BONNEVILLE/WESTERN U.S. POWER OUTAGE 

OVERSIGHT HEARING 

BEFORE THE 

SUBCOMMITTEE ON WATER AND 

POWER RESOURCES 

OF THE 

COMMITTEE ON RESOURCES 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED FOURTH CONGRESS 

SECOND SESSION 

ON 

ISSUES AND RECOMMENDATIONS CONCERNING THE 

AUGUST 10, 1996, BONNEVILLE/WESTERN U.S. POWER 

OUTAGE 

36-069cc 

NOVEMBER 7, 1996--LOS ANGELES, CA 

Serial No. 104-103 

Printed for the use of the Committee on Resources 

U.S. GOVERNMENT PRINTING OFFICE 

WASHINGTON : 1997 

For sale by the U.S. Government Printing Oftice 

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

ISBN 0 - 16 -054153- 0 
COMMITTEE ON RESOURCES 

DON YOUNG, Alaska, Chairman 

W.J. (BILLY) TAUZIN, Louisiana 

JAMES V. HANSEN, Utah 

JIM SAXTON, New Jersey 

ELTON GALLEGLY, California 

JOHN J. DUNCAN, JR., Tennessee 

JOEL HEFLEY, Colorado 

JOHN T. DOOLI'ITLE, California 

WAYNE ALLARD, Colorado 

WAYNE T. GILCHREST, Maryland 

KEN CALVERT, California 

RICHARD W. POMBO, California 

PETER G. TORKILDSEN, Massachusetts 

J.D. HAYWORTH, Arizona 

FRANK A. CREMEANS, Ohio 

BARBARA CUBIN, Wyoming 

WES COOLEY, Oregon 

HELEN CHENOWETH, Idaho 

LINDA SMITH, Washington 

GEORGE P. RADANOVICH, California 

WALTER B. JONES, JR., North Carolina 

WILLIAM M. (MAC) THORNBERRY, Texas 

RICHARD (DOCl HASTINGS, Washington 

JACK METCALF, Washington 

JAMES B. LONGLEY, JR., Maine 

JOHN B. SHADEGG, Arizona 

JOHN E. ENSIGN, Nevada 

GEORGE MILLER, California 

EDWARD J . MARKEY, Massachusetts 

NICK J. RAHALL II, West Virginia 

BRUCE F. VENTO, Minnesota 

DALE E. KILDEE, Mi chigan 

PAT WILLIAMS, Montana 

SAM GEJDENSON, Connecticut 

BILL RICHARDSON, New Mexico 

PETER A. DEFAZIO, Oregon 

ENI F.H. FALEOMAVAEGA, American 

Samoa 

TIM JOHNSON, South Dakota 

NEIL ABERCROMBIE, Hawaii 

GERRY E. STUDDS, Massachusetts 

SOLOMON P. ORTIZ, Texas 

OWEN B. PICKE'IT, Virginia 

FRANK PALLONE, JR., New Jersey 

CALVIN M. DOOLEY, California 

CARLOS A. ROMERO-BAHCELO, Puerto 

Rico 

MAURICE D. HINCHEY, New York 

ROBERT A. UNDERWOOD, Guam 

SAM F ARR, California 

PATRICK J. KENNEDY, Rhode Island 

DANIEL VAL KISH, Chief of Staff 

ELIZABETH MEGGINSON, Chief Counsel 

CHRISTINE A. KENNEDY, Chief Clerk/Administrator 

JOHN LAWRENCE, Democratic Staff Director 

SUBCOMMITTEE ON WATER AND POWER RESOURCES 

JOHN DOOLITTLE, California, Chairman 

JAMES V. HANSEN, Utah PETER A. DEFAZIO, Oregon 

WAYNE ALLARD, Colorado GEORGE MILLER, California 

RICHARD W. POMBO, California BRUCE F. VENTO, Minnesota 

FRANK A. CREMEANS, Ohio SAM GEJDENSON, Connecticut 

WES COOLEY, Oregon OWEN B. PICKETT, Virginia 

HELEN CHENOWETH, Idaho CALVIN, M. DOOLEY, California 

GEORGE P. RADANOVICH, California MAURICE D. HINCHEY, N~w York 

WILLIAM M. (MAC) THORNBERRY, Texas SAM FARR, California 

RICHARD (DOC) HASTINGS, Washington 

JOHN E. SHADEGG, Arizona 

JOHN E. ENSIGN, Nevada 

ROBERT FABER, Staff Director 

VALERIE WEST, Professional Staff 

S. ELIZABETH BIRNBAUM, Democratic Counsel 

(II) 
CONTENTS 

Hearing held November 7, 1996 ............................... ... ............ ...... ........................ . Statement of Members: DeFazio, Hon. Peter, a U.S. Representative from Oregon ........................... . Doolittle, Hon. John T., a U.S. Representative from California, Chairman, 

Subcommittee on Water and Power Resources ... ........................ ...... ........ . 

Statement of Witnesses: 

Bonsall, Mark B., Chairman, Western Systems Coordinating Council ...... . Prepared Statement .... ............ ..... ............................................................ . Budhraja, Vikram S., Senior Vice President, Southern California Edison .. Conlon, P. Gregory, President, California Public Utilities Commission .... .. Prepared Statement .... ....................... ......................................... ............. . Edwards, Marcie L., Bulk Power Operations and Maintenance, Los Angeles Department of Water and Power .......................... .... ............................ . Prepared Statement ................. .......... ........... ................... ........................ . Ferraro, John, President, Los Angeles City Council ............... .. .................. .. Hardy, Randall, Administrator, Bonneville Power Administration, U.S. 

Department of Energy .......... ......................... ............... ... ............................ . Prepared Statement ....................... .... ......... ........................................... .. . Jennings, Renz D., Chairman, Arizona Corporation Commission ... ............ . Prepared Statement ...... ........... .... ...... ...................... ...... ................. ......... . Macias, E. James, Vice President and General Manager, Electric Trans- mission Business Unit, Pacific Gas & Electric Company .................... ..... . Prepared Statement ..... ................ ................. ...... ................................. .... . Velehradsky, John E., Director, Engineering and Technical Services, 

North Pacific Division, U.S. Army Corps of Engineers ....... ................ ... ... . Prepared Statement ... ...... ... ................................... ........ .......................... . 

Additional material supplied: Bonneville Power Administration: 

Frequency of outages on 500 kilovolt lines .... ....... ...... ................... ....... .. Herbicide discontinuance ............................................. ............... ............. . Lost power generation due to fish spill .... ..................... ......................... . Power system stabilizers ................. ...... ............................... ....... ........... . . Significance of stabilizers .... ........................... ....... ....................... ........... . Western System Coordinating Council Report .............................................. . 

Communication submitted: 

Budhraja, Vikram: Letter of November 19, 1996, to Hon. John T. Doolittle with answer to question ....... ..... ......................................................... . 

(III) 

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BONNEVILLE/WESTERN U.S. POWER OUTAGE 

OF AUGUST 10, 1996 

THURSDAY, NOVEMBER 7, 1996 

U.S. HOUSE OF REPRESENTATIVES, 

SUBCOMMITTEE ON WATER AND POWER RESOURCES, 

COMMITTEE ON RESOURCES, 

Los Angeles, CA. 

The Subcommittee met, pursuant to call, at 10:08 a.m., in the 

15th floor Boardroom, Los Angeles Department of Water and 

Power, 111 North Hope Street, Los Angeles, California, Hon. John 

T. Doolittle (Chairman of the Subcommittee) presiding . . Mr. DooLITTLE. The Subcommittee on Water and Power Re- "sources will come to order. We are meeting today to hear testimony 

regarding issues and recommendations concerning the August 10, 

1996, Bonneville Western U.S. power outage. 

Before I go any further, I am very pleased to introduce the president of the Los Angeles City Council and our host, Mr. John Ferraro, for comments that he would care to offer. 

Mr. FERRARO. Mr. Chairman, first of all, congratulations on your 

victory 2 days ago, and welcome back to Los Angeles. 

Mr. DOOLITTLE. Thank you. 

STATEMENT OF JOHN FERRARO, PRESIDENT OF LOS 

ANGELES CITY COUNCIL 

Mr. FERRARO. I know you have lived in Los Angeles in the past. 

We had another famous Doolittle in Los Angeles, the generaL 

On behalf of the city council and the mayor, Mayor Riordan, I 

would like to welcome you to the City of Los Angeles. We are honored that you have selected Los Angeles as the location for the first 

congressional hearing regarding the power outage of August lOth. 

In my more than 30 years on the city council, I have had an opportunity to closely monitor the activities of our electric utility, the 

Los Angeles Department of Water and Power, and I long have been 

impressed by the reliability of service the DWP provides to the people of Los Angeles. 

The three-and-a-half milliqn people who live in the City of Los 

Angeles are like most people everywhere. They really do not think 

about electric service until they lose it, as they did on August lOth. 

We in Los Angeles felt very fortunate when our Department of 

Water and Power was able to restore the service completely within 

2 hours. And I have been told that our quick recovery enabled us 

to assist other utilities in bringing up their systems. That speaks 

well for our Department of Water and Power. 

(1) 
2 

The August outage, as well as the one in July, highlighted the 

need for reliability in the interconnected transmission system and 

for the need of prompt exchange of information between utilities. 

You are to be commended for holding this hearing. We appreciate 

your inquiry and look forward to any light that you can shed on 

how future outages of this magnitude can be avoided. 

Your presence here demonstrates the importance you place on 

the reliability of electric service for the people of our country. The 

mayor and the city council of Los Angeles greatly appreciate your 

efforts in this regard and want you to know that our city is at your 

service, ready to assist you in any way we can. 

Again, welcome to Los Angeles. We are happy to have you here, 

and we wish you every success in this important effort. 

Mr. DOOLITTLE. Well, thank you very much for your kind remarks, and we are grateful to you and the city and the Department 

of Water and Power for making available the hearing room today 

and providing us with all the attendant services. 

STATEMENT OF THE HON. JOHN T. DOOLITTLE, A U.S. REPRESENTATIVE FROM CALIFORNIA, CHAIRMAN, SUBCOMMITTEE ON WATER AND POWER RESOURCES 

Mr. DOOLITTLE. Beginning at about 3:45 p.m. PDT on Saturday, 

August 10, 1996, the interstate power grid disappeared for approximately 7.5 million customers in the Western United States and 

Canada. People, businesses, governments, even the operators of the 

electric generating stations themselves were without power for periods ranging from several minutes to about 9 hours. 

The outage was triggered by the loss of transmission lines in the 

Portland area, which was due to the failure by the Bonneville 

Power Administration to keep trees trimmed in its transmission 

right-of-way areas. The lines came in contact with the trees and 

shorted out. 

Although BPA's failure to keep trees trimmed initiated the chain 

reaction that caused the system to fail, I believe it will be clear 

from this hearing that many other factors contributed to the outage. A small percentage of those factors were acts of nature, but 

most were the result of the exercise of human judgment. 

In addition to interrupting service to customers that day, the outage also resulted in the automatic shutdown of 15 large thermal 

and nuclear generating units in California and the southwest. I do 

not think most of the public realized that this secondary consequence put the entire Western grid in a compromised condition 

for several days. 

A few of those large units did not return to service until the following Tuesday or Wednesday of that week, requiring the purchase 

of emergency power during that period. 

The purpose of this hearing is to address the following questions: 

1. What did occur on August 10, 1996? 

2. Why did it occur? 

3. What steps should be taken by the Federal agencies that 

caused the outage to change their policies, procedures, and equipment to make sure that the events are not repeated? 

4. What legislative action, if any, may be required? 
3 

I would like to take a minute to provide some background on several issues. The Bonneville Power Administration, a part of the Department of Energy, was created by the Federal Government in 

1937 to market power from Federal hydropower projects in the Pacific Northwest. 

Since then, the Federal Government has played a dominant role 

in Northwest power markets through the operations of Bonneville. 

Bonneville has control over 80 percent of the region's high voltage 

transmission. Historically, Bonneville has had a good record of 

maintaining its transmission service. 

Although Bonneville sells most of the Federal power in the Pacific Northwest, it provides a significant amount of power directly 

to California during the summer months. In addition, Bonneville 

transmits power from other Northwest utility companies to California over its lines. As a result, there are heavy power flows from the Pacific Northwest to California and the Southwest in the summer. In the winter, 

the power flows north to heat the Pacific Northwest. 

In response to this outage, the Western Systems Coordinating 

Council, the entity which currently has the responsibility to evaluate these events, conducted an investigation and released a report 

on October 18, 1996, describing the causes of the outage and recommending solutions. The WSCC report on the August lOth outage raises many technical questions about the way in which Bonneville operates its hydroelectric and transmission facilities. However, some of the larger 

issues in this case concern Bonneville's and the Federal Government's overall ability to realize when there is a problem, the Federal Government's ability to manage these assets and the relative 

consequences of Federal action or inaction compared with the rest 

of the electric utility industry. 

Several transmission line flashovers and equipment problems 

contributed to the August lOth outage. Perhaps none of these incidents would, in isolation, have resulted in an outage, but taken together their cumulative effect was to put the entire system in a 

precarious state. Western concluded that Bonneville was not in fact 

operating in accordance with Western's minimum standards. There is a lot of talk in this case of unexpected contingencies and 

the low probability of all of these events occurring at one time. I 

believe this discussion misses the point. The question is whether 

there is an ongoing awareness of the state of the system so that 

as events and decisions are made operators are conscious of the 

factors which are pushing the system closer and closer to failure. 

Although three 500-kv lines were lost in the hour and a half 

prior to the outage, though such flashovers indeed had caused similar problems in the region a month earlier and though Bonneville 

had realized that there was reduced backup capability based on 

planned and unplanned maintenance outages as well as units out 

of service for fish flows, it seems that Bonneville did not understand the implications of the transmission lines systematically failing one after another on the afternoon of August lOth and did not 

take the necessary steps to mitigate the impact on the system. 

I believe it is our responsibility to look at these risks, not just 

in terms of the isolated technical events but in terms of the bigger 
4 

picture and our need to be aware of the factors that are pushing 

the system beyond its capability. 

We will also look at the role played by individual operating decisions leading up to the events like this one, decisions such as when 

maintenance is scheduled and when units are off-line or at reduced 

capacity for fish recovery operations. 

More importantly, we want to look at whether we retain the 

flexibility to modify those decisions if a decision that was good 6 

months or a year ago no longer makes sense in light of rapidly 

evolving crises. 

I look forward to hearing from the witnesses and determining 

what steps need to be taken to ensure that the Federal agencies 

play a responsible role in ensuring a reliable electric supply system. 

I might mention that we had other members scheduled to attend 

today and one has a very ill mother and elected to remain near her 

side and just with the rush of events following the elections made 

it difficult for some to make it. 

Our ranking member, Mr. DeFazio, has submitted a statement 

for the record which will be incorporated in the hearing transcript. 

[The prepared statement of Hon. Peter DeFazio follows:] 

PREPARED STATEMENT OF HON. PETER DEFAZIO, A U .S. REPRESENTATIVE FROM 

O REGON 

Mr. Chairman, this hearing has been called to investigate the issues associated 

with the electric power outage of August 10, 1996. This outage, which was the sec- ond major outage of the summer, has ~riven consumers reason to wonder whether 

the lights will come on when they hit t'he switch. I am deeply coneerned that this 

outage, and the previous outages of July 2 and July 3, may be indicative of underlying problems in the electric power system. Because it is the basic reliability of the 

system that ought to be our fundamental concern, I am disafpointed that the Chair- man has limited this hearing to the August 10 outage. I we want to determine causes of past outages and identify remedies to those causes, we shouldn't let politics limit the scope of our analysis. 

The preliminary report from the Western Systems Coordinating Council (WSCC) 

provides a number of conclusions and recommendations regarding the August 10 

outage. The report faults the Bonneville Power Administration and Army Corps of 

Engineers, among others. I am anxious to hear what steps EPA and the Corps are taking to respond to these findings. The public has every reason to expect that our Federal agencies will effectively manage the resources under their jurisdiction. 

I would also note that the WSCC report makes recommendations for actions that 

Southwest utilities-and California utilities, in particular-can take to protect California and Southwest consumers from another intertie separation. It does seem sur- prising that as a result of a loss of 7,000 MW from the Northwest, more than 27,000 

MW of generation went off-line in Califc)rnia. I am anxious to hear from non-Northwest utilities what actions they intend to take to implement these recommendations. 

It would be unreasonable to expect Northwest ratepayers to pay for system enhancements that aid California responsibility. To put that another way; while we in the 

Northwest are putting our house in order, we do not wish to have rocks thrown from 

the glass house across the street. 

Mr. DOOLITTLE. I would like to invite our first panel of witnesses 

to come forward please, if Mr. Bonsall will come up and Mr. Hardy 

and Mr. Velehradsky, they will be our first panel. 

And if you gentlemen would remain standing and raise your 

right hand, we will administer the oath here. 

[Witnesses sworn.] 

Mr. DOOLITTLE. Let the record reflect each answered in the affirmative. 

Please be seated. 
5 

Mr. Bonsall is Chairman of the Western Systems Coordinating 

Council. Mr. Hardy is the Administrator of the Bonneville Power 

Administration. Mr. Velehradsky is the Director of Engineering 

and Technical Services, North Pacific Division, U.S. Army Corps of 

Engineers. 

My counsel has reminded me that we have given Mr. Bonsall 

some extra time, but I guess in view of the fact that we are it, time 

will not be such a factor, so while the lights will be there for your 

guidance, I feel comfortable in telling you if you wish to go beyond 

that, please feel free to do so. 

Mr. Bonsall, will you please begin with your testimony? 

STATEMENT OF MARK B. BONSALL, CHAIRMAN, WESTERN 

SYSTEMS COORDINATING COUNCIL 

Mr. BONSALL. Thank you, Chairman Doolittle. It is a pleasure to 

appear before you today to discuss the August 10, 1996, power outage that affected the Western United States, Western Canada and 

Northern Mexico and the actions taken following the outage and 

the conclusions and recommendations that have been developed as 

a result of the outage. 

I am Mark Bonsall. I am Chairman of the Western Systems Coordinating Council and Associate General Manager for Marketing, 

Customer Service, Finance and Planning at the Salt River Project 

in Phoenix, Arizona. 

WSCC is the largest and most diverse of the ten regional reliability councils of the North American Electric Reliability Council, or 

NERC. WSCC's service territory extends from Canada to Mexico, 

an area of nearly 1.8 million square miles. It includes the provinces 

of Alberta and British Columbia, the northern portion of Baja, California, Mexico and all or portions of the 14 Western states in between. 

Due to the vastness and diverse characteristics of the region, 

WSCC's members face unique challenges in coordinating the dayto-day operation and long-range planning required to provide reliable and affordable electric service to the more than 59 million people within the WSCC region. 

The interconnected transmission system within the WSCC region 

is known as the Western Interconnection. It is one of the five major 

electric system networks in NERC. 

At 3:48 p.m. Pacific Advanced Standard Time on Saturday, August lOth, a major power outage occurred on the Western Interconnection, interrupting service to seven and a half million customers for periods ranging from several minutes to about 9 hours. 

In the hours before the power outage, three lightly loaded 

500,000-volt or kv, 500 kv lines, Big Eddy-Ostrander, John DayMarion and Marion-Lane, in the Portland area were forced out of 

service. These 500 kv lines were providing voltage support for the 

transmission system. Two of the line outages were caused by 

flashovers or short circuits to trees. A third line was forced out of 

service because a circuit breaker was out of service when the second line outage occurred. 

While none of these line outages were individually judged to be 

crucial by Bonneville Power Administration dispatchers, the cumulative impact resulted in a weaker system. 
6 

Voltages were adjusted, but no schedules were reduced. In addition, two 115 kv transmission lines, two 500-volt circuit breakers 

and a 500,000/230,000-volt transformer, all in the Portland area, 

were out of service for modifications and/or repairs. These outages 

contributed to the system stress following the subsequent loss of 

the Keeler-Allston 500 kv line. 

The power outage effectively began when the heavily loaded 

Keeler-Allston 500 kv line, which is in the Portland, Oregon area, 

sagged too close to a tree and flashed over. Loss of the KeelerAllston 500 kv line precipitated the overloading and tripping of two 

underlying parallel transmission lines in the Portland area, one 

due to a flashover to a tree and one due to a relay malfunction, 

which depressed the surrounding transmission system voltages. 

The depressed voltages led to the subsequent tripping of hydroelectric generating units at the McNary Dam due to excitation 

equipment problems. 

This combination of events t:riggered increasing voltage oscillations on the interconnected transmission system, eventually causing protective devices to trip the three 500 kv California-Oregon 

Intertie lines, three of the four major transmission lines that tie 

the Pacific Northwest to California. 

The outage of these three lines resulted in transmission and generation outages that culminated in the system separating into four 

islands. 

System islanding is used in the West as a safety net to prevent 

a total blackout, minimize the number of customers affected and 

minimize the time required to restore customer service. Because 

islanding did not occur in a fully controlled manner, loss of the 

California-Oregon Intertie resulted in the loss of approximately 

21,400 megawatts of generation and approximately 27,400 

megawatts of under frequency load shedding, over seven million 

customers in northern California and the southwest. 

The interconnected transmiE.sion system from Canada south 

through Washington and Oregon to California was heavily loaded 

because of high temperatures near or above 100 degrees throughout much of the WSCC region. In addition, because of the excellent 

hydroelectric conditions in Canada and the Northwest, the amount 

of power being transferred including large economy transfers from 

Canada into the Northwest and from the Northwest to California 

was high but within established transfer capability limits. 

In the wake of this outage, an emergency meeting of senior management from Western utilities, the United States Department of 

Energy and the State regulatory community was convened on August 12th. A lower power flow transfer limit from 4800 megawatts 

to 3200 megawatts was established for the California-Oregon 

Intertie until additional studies had been conducted and the results 

approved by a newly established WSCC operating capability policy 

committee. 

In addition, Bonneville Power Administration began a comprehensive study to assess the voltage support capability of its sys-· 

tern. BPA also agreed to report all outages of 500 kv transmission 

lines and other key facilities on its system. 
7 

In conjunction with the U.S. Army Corps of Engineers, BPA also 

initiated a review to understand the loss of the McNary generators 

and to prevent their loss in the event of a future disturbance. 

Changes have been made to the McNary excitation systems. As 

an additional precaution, the Northeast/Southeast Separation 

Scheme was placed back in service. Additionally, all WSCC members have been asked to review their tree trimming programs, their 

system's voltage support capability and the NERC recommendations set forth in the publication entitled "Survey of the Voltage 

Collapse Phenomenon." 

As is standard practice for WSCC and its members following a 

system-wide power outage, a task force of industry experts conducted a thorough review of the power outage and recommended 

actions to lessen the potential for the occurrence of a similar event 

in the future. 

As part of the standard outage analysis and review process, 

WSCC policies, procedures and monitoring activities are being reviewed as well to identify any necessary improvements. 

The final report on the August lOth outage includes 32 conclusions and over 90 associated recommendations. All recommendations are logged and tracked until they are completed. The report 

has been submitted to the U.S. Department of Energy and the 

North American Electric Reliability Council. 

In reviewing the August lOth outage, the task force identified 

four key findings: the interconnected transmission system was unknowingly being operated in violation of WSCC reliability criteria; 

transmission line right-of-way maintenance, operating studies and 

system operating instructions to dispatchers were inadequate; contingency plans should have been adopted to mitigate the effects of 

an outage of the Keeler-Allston 500 kv transmission line; and, last, 

the loss of the 13 McNary hydroelectric generating units in the 

Northwest was a major factor leading to the outage of the three 

500 kv California-Oregon Intertie lines and the subsequent 

islanding of the WSCC interconnected system. 

This power outage indicates the need to identify and implement 

strategies that will minimize the potential for more severe unforeseen events and should such events occur minimize the impact of 

the outages. It also highlights the need for continued vigilance to 

reasonably ensure that all equipment will operate as expected. 

WSCC and the other regional councils are in the process of implementing additional security process measures. These measures 

will enhance interconnected system reliability through the exchange of information required to augment system security andreliability, including on-line power flow and security analysis and increased system monitoring. 

These measures will enhance the operators' ability to identify potential problem outages and take corrective actions. Within the 

WSCC region, there will be four security coordinators responsible 

for the active monitoring of electric system conditions on a realtime basis to proactively anticipate and mitigate potential problems 

and coordinate restoration following a system emergency. 

In addition, to safeguard the reliability of interconnected electric 

system operation, numerous technical studies are conducted each 

year to reasonably ensure that critical operating conditions are 
8 

thoroughly examined and evaluated. These studies include assessments of low probability events that are expected to result in system islanding and under frequency load shedding. Islanding and under frequency load shedding are protective actions used in the West for severe low probability disturbances to 

stabilize the system, minimize customer interruptions and allow 

rapid system restoration. 

Additional studies are being conducted to ensure a broad range 

of operating conditions have been adequately studied and that the 

system is being operated in compliance with WSCC and NERC criteria and policies. 

WSCC members are looking at a wide variety of conditions and 

contingencies to ensure that the system is planned and operated 

within established WSCC reliability criteria. 

In all likelihood, the August lOth power outage could have been 

avoided if contingency plans had been adopted to minimize the effects of an outage of the Keeler-Allston 500 kv line in the Pacific 

Northwest. 

In addition, the task force determined that the loss of the 

McNary generating units and inadequate tree trimming practices, 

operating studies and instructions to dispatchers did play a significant role in the severity of the disturbance. 

As the electric industry becomes more competitive, we must 

make certain that interconnected system reliability is preserved. We must ensure that all entities that own, operate or use the interconnected transmission system are complying with the established 

criteria, guidelines, policies and procedures of WSCC and NERC. 

I believe there are three essential steps that must be taken to 

ensure system reliability in an E~ra of competition: 

1. Mandatory compliance with established standards; 

2. Mandatory membership in the regional reliability councils and 

NERC; and 

3. Expanded compliance monitoring with appropriate incentives, 

sanctions or fines. 

As the industry is restructured and competition increases, it will 

become even more important for all market participants to adhere 

to the rules of the road, especially since fewer participants, if any, 

will be willing to go the extra mile and incur the added expense 

to meet a competitor's obligation for ensuring reliability. It is for 

this reason that the industry widely shares the view that voluntary 

compliance will no longer be adequate. 

And if I might expedite the completion of my comments, I would 

like to add a couple of comments in addition to those submitted for 

the record. 

Mr. Chairman, it is obviously in no one's best interest in this industry that events of this magnitude, either the July 2nd or the 

August lOth event, take place. I would like to thank the members 

of the task force that completed the disturbance report for the 

WSCC for their, I think, timely and exhaustive efforts to compile 

the disturbance report and accumulate the recommendations therein. 

I would also like to recognize the two organizations that are the 

subject of those reports, Idaho Power Company and Bonneville 

Power Administration, as having fine reliability records over all 
9 

and I would like to th2nk BPA in particular for its aggressive cooperation and pursuit of the root causes of the August lOth outage. 

Unfortunately, both of these organizations encountered fairly 

unique conditions and, as a result, the incidents did take place. 

From WSCC's point of view, these incidents are absolutely unacceptable and we will do everything in our power to prevent their 

recurrence. 

If there are two facts I would point out as a result of these occurrences, the first is that as we consider the deregulation of the electric utility industry as a matter of economic structure and conduct 

and performance, it is entirely possible to consider or segment the 

industry into generation, transmission and distribution components. As a matter of reliability, it is not. The components operate 

conjunctively to preserve reliability and we need to keep that fact 

in mind as we address otherwise restructuring the industry in a 

deregulated environment. Secondly, the reliability councils that are in place throughout the 

United States in at least one way represent the cumulative reliability intelligence of this nation and I think they are good institutions 

and as we address the issue of how to preserve reliability in a deregulated environment, I would encourage your consideration of the 

continued or extended use of the existing reliability councils. Thank you, Mr. Chairman, and I am happy to accept any questions you may have. 

[The prepared statement of Mr. Bonsall may be found at the end 

of the hearing.] 

[Western System Coordinating Council Report may be found at 

the end of hearing.] 

Mr. DOOLITTLE. Thank you. What we will do is hear from the other witnesses on the panel, 

and then I will ask questions of all three of you. Mr. Hardy, you are recognized for your testimony. 

STATEMENT OF RANDALL HARDY, ADMINISTRATOR, BONNEVILLE POWER ADMINISTRATION, U.S. DEPARTMENT OF ENERGY 

Mr. HARDY. Thank you, Mr. Chairman. I am Randall Hardy, the 

Administrator and Chief Executive Officer of the Bonneville Power 

Administration. 

I would like to start this morning by talking a little bit about the 

benefits the intertie has provided, Bonneville's reliability record, then discuss the specifics of the events and, more specifically, what 

Bonneville and the Corps are doing to make sure this does not happen again. 

The Pacific NorthwestJSouthwest Intertie has a total transfer capability of some 7900 megawatts. Mr. Chairman, you pointed out 

in your statement, it takes advantage of the seasonal diversity be- tween the Northwest and the southwest to maximize the economic 

benefits for both regions. 

California consumers have benefited to the tune of roughly $1 

million a day for the last 30 years as a result of the interties being 

in place. The interties have also led to significant reductions in pollution, particularly in the L.A. basin during critical times of the 

year. 
10 

BPA has a good, and I would say excellent, reliability record historically. That being said, we are severely chastened by the events 

of August lOth in particular and accept full responsibility for our 

part in those events, which was considerable. 

As regards our reliability record, a recent WSCC audit has found 

us to have a well operated system that consistently operates in conformance with WSCC reliability criteria and even in spite of the 

August lOth outage, we made the NERC honor roll this year with 

a 96.8 percent compliance capability with NERC standards. 

I think Mark has described fairly accurately the events on August lOth. Let me just offer an observation in a more general sense. 

This was produced by a combination of inadequate tree trimming, 

and failure to anticipate a combination of high hydro runoff and 

high load conditions that in retrospect exposed our system to some 

voltage support vulnerabilities that we did not fully understand. 

This was the highest hydro year we had in 20 years. Normally, 

the runoff ends around June 30th and hence you have lower loadings in July and August, the peak load times in California. This 

year, the runoff went all the way through August, and that created 

some vulnerabilities that we had not fully understood and which 

we are now working to understand and to correct. 

Finally, we had events surrounding McNary where we lost 13 

units in 73 seconds, really an unprecedented kind of circumstance 

relative to a major hydro facility. We are working with the Corps 

to actively try to correct that problem and make sure that we do 

not have similar problems at other hydroelectric facilities. 

