My time is up. Here is what I am going to do: I 

am going to run over, since we are in the first part of the vote and 

vote, and leave Bob for his 10 minutes, and I should get back just 

about the time he has to leave to vote. Do you think that will work out okay? 

Mr. SMITH. Sure. You want me to miss the vote, don't you? 

Mr. DEFAZIO. So I will be back as quickly as I can. Bob will question for a while. There may be a brief hiatus, but don't go anywhere. 

Mr. SMITH. This is the new Chinese drill. It is called the Turtle 

Visit; we must go over and register our presence, very important. 

First of all, Mr. Golden, I would like to ask you if you support 

a special rate for irrigation. 

Mr. GoLDEN. We testified in the 1993 rate case that the irrigation rate as it is presently structured should be eliminated. Mr. SMITH. I assumed that you might have; I didn't know that 

you testified to that extent. 

So while you are suggesting that Mr. Piper's concern that he 

spends $150 million, his group, and receives $10 million back is 

even, you want to take away his irrigation rate as well. Do you 

think that is even? 
159 

Mr. GoLDEN. I think that all customers should pay the cost of 

serving their loads. I think that is one of the principal threats of 

Bonneville's competitiveness, is that many customers, the revenue 

that it collects from some customers is significantly less than the 

costs that it incurs to serve their loads. 

Now, is providing some sort of preferred rate to irrigated agriculture a desirable social agenda? It may well be. 

Mr. SMITH. But you are opposed to it. 

Mr. GoLDEN. But I don't think that Bonneville should pursue 

that agenda through its rate structure. 

Mr. SMITH. Do you believe Bonneville should have, as well as a 

competitive private agenda, a social agenda? 

Mr. GoLDEN. I think Bonneville inescapably does, yes, and it 

should. 

Mr. SMITH. And it should. Would that include making sure that 

agriculture as we know it would continue to exist with reasonable 

rates? 

Mr. GoLDEN. Yes, and I think reasonable rates are rates that recover the cost of serving those loads. 

Mr. SMITH. Mr. Piper--

Mr. GoLDEN. Incidently, I would say that we have talked to some 

of the irrigation utilities about how they might continue to gain 

preferential access to some Federal power by making efficiency investments and other investments that help solve some of Bonneville's other problems, such as providing for fish. 

Mr. SMITH. You contend that irrigation and DSis are subsidized? 

Mr. GoLDEN. To the extent that Bonneville fails to collect revenue sufficient to cover the cost of serving them, yes. 

Mr. SMITH. So they are receiving power by your determination, 

energy, below their cost of providing it. 

Mr. GoLDEN. Correct. 

Mr. SMITH. Mr. Piper, do you agree with that contention? 

Mr. PIPER. In terms of a subsidy? 

Mr. SMITH. Yeah. 

Mr. PIPER. It depends on how you define costs, obviously. And 

you can come up with various definitions. I think I would have to 

agree that there is a difference in the rate paid by irrigation companies--

Mr. SMITH. Understood. 

Mr. PIPER [continuing]. From everybody else. But it gets back to 

the same issue that I was talking about earlier, and that is like the 

DSis in jobs, rural economies and jobs are extremely important, 

and to the extent irrigators don't have cost-effective rates because 

their commodity prices aren't going to change, the market dictates 

that, just the way aluminum does. They can't stay in business, the 

retail business can't stay in operation, people leave, and so forth. 

Mr. SMITH. How many irrigators-how many farmers does your 

organizations serve, any idea? 

Mr. PIPER. I don't. We could sure try to make an estimate of 

that, though, and get it into the record. 

Mr. SMITH. I think if we are going to analyze cost benefit issues, 

we need to know those kinds of things, because when the business 

plan finally takes form, I have a suspicion that there ought to be 

a balance in BPA's determination as to not only being competitive, 
160 

but also, as everybody has testified, part of their program as a social program which they have got to balance. 

Mr. Wilcox, I want to ask you about the subsidy question. You 

have heard the contention that DSis are subsidized and in fact irrigation at special rates are subsidized, meaning that BPA is selling 

energy to you below its cost. Do you believe that? 

Mr. WILCOX. No, I don't. 

Mr. SMITH. Well then tell me why you don't believe that. 

Mr. WILCOX. I think the principal argument that people are making about the DSis being subsidized has to do with the variable 

rate. In the task force report, it said that NCAC estimated that at 

current low aluminum prices, that that would result in up to a 

$300 million a year subsidy, and I think that is where the source 

of that number is, the NCAC estimate and report. Mr. SMITH. So if I had sold it for 26 mills rather than 21, I would 

have received $176 million more money. That is where you think 

the subsidy comes in? 

Mr. WILCOX. Well, but that wasn't-what happened in the variable rate is, when it was adopted in 1986, Bonneville had a 1,500 

megawatt surplus of power. Bonneville and all its utility customers 

said, hey, we can't sell this. This is going to be water over the dam. 

And so they adopted a rate structure that was designed to sell 

power to the aluminum industry that was then facing very low 

prices, and shut down plants for more than they could have gotten 

it sold in the open market to California. 

And so they adopted a rate structure that varied up and down 

with the price of aluminum, but was very intentionally designed 

that it would recover far more revenues by doing that than letting 

the water spill and dump rates to California. And it has served 

that purpose dramatically. 

It is, by Bonneville's estimates, it is ahead, and even the 

NCAC-what the NCAC analysis does is I think is faulty in two 

respects. They said, assuming aluminum prices stay at low levels, 

and they haven't, aluminum prices are up and the DSis, I am very 

hopeful, will be at the base rate for the rest of the variable rate. 

So that assumption hasn't proved out factually. 

But the second thing which is more fundamental is that their 

analysis is based upon the assumption that the amount of power 

you purchased is the same with or without the variable rate, and 

that is obviously not correct. If you just say you are purchasing the 

same 3,000 megawatts with one rate as you do with another rate, 

they just add up the difference and come to that number. 

But the whole point of the variable rate was to ensure that you 

purchased more power and Bonneville got more total revenues. And 

by everybody's estimate that does that analysis, Bonneville is way 

ahead. Nobody complained about DSis' subsidies when the variable 

rate peaked in 1990, and they collected $280 million more than we 

would have paid under the standard rate. 

Mr. SMITH. Well, I-with respect to that point, I am reading now 

from the staff report here that makes that same allegation, that if 

world aluminum prices do not increase significantly, the DSI rate 

could cost regional ratepayers more than $300 million by 1996. You 

testified that in fact, the DSis have had a surplus of some $52 million; is that right? 
161 

Mr. WILCOX. That is correct. That is our estimate through the 

entire 10-year period of the rate. 

Mr. SMITH. I might note, however, that BPA doesn't agree with 

that. There is a footnote here that says Bonneville Power Administration says this contention is wrong; they don't agree with it. 

Mr. WILCOX. BonnevilleMr. SMITH. I am not sure where this came from, you know. It is 

in this report. Nobody agrees with it. I can't figure out who wrote 

it. Mr. Golden, you testified-! know you testified that it is going 

to cost $300 million. Is this your--

Mr. GoLDEN. I don't have the analysis in front of me. As Brett 

said, we testified that if aluminum prices were to remain low; we 

didn't assume that they would, we said if we do, so that is explicit 

in the analysis. 

Mr. SMITH. So this is a wish list. They might lose $300 million; 

you don't know. 

Mr. GoLDEN. I would certainly never wish that upon the DSI. 

What it says is that--

Mr. SMITH. Well, I think it might promote your argument. 

Mr. GoLDEN. No. It is not what we wish, it is not what we predict. It simply says, if and when prices stay low, this will be the 

effect on other consumers. 

Mr. SMITH. The question of, as I understood you, you said that 

you shouldn't sell energy to anybody below cost. And I am sure I 

should ask this question of somebody at BPA, but in your opinion, 

Mr. Piper, are they selling energy below cost, be it a variable rate 

or be it an irrigation rate, but below their cost? Again, I ask you 

that again. I asked you that one time. 

Mr. PIPER. On average, Bonneville recovers sufficient revenues to 

equal all the cost. 

Mr. SMITH. That is what Randy Hardy said here in fact. He said 

the variable rate we think has-we have broken even is, in fact, 

what he said. So what is this idea that they are selling, Mr. Golden, again, where is this idea they are selling energy at a variable 

rate below their cost to either irrigators or to DSis? 

Mr. GoLDEN. Quite apart from the variable rate, the idea comes 

from Bonneville's wholesale power rate development study which 

the infamous 7C2 Delta, which is sort of a nicer way of saying subsidies, but it comes to the same, which Bonneville calculates at 

$350 million for the two-year rate period. 

Mr. SMITH. Anybody wish to comment on that point? 

Mr. WILCOX. I can comment on it. It is just not true. I haven't 

seen the document that they are referring to. If I have the document, I could respond in detail. 

Mr. SMITH. All right. 

Mr. WILCOX. I could tell you exactly, and it might-since Congressman DeFazio has similar questions, probably go through it 

when he gets here, but the DSI rate is by statute, Section 7(c)(2) 

of the Regional Act is required to meet Bonneville's applicable 

wholesale rates to its public utility customers, plus the typical margin that they charge their own industrial customers, minus adjustments for the character of the DSI service, and the value reserves. 

And so the base power cost is the exact same PF rate that public 

utilities customers have to pay, and in the new business plan, it 
162 

will be exactly the same tier 1, tier 2 PF rate. So the base rate is 

the same. 

Bonneville takes that base rate and adds the typical margin, 

which they computed to be 3 mills, and then they subtract the 

credit they get for value reserves and the character of the service, 

and that subtraction is 2.5 mills. So bottom line, the DSI rate is 

half a mill higher than the rate that is charged to public utilities. 

Now, I don't see how anybody can call that a subsidy. 

Mr. SMITH. Okay. I want to get back into this, but excuse me, 

I have to go run and vote. 

[Vote recess]. 

Mr. DEFAZIO. We will come back into session here. I would like 

to move these things along as quickly as we can so we don't hold 

people all day. I understand there was a discussion of the 7C2 

Delta going on when I left, and I would like to continue that discussion because I didn't have an opportunity to benefit from it. 

I understand the question was raised as to what document we 

were referring to. We got our numbers from the 1993 final rate proposal, Wholesale Power Rate Development Study, it's got some 

numbers from it, published July 1993 by the Bonneville Power Administration. 

In there on page 98 they compute the 7C2 Delta, as they call it, 

and what they do there is they compute the total cost of service by 

their numbers to provide power to the DSis, and then they compute the total revenues, and then in this case they subtract the 

total revenues from the cost of service, since it is less, and come 

up with a delta, which I guess means deficit, of $337.999 million 

on a biannual basis. So hopefully that answers the questions. 

Now, it may be that without the benefit of Mr. Robertson's testimony that other persons are unfamiliar enough with this process 

to comment on it, but that is the existing system, let alone the 

questions raised by Mr. Wolverton in the proposed changes and 

other questions raised by other people on the panel regarding-including the DSis as the same as preference customers in tier 1, 

when in fact the preference customers would not just get a tier 1 

power rate, obviously they have to purchase unbundled services, so 

the preference power rate would be lower for the DSis than it 

would be for publicly-mandated, legally-mandated preference customers because they have to buy the service plus whereas obviously 

the industry doesn't need any of those services. So I assume that 

is the discussion. Now, I would invite any of the panelists to respond to that. That is a question-yes. 

Mr. LAMsoN. I would just like to concur with that reference to 

the 1993 BPA study, and also state that the rate equivalent for the 

DSI should be the retail industrial rates of the public utilities and 

not the wholesalers, more or less the equivalent of the retail rates. 

Mr. DEFAZIO. And I think you gave me number-or well, no, I 

got the numbers from Mr. Canon or his customers. He said 26 mills 

to 32 mills. I think that was retail. What numbers do you have for 

industrial customers? 

Mr. LAMsoN. I don't have any precise numbers today. 

Mr. DEFAZIO. Do you think his numbers are ballpark? 

Mr. LAMSON. They are ballpark, sure. 

Mr. DEFAZIO. All right. Mr. Wilcox? 
163 

Mr. WILCOX. Since you invited a response, if you look at Section 

7(c) of the Regional Act which establishes the DSI rate, the first 

Section 7(c)(l)(b) sets out a general principle that says, after 1985, 

DSI rates are supposed to be set at a level that is equitable in relationship to the retail rates that preference utilities charge their industrial customers. 

And then you go down to 7C2, which says that for purposes of 

interpreting Section 7(c)(1)(b), that is determined by taking the applicable wholesale rate that Bonneville charges preference utilities, 

adding to that applicable wholesale rate the typical margin that 

those utilities charge their industrial customers, and subtracting 

from that the value reserves and differences for the character of 

the DSI load. 

And, you know, this is a-this rate has been involved in very extensive public processes, many rate cases over-since 1985, intense 

scrutiny by the public utilities and constituent interest groups, and 

basically what Bonneville has determined in these rate cases that 

were reviewed by FERC is that doing a detailed survey of all the 

preference agency and large and industrial customers, the typical 

margin above their wholesale power costs was 3 mills. 

And then they did the value reserve study, which is an issue you 

have raised, and have determined that some of the value reserves 

was 2.5 mills, so they deducted that, which left the DSI rate at .5 

mill above the-a net of half a mill above the rates charged the 

public utilities. And so that--

Mr. DEFAZIO. That doesn't pertain today, though. And what are 

you paying today? 

Mr. WILCOX. It does and it doesn't. It does--

Mr. DEFAZIO. You are paying 21 mills and they are paying 27, 

so you are paying more than they are. 

Mr. WILCOX. No. 

Mr. DEFAZIO. Explain this to me. 

Mr. WILCOX. Let me finish. That rate determines what Bonneville calls the plateau of the variable rate, which is the normal 

charge that is expected to be covered under the normal aluminum 

prices, and I think that extends from 64 cents a pound and above 

is the plateau, and then that rate goes down at low aluminum 

prices to a floor rate of 22 mills. 

Mr. DEFAZIO. Okay. So today you are not paying half a mill more 

than a preference customer; today you are paying quite a bit less. 

Mr. WILCOX. No, but at current aluminum prices, we--

Mr. DEFAZIO. Right. But my understanding is that next month 

because of the low aluminum prices that you will go above that 65 

cents and you will go to 23 mills, which still is not what preference 

customers are paying for power. 

I mean I guess the problem I have is in characterizing-see, I 

said I like people to be advocates, but I also want to say things 

pretty straight here. I don't know how one can say when one pays 

less than somebody else that they are paying more. They aren't. 

I mean you can say well, there are these other things that are 

figured in. But the point is, cash out-of-pocket, you are paying 6 

mills less per kilowatt hour, and after the adjustment, you will pay 

4 mills less per kilowatt hour. 
164 

So we ought to at least temper the statements with saying, after 

we take into effect the other benefits to the system, we are paying, 

you know, we are paying only this much less than a preferenced 

customer. And then the question becomes, in the new structure, should you 

pay again less than preference customers, because they are going 

to have to buy unbundled services. So first of all, we have the old value of reserves argument, which 

I think we have resolved, because we agree, let everybody bid on 

it. So we can put that aside. The value of reserves as we knew it 

is history; whether it was a good idea or bad idea, it is history. 

Now, everybody seems amenable to that. That is something we can 

agree on. But then the question becomes, you know, how should 

your basic rate be set in the future? 

Yes, Mr. Peterson. 

Mr. PETERSON. Mr. Chairman, if I might intelject here, what is 

easy to fall into is to take a look at one minute and say, and project 

that on to a longer term time frame, and what I heard both you 

and Mr. Duncan say earlier is that what we want to do is take a 

long-term view of things, that is, we want to be a long-term competitor in that context. 

Now, I would like to ask you to take that same look at the vari- able rate. The variable rate was never contemplated that at any 

one particular moment in time, that if we compare that against 

something else, that it will be exactly equal. 

The variable rate was consciously put into place so that over its 

term, and that was contemplated to be 10 years, and in fact that 

is what it will be, over its term, the receipts from that rate will be 

what it would otherwise have been if there was only the plateau 

or the regular rate. So when we say here is how we set the regular rate, Brett is saying the regular rate is set at such and such, and it is not below 

the preference rate. Now, when you say, well now, look at this moment in time, where is the variable rate? 

Well, for several years, the variable rate was many mills above 

the plateau rate, and the fallacy that the NCAC analysis gets into 

is at bottom, I think, a matter of what I will call a static analysis. 

That is, it says, well, this particular customer group bought, you 

know, 50 billion kilowatt hours over this period of time with this 

rate, and if they would have paid a different rate, they would have 

generated different revenues. The problem is that the variable rate 

was intended and in fact--

Mr. DEFAZIO. Sure. I understand that. Mr. PETERSON [continuing]. My company would not even have 

been in existence. 

Mr. DEFAZIO. I understand that, and I have never in the past, 

you know, been one who said there should not be a variable rate. 

The problem is, the problem is, the only dynamic analysis that has 

been done, which is paid for by ratepayers, is proprietary information, so there is this great dynamic analysis out there that tells us 

of all of the benefits the variable rate provides and how in fact we 

are not even really reaching the break even point this year or 

didn't reach it last year, it is off in the future somewhere, which 

has some assumptions of whether or not you would have gone out 
165 

of business or someone else would have or something else, but none 

of the public policymakers or other customers can see it. 

You know, I have a problem in dealing with a for-profit industry 

where they just say, we have a great analysis that shows that all 

of your ratepayers have benefited from us being here, but we can't 

show it to you. I mean I just got to tell you--

Mr. PETERSON. I don't know what you are talking about. I am 

not aware of a secret study that I would have anything to do with. 

Mr. DEFAZIO. Well, BPA can tell you about it and they will. It 

was a proprietary analysis that was done under contract involving 

the aluminum industry which is what they used to come up with 

the so-called cost benefit and show at what point we cross what 

line. 

It is just hard, you know, to hear that kind of testimony. But I 

think the point-if you would just give me a moment, the point I 

am getting at here is in the testimony is-again, I want people to 

be advocates. 

But I mean the point is, Mr. Wilcox has said, DSis should be 

treated no differently than other customers. Well, that is a point 

I am raising. But you do want to be treated differently because my 

pulp and paper plants can't get a variable rate. Boeing can't get a 

variable rate. The market is down for airplanes. We have heard 

from Mr. Canon, his industries employ 1 million people direct and 

indirect, you employ 40,000 direct and indirect, you don't want to 

be treated any differently, but, you do, and you are. 

Mr. PETERSON. No. 

Mr. DEFAZIO. These are some of the points. And then beyond 

that, I mean we still haven't got exactly to the bottom of the 7C2 

Delta. In 1979, they had a forecast. They said, residential exchanging will be 34 mills per kilowatt hour, priority firm will be 22. 

Therefore, there would be a 12-mill benefit to residential customers, instead of course exchange is 32, preferred is 28. 

They also forecasted for 1994 that the DSis would pay 10 mills 

per kilowatt hour more than the priority firm rate paid by public 

utilities and residential customers. Now, we are off a little bit here. 

You are paying, instead of paying 38, which would be 10 mills 

more, or even 32, which was their old forecast plus 10, you are paying 21 and you are going to 23, and you want a future arrangement 

that locks something equivalent to that into place. 

You know, my question would be, why don't we continue the 

variable rate with some adjustments, like taking out the value of 

reserves and putting it up for bid as opposed to putting you in the 

same status as the priority customers mandated by United States 

law, preference customers. I don't see anywhere in the law where 

the aluminum industry is entitled to a share of the Federal base 

system. It is just not in the law. 

Mr. PETERSON. Well, it is in the law at the present time, and I 

think there is some discussion about it that you have brought up 

and the Majority report has brought up is the concept of regional 

preference. And I happen to be an electricity user in the region, so 

in that regard--

Mr. DEFAZIO. So we are going to run BPA like a business, but 

we might require that business to sell power at a loss in the region 

than it could sell elsewhere. I mean the problem is, some people 
166 

want BPA to be Adam Smith on some issues, but not theirs, and 

other people want BPA to be Adam Smith on their issues, but not 

others. 

I am just trying to reach some consistency here. I am not against 

your industry. I think it has been vital and dynamic for the Northwest. I want to get a fair deal for everybody. But the question is, 

is BPA's proposed rate structure a fair deal or not. BPA can't even 

answer the question since the administrator told me to throw out 

the only analysis tr..at has been done. Despite that, we have people 

sitting here saying we should go ahead with it. 

How can you say that when we don't even know what it means? 

What does it mean to Boeing, what does it mean to IP at Gardiner? 

What does it mean to you? Those are all questions we should balance. 

I am not here to attack you and say, gee, we should get rid of 

the aluminum companies and stick it to them. What I am saying 

is let's talk about a fair analysis and try to bring everybody in the 

Northwest along. That is all I am talking about. 

Mr. PETERSON. That is all that I am talking about. 

Mr. DEFAZIO. Okay. Well then, we have agreement, and my time 

has expired, and I will yield 10 minutes to the gentleman. 

Mr. SMITH. Thank you. We spent the 10 minutes before you arrived trying to get at this question of cost, really. And basically Mr. 

Golden's contention is that you ought not to subsidize either 

irrigators or DSis, and we are hung up on the question of what is 

the cost. 

Mr. Wilcox has testified that they are paying cost plus half a 

mill, would you say? 

Mr. WILCOX. Yes, sir. 

Mr. SMITH. Cost plus half a mill. And you know, there is one 

benefit I see obviously, that is 460 jobs in The Dalles in Oregon. 

It is a hell of a benefit especially if you are living in The Dalles. 

And my suspicion that if those 460 jobs were in Eugene, it might 

be a different tilt on this whole discussion. I would suppose that 

that would be the case. However, we are back to the question of 

fairness. 

And again, Mr. Golden, I am having trouble determining what 

you believe the costs are. You have heard Mr. Wilcox testify that 

he is paying one-half mill over Bonneville cost. Do you agree with 

that? 

Mr. GoLDEN. I believe he testified he is paying one-half mill over 

what the public customers who have full legal entitlement to the 

Federal base system are paying. I don't think he made any assertion between the relationship of that and cost. 

Mr. SMITH. Let me ask Mr. Wilcox again. 

Mr. WILCOX. When you were out voting, there was a further clarification of what I said. What I said was the DSI rate, the net average rate under Section 7(c) is half a mill higher than the PF wholesale rates. 

Now, obviously, that average rate is adjusted in the variable 

rate, so Congressman DeFazio is absolutely correct, that at low aluminum prices, we are paying less than the average rate. But at average aluminum prices over the 10-year period, we are paying basically the average rate plus the half a mill. 
167 

Mr. SMITH. And over the 10-year period of time, Randy Hardy 

testified that that was a wash. 

Mr. WILCOX. Correct. 

Mr. SMITH. OK. So if you-in other words, you can't take it at 

a one-year window; I have to take it over the period, because the 

variable rate moves with the costs of aluminum? 

Mr. WILCOX. That is correct. One thing that I would hopefully 

like to put the variable rate subsidy issue behind us in the same 

way that Congressman DeFazio put the value reserves argument 

behind us. 

You have a 10-year variable rate that expires in 1996. Ken and 

I are not here saying in the new arrangement, renew it or don't 

renew it. The variable rate was adopted 10 years ago because the 

region felt it was a win/win situation for everybody; it was a way 

to keep the aluminum industry operating at the time that we were 

spilling energy or selling at dump rates to California. And if we don't have a win/win situation in 1996, there should 

not be a continuation of the variable rate. If I can't convince you 

that it is the right public policy issue, there will not be a variable 

rate. And so we are not here saying continue this subsidy or not 

subsidy regardless of what you call it indefinitely, we are just saying it was a thing that made sense over its life; it is about to expire 

and it is a public policy issue on the table, whether it is appropriate to continue it or not. Mr. SMITH. But it broke even? 

Mr. WILCOX. Correct. Mr. SMITH. Mr. Piper, you know, I have been in agriculture all 

of my life ancl I understand the difficulty in trying to work through 

farm programs and make it work. And given the fact that over the 

years, there is a return on investment of less than 2 percent in agriculture, generally speaking, tell me how sensitive you believe 

your irrigators are to any kind of rate increases? 

Mr. PIPER. Mr. Smith, I can't tell you in specific terms; I just 

don't know the answer. But in general terms, they have no ability 

to control the market. 

Mr. SMITH. In other words, they can't pass on any increased 

costs? 

Mr. PIPER. They cannot pass it on. 

Mr. SMITH. So they are doubly sensitive, at least if you were in 

some other business, you might have a shot at passing along costs, 

although unless Mr. Wilcox fixes a price on aluminum, I don't see 

what chance he has either. But they are sensitiveMr. PIPER. Very much so. 

Mr. SMITH [continuing]. To any increases. And that was one of 

the-and I assume that was one of the reasons that BP A took a 

real close look at the question of a special rate for agriculture, recognizing that indeed, that is a social issue, isn't it? 

It would be anti-social if you raised the rate to the point that you 

lose a third of agriculture in Oregon, or the Pacific Northwest, 

wouldn't it? It would be anti-social for sure. 

Mr. PIPER. No question that it is a social issue. 

Mr. SMITH. Yes. It is a social issue. But at the same token, I 

think it is a social issue that we maintain 4 70 jobs in The Dalles 

as well. That is all I have. 
168 

Thank you very much, Mr. Chairman. 

Mr. DEFAZIO. I thank the gentleman. We will move on from this, 

and I will state for my purposes, you know, given the mishmash 

and the murky presentation by Bonneville so far, particularly having heard that I can throw out the only economic analysis provided 

me by BPA, I would prefer to have a bifurcated structure with a 

discernible, variable rate out there so that we can better understand what they are proposing today. 

But we will see what they come up with as we go through this 

extended process, with modifications of bidding out the value reserve and other things. So you know, I would like to say that this 

is about jobs in the Dalles; it is also about jobs in Gardiner at the 

pulp and paper mill there, where one of their greatest costs is electricity and they would like to see a floating rate too, or Halsey 

Paper Mill or Greenbrier Rail Car Manufacturing in Portland or 

Boeing in Seattle. 

All of these industries are subject to the same competitive international pressures as others, and what I want to see is a Northwest that grows vibrantly with jobs available both in rural areas 

and in urban areas, so we can accommodate that growth. So that is what I think this hearing is all about, to come up with 

that fair and equitable treatment and the Northwest Power Act 

was pretty well structured among some extraordinarily divisive 

and competing interests to do that. My question is whether or not 

we are administratively unbalancing that bargain in a way that 

doesn't make sense for the 1990s and 2000 and after. 

Miss Leone, one thing you brought up, which I think is really important here, and we haven't gotten to it, is this rate stability argument. We had some brief discussion earlier. I have a question for 

you and other people may respond. You know, there is all this thing about Independent Power Producers and all the tremendous competition they are going to provide. But my question is, if I have a high value on stability or longterm, what backs up some individual IPP that doesn't own or operate on anything other than one plant which has a gas contract with 

someone, somewhere and has told me, don't worry, I am going to 

give you this great gas deal for 20 years? What if once they have 

the return on their equity, they just say, sorry, we just went bankrupt, we are out of business. 

I mean I can see a scenario here where some people sign on to 

what look like sweet deals, and something unexpected happens in 

the gas market. The Wall Street Journal has just opined we will 

see a dramatic increase in gas prices because of changes in Canada. The Economist has about a 10-page article this month on the 

dramatic increase coming in energy costs worldwide. You know, 

what backs up these IPPs? 

I mean if we are looking for stability, do you think people are 

going to find it there? 

Ms. LEONE. Well, I think you are exactly right. This is a risk 

that customers are going to have to look at when they deal with 

these IPPs. What are their track-not just IPPs, marketers and 

others-what are their track records? What kind of guarantees can 

they get from them? 
169 

I suppose, perhaps, even with Bonneville's unbundling, you 

might be able to fix some short-term outage-type things, but, you 

know, I don't know if they will have a product that will go for 20 

years. If you are in eastern Idaho, you might want to look to Utah 

Power for the same kind of short-term fix or at least reserve power. 

This is what makes the choice of freedom difficult. 

If utilities are going to look to other suppliers for what we are 

starting to call Tier 2 price, Bonneville is tried and true to date in 

its product. Are the other choices going to be as operationally reliable? I don't know. Some seem to have been. Others could well be 

fly-by-nights. 

Mr. DEFAZIO. On Tier 2 Power, I am curious, BPA, in the to-be 

discarded DEIS analysis, said the Tier 2 power will cost 38 mills. 

I guess I am wondering, if there is all this power out there at less 

than the 38 mill rate, who is going to buy power from BPA? I assume it is Mr. Scott and other small utilities, as he said, who don't 

even have the staff to go out and parse through the market. 

It is like I don't go through my mail every month and figure out 

whether I am going to go to a new long distance provider because 

I could figure out half the offerings and what it means to me. I just 

throw it out. 

You represent some of those people, the PPC? 

Mr. DUNCAN. One hundred fourteen of them. Mr. DEFAZIO. Do you think they are going to get stuck buying 

the Tier 2? Who is buying this stuff? Obviously we are planning on 

selling this stuff. Somebody is going to make a bunch of money 

from selling it. Who is going to buy it? 

Ms. LEONE. If purchase power is included in Tier 2, that is what 

its cost is going to be and that is what it is going to be sold at from 

Bonneville. To take your analysis one step further, PPC may be 

reinventing itself to see what it can do to help customers like Mr. 

Scott. 

Mr. DEFAZIO. I see. That is an interesting idea. 

Do you have any estimate, since they can't tell me, how much additional cost the shaping and the other services might add on top 

of the Tier 1 cost? I mean, have you done any analysis, independent analysis of that, or do you think that is just basically imponderable because it is all up to BPA and how they price those products? 

They obviously have some market in mind or competition in 

mind in pricing those products. I am wondering if anybody has 

done an analysis. 

Mr. DUNCAN. We have not. In fact, I went to great pains to tell 

the Seattle Post Intelligencer the Link Wolverton study wasn't 

done by or for the PPC. 

Mr. DEFAZIO. No. We know who to blame for that. 

Ms. LEONE. We have not. And we are hoping, certainly within 

the next six months, to get exactly that done through working with 

BPA. 

I would like to emphasize again that these contract discussions, 

as they are termed, are actually resolutions of core contract issues. 

Now, at the same time, I think earlier today, someone mentioned 

that the TRIM, the Tiered Rates Impact Model, was nearing completion. My understanding is it will be out within the next couple 

of weeks and up and running and available. And we are hoping 
170 

that all kinds of answers to questions we have about the business 

plan numbers and lack thereof will be available within the next 

couple months so that we can make decisions. 

Mr. DEFAZIO. Okay. On page 3 of your testimony, you raise the 

point that, again, when I refer rather facetiously but I think realistically to the Soviet style of bureaucracy at BPA, you talk about 

the central implant programs the last 14 years with the attendant 

shortcoming: 40 percent overhead. 

Is that 40 percent out of BPA or is that 40 percent including the 

local overhead and the BPA overhead? I haven't seen that number 

before. 

Mr. DUNCAN. I believe that is BPA, but I will check and get back 

to you. Mr. DEFAZIO. We can ask BPA about that. That is a pretty extraordinary overhead. Did you have a chance to look at those proposals made by, again, 

by earlier testimony by Mr. Duncan on possible changes to the conservation program, additional cost sharing, doing away with the 

central control of the actual measures and those sorts of things, 

having it results oriented? Did you have a chance to look at some 

of those as an alternative? 

Ms. LEONE. I skimmed them briefly this morning while he was 

testifying. And my view is this. Both he and Mr. Golden and others 

were involved in preparing and drafting up conservation 

reinvention principles, I believe. Now seemingly other alternatives 

are being proposed. I wish that we could head off in some direction. 

Right now, the Northwest, my members are prepared to go decentralized and pull the cart all by themselves. If we are now supposed to do something else, we need to know yesterday. We expect 

to come up with some IRP guidelines by, I think, the 23rd of August. 

Now, if this isn't-if we are spinning our wheels, we need to 

know. 

Mr. DEFAZIO. It seems to me you represent, again, a lot of the 

smaller utilities, such as Mr. Scott represents. And this was a concern that came up when we were doing the IRP's with WAPA-and 

that a lot of small utilities have very little capability. They don't 

have a lot of staff sitting around. They can't afford expensive consultants to sort of start up their own programs. 

Now, I guess what I am thinking is-I mean, looking at Mr. 

Duncan's conservation proposals again, if BPA were helping local 

utilities with start-up costs or they were doing some continued cost 

sharing but at a lower level, I mean, something, you know, rather 

than just a cutoff and a total send it out to the local utilities. 

I mean, we could certainly lower the cost, do away with the BPA 

bureaucracy. You know, it would be more like what we do with 

grants from the Federal Government where you set guidelines. The 

people have to show their results. But you don't-it is not regulated day to day the way it is now. I mean, you wouldn't have BPA 

in there looking at what the weather-stripping people were putting 

on the doors and stuff like they do now. So----

Ms. LEONE. Right. I think Bonneville's proposed energy service 

charge takes a big step in that direction. 

Mr. DEFAZIO. The DSM stuff, you are thinking of? 
171 

Ms. LEONE. Right. 

Mr. DEFAZIO. Okay. My time has again expired. I will defer to 

Bob again. Mr. SMITH. You are welcome to it. 

Mr. DEFAZIO. Great. Because I want to go through some other 

questions. I thank the gentleman. At any point you want to jump 

back in. 

Mr. Scott, I hesitate to bring up the DSI's versus preference 

again. I think we pretty much covered that ground. You may have 

been involved when I was out of the room and you weren't involved 

in a later exchange. You certainly made it a major focus. 

Is there anything you think we missed? Unless you think there 

is something we missed, I would as soon leave it lie. 

Mr. ScoTT. I guess the only thing that I might add is it disturbs 

me that Bonneville's business plan anticipates adding or at least 

not losing about, I believe it is, 420 megawatts of DSI load due to 

what they call price signals, and losing it again. 

Due again to what they call price signals, about 130, 120 

megawatts of preference load. There again, I don't quite understand why they intend to send those price signals, because it seems 

to me that preference should have more meaning than that. 

Mr. DEFAZIO. Well, perhaps when Mr. Robertson comes up, he 

can discuss those assumptions. I don't know if they based it on 

Clark and Snohomish, they are looking at alternatives no matter 

what the price, or what they base that on. If he takes note of that, 

we can get a response out of them. 

Mr. SCOTT. They say that is due to price signals. 

Mr. DEFAZIO. Right. I would be interested in how-and do they 

have-that is the point you raised. Shouldn't they have some additional concern about trying to keep all the preference customers 

somehow in the net, if possible. Certainly. 

Mr. SMITH. Mr. Scott, would you also criticize Bonneville for 

spending $1 million on salmon mitigation? One billion, not a million. 

Mr. ScoTT. That is a whole other issue to get into. I have some 

real reservations about the salmon recovery program. I do not want 

to be a commissioner when the last salmon goes through the turbines or through the river. Mr. SMITH. They already have. 

Mr. SCOTT. You might be right. However, I think that the region 

needs to get together and that there are several causes for the 

salmon problem that we have, hydroelectric power being only one 

of them, and that we need to address all of the causes. 

Mr. SMITH. No. I was just trying to make a point to you while 

you are criticizing them, if they had had a billion in the bank and 

hadn't had to spend it for salmon, which obviously didn't make any 

difference that anybody can measure, then there wouldn't be this 

agony about rates so much. 

Mr. ScoTT. A billion dollars would be fine if it was working. Like 

a friend of mine said, if we are going to fail, let's fail cheap. 

Mr. SMITH. Well, that is not cheap. If they had it back, we probably wouldn't be meeting here today. So when you criticize them, 

let's criticize-l've heard no one criticize them for spending a billion dollars for fish, not even the wildest environmentalist. They 
172 

think it is great. But it produced zero and with no opportunity in 

the future. 

I yield back. Mr. DEFAZIO. Thank you, gentleman. I will reclaim my time. You know, I would like you to give us some perspective on 

unbundled services. You alluded to it. I think it is an important 

point for a large number of Ms. Leone's members and I think Mr. 

Piper's members, but maybe not necessarily the preponderance in 

terms of contributions to the organizations because the bigger ones 

contribute more. Can you expand a little bit on what you see the challenges to be 

with the Tier 2 rate and the unbundled services for small utilities 

like yours? 

Mr. Scott, that is for you. I am just trying to get it in a perspective. 

Mr. ScOTT. Well, we don't know yet what they are going to offer 

in terms of unbundled services exactly. They haven't told us what 

they are going to be or what the prices are going to be, so it is really hard to analyze. And there again, when the time does come, we 

are probably going to have to hire some consultant or join some 

sort of group to help us do that, which is kind of disappointing to 

us because that in itself gives us some upward rate pressure. 

Every time you join another organization or hire a consultant, it 

costs money. And that, of course, gives rate pressure. I would, I 

guess, prefer to be able to do what we have done in the past, and 

that is just buy what Bonneville has called vanilla power. We like 

vanilla power. It works well for us. We are not unlike our consumers when we look to the switch. When we flip the switch, we need 

the light bulb to come on. We don't have the flexibility like, say, a Clark or a Snohomish might have or some of those other utilities 

of shaping our load differently other than some DSM activities that 

we might undertake. Even that is not really going to contribute 

much. Nobody has come along and offered any interest in our sixmegawatt load. Louie Dreyfuss hasn't called us or any of the oth- ers. 

Mr. DEFAZIO. They haven't. Mr. SCOTT. We don't expect to hear from them. 

Mr. DEFAZIO. We know you are on the list. 

Mr. ScOTT. They certainly aren't going to offer us a full meal 

deal at 27 mills for 20 years, or levelized. 

Mr. DEFAZIO. Okay. Unfortunately, there is going to be some 

change, things will never be as they were. I also want to make the point that there are varying needs 

among the customers, and you are expressing the needs for the 

preponderance of the customers but not perhaps the preponderance 

of the load on the system. So I think it is a really valid point that 

we need to remain sensitive to. Mr. Piper, there is a point that I will be asking BPA about but 

you raised it, which puzzles me, which is about this rate increase 

in October of next year if we go with an interim rate case of 10 

to 15 percent. Now, I have seen the numbers. Let's just do it this 

way. That rate increase of 10 to 15 percent assumes a certain level 

of revenues. 
173 

Now, the question which I have asked BPA is, you are going to 

need 15 percent more revenues next October, either through an interim rate increase or through unbundled services and tiered rates. 

Who is going to pay? Are you confident that your customers or 

your members are not the ones who are going to pay? Do you know 

where the disparate rate impacts are going to fall? Do you know 

who is going to pay the additional bill? 

BPA is seeking more revenue. That is from the customers. Some 

are going to be buying unbundled services, some are going to be 

buying Tier 2. Some are going to be doing this and that. The money 

is still coming out of the purse of ratepayers in the region. 

There is one part I should add, and it is a proviso. They obviously, as Mr. Robertson said earlier, they did assume in their market-driven alternative things that they admit they could do, even 

if they didn't unbundle services and go to tiered rates. They assume $100 million in annual administrative savings. They assumed 

worst-case scenarios and all that. They prejudiced it as much as 

they can. 

So actually 10 to 15 percent is probably not accurate. Maybe we 

are looking at 5 to 10, after you assume all the common things you 

could capture in terms of administrative savings, reduction in staff 

and other efficiencies. 

Still, who is going to pay for that? Somebody is paying for it in 

the region. I mean, do you know who that is? And are they your 

members, or whose members are they at the table? Who at this 

table is going to be ponying up the extra money? 

That is my question. And BPA can't answer that. I am hoping 

maybe you can because you were strongly advocating we move 

ahead right now. So I assume you have done an analysis and you 

understand where that is going to go, because there can't be any 

other reason for saying we should go ahead now. 

Mr. PIPER. No. I can't tell you that. I haven't done an analysis 

because there is nothing at this point to analyze. That is our whole 

point for proceeding as fast as we can, to get these things defined. 

If Bonneville comes back with an unworkable program, we will go 

elsewhere for power. There is not a difference anymore. We can 

buy reserves. We can buy maintenance downtime. We can buy storage and shaping. IOUs have already been around talking to us. 

Mr. DEFAZIO. I guess I am really puzzled at her testimony, then, 

Ms. Lamson, that we have got a large utility in Washington that 

will be thrilled to buy power well above the preferred rate. So you 

are saying--

Mr. PIPER. That is today's PF rate. 

Mr. DEFAZIO. That is pretty high above it. It is above the worst 

case projections I have seen for 2010 for BPA. 

Mr. PIPER. All I am saying, the practical economic realities are 

such that if Bonneville raises costs to a level that is unacceptable 

to us, we have alternatives. 

Mr. DEFAZIO. That is the key, the raising of the costs. You are 

assuming that if they adopt an interim rate, they can't have any 

cost savings. They assumed, which is now fallacious and they 

admit they did that, because when they interpreted the word "status quo," they didn't change anything. So part of it is the cost could 

still come down. 
174 

But the question is, after the costs come down, approximately the 

same amount absent the small amounts that go to conservation, 

where does the additional revenue come from? You are telling me 

you don't know and no one else knows. 

Mr. PIPER. I don't know where it is going to come from, because 

as you point out, this question of the unbundled services and under 

what class of customers they fall is critical. 

Transmission is a beautiful example of it. We are very concerned 

about that. As I stated earlier, yes, we are concerned. Yes, we care. 

That is why we want it defined, because we can't make any decisions on our own. Until those things are defined and until that 

happens, we have no choices. 

Mr. DEFAZIO. Okay. So then it isn't quite the go-fast. In an earlier phone conversation with Mr. Wilcox, he told me BPA was going 

to use transmission to keep people from going to IPPs by pricing 

the unbundled products that people would have to get to follow an 

IPP load in such a way that they can keep competition at bay. 

Now you seem to be assuming that if those prices are bundled 

in a way that is not acceptable to your customers, that you are 

going to be able to go out and buy IPP power at some extraordinarily low rate, despite what you might have to pay for wheeling, 

shaping, following, whatever else you have to buy. 

Mr. PIPER. There are competitive factors at work that will allow 

us to do that, not necessarily all products, and services transmission is one of them. Transmission access rates are protected by 

the 1992 Energy Policy Act. Mr. DEFAZIO. We are not sure what the 1992 Energy Policy Act 

means particularly in our region and even in California. It means 

there are changes coming, but we don't know exactly what they 

mean. 

Mr. PIPER. They need to be tested, I agree with that. 

Mr. DEFAZIO. Ms. Lamson, coming from the regulator's seat, I 

am curious why your major utilities haven't accessed this plethora 

of power at this rate and why they are paying the outrageous 45 

mills, when I am told there are bundles of it out there at much less 

than that. You regulators are really asleep up there. 

Ms. LAMSON. I am afraid I can't talk too much about that because there is a prudence review right now on that issue. The staff 

of the Washington Transportation Commission, the advocacy staff 

has challenged the prices of those contracts. And we just completed 

the hearings so that that decision is pending. 

Mr. DEFAZIO. Okay. 

Mr. SMITH. Mr. Chairman. 

Mr. DEFAZIO. Yes, certainly. 

Mr. SMITH. Mr. Wilcox, I saw you shaking your head. Are you 

brokering transmission around the country? 

Mr. WILCOX. No. I was trying to figure out what Peter-! am 

sorry, Congressman. 

Mr. DEFAZIO. He was referring to an earlier conversation. 

Mr. WILCOX. It wasn't anything I testified to today. 

Mr. DEFAZIO. It was a phone conversation, if the gentleman 

would yield back. BPA is telling me they have to do these things 

because they are worried about lack of control of transmission. This 
175 

was intended because they want to unbundle projects. Then they 

can charge for the other services which they can't charge for now. 

You get the incremental cost of the wheeling. They could be putting prices on it which would require an even lower rate for the 

IPPs to be competitive or would raise the total cost of the package. 

Mr. WILCOX. What I was trying to get back in that conversation 

was in the point of the testimony I gave today. Really, right now, 

Bonneville, in their one-size-fits-all rate making, is trying to compete in a market that isn't a level playing field. An IPP is selling 

vanilla power at as high a plant factor as they can, and that is 

what the IPP market is, and the Bonneville market is the same vanilla power plus load phone services, plus load shaping services, 

plus reserve service, plus, plus, plus. And part of the competitiveness project is to change these things so that Bonn~ville no longer 

is competing with its hands tied, that there is an apples-to-apples 

comparison that they are selling-vanilla power is being compared 

to vanilla power. 

And if you buy from Bonneville or buy from IPP and need these 

other services, you are paying for those separately, and I think that 

is an appropriate thing to do. In my opinion-and this is personal rather than kind of a DSI 

position-! think a big part of what is rightly or wrongly going on 

in the competitiveness project is because Bonneville's historic ratemaking practices have given you built-in incentives to build your 

own resources. And what they are trying to do is take away those 

incentives that currently exist so that they can compete in the new 

generation business. 

Mr. DEFAZIO. Okay. Just to sort of explore for anybody who 

wants to respond a little bit more about the transmission issue, because I think it is key, both to EPA's hysteria and-excuse me, 

their sense of urgency and to some of the arguments about the economics of the alternate power that is available. And back to the 1992 act, which Randy says doesn't help him, 

but I always remind him that I voted against it. I was one of two 

Members of the conference committee that voted against it, one of 

47 Members of the House that voted against it. It was ill-defined 

legislation. 

Mr. SMITH. I was not here. 

Mr. DEFAZIO. Congress didn't understand it. It wasn't this committee. It was the Energy and Commerce Committee which dealt 

with that section of the bill. Unfortunately, we didn't have jurisdiction. It would have been better. Mr. SMITH. Transmission. 

Mr. DEFAZIO. But only of BPA. On BPA, we did geL a little bit 

of special language with the help of Al Swift and this committee. 

And the question is, BPA has an undefined degree of discretion 

in managing its transmission system, for example, BPA says that 

the transmission costs would have to be just and reasonable, but 

that that doesn't apply to terms and conditions. 

Now, that would be a question applicable to anybody at the table 

who thinks they have more of a handle on exactly what that 

means. I will hear more from BPA on that, I am sure. But maybe 

it is a little esoteric. 
176 

This does go to some of these issues about who is going to be 

competitive or not competitive in terms of coming into the region 

and transmitting power, under what conditions they can do it. Because BPA has not totally lost control. We have not suddenly created a common carrier, anybody can plug in any time they want. 

That is not the way BPA seems to have interpreted it. 

Mr. PIPER. Mr. Chairman, if I can respond, I don't think we are 

concerned about access to the Bonneville system for non-Bonneville 

power so much as we are concerned about the pricing of it. 

Having said that, I also will say when it comes to non-BPA Tier 

2 power, we are very concerned in the rural areas about the transmit agreements over which that power would flow. The agreement 

with Idaho Pacific, Puget Sound Power and Light, those agreements exist because Bonneville found it appropriately cheaper to 

wheel over those lines than to build new facilities. So there aren't 

facilities connecting the Bonneville network to a number of the cooperative rural areas. Transfer agreements are a major concern 

that we have. 

Mr. DEFAZIO. When are those agreements up? 

Mr. PIPER. They vary in time. I think a number of them were negotiated about three years ago and I would guess they are 20-year 

contracts. We could get a schedule for you if you would be interested. Mr. DEFAZIO. I think that is a very real concern. BPA is talking 

about a number of other things that go to your customers, low-density discount and that. I want to see that we are not sticking it to 

the rural areas here. I would be interested in the schedule of those 

things. BPA might be able to provide it, or you can, those agreements. Anyone else want to comment on the new world of transmission? 

Okay. My eyes glaze over on some of these things, too. And unfortunately, Ms. Lamson was constrained from answering. I did have 

a question about the price. But as you said, there is a review going 

on so you can't. Ms. LAMSON. I could add one point. That is, I believe it was 

Puget Power who said at that meeting that Mr. Duncan mentioned, 

Boy, give us a call, we will buy it. And I have heard some other 

comments from several other people in the region. 

Mr. DEFAZIO. And that is at today's or even the projected, I 

would assume, hearing what I have been hearing, is a voided cost. 

Even the worst-case scenario for preferred firm rate under the DIS, which is, unfortunately, going to be thrown away and is not an accurate analysis, but when they were talking about 3--

Ms. LAMSON. I believe that is the rate they were talking about, 

yes. 

Mr. DEFAZIO. Okay. I am being reminded I have neglected some 

important point. Okay, a couple of people have alluded to this. We 

have a new process in place, but in particular, Ms. Leone referred 

to this and I think there were some others. You said we needed to have resolved the major issues or all the 

major issues in the contracts by the time we go into the rates or 

something else would need to be done. Are you saying that if we 

can't get that done-and I think it is a very ambitious schedule. 

But maybe perhaps it can be done, given the new BPA and their 
177 

new willingness to negotiate things more quickly. I would expect it 

took them three years to negotiate the contract for the three megawatt plant. Now they are going to renegotiate every contract with 

everybody in three months. This will be a reflection of the new 

BPA. 

What do you have in mind if we can't get that done, I mean, just 

a worst case? 

Ms. LEONE. Well, we are thinking about what contingency arrangements might be done. And this is not planning for failure, but 

we also don't want to fail to plan. 