Let me focus now on the specific things that Bonneville is doing 

to try to ensure that a repeat of this action will not occur. First, as Mark mentioned, in -conjunction with the other WSCC 

parties, we have restricted transfer capability over the AC intertie 

to 3200 megawatts. Its design capability is 4800 megawatts. 

Secondly, we have completed a complete review of our vegetation 

management program with Bonneville, entailing some 46 recommendations and we intend to implement all of them. Significant 

among those recommendations are, first, a variety of management 

actions to clarify responsibilities in the tree trimming area. These 

involve both who is responsible for what, actions and better defining what constitutes danger brush versus just high brush. If you 

have a danger brush circumstance, action has to be taken with 24 

hours to clear that brush. Secondly, we have increased our tree trimming budget on the 

order of 50 percent for the next 3 years. We had in fact increased 

it last year and the year before from $2.5 million to $3 million but 

in retrospect that clearly was inadequate to cope with the magnitude of tree growth that we had, particularly growth brought on 

by the high hydro conditions of the last year. 

And, finally, we will go back to the selective use of herbicides 

and right-of-way management control. We discontinued all but spot 

herbicide use for right-of-way management in 1984 for environmental reasons. We now have to go back to some more selective use 

of herbicides to control some of the brush rather than relying strictly on hand cutting. We think we can use herbicides in an environmentally responsible way, but that is an important part of being 

able to comprehensively address this reliability issue. 
11 

The third major action is we have initiated, as Mark referenced, 

a comprehensive review of the adequacy of voltage support in the 

Bonneville system. This review is now underway. We have a panel 

of nationwide and, in some cases, international experts to review 

those results and suggest other studies that we need to do. They 

include representatives of the California utilities, from NERC, from 

WSCC as well as East Coast utilities and other reliability experts 

from around the country. 

I expect that this voltage support review which should be done 

around the first of the year will produce conclusions in three areas. 

First, it will clearly show where we need to add additional system reactive capability on the Bonneville system. This will not be 

cheap. I anticipate that it will cost somewhere between 10 and 50 

million dollars to install the appropriate reactive capacity at key 

points in the system to fix these vulnerability problems. 

Secondly, it will focus on getting better availability of Corps generation at key plants in the lower Snake and lower Columbia. 

And, third, I think it will address the fish problems and the kind 

of reliability consequences of the fish operation that we have been 

running in the Northwest for the last 2 to 3 years, consequences 

which we had not fully appreciated prior to the August lOth outage. 

The fourth major action addresses communication problems we 

had with other utilities in the August lOth outage. We have now 

an operating agreement with Pacific Gas and with Southern Cal 

Edison which I expect will be expanded to all the intertie owners 

over the next few weeks where we have identified specific so-called 

key facilities, quote-unquote, where if we have a problem, we will 

notify each other that there is a problem or there is an outage. 

Prior to this time, the definition of key facilities was the criteria 

used in WSCC reliability criteria but that was at the discretion of 

the owning utility. We have essentially taken an action with all 

three utilities to remove the element of discretion from dispatchers 

and simply specify what facilities, if there is an outage, will be reported to the other intertie owners and participants. 

Secondly, a key part of this operating agreement is a change in 

the paradigm that our dispatchers jointly used up to this point. 

Prior to August 10, if we had something looked like it might be a 

problem on the system, our tendency was to not cut schedules but 

to try to resolve the problem first. The paradigm is now cut schedules first, ask questions afterwards. 

We will reduce the schedules if there is an apparent problem and 

then argue about whether there is a problem or not and then restore the schedules once we determine whether there is a problem 

and, if so, what the fix is. That is a significant change in the operating that all of our dispatchers have used. 

Fifth, we are working with the Corps of Engineers. We think we 

have found the fix to the exciter problem and associated relay problem at McNary and, as I am sure John Velehradsky will describe, 

we are probably within 30 days, I think, of being able to install the 

necessary equipment, test it to the satisfaction of all WSCC members and that will enable us to take the AC intertie limitations 

back up from 3200 to maybe 3600 or a little higher. 
12 

Sixth and finally, we have instituted a variety of actions with the 

Corps of Engineers to try to improve our communication, and data 

coordination, between the generation and transmission facilities 

since the Corps is the owner and operator of the generation facilities and we simply are the marketer of the power output from 

those facilities. We also will ensure that the Corps plants are operated in a way where they are fully cognizant of the various transmission system exposures that they are likely to be subject to. 

Those are the major areas of a much more comprehensive set of 

recommendations that we are implementing. We intend to implement every recommendation that applies to us in the WSCC report 

and probably go well beyond that, particularly with the results of 

the voltage support study that we are engaged in now. I would like to say just a couple of words about the future as distinct from this particular set of circumstances. 

Let me make clear at the outset that I do not think that you can 

legitimately attribute this outage to any factors involved with deregulation. That being said, it is clear that we have major challenges ahead of us in the deregulation area to ensure we make this 

transition to a fully competitive marketplace, at least at wholesale 

and possibly at retail, in ways that do not impact system reliability. 

I would like to suggest three things that pretty much parallel 

what Mark said and what I expect you will hear from Pacific Gas 

and Edison as well. 

First, we need mandatory membership in reliability councils and 

in NERC. We cannot have a load control area operator that can opt 

out of membership in a reliability council structure as they can 

now. 

Second, we need mandatory compliance with NERC and WSCC 

recommendations. You cannot have the option to opt out if that is 

necessary to maintain system reliability. 

Third, we need strong independent system operators. The industry is moving toward the ISOIIGO concept, but it is imperative that 

the system operator have both the scheduling responsibility and 

the dispatch responsibility under his control. If we allow those two 

things to be separated, we are asking for significant problems as 

we move into the deregulated marketplace. 

Mr. Chairman, that concludes my statement. I would be happy 

to answer any questions at your discretion. 

[The prepared statement of Mr. Randall Hardy may be found at 

the end of the hearing.] 

Mr. DOOLITTLE. Thank you very much. 

Mr. Velehradsky, you are recognized. 

STATEMENT OF JOHN E. VELEHRADSKY, DIRECTOR, ENGINEERING AND TECHNICAL SERVICES, NORTH PACIFIC DMSION, U.S. ARMY CORPS OF ENGINEERS 

Mr. VELEHRADSKY. Mr. Chairman, I am John Velehradsky, Di- rector of Engineering and Technical Services, North Pacific Division, U.S. Army Corps of Engineers. I am pleased to be here today 

representing Mr. Martin Lancaster, the Assistant Secretary of 

Army for Civil Works. 
13 

I am responsible for the technical direction of the planning, design, construction, operations, readiness and real estate activities 

associated with the Corps of Engineers' water resources management activities in the Columbia River basin. In my testimony, I 

will briefly describe the Corps' hydroelectric generation facilities in 

the Northwest and how they are managed. I will address the outage of August 10, 1996, as it relates to the Corps' operation and 

management. I will also explain the actions that the Corps has 

taken since the incident to help this multi-jurisdictional power system respond to such abnormal occurrences. 

The Corps of Engineers operates and maintains 21 hydroelectric 

projects in the Western Systems Coordinating Council service area. 

The maximum generation capacity at the 21 Corps dams is 12,937 

megawatts, which represents approximately 24.5 percent of the 

hydro power capacity of the Northwest. 

One of these 21 Corps projects is at McNary Dam, located about 

292 miles upstream from the mouth of the Columbia River and 

near Umatilla, Oregon. As a result of the voltage depression in the 

system on August lOth, the generators at McNary tripped off in 

order to protect the equipment. 

Power generated at the Corps projects is marketed and transmitted to customers by another Federal agency, the Bonneville Power 

Administration. Many factors affect how these dams and reservoirs 

are managed to produce power. The Columbia River Treaty regulates how water and power are traded between the United States 

and Canada, and the Pacific Northwest Coordination Agreement 

specifies how power is produced and shared among regional utilities. 

There are also many non-power uses for the Columbia River that 

affect how Corps facilities are operated. The dams and reservoirs 

that the Corps operates are multi-purpose projects that balance the 

demand for hydro power with other legitimate uses for the water, 

including navigation, flood control, water supply, recreation and 

fish passage. All these factors are considered in the development of 

operation plans for the reservoirs in the Columbia River system. 

The Columbia River and its tributaries are home to salmon and 

sturgeon that annually migrate the rivers moving past these series 

of dams that have been constructed in their path. During critical 

fish passage periods from April through August, water control and 

hydro power operations are managed to avoid jeopardy to salmon 

and sturgeon that are protected under the Endangered Species Act 

and to mitigate impact to other important fish and wildlife resources. 

To facilitate fish migration, extra releases are allowed to bypass 

the generators at carefully timed intervals. This activity requires 

close coordination among the Corps' water managers, Bonneville 

Power Administration's dispatchers and power plant operators. 

Following the power disturbance that occurred on August 10, 

1996, the WSCC released findings concerning the July 2-3 and August 10, 1996, disturbances. The council's findings as they relate to 

the Corps operations are paraphrased as follows: the power system 

experienced depressed transmission system voltage prior to 

McNary tripping; the McNary generators tripped off sooner than 

would have been expected based on power system studies; the level 
14 

of generator voltage support available in the Hanford area was inadequate to prevent system collapse; and the North American Electric Reliability Council recommendations in the report entitled 

"Survey of Voltage Collapse Phenomena" need to be implemented. 

After this incident, the Corp~. performed its own assessment of 

the performance of the generat ion equipment. We found that the 

McNary units performed as originally commissioned by the manufacturer. During the period of depressed transmission system voltage just prior to the system shutting down, McNary provided voltage support above machine design capacity for about 5 minutes. 

Eventually, however, this was insufficient to overcome the losses 

elsewhere in the system and the generators tripped off. 

The 13 McNary generating units shut down in a self-protective 

mode in response to the major voltage depressions that were occurring in the transmission lines. The automatic tripping of the 

McNary generators is a safety measure that protects the equipment during such abnormal fluctuations in voltage. 

While we found that equipment performance was generally consistent with our expectations, we also learned that the power system voltage in the McNary area was depressed far below any level 

anticipated, placing a higher than expected demand on the McNary 

units. As a result, the McNary units tripped off sooner than we had 

expected. We do not know that had the units stayed on line a few 

minutes longer the ultimate result of the incident would have been 

any different. 

Although the tripping of the McNary units was only one of the 

problems associated with the outage, we have identif1ed a few improvements we can make that will help us respond if we are faced 

with a similar event in the future. These measures respond to the 

WSCC's f1ndings and recommendations and our program for improving the availability of generation and equipment reliability. 

We are making some adjustments to fhe McNary and other units 

that will improve their response to an impending voltage collapse 

in the system. We are improving coordination among Bonneville 

Power Administration, WSCC and the Corps to assure that everyone involved is aware of the capability of Corps equipment in operation. 

These measures that the Corps is taking will not by themselves 

prevent any future incident like the one we just experienced, but 

they will assure that the Corps' operated and maintained facilities 

are more responsive to the power system's future requirements. Together with steps that can be taken by other players in this power 

network, the whole system will be more reliable. 

Mr. Chairman, this completes my testimony. I would be happy 

to respond to questions. 

[The prepared statement of Mr. John E. Velehradsky may be 

found at the end of the hearing.] 

Mr. DOOLITTLE. Thank you very much. 

Let me try and understand. I have read quite a bit of this material. It takes a great deal of power to keep pushing the voltage 

through the lines, does it not? Is not that the problem, you were 

suffering from low voltage once some of these lines had gone down 

and you were trying to beef them up and that is what the McNary 

generators were supposed to kick in and do, but they did not? I am 
15 

just trying to get the big picture here as to what is happening 

when we lose these huge transmission lines. Can I get one of you 

to comment on that for me? 

Mr. HARDY. I suppose the best analogy is water through a hose, 

Mr. Chairman. You need both voltage and current to produce 

power. One is analogous to the amount of water going through the 

hose and the other is analogous to the spigot that you are using 

to adjust it. You need to have both to maintain a reliable power 

system. 

The voltage support/voltage collapse phenomenon is frankly one 

that is relatively new in the power industry that we are all struggling with to understand. Our system as originally designed, places 

most of our voltage support at the California-Oregon border. That 

is where most of our major generation is and that is where most 

of our voltage support was. 

As a result of a variety of changes in system operation, not the 

least of which is the fish spill program that we now have, and to 

some extent the availability of generation on the Columbia River, 

our system center has essentially moved north by a couple hundred 

miles, and the voltage support has not moved with it. We expect 

one of the results of the blue ribbon panel study will be to identify 

where we need to add additional voltage support to make sure that 

when you have other outages, either on lines that were involved on 

August lOth or other lines that are critical support of the AC 

intertie system, we will have an adequate voltage support or reactive capability margin to prevent the recurrence of those events 

Mr. DOOLI'ITLE. I guess what intrigues me is that, it seems like 

the way the system was set up, you were trying to generate more 

power to make up for the loss of the lines. Alternatively, you talked 

about the issue of cutting schedules, which I assume means reducing the amount of power that is produced, right? 

Mr. HARDY. Right. That is correct. 

Mr. DooLI'ITLE. So are there two ways that this problem could 

be dealt with, either produce more power or produce less? 

Mr. HARDY. There are a whole variety of ways that it can be 

dealt with. Let me try to give you some feel for the different dimensions of how one can tackle this. 

One is to keep producing the same amount of power but install 

additional reactive equipment at key points to prevent voltage oscillations. The second is to cut schedules. If you see a problem developing or something you think might be a problem, then you simply reduce the amount of throughput. 

That is what we have basically agreed with Pacific Gas and Edison to do as an operating matter to protect the system now and/ 

or to reduce the overall transfer capability of the system to the 

3200 megawatts that it is now at. 

A third is to increase the amount of generation that is available 

to support those lines at key locations. For example, after we restricted interior capacity to 3200 megawatts, Pacific Gas had run 

studies Sunday afternoon with these restrictions intertie then restricted to 3200 megawatts and facing record peak loads coming up 

that Monday, August 12, they did not know whether they could 

carry the load, so we were facing a third potential outage. 
16 

At that time, we completely curtailed the fish spill program at 

The Dalles Dam. The Dalles, again, like McNary, is relatively near 

to the northern terminus of the intertie. That gave us another 800 

megawatts worth of generation and enough associated voltage support that we could take the 3200 limit on the intertie and raise it 

to 3600 megawatts temporarily. We did curtail fish spill at about 

8:30 a.m. Monday, and kept that in effect until Thursday, when 

Diablo Canyon started to come back on line. But that essentially 

prevented the lights from going out a third time in California. That 

Action created considerable political controversy within the Northwest, vis-a-vis the endangered fish that were involved, but that is 

another issue. 

But my point here is you can also solve the problem by having 

a greater amount of generation available at key points as well as 

installing reactive as well as cutting schedules or taking other 

operational actions or having a variety of other automatic control 

schemes. We are really proceeding on all of those fronts, both within the sphere of the WSCC reeommendations as well as our own 

voltage support study and the other recommendations that I described to you in my testimony. 

Mr. DOOLITILE. This issue of The Dalles, I think I read some 

place that only 16 percent of its power generating capability was 

being used on August lOth. I guess that the rest was devoted or 

foregone in order to support the fish flow. Is that according to your 

understanding? 

Mr. VELEHRADSKY. At the time of the outage or the disturbance, 

we were scheduled to pass 64 percent of the flows to support the 

fish passage requirements. 

Mr. DOOLITTLE. And I guess ultimately at The Dalles, as you 

said, they went ahead and changed that around, terminated the 

fish flows and ran it through the generators. Is that what happened on Monday? 

Mr. HARDY. That is correct. That is exactly what happened. We 

declared an emergency. I went to John's boss at the Corps of Engineers and to the regional director of the National Marine Fisheries 

Service. 

We declared an emergency, suspended the spill program which 

allowed us to take that unit from about 400 megawatts up to about 

1200 megawatts of generation which, along with the associated reactive capability, allowed us to take the total transfer capability in 

the AC system from 3200 to 3600 megawatts, which was the margin that allowed Pacific Gas to meet load. 

Mr. DOOLITILE. How many hours did it take from the time-is 

it you as the administrator who declares the emergency? Is that 

the procedure? 

Mr. HARDY. It takes a joint kind of declaration among the three 

of us. 

Mr. DOOLITTLE. The three entities? 

Mr. HARDY. I would say the key decisionmaking official here is 

really not either of us, but the head of the National Marine Fisheries Service who has to say that this in fact meets the criteria for 

an emergency under the biologic opinion in the Endangered Species 

Act and we were able to get his immediate concurrence and do this. 

Mr. DOOLITILE. And is that the national head of it? 
17 

Mr. HARDY. No, just the regional head. So we can handle the 

problem and did handle the problem in the region. I think one of 

the issues, Mr. Chairman, that we are going to look at as we do 

the voltage support study is can we get that down a level furtherto the dispatchers-and have a set of criteria that if the system is 

started to get in extremist, the dispatcher can take an action to 

suspend the spill program in order to stabilize the system. 

We did not have such an approach in place on August 10, nor 

do we now have such an approach, but this highlighted, I think, 

the need to develop one in a way that would be satisfactory to the 

fish interests in the Northwest. 

Mr. DOOLITILE. Now, under that proposal, the dispatcher is an 

employee of BPA, is that right? 

Mr. HARDY. That is correct. Mr. DOOLI'ITLE. So how would this work if your proposal took effect? Who would he have to consult with in order to suspend the 

fish flow, for example? 

Mr. HARDY. The idea, again, I am speaking in advance of what 

is going to require an elaborate amount of consultation and agreement within the Northwest--

Mr. DOOLITTLE. Sure. Mr. HARDY. [continuing]--but the idea would be that the dispatcher would have the unilateral ability, if he saw the system 

being in trouble, to call up the Corps plant manager and say curtail the fish spill operation, which can be done in a minute or two. It is a fairly quick operation. But, for example, there was 5 minutes 

between the time that Keeler-Allston sagged into the trees and we 

lost McNary. 

We clearly knew we had significant problems when KeelerAllston went into the trees. If we would have had the ability at 

that time to call up the plant operator at The Dalles and he/she 

would have been empowered to take that direction from the Bonneville dispatcher, the outage might have been avoided and we might 

have been able to stabilize there. That is the kind of a system that 

I think we ought to seriously investigate as one of several mitigative measures that we might be able to take. 

Mr. DoOLITILE. I am just curious. I have recently-in fact, Mr. Bonsall, I had the privilege of touring some of your facilities in Salt 

River, and we went to Hoover Dam and saw several other major 

power generating facilities. Is it literally a telephone call that you 

propose when this happens? Is there some other means? I know the 

controllers sit there. I think from Glen Canyon they control several 

dams from that one physical location. Is it a telephone call? Do you 

have to hope the guy is not on a break? Or is there some electronic 

communication that would occur? 

Mr. HARDY. It depends on which facility you are talking about. 

Some of them are telephone calls, some of them we have automatic 

generation. Most of them we, in fact, have automatic generation 

control equipment. But I think the key here is the Corps plant 

manager is the guy who has the ultimate responsibility for overriding or complying or not complying. The circumstance relative to 

the fish spill program that we both faced, the Bonneville dispatcher 

and the Corps plant operator at The Dalles, was that neither of 

them were authorized to curtail that fish program, absent going all 
18 

the way up to my level, and to the regional director of the National 

Marine Fisheries Service. 

That clearly is not going to happen at 3:45 on a Saturday afternoon. And what we have to do is operationalize that at the working 

level, hopefully to have some agreement where if you meet certain 

criteria you can do that immediately. 

Mr. DOOLITTLE. I have to tell you, considering how big these bureaucracies are and how many of them there are, I am very impressed that you were able to make that happen in time for Monday. 

Mr. HARDY. We had about 30 minutes before I think Pacific Gas 

was going to get in significant problems, but fortunately we had 

the right people in the right places and we were able to do that. 

Mr. DooLITTLE. The time it takes to make that decision would 

be a rather extraordinary record for quick action, would it not? 

Mr. HARDY. I guess it is relative to your view of how quickly Federal agencies react, Mr. Chairman. We took the action and, like I 

alluded to before, there was a consequence to taking that action, 

a week of fairly substantial political controversy within the Northwest context about the appropriateness of that action or other actions. Mr. DOOLITTLE. It has been my observation that even the remote 

possibility of such controversy has paralyzed Federal agencies from 

acting decisively, at least in any situation I am familiar with. I 

mean, was this an extraordinary occurrence in your mind? 

Can anybody think of a recent example where this kind of concerted action, going against the flow, so to speak, has been able to 

occur? 

Mr. HARDY. I have been administrator for 5 years. I cannot think 

of another comparable set of cireumstances, but I was basically the 

guy that made the decision and to my mind there was no question. 

We had a bona fide emergency and we had the needs of some legitimately endangered fish pitted against a basic health and safety 

issue relative to putting the lights out a third time in California 

and there was not any question relative to that. And in fairness, even in the Northwest, when you question the 

fisheries advocates closely, they were not suggesting that was an 

inappropriate decision. Most of their criticism was focused on could 

you not then have taken other actions, to mitigate the consequences of curtailing the spill program. A fair question and we 

probably were not able to act as quickly on that front as we might 

otherwise have done. Mr. DOOLITTLE. Let me ask to speculate on this. Assume that 

you had this new proposal you are talking about in effect that time 

on August lOth. The dispatcher, I guess, could have sent the word 

and fired up The Dalles. Do you believe that would have stopped 

the outage that subsequently occurred? 

Mr. HARDY. Hindsight is perfect. I think it certainly could have. 

I would say it is probable that it would have, but I cannot say with 

absolute certainty. Mr. DOOLITTLE. Do either one of you other gentlemen want to 

comment? 

Mr. BONSALL. I think we will have a better idea on that upon the 

completion of the studies that are currently underway. 
19 

Mr. DooLITTLE. I read that-what are there, three AC 500,000-

volt lines in the California-Oregon Intertie and one DC, is that correct? 

Mr. HARDY. That is correct. Three AC and one DC. They are in 

different locations. 

Mr. DooLITTLE. I think the oldest of them is the DC line, is that 

right? It seems like the newer ones were AC lines. Is that because 

those are felt to be preferable or maybe they serve different functions. I do not know. 

Mr. HARDY. They do serve different functions. The first two built 

were the two AC lines, then we built the DC and then the third 

AC line, which is in a separate right-of-way from the first two AC 

lines. And that was more of a matter of the kind of economics that 

I described in the opening part of my testimony. 

I think we all agreed with the California owners that added capability which took the total transfer capability of the AC system 

up substantially could allow us to trade additional power back and 

forth on a seasonal basis to the economic benefit of both Californians and the Northwest. 

Mr. DOOLITTLE. Bonneville has about 15,000 miles of high voltage transmission lines, is that right? 

Mr. HARDY. That is correct, Mr. Chairman. 

Mr. DOOLITTLE. I am just curious. I have often wondered this as 

we fly around and see these transmission lines out in remote areas. 

How do you keep all the vegetation away from those? 

Mr. HARDY. We have a combination of ground patrols and aerial 

patrols to try to spot those problems when they occur. Typically we 

do at least one ground patrol each year and three aerial patrols a 

year to try to monitor the growth of vegetation in the various rightof-ways on all of those lines. 

Mr. DOOLITTLE. And so in 1 year you mean there are people 

physically out there on the ground over those 15,000 miles? 

Mr. HARDY. Yes, sir. 

Mr. DOOLITTLE. How many people are devoted to this purpose? 

Mr. HARDY. We have a total of about 1,600 people in our total 

transmission organization. My guess is you have a total of maybe 

a couple hundred that are basically the line crew people conduct, 

patrols along with a variety of other maintenance functions on that 

15,000 miles of line. So you are not just looking for brush clearance, you are looking for shot out insulators, you are looking for 

a variety of other equipment problems. 

I used to be an area manager for the Puget Sound area 15 years 

ago at Bonneville and you regularly fly all of those lines looking for 

a variety of problems. One of them is vegetation management, but 

you have a number of other things, particularly damaged 

insulators, that you are looking for, which could be equally problematic in causing an outage if you are not careful and attentive 

to replacing those. 

Mr. DooLITTLE. You can tell from the air whether you have damaged insulators? 

Mr. HARDY. Yes, sir. That is the principal means-you can fly the 

helicopter actually quite close. We take videotapes of most of our 

flyovers so we can go back and review the tapes. Some of the recommendations that I described, the 46 recommendations in our 
20 

vegetation management program to do we need to change the type 

of videotape to get a better picture. We are also going to add a 

fourth aerial patrol each year focusing just on vegetation management. 

One of the problems we discovered we had is when you are asking the observer in the helicopter to look for both damaged 

insulators, other equipment damage and high brush,. you are probably asking him to do too much. So we are going to institute a 

fourth kind of flyover of the entire system, looking just the amount 

of brush control combined that action, with the ground reports, and 

clarification of responsibilities among line crews and the other individuals in the individual maintenance districts, will produce a 

much more comprehensive approach to vegetation control. 

Mr. DOOLITTLE. And how far off the ground are these transmission lines typically? I mean, I guess there is a minimum legal 

standard, is that right? 

Mr. HARDY. I would say typically 40 to 60 feet, sometimes higher 

than that. 

Mr. DOOLITTLE. And when you talk about brush, we would think 

of that as the trees, right? 

Mr. HARDY. Right. You are talking about trees as opposed to 

brush. Particularly in Western Oregon and Western Washington, 

given the rainfall that occurs there, an alder or a cottonwood can 

grow eight to ten feet in a single year. 

Mr. DooLITTLE. So when you control that type of vegetation, do 

you cut the tree down or do you just scale the tree and cut off the 

last 15 feet or something? 

Mr. HARDY. It varies. Sometimes you cut it all the way down, 

sometimes you just scale it, as you have described. 

One of the other things that we have concluded is that hand cutting, whether you are scaling or whether you are completely cutting the tree down, in fact stimulates tree growth in a variety of 

ways. Hence, one of the recommendations that I described earlier 

is going back to hand application of herbicides to selected trees 

where you can actually kill the tree permanently but yet not 

spread the herbicide to surrounding areas. And we eoncluded that 

probably our virtual cessation of use of herbicides in 1984 created 

some problems that we did not fully appreciate at the time. 

Mr. DOOLITTLE. In 1989, who made the decision or at what level 

was that decision made to suspend using herbicides? 

Mr. HARDY. I am not sure, Mr. Chairman. I would like to answer 

that for the record, if I could. 

[The following was submitted:] 

HERBICIDES DISCONTINUANCE 

The Bonneville Power Administration (Bonneville) restricted the use of herbicides 

to spot and stump application and control of noxious weeds on Bonneville's rightof-ways in March of 1984. This decision was made by the senior management official 

responsible for Operations and Maintenance of the Transmission system at the time. 

Mr. DooLITTLE. OK. But, as far as you know, was that something 

that was peculiar to Bonneville? It was not something that occurred across the country, was it? 

Mr. HARDY. I do not think it was peculiar to us at all. In the 7 

years before I took over as Bonneville administrator in 1991, I ran 
21 

the Seattle municipal utility, which is the sixth or seventh largest 

municipal utility in the country, and we had done the same thing 

back in the mid 1980's. 

For environmental reasons, we had completely ceased using herbicides and gone to basically handcutting and other forms of vegetation management. And I think there was a trend in the industry 

to do that as a result of the kind of controversies over 2-4-D and 

other kinds of herbicides in the early 1980's that had some fairly 

severe environmental consequences. 

Today, you have more environmentally benign herbicides and I 

think we have a more selective way to go about that. 

Mr. DoOLITTLE. As you understand it, and I assume you were not 

there in 1989 when this decision was made--

Mr. HARDY. No, sir. I was not. 

Mr. DOOLITTLE. But was it because of this so-called political controversy that the decision not to use herbicides was made, or was 

it because there was actually some legal impediment imposed by 

the environmental laws? 

Mr. HARDY. I am not certain, Mr. Chairman. I expect it was more 

the former than the latter. And not just a political controversy but 

a genuine concern about responsible management in the right-ofways and what was the right balance between managing these 

right-of-ways in an environmentally responsible fashion versus 

maintaining a reliable power system. 

And, like I said, for the two utilities, Bonneville and Seattle City 

Light, that I have been associated with, both of them made the 

same decision to completely cease herbicide use and I suspect there 

are a number of other utilities nationwide that if they did not completely cease, significantly cut back because of the controversies 

that had resulted in the 1970's and early 1980's over more extensive herbicide use. 

Mr. DOOLITTLE. Prior to 1989, was it your understanding that 

utilities preferred not to let any trees grow underneath the power 

lines? 

Mr. HARDY. No, you let some trees grow but you used a variety 

of control techniques. The fastest growing trees like alder, were 

typically where you would use herbicides. For example if an alder 

is 15 feet tall, you can cut it at the base and 2 years later it is back 

at 20 feet. That is not a particularly cost effective way to manage 

your right-of-ways nor, in retrospect, is it the safest way. 

Mr. DooLITTLE. I think I read that since the August lOth outage 

you have inspected 2000-some miles of your right-of-way and I 

guess dealt with that. How long will it take you to cover the rest 

and get it taken care of? 

Mr. HARDY. We patrolled and inspected all of the miles of rightof-way that are critical or central to support and protection of the 

AC intertie system. Throughout the remainder of this fiscal year 

we are currently in, we will do the rest of it on the normal schedule 

with the additional helicopter patrol that I described before, but I 

am pretty confident that we have already patrolled and cut, in an 

initial phase, all of those right-of-ways that are most critical to the 

reliable support of the AC intertie system. 

Mr. DooLITTLE. When these lines are heavily loaded, they normally sag, right? 
22 

Mr. HARDY. That is correct. 

Mr. DooLITTLE. What is the :range of movement anyway on high 

tension lines? 

Mr. HARDY. It is considerable. As I recall, to give you one example, as I recall the WSCC report on the July 2nd outage relative 

to the Pacific Corp line that was involved in between Idaho and the 

Bridger Cole plant, there was a sag of something in excess of 40 

feet, I think. 

And I might say that while this is a matter we are still investigating, we have some number of feet unaccounted for in the formulas and the standards that we have used, which is a function 

of both ambient temperature and line loading, as to how far the 

lines sag. And we have basically just adapted industry standards 

for ours. 

On some of the key lines, John Day-Marion and Big EddyOstrander, I have about-what is it, Vickie, five to seven feet? Yes. 

Five to seven feet that I cannot account for yet. I mean, my formula says the line should not have sagged into the tree and yet 

it did. Or it got close enough, two, three feet, to flashover. 