One thing that was mentioned at the executive committee meeting last week-executive committee of the Public Power Council, 

Sue Hickey, when we were talking about the sequencing of events, 

contracts first', in response to a question, I think from the Mason 

Canby group, What happens if we don't reach agreement, we don't 

resolve these core questions, core issues. 

She said, Well, you guys would not want this, but it may be that 

we will have a rate case under the current methodologies that 

seeks 15, 10 percent, whatever rate increase that would be in place 

until we can get the contract issues resolved. And so I am guessing 

that that is one alternative. 

PPC is not adamently opposed to that. We haven't-as I say, we 

haven't come to any position on contingency arrangements yet, but 

apparently that is one that Bonneville is considering and it is one 

that we are open to. 

Mr. DEFAZIO. And I guess, perhaps, if we reflect on my earlier 

dialogue with Mr. Piper, I mean, if you move some of the assumptions which are common to all the alternatives into the status quo 

alternative, I don't think we need to look at the 10 to 15 percent 

because some of the assumptions they made there are contingent 

upon whether or not they can reduce staff, which they are trying 

to do in any case, and they might need the corporate status to do 

better and so on and so forth. 

So I guess, though Mr. Piper would say that that would be from 

your earlier testimony, that you would be adamently opposed to 

that disaster, wouldn't it be better to go ahead with contracts, with 

issues hanging out there, to go ahead with the rate case on the 

tiered rates on the first of the year? 

I think that is what I caught in your earlier testimony because 

that would be such disaster to the system. Is that correct? 

Ms. LEONE. I think it would be a disaster not to have core contract issues resolved. 

Mr. DEFAZIO. Right. 

Ms. LEONE. And go into a brand new, brave new world rate case. 

Mr. DEFAZIO. Okay. 

Ms. LEONE. I think Bonneville, if it needs more revenues, will, 

of course, have to prove whatever it says it needs. But it would be 

under the old methodologies. That, I believe, is Bonneville's proposal. 

Mr. DEFAZIO. Of course, we can all pray for snow, too. Ms. LEONE. Right. Mr. DEFAZIO. A lot of snow in the right places. Okay. I don't 

think that I have any more questions for this panel. Let's see if 

Bob does. No. 
178 

Is there anybody there who just didn't get to say something that 

you wanted to say that you came all the way to Washington for? 

Okay. 

Ms. LEONE. I really want to say that that 40 percent apparently 

comes from the function-by-function review, the conservation overhead. I believe that is a Bonneville number. 

Mr. DEFAZIO. It is a BPA, not a total adding in. If you added in 

the administrative costs of the local utilities, we are looking at less 

than 50 cents on the dollar getting applied to conservation. 

Ms. LEONE. Right, through the overhead. 

Mr. PIPER. Mr. Chairman, if I could make one statement. 

Mr. DEFAZIO. Sure. 

Mr. PIPER. It is not the reason I came to Washington. 

Mr. DEFAZIO. You can't talk about health care. 

Mr. PIPER. The weather is nice. One earlier statement by Mr. 

Golden I want to refute, that is, we care more about generating resources than we do about conservation. That is absolutely, unequivocally untrue. Two-tiered rates, we are totally blind as to 

what type of resources we want to see developed. It is strictly a financial issue. Our members' concern is the only thing we care 

about. Mr. DEFAZIO. Okay. Okay, thank you. We will move on to the 

next panel, which is very small in number. 

Okay. The next panel consists of one person, Mr. William G. 

Counsil, who is the Managing Director of the Washington Public 

Power Supply System. 

Mr. Counsil, same rules pertain. We have your testimony. It has 

been read and we will give you five minutes to summarize tha pertinent points. Go right ahead. 

STATEMENT OF WILLIAM G. COUNSIL, MANAGING DIRECTOR, 

WASHINGTON PUBLIC POWER SUPPLY SYSTEM 

Mr. COUNSIL. Mr. Chairman, I am Bill Counsil, Managing Director of the Washington Public Power Supply System. In that capacity, I am responsible for the management of all supply system activities. 

You have asked that my remarks address specifically the appropriateness of the recommendations in BPA's draft strategic business plan that pertain to the supply system. Those recommendations center around improving the performance of the planned two 

nuclear power plants focusing on three specific initiatives: completion of the plant, megawatt improvement program, cost control over 

the growth and cost of work performed at Plant 2 and identification 

of opportunities to further improve the plant heat rate in measure 

of fuel use efficiency. 

The supply system agrees that these initiatives are important to 

the future success of the supply system and BPA and believes that 

they are achieveable. In fact, the supply system has already demonstrated success on these fronts. The reactor power upgrade program should be completed during the next refueling outage. 

This will increase the output capacity rating of Plant 2, allowing 

it to generate about 5 percent more electricity for BPA at low capital cost. And I might point out that calculating it this morning, it 

is a little under 17 mills power. 
179 

The supply system continues to concentrate on optimizing work 

schedules during refueling outages, minimizing the number of unscheduled outages and minimizing better budget in planning and 

control. As a result of these efforts, Plant 2 performance is on track 

to meet fiscal year 2000 generation two targets. 

With respect to the third initiative, heat rate improvement, last 

year Plant 2 was the most efficient boiling water reactor in the 

United States. 

Mr. Chairman, let me say a bit more about the recent accomplishments of the supply system and point out how the system's 

performance has benefitted BPA and the rate payers of the Pacific 

Northwest. I should say first that on-line performance and safe operations at Plant 2 are the top priorities at the supply system. 

Plant 2 recorded its best generation rates ever during this past 

fiscal year, greatly exceeding all projected estimates and providing 

BPA with 7.4 more million megawatts of electricity to sell, which 

was 10 percent more than BPA expected to receive from the supply 

system. This extra power allowed BPA to avoid 20 million in power 

purchase costs from other sources. 

In addition, during the last fiscal year, Plant 2 achieved a capacity factor 76.6 percent, its best ever. The goal for this year is 78 

percent, ahead of the performance target established m BPA's draft 

strategic plan. During this same period, Plant 2 remained on-line 

for the entire winter, BPA's peak load period. 

In fact, the plant was on line continuously 257 days, its longest 

run to date by 54 days. With ongoing drought conditions and a region that is heavily dependent on hydro power, this additional 

power was timely and appreciated. 

Mr. Chairman, the supply system has achieved these performance levels while holding the line on costs and even trimming costs 

where possible without impacting safe operations. The cost of 

power for Plant 2 the past few years has been very close to the industry average and our preliminary calculations so that this will 

again be true in fiscal year 1994. As the majority task force report 

recognizes, I intend to maintain Plant 2 expenditures at the industry average or below. 

As the task force report also notes, the supplies system programs 

includes optimization of staffing levels. Currently, the Plant 2 staffing level is approximately 1300, about 150 of whom are security 

personnel. This total, which is derived in accordance with industry 

standards at that facility, state valid plant-to-plant comparison is 

not out of line with the industry. These numbers may be trimmed 

further as appropriate to maximize efficiency and to allow the dedication of resources to areas that most directly improve safety and 

performance. 

Overall for the last two years, supply system budgets have remained level and have been scrutinized and approved by the supply executive board and BP A. The supply system has also reaped 

considerable financial savings for the region as ratepayers, through 

a joint bond refunding program with BPA, through a series of 13 

bond refunding sales that began in 1989, the supply system has re- duced its debt service requirement by a cumulative total of more 

than $1.62 billion. These savings are passed directly to BPA and 

ultimately are reflected in lower rates. 
180 

Also, I think you are well aware that on May 13th of this year, the supply system board voted to terminate units 1 and 3, keeping 

with the BPA recommendation. 

In summary, Mr. Chairman, the supply system is committed to 

performance improvement, as evidenced by our actions during ~he 

past two years. Plant 2 performance has improved and costs have 

stabilized. Optimization of capital expenditures and staffing are 

critical elements of our success and operations and cost control. 

Thank you, Mr. Chairman. I will be pleased to answer any additional questions you may have. 

[Prepared statement of Mr. Counsil follows:) 
181 

Statement of 

William G. Counsil 

Managing Director, 

Washington Public Power Supply System 

before the 

Committee on Natural Resources, 

Subcommittee on Oversight and Investigations 

United States House of Representatives 

Washington, D.C. 

August 9, 1994 
182 

Mr. Chairman, members of the Subcommittee . I am William G. 

Counsil, Managing Director of the Washington Public Power Supply System. For 

those who may not be familiar with the Supply System, we are a municipal 

corporation and joint operating agency of the State of Washington that is 

empowered to finance, acquire, construct and operate facilities for the generation 

and transmission of electric power in the Pacific Northwest. All electricity 

produced by Supply System projects is delivered to electrical distribution facilities 

owned and operated by the Bonneville Power Administration (BPA), which in turn 

distributes the electricity to utility systems throughout the region. 

In my capacity as Managing Director, I am responsible for the 

management of all Supply System activities, including the operation of the Plant 2 

nuclear power plant and the Packwood Lake Hydroelectric Project. I am also 

responsible for overseeing the disposition of the Supply System's two recently 

terminated nuclear power plants, WNP-1 and WNP-3 . 

Mr. Chairman, at your request, I am appearing today to provide the 

views of the Supply System regarding its impact on, and role in improving, the 

operations and finances of BPA. In particular, I wish to discuss some of the 

Supply System's recent accomplishments and to explain why I believe that the 

Supply System's achievements and goals wilt continue to support BPA in its 
183 

performance improvement efforts. I am pleased to be here, and I hope that my 

comments will be helpful. 

Supply System Support For BPA Business Plan 

Mr. Chairman, you have asked that my remarks address specifically 

the appropriateness of the recommendations in BP A's Draft Strategic Business Plan 

that pertain to the Supply System. Those recommendations center around 

improving the performance of the Plant 2 nuclear power plant, related specifically 

to plant capacity factor, power production levels, and cost of power. 

In particular, the Plan calls for implementation of the following three 

initiatives in support of the general performance improvement objective: First, 

completion of the Plant Megawatt Improvement Program, which includes the 

Reactor Power Uprate Program to increase the output capacity rating of Plant 2 

to approximately 1160 megawatts (electric), which will allow Plant 2 to generate 

about five percent more electricity for BPA; second , tighter control over the 

growth and cost of work performed at Plant 2, including optimizing work 

schedules during refueling outages, minimizing the number of unscheduled plant 

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184 

outages, and implementing better budget planning and control ; and third , 

identifi cation of opportunities to further improve the plant heat rate . 

The Supply System agrees that these initiatives are important to the 

future success of the Supply System and BPA and believes that they are 

achievable. In fact, the Supply System has already demonstrated success on these 

fronts. The Megawatt Improvement Program should be completed on schedule (by 

the end of the 1996 Spring outage), and Plant 2 performance is on track to meet 

FY 2000 generation targets. With respect to heat rate -- a measure of fuel use 

efficiency -- last year Plant 2 was the most efficient boiling water reactor in the 

United States. In spite of its number one ranking, the Supply System continues 

to strive for further increases in heat rate efficiency. 

Mr. Chairman, let me say a bit more about the recent 

accomplishments of the Supply System and point out how the Supply System's 

performance has benefitted BPA and the ratepayers of the Pacific Northwest. 

Supply System Accomplishments 

The Supply System has recorded numerous business and operational 

successes and improvement trends over the past few years, all of which benefit 

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185 

BPA directly. Three areas in which the Supply System has made significant 

progress are nuclear plant performance improvements, operating cost reductions, 

and debt service reductions. These successes demonstrate that the Supply System 

shares BPA's commitment to stronger, more efficient operations and will continue 

to support BPA's performance improvement objectives in the years ahead. Let me 

briefly expand upon each of these three areas of success. 

Performance and Reliability 

On-line performance and safe operations at Plant 2 are the top 

priorities at the Supply System. The Supply System has made great strides in the 

past few years toward excellence in performance among the nation's nuclear power 

plant operators. Success in this area benefits BPA directly in the form of reliable , 

abundant power supplies and, ultimately, lower costs. I will give you a few 

examples of performance improvements. 

Plant 2 recorded its best generation rates ever during this past fiscal 

year, greatly exceeding all projected estimates and providing BPA with 7.4 million 

megav:att-hours of electricity to sell-- which was 765,000 megawatt-hours, or ten 

percent, more than BPA expected to receive from the Supply System. This extra 

power -- the equivalent of about an extra month of full power operation -- allowed 

- 4-
186 

BPA to avoid approximately $20 million in power purchase costs from other 

sources. 

During the last fiscal year, Plant 2 achieved a capacity factor of 

76.6%, its best ever. The goal for this year is 78%, ahead of the performance 

target established in BPA's Draft Strategic Business Plan. During the same 

period, Plant 2 remained on-line for the entire winter, BPA's peak load period. 

In fact, the plant was on-line continuously for 257 days-- from August 12, 1993, 

through April 26, 1994 -- its longest run to date by 54 days. With ongoing 

drought conditions in a region that is heavily dependent on hydro power, this 

additional power was timely and appreciated . 

Cost Control 

Mr. Chairman, the Supply System has achieved these performance 

levels while at the same time holding the line on costs and even trimming costs 

where possible without impacting safe operations. 

Plant 2 costs for the last several years have been very close to the 

average for nuclear plants of its type operating in the U.S. As the Task Force 

Report recognizes, I intend to maintain Plant 2 capital expenditures at the industry 

average or below. 

- 5 -
187 

As the Task Force Report also notes, the Supply System's program 

includes optimization of staffing levels. Currently , the Plant 2 staffing level is 

approximately 1300, about 150 of whom are security personnel. This total, which 

is derived in accordance with industry standards that facilitate valid plant-to-plant 

comparison, is not out of line with the industry. These numbers may be trimmed 

further, as appropriate , to maximize efficiency and to allow the dedication of 

resources to areas that most directly improve safety and performance. 

During two of the past three years the cost of power, as measured by 

the industry, for Plant 2 has been close to the industry average, as indicated in the 

table below: 

Fiscal Year 

1991 

1992 

1993 

Cost of Power 

Mills/Kilowatt-Hour 

21.65 

30.76 

22.61 

Industry Average 

21.52 

21.61 

21.52 

For FY 94, just ended, our preliminary calculation of the cost of power for Plant 2 

is 21.5 mills per kilowatt-hour. 

Overall, for the last two years, Supply System budgets have remained 

level and have been scrutinized and approved by both the Supply System Executive 

Board and BPA. 

- 6-
188 

Mr. Chairman, the Supply System is also cognizant of the sensitivity 

of SPA's financial situation to such factors as weather and market conditions. To 

provide needed flexibility in BPA's budget, the Supply System has on several 

occasions agreed to postpone to a later rate period certain capital expenditures that 

were not safety significant. Supply System expenditures are guided by the 

fundamental objective of sustaining safe, reliable, and cost-efficient operations at 

Plant 2 and throughout the system. 

Mr. Chairman, controlling Supply System costs remains a top priority 

for Supply System management. We have initiated a three-year "Get Well 

Program" to improve Plant 2 operating performance. We have made good 

progress so far, without increasin~: bud~:ets as have other nuclear plants. In the 

first year of the program, we focused on plant reliability and providing BP A with 

needed power. The result was an impressive 20 percent increase in Plant 2's 

capacity factor for the year. While continuing to look for improvements in 

Plant 2 performance, we are now concentrating on improving organization and 

process efficiencies, which should lead to lower operating costs and reduced 

capital expenditures. Our improvements to date have already been recognized by 

our regulator, the Nuclear Regulatory Commission, and we intend to continue 

them until we become one of the nation's top performing plants. These 

- 7 -
189 

performance improvements benefit BPA directly in the form of a more abundant, 

more reliable, lower-cost supply of electricity. 

At the same time, I wish to emphasize that while low cost power 

production is a Supply System goal, broader commitments to reliability and ~afety 

dictate that less is not always better. Safety considerations and regulatory 

constraints will in part dictate appropriate standards in areas such as staffing, 

operating and maintenance budgets, and capital expenditures. Supply System 

management will continue to aim for maximum efficiency in these areas, without 

compromising in the least its commitment to safe and reliable operations. 

Debt Service Reductions 

The Supply System has also reaped considerable financial savings for 

the region's ratepayers through a joint bond refunding program with BPA. 

Through a series of 13 bond refunding sales that began in 1989, the Supply System 

has reduced its gross debt service requirement by a cumulative total of more than 

$1.62 billion. Since inception of the refunding program, the Supply System's 

overall weighted average true interest cost has been reduced from 10.46 percent 

to 5.86 percent. These savings are passed directly to BPA and ultimately are 

reflected in lower rates paid by electric customers in the region. Each year those 

- 8 -

84-374 0 - 94 - 7 
190 

savings translate into more money that is available for other critical activities in 

the region, such as the pursuit of conservation and salmon recovery efforts. 

Termination of WNP-1 and WNP-3 Projects 

Mr. Chairman, the Supply System has demonstrated support for the 

policies and objectives of BPA. On May 13, 1994, the Supply System Board 

voted, consistent with BPA's recommendation, to terminate the WNP-1 and 

WNP-3 nuclear projects in their current conception. The decision will lead to the 

termination of certain contract provisions between the Supply System and BPA for 

the WNP-1 and WNP-3 projects and could save BPA millions of dollars in project 

preservation costs beginning as early as 1995. 

At the same time, the Supply System continues to explore possibilities 

for future use of these valuable assets which would benefit BPA. As noted in the 

Majority's Task. Force report, one such option would be dedication of one of the 

plants, WNP-1, for use in reducing U.S. stockpiles of surplus weapons-grade 

plutonium. This is by no means a far-fetched proposal but rather a concept which 

employs existing technology and processes, which the National Academy of 

Sciences itself has recommended as one of the most desirable means of plutonium 

- 9-
191 

disposition, and which continues to receive much attention within the U.S. 

Department of Energy and other bodies tasked with identifying the best options for 

disposing of surplus U.S. nuclear weapons materials. 

The Supply System has explored the reactor-use concept prudently, 

without overcommitment of resources, and plans to continue to seek to preserve 

the option, as appropriate, as long as U.S. scientific and policy debate endorse it 

as a desired means of disposing of these materials. 

Conclusions 

Mr. Chairman, the Supply System is committed to performance 

improvement. Our actions during the past two years are evidence of that. A nearcomplete change-out of senior management with highly-qualified individuals has 

brought new approaches and experience from top-performing nuclear plants around 

the country. The safe, reliable and cost-effective operation of Plant 2 remains our 

top priority. Excellence in this area alone will do much to support the 

performance objectives of BPA. At the same time, efforts such as our bond 

refinancings and WNP project terminations have further boosted the operations and 

financial position of BPA. Going forward, we are working to diversify our 

- 10-
192 

generation resources -- vigorously pursuing, for example, opportunities to 

construct and operate natural gas-fired combustion turbines in the Pacific 

Northwest. 

These initiatives are consistent with, and are addressing, the findings 

and recommendations in the Task Force Report. Plant 2 performance has 

improved and costs have stabilized. Optimization of capital expenditures and 

staffing are critical elements of our success in operations and cost control. 

I am convinced that through continued dedication to performance 

improvement and cost control, the Supply System will continue to contribute to the 

mission of BPA. 

Thank you, Mr. Chairman. I will be pleased to answer any questions 

the Subcommittee may have. 

- 11 -
193 

Mr. DEFAZIO. Thank you, Mr. Counsil. 

We have some analysis provided both by the Bonneville Power 

Administration and from Mark Holt of the Congressional Research 

Service surveying literature and studies that are out there. Just 

want to go through some questions regarding that, particularly 

having to do with staffing levels. 

You said that there are approximately 1,300 employees, 150 of 

those being security. That is actually a little higher than the number I had, but that is fine. We will work with that number. 

The INPO study, which is the Institute of Nuclear Power Operations, basically shows on-site nonsecurity staffing at a plant the 

size of WPPSS II of 783. And that has excluded security personnel 

again, nonsecurity staffing. Don't you feel that you are quite a bit 

above that level? You are basically at 150. 

Mr. COUNSIL. Our staffing right now, Mr. Chairman, is higher 

than I would like to see our staffing. However, our costs are in line 

with the average in the industry. Since our costs are made up of 

approximately 80 percent staffing, I believe overall, you know, that 

we are on line. 

We have a great deal of work that has to be done in the next 

two years. So consequently, I have elected not to reduce staff during that two-year period but to accomplish the work that perhaps 

should have been accomplished before the plant started up. 

Mr. DEFAZIO. Well, if I were to apply a similar analogy, I would 

say BPA's costs, wholesale power costs, are better than in line. 

They are lower than most costs around the country. So, therefore, 

they shouldn't be concerned about the 4,000 some odd staff they 

have. But, in fact, they are concerned about having such a large 

staff. And they are going to take some extraordinary measures to 

reduce it. 

I mean, I am glad you have admitted that you would like to see 

it lower, because I was going to go through a series of questions 

with analysis from the energy utility cost group, T.D. Martin and 

Associates. I mean, every one of these studies would find that 

WPPSS is considerably above. 

I guess I will take a little different tact, since you basically admitted at the outset that you are higher than you would like to be, 

and just go to this cost issue. I mean, as you have heard from all 

the previous testimony, we are expecting a brave new world out 

there in terms of power generation. 

You are a significant cost factor. When you add in the amortization for the debt for all the other WPPSS disasters, you are the 

most significant cost factor the bundle administrator has to suffer 

under. But with one operating nuclear power plant, you are still, 

if we exclude all of the water under the bridge there, you are still 

a significant cost factor. 

I guess I am concerned that you are saying, Well, the staffing is 

higher but your costs are in line. Well, it would be nice if your costs 

were way below anyone, your costs were lower. What is your plan 

to reduce staffing to come in line with other comparable plants in 

the industry? 

Mr. COUNSIL. We are in line with other comparable plants. 

Mr. DEFAZIO. No, no. You admitted you weren't. We have the 

INPO study 783, okay? We have got the EUCG study, which would 
194 

be, you know, about 300 lower. We have got the TDM Associates 

study, which would put you down, again, as being about 500 over 

the average. So, I mean, you are not in line. 

What is your plan to get more efficient and to remove some of 

these inefficiencies from the operation of that plant and reduce the 

most significant cost factor you have, which is payroll? 

Mr. COUNSIL. Until I finish the Get Well Program for WMPT, I 

am not going to reduce staff. 

Mr. DEFAZIO. The Get Well Program involves you being 

overstaffed. 

Mr. CoUNSIL. No, it does not involve being overstaffed. 

Mr. DEFAZIO. You said you are in line with everybody-excuse 

me. 

Mr. COUNSIL. It involves finishing the work I have to do. 

Mr. DEFAZIO. Mr. Counsil, please. Let me frame the question 

better. The three studies I have show that you range from 300 to 

500 more for comparable plants. You told me you are equivalent to 

comparable plants. 

Please address those three studies, why you are wrong, why you 

are not 300 to 500 over comparable plants around the country, and 

then we will get to the second part of the question. 

Mr. COUNSIL. The INPO study for our plant is 1031 people. You 

said 768 was the average. 

Mr. DEFAZIO. Seven hundred eighty-three. 

Mr. COUNSIL. Seven hundred eighty-three. So we are approximately 250 above that number, of which 150 is security. We included security in our study. 

Mr. DEFAZIO. No, you told me you had 1,300 when you include 

security. 

Mr. COUNSIL. I also said that that was our study. Mr. DEFAZIO. No, no, wait a minute. Let's-how many people do 

you have? You are saying their study says 1150 and you told me 

you have 1300. Do you have 1300 employees? 

Mr. COUNSIL. I have 1300 by my count at WMPT. 

Mr. DEFAZIO. And 150 are security. 

Mr. COUNSIL. Yes. 

Mr. DEFAZIO. So you have 1150 people who aren't security at 

Plant 2, and the industry average, according to INPO, is 783. If I 

subtract 783 from 1150, I get approximately, it looks to me, like 

17-that is 67, plus--477. 

Mr. COUNSIL. The same INPO study lists us at 1031 people. 

Mr. DEFAZIO. I don't care what they list you Rt. I am talking 

about the average. You say you are comparable to other plants. 

They say the average is 783. You have 477 more people. 

Mr. COUNSIL. I am using the same numbers, same cost basis, so 

forth as INPO. If I use their numbers, which they have provided 

back to us, it is 1031. I told you, I have really 1300. I have 250 

additional personnel working on additional regulatory required programs for the next two years. 

Mr. DEFAZIO. Okay. Okay. You have 477 more employees than 

the industry average, but if you use their numbers, you don't have 

477 more. Fine. But the point is, you have 1300 people; 150 are 

nonsecurity. They say 783 is the average. 
195 

Let's try the EUCG, okay? Since you don't like the INPO study. 

They give you a much higher number of staff. I guess-1 don't 

know where they get these additional staff. 

Are they attributing headquarters staff, people who sit around 

and handle the bond payments? How do they include the higher 

number? 

Mr. CoUNSIL. They do include bond, finance people, so forth. If 

you look at the EUCG study for large BURs, we are comparable 

with the rest of the industry in numbers of personnel. 

Mr. DEFAZIO. How many people does WPPSS employ total? 

Mr. COUNSIL. One thousand seven hundred, approximately. 

Mr. DEFAZIO. One thousand seven hundred, okay. And you are 

saying 1300 of those can be attributed to the functioning reactor, 

and 400 are other. Have you looked at the "other" for reductions? 

Mr. COUNSIL. Absolutely. And we will be in fact reducing in the 

future. 

Mr. DEFAZIO. By how many and by when? 

Mr. COUNSIL. We are going to go down by attrition. I us~I lose 

approximately 80 people per year. 

Mr. DEFAZIO. Why have you chosen attrition? That is obviously 

easiest for the people. But is that best for the ratepayers or the 

upper-most efficient operation? 

Mr. COUNSIL. No. 

Mr. DEFAZIO. We are running it like a business, remember. Everything is run like a business. 

Mr. COUNSIL. I am well aware of that. It does match, as the work 

gets completed, that does in fact match approximately what we 

have as a completion plan. 

Mr. DEFAZIO. Okay. How about the 1300 people at the operating 

plant? When are we going to see the reductions there? How many, 

on what time schedule? 

Mr. COUNSIL. Don't know that answer yet. 

Mr. DEFAZIO. When will you know it? 

Mr. COUNSIL. Approximately two years. 

Mr. DEFAZIO. In two years, we will look at the 477 or 300 or 

whatever people more we have above the industry average. In the 

meantime, you will just pass those costs on to the region while the 

region is struggling and cutting everything else. 

Mr. COUNSIL. No. I look at those costs each and every year. And 

as a matter of fact, we are attempting to reduce the costs each 

year. 

Mr. DEFAZIO. What if BPA refused to pay your total bill, what 

happens? 

Mr. COUNSIL. I shut the plant down. 

Mr. DEFAZIO. Okay. 

Mr. COUNSIL. I think you would be well aware of that. I wouldn't 

even have to worry about shutting it down. The Nuclear Regulatory 

Commission would do it for me. 

Mr. DEFAZIO. They would do it for you if BPA mandated on you, 

mandated reductions on unnecessary staff? 

Mr. COUNSIL. I didn't say mandate reductions in unnecessary 

staff. If there was no compromise in safety, yes, they would shut 

it down. 
196 

Mr. DEFAZIO. Well, are you telling me that all the other nuclear 

plants in the United States are operated unsafely because their 

staffing levels in comparable plants are significantly below yours? 

Should I get FERC in here to find out if there are not--

Mr. COUNSIL. Mr. DeFazio, I stated comparable plants to WBU2, a water boiler reactor of the 1200 megawatts vintage have approximately 1200 to 1250 people at their operating units. That is an 

easy number to check. I would be happy to fmward it back to you. 

Mr. DEFAZIO. Sure. The problem is we have three studies that 

find a difference with your numbers. But I would be happy--

Mr. COUNSIL. I will be happy to take those numbers directly from 

those studies for large boiling water reactors and give you those 

numbers, unvarnished by me whatsoever. 

Mr. DEFAZIO. Okay. Now, what about this termination date? We 

are talking 1995. When is the termination date? 

Mr. COUNSIL. I don't understand the question. 

Mr. DEFAZIO. What is the specific date for termination? 

Mr. COUNSIL. Oh, termination of units 1 and 3? 

Mr. DEFAZIO. Uh-huh. 

Mr. COUNSIL. They have been terminated. 

Mr. DEFAZIO. Well, my understanding is there is some sort of 

holding open the final actions involved in termination, turning back 

the licenses and going to a restoration license or whatever's necessary. 

Mr. COUNSIL. No, sir. We are trying to sell the units now. But 

during the period of this sale of assets and/or utilization of the 

units as a different project, such as plutonium burning and/or as 

a gas-fired unit, we have to preserve those assets in case somebody 

wants to buy the assets, in whole or in part. So in order to maintain the qualifications of those assets as nuclear qualifications, we 

have to maintain the preservation of such asset. 

Mr. DEFAZIO. And how long do you expect that condition to pertain? How long will you look for buyers? I know in the past five, 

six years ago, you were looking at China and some other places. Now we have some new fantasies, Project Isiah. How long do we 

pay for this? 

Mr. COUNSIL. I am sorry, we have no fantasies about Project 

Isiah. I do not support Project Isiah. Mr. DEFAZIO. Well, then, how long before these alternatives are 

ever fully explored and you reach a final decision? 

Mr. COUNSIL. The final decision as far as asset indication for plutonium burn on MP-1 and 2 is January 13, 1995. In the meantime, we are attempting to sell such assets. 

Mr. DEFAZIO. Okay. January 13, 1995. Now, let's get into a subject that pertains a little bit to this: termination. 

I mean, I have a question. One of the reasons why BPA has 

never terminated its involvement with the mothballing is because 

of the very large cost involved with termination. I understand in 

part that may require site restoration and so forth. My own idea 

is that we actually put a fence around these things and maybe 

even a high enough fence so we could charge admission for people 

to come in and look at these monuments to folly. They are not a 

danger to anybody. They are not radioactive in there. If you keep 

kids out so they don't fall in the hole anywhere, why not explore 
197 

those sites? Are you exploring any alternatives why-1 understand 

this is pretty much under the purview of the utility commission in 

Washington State and State law. Are you exploring lower-cost alternatives should the plants be terminated? 

Mr. COUNSIL. We are exploring all options with the Washington 

State Energy Facility Siting Council, yes. 

Mr. DEFAZIO. All right. 

Mr. COUNSIL. And hopefully, as long as you can prove that the 

site is safe for people that happen to wander in or want to play 

games there or whatever else, that it doesn't present a public 

health hazard, I am quite certain they will cooperate with us. 

Mr. DEFAZIO. Okay. It seems like you could basically put a fence 

around it, maybe hire Pinkerton's or something. 

Mr. COUNSIL. No. That is not what they have in mind. They have 

insisted on demolishing the cooling towers, taking down the cooling 

building and various others. 

Mr. DEFAZIO. Why? What danger does that present to the public? 

Mr. COUNSIL. They can rust. In fact, there are many many open 

hatches in the turbine building. 

Mr. DEFAZIO. What if we have a fence and we keep people out? 

Mr. COUNSIL. I have a fence now. 

Mr. DEFAZIO. Well, double fence with dogs. 

Mr. COUNSIL. Dogs, by the way, there are many utilities that 

have tried that and have been sued. Long Island Lighting is one. 

Mr. DEFAZIO. Well, I would suggest that you should continue to 

pressure them and wouldn't necessarily accept their decisions, because it is pretty easy, I guess, to pass the costs off onto the region 

of the termination. But as a part of the region that doesn't have 

jurisdiction, I have a concern, and I think the more reasonable alternatives, particularly for plants that were never operated, there 

would be lower costs. So perhaps I will take that up with the 

Washington authorities. 

Now, you have had some pretty high capital investments in the 

past and now you are projecting to have some lower ones in the future. 1993 to 1996, you are going to average $60 million annually. 

Is this because of past neglect, or why are they so high and so 

high above the average for that three-year period? And then you 

are going to get below the average in the future, you are saying. 

Mr. COUNSIL. They are largely part of the General Electric settlement and the megawatt improvement program of Bonneville itself. 

And these were costs that were going to be spent, for instance, in 

the year 1992 but Bonneville asked us to put them off. And they 

are not all cash. They are a cost basis largely. 

For instance, the General Electric settlement is no-does not involve cash. It involves adding to the cost basis of the plant only. 

Mr. DEFAZIO. Hm-mmm. 

Mr. COUNSIL. Largely where we have been is the plant capital 

itself has been on the order of $16 to $25 million. The remainder 

of those are megawatt improvement and noncash type capital. 

Mr. DEFAZIO. Okay. You were telling us about the operating factors and how great everything was going. I saw some news stories 

not too long ago about an unanticipated outage that extended for 

some period of time because of something strange, a light bulb or 

something. 
198 

Mr. CoUNSIL. Well, it was partially that. It wasn't a light bulb. 

It was a light fixture. And during this past August, it was a 10-

year in-service inspection and hydrostatic testing of the unit. We 

hoped we could get it done in 60 days. It actually took closer to 90. 

Part of what happened to us during that period of time was that 

we had a gross deterioration of our electrical penetrations that go 

through the primary containment. There are some 60 electrical 

penetrations carrying electrical signals, both in and out of that primary containment. Of those 60 penetration modules, each of which 

has upwards of 300 wire pairs, of those 60, we reworked 25 and 

replaced 10. For the next two refueling outages, we will be working 

some additional. During that period of time, we also discovered we 

had a crack on an internal component in the reactor vessel itself. 

That internal crack took six days to resolve. 

During the period of resolution of that, in rotating a service platform over the reactor vessel, we tore off one of the lights because 

we do have to have underwater lights and TV cameras because we 

are working through 60 feet of water. And that light itself fell 

down and went through the suction to one of our pumps. And so 

we had to go in, open up the system and get into the pump to take 

out that light. That took an additional five days. 

Mr. DEFAZIO. So the-this was 90 days. You say you are going 

to have to rework some of these through the wall components next 

time. Does that mean that the next outage is going to be also extended? . Mr. COUNSIL. We expect that next outage should be on the order 

of 45 days, and depending on the amount of capital that we have 

to put in, such as electrical penetrations, it may have to be extended to 60 days. I am hopeful we can hold it to much less than 

that. Mr. DEFAZIO. Okay. What is the industry average on this age 

plant? 

Mr. COUNSIL. On this type plant is approximately 60 to 65 days, 

is the normal refueling outage. 

Mr. DEFAZIO. Okay. So the problems this time in part were the 

unanticipated replacement of some of those modules and then the 

problem with the crack and the problem with the light fixture. 

Mr. CoUNSIL. That is correct. 

Mr. DEFAZIO. What was the crack? 

Mr. COUNSIL. The crack was on a jet pump sensing line. There 

are 20 internal jet pumps to the reactor vessel. They basically 

measure the flow going through the fuel bundles. Four of the sixfour of the 20 jet pumps are fully instrumented with two lines each 

and 16 have a single line. So you are only measuring the reference 

lake. We found the crack on the backside of one of those single-instrument jet pumps. 

Mr. DEFAZIO. So you replaced that one. Did you check all the 

others thoroughly? 

Mr. CoUNSIL. We checked all the others and did not replace that 

one. 

Mr. DEFAZIO. You did not. 

Mr. COUNSIL. No. Our analysis showed it would not crack further, that the jet pump would still indicate, and even if it did 

crack, it wouldn't present a safety consideration. Mter five days of 
199 

analysis, the NRC basically agreed with us, so we went back to put 

the reactor vessel back together with a crack. 

Mr. DEFAZIO. Okay. All right, I don't have any further questions. 

I thank you for traveling all the way back to provide testimony 

to the committee; I will look forward to your providing the analysis 

of the staffing levels in writing. 

Mr. COUNSIL. Thank you. 

[Editor's note.-See Appendix.] 

Mr. ROBERTSON. Mr. Chairman, does the committee send out for 

sandwiches? 

Mr. DEFAZIO. Well, I figure we would put you on now, and we 

could get done in time for a fashionably late lunch, or an early dinner. We have got both you and Mr. Pollock, and Mr. Wright as 

well. How much time would you require for your basic presentation? 

Mr. ROBERTSON. I think I need about 10 to 15 minutes. 

Mr. DEFAZIO. Okay. We will set it on 10, and if that isn't enough, 

we will then go with another 5. How is that? 

Mr. ROBERTSON. Thanks. 

I appreciate the time. 

Mr. DEFAZIO. Okay. Go right ahead. 

STATEMENT OF JACK S. ROBERTSON, DEPUTY ADMINISTRATOR, BONNEVIT...LE POWER ADMINISTRATION, DEPARTMENT OF ENERGY, PORTLAND, OR, ACCOMPANIED BY WALTER E. POLLOCK, ASSISTANT ADMINISTRATOR FOR POWER 

SALES, BONNEVILLE POWER ADMINISTRATION, DEPARTMENT OF ENERGY, PORTLAND, OR 

Mr. ROBERTSON. Thanks again, Mr. Chairman. 

My name again, gentleman, is Jack Robertson, Deputy Administrator of Bonneville Power Administration. I would like to respond 

to some of the questions and comments I have heard today as best 

we can. But I would like to start by making a couple of, I think, 

overarching and fundamental points. 

The first point I would like to make again is the fact that we encourage and appreciate the review of the committee. You have had 

a series of task force reviews for us. This is a complicated and challenging period we are entering. We recognize that no one agrees 

with everything we do at any time, and we understand that you 

as the Chairman also have serious concerns about what we are 

doing. We believe strongly, though, in this kind of public review 

process and it will make us a lot better. 

The one thing I wanted to leave with you is I think a fundamental and overarching concern is this: Bonneville is doing its best to 

try to deliver to the people of the Northwest what I think the people of the Northwest believe and demand the government give 

them in the 21st Century-to continue to strive to give them much 

higher value for far less cost. 

We think this means a goal of delivering stable rates on our fundamental product for the balance of this century, while continuing 

to also deliver, one of the most aggressive and innovative conservation and fish and wildlife programs in the world. We recognize to 

an important degree the economic viability and environmental val-
200 

ues of the Northwest depends on our success, and it is a big job 

ahead of us. 

Let me talk first about a regulatory change. We have heard this 

today, and I just want to go through a couple of things quickly to 

make sure you understand the examples we think at least show 

the fact that, as most people agree, some change is on us. There 

is a question today about how much change. But to us the fundamentals look pretty clear. 

First of all, I would like to make a couple of analogies. We have 

seen the deregulation that has occurred in the airline industry, in 

the natural gas industry, and in the telecommunications industry, 

but we have seen it other places as well. · One of the analogies that I think is most apt ironically for Bonneville in terms of our concern, is none of those, but is IBM. IBM 

was-is one of the great American corporations; it made its money, 

it has made its spot in the marketplace based on one fundamental 

concept, and that fundamental concept was that you could control 

central computing power. And in the course of its history, it made 

and grew into the biggest, one of the biggest corporations in the 

world, based on that fundamental premise. 

IBM today is a far different corporation. I would argue that the 

reason it is now a far different corporation is because it did not anticipate a wave of change which occurred in two fundamental 

areas. One was the access of individuals to computing power, and 

the second one is the technological breakthroughs associated with 

vast amounts of power on work disks. The result of these twin 

changes of computing power and open architecture, fundamentally 

destroyed the basic tenants of what IBM had based its business on. 

Similarly, if you look at the retail industry and you talk about 

Sears. Sears was a retail giant for the entire century, and passing 

back in the 19th Century. It was all things to all people. It marketed from a central concept. It delivered high value to high-end 

customers and low value and low-cost goods to low-end customers. 

But then as the retail environment began to get more competitive, 

the Nordstroms of the world and the high-end customers began to 

eat Sears' lunch from the top down, and the COSTCO's of the 

world and the wholesale-based customers began to erode it from 

the bottom up. The fundamental is now Sears, a formerly major institution, has lost fundamental market shares. 

Now, the Northwest can't afford Bonneville to become obsolete 

and lose market shares similar to what has happened to IBM and 

Sears. We do not believe we are on the verge of a death spiral, and 

I want to make that clear. What we are trying to do is anticipate 

what we think is a combination of unique changes and events 

which are fundamentally affecting the electric industry. We want 

to do this to stay ahead of this change. We do not want to be toppled by a shock wave of change later on as happened with IBM and 

Sears, to some degree. 

Now, what are the three elements of these changes? I just want 

to briefly go through them. We think they are in three areas: The 

generation competition we have talked about, and you alluded to 

earlier; the global competition in trade, which we think is increasingly an important aspect for competitiveness of the Northwest 
201 

economy; and finally, the transmission changes you alluded to in 

1992 National Energy Policy Act. 

If I can go quickly, I would like to go to Chart 1. Chart 1 shows 

the competitiveness of our product versus the competition. It becomes more and more severe as we have gone through the last two 

decades. 

This has been well-publicized in the region. My purpose in raising it is not to pound it in the ground, except to make the obvious 

point that something fundamental is going on in terms of the margin of the change. We can argue amongst ourselves or even project 

whether the cost of alternative energy is going to go up faster than 

not, whether gas prices are going to become more costly, and so on, 

but the fundamentals of that chart are these: our price advantage 

a decade ago was 400 percent, compared to the competition. And 

in that chart today, that same split is 15 percent. 

Customers--now, change associated with this, the petition we 

talked about, is in motion now. It is not some hypothetical change 

that might take customer share away from us. We think the signs 

of this are clear, and again, we want to respond to the signs. We 

don't want to stick our head in the sand because too much is riding 

on Bonneville staying competitive in the region. You have talked about Clark County PUD recently signing a letter of agreement to purchase a 245-megawatt cogeneration unit. 

That would cost us, we think, about $10 to $20 million, if they go 

through with that. You indicated that we hadn't gotten notices yet 

on that and we wouldn't expect to get notices because of the provisions. But we think they are serious and they think they are serious from everything we have described. 

Snohomish County PUD has requested resource proposals and 

received 88 responses for a total of 8,000 megawatts. This is a huge 

number. These are the same megawatts and proposals largely that 

come in our door when we asked for resource proposals. They are 

waiting outside as competitors to fundamentally go after Bonneville's load if we don't maintain our cost competition. 

According to Snohomish, the cost is 27 to 32 mills, starting in 

1997. We can have a debate on whether that is the right number 

or not, but the number is very close to Bonneville's base rate, we 

think. Twenty six of our customers have signed an agreement with 

power resource managers for a 600-800 megawatt package of alternative resources. A final decision on whether to proceed with this 

resource package is expected next year. 

Washington Water Power and Sierra Pacific have announced a 

planed merger which could create another strong competitor for 

Bonneville inside the region for wholesale supply. In the Northwest 

alone, 1,400 megawatts of new generation are now in service, or 

under construction, and another 3,000 or 4,000 megawatts are 

being studied. 

The FERC has approved more than 20 new power-marketing 

firms to buy and sell power in the wholesale market. Moreover, 

work is underway to establish a West Coast electric futures market. All of these we think are signs of a fundamental change. How 

fast is the change coming is a serious question. But we think fundamental change is on the way. 
202 

All of this, by the way, I think is excellent news for consumers. 

The cost of electricity is going to be very competitive. Bonneville is 

going to be in a much more competitive world; the prices will probably go down. The fundamentals are, if we can't compete, we cannot deliver the mission of Bonneville, which is vital to the region's 

economy and environment. 

The second point is global competition. We talked earlier about 

the variable rate and I would just like to make this point. Up until 

the fall of the Berlin Wall, the variable rate for the DSis was making the region about $250 million. What we did not anticipate, and 

what I think few anticipated, was that the Berlin Wall would fall 

and the integration of the eastern and western economies would 

have to take place in the last few years. 

The result of that, in simple terms was, during the period of 

worldwide recession, we had to integrate the aluminum production 

facilities. The vast aluminum production facilities of the former Soviet Union that was devoted to its defense industries in the westem world and the commodity prices plunged. The result of that 

was what you see today, which is a leveling out of the variable rate 

in materials of its cost and benefits. 

So, the global competition plays a huge factor in whether the 

Northwest can continue to regionally compete. 

Finally, the third area is transmission access. We have talked 

about the changes of NEPA 1992. What factually will come from 

NEPA 1992, I think has been clearly stated here as uncertain. It 

is clear that the fundamental premise under NEPA 1992 is allowance for more transmission access increasingly as we move forward. 

Now, again, I just want to say we are confident about our ability 

to stay ahead of these trends, but we have to recognize them and 

not ignore them. 

The third chart, the one up on top which talks about rate increases, projected rate increases, are really the focus of my testimony today because it kind of puts in perspective the discussions 

we have had. We have talked about how different customer groups 

would or wouldn't benefit under the draft proposal. 

What you see in the comparison chart is the fundamentals of 

how our product design would look before and after taking any actions. The upper path is the most current data. We would expect 

to need increases in our rates in 1996, as we indicated, of somewhere between 10 to 15 percent on that upper path. This is indicated in that first increase associated with the path. 

With continued inaction, and again, this assumes that we do not 

act and assumes some actions we would take no matter what; but 

with continued inaction, we think this would total 40 percent by 

the year 2002, on the upper path. 

Now, the earlier estimates that you talked about with Randy 

Hardy, you said he said was thrown out. This was really a reference point to this graph so at least you could see where it would 

be placed, and we have some more information to give about that, 

but that is basically the reference point that is indicated by the November 1993 data. 

The business plan EIS, which you reviewed and based some of 

your comments on, was developed basically in October a year ago. 
203 

It had lesser numbers at the top. It also had less accomplishments 

at the bottom, and the differential was less than it is described 

here. But we think that has, as I think you are aware, first-cut 

data that was not anywhere near as sophisticated as the models we 

now have as we begin to apply ourselves in more details in the implications of the change. 

So, the bottom two lines show, we think, what we can achievea goal of trying to flatten the rate through the year 2000. The bottom darkest line is basically the tier-1 rate plus shaping services, 

and again, we are trying to flatten it in real terms through the century. On top of that is basically what we think is a combination of 

tier-1 and tier-2 products which would come as close as we can to 

simulating today's PF rate. And that upper line, the second upper 

line goes up to 15 percent by the year 2002, the bottom line goes 

up to 10 percent in the year 2002. 

So, the fundamental point here is from the bottom line to the top, 

we are talking about roughly a difference between 40 percent rate 

increase and 15 percent rate increase, if we can achieve the objectives of the Business Plan. We think that is significant; we think 

it will help the regional economy; and we think it will help keep 

ratepayers' rates flat. We think we can achieve that by also keeping our eye on the long term in the conservation program we are 

proposing, because we again believe we can deliver as much conservation as we can with the new program as with the old, just for 

less money and less up-front costs. 

The other point that needs to be made by this graphic is even 

though we will have a continuing debate as we should about how 

the costs are split between customer groups, the fundamentals are 

that customers as a whole, if we are successful, should see substantial benefits in the way of additional monies remaining in the region for economic growth purposes and for conservation purposes 

as well. 

Now, how are we going to get down to this bottom line? There 

are three fundamental areas. Let me go briefly through those: 

strict cost-management control; program reinvention; and finally, 

new products and services. 

You are aware of the two tiers we have proposed, tier 1 and tier 

2. Tier 2 is designed to reflect the cost of new generating resources 

and we expect these rates would serve about 10 percent of the utility existing load and any future low growth that they choose to 

have Bonneville serve. This tier-2 rate would compete directly with 

other power suppliers in the market. 

We must also unbundle our products and services. We think in 

the unbundling of these products and services, there is a lot higher 

value in shaping specific products and services toward the unique 

needs of each utility. These unique products that they would buy 

from a menu of services in a willing manner, we think there is 

higher value that is added, and that is where some of the money 

comes from in terms of new revenues. And, we think that money 

will come from a willing buyer/willing seller basis. 

We also fundamentally changed what we think is the hassle factor of doing business with Bonneville. I don't think we are a Sovietstyle bureaucracy, but I get your point. Ironically, I think the Russians are coming out here next month for us to teach them how we 
204 

do public involvement, because we have been given exemplary sta- tus on that, which I am very proud of. But in any event, we have 

a focus now on our universities and constituent groups, Northwest 

tribes, States and local groups which we have never had before. 

Finally, we are reducing costs and we believe we have to do this 

because, again, market forces leave us very little room to cover 

costs otherwise. With our project rates at the top of that schedule, 

we would expect to have a cost of 2.8 billion in 1996, and 3.3 billion 

by 2002. Under our changes, we would hope to hold the cost constant roughly, 2.8 billion through the year 2000. 

Now, you have asked us specifically, and I am going to be real 

brief here, to talk about how we responded to the task force recommendations. And I am going to go through these and we can 

provide more of this information as you like. First of all, we congratulate you and Senator Hatfield for introducing the refinancing legislation which we think will end one of 

the big uncertainties that hangs over the future of our rate questions, and that is this uncertainty about repayment reform, and we 

appreciate your efforts on that front. 

We agree we need to cut positions and we are already reducing 

our work force and our objective is to go to at least 600 to 800 positions within the next few years. To date, we have already gone 

down. We have reduced over 260 positions from our VSI, the Voluntary Separation Incentive Program, and we expect to make 

greater progress as the business plan picks up. We agree that one 

in three needed to be terminated. We proposed that to the Supply 

System and the board voted to do that earlier this spring. 