But before we reach a conclusion here, I have asked our staff to 

go back and talk to some of the East Coast utilities who have similar problems and try to get a better handle on whether this is a 

standards problem, or is it that we just did not know something 

that we should have known or what. 

Mr. DOOLITTLE. Now, when it touches the tree, it shorts out the 

line. What happens to the tree? 

Mr. HARDY. The tree gets burned. Sometimes you start a fire. So 

there are other issues involved as well. 

Mr. DOOLITTLE. So if the lines are only 40 feet off the ground and 

they sag 40 feet, I mean, hopefully those are 60 feet off the ground, 

but there is a fairly dramatic movement. Much more than I realized. 

Mr. HARDY. You have a huge amount of movement that can occur 

on a hot day with heavily loaded lines. I mean, 20, ao feet easily 

and those are some of the problems that frankly we are all struggling with. I think if you talk to Idaho Power, and PacifiCorp relative to the July 2nd outage, they would say they cannot figure out 

how that line sagged into a tree; that it was well beyond anything 

that they had contemplated, even though that was an isolated incident as compared to what we were dealing with. 

Mr. DOOLITTLE. That was one incident. I think there was another 

one. The two incidents of this type occurred about a month before 

the August lOth incident and I am just wondering, did that set off 

warning bells for anyone? In light of what subsequently happened 

where essentially the same type of thing happened. 

Mr. HARDY. It should have and it did not. 

Mr. DooLITTLE. As you have analyzed the structure with BPA, 

now with hindsight, why did it not? 

Mr. HARDY. I think-those outages were on more lightly loaded 

lines. It was a case of not expecting that those lines would be integral to the support of the AC ,system and a matter of still struggling with what appeared to be other more significant problems 

that were the cause of the July 2nd outage. These lines occurred 

in the July 13th and 14th, I think. 
23 

And we were still focused on the voltage supportJvoltage collapse 

phenomenon, in this case, as it affected Idaho Power service territory and how that created a cascading outage that came through 

our system. As a result of that kind of focus and a variety of management reporting issues within the particular districts involved, 

we did not pay sufficient attention to that. In retrospect, we clearly 

should have. 

Mr. DooLITTLE. Just for my information, a 500,000 volt line, is 

that the biggest line? 

Mr. HARDY. That is the biggest one that we have. There are 

some, some sections of the country have 765 lines and that is about 

the biggest in the U.S., I think. 

Mr. DooLITTLE. Well, what is the diameter of a 500,000 volt line 

anyway? 

Mr. HARDY. About like that. Probably six to eight inches for out 

typical bundle of three conductors. I mean, these are big, big lines. 

They are not something that even de-energized you can horse 

around manually. It is something that requires high powered 

equipment to deal with. 

Mr. DOOLITTLE. So I guess wherever you have these passing 

through you have roads nearby to get that equipment into? Is that 

how it works? 

Mr. HARDY. That is right. You have to have access roads to get 

in. Typically, these are-at least the 500 and 230 lines are all on 

steel towers as opposed to wood poles, pretty massive kinds of steel 

structures. You have to have access roads sometimes in pretty remote territory. 

For example, one of the complicating factors that we had in responding in the vegetation management area were the significant 

floods in the Northwest in the February timeframe that wiped out 

a variety of our access roads. Some of these areas that we simply 

could not physically access until the roads were repaired. So there 

were a variety of complicating factors in retrospect that prevented 

or inhibited our ability to provide adequate maintenance. 

Mr. DOOLITTLE. Has there been a drop in the reliability of the 

Corps facilities over the last 10 years, in your opinion? 

Mr. HARDY. John? 

Mr. VELEHRADSKY. I do not know whether I could address reliability. We have had a drop in the availability of units. 

Mr. DOOLITTLE. Because it seems to me I recall in another hearing seeing that projected. 

Mr. VELEHRADSKY. Yes. 

Mr. HARDY. I would make the same observation, Mr. Chairman, 

that Mr. Velehradsky did. I could not comment per se because I 

have not seen statistics on reliability, but there has been a definite 

drop in the availability of units and there are a variety of factors 

associated with that, not the least of which I think is the Federal 

appropriations process. 

Mr. DOOLITTLE. Well, do you think there is a problem with the 

government's maintenance, then, of the equipment, since I guess 

that is what the appropriations process would relate to? 

Mr. VELEHRADSKY. We do have units that need to be rehabilitated. We have a study underway, for example, right now at Ice 
24 

Harbor for rehabilitation of the units at Ice Harbor, so there is a 

process underway. 

Back in about 1989, there was a change in the way we funded 

those kind of activities. We went from the operation and maintenance account to the construction general account, so I think we 

are moving in a direction to get more units available. 

Mr. DOOLITTLE. Mr. Hardy, the WSCC has recommended mandatory membership and the ability to issue sanctions. What is the administration's position on the Federal entities being subject to 

WSCC sanctions? 

Mr. HARDY. I do not know that the administration has formally 

addressed this. I can tell you my personal position is that is appropriate and if there are constitutional or other issues, I am sure we 

can work out the requisite agreements with WSCC to fix those. 

Typically, we have complied with virtually all WSCC recommendations, so from Bonneville's perspective, I do not see that as a problem. 

Mr. DooLITTLE. I want to go back to this proposal that you are 

making to modify how you can, in an emergency, declare an emergency and re-operate the dam when you have the fish flows involved. Is that a change that the three agencies can just make 

amongst themselves? What sort of action is that going to take in 

order to be implemented? 

Mr. HARDY. I think it is possible that with the agreement of the 

three agencies we can do that but there are a number of predicate 

steps. First we need to complete the voltage support study so we 

can identify in a quite precise fashion what benefit this provides. 

I do not want to go back to the fish interests in the region, Federal, State and otherwise, until I can tell them exactly what I think 

the exposure is and what the choices are vis-a-vis other measures 

that we might institute. Secondly, it would require--and we are proceeding with this 

now-very extensive consultations with the State fisheries agencies, the Indian tribes, the National Marine Fisheries Service, and 

the U.S. Fish and Wildlife Service. Everybody would then have a 

clear understanding under what conditions this would be done and 

how it would be done and, probably most importantly from their 

perspective, if it is done what are the mitigating actions that Bon- neville, the Corps, the Bureau of Reclamation would take to try to 

minimize the impact on fish. I think we need to be clear on all 

those points, and then I am optimistic that we can reach some 

agreement to make this happen. 

Mr. DooLITTLE. For what period was The Dalles re-operated? 

From when you began it on Monday, for how many days did that 

go on? 

Mr. HARDY. It went on through about mid-afternoon on Thursday. 

Mr. DOOLITTLE. OK. 8~ 

Mr. HARDY. We were doing this on almost an hour-to-hour basis 

with Pacific Gas, checking with their dispatchers and their systems 

operations people on what the loads were, what they needed, how 

serious their circumstance was. During that time I was talking several times to Bob Glen, who was their chief operating officer, at the 
25 

policy level to make sure that we had a clear sense of what was 

happening. So it went on for three-and-a-half days. 

Mr. DOOLITTLE. And do you have some sense or is there some estimate of how many fish were killed or negatively impacted during 

that three-and-a-half days? 

Mr. HARDY. I would say there were about 2000 juvenile fish total 

and probably half a dozen endangered juvenile fish. 

Mr. DOOLITTLE. Half a dozen endangered fish? 

Mr. HARDY. Yes, sir. 

Mr. DooLITTLE. Which is the real reason the fish spills are being 

done, right? 

Mr. HARDY. That is correct. 

Mr. DOOLITTLE. And the value-just as long as we are talking 

here, if we have a half a dozen endangered fish, what is the value 

of the power generation that is being lost as a result of the fish 

spills? 

Mr. HARDY. I would like to answer that one for the record, Mr. 

Chairman. I would have to be specific about that particular spill 

operation. 

[The following was submitted:] 

LOST POWER GENERATION DUE TO FISH SPILLS 

During the emergency (August 12-15), spill at The Dalles was reduced. This re- duction resulted in increased generation at this project of approximately 60600 

megawatthours or 361 average megawatts for the week (7 days). At the prevailing 

rates for surplus energy during that period, this amount of energy results in about 

$1.0 million in sales. Following the emergency, Bonneville provided spill for an additional four days resulting in offsetting loss in sales. 

Through evaluations of fish spill required under the 1995 National Marine Fisheries Service' Biological Opinion, Bonneville estimates that the spill program results 

in lost revenues averaging $38.3 million per year. This is an average of 50 water 

years with a range of $2.1 to $93.7 million. This cost includes spill at the mainstream projects according to the Biological Opinion provisions. 

Similar analysis for The Dalles projects yield an average cost for fish spill of $16.6 

million with a range of $0.8 to $39.3 million. 

Mr. DooLITTLE. I mean, would you guess, is it in hundreds of 

thousands or millions of dollars? 

Mr. HARDY. Probably the latter. 

Mr. DOOLITTLE. OK. I just think it is important that we bring 

these things out, for half a dozen fish. 

Now, were the McNary Dam units configured differently, Mr. 

Hardy, than BPA understood them to be? 

Mr. HARDY. I think that we did not, and I do not know that the 

Corps did, fully appreciate the way that the McNary units would 

react when faced with the kind of voltage oscillation circumstances 

that occurred after Keeler-Allston went out. 

I cannot answer whether they were different than other units or 

not, but we did go after the outage occurred, go with the Corps and 

with a team of WSCC technical generation experts, and we reset 

the exciters. We are now in the process of replacing the associated 

control relays so they will not trip off line if exposed to a similar 

kind of circumstance. 

The WSCC panel that has looked at this has agreed if we complete the installation of that equipment, which should occur next 

week, and then test it in accordance with a testing protocol that 

we have reviewed with the WSCC panel, that that should be ade-
26 

quate to go back to relying on the full capability of the McNary 

units. I would expect that we would have that fully completed with- in the next 30 days. 

Mr. DooLITTLE. Mr. Bonsall, do you have anything that you want 

to share in that regard? 

Mr. BONSALL. No, sir. I do not. 

Mr. DoOLITTLE. And Mr. Velehradsky? What do you think went 

on? It seemed like there was some discrepancy, somebody thought 

that these were different than in fact they were. Mr. VELEHRADSKY. Well, basically we had set them to certain 

limits and they performed well above those limits and so that is all 

I can speak to at this point. They performed about 5 minutes above 

the limits that we had set them. Following the disturbance, I think Bonneville, WSCC, and ourselves and others looked at the situation and that is when the relay 

issue was discovered. We had a faulty relay, and we needed to set 

some tap settings on exciters that were a little bit out of tune. So 

those actions have been taken care of. 

Mr. DOOLITTLE. Why were they out of tune or why did you not 

know they were out of tune? 

Mr. VELEHRADSKY. They had not been tested in that state, the 

dynamic state, I believe. 

Mr. DOOLITTLE. Well, is such testing in a dynamic state thought 

to be the best industry practice? 

Mr. VELEHRADSKY. Well, what we are going to do is with Bonneville and the Western States Coordinating Council is we are going 

to train our operators and maintenance folks in that testing procedure and we will have a more rigorous testing program in the future. 

Mr. DOOLITTLE. Mr. Bonsall, with Salt River, do they do this 

kind of dynamic testing? 

Mr. BONSALL. You know, I would have to answer that one for the 

record myself. I need to check on that, Mr. Chairman. 

Mr. DOOLITTLE. OK I am just trying to get some sense. It seems 

like they certainly should have. Maybe we can ask our investorowned utilities when they come up here in Panel III what their 

practice is, but I think it would be interesting to get that for the 

record just to see the comparison. There is a recommendation, Mr. Bonsall, on page 16, or a comment, of this disturbance report which is very thorough, it says, 

"All transmission owning members shall evaluate the need for 

changes in the tree trimming policies of the U.S. Forest Service 

and other Federal land agencies and submit recommended enhancements to WSCC." Could you comment upon that? Are there 

problems with the tree trimming policies of the Forest Service? 

Mr. HARDY. Mr. Chairman, if I could, I do not want to speak for 

WSCC, but I think I know what the recommendation is trying to 

get at. 

Mr. DOOLITTLE. OK 

Mr. HARDY. And it is one of our 46 in our vegetation management problem. We all have lines that cross Forest Service and 

BLM lands and there are a variety of different standards, particularly environmental standards, when you can use herbicides, when 

you cannot, what you can cut, what you cannot, when you have to 
27 

do an environmental assessment, when no environmental work is 

required, when is some greater environmental work required, etc. 

and I think it is fair to say, given the organizational structure in 

those two agencies, in the Forest Service in particular, that there 

is not complete consistency among different districts as to what requirements are. That is tremendously frustrating to a utility, 

whether that is a federally owned utility like Bonneville or whether 

it is an investor owned utility, relative to executing a consistent 

vegetation management program over 15,000 miles worth of rightof-way when you have 20 different standards in different areas 

that you are trying to comply with relative to the degree of environmental paperwork that needs to be done or what you can actually do on the ground. And I suspect that is part of what the WSCC 

recommendation is trying to get at. 

Mr. DOOLITTLE. When you say different districts, do you mean 

different national forests or do you mean different ranger districts 

within the same national forest? 

Mr. HARDY. I mean different ranger districts within the same national forest. 

Mr. DooLITTLE. They have different standards? 

Mr. HARDY. All I can tell you, Mr. Chairman, is there is considerable variation. There is a lot of autonomy given to individual districts for I am assuming legitimate management purposes, but that 

leads to considerable variation in what the requirements are for 

particularly environmental compliance relative to various aspects 

of what I would consider an adequate vegetation management program. We need to work more actively and aggressively with the 

Forest Service and with BLM to try to get better consistency so we 

can execute that kind of a program. 

Mr. DooLITTLE. Let us see now. I think your statistics, Mr. 

Hardy, on the frequency and duration of transmission line outages 

indicate that on your 500,000 volt lines BPA has a frequency of 

outage 60 percent higher than the national average. What do you 

attribute that figure to? Why is it higher? 

Mr. HARDY. I frankly do not know, Mr. Chairman. I would point 

out that our overall reliability rating, 230 and 500, is better than 

the national average by a significant extent and why the particular 

500 rating is worse than national average I would have to answer 

for the record. 

[The following was submitted:] 

FREQUENCY OF OUTAGES ON 500 KILOVOLT LINES 

The reliability statistics in question, the System Average Interruption Frequency Index for 500 kilovolt lines, reports outage frequency on a per-line basis. Since Bonneville's system has a large number of rather long 500 kilovolt lines, any given 500 

kilovolt line on our system has a greater exposure and potential for outages than 

shorter 500 kilovolt lines. Therefore, when compared with utility systems with 

shorter 500 kilovolt lines, outage frequency rates of longer lines will appear relatively higher. In addition, many of our 500 kilovolt lines traverse arid, inland areas where the 

frequency of lightning strikes is great. Lightning-induced outages tend to be very short in duration, often only a few seconds long. The System Average Interruption Duration Index of outages for 500 kilovolt lines shows Bonneville with considerably better performance than the national average as reflected in the Institute for Electrical and Electronic Engineers survey. 
28 

Mr. DoOLITTLE. According to the WSCC report on the August 

lOth outage, some power system stabilizers used to, I understand, 

damp system oscillation were not operational at The Dalles. In fact, 

I guess at The Dalles there were five units on line and three of 

them were without stabilizers and at John Day 13 units on line 

and four without stabilizers. Do you know as of August lOth how 

long had those problems existed? 

Mr. HARDY. I would have to provide that for the record, Mr. 

Chairman. 

[The following was submitted:] 

POWER SYETEM STABILIZERS 

The stabilizers you cited have been out of service since prior to 1993. Power system stabilizers are installed on most Western Systems Coordinating Council generators to provide damping of oscillations. For low frequency oscillations, such as oc- curred on August 10, it is the combined action of many power system stabilizers 

that are expected to provide damping. The absence of operational stabilizers on six 

units at .John Day and The Dalles were not deemed to be critical. 

Mr. DOOLITTLE. OK. Would you, please? I just wondered. And 

how significant are these stabilizers anyway? Apparently the units 

can be operated without them. I just wondered what risk is there 

to doing so. 

Mr. VELEHRADSKY. We can provide that for the record. 

[The following was submitted:] 

SIGNIFICANCE OF STABILIZERS 

The generators at The Dalles Dam and John Day Dam can be operated without 

power system stabilizers. For the August 10 low frequency oscillations, the com- bined action of many power system stabilizers is important, and outage of a few stabilizers will have only a small effect. The Western Systems Coordinating Council re- quires that each company have at least 80 percent of stabilizers in service at all 

times. The United States Corps of Engineers is almost always in compliance with 

this requirement; on August 10 seventy of seventy-seven stabilizers were operating. 

Mr. DOOLITTLE. Sure. OK. Well, I think I have covered most of 

my questions of this panel. 

Mr. Hardy, if you would not mind, would you be available to hear 

the other two panels, since generally the whole hearing relates to 

BPA? 

I would like to thank all three of you gentlemen for your testimony. It has been very helpful. We will excuse panel No. 1 and invite panel No. 2 to come up. 

[Witnesses excused.] 

Mr. DOOLITTLE. Panel No. 2, if you gentlemen would remain 

standing? Will you raise your right hands? 

[Witnesses sworn.] 

Mr. DOOLITTLE. Thank you. 

Let the record reflect each responded in the affirmative. 

Please be seated. 

We have with us today on this panel P. Gregory Conlon, President of the State of California Public Utilities Commission, and 

Renz D. Jennings, Chairman of the Arizona Corporation Commission. 

Gentlemen, welcome. As you can see, it is a fairly free-flowing 

discussion, so do not worry about the lights. They just kind of give 

you an indicator of where we are on this and at the conclusion of 

both of you testifying, then I will ask you some questions. 
29 

Mr. Conlon, you are recognized for your testimony. 

STATEMENT OF P. GREGORY CONLON, PRESIDENT, 

CALIFORNIA PUBLIC UTILITIES COMMISSION 

Mr. CONLON. Thank you. I want to start by welcoming you to 

California. I know that you are a California legislator, but I think 

the committee is a Federal group, so I want to welcome you here 

to California for the commission and the Governor. 

Mr. DOOLITTLE. Thank you. Mr. CONLON. I think the WSCC should be commended for the excellent report that they gave on the outage, as well as its continuing work to system reliability. And since they have already gone 

through the causes of the outage, I do not think I want to do that. 

I thought maybe I would go off my statement a little bit and just 

let you know what we did in California after the outage to confront 

the problems that they just talked about. 

Mr. DOOLITTLE. I think that is great. Your statement is part of 

the record, so please feel free to make any comments you would 

like, knowing that that will, of course, be in the record any way. 

Mr. CONLON. I think on Sunday it became apparent with the 

temperatures over 110 degrees in the Valley with the number of 

units that were out that California had a very serious problem 

starting Monday and Tuesday when everybody went back to work, 

so at the commission we worked with the Governor's office to see 

what degree of emergency we needed to deal with and we concluded after discussing it with the companies that at a minimum 

we would restrict air conditioning usage of all 220,000 State employees during the following week, so we did take that action. 

We went to Oregon on Monday morning with an emergency 

meeting of WSCC and I did participate in the press conference to 

help assure the environmentalists that we did have an emergency 

in California, that it was a serious matter and their decision to declare an emergency to put The Dalles units back up was appropriate. 

We helped the company get the message to consumers in California that on Monday, Tuesday and Wednesday that we had a very 

serious problem and everybody should conserve electricity, so that 

was about all we could do in that short timeframe, but we worked 

with PG&E, particularly PG&E because they had lost the two Diablo units which was making it very critical and their reserves were 

very low during that period because we had record peaks almost 

each day of that week. So it was very touch and go there for those few days, but we 

were able to get through it. The companies, they will, I am sure, 

confirm that, restrained their interruptible customers and we were 

able to get through those 3 days by everything we could possibly 

do. 

So I do think that this is a good example of how to prevent fu- ture outages. I think California as well as the West cannot tolerate 

another outage of the magnitude we had on August lOth. 

I think it gave us all a wake-up call and I think California is a 

three strikes you are out State, that we have had two strikes and 

I know that if we have a third strike of a great magnitude that several of us will be-the fingers will be pointed at us, so I think that 

36-069 - 9 7 - 2 
30 

I want to try and assure you that the California commiSSion is 

going to do everything we can to look at this and deal with it on 

an effective basis. 

The lasting effect of the outage has been that the de-rating of the 

north-south intertie to California from 4750 megawatts down to 

3200 pending the WSCC's review and I think California, we have 

already had a significant loss as a result of the August lOth. 

I am sure it is several million dollars, tens of millions of dollars, 

between the customers and the power that we lost during that period, that we do not want to continue to do that. So we are hoping 

that that intertie situation can be corrected at the minimum by 

next summer so that we would have full availability of that power 

for the companies and the States that are south of that border, the 

Oregon-California border. And as for what should be done in the future, we think it is clear 

that the inspection, maintenance and testing of transmission facilities should be strengthened. The WSCC report details many instances of inadequate tree trimming and equipment failures. I 

think five flashovers occurred on August lOth. And in California, 

I am personally recommending that our commission implement 

periodic inspections by our staff of our high voltage transmission 

system, as well as a review of the utilities' line patrol and tree 

trimming records. 

In looking back at our own staffing, we have safety responsibilities for electric, gas and rail procedures and we had cut back on 

our electricity because of appropriations problems that we talked 

about earlier, and so we are looking at beefing that up now and one 

of the steps that we would consider doing is personally having our 

staff inspect some of these facilities. 

Second, the operating procedures and training of operating personnel need to be reviewed and strengthened and I think that was 

brought out in the report, that the WSCC notes that the operators 

were unknowingly violating WSCC reliability criteria. 

And, third, improved communications and coordinations between 

all utilities and control area operators appears to be needed. The 

one and a half hours before the outage BPA, has indicated in the 

report, did not communicate the loss of the three 500 kv lines. And, 

as indicated, such information if communicated may have alerted 

other control areas to take mitigating evidence. 

There is also evidence that the communications within the control area could be improved and I think you got into that with your 

line of questioning between the Bureau and the Corps and BPA 

and I think the focus of those units, not being from the Northwest 

and not having the political sensitivity that goes on in the Northwest, I think in the peak summer months we would like to see a 

higher focus on electric production, but they have to make those decisions. We would certainly welcome it and hopefully they can 

make some adjustments. 

I believe the system reliability requires enforceable standards 

and rules and there is a clear need to create regional standards 

with a mechanism to impose penalties on entities that fail to operate within those standards. We believe those penalties would need 

to exceed the cost of failure to comply with the standards. Other-
31 

wise, if it is cheaper to not comply than it would be to get the fine, 

then we would have ineffective fines. 

So I think the four steps, improve inspection and maintenance 

operating training and improve communication and coordination 

and enforceable standards, are the goals that we would hope that 

everyone would achieve from this lesson. 

No'v, how do we do that? I think as State regulators, we will 

have an important role to play, but most of these are--at least for 

the non-Federal facilities, because we do do site reviews, we do constructions standards, we perform inspections and enforce safety requirements, so these are the kind of standards that we can deal 

with on a regional basis. 

But standards set by a single State could not be sufficient, so we 

need to coordinate with the other States and I think there are several ways we can do that. First, I think reliance on an independent 

system operator, the use of an interstate compact or ultimately 

maybe an international treaty because we have both Canada and 

Mexico involved in this grid. I mean, we cannot isolate the grid. 

These grids go into these countries and then if there are problems 

there they are going to affect us just as much in California as if 

they were in Mexico or Canada. 

We certainly need to increase coordination between the States 

and interstate compact and increased authority needs to be given 

to the region groups such as WSCC. 

So if I have a couple more minutes, I just could amplify on those 

couple---

Mr. DOOLITTLE. Please. 

Mr. CONLON. OK I think on the ISO, California is moving to promote competition in the electric industry and maintaining system 

reliability is a critical concern. I know in my study of the UK situation that was their primary concern also, that the lights stay on. 

And I think if we start open competition on January 1, 1998, and 

we have a major incident right after that, that it would be very unfortunate. So I think we need to be very sensitive to that. And I think California's answer to reliability will be to create a 

statewide, independent system operator which will set and maintain system reliability standards and we have hired a gentleman, 

David Friedman, who you may or may not know, to help us in the 

next few months to keep that process going. And I think that we 

are fortunate to have David to help us. 

And then as I mentioned, I personally recommend that we develop a region-wide ISO, independent system operator. And as a 

transition, I know that we are developing our own ISO in California and the Northwest is doing the same and I am sure there will 

probably be two or three others that form, but ultimately I think 

a one-region ISO would be the ultimate in reliability because one 

control center would have the ultimate information in front of it. 

It would have communication systems that would eliminate some 

of this communications problem, at least that is our view and I 

would certainly support that as a long-term goal. 

Now, the use of an interstate compact is another way to try and 

do that while the ISO is developing and the California legislature 

has directed our commission to work with the other States to get 

an interstate compact developed if we can in the Western grid. 
32 

Under this compact, all Western States would join together to develop enforceable standards and protocols to protect the reliability 

of the region's electric supply. And since it would probably take 

some legislation, your Committee could certainly be a sponsor of 

any legislation that we would need at the Federal level. Since the 

Western grid is becoming international, it even may get into some 

kind of international treaty or amendment to NAFTA or something 

to get those other two countries involved. 

Improved reliability coordination may not require an interstate 

compact if each state or province on its own would require compliance with uniform standards, such as the WSCC, and if we implemented our own program for enforcements. Models for this type of 

action could include the Western Interstate Energy Board and various other boards that have been established to coordinate rulemaking for multi-State utilities. 

And a final possibility would be to utilize the existing reliability 

council, the WSCC, to functionally perform as an entity that both 

sets and enforces regional standards. For this to occur, the organization and function of the WSCC would have to change. As others 

have said, membership in the WSCC would have to be mandatory 

for all grid users. State regulatory agencies would have to play a 

larger role in setting WSCC policy and WSCC would need sufficient 

staff and, again, more importantly the WSCC would need to make 

sure that failure to meet its standards could result in enforceable 

sanctions, as I previously mentioned. Each of these options for creating regional enforceable reliability standards is worth pursuing. 

I have recently sent a letter to the members of the Committee 

on Regional Power Cooperation, which consists of the State commissioners here in the Western United States, asking them if they 

would work with California in establishing regional reliability 

standards and, additionally, this issue has been discussed at a recent meeting in Santa Fe of this group and we are going to meet 

2 weeks from now in San Francisco and hopefully some kind of a 

compact will result. 

In conclusion, I would like to say that ultimately reliability is the 

responsibility of all of us, the grid users, the utilities, the control 

area reliability councils, the State regulators, the Federal agencies 

and even customers as we move into a competitive market. So as 

this competition increases, it will provide both challenges and opportunities and we look forward to working with each of these 

groups as well as the committee to ensure an efficient, reliable 

electric system in the West. 

Thank you. 

[The prepared statement of Mr. Conlon may be found at the end 

of the hearing.] 

Mr. DOOLITTLE. Thank you very much. 

Mr. Jennings, you are recognized, sir. 

STATEMENT OF RENZ D. JENNINGS, CHAIRMAN, ARIZONA 

CORPORATION COMMISSION 

Mr. JENNINGS. Thank you, Mr. Chairman. I appreciate the opportunity to bring a non-California perspective to this or a non-California-Pacific Northwest perspective. We consider ourselves somewhat 
33 

remote from the triggering events of this, but yet we had a fair 

amount of consequence. 

I would also like to thank President Conlon for his kind offer of 

help. He was not quite sure where Arizona was in terms of difficulties we might be having and he offered to intervene on our behalf. I guess they call that leveraging one's position with the utilities. We do appreciate his kind offer. First of all, I want to approach this with a certain amount of humility. This is pretty technical stuff and I am not an engineer or 

an electric reliability expert. 

Mr. DOOLITTLE. I am not either, so that makes two of us. Mr. JENNINGS. All right. A couple of policy folks here with some 

perspective. The two outages have left us with sort of an interesting risk 

management problem and we certainly know we will not be able 

to eliminate completely the outages, but we can develop reasonable 

risk management strategies that will reduce the possibility and impacts of future outages. 

In order to address this risk management problem, we need to 

look at six aspects and they are: the need for more and better quality information; the need for credible commitments to reliability; 

the need for better communication among utilities and others; the 

need for a clear delineation of responsibility; the need to develop 

better damage control; and the need for participation by all appropriate parties in the development of risk management solutions. Let me take each one of these and discuss them a bit. 

First, the need for more information relates to our need to better 

understand the Western integrated electric grid under a wide variety of possible operating conditions. Rather than merely looking at 

likely single contingency scenarios, known as N-1 scenarios, we 

need to have WSCC and utilities look at models of multiple contingencies known as N-2, N-3, et cetera, scenarios. 

Second, we need to elicit credible commitments to reliability from 

all participants in the interconnected grid. This should start with 

mandatory membership in the WSCC or at least mandatory requirements to meet WSCC minimum reliability standards. A performance bond could be required as a sign of credible commitment 

and could be attached in case of failure to comply with reliability 

criteria. 

Since the two major Western power outages this summer in July 

and August, we have heard over and over again that the safeguards built into the Western interconnected grid worked as designed. The system islanded power plants were tripped to prevent 

equipment damage and loads were shed to help stabilize the system, thereby avoiding a complete shutdown of all Western power 

generation. Yes, it appears that the protective mechanisms worked 

after an irreversible -problem started the blackout. 

While it is important to improve the system in ways that will 

limit the damage from a system outage, it is far more important 

to take steps to avoid the conditions which led to the start of the 

outage. 

This brings me to a major concern that we in Arizona have. If 

in fact the NERC and the WSCC criteria and requirements are appropriate, there is still a major problem ensuring that those stand-
34 

ards are enforced. Unless there are some credible penalties or sanctions applied to those who fail to meet the standards or shirk their 

responsibilities, we will have a reliability system that works in theory, but not in fact. 

Enforcement and penalties can be handled in a number of ways. 

First, WSCC and other regional reliability councils could take on 

the responsibility of enforcement of penalties. Second, the Federal 

Government could take the responsibility. Finally, the various 

State PUCs could take on the enforcement and penalty responsibility. However, achieving uniformity among States might prove difficult. 

My preference would be to have WSCC perform this function. 

WSCC would monitor and measure compliance. Although NERC 

has the national responsibility for reliability, it is not staffed or 

prepared to take on an enforcement mission. Concerted State action might be much more difficult than having one entity in each 

region, WSCC and the other regional reliability councils, handle 

the enforcement of standards. 