As you heard, I think from Mr. Counsil, Bonneville has initiated 

an effort to try to work with them directly to reduce their costs 3 

to 4 percent annually over the next years. This will begin to more 

closely align those costs with what we believe to be the appropriate 

industry levels. 

We are proceeding to implement the world's most costly fish and 

wildlife program and we think it is vital again to Bonneville's mission that we do so, and we get results for it. We have been consistent in the application of the fish program for the last 14 years, by 

the definition of the governors and the NW Power Planning Council 

that put it together. We have tried our best to respond to the region's program. We are now responding to the needs of the National Marine 

Fisheries Service in enhancement of river operations for fish. As 

you know, this is a major program, and for the money we are 

spending as ratepayers and Northwesterners, I think we can all 

agree we need a world-class fish and wildlife program. We simply 

have to deliver this, because people are demanding that the value 

we are putting on this show up in the way of environmental benefits. 

We agree that there needs to be a comprehensive analysis of economic costs and benefits to the Northwest region's aluminium in- dustry. Bonneville and public utilities agree that the contractual 

mechanism should be developed, as was described earlier, which 

will require customers to develop integrated resource plans. We believe strongly that the government corporation status, as 

you and I have discussed previously, has $25 to $35 million in ben-
205 

efits. It is a very focused piece of legislation that has been discussed in the region in the recent months and we have to have that 

presented by the administration in the near future. 

We agree that current rates for irrigators and aluminum companies must be reviewed to eliminate subsidies. We are addressing 

these issues in our business plan development and, in fact, are 

going further by reviewing all rates, including the residential exchange, the irrigation discount, the low-density discount and melded rates in an honest effort to assure that customers pay for the 

cost they place on the system. 

Finally, on the reinvention of the conservation program, if I could 

have the final graphic, I want to make a couple of important points 

that I think are valuable with respect to Bonneville's reinvention. 

Now, you have heard that we have gone through a fairly comprehensive effort, we have created a conservation subgroup, we 

have worked with environmental council members, and so on, to 

try to shape this program so that the objective stays the same, and 

this graphic simply gets to that objective. 

The objective before in the old plan was to achieve 660 

megawatts, within the period of time described on the chart. That 

was done in a program which we borrowed a lot of money and we 

directly financed it or applied it with a series of grants, essentially, 

to utilities. There are overheads associated with that. It is a centrally designed and controlled system, and that way it does kind 

of look like a system from an older era. 

We think that it can accomplish much, much better ends if we 

begin to decentralize that system, cut the overheads and allow conservation to become focused more on the unique needs of each customer utility, along with a tiered rate signal that we think is essential to its success. 

The important point I wanted to make on this, Mr. Chairman, 

is the borrowing cap question, and this is something that I know 

people have worried about, but I want to make sure it is front and 

center in the debate. We will continue to discuss the best way to 

deliver a decentralized conservation program and achieve the 660 

megawatts, because we plan to achieve them with or without the 

business plan suggestions. 

The borrowing cap issue relates to the 1.25 billion that was previously appropriated and authorized by Congress for Bonneville's 

conservation borrowings. If we do not change our program, we blow 

through the borrowing cap in approximately 1999. To me, as a 

Northwesterner, that means that the issue of how we do conservation, whether conservation is valued, becomes a Washington, D.C. 

issue, because we would have to come back to Congress and ask 

for additional borrowing authority on the basis of our achievements. 

Under our new proposal, and the way we have designed it, we 

think that we will maintain a 660-megawatt program and do so 

without going through the borrowing cap and without having to 

come to Washington D.C. for additional costs, and we think that 

adds tremendous value. 

So to sum up, Mr. Chairman, and then we can get right into 

questions, I just want to say this-in the final report, as I was 

reading on the plane coming back out here, you made a fundamen-
206 

tal point, and that was that in the final analysis, the Bonneville 

Power Administration's first responsibility is to serve the people of 

the Pacific Northwest. 

Now, we want to pledge to you and to those people something 

very straightforwardly. And that is, to those thousands of Northwesterners and the millions of people that are affected by Bonneville, we want to pledge a smaller, more efficient government, delivering greater value as we enter the twenty-first century, that is 

going to demand a great deal of all of us. We want to pledge to do 

everything we can within our powers and with your help to deliver 

fundamentally stable rates in our most important product lines, 

and the reason is because we want to stay ahead of changes in the 

industry so that we can deliver the fundamental values associated 

with our mission and what people have come to expect from Bonneville. 

Finally, we pledge to do everything in our power at the same 

time to deliver world-class results in a comprehensive conservation 

and fish and wildlife program. And finally, to get and enhance the 

promise and the vision of the Pacific Northwest Power Act which 

we continue to believe is correct in its vision and can be applied 

in an innovative way as the twenty-first century approaches. 

Thank you very much for your time. 

[Prepared statement of Mr. Robertson follows:] 
207 

STATEMENT OF 

JACKS. ROBERTSON 

DEPUTY ADMINISTRATOR 

BONNEVILLE POWER ADMINISTRATION 

U.S. DEPARTMENT OF ENERGY 

BEFORE THE 

COMMITTEE ON NATURAL RESOURCES 

SUBCOMMITTEE ON OVERSIGHT AND INVESTIGATIONS 

U.S. HOUSE OF REPRESENTATIVES 

AUGUST 9, 1994 
208 

Statement of John S. Robertson, Deputy Administrator 

Bonneville Power Administration 

August 9, 1994 

Chairman Miller, Congressman DeFazio, and Committee members, it is my pleasure to 

appear before the House Committee on Natural Resources. I am Jack Robertson, Deputy 

Administrator of ~he Bonneville Power Administration. 

Today, I am prepared to provide the Committee with updates on several critical issues 

involving the future of Bonneville. Our goal is to become an exemplary Federal agency. 

We seek to become the epitome of good government aimed at delivering more value for 

less cost. 

In my testimony, I will first discuss how the electric utility industry, particularly in the 

Northwest, is continuing to evolve into a more competitive marketplace. Next, I will 

address the draft Business Plan -- our roadmap for adjusting to this new competitive 

environment by managing financial risks and reducing agency costs, providing for more 

efficient and effective delivery of agency services (including conservation), and increasing 

focus on customer service. In closing, I will discuss the actions we are taking to 

implement the recommendations in the Majority Staff Report of the Bonneville Power 

Administration Task Force. 

Evolution of a Competitive Market 

The wave of deregulation that has swept the airline, natural gas, and telecommunication 

industries is now also fundamentally affecting the electric industry. 

Deregulation has arrived at the wholesale level of the electric power industry. A strong, 

independent power production industry has recently emerged providing every utility with a 
209 

ready alternative to traditional wholesale suppliers such as Bonneville. Since the last 

hearing of the Bonneville Task Force, there has been considerable evolution of the electric 

utility market in the western United States -- particularly in the Pacific Northwest. 

For Bonneville's customers, the average cost of power is currently lower than the 

marginal cost of alternatives such as buying gas-fired turbine genera!ing capacity 

themselves, or buying power from outside the Region. The difference, however, between 

Bonneville's price and that of alternative sources of electricity is now much smaller than it 

has been historically when nuclear power and coal were the principal alternatives to BP A 

power (see attached graph). The competition is within 15 to 20 percent of the BPA rate. 

Customers are now considering several factors other than price. The financial stability and 

predictability of Bonneville as a supplier is a key issue with our customers. Some 

Bonneville customers are considering or planning to pay premium prices for power 

elsewhere in order to avoid unpredictable cost increases. 

The prospect of competition for sales to Bonneville's customers appears increasingly real 

as time has passed. We believe that absent a significant change in direction, Bonneville's 

rates can become uncompetitive. While we understand that not everyone agrees with our 

assessment, it is clear that some of our customers are taking actions. For example, Clark 

County Public Utility District (Clark) has recently signed a letter of agreement to purchase 

the output of a 245 megawatt cogeneration unit. Clark is Bonneville's fifth largest 

customer and this purchase would displace half of this utility's load. If this resource is 

brought on-line, it will reduce Bonneville's revenues in the range of$10 to 20 million 

annually. 

Another Northwest utility, Snohomish County Public Utility District, issued a request for 

resource proposals and has received 88 responses totaling more than 8,000 megawatts. 

The National Energy Policy Act of 1992 opened access to transmission lines, bringing new 

players and new arrangements to the energy arena. A variety of resources are being 

offered, from new gas-fired resources in the Northwest to extraregional resources that 

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would rely on wheeling arrangements over Bonneville's system. This plethora of offers 

clearly has implications for Bonneville's ability to market its products both within and 

outside the Pacific Northwest. 

·In the Northwest alone, some 1,400 megawatts of new generation are in service or under 

construction and another 3,000 to 4,000 megawatts are being studied. The Federal 

Energy Regulatory Commission has approved more than 20 new power marketing firms to 

buy and sell power at market prices. Moreover, work is underway to establish a west 

coast electricity futures market. 

While our rates are still competitive, customers must consider the future financial and 

business risks of relying on Bonneville when deciding whether to continue to buy power 

from us or choose other sources. Unless we take action to increase the competitiveness of 

our rates, we could face a loss of 1,400 average megawatts from Bonneville's 9,000 

average megawatts load in the next few years. 

Financial markets are also changing the views of electric utilities -- particularly those such 

as Bonneville with high fixed costs, and/or operating at the wholesale level where the 

greatest competition is occurring. 

Several recent analyses by bond rating agencies and other financial institutions have 

reached similar conclusions about changes coming to the electric power industry. The 

message is that a utility's ability to survive will be based on favorably maintaining or 

achieving a competitive advantage in key risk areas. Three of the most common rating 

factors are cost structure and financial flexibility, relative cost of power, and customer 

alternatives. 

Utilities such as PacifiCorp, Idaho Power Company, Washington Water Power, and Puget 

Sound Power and Light are viewed by financial analysts as likely to emerge as strong 

competitors. Most of these companies have fixed cost ratios of between 50 and 60 

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211 

percent; average generation costs below the Western States Coordinating Council 

average; and generally low industrial load exposure. In comparison, Bonneville's fixed 

cost ratio is 80 to 85 percent. The fixed cost ratio is due primarily to a heavy debt load 

from our nuclear investment in the 70's and 80's, including two non-working plants, and a 

historical reliance on 100 percent debt financing for other BP A capital investments. 

Bonneville's higher fixed costs reduce our flexibility to respond to price competition and 

still assure cost recovery. This situation would be further aggravated by any major loss of 

existing loads. It is unlikely that the power from large quantities oflost loads could be 

resold at similar or higher prices. 

We are at risk in a number of areas. These risks spring not only from our agency's high 

proportion of fixed costs, but also from significant environmental cost exposure; pricesensitive direct service industrial customers; potential regulatory burdens and delays; and 

the vulnerability of certain small customers to merger or takeover. Because of these risks, 

Bonneville could be viewed as an unstable power supplier, business partner, or credit risk. 

In August 1993, Standard & Poor's noted three factors critical to Bonneville's financial 

flexibility: rate-raising capability; reserves; and cost control. They concluded that the use 

of further Bonneville rate increases should be increasingly discounted as a viable 

alternative. This would leave the maintenance of adequate reserves and cost control as the 

two elements over which Bonneville can exercise primary influence to maintain its 

competitiveness. 

While the industry is being significantly transformed by these and other trends, Bonneville 

is uniquely situated to carefully consider and respond to these changes. Bonneville has a 

renowned hydro-based power system that enables considerable operating flexibility at low 

cost, plus a strong transmission system which provides access to diverse markets and may 

be used to create new, competitive markets. The challenge that confronts Bonneville is 

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212 

how to balance and preserve these strengths for the benefit of customers and other 

stakeholders given the strong forces of change. 

Business Plan 

Like a commercial business, Bonneville succeeds only if its customers buy its products. 

Until recently, our agency faced no real competition. Our prices were so low compared to 

other sources, that most customers saw no reasonable alternative. Today, for the first 

time ever, our rates are not dramatically lower than those of other power suppliers. And, 

at the same time, our costs -- particularly those for fish and wildlife --have been increasing 

dramatically. 

In 1993, ouranalyses revealed that we were planning to spend $300 million to $600 

million more each year than we would likely receive in revenues if our rates were left 

unchanged. We are proposing to close this gap by exerting strict cost management and 

becoming market driven -- that is, broadening our revenue base by redesigning products 

and services to retain and build our customer base. The Business Plan is the pivotal 

element of the Competitiveness Project launched in February 1993. The plan will help 

steer Bonneville through the competitive challenges it faces to achieve its fundamental 

legislative mandates. 

Bonneville believes implementation of the Business Plan is necessary for two key reasons. 

First, we believe that business as usual is likely to lead to a path of significant rate 

increases over the next decade. As our revenue base shrinks, we risk being unable to 

fulfill our legislative mandates. The Business Plan is our attempt to minimize or eliminate 

those projected rate increases. 

Moreover, we believe that the type of fundamental change the electric utility industry is 

experiencing as a result of increasing competition compels a new approach to our business 

in addition to addressing the financial dimension of the business. We are trying to get in 

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213 

front of these problems. We share the view of the Majority Staff Task Force Report that 

the goals of the Northwest Power Act are sound. We are seeking means to assure the 

objectives ofBPA's existing authorities will continue to be carried out. 

Marketing 'Strategy 

Our draft Business Plan proposes new approaches to Bonneville's major programs 

including conseJVation, fish and wildlife, resource acquisition, and financial management. 

It includes new marketing strategies designed to give utility and industrial customers more 

choices, and highlights three business lines -- power, transmission, and energy services. 

Bonneville's new marketing strategy has two key goals. The first is to stabilize its current 

business and revenue base. This goal will be secured through reducing or holding costs 

constant and by tiering rates - providing a stable rate signal to existing loads while 

allocating costs of serving new loads with competitively based price signals. The second 

goal is to unbundle Bonneville's products and servires so as to provide customers a choice 

of tailored and flexible products to meet their individual needs. To accomplish this, we are 

"unbundling" or separately pricing individual power products while also offering fullservice packages. We are also focusing on the distinct needs of customers through market 

segmentation, and have placed account executives in the field to work one-on-one 

identifying needs, negotiating contracts, and solving problems. Constituent account 

executives have also been established to maintain our critical links with Northwest Tribes, 

interest groups, and state and local governments. 

The draft Business Plan envisions the new Bonneville as three linked businesses -- power, 

transmission, and energy services including conseJVation. Each of the business lines will 

be self supporting and together they will provide the full range of Bonneville products and 

services. Customers and constituents alike assisted us in addressing issues relevant to 

development of these business lines. 

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The power business line holds a key element of the Business Plan-- a two-tier rate 

proposal which will reflect the costs of existing and new resources. Most of Bonneville's 

customers' existing electricity needs would be served at the lower tier I rate. Tier I is 

designed to reflect costs of existing resources, including fish and wildlife. We expect that 

about 90 percent of firm loads now served by Bonneville would be at this level. 

Tier 2, set at a higher rate, is designed to reflect the costs of new generating resources. 

Bonneville expects that these rates would serve about I 0 percent of utilities' existing firm 

loads and any future load growth they choose Bonneville to serve. Tier 2 would compete 

directly with other power suppliers in the market. I would add that tiered rates give 

utilities a strong incentive to run their own conservation programs to avoid the higher tier 

2 rate. 

The transmission business line provides wheeling services and transmission for all power. 

Our goal is to remain the bulk power transmitter or "wheeler" of choice for Northwest and 

interregional power flows by providing fair and open access to our grid consistent with the 

requirements of Section 722 of the I992 Energy Policy Act. Opening access will foster 

competitive power markets and help Bonneville sell its tier 2 and unbundled power 

products in those markets. 

Bonneville's first priority will be to provide reliable transmission for its existing firm 

power and transmission obligations. If there are competing requests for new services over 

limited space, priority will go to Northwest loads in a manner that comports with all 

applicable laws. Transmission services will be provided at the lowest rates that recover 

total transmission costs, without placing undue burdens on existing customers. 

Demand-side management is the first in what we expect will become a broad-based set of 

services offered under the energy services business line. Others will be added as customer 

needs become more clear. The demand-side management product line is part of 

Bonneville's new approach to conservation. It will include the agency's existing 

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215 

conservation programs and portions of those programs, plus new services for peak-load 

management, as is now practiced in some other parts of the country. Demand side 

management products and services will be competitively priced with tier 2 service and 

unbundled products. 

Direct Service Industry Loads 

About one-fourth of Bonneville's sales are to aluminum smelters and other large, directservice industrial customers. Bonneville is proposing to tier rates to the direct service 

industries (DSis) in a manner consistent with tiering to publicly owned utilities. 

As with rates for the publicly owned utilities, DSI rates would be tiered to send an 

appropriate price signal to promote more efficient resource acquisitions and conservation. 

Even ifDSI loads do not grow, any portion of their load facing higher cost tier 2 service 

would have added incentive for more efficient power usage. 

Our approach to tiering rates for the DSis follows the approach for publicly owned 

utilities. But since the DSis do not receive firm service for their entire load, arpercentage 

of the DSis' historical purchases would be used to determine a billing amount for any 

power sold at the tier 1 price. Each DSI can purchase any additional amount of service at 

the tier 2 price up to its contract demand amount. 

Regarding follow-on contracts with the DSis, Bonneville is contractually obligated upon 

request to attempt to acquire sufficient resources to serve the requests and to negotiate a 

power sales contract in good faith if sufficient resources are found. If those resources are 

not available, however, Bonneville is not obligated to offer new contracts. 

In terms of resources available to serve the DSls generally, Bonneville supports the 

development of integrated resource plans by the DSis to assure that through proper 

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216 

resource development, including cost-effective conservation, there will be sources of 

supply available to the DSis. 

Reducing Costs & Managing Financial Risks 

As is true with any business, reducing costs and managing financial risk is key to 

remaining competitive. However, market forces are leaving very little room for 

Bonneville to cover its costs or otherwise increase revenues by increasing rates. 

When Bonneville set its current rates, total costs were projected to run $2.8 billion in 

1996, increasing to $3.3 billion by 2002. Since that time, certain costs have risen, such as 

power purchases due to drought, and mitigation costs for fishery impacts. 

We are proposing to cut other costs by an average of$279 million per year by 2002. The 

magnitude and direction of these reductions were determined by· the Marketing Plan along 

with other aspects of Bonneville's competitiveness project, including the Function by 

Function Review. These cost reductions are based or. two separate efforts. The first are 

general productivity improvements across all Bonneville activities. These reductions can 

be characterized as "doing what we currently do more efficiently". 

The second area of reductions is in program reinvention, or fundamentally changing what 

we do. Reinvention efforts impact all Bonneville activities, with particular emphasis on 

Conservation, Fish & Wildlife, Sales and Customer Services, and Transmission Services. 

As a result of these reductions, our cost projections under the Draft Business Plan remain 

at $2.8 billion for 1996, and will stay flat at $2.8 billion per year through 2002. 

Capital Sources 

A recent report issued by the General Accounting Office criticized Bonneville's policy of 

borrowing for substantially all its capital programs, stating the agency leaves little 

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217 

flexibility for meeting future challenges. The GAO point~d out that "BonneviUe is more 

heavily leveraged than other utilities" and that "over 50 percent ofBPA's revenues went 

toward debt-servicing costs in 1993." 

Bonneville borrows from two lines of credit with the U.S. Treasury, a $1.25-billion line 

for conservation and renewable resource acquisitions, and a $2.5-billion line for 

transmission, fish and wildlife, and other costs. Prior to the Business Plan, Bonneville 

projected that the second credit line would be obligated as early as 1997, and the first by 

1999. 

For the conservation borrowing authority cap, we believe there is a solution to the 

problem of approaching the cap. We are proposing new approaches to financing 

conservation such as tiered rates and user -financed conservation energy service charges or 

other products aUowing us to continue to support conservation within the current 

borrowing cap for the foreseeable future. Capital borrowed by Bonneville to invest in 

market transformation and related efforts will still be repaid through Bonneville power 

rates. 

For the transmission and fish and wildlife borrowing authority cap, the draft Business Plan 

proposes to limit capital investments to those which best meet consistent Bonneville-wide 

criteria. This is expected to help us reduce capital spending. We also propose to pay for 

$30 million a year of new capital investments through current revenues. We are also 

assessing other potential sources of capital such as third-party financing . Using these 

techniques, we believe we can avoid exhausting the transmission and fish and wildlife fund 

until 200 I, but this is not a permanent solution. 

Managing Financial Risks 

A significant issue in the draft Business Plan is managing the agency's financial risks. 

Bonneville completed a 10-year Financial Plan in early 1993 that called for a 95 percent 

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218 

probability of meeting all of our annual debt payments to the U.S. Treasury in full and on 

time. To achieve this repayment goal, Bonneville targeted reserves of$535 million 

maintained over a I 0-year period and an interim rate adjustment of up to I 0 percent as a 

risk mitigation feature in Bonneville rates. 

Since then, BPA's financial risks have increased substantially. Much more water is now 

stored and released for fish flow requirements. Persistent drought has increased 

Bonneville purchase power costs and significantly decreased power sales revenues. 

Bonneville proposes to achieve the targeted reserves of$535 million assumed in the draft 

Business Plan but because of these increased risks this level of reserves yields only an 85 

to 90 percent certainty of making payments to the Treasury in full each year. 

Reinventing Conservation Programs 

Bonneville believes its conservation program is the flagship for the electric utility industry. 

The largest energy conservation effort in the world lies in the Northwest. With nearly l 5 

years of successful programs and investments exceeding $I billion, Bonneville has worked 

with the region to set up an infrastructure which has transformed public perceptions about 

energy use, and has led to the most energy-efficient building codes in the nation. 

In building the region's infrastructure, our agency provided sizable cash incentives to utilities, 

industries, state and local governments, and Northwest consumers. That, however, was the 

1980s. With the infrastructure in place, what is needed now is a new approach to 

conservation -- an approach that will work in the more competitive 1990s marketplace. 

The new approach for the 1990s will not scrap the I980s approach. We intend to keep what 

has worked best and build upon it. Under our new approach, conservation will remain 

unequivocally our resource of choice. We remain committed to achieving the megawatt 

targets set by the Northwest Power Planning Council, and have no plans to acquire new 

II 
219 

generation beyond our existing commitments. Our goals are not changing. What is changing 

is how we achieve these goals. We are working with our customers and enviro.nmental 

groups to develop principles to guide our efforts, and are proposing a four-part approach in 

redesigning the conservation program. 

The first involves tiered rates. With tiered rates, utilities will pay a lower rate for the bulk of 

their electricity load served with existing resources. Should they increase their loads on 

Bonneville, requiring our purchase of additional resources, they would pay a higher rate than 

for existing load service. The rationale is that new resources are much more expensive and 

the cost of these resources is not reflected when all new resource costs are averaged into a 

single rate. With tiered rates, utilities will have an incentive to run conservation programs 

thereby avoiding the high cost of increased consumption served at the higher rate. 

Second are new Bonneville products and services. Rather than simply implementing 

Bonneville financed conservation programs, utilities can purchase our new products and 

services and tailor their own programs. This approach will simplifY Bonneville programs and 

reduce overhead costs. Currently, a large portion of Bonneville's conservation investment 

does not go for the measures that save, but rather to administering programs that utilities 

could tailor and better run themselves. 

Third, we are working with our customers, the Northwest Power Planning Council, and 

others to develop a system of decentralized Integrated Resource Plans (IRPs) that would 

ensure achievement of conservation targets. This approach to IRPs would include common 

criteria, independent tracking, and performance accountability. One key aspect to the success 

of such a decentralized IRP system is balancing customer choice against the Bonneville 

Administrator's ultimate accountability under the Northwest Power Act. 

Fourth, Bonneville can help in transforming markets. Individual utilities cannot independently 

change government and manufacturers' policies and practices. Bonneville is making a strong 

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commitment to continue to take the lead on promoting appliance efficiency standards, 

technology improvements, and adoption of national and state efficiency codes. 

To summarize, we intend to keep what's best from the 1980s approach and build on it to meet 

the needs of the 1990s. Conservation remains our resource of choice. We believe our 

approach provides safeguards by building in a transition period and allowing flexibility to 

make mid-course corrections to ensure that the conservation targets set by the Council are 

met. Utility customers and environmental groups will continue to play a key role in how the 

new program evolves. 

Business Plan Schedule 

In light of these ongoing radical changes in the utility marketplace, we are continuing to 

refine Bonneville's Business Plan. We want to assure the Committee that we are 

developing the Business Plan with significant input from interested regional entities. A 

Sounding Board comprised of Bonneville customers and other regional stakeholders was 

formed early in the Business Plan process to provide on-going advice and counsel. 

Regional participation has been a critical element to development of the Business Plan. 

A year and a halt:.ago, we initiated Bonneville's reorganization under the umbrella of the 

Competitiveness Project. We set our course with Strategic Business Objectives. A 

Function-by-Function Review sought out opportunities for accomplishing work more 

efficiently. The Marketing Plan identified customer needs and studied choices about how 

to meet those needs. Through Leadership EDGE (Empowerment, Diversity, Growth and 

Excellence) we are striving to develop excellence in managers, promote teamwork across 

the organization, and reinforce a strong customer and constituent orientation. All of this 

has been accomplished with significant and valuable public input. 

A draft Business Plan was released in June. We are taking public comment through 

September 9th and plan to complete the Business Plan in November. We have lengthened 

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221 

the comment period by three weeks in response to customer and constituent requests. 

This is an ambitious and demanding schedule, but it is necessary in order to reach 

conclusions which can be included in the President's budget submittal for fiscal year 1996 

and the 1995 rate case for fiscal years 1996 and 1997. 

We are listening and are being sensitive to regional parties. During the comment period 

we are meeting informally with customers, customer groups, government officials, public 

interest groups, and others on request. Over the past week, we have conducted three 

formal information and comment meetings, and have scheduled a wrap-up session towards 

the end of the comment period. 

There is significant regional interest in our draft Business Plan. We have received 

supportive comments, but we have also heard concerns expressed about the scope and 

pace of the changes we are proposing. We acknowledge that our proposals represent a 

significant change in long-standing relationships. 

But the changes in the utility industry continue to occur at an increasingly rapid pace. 

BoMeville is anticipating these changes and staying in front of them-- but barely in front. 

Absent significant actions now, we and our customers will face even greater disruptions 

later. By moving ahead aggressively to implement the Business Plan in the 1995 rate case 

and power sales contract renegotiations, we hope to avoid substantial rate increases and 

minimize the period of uncertainty. 

If we are unable to begin introducing tiered rates and unbundled products in fiscal year 

1996, we and our customers will face continued uncertainty. If we m~ntain the status 

quo, we would expect to need to increase our rates in fiscal year 1996 by 10 to 15 

percent. The competitiveness of our rates is directly related to our ability to recover costs, 

and therefore to our ability to repay Treasury on time and in full in the future. 

14 

84-374 0 - 94 - 8 
222 

We will continue to engage the region in these discussions, and we remain open to 

revising our Business Plan and implementation schedule. However, I want to stress the 

potential consequences of delay -- extended disruption and uncertainty throughout the 

Northwest utility community. 

If utility markets unfold as we project, and Bonneville is unable to make the adjustments 

necessary to compete successfully, these issues may require Congressional action to 

resolve. We believe we are on the right track, and if we can maintain our current 

momentum, we expect to stay ahead of our competitors and secure our position in the 

evolving west coast energy market. 

Implementation of Majority Staff Recommendations 

As indicated in the Majority Staff Report, Bonneville is at a crossroads. We recognize the 

issues the report raises and believe the Task Force produced numerous useful outcomes. 

The Northwest economy needs a healthy Bonneville and this report helps by focusing 

attention on our situation. No one disagrees that we need to change. 

As a result of the competitiveness efforts we initiated over a year ago and the 

recommendations contained in the Task Force Report, we are making great strides in 

adjusting to this more competitive industry. I would take this opportunity to discuss some 

of the specific actions we have taken. 

I will reiterate the first of the report's findings -- the goals of the Northwest Power Act 

reinain sound. Bonneville remains fully committed to the Northwest Power Act --

particularly with respect to energy conservation and fish and wildlife. Our agency needs 

to become more competitive, but we will not do so· at the risk of sacrificing the region's 

commitment to conservation and renewables and rebuilding salmon runs. 

IS 
223 

Consistent with the recommendations in the Task Force Report, a debt refinancing bill has 

been intr.oduced which can resolve the repayment reform debate and not lead to any 

significant increases in Bonneville's rates. 

Contrary to our earlier view, Bonneville agrees with the Task Force that a tiered 

wholesale electric rate should be only one element of the agency's conservation 

acquisition strategy. Consistent with requests from conservation interest groups, we are 

now proposing to retain regionally subsidized conservation through market transformation 

activities. We have also agreed to maintain our energy conservation programs, but will 

finance them through an energy service charge rather than through power rates. 

We are pleased to report that in response to Bonneville's urging, the Washington Public 

Power Supply System's Full Board of Directors voted to terminate Washington Nuclear 

Projects I and 3 on May 13, 1994. The Supply System has begun the termination process 

by advertising the sale of the projects and starting the planning process for termination in 

the event that no buyers of the projects as a whole are found. 

With regards to Washington Nuclear Project No. 2, Bonneville and the Supply Systeni 

have agreed to have substantive discussions this fall on the setting of specific cost and 

performance goals. We have requested that the Supply System reduce their budgets by 

approximately 3 to 4 percent annually for the next few years until their costs are more 

closely aligned with what we believe to be industry levels. 

Bonneville is proceeding with implementation of both the Regional Council's Strategy for 

Salmon and the National Marine Fisheries Service recommendations for avoiding jeopardy 

to the continued existence of listed salmon stocks. We absolutely agree that Bonneville 

must remain committed to the conservation and fish and wildlife goals of the Northwest 

Power Planning Council. The draft Business Plan focuses our programs on results and 

providing greater certainty, not on dollars spent. 

16 
224 

Bonneville agrees there needs to be a comprehensive analysis of the economic costs and 

benefits to the Northwest of the region's aluminum industry. We are, in fact, attempting 

to conduct cost of service analysis for all customer groups to gain a better "understanding 

of where costs are incurred on our system. 

Bonneville and its public utility customers agree that contractual mechanisms should be 

developed which will require customers to develop integrated resource plans. We are 

committed to developing this mechanism collaboratively with our customers. 

Bonneville has proceeded cautiously with the government corporation proposal. We are 

addressing the "side effect" concerns with interested parties, and will continue to seek 

regional consensus before proceeding with legislation. 

With respect to the proposed cost savings identified in the Task Force Report, there was 

approximately $150 million in savings identified. Of this amount, over $90 million is 

associated with costs which BP A does not directly control, that of the Supply System and 

the Bureau of Reclamation Power Rate. 

Of the remaining amount the vast majority is in the category of reviewing current. rates for 

irrigators and aluminum companies to attempt to eliminate subsidies. We are addressing 

these issues in our Business Plan development and in fact are going further by reviewing 

all rates including the residential exchange, the low-density discount and melded rates to 

attempt to assure that customers pay for the costs they place on the system. 

The Business Plan proposes real change in the way Bonneville conducts business with its 

customers. At the July Task Force hearing in Portland, much discussion was focused on 

the "hassle factor" associated with doing business with.Bonneville. It was a fiustration 

expressed by our customers and stakeholders alike. That's exactly why we are 

streamlining our functions and moving to become more customer-focused and results17 
225 

oriented in all of our business dealings. To our customers and stakeholders we are saying, 

"We hear you." 

We have completely reorganized the agency aimed at improving customer and constituent 

service. Customer and constituent account executive positions have been created and it 

has been made clear to all employees that everyone in the organization works to support 

the account executives. Granted, these types of changes do not occur overnight and do 

not occur without some pain. We believe, however, and the Portland hearing made this 

eminently clear, that this type of fundamental change is necessary. 

The Portland hearing was also especially important to us in terms of initiating internal 

actions. We are well on our way to reducing our total workforce by 600 to 800 positions. 

To date, we have reduced our Bonneville personnel by more than 260 positions. 

Conclusion 

This testimony is one in a series of progress reports. Much remains to be done and a 

number of opportunities remain for involvement of our customers and constituents. 

By becoming more market-driven, customer-focused, cost-conscious, and results-oriented, 

BonneviUe can expand the benefits it has provided the region for the last 57 years, without 

fundamentally changing the agency's mission. 

I reiterate that goals of the Northwest Power Act remain sound. Bonneville needs to be 

more competitive; however, we will not do so at the risk of sacrificing the region's 

commitinel)t to conservation and rebuilding salmon runs. 

In closing, I will reiterate that Bonneville's competitiveness is critical on a number of 

fronts -- both regional and national. 

18 
226 

Our competitiveness is critical to the Pacific Northwest regional economy because we 

provide nearly half of the electric power and three-fourths of the high-voltage transmission 

in a very electricity-dependent region. Nearly 3 million people and over 1.2 million jobs in 

the region depend on Bonneville power. 

Our competitiveness is critical to our customers because the competitiveness and survival 

of many of the ISO utilities and large industrial customers our agency serves in the region 

is closely linked to Bonneville's rate levels. Likewise, businesses and industries served by 

these utilities depend on an economic power supply. 

Bonneville's competitiveness is critical to the environment because we contribute over 

$300 million per year, including obligations and foregone revenues, to fish and wildlife, in 

addition to tens of millions for clear air, clean water, and hazardous waste cleanup. 

Further, Bonneville's competitiveness is important to U.S. taxpayers for operations and 

maintenance, principal and interest annual payments of approximately $700 million wemake to the U.S. Treasury. 

In our invitation to testifY, the Task Force requested that we respond in more detail to 

some specific points. You will find our responses attached to this testimony. 

We welcome this opportunity to share our progress in creating a new Bonneville and look 

forward to your input, and to sharing future progress reports. 

I would be pleased to respond to any questions you may have. 

19 
A JIO/OEO COST OF 6EN

JIS. BPA AJIERA6E R

100 _NUCLEAR COAL 

80 

M' 

., 

~ 6o T i 40 

I ~ 

·e 20 

0 

80 81 82 83 84 85 86 87 88 89 90 

Year 

-+-Avoided Cost of Generation -

NUCLEAR: based on actual cost of Washington Pub

COAL: based on studies by Kaiser Engineers Power Cor

GAS: based on studies by Fluor Daniel Inc., a
228 

Bonneville Power Administration's (Bonneville) Responses to 

Pre-Hearing Questions 

Representative Peter DeFazio 

August 9, 1994 

QUESTIONS FROM REPRESENTATIVE DEFAZIO 

Question 1: Please discuss BPA's competitive position at present and over the next ten 

years. What are the competitive threats? What are BP A's competitive 

advantages? 

Answer: BPA faces many serious competitive challenges over the next 10 years, but 

the real competitive test will be over the next few years, when our 

customers will be making long-term choices about their business 

relationship with BPA. At present, BPA's average cost of power remains 

below the marginal cost of the competition ( 2. 7 cents per kilowatt hour 

compared to 3.2 cents per kilowatt hour.) But BPA's price advantage has 

dropped from over 400 percent 10 years ago to roughly 15 to 20 percent 

now, and BPA's customers are wondering how much further that trend will 

go. 

To succeed, we will have to deal successfully with a number of competitive 

challenges, including: (1) a steep decline in the cost of alternative power 

sources; (2) increases in our costs and uncertainty about how high some 

costs will ultimately go; (3) many capable and aggressive alternative 

suppliers knocking on our customers' doors; (4) deregulation of the 

wholesale power business which has virtually eliminated the market power 

BP A used to have; aitd ( 5) dissatisfied customers who would currently 
229 

prefer to do business with other suppliers. BP A's high proportion of fixed 

costs and seriously depleted financial reserves add to the difficulty of 

responding to these challenges. 

The Draft Business Plan details the challenges listed above. Since the draft 

was published, some additional developments have reinforced the 

seriousness of the situation we face: 

• More detail on the offers made to Snohomish Public Utility District have 

surfaced. Snohomish has several offers of firm power delivered to its 

system with prices starting in 1997 of 27 to 32 mills per kilowatt-hours. 

Many suppliers are offering guaranteed prices. 

• 26 of our customers have signed an agreement with Power Resources 

Managers (PRM) for a 600 to 800 MW package of alternative resources to 

be managed, by PRM. A final decision on going forward with this resource 

package is expected next year. 

• Washington Water Power Company and Sierra Pacific have announced a 

planned merger that would create another very strong competitor for BP A. 

• In terms of plant efficiencies only, new advancements in combustion 

turbine technology have been announced that promise to move single-cycle 

efficiencies from the current 40 percent to 48 percent and combined-cycle 

2 
230 

efficiencies from the current 48 percent to nearly 60 percent of the total 

BTUs available from the fuel. In addition, these new turbines will offer 

smaller unit sizes, greater operating flexibility, and lower emissions at no 

increase in cost. 

BPA's substantial competitive strengths include the large hydro system 

which has essentially zero fuel costs and zero air emissions, more 

operational flexibility than most utilities, ownership of 80 percent of the 

regional transmission grid, and a highly skiUed workforce. Our challenge is 

to continue to leverage these strengths to overcome the challenges we are 

now confronting. That is what we are attempting to do in the Business 

Plan. 
231 

Question 2: How likely is it that BPA's rates will be uncompetitive when compared to 

alternative generation sources in the 2002-2003 rate period under each of 

the alternatives presented in the Business Plan DEIS? What analysis has 

BP A done to support its views? 

Answer: The analysis conducted for the Marketing Plan indicated that the mostlikely scenario was that our rates should stay below those of competing 

power sources to year 2003 and beyond, if we succeed in our efforts to 

control costs, offer more choice of products and services, and improve our 

customer service as proposed in the Draft Business Plan (and in the 

Market-Driven alternative in the Business Plan DEIS). 

It is becoming increasingly clear that customer perception ofBPA as a 

supplier vs. competitors is the key to our competitiveness. Many 

customers will not wait until 2003 to find out ifBPA offers the best deal. 

They are acting now based on their current assessment ofBPA vs. the 

competition. Even though long-term analysis of our rates may show that 

we are likely to be the lowest -cost supplier, we still can suffer major load 

loss if our customers see other suppliers as offering less risk, better service, 

and/or more stability; particularly when the long-term analysis shows only a 

relatively small cost advantage for BP A. 

A key question about the Business Plan Draft Environment Impact 

Statement (DEIS) alternatives is the amount of risk they create for BPA's 

competitiveness. While we have not quantified this risk probabilistically, 

4 
232 

the analysis we have done suggests that the Status Quo ai.Iternative would 

create more risk of noncompetitiveness because it would entail higher 

costs, less focus on customer service, and less customer choice about 

products and services. The BPA Influence alternative would provide many 

of the features of the Market-Driven alternative, but due to somewhat 

higher costs and conditions on BP A services, it poses a greater risk that 

BPA's rates and market position would not be as competitive. The 

Minimal BP A alternative could make our rates more competitive because it 

would entail drastic cost cuts at the expense of fulfilling parts of our 

mission. The Maximum Financial Returns alternative would be designed to 

maintain competitive rates, but would tend to exploit SPA's lower-cost 

services to increase net revenues. The Short-Term Marketing alternative 

might provide competitive rates, but at the cost of greater uncertainty of 

BP A loads and future rates. 

The rate analysis in the DEIS shows relatively small differences in rates 

among the alternatives. However, that rate analysis did not include lill the 

factors that would affect the rate differentials, because the focus of the 

DEIS was more on physical environmental impacts than on rates. For 

example, the DEIS rates analysis for the Status Quo alternative did not 

account for the impacts on rates of the load loss caused by the alternatives. 

Nor did it fuUy account for all the additional revenues likely to be achieved 
233 

under the Market-Driven alternative. If these factors had been included in 

the analysis, the rate differentials would have been substantially larger. The 

final EIS will address these additional factors. 

6 
234 

Question 3: BPA' s Business Plan asserts that BPA will lose at least 1400 aMW ofload 

if the actions proposed in the plan are not implemented. However, the 

analysis contained in the Business Plan DEIS concludes that under the 

status quo only 599 aMW of firm load will be lost. How do you reconcile 

these figures? How likely is it that the BPA Business Plan's "death spiral" 

scenario, in which BPA loses more than 7000 aMW out of its present load, 

will actually take place? 

Answer The differences in load low projections between the Business Plan and 

the Draft EIS are summarized in the accompanying table. The load 

losses expected under the DEIS Status Quo alternative included 213 

average megawatts (aMW) ofnonfirm DSI load losses in addition to 

251 aMW of utility load losses and 348 aMW. of firm DSI load losses, 

for a total loss in the DEIS of 812 aMW. The 1400 aMW load losses 

described in the Business Plan include 450 aMW of retail wheeling and 

self-generation. The Draft Environmental Impact Statement (DEIS) 

did not assume retail wheeling, because that would require regulatory 

changes that the EIS team did not include in the "no-action" 

alternative. (The final EIS wiU probably incorporate retail wheeling as 

a factor in load loss for the Status Quo alternative.) The other 

differences between the DEIS and the Draft Business Plan are a 

difference of39 aMW in the total amount of direct service industry 

(DSI) load loss and about a 99 aMW difference in utility load loss due 

to somewhat more conservative assumptions in the DEIS about 

independent utility development of energy resources. These 

differences stem from the fact that load loss assumptions for the DEIS 

7 
235 

had to be established early to allow time for the more comprehensive 

assessment of resource development, operations, and physical impacts. 

These amounts are shown in the accompanying table: 

Comparison of Business Plan and EIS Load Losses (aMW) 

Type of Load Loss Business Plan "Business EIS Status Quo 

As Usual" Case, by 2002 Alternative Load Changes 

in 2003 

Public Agency Non-BPA 350 231 

Generation 

Shift ofBPA Load not listed separately 20 

Obligation to Public 

Agencies (Independent 

Conservation Programs) 

DSI Non-BPA Generation 600 348 (firm load) 

Subtotal: BPA Firm Load 950 599 

Loss 

DSI Non-BPA Generation not listed separately 213 

for Nonfirm Load (Top 

Quartile) 

Retail Wheeling 450 none assumed 

Total 1400 812 

It is unlikely that BP A would lose 7000 aMW of its present load. The 

"Extreme Potential" Market loss figures are merely intended to illustrate 

the extreme upper bound of market loss potential, given possible conditions 

conducive to market loss in the industrial sector and the generating 

capacity currently being studied by developers in the region. Though this 

scenario is unlikely, it is no longer totally implausible. Its plausibility 

reinforces the significance of the challenge BP A faces. 

8 
236 

Question 4: The Task Force report discussed what it called the BP A "hassle factor." 

Described the actions you are taking to reduce the difficulties customers 

experience in their dealings with the agency. 

Answer: BP A has set achieving customer satisfaction as its first Strategic Business 

Objective. Our early steps to reach that objective are as follows: 

First, the reorganization now underway at BP A created a Sales and 

Customer Service Group. This group replaces the old Area Office 

structure with account executives charged specifically with improving our 

business transactions with the customer utilities and direct service 

industries. Each account executive is assigned several utilities and/or direct 

service industrial customers with which to deal in a much closer 

relationship than has hitherto been the case. The primary goal of each 

account executive is to improve the agency's response to customer needs. 

Specifically, there are five basic business transactions with BPA that are the 

core ofbusiness between BPA and its customers. They include: (I) power 

contracts, (2) transmission and transfer contracts and agreements, (3) · 

demand side management (conservation) agreements, (4) new and modified 

points of delivery, and (5) operations and maintenance agreements. 

9 
237 

In each of these areas, the account executives will have the ability to create 

agreements with the customers, based on each customer's individual need, 

for the services available from BP A. This mechanism should reduce the 

majority of difficulties customers have with the agency in their day-to-day 

dealings. The account executives should have direct knowledge of each 

customer's particular circumstances. Finally, the customers should have no 

difficulty finding answers to their questions, and should have no question 

about the agency's concern for each customer's business health. 

We are also revising rather dramatically the systems and processes backing 

up delivery of products and services to the customers through the account 

executives. In contrast to former practices that forced the customer to deal 

extensively with BPA' s internal processes to meet a need, we will make 

those systems and processes support the account executives' direct dealing 

with the customers. This should reduce most of the remaining difficulties 

the customers experience in dealing with BP A. 

We believe our conservation program should remain the flagship for the 

electric utility industty. Our new approach for the 1990's will build on 

successes of the 1980's approach. We intend to keep what has worked 

best and build upon it. Under our new approach, conservation will remain 

our resource of choice. We remain committed to achieving the megawatt 

10 
238 

targets set by the Northwest Power Planning Council, and have no plans to 

acquire new generation resources beyond our existing commitments. Our 

goals are not changing. What is changing is how we achieve these goals. 

We are working with our customers and environmental groups to develop 

principles to guide our efforts. 

We also intend to track, in a much more businesslike way, our progress 

toward making our customers' business with the agency easier, and adjust 

as necessary toward that end. 

We do not intend, however, to equate reducing the "hassle factor" with 

always being able to give each customer exactly what he or she wants. We 

do intend to ensure that our business transactions are quicker, smoother, 

and more satisfactory to the customer. We also intend to ensure that each 

business arrangement with a customer meets as closely as possible both the 

customer's need and BPA's statutory obligations. 

11 
239 

Question S: BPA estimates unspecified administrative savings of$! 00 million per year 

for the market driven alternative, but not for any other alternatives. Please 

describe the savings you anticipate. Would new legislative authority be 

required to achieve these savings? If not, why could they not be obtained 

under any of the other alternatives? 

' Answer: The $100 million administrative cost savings were not included in the 

Status Quo alternative because this alternative was intended to represent 

conditions without the changes proposed in the Draft Business Plan. The 

Environmental Impact Statement (EIS) estimates were rough and some of 

the savings probably should have been shown and would have been 

achievable under the other alternatives. This modification will be made in 

the final Business Plan. We expect to achieve these savings through 

reductions in staffing, increased productivity, procurement efficiencies, 

better use of equipment and management of property, as well as increased 

performance from our contractors. While much of these savings can be 

captured administratively in the short run, Bonneville believes permanent 

administrative savings cannot be assured unless BP A obtains appropriate 

legislation. We will need legislative authority to achieve all of these 

savings in a timely manner and maintain them over time. 

12 
240 

Question 6: Actions proposed in SPA's Business Plan, such as tiered rates, unbundled 

services and conservation reinvention, taken together are likely to shift 

costs between customer categories. For example, all customers now bear 

part of the costs of regional conservation investment, but many will see 

those costs decline under the actions proposed in the Business Plan. 

Others will likely see their ove~;all costs increase. What cost shifts does 

BPA anticipate as a result of the proposed actions in the Business Plan 

DEIS? Can BPA quantifY those changes for different customer groups? 

Answer: BPA customers as a whole would be substantially benefited by the cost 

reductions and other changes proposed in the Draft Business Plan. As 

BP A customers now have many choices about how they meet their needs, 

how they are affected will depend largely on their own choices. This 

makes it very difficult to predict how any customer or even class of 

customers will be affected by the changes we are proposing. 

To allow customers to make their own assessments of how they are 

affected by some of the proposals in the Business Plan, we are developing a 

Tiered Rate Impact Model jointly with our customers. This model should 

be available for use in September 1994. In addition, BP A has recently 

developed and will make available to its customers an analytic tool that 

calculates the retail cost of utilities paying directly for the conservation 

resources within their service tcnitory and compares that to a scenario 

where BP A continues to rate-base the costs of a regional conservation 

program. 

13 
241 

Question 7: Under the tiered rate and unbundled services scenario described in the 

Business Plan many preference customers will be purchasing a "rebundled" 

package including tier I and tier 2 power, as well as shaping services. Will 

the price of shaping services for such customers be cost -based and, if not, 

how does that satisfY BPA's c6st-based rate-making mandate? 

Answer: BPA rates in total will be cost-based, consistent with Section 7 of the 

Northwest Power Act and other applicable statutes. Shaping services will 

be priced within that context. 

14 
242 

Question 8: The Business Plan DEIS estimates that, compared to the status quo, the 

market-driven alternative will yield about 40 aMW of utility-sponsored 

conservation as a result of a tiered rate's price signal, 22 aMW as a result 

of fuel switching, and 130 aMW as a result of independent utility programs. 

What elements in the market-driven alternative contribute to the 130 aMW 

of additional utility sponsored conservation? 

Answer: The total regional conservation is the same under both status quo and the 

market-driven approach. Both the status quo and market driven approach 

have embedded the same 130 aMW of conservation savings. In the status 

quo approach these savings were to be obtained through the retail utilities 

operating (and paying through their wholesale power bills) BPA's existing 

conservation programs. Under the Market Driven approach the public 

utilities will acquire approximately 130 aMW of conservation savings with 

their own funds. The large generating public utilities are expected to 

acquire roughly 100 aMW. This estimate is based upon our review of 

these utilities' existing conservation plans (prepared in late 1992) and 

supplemented by recent discussions with staff from these utilities pertaining 

to their likely response to BP A's Conservation Reinvention. These utilities 

indicated that they would most likely continue to fund their conservation 

programs to the level that made sense for their specific situations. The 

conservation savings estimates are assumed to be spread across consuming 

sectors consistent with each utility's previous local conservation plans. 

However, many utilities feel that they are capable of delivering the right 

"mix" of conservation for their utility more efficiently and cost-effectively 

IS 
243 

under the market-driven alternative than under the current BPA system. 

Cost savings mentioned by these utilities have included lower incentive 

levels and access to tax-free financmg. The remaining public utilities 

served by BPA are expected to' acquire nearly 30 aMW through similar, 

independent actions. 

The 40 aMW of price-induced conservation is a direct result of endconsumer efficiency actions in response to retail tiered rates. Our analysis 

indicates that some of BP A's retail utility customers are likely to pass along 

tiered rates to their retail consumers in response to BP A's wholesale tiered 

rates. In addition, the 22 aMW of fuel switching reflects the lost 

conservation potential associated with a total fuel switching response to 

tiered rates of ISO- 200 aMW. 

16 
244 

Question 9: What steps is BPA prepared to take if the plan's expected conservation 

achievements are not fulfilled? How many years of underachievement will 

be allowed to pass before BP A takes steps to improve regional 

conservation acquisition? 

Answer: BP A. working with customers, 'Northwest Power Planning Council, and 

constituent groups (Northwest Conservation Act Coalition, state energy 

offices, Natural Resources Defense Council), is currently developing a 

collaborative and mutually agreeable system for tracking the region's 

conservation acquisition efforts. A component of this system will entail 

periodic review and assessment of whether the region is acquiring the 

appropriate level of conservation resources. During this review, if it were 

determined that the region is falling short of our conservation goals, a 

temporary mid-course correction would be implemented. This correction 

would remain until we are assured that the pace of regional conservation 

acquisition is, and will likely remain, consistent with our goal. The specific 

components underlying this mid-course correction are also being developed 

by BP A, its customers and constituents. 

17 
245 

Question Hl: Does BP A need new legislative authority or any changes in existing 

authorities to implement its conservation reinvention plans? 

Answer: BP A does not need new legislative authority or any changes in existing 

authorities to implement its conservation reinvention plans. The Draft 

Business Plan proposal for conservation reinvention merely reshapes the 

way in which BPA will achieve its conservation goals. In this way, BPA 

plans to utilize scarce conservation doUars in the most efficient way 

possible. 

The Northwest Power Act authorizes the Administrator to determine the 

mix of conservation measures that will most efficiently and econornicaUy 

meet the Act's conservation goals, as defined by the Council. The Act 

gives BPA broad flexibility to cilrry this out in a variety of ways. 

BP A believes it can achieve its share of the Council's conservation goals 

while reducing doUar expenditures on conservation. By doing so, BPA will 

not only achieve the goals of the Northwest Power Act with respect to 

conservation acquisition, but will also be operating in a businesslike manner 

to assure the Pacific Northwest an economical supply of electric power, as 

the Northwest Power Act requires. 

18 
246 

BPA would consider offering loans as a future demand side management 

product. Each appropriations act for the past several years has contained 

language prohibiting BPA and other agencies from making loans or loan 

guarantees, e'Ven though BPA is otherwise authorized to do so. BP A is 

developing suggested language for the Fiscal Year 1996 appropriations bill 

that would allow us to offer loans. 

19 
247 

Question 11: What are the implications of the Business Plan for the development of 

renewable energy resources? 

Answer: Under the Status Quo, BPA is conducting several demonstration programs 

for wind and geothermal development. It is expected that these projects 

will be equally valuable in a market driven future. In fact, BPA customers 

with extensive transmission costs to reach their service areas may see 

advantages in small scale, on site renewable generation. BPA intends to 

address the needs of those customers through expertise gained in the 

current renewable demonstrations. It is also possible that there may be a 

market for "greenpower" products in Tier 2. BP A is just beginning to 

explore these alternatives, and what specific mix of wind and geothermal 

products best achieves these goals consistent with our overall objective of 

minimizing future expenses. 

20 
248 

Question 12: In the Business Plan DEIS, it is correctly stated that BPA has no statutory 

obligation to serve the DSI load after the current contracts ex;pire. Does 

BPA plan to conduct a comprehensive review of the costs and benefits to 

the region of the DSis as a means toward developing alternative rate 

structures and contract provisions for that customer group? Why is there 

no discussion in the Business Plan of alternative contractual arrangements 

for the DSis, such as increased interruptibility, greater reliance on nonfirm 

power sales or seasonal sales. 

Answer:· The Northwest Power Act required BPA to offer initial contracts, but did 

not address the question of service under subsequent contracts. However, 

BPA's 1981 Direct Service Industry (DSD contracts obligate BPA to 

attempt to provide service by purchasing sufficient resources to serve any 

DSI request for follow-on service. The 1981 DSI contracts imply a BPA 

good faith obligation to try to provide continued DSI power service. 

BPA is conducting a DSI cost of power service study. We intend to 

address the 1995 net cost of power service to the DSis based on the 

estimated 1995 cost allocation to the DSis, the seasonal and hourly benefits 

ofDSI loads, and the value ofDSI stability reserves. We also intend to 

estimate the value of BPA power to the DSis, as well as the potential BP A 

margin for the DSI segment. The study should help to clarifY issues such 

as alternative DSI rate structures and contract provisions. 

One of the purposes of the Draft Business Plan was to close the anticipated 

BP A revenue gap through customer load retention. Under the "businessas-usual" scenario, BPA was at risk oflosing up to 750 aMW ofDSI load 

21 
249 

to alternative power sources such as combustion turbines and retail 

wheeling. 

Our current intent is to try to shape product and services offerings to DSis 

so that both BPA's business needs and the DSis' needs are met. The 

Northwest Power Act does require that DSI rates be equitable in relation 

to rates paid by industrial customers. of public agency utilities. This 

requirement will guide pricing proposals for DSI rates. We do not know 

yet what specific products and services will yield the best economics for 

BP A as a supplier and the DSis as customers., but we should be able to 

define this for the final Business Plan. There will also be ample opportunity 

for interested parties to participate in the discussion about DSI service 

through the rate case. We anticipate that issues such as greater 

interruptability or seasonal sales will be addressed during power sales 

contract renegotiations. 

In both the business plan and the upcoming rate case, our goal is to 

provide rates to the DSis comparable to rates paid by public utility 

industrial customers. 

22 
250 

Question 13: How does BP A justifY its proposed treatment of new public power entities 

under its tiered rate proposal? 

Answer: "Section S(b) (I) of the Northwest Power Act, 16 U.S. C. § 839c (b) )I) 

obligates BP A, if requested, to offer to sell power to Pacific Northwest 

publicly-owned and investor-owned utilities to meet their firm power 

needs." This obligation extends to newly formed preference customers. 

We are proposing that if the original customer purchased or could have 

purchased, either directly or indirectly, some of its power from BP A at the 

Tier I rate, the newly formed customer should purchase a similar amount 

of power at the Tier 1 rate. When a new customer is formed from existing 

public preference customers in a merger, the new customer will get the sum 

of the original customers' Tier I amounts. When a new customer is 

formed from an existing public preference customer by dividing the service 

territory, the new customer will get a pro rata share of the existing 

customers' Tier I amount. Since this approach combines or divides the 

original Tier I billing amounts of existing customers it will not affect other 

customers' Tier 1 billing amounts. 

When a new preference customer is formed from an Investor Owned Utility 

(IOU) service territory we are proposing that the new customers' Tier 

billing amount would be calculated based on a pro rata share of the 

residential and small farm loads in that portion of the IOU' s service 

23 
251 

territory which formed the new preference customer. This approach 

divides the original residential exchange Tier I billing amount of the IOU 

with the new customer. Many ofBPA's public preference customers have 

advocated that the new customers' Tier I billing amount be calculated 

based on the total load (residential and small farm ~ commercial and 

industrial load) in that portion of the lOU's service territory which formed 

the new preference customer. We believe that this could-create a greater 

incentive than would otherwise exist for new cuStomers to form if a large 

industrial or commercial historical load, which would be used in developing 

the Tier I billing amount, went away. In addition, this proposal would 

result in less stable shares for existing preference customers. 

24 
252 

Question 14: What is BPA's expected schedule for implementing its tiered rate proposal? 

Answer: 

Is BPA prepared to take an alternative course if regional support for BPA's 

tiered rate proposal is lacking? If so, what alternatives is BP A considering? 

BPA is planning to propose the implementation of tiered rates in its 1995 

Rate Case. Rates developed during that rate case will go into effect on 

October 1, 1995. In all likelihood there will be disagreements about the 

details of tiered rates, and we intend to use the current regional tiered rate 

workshop process and the 1995 Rate Case to consider any alternatives 

presented to BPA's tiered rate proposal. 

25 
253 

Question 15: What opportunities exist for BPA to expand its sales of power outside the 

region and the profits from those sales? Should Congress consider 

providing any new authorities that would allow BP A to maximize its 

returns on the sale of power surplus to regional needs? 

Answer: Several years ago, greater opportunities to sell surplus power outside the 

region existed than do today. Even so, BPA had difficulty marketing its 

surplus at favorable prices during the 1980's. The days of such a 

demanding extraregional market for surplus BP A power are gone -- victims 

of the decline of the California economy, the construction of huge amounts 

of new nonutility generation in the southwest, and the steep decline in gas 

prices. Even with the continued scarcity of nonfirm hydro, prevailing 

wholesale prices for energy have recently fallen to levels within the high 

teens to mid-20 mills/kWh range for transactions between the Northwest 

and California. The more surplus power BP A attempts to sell, the lower 

the price tends to go. 

There is still an extraregional market in which BP A will participate, but it is 

unlikely to fully replace the loss of revenues created by loss of Northwest 

load. Prices for _surplus BP A power wquld be somewhat higher without 

the required termination of delivery provisions which are required by the 

Northwest Preference Act. However, we do not believe that the limited, 

additional revenues would justifY revisitation of such a fundamental aspect 

of preference to BP A power at this time. 

26 

84-374 0 - 94 - 9 
254 

Mr. DEFAZIO. Okay. Thank you. 

There were not a lot of items in total agreement here today, but 

we did seem to come to some consensus on something, which I 

don't believe was in the original business plan which would be to 

basically go to a market-based system on the value of reserve and 

allow bidding by other interested parties than the aluminum industry. 

Do you think that is something that we can get consensus from? 

Mr. ROBERTSON. It is an interesting idea and Walt and I were 

talking about that. I would like to have him answer the question, 

if he may. 

Mr. DEFAZIO. Yes. 

Mr. POLLOCK. Mr. Chairman, I think some of the reserves ought 

to be priced according to what their availability is at and sold by 

other parties in the marketplace. There may be others that should 

be required of customers obtaining service from us or other utilities. So, I would be hesitant to say all reserves ought to be priced 

at market, because there is a statutory requirement for the DSis 

to provide certain reserves to the region through Bonneville where 

we are uniquely-where they are uniquely able to provide them. 

So, in general, the market should determine the value of these 

products and services, but I think there might be some exceptions 

when it comes to the DSI reserves and we would like to, I think, 

provide you some follow up information on that. 

[The information follows:] 

BPA's system needs stability and operating reserves. Stability reserves are used 

to protect the transmission system from catastrophic impacts resulting from loss of a manor power facility, particularly large transmission lines linking the Pacific 

Northwest and Pacific Southwest Interties. Operating reserves ensure that a utility has enough generation to meet its load even if it suddenly loses a resource. There are two types of operating reserves, spinning and non-spinning. The Northwest Power Pool (NWPP) requires each member utility to carry operat- ing reserves equal to 5 percent of its on-line hydro generation and 7 percent of its 

on-line thermal generation. Under current Northwest Power Pool criteria, spinning reserves must be in the form of on-line unloaded generation. Non-spinning reserves may be either (1) generation that can be brought on-line within 10 minutes of a system disturbance, or (2) load dropping that can be accomplished in the same time 

frame. 

The DSI's currently provide a portion of BPA's non-spinning operating reserves. Because of the adverse revenue and customer service impacts of dropping load, BPA 

used these reserves as a last resort. They are used primarily during cold snaps and 

fish flushes. There are discussions underway that would potentially allow restriction 

rights to be counted as spinning reserves. (Restriction rights are BPA's right to utilize the DSI power reserves by cutting them off.) 

BPA builds its system to meet BPA reliability criteria, which are based on West- em States Coordinating Council (WSCC) reliability criteria. Utilities are expected 

to be able to provide continuous electrical service to their loads during "credible" 

system emergencies. Loss of both DC Intertie circuits is considered a "credible" system event. BPA can withstand loss of the DC Intertie (both circuits) during export 

conditions and during import conditions when DC line loadings are less than 1500 

MW, without relying on the DSI stability reserves. However, BPA needs the DSI 

stability reserves in order to import between 1500 and 3100 MW on the DC circuits 

and still meet the WSCC and BPA reliability criteria. 

While BPA does not need the DSI stability reserves to maintain AC import capability ratings, these reserves are needed in BPA wants to continue importing at 

those ratings during an outage of one of the three AC lines (to protect against an outage of another line). BPA would also likely need the DSI stability reserves if the 

AC import ratings were increased relative to today's values. 

Based on the preceding discussion, BP A feels that the DSI's are ideally suited to 

provide BPA stability reserves, probably up to 1800 MW for parts of each year to 
255 

maintain BPA's power import capabilities. BPA's operating reserve needs may be 

purchased on the competitive market, which also includes the DSI's. 

Mr. DEFAZIO. What do you mean? One reserve in particular? 

Mr. POLLOCK. Yes. One in particular. The stability reserves, 

which are the-is the capability of these large loads to be immediately tripped 100 percent, or to be brought back on slowly if there 

is a massive power outage in the Northwest. Those are uniquely 

able to be provided by large industries with these capabilities, and 

there was some recognition of that in the history of the Regional 

Power Act. 

The other types of reserve, the plant, the labor reserves and 

what we have called forced outage reserves, I think are more amenable to the approach that you are suggesting. 

Mr. DEFAZIO. Okay. Well, I would urge review of all of that and 

would look forward to a more detailed response. 

This-there was a rather raging controversy over this 7(c)(2) 

delta. What is that? Can you tell us? 

Mr. ROBERTSON. Walt? 

Mr. POLLOCK. I will give this a shot. It will take a minute or two. 

But Section 7(c) of the Regional Power Act is the portion that attempts to describe to us how we should set the DSI rate. And I 

think you have heard other witnesses describe the basic process 

that is called for in Section 7(c), which is to-which is really linked 

to the rate that a DSI would have been served at, had it. been 

served by a public agency. That was the underlying logic, and in 

my opinion, that Congress used in the Regional Power Act. 

So, what it told us to do is, you take the generally applicable rate 

that we sell to the public agency, and then you add to that a margin or markup which would be typical for a public agency, and you 

deduct or adjust that for any changes in the character of service 

and the value of reserves. When we do that computation based on 

the Regional Act directives and then apply to that the history of 

the variable rate, in our view, we come out at the end of the variable rate period in 1996, roughly where we otherwise would have 

been had we not had a variable rate, and in either case, we would 

have complied with the Section 7(c) rate directives. 

Now, there was another question that came up that I think you 

asked, Mr. Chairman, about the wholesale power rate design study, 

and I think there was a $300 million number that you referred to, 

and that is-with the earlier witnesses. That is a different issue 

and a different number. 

Mr. DEFAZIO. Well, tell usMr. POLLOCK. In the course of developing the rates-it is actually 

in the course of developing the public agency rates, we stack up the 

resources that we have in our system, and we put the DSis in the 

stack, in this particular rate design step, after we put the public 

agencies. And what you were seeing in that wholesale power rate 

design study is in effect a what if? 

What if the DSis had been stacked after all of the public agency 

loads and had to pay the next higher resource cost in the stack, 

how different would it have been? 

Now, what we actually do in the rate design is we set the public 

agency rate and then reiterate through the process several times 

to get to the result Congress told us to get to in 7(c). So the whole-
256 

sale power rate design number is really an irrelevant number to 

the questions you were asking the earlier panel about whether we 

have made money or lost money. 

Mr. DEFAZIO. Well, after the term of the initial contracts, which 

were required by the act, isn't what you just described the future 

condition required by the act; that is, didn't the act anticipate that 

they would be served by BPA and would require resources or other 

resources, other than Federal base system resources would serve 

their load? Wasn't that what the act says? 

Mr. POLLOCK. Not exactly, no, sir. The way I would characterize 

what the Act said about the DSI rate was between 1980 and 1985, 

it was set to recover the net costs of the residential exchange. From 

1985 on, irrespective of the term of any contract, the 7(c) rate directives apply. They are not tied to the duration of the contracts. 

So whatever new contract we write, if we write one with the DSis, 

would have to also comply--

Mr. DEFAZIO. So there is an inherent contradiction in the act 

where you have the 7(c)(2) rate process, and on the other hand, you 

have got the language pertaining to what resources would serve 

them and the future. 

Mr. POLLOCK. There certainly are two parts you can interpret 

differently, but we think the 7(c) rate directives are pretty clear 

about how we set the--

Mr. DEFAZIO. I mean, you know, clearly the act says, Federal- . based system goes to preference customers; right? 

Mr. POLLOCK. With respect to supply. 

Mr. DEFAZIO. Right. And we have been very careful in drafting, 

or you have, this business plan to say this is not an allocation of 

resources, but merely a way of pricing power. 

Mr. POLLOCK. Yes, sir. 

Mr. DEFAZIO. Yet, when you put the aluminum companies or the 

DSis altogether, including the aluminum companies, into tier 1, we 

are essentially allocating then part of the Federal base system. 

Mr. POLLOCK. Mr. Chairman, that is the way some of the customers have viewed it, and if I were-if I could, maybe take a 

minute to summarize the principal comments and concerns we 

have heard so far about--

Mr. DEFAZIO. Sure, go ahead. 

Mr. POLLOCK [continuing]. How we are doing this tier 1 and how 

we are implementing the rate directives? 

Mr. DEFAZIO. All right. If you can do that in a minute, it will 

be a miracle. 

Mr. POLLOCK. I will try. Issue number one is did we pick the 

right amount of DSI power to allocate tier 1 and tier 2, and some 

have said, and expressed concerns that 85 percent of the historic 

load is too high, and that is a question we have gotten a lot of comment on and we will take a look at. 

The second question we have heard is why should there be an 

allocation of tier 1 in perpetuity to the DSis, because the public 

agencies will grow. And when the public agencies grow, they will 

be disadvantaged, not with respect necessarily to the supply of 

power, but with respect to the price. That is a substantial issue, 

we are going to take another look at that. 
257 

Issue number three has to do with the sizing of tier 1 vis-a-vis 

public agencies and the residential exchange and how we treat the 

formation of new publics. So as we have-we put a proposal out in 

the business plan, and we are getting a lot of comment on it, and 

those three issues are really where the most comment is coming 

and we have committed to take another look at each one of those, 

and we will do that in the next two months. 

Mr. ROBERTSON. I should add, Mr. Chairman, I think I heard you 

indicate that you had an interest in the potential of us assessing 

the continuation of some variant of the variable rate in through of 

a tier 1 allocation. If I understood you correctly, that is another one 

we will be looking at. 

Mr. DEFAZIO. I wouldn't discount that as a possibility. I mean I 

am willing to admit it is a totally unique load and maybe it needs 

to be treated uniquely rather than melded over into this tier 1 with 

everybody else, because I think that is creating not only concern 

with the preference customers, but it also makes the whole thing 

at this point at least in terms of the analysis that has been provided an imponderable in terms of where the rate shifts are occurring and who is paying, and treating them with a variable rate 

might be preferable. 

Mr. Pollock, on the point of the new publics, boy, I don't know. 

I mean, I am not a lawyer, but I don't know how preference, as I 

read it in the act, would allow us to have two categories of preference customers. You know, those that were and those that will 

be, who have different entitlements. It seems that probably the law 

would require that all preference customers be treated alike. 

Mr. POLLOCK. I think that is what we attempted to do. So I agree 

with you conceptually. What we sought to do in the Business Plan, 

and some would argue we didn't achieve it, was to treat all preference customers on an equal footing, and what that meant is, 

when a new preference customer were formed, that there would be 

a reallocation of the amount of tier 1 power entitlement from a rate 

perspective to accommodate that new customer, which meant it 

would come out of the hides of existing customers, unless something were freed up somewhere. And that is where the DSI issue 

begins--

Mr. DEFAZIO. Right. It raises two issues: the DSI issue, but also 

the exclusion of industrial load; that is, the new preference rate 

would only pertain to residential and farm load if it was formed out 

of an exchange utility. I mean, I have talked to some of the exchange utilities, and of course they think that is great, because it 

removes any threat of public formation out of their service territory. 

On the other hand, the Federal law wasn't set up that way, and 

I think they have other arguments to make, and/or they certainly 

can defend themselves against such utilities, and have. So I am 

questioning why that exclusion is in there, why, you know, if I pick 

up a service territory that I have got to draw lines that exclude all 

of the industrial load, or if I take the industrial load, I am going 

to have to tell them, by the way, if we include you in our new public service territory, your rates are going to go up. 

Mr. POLLOCK. Mr. Chairman, I can tell you why we did it, but 

we are getting a lot of opinions about whether we did it right. The 
258 

objective that we stated in the business plan was that tiered rates 

not significantly alter the incentives that currently exist for the formation of new preference customers. So we wanted to hold things 

constant. 

Mr. DEFAZIO. But you wouldn't-here I have to disagree with 

you, maybe in your expanded remarks. I would say you are dramatically altering it, because today if I form a preference utility, 

I get a preference rate for my industrial, my farm and my residential. If I form it out of an exchange utility or anything else, and 

you are saying you want to keep the playing field level; I don't see 

that at all. I mean, you got some other bizarre stuff we are proposing over here with the cap and all that. I suppose you are trying 

to pay it off over here somehow. But I think we are creating an equity over here and you are not creating a level playing field in 

order to balance off some of the other things you are doing with 

the exchange. I don't know. Mr. POLLOCK. I think, Mr. Chairman, the only difference is that 

tier 1 allocation collectively, for all the publics, would go down, and 

some have argued that is different than it exists today, because the 

same situation would-there wouldn't be any change in the new 

preference agency formed today than there would under this tiered 

rates proposal. I think that is an issue we are taking under advisement and we haven't concluded. So, I think you are raising a legitimate question. 

With regard to the exchange loads, I just want to comment a little more on that. The reason we said that if a new public agency 

forms out of an investor and a utility service territory, only the residential and rural loads would be eligible, because we were trying 

not to alter the competitive balance that exists today for the incentive for public agencies to form out of IOU service territories. We 

have also gotten a lot of comments on that issue. Mr. DEFAZIO. Right. Well, I am sure you will also have some lead 

on that. I believe it is probably illegal, I mean whether or not you 

could make a case for being desirable, I believe it is probably not 

legal to have two categories of preference customers. But in any 

case, we will see as you further develop that. On the exchange, I mean, the current exchange program, and 

this came up in one of our earlier hearings, would seem in some 

ways to discourage efficiency. That is, an exchanging utility, you 

know, if they were to become extraordinarily efficient or more efficient than they have been, they can drop off the exchange roster, 

essentially. They go below the line there for the exchange. This 

would seem to me to be perverse; that is, those who perform better 

or more efficiently don't get the exchange, and those who perform 

less well do get the exchange. How would you be addressing this 

issue? Do you think that is an issue, and if it is an issue, how are 

you addressing it? I got to tell you, I have read your new exchange 

proposal and I don't understand it. Mr. ROBERTSON. Well, let me make a couple of points about the 

nature of the exchange. If it is perverse, it is perverse both ways. 

That is to say, if we are successful in securing our flat rates, we 

are going to have to pay more in terms of exchange costs unless 

we come up with some kind of mutually agreed upon flattening of 

the exchange cost. If we have more than $1 billion in exchange 
259 

benefits that have been put through throughout the region, mostly 

in the State of Oregon, as a result of the act, so it is a fundamentally important aspect of essentially guaranteeing rights for farm 

and rural, and homeowners. 

I will say this, that you are right, if a utility becomes more efficient, they don't get as much of an exchange benefit from Bonneville for their homeowners and small farms; they still get a benefit 

for their industrial and commercial systems, which are not covered 

by the exchange according to the Act. Walt, do you want to add anything to that? 

Mr. POLLOCK. Just an additional point or two. The concern you 

have is a real one to us as well, Mr. Chairman, and we have some 

limited abilities to reflect a new competitive circumstances, and I 

will enumerate a couple. 

First of all, there is a provision in our exchange contract that 

permits us, if we have a lower-cost supply of power than the supply 

we are receiving from the utility with whom we are exchanging, to 

buy that, instead of taking the exchange power. We have already 

given notice of that action and it is called an in lieu--

Mr. DEFAZIO. The delivery, essentially. 

Mr. PoLLOCK. Yes. The Utah Power portion of Pacific Corps, and 

now they have the choice of either matching the price or having us 

buy from an alternative lower cost supplier. We will consider doing 

that with other utilities where the costs of the power coming into 

our system is high and we think we can do better. But we have 

a seven-year notice provision in the existing contract that limits 

our ability to do that. We also have a methodology that was extensively developed and 

litigated a few years ago that we think constrains the bounds within which we can work. But within those boundaries, we expect to 

exercise fully our contract rights and any other abilities we have 

to manage the net costs of the exchange. And we think that is ap- propriate. 

Mr. DEFAZIO. Okay. On the issue of the negotiation of the contracts by the first of the year, one point was raised by Mr. Scott, 

actually, in his testimony of two precedents. What I am trying to 

get at here is whether or not that is a realistic time line and 

whether or not we need to be working a little harder on the backup 

plan as was raised by some of the other questioners. And Port 

Astoria, Oregon versus Hodel, and Forelaws on Board versus Johnson. In both cases, apparently an EIS was required on new contracts. How are you going to address that and get these contracts 

done by the beginning of the year? 

Mr. POLLOCK. Two parts to that. One is how are we going to get 

the contracts done, and I think second isMr. DEFAZIO. Well, that is a different issue altogether, accompanied by an EIS analysis of the contracts which can't be done 

until the contracts are basically formulated. 

Mr. POLLOCK. The EIS can be done before the contract details 

are formulated, and that is what we are attempting to do. 

Mr. DEFAZIO. Well, but if it is like the EIS that was done on the 

business plan, it won't pass a laugh test. I can't start asking questions, having read the thing, and have the administrator, after five 

or six points, admit to me, well, in fact, those are all very good 
260 

points and those are all tremendous inconsistencies and problems 

and, in fact, it is because it is a useless document. An EIS has to 

have some reference to reality and actual real-world impacts, and 

that one apparently did not. 

Now, you are telling me it was developed last October, although 

it was given to me four weeks ago. I guess maybe I could have had 

a draft of it in November and spent my Christmas vacation reading 

it, and it would have had the same numbers in it. That is kind of 

disappointing to me. 

I don't know why it didn't change, and why should-if you published it, you didn't publish it with a disclaimer saying that this 

is a useless document, don't bother reading it, the numbers are out 

of date and it is totally useless. So my question is, you can't do that 

with the contracts of these legal precedents. You can't just throw 

out an EIS that is meaningless, that has no meaningful analysis 

of what is going to happen in the region withoutMr. POLLOCK. I think we differ on that point, Mr. Chairman. 

Mr. DEFAZIO. So you can do one that is meaningless? 

Mr. POLLOCK. No. The analysis and the EIS is an excellent environmental impact statement and we stand by it, and I think what 

the Administrator told you was that the rate numbers shouldn't be 

relied on in this EIS with precision. Because what the EIS is about 

is assessing the environmental impacts of alternatives. 

Mr. DEFAZIO. Well, you can't assess the environmental impacts, 

if you don't know the disparate impacts on your customer groups 

and which ones might then be provoked into going out and buying 

thermal resources or which ones might be provoked into inducing 

more conservation, or this or that, and if we don't know the distribution among the customer classes, we can't even estimate those 

things, or if we do estimate them, it is not very useful. 

Mr. POLLOCK. I think we do know from the EIS what the relative 

impacts are. 

Okay. Then who is going to pay the additional bill, since no one 

else can answer that question, we are going to raise 10 to 15 percent additional revenues next year under your proposed tier grade 

proposal. Tell me who is paying the additional 10 to 15 percent. Mr. ROBERTSON. Let me make a couple of points on that. First 

of all, the EIS's numbers that were a part of the EIS as we are 

showing on that chart, did have a range in them that we thought 

was relevant about a year ago. And the range expanded based on 

the new numbers we knew we would be getting in as the analysis 

began to get more and more sophisticated. And we are simply at 

a stage now where our analysis--

Mr. DEFAZIO. No offense, Jack, but how are you going to be a 

real time competitor if in analyzing rate impacts you are a year out 

of date? If we are going to compete, I would assume that, you 

know, we have to do a little better than saying, well, we published 

this and it is a year out of date. 

Mr. ROBERTSON. I get your point. It is an important point about 

the movement of a rapid, competitive marketplace and how Bonneville's rates are going to interact with it, and you have got a good 

point about how relevant EIS information is going to be at any 

given stage. We are getting to the point now, though, as we designed ourselves into this process, that we are getting to more rel-
261 

evant infonnation and the analysis is becoming far more sophisticated. 

The interactive models are beginning to work in tenns of how 

they interact with load fonnation. And they just weren't part of the 

original EIS, and as the EIS goes along with this, it will begin to 

get more sophisticated as well. 

The idea is that these things track together as we begin to make 

the decision-making point and as we enter into this expanded discussion process, that we have discussed earlier on with you, Mr. 

Chainnan. I think that you will find that infonnation will come out 

by the end of the month that will be helpful in this study and we 

will also begin to make clear how these interrelationships work. 

Now, you asked about who is going to pay the bill, who is going 

to pay the revenues associated with this, and who is getting the 

rate increase. I think that is what your bottom line was. I want to 

make a couple of points, because Walt can best answer that. 

A tremendous percentage, a significant percentage of this rate 

stability that you see us having, going through the next rate case 

and the avoidance of the 10 to 15 percent rate increase, comes from 

deeper cost cuts, which would effectMr. DEFAZIO. Okay. Now, would you detail which deeper cost 

cuts and how much they are, that you can't make under the current system? 

Mr. ROBERTSON. The current system, we think--

Mr. DEFAZIO. Because there were some assumptions there, it 

seemed to me, you were going to achieve under, no matter what, 

because you assume the status quo, you are not reducing personnel. 

Mr. RoBERTSON. Let me direct you to the chart, because you indicated earlier that the top line was a worst case. It is not a worst 

case top line. There are lots worse scenarios than that. 

We think that is a reasonable line, based on some load loss expectations that I think Walt can describe better than I. We start 

from a point where those charts begin to demarcate. We start from 

a point basically after we have cut $200 million in our program levels already; those were the cuts associated with post-rate case discussions last year. 

So we started through our review, function-by-function review, 

and we found $200 million in cuts. Fundamentally, from that point 

forward, based on getting down to the bottom line, we are going to 

need to cut or change about $297 million per year in tenns of helping in addition to Walt's new revenues that he is going to describe 

in a second. The combination of those things gets us hopefully to 

the goal of flat rates. 

Mr. DEFAZIO. Let's focus on reductions for a moment. 

The 297 per year, okay, if we had to do an interim rate case, 

what percentage of that 297 can you capture? These are now not 

new revenues, these are cost reductions? 

Mr. ROBERTSON. We can give you more specific infonnation on 

this. We would begin to go for cost reductions in the $50 to $100 

million range. We would look at the percentage of our Treasury repayment and see whether or not we could afford to reduce that, 

which we don't like to do, because that tends to leverage the repayment refonn issue back on to the Northwest delegation. 
262 

Mr. DEFAZIO. So you are saying somewhere in there, there is between $247 and $197 million of cuts that somehow you can't make 

without tiered rates and those things? 

Mr. ROBERTSON. There are some that we can make on the top 

line, and they are not significantly shown in that line, but I cannot 

get down to the flat-rate line with the cuts without the addition of 

the other revenues. 

Mr. DEFAZIO. I need to know what those things are, Jack. What 

are those things that--conservation is one of them. How much? 

How much of the 247 to 197 million is conservation? 

Mr. ROBERTSON. Okay. Walt that is details. 

Mr. POLLOCK. I was going to suggest, Mr. Chairman, we can give 

you that for the record. Conservation is one. There are a whole series of things. 

Mr. DEFAZIO. Well, if you could give me just a few of them, you 

know, penciled on the back of a napkin here. I am just curious. I 

mean, I am-you know, I just want to know what the worst case 

here is. I mean, if we have to go into an interim rate case, what 

cuts can't you make and maybe are there ways that we could deal 

with that? So I need to know what they are. 

Mr. POLLOCK. We can give you that, Mr. Chairman. I don't have 

it on the tip of my tongue. 

[The information follows:] 

Average 1996-2002 cost reductions associated with BPA's conservation 

reinvention are roul!hl:r $84 million, relative to BPA's 1993 Rate Case. Of this 

amount approximately $34 million is expensed dollars and $50 million is debt serv- ice associated with foregone capital borrowing. 

Mr. POLLOCK. The reason is we are doing this a dollar at a time, 

and there are probably two dozen areas where we are attempting 

either to get new revenues or to reposition products to get revenues 

that were not being paid for or to cut costs. And you really have 

to go down them one by one and judge the feasibility. 

Let me give you a few examples. 

Mr. DEFAZIO. I am trying to divide cost from revenue. Let's deal 

with cost first, because that is the one that is more puzzling to me, 

and then we'll deal with revenues. Deal with cost first. Mr. POLLOCK. Well, in the cost area, we are proposing very deep 

cuts in all BPA programs, and that is not only transmission services, as you pointed out; we think that by reinventing conservation, 

we can reduce the cost of those programs in 1996, 1997. We think 

by reinventing fish and wildlife, we can reduce what otherwise 

might be the costs of those programs. 

You can ask the question: Could we reinvent those programs 

without all of this? And the difficulty is, this is webbed together in 

a way that maybe none of us like all that much, but every particular party with an interest here wants to know what is happening 

on the other side of the equation. You want to know what we are 

going to do with the irrigation discount, for example. And others 

do as well. 

Mr. DEFAZIO. That is just one of many questions I have, sure. 

Summer rates, special summer rate, I guess if you want to irrigate 

in the winter, you are going to have to pay a higher rate, but I 

don't know of anybody that does that. So it sounds like you are 

going to have to continue the discount. 
263 

Mr. POLLOCK. But when people are asked to take a cut in one 

area, they immediately look in another area and say why are you 

still spending money there; or why aren't you doing what you need 

to be doing there? Every constituent of Bonneville asks that, every 

employee of BPA asks that. So while we can give you that information, it is very difficult to engage in a very meaningful discussion 

of, well, let's just do part of this. 

Now, I think I can give you some instructive information on what 

the parts are and how likely we will be able to attain them. For 

example, you really can't reinvent conservation and achieve the 

cost reductions without tiered rates. You need the tiered rates to 

reinvent conservation. So that is why I am suggesting these things 

are hooked together in a way that needs to be fully appreciated. 

Mr. DEFAZIO. Well, I understand some of those things are hinged 

together. On the other hand, it would be useful to have, these are 

what we expect in terms of cost savings, so we can assess what of 

those could be gained in that way, or alternate ways if we come to 

worst case. 

I worry, particularly having heard the Public Power Council testimony and others saying: We want to see, you know, all the major 

issues of these contracts resolved before we move ahead on January 

1st with the rate case. And I am just saying I have some doubts 

about whether that rather ambitious schedule can be met. 

I mean, again, I am sort of prejudiced by looking at little things 

like what happened to EPUD for three years on a conservation 

power plant contract. But maybe you can renegotiate every contract with every major user in three-and-a-half months, maybe the 

agency has changed that much. Maybe everybody has been spending their summer vacation and they are all there working on it 

today. I don't know. I am very doubtful. 

Do you think that the EIS that was provided for the business 

plan is adequate for new contracts? It doesn't mention contract issues. 

Mr. POLLOCK. Yes, it does, Mr. Chairman. 

Let me respond maybe for a minute to what I view to be the adequacy of the EIS question. 

This is an EIS that examines seven alternatives, including not 

only the two you focused us on a minute ago, but another five that 

go over a much broader range. Our responsibility when we take an 

action is to have an EIS that competently annualizes the environmental consequences of the action. 

So the question is, when we finish these contracts from a principled standpoint and the major issues in December, will the EIS 

have contemplated the outcome and adequately considered the environmental consequences? I think the answer to that is yes, but 

we won't know until we get there. Because we knew it when we 

went into this EIS, and that is why we scoped it so broadly, to examine alternatives not only including these two, but much more extreme in both directions. So I think we will have an adequate EIS, 

but it is our responsibility to determine that when we get to December. And if we don't, we will have to supplement it. 

Mr. DEFAZIO. Well, I mean, you know, I sort of suffer from having read through it before the Administrator told me I shouldn't 
264 

bother. And you know, I guess maybe I am-where are the alternatives on, say, the DSI contracts discussed in the EIS? 

Mr. POLLOCK. Under at least one alternative in the EIS, there 

are major losses of DSI loads and that could be driven by an unfavorable contract. 

Mr. DEFAZIO. Yes, but that doesn't exactly seem to me to go to 

some of the issues we talked about here, continuing the variable 

rate, not continuing the variable rate, bidding out VORs, those 

sorts of things and what impacts that might have. Those haven't 

been anticipated. 

Mr. POLLOCK. But the key question for the EIS is whether the 

environmental impacts of the result have been analyzed. So if we 

have an alternative that contemplates a major loss of DSI load in 

this EIS, which we do, then the question is, did that anticipate the 

outcome, whether we get there through unfavorable contracts or 

higher rates? So that is the test t.hat an EIS has to measure up 

to, not did you get the proposed action exactly right when you put 

out the draft. 

Mr. DEFAZIO. What-I am learning about EISs. What water assumptions? Do we make the same exact water assumptions under 

the status quo and/or interim rate as we do under the tiered-rate 

proposal? 

I just want to make sure we are using constants here, underlying 

this. Are we using the same assumption regarding the water conditions under both of those proposals? Are the water conditions assumed-are they underlining this all the same? 

Just sort of in reading this, I got an idea that we are sort of 

prejudicing when we leave out administrative savings out of the 

status quo. I think, well, gee, that means we are kind of 

prejudicing things toward this tiered-rate alternative, because I 

don't see why we couldn't get the administrative savings in either 

one. 

So I am wondering if there are other assumptions that might be 

prejudicing these things. Could you tell me? Are there any other 

major varying assumptions, particularly the most major one which 

has to do with what are the flows going to be on the system? 

Mr. POLLOCK. I don't think that there is-there are differing assumptions about how we operate the system. But I don't think 

there are any different assumptions about the statistical probability of water years. 

Mr. DEFAZIO. Okay. I just want to know, you know. 

Mr. POLLOCK. I know, Mr. Chairman, you have obviously gone 

through this in some detail, but there actually is about a 6-page 

table in the middle of the EIS that describes in detail the alternatives by issue. That is, what have we assumed about each issue 

or each of the various alternatives, and it runs for about-starts on 

page 2-17 and runs through 2-26. So there is a lot of detail in here 

that I think will answer most of those questions. 

Mr. DEFAZIO. Went through that. I don't know. I guess I just had 

a different idea about an EIS. I thought an EIS had to do with 

pretty specific Federal actions in a real world best case, I mean, 

best analysis applied to that. And you are telling me that if we had 

to stumble upon covering the loss of DSI load in one of the alternatives, whether it is intentional or not intentional, no matter 
265 

what gets us to that, we don't need to analyze the different things 

that lead us to that, just what the ultimate result was. 

Mr. POLLOCK. I guess the way I would characterize it, at least 

my view of NEPA, Mr. Chairman, is it requires us, as a Federal 

agency, to be informed of the environmental consequences of the 

action that we are about to take. That is the most fundamental role 

that an EIS provides, and that is the test that it has to meet, that 

it has to have competent environmental information for us about 

the action that we take, and we tried to put a broad enough range 

of alternatives in so we would have that information. 

Mr. RoBERTSON. I would like to say another point that I think 

gets to the issue you raised, Mr. Chairman, and also I believe Mr. 

Duncan raised this morning about this issue of whether our analysis prebiases, or seems to prebias us toward a certain outcome. We 

have tried to be as straightforward as we can about this, and we 

have gone through a fairly-a very open public process, and we are 

now going to go through a longer one to make sure that if there 

are any biases that are seen here, we certainly hear about that 

from both our customers, the interest groups and the congressional 

committees giving us oversight. 

Biases in this would fundamentally undercut our ability to deliver what we think is important. If they are there, we need to find 

them. It is possible there are--it certainly wouldn't be our intent 

as an organization. We are trying to do the best we can to reflect 

a reasonable set in a competitive world that is unfolding in front 

of us. 

Mr. DEFAZIO. What about this issue of transmission which the 

last panel sort of deferred the question? Your communication with 

FERC regarding terms and conditions versus costs? Where are we 

at on that? 

I mean, where does that fit into this whole puzzle? I mean, you 

know, there are sort of varying analyses of how transmission is either going to be applied to cause you to be threatened by competition; we have heard analyses of where, you know, transmission and 

unbundling is going to be used to increase revenues. 

I have had other conversations where it is going to be used to 

basically to in a way help, you know, stave off competition, because 

of the unbundled services of people and the pricing category to be 

put in place. I mean, where does your interpretation of what is required in your little provision in the misbegotten Energy Act of 

1992 put you on transmission and how does that pertain to this 

puzzle? 

Mr. POLLOCK. Well, first, most generally, we view the transmission business as something we are good at; we do well and we 

want to provide more transmission in the future, not less. And we 

believe that the industry is moving towards open access transmission, Bonneville has been in the leadership role in that approach, and we intend to stay there. 

We do not want the availability of our transmission to be an impediment of the fully functional power market, nor do we want it 

to be a leverage point to force customers to buy from us, and we 

have told our customers that and I expect that policy to be carried 

forward. 
266 

That means that if a customer wants to buy from an independent 

power producer or buy additional power from BPA, we will treat 

the request for transmission from a new provider, the same as we 

would as if we were competing for the load ourselves. So that is 

first and foremost principle here. We want to provide transmission; 

we will treat ourselves with regard to competing for new loads like 

we treat others. Now, there may be instances when transmission 

is not available to us or anybody else and we will do something 

about that. 

With regard to the Energy Policy Act, at least my interpretation 

of the Energy Policy Act and you are obviously probably more familiar with it than I am, was it put BPA or: a roughly equivalent 

footing with other utilities in terms of transmission with a couple 

of exceptions. 

Mr. POLLOCK. One, is it didn't change our transmission ratemaking, that is the Section 7 provisions of the Regional Act and 

the FERC authorities and the judicial reviews. And second, it preserved regional preference to transmission. And those are the two 

fundamental differences with respect to Bonneville from any other 

utility. 

We are subject to FERC jurisdiction if there is a matter that is 

to be adjudicated. One of the reasons we have joined the Westwide 

Regional Transmission Group is we are willing to engage in a voluntary utility organization to open up transmission access. So I 

have-I don't see that as a significant impediment to our customers' desires to have options here. I was a little puzzled by some 

of the discussion in the last panel. 

Mr. ROBERTSON. Mr. Chairman, your question I think was more 

specific, because you have this dichotomy, how can we open up 

transmission in one case and then guarantee essentially we can 

help achieve the conservation, for example, objectives of utilities. 

Mr. DEFAZIO. That is the question I had from the beginning. 

Mr. ROBERTSON. And I guess Walt can fill in here, but my response is with the principle we have got in terms of achieving the 

conservation objectives and of reinvention. It is based on an accountability principle that we are going to invent, along with this 

subcommittee, that we are working with at the Council and others. 

The accountability principle is the mechanism that Bonneville will 

put in place to assure that the objectives of the 660 megawatts that 

we talked about earlier are there. Accountability can be achieved 

in various ways. Transmission might be one of those. 

Other ways have been suggested-including a loss of tier 1 resources similar to that which wasn't achieved under the IRP. We 

are looking at a host of ways to do this, and I think perhaps what 

has happened is transmission may have been seen as the only way 

in which that accountability can be achieved. I think there is a 

package of possibilities there that we are going to work with the 

region on. 

Mr. DEFAZIO. You mentioned something about getting WPPSS 

staffing to more appropriate levels. I had this exchange with Mr. 

Counsil, I think you were here, where I have access to only three 

studies, and those three studies find that they are overstaffed. And 

he just says adamantly he is not going to reduce his operating 

staffing until a couple years from now, no matter what. I mean, is 
267 

BPA so sanguine about the staffing levels? He also claims that he 

is basically a low-cost provider here and we shouldn't be concerned 

about it anyway. 

Mr. ROBERTSON. I have had a number of conversations with Mr. 

Counsil directly on our needs to assure that in these fundamental 

cost areas that we have to get control. We work with the Corps, 

the Bureau, the supply system, the Power Council and others to try 

to assure that they are delivering higher and higher productivity 

as time goes on. 

For us, that means fundamentally that we would like them to try 

to eat 3 to 4 to 5 percent of inflation per year. The objective isMr. Counsil's point is he is worried about the NRC license and the 

issue of safety. Obviously, we are all worried about safety first in 

the nuclear plant. 

The fundamental issue here is progress can be made. We have 

encouraged him to work on that. Our mechanism for achieving 

progress with the Supply System is the net billing contracts, which 

does give Bonneville a total ability to not agree to a budget in total 

submitted by the Supply System. But, it is not a very elegant management tool. And so we are in this position of having a thing that 

was written 20 years ago that is a comprehensive review of the 

budget, but it is not a line-by-line item review. So we have to work 

with them and these other parties in a partnership way to try to 

get to these objectives. In my view, and I think Mr. Counsil would 

agree, everybody with large organizations can make productivity 

improvements. The question is how, when, and how fast can we do 

it. 

Mr. DEFAZIO. Well, you know, the President is confronted with 

that situation often. Congress sends him a bill, he might not like 

parts of it, particularly an appropriations bill, and he has a right 

to veto it. Sometimes you got to use a veto. Particularly if someone 

hasn't been paying any attention to you for two decades, and they 

tell us we won't even think about that for another two years and 

is sanguine about those costs. 

I mean, 3,400 people, you know, that is-you know, I mean, 

when we are talking about these kind of margins, you are talking 

about rate increases, I would assume that adds up to, you know, 

maybe a percent, I don't know, maybe a little more. Mr. ROBERTSON. It is all very significant money, particularly 

when we feel like every dollar at this point is very important to our 

maintenance of stable rates. So I agree with you, that is an important factor. And we need to get as efficient as we can. 

I will tell you that the contract mechanism, if we say no to a 

budget, goes to what is called "prudent utility practice." This 

means basically we have to go to a third party to determine whether we were right or the Supply System was right in terms of our 

decision. 

Mr. DEFAZIO. Well, I am going to assume since you are so much 

above the average that you are not going to get, if it is an arbitration, an arbitration that requires them to hire more. So maybe we 

want to roll the dice. I don't know. But I mean, he has taken a 

very, very hard line here. I know he is paid twice as much as the 

Administrator, so he is twice as good, I guess. But I am disturbed 

at that recalcitrance. 
268 

Mr. ROBERTSON. I hear you. 

Mr. DEFAZIO. And that is a concern I raised with Mr. Jura for 

a number of years, and I raised it with Mr. Hardy, and I just really 

think that, you know, you would find more backing out there than 

perhaps you anticipate for finally getting tough with, you know, the 

supply system, so-called. 

A little bit of discussion, conservation. You know, I am notagain, when we talk about the transmission and how we are going 

to-you know, I mean, I raised that question before, both in terms 

of tier 2 and in terms of driving people to conservation, which is, 

you know, okay, I get this much in my tier 1, now I am either 

going to buy tier 2 or I am supposed to be inducing conservation. 

I mean, first off, there are the equity issues of people who made 

a tremendous amount of conservation investment, whether it is 

funded by you or themselves or anybody else, have fewer immediate and easy gains to get. Other people have done nothing, and 

there are utilities that have done nothing, have some gains they 

can capture rather quickly. I mean, that is a concern. 

But secondly, there is a concern about how we are really going 

to drive this thing, whether we are driving it through transmission 

and costs there or other agreements, or whether we are driving it 

through IRPs that have some sort of enforceability and penalty 

against the tier 1 allocation. I don't know. But 1-at the moment, 

I have a doubt about triggering a great amount of conservation, 

particularly the high levels we have been getting, with just a market signal. 

You know, there is a big market signal in this area, sort of like 

9, 10 mills, I don't know what it is, I mean, there are very high 

electric rates in the Northeast, and they go up dramatically in the 

summertime to induce people not to use their air-conditioning so 

much. It doesn't do any good. So, you know, I am not quite so sanguine about getting the very desirable regional goal of cost avoidance and conservation and the environmental goals that come with 

that, just through market price signals. So what are we going to 

supplement it with? 

Mr. RoBERTSON. I agree with you on that. I don't think you will 

find anybody at Bonneville saying that the market price signal 

alone will accomplish this level of conservation. I wouldn't agree to 

that, I don't believe it. 