Effective enforcement would only be a possibility if mandatory 

membership were made possible by FERC ruling or by Federal legislation. States could require membership, but this would only 

work if each and every State made membership a requirement. 

Third, we need better communications among the participants in 

the Western grid. It is very likely that if we had a better inter-utility communication system on August lOth that the outage might 

have been avoided or at least it might have given enough warning 

so that the resulting impact may have been reduced. 

We need a real time disturbance alert mechanism so that operators on the integrated system can get early warning of problems 

which may affect their system operation. 

Fourth, we need to ensure that as we move to a more competitive 

electricity market there is a clear delineation of reliability and the 

responsibilities either through market mechanisms, through contracts, through State or Federal regulations, through independent 

system operator mechanisms or through WSCC requirements. 

Fifth, we need to develop better damage control mechanisms. 

These could include better islanding methods. Arizona is a relatively small State in terms of population and power usage compared to our neighbor to the West, so to the extent that California 

utilities and Northwest utilities ignore potential problems on the 

Western interconnected grid, the resulting outages will probably 

continue to have a major negative impact on Arizona's electric system. 

Whatever happens in the California power markets has a significant impact on all of the adjoining States. Since California is going 

to lead Western States in the move toward restructuring and competition in the electric utility system starting in 1998, they are the 

earliest at this point and continue to be the earliest, we hope that 

adequate care will be taken to ensure that all competitors in the 

California market meet reliability standards, along with a fairly explicit and equitable load shedding protocol. I think that would be 

our major issue, the load shedding protocol. 

It is my understanding that on July 3rd, the day after the big 

July 2, 1996 outage, a similar problem occurred and Idaho dropped 
35 

load for the entire City of Boise, which kept the entire system in 

the West from going down again. This incident and the smart and 

timely actions taken by Idaho operators should be proof that a load 

shedding protocol may limit the severity of outages. It also should 

perhaps underscore the potential in a more competitive market 

doing the right thing is less intuitive, where they clearly did the 

right thing and saved the rest of the West from going through a 

subsequent outage. 

Finally, we need to encourage the participation of all appropriate 

parties in the process to develop solutions. In particular, the State 

PUCs need to be involved as honest brokers. 

A few years ago, it would have been unlikely for State regulators 

to be welcomed into this kind of problem solving process, but I 

think the times have changed, the process is much more open to 

a broader set of inputs. 

Participation of State PUC representatives in the various Western RTGs has been beneficial and has opened new avenues of communication among the parties involved. We need to continue to 

work together in order to understand and solve this complex reliability problem. Indeed, PUC regulators bring a ground level public 

interest perspective of concern for overall reliability and economic 

efficiency that individual market players may not necessarily bring. Without this broad perspective, the narrower interests of market 

players may dominate reliability protocols. The regulators can help develop a balance between system reliability obligations of non-WSCC members without allowing WSCC 

members to inhibit the transition to competition under the guise of 

reliability. While this will be challenging, I and other regulators 

are ready to meet these challenges. 

That concludes my statement. If I could just read four bullet 

points from a recent declaration of independence, it is why the 

transmission and system operation must be truly independent from 

the ownership of generation, and I will just read four bullets. This 

was a declaration of independence that regulators throughout the 

country have looked at and many have embraced. In competitive electricity markets, all generators will benefit 

from high prices, while customers will benefit from low prices. 

In competitive markets, higher prices achieved through any ac- tion, including control or transmission system, by any generator or 

group of generators will benefit all generators. In the absence of a clear structural solution such as divestiture, we must create solutions equivalent to a non-voting transmission 

trust. Generating companies must cede all control of their transmission lines to the ISO. They will be entitled to fair compensation 

on their investment, but afforded no opportunity to influence the 

use of those lines. 

And, finally, only when transmission constraints cannot be used 

to leverage above-market value from generation assets will the 

public's interests in genuine competition be well served. 

I think that is a good description of the concern that State regulators have as you balance the interests between a reliable system 

and a competitive, efficient functioning marketplace. [The prepared statement of Mr. Jennings may be found at the 

end of the hearing.] 
36 

Mr. DOOLITTLE. Thank you. The comments you just made, Mr. Bonsall explained how generation, transmission and distribution all relate to each other, and yet 

the trend of the market is to take entities where all three of those 

are united, which I presume is the case with PG&E or Southern 

California Edison or other investor-owned utilities in many cases, 

and we are going to go to the Federal model, I guess, where all 

three of those things are separate. 

I mean, that is sort of a paradox in my mind. We recognize that 

to deal with this issue of reliability all those three things have got 

to be coordinated and yet the trend we are going is in the opposite 

direction, is it not? 

Mr. CONLON. Well, I guess in California, since we are kind of 

leading the way on doing this, maybe I should comment on our 

thinking there. I think today in California we have at least 400 plants that are 

not utility-owned generators, so I do not think it is true that generation is necessarily tied into the integrated system. We have 

more independent generators in California than any State in the 

union. 

As far as the transmission is concerned, our expectation is with 

an independent system operator that we will enhance the reliability. Instead of having six control areas in California, we will basically have one ISO that will be able to dispatch the generators in 

an efficient manner, based on prices of each generation, so we will 

get an efficient dispatch based on the economics and yet he will 

have the overriding control. If he believes that he has a problem, 

whether it is voltage support or spinning reserves or anything else, 

he will have the ultimate power to order those units to run. 

So I think that in my view that is enhancing reliability and it 

not only picks up the IOUs but it includes the munis and on the 

transmission system, I think th1~ munis are about 40 percent of the 

State's transmission. So assuming they agree to participate in the 

ISOs, and I think that is everyone's expectations, for the first time 

in California we have one entity that controls both the transmission of the munis and the IOUS, and it would be done on a 

statewide basis so that I think that our reliability for the State 

would be enhanced and the economics should be improved because 

of the ability to dispatch on a wider basis. 

Mr. DooLITTLE. Now, this entity would not include, would it, the 

Federal power marketing administrators? 

Mr. CONLON. Well, you know, we are just dealing with California. If this expands to a regional basis, I think you do have the 

same challenges in the Northwest that we have had here in California about separating the generation, the marketing of generation and the dispatch function. And I know from my discussions, 

informal discussions, with BPA that there are discussions about 

separating off the marketing function of the power from the dispatch of the transmission systems so that they would not have an 

internal conflict, which is what would happen today. And I do not know how the Corps and the Bureau would dispatch generation. In the ultimate, I guess the ISO would have to 

have some control over the units of the Corps and the Bureau, taking into effect the mitigation, the navigation and othE r responsibil-
37 

ities they have. And I do not know how they would do that, but 

it seems to me that to follow the model of an independent system 

operator that they would have to have dispatch control of those 

units. 

Mr. DOOLITTLE. Since one of the things this whole issue has 

brought out to me is how-l mean, clearly, we go to other States 

to get not only our water but our power. I mean, it is not just confined to within the State of California, so is not this idea going to 

have to expand beyond the State boundaries? 

Mr. CONLON. Well, we certainly would recommend that and I 

think-we had a meeting 2 weeks ago in New Mexico with the Department of Energy and the National Association of Regulatory 

Utility Commissioners and I think there was spontaneous recognition of a group of about 1000 people in the industry that regional 

ISOs were the obvious end result. So I think there was recognition 

at that meeting. And I think a year ago or 2 years ago that would 

never have occurred. 

Those people would have never said, well, hey, we are going to 

give up control of our transmission system to an independent operator and he is going to dispatch the power. I mean, they would 

have said you have to be kidding. 

So I think the process has come a long way in the last 2 years 

and I am optimistic that the reliability will be improved as we get 

to a larger and larger ISO for more and more States. 

Mr. JENNINGS. Mr. Chairman, I would agree. I think we are 

heading in that direction, not drifting, necessarily, totally 

rudderless, but I think there is a sense that we want to take this 

in increments. Do the reliability thing well and first to make sure 

that there is not-that the market power issue is adequately dealt 

with and that is, I think, what we have addressed in the declaration of independence. 

But there are some regional-California is perfectly rational to 

have done what it did early, it got high prices and there is a lot 

of cheaper power out there in the marketplace and I think the intent is to reprice power lower in California and it probably will increase prices elsewhere. So there is naturally places with the lowest cost power are not particular anxious to transfer that highest 

and best use or highest and biggest dollar to take what they have 

had as low cost power and transfer that in to California. So there 

is some incremental reluctance there, but I think in time as the 

market evolves there will be independent system operators. Perhaps Arizona, New Mexico, for example, might be one ISO, California will have one ISO. Probably the Pacific Northwest might be one 

ISO. I think Colorado has already got one in the works. 

Mr. DOOLITTLE. What about the PMAs, though? Where is Bonneville going to fit into this or WAPA? 

Mr. JENNINGS. Well, Mr. Chainnan, I am under oath and I am 

not supposed to dissemble or do anything bad here today, but I do 

not want to touch that one. That one is going to be-l have not 

thought it through sufficiently. That is not an easy piece. This system evolved over a number of years to work pretty well and we 

have gone down just two absolutely divergent roads and now we 

are going to go to a sort of overall competitive marketplace and 

there are clearly some large issues. I get service from the Salt 
38 

River Project here. He is going to hear me and they are going to 

read the transcripts. 

No, I am not ready to sort that one out for Congress. I have not 

sorted it out in my own mind. But it is going to be an issue that 

will be with us for some period of time. 

The commission in Arizona bas just opened up the marketplace 

to competition, but we do not regulate the Salt River Project and 

we have given two options. One, if we can figure out some way that 

they can agree to be bound by the same terms and conditions of 

other market players, that there may be some voluntary way to do 

it. The other choice we gave them is to go to the legislature and 

take their chances. 

Now, they do not like either of those choices, I am sure, but it 

does not make any sense to have islands of non-competition in a 

world that is moving toward competition. I know the project is 

wrestling with that issue and others are trying to figure out how 

to make the rules of the game of competition fairer and everybody 

sees-if you get investment tax credits and you are a muni, the 

muni thinks that is bad or that is a comparative disadvantage, but 

if you do not pay full taxes and have municipality status and cheap 

tax-free bond status, the IOUs are quick to rocket off on that one. So it may be that Congress wants to deal with this and State leg--

islative bodies, but at some point I think there will be a recognition 

that a seamless, smooth opera1:ing marketplace that is relatively 

distortion-free and offers high reliability is going to b•~ in the public 

interest. How we get there, I am not sure. 

Mr. DOOLITTLE. I am going to ask Mr. Hardy to comment. 

Why not come up now because we might have some--- Mr. JENNINGS. Sorry to do this. 

Mr. HARDY. That is OK. 

Mr. DooLITTLE. How do you see, Mr. Hardy, the power marketing administrations fitting into this new world of deregulation and 

competition and an ISO that i;s the absolute master of all these 

lines? 

Mr. HARDY. I think it is not clear yet. The administration, Mr. 

Chairman, really has not gotten to the point of taking a position 

on this, so let me caveat anything I say by that. 

Mr. DOOLITTLE. Right. Sure. I understand that. 

Mr. HARDY. From my personal perspective of 20 years in this industry in a variety of positions, not just with the Federal Government, but in various positions in both the private and the public 

sector, I think Bonneville and WAJJA probably have to be part of 

an ISO. In the Northwest, my perspective is if Bonneville can be 

legislatively separated into two corporations, I think we should be 

the ISO in the Northwest. That begs the question of if you have 

a WSCC-wide ISO how that works, but clearly I think we n1~ed to 

and W AJJ A needs to be part of that. How you work through the constitutional and legal questions associated with how Federal officials participate and to some extent 

get directed by non-Federal parties is a tricky set of issues. We are 

dealing with that in the Northwest right now. The Northwest investor-owned. utilities have formed or are in the 

process of forming an organization called Indego, which is their 

version of an ISO, kind of half an ISO. How that organization is 
39 

formed, and how it relates to BPA's transmission system involves 

some very tricky questions of governance, and operations. For example, it is especially important to have scheduling and dispatch 

functions together. Whatever else you do with the ISO, you absolutely have to have those two things together or you are asking for 

trouble. 

I think California is moving down that line fairly well. Frankly, 

I am worried about the Northwest in that respect. But you have 

a whole series of questions there and it may well be that legislation 

could facilitate that, but, like I say, we will have to deal with the 

administration to examine whether that is appropriate. 

The administration is really waiting on the Northwest. The 

Northwest Governors, I think you may know, have convened a 

panel called the Comprehensive Northwest Energy Review to review Bonneville's status, what role should Bonneville play, not just 

in maintaining reliability, but in all aspects of this competitive 

marketplace in the Northwest. That panel should have a series of 

recommendations to the administration and to the Congress in December. Those recommendations will hopefully give us some clarity 

on what fork of the road we are on here. 

Mr. DOOLITTLE. Do you gentlemen contemplate that the ISO is 

going to be in many cases some existing utility that volunteers to 

do that job? 

Mr. CONLON. No, it will be an independent-in fact, that is one 

of the big challenges the State legislature had, was how to govern 

the ISO and in the original proposed decision or the decision we 

issued, the commission, we had a governing board that was made 

up of 15 members or approximately 15, less than half of which 

were utilities or municipalities, so the majority of those were nongenerating producers. 

Now, the legislature was not satisfied with that. They imposed 

a three-member board above that group as an oversight or an appeals board, if you will, that will be strictly public purpose representatives and we are going through the process now of recommending to the Governor names that would be appointed that 

would go in place on January 1, those three members. And Mr. 

Friedman is functioning in that capacity as an individual for the 

next 3 months so that the process keeps going but that board, it 

is essential it not be controlled by the generators or you have lost 

the independence that the word implies. An independent system 

operator would not have any interest or minimal interest in any of 

the generators. 

Mr. DOOLITTLE. Nevertheless, you have to have the knowledge 

and the technical expertise of how to do it and that is why you are 

talking about splitting the two corporations, is it not, Mr. Hardy? 

Mr. HARDY. In part and in part to eliminate the conflict between 

us being a major transmission owner and yet still having marketing rights to the output of the dams. The issue we are struggling 

with is the fact that that conflict is there and FERC is driving the 

whole industry in a direction of separating those functions. The 

statement of principles that was just read clearly indicates that is 

also where most of the States or State regulators are appearing to 

go. 
40 

The problem that that creates for Bonneville is that while separation is clearly necessary to have a viably functioning and competitive marketplace, it is in conflict with most of thEl rest of Bonneville's organic statutes, which say the administrator singular 

shall do A, B, C, or D. So all of the legal responsibility and, probably more importantly, 

the political accountability is vested in this single decisionmaking 

official who has control over both the power marketing and the 

transmission assets. Added to this, Bonneville still writes a single 

check to Treasury each September 30th to repay the outstanding 

debt to the tune of some $800 million to a billion dollars a year 

that is a blend of power and transmission revenues. 

That puts me in the position of if my power business is in trouble 

absent legislative separation, I may have a legal obligation to manipulate my transmission business to help out my power business 

if that optimizes the chance I am going to make my Treasury payment. 

That is fundamentally in conflict with the way the whole rest of 

the industry is going. That has to be rationalized. Maybe it can be 

done administratively where you set up a process within the region 

for those conflicts, or maybe it should be done legislatively. That 

is one of the issues the Northwest Governors panel is debating 

right now. 

I think the administration, and to some extent at least the 

Northwest congressional delegation, is waiting to see what the 

panel will recommend on this issue. 

Mr. CONLON. But the important thing here is that the California 

utilities have given up physical control, operating control, of their 

transmission facilities to a third party. 

Mr. DOOLITTLE. Now, they will retain, I guess, ownership. 

Mr. CONLON. The ownership. 

Mr. DOOLITTLE. Right. 

Mr. CONLON. So EPA could, I guess, hypothetically EPA could retain ownership even if they did-but could give up control of the 

facilities or they could be the ISO and give up-it is a difficult 

issue how to separate it so that there is independence from the 

generation. But I just want to say that I think the Corps or the 

Bureau has a tremendous asset in these units that they obviously 

are not optimizing because they have other purposes. 

As I have heard here today and in other hearings, that they have 

the fish mitigation, they have the navigation and the flood and all 

this other stuff, but they have the ability to make some money with 

those units. They are there for voltage support, spinning reserves 

and just power production to sell into the grid. 

So I do not know-you know, I know the Federal spending is always cut back but it seems to me they could probably enhance 

their financial capabilities by being more aggressive in the market 

if their overall objectives would allow them to do that or if somehow it was legislated that they could do it. I am just trying to use the analogy of the California situation 

with the munis and the Northwest situation with the Federal agencies and trying to draw-because this agency right here, the Los 

Angeles Department of Water and Power, is faced with the same 

decision. They are a municipally owned company. 
41 

What do they do with their transmission? What do they do with 

their generation? And then how do they operate their transmission? Because they are surrounded by investor-owned utilities 

who are going to be open to competition within 18 months or whatever number of months it is and it is going to be a tremendous 

pressure on them to do something. 

Mr. JENNINGS. I wonder if I could go back to your earlier question that implied, well, should you not have the people who know 

the most about running this technical system be the ones designing 

it and the answer is yes and no. And I think you will get into that 

in the next panel. 

We had a meeting after the outage of August lOth in Arizona 

and I thought one of the most prescient observations made was a 

fellow stood up and said, you know, here we have a system designed by economists that is to be run by engineers and yet there 

is a physics to all this, will the electrons really continue to flow if 

this system is really designed-so I think what we are doing in this 

next panel really gets at some of that. 

And it is interesting, if you look at the next panel, I know in 

Vikram's case, he is the only one I know on the panel, but if you 

look at the Western Systems Coordinating Council sort of description of those events and what is going on here, you do not get quite 

the-you get just a hint that this governance issue is a big deal, 

but I think the brain storming group that will be on your next 

panel hinted at it even more broadly. This governance issue of who 

is going to be setting the rules of the road really makes a huge difference. 

If it is all the suppliers, well, again, you are back to they will 

make it work out for suppliers. And, of course, the engineering criteria, we all want to have a reliable system, but it is going to be 

easy to hide behind how those criteria inhibit a low price world. 

So just so I think my earlier comment, that regulators have been 

sort of-we used to be the goat in the manger at any of these gatherings, I think we are much more happily received these days because we sort of give a broader cover to the public policy issues. 

And I think, if I can give some comment on the panel to be, that 

appears next, that they will be well served if they figure out how 

to get some folks' perspective who are consumers into those decisionmaking bodies, to have some of that input. Otherwise, we may 

be cheated out of the benefit of going through all of this agony to 

develop ostensibly a competitive market which may not develop. It 

may end up just being a supplier's market. 

Mr. DOOLITTLE. Your proposal in Arizona and California, this 

idea of deregulation and an independent system operator controlling the transmission, the companies that own these things get prorated credit or something, do they not? 

Mr. CONLON. They get their normal return on their assets at a 

minimum on this, so they are not going to lose any profitability per 

se. 

Mr. DOOLITTLE. Right. Mr. CONLON. That is the concept. 

Mr. DOOLITTLE. And you, Mr. Jennings, were referring to-I just 

want to understand the point you are making. California is going 
42 

to have cheaper power, but that means it is going to be more expensive in some other place. Will you explain? 

Mr. JENNINGS. Sure. Right now, Idaho residents have probably 

the cheapest power in the country. You can correct me if that isthey have very, very cheap power. It is almost hydro based, some 

coal. And it is just incredibly cheap, so they have built their entire 

economy around cheap power. 

What California would like to do, undoubtedly, is to have access 

to cheaper power and so lower their average price of electricity. 

There is nothing irrational about that. 

If you are a resident in Idaho, you want cheaper power. If you 

are a shareholder of Idaho Power, you want to sell into the power 

exchange because it is the last one in that sets the price. So whoever can make a profit by being last in of the Idaho Powers of the 

world can make a boodle of dough. So I think therein lies some of the-it is the politics of envy. Anybody who has cheaper power costs, somebody else is saying, gee, we 

manufacture, too, and we would like to get a cheaper price, we are 

in competition with these people that are making this in such a 

such State. 

I think the real risk is that right now everybody thinks that 

power is much cheaper than it really is and once we go through 

this, and I am glad that we had the outages, it has been a great 

wake-up call to put first things first. But there is certainly a lot 

of risk that this will not turn out to be-although the cheap power, 

in that right now there is an excess of capacity in the region and 

everybody else is selling that back and forth to each other right 

now. When this marketplace tightens up and the reliability criteria 

are built in, there is a lot of resistance to investor-owned utilities 

to go out and make some new investments on long-lived plant and 

so it becomes a more speculativ1:l deal to sort of plan that over the 

next 20 years that your millions of dollars, you are going to get a 

cost recovery. 

Well, you used to get them under the old regulatory regime 

where your earnings are pegged directly to your investment. Here 

they are pegged to the marketplace. If the market goes up or down, 

you have some risks. It is going to be a tightening up, I think, many people suggest 

in the next 4 or 5 years, just when all this competition transition 

we have gone through and then there may be another consequence 

that we have beefed up the transmission system and then as new 

technology comes on board, the micro generation, the solar stuff, 

fuel cells maybe, maybe not 5 years, but when that stuff starts to 

come in, we are going to have a whole new way of doing things potentially. So there is a lot of risk out there and right now we are doing 

this on faith that markets work and that we will be able to get rid 

of a lot of the market imperfections and sort of figure out most of 

it on the fly. And we usually do reasonably well at that as a country. So I am somewhat optimistic, but some of the benefits probably 

are being oversold and at least it is worth considering whether that 

is the case. Mr. DOOLITTLE. So you are saying, when you say tightening up 

in four or 5 years, you mean there is a relative scarcity today. 
43 

Mr. JENNINGS. Yes. 

Mr. DOOLITTLE. And therefore higher prices. 

Mr. JENNINGS. Yes. A lot of plants right now are slated to be decommissioned over the next five, 10 years. 

Mr. CONLON. I would like equal time here, if I may, but I will 

let you go ahead and finish, Renz. I do not want to cut you off. 

Mr. DOOLITTLE. OK. We will give you equal time. 

Mr. JENNINGS. There is quite a large number of power plants 

that are planned to be decommissioned within the next five or 10 

years. I do not know, something like 30 or 40 percent, some large 

component of the generating mix right now. 

Mr. DOOLITTLE. And are they really decommissioned or are they 

just refurbished and keep on going? 

Mr. JENNINGS. Well, they have been. They have been refurbishing them, but they can only do that-I think we are going to inescapably come to the point where there is going to be a national rethink of whether it is OK for the midwest to wreck the air shed 

of the northeast. This is something mercifully you probably will not 

have a dog in the fight so much so you can be an honest broker, 

but I think that is going to be a big cat fight down the road. And 

you could run a whole lot of these older plants flat out and make 

the air dirty in the West and that is probably a loser. I mean, there 

is maybe some temptation to do that. I think on reflection we probably will end up not doing that. 

So that there is some risk, if you do not have a service territory 

where you can sell to a native load and then if you have any excess 

to sell it around in the marketplace, that is kind of the old system 

or where we are right now. But I think it is going to be a lot dicier. 

We have had fairly low cost capital in this benevolent regulated 

world. 

But in the new world that is coming up, it is the cost of capital, 

I suspect, that is going to go up because these plants are going to 

be risky and you do not have a captive customer base that can absorb some of that risk and sort of an assured cost recovery. 

So I am not sure that that does not have a fair set of risks associated with it, but on balance, and I think Gregory and I would 

agree on this, that the benefits of competition in generation are 

probably out there and it is certainly not a natural monopoly any 

more, which is a reason to do what we are all doing at a various 

rate of speed, but I naturally would be interested in what others 

think about the looming risks, but this is not just going to be cheap 

power forever for everybody, I do not think. 

Mr. DOOLITTLE. We are going to get to Mr. Conlon here in a 

minute, but let me--you seem to imply that because of the increased risks that we would see fewer new transmission and perhaps generating systems built. Is that correct? 

Mr. JENNINGS. I think in the short run, we are going to probably-transmission is going to get harder to do. In the old days, 

you had eminent domain and the local dog in the fight, the big utilities that had the ability to get things done with an interest in 

making sure that it got done. 

Now, an incumbent utility already has the ability to serve its 

own customer base and a new line may be seen as somebody's ability to bring in competitive power from some place else. 
44 

Now, what I just said is diminished somewhat by the fact that 

there is going to be a lot of open network architecture on this, open 

access, but still there is the existing architecture. There are going 

to be some power plants that are here and they have a line to the 

load center and that is going to be basically the plant that gets output that gets sold into a marketplace. So there is a lot of residual 

market power just from the architecture of the old system. 

Mr. DOOLITTLE. Mr. Conlon? 

Mr. CONLON. I apologize for getting into a restructuring discussion, but that is where we have moved to and I think in due respect to what we are trying to do here in California. I think the 

driving force behind this is one technology, that the cost of generating electricity with the gas turbine technology has got to a point 

where the cost of building new generation is much less than anything that we are operating today, so there is a tremendous opportunity that the large industrial customers and the small ones that 

have meaningful loads want to take advantage of. 

They want that new technology just like 10 years ago they wanted the low price gas when gas was available but you could not get 

it inside the State. So 10 years ago we went through this in the 

gas industry and we have the lowest gas prices in the United 

States today. So we are trying to go through it in electricity by taking the generation market and only the generation market and deregulating it to a point where you have a viable competitive market 

and I think that most of the excess capacity today is plants that 

are not as-you know, like 10,000 heat rate and above compared 

to new plants of 7000 so they are 30 percent less efficient in using 

fuel. That is probably a third of the generation in Southern California are those kind of plants. 

I was at a meeting just recently where somebody said there was 

18,000 megawatts out of 60,000 megawatts in Southern California 

and Arizona that have heat rates over 10,000 BTU, which is very 

inefficient. 

So with new technology and a competitive market., eventually 

once you get the initial-everybody is going to be bidding their 

variable cost and once that ends and we are into a level of bidding 

where you cannot just bid your variable cost, that new technology 

will come in, we will get new investment in California and the market will flourish with new investment of these efficient generators. 

And big customers will get direct access contracts for a new generator. I mean, that is the name of the game. 

And slowly the market will flourish and hopefully the economy 

will flourish with it. So we are trying to use a market-based concept for just the generation. The transmission is still regulated, but 

it has to be done on an independent basis. The distribution is still 

regulated on a cost-of-service basis or a variation thereof, so it is 

just-and as far as the people at Idaho, I wish I had their problem. 

I mean, they have the resources-! mean, they get the money. I 

mean, they can share it with their residential ratepayers and have 

zero bills. I mean, to sell the money into the pool and share that 

with the ratepayer, I mean, they could reduce their rates even further in Idaho with any kind of sharing arrangements between the 

residential ratepayer and the stockholder. 
45 

So, I mean, it is an opportunity to use their excess supplies to 

sell into a market and maximize the value that they can share with 

the residential ratepayers and everybody wins in Idaho. I mean, I 

wish I had their problem. 

Mr. JENNINGS. I do have a different perspective here and not to 

sort of request equal time on everything and we are a little--

Mr. DooLITTLE. This hearing is going to last a long time, but go 

ahead. That is all right. I am interested. 

Mr. JENNINGS. I certainly agree with Pr2sident Conlon that the 

gas turbine technology is the driver. But is also predicated on the 

perception and the reality of low gas prices and there are a lot of 

factors in here. There is an oversubscription of the hydro base and 

you are seeing a problem worrying about what some have termed 

a few fish. Well, if you spend a little time in the Pacific Northwest 

and they are pretty serious about the runs of salmon. It is part of 

their culture and that is their patrimony and they want to preserve 

that. 

In Idaho, there is not going to be a whole new set of dams. I 

mean, that resource is already pretty well subscribed. Which takes 

me to the point, I think, we should not lose sight of the role of technology, but we also ought to not lose sight of the importance of having a portfolio of resources. 

That is why I think California is to be commended and has done 

a good job in maintaining their commitments to renewable energy 

and why others of us who have been a little late, even with the 

great solar resource coming into this with a solar portfolio standard 

for a State like Arizona, and there is really a good reason and I 

would like to-it does not often make its way into the discussion, 

but I hope that you take this, if it is a good insight, take it back 

to Congress. 

For whatever reasons the low-lying countries and cities of the 

world take the threat of global warming a lot more seriously or climate change than perhaps people at 5000 feet, and they may have 

a fair amount of political pressure and we do not know where 

greenhouse science is taking us, but we know that there is a risk 

out there and it is a fairly large risk, we just do not know how likely the risk will be to come due. 

So if you need to back away from carbon fuels, that puts you 

right into natural gas, which any time one fuel gets in essence a 

monopoly you can extract monopoly rents, which is why the value 

of having new technologies to do research and development to be 

able to hedge those long-term risks is probably a pretty good bet 

to place. And to the degree that everybody is thinking right now 

about low price, they ought to be thinking about how you hedge 

long-terms risks as well as get the benefit of low price now, but to 

make sure that you can keep it as low and environmentally sustainable over the long haul as well. 

Once a fuel gets a monopoly, it is going to do what you would 

expect it to do, charge monopoly rents. 

Mr. CONLON. I would agree with that and I would just add that 

in California we have committed for the next 5 years that we will 

maintain our renewables as a percentage of the total load as what 

we have had in the last 5 years, so we are not in any way taking 

away from the portfolio diversity of renewables. 
46 

Mr. DOOLITTLE. I want to switch subjects here. 

Now, do you regulate----do your public utilities commissions have 

anything to do with maintenance of rights-of-way and herbicide use 

and that kind of thing? Or is that strictly up to the utilities themselves? 

Mr. CONLON. In fact, we just published yesterday, we had a commission meeting yesterday, and we published standards to be commented on by the parties for distribution assets, otherwise the 

poles, wires and transformers in the neighborhood. 

We put out standards that we will get comments on and hopefully we will act on within a short period of time to at least on the 

distribution side-but to my knowledge, we have not discussed the 

herbicide issue at all and maybe we should because we are right 

at that point of considering what should and should not be done. 

Now, in my testimony I mentioned that I think that on the higher voltages that we need to get more involved because of the global 

risk for the entire State based on the August lOth event. As far as 

I am concerned, our commission staff focus will be at the higher 

levels, but we will set standards and do compliance work at the 

distribution level also. But herbicides I think you will have to ask 

these two gentlemen what their experience has been. 

Mr. DOOLITTLE. OK. 

Mr. JENNINGS. Happily, we have no relationship to herbicides 

that I know of. Our cactus grow an inch a year and we had seven 

inches of water, rainwater, in the higher country, where much of 

the transmission stuff is. The sagebrush has a hard time growing, 

it is pretty windswept and pretty dry, so this issue has just never 

come up. 

Mr. DOOLITTLE. OK You indicated, Mr. Jennings, that Idaho or 

in Boise, I guess it was Idaho Power that let Boise have an outage 

in order to save the rest? 

Mr. JENNINGS. Yes. That is as I understand it and, again, others 

perhaps are better positioned to comment on it than I am. The 

point of that was that in this sort of fraternity network that we 

have now where valor and decency is highly rewarded, perhaps you 

get a CEO plaque or something at the EEl meeting, inducted into 

the hall of fame or whatever, but you would be considered to be a 

chump in a competitive marketplace if you cut your own power to 

your own communities to keep the grid from unraveling, although, 

as I understand it, their quick action to dump Boise helped it from 

then everything going black. 

My understanding of the situation is if you can retain some 

amount of generation and load and try to have something like a 

flywheel up in balance it is much easier than to have the whole 

system go down and then try to build it back slowly in increments 

over a couple of days. 

Mr. DOOLITTLE. Is that what happened, Mr. Hardy? Idaho voluntarily did that to itself? 

Mr. HARDY. Essentially, yes. They had a repeat on. July 3rd of 

similar sorts of circumstances that had occurred that had 

precipitated the widespread outage on July 2nd. Their dispatchers 

recognized it, intervened manually, put Boise in the dark, but that 

probably was the difference between having yet a second cascading 
47 

outage on July 3rd which would have paralleled the one on July 

2nd. 

And the difference there would be what we had on July 2nd was 

you had total voltage collapse in Idaho. No system is designed to 

withstand total voltage collapse in an adjacent system. 

They put the Boise area in the dark, but they stabilized the rest 

of their system, so the outage did not spread into the Bonneville 

system and hence did not separate the intertie like it did on July 

2nd. 

And that is an example of the kind of islanding schemes that Mr. 

Bonsall was referring to and that the WSCC report references in 

other parts of its recommendation. It is not just preventing the initial cause of the outage. While prevention is the most important 

part, given that you cannot give 100 percent assurance that you 

will never have circumstances leading to another outage, you also 

have to take actions that mitigate the extent of the outage. Such 

actions typically involve load tripping and generation tripping, either automatic or manual, to mitigate the extent of the outage. 

Mr. DooLITTLE. So in the Boise example, they islanded themselves, is that right? 

Mr. HARDY. Essentially. Yes. 

Mr. DooLITTLE. Is that a term we could find in the dictionary? 

Apparently it is a fairly common concept. 

Mr. JENNINGS. Probably after August lOth editions. 

Mr. HARDY. It is a common concept in NERC and all the reliability councils. I mean, that is what the system is designed to do. And 

how well you do it determines what the extent of the outage is and 

how long it takes you to restore. 

Mr. DOOLITTLE. We had tried in setting up the witnesses to get 

some direct testimony as to the impacts when you do have an outage, but let me ask any of the three of you or all three if you care 

to, to comment, particularly the two heads of the public utilities 

commissions, what impacts did you see in your States as a result 

of the August lOth outage, both in terms of the impact on any 

given business or the overall perception, the business climate. 

Can you comment on that? I understand this has a tremendous 

impact, say, on the chip manufacturing industry, for example. 

Mr. CONLON. Well, I think the two utilities should comment in 

more detail but generally I think in California we lost over four 

million customers on Saturday and it was into the night before 

they got restored. Probably I think by midnight they got most of 

it restored. Fortunately, it was on a Saturday, so we did not, I do 

not think, have the chip problem as much as we would have had 

if it would have been on Monday or Tuesday. 

Mr. DooLITTLE. It would have been much greater if it had been 

during the business week? 

Mr. CONLON. You should confirm this with the utilities, but I 

think that is right. We estimate tens of millions as a result of the 

outage. And, you know, I was startled, as I think you were, with 

the analogy of the six fish for tens of millions of dollars but, you 

know, it is just-it is difficult to make those judgments and what 

your interests are, but it was tough. 

At one point, I found out after the fact, and I am an accountant 

by training and I am learning a little bit more about electrical en-
48 

gineering, and I guess there is a way to run The Dalles units without having water going through them by treating them as a motor 

or somehow, and, again, my colleagues from the utilities behind me 

can explain how it works. But I think if that would have been 

done, and I understand it is not that expensive to convert those 

units to be able to do that, if those units had been running without 

water going through them, just at the system voltage as a motor, 

in other words, you would be using electricity to drive those turbines to run, but if they had been spinning, then they could immediately have activated them to help this situation. So that would 

be another remedial action that could be taken by the Corps and 

the Bureau that would be very helpful for the voltage control for 

the intertie. 

Mr. DooLITTLE. Is that what spinning reserve is? 

Mr. CONLON. Well, I do not think so. I think it is more than that 

and I think we should let the two gentlemen who arE! more knowledgeable---

Mr. DooLITTLE. OK. All right. We are going to have lots of fun 

things for them to talk about. 

Did you want to comment in terms of any--

Mr. JENNINGS. Again, it was a blessing that it happened when 

it did. It does not take much imagination to think, gee, if this had 

been at 4 on an afternoon on a Friday and you are trapped in an 

elevator for 4 or 5 hours, I suppose a lot of buildings have back up 

power, or it happened on a Saturday night when the kids were all 

out liquored up and the lights went out and the cops were spread 

thin, you know, it could have happened at a much worse time. The 

fact that it happened and everybody is now so focused on this before we move into a situation that may destabilize the situation as 

opposed to correct it, it was a benefit that it happened when it did. 

Yes. There would be a huge loss of productivity. What I found is 

that our utilities were very quiek to recognize the magnitude, the 

importance of it. How people would have freezers full of food. They 

were buying dry ice from all over, way out of the region, and flying 

it in and letting people know that they could get dry ice to protect 

stuff. So it was a nice dry run in the sense to see how committed 

they were to customers and how quickly they could crisis manage 

I think stimulated a lot of thinking. But it really happened at a 

time that was pretty favorable and there was not the loss of the 

manufacturing base, a day or a week's production or whatever, you 

are in process and you go down and you have lost millions and millions of dollars. So we really bypassed a whole lot of that. 

There were a few situations where there were health situations, 

but for the most part there was just a handful of economic consequences. 

We did get an awful lot of calls, I have been trying to send them 

up to Randy and I suspect that there is a big thick file of people 

who either were impacted by computers or refrigerators or air conditioning units and so forth that were fried or people had old ones 

and claimed that they lost things, but we did get quite a few calls 

on that and some people were pretty irate. And, again, it happened 

at a time of day where you would probably have the least amount 

of that kind of-do people really surf the Internet on a Saturday 

afternoon? I do not know. 
49 

Mr. DOOLITTLE. Knowing what you know about the August lOth 

incident, let me address this to the two PUC people, is it likely that 

had the utilities under your jurisdiction been the ones who werepretend they were BPA but they were under your jurisdiction, the 

same set of circumstances, is it likely that they would have been 

sanctioned or not? And if so, what would the sanctions have been? 

Mr. JENNINGS. It depends on whether it was the first time or the 

second time. 

Mr. DOOLITTLE. Well, what about with the history we have 

where there were at least two prior incidents about a month before, 

raising the possibility of such things in the future, which then ultimately happened on August lOth? 

Mr. JENNINGS. You almost have to answer hypothetically because 

right now we have a voluntary system in place and you play with 

the rules that are in place, but I think it is a clear case of there 

need to be sanctions for people who do not meet their obligation because it screws it all up for everybody else. So one participant, 

whether small or large, could do something that would have a cascading effect and that is unacceptable. 

I think the old system has worked marvelously well. It did not 

work in this situation. It would work much less well with a larger 

number of players and with people who are doing bilateral contracts as well as just a huge increase in the number of transactions 

and players making transactions. 

Mr. CONLON. You know, we just fined PG&E a half a million dollars yesterday for not meeting their call center, their telephone call 

center up in Sacramento. 

Mr. DOOLITTLE. For not doing what with the call center? 

Mr. CONLON. Not meeting the response time of 20 seconds for 

their calls. We have pending reviews of their storm for last December on their distribution system and how it behaved and I do not 

know what we are going to do and it takes three votes to get anything done, but that is yet to come before us. But I think that it 

would be difficult to take sanctions if you did not have standards, so I think the first thing that we probably would do was do what 

we are doing, is getting standards established and then I think 

probably the first time out of the box we would probably not have 

been so anxious to have sanctions. There has been a lot of political pressure to do that, but I think 

that until we have standards that we can judge them by as to 

whether it was reasonable or not or prudent or not, that it would 

have been difficult to do something. But I would say the second 

time, once we get standards established and then there are violations, then I think there would be sanctions and the main sanctions would be fines and penalties. And we fined Pacific Bell $1f5 

million for not applying the cash properly after we had told them 

at least 10 times to do it. 

So I think that, you know, you would have to judge the sanctions 

with the violation, but I think it would have been tough to do anything right out of the box. But we get the standards establishedyou know, one of the suggestions is that we have standard fines 

and sanctions depending upon what the violation is so that the 

WSCC could impose them if they were automatic. Otherwise, if you 

violated this, it is going to cost you $1 million, if you violated that, 
50 

it is going to cost you $10 million. And if you have some muscle 

in those sanctions the attention to the detail would be a lot greater. 

So that is really-! do not think we would have fined them anything. I would not have voted for it unless I felt it was clearly imprudent or unreasonable what they did, unless there were clear 

standards and they violated them. 

Mr. DOOLITTLE. And I am just trying to assess how commonplace 

these are. I gather that 500,000-volt lines are not that commonplace. I mean, they are the biggest lines, I guess in California, anyway, right, that we have? 

Mr. HARDY. I think so. 

Mr. DooLITILE. I am just-this criteria of WSCC and it is in this 

report they gave, their procedure for coordination of scheduled outages, notification of forced outages, on pages 14 and 15, where it 

says, "Each WSCC member system which owns or operates a key 

generation or transmission element scheduled to be mmoved from 

service or which has been forced out of service is responsible for notifying the other WSCC members via the WSCC communications 

system of the facility outage. Key facilities are those which are considered important to interconnected system operation by the system which owns the facilities. Key facilities generally include" and 

then it skips down and cites thE! relevant paragraph, three, "transmission operated at 230 kilovolts and higher that can significantly 

affect interarea system operation." 

Maybe simply as a layman it seems to me that a 500,000-volt 

line that goes down would certainly be a key facility, would it not? 

Mr. HARDY. Can I speak to that, Mr. Chairman? 

Mr. DOOLITTLE. Yes. Yes. Jump in. 

Mr. HARDY. I think that there is some confusion here. As the 

standard that you just read indicates, what is a key facility is in 

fact determined by the transmission owner. The first two lines that 

went out before we got the Keeler-Allston were 500 kv lines but 

they are lightly loaded. We did not, knowing what we knew at the 

time, think those met the definition of key facilities. In retrospect, 

we were probably wrong, even though that has not been firmly established yet, given that we have not run the studies. KeelerAllston clearly was. 

What we have moved to do with the operating agreement that 

I described with Pacific Gas and with Edison is to remove that discretionary judgment. It is an attempt to reach the standard Commissioner Conlon talked about so that it is clear, which facilitiesline by line, transformer by transformer-will require notification 

of adjacent utilities in the event of an outage. 

In retrospect, it would have been nice to have that earlier and 

at least that would have afforded Pacific Gas and Edison the opportunity to potentially take corrective actions which may or may not 

have had an effect. Prior to August 10, and you had an awful lot 

that was in the judgment of the dispatchers relative to what happened and now we have moved to correct that. 

Mr. DOOLITTLE. OK. And that is in fact corrected, I guess, internally within BPA, at least. 

Mr. HARDY. I think that element of discretion is removed not just 

for us, but for Pacific Gas and Edison as well. My guess is when 

we finally get through with this we will have such an understand-
51 

ing with all the transmission owners; that is we will have a similar 

list of key facilities that they will be required to notify other owners about when there is an outage, either planned or unplanned. 

Mr. DOOLITTLE. Now, is WAPA involved in this? 

Mr. HARDY. Yes. WAPA would presumptively be involved in it if 

it is expanded to the other owners. 

Mr. DooLITTLE. OK Well, I do not think I have any other questions. This has been a good panel, too. I appreciate your testimony 

and we may have--I should have mentioned to the first panel but 

I will mention it now, all these panels, there may be further questions that we will have and we will submit them in writing. We 

urge you to try and get back quickly with a response. Mr. CONLON. I appreciate the honor. 

Mr. DOOLITTLE. Thank you very much for attending. 

[Witnesses excused.] 

Mr. DoOLITTLE. With that, we will call up the third and final 

panel. 

I think we are waiting for our third panelist, so just have a seat 

and we will ask you to take the oath when he is here. If I may ask 

you to rise and take the oath. Raise your right hands. 

[Witnesses sworn.] 

Mr. DooLITTLE. Let the record reflect each responded and replied 

in the affirmative. 

We are pleased to have you here and we are looking forward to 

your testimony. We have on this panel E. James Macias, Vice President and General Manager, Electric Transmission Business Unit, Pacific Gas 

and Electric Company; Marcie L. Edwards, Manager, Bulk Power 

Operations and Maintenance, Los Angeles Department of Water 

and Power; and Vikram S. Budhraja, Senior Vice President, Southern California Edison. 

Thank you for being here. 

Mr. Macias, please begin with your testimony. 

STATEMENT OF E. JAMES MACIAS, VICE PRESIDENT AND GENERAL MANAGER, ELECTRIC TRANSMISSION BUSINESS UNIT, 

PACIFIC GAS & ELECTRIC COMPANY 

Mr. MACIAS. Thank you, Mr. Chairman. For the record, I would 

like to state that I am not happy with the outage event that occurred and I do not consider it a blessing. Nevertheless, there are 

a number of things we can learn from it and actions we can take. 

On August lOth of this year, the Western grid in the United 

States suffered its second major disturbance in 2 months, its third 

in 14 months. In our opinion, the cause of both events was a lack 

of effective voltage management by exporting utilities in the regions. This lack of adequate voltage management caused a series 

of line and equipment failures to escalate into massive voltage collapse and grid instability in the Northwest. 

These instabilities in turn led to widespread customer load shedding throughout the Western United States as other utilities' secu- rity systems operated automatically to stabilize the grid. 

Economic trends in the industry are driving usage of the grid to 

a greater extent than ever before. These forces are pushing many 

generators to maximize electrical output for sale to distant markets 
52 

and retailers to reach further out in search of low cost supplies. Recent enhancements to the regional grid and open access regulation 

now make this access to long distance supplies easier. These conditions are increasing regional flows to higher levels and different 

patterns than we have ever experienced before. This trend will continue. 

My analogy is driving on a winding road. With ideal weather 

conditions and at speeds well below the maximum speed limit, the 

driver feels safe and complacent even if they have a poor suspension and bald and over-inflated tires. However, as weather conditions worsen and they try to drive at the safe speed limit, all of 

a sudden they can find themselves in a very bad situation that can 

lead to disastrous results. I think that is a very good analogy of 

what we experienced. 

On August lOth, less than ideal operating conditions existed. 

Critical generating and switchyard voltage support equipment was 

either unavailable or experiencing operating problems. System operators failed to recognize early warning signs of voltage instability 

in their control areas. Further failure of unreliable equipment led 

to these disastrous results. 

Why is voltage management so important? Voltage is the back 

pressure that allows electricity to flow across the wires. To safely 

control the flow of electricity across the wire network, voltage has 

to be carefully managed at the generating source, at the consumption end and in steps in between. The longer the distance between 

the generating source and the consumption end makes it technically more difficult to control this voltage at the appropriate levels. 

What corrective actions can be taken? You have heard of some 

of them that were immediately taken. The first step is to restrict 

the flow of energy that can flow across the California-Oregon border until we are satisfied that effective voltage management controls are in place, the procedures are there, operators are trained, 

they are monitored and they are enforced. 

The second step was the communication that was discussed earlier. That is very important. Taking away the ambiguity and having clear communications will allow utilities like ourselves to take 

actions to better insulate our customers from operations and disturbances that are occurring outside our border. 

I think it is very important that the WSCC proceed with this review of voltage procedures and training from a top to bottom review. I am confident the procedures and training will be enhanced. 

WSCC will determine compliance with all WSCC operating procedures, especially voltage management. This has already begun. 

And WSCC is working to establish four regional security centers, 

one of which will be PG&E, to exchange data, monitor system conditions for potential reliability problems and coordinating system 

restoration. 

In a further long-term correction, the proposal that California is 

proceeding with I think will have dramatic improvements on system reliability. The restructuring proposal before the Federal Energy Regulatory Commission would separate and isolate reliable 

grid operations from the economic drivers of the competitive supply 

market. The independent system operator will be solely responsible 
53 

for reliable grid operations and will have no economic interests in 

the market. Organizational separation of the ISO from generation 

markets and other supply coordinators will ensure this reliabilityonly focus. 

ISO regional control would replace numerous utility-specific control points. Today's regional control is a patchwork of dozens of 

local utilities coordinating with each other. Regional ISOs are being 

considered to better monitor system conditions. 

And the third are the mandatory protocols with financial settlements for non-compliance. 

I think those are the critical steps that need to continue. The discussion and debate on industry restructuring I think is in some 

part beside the point. These outages and these occurrences have occurred before any restructuring events have taken place. 

Mr. Chairman, that concludes my testimony. 

[The prepared statement of Mr. Macias may be found at the end 

of the hearing.] 

Mr. DOOLITTLE. Thank you very much. 

Ms. Edwards is recognized for her testimony. 

STATEMENT OF MARCIE L. EDWARDS, MANAGER, BULK 

POWER OPERATIONS AND MAINTENANCE, LOS ANGELES DEPARTMENT OF WATER AND POWER 

Ms. EDWARDS. Mr. Chairman, I want to thank you for the opportunity to share a Los Angeles perspective of the August lOth event, 

though I must comment at this point that much of my testimony 

will be an echo of much of what you have heard already today. 

On August lOth, Los Angeles Department of Water and Power, 

like the rest of our neighboring utilities in the southwest, was significantly impacted by an electrical disturbance which originated a 

thousand miles away. We intentionally disconnected nearly 600,000 

customers to help stabilize the power system during the first 15 

minutes of the disturbance, while 11 of our electrical generating 

units were automatically disconnected from the system. Our ongoing concern for the reliability of the interconnected 

transmission system was subsequently demonstrated by our active 

participation in the investigation of this disturbance. 

A considerable number of technical and operational factors underlie this complex disturbance. In reviewing these factors, we believe there are four primary issues that lie behind the events of August lOth. 

First, the disturbance reminds us we are part of a single interconnected power supply and one that is shrinking in commercial 

distance as competition suggests more and more consumers may be 

purchasing their energy from places further away. As the commercial distance across the interconnected system shrinks, it will be 

imperative for all the entities deriving benefit from the interconnected system to join utilities in taking prudent, consistent 

steps to ensure power system reliability. We cannot assume that 

the operational practices of what's been called a monopolistic past 

will suffice in a competitive future. 

The voluntary reliability mechanisms of the past 30 years have 

served this industry very well. However, we cannot assume that reliability standards will continue to be enforced in a competitive en-
54 

vironment and we should reviHw the applicability of commercial 

sanctions and/or penalties. 

Second, while the coming competition is moving the industry 

away from its once held position of freely sharing financial information, competition will be simultaneously increasing the pressure 

on studying and operating the Bystem more aggressively and moving the industry toward a need to share more technical and operational information and to do so in a much better way. 

Significant to the August lOth investigation was the question of 

whether the Bonneville Power Administration should have made 

wider notification of transmission outages in their system occurring 

just before the disturbance. 

While the technical jury is still out on the impact these outages 

had on the initiation and severity of the disturbance, future reliable system operation will depend highly on companies sharing 

operational information such as voltage levels, real and reactive 

power flows and lines out of service in a timely fashion. 

Regional security centers like the type that Jim mentioned and 

the soon to be implemented California independent system operator 

will play major roles in sharing the operational information. 

Third, aggressive energy marketing, heretofore rarely seen in 

this industry, places additional stress on the existing transmission 

system. To the consumer's benefit, aggressive energy marketing is 

here to stay and so the burden falls to the industry to increase its 

efforts to effectively monitor, study and predict the State of the 

power system. 

As the industry relies more and more on operating the existing 

system to its full capacity, the reliability of the system will increasingly depend on our ability to accurately model, simulate and control the flow of electric energy. Again, the WSCC's progress toward establishing regional security centers to monitor the flow of energy, plus California's push to 

establish an independent system operator to control the State's 

transmission grid speak to the requirement for more comprehensive and timely predictive analysis. 

Fourth and finally, while it is true that the power provided by 

electric utilities has an impact on society and its environment, it 

is increasingly true that societal and environmental forces also 

have an impact on an electric utility's ability to generate and deliver power reliably and economically. On August lOth, as you have heard, the operations at The Dalles 

reduced the power support that. this station provided to the transmission system. Electric utilities must not shirk their responsibility 

to work within environmental constraints which are put in place to 

preserve a common good. Nevertheless, it is worth pointing out 

that reliable electric power is in itself a common good worthy of 

equal consideration in the public debate. 

In summary, Mr. Chairman, we believe the major lessons to be 

learned from this disturbance are the need for old assumptions to 

be put aside and for all of the parties deriving benefit from the 

interconnected transmission grid to work together to ensure the 

continued high degree of reliability we previously enjoyed; the need 

to increase the sharing of technical information, even as there is 

a competition directed move away from sharing commercial infor-
55 

mation; the need to more carefully and completely study a system 

which is being operated as never before, and the need to balance 

the impacts of external constraints with the need for reliable economic electric energy. Thank you, Mr. Chairman, for this opportunity to speak to these 

issues. This concludes my testimony. However, in response to an 

earlier inquiry, 500 kv is actually two of these bundled and then 

you would see three strands going in between the transmission 

towers, and we will have this for you, if you would like to look at 

it, sir. 

[The prepared statement of Ms. Edwards may be found at the 

end of the hearing.] 

Mr. DOOLITTLE. Thank you very much. 

Mr. Budhraja, you are recognized, sir. 

STATEMENT OF VIKRAM S. BUDHRAJA, SENIOR VICE 

PRESIDENT, SOUTHERN CALIFORNIA EDISON 

Mr. BUDHRAJA. Thank you very much, Mr. Chairman, for the opportunity to appear before this Committee. You have already by 

now heard the details of the outage and I am going to briefly focus 

my remarks on the impact on Edison, steps to be taken to avoid 

such events in the future and, most importantly, in my judgment, 

focusing on how to manage reliability in the emerging competitive 

market. 

First, let me say that for Edison reliability is very important. We 

are committed to providing reliable service to our customers and 

this involves focusing on all of the elements that constitute reliability, including maintenance, design, planning, training and oper- ation of our system. As you know, the August lOth outage and the previous July 2nd 

outage, both of which originated in the Northwest, were attributed 

in part to deficiencies in tree trimming. Also on August lOth, five 

major transmission lines went out of service over a period of 1 hour 

and 42 minutes without corrective action. At Edison, we play a lot of attention to trimming our trees and 

we have gone back over the last 5 years in our records and we have 

not had even one outage attributed to deficiencies in tree trimming 

for our bulk power system. Of course, that is not good enough. We 

need to maintain this record in the future. 

With respect to corrective actions, our operators have strict in- structions that in the event of any doubt about reliability due to 

equipment outages or operating conditions, take corrective action 

first, assure reliable operation to our customers and then evaluate 

the state of the system. In terms of what Mr. Macias said, slow 

down your speed on a winding road. The August lOth outage had a significant impact on our customers. In Southern California, we have 4 million customers affecting a population of 10 million people. On that day, 1.8 million customers lost power, almost 40 percent of our system. Our service 

restoration started immediately and within approximately 3 hours 

we had a substantial portion of our system back in service. 

Our system behaved well. We started 19 power plants. Most of 

them were on by later that evening and continued to operate in the 

ensuing days to help out not only service to our customers, but also 
56 

to help PG&E and other neighboring utilities in the West because 

of the heat wave. 

The August lOth outage should not have happened. We have 

taken steps within WSCC, and I must congratulate Randy Hardy 

and EPA's proactive approach in fixing the problems that were 

identified. I think that has been very good. And we need to make 

sure that these efforts continue. 

In addition to paying attention to tree trimming or vegetation 

management, maintenance and review of local voltage supply, 

there are several other preventative measures that have been instituted among the utilities in WSCC. These include, for example, requirements to communicate information on status of major equipment outages to other utilities; in the event of outage of any equip~ 

ment, to reduce system usage to safe levels; and, in the event of 

any uncertainty regarding the safe and reliable operation of the 

system, to take corrective action first and make engineering evaluations later. 

These items focus on good operating practices which you must 

do. Looking forward as we transition to competitive markets, it is 

also important to focus on rules to manage reliability consistent 

with a competitive marketplace. In a competitive market, the current voluntary system is unlikely to be adequate. The vertically integrated structure of electric utilities is transitioning to a 

disaggregated structure with functional separation of the generation, transmission, distribution, marketing and operating functions. 

In this new environment, with many more players, we need mandatory reliability management protocols, compliance monitoring 

and mandatory enforcement with consequences for lack of compliance. The key building blocks for such a system would include: focusing reliability management responsibility; industry should take 

the leadership to overhaul the existing framework to strengthen 

the role of the North American Electric Reliability Council and the 

regional reliability councils; volunteerism must be replaced with 

mandatory reliability protocols; all market participants must accept 

an obligation to comply with reliability protocols. It is not just 

enough to focus on utilities, but all market participants. 

Formation of independent system operators, as we have heard, 

should be encouraged as this will help to unify control areas, enhance coordination, and implement mandatory protocols. 

NERC and regional reliability councils should have standard setting, monitoring, enforcement and sanction capability. 

FERC should support mandatory reliability protocols and require 

an obligation to comply as part of an open access tariff and power 

marketing licenses. 

The costs of reliability must be fully recoverable and paid for by 

all consumers and market participants. 

And, finally, the ISOs and control area operators should be members of reliability councils. 

There has been some debate on the role of ISOs and whether 

they will help in reliability management. Let me suggest that in 

my judgment they will because they will establish focused responsibility for reliability management, unified control areas, simplified 

communications and coordination, help in implementing mandatory 
57 

protocols and, most importantly, separate the commercial and reliability functions. 

The industry has to take a leadership role to make this happen 

and some of this is already happening through the leadership at 

NERC and at Edison Electric Institute. I also believe that the Federal Energy Regulatory Commission can play a very important role 

by supporting industry efforts to strengthen the reliability focus requiring the use of mandatory protocols for reliability in ISOs and 

including mandatory reliability compliance as part of open access 

tariffs and power marketing licenses. However, this alone may not be enough. You had asked a question earlier regarding the role of PMAs and let me address that directly. In this country, about 30 percent of the power systems are 

not within the jurisdiction of FERC. This includes, for example, 

Federal power marketing agencies such as Bonneville. 

I believe it is very important for BPA and W AP A to be fully committed to join an ISO, to separate the commercial and reliability 

management functions. We need a level playing field with the same 

rules for all players. Integrating BPA, WAPA and other power marketing agencies' transmission systems with ISOs and recognizing 

that the ISOs will be under the regulatory jurisdiction of FERC, 

this would be an important step to unifying the electric power systems in the West as well as in the rest of the country and should 

help in dealing with many of the issues in the emerging competitive marketplace. 

In closing, let me just emphasize that reliability need not be sacrificed as we transition to a competitive marketplace. In fact, it can 

be strengthened. However, we cannot take reliability for granted. 

We have to pay attention to the creation of ISOs because they will 

go a long way toward focusing responsibility for reliability management and imposing mandatory reliability protocols. 

In California, we are moving in this direction and I urge you to 

support such a transition. 

Thank you. 

Mr. DOOLITTLE. Thank you. 

Mr. Macias, could you describe the secondary impacts on PG&E 

facilities from the outage? We have heard about Diablo Canyon, 

both units, I guess, going down, and I believe there were others as 

well. 

Mr. MACIAS. The operational impact and the customer impact is 

when the instability hit and the voltage collapse hit, the wire system, the grid system, actually sees a physical impact. It is like a 

water hammer hitting the system. And the protection devices on 

the plants feel that and open up and separate the plants from this 

water hammer to protect it from being damaged. That is what led 

to this widespread dropping of plants. 

As this instability and collapse spread from the Northwest in a 

parallel path through the Western grid, those plants closer to the 

origin of it saw a bigger impact. That is why you saw ones on both 

the eastern side and the western side were impacted. 

Both our Diablo Canyon plants went down. Well, nine of our 

plants went down. A non-nuclear plant you can bring up even if it 

has damage. We had a number of plants that blew steam tubes but 
58 

you can still operate them, limp them along. A nuclear power plant 

you cannot do that. 

When the plant tripped and it separates, the steam valves lift. 

Now, we have about five steam valves per unit. One of the valves 

lifted literally a nanosecond slower than what it was supposed to 

by the textbooks. We have to do a thorough review of the plant top 

to bottom as well as we had to identify why did that safety valve 

not operate the nanosecond it did not. Is that a generic problem 

with others? And it took us several days before we could adequately operate, bring the plant back on line. Forty percent of our 

customers lost power. The longest was out as many as 9 hours. We 

have estimated the direct cost to us, cash cost to PG&E, to be 

about $40 million. 

I am not an economist on what the economic impact is to our customers' economy, but just aneedotally, the stories you hear from 

customers of the impact, it is probably ten times that amount to 

the economy, so the economic impact is quite significant. A lot of 

our customers operate 24 hours a day, 7 days a week, in continuous 

operations. They cannot drop oif their mass productions, be it chip 

productions or gas manufacturing or other mass production facilities, so we have significant impact, even if it occurs on a weekend 

or during the night. Mr. DOOLITTLE. So just the impact directly to PG&E was $40 

million. 

Mr. MACIAS. Yes. 

Mr. DOOLITTLE. And you estimate $400 million to your customers. 

Mr. MACIAS. Could be. It is probably in the hundreds of millions 

to the California economy, at least in our service territory. And the 

loss, the stories you hear of lost production, lost downtime, for customers. 

Mr. DOOLITTLE. Let me ask our other two witnesses if you can 

give us the same estimates for your service areas. 

Ms. EDWARDS. The financial estimates for the department were 

probably somewhat under a million, though the magnifier for the 

community impact is probably equivalent to what .Jim had mentioned. Interestingly enough, though, in addition to the economic impacts, there are a lot of societal impacts that occur on these type 

of outages. Due to the low voltage, we lost some of the waste treatment facilities at Hyperion and there was partially treated sewage 

that went into the bay. There were some problems with resetting 

traffic lights. We had hundreds of traffic lights out across the Los 

Angeles area which caused snarls for hours. So there are multiple 

areas in which these type of occurrences can impact us. 