The market price signal is an important mechanism which can 

induce, we think, a much more innovative tiering program which 

borrows less money against our borrowing cap for the purposes of 

Federal borrowing: But also I think this also allows for a decentralization of the programs, a guarantee hopefully based on this accountability mechanism we are going to come up with of the 660 

being achieved, befor~ and after, and in the bargain creating, I 

think, more innovative programs, decentralized programs with less 

overhead, less central controls. 

You talked about the overheads of Bonneville. We have 

overheads, like any other agency. And if we can minimize those 

overheads and accomplish the megawattsMr. DEFAZIO. What was that figure? 
269 

Mr. ROBERTSON. We are trying to get the information on that. 

That might be a combination. We are just-the answer is, I don't 

know, but we will provide it for the record. 

Mr. DEFAZIO. Okay. We would like that for the record. 

[The information follows:] 

In FY 1992 BPA's administrative costs as a percent of Direct program expenditures were 16 percent. This figure declined to 15 percent in FY 1993. This number 

increases to 29 percent and 26 percent, respectively, if Corporate overheads and Indirect Program costs are included. 

Mr. ROBERTSON. Yes, that is a big-but overheads, if you look at 

fish and wildlife programs and you ask what are the overheads of 

fish and wildlife agencies or other States, Federals, basically, they 

range between 70, in some cases, 30 to 70 percent. You have got 

an overhead problem throughout the delivery of our systems, it is 

very significant, that we all have to get to. 

Bonneville has its overheads, but so does everybody else. So the 

more we can decentralize these programs and get more innovative 

out there in the field, I think the more megawatts that will be 

achieved. 

Walt, you want to add anything to the tier effect we are going 

to have out there? 

Mr. DEFAZIO. Let me add, it is a small proportion of it that you 

think comes through the market price signals. 

Mr. ROBERTSON. Yes, it is a small portion, but then we add to 

that, we are continuing to fund market transformation which will 

be codes and the kind of things that we can do only on a regional 

basis. Then we are going to propose the energy service charge, and 

we convert what now looks like approximately $200 million a year 

and pull down from our borrowing capital, which we go through in 

1999. Now we convert it to a loan program that we think we 

have-we want to get authority to do what we think we can accomplish. That ironically, it is much easier to give money away in our 

authority than it is to loan money and get money back for it. But 

we think we can achieve that. 

If we add that layer cake of objectives together with the tiered 

signal, and then get the innovation and decentralization going, we 

think it could be quite a powerful market change. And we think it 

might shape the conservation acquisition of the 21st Century and 

get it out of this more centralized control. Even if we continue to 

succeed on this, it is clear that we have a political issue coming up 

ahead of us with regard to the borrowing cap. 

Mr. POLLOCK. Mr. Chairman, we don't need to go through it now, 

but we can submit for the record, we have a chart here that actually shows the components that Jack was just describing. And 

there is some numerical detail on page 57 in the business plan. 

But we would be glad to just supply you this chart, that graphically shows it for the record. 

[The information follows:] 

BPA's current goal, based on the Council's Regional Plan, is to achieve 660 aMWs 

which includes all cost-effective conservation between 1992 and 2003. 

The major sources of contributions to meet regional and BPA conservation targets are existing programs and other contractual obligations, utility-initiated programs, 

and BPA DSM products and services. Current projections are that lesser accom- plishments will be made with market transformation and tiered rates. Table 2-3, 

BPA Conservation Goals and Accomplishments, on page 57 of the Draft Business 
270 

Plan give specific year-by-year specific accomplishments and projects. The components of the sources are described as follows: 

Accomplishments. BPA has accomplished 79 aMWs from FY 1992-1993 programs 

and another 55 aMWs are projected to be achieved through codes and standards put 

into place since the target was established. 

Existing Programs. BPA's current regionwide programs including Super Good 

Cents, Energy Smart Design, Energy Savings Plan, Waterwise, Weatherwise, Water 

Heating, Appliance Efficiency and Manufactured Home Acquisition Program will 

achieve 96 aMWs through FY 1995. Additional special contracts BPA put into place over the past few years are ex- pected to achieve 101 aMWs of savings. These include energy services company con- tracts, targeted acquisition programs, utility power plants and others. Most are ex- pected to be completed by FY 1997. 

Utility-initiated DSM. Many utilities indicate that they will run their own con- servation programs in their service territories. The large generating utilities (Snohomish, Clark, Tacoma, and EWEB) are projected to acquire 100 aMWs of conserva- tion beginning in FY 1996. Other utility segments are projected to achieve about 

30 aMWs of conservation. 

BPA DSM Products and Services: Energy service charge (ESc) results are projected to achieve conservation in mostly large industrial and commercial firms outside of the large generating utilities. In addition to the 50 aMWs projected for ESc, an initial set of products and services was analyzed as a proxy for the future busi- ness line with projected accomplishments of 37 aMWs. 

Tiered Rates: The impact of tiered rates was assumed to result in 40 aMWs of 

conservation, based on the assumption that about 50 percent of end-use consumers see a retail tiered rate structure from their utilities as a result of BPA's wholesale 

tiered rates initiated in FY 1996. An additional 22 aMWs would be the result of end use consumers choosing an alternative fuel which would result in less conservation 

potential. Market Transformation. Based on initial analysis BPA expects that at least 27 

aMWs would result from market transformation efforts. The calculations leave BPA 28 aMWs short of achieving the 660 goal, however, the numbers cited are intentionally conservative. BPA is confident that the proposed 

conservation reinvention is a viable approach to accomplish all cost-effective con- servation for the region. 
BPA CONSERVATION ACQIJISIT

660 I 

6X) _ _ ::::::lllllllil ji"

Em 

~ 

<1l 400 

Q) 

> 

~ :ro - 

::I 

E 

::I 200 (.) 

100 

0 l _ 

1002 1934 1~ 1~ 2COO 2002 

Year 
272 

Mr. DEFAZIO. Okay. And then where are we at in tenns of discussions with the customers about enforceable IRPs? 

Mr. POLLOCK. We are right in the middle of that discussion. As 

you heard a little earlier, I think from Angus and some other witnesses, that we are working with the Council, with customers, with 

public interest groups, to try to figure out how to manage each 

component of this plan. If you go to the Senate report language or 

the way we have described it in the Business Plan, there is a component that has to do with planning, and the integrated resource 

planning. 

We are working on that to figure out how we do it, what the 

standard is, who does it, how is it done. We are also looking onat the independent perfonnance review and there are two or three 

ideas about how to do that. And we are looking at the accountability mechanisms. And there are two or three ideas about how to do 

that. One of them is that-is the transmission idea. I have got 

some misgivings about that, frankly, that I have got to admit to 

you, but it is on the table for discussion. There is also the possibility of changing allocations of tier 1 or providing incentives or disincentives. I think all of those are in play right now in that discussion group. 

Mr. DEFAZIO. Okay. Yes, the Senate report does reference a 

meaningful perfonnance accountability mechanism incorporating 

penalties for poor perfonnance and benefits for good perfonnance. 

I mean, carrot-stick kind of thing. 

Mr. POLLOCK. Yes, and we are being guided by that report in 

tenns of what this approach needs to embrace. 

Mr. DEFAZIO. Okay. I am--oh, all right. Going to ask you this. 

I will just read it. I am tired. I would like more detail on what specific measures BPA-most of my colleagues just do it this way anyway. I would like more detail on what specific measures BPA is 

considering taking in the event its conservation reinvention plans 

fail to deliver the expected savings. 

How long do we wait before acting and what will BPA do to 

make up the difference? 

Mr. ROBERTSON. Okay. We will give you that. You want the detail right now? 

Mr. DEFAZIO. How long will it take? 

Mr. ROBERTSON. As Walt indicated, we are in the middle of inventing how we account for this. As part of that we will also have 

to have some kind of a benchmark which will detennine that we 

are on the path and we are making enough progress to achieve the 

660 megawatt goal. 

[The infonnation follows:] 

BPA has been working with utility customers, the Northwest Power Planning 

Council, states, and interest groups to further define the tiered rates and conserva- tion reinvention proposals. Currently a plan has been devised which calls for cus- tomers to prepare local conservation plans that describe their approaches to developing all cost-effective conservation in their services territories. 

BPA will monitor implementation of the plans according to regionally developed 

verification and evaluation standards and will remain responsible for mitigating any 

persistent shortfalls that may occur during implementation by customers. A performance accountability mechanism is currently being developed that incorporates 

penalties for poor performance and benefits for good performance with respect to 

conservation acquisition. 
273 

BPA's conservation reinvention is based on utilities making choices. BPA will no longer rely on centralized decision-making. Through tiered wholesale rates, utilities 

will see the right price signals so that informed choices will be made. 

BPA fully expects that this approach will enable BPA to achieve our share of the 

region's conservation goal, but BPA is prepared to adjust our approach if necessary 

to ensure continuous regional conservation achievement at or above the Council's 

target. 

The one thing I want to leave with you on this issue, because it 

is very important, is we are pledging to achieve the same amount 

of conservation with the reinvention that we would have achieved 

before. That is our obligation to you. We have to achieve that. And 

we will have to get back to you as we design the accountability 

mechanisms, I think. 

Mr. DEFAZIO. Okay. And since I raised conservation, this is another thing from the beginning when I talked about designing 

tiered rates, and I would like you to think about this a bit, I have 

raised it with Mr. Hardy. And that is-and why there is a particular concern with Mr. Wolberton's study and/or your analysis internally, which I haven't seen, about the, you know, the costs of some 

of these things on growing public utilities. And that is, you know, 

growth, responsible growth is good. You know, we want to grow responsibly. I am an Oregonian, we have zoned our whole State so 

we can grow responsibly and not become Los Angeles. So my question is, how do we discriminate between types of growth? And 

wouldn't it be desirable to construct something to do that? 

Someone who wants to grow sloppily and inefficiently, who hasn't 

taken conservation measures, who isn't pushing their customers on 

to gas, where gas is available and other things, how do we account 

for that as opposed to some areas that have taken extraordinarily 

rigorous measures, as Seattle or EWEB or someone else, to induce 

conservation and to grow-but inevitably to grow, because people 

are moving there and grow responsibly. 

I mean, it seems to me, I know this is a difficult question, but 

I think it is something that needs to be addressed. And, you know, 

we shouldn't just say everybody is penalized because everybody has 

to buy their additional power out of the same tier 2 if they are 

growing responsibly or they are growing irresponsibly. 

Mr. ROBERTSON. I want to make one point. 

Mr. DEFAZIO. Or I should say growing in an energy efficient 

manner and growing in an energy inefficient manner, less 

judgmental. 

Mr. ROBERTSON. The fundamental idea to get to the issue of tier 

2 and the question of how this will be dealt with, the fundamental 

idea of having an accountability mechanism in the question of the 

conservation acquisitions and the targets that might be established, is fundamentally a mechanism which can be described as 

making sure that people who grow efficiently, get rewarded, and 

those who choose to do something else, don't. So I think we are trying to precisely--

Mr. DEFAZIO. So it doesn't assume-the problem is I look at a 

lot of this and since we are cutting off the tier at a certain point 

in time, I am assuming here is my load, I have chosen one year 

out of these five years that I am allowed to choose, probably for 

growing utilities the most recent year, having to do with weather 

conditions, whatever they find is to their advantage, but as soon as 
274 

I exceed whatever kilowatt, megawatt over that, I am paying in 

tier 2, I am saying that it shouldn't just be-l understand what you 

are saying, I applaud that, but I am saying you also should maybe 

look at whether this is a static allocation or determination. 

Mr. ROBERTSON. Okay, yes, I hear you, but I think the fundamentals here we are after are to do what you are suggesting. I 

don't think we can achieve the 660 without a viable accountability 

mechanism, in any event. I want to make one other quick point 

about fast-growing publics and those who have contributed to energy growth in the last-or energy efficiency in the last decade and 

a half. 

We are extremely proud of the energy conservation program of 

the last decade. We had to begin a program from nothing as a region. The Council put together a plan, we worked it out over a complex decade, and we spent over a billion dollars largely in the fastgrowing public areas, but also in the industrial sector, to create a 

mainline program that has become a benchmark for the industry, 

not just in this country but elsewhere. 

What we are trying to do with this reinvention is simply take 

what worked best with that program and apply new standards to 

make it more responsive to markets for the 21st Century. For the 

fast-growing publics, a lot of that was financed I think, and willingly financed, by Bonneville through the Council's program, and 

we are proud of the results of that. 

Mr. DEFAZIO. Okay. Well, I want to thank the last witnesses representing BPA and certainly all the other witnesses who testified. 

I mean, to me, perhaps we are moving in a direction that will raise 

my level of confidence and others. We need an analysis of the range 

of the issues and the contracts, the impacts of tiered rates. 

I think it needs to be done in a very open and public way so that 

we can discuss the relative merits. And, you know, that we understand where costs are being shifted, where to, where from, and 

what it means to us as a region in the future. I guess at this point, 

I would have to agree with the Public Power Council testimony, 

which was: Don't go forward if we don't know what we are going 

forward with and we don't have it right. 

We got one thing horribly wrong, which was WPPSS and notices 

of insufficiency, and that was given to us by the last generation, 

and our generation is going to pay for it until the day we die. I 

want to be sure that our generation doesn't stick the next generation with another series of mistakes that may have been adopted 

in a very well-intentioned manner under a false sense of urgency. 

I think an extraordinarily well-thought-out, balanced, and fair 

plan that doesn't go into effect for 18 months or 24 months or 

whatever is going to be better than one that is rushed through because of the exigencies or the perceived exigencies of competition 

and the market. This is not the last hearing we will have on this, 

I am sure, and we will have more opportunities for further discussion and I hope to do the next hearing out in the region so we can 

get a little bit more public involvement. 

So again, I thank you, I think all the testimony was good, and 

look forward to continuing the discussion. 

The committ~ is adjourned. 

[Whereupon, at 3:02p.m., the subcommittee was adjourned.] 
APPENDIX 

AUGUST 9, 1994 

ADDITIONAL MATERIAL SUBMITTED FOR THE HEARING RECORD 

WASHINGTON PUBLIC POWER SUPPLY SYSTEM 

P.O. Box 968 • 3000 George Washington Way • Richland, Washington 99352-0968 • (509) 372-5000 

The Honorable Peter DeFazio 

U.S. House of Representatives 

1233 Longworth House Office Bldg. 

Washington, D.C. 20515 

Dear Representative DeFazio: 

June 9, 1994 q!=t'El\JErJ & ·.~,.. -~ ./ 1;. · 

·· i 1 5 1994 

''/-,SHJNGTON, DC 20!51• 

Subject: CONGRESSIONAL TASK FORCE REPORT ON 

BONNEVILLE POWER ADMINISTRATION 

A Congressional task force headed by Oregon Representative Peter DeFazio recently released 

a report on the Bonneville Power Administration's (BPA) operations and finances. The report 

addresses BPA business practices and includes recommendations for cost-cutting measures. 

The Supply System is mentioned in several places throughout the report, with references to costs 

associated with Plant 2 operations, preservation of WNP-1 and -3, and our proposal to use 

Plant 2 and WNP-1 to dispose of the nation's stockpiled weapons-grade plutonium. Comments 

in respect to these projects are particularly focused on ways the BPA could reduce spending. 

While some of the task force's recommendations have merit and may warrant consideration, 

others would interfere with the Supply System's ability to continue safe, reliable and costeffective operation of Plant 2. Additionally, several statements in the report are inaccurate. For 

example, the report states that Plant 2 costs are "far higher than the nuclear industry average for 

similar plants." In reality , Plant 2 costs for the last several years have either been below or very 

close to the average for nuclear plants of its type operating in the U.S. today. 

I take particular exception to the "wasteful spending" reference to the Supply System. For the 

last two years, Supply System budgets have remained level and been approved by both the 

Supply System Executive Board and BPA. All Supply System expenses are substantiated by a 

well justified need to sustain safe, reliable and cost-efficient operations. 

Where we are in agreement is that trimming Supply System costs where appropriate remains a 

top priority for Supply System management. We have tasked ourselves with a three-year getwell program to improve Plant 2 operating performance and the general way we do business. 

Without increasing budgets as other plants have had to do, we have made good progress so far 

in improving Plant 2 performance and will continue until we become one of the nation's top 

nuclear power plants. Coinciding with this effort, we're working to identify ways we can 

become more efficient and then incorporate these methods and processes into our routine work 

practices. 

(275) 
The Honorable Peter DeFazio 

Page 2 

June 9, 1994 

276 

CONGRESSIONAL TASK FORCE REPORT 

I'm convinced that through continued performance improvements, the Supply System will earn 

more positive comments in such future reports. 

WGC:SJS:pp 

cc: Supply System Executive Board 

Supply System Board of Directors 

Very truly yours, 

jj(~Gz~~J W. G. Counsil 

Managing Director 
~:~ S~~~~£ ~;!~ 0RNifJ.. CHAIRMAN 

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277 

m.~. J)oust of l\tprt5tntatibt5 

i!ommitttt on 

ftatural Resources 

l.illlalibington, J:lf! 20515-6201 

September 8, 1994 

Mr. William G. Counsil 

Managing Director 

Washington Public Power Supply System 

P.O. Box 968 

3000 George Washington Way 

Richland, Washington 99352-0968 

Dear Mr. Counsil: 

DON YOUNG . ..>oLASK A 

A.AN«IHCi R( PUSLIC.\N Mf:MS:: 

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SU.HOIAECIOA 

STA .. LEV SCO\IOI.U 

Gl .. UALCOU'<SEl 

OANif:l \l ... lKISH 

illf., DliCANU IAf ClO~ 

Thank you for your letter of June 9, 1994, regarding the 

Committee on Natural Resources May 1994 Majority Staff Report 

entitled 11 BPA at a Crossroads" and the testimony you delivered 

before the Subcommittee on Oversight and Investigations regarding 

the Report on August 9, 1994. Your letter asserts that portions 

of the Report regarding wasteful spending by the Supply System 

are inaccurate but does not include specific data in support of 

these assertions. 

In order to assess the basis of the assertions you have made 

regarding the accuracy of the Report I request that you respond 

to the attached questions. I would appreciate receivin~ 

responses to these questions no later than October 3, 1994. 

Please provide a copy of your response to Representative Peter 

DeFazio, who, as you know, chaired the Task Force respo nsible for 

the BPA Report and the August 9, 1994, Subcommittee hearing . 

for your cooperation. 

on Oversight and Investigations 

cc: The Honorable Bob Smith, Ranking Member, 

Subcommittee on Oversight and Investigations 

The Honorable Peter DeFazio, Member, 

Subcommittee on oversight and Investi qations 
278 

Questions for the Washington Public Power Supply System 

Follow-up to Oversight Hearing on the Bonneville Power 

Administration 

House Committee on Natural Resources 

Subcommittee on Oversight and Investigations 

August 9, 1994 

WNP-2 Staff Levels 

1. The following table shows nuclear plant staffing according to the latest 

industry survey by the Institute of Nuclear Power Operations. As the table 

indicates, on-site staff (minus security) averages 783 for a plant the size of 

WNP-2; that is about 200 fewer than reported at WNP-2 by the Washington 

Public Power Supply System in its own response to the INPO survey. The INFO 

survey's total for off-site staff averages 322 for the 46 U.S. nuclear utilities, 

while the Supply System's survey response reported 432, even though most 

other nuclear utilities operate more than a single unit. What is the Supply 

System's analysis of these statistics? Are they a legitimate indicator that WNP-2 

on- and off-site staffing is higher than the industry average? 

Average Nuclear Plant Staffing (permanent positions) 

Total Per Per Per WNP-2 

u.s. 1,100 utility plant INPO 

MW (46) (69) response 

On-site staff 72,487 783 989 

minus 

security 

Security 8,621 125 137 

Off-site 14,796 322 432 

Total 95,904 1,229 1,558 

Source: 1993 Survey of Nuclear-Related Employment in United States Electric 

Utilities. Institute of Nuclear Power Operations. INPO 93-007. October 1993. 

2. The attached chart shows a staffing comparison of WNP-2 with four 

other nuclear units of similar age and size, based on data from the Electric 

Utility Cost Group (EUCG). The chart indicates that WNP-2's staff level is 

nearly 400 above the average of the other four units, and 300 higher than the 

average when WNP-2 is included. Does the Supply System believe those units 

provide a good benchmark for WNP-2 staffing and costs? If not, please provide 

EUCG staffing data, including off-site numbers, for the nuclear units that you 

believe are most comparable to WNP-2. 

3. The consulting firm Tim D. Martin & Associates (TDM), which helps 

nuclear utilities manage their staff levels, has developed a staffing database that 

is based partly on its own investigations of utility corporate structures, rather 

than entirely on utility self-reporting. The TDM database includes all regular 
279 

utility employees at nuclear plants, all off-site corporate support staff, and all 

long-term contractor staff (defined as being on the job at least 6 months). The 

attached summary of the database indicates that the total average staffing for 

a 1,000 megawatt General Electric reactor is about 1,100. To make that figure 

more comparable to WNP-2, 10 percent adjustments could be made for WNP-2's 

larger size (1,100 megawatts), its status as a single-unit plant, and the Supply 

System's status as a single-plant utility. The resulting average staff level of 

1,400 compares with the Bonneville Power Administration's count of permanent 

on- and off-site WNP-2 staff of 1,881. How does the Supply System account for 

such a large difference? 

4. The attached table from Bonneville shows total WNP-2 staffing rising by 

89 from December 1991 to March 1994. Why did that increase take place? 

5. Supply System Managing Director William G. Counsil testified at the 

hearing that WNP-2 staffing was higher than he would prefer. If current 

staffing is too high, what does the Supply System believe is the optimal staff 

level? Does the Suppy System have a plan to reach that level? If so, what is the 

timetable for that program, and how will the reductions be achieved? How much 

will WNP-2's annual costs be reduced? 

6. At the hearing, Mr. Counsil testified that staff reductions could force him 

to shut down WNP-2 for safety reasons. Please elaborate on that assertion. How 

rapidly and deeply could WNP-2 staff be reduced without threatening safety? 

Aren't there similar plants t hat operate safely at substantially lower staff levels? 

Capital Costs 

1. According to information provided by Bonneville in December 1993, 

expenditures on WNP-2 "special capital" projects after 1996 were expected to 

total $8.1 million. However, in April 1994 the Supply System estimated that 

special capital expenditures after 1996 would total $32.4 million. What is the 

reason for that increase? How firm is the latest schedule, which indicates that 

all special capital projects will be completed by 1999? 

2. Capital additions at U.S. nuclear plants have averaged $25 per kilowatt 

of capacity per year during the past five years, according to the Utility Data 

Institute. That is about $27.5 million per year for a plant the size of WNP-2. 

The Supply System's April 1994 projection shows regular capital additions 

averaging about $32 million per year through the end of the 1990s, in constant 

FY1995 dollars, and rising to about $40 million a year from 2000-2004. Why will 

such a relatively new plant as WNP-2 require above-average capital additions 

during the next decade? Does the Supply System have any plans to reduce those 

scheduled expenditures? 
1 ,600 .--------., 

1,400 I 

1,200 

1/) 1,000 c 

0 

:!::: 

1/) 

0 

a. 

:t:: 

ro 

u; 

Total Staff Pos

- Other 

- Security 

- OAIOC 

- Training 

- Engineering 

- Maintenance 

I=:::::J Operations 

- Administration 

Figure 3 
#Vc,Cr 

Selected Units For Co

WNP-2 

1150 p 85 

1100 B 88 

930 p 84 

1140 B 84 

1150 p 85 

Table 2 
282 

SUPPLY SYSTEM STAFFING 

The March WNP-2 Headcount to Mega wan Ratio has increased from 1. 72 to 1. 8 employees per 

megawatt (1,924 employees 11,086 megawatts), which reflects some staffing-up for the outage. 

Since December 1991, there have not been reductions at WNP-2; however, there has been a total 

reduction of 42 in the corporate areas (corporate allocation to WNP-2 is down 24 and corporate 

head count for all other projects has been reduced by 18). 

The program for 'Reduction OfRdiance On Outside Services' was initiated in January of this 

year by Vic Parrish. Contractor headcount (excluding outage contractors) charged to WNP-2 has 

decreased ;lightly to about the same level as it was 18 month! ago. Vic has invited all 111llru\gers to 

initiate reviews and controls of the use of contractors to "help reduce the cost of power t.o BP A 

and the ratepayers of the Northwest." Last month, Planning and Control staff met with the various ••*•-- managers to get commitments for contractor staff reductions. The current foreca..t shows planned 

~ reductions of7 in May, 16 in June, and 45 in July. 

The table below, based upon data reponed in the Supply System Monthly Reports, tracks actu.a.l 

total staffing from De=bcr 1991 to the present. 

1,243 1,247 1,252 1,313 +70 

23 67 43 43 +20 

322 322 312 298 -24 

1,588 1,636 1,607 1,654 + 66 

247• 254 345 270 +23 

1,835 1,890 1,962 1,924 +89 

169 175 168 151 -18 

9• 5 11 14 +5 

178 180 179 165 -8 

GRAND TOTAL 131 2,089 +76 

~ 

All data is based on actual headcount extracted from Supply System Monthly Reports. 

The "All Other Projects" section is composed of all Supply System staff charged to Wl'-<1'-1, 

WNP-3, WNP-4/5, HGP, Packwood, and 9 percent of corporate. 

• Numbers are as of August 1992, because reliable non-outage support contractor data was not 

available until then. 

Source: Bonneville Power Administration 
[f) 

0 

~ 

" ~ 

§-

l:l 

;,: 

~ s· 

R<> 

~ 

~ 

" 

~ 

"' 

"' 

'4 

17 .... BAD NEWS ... IT HA

.;<;t-'t-l> AT VERY HIGH LEVE

• • • • • • • • • • • • • • 

(Staffing for Standard 1 O

':/·· :S::-~ • ~- -~---· 

FUNgTIQN . "' ~w .QE 

·~ ~~ - ·-"" 

Plant 392 376 

Technical 193 177 

RAD/ 59 61 

Environmental 

Nuclear 74 105 

Assurance 

Services 254 276 

Management 33 36 

Clerical 96 96 

Total 1101 1127 

iource: TOM Analysis 

II J~ 
284 

WASHINGTON PUBLIC POWER SUPPLY SYSTEM 

P.O. Box 9Ql._L. 3000 George Washington y • Richland. Washington 99352-0968 • !509) 372-5000 

September 30, f~ 

The Honorable George Miller 

Committee on Natural Resources 

U.S. House of Representatives 

Washington, D.C. 20515-6205 

Dear Representative Miller: 

Enclosed are responses to the questions raised in your September 8 letter (enclosed) regarding 

the Supply System and Plant 2 operations. One of our concerns, as expressed in several 

exchanges of information between the Supply System and your staff, is how Plant 2 is compared 

with other operating nuclear plants of similar type. Every plant is unique in its specific design, 

location, political environment and organizational form and authorities. 

As a joint operating agency in the state of Washington, the Supply System operates under very 

specific authorities and requirements of the state. Because we are a single plant operator with 

one customer, Bonneville Power Administration (BPA), we do not have a traditional electric 

utility infrastructure and corporate organization to provide the plant administrative support. This 

support is not included in the nuclear industry comparison data, but because BPA pays our total 

costs, these administrative costs must be paid by the region's ratepayers and included in EPA's 

costs. These differences are mentioned only to help clarify why it is difficult to make exact 

comparisons between operating plants. 

The Supply System recognizes the importance of being compared with other plants throughout 

the industry and we do so on a monthly basis. One such comparison that was pointed out by 

Mark Holt iri his January 24, 1994 memo to the House Natural Resources Committee, was that 

the Supply System's costs in calendar years 1989 through 1992 were approximately equal to or 

below the industry average. 

We also recognize that our future in today's competitive market will be dependent on our ability 

to cut our costs below_ the industry average. Toward this end , I initiated a program last month 

to reduce our fiscal year 1995 costs by approximately ten percent. We expect our current year's 

operation and maintenance costs to be $10 to $15 million below our fiscal year 1994 costs. 

We are in agreement that costs must be lowered and believe that our current initiative will put 

us on a path to become more efficient over the next few years. 

Ve~yours, 

~(,~/;t~ W. G. Counstl '..1f~ / 

Managing Director 
285 

RESPONSE TO GEORGE MILLER'S OUESTIONS 

A. WNP-2 STAFF LEVELS 

1. Institute of Nuclear Power Operations (INPQ) Statistics on Manpower. 

QUESTION: What is the Supply System's analysis of these statistics? Are they 

a legitimate indicator that WNP-2 on- and off-site staffing is 

higher that the industry average? 

ANSWER: The Supply System, like every other nuclear operating plant, 

submits staffing numbers to INPO in various categories, including 

the general groupings of on-site and off-site per the table displayed 

in your questions. The data in the first and last columns are 

verifiable from the INPO report. We assume the averages 

combine all plants of all vintages and sizes and an attempt is made 

to normalize the data by plant size. These averages are useful as 

broad general observations but cannot be used for specific plant 

comparisons. The most realistic comparative data from the INPO 

staffing report is to compare "on-site" data for like plants. In 

Attachment I, we have compared the INPO staffing data for onsite employees for large single unit BWRs which entered 

commercial operation in the mid-to-late 1980's. This chart shows 

that our on-site staffing levels are in the middle of the group of six 

plants. The off-site data is also displayed, however we feel this 

data is very inconsistent and cannot be used for valid comparison. 

2. EUCG shows staffing levels 300-400 higher than others. 

QUESTION: Does the Supply System believe those units provide a good 

benchmark/or WNP-2 staffing and costs? lf not, please provide 

EUCG staffing daiiJ, including off-site numbers, for the nuclear 

units thai you believe are most comparable to WNP-2. 

ANSWER: The Electric Utility Cost Group (EUCG) is an ad-hoc utility group 

which has collected nuclear power plant cost and manpower data 

over the past eight years. The database is proprietary with the 

data to be for the sole use of submitting members. Data is 

categorized by work functions with staffing data provided on an 

equivalent staffing basis and includes contractors. On-site and offsite are not reporting categories for this database. Using the same 

six plants described above, we have looked at the latest 

information which is for reporting year 1992. Attachment 2 shows 

84-374 0 - 94 - 10 
286 

a graph of this data. Plant 2 falls in the middle of the range for 

the staffing data collected by the EUCG for the aforementioned set 

of plants. The average equivalent staffing number is 1352 and the 

Supply System number is !310 for direct work functions. 

3. TDM database predicts 1400 staffing vs 1881 reported by BPA. 

QUESTION: How does the Supply System account/or such a large difference? 

ANSWER: Tim D. Martin & Associates (fDM) also has a proprietary 

database of which we have no detailed knowledge and therefore 

have a very difficult time analyzing any results or conclusions 

from that data. Your letter states that the database "includes all 

regular utility employees at nuclear plants, and off-site corporate 

support staff, and all long-term contractor staff" . Based on our 

experience in discussing staffing with other utilities, we have not 

found any utility that includes allocations of corporate functions as 

part of total staffing for a plant as is reported by the Supply 

System and BPA. 

4. BPA report shows total WNP-2 staffing increasing to 89 from December 1991 

to March 1994. 

QUESTION: Why did that increase take place? 

ANSWER: The increase in staffing of 89 from December 1991 to March , 

1994, is the result of many shifts and changes in the organization. 

In that time period there has been a reduction in corporate support 

to Plant 2 and increases in plant operations, maintenance and 

capital programs. In the operations and maintenance areas, the 

plant placed increased emphasis on reliability as addressed in my 

testimony. Operations and training are targeted areas. Other areas 

with increases are health physics and plant chemistry. In the 

capital area, we have been working on megawatt improvement 

projects and implementing a large construction contract settlement. 

Work on these projects have also increased staffing to the plant. 

2 
287 

S. WNP-2 staffing higher than Managing Director would prefer. 

(JJJ!:_STION: What does the Supply System believe is the optimal staff level? 

Does the Supply System have a plan to reach that level? If so, 

what is the timetable for that program, and how will the 

reductions be achieved? How much will WNP-2's annual costs 

be reduced? 

ANSWER: During my testimony, when I stated that staffing levels are higher 

than I prefer, I was primarily referring to the number of contractor 

support personnel, however, some reductions can also occur in 

Supply System staffing levels. 

An optimal staff level is very difficult to define due to the 

complexity of operations, uncompromising demands for safety and 

the challenging regulatory environment in which we operate. As 

stated in my testimony, we are on a three year "get well" program 

in which the first year has achieved some excellent operational 

results. Ideally, we would like to sustain and institutionalize this 

good performance before entering into staff reductions. However, 

due to the increased competitiveness of the industry at this time, 

we are reducing year-round contractor support to about 80 

contractors. (This number could be smaller but we must maintain 

adequate staff to support an annual outage cycle.) We are also 

looking at reducing the Supply System staff in areas where 

managers feel they can take some business risk but with no risk to 

the safe operation of the plant. The estimated annual budget 

reductions as a result of this effort is estimated to be $10-15 

million for the current fiscal year. 

6. Staff reduction could force shutdown. 

QUESTION: How rapidly and deeply could WNP-2 staff be reduced without 

threatening safety? Aren't there similar plants that operate safely 

at substantially power staff levels? 

ANSWER: If staff reductions are ordered without reducing the work and fully 

evaluating the impact to safety, then the plant safety could be 

jeopardized. The level and time period for staff reductions must 

be carefully considered with close attention paid to current 

regulatory changes, the experience and training of the staff and the 

physical condition of the plant. Items of work which have an 

impact on staffing levels include the attention received from the 

NRC. For example, in 1993, Plant 2 had more NRC attention 

3 
B. CAPITAL COSTS 

288 

than any other nuclear operating_ plant in the nation. In 1993, 

according to a NRC repon, they e~tpended 16783 hours on Plant 

2 compared to the mean of 7515 and an average of 6792 . This 

attention requires considerable staff time to prepare information, 

answer questions, provide follow up and resolve concerns. 

Industry "rule of thumb' is that the utility spends 25 hours for 

every hour of auention by NRC. 

Regarding similar plants which operate safely at substantially lower 

staff levels, we are aware of one in our databases. This is a 

highly rated plant for some time with an excellent operating 

record . We are striving to achieve that standard of excellence. 

However, as shown by the EUCG data in Attachment 2, we are 

close to the staffin& average of similar plants and are striving to 

reach the best of the group. Another comment regarding similar 

plants is that none operate on a 12-month fuel cycle as we do. 

This means that each year we must plan, schedule and execute an 

outage which increases work and reduces the amount of generation 

Plant 2 can achieve. In a non-outage yea:r, other plants can 

achieve a 100 percent capacity factor while our theoretical limit is 

83 percent. This operating characteristic, which is required for 

integration with the hydro-dominated Federal Columbia River 

Power System, does increase work and staffing levels. 

L "Special Capital" projects increase by $24.3 million in new estimate. 

QUESTION: What is the reason for that increase'! How firm is the late!>1 

schedule, which indit:ates that all special capital projects will be 

completed by 1999? 

ANSWER: According to our Fiscal Year 1994 Long Range Forecast, "special 

capital" projects past Fiscal Year 1996 are estimated to cost $11.7 

million and in April 1994, the same forecast for Fiscal Year 1995 

has estimated costs beyond Fiscal Year 1996 to be $32.4 million. 

The reason for the increase in future Fiscal Year 1995 is a delay 

in the implementation of some projects so we can closely evaluate 

the cost-benefit of each project, the schedule in which the project 

can be successfully implemented and the impact such an 

implementation has on the outage length. A common period 

comparison of the two referenced plans (FY95 through FY99) 

shows the FY94 forecast to be $77.7 million while the FY95 

version is $83.9 million. The difference of the two estimates is 

4 
289 

primarily deferral of work planned but not executed in FY94. All 

special projects may not be completed by FY99 if the: schedule and 

cost-benefit analysis does not support such a completion schedule. 

2. Routine capital 11dditions higher than industry ave1·age per Utility Data 

Institute (UDD. 

QUESTION: Why will such a relatively new plant as WNP-2 require above 

average capital additions durin& the next decade? Does the 

Supply System have any pla!L~ to reduce those scheduled 

expenditures'! 

ANSWER: In speaking with a representative: of the Utility Data Institute 

(UDI), we found that the capital numbers in their report are 

industry-wide averages obtained by calculating the change in plant 

capitalization from ye;u to year. According to our property 

accounting records, Plant 2 total capitaliation over the first I 0 

years of operation averaged $13 million per year or $11.38 per 

megawatt installed capacity. For Fiscal Years 1992, 1993 and 

1994 the: plant capitalization change was $14.7 million, $33.3 

million and $12.5 million respectively. UDI stated that the change 

in capitalization between 1992 and 1993 (their latest data) is $33 

per kilowatt hour. For a I, 150 megawatt facility such as Plant 2 

that would equate to $38 million. This is higher than current Plant 

2 plans. Once again, without understanding how each utility 

submits this data and what is/is not included, we do not consider 

the data accurate enough on which to base capital spending 

decisions. 

In regard to why Plant 2 needs to have such a large amount of 

capital additions, the plant will have operated 20 ye;us by 2004, 

which is not a "relatively new· plant. Much of the equipment was 

procured in the 1970's which means that the equipment may be a 

much as 30 years old by 2004. According to our depreciation 

schedules, t0.5 percent of the plant in :service (which is $338 

million) has an expected life of 20 ye;us or less. Although 

depreciation schedules do not dictate equipment life, they do 

provide a guideline for expected replacements. In addition, not all 

of the capital is to replace old equipment but is used to provide 

upgrades and to implement regulatory required changes. Even 

with the above infonnation, the Supply System is trying to reduce 

the level of capital expenditures in the future. When we believe 

this can be realistically achieved, the Long Range Forecast will 

reflect lower capital costs. 

5 
INPO'S 1993 STAFFING C

---- ------ ·- . -·--------- ------- . 

- ---------- - -- -- 

-~~ N ~~E STAF I~G -. O~F ~ITE STAFFING 

2,000 · . , .. -· 

1,500 . 

<.9 

• I 

z , N/R 

LL 

LL 1,000 · <( 

r-

(f) 

500 

0 . !> '\'\'\'\'\'\'\'01 

A B c WNP-

L!llliJHIIi>illll witil other late vlntaoe. sinule llllil nwn Plants 
2,500 

2,000 

1,500 

1,000 

500 

0 

LARGE UNIT BW

EUCG DATA BAS

Equivalent Man-Years 

, 

n 

-

-

Fll 

-

1 

-

- " . . 

n r ~ . v '·: 

' ' TI 

· · f 11 · 

r V" v;• [ • 

1/ ' ~ : v 

.. !j . . I . ~ . ( . I' ~ - . . :j 

l~ ~ ~ I =I ~ iiB II ~ . - 

r11 · r11 

- 

1987 1988 1989 1990 1991 

Year 

Comparison with other late vintage, single unit BWR Plants 
CO~MITHE 0'< WAYS "-"0 M<~"<S 

SUBLOM ... IT~H ON HO<lH< 

5 'J BCOM.,.I~TE ~ 0" Hu ... u., RESOURCES 

CH"-i~M.O.'. 

292 

JIM McDERMOTI 7TH DISTRICT. WASHINGTON 

C'1M'-'17HE Su,OHDSOF (:ongress of tbe ~niteb ~tates 

~oust of l\epresentatii.Jtll 

Rlas!}mgton, I» I{ 203 1:; 

September 8, 1994 

Chairman George Miller 

Subcommittee on Oversight and Investigations 

1324 Longworth 

Washington, D.C. 20515 

Dear Mr. Chairman: 

(Q.(>t~IRMAN 

(O-<GAf~SIONAl URB AN 

CON<-AE»'o"•L T•s~ 

1NTfA'<ATIUN Al HI'/ 

On behalf of Seattle City Light, I would like to submit the 

following testimony to be included in the record for the August 9 

hearing concerning, "BPA at the Crossroads," the Majority Staff 

Report from the BPA Task Force. 

Thank you for your assistance. 

Sincerely, 

. JJ1f~-

cDermott 

r of Congress 

1707 LONGWOIIT>t BUILDING 

W.t.SI<INGTON, DC 20515-4707 

(202) 225-3106 

PRINTEOONRECVCLEDPAPER 0 1809 7TI< AIHNU~. SUIH I 2 1 2 

su.nu. WA 98101-1399 

(206) 553-7170 
Office of the Mavor 

City of Seattle · 

293 

Testimony of Mayor Norm Rice on 

"BPA at a Crossroads" 

The 1994 Majority Staff Report of the 

Task Force on the Bonneville Power Administration 

Before the Subcommittee on Oversight and Investigations 

House Committee on Natural Resources 

Washington, D.C. 

August 9 , 1994 

I would like to thank Chairman George Miller for this opportunity to discuss the 

Bonneville Power Administration's (BPA) competitiveness project, and I commend 

Representative Peter DeFazio for his thorough investigation of this issue as Chair of the 

Natural Resource Committee's Task Force on BPA. 

The release of "BPA at a Crossroads," a report of the Natural Resource Committee, 

has contributed greatly to the Pacific Northwest's understanding of the challenges 

facing BPA as it struggles to "reinvent" itself. I share many of the report's findings 

and I look forward to working with BPA, fellow utilities, my constituents, Congress, 

and the Administration to identify a role for BPA in the Pacific Northwest that permits 

the agency to guard its competitiveness and fulfill its responsibilities to the region. 

First, I want to express my wholehearted support for BPA's efforts to improve its 

competitiveness and customer service, known as the Competitiveness Project, the most 

commonly stated purposes of BPA's "reinvention." The entire nation will benefit from 

a more competitive electric utility industry and it is wise for BPA to respond to new 

opportunities for competition brought forth in the 1992 National Energy Policy Act. 

Also , the Pacific Northwest will benefit from a reinvigorated BPA that is leaner, less 

bureaucratic , and more responsive to the public. 

As the process of reinvention unfolds, however, I am deeply concerned by BPA's 

apparent narrow view of its role in the Pacific Northwest. To date, the process has 

been dominated by a model of competitiveness the principal purpose of which is to 

minimize the kilowatt hour price of electricity in the short run, and to maximize shortrun revenues to the agency. These goals exclude much of BPA 's mission . 

The American people have empowered BPA with special responsibilities of governance 

that transcend those expected of a private corporation. These responsibilities are not 

just a matter of trust, but are contained in the federal laws governing management of 

the Pacific Northwest's power system. In particular, we expect and the law directs 

BPA to employ its ownership of the Federal Columbia River Power system so as to 

safeguard our environment, promote conservation and efficiency in the use of electric 

· "J ' :_.--_:o ·• -.•: :•· ~, ;o · ..;.~ ::.-::.". c-:,_•0 · ' ,::- ·. :·,) ;."~' ,;.·-.:;)18 i l">::'rl1 ·?PrJCr~. " •., ~· f. ·- ··. 1' ·. '.' 

~,. c :~~-cc.·~ ·-4 . .,.· . .-. ::.~· 1' : ·s·-~J , :-373 -2o6·: GB.! ..:c::· ~ ~A.x -ji3 J s: :< 
Mayor Norm Rice 

August 9, 1994 

Page 2 

294 

power, encourage the development of renewable resources within the Pacific 

Northwest, protect and enhance fish and wildlife resources, and foster cooperation and 

coordination among the region's electric utilities. 

I am particularly concerned that the Competitiveness Project appears to reject a 

fundamental agreement I thought the Pacific Northwest had firmly established with the 

passage of the Regional Power Act. As part of a sensible strategy to purchase "leastcost" resources, BPA commited to an aggressive pursuit of energy conservation as its 

resource of highest priority. Under its Competitiveness Project, however, BPA 

proposes to replace its aggressive and direct involvement in the planning and 

acquisition of energy conservation with a passive approach that relies on "market 

forces." It is doubtful that this new strategy will achieve the conservation acquisition 

called for in the Regional Power Plan and SPA's 1992 Resource Program. 

The City of Seattle's direct experience with energy conservation contrasts with BPA's 

new approach. Since 1987, City Light conservation programs have saved 2 billion 

kilowatt hours of energy, with Seattle residents paying for nearly three-quarters of this 

accomplishment. These investments have been an integral part of our resource strategy 

and have boosted rather than thwarted City Light's competitiveness by enabling us to 

avoid the high costs and uncertainty associated with building new thermal resources. 

The Pacific Northwest has traditionally contributed toward the purchase of energy 

conservation in the Seattle area because this investment makes sense for the region as 

well. No energy resource is cheaper than conservation and nowhere is it more plentiful 

than in the central Puget Sound area. Each kilowatt hour of energy saved in Seattle 

means an additional kilowatt hour of affordable energy is available for consumption 

elsewhere in the region. These savings reduce the region's reliance on sources of 

electricity that cause harm to our environment. 

In 1992, BPA formally recognized the value of Seattle's conservation resources when it 

agreed to increase financial support for City Light's conservation program. In 

exchange, City Light agreed to increase its acquisition of conservation to help the 

region achieve conservation targets. The City's commitment followed a promise of 

direct financial assistance from BPA. In 1993, our cooperation bore fruit when BPA 

exceeded its conservation target by nearly one-third, saving 50 megawatts of energy 

across the region . Seattle contributed 9 megawatts, or 18 percent, of that region-wide 

total, enough to supply power to 36,000 residential customers for one year. 

Despite BPA 's withdrawal of support for our programs, Seattle will not abandon its 

aggressive pursuit of conservation and the region will continue to benefit from our 

efforts. Our commitment has been to meet all of Seattle's projected increase in 

demand for electricity through conservation measures until the year 2003--not through 

building more dams or burning more fossil fuels. 
Mayor Norm Rice 

August 9, 1994 

Page 3 

295 

While our resolve remains, BPA's withdrawal of support for our programs casts doubt 

on the city's ability to fulfill its commitment. In dollar terms, BPA's proposal will 

mean an annual loss of about $20 million for Seattle's conservation programs. In real 

terms, its effect means that much energy conservation will be left undeveloped in 

Seattle, the city offering the region its most abundant and affordable opportunities for 

energy savings. 

The diminished imortance of energy conservation at BPA also threatens the success of 

regional efforts to save energy . In 1991, the region completed a formal energy 

planning process, as required by the 1980 Northwest Power Planning and Conservation 

Act, in which BPA was assigned responsibility for acquiring 660 megawatts of energy 

conservation. BPA formally committed to achieving a minimum of 660 magawatts of 

energy conservation in its 1992 Resource Program. By BPA's own estimate, its 

"market reforms" will lead to savings that fall short of its 1992 commitment for energy 

conservation. Where the region will find the additional resources and effort needed to 

to fill the void of BPA' s virtual absence in regional conservation efforts is a troubling 

and as of yet unanswered question. 

Whether the Pacific Northwest is ultimately able to achieve its minimum targets for 

energy conservation is a secondary concern. The most important question for the 

region is how far beyond the "minimum" could we have achieved , as witnessed in 

1993, had BPA maintained its resolve and financial commitment to energy 

conservation? How many power plants would we have avoided building? How much 

healthier would our environment be? It is my sincere hope that fifteen y~rs from now 

our children will not be reviewing our legacy and asking these same questions, with no 

ability to affect the outcomes. 

Although Seattle cares deeply about energy conservation, other aspects of Bonneville's 

Competitiveness Project may have far greater financial impact on the City. In addition 

to the loss of $20 million in conservation funding, a recent study completed on behalf 

of the Association of Public Agency Customers concluded that BPA's new rate 

structure will shift about $200 million in annual costs from the Direct Service 

Industries, composed of the region's aluminum companies, to public utilities 

throughout the Pacific Northwest. Also, BPA 's Business Plan projects the agency will 

receive an additional $231 million in revenues from new charges for its products and 

services. Public utilities with generating facilities, such as City Light, appear to be 

likely candidates to absorb the vast majority of these cost shifts. 

Before BPA can expect the public to support its plans, the agency must be more 

forthcoming with information about who will be paying how much for these shifted 

costs. City Light has no specific information about likely rate increases to result from 

BPA's reinvention, yet until recently BPA was prepared to begin a formal rate case 
Mayor Norm Rice 

August 9, 1994 

Page 4 

296 

next October to implement its proposed changes. The decision to postpone the rate 

case until next January is welcome, but does not solve the problem. BPA's business 

plan recently revealed that the full financial impact of the proposed changes will not be 

known until 1999, the year in which BPA hopes to phase in the last of its new charges 

for energy services. 

If BPA ' s competitiveness is truly at risk , I urge it to look more closely at other 

methods of cutting costs, and the postponement of the rate case provides a good 

opportunity to do so. In particular, the Natural Resource Committee's BPA Task force 

recommends $150 million in potential annual budget savings in addition to BPA's 

current plan to cut its conservation budget and increase rates for its services. Among 

others, the savings include $110 million in cuts associated with management of the 

Washington Public Power System's nuclear plants, whose total annual costs amount to 

25% of BPA's entire budget. In addition, the Committee urges BPA to reevaluate its 

calculation of a credit applied to the electricity bills paid by the Direct Service 

Industries. An updated calculation using today's interest rates would save BPA $40 

million each year. 