Mr. DOOLITTLE. Mr. Budhraja? 

Mr. BUDHRAJA. Yes. As I indicated, 1.8 million customers were 

impacted, which is about 40 percent of our system. It is very difficult to estimate exactly the economic loss due to production and 

the disruption that took place on the Edison system. The financial 

impact of the experience was not even close to what Mr. Macias 

did. I think PG&E was impacted more being closer to the trigger 

event, but I would venture to say that for us it would be in the single digit millions of dollars. 
59 

Mr. DoOLITTLE. And much of your cost, Mr. Macias, was because 

of the nuclear reactors going down? 

Mr. MACIAS. That was by far the greatest one we have had. We 

had transformers that were damaged on the disturbance. 

Mr. DOOLITTLE. Let me ask, you have heard a little bit of the discussion over the testing of some of the generating equipment, I believe it was at the McNary Dam. How does your testing-you have 

dams, do you not? 

Mr. MACIAS. Yes. 

Mr, DOOLITTLE. How does your testing policy compare with what 

you understand to be the case in BPA and the Corps? 

Mr. MACIAS. I am not that familiar with BPA or the Corps' operation, but I can describe our operations. 

Mr. DOOLITTLE. Sure. Describe yours. 

Mr. MACIAS. Hydroelectric operations in California are really no 

different than anywhere else. You have safety, you have environmental, you have recreation usage that you have to balance as well 

as economic operations, so it is a complicated operation. Your hydroelectric resources are your most valuable, your most economic. 

You try to maximize their operations during the highest cost hours 

to maximize the value of them. Because they are so valuable, you 

have real clear availability standards that your operating organization operates to and you have clear performance measures. 

Our operating availability of our hydro facilities is in the above 

90 percent range, with the majority of them above 95 percent 

range. Hydroelectric facilities really are not that complicated. They 

are less complicated than steam plants as far as complexity. 

Mr. DooLITTLE. This is the availability figure you are giving us? 

Mr. MACIAS. Yes. 

Mr. DOOLITTLE. And you said 90 to 95? 

Mr. MACIAS. Correct. 

Mr. DOOLITTLE. So that is substantially higher than the Corps of 

Engineers. 

Mr. MACIAS. Than the numbers I heard earlier. Yes. 

Mr. DOOLITTLE. OK. 

Mr. MACIAS. The operating equipment is no different than automobile vehicle. If you have a vehicle and you take very good care 

of it and you do your routine maintenance, you are religious about 

changing the oil and you replace parts as you go, as they wear out, 

they can continue to operate very effectively for long periods of 

time. 

Mr. DooLITTLE. Or you can kind of run them into the ground and 

then it is more expensive. 

Mr. MACIAS. Correct. 

Mr. DOOLITTLE. Ms. Edwards, give us this information for your 

area. 

Ms. EDWARDS. I would suggest, sir, that the issue surrounding 

McNary, while involved in the utilization of a hydroelectric facility 

as a whole, really targeted to a large extent on the voltage support 

components provided by those individual facilities, what they call 

the excitation systems or power stabilizer systems, and the effect 

that that had. Our response was what the Corps of Engineers was 

going through in greater detail earlier. 
60 

It did send, I think, a wake-up signal to many in the industry 

to review their own power system stabilizers; their own voltage 

support equipment on their generating facilities. And I think that 

is really more the issue involving McNary itself. When those 13 

units tripped as a result, the exacerbating effect, then, that they 

had by removal of that support,. how much further that caused the 

collapse, if in fact it contributed much more to the downfall. 

Mr. DOOLITTLE. I guess we bad heard the testimony that there 

was a lack of proper tuning of some of that equipment and they 

did not discover that because they did not-it sounded like they did 

not routinely perform that kind of a test in a dynamic state. I just 

wondered, do you--

Ms. EDWARDS. I think since that point, in response to WSCC, 

particular to our own utility, the report came in fairly recent, on 

October 25th, that we reviewed the status of the power system stabilizers across all of the generating units in our system, including 

the hydro plants, and those that meet the WSCC criteria have been 

tested and found to operate within the established parameters. 

We reviewed the testing schedules to make sure we are on track. 

We tested most recently in 1992:. We are projected again to in 1997. 

We may in fact set that up. This is probably fairly common to what 

a lot of the utilities, though, have done as a result of the disturbance. 

Mr. DOOLITTLE. I want to hear Mr. Budhraja's answer, but let 

me say when I visited the Glen Canyon Dam, they had a maintenance schedule that went into the year 2000, projecting different 

things they were going to routinely do. But I assume, or maybe I 

should not assume, do you not adjust those according t()-I mean, if there is something that come.s up like this August lOth incident, 

you would alter that maintenance schedule, would you not? 

Ms. EDWARDS. Typically, thi.s review of the power system stabilizers would have been performed in 1997. But as a result--

Mr. DOOLITTLE. And so you updated it immediately. 

Ms. EDWARDS. Yes. Mr. DOOLITTLE. OK Mr. Budhraja? 

Mr. BUDHRAJA. Yes. There are two issues here. One is McNary 

and its performance and second is adequate voltage and I think the 

issue that happened was whether you use dynamic testing or static 

testing, if you assume you have voltage support when in fact you 

do not, you are going to run into a problem. And I think the key 

issue to focus on here is that all power systems must have adequate local voltage support and, as you heard earlier, it could be 

supplied through transmission lines, local generation, nearby generation, far away generation, cutting schedules. 

Now, how each system manages that may vary, but I can tell you 

that on the Edison system we do look at power system stabilizers, 

are they operating or not and it could be that on a given plant they 

do not operate but that does not mean that we have inadequate 

voltage support because we might start other power plants that 

would provide the requisite amount of voltage support. 

I think in terms of availability of units, our experience is not unlike PG&E's. Transmission systems tend to have the highest availability, in excess of 99 percent generally. Hydro units are next, in 
61 

the 90-95 percent, and then thermal units generally are in the 80-

85 percent availability range. 

Mr. DoOLITTLE. If I remember the GAO report on the Corps' facilities, which I think were in the Southeastern Power Administration, I think they are getting down to where the thermal units are 

that you are talking about. I think it was around 84 percent for 

their hydro. So Southern California Edison is right up there with 

PG&E. Is that the case, Marcie, that the Department of Water and 

Power has 90 to 95 percent? 

Ms. EDWARDS. Our hydro units are still well in the nineties. 

Mr. DoOLITTLE. Yes. OK. So the Corps of Engineers, at least, is 

significantly below your three entities, which I believe to be pretty 

much the industry standard. 

Well, let me ask you three, if you had had adequate notice that 

things were going awry on August lOth up in the Portland area, 

would you have been able to have taken steps to avert the outage, 

do you think? 

Mr. BUDHRAJA. I think if we had adequate notification, there is 

no question that some remedial actions would have been taken. 

The most obvious one is to reduce schedules on the intertie and in- crease generation in California such that you reduce your dependence on that critical artery. Mr. DOOLITTLE. And that can happen in a matter of-what, a few 

minutes, a few hours? How much time does it take to do that? 

Mr. BuDHRAJA. Well, I think, you know, these things can vary, 

but generally let me just say if there was some significant equipment outage, it may be some minutes, whether it is five to 10 minutes before the information gets shared, assuming this is not an 

emergency because in an emergency things would happen automatically. We would generally then raise generation. It could be done in a 

matter of minutes, no more than 10 minutes, to alter schedules. 

Now, it can vary from a system situation. I mean, if it is not judged 

to be very critical, we might do it over a period of 1 hour, but the 

response capability exists to increase schedules within 10 minutes. Mr. DOOLITTLE. Ms. Edwards, what do you think? 

Ms. EDWARDS. It brings two thoughts to mind. One is that issue 

of examining what before were really non-credible events to us, multiple series of line outages, and the need now that presents itself to do that to a much larger extent. And also it highlights the 

dispatcher training issue. 

I think particularly in the California area, we have targeted that 

fairly substantially over the last couple of years. There are hotlines 

established between the major control centers. The senior load dispatchers are empowered, they get on the phone together, they can 

shed customer load to stabilize the power system in probably under 

a minute. There is a series of very rapid actions that they can take 

and they are empowered to in fact do that. We do not have, at least immediately, the environmental constraint that came about with the fish flush issue where that needs 

to move upwards substantially before a decision can be made. In 

fact, I would underscore the comment that was made, that needs 

36- 069 - 9 7 - 3 
62 

to be pushed downward when you are talking about a power system emergency. The time to act can be very short. Mr. DOOLITTLE. Mr. Macias? 

Mr. MACIAS. In operations, because electricity travels so fast and 

your response time is so critical, your operators are trained to 

think ahead, think the worst ahead and always plan contingencies. 

And as you start actually seeing events occur, you start planning 

ahead for what else can go wrong, what could, and operators do not 

assess what is the probability of something occurring, they assume 

what if something else should occur. As this escalating event occurred, you would have started to see 

escalating actions taken as the things continued. Nothing would 

have happened on the notification of the first line outage. Transmission lines do go out; even though, as we heard, they are the 

highest, most reliable systems, an outage does occur. But it is an 

unusual event. We consider a single transmission line to be such 

an unusual event, I will get woken up during the middle of the 

night if a single line goes out. 

When the second line goes out, a third line went out, we would 

have started putting additional standby generation on line, gas turbines on line, to strengthen the system. We then would have started to actually cut flows. 

About a month after August lOth, we had a planned maintenance outage on one of the lines on the three-line intertie and temperatures went up and the flows went up and then an outage occurred on BPA voltage support equipment on another line on their 

side. And communication was started and in that case the operators reduced the flows. That is the type of action that you would 

see. You would start seeing it associated with incremental actions. 

Mr. DooLI'ITLE. You are saying that even though the first line 

going out, while unusual, is not too great a cause for concern, but 

even that first line going out would wake up you in the middle of 

the night. 

Mr. MACIAS. If it was one of PG&E's lines, yes. 

Mr. DooLITTLE. Yes. Does the fact that it is the biggest type of 

a line, a 500 kilovolt line, is that more significant than a 230? 

Mr. MACIAS. Yes. Yes. 

Mr. DOOLITTLE. So certainly by the time the second one went 

out, you would have the red flags clearly--

Mr. MACIAS. We would have started taking action, especially 

when a second line on a separate corridor, what is going on? It is 

so unusual of having two of those, these highly reliable lines, go 

out on separate corridors. You put them on separate corridors so 

if something happens in one you do not impact the other. Two lines 

going out simultaneously, at least for us, is a most unusual event. 

Mr. DooLITTLE. Now, if you had had illustrations of problems a 

couple, three, 4 weeks, I do not know, a few weeks ahead of the 

big one on August lOth, would that have triggered a comprehensive 

evaluation of conditions and rights-of-way and that kind of thing 

in your mind, in PG&E? 

Mr. MACIAS. I am sorry. I missed the first part of the question. 

Mr. DOOLITTLE. Well, if you had-I mean, this had happened, I 

believe, twice before in July where the power lines sagged into the 

trees and shorted out the line. Would that have triggered then a 
63 

review within PG&E of its rights-of-way and things so you might 

have averted theMr. MACIAS. Yes. We have undertaken an extensive vegetation 

management and tree trimming in our system over the past 2 

years because we have had problems of our own with tree contact 

that is mostly on the distribution side. 

Vikram mentioned that on his system they have not had any outages as a result of tree contact, any customer impact. We are the 

same. 

Mr. DOOLITILE. Let me just ask. Distribution is from-what, the 

substation to the end user? 

Mr. MACIAS. Right. It is in the neighborhoods. It is less than 60 

kv. On our system of 14,000 miles of transmission line, we experience about 15 tree contacts per year that will cause a line to correct but does not cause an outage. Mr. DOOLITILE. Now, say that-that will cause a line to correct? 

Mr. MACIAS. A line to go out, but not cause a customer outage. 

Mr. DOOLITTLE. Oh, right. OK. 

Mr. MACIAS. And because of the problems we have had on our 

distribution side, we have had an extensiveMr. DoOLITTLE. Were those distribution problems, those 15, or 

were they transmission? 

Mr. MACIAS. No, those were transmission. 

Mr. DOOLITILE. Those were transmission. 

Mr. MACIAS. We have considerably more on the distribution side. 

Mr. DOOLITTLE. OK. 

Mr. MACIAS. Over the past 3 years, we have doubled the amount 

of money and effort we have spent into tree trimming. We also cut 

back on any herbicide or chemical vegetation management, but the 

loss of that as one tree trimming action does not mean you cannot 

do others. 

We found that by being very smart with tree trimming and using 

tree experts on how you trim trees you can actually train it to grow 

away from your transmission lines. Also on transmission, the majority of our outages occur from 

trees that are outside our right-of-way. The worst we have is on the 

California north coast. We have 80-foot high redwoods and our 

right-of-way is only 40 feet tall and the lines are in the middle. Mr. DOOLITILE. You mean the right-of-way has a vertical dimension? Is that what I understood you to say? 

Mr. MACIAS. Well, your line, you heard before that it will sag. 

Mr. DOOLITTLE. Yes. 

Mr. MACIAS. Your high voltage ones, especially the long spans, 

will sag as much as 40 feet. They will also sway in the wind. So 

essentially you have a circle and a corridor that you have to keep 

protected. 

Now, you asked earlier about some of the problems with the regulations. Our pet peeve, my pet peeve is the regulations call for a 

minimum distance from the wire, so essentially you have to have 

a circle around your wire sitting there stagnant. The trees will 

blow in the wind so in some cases, it is 20 feet, you have to have 

it 20 feet. It says minimum. There is nothing about maximum. And 

we have gone in and tried to trim greater and we have gotten com-
64 

munities and other agencies after us that we are too aggressively 

trimming trees. 

Well, you go in there and you trim your minimum and you cannot do a maximum, the next day the wind blows the tree in or it 

grows, you are now in violation. 

Mr. DOOLI'ITLE. Well, so can these lines go out-surely it is not 

40 feet from side to side, is it? 

Mr. MACIAS. Some of them can swing as much as 20 feet out. 

There is a big arc that these things can swing in winds. They are 

designed to withstand up to 100 mile per hour winds, cross-winds 

that we can have in storms in California. Mr. DooLI'ITLE. But you said your right-of-way has a certain 

limit. Which right-of-way? 

Mr. MACIAS. Just about all right-of-ways-a 500 kv right-of-way 

has a right-of-way, I believe, of about 200 feet and then a 230 is 

like maybe 100 feet and then a 110, so it shrinks by the voltage. 

Mr. DOOLITTLE. And this is how wide the right-of-way is, you are 

talking about? 

Mr. MACIAS. Correct. And our preference for right-of-ways, it varies by property owners. It is what the original easement was negotiated with the property owners. Where we have the rights, we prefer to just clear cut it out, remove the trees. Not only does that reduce your tree trimming costs because you do not have to go in 

there every year and trim it, but when you do have an outage, your 

access and your response time is greatly reduced. 

Mr. DOOLI'ITLE. Now, did PG&E discontinue entirely your herbicides? 

Mr. MACIAS. I wish I had looked into that. I do not know for 

sure, but I believe-if we have not eliminated it, we have dramatically reduced it. 

Mr. DOOLI'ITLE. So then you are forced to labor--

Mr. MACIAS. Forced to use other methods. Yes. 

Mr. DOOLI'ITLE. Well, find out, unless you know the year, find 

out. I would be interested in knowing what year that happened because it sounds like BPA is going to reinstitute herbicides because 

they have a different-well, I guess their whole area would be like 

the north coast of California in terms of how fast trees grow. Mr. MACIAS. Our herbicide is a chain saw. 

Mr. DOOLI'ITLE. Right. Ms. Edwards, what is your situation? 

Ms. EDWARDS. As far as herbicides, I would probably have to answer for the record. I would have to do some research. 

Mr. DOOLI'ITLE. OK. That is fine . Ms. EDWARDS. But bear in mind, too, in Southern California, 

very frequently the largest thing near some of these transmission 

towers is a tumbleweed crossing the desert. Mr. DOOLITTLE. Right. You do not have the same problem. Mr. Budhraja? 

Mr. BUDHRAJA. I would have to get back to you on the herbicide 

issue. [The response may be found at end of hearing.] 

Mr. DOOLITTLE. OK. Well, let me just ask the three of you, getting back to the other issue of appropriate notice-we did not get 

the answers on appropriate notice, did we? If you had had appro-
65 

priate notice from BPA about the problem with their lines going 

down, could you--

Ms. EDWARDS. I would have to echo Mr. Macias. It would be the 

cascading or cumulative nature of the event that would have 

caught our attention. A single 500 kv relay would really be consid- ered as routine trouble on a power system and would not necessarily draw a large amount of notice. 

Mr. D OOLITTLE. So you do not get up in the night--

Ms. EDWARDS. They wake me up at two. 

Mr. DOOLITTLE. For two? 

Ms. EDWARDS. Right. Mr. DOOLITTLE. All right. 

Ms. EDWARDS. And actually there are some, as we talked about 

the discussion earlier regarding key facilities, there are some facilities and some circuits that are so important to all of us on the system that that type of notification will take place. But on the whole, 

I would not normally hear about it until it started to cascade. And 

we would have taken the same type of actions. We would have committed additional spinning generation with some potential that 

there may have been some greater loss of either transmission paths 

or voltage support, so we would have taken a proactive stance as 

well. 

Mr. DoOLITTLE. If you had had it happen twice before, and I realize one of those times was not the BPA, I think it was in Idaho, 

it was the Idaho Power Company, I guess, but it was a widely reported event, if you had had that set of circumstances, would that 

have caused you to examine your own areas to make sure that you 

were not going to experience a problem like that? 

Ms. EDWARDS. A lot of the work that we undertook, the voltage 

support examination, the tree trimming programs, we actually initiated as a result of the July 2nd instance. 

Mr. DOOLITTLE. Oh, as a result-oh, all right. So you took those 

things very seriously. 

And, Mr. Budhraja, tell us--

Mr. BUDHRAJA. Yes. I think an event like July 2nd is a very serious event and we reviewed our procedures after that. We lost 

260,000 customers on that day. It was not as severe, obviously, as 

the August lOth, but any time you have customer interruption, it 

is a very significant issue. We pay a lot of attention to it and we 

just do not like to have those things happen. Period. 

Mr. DOOLITTLE. So if you had had appropriate notice from BPA, 

would you have been able to take action to protect yourselves? 

Mr. BUDHRAJA. Yes. I think-! just would echo what you already 

heard from Ms. Edwards and Mr. Macias and that is if it was understood the state of the system had weakened because of multiple 

500 kv lines out, there is no question in my mind that we would 

have taken protective action. 

Now, I think one line, if it is not viewed as critical, that is a 

judgment we do leave to the system dispatchers, but you just cannot have a very weak system which can-and operating in a way 

in a power system in which the next contingency can take the 

whole system down. You just do not do that. I think Mr. Jennings 

mentioned earlier N-1, N-2 and that is what we do look at, you 
66 

know, that the power system should be able to withstand the outage of the next contingency without affecting customer loads. 

Mr. DOOLITTLE. And when do they wake you up at night? Does 

that happen? 

Mr. BUDHRAJA. They wake a lot of people up at night. I guess, 

if it is really serious, I will get woken up, too. 

Mr. DooLITTLE. One 500 kilovolt line would not necessarily trigger that. 

Mr. BUDHRAJA. No, it would not. Mr. DOOLITTLE. Would two trigger it? 

Mr. BUDHRAJA. We have a slightly different reporting structure, 

so I get spared even on two. Mr. DooLITTLE. All right. But, I mean, somebody-- Mr. BUDHRAJA. Yes. Mr. DOOLITTLE. Some person in charge is-- Mr. BUDHRAJA. Yes. Yes. I would like to, if I may, with your permission, Mr. Chairman, address another issue that came up in the 

earlier discussion, the issue on July 3rd and Idaho cutting off 

power to Boise? 

Mr. DooLITTLE. Yes. 

Mr. BUDHRAJA. One of the rules in an interconnected system is 

if you have a problem on your system, you should correct it and 

not allow it to propagate to other systems, so we commend Idaho 

for doing it on July 3rd. I wish they had done it on ,July 2nd also 

and not allowed it to propagate beyond the Northwest. 

Mr. DOOLITTLE. And they could have done it on July 2nd, I suppose. Mr. BUDHRAJA. Well, I think if you have a low voltage situation, we have an obligation to either increase local generation or reduce 

load such that we do not impact other systems. Mr. DOOLITTLE. Now, what is the possibility that your utilities 

would have continued to take Northwest power even with this notice that things were going awry simply because it was cheaper 

power? Would any of them have continued to have done that at 

that point? 

Mr. MACIAS. On August 11th, you heard earlier where we were 

declaring it an emergency. We were seeing all-time record highs, 

5 percent even higher than we had previously seen the year before. 

We had lost 2200 megawatts of our nuclear capability. We were on 

the ragged edge. We had already derated the line, BPA and PG&E. 

We would not have increased it. If they could not have taken the 

emergency action to get The Dalles plant operating, we would have 

suffered the consequences with our customers. 

As Vikram said, you have a responsibility to operate according 

to WSCC criteria and procedures in your service territory. So we 

would not have increased the flows even for customer service. Even 

when we got beyond that hurdle, we were suffering costs of 

$100,000 a day and lost increased economic supplies. But just like 

you do with any commodity, you have a very pivotal supply to you, 

if your supplier, if you have a lack of confidence in that supply, you 

do not rely on it, even if it is economical. 

Mr. DOOLITTLE. Your company and that of Mr. Budhraja are subject to the public utilities commission, right? 

Mr. BUDHRAJA. Yes. 
67 

Mr. MACIAS. Correct. Mr. DOOLITTLE. So I know those to be both very fine companies, 

but in addition to just being good corporate citizens, I mean, you 

would have suffered significantly from penalties levied against you, 

would you not? 

Mr. MACIAS. Our president, Mr. Conlon, was very diplomatic in 

his answer, but when you asked the question I could not help but 

be squirming in my seat. With the clear WSCC standards, they 

would use those as the standards of criteria we were not following. 

As he mentioned, we just yesterday received the maximum fine 

allowable because we did not meet this 20-second call center response that is the most stringent of any utility in the United 

States. 

Mr. DOOLITTLE. By the way, how many seconds was it, anyway? 

Apparently, you went over the 20 seconds, that is the standard, so 

how many seconds was it taking? 

Mr. MACIAS. Some of them, because we were receiving as many 

as 4 million calls--

Mr. DOOLITTLE. Oh, as a result of this August lOth outage? 

Mr. MACIAS. This was another storm. This was unrelated. 

Mr. DOOLITTLE. Oh, OK. 

Mr. MACIAS. This was another major storm with a lot of stormrelated outages. The commission felt, as I understand it, we did not 

meet our goals and standards that they had requested of us and 

we had committed to in our 20-second call response. Mr. DOOLITTLE. How long did it take, 30 seconds? 

Mr. MACIAS. Well, some of them could not get through. Mr. DOOLITTLE. Just could not get through? So what are you supposed to do, hire more operators? 

Mr. MACIAS. You put in more lines. 

Mr. DOOLITTLE. More lines? 

Mr. MACIAS. And you hire more operators and you have back-up 

systems because you do not sit there and man for 24 hours a day 

for that. Mr. CONLON. They have met it on every one since then. Mr. DooLITTLE. OK. What about the issue of taking the cheaper 

power, assuming the risk because it is cheaper. You would not have 

done that, would you? 

Ms. EDWARDS. The economics become very secondary in an electrical emergency situation. Even though the Department of Water 

and Power is not a CPUC regulated entity, our relationship with 

the Western systems has been very staunch for a number of years. 

I am held personally accountable that we operate within the Western systems criteria for interconnected system operation and that 

will and does, unfortunately, very often, take precedence over the 

economic criteria because the reliability is the first thing we need 

to maintain. Mr. DOOLITTLE. One of the things we seemed to hear from almost 

everyone today was that if you are generating power you ought to 

have to belong to the WSCC. Ms. EDWARDS. Not only just generating, sir. I would suggest that 

it is a broader participation than that. Part of the difficulty in 

transitioning to this competitive environment is that utilities find 

themselves bearing more of the economic brunt for the reliability 
68 

issues. And so the mechanisms to establish more of a parity such 

that that is spread amongst everyone deriving benefit from using 

the system is a very critical issue for us. Mr. DOOLITTLE. So, do you all support the idea that you ought 

to have to join and be subject to mandatory sanctions for failure 

to comply with the standards? 

Ms. EDWARDS. I would say from a Los Angeles position, we are 

already in compliance with Western systems, so the economic impact to us would be nil and the advantages by having others 

brought in and forced to comply would be nothing but to our benefit. 

Mr. DOOLITTLE. In other words, the supply of power is not just 

like delivering some commodity because it is an essential service 

and so the issue of reliability is critical and therefore it is not 

strictly speaking just a free market situation. There is more responsibility that goes with providing the-what do we call it, it is 

a service, is it not? Anyway, getting people who come into it who 

presently are not subject to obeying the standards or at least they 

do not have to belong, I guess they can withdraw at any time they 

choose. Mr. BUDHRAJA. I think the issue is reliability first, economics 

second. I mean, obviously we do not want to spend money where 

we do not have to, but it cannot be to compromise reliability. An 

analogy I would use is the air traffic system. Obviously if a plane 

is in a hold pattern, they are burning up fuel, it is costing them 

money, but the air traffic controllers have absolutely reliability 

first, safety first, and economics second. That is the way we operate 

our power system and that is the way it should be in the future. 

To the point of mandatory protocols, I would just suggest that at 

least in my judgment, the issue of membership may be more exaggerated than what we need to do and that is there are going to be 

hundreds of players in the marketplace. We do not need necessarily 

all of them to be members of the reliability council, but they must 

play by the rules, they must have the obligation to comply, just as 

everybody who flies has to comply with the rules in terms of the 

air safety situation. 

But that is not to say that it should not be mandatory protocols. I think we need mandatory protocols, we need a mandatory obligation to comply, not just on the generators, but also the transmission companies and marketeers. 

Mr. DOOLITTLE. Ladies and gentlemen, thank you very much for 

your testimony. We may have further questions of you and the 

other panelists. We would ask you to respond quickly when we 

send them to you. 

I have found this hearing to be very informative. I really appreciate your participation and that of the previous panelists. 

Again, we thank the City of Los Angeles and this Department of 

Water and Power for the many courtesies it has extended this Subcommittee. 

The record will be held open for a few days for comments-two 

weeks, to be specific. 

With that, the Subcommittee will stand adjourned. 

[Whereupon, at 1:57 p.m., the Subcommittee was adjourned; and 

the following was submitted for the record:) 
69 

PREPARED STATEMENT OF MARK B . BONSALL 

MARK B. BONSALL CHAIRMAN 

SALT RIVER PROJECT 

P.O. BOX 52025 

PHOENIX, ARIZONA 85072-2025 

TEL.: {602) 236·5702 

FAX:(602) 236·4350 

Statement of the Western Systems Coordinating Council Regarding 

Issues and Recommendations Concerning the August 1 0, 1996 

Western Power Outage 

Before the Water and Power Resources Subcommittee of the 

Committee on Resources 

U.S. House of Representatives 

November 7, 1996 

By Mr. Mark B. Bonsall 

Chairman, Western Systems Coordinating Council 

and 

Associate General Manager Marketin g, Customer Service, Financ ial and Planning 

Salt River Project 

Phoenix, Arizona 
70 

Chairman Doolittle and members of the Water end Power Subcommittee, it is 

e distinct pleasure to appear before you today to discuss the August 10, 1996, 

power outage that affected the western United States, western Canada, and 

northern Mexico, the actions taken following the outage, and the conclusions and 

the recommendations that have been d!lveloped as a result of the outage. 

I am Mark Bonsall, chairman of the Western Systems Coordinating Council 

and associate general manager, marketing, customer service, financial and planning 

at Salt River Project in Phoenix, Arizona. 

WSCC is the largest and most diverse of the 10 regional reliability councils 

of the North American Electric Reliability Council (NERC). WSCC's service territory 

extends from Canada to Mexico, an area of nearly 1.8 million square miles. It 

includes the provinces of Alberta and British Columbia, the northern portion of Baja 

California, Mexico, and all or portions of the 14 western states in between. Due to 

the vastness and diverse characteristics of the reg ion, WSCC's members face 

unique challenges in coordinating the day-to-day operation and long-range planning 

required to provide reliable and affordable electric service to the morEl than 

59 million people within the WSCC region. 

The interconnected transmission system within the WSCC region is known 

as the Western Interconnection. It is one of the five major electric system 

networks in NERC. 

OVERVIEW OF THE AUGUST 10 POWER OUTAGE 

At 3 :48p.m. pacific advanced standard time (PAST) on Saturday, August 

10, a major power outage occurred on the Western Interconnection, interrupting 

service to 7.5 million customers for periods ranging from several minutes to about 

nine hours. 

In the hours before the power ou·tage, three lightly loaded 500,000-volt lines 

(Big Eddy-Ostrander, John Day-Marion, and Marion-Lane) in the Portland area were 

forced out of service. These 500,000-volt lines were providing voltage support for 

the transmission system. Two of the line outages were caused by flashovers 

(short circuits) to trees . The third line was forced out of service because a circuit 

breaker was out of service when the second line outage occurred. While none of 

these line outages were individually judged to be crucial by Bonneville Power 

Administration dispatchers, the cumulative impact resulted in a weaker system. 

Voltages were adjusted but no schedules were reduced . In addition, two 115,000-

volt transmission lines, two 500,000-volt circuit breakers, and a 500,000/230,000-

volt transformer, all in the Portland area, were out of service for modifications 

and/or repairs . These outages contributed to the system stress following the 

subsequent loss of the Keeler-Allston 500,000-volt line. 

2 
71 

The power outage effectively began when the heavily loaded Keeler-Allston 

500,000-volt line, which is in the Portland, Oregon, area, sagged too close to a 

tree and flashed over. Loss of the Keeler-Allston 500,000-volt line precipitated the 

overloading and tripping of two underlying parallel transmission lines in the Portland 

area, one due to a flashover to a tree and one due to a relay malfunction, which 

depressed the surrounding transmission system voltages. The depressed voltages 

led to the subsequent tripping of hydroelectric generating units at the McNary Dam 

due to excitation equipment problems. This combination of events triggered 

increasing voltage oscillations on the interconnected transmission system, 

eventually causing protective devices to trip the three 500,000-volt CaliforniaOregon lntertie (COl) lines (three of the four major transmission lines that tie the 

Pacific Northwest to California). The outage of the these three lines resulted in 

transmission and generation outages that culminated in the system separating into 

four islands. (See Attachment 1.) 

System islanding is used in the West as a safety net to prevent a total 

blackout, minimize the number of customers affected, and minimize the time 

required to restore customer service. Because islanding did not occur in a 

controlled manner, loss of the COl resulted in the loss of approximately 21,400 

megawatts of generation and approximately 27,400 megawatts of underfrequency 

load shedding (over 7 million customers) in northern California and the Southwest 

(see table below). 

AUGUST 10, 1996, POWER OUTAGE 

Customers Load Shed Generation Restoration 

Affected (MW) Tripped Time 

(MW) (hours) 

Alberta 191,904 968 146 1 

Northwest 209,858 2,099 5,689 4 

Southwest 4,226,972 15,982 13,497 6 

Northern 2,861,343 11,440 7,918 9 

California 

Totals 7,490,077 30,489 27,250 9 

CONTRIBUTING FACTORS 

The interconnected transmission system from Canada south through 

Washington and Oregon to California was heavily loaded because of high 

temperatures (near or above 100 degrees) throughout much of the WSCC region. 

In addition, because of the excellent hydroelectric conditions in Canada and the 

Northwest, the amount of power being transferred (including large economy 

3 
72 

transfers) from Canada into the Northwest and from the Northwest to California 

was high, but within established transfer capability limits. 

IMMEPIATE ACTIONS TAKEN 

In the wake of this outage, an emergency meeting of senior management 

from the western utilities, the U.S. Department of Energy, and the state regulatory 

community was convened on August 12. A lower power flow transfer limit (from 

4,800 megawatts to 3,200 megawatts) was established for the California-Oregon 

lntertie until additional studies have been conducted and the results approved by a 

newly established WSCC Operating Capability Policy Committee . In addition, 

Bonneville Power Administration (BPAJ began a comprehensive study to assess the 

voltage support capability of its system. BPA also agreed to report all outages of 

500,000-volt transmission lines and other key facilities on its system . In 

conjunction with the U.S. Army Corps of Engineers, BPA also initiated a review to 

understand the loss of the McNary generators and to prevent their loss in the event 

of a future disturbance. Changes have been made to the McNary excitation 

systems. As an additional precaution, the Northeast/Southeast Separation Scheme 

was placed back in service. Additionally, all WSCC members have been asked to 

review their tree trimming programs, their system's voltage support capability, and 

the NERC recommendations set forth in the publication entitled "Survey of the 

Voltage Collapse Phenomenon." 

COMPREHENSIVE OUTAGE ASSESSMENT 

As is standard practice for WSCC and its members following. a system-wide 

power outage, a task force of industry experts conducted a thorough review of the 

power outage and recommended actions to lessen the potential for the occurrence 

of a similar event in the future. As part of the standard outage analysis and review 

process, WSCC procedures, policies, and monitoring activities are being reviewed 

to identify any necessary improvements. 

The final report on the August 10 outage includes 32 conclusions and over 

90 associated recommendations. All recommendations are logged and tracked until 

they are completed. The report has been submitted to the U.S. Department of 

Energy and the North American Electric Reliability Council. 

Key Findings 

In reviewing the August 10 outage, the task force identified four key 

findings: 

the interconnected transmission system was unknowingly being 

operated in violation of WSCC Reliability Criteria; 

4 
73 

• transmission line right-of-way maintenance, operating' studies, and 

system operating instructions to dispatchers were inadequate; 

• contingency plans should have been adopted to mitigate the effects of 

an outage of the Keeler-Allston 500,000-volt transmission line, and 

• the loss of the 13 McNary hydroelectric generating units in the 

Northwest was a major factor leading to the outage of the three 

500,000-volt California-Oregon lntertie lines and the subsequent 

islanding of the WSCC interconnected system, 

Corrective Actions 

This power outage indicates the need to identify and implement strategies 

that will minimize the potential for the more severe, unforeseen events, and should 

such events occur, minimize the impact of the outages , It also highlights the need 

for continued vigilance to reasonably ensure that all equipment will operate as 

expected, 

WSCC and the other regional councils are in the process of implementing 

additional security process measures. These measures will enhance interconnected 

system reliability through the exchange of information requ ired to augment system 

security and reliability , including on-line power flow and security analysis and 

increased system monitoring. These measures will enhance the operators ' ability 

to identify potential problem outages and take corrective actions. Within the 

WSCC region, there will be four security coordinators responsible for the active 

monitoring of electric system conditions on a real-time basis to proactively 

anticipate and mitigate potential problems and coordinate restoration following a 

system emergency , 

In addition, to safeguard the reliability of interconnected electric system 

operation, numerous technical studies are conducted each year to reasonably 

ensure that critical operating conditions are thoroughly examined and evaluated. 

These studies include assessments of low probability events that are expected to 

result in system islanding and underfrequency load shedding . Islanding and 

underfrequency load shedding are protective actions used in the West for severe 

low probability disturbances to stabilize the system, minimize customer 

interruptions, and allow rapid system restoration. Additional stud ies are being 

conducted to ensure a broad range of operating conditions have been adequately 

studied and that the system is being operated in compliance with WSCC and NERC 

criteria and policies, The WSCC members are looking at a wide variety of 

conditions and contingencies to ensure that the system is planned and operated 

within the established WSCC Reliability Criteria . 

5 
74 

SUMMARY 

In all likelihood, the August 10 power outage could have been avoided if 

contingency plans had been adopted to minimize the effects of an outage of the 

Keeler-Allston 500,000-volt line in the Pacific Northwest. In addition, the task 

force determined that the loss of the McNary generating units and inadequate treetrimming practices, operating studies, and instructions to dispatchers played a 

significant role in the severity of this disturbance . 

~Required to Ensure Reliability 

As the electric industry becomes more competitive, we must make certain 

that interconnected system reliab ility is preserved . We must ensure that all entities 

that own, operate, or use the interconnected transmission system are complying 

with the established criteria, guidelines, policies , and procedures of WSCC and 

NERC . I believe there are three essential steps that must be taken to ensure 

system reliability and a level playing field in an era of competition: 

1) mandatory compliance with established standards; 

2) mandatory membership in the regional reliability councils and NERC; and 

3) expanded compliance monitoring , with appropriate incentives, sanctions, 

or fines . 

As the industry is restructured and competition increases, it will become 

even more important for ALL market participants to adhere to the "rules of the 

road," especially since fewer participants (if any) will be willing to !JO the extra 

mile, and incur the added expense, to meet a competitor's obligation for ensuring 

reliabil ity. It is for this reason, that the industry w idely shares the view that 

voluntary compliance w ill no longer be adequate . 

To ensure mandatory compl iance, we must be able to monitor those involved 

and correct those in noncompliance. This raises some questions. How do you 

ensure compliance ? Is peer pressure enough? How will we ensure an organization 

implements corrective actions? Will fines or sanctions become necessary? 

First, we need to conside r economic-based mechanisms to ensure 

compliance and accountability - enforceable mechanisms, such as financial 

incentives in the form of market trade privileges or possibly compliance-based 

operator's licenses that would somehow allow participants to reduce their costs . 

Where financial or business incentives cannot be developed to ensure compliance 

and accountability, the regional reliability councils must have the ability to impose 

sanctions or fines on noncomplying members, so that one participant's 

noncompliance does not degrade reliability or increase costs for other market 

participants. Consequences for noncompliance must be applied in a timely , 

consistent, and nondiscriminatory manrer. 

6 
75 

The next question is ... How do you ensure compliance with the established 

"rules of the road" without mandatory membership in the regional councils and 

NERC, especially with all of the new players entering the industry? If membership 

is not mandatory, what stops an organization from withdrawing its membership if it 

does not agree with the noncompliance findings, fines, sanctions, etc.? 

By mandating membership, all essential players will be at the table . 

Everyone will have a hand in developing the compliance standards, allaying the fear 

of discrimination and ensuring an understanding of the adopted standards . 

Everyone will be required to comply with established standards and will not be able 

to terminate their membership to merely avoid mandatory compliance. Everyone 

will participate in the necessary functions of data collection, reliability assessments, 

and regional operation and planning. Everyone will have a stake in and be 

contributing financial support to promoting regional rel iability. Mandatory 

membership will impart a sense of equity among all entities. and will promote 

cooperation and coordination ... something we may see less of as competition 

increases . 

We must remember, however, that the regional councils and NERC have the 

ability to mandate compliance. but not to mandate membership. Mandating 

membership will require state and /or federal legislation or other action. 

As in a quality assurance program, there needs to be a monitoring program 

with checks and balances . Consequently, compliance monitoring will be an 

essential element for preserving reliability. Reliability must be maintained moment 

by moment; therefore, compliance with reliability standards must be monitored on 

a continuous basis . We believe that NERC and the regional reliability councils will 

need to expand their compliance monitoring programs if we are to ensure reliability 

and a level playing field . 

No matter how dramatically the industry changes and evolves, mandatory 

compliance, reliability monitoring, enforcement capability, and accountability will be 

essential for ensuring reliability. 

For over 30 years , NERC and the regional councils have been the caretakers 

of reliabi lity through the cooperative development of NERC and regional council 

policies , proced ures, and criteria ... and voluntary compliance with these standards. 

As the industry is restructured and competition increases, it will become even more 

important that the electric industry has a structure in place with the necessary 

authority and tools to ensure ALL market participants adhere to these "rules of the 

road ." WSCC's Ag reement states that its members are responsible for meet ing 

the established criteria, policies, and procedures . I anticipate that in January of 

1997 the NERC Board of Trustees w ill adopt a resolution making compliance with 

its policies mandatory. NERC also will continue its oversight role in monitoring the 

security processes being implemented by the 10 regional councils to ensure they 

are consistent w ith NERC's recommendations. 

7 
76 

There is no reason to doubt the ability, appropriateness, and the resolve of 

NERC end the regional councils to continue to establish and monitor compliance 

with the required reliability standards . As the Department of Energy stated in its 

report to the President, the " .. . self-regulated system for ensuring electric system 

reliability through NERC and the regional reliability councils has worked quite well, 

and works well today . It can continue tiJ work well in the future ... " and "WSCC 

and NERC have committed to take actions to enhance accountability tor reliability, 

improve the tracking of compliance with reliability standards, and address the pace 

of industry change." 

Given the quick and decisive steps being taken by the industry toward 

mandatory compliance and the implementation of security processes to ensure 

reliability, I see no need for federal legislation that would require the ~1overnment to 

develop reliability criteria or to implement mechanisms for enforcing compliance 

with the "rules of the road ." However, as previously noted , federal or state action 

mandating membership in the reliability councils and NERC is needed t o equitably 

administer and ensure compliance w ith the "rules of the road" that have been 

etablished to preserve rel iability . 

Mr. Chairman and members of the Water and Power Subcommittee, this concludes 

my statement. I would be pleased to address any questions you may have . 

8 
77 

Attachment I 

Islands Formed During the August 1 0 Power Outage 

9 
., . ~ 

le ---. "'--

{..:_. ' 

---:: 

-.. 

!' 

--- • ! 

I 

~ . "'--' ...... -., 

.....

-~--~ . --) .-~ . 

78 

. -- · --~--:~ 

~---·--- .! ' . 1-- .• -li - ·• , e l. 

L ---

Islands Formed August 10,1996 

10 
79 

WESTERN SYSTEMS COORDINATING COUNCil.. 

DISTURBANCE REPORT 

For the Power System Outage that Occurred on the 

Western Interconnection 

August 10, 1996 1548 PAST 

Approved by the WSCC Operations 

Committee on October 18, 1996 
80 

DISTURBANCE REPORT TASK FORCE MEMBERS 

Don Watkins, BPA - Chairman 

Bernie Alfonso, SDGE 

Dean Athow, W APA 

Don Badley, NWPP 

Jim Beck, NCPA 

Sharon Blair, BPA 

Mark Bonsall, SRP 

Steve Brockschink, COE 

Jim Bums, BPA 

Gene Byars, NERC 

Paul Carrier, DOE 

Douglas Cave, BCHA 

Bill Cornish, WSCC 

Jon Daume, BPA 

Robert Dintelman, WSCC 

Jim Eden, PGE 

Christine Elliott, NWPP 

Michael Flores, TEP 

John Forman, T ANC 

Kevin Graves, W AP A 

Dharam Gupta, PAC 

Mark Hanson, IPC 

Bob Harshbarger, PSPL 

Jack Kelley, SCL 

Eric Law, PG&E 

Lou, Leffler, NERC 

Eddie Lim, SMUD 

Mike Lopez, SCE 

Wayne Mays, PGE 

AI McCuen, CEC 

Don Mcinnis, NERC 

Bill Mittelstadt, BPA 

Bernie O'Connell, PAC 

Brad Osburn, W APA 

Leslie Padilla, SDGE 

Vern Parry, COE 

Dan Sauter, IPC 

Ron Schelberg, IPC 

Joe Seabrook, PSPL 

Bob Smith, APS 

Bob Stuart, PG&E 

Brian Theaker, LDWP 

Yu Wang, PAC 

Scott Waples, WWP 
81 

TABLE OF CONTENTS 

System Identifiers 

I. SUMMARY AND INTRODUCTION . . . . . . . . . . . . . . . . . . . . 2 

II. CONCLUSIONS AND RECOMMENDATIONS . . . . . . . . . . . . 8 

III. PREDISTURBANCE CONDITIONS . . . . . . . . . . . . . . . . . . . . . 27 

IV. DETAILED DESCRIPTION . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 

Customers Affected and Load Lost . . . . . . . . . . . . . . . . . . . . App. l 

Generation Lost .... ... ................. ..... . . ... App. 2 

Transmission Lines Tripped ......................... App. 3 

Abnormal Conditions .............................. App. 4 

V. SEQUENCE OF EVENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 

Sequence of Events Details ............... ....... . . .. App. 5 

VI. DISTURBANCE EVALUATION CHECKLIST ............. 42 

VII. EXHffiiTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 
82 

System Identifiers 

Throughout the report, organizations are identified using: the 

acronyms listed below. 

APS - Arizona Public Service Company 

BPA - Bonneville Power Administration 

BURB - Burbank, City of 

BCHA - British Columbia Hydro and Power 

Authority 

CDWR - Department of Water Resources/California 

CSU - Colorado Springs Utilities 

CFE - Comision Federal de Electricidad 

EPE - El Paso Electric Company 

EWEB - Eugene Water & Electric Board 

FARM - Farmington, City of 

GLEN - Glendale, City of 

!PC - Idaho Power Company 

LDWP - Los Angeles Department of Water 

and Power 

MWD - Metropolitan Water District! 

Southern California 

MID - Modesto Irrigation District 

MPC - Montana Power Company. The 

NEVP - Nevada Power Company 

NCPA - Northern California Power Agency 

NWPP - Northwest Power Pool 

OXGC - Oxbow Geothermal Corporation 

PG&E - Pacific Gas and Electric Company 

PAC - PacifiCorp 

PASA - Pasadena. City of 

PEGT - Plains Electric Generation and 

Transmission Cooperative, Inc. 

PGE - Portland General Electric Company 

PNM - Public Service Company of New Mexico 

COPD - PUD No. I of Cowlitz County 

DOPD - PUD No. I of Douglas County 

GCPD - PUD No. 2 of Grant County 

SNPD - PUD No I of Snohomish County 

PSPL - Puget Sound Power & Light Company 

SMUD - Sacramento Municipal Utility District 

SRP - Salt River Project 

SDGE - San Diego Gas & Electric Company 

SCL - Seattle Department of Lighting 

(Seattle City Light) 

SPP - Sierra Pacific Power Company 

SCE - Southern California Edison Company 

TCL - Tacoma Department of Public Utilities 

(Tacoma City Light) 

TNP Texas-New Mexico Power Company 

TAUC - TransAlta Utilities Corporation 

TSGT - Tri-State Generation & Transmission 

Association. Inc. 

TEP - Tucson Electric Power Company 

TID - Turlock Irrigation District 

USBR - U.S. Department of Interior 

Bureau of Reclamation 

USDO - (Denv<:r Office) 

USGP - (Great Plains) 

USLC - (Lower Colorado) 

USMP - (Mid-Pacific) 

USPN - (Pacitic Northwest) 

USUC - (Upper Colorado) 

VERN - Vernon, City of 

WWPC Washington Wate:r Power Company 

W APA Western Area Power Administration 

W AHQ - (Golden, Colorado) 

W ALC - (Phoenix, Arizona) 

W ALM - (Loveland, Colorado) 

W AMP - (Sacramento, California) 

WAUC -(Salt Lake City, Utah) 

W AUM - (Billings, Montana) 
83 

I. SUMMARY AND INTRODUCTION 

At 1548 PAST on Saturday, August 10, a major system disturbance separated the 

Western Systems Coordinating Council (WSCC) system into four islands, interrupting 

service to 7.5 million customers for periods ranging from several minutes to about 

nine hours. This disturbance effectively began with the loss of the Keeler-Allston 

500-kV line in the Portland area, due to inadequate right-of-way maintenance, which 

overloaded parallel lines and depressed transmission voltages. These conditions led to 

subsequent tripping of additional lines and McNary generating units, triggering 

increasing oscillations that eventually caused protective devices to trip the three 500-

kV California-Oregon lntertie (COl) lines and other major lines. 

In addition to interrupting service to a large number of customers, this severe 

disturbance tripped fifteen large thermal and nuclear units in California and the 

Southwest, delaying load restoration. A few large units did not return to service for 

several days, requiring operators to purchase emergency power to serve the high, hotweather loads experienced during the following days. 

In the wake of this disturbance, a lower limit (3,200 MW) was maintained on the COl 

to account for operational limits on generation at McNary (exciter problems) and The 

Dalles (fish protection). To avoid implementing an emergency operating plan in 

California which, under a worst case scenario, could have necessitated rotating 

blackouts, the COl limit was increased to 3,600 MW from August 12 to August 14. 

This was made possible, on an emergency basis, by temporarily reducing Endangered 

Species Act (ESA) compliance spills and increasing generation output at The Dalles. 

Several factors contributed to the occurrence and severity of this disturbance. 

l. HIGH NORTHWEST TRANSMISSION LOADING 

The 500-kV and underlying interstate transmission system from Canada south 

through Washington and Oregon to California was heavily loaded due to: 

Relatively high loads, caused by hot weather throughout much of the WSCC 

region. 

Excellent hydroelectric conditions in Canada and the Northwest, leading to 

high power transfers (including large economy transfers) from Canada into 

the Northwest and from the Northwest to California. System conditions in the 

Northwest were similar to the conditions prior to the July 2, 1996, 

disturbance, except power was flowing into the Northwest from Idaho. This 

allowed exports to California on the COl of up to 4,750 MW, as determined 

by operating nomogram limits developed by BPA, PG&E, IPC, and PAC 

following the July 2 disturbance. 

During these periods of high transmission loading, BP A operators had 

previously noticed small changes in power flows causing large changes in 

2 
84 

voltage, indicating voltage support problems in the Northwest during stressed 

operating conditions. 

2. EQUIPMENT OUT OF SERVICE 

In the hours before the disturbance, three lightly loaded 500-kV lines (Big 

Eddy-Ostrander, John Day-Marion, and Marion-Lane) in the Portland area 

were forced out of service. These 500-kV lines were providing reactive 

power support for the transmission system. Two of the outages were caused 

by flashovers to trees resulting from inadequate right-of-way maintenance, 

and one outage resulted from a circuit breaker being out of service. 

The Allston-Rainier 115-kV line was out of service due to degraded 

capability of line hardware. The Longview-Lexington 115-kV line was out of 

service for fiber-optic cable installation. These outages contributed to the 

system stress following the loss of the Keeler-Allston 500-kV line. 

A 500-kV circuit breaker at Marion, a 500-kV circuit breaker at Keeler, and 

the 500/230-kV transformer at Keeler were out of service for modification. 

The Static V AR Compensator (SVC) at Keeler was reduced in its ability to 

support the 500-kV system voltage due to the transformer outage (the SVC is 

tied to the 230-kV side). Since Northwest loads are historically lower in the 

summer than in the winter, BPA performs most system maintenance during 

the summer. 

3. TRIGGERING EVENTS 

At 1542:37 PAST, the heavily loaded Keeler-Allston 500-kV Line sagged too 

close to a tree and flashed over, additionally forcing the Pearl-Keeler 500-kV 

line out of service due to the 500/230-kV transformer outage and breaker 

replacement work at Keeler. These outages overloaded the parallel 230-kV 

and 115-kV lines into the Portland area and depressed the 500 .. kV voltage at 

Hanford from 527 to 506 kV. The reactive power output from McNary 

increased to its maximum sustainable level to support the voltage, and held 

this level for nearly five minutes. 

Approximately five minutes lat(:r, (about 1547:29 PAST), the St. JahnsMerwin 115-kV line tripped due to a zone l KD relay malfunction, 

contributing to the loading of other lines parallel to the Keekr .. Allston 500-

kV line. (The exact time of this event is not known.) 

At 1547:36, the overloaded Ross-Lexington 230-kV line sagged too close to a 

tree and flashed over, resulting in loss of 207 MW of Swift generation, thus 

further depressing system voltage and further increasing the demand for 

reactive power output from McNary generating units, already at their 

maximum sustainable level. This outage also contributed to loading on the 

lines parallel to the Keeler-Allston 500-kV line. 

3 
85 

At 1547:37, units at McNary began tripping (due to excitation equipment 

problems), and increasing power and voltage oscillations began. These 

oscillations increased in magnitude for approximately 70 seconds, until the 

three 500-kV COl lines relayed due to low voltage (less than 315 kV on the 

Malin 500-kV bus) at 1548:52. These oscillations were a major factor leading 

to the separation of COl and subsequent islanding of the WSCC system. 

Some of the power that had been flowing to northern California on the COl 

surged east then south through Idaho, Utah, Colorado, Arizona, New Mexico, 

Nevada and southern California. Numerous transmission lines in this path 

subsequently tripped due to out-of-step conditions and low voltage. Although 

several lines between Arizona and southern California tripped, the two areas 

remained tied together through remaining lines. 

4. KEY FACTORS 

• BPA's right-of-way maintenance was inadequate. Consequently, BPA's 

failure to trim trees and remove identified danger trees caused flashovers on 

and the loss of several 500-kV transmission lines, the last of which led to 

overloads and cascading outages throughout the Western Interconnection. 

BPA operators were operating the system in a condition in which a single 

contingency outage (the Keeler-Allston 500-kV line) would overload parallel 

transmission lines. They were aware that on July 13, the Pearl-Keeler 500-

kV line sagged too close to a tree, flashed over and tripped. This forced 

open the Keeler-Allston 500-kV line at Keeler due to a breaker outage. The 

outages loaded the parallel Longview-Allston No. 4 115-kV line to 109 

percent. Additionally, a jumper on the parallel Allston-St. Helens 115-kV 

line burned open within two minutes due to failure of conductor hardware 

that had degraded. It was not loaded above its thermal rating. The two 

Allston-Trojan 230-kV lines and the Ross-Lexington 230-kV line loaded to 

their thermal limits. Loading on other lines also increased substantially. 

While this incident did not lead to cascading outages, it should have served 

as a warning prior to the August I 0 outage and led to further technical 

analysis. 

BPA operators were unknowingly operating the system in a condition in 

which the Keeler-Allston 500-kV line outage would trigger subsequent 

cascading outages because adequate operating studies had not been 

conducted. Operating in a condition where cascading outages could occur is 

a violation of the WSCC Minimum Operating Reliability Criteria. 

In the hour and a half prior to the disturbance, BPA's Big Eddy-Ostrander, 

John Day-Marion and Marion-Lane 500-kV lines were forced out of service. 

While none of these lines were individually judged to be crucial by BPA 

dispatchers, the cumulative impact resulted in a weaker system. BPA did not 

widely communicate these outages to other WSCC members nor did they 

4 
86 

reduce loadings on lines or adjust local generation as precautionary measures 

to protect against the weakened state of the system. 

BPA notified PGE of maintenance outages in effect, but did not notify other 

WSCC members. BPA did not widely communicate the forced line outages 

to other WSCC members, precluding them from making system adjustments 

had they perceived a need to take such action. BPA did not consider these to 

be key facility outages for reporting purposes. 

All the units at McNary tripped due to exciter protection as units responded 

to reduced voltage after the Keeler-Allston 500-kV and subsequent line trips. 

Even though the loss of McNary units (of ten units operating, three tripped 

immediately prior to COl separation and two tripped after separation) during 

the July 2 disturbance had demonstrated problems with the excitation systems 

on these units, this information had not yet been analyzed and factored into 

studies performed to develop COI/Midpoint-Summer Lake and other 

operating limits after July 2. Additionally, some other area generators did not 

respond to support voltage to the extent modeled in studies used by WSCC 

utilities. 

The Dalles had only five of 22 gene1ating units operating, generating a total 

of 320 MW, due to spill requirements imposed to protect salmon smolts 

migrating downstream, significantly diminishing the voltage support available 

for the transmission system. The effect of this known operating constraint 

had not been factored into system studies. 

Growing system oscillations resulted in increasing voltage and power swings 

on the COI, leading to COI instability and separations. The growing 

oscillations may be attributed to an increased electrical angle between 

northwest generation and the COl due to: 

- weakening of the transmission system (loss of Keeler-Allston 500-kV, RossLexington 230-kV and other, lower voltage lines) 

- a shift of generation to Grand Coulee and Chief Joseph following tripping 

of the McNary units 

- reduced reactive support to the COl resulting from loss of McNary units 

and nonparticipation of Coyote Springs, and Hermiston 

In addition, the response of the PDCI to system voltage swings may have 

contributed to growing oscillations. 

5 
87 

5. WIDESPREAD LOSS OF GENERATION AND LOAD. 

The loss of the COI (which also occurred on July 2) resulted in 

approximately 28,000 MW of underfrequency load shedding and 

approximately 20,000 MW of undesired generation loss in the northern 

California and southern islands in this disturbance. 

In summary, the disturbance could have been avoided, in all likelihood, if contingency 

plans had been adopted to mitigate the effects of the Keeler-Allston 500-kV line 

outage. Inadequate tree-trimming practices, operating studies, and instructions to 

dispatchers also played a significant role in this disturbance. 

ISLANDS 

The disturbance created four electrical islands: 

1. Northern California Island (north of Los Angeles extending to the Oregon 

border) 

Created by: loss of the COl, Midway-Vincent out-of-step tripping, tripping of 

the PG&E-SPP ties 

Load lost: 11,602 MW (388,017 MW-minutes) -due to manual and automatic 

underfrequency load shedding 

Generation lost: Over 4Q units totaling 7,937 MW due to loss of excitation 

from low voltage and out-of-step conditions, turbine-generator vibration, 

antimotoring and line trips 

Customers affected: 2,892,343 

Frequency: dipped initially to 58.54 Hz, spiked to 60.7 Hz, dropped again to 

58.3 Hz, and returned to normal in two and a half hours 

2. Southern Island (southern California; southern Nevada; Arizona; New Mexico; El 

Paso, Texas and northern Baja California) 

Created by: out-of-step tripping between Utah/Colorado and Arizona/New 

Mexico/Nevada and out-of-step tripping berween Midway and Vincent and 

tripping of the SCE-SPP 55-kV ties 

Load lost: 15,820 MW, (1.98 million MW-minutes) due to automatic and 

manual underfrequency load shedding 

Generation lost: Over 90 units totaling 13,497 MW due to loss of excitation, 

boiler instability, overcurrent, underfrequency, flame failure, overfrequency 

and line trips 

Customers affected: 4,195,972 

Frequency: spiked to 61.3 Hz, dropped to 58.5 Hz, returned to normal in 70 

minutes 

6 
88 

3. Northern Island (British Columbia, Oregon, Washington. Montana, Wyoming, 

Idaho, Utah, Northern Nevada, Colorado. western South Dakota, and western 

Nebraska) 

Created by: loss of COl, BCHAffAUC separation, tripping of PG&E-SPP 

ties, SCE-SPP ties, and Utah/Colorado-Arizona/New Mexico/Nevada ties 

Load lost: 2,099 MW (95,075 MW-minutes) due to Joss of transmission 

Generation lost: 60 units totaling 5,689 MW, due to activation of the Pacific 

AC and DC Intertie remedial action schemes, overfrequency, or Joss of 

excitation due to low voltage 

Customers affected: 209,858 

Frequency: increased to 60.4 Hz, returned to normal in 17 minutes 

4. Alberta Island (Alberta) 

Created at 1554:36 by: generation in Alberta ramped back due to high 

frequency, overloading and tripping the BCHAffAUC interconnection. 

Load lost: 968 MW (24,888 MW-minutes, due to automatic underfrequency 

load shedding 

Generation lost: six units totaling 146 MW due to overfrequency 

Customers affected: 191,904 

Frequency: increased to 60.4 Hz, then dropped to 59.0 Hz and returned to 

normal within six minutes 

TOTAL WSCC IMPACTS: 

Load lost: 30,489 MW 

Generation lost: 27,269 MW 

Customers affected: 7.49 million 

Load not served: 2.48 million MW-minutes 

7 
89 

II. CONCLUSIONS AND RECOMMENDATIONS 

All recommendations will require a response to WSCC by the indicated date and 

denote the party responsible for reporting. The WSCC will track progress on each 

recommendation. The WSCC Board of Trustees will be responsible for ensuring that 

all recommendations are implemented in accordance with the schedule. Target 

completion dates are indicated in parentheses following each recommendation. 

1. Conclusion: System operation was not in compliance with the WSCC Minimum 

Operating Reliability Criteria (MORC) prior to the outage of the Keeler-Allston 

500-kV line. Outage of the Keeler-Allston 500-kV line precipitated the 

overloading and tripping of parallel lines, voltage drops, the undesirable tripping 

of key hydro units, and subsequent increasing oscillations, all of which led to 

tripping the COl and other major lines, and separating the system into four 

islands, causing the widespread uncontrolled outage of generation, and 

interrupting electric service to approximately 7.5 million customers. 

The following are excerpts from the WSCC MORC and the WSCC Reliability 

Criteria for Transmission System Planning: 

" ... Member Systems shall establish interarea transfer capability limits for 

conditions representing the outage of any of the facilities that affect the 

transfer capability limits. n 

"The systems or control areas will remain stable upon loss of any one single 

element without system cascading that could result in the successive loss of 

additional elements. n 

"Systems or control areas should immediately take steps to ... ensure that 

loss of any subsequent element will not violate the transfer capability limit 

criteria." 