Decades ago, the citizens of Seattle made far-sighted investments in hydroelectric 

generation that has blessed the city with stable and low electric rates. While we are 

proud of this legacy, the cost of maintaining and upgrading our hydroelectric system 

and financing our conservation programs have recently led to sizable rate increases. In 

1993, Seattle's rates were increased by an average of 12 .6 %, and its average rate for 

industrial customers was higher than four of the seven large regional utilities which the 

City uses as a basis for comparison . Another rate increase is scheduled next year and 

by 1998, our rates are expected to be one-third higher than their 1992 levels. 

As difficult as these rate increases will be on the citizens of Seattle, they do not include 

BPA's withdrawal of support for conservation or other costs that will be shifted to the 

City under BPA 's "reinvention" proposal. Although the amount of the additional costs 

Seattle will bear as a result of BPA's changes is undetermined at this time, early 

indications are that it will be significant. For this reason , I must conclude that BPA 's 

"reinvention" plans, as currently contigured, will impose an unacceptably heavy burden 

on Seattle and its economy. 

Many aspects of BPA 's Competitiveness Project are praiseworthy and should be 

implemented without delay. For example, decentralizing the administration of 

conservation programs is a sensible move that will reduce overhead and result in 

programs that are more responsive to local customers. Likewise, BPA proposals to 

operate more efficiently and simplify its organizational structure will reduce costs and 

improve the performance of the agency. 
Mayor Norm Rice 

August 9, 1994 

PageS 

297 

I must oppose, however, other aspects of BPA's reinvention plans and recommend that 

their implementation be delayed. For example, "reinvention" of conservation calls for 

a series of changes that appear unable to match the tremendous accomplishments of the 

conservation strategies they will replace. Also, other cost savings offered by BPA 

amount to little more than shifts in costs that appear to be distributed inequitably 

throughout the region. 

The Northwest Power Act was enacted under the premise that those who share in the 

benefits of the system shall also in meeting its goals. Perhaps inadvertantly, BPA' s 

"reinvention" of itself fundamentally alters that assumption. In essence, through its 

proposed changes, BPA hands out a portion of the federal system to its customers, and 

in doing so, releases them from the responsibilties of contributing to efforts to conserve 

energy and meet new load growth. The net effect is that the growing municipalities in 

our region, such as Seattle, will shoulder all these costs. 

I am concerned that such a dramatic recasting of the Power Act's purpose should 

originate from BPA and occur with such little examination of its implications. In 

common with BPA and other utilities throughout the region, Seattle City Light is 

adjusting to intensified competitive pressures. The entire region will benefit from 

efforts to cut costs and surely we can identify a fairer distribution of existing costs. 

However, I firmly believe that in the end, continued cooperative management and 

development of the region's energy resources is the most effective means of helping 

BPA and all Pacific Northwest utilities remain competitive. In its current form, the 

Northwest Power Act assumes the same . 

I pledge to work together with the region, the federal government, and Congress to 

seek reform of BPA in a manner which preserves its competitiveness, respects its 

responsibilities, and balances fairly the costs of these changes throughout the region. 

Unfortunately, BPA 's efforts to date fall short of this challenge. 

As a first step, I offer the following suggestions. First, the entire process should be 

delayed until all communities have a better understanding of how much BPA 's "cost 

cutting" measures will raise their rates. Second, BPA should introduce "market-forces" 

as a supplement to its conservation programs, not a replacement. Finally, the region 

must look more closely at all possible cost cutting opportunities and the Committee's 

report offers appropriate suggestions to begin this scrutiny. 

The decisions we make today influence more than tomorrow's rates and revenues. Our 

actions will have a profound effect on the quality of life and choices we leave for our 

children. With this imperative in mind, I am confident that as a region we can find a 

better solution . I would like to thank Chairman Miller for this opportunity to testify 

and Rep. DeFazio for his tireless work on these issues on behalf of the Pacific 

Northwest. 
298 

Comparison of WNP-2 Staff Levels With Industry Averages 

Mark Holt 

Congressional Research Service 

August 8, 1994 

Comparing staff levels at different nuclear plants can be difficult, because 

utilities vary in their reporting of nuclear-related employment, both at plant 

sites and at headquarters. However, the databases located for this review 

indicate that staffing at Washington Nuclear Project No. 2 (WNP-2), near 

Richland, Washington, may be significantly above average. 

Institute of Nuclear Power Operations (INPO) Survey. All nuclear 

utilities are asked by INPO to fill out a questionnaire indicating on- and off-site 

nuclear-related employment. The Washington Public Power Supply System 

(WPPSS), which operates WNP-2, believes other utilities undercount their 

nuclear staff for the INPO survey, particularly off-site positions. WPPSS also 

doubts that all security personnel, who are often contractors, are counted at all 

sites. In response to those objections, only the INPO data for on-site, nonsecurity staffing is used here; a rough calculation based on plant capacity yields 

an average of 783 workers for a reactor the size of WNP-2.

1 WPPSS says its 

permanent WNP-2 staff, excluding security, totals 1,1672 - almost 400 more. 

Electric Utility Cost Group (EUCG). Data collected by the EUCG is 

intended to be more rigorously uniform than the INPO survey, although WPPSS 

believes that staffing at other utilities is still underreported. A chart provided 

by the Bonneville Power Administration CBPA), based on EUCG data, shows 

total staff positions at WNP-2 at about 1,550, while comparable staff at four 

other plants of approximately the same age average about 1,175 - also nearly 

400 lower. Even ifWNP-2 is included in the average, its staff level is 300 higher. 

Tim D. Martin & Associates (TDM). One of the primary activities of the 

consulting firm TDM is to help nuclear utilities manage their staff levels. For 

each client utility, the firm identifies all nuclear-related staff throughout the 

organization, including all regular utility employees at nuclear plants, all off-site 

corporate support staff, and all long-term contractor staff (those on the job at 

least 6 months). A database developed from that information indicates that the 

total average staffing for a 1,000-megawatt General Electric reactor is about 

1,100.

3 Allowing 10 percent adjustments for WNP-2's larger size (1,100 MW), 

its status as a single-unit plant, and WPPSS' status as a single-plant utility 

results in a rough baseline of about 1,400 employees. EPA's count of permanent 

1 1993 Survey of Nuclear-Related Employment in United States Electric 

Utilities. Institute of Nuclear Power Operations. INPO 93-007. October 1993. 

2 Analysis of WNP-2 Staffing and Capital Expenditures. WPPSS Financial 

Management office. May 18, 1994. 

3 Nuclear Industry Costs. Tim D. Martin & Associates, Inc. Presentation to 

U.S. Council for Energy Awareness. November 29, 1993. 
299 

WPPSS staff and contractors allocated to WNP-2 totals 1,8814 - nearly 500 

more. 

Potential Savings. According to BPA, which pays all of WNP-2's costs, 

the average annual cost per staffer at the plant is $64,573. Reducing WNP-2 

staffing to average industry levels, as indicated by the data discussed above, 

could therefore save about $20-30 million per year. 

4 Chart provided by James Lewis, BPA Nuclear Project Office Director. July 

28, 1994. 
103d Congress } 

2d Session 

300 

COMMITIEE PRINT NO. 7 

BPA AT A CROSSROADS 

MAJORITY STAFF REPORT 

OF THE 

TASK FORCE ON 

BONNEVILLE POWER ADMINISTRATION 

OF THE 

COMMITTEE ON NATURAL RESOURCES 

OF THE 

U.S. HOUSE OF REPRESENTATIVES 

79-568 

ONE HUNDRED THIRD CONGRESS 

SECOND SESSION 

MAY1994 

Printed for the use of the Committee on Natural Resources 

George Miller, Chairman 

U.S. GOVERNMENT PRINTING OFFICE 

WASHINGTON : 1994 

For sale by the U.S. Government Printing Office 

Superintendent of Documents, Congressional Sales Office. Washington. DC 20402 

ISBN 0-16-044412-8 
301 

COMMI'ITEE ON NATURAL RESOURCES 

GEORGE MILLER California, Chairman 

PHILIP R. SHARP, Indiana 

EDWARD J. MARKEY, Massachusetts 

AUSTIN J. MURPHY, Pennsylvarua 

NICK JOE RAHALL II, West Virgirua 

BRUCE F. VENTO, Minnesota 

PAT WILLIAMS, Montana 

RON DE LUGO, Virgin Islands 

SAM GEJDENSON, Connecticut 

RICHARD H. LEHMAN, Califorrua 

BILL RICHARDSON, New Mexico 

PETER A. DEFAZIO, Oregon 

EN! F.H. FA.LEOMAVAEGA, American 

Samoa 

TIM JOHNSON, South Dakota 

LARRY LAROCCO, Idaho 

NEIL ABERCROMBIE, Hawaii 

CALVIN M. DOOLEY, California 

CARLOS ROMERO-BARCELO, Puerto Rico 

KARAN ENGLISH, Ariwna 

KAREN SHEPHERD, Utah 

NATHAN DEAL, Georgia 

MAURICE D. HINCHEY, New York 

ROBERT A. UNDERWOOD, Guam 

SAM FARR, Califorrua 

LANE EVANS, Illinois 

PATSY T. MINK, Hawaii 

THOMAS J. BARLOW Ill, Kentucky 

THOMAS M. BARRETT, Wisconsin 

DON YOUNG, Alaska 

Ranking Republican Member 

JAMES V. HANSEN, Utah 

BARBARA F. VUCANOVICH, Nevada 

ELTONGALLEGLY, Califurrua 

ROBERT F. (BOB) SMITH, Oregon 

CRAIG THOMAS, Wyoming 

JOHN J. DUNCAN, JR., Tennessee 

JOEL HEFLEY, Colorado 

JOHN T. DOOLITTLE, California 

WAYNE ALLARD, Colorado 

RICHARD H. BAKER, Louisiana 

KEN CALVERT, California 

SCOTT MciNNIS, Colorado 

RICHARD W. POMBO, Califorrua 

JAY DICKEY, Arkansas 

JOHN LAWRENCE, Staff Director, 

STANLEY SCOVILLE, General Counsel 

TASK FORCE ON BONNEVILLE POWER ADMINISTRATION 

PETER A. DEFAZIO, Oregon, Chairman 

PHILIP R. SHARP, Indiana ROBERT F. (BOB) SMITH, Oregon, 

PAT WILLIAMS, Montana Ranking Republican Member 

RICHARD H. LEHMAN, Califorrua BARBARA F. VUCANOVICH, Nevada 

LARRY LAROCCO, Idaho CRAIG THOMAS, Wyoming 

GEORGE MILLER, Califorrua JOHN T. DOOLITTLE, California 

(Ex Officio) DON YOUNG, Alsaka 

(Ex Officio) 

DANIEL M. ADAMSON, Legislative Staff 

S. ELIZABETH BIRNBAUM, Counsel 

JEFF STIER, Legislative Staff 

LINDA GoRDON STEVENS, Ckrk 

ELIZABETH McMILLAN, Clerk 

(II) 
~J~~~~E'~~;~E ~.:~FQANIA CKAIRMA'I 

!Ow• O J .. U o!> .. ~SS~CHUSETTS 

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lAN!(VANSIW .. OIS 

THOWASJ I A.lOWIIt.H!OTliC<Y 

T><O .. AS .. A~HT.WISCONSIN 

To Members of the 

302 

11.& . .,ou~t of )itprt~tntatibt~ 

€ommitttt on Jlatural l\tsourcts 

•asbington. II€ 20515-<i20t 

May 1994 

MEMORANDUM OF TRANSMITTAL 

DON YOUNG. ALASkA FlANkiNG REPli8LIC N~EM8ER 

JAWHVHANSf .. UTAH 

UA ......... fV\KAN(>VtCHNlVAOA 

lllON!;All>GlY,CAl,.ORNIA 

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.J(I(lHt>LEY,COLOitAOO 

JQHO<f OOOLI"L(_CAL"ORNIA 

WAYNEAllARO.COLOMOO 

RICHAIIO H ·A~lR. LOUISI .... A 

UNCAI.VIOIT.CALIFOMOI.o, 

SCO"Ioi<INNIS,COLOIIAOO 

IIICttAIIOW ~0"'10. CAUfC'~NI .. 

JAY OIC~EY. M~ .... ~AS 

COMMITTEE ON NATURAL RESOURCES, 

U.S. HOUSE OF REPRESENTATIVES, 

WASHINGTON, DC. 

Committee on Natural Resources 

of the House of Representatives 

The Bonneville Power Administration Task Force has submitted the following 

report entitled BPA at a Crossroads, which is hereby made available to all 

members of the committee. This report summarizes the results of the most 

comprehensive congressional oversight of BPA since the passage of the Pacific 

Northwest Electric Power Planning and Conservation Act of 1980. 

I commend Representative DeFazio, Chair of the committee's Task Force on 

the Bonneville Power Administration, for his fine work on this report. 

Representative DeFazio's understanding of the extremely complex issues 

surrounding the Columbia River power system is unparalleled in the Congress. 

His understanding and insight may well be the key to resolving the many difficult 

challenges facing BPA and the Northwest region in the coming years. 

I am particularly impressed by the work that Representative DeFazio has done 

to uncover potential reductions in BPA costs and power rates that would not 

sacrifice BPA's commitment to energy efficiency and the conservation of the 

Northwest's wildlife resources. As Representative DeFazio's report points out, the 

energy efficiency and wildlife conservation programs have received 

disproportionate criticism over their costs, despite the fact that other areas of 

BPA's budget offer large savings potential. The Washington Public Power Supply 

I III) 
303 

IV 

System nuclear reactors are perhaps the best example of such possible budget 

savings. Better management of these facilities offers large potential savings that 

have received relatively little scrutiny. 

The report also finds that the "project power" rates for the Bureau of 

Reclamation's Columbia Basin Project reduce power costs to one-tenth of one cent 

per kilowatt hour of electricity, which is less than one twenty-eighth of the price 

paid by other BPA customers. This cut-rate price for power imposes considerable 

costs on the economy and environment of the Northwest by increasing the price 

other BPA customers pay for power and encouraging excessive use of water. 

Excess water use leads to diminished flows that not only impede the effort to 

restore salmon stocks but also reduce power generation. 

The recent work of the committee on ecosystem management is borne out by 

the Report's findings regarding the need to implement the basin-wide StraJegy for 

Salmon adopt~d by the Northwest Power Planning Council. These salmon 

conservation measures exemplify the need to look at activities across the ecosystem 

and involve all stakeholders in achieving a sustainable environmental and 

ecological status for the Northwest. 

Again, I praise Representative DeFazio for bringing these issues to the attention 

of the committee, and I look forward to working with him and other Members of 

the Pacific Northwest congressional delegation on these matters in the future. 

c· 

~R 

~ L 

Chair 
304 

11.6 . ._,ousr of 1\rprrsrntatibrs 

C:ommilttt on Jlatural !'.tsoums 

8afbin!llon. J)( 20515~201 

May 1994 

MEMORANDUM OF TRANSMITI AL 

-VIWittiOCI 

"""'-"Oio SUoM,n K-\1 

Cl ool""l C-lU 

....... '""""'l.ICAII'ST.,I-(TO """""'" R 

COMMITTEE ON NATURAL RESOURCES, 

U.S. HOUSE OF REPRESENTATIVES, 

WASHINGTON, DC. 

To the Honorable George Miller, Chainnan, 

Committee on Natural Resources 

of the House of Representatives 

I am formally submitting the original of the Bonneville Power Administration 

Task Force report entitled BPA at a Crossroads. 

Sincerely , 

~~ PETER DeFAZIO 

Chair 

Bonneville Power Administration Task Force 

(Y) 
305 

CONTENTS 

Memorandum of Transmittal to the Committee . . . . 

Memorandum of Transmittal from the Task Force 

List of Abbreviations . . . . . 

Task Force Chair's Summary .. .. . . . . . . . 

I. Introduction . . . . . . . . . . . . . . 

II. BPA's Competitiveness Project . 

A. Tiered Wholesale Power Rates 

B. Unbundling BPA Services ... 

C. BPA's Future Price Competitiveness 

D. The BPA "Hassle Factor" ... . 

E. Potential Loss of Market Share . ... .... . 

F. Other Competitiveness Issues .... . .... . 

I . Relationship to the Direct Service Industries 

2. Integrated Resource Planning .. .. ..... . 

3. Market Loss Potential and Extra-regional Power Sales 

G. Findings and Recommendations . . . . . . . . . . . . . . 

III. Restructuring BP A . . . . . . . 

A. Refinancing the BPA Debt . . ... . 

B. Government Corporation .. 

I. Accountability . . . . . . 

2. Environmental Responsibility 

3. Administrative Savings . . .. 

4 . Other Considerations 

C. Findings and Recommendations 

ll1 

v 

ix 

xi 

3 

3 

4 

5 

6 

7 

7 

7 

9 

9 

10 

15 

15 

16 

16 

16 

17 

17 

17 

IV. Cutting Costs-Cutting Rates . . . . 19 

A. Washington Public Power Supply System 19 

B. Irrigation Power Rates . . . . . . . . . . . . 21 

1. Bureau of Reclamation . . . . . . . . . . . . . . . . . . . . 21 

(vii) 
306 

viii 

2. Private Irrigation Discount 21 

C. Super Good Cents . . . . . . . . 22 

D. Findings and Recommendations 23 

V. Salmon Recovery . . . . . . . . . . . . 27 

A. Status of the Salmon . . . . . . . . . 27 

B. Salmon Recovery Mandates . . . . . 28 

1. Council Plan-the Strategy for Salmon . 29 

2. NMFS Endangered Species Act Mandates 32 

C. Agency Compliance with the Mandates 35 

1 . Bonneville Power Administration 35 

2. Corps of Engineers . . . 37 

3. Bureau of Reclamation . . . . . . 37 

D. Water Law Limitations . . . . . . . . . 38 

E. Agency Satisfaction of Indian Trust Responsibility 39 

F. Fish and Wildlife Programs in the Competitiveness Project 40 

G. Findings and Recommendations . . . . . . . . . . . . . . . . 40 

VI. Conclusion ... 45 

Index . . . . . . . . . . 47 
aMW 

BPA 

BuRec 

CBO 

cfs 

Council 

CRITFC 

CRS 

DSI 

EIS 

EPUD 

ESA 

FTE 

IRP 

kwh 

mills 

mW 

MW 

NCAC 

NMFS 

PF-rate 

PMA 

PNCA 

SOR 

VOR 

WAPA 

WPPSS 

307 

LIST OF ABBREVIATIONS 

Average megawatt 

Bonneville Power Administration 

Bureau of Reclamation , U.S. Department of the Interior 

Congressional Budget Office 

Cubic feet per second 

Northwest Power and Planning Council 

Columbia River Inter-Tribal Fish Commission 

Congressional Research Service, Library of Congress 

Direct service industries 

Environmental impact statement 

Emerald People's Utility District 

Endangered Species Act 

Full time equivalent 

Integrated resource plans 

Kilowatt-hour 

One-tenth of one cent or one one-thousandth of one U.S. dollar 

Milliwatt 

Megawatt 

Northwest Conservation Act Coalition 

National Marine Fisheries Service 

Priority firm rate 

Power Marketing Administrations 

Pacific Northwest Coordination Agreement 

System Operation Review 

Value of reserves 

Washington Area Power Administration 

Washington Public Power Supply System 

(ix) 
308 

TASK FORCE CHAIR'S SUMMARY 

The Bonneville Power Administration (BPA) supplies about one-half of 

all the energy consumed in the Pacific Northwest. It controls about 80 

percent of the region's high voltage transmission capacity. By any measure, 

BPA is central to the region 's economic well-being. 

BPA is at a pivotal point in its 57 -year history. The ground is shifting 

under the agency's feet , upsetting political and economic arrangements that 

have served the region since the passage of the Pacific Northwest Electric 

Power Planning and Conservation Act (Northwest Power Act) in 1980. 

The following are among the significant challenges facing the agency: 

~ Increasingly deregulated and competitive energy markets are prompting 

BPA to reexamine its structure and mission . The agency is considering, 

and in many cases moving to implement, major changes in its structure 

and the manner in which it seeks to fulfill its mandates. 

~ Threatened and endangered Snake River salmon runs, and the decline of 

other Columbia River stocks, pose an extraordinary challenge to the 

agency and the region. 

~ Continuing pressure from Washington, DC to alter fundamentally the 

financial compact between the Federal Government and BP A adds 

another degree of uncertainty to a world increasingly defined by 

uncertainty. 

The agency's last great shakeup occurred in the 1970s and early 1980s 

when the region bet heavily- and mistakenly- on nuclear power. The fallout 

from that series of bad decisions is reflected in every Northwest ratepayer's 

electric bill . 

· Between 1979 and 1984, BP A wholesale electric rates increased by 600 

percent. That whopping rate hike was the direct result of BPA's decision to 

invest in three nuclear power plants owned by the Washington Public Power 

Supply System (WPPSS). Between 15 and 25 percent of every Northwest 

residential electric bill is dedicated to paying for one ailing and two 

uncompleted nuclear power plants in the State of Washington. 

The Northwest Power Act, with its emphasis on comprehensive energy 

planning and regional resource development, grew out of the WPPSS fiasco. 

The Northwest Power Act created the Northwest Power Planning Council 

(Council), appointed by the Governors of the four States in the region-Idaho, 

Montana, Oregon, and Washington-and charged it with developing regional 

energy and fish and wildlife mitigation plans. Today, there are many who 

ask whether energy planning and regional resource development make sense 

in an increasingly competitive and deregulated energy market. 

The Northwest Power Act 's requirement to protect, mitigate , and enhance 

fish and wildlife populations affected by the hydroelectric facilities on the 

Columbia River system is also being challenged-though the challenges are 

more subtle. 

The BPA Task Force set out to answer some not-so-simple questions: 

How has the Northwest Power Act withstood the test of time? Is BP A doing 

a good job of implementing the Northwest Power Act's provisions? And how 

(xi) 
309 

xii 

can we continue to enjoy the benefits of regional planning and coordination 

in the brave new world of more open and competitive energy markets? 

This report's findings include the following: 

,. The Northwest Power Act sought to encourage conservation and 

efficient energy use and promote the development of renewable energy 

resources, thus assuring the Northwest an adequate, efficient, and 

economical supply of power. It requires BPA to protect, mitigate, and 

enhance the Columbia River basin's fish and wildlife populations and 

requires that fish and wildlife receive equitable treatment with respect to 

power production. The Northwest Power Act's goals remain sound. 

,. A more competitive BPA could better achieve the Northwest Power 

Act's goals. However, the region's long-term interest in promoting 

efficient energy use, developing renewable energy resources, and 

rebuilding the Columbia River basin's incomparable salmon stocks should 

not be sacrificed in order to minimize electric rates in the short term. 

,. A sigaificant factor driving many of BPA's utility customers to 

consider alternative energy sources is the BPA "hassle factor." BPA's 

customers are legitimately dissatisfied with BPA's bureaucratic processes 

and cumbersome decisionmaking . However, BPA's focus seems to have 

shifted largely to the issues of price, and away from the customers' 

concerns about unwieldy BPA processes. BPA should refocus its efforts 

on responding to its customers' legitimate concerns about BPA's 

bureaucratic tendencies. ,. BPA's conclusion that its rates are imminently uncompetitive is not 

supported by the analysis in its Draft Marketing Plan or by testimony 

presented during the task force's hearings. That is not to say, however, 

that BPA's interest in maintaining its competitive position is not prudent 

and appropriate. Rapidly changing energy markets could ultimately pose 

a significant threat and already offer alternatives to BPA-supplied power 

for some of BPA's utility customers. Therefore, BPA should make every 

effort to become a more efficient provider of conservation and energy 

resources while continuing to satisfy its statutory mandates. ,. The task force staff identified up to $150 million in achievable 

annual savings, most of which are not being prominently discussed by 

BPA as part of its Competitiveness Project. In addition, BPA has 

identified another $66 million in annual savings it could gain through 

greater administrative efficiency-without any new legislation. More than 

$50 million of the savings identified by the task force staff are associated 

with the WPPSS' three nuclear power plants, only one of which was ever 

completed. 

If all of these savings were achieved, they could lead to a BPA rate 

decrease of 8 percent. 

,. A tiered wholesale electric rate should be one element in BPA's 

conservation acquisition strategy. However a tiered rate-by itself-is 

not likely to provide an incentive sufficient to cause utilities to make 

substantial direct investments in conservation and energy-efficiency 

measures. ,. BP A must provide a stable, long-term financial commitment to 

conservation if the region expects to reach the energy-efficiency goals set 

out in the Council's Conservation and Electric Power Plan. The agency 

should not abandon direct investment in energy-efficiency measures, 

retreat from its fish and wildlife responsibilities, or decrease its 
310 

XU! 

commitment to improve delivery of services in favor of untried "market 

mechanisms" until those mechanisms are proven to be widely effective. 

~ BP A needs to conduct a comprehensive analysis of the economic 

costs and benefits to the Northwest of the region's aluminum industry, 

known as the direct service industries (DSis). Based upon this analysis, 

a new rate structure should be designed for the DSis that equitably 

balances the interests of the DSis and all other regional ratepayers. 

Furthermore, BPA must prepare for the very real possibility that some 

of the individual DSis may not survive the competitive challenges facing 

the industry in the near term. 

~ Those who benefit from the power provided by the Columbia River 

hydroelectric system bear a responsibility to further the efficiency goals 

of the Northwest Power Act. Therefore, BPA's public utility customers 

should be required to prepare integrated resource plans (IRPs). These 

plans should be consistent with regionally developed guidelines stressing 

long-term, least-cost approaches such as conservation and renewable 

energy resources. 

~ A properly structured proposal recreating BP A as a government 

corporation could be a benefit for BPA and the region. However, the 

Clinton Administration should proceed very cautiously in developing a 

proposal to convert BPA to a government corporation. No clear 

consensus supporting such a proposal emerged from hearings held by the 

Department of Energy and the Northwest Power Planning Council earlier 

this year. There are legitimate concerns that the "side effects" from the 

enactment of a government corporation bill could conceivably cause harm 

far in excess of any benefits that might result from the legislation. 

~ The goal of debt-restructuring legislation-to stabilize BPA rates and 

resolve the "repayment reform" controversy-is sound. The repayment 

issue should be resolved in a manner that will not lead to any significant 

increase in BPA electric rates. 

,. The Northwest must unite behind a single vision for salmon recovery 

if the purposes of the Northwest Power Act are to be achieved. To the 

exteni a regional consensus on salmon recovery exists, it is represented 

by the Northwest Power Planning Council's Strategy for Salmon 

(Strategy). The Strategy is a comprehensive plan for rebuilding healthy 

and genetically diverse anadromous fish populations throughout the basin. 

It is aimed not only at recovering listed stocks and making future listings 

unnecessary, but at producing harvestable numbers of fish for both Indian 

and non-Indian harvesters. The Strategy was developed within the region 

with strong public participation and merits the region's support. 

~ No matter what measures are proposed in any future Endangered 

Species Act (ESA) recovery plan or biological opinion governing 

operation of the Columbia River system, the BP A and other Federal 

agencies continue to bear a responsibility to implement the Strategy. The 

Strategy should not be delayed while ESA recovery plans are developed 

or National Marine Fisheries Service's (NMFS) biological opinions are 

litigated. The National Marine Fisheries Service should work closely 

with the Council to ensure that its proposed actions are consistent with 

the Strategy . 

~ The causes of salmon decline are numerous, although the 

development of the Columbia basin's hydroelectric system almost 

certainly represents the single most significant human-caused source of 
311 

xiv 

salmon mortality. Intuition as well as the available science argue that 

juvenile salmon need greater flows and river velocities during the 

migration period than those that prevail when the system is operated to 

maximize hydroelectric generation. Although a considerable degree of 

scientific uncertainty exists, it is imperative that the region act quickly 

and prudently to improve downstream passage conditions, relying on the 

best available science. 

~ The Army Corps of Engineers should use the money specifically 

appropriated for that purpose and begin design work on the necessary 

modifications to allow operation of John Day reservoir at minimum 

operating pool. Congress should provide the funding and direction 

necessary to expedite implementation of a John Day drawdown to 

minimum operating pool while providing mitigation to affected irrigators 

and others. 

~ As part of its effort to remain competitive, BPA should negotiate an 

agreement transferring its fish and wildlife functions to one or more fish 

and wildlife agencies. Such an agreement must be conditioned on 

thorough monitoring and evaluation of results, and tied to specific 

rebuilding targets, as well as a commitment on the part of the 

implementing entity to carry out fully the Council's Strategy. ~ A common theme heard during the task force's deliberations was the 

lack of coordination between Federal agencies, State fish and wildlife 

managers, and Indian tribes. The Chair of the task force recommends 

one of two approaches to improving regional coordination in salmonrecovery efforts. 

During the task force's September 24, 1993, hearing, the creation of 

a new regional entity responsible for basin planning and implementation 

was discussed. There may be merit in such an approach as long as the 

new planning effort: (1) incorporates existing plans and processes; (2) 

is not used as a pretext for delay in the implementation of the Strategy; 

(3) provides for full public participation; and ( 4) produces binding 

agreements that commit the participants to undertake the recommended 

measures. 

Alternatively, NMFS, working with the Council, BPA and other 

Federal, State, tribal and private interests, could seek to develop a basinwide conservation plan, using the Strategy as a framework. Such a plan 

should include rebuilding objectives and a timetable for implementation 

as well as a strong monitoring and adaptive management component. A 

basin-wide conservation plan, if fully implemented, could provide 

justification for the Secretary of Commerce to use his authority under 

§4(b) of the ESA to defer further ESA listings pending evaluation of the 

effectiveness of actions taken under the plan. 

~ The Federal agencies and the States should continue their efforts to 

reform water law so that conserved water may be dedicated to instream 

flows. The same logic that counts lost-generation opportunities caused 

by increased fish flows as lost revenues would consider water purchases 

for instream flows as an energy resource acquisition cost, not a fish and 

wildlife program cost. BPA should make this conceptual leap. 

Federal policies that discourage water conservation should be 

reformed. BPA should develop alternatives to its present practice of 

discounting power for irrigation uses, including new power-pricing 

methodologies that provide incentives for water conservation. 
312 

XV 

CONCLUSION 

The Bonneville Power Administration is at a crossroads. Decisions being 

made over the course of the next few years will have profound implications 

not only for BPA, but for the economy and culture of the Pacific Northwest. 

In the final analysis, the Bonneville Power Administration's first 

responsibility is not to serve its Federal masters, the Governors of the four 

States in the Pacific Northwest region, or its utility and non-utility customers' 

individual interests; it is to serve the people of the Pacific Northwest. 

Whether BP A makes choices in the next two to three years that best serve the 

long-term interests of the people of the region remains to be seen. 

The hearings held by the Bonneville Power Administration Task Force 

constitute what is arguably the most extensive congressional oversight of the 

BPA since the passage of the 1980 Northwest Power Act. Continuing 

informed congressional oversight is essential during this crucial period in 

SPA's history. 

Sincerely, 

PETER DEFAZIO, Chair 
313 

I. INTRODUCTION 

The Task Force on Bonneville Power Administration of the Committee 

on Natural Resources convened on April 28, 1993 . Over the following six 

months, the task force held five hearings on issues that will shape the future 

course of the Bonneville Power Administration. BPA has far-reaching 

responsibilities under the Pacific Northwest Electric Power Planning and 

Conservation Act' to meet the Pacific Northwest's electric power needs 

through sales of Federal power, while encouraging energy conservation and 

protecting, mitigating and enhancing regional fish and wildlife resources. All 

these purposes are to be met by BPA based upon recommendations of the 

Northwest Power Planning Council (Council), which was established under 

the Northwest Power Act to provide regional planning and participation in the 

Federal power system. 2 

The task force hearings were similarly wide-ranging. On April 28, the 

task force addressed BPA's FY 1994 budget, and its implications for BPA's 

near-term financial condition .

3 The second hearing, held in Portland , 

Oregon, reviewed BPA 's programs for power resources acquisition. 4 The 

task force's next field hearing was held in Boise, Idaho, to examine BP A's 

participation in salmon restoration efforts in the Columbia River basin. 5 The 

Task Force then traveled to Eugene, Oregon, to discuss SPA's plans to 

remain competitive in future power markets.

6 The final hearing addressed 

SPA's legislative proposals to allow the agency to buy out its Federal debt 

and to convert itself into a government corporation. 7 

Upon review of the transcripts of these hearings, and other materials 

submitted to the task force, the Chair of the Committee on Natural Resources 

1 P.L. 96-501 .94 Stat. 2697 . codified at 16 U.S.C . §§ 839-839h (hereinafter Nonhwest 

Power Act). 

2 Nonhwesl Power Act § 4, 16 U .S.C. § 839b. 

3 "BPA Proposed Fiscal Y~ r 1994 Budget," Oversight Hearing before the Task Force on 

Bonneville Power Administralion, Commiltee on Natural Resources. 103d Congress, 1st Session, 

Serial No. 103-20 Part I (April 28, 1993) (hereinafter Hearing Part 1). 

4 "BPA Electric Power Resources Acquisition," Oversight Hearing before the Task Force on Bonneville Power Administration. Committee on Natural Resources. 103d Congress, 1st 

Session, Serial No. 103-20 Part II (July 12 , 1993) (hereinafter Hearing Pan II). 

5 "BPA Columbia River Salmon Restoration," Oversight Hearing before the Task Force on 

Bonneville Power Administration, Committee on Natural Resources, 103d Congress, I st Session, 

Serial No . 103-20 Pan III (September 24, 1993) (hereinafter Hearing Part Ill). 

6 "BPA Competitiveness," Oversight Hearing before the Task Force on Bonneville Power 

Administration, Committee on Natu ral Resources, 103d Congress, I st Session, Serial No. 103-20 

Pan IV (Seplember 25, 1993) (hereinafter Hearing Pan IV). 

7 "BPA Proposals, " Oversight Hearing before the Task Force on Bonneville Power 

Administration, Committee on Natural Resources, 103d Congress, I st Session, Serial No. 103-20 

Pan V (October 28, 1993) (hereinafter Hearing Pan V). 

(l) 

79-568 0 - 94 - 2 
314 

2 

and the Chair of the task force concluded that a report bringing together the 

many disparate issues influencing the future of BP A, and providing guidance 

in directing the agency into the twenty-first century, could be a benefit to 

BPA and the Pacific Northwest. 
315 

II. BPA'S COMPETITIVENESS PROJECT 

BPA is considering far-reaching changes in its marketing strategies and 

structure in response to real and perceived threats to the agency's competitive 

position . BPA is concerned that electric industry deregulation and the 

narrowing gap between its wholesale electric power rates and the cost of 

power from natural gas combined-cycle combustion turbines could cause a 

critical mass of BPA's customers either to seek other energy suppliers or 

develop their own resources. Such an abandonment of the Federal power 

resource would erode BPA's revenue base and undermine its ability to carry 

out its statutory mandates. It would also place the burden of Treasury debt 

repayment, fish and wildlife costs, and other BPA obligations on a smaller 

pool of utility customers. 

Specifically, BPA's concerns are prompted by : the expansion of the 

Federal Energy Regulatory Commission's power to order wholesale wheeling; 

the growing interest on the part of some States in allowing and regulating 

retail wheeling; the increasing importance of independent power producers; 

and the decrease in the marginal cost of gas-fired generation. 1l is fair to say 

that the Nation's energy markets are undergoing significant change. It is also 

fair to say that the utility industry and BP A are uncertain about what the 

future holds. 

In November 1993, BPA released a Draft Strategic Marketing Plan, 

which provided the most detailed description to that date of changes BP A is 

considering as part of its Competitiveness Project. 8 Subsequently, the 

Council's staff completed an analysis of the Draft Strategic Marketing Plan. 

In February 1994, a Final Draft Strategic Marketing Plan was released. 

9 

Some of the changes BP A is proposing include designing and implementing a tiered wholesale electric power rate, "unbundling" its melded services, 

and generally becoming less bureaucratic and more responsive to its 

customers' needs. BPA plans to implement many of these changes between 

1994 and 1996. 

A. TIERED WHOLESALE POWER RATES 

BP A is engaged in discussions with its customers and other shareholders 

aimed at designing a tiered wholesale electric power rate. In its simplest 

form, a two-tiered rate would offer customers a first tier allocation consisting 

in whole or part of less expensive power generated by Federal base system 

resources, and a second tier priced to reflect the marginal cost of more 

expensive, new generating resources. By sending marginal cost price signals 

at the wholesale level, a tiered rate should encourage more efficient energy 

development and use. 

8 Bonneville Power Administration, Strategic Marketing Plan, Draft, November 1993. 

9 Bonneville Power Administration, Final Draft Strategic Marketing Plan, February 1994. 

(3) 
316 

4 

BPA considers a tiered rate to be a central element in its effort to "reinvent" its conservation program. The Final Draft Marketing Plan states that 

"[t]o the greatest extent possible, the conservation program will become a self 

supporting product line. "10 BPA believes that a tiered rate will prompt 

BPA's utility customers to make their own investments in conservation, 

relieving BPA of much of its liability for the direct acquisition of conservation resources. BPA's description of conservation as a product line, as well 

as discussions with BP A staff, suggests that BP A believes it can sell 

conservation services to its utility customers, or loan BPA customers the 

funds needed to purchase energy-efficiency measures as an alternative to new 

utility-sponsored generation. 

A properly designed tiered rate would force BPA customers to face the 

realities of the marketplace, i.e., the marginal cost of new resources, as they 

deal with load growth. However, the Council staff makes the point that in 

the absence of SPA-sponsored programs or incentives, a tiered rate would be 

unlikely to offer a sufficient incentive to cause utilities to invest in 

conservation as opposed to new generation.

11 BPA's analysis tends to 

support this view. In a February 1994 draft BPA document, BPA concludes 

that only about 40 aMW of a revised target of 608 aMW of conservation will 

result directly from implementing a tiered rate . 

12 

B. UNBUNDLING BPA SERVICES 

BPA now offers melded service packages to its various customer groups. 

Generally , these packages combine a number of discrete services into a single 

package at a single price. For example, BPA's firm power package for small 

customers includes transmission and shaping services, as well as transformation from network voltages to the customer's lower distribution voltage. 

The direct service industries-industrial customers that purchase power 

service directly from BPA without a utility intermediary-receive transmission 

services as well as a credit on their bills for the estimated value of certain 

portions of their contracted power that are deemed to be interruptible under 

some conditions. 

BPA is proposing to identify and market a range of individual services 

for its partial-requirements customers and others who may prefer to provide 

for some but not all of their own needs. For example, a customer with its 

own generating resources may wish to purchase shaping services or power 

reserves from BPA. Others may wish to wheel power over BPA-owned 

transmission lines. BPA believes that offering an array of unbundled services 

will allow it to better tailor its services to its customers' needs. It also 

believes that it may be able to offer higher-value services that could enable 

customers to use or develop their own resources more efficiently . 

The challenge for BP A will be to price ~hese unbundled products in a 

manner that avoids cross-subsidization between customer groups and services 

10 Bonneville Power Administration, Final Draft Strategic Marketing Plan, February 1994, 

p. 47 . 

11 "Bonneville Marketing Plan Issue Briefing," Northwest Power Planning Council staff 

paper, p. 10. 

12 Document titled "Bonneville Power Administration, Conservation Reinvention, February 

1994 (Draft)." 
317 

5 

and continues to promote regional least-cost energy resource development. 

Unbundled services, if appropriately priced, could help deter BPA customers 

from uneconomical development of new generation resources. 

In the worst case, however, unbundled services could facilitate 

uncoordinated and environmentally unsound resource development, imposing 

environmental and economic costs on the region as a whole at the same time 

that a tiered rate encourages utilities to look to suppliers other than BPA for 

their needs. It is not inconceivable that the combination of the two could 

serve to undermine the region's goals of coordinated and least-cost resource 

development. 

BPA asserts its intention to design and price unbundled services in a 

manner that will promote the goals of the Northwest Power Act. It is 

interesting to note, however, that on the one hand BPA argues that open 

transmission access is one of the most significant forces driving its 

competitiveness concerns, while on the other hand BPA contends that its 

ability to set the price of transmission and related services--i.e., its control 

over the transmission grid--will enable it to promote regional planning and 

resource development. 

C. BPA'S FUTURE PRICE COMPETITIVENESS 

BPA's Competitiveness Project is driven in large part by the agency 's 

concern that its wholesale electric power rates could soon be higher than the 

cost of competing energy resources. BPA's average priority firm (PF) rate 

is currently 26.8 mills for preference customers and 27.4 mills for residential 

exchange customers. BPA's PF-rate has declined in real terms since 1984. 

Even taking BPA's 1993 rate increase into account, BPA's current PF-rate 

is nearly 8 percent lower than the 1984 rate in real terms." 

Improvements in natural gas turbine technology and other changes in the 

market have substantially narrowed the gap between BPA's rates and the cost 

of gas-fired generation. The Tenaska Project, a gas-fired combustion turbine 

which is being acquired by BPA, is expected to provide power costing about 

38 mills in 1993 levelized dollars. about 41 percent higher than the current 

PF-rate. Recent bids to construct cogeneration plants seem to offer very 

attractive terms, though uncertainty about future gas price increases or 

possible energy or carbon taxes remains. 

For example, Clark public utility commissioners recently voted to begin 

final negotiations with a North Carolina-based company for construction of 

a 240 MW cogeneration plant whose estimated long-term costs, in 1994 

levelized dollars, are about 30.1 mills/kwh. 14 However, it should be noted 

that near-term costs for most generating projects are higher than the levelized 

costs and must be recovered through rates. 

The Draft Marketing Plan includes projections of BPA's PF-rate and 

compares them to the projected costs of power from a gas-fired combined 

cycle combustion turbine. The Draft Marketing Plan's analysis shows the gap 

between the two rates remaining more or less constant in the medium 

forecasts, with the PF-rate remaining 5-l 0 mills lower in real terms than the 

13 BPA Wholesale Power and Transmission Rate Projections and Historic Wholesale Power 

Rates. November 1993. 

14 Clearing Up. May 2, 1994, p. 8. 

84-374 0 - 94 - 11 
318 

6 

cost of gas-fired power. However, when comparing the high PF-rate 

projection with the low gas-cost projection, BPA's rates can be shown to be 

marginally uncompetitive in 10- 15 years. 15 

The November 1993 Draft Strategic Marketing Plan concludes that 

without dramatic changes, BPA's position as low-cost energy provider for the 

region is in "serious jeopardy. "16 However, BPA included in its high PFrate projection a number of costs that are not currently borne by the agency. 

For example, $200 million a year was added to represent uncertainties such 

as possible BPA debt repayment reform. Significant generation losses from 

the hydroelectric system arc assumed to account for contingencies such as 

increased fish flows. 

17 The Draft Marketing Plan also gives a projection of 

the PF-rate that includes a 5 mill "independence premium," in an attempt to 

quantify what BPA perceives as a widespread desire on the part of its utility 

customers to develop their own generating resources. 

On the other hand, there is no corresponding projection that attempts to 

quantify the risk that a BPA utility customer assumes when it invests in its 

own generation or signs a long-term contract for thermally generated power. 

Nor is any value assigned to the fact that BPA currently has virtually no 

exposure to the financial risks associated with possible limits or taxes on 

carbon dioxide emissions. The analysis also fails to include the costs of 

wheeling, shaping, and reserves in the projected costs of power from a gasfired combustion turbine . BPA estimates that wheeling costs alone could add 

as much as 10 percent to the cost of gas-fired generation. 18 

D. THE BPA "HASSLE FACTOR" 

During its hearings, the task force heard a considerable amount of 

testimony about what has become known as the "hassle factor" inherent in 

dealing with BPA. Customers almost uniformly complain that BPA is 

excessively bureaucratic, and that its decisionmaking processes are hopelessly 

complex. In response to its customers' concerns and the concerns of the 

Chair of the task force, BPA has taken steps to begin to address this problem, 

including a simplification of its negotiating process and a proposal to 

restructure the organization. 

An example of the BP A hassle factor can be found in Chairman 

DeFazio's congressional district. The Emerald People 's Utility District 

(EPUD) had to spend nearly 4 years negotiating a third-party financing 

agreement for its conservation power plant proposal. More than 50 BPA 

employees were involved in the multi-stage process. The hurdles to 

completion of a billing credits agreement for EPUD's Short Mt. methane 

generation project were equally daunting . 

15 Bonneville Power Administration, Final Draft Strategic Marketing Plan, February 1994, 

p. 38 . 

16 Bonneville Power Administration, Strategic Marketing Plan, Draft, November 1993, 

"BPA Competitiveness." p. I. 

17 Bonneville Power Administratio n, Final Draft Strategic Marketing Plan, February 1994, 

p. 38 . 

18 Ibid . 
319 

7 

BPA's focus in the Competitiveness Project seems to have drifted away 

from this central and pressing problem. That point is illustrated in BPA's 

Final Draft Marketing Plan. The "Strategic Marketing Thrusts" section of the 

marketing plan seeks "[t]he creation of customer satisfaction through process 

enhancements, rate stabilization and product choice. "19 

However, the discussion in that section highlights not the need to address 

the hassle factor, but the need to "minimiz[e] ... rate increases in the next 

six years." Only one sentence is given over to describing BPA's intention to 

"streamline its decisionmaking process and establish clear accountability." 

BPA's importance to the Pacific Northwest 's economy is ample reason 

for the agency to seek to minimize electric rate increases. But BPA's focus 

seems to have shifted too much toward rate issues- · many of which are highly 

speculative--and away from the more immediate and pressing customersatisfaction concerns. 

E. POTENTIAL LOSS OF MARKET SHARE 

The Final Draft Marketing Plan concludes that BPA is likely to lose 

1,400 aMW of load within ten years unless the Marketing Plan's 

recommendations arc implemented ."> The possibilities that the DSis and 

other cuswmers might purchase power from new suppliers, that some large 

industrial customers will develop t.heir own generation, and that sales in the 

Califo rni a market will decline , all contribute to the load-loss scenario 

described in the Draft Marketing Plan. The Draft Marketing Plan suggests 

that even greater load-losses are possible , including the potential loss of 1,450 

aMW from DSI closures and significantly greater losses due to other causes. 

F. OTHER COMPETITIVENESS ISSUES 

In addition to the issues evaluated in the agency 's Draft Marketing Plan, 

the majority staff has identified three other issues that BPA should address in 

evaluating the agency's current and future competitiveness in the power 

marketplace. 

1. Relmionship to the Direct Service Industries 

In addition to more traditional contracts with local utilities and 

government entities, BPA sells a significant amount of power to the DSls. 

The price that the DSis pay for BPA power is linked to the worldwide price 

of aluminum. BPA adopted this rate to increase the economic viability of the 

aluminum industry by lowering the DSis' electricity rate when aluminum 

prices were low <Uld increasing their rate when aluminum prices were high. 

BPA intends to keep the current variable rate in effect until June 1996. 

Aluminum prices have plummeted in recent years and have been near 

historical lows for almost two years. Consequently , the current DSI rate is 

about 2 1 mills, considerably lower than the 26.8 mills PF-rate paid by 

preference customers.

21 The Northwest Conservation Act Coalition (NCAC) 

estimates that at current world aluminum prices, the variable rate currently 

'

9 Final Draft Strategic Marketing Plan. p. 45 . 

20 lbtd ., p. 42 . 

ll Ms. Leslie Ratcheye . BPA Washington DC Office. telephone conversation with task force 

staff, January 1994. 
320 

8 

costs regional ratepayers about $11 million per month. 22 If world aluminum 

prices do not increru.e significantly, the DSI rate could cost regional 

ratepayers more than $300 million by June 1996.23 

It must be noted that there have been extended periods since the variable 

rate was adopted in 1986 when high aluminum prices raised the DSI rate 

higher than the PF-rate. Regional ratepayers and non-DSI utility customers 

benefitted from these additional revenues. However, according to the 

majority staff's estimate, the crossover point where revenues losses from the 

rate exceeded revenue gains was reached in 1993. 

Another special feature of the DSis' contracts is the curtailment 

provision. In the utility industry the willingness of a customer to agree to 

curtail the amount of power it receives is a service that has considerable 

economic value. In consideration of the DSis' agreement to curtail their use 

of power under certain circumstances, BPA has quantified the value of 

reserves (VOR) provided by the DSis. The rate they pay for power has been 

adjusted to factor in the value of this service. Consequently, if the value 

assigned to these reserves is lowered, then the rate that the DSis pay for 

power will increase. 

BPA has not recalculated the VOR since 1987 and has agreed to freeze 

the 1987 VOR value until 1996. NCAC and others contend that the 1987 

calculation is inaccurate and out-of-date since it is based in part on the cost 

of replacement power from a theoretical natural gas combustion turbine 

purchased at a prevailing interest rate of 14 percent and includes an 

overestimation of the amount of reserves actually provided by the DSis. 

NCAC estimates that the subsidy for overpayment of the VOR is about $40 

million per year.

24 

The question for the Northwest region is whether the regional economic 

benefits from the aluminum industry justify a continuation of the variable rate 

over the long term. The DSis are a major economic force. According to the 

DSis, they pay $550 million in wages each year. The DSis also provide 

important benefits to the Northwest's power system, including the provision 

of interruptible reserves and a significant demand for night-time load. At the 

same time, the low price the DSis pay for power and the overvaluation of the 

reserves they provide impose an economic cost on the region by increasing 

the electricity rates paid by all other BPA customers. For example, if 

aluminum prices are stable, the revenue loss to BPA in FY 1994 due to the 

variable rate will be approximately $132 million, which translates into a cost 

to non-DSI BPA ratepayers of about 5 percent of the price they pay for BPA 

22 Hearing Part IV, p. 192 (testimony of Mr. K.C. Golden, executive director, Northwest 

Conservation Act Coalition). 

23 See BPA chart "Variable Industrial Rate-Cumulative Simple VI vs. IP" prepared at the 

request of the task force staff, who asked BPA staff to calculate the difference between charging 

the DSis the VI rate and the IP rate paid by other industrial customers. BPA does not agree wtth 

these assumptions. 

24 Hearing Part IV, p. 123 (testimony of Mr. K.C. Golden). 
321 

9 

electricity. 25 However, as noted earlier, the variable rate has proven to be 

a benefit over part of its history. 

2. Inugrated Resource Planning 

In the Northwest Power Act, Congress recognized "the unique 

opportunity provided by the Federal Columbia River power system" as a 

means to encourage efficient energy use and the development of renewable 

resources in the Pacific Northwest. 26 These goals have been advanced by 

BPA's participation in regional energy planning and acquisition. 

The deregulation of the Nation's energy markets could, however, 

undermine the Northwest Power Act's goal of regional least-cost energy 

planning and development, particularly if BPA retreats from its role as a 

regional resource provider. This loss of efficiency could be overcome by 

bringing more efficient decisions into localized power acquisition. Least-cost 

planning, or integrated resource planning, by BPA's public utility customers 

would provide a mechanism to achieve such localized least-cost planning, 

preserving the regional commitment to least-cost solutions. 

The region's investor-owned utilities are required to prepare integrated 

resource plans. The Energy Policy Act of 1992 placed an IRP requirement 

on the public utility customers of the Western Area Power Administration 

(WAPA) 27 Due to the historically integrated nature of the Northwest's 

energy system and the planning requirements of the Northwest Power Act, 

BPA's public utility customers have not previously been required to engage 

in least-cost planning, though many already do so. 

3. Market Loss Potential and Extra-regional Power Sales 

The Regional Preference Act provides that BP A may sell outside the 

region only power that is surplus to the needs of the Pacific Northwest. Any 

contract to sell surplus power outside the region must include a call-back 

provision that allows the Administrator to suspend the sale of such power on 

60-days notice when necessary to serve the energy requirements of any 

Pacific Northwest customer. For the purposes of the Act, the Pacific 

Northwest is generally defined as "the reg10n consisting of the States of 

Oregon and Washington, the State of Montana west of the Continental Divide, 

and those portions of the States of Nevada, Utah and Wyoming within the 

Columbia drainage basin and of the State of Idaho as the Secretary may 

determine to be within the marketing area of the Federal Columbia River 

power system. "28 

25 Task force staff calculation: 

($11millionfmonth•)x(12months) =S.2B% 

($25million • •) 

* Council estimate of subsidy 

** Hardy estimate of I% rate of savings for each $25 million saved 

26 16 U.S.C. § 839. 

27 42 U.S.C. §§ 7275-7276(c) 

28 16 U.S.C. § 837(b). 
322 

10 

If the load-loss scenario described in the Draft Marketing Plan becomes 

a reality, it may be advantageous for BP A and the region to reexamine the 

requirements that apply to the sale of surplus power outside the region. If 

BPA's fears of a 1,400 aMW load-loss become a reality, and extra-regional 

markets for that power exist, BPA could realize significant additional 

revenues if it were able to sell the power under more favorable contract 

terms. Put another way, if BPA were able to market surplus power under 

more favorable terms, it should be able to sell the power for at least as much 

as it stands to lose due to the projected load-losses. 29 

G. FINDINGS AND RECOMMENDATIONS 

~ The Northwest Power Act sought to encourage conservation and 

efficient energy use and promote the development of renewable energy 

resources, thus assuring the Northwest an adequate, efficient and 

economical supply of power. The goals of the Northwest Power Act 

remain sound. In the final analysis, these goals are the yardstick by 

which BPA's new Marketing and Business Plans should be measured. 

A more competitive BPA could better achieve the Northwest Power Act's 

goals. However, the region's long-term interest in promoting efficient 

energy use, d.:veloping renewable energy resources, and rebuilding the 

Columbia River basin's incomparable salmon stocks should not be 

sacrificed solely in order to minimize electric rates in the short term. 

~ BPA's conclusion that its rates are imminently uncompetitive is not 

supported by the analysis in the Draft Marketing Plan or by testimony 

presented during the task force's hearings. That is not to say, however, 

that BPA's interest in maintaining its competitive position is not prudent 

and appropriate. BPA should make every effort to become a more 

efficient provider of conservation and energy resources, while continuing 

to satisfy its statutory mandates. 

However, the BPA Draft Marketing Plan's analysis seems to have 

been structured to arrive at a predetermined conclusion, i.e., that BPA's 

rates would soon be uncompetitive when compared to the costs of gasfired generation. The Council's analysis of the Draft Marketing Plan 

disagrees: "The examination of competitive cost issues in the marketing 

plan does not strongly support the conclusion that there is a current or 

likely problem ;.vith the competitiveness of BPA's rates for most of its 

customers. "30 

BPA's excessive public concern over its prospects may have the 

unintended consequence of encouraging individual utilities to make 

questionable resource decisions based on their mistaken perception of 

BPA's unreliability as a low-cost energy supplier. Alternatively, 

customers may be encouraged to threaten such actions in order to extract 

rate concessions, to the detriment of other stakeholders. In either event, 

greater institutional self-confidence at BPA would benefit the region. 

~ A significant factor driving many of BPA's utility customers to 

consider alternative energy sources is the BPA hassle factor. BPA's 

29 This assumes that an extra-regional market will exist for BPA power priced within the 

projected range of the PF-rate even in the face of substantial Northwest load losses. 

30 Northwest Power Planning Council. Bonneville Marketing Plan Issue Briefing. 
323 

11 

customers are immediately and legitimately dissatisfied with BPA's 

bureaucratic processes and cumbersome decisionmaking. However, 

BPA's focus seems to have shifted largely to the issue of price, and away 

from the customers' concerns about unwieldy BPA processes. BPA 

should refocus its efforts on responding to its customers' legitimate 

concerns about BPA's bureaucratic tendencies. 

~ A tiered rate should be one element in BPA's conservation 

acqutsltwn strategy . However, BPA has apparently concluded that 

continued regional investment in energy efficiency is inconsistent with a 

strategy emphasizing improved price signals and new conservation-based 

products and services. That conclusion should be rejected . Market 

signals and direct investment should be mutually reinforcing pans of a 

regionally integrated energy conservation program. 

~ There are many potential responses to a wholesale tiered rate's 

marginal price signal. One of them is direct utility investment in energyefficiency measures, which the Northwest Power Act seeks to promote. 

Other responses could include fuel switching, the curtailment of 

residential energy consumption in response to a retail tiered rate 

(sometimes referred to as "freezing in the dark"), or investments in new 

generation. Though some of these responses may be preferable to 

overbuilding new thermal generation capacity, they do not conform to the 

Northwest Power Act 's purposes, which are to promote efficient energy 

use and provide an adequate and economical supply of power. 

~ BPA should implement tiered wholesale electric power rates and 

offer certain unbundled services to better serve customer needs. But 

BPA should not abandon direct investment in energy-efficiency measures, 

retreat from its fish and wildlife responsibilities, or decrease its 

commitment to improving its delivery of services in favor of untried 

"market mechanisms" until those mechanisms have been proven to be 

widely effective. The Northwest Power Act's mandate that the 

Administrator "acquire" conservation resources remains in effect. 

~ BPA must maintain a stable, long-term commitment to conservation 

if the region expects to reach the energy-efficiency goals set out in the 

Council's Conservation and Electric Power Plan . In 1993, BPA achieved 

record conservation savings of 52 aMW at an average weighted cost of 

23 mills. Rather than abandon acquisition processes that are clearly 

working, BPA should build on its successes. 

Although BPA's conservation performance improved markedl y 

during 1993, the task force heard a considerable amount of testimony 

indicating that significant amounts of cost-effective conservation are not 

being acquired due to BPA budget constraints. 3' Slashing conservation 

budgets will only exacerbate the problem. 

However, greater decentralization of conservation acquisition would 

benefit BPA and the region , as long as it is combined with some level of 

regional support for local energy efficiency measures. As part of its 

continuing commitment to energy-efficiency, BPA should place particular 

emphasis on mechanisms that enable utility customers to develop their 

own conservation and renewable resources, consistent with the priorities 

31 Heanng Part II , p. 124 (testimony of Ms. Sue Hickey). 
324 

12 

of the Northwest Power Act, and in a manner that obviates the need for 

new BPA Treasury-borrowing authority. Such mechanisms could include 

long-term third-party financing agreements, billing credits, and the use 

of energy service companies. 

... BPA needs to work with the Council on a comprehensive analysis of 

the economic costs and benefits to the Northwest region of the current 

variable rate/value of reserve structure. Based upon this analysis, a new 

rate structure should be designed for the DSis that equitably balances the 

interests of the DS!s and all other regional ratepayers. The assumptions 

underlying the calculated value of reserves are clearly out-of-date and 

need to be revised . Furthermore, BPA must prepare for the very real 

possibility that some of the individual DSis may not survive the 

competitive challenges facing the industry in the near term. 

During new DSI power sales contract negotiations, BPA should 

examine the possibilities of increased interruptibility, shorter contract 

periods, and any other provisions that may be deemed to be necessary to 

protect BPA's ratepayers and non-DSI customers from the potential 

disruptions that sudden DSI load-loss may cause. 

... Those who benefit from the power provided by the Columbia River 

hydroelectric system bear a responsibility to further the efficiency goals 

of the Act. Therefore, BPA's public utility customers should be required 

to prepare integrated resource plans as a pre-condition to independent 

resource acquisition . The requirement could either be laid upon BPA's 

customers by legislative mandate or as an obligation in their power sales 

contracts. Technical assistance should be provided to smaller utilities that 

lack the resources to undertake an IRP exercise. 

The majority staff notes that the Council , in a letter to task force 

Chairman DeFazio, stated : 

"[1-l]embers of the Public Power Council are willing to accept a 

contractual obligation, if properly structured, to prepare and comply 

with an integrated resource plan as a condition for independent 

resource acquisition . The power sales contracts are currently being 

rewritten, affording a timely opportunity to develop and incorporate an 

IRP provision . "32 

BPA should commence discussions with its public utility customers, 

the Northwest Power Planning Council and other interested parties 

toward the development of regionally acceptable IRP guidelines. IRPs 

should promote the goals of the regional power plan. They should be 

developed in an open and public process. Mandatory penalties (such as 

a power surcharge) or the use of incentives (such as discounted costs of 

services) should be employed to enforce compliance with regionally 

developed IRP guidelines. It may be necessary to give the Council 

authority to make consistency determinations once the IRP requirements 

are incorporated into the power-sales contracts. 

If progress is not made toward the development of acceptable 

contract provisions, a legislative mandate should be placed on BPA's 

32 Lener from Mr. William K. Drummond to Chairman DeFazio, February 24, 1994. 
325 

13 

publicly owned utility customers, similar to the one placed on the 

Western Area Power Administration public utility customers in the 

Energy Policy Act of 1992. 

~ The discussion above of regional preference issues should not be 

construed as an endorsement of eliminating regional preference. To the 

contrary, regional preference provides significant benefits to BP A 

customers and their ratepayers. But a financially insolvent BPA cannot 

serve the region, fulfill its mandates under the Northwest Power Act, or 

satisfy its financial obligations to the U.S. Treasury. If regional 

preference entities effectively abandon BPA by signing long-term powerpurchase contracts with other suppliers, BPA's remaining customers will 

have a stake in allowing BPA to maximize revenues from extra-regional 

surplus-power sales. 
326 

Ill. RESTRUCTURING BP A 

Over the past year, two major proposals have emerged that could 

significantly alter BPA's relationship to the Federal Government: refinancing 

BPA's appropriated Treasury debt by allowing BPA to pay off the Federal 

investment in one lump sum using privately borrowed funds; and recreating 

BPA as a government corporation. Each of these proposals is intended to 

assist BPA in better meeting regional needs, with less interference by the 

Federal Government. However, each of these proposals as currently designed 

raises questions regarding BPA's accountability. 

A. REFINANCING THE BPA DEBT 

The budget proposals of three consecutive Presidents have contained debtrepayment reform proposals aimed at changing BPA's repayment obligation 

to the U.S. Treasury. Though different in scope and impact, each has 

proposed substantial increases in project interest rates and conversion to a 

fixed schedule of annual repayment. The last Bush Administration proposal 

would have cost Pacific Northwest ratepayers about $2.6 billion. 

The recurring threat of debt-repayment reform represents one of the most 

significant uncertainties facing BPA and its customers. Resolving this issue 

in a manner fair both to the ratepayers in the Northwest and the U.S. 

Treasury will better enable BPA to serve the region and continue to satisfy 

its obligations to the Treasury. 

The "Bonneville Power Administration Repayment Bonds Act" was 

included in the Clinton Administration "Reinventing Government" legislation 

(H .R. 3400). 33 As introduced, this legislation authorized BPA to borrow 

funds on the private market in order to make a single payment to the U.S. 

Treasury that would discharge all of BPA's obligations for appropriated 

Treasury debt. 

On October 28, 1993, the task force conducted a hearing on this 

legislative proposal. The language submitted by the Administration had a 

number of technical problems. The Congressional Budget Office (CBO) 

scored the BPA refinancing legislation as a budget "cost" due to the increased 

cost of borrowing from private markets as opposed to current Treasuryborrowing practices. Because of the budget cost found by CBO, the 

committee could only approve the BPA refinancing proposal if equivalent 

budget "savings" were found to offset these costs. In addition, a number of 

provisions included in the bill may have had potentially far-reaching, if 

unintended, effects. These concerns made it impracticable for the committee 

to act on the legislation. 

Unfortunately, the Chair of the task force was left with no choice but to 

request that the Committee on Natural Resources refrain from acting on the 

Administration proposal before the end of the committee's brief referral of 

l3 H .R. 3400, Part I, Subtitle C, Title IV. 

(15) 
327 

16 

H.R. 3400. The committee complied with this request and replaced the BPA 

refinancing provision with study language intended to serve as a placeholder 

for future efforts by the committee on the issue. The Chair of the task force 

and other members of the region's congressional delegation are continuing 

discussions with the Administration and parties in the region over a possible 

Treasury debt buy-out proposal. 

B. GOVERNMENT CORPORATION 

On December 17, 1993, BP A released a draft bill proposing to convert 

BPA to a government corporation. Both the Northwest Power Planning 

Council and the Department of Energy conducted public hearings to obtain 

comments on the draft bill. Many concerns were raised regarding the 

possible unintended consequences of such a change. 

I. Accountability 

Converting BP A into a government corporation could reduce the 

accountability of the agency to the citizens of the Northwest, its utility 

customers, the Northwest Power Planning Council, the executive branch, and 

the Congress. For example, the Council staff issue paper on the December 

17 draft bill states that the bill would remove BPA's budget entirely from the 

annual congressional appropriations process. Although there are significant 

drawbacks to being part of the appropriations/budget process, it remains a 

primary avenue of access for regional interests seeking review or modification 

of BPA policies. 

In addition, BPA already has more autonomy than the other Federal 

Power Marketing Administrations (PM As) because it is self-financing and has 

the authority to borrow funds directly from the Federal Treasury. Unlike the 

other PMAs, the agency can spend funds and incur most obligations without 

an annual appropriation, although certain planned expenditures-such as for 

major transmission lines and fish and wildlife facilities with a useful life 

greater than 15 years and a cost greater than $1 million-must be approved 

in an appropriations bill. 

2. Environmental Responsibility 

Another concern is the lack of a precedent for giving a government 

corporation environmental responsibilities, such as BPA's responsibility to 

help restore fish and wildlife resources in the Columbia River basin. Careful 

deliberation should be devoted to the issue of whether a corporate structure 

is best suited to carry out the environmental mandates of the Northwest Power 

Act. 

In this regard, it should be noted that when Congress recently converted 

the Department of Energy uranium enrichment complex into a government 

corporation in the Energy Policy Act of 1992 it did not assign the new 

government corporation responsibility for cleanup of past contamination of the 

enrichment complex. Congress withheld this environmental responsibility due 

to concerns that the cleanup duties would not be consistent with the profitmaximizing mission of a corporation. Instead, cleanup responsibility 

remained with the Federal Government, and a fee on nuclear electricity .was 

imposed to finance these costs. 

The draft incorporation legislation would also allow BP A to represent 

itself in legal proceedings. The result could be that in some proceedings, 

including those in which other agencies of the Federal Government are 
328 

17 

parties, BPA would not necessarily be required to take positions consistent 

with broader Federal policy. 

3. Administrative Savings 

BPA estimates that legislation making BPA a government corporation 

would allow BP A to reduce its permanent and contracted work force by a 

total of 1,000 full time equivalent (FTE) positions and save the agency 

$100 ,580,000 a year. BPA estimates that it could achieve savings of 

$66,310,000 and reduce its work force by 650 FTE positions in the absence 

of government corporation legislation. 34 The fiscal savings possible through 

legislation include greater flexibility in personnel and procurement practices, 

and a decrease in budgeting and reporting requirements BP A feels are a 

hindrance to its mission. 

4. Other Considerations 

The December 17 draft bill states that one of the purposes of the new 

corporation is "to operate as a commercial enterprise." The unanswered 

question is whether BPA could use its new corporate authorities along with 

its existing broad powers as a governmental entity to hinder competition. In 

addition, many of BPA's responsibilities, including its fish and wildlife 

obligations, could be considered to be of secondary importance to a 

"commercial enterprise." 

The draft legislation also creates a new exception to the Freedom of 

Information Act that would allow BPA to refuse to disclose any information 

it defines as "government commercial information." BPA has been criticized 

in the past for unnecessarily withholding information from the Council, 

Congress, and the public. In the task force's July 12, 1993, hearing, the 

Chair criticized BPA for failing to share with the Council information relating 

to natural-gas costs for the Tenaska natural gas combustion turbine. He also 

criticized the Council for approving the project without having reviewed the 

data being held in confidentiality by BPA.

35 As drafted, the Freedom of 

Information Act exception is overly broad , perhaps even unnecessary. 

Finally, in many instances throughout the draft, unspecified laws are 

made inapplicable to the corporation. This makes it very difficult for 

members of the public to understand the likely impacts of the legislation. 

C. FINDINGS AND RECOMMENDATIONS 

~ The goal of debt-restructuring legislation-to stabilize BPA rates and 

resolve the "repayment reform" controversy-is sound. The repayment 

issue should be resolved in a manner that will (1) provide long-term 

repayment certainty for BPA and its customers; (2) minimize near-term 

BPA rate impacts; and (3) not cause any increase in the Federal deficit 

as determined by the Congressional Budget Office. 

~ Despite failings by BPA, such as exceeding the annual borrowing 

limit recommended by the Appropriations Committees in the report 

accompanying the Fiscal Year 1993 Appropriations Act, the independence 

34 "Savings from BPA Incorporation vs. Existing Siruation and Administrative Action," 

Bonneville Power Administration memo. January 6, 1994. 

35 Hearing Part II, p. 111 . 

79-568 0 - 94 - 3 
329 

18 

the agency has under current law should be retained. BPA requires 

flexibility to meet its legal obligations. However, a conclusive case has 

not yet been made that even more independence is necessary or appropriate. 

~ A properly structured government corporation proposal could be a 

benefit for BPA and the region. However, the Administration should 

proceed very cautiously in developing a proposal to convert BP A to a 

government corporation. No clear consensus supporting such a proposal 

emerged from hearings held by the Department of Energy and the 

Council earlier this year. There are legitimate concerns that the "side 

effects" from the enactment of a government corporation bill could 

conceivably cause harm far in excess of any benefits that might result 

from the legislation. 

~ The December 17 draft corporation bill would give BPA new 

authorities that exceed those the agency identified as necessary to make 

itself more efficient and competitive. BPA must take care to draft any 

new version of the corporation bill narrowly, to achieve the goals of the 

legislation as represented by BPA and only those goals. Where the needs 

of a BPA corporation require an exemption from a Federal statute, the 

statute should be specifically identified. 

~ Discussion regarding the potential savings from the corporation 

should be kept in perspective in relation to savings that can be achieved 

without legislation. BP A has identified $66 million in annual savings that 

it has the authority to achieve now under current law. BP A and the 

Administration should aggressively pursue these savings as well as other 

savings identified in this report. According to BPA, $34 million in 

additional annual savings would result from corporate status. Of course, 

a corporation could also give BPA greater flexibility in meeting the 

demands of changing energy markets and customer concerns. It is 

difficult to place a value on the benefits such flexibility could provide. 

84-374 0 - 94 - 12 
330 

IV . CUTTING COSTS-CUTTING RATES 

BP A is currently experiencing severe financial pressures due to a wide 

variety of factors, including a serit:~ of extremely dry years, increased electric 

demand, low aluminum prices, 36 failure to increase rates in the past, and 

modifications of power operations to reduce harm to endangered salmon. As 

a consequence, BPA raised its rates about 14 percent in October 1993. 

As noted above, even this recent rate increase has not raised BPA's rates 

to their 1984 level in real terms. However, the rate increase has led BPA 

and many others concerned with regional power matters to embark on an 

effort to cut BPA costs and make BPA more "competitive." According to 

BPA Administrator Randy Hardy, every $25 million that BPA saves roughly 

translates into reducing electricity rates by 1 percentage pointY 

The majority staff has identified about $150 million in potential annual 

budget savings that do not compromise BPA's commitment to sound 

environmental stewardship. In a number of instances, these budget savings 

could also advance important Northwest Power Act goals such as encouraging 

more efficient use of regional water and power resources. BPA is properly 

considering many additional savings and efficiencies as part of its 

Competitiveness Project. 

A. WASHINGTON PUBLIC POWER SUPPLY SYSTEM 

Proponents of cutting BPA costs often- fail to focus on the fact that 

approximately 25 percent of BPA's budget is devoted to paying for debt 

service, operations, and "mothballing" of the three Washington Public Power 

System nuclear plants. The WPPSS fiasco occurred because BPA in effect 

agreed to pay for all of the costs of three nuclear plants built by WPPSS. 

Only one of these three plants has been completed (WNP-2) and it has a very 

poor operating record, though the plant's management has been able to 

substantially improve the plant's capacity during the last year. The other two 

(WNP- 1 and WNP-3) were never completed, but BPA continues to pay for 

the debt incurred on their construction and for the cost of mothballing them 

in case their power is ever needed. Between 1979 and 1983 BPA's priority 

firm electric power rate increased b(' about 600 percent in nominal terms, 

largely due to the costs of WPPSS.

3 

According to data provided by BPA and the Congressional Research 

Service (CRS), the costs of running the WPPSS WNP- 2 reactor are far 

higher than the nuclear industry average for similar plants. WPPSS costs are 

further increased by wasteful spending on mothballing the incomplete WNP- 1 

36 As discussed on p. 7 above, the DSI power rate is linked to the price of aluminum. 

37 Hearing Part I, p. 18 (testimony of Mr. Randall W. Hardy). 

38 Wholesale Power and Transmission Rate Projections and Historic Wholesale Power Rates 

1939-1992, Bonneville Power Administration, November 1993. 

(19) 
331 

20 

and WNP-3 rea.::tors. Despite the apparent inefficiencies in WNP-2 

operations, BPA has never formally disapproved any WNP-2 expenses. 

39 

CRS estimates that the average industry capital expenditure for reactors 

comparable to WNP-2 is ab0ut $23 million per year. 40 In 1993, WNP-2 

capital expenditures were almost $80 million. 

41 For FY 1994-1996 capital 

additions are budgeted at approximately $50 million per year, and for FY 

1997-2003 capital additions are estimated to be $35-$40 million. 42 Some 

of the 1993 costs were one-time only costs. 43 Nonetheless, if WNP-2 

capital expenditures were reduced to the industry average, annual savings of 

between $10 million and $25 million per year would result in FY 1995 and 

FY 1996. 

WPPSS currently has approximately I ,550 full-time staff for the WNP-2 

reactor. 44 CRS estimates that the average staffing for comparable reactors 

is I ,250 positions. 

45 The average annual cost per staffer at WNP-2 is 

$64,573. 4 Consequently, if WNP-2 staffing is brought down to the 

industry average, eliminating 300 extra positions, savings of about $20 

million per year would result. 

In April 1993, BPA initiated efforts to terminate WNP-1 and WNP-3; 

however, the WPPSS Board has yet to vote for termination. Thus, the 

continuing cost of mothballing the WNP-1 and WNP-3 reactors remains at 

about $10.5 million per year, half of which is paid from BPA revenues, the 

other half from the WNP-1 construction fund. 47 In addition to annual 

savings, termination of WNP-1 and WNP-3 would also yield one-time 

savings from the sale of as much as $100 million of reactor fuel that would 

no longer be needed. 48 

Because so much of the BPA budget is devoted to WPPSS, the majority 

staff has devoted considerable attention to identifying savings in this area. Of 

39 Hearing Pan I. p. 93 (supplement to.the statement of Mr. Randall W. Hardy). 

4

° Congressional Research Service. "Nuclear Power Plant Costs and Staffing," 

Memorandum to Committee on Natural Resources by Mark Holt, Specialist in Energy Policy, 

Environment and Natural Resources Policy Division, January 5, 1994 (hereinafter CRS January 

5 Memo). 

41 Hearing Pan I, p. 96 (supplement to statement of Mr. Randall W. Hardy). 

42 CRS January 5 Memo. 

43 According to BPA staff, $24 million of the $80 million was an investment in increased 

plant capacity . which BPA considers a resource acquisition cost. and $17 million is attributable to the settlement of a lawsuit between the WPPSS and General Electric. 

44 Congressional Research Service, "Additional WNP- 2 Cost and Staffing Information," 

Memorandum to Committee on Natural Resources by Mark Hoh, Specialist in Energy Policy. 

Environment and Natural Resources Division, January 24, 1994. 

45 Ibid . 

46 Ibid . 

47 Hearing Pan I. p. 92 (supplement to statement of Mr. Randall W. Hardy). 

48 Ibid. 
332 

21 

course, the fundamental mistake that BPA made many years ago to back these 

plants financially cannot be reversed, and the region will continue to live with 

the consequences for many decades. Nevertheless, considerable opportunities 

for savings do exist within WPPSS. 

B. IRRIGATION POWER RATES 

1. Bureau of Reclamation 

One of the largest consumers of federally generated hydropower in the 

Northwest is the Federal Bureau of Reclamation (BuRec), which uses the 

electricity to pump water through its irrigation distribution systems. BuRec 

estimates that it uses about 480 MW of hydropower for pumping. 49 The 

price that BuRec pays for power is passed on to its irrigation customers 

through operation and maintenance payments or a separate energy charge. 

The rate that BuRec pays for this power-and passes through to its 

customers-is generally set by the Secretary of the Interior under Reclamation 

law. The price BuRec pays varies depending upon the project; however, in 

all cases it is less than half the 26.8 mill priority firm rate paid by most BPA 

customers. 50 In fact, over two-thirds of the power consumed by BuRec is 

used in the Columbia Basin Project and is sold for 0.95 mills, less than one 

twenty-eighth of the 26.8 mill priority firm rate .

51 Charging BuRec the 

same rate for power that other BPA customers pay would raise approx:imateiy 

$32 million a year. 

Before the 600 percent BPA rate increase that resulted in the early 1980s 

from the WPPSS fiasco, the disparity between the electricity price paid by 

BuRec and the price paid by other BPA customers was not a major concern. 

But by 1994 this disparity has grown to the point where other regional power 

consumers find themselves paying the lion's share of the costs for BuRec 

power. 

In addition, the extremely low price for irrigation pumping electricity also 

encourages the increased use of water resources that might otherwise be used 

for power generation or other purposes. BPA has not quantified the amount 

of power generation lost due to BuRec's irrigation pumping discount. 

However, even if the low rate BuRec pays for power causes only a moderate 

increase in water use and consequent loss of power generation, considerable 

revenue is lost to the region . Finally, more efficient water use would also 

assist efforts to restore salmon runs. 

2. Private Irrigation Discount 

In addition to the extremely low price BuRec pays for power used for 

pumping purposes, BPA provides discounts to individual irrigators who use 

electricity for water pumping in their own irrigation distribution systems. 

BPA will forego a total $27.018 million in FY 1994 and FY 1995 due to the 

49 Mr. AI Bolin, Bureau of Reclamation, Boise Office, telephone conversation with task 

force staff, February 1994. 

50 Bureau of Reclamation, Boise Office, wrinen response to task force inquiry , February 

II, 1994 . 

5 1 Bureau of Reclamation, wrinen response to task force inquiry, February 9, 1994. 
333 

22 

irrigation discount. 52 In order to understand the magnitude of the water 

depletion attributable to irrigation withdrawals in the Columbia River basin, 

and the theoretical resulting lost power-generation opportunities, the task 

force asked BPA to provide an estimate of the amount of foregone revenue 

attributable to water withdrawals using discounted BPA-supplied power. 

BPA's estimate of lost power sale revenues attributable to irrigation 

withdrawals was $150- $300 million per year.

53 

Proponents of the irrigation discount argue that it helps increase energy 

consumption in the summer when other BPA loads are low and BPA needs 

to increase flows for fish purposes. This argument, however, ignores the fact 

that the value of this power to the region can be maximized through exchange 

agreements with Southwest utilities, in which BPA agrees to supply power to 

meet their peak summer loads in exchange for the Southwest utilities 

providing power to the Northwest to meet peak winter loads. Thus, by 

increasing electricity consumption for irrigation pumping, the discount in 

some cases prevents more valuable power exchanges. 

In addition, like the low rates that the Bureau of Reclamation pays for 

power, the irrigation discount may have the effect of increasing water use, or 

at the very least, offering no incentive for more efficient water use . Again, 

increased water use has a variety of negative impacts on the region, including 

diminishing hydroelectric production and increasing the cost and complexity 

of restoring salmon runs. 

It should be noted that BPA's Draft Marketing Plan assumes the 

elimination of the irrigation discount. 

C. SUPER GOOD CENTS 

BPA's "Super Good Cents " program provides a $2,500 payment toward 

the construction of energy-efficient all-electric homes. This payment is 

provided throughout the BPA service territory, including areas that are 

currently served by natural gas. According to BPA, between FY 1985 and 

FY 1992 it spent about $8.4 million on Super Good Cents subsidies for new 

construction in areas where gas is currently available.

54 BPA estimates that 

it will spend $3-$5 million per year on these payments from FY 1994 to FY 

1998. 55 

This has the effect of encouraging builders, who are economically 

compelled to minimize up-front construction costs, to install electric space and 

water heating systems in new homes, even when it would be more prudent to 

install gas systems. As a result, Super Good Cents discourages the use of 

natural gas for space and water heating in new homes constructed in the 

Northwest. This in tum stimulates new demand for electricity, which 

requires BPA to acquire costly new resources contrary to the energy 

conservation mandate of the Northwest Power Act. 

52 Hearing Part I, p. 88 (supplement to the statement of Mr. Randall W. Hardy). 

53 Hearing Part Ill, pp. 57- 58 (prepared statement of Mr. Randall W. Hardy). 

54 Hearing Part I, p. 99 (supplement to the statement of Mr. Randall W. Hardy). 

55 Ibid. 
334 

23 

Ironically, BP A intends to meet part of the increased demand for 

electricity in the Northwest by purchasing the output of the proposed Tenaska 

natural gas turbines. It must be noted that direct gas use in the horne 

produces about two times more energy than burning the same gas in a turbine 

to produce electricity that is subsequently used for space- or water-heating 

purposes. 

In defense of its practice of providing electric heating subsidies in areas 

served by natural gas, BPA claims that 2.0 MW of efficiencies would be lost 

in multifamily construction if the payments were canceled. 5

6 BPA neglects 

to mention, however, the cost savings that would result from the reduced 

demand for electricity if gas is utilized for heating purposes. It is also 

interesting that BP A does not claim that any electrical efficiencies would be 

lost from terminating Super Good Cents payments for single-family 

construction in areas currently served by natural gas. 

BP A asserts that market forces are sufficient to encourage appropriate 

fuel switching to natural gas, without considering the market barriers that 

exist to prevent customers from using gas. For example, according to the 

NCAC, a number of BPA's customer utilities require their customers that 

receive weatherization financing to agree not to convert to gas. This prompts 

NCAC to ask the following question, "If it is worth paying a customer $2,000 

to reduce their heating load on the electric system by 30 percent, through 

weatherization, why discourage that customer from reducing their heating 

load by 100 percent for the same price?" 57 

D. FINDINGS AND RECOMMENDATIONS 

As part of its "reinvention" effort, BPA has identified $66 million in 

annual administrative savings that it has the authority to accomplish under 

current law, without becoming a government corporation. These savings 

include personnel cuts, procurement changes and other reforms. However, 

current efforts to cut BPA costs could ultimately compromise important 

regional goals established by the Northwest Power Act, such as energy 

efficiency and the protection of fish and wildlife resources. 

What follows are budget savings that BPA could achieve that would 

produce approximately $150.5 million of savings per year starting in 1995 . 

BPA's proposed savings combined with the potential savings of up to $150.5 

million identified by the majority staff can significantly reduce BPA's costs 

and rates. BPA should move to implement as many of these savings as 

possible . 

Strongly Recommended Savings: 

.,.. WPPSS: Total Annual Savings-$55.5 million 

About $55 million in annual savings could be gained through 

improving the efficiency of WPPSS. If WNP-2 costs cannot be 

reduced-and safety improved- then BPA and the region should consider 

the option of permanently shutting down the reactor. At any rate, BPA 

must use the tools at its disposal to reduce wasteful spending at WPPSS. 

56 Ibid . 

57 Hea ri ng Pan II, p. 170 (attachment to prepared statement of Mr. K.C. Golden , 

Nonhwest Conservation Act Coalition). 
335 

24 

Legend 

D (a) Reduce WNP-2 Capital Expenditures 

• (b) WNP-2 Staff Reductions 

1111 (c) Reevaluate DSI Value of Reserves 

• (d) Redesign Private Irrigation Discount Rate Structure 

• (e) Recalculate BuRec Power Rate 

[:::J (f) Discontinue Super Good Cents Natural Gas Subsidy 

• (g) Terminate Mothballing WNP-1/ WNP-3 

Figure 1. Strongly Recommended and Other Potential Savings Totaling 

$150.5Million 

BPA should insist upon the following savings in WPPSS expenses: 

• WNP-2 Capital Expenditures: Annual Savings-$25 million 

It should be noted that the new manager of WPPSS, William 

Counsil, plans to reduce WNP-2 capital expenditures to below the 

industry average. BPA should hold him to his stated goal. 

• WNP-2 Staff: Annual Savings-$20 million 

BPA, and the region, can no longer afford to permit WPPSS to run 

a jobs program. Again, it should be noted that Mr. Counsil is attempting 

to reduce the size of the WNP-2 staff. 
336 

25 

• Terminate Mothballing: Annual Savings- $10.5 million 

Continuation of mothballing is unjustifiable. The practice should 

have been terminated years ago when it became apparent that completing 

WNP-1 and WNP-3 would be far more expensive than a wide range of 

other energy resources available in the Northwest. The recent closure of 

the Trojan reactor reinforces the conclusion that additional nuclear 

generation is not economically viable in the Pacific Northwest. 

Recently, WPPSS has announced that it is exploring the option of 

completing WNP-1, using a mixture of uranium and weapons grade 

plutonium to fuel both WNP-1 and WNP-2. The decision to end BPA 

funding of mothballing should not be delayed on account of this farfetched proposal, which may just be a tactic to delay the mothballing 

decision. 

If the WPPSS Board does not vote for termination by May 1994 as 

requested by Administrator Hardy, BPA should take a series of unilateral 

actions to force the WPPSS Board to agree to termination , including the 

following: 

disapproval of any proposed WPPSS budget that continues to 

preserve WNP-1 and WNP-3; and 

joining the Clark and Mason utilities as a party plaintiff in their 

suit supporting termination of WNP- 1 and WNP-3. 

BPA should also consider other steps, including filing a separate lawsuit 

barring WPPSS from using any Construction Fund money to pay for 

preservation and seeking State legislation to terminate WNP-1 and 

WNP-3. 

If BPA and WPPSS do not act as expeditiously as possible to 

terminate mothballing then it may be necessary for Congress to address 

the issue through legislation that would remove WNP-1 and WNP- 3 

from the Federal base system. 

" Super Good Cents Paymeflfs: Annual Savings-Up to $5 million 

BPA should stop making Super Good Cents payments in areas served 

by natural gas. At bottom, BPA 's reluctance to discontinue Super Good 

Cents payments in areas served by natural gas results from pressure by 

some of its utility customers to increase electricity demand and utility 

revenues. BPA can no longer afford to support this type of subsidy at 

the expense of regional ratepayers. 

Other Potential Savings: 

Along with the strongly recommended savings, the majority staff has 

identified certain costs to BPA associated with the lower wholesale rates 

offered to BPA's irrigation utility customers and the Bureau of Reclamation. 

Whether these subsidies should be discontinued or modified in order to 

provide incentives for greater water conservation is an open question , but one 

that should be addressed. For the purposes of comparison, this report 

includes the estimated savings from a complete elimination of the known 

irrigation subsidies. 

Another open question is the appropriate value of the DSI reserves. 

Though the reserves are clearly overvalued at present , the majority staff does 

not take a position as to their appropriate value. Again, for the purposes of 
337 

26 

comparison, this report uses figures provided during the task force 's hearings 

to estimate the savings that could be attained by recalculating the value of the 

DSI reserves. 

~ BuRec Power Rate: Annual Savings-$36.5 million 

The Secretary of the Interior should reevaluate the policies that have 

led to BuRec's paying less than 1 mill per kwh when most customers are 

paying ovet 26.8 mills. Minimally, the agency should seek to set rates 

that encourage energy and water conservation in the region. If 

necessary, the agency should consider seeking congressional authorization 

to do so. 

~ Private Irrigation Discount: Annual Savings-$13.5 million 

The discount for private irrigation pumping, which tends to 

encourage increased electricity and water use , also runs contrary to the 

Northwest Power Act's mandate to encourage efficient use of energy. At 

a time when BPA is considering establishing a tiered rate that will charge 

customers a higher rate as their consumption increases, the results will 

be undercut by the irrigation discount, which actually encourages 

increased consumption. It also makes little sense to perpetuate a rate 

structure that offers no incentive for water conservation when the region 

is trying to provide more water for fish flows. As noted, BPA plans to 

eliminate the irrigation discount as it is now structured . BPA should 

design a rate structure in its place that discourages excessive energy and 

water consumption and encourages new conservation efforts. 

More efficient water use would also translate into additional revenues 

for BPA from the sale of power generated by increased flows. 

~ Value of DS/ Reserves: Annual Savings-Up to $40 million . 

As mentioned on page 8, the value of the interruptible portions of the 

DSI loads is clearly out of date and should be reevaluated. The potential 

savings to BPA and its ratepayers range as high as $40 million. 
338 

V. SALMON RECOVERY 

The Northwest Power Act requires that the Columbia basin's fish and 

wildlife resources receive equitable treatment with respect to power 

production .

58 As with planning a strategy for meeting regional power 

demand into the next century, planning a strategy for restoring and 

maintaining Columbia basin salmon stocks into the next century must begin 

with regionwide participation and coordination under the Northwest Power 

Act. Although a regional fish and wildlife plan has been developed, efforts 

to implement that plan have been only partially successful. 

The task force's examination of this issue focused on the Slrategy for 

Salmon developed by the Northwest Power Planning Council 59 and efforts 

by BPA and others to carry out the Strategy. The plan's goal is "the doubling 

of the total number of adult salmon and steelhead in the Columbia basin as 

fast as possible without further loss of biological diversity among or within 

anadromous and resident fish populations. "60 The Endangered Species Act 

requires that these efforts be supplemented by the National Marine Fisheries 

Service's adoption of a recovery plan for ti10se salmon stocks listed as 

endangered or threatened under Federal law. 61 

A. STATUS OF THE SALMON 

Estimates of Columbia basin salmon runs predating European settlement 

range from 7.5-16 million.

62 Those stocks have now been reduced to fewer 

than 2.5 million, more than 70 percent of which come from hatcheries. 63 

58 Section 4{h)( II )(A)(i) of the Pac ific Northwest Electric Power Planning and Conservation 

Act requires that the BPA Administrator exercise his responsibilities in a manner that ''provides 

equitable treatment for ... fish and wildlife .... " Northwest Power Planning Act § 2, 16 

U S.C.§ 839. 

59 Northwest Power Planning Council, Strategy for Salmon, Yols. I & II, Doc. Nos. 92·21 

and 92·21 A (Octobe r 1992). 

60 Ibid ., sectio n 2.1A, Vol. II. p . 18. 

61 NMFS' Endangered Species Act responsibilities have given it a role in salmon restoration 

at three different stages: (I) listing individual salmon stocks as threatened or endangered species; 

(2 ) issuing "biological opinions" that determine whethe r proposed federal agency actions will 

"jeopardize" the survival of listed species; and (3) developing recovery plans for listed species. 

ESA §§ 4 , 7, 16 U.S.C. §§ 1533, 1536. 

61 Congressional Research Service , "Sa lmon in the Pac ific Northwest: Endangered Species 

Act Issue s," Issue Brief by Eugene H . Buck, Amy Abel, and Betsy Cody, Environment and 

Narural Resources Policy Division, p. I, April 5, 1993 . 

63 Ibid . 

(27) 
339 

28 

The major factors that have contributed to this depletion have been described 

as the "four Hs": 

• poor hatchery management; 

• fisheries harvest; 

• hydropower dam construction and operation; and 

• habitat degradation due to many activities in the watershed, 

including pollution, which reduce salmon health and survival, 

and water diversions for irrigated agriculture. 

Despite regional efforts to restore and maintain wild salmon stocks, 

NMFS listed the Snake River sockeye as "endangered" under the Federal 

Endangered Species Act in November 1991, followed by separate 

"threatened" listings for two Snake River chinook stocks in April 1992. 

During 1993, regional conservationists filed two additional petitions with 

NMFS, requesting ESA listing of three additional salmon stocks: (1) the 

mid-Columbia chinook populations; (2) the entire southern range of coho; 64 

and (3) steelhead populations throughout the basin. 

Further endangered species listings may well occur. In early 1992, the 

American Fisheries Society reported 214 separate native salmon stocks at risk 

in California, Washington, Oregon, and Idaho. 65 Since NMFS applies 

different standards from those used by the Fisheries Society to determine 

whether various salmon runs should be treated as separate species under the 

Endangered Species Act, the number of endangered species listings will be 

far lower than 214. Once a species is listed, however, NMFS may address 

the independent needs of the various populations of the species in developing 

a species recovery plan. 

Two potentially inconsistent goals have guided efforts to restore salmon 

populations: maintaining and increasing treaty and commercial salmon stocks 

for harvest and protecting and restoring naturally spawning salmon stocks. 

These goals are not inherently contradictory, but can become inconsistent 

when hatchery management and harvest practices targeted at the commercial 

stocks also damage wild runs. However, wild fish advocates argue that the 

hatchery stocks are doomed as well unless wild stocks are maintained to 

support genetic diversity in the hatcheries. 

B. SALMON RECOVERY MANDATES 

Regional efforts to restore salmon populations and maintain wild salmon 

stocks have centered around the measures recommended in the Strategy for 

Salmon. In the Columbia River mainstem, the principal responsibility for 

executing the plan rests with the BPA, but the other river management 

agencies, the U.S. Army Corps of Engineers (Corps) and Bureau of 

Reclamation, also play a role. The actions of these three river managers 

under the Council's plan are constrained by their separate duty to comply 

64 Coho salmon are largely extinct in the Columbia basin; but if the remaining stocks are 

listed, recovery effons could affect the Columbia River and cenainly would affect ocean fishery 

management. 

65 Willa Nelson, Jack E. Williams, and James A. Lichatowich, "Pacific Salmon at the 

Crossroads: Stocks at Risk from California, Oregon, Idaho, and Washington," Trout, Winter 

1992. p. 21. 
340 

29 

with the ESA as interpreted by NMFS . Other Federal agencies, such as the 

Forest Service and Bureau of Land Management, are also directed to take the 

Council's program into consideration when planning their management 

actions. 

I. Council Plan-the Strategy for Salmon 

Under the Northwest Power Act, the Council must develop a program: 

to protect, mitigate and enhance fish and wildlife affected by the 

development, operation, and management of [federal power] facilities while 

assuring the Pacific Northwest an adequate, efficient, economical , and 

reliable power supply .~ 

The Council has approached this challenging task in stages. The third 

phase of the Council's fish and wildlife program merged its earlier efforts 

into the comprehensive Strategy for Salmon. A fourth-phase plan addresses 

conservation of resident fish and wildlife. 

The Strategy for Salmon adopted two separate goals-to double the total 

salmon runs and to conserve existing diversity . Both of these goals are 

essential to the purposes of the Northwest Powe~ Act and to the full 

implementation of the Council's mandate . Although the mandates of the 

Endangered Species Act draw public focus to the plight of the weakest stocks, 

restoring harvestable stocks is also essential to the Northwest Power Act and 

to meeting treaty commitments to the basin's Indian tribes. 

The Strategy seeks improvements in salmon survival at every stage in the 

salmon's life cycle . The plan calls for the development of rebuilding targets 

for each run of naturally spawning salmonY It provides interim rebuilding 

targets for Snake River spring , summer, and fall chinook. 68 

Like most projects affecting salmon in the Northwest , the Strategy for 

Salmon has not gained universal endorsement. Certain commercial interests 

whose use of the Columbia River would be affected filed a lawsuit 

challenging the plan in Federal District Court; environmental advocates have 

joined the suit. The Strategy has been correctly criticized for its weakness in 

the areas of ocean survival and harvest. 69 

The Strategy for Salmon requires scores of individual actions by all the 

agencies acting in the Columbia basin to achieve the goal of doubling salmon 

populations without losing biological diversity . Two of the most controversial 

aspects of the Strategy have been measures affecting management of water 

and power; namely, increases in river velocity and salmon transportation. 

Two principal mechanisms are designated to increase river velocities for 

improved salmon passage : increased water flow and drawing down the level 

of reservoirs along the migration corridor. 

66 Northwest Power Act § 4(h)(5), 16 U.S.C. § 839b(h)(5). 

67 Ibid ., section 2.3, Vol. II, p. 2 1. 

68 Ihid ., section 2.2. Vol. II, p. 20. 

69 For example , see Hearing Part III, p. 44 (testimony of Mr. Randall W. Hardy). 
341 

30 

The Strategy makes a distinction between actions to improve mainstem 

survival that can be taken immediately and actions that will require more time 

to evaluate and implement. The plan states specifically that the immediate 

measures will not be sufficient to rebuild some weak stocks. 70 

The Strategy for Salmon specifies immediate actions to achieve a "flow 

equivalent" target of at least 85,000 cfs at Lower Granite from April 16 

through June 15 for Snake River spring migrants. 71 This level of water flow 

was met in 1993 operations, in part because BPA, the Corps, and NMFS had 

to meet targets set by NMFS under the ESA, discussed below. The Strategy 

also requires further flow augmentation to reduce water temperature for fall 

Snake River migrants and enhance flows in the Columbia as well. By 

contrast, the Columbia Basin Fish and Wildlife Authority has requested 

minimum flows between 100,000 and 140,000 cfs in all years in the Snake 

and between 220,000 and 300,000 cfs in the Columbia. 72 

As stated, the Council's plan recognizes that its immediate measures are 

not likely to be sufficient to rebuild salmon populations. As an additional 

means for improving water velocities, the Strategy for Salmon requires studies 

of the potential to lower the level of certain reservoirs to make the shape of 

the reservoirs more like the historic river during juvenile migration periods. 

There are two major parts of these drawdown recommendations. The first 

involves drawing down the level of the John Day reservoir on the lower 

Columbia River to minimum operating pool-the minimum level at which the 

John Day Dam was designed to operate. 73 The second would depend upon 

new studies of lowering four lower Snake River reservoirs, possibly below 

minimum operating pool, which would require dam modifications. 74 

These drawdown proposals have been quite controversial among many 

entities that rely upon commercial use of the reservoirs. At the task force 

hearing, utility representatives argued that there was insufficient evidence that 

drawdowns or increased river speeds would help the salmon. 75 An 

organization representing various commercial users of the river presented the 

irrigation utilities' argument that drawdowns would be the "least viable, least 

70 Strategy for Salmon, section 3, Vol. II., p. 23. 

71 Ibid., section 3.2, Vol. II, p. 25. The "flow equivalent" is a measure of water particle 

travel time, which may be met in part by lowering reservoirs levels instead of increasing water 

amounts passed down the river. 

72 Columbia Basin Fish and Wildlife Authority, "Proposed Floi''S for Columbia Basin 

Anadromous Fish," p. 9, March 1990. The Columbia Basin Fish and Wildlife Authority is 

composed of all the major fisheries agencies and Indian tribes in the Columbia basin. Although 

its original flow proposal was fairly brief, substantial technical justification was published in 

February 1991. 

73 Strategy for Salmon, section 3.6A, Vol. II, pp. 32-33. 

74 Ibid., section 3.5, Vol. II, pp. 30-32. 

75 Hearing Part III, p. 378 (prepared statement of Mr. Don Godard), pp. 461-462 (prepared 

statement of Mr. AI Wright), p. 475 (testimony of Mr. AI Wright), pp. 483-484 (testimony of 

Mr. Don Godard). 
342 

31 

cost-effective" mechanism for restoring salmon runs. 76 An Idaho grain 

elevator operator argued that drawdowns would be costly and unnecessary 77 

By now, the studies and implementation of the drawdown plans have been 

delayed many years past the deadlines set in the Strategy. 

The Strategy for Salmon acknowledges the degree of scientific uncertainty 

surrounding reservoir drawdowns, and establishes a process to monitor and 

evaluate the effectiveness of the measures taken in a manner that adds to 

scientific understanding and, ultimately, salmon recovery . Specifically, the 

Strategy for Salmon calls for reservoir drawdowns for the lower Snake River, 

unless such drawdowns are shown to be structurally or economically 

infeasible or biologically imprudent. 78 

The Strategy also requires that measures necessary to operate the John 

Day reservoir at minimum operating pool from May I to August 31 be 

evaluated and implemented while providing mitigation for the impacts of 

operating the reservoir below the minimum irrigation pool. 79 The Council 

estimates that a John Day drawdown would reduce water particle travel time 

between McNary and Bonneville Dams by one to two days, which represents 

a decrease of about 10 percent. To achieve the same reduction in travel time 

from increased flows would require about 3.1 million acre-feet of water from 

upstream storage. 80 A John Day drawdown would benefit not only listed 

Snake River salmon stocks, but a;so mid-Columbia summer chinook now 

petitioned for listing. 

In 1993 , Congress appropriated $2 million for Advanced Planning and 

Design of modifications to public and private facilitie£ that would be affected 

by a drawdown. The Corps has barely begun design work. The Corps 

estimates that at its present rate of progress, it will be 1999 before a John 

Day draw down can be implemented. 81 

Another controversial feature of the Strategy for Salmon is the provision 

for juvenile salmon "transportation," which involves collecting salmon smolts 

at each of the Lower Snake River dams and barging them downstream to the 

Columbia River estuary . The effectiveness of this practice has been the 

subject of substantial dispute. Competing scientific studies suggest on the one 

hand that most of the smolts survive the trip and on the other hand that , 

although the voyage in artificial containers does not kill many hatchery fish , 

it has a much greater impact on wild salmon. In addition, survival to the 

estuary may not be the full measure of success for transportation ; some argue 

?h !hid .. p. 342 ~r s accompanying prepared statement of Mr. Bruce Lovelin), 

p. 330 (prepared statement of Mr. Bruce Lo velin), p. 473 (testimony of Mr. Bruce Lovelin). 

77 !hid .. pp. 509-510 (testimony of Mr. Joe St~gner). 

78 Strait'!:.\' for Salmon. sec tion 3.5, Vo l. II. p. 30. 

70 !hid .. section 3.1iA, Vo l. II. pp . 32·33. 

1\il !hid .. p. 428 (mate rials accompanying prepared statement of Mr. Jim Baker). 

81 Hearing Pan Ill , p. 293 (testimony of MaJ. Gen . Ernest J. Harrell). 
343 

32 

that the smolts have high mortality after release from the barges and may not 

receive the imprinting necessary for adult return to their native streams. 82 

Despite the regional consensus represented by development of the 

Council's plan, the Northwest Power Act does not require that Federal 

agencies adhere to the Council's fish and wildlife program. Instead, it 

requires that Federal agencies operating power facilities on the Columbia 

River "tak[e] into account at each relevant stage of decisionmaking processes 

to the fullest extent practicable, the program adopted by the Council .... " 

In addition, BPA is to use its financial resources and authorities "in a manner 

consistent with the plan." There has been much dispute over whether the 

agencies have met these standards. 83 

If the Council finds BPA's actions inadequate, it may make a formal 

Council determination of inconsistency with the plan. A Council finding of 

inconsistency would trigger a series of actions under the Northwest Power 

Act. 84 Again, this statutory process ends with a judgment made by the BPA 

Administrator, rather than the Council, regarding consistency with the 

Council's plan and Federal law. The threat of an inconsistency finding in 

mid-1993 led to productive negotiations between BPA and the Council over 

the content of BPA's fish and wildlife program. 

2. NMFS Endangered Species Act Mandates 

NMFS's efforts on behalf of salmon are focused on those naturally 

spawning salmon stocks listed or proposed for listing as threatened or 

endangered. Since the 1991 and 1992 listings of Snake River stocks, the 

agency has reviewed annual plans of operations for the river and begun to 

develop a recovery plan for those stocks. 

As part of its statutory obligation to review whether agency activities will 

jeopardize listed species, NMFS has been heavily involved in the development 

of annual plans of operations for the reservoirs developed by BPA, the Corps, 

and BuRec. The 1992 and 1993 operating plans and biological opinions were 

challenged in court by several fishing and environmental groups. The State 

of Idaho filed a separate suit over the 1993 biological opinion. The State of 

Oregon joined Idaho in its challenge. 

Environmentalists' attempts to obtain a court order to stop barging of 

salmon smolts in 1993 were unsuccessful. A recent decision on the States' 

suit in federal court, however, overturned the 1993 biological opinion, which 

formed the basis for a' biological opinion on 1994-1998 operations as well. 

82 Ibid., pp. 398-939, 403 (materials accompanying prepared statement of Mr. Jim Baker). 

83 Contrast Ibid., pp. 45-47 (prepared statement of Mr. Randall W. Hardy) and p. 159 

(prepared statement of Maj. Gen. Ernest J. Harrell) with Ibid., pp. 365-367 (prepared statement 

of Mr. Ed Chaney), pp. 384-385, 393 (prepared statement of Mr. Jim Baker), pp. 597-598 

(additional material submitted by Mr. Lionel Q. Boyer), and pp. 658-659 (additional material 

submitted by Columbia River Inter-Tribal Fish Commission (CRITFC)). CRITFC represents 

four tribes living in the Columbia River basin: the Umatilla, Warm Springs, Yakama, and Nez 

Perce Tribes. Ibid., p. 288. 

84 Northwest Power Planning Act§ 4(j), 16 U.S.C. § 839b(j). 
344 

33 

The judge found that NMFS's 1993 finding of "no jeopardy" to the 

endangered and threatened stocks was based on an analytical process that 

. . . is too heavily geared towards the status quo that has allowed all forms 

of river activity to proceed in a deficit situation-that is, relatively small 

steps, minor improvements and adjustments-when the situation literally 

cries out for a major overhaul. Instead of looking for what can be done to 

protect the species from jeopardy, NMFS and the action agencies have 

narrowly focused their attention on what the establishment is capable of 

handling with minimal disruption. 85 

The court remanded the biological opinion to NMFS for revision; further 

proceedings to bring the biological opinion on river operations into 

compliance with the ESA will continue over the next weeks and months. 

The 1993 biological opinion was arrived at in negotiation with the Corps 

and led to the adoption of the following targets for both spring and summer 

flows, in addition to other management practices: 86 

Lower Snake River 85,000 cfs 

(at Lower Granite Dam) 50,000 cfs 

Columbia River 

(at McNary Dam) 

200,000 cfs 

160,000 cfs 

Time Period 

April 10 - June 20 

June 21 -July 31 

April 20 - June 30 

July 1 - July 31 

The decision to require the summer flow meant that less of the 10.4 million 

acre-foot "water budget" stored for fish could be used in the spring, but 

substantial spring rainfall in the Snake River basin helped the agencies to 

meet these targets. One part of the biological opinion that caused some 

concern among fish advocates was designating these flows as "targets" rather 

than required minimums. But in fact , the flow targets were generally met. 

NMFS recently issued a biological opinion finding that river operations 

over the next five years, 1994-1998, will not jeopardize the listed species of 

Snake River salmonY This opinion evaluates an operations plan again 

developed by BPA, the Corps, and BuRec in consultation with NMFS. The 

flow targets remain the same, but varying amounts of additional water will 

be devoted to the flow augmentation "water budget" depending on water 

conditions each year. In addition, BP A will undertake to acquire more water 

for flow augmentation over the next five years. ESA consultation may be reinitiated if the agencies are unable to meet the flow requirements or the water 

85 Idaho Department ofFish and Game vs. National Marine Fisheries Service, Civ . No. 92-

973 -MA, slip op. at 36 (D. Ore . March 28 . 1994). 

86 Corps of Engi neers, "Record of Decision, Columbia and Snake River Flow Improvement 

Measures for Salmon, Supplemental Environmental Impact Statement, Plan of Reservoir 

Regulation and Project Operations." pp. 16-17 . June 18, 1993. 

87 National Marine Fisheries Service, biological opinion, March 16, 1994. 
345 

34 

budgets prove inadequate due to drought. 88 The biological opmton also 

directs the Corps to design a biological test of a Lower Granite reservoir 

drawdown by January 1, 1995. Since this 1994- 1998 biological opinion was 

based on the same analysis as the 1993 opinion, it will presumably be 

modified as well in light of the recent court order. 

Each of NMFS's biological opinions regarding river operations has led 

to controversy, in part because the ESA consultation process has been 

conducted among the agencies in private with minimal public involvement. 

For example, the first public notice of the alternative under consideration for 

operations over the next five years was the issuance of a draft biological 

opinion allowing just seven days for technical review and comment . And 

under the ESA regulations, this notice and opportunity for comment was 

provided only to State and tribal governments. But, as noted by the court in 

the recent decision overturning NMFS 's 1993 biological opinion, "the 

underlying root of the litigation problem is the feeling of these parties that the 

Federal Government is simply not listening to them. "89 

NMFS does claim to "encourage and consider any information 

volunteered by the public in its decision process. "

90 In response to 

Chairman DeFazio's inquiry regarding this lack of public participation, 

NMFS acknowledged that there is no statutory or regulatory provision 

forbidding public involvement. 91 Rather, the ESA is silent on this issue 

while it requires public notice and comment for certain other activities related 

to endangered species. 

NMFS suggests public participation in the process of developing a 

biological opinion would be "unwieldy. "92 NMFS also argues that such 

participation is less essential, since the biological opinion is not the product 

of policy debate, but rather scientific inquiry; the decision on final action by 

the consulting agency after issuance of the biological opinion is the 

appropriate point for public comment on policy. 

93 This analysis disregards 

the practical process that takes place in developing a biological opinion and 

the potential benefits of public input. In a situation where NMFS is working 

actively with the river operating agencies to develop an alternative plan of 

operations that will not jeopardize the species, public comment-even 

constrained by short statutory time frames-might well suggest creative and 

valuable alternatives, or bring to the attention of agency scientists information 

regarding the potential impacts of a given alternative. The seven-day 

comment period provided for technical review by State and tribal 

governments might have been more useful if proposed alternatives had been 

suggested and public comments obtained in advance. 

88 Ibid . 

89 Idaho Department of Fish and Game vs. National Marine Fisheries Service, slip op. at 

34-35. 

90 Hearing Part III, p. 282 (prepared statement of Mr. J. Gary Smith). 

91 Ibid .. pp. 302-306 (inse rt to testimony of Mr. J. Gary Smith). 

92 Ibid .. p. 304. 

93 Ibid .• pp. 302-303. 
346 

35 

In fact, NMFS has tried seeking public comment more extensively in the 

development of a recovery plan for the listed species. A team of outside 

analysts convened by NMFS to develop a recommendation for a recovery 

plan for the three listed Snake River stocks has received public comment on 

its draft recommendations. Final recommendations for a recovery plan will 

be issued later this year; NMFS will then review the recommendations and 

adopt a final recovery plan. 

Unfortunately, the ESA does not require that measures be taken to 

achieve species recovery in fact after a "recovery plan" is adopted. This gap 

in the statutory scheme means :hat once the recovery plan is developed there 

is no guarantee that it will be followed. Agencies need not implement its 

recommendations. They may take any actions that a NMFS biological 

opinion determines will not place the species in "jeopardy." Agency actions 

would be limited only occasionally by NMFS opinions that actions will 

actually place the species in jeopardy of final extinction. Without any 

mandate for actual recovery, the ESA raises the prospect of salmon stocks 

constantly sustained on the brink of extinction. 

C. AGENCY COMPLIANCE WITH THE MANDATES 

Under the Northwest Power Act, BPA is the primary entity responsible 

for implementing the fish and wildlife program developed by the Council. 

The cost of the program is repaid by power sales. BPA Administrator Hardy 

testified that "virtually all" of 117 separate salmon-related actions identified 

in the Strategy for Salmon have been funded by the agency. 94 However, 

timetables for many of these actions, including major activities like reservoir 

draw down studies, have slipped substantially. 

1. Bonneville Power Administration 

According to BPA figures, the cost of the fish and wildlife program has 

risen from $150 million in 1991 to $300 million in 1993 95 These figures 

include $149 million in 1993 for foregone power production, which rose in 

cost over the last few years as water flows for fish increased and as regional 

drought raised the amount of BPA's power purchases and also the cost of 

each kilowatt-hour purchased. 96 Thus, much of BPA's cost resulting from 

reduced flows due to drought has been attributed to salmon recovery. This 

accounting is inconsistent with BPA's budget treatment of other constraints 

on flows available for hydropower production; for example, as mentioned, 

irrigation withdrawals reduce water flows that might produce $150-$300 

million worth of annual power production, yet irrigation withdrawals are not 

treated as an annual expense by BPA. 

BPA's administration of the fish and wildlife program has been criticized 

by both power users and environmental advocates. BPA's customers, 

conducting a "function-by-function review" of BPA's programs, presented 

draft recommendations to streamline and possibly restructure the 

94 Ibid., p. 45 (prepared statement of Mr. Randall W. Hardy). 

95 Ibid .. pp. 19. 28-29 (testimony and prepared statement of Mr. Randall W. Hardy). BPA 

estimates that the 1994-1998 biological opinion will boost annual fish and wildlife costs to $350 

million. 

96 Ibid .. pp. 19, 28-30, 40-41 (testimony and prepared statement of Mr. Randall W. Hardy). 
347 

36 

administration of the fish and wildlife program. 97 Environmental advocates 

have argued that BP A commits excessive program resources to activities that 

are better implemented by fish and wildlife specialist agencies and that BPA 

has failed to implement all of the actions required by the Strategy for Salmon 

on the schedule set by the Council. 98 

The Columbia River Inter-Tribal Fish Commission and some private 

entities have recommended that BPA's fish and wildlife programs be 

transferred en bloc to the Fish and Wildlife Service, NMFS, or some 

combined group of fishery management agencies. In Administrator Hardy's 

written and oral testimony at the Bonneville Power Administration Task 

Force's September 24 hearing, he indicated a willingness to consider a lump 

sum transfer of fish and wildlife funds to one or more fish and wildlife 

agencies. 

99 

A lump sum transfer could allow BPA to substantially reduce its fish and 

wildlife staffing level , which now stands at 77 FTE positions. Many of 

BPA's critics complain that the BPA's fish and wildlife program is at best 

redundant and, in some cases, operates at cross purposes with other Federal, 

State, and tribal fish and wildlife agencies. 

BPA has adopted an analogous approach to funding its responsibility to 

implement the Council 's resident fish and wildlife program. BPA has signed 

resident fish and wildlife trust agreements satisfying its responsibilities to the 

States of Idaho and Montana . Those agreements provide long-term mitigation 

for projects in those States while indemnifying BPA against further claims. 

The agency has signed an interim funding agreement with the State of 

Washington, worth $43 million and has provided the State of Oregon with 

$150,000 to fund its efforts to negotiate a resident fish and wildlife trust 

agreement. 100 

Apart from financing issues, BP A's implementation of flow augmentation 

for fish came under particular criticism in 1992, when the agency used water 

provided by Idaho water users only to move fish to barge collection sites at 

Lower Granite reservoir. From Lower Granite on, water intended to enhance 

flows for the length of the river downstream was offset by reduced flows 

from the Upper Columbia , whose water was held for power production 

instead. 

BPA Administrator Hardy explained that the agency felt the flows were 

unnecessary in the Columbia because most of the endangered salmon smolts 

from the Snake River were presumed to be in barges by the Columbia reach 

of the river. 101 However, water is necessary in the Lower Columbia River 

to transport fish coming from the Columbia River watershed as well as any 

other smolts that have avoided the collection facilities in the Snake. In 

97 "A Functional Review of Fish and Wildlife in the BPA," Draft Review Team Report, Octobe r 13, 1993 . 

98 Hearing Part III, pp. 368 and 372 (prepared statement of Mr. Ed Chaney), pp. 384-85 

(prepared statement of Mr. Jim Baker). 

99 Ibid ., pp. 68-69 (prepared statement of Mr. Randall W. Hardy). 

100 Hearing Part III, p. 140 (testimony of Mr. Randall W. Hardy). 

101 Ibid ., p. 152 (te stimony of Mr. Randall W. Hardy). 
348 

37 

addition, this reasoning leads to the contradictory result noted by Chairman 

DeFazio, 

We have got to barge salmon because there are not enough flows and then 

we do not have flows because we have got barges. It is hard for people to 

understand , mere mortals like me and I think some of the farmers; it is a 

little counter-intuitive. 102 

2. Corps of Engineers 

The COJl>S of Engineers, not BPA, took the lead in developing the 

1994-1998 river operation plan currently under consultation with NMFS. 

The CoJl>S is also the lead agency for two long-term studies, the System 

Operation Review (SOR), and the System Configuration Study . 

The System Configuration Study will evaluate various changes in the 

Columbia River system that might require new construction by the CoJl>S. 

These include the Strategy for Salmon's recommended drawdowns of the John 

Day reservoir below minimum irrigation pool and drawdowns of the lower 

Snake River reservoirs below minimum operating pool. The CoJl>s' timetable 

for this analysis requires ten years before drawdown tests on the lower Snake 

are complete, salmon survival is analyzed, and a decision is made . A "Phase 

I" report on the study is scheduled for completion in spring of 1994, with 

drawdown testing in 1996. 103 The System Configuration Study also 

includes the possible construction of new salmon collection facilities to aid in 

barging smolts. As discussed above, the COJl>S has accelerated studies on the 

John Day drawdown, anticipating that the modifications might be completed 

as early as 1999. 

The SOR, which incoJl>orates some of the study questions recommended 

in the Strategy for Salmon, 1114 is a separate study of hydropower operations 

in the Columbia River hydropower system taking into account the needs of 

the salmon. The SOR will produce an environmental impact statement (EIS) 

with options for new procedures to set hydropower operations, as well as new 

terms for the Pacific Northwest Coordination Agreement (PNCA), which 

expires in 1998. 105 The PNCA is a contract that determines how 

hydropower operations will be coordinated among Federal and non-Federal 

entities to guarantee, among other things, that the power production terms of 

the Columbia River Treaty with Canada are met. 

3. Bureau of Reclamation 

Despite the Council's recommendation that the Federal agencies explore 

alternatives for increasing water quantities available for salmon in the 

Columbia basin, 106 non-power-producing reservoirs of the Bureau of 

102 Ibid ., p. 153. 

103 Ibid ., p. 293 (supplemental information included in testimony of Maj. Gen . Ernest J. 

Harrell). 

104 Strategy for Salmon. section 3.60, Vol. II, p. 34. 

105 Hearing Part III. pp. 159-160 (prepared statement of Maj. Gen. Ernest J. Harrell). 

106 Strategy for Salmon, section 3.6C, Volume II, pp. 33-34. 
349 

38 

Reclamation have been excluded from the SOR studies. BuRec Assistant 

Regional Director Kenneth Pedde asserted that incorporating these BuRec 

reservoirs into the study could delay the outcome of the SOR by 3-4 years, 

although the possible availability of BuRec water has been modeled using a 

hypothetical 15th reservoir in the studies. 107 The Corps also has mentioned 

that salmon needs would be protected as non-power uses which take priority 

under the terms of the PNCA. 

BuRec's major role in the Columbia River system is to store and divert 

water for irrigation, but its Grand Coulee and Hungry Horse Dams also 

produce hydropower sold through BPA. BuRec has played a substantial role 

in obtaining additional water for salmon flows. The agency is working on 

model water conservation programs in the Grande Ronde River basin and the 

Yakima River basin . Unfortunately, water conservation efforts are to some 

extent undercut by BPA's prices for irrigation pumping power. In addition, 

as discussed in section D below, illegal water use and limitations of State 

water law have limited BuRec's effectiveness. 

D. WATER LAW LIMITATIONS 

Acquiring additional water to assist in moving juvenile salmon 

downstream is a major theme of the Strategy for Salmon , as well as NMFS 's 

biological opinions under the ESA . BuRec has been able to assist in this 

effort because not all BuRec water has been contracted for, and significant 

water conservation savings can be obtained from BuRec customers in the 

Northwest. One area in which BuRec has directly moved to carry out the 

Strategy's recommendations is in developing new conservation demonstration 

projects providing Federal money toward improved water conservation in the 

region. 

However, BuRec's efforts to obtain water in the Snake River basin for 

out-of-state use have been stymied somewhat by restrictions in Idaho water 

law. 108 In addition , illegal "water spreading" -applications of irrigation 

water outside project boundaries or on land deemed unsuitable for 

irrigation- has prevented some conserved water from returning to the river 

system. 

Idaho State law makes it very difficult to provide permanent protection 

for water used for fish. The Idaho Natural Resources Board may obtain 

permanent water rights for instream flows, or an existing water user may 

transfer its water to instream use, but several further standards constrain 

water that will flow out of the State. These standards make it virtually 

impossible to protect such water; a 1991 BuRec attempt to change the nature 

of use of its existing storage water rights to instream flow rights for salmon 

recovery encountered more than 650 letters of protest to the State water 

board. 

Annual water rentals through Idaho water banks can provide water for 

salmon from year-to-year. Again, State law makes it difficult to obtain such 

rentals, and water bank rules discourage users from transferring water to 

107 Hearing Part III. pp. 590-591 (testimony of Mr. Kennelh R. Pedde). 

108 Water conservation measures in the 1980s reduced irrigation diversions by 800,000 acre- feet, bur none of that water was transferred to flows for fish. Hearing Part III, p. 578 (prepared statement of Ms. Garrison). 
350 

39 

instream use. 109 The State legislature passed a special three-year exemption 

for BuRec to provide out-of-state flows from rented water through January 

I, 1995 1 10 This law requires only that the flows be part of an overall 

augmentation plan , and that other parties make a proportional contribution to 

salmon restoration. The BPA decision to offset Snake River flows by 

reducing flows from the Upper Columbia in 1992 led to allegations that 

BuRec's flows violated the provisions of the three-year exemption law. 

On top of the State disincentives to transfer water to instream flows, 

Federal involvement in irrigation often undercuts BuRec's efforts to obtain 

water for salmon flows. BPA's reduced rate for irrigation pumping 

(discussed above on page 21) lowers the cost of irrigating and thus provides 

a disincentive to water conservation. In addition, BuRec has known for years 

that irrigation districts have illegally applied water to lands lying outside the 

approved scope of the Reclamation projects, yet has only recently convened 

a task force to address this practice. And BuRec has in the past been quite 

lax in enforcing the water conservation requirements of the Reclamation 

Reform Act of 1982, although new water conservation regulations are 

currently being drafted . As the region continues to look for ways to provide 

fish flows in the rivers, reform of these Federal policies could supply some 

of the needed water. 

E. AGENCY SATISFACTION OF INDIAN TRUST RESPONSIBILITY 

The Indian tribes of the Pacific Northwest region are among those most 

concerned with salmon recovery activities due to their historic dependence on 

salmon fisheries and their treaty rights to continued access to those fisheries. 

Since the Federal Government has a general trust responsibility to the tribes 

in addition to these specific treaty obligations, the Federal agencies must take 

tribal concerns into account in decisionmaking regarding the salmon. 

Unfortunately , the tribes have found the agencies' decision processes 

unresponsive and have remained some of the most vocal critics of BPA and 

other Federal entities in the Northwest. A petition by the Shoshone-Bannock 

Tribes led to the listing of the threatened and endangered stocks in the Snake 

River. 

The tribes' criticism of ~almon recovery efforts begins with the Strategy 

for Salmon . The Yakama Tribe has sued the Council over the adequacy of 

the plan, arguing that it meets the requirements of politics but not those of 

science.

111 Both the Columbia River Inter-Tribal Fish Commission and the 

Shoshone-Bannock Tribes told the task force that tribal concerns were 

inadequately addressed because of lack of tribal membership on or an intergovernmental relationship with the Council. 112 (Even NMFS supported 

adding tribal representation to the Council, which would require amending the 

Northwest Power Act. 113) 

109 Ibid ., p. 579 (prepared statement of Ms. Garrison). 

110 Idaho Code § 42-1763A. 

111 Hearing Part Ill, p. 288 (testimony of Mr. Anthony Van Pelt). 

112 Ibid .. pp. 602 (additional material submined by Mr. Lionel Q. Boyer), 657. and 660 

(additional material submiued by CRJTFC). 

113 Hearing Part lll, p. 283 (prepared statement of J. Gary Smith). 
351 

40 

In addition, the tribes have been highly critical of Federal agency efforts 

to restore salmon stocks, particularly the efforts of BPA. They feel they have 

been left out of important decisionmaking erocesses, even where the Strategy 

for Salmon mandates their involvement.' 4 They expressed doubt that the 

agencies managing Columbia basin resources were even aware of the 

existence of their trust responsibility to the tribes. 115 

The lack of attention to tribal concerns is unfortunate also because Indian 

water rights could contribute to the solution to the problem of protecting 

water flows for fish . The Nez Perce Tribe has intervened in an Idaho State 

court adjudication of water rights on the Snake River, claiming a right to the 

water necessary to sustain salmon to meet their treaty fishing rights, with a 

mid-1800s priority date set by the treaties. If upheld by the court, this claim 

could provide the legal basis for maintaining adequate flows for Snake River 

stock. 

F. FISH AND WILDLIFE PROGRAMS IN THE 

COMPETITIVENESS PROJECT 

BPA has proposed tying fish and wildlife program spending to the 

agency's fiscal success.

116 One stated purpose is to give fish -protection 

advocates some stake in BPA's financial well-being. BPA also hopes to g:J.in 

greater planning certainty by setting a "floor" for fish and wilulife 

expenditures that would only be exceeded during periods in which BPA is 

financially successful. 

Since BPA's actual outlays for fish and wildlife expenses and capital 

outlays amounted to $82 .5 million in 1993,

117 the potential for real savings 

through "incentivization" of the fish and wildlife program is probably small. 

In addition, BPA's statutory fish and wildlife responsibilities do not somehow 

evaporate during bad water years or other financially difficult periods. 

G. FINDINGS AND RECOMMENDATIONS 

~ The Northwest must unite behind a single vision for salmon recovery 

if the purposes of the Northwest Power Act are to be achieved. To the 

extent a regional consensus on s:;~lmon recovery exists, it is represented 

by the Council's Strategy for Salmon. The Strategy is a comprehensive 

plan for rebuilding healthy and genetically diverse anadromous fish 

populations throughout the basin. It is aimed not only at recovering listed 

stocks and making future listings unnecessary, but also at producing 

harvestable numbers of fish for both Indian and non-Indian harvesters. 

The Strategy for Salmon was developed within the region with strong 

public participation. 

114 Ibid .. p. 289 (testimony of Mr. Anthony Van Pelt). pp. 597-598 (additional material 

submitted by Mr. Lionel Q. Boyer). 

115 Ibid ., p. 604 (additional material submitted by Mr. Lionel Q. Boye r), p. 662 (additional 

material submitted by CRITFC). 

116 Hearing Part III, pp. 20-2 1 ( testimony of Mr. Randall W. Hardy). Also see Final Draft 

Strategic Marketing Plan, February 1994 at p. 48 . 

117 About one-half of BPA "s estimated $300 million fish and wildlife budget consists of "losses" attributed to foregone powe r sales and resulting power purchases: see Hearing Part III. 

p. 29 (testimony of Mr. Randall W. Hardy). 
352 

41 

~ There has been considerable interest in the actions proposed to 

recover Snake River salmon stocks listed under the Endangered Species 

Act. However, the focus on listed stocks could detract from the 

fundamental purposes of the Northwest Power Act and the Strategy for 

Salmon, which seek basin-wide recovery of all affected fish and wildlife 

populations. Whatever the outcome of NMFS's ongoing efforts to 

protect and recover threatened and endangered species under the 

Endangered Species Act, those efforts should not compromise the 

implementation of an overall regional plan under the authority of the 

Council. 

Notwithstanding the measures proposed in any future ESA recovery 

plan or biological opinion governing operation of the Columbia River 

system, BP A and other Federal agencies continue to bear a responsibility 

to implement the Strategy. The Strategy for Salmon should not be 

delayed while ESA recovery plans are developed or NMFS's biological 

opinions are litigated. NMFS should work closely with the Council to 

ensure that its proposed actions are consistent with the Strategy for 

Salmon. 

On the other hand, the four States in the region should avoid 

undermining the regional consensus as they pursue their own parochial 

interests. The Council has been and should continue to be the forum for 

resolving regional conflicts. 

~ The Strategy for Salmon has suffered from uneven implementation 

and uncertain funding, with some significant actions falling well behind 

schedule. One theme sounded by many witnesses was the need for 

accountability for fish and wildlife mitigation measures. 118 

The rebuilding targets called for in the Strategy for Salmon are the 

standard that must be used to evaluate salmon recovery efforts. It will 

be difficult, if not impossible, to judge the effectiveness of individual 

actions taken under the Strategy until these objectives are determined. 

State and tribal fish managers, working with the Council, should quickly 

complete the development of rebuilding targets for individual naturally 

spawning salmon runs within the Columbia basin. 

~ The causes of salmon decline are numerous, although the 

development of the Columbia basin's hydroelectric system almost 

certainly represents the single most significant human-caused source of 

salmon mortality. Intuition as well as the available science argue that 

juvenile salmon need greater flows and river velocities during the 

migration period than those that prevail when the system is operated to 

maximize hydroelectric generation. 

Though a considerable degree of scientific uncertainty exists, it is 

imperative that the region act quickly and prudently to improve 

downstream passage conditions relying on the best available science. To 

that end, the Strategy for Salmon calls for both immediate and longerterm measures to decrease downstream travel times through a 

combination of increased storage for flows and reservoir drawdowns. 

Without pre-judging the outcome of the Lower Granite Dam test now 

being designed and fully understanding the difficulty of designing and 

118 For example. see Hearing Part lll. p. 44 (testimony of Mr. Randall W. Hardy) or p. 457 (testimony of Mr.. AI Wright). 
353 

42 

conducting a meaningful experiment under minimally controllable 

circumstances, the Corps should move aggressively to design and conduct 

a meaningful biological test. The decline of Snake River salmon stocks 

represents a biological emergency that demands prompt action. Sufficient 

staff and funding should be allocated to ensure that this effort proceeds 

in a timely manner. 

• The Corps is proceeding at what can only be described as a glacial 

pace in its efforts to evaluate and design measures to mitigate operation 

of John Day reservoir at minimum operating pool. The Corps should 

begin design work on the necessary modifications immediately, using the 

money specifically appropriated for that purpose. Congress should 

provide tht: funding and direction necessary to expedite implementation 

of a John Day drawdown to minimum operating pool while providing full 

mitigation to affected irrigators. 

• As part of its effort to remain competitive, BPA should negotiate an 

agreement transferring its fish and wildlife functions to one or more fish 

and wildlife agencies. Such an agreement must be conditioned on 

thorough monitoring and evaluation of results, tied to specific rebuilding 

targets, as well as a commitment on the part of the implementing entity 

to fully carry out the Council's Strategy for Salmon . BPA, in turn, 

would reasonably expect that such an agreement would hold the 

implementing agency or agencies accountable for results, perhaps through 

the use of independent audits, and provide a significant degree of 

planning certainty over a specific period of time . 

Administrator Hardy, in his testimony before the task force, 

indicated a willingness, if not an eagerness, to begin discussions toward 

a lump sum transfer of many of its fish and wildlife responsibilities. 

However, no such discussions have commenced between BPA, any other 

Federal entities, and the Council. 

• Another common theme heard during the task force's deliberations 

was the lack of coordination between Federal agencies, State fish and 

wildlife managers, and tribes. Since the demise of the Northwest River 

Basins Commission in 1981, there has been no single entity responsible 

for developing a comprehensive basin plan and coordinating the 

implementation of that plan. 

During the task force's September 24, 1993 hearing, the creation of 

a new regional entity responsible for basin planning and implementation 

was discussed. There may be merit in such an approach as long as the 

new planning effort: (1) incorporates existing plans and processes; (2) 

is not used as a pretext for delay in the implementation of the Strategy for 

Salmon; (3) provides for full public participation; and (4) produces 

binding agreements that commit the participants to undertake the 

recommended measures. 

Alternatively, NMFS, working with the Council, BPA, and other 

Federal, State, tribal, and private interests, could seek to develop a basinwide conservation plan, using the Strategy for Salmon as a framework . 

Such a plan should include rebuilding objectives and a timetable for 

implementation, as well as a strong monitoring and adaptive management 

component. A basin-wide conservation plan, if fully implemented, could 

provide justification for the Secretary of Commerce to use his authority 

under §4(b) of the ESA to defer further ESA listings pending evaluation 

of the effectiveness of actions taken under the plan. 
354 

43 

.,. The Federal agencies and the States should continue their efforts to 

reform water law so that conserved water may be dedicated to instream 

flows. The same logic that counts lost-generation opportunities caused 

by increased fish flows as lost revenues would consider water purchases 

for instream flows as an energy resource acquisition cost, not a fish and 

wildlife program cost. BPA should consider making this conceptual leap. 

Federal policies that discourage water conservation should be 

reformed. BPA should develop alternatives to its present practice of 

discounting power for irrigation uses, including new power-pricing 

methodologies that provide incentives for water conservation . 

.,. BPA and the State of Oregon should begin negotiations on a longterm resident fish and wildlife trust agreement. In the interest of equity, 

BPA should consider an interim funding agreement with the State of 

Oregon, similar to its agreement with the State of Washington . 

.,. Federal efforts to restore salmon stocks have not always given 

sufficient deference to the Federal trust responsibility to Indian tribes in 

the region or to Indian treaty rights. The Federal agencies should 

redouble their efforts to involve the Indian tribes at all levels of 

decisionmaking on management of the Federal water system. Impacts on 

traditional hunting and fishing rights should be an essential part of the 

analysis of all Federal activities. In addition, Federal agencies, the 

Council, and the States should recognize the tribes' status as separate 

governments within the Northwest region . 

.,. In the interest of open government, as well as greater public 

understanding of the tradeoffs inherent in balancing scientific uncertainty 

against social and economic interests, the National Marine Fisheries 

Service and other Federal agencies should explore options aimed at opening Endangered Species Act consultations to public scrutiny , if not 

public participation . 

.,. Though there may be some merit in allowing BP A a greater degree 

of flexibility in determining its fish and wildlife program spending levels 

(or "incentivizing" its fish and wildlife program, as proposed in the Final 

Draft Marketing Plan), it must be recognized that in the final analysis 

BPA is not a utility; it is a public agency with a mandate from the public. 

The Northwest Power Act's conservation and fish and wildlife 

mandates are at the very core of BPA's mission. They distinguish BPA 

as a steward of the Columbia River's fish and energy resources and as 

a power supplier committed to providing affordable energy to the people 

of the region at the lowest long-term cost. Fulfilling that mission more 

effectively and efficiently should be the primary aim of BPA's Competitiveness Project. 
355 

VI. CONCLUSION 

The Bonneville Power Administration is at a crossroads. The agency is 

considering, and in many cases moving to implement, major changes in its 

structure and the manner in which it seeks to fulfill its mandates. Decisions 

being made over the course of the next few years will have profound 

implications not only for BPA, but also for the economy and culture of the 

Pacific Northwest. 

In the final analysis, the Bonneville Power Administration's first 

responsibility is not to serve its Federal masters, the Governors of the four 

States in the Pacific Northwest region, or its utility and non-utility customers' 

individual interests; it is to serve the people of the Pacific Northwest. 

Whether BP A makes choices in the next two to three years that best serve the 

long-term interests of the people of the region remains to be seen. 

The hearings held by the Bonneville Power Administration Task Force 

constitute what is arguably the most extensive congressional oversight of the 

BPA since the passage of the Northwest Power Act in 1980. Continuing 

informed congressional oversight is essential during this crucial period in 

BPA's history. 

(45) 
356 

INDEX 

A 

Abel, Amy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .. . ... 27 

Aluminum . . . . . . . . . . . . . . . . . . . . . . . . . . . xiii , 7, 8, 19 

Aluminum industry . . . . . . . . . . . . . . . . . . . xiii, 7, 8 

American Fisheries Society . . . . . . . . . . . . . . . ... 28 

Appropriations . . . . . . . . . . . 16, 17 

Army Corps of Engineers (Corps) . . . . . . . . . . . xiv, 28, 33, 37, 38, 42 

.!:! 

Baker, Jim 

Bolin, AI . 

Bonneville Dams 

31, 32, 36 

. .... 21 

31 

Bonneville Power Administration (BPA) . iii, iv, v, ix, xi, xii, xiii, xiv, xv, 1-13, 

15-28, 30, 32, 33, 35-43, 45 

Bonneville Power Administration Repayment Bonds Act . . . . . . .... 15 

Boyer, Lionel Q. . . . . . . . . . . . . . . . . . 32, 39, 40 

Buck, Eugene H. . . . . . . . . . . . . . . . . . . . . ....... 27 

Bureau of Land Management . . . . . . . . . . . . . . . . . . . . 29 

Bureau of Reclamation (BuRec) iv, ix, 21, 22, 25, 26, 28, 32, 33, 37 , 38, 39 

Bush Administration . . . . . . . . . . . . . . 15 

California 

Canada .. 

Chaney , Ed 

Chinook salmon 

Clark Public Utility .. 

Clinton Administration 

Cody , Betsy . 

Coho salmon ..... . 

.... 7, 28 

. ..... 37 

... 32, 36 

. 28, 29, 31 

. 5, 25 

xiii, IS 

. 27 

. .. 28 

Columbia Basin Fish and Wildlife Authority . . . . . . . . .. 30 

Columbia Basin Project 

Columbia River . . . . 

. . . . . . . iv, 21 

iii, ix , xi, xii, xiii, 1, 9, 10, 12, 16, 22, 

Columbia River basin ... .. ... . 

28-33, 36-39,41,43 

xii, I, 10, 16, 22, 32 

Columbia River hydroelectric system . . . . . . . . .. . ..... xiii, 12 

Columbia River Inter-Tribal Fish Commission (CRITFC) ... ix, 32, 36, 39, 40 

Columbia River Treaty . 

Competitiveness Project . 

Congressional Budget Office (CBO) . 

Congressional Research Service (CRS) 

Conservation and Electric Power Plan 

Construction Fund . . . ..... . 

Counsil, William ... ... . ..... . 

. . . . . . . . . . . . . 37 

. . . . . . . . . . . xii, 3, 5, 7, 19, 40, 43 

. . . . . . . . . . . . . . . . ix, 15, 17 

. . . . . . . . . . . . . . ix , 19, 20, 27 

. .. .. .. .. .. .. . xii, II 

(47) 

20, 25 

24 
357 

48 

Curtailment .. . .. 8, 11 

.!2 

Department of Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xiii, 16, 18 

Direct Service Industries (DSI) .... . ... . ... ix, xiii, 4, 7, 8, 12, 19, 25, 26 

Draft Strategic Marketing Plan .... .. ........ . xii, 3, 4-7, 10, 22, 40,43 

Drummond, William K ... .......... . . ...... ... . . .... .. . ... 12 

DSI reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25, 26 

.!;; 

Emerald People's Utility District (EPUD) . . . . . . . . . . . . . . . . . . . . . . ix, 6 

Endangered Species Act (ESA) ...... . ix, xiii, xiv, 27-29, 32-35, 38, 41-43 

Energy conservation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1, 11, 22 

Energy efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii, xii, 4, 11, 23 

Energy Policy Act of 1992 .. ... .... . . . ..... . . . .. ..... . 9, 13, 16 

Environmental Impact Statement (EIS) . . . . . . . . . . . . . . . . . . . . . . . ix, 37 

.E 

Federal Energy Regulatory Commission . . . . . . . . . . . . . . . . . . . . . . . . . 3 

Fish and Wildlife Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 

Forest Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . 29 

Four Hs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........... . 28 

Freedom of Information Act . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 

Fuel switching . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II, 23 

Q 

Garrison, Karen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38, 39 

Godard, Don .. . . . . ... ... . .... . .................... . .. 30 

Golden, K.C. . . .. . ... . . . . . ... . ... ... ..... . ... ...... . 8, 23 

Government corporation . . . . . . . . . . . . . . . . . . . xiii , I , 15- 18, 23 

Grand Coulee . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 38 

Grande Ronde . . . . . . . . . . . . . . . . . . . . . . .... . . ..... 38 

H 

Hardy , Randall W .. ... .... . . . . . . 9, 19, 20, 22, 25 , 29, 32, 35, 36, 40-42 

Harrell , Maj . Gen . Ernest J. . . . . . . . . . . . . . . . . . . . . ... 31 , 32, 37 

Hassle Factor . . . . . . . . . . . . . . . . . . . . xii, 6, 7, 10 

Hickey , Sue . . . . . . . . . . . . . . .. II 

Holt, Mark . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........ . ... 20 

Hungry Horse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . 38 

Hydropower ........... . .............. ... ... 21, 28, 35, 37, 38 

! 

Idaho .. .... .... . .. .. .. . . . . .... .. xi, I, 9, 28, 31-34 , 36, 38-40 

Idaho Natural Resources Board . . . . . . . . . . . . . . ... ... . .. 38 

Indian tribes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xiv, 29, 30, 39, 43 

Indian water rights . . . . . . . . . . . . . . . . . . . . . . . . . . . ........ .. . 40 

Integrated resource plans (IRP) ... ... . . ...... . .. .. .... ix, xiii, 9, 12 

Irrigation . . . . . . . . . . . . . . . . . . xiv, 21, 22, 25, 26, 30, 31, 35, 37-39, 43 

Irrigation discount . . . . . . . . . . . . . . . . . . . . . . ..... .... 21, 22, 26 

Irrigation districts . . .. .. . . .. . . .. . . . . ..... . .. . . .. .... . . . 39 

Irrigation utility customers ... ....... . .... . .... .. .. ... . ..... 25 
! 

John Day Dam 

John Day reservoir 

1 

Lichatowich, James A. 

Lovelin, Bruce 

Lower Granite 

M 

Mason utility district 

McNary Dam 

Montana . 

Mothballing . . . ... ..... . 

.1'-! 

358 

49 

. ... .. .. 30 

xiv, 30, 31, 37, 42 

. ........ . 28 

.... 31 

30, 33, 34, 36, 41 

. ' .. 25 . 31, 33 

xi , 9, 36 

19, 20, 25 

National Marine Fisheries Service (NMFS) ix, xiii , xiv , 27~30, 32 39 , 4 I 43 

Natural gas . . . 3, 5, 8, 17, 22, 23, 25 

Nelson . Willa . . . . . . . . . 28 

Nevada . . . 9 

Nez Perce Tribe 40 

Northwest Conservation Act Coalition ix , 7, 8, 23 

Northwest Power Act . . xi , xii , xiii , xv , I , 5, 9-13 , 16, 19, 22 , 23 , 26, 

Northwest Power Planning Council (Council) 

Northwest River Basins Commission 

Nuclear electricity 

Nuclear generation . ..... . .. . 

Q 

Oregon 

£ 

29, 32, 35, 39-41 , 43 , 45 

iv, xi, xiii, xiv, I, 4, 10, 12, 16 

27~30, 32- 39, 41, 42 

'42 

16 

25 

xi, I, 9, 28 , 32 , 36, 43 

Pacific Northwest Coordination Agreement (PNCA) 

Pedde , Kenneth R. 

.. ix, 37, 38 

. .. 38 

ix , 16 

ix , 5, 19, 21 

21 , 26 

' 21 

Power Marketing Administrations (PMA) 

Priority firm rate (PF-rate) 

Private Irrigation discount 

Pumping discount 

Ratcheye, Leslie ... .... .. . 

Reclamation Reform Act of I 982 

Regional preference ... 

Regional Preference Act . ....... . .. .. . . 

Reinventing BP A . . . . . 

Reinventing Government 

Renewable energy 

Retail wheeling . ... . . 

. . 7 

' ' 39 

9, 13 

. . 9 

4, 15, 23 

15 

xii , xiii, 10 

.. ...... 3 
359 

50 

~ 

Salmon . .. ..... . . ... iv , xi, xii, xiii, xiv, 1, 10, 19, 21 , 22, 27-33 , 35-43 

Salmon recovery . . . . . . . . . . . . . . . . . . . . . . . xiii, 27, 28, 31 , 35 , 38-41 

Salmon restoration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I , 27, 39 

Secretary of Commerce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xiv, 42 

Secretary of the Interior . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 , 26 

Shaping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4, 6 

Short Mt. Methane Generation Project . . . . . . . . . . . . . . . . . . . . . . . . . . 6 

Shoshone-Bannock Tribes .. .... . .. . . .. . . .. ...... ... . . ...... 39 

Smith, J. Gary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34, 39 

Snake River . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi, 28-33, 35-42 

Southwest utilities . . . . . . . . . . . . . . . . . . . . . . . . . . ....... .. . . . 22 

Steelhead . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27, 28 

Stegner, Joe .... ..... ... . ..... . .. ... . ..... ..... . . ..... 31 

Strategy for Salmon (Strategy) . . . . . . . . . . iv, xii, xiii , xiv, 11 , 27-31 , 35-42 

Subsidies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . 22 , 23, 25 

Super Good Cents . .... ...... . . . .. . ........ . . . .. ... 22 , 23, 25 

System Configuration Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 37 

System Operation Review (SOR) . . . . . . . . . . . . . . . . . . . . . . . . ix, 37, 38 

I 

Tenaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5, 17, 23 

Tiered rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii , 3- 5, II, 26 

Tribe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39, 40 

Trojan reactor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 

Turbine . . . . .. . ... . .... . ......... . . . ... 5, 6, 8, 17, 23 

!1 

Umatilla ... .. . ... ... . .. . . .. . . . . ... .. . . . . . .... ....... 32 

Unbundling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3, 4, 5, II 

Upper Columbia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36, 39 

U.S. Treasury .... . . . ... . ..... ... ..... .. ..... 3, 12, 13 , 15, 16 

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 

y_ 

Value of reserves (VOR) .. .. . . . .. ... . . . . . . . . . . . . . . . . . . ix, 8, 12 

Van Pelt, Anthony .. ... ..... .... . . ...... ... . .... .. 39, 40 

w 

Warm Springs .... .. . . ........ . ........... . ....... .... . 32 

Washington, State of .. . . ..... . .. . ..... . .... ... . xi, 9, 28, 36, 43 

Washington Public Power Supply System (WPPSS) . iii , ix, xi, xii, 19-21 , 23-25 

Water banks ....... .. .... . .. . . .. ..... ... . . ...... .... .. 38 

Water conservation ... .. .... .. .. .... .. . .... . xiv, 25 , 26, 38, 39, 43 

Water law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xiv, 38, 43 

Water rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38, 40 

Water spreading ... . ........ . . . ........... . ............ 38 

Weatherization ............... . ....... . . . . . .... .... .. . . 23 

Western Area Power Administration (WAPA) . . . . . . . . .. . .. ix, 9, 13 

Wheeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3, 6 

Wholesale wheeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 

Williams, Jack E. . . ... .... . .. . ..... . .... . . . . ... .. . ... . 28 
360 

51 

WNP-1 . .... . . .. ... . ... . .... ... . . .... . . . ....... 19, 20, 25 

WNP-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19, 20, 23-25 

WNP-3 .. . ......... . ... .... .. . . . .. . ......... . .. 19, 20, 25 

Wright, AI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30, 41 

Wyoming . ...... . . . .. . ... . .. . . . .. ... .......... . ... .. 9 

.Y 

Yakama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32, 39 

Yakima River Basin . . . .. . . . . ........ . ... . . . .... . ..... . .. 38 

0 

ISBN 0-16-046201-0 

90000