"During an emergency condition, security and reliability of the bulk power 

system are threatened; therefore, immediate steps must be taken to provide 

relief .. . Loss of Any Element- The system(s) causing the emergency 

condition shall take immediate steps to relieve the condition by adjusting 

generation, changing schedules between control areas, and initiating relief 

measures including manual or automatic load shedding (if required) to relieve 

overloading or imminent voltage collapse." 

"The Criteria does not permit any uncontrolled loss of generation, load, or 

uncontrolled separation of transmission facilities." 

8 
90 

Recommendation: 

a. BPA shall assess why it failed to identify that a Keeler-Allston 500-kV line 

outage would overload parallel lines, and potentially violate the WSCC 

MORC. BPA shall immediately implement corrective action as appropriate. 

BPA's assessment and mitigating actions (e.g., operating procedures, training, 

studies, etc.) that have been or are being taken shall be submitted to WSCC's 

Compliance Monitoring and OptTating Practices Subcommittee (CMOPS). 

(December 1996) 

b. Northwest Power Pool members shall reassess their operating policies, 

practices, and procedures to ensure that the Northwest bulk power system is 

operated in compliance with WSCC and NERC criteria and procedures in 

light of the August 10 and July 2 disturbances and report to CMOPS. 

(December 1996) 

2. Conclusion: The outage of the Keeler-Allston 500-kV line overloaded the four 

parallel lower voltage lines. PAC's Merwin-St. Johns 115-kV (by relay 

misoperation) and BPA's Ross-Lexington 230-kV lines subsequently tripped and 

the remaining two PGE 230-kV lines loaded to 150 percent of their emergency 

rating. PGE's parallel 230-kV lines were overloaded (for approximately seven 

minutes) after the loss of the Keeler-Allston 500-kV line. These outages and 

overloads caused a voltage drop in the Hanford area, in tum causing the McNary 

generating units to increase their reactive power output- already at the 

maximum sustainable level. 

Recommendation: 

a. The WSCC Operations Committee (OC) and Planning Coordination 

Committee (PCC) shall thoroughly review WSCC's and its members' 

processes for studying upcoming system operating conditions and implement 

any changes for WSCC processes and recommend changes for members' 

processes as needed to ensure that these processes for identifying all critical 

and unusual operating conditions are adequate, and that credible disturbances 

are adequately studied prior to encountering them in real-time operating 

conditions. (March 1997) 

b. The WSCC OC shall develop a process for reporting on anticipated operating 

conditions, critical conditions, and the results of studies conducted to assess 

these conditions. (March 1997) 

c. BPA shall review and report to CMOPS regarding procedures for identifying 

and accounting for critical operating conditions and implement appropriate 

corrective measures. (December 1996) 

d. WSCC's Security Process Task Force (SPTF) shall pursue implementation of 

on-line power flow and security analysis, and recommend appropriate actions 

to increase the monitoring of key system parameters that would allow 

9 
91 

operators to identify potential problem outages and take corrective actions. 

(December 1996) 

e. All WSCC members shall provide the data requested by other members 

required for system monitoring and on-line security programs. In conjunction 

with NERC SPTF requirements, the data shall be exchanged by April 1997. 

f. The WSCC Dispatcher Training Subcommittee (DTS), in conjunction with 

BPA, PGE, and PAC shall evaluate and report to CMOPS whether the 

dispatcher response to the Keeler-Allston outage was proper and recommend 

appropriate actions. (December 1996) 

g. BPA shall ensure, and report to CMOPS, that its dispatchers are trained and 

have appropriate guidelines regarding actions to be taken when they 

encounter stressed or unusual operating conditions for which there are no 

prescribed operating instructions. The WSCC Dispatcher Training 

Subcommittee shall similarly develop generic guidelines for all WSCC 

members. (December 1996) 

h. The WSCC PCC/OC Joint Guidance Committee shall review methodologies 

being used for off-line studies and develop a process that will reasonably 

ensure that all credible contingencies are considered both in rating studies and 

in operating studies. (December 19%) 

i. The WSCC Intertie Study Group (ISG) shall investigate, and make 

appropriate recommendations regarding, the conditions of August 10, 

including increased system stress due to simultaneous transfers from British 

Columbia to the Northwest and from the Northwest to California and 

determine the impact that the Canadian transfers had on the severity of this 

contingency. The effects of Montana-Northwest and Idaho-Northwest (in 

both directions) transfers shall also be studied. (December 1996) 

j. The Northwest Power Pool (NWPP) Transmission Planning Committee (TPC) 

shall investigate and determine appropriate operational limits for several 

portions of the I-5 corridor between Seattle and Portland, including the 

Keeler-Allston cut plane. This cut plane shall include appropriate 

transmission lines on the west and east sides of the Cascades. (May 1997) 

Status: The Seattle-Portland (SeaPort) study group was formed by the 

NWPP-TPC to review critical paths along the I-5 corridor between Seattle 

and Portland associated with the 3,150 MW BCHA-to-Northwest path uprate 

planned for completion in 1997. This planning study was agreed upon by 

BPA, PGE, and PAC to facilitate acceptance of the WSCC Facilities Rating 

process Phase III status of the BCHA-to-NW uprate. Participation in this 

study group was open to all interested parties. One portion of these studies 

focused on the Keeler-Allston 500-kV outage and potential overloads on the 

underlying transmission lines. The report on the Keeler-Allston path was 

presented to the SeaPort group in May 1996. Shortly thereafter, a 

10 
92 

presentation was also made to the NWPP-TPC. The effon to compile all of 

the sections of the study into a comprehensive repon was in progress at the 

time of the August 10 disturbance. This comprehensive repon was not yet 

available to the NWPP-TPC or the WSCC. Following the August 10 

disturbance, an evaluation is being done, factoring in additional generation 

patterns on the existing system as well as the future system. 

3. Conclusion: A wide variety of conditions and contingencies must be looked at to 

ensure that the system is planned and operated within the WSCC Reliability 

Criteria. Nevenheless, it is recognized that improbable conditions can develop 

that will lead to system separation across major transfer paths, such as the COl 

and other paths. 

Recommendation: The Technical Studies Subcommittee (TSS) shall repon (to 

PCC) to what extent studies have been run to determine the consequences of loss 

of the COl and other critical paths and what mitigative measures 311! in place to 

minimize the consequences of such disturbances. (December 1996) 

4. Conclusion: Immediately following the loss of the Ross-Lexington 230-kV line 

and the Merwin-St. Johns 115-kV line, the McNary units began tripping due to 

excitation system protection problems, withdrawing substantial real, reactive, and 

inertial suppon from the system. Three McNary units also tripped prior to COl 

separation during the July 2 disturbance and were identified in the disturbance 

review. 

Recommendation: 

a USCE shall review and repon to CMOPS whether exciter protection at 

McNary was proper on both July 2 and August 10, identify why the McNary 

units tripped and take appropriate action so that undesirable unit tripping will 

not occur. (December 1996) 

Status: On August 16 and Augu:;t 17, work was completed to adjust the 

McNary voltage regulators for units 1-12 and 14. The WSCC lntenie 

Transfer Capability Policy Committee will review corrective measures. Work 

is also underway to change taps on all 13.8/230-kV transformers at the 

McNary powerhouse to increase the 230-kV voltage. Testing underway 

suggests the problem was false tripping of the phase imbalance relay on the 

exciter system. By September II, most testing and corrections were 

completed at McNary powerhouse. Replacement parts for the faulty relay 

have been ordered and modifications will be completed in November 1996. 

b. USCE shall review and test their generating unit exciters in the Nonhwest to 

ensure proper operation of exciter controls and protection. Results should be 

properly modeled by BPA in system studies and actions taken by BPA and 

USCE reported to CMOPS. (December 1996) 

II 
93 

c. The WSCC Control Work Group (CWG) shall determine what tests need to 

be applied to generating unit exciters to ensure proper operation of exciter 

controls and protection. They shall also determine what unit MY A level 

must be tested and develop a procedure to ensure uniform testing, including 

the frequency of testing and a recommended priority list of units to be tested 

first. (The CWG work must be completed by November I, 1996.) All 

generation owning and operating entities in the WSCC region shall perform 

the prescribed testing and report to CMOPS. (June 1997) The results should 

be used to properly model generating units in sys!em studies, and actions 

taken reported to CMOPS. (June 1997) 

d. The WSCC ISG shall determine the effect of the McNary and other 

Northwest units on system dynamic and voltage stability. (December 1996) 

e. Conclusion I, recommendation a of the July 2, 1996 disturbance report states 

"Idaho Power Company, PaciflCorp, Bonneville Power Administration (BPA), 

and other Northwest area entities shall reduce scheduled transfers to a safe 

and prudent level until studies have been conducted to determine the 

maximum simultaneous transfer capability limits and to thoroughly evaluate 

operating conditions actually observed on July 2." BPA shall determine and 

report to CMOPS why McNary problems were not considered in establishing 

new COl, BCHA-NW, and other operating limits following the July 2 

disturbance and prior to the August 10 disturbance. (October 1996) 

f. BPA shall also determine why corrective measures at McNary were not 

implemented prior to increasing AC Intertie operating limits after the July 2 

limits were imposed and report to CMOPS. (October 1996) 

g. BPA, USPN and USCE shall ensure that transmission planning models are 

accurate and reflect the up-to-date capability of the system. (October 1996) 

h. BPA, USCE, and USPN shall review the adequacy of their interorganizational communications and shall jointly plan and initiate corrective 

actions to their respective systems to ensure reliable operation. (October 

1996) 

5. Conclusion: During the tripping of the McNary units, 0.2-Hz power system 

oscillations were initiated and increased in magnitude. 

Recommendation: 

a. The WSCC ISG shall investigate the cause of the undamped oscillations and 

make recommendations. (December 1996) 

b. The WSCC CWG shall review the number of power system stabilizers (PSS) 

in service at the time of the disturbance and make appropriate 

recommendations. (March 1997) 

12 

36-069 - 97 - 4 
94 

c. The WSCC ISG shall detennine whether high levels of excitation made PSS 

ineffective and make appropriate recommendations. (March 1997) 

d. The WSCC CWG shall review the application and settings of PSS to 

detennine adequacy and make appropriate recommendations. (March 1997) 

e. The WSCC Technical Studies Subcommittee (TSS) shall review the 

feasibility and desirability of implementing other oscillation damping 

controls, such as high voltage direct current (HVDC) modulation and make 

appropriate recommendations. (June 1997) 

f. All WSCC owners of generators, in conjunction with the WSCC TSS and 

CWG shall assess whether installed excitation systems and PSS on units with 

capacity of ten MW or larger, are properly tested, tuned, and correctly 

modeled in transient stability studies and make appropriate recommendations. 

(March 1997) 

6. Conclusion: COl operational limits, and any misjudgment in establishing those 

limits, can have a profound effect on the entire WSCC Interconnection. 

Although the COl operating limits and associated high transfers were not the root 

cause of the disturbance, they contributed to the overall severity of the 

disturbance. At the time of the August 10 disturbance, the COl schedule was 

4,285 MW and actual flow was 4,350 MW. The operating limit at the time 

(based on the nomogram) was 4,740 MW. The operational limit in place at the 

time of the disturbance had been developed by BPA, PG&E, IPC, and PAC after 

the July 2 disturbance, with only cursory review by other WSCC parties. 

Recommendation: 

a WSCC shall form an lntertie Transfer Capability Policy Committee to ensure 

that NW imports/exports, including COl, Midpoint-Summer Lake, BCHANW, NW-Montana and other transfer levels are maintained at safe levels. 

They shall have the authority to raise or lower operational limits. As agreed 

upon at the August 12 emergency meeting of the WSCC Executive 

Committee, approval shall be required from the Intertie Transfer Capability 

Policy Committee to exceed north to south transfer levels of 3,200 MW at 

the California-Oregon Border. Subsequent technical discussions led to 

allocating a north to south limit on the Pacific HVDC lntertie (PDCI) of 2000 

MW unless the Midpoint-Summer Lake 500-kV line flow exceeds 200 MW 

into Summer Lake, at which point the PDCI may be loaded to 2200 MW. A 

WSCC-wide process using the WSCC lntertie Study Group and the lntertie 

Transfer Capability Policy Committee shall be developed and implemented 

for the interim review of changes to operating procedures and operating limits 

affecting the Northwest interconnected system. This review function is for 

operational limits and shall not replace WSCC's established project rating 

review process and shall not be used to establish ratings higher than those 

currently existing. This process shall be expanded to encompass all major 

WSCC transfer paths. (October 1996) 

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b. The WSCC ISG shall identify and report to CMOPS the operating practices 

needed to ensure that credible generation and transmission outages within the 

Interconnection do not result in the loss of the California-Oregon Intertie. The 

WSCC members shall implement revised operating practices as appropriate. 

(April 1997) 

7. Conclusion: In the hour and a half prior to the disturbance, SPA's Big EddyOstrander, John Day-Marion, and Marion-Lane 500-kV lines were forced out of 

service. Local load area voltage adjustments were made; however, no 

vulnerabilities were identified by BPA dispatchers and no changes were made to 

interarea transfers or internal line loadings to reduce system stress. It is not yet 

known to what degree these outages contributed to the severity of the 

disturbance. No BCHA-NW or other COl limits had been identified in relation 

to these outages. Had a need for limits related to these line outages been 

identified, ample time was available to make system adjustments. 

Recommendation: 

a BPA shall determine what tools and information are needed to recognize and 

deal with potential system problems such as those experienced on August 10, 

and ensure that its operators are informed and trained to respond to such 

operating problems. BPA shall ensure that operating procedures are in place 

to mitigate potential operating problems before they escalate and cause 

reliability problems. SPA's actions shall be reported to CMOPS and the 

WSCC SPTF. (December 1996) 

b. WSCC's Intertie Study Group shall investigate the impact of the Big EddyOstrander and John Day-Marion-Lane line outages. This investigation shall 

determine whether the Keeler-Allston and/or Keeler-Pearl line outage would 

have overloaded the Ross-Lexington 230-kV, PacifiCorp's Merwin-St. Johns 

115-kV and PGE's 230-kV Trojan lines or resulted in voltage collapse if 

these three lines had still been in service. (December 1996) 

c. BPA shall implement various off-line, on-line, and real-time monitoring tools 

to identify at-risk system operating conditions. (Report status to CMOPS by 

December 1996 and implement by June 1997) 

8. Conclusion: While the outage of the Big Eddy-Ostrander 500-kV line was 

known to PGE and the John Day-Marion 500-kV line outage was known to 

PG&E by inter-utility data exchange, the three 500-kV line outages experienced 

by BPA during the hour and a half prior to the disturbance were not reported to 

other WSCC members, precluding their ability to take mitigating actions had they 

perceived a need for such action. 

Excerpt from the WSCC Procedure for Coordination of Scheduled Outages and 

Notification of Forced Outages: 

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"A. Each WSCC Member System which owns or operates a key 

generation or transmission element scheduled to be removed from 

service or which has been forced out of service is responsible for 

notifying the other WSCC members via the WSCC Communication 

System of the facility outage. Key facilities are those which are 

considered important to interconnected system operation by the 

system which owns the facilities. Key facilities generally include: 

3. Transmission operated at 230-kV and higher that can 

significantly affect interarea system operation ... " 

Up to this time, BPA had not considered the named lines as key facilities for 

reporting. 

Recommendation: 

a. CMOPS shall review WSCC's policies, procedures, and criteria for reporting 

key facility outages (considering that lightly loaded lines are an important 

source of V ARs and provide system supPort during disturbances) and 

implement improvements and eliminate ambiguity in reporting requirements. 

This review shall include lower voltage lines similar to those out of service 

on the BPA system prior to the August 10 disrurbance and should address 

key generating facilities as well. (December 1996) 

b. BPA shall review its criteria for designating key facility outages for reporting 

and indicate why the lines were not designated as "key" facilities and why 

the outages prior to the disturbance were not widely reported to other WSCC 

members. (December 1996) 

c. BPA shall ensure its system operators are trained to recognize and report 

critical and abnormal system conditions and key facility outages to WSCC, 

and shall develop appropriate tools, such as on-line power flow, to aid in 

these assessments. (December 1996) 

9. Conclusion: On August 10, the Big Eddy-Ostrander; John Day-Marion 500-kV, 

Keeler-Allston 500-kV, and Ross-Lexington 230-kV lines were faulted due to 

conductors flashing over to trees in the right-of-way. All of these outages are the 

result of inadequate right-of-way (ROW) maintenance by BPA. During the 

period from June 1 to August 9, a total of five 500-kV line outages (two of these 

were the same problem on the same line within 40 minutes), and two -115-kV 

line outages (both momentary outages on the same line within two days of each 

other) on the BPA system were caused by flashovers to trees. BPA has 4,447 

miles of 500-kV, 5,233 miles of 230-kV, and 3,676 miles of 1 15-kV lines. 

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Recommendation: 

a. BPA shall submit a copy of its tree-trimming and line-patrolling procedures 

as of August 10 to CMOPS, identifying what parts of the procedure had not 

been complied with (if any) as of August 10, including reasons for any 

noncompliance. Dollar amounts budgeted and actual expenditures for tree 

trimming for 1993 through 1996 shall also be provided. (September 1996) 

b. BPA shall determine why the trees that resulted in the flashovers on the lines 

involved were not identified and removed or cut to design clearances prior to 

the incident on August 10 and report to WSCC. (September 1996) 

c. BP A shall determine why identified danger trees were not removed and shall 

reevaluate procedures, environmental impacts, and legal requirements for 

removing danger trees affecting fJre safety and reliability. (December 1996) 

d. BPA shall report to WSCC what actions have been taken since August 10 to 

improve its tree-trimming procedures and describe any ongoing efforts to 

improve their effectiveness. (September 1996) 

e. All transmission-owning member systems shall review their tree-trimming 

programs to ensure that they are adequate and shall provide information to 

WSCC that indicates any changes (including budgeted monies) made to the 

programs over the past two years and/or that are intended to be made in the 

near future. (September 1996) 

f. All transmission owning members shall evaluate the need for changes in the 

tree- trimming policies of the U.S. Forest Service and other federal land 

agencies and submit recommended enhancements to WSCC. Canadian and 

Mexican members shall evaluate the need for change in their respective 

jurisdictions. (December 1996) 

10. Conclusion: The system oscillations increased until voltage fmally collapsed on 

the COl, leading to the COl opening and the subsequent formation of four 

islands in the WSCC. Generating units in the Northwest (such as Hermiston, and 

Coyote Springs ) did not respond dynamically or in the steady state with reactive 

support as predicted in studies. The level of dynamic reactive support from 

generation at the northern terminus of the COl and PDCI has been greatly 

reduced by fish operation constraints, particularly at The Dalles. 

Recommendation: 

a By November 1997, the WSCC CWG shall determine what tests should be 

applied to genera{ing units to determine their steady state and dynamic 

reactive capabilities and provide appropriate guidelines. They shall also 

determine what unit MV A level must be tested and develop a procedure to 

ensure uniform testing, including the frequency of testing, and a 

recommended priority list of units to be tested first. (The CWG work must 

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be completed by November I, 1996.) Generation-owning and operating 

entities in WSCC shall test, or provide proof of tests on, their generating 

units with capacity of ten MW or greater to determine their steady state and 

dynamic reactive capabilities. adjust study assumptions to match the test 

results, and report to CMOPS. (June 1997) 

b. BPA shall take into account fish spill requirements at The Dalles, John Day, 

McNary, and other Northwest hydro generation plants when determining 

transmission capabilities. BPA shall report to CMOPS how this will be 

accomplished. Special attention shall be given to the loss of dynamic 

reactive reserves from these plants. (December 1996) 

c. BPA shall report to CMOPS regarding actions taken to ensure that 

instructions to system operators relating to the reactive requirements of the 

system under various contingency conditions are adequate. The.se instructions 

shall include actions required to mitigate the loss of reactive margin, such as 

bringing generating units on line, switching shunt devices, reducing schedules 

and line loadings, and manually shedding load. (December 1996) 

d. The WSCC PCC/OC Joint Guidance Committee shall review the 

n:commendations made in the NERC publication entitled "Survc:y of the 

Voltage Collapse Phenomenon" and make appropriate assignments to review 

the recommendations and ensure that they have been appropriately 

implemented within the Western Interconnection. (June 1997) 

e. The WSCC PCC shall develop reliability criteria for reactive reserves and 

reactive margin. (December 1996) 

f. Generation-owning and operating entities in WSCC shall ensure that 

generating units will .provide proper steady state and dynamic voltage 

support, through actions such as keeping voltage regulators on automatic 

voltage control. The MORC Work Group shall develop suitabl!: 

modifications to the criteria, including criteria relating to constant power 

factor control. Results shall be reported to CMOPS. (June 1997) 

g. BPA and all other control areas shall perform reactive margin studies for 

worst case scenarios and report study results to the WSCC OC. (June 1997) 

h. PGE, PAC, and USCE, in conjunction with the WSCC ISG shall determine 

and report to CMOPS the extent to which Coyote Springs and Hermiston 

generation were or were not providing effective voltage control and reactive 

support in the McNary area during this disturbance and make 

recommendations as appropriate to enhance system performance. (December 

1996) 

i. The WSCC ISG shall determine whether circuit outages in the Portland area 

impacted the simultaneous transfer capability of the COl and other paths to 

the Northwest. (December 1996) 

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j. BPA. USPN and USCE shall detennine and report to CMOPS how plant 

reactive power may be increased by considering options such as operating 

units in condensing mode or with more units on line for a given power level 

(reduced efficiency), or other alternatives. (December 1996) 

k. The WSCC TSS shall respond to regulatory questions about the use of 

flexible AC transmission system (FACTS) devices and other voltage support 

devices to enhance system performance and make recommendations to the 

PCC. (June 1997) 

I. The WSCC ISG shall develop nomograms for Northwest Intertie operations, 

including the COl, PDCI, BCHA, Idaho, Montana, and other transfer paths, 

that will ensure reliable operation. Such nomograms shall consider the 

generation availability and load level of the Northwest. BPA shall provide 

information to WSCC illustrating actual flows relative to the nomograms on a 

daily basis until such reporting is no longer deemed necessary. (December 

1996) 

m. The WSCC member systems shall evaluate the need for and report to WSCC 

regarding the application of undervoltage load shedding on their individual 

systems to enhance interconnected system reliability. (March 1997) 

11. Conclusion: Boardman coal plant responded dynamically to the loss of the 

Keeler-Allston 500-kV line, increasing its reactive output to 157 MY AR at Slatt, 

but backed down to 78 MY AR, by operator intervention, after approximately 30 

seconds. 

Recommendation: PGE shall determine whether the response of Boardman to 

this disturbance was proper. (November 1996) 

12. Conclusion: Special operations to protect fish (such as reducing generation and 

increasing spill at The Dalles) reduced the amount of real power, reactive power, 

and inertial support provided to the system, and therefore adversely impacted 

system reliability. 

Recommendation: The WSCC ISG shall model these special fish-protecting 

operations in the studies they are conducting to detennine the impact on COl 

transfer capability, paying particular attention to the loss of reactive power 

support due to these operations. The WSCC ISG shall report its fmdings and 

recommendations to CMOPS. (April 1997) 

13. Conclusion: On August 10, temperatures were high throughout much of the 

WSCC region. As a result, loads in some areas were very high for a Saturday, 

including air conditioning induction motor loads. These load characteristics may 

have had a significant effect on the nature and severity of the disturbance. 

Recommendation: The WSCC ISG shall determine and report to WSCC 

regarding the impact of load levels and load characteristics on this disturbance 

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and make appropriate recommendations to enhance study capabilities, improve 

system models, and improve system performance. (June 1997) 

14. Conclusion: Upon opening of the COl, the Northern California and Southern 

Islands lost nearly 28,000 MW of load and approximately 20,000 MW of 

generation. A similar separation occurred on the COl on July 2, 1996. In a 

generation deficient condition, the intended outcome is for only load to trip. 

Unlike the July 2 disturbance, in this instance, system performance in the 

Northern California and Southern Islands was adversely affected by the 

uncontrolled tripping of a substantial amount of generation. 

Recommendation: 

a. Generation owning entities that lost generation in the low frequency islands 

shall report to the Relay Work Group the reasons for units tripping and any 

corrective actions taken since August 10. (October 1996) 

b. The WSCC Relay and Control Work Groups shall determine why actions 

taken in response to the December 14, 1994, system disturbance were not 

effective in preventing the uncontrolled loss of generation on August 10 and 

recommend corrective actions. (March 1997) 

c. The WSCC CMOPS shall determine why the frequency could not be restored 

without manual load shedding after extensive underfrequency load shedding 

and make appropriate recommendations. (March 1997) 

d. All WSCC members, or groups of members, experiencing low frequency in 

this disturbance shall analyze whether operation of underfrequency load 

shedding systems was proper and appropriately coordinated among entities 

within each island. Deficiencies shall be reported to WSCC and corrective 

measures implemented. (December 1996) 

Status: Three of the six load banks ( with a load of 154 MW at the time of 

the disturbance) in LDWP's 58.5 Hz underfrequency load shedding block 

failed to trip. An underfrequency relay on one of the banks was found to be 

defective and replaced. The relays on the other two banks were tested and 

found to be set within tolerance (58.49 Hz) and operating properly. These 

relays apparently did not trip because the frequency was not low enough for 

long enough to activate them. 

e. The WSCC OC shall initiate a study to review the coordinated 

underfrequency load shedding programs on a subregional and regional scale. 

The coordination of underfrequency load shedding with underfrequency 

generator protection shall be included in the study. Recommendations shall 

be developed and implemented. (June 1997) 

15. Conclusion: Colstrip Units I, 3, and 4 tripped by Acceleration Trend Relay 

action during the disturbance. 

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Recommendation: MPC shall determine and report to CMOPS whether Colstrip 

tripping was appropriate and take corrective action if needed. (December 1996) 

16. Conclusion: At the time of the August 10 disturbance, the Northeast/Southeast 

Separation Scheme was out of service in accordance with the WSCC Committed 

Action Plan Agreement. The power system separated on out-of-step across the 

NFJSE boundary 1-2 seconds after it would have separated had the scheme been 

in service. It is possible that the faster, more coordinated separation provided by 

the scheme could have lessened the impact of this disturbance in the Southern 

Island. 

Recommendation: The WSCC ad hoc Controlled Islanding Work Group shall 

study the impact on this disturbance of not having the NE/SE Separation Scheme 

in service and make appropriate recommendations. This study shall also consider 

direct load tripping in the southern island and the northern California island as 

remedial action for loss of the COl and the negative impact of a false operation 

of the NE/SE Separation Scheme. (June 1997) 

17. Conclusion: The NE'JSE Separation Scheme was placed in service at 0101 PAST 

on August 11, 1996, after some discussion among the major participants in the 

scheme. This scheme had been out of service since the completion of the 

California-Oregon Transmission Project (COTP) except under certain loading 

conditions and when the COTP is out of service. Notification was posted by 

APS on the WSCC Communication System. However, SPP was not informed by 

PG&E of the change in accordance with procedures and did not enable its part of 

the scheme until about three days later. 

Recommendation: 

a. The WSCC OC shall review the procedure for notification of status changes 

for this scheme and make appropriate changes. Operating and planning 

engineers shall also be notified to ensure that future changes in status of the 

scheme are properly coordinated. (March 1997) 

b. The WSCC OC shall evaluate a means to include feedback in the notification 

process to ensure notifications have been received and read. (March 1997) 

c. PG&E shall review and report to CMOPS regarding procedures to ensure 

appropriate communication of changes in status of the NE'JSE Separation 

Scheme. (October 1996) 

d. SPP shall report to CMOPS why it did not act upon the WSCC message 

informing members of the NE'JSE Separation Scheme activation. 

e. The PCC/OC Joint Guidance Committee shall determine whether it is prudent 

to continue with the NFJSE Separation Scheme in service and make 

appropriate recommendations. (November I, 1996) 

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18. Conclusion: Multiple transmission paths opened by out-of-step relay action, 

separating the main WSCC loop into four electrical islands. 

Recommendation: The WSCC ad hoc Islanding Work Group shall investigate 

and report to CMOPS the contributing causes of the separations and recommend 

appropriate actions to enhance system performance. (March 1997) 

19. Conclusion: Governor response to high frequency resulted in increased flows 

into Alberta from British Columbia. Five minutes into the disturbance, the 

increased flow caused low voltage and high current which resulted in the tripping 

of the interconnection between BCHA and TAUC. 

Recommendation: 

a. BCHA and T AUC shall evaluate why the tie tripped, take appropriate action 

and report to CMOPS. (October 1996) 

b. TAUC and BCHA shall determine and report to CMOPS whether governor 

response was appropriate and implement any necessary corrective measures. 

(October 1996) 

20. Conclusion: The frequency stayed high in the Northern Island (about 60.4 Hz for 

fourteen minutes, crossing 60 Hz after seventeen minutes). After returning to 60 

Hz, the frequency rose again to 60.04 Hz and remained there for 50 minutes. 

Despite having no direct schedules to California, BCHA unilaterally cut 

schedules by approximately 600 MW to reduce island frequency, absorbing 2,200 

MWH of inadvertent interchange over the next three hours. 

Recommendation: 

a. The WSCC CMOPS shall determine why frequency did not return to normal 

in a timely manner and recommend corrective action. (December 1996) 

b. BPA, PAC, BCHA, PSPL, PGE, and other Northwest island parties shall 

evaluate and report to CMOPS the role scheduling played in keeping the 

frequency high. The parties shall determine what schedules, if any, were not 

cut that should have been. (December 1996) 

c. The WSCC SPWG shall review and report the process for rapid changes of 

schedules on the COl and PDCI. They shall determine the required time for 

operator initiated emergency schedule changes and the effectiveness (system 

response in time, MW, and frequency) of those changes. (December 1996) 

21. Conclusion: 

Southern Island frequency was below .59.0 Hz for twenty minutes and below 60 

Hz for over an hour. 

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Northern California Island frequency hovered around 59.5 Hz for 75 minutes. 

Automatic load restoration impeded frequency restoration in the Northern 

California Island. Low frequency in the Southern and Northern California Islands 

impeded the restoration process by preventing synchronization of any two 

islands. 

Recommendation: 

a. All member systems shall review and report to CMOPS regarding the 

problems associated with coordination of automatic and manual load 

restoration and take appropriate action. (March 1997) 

b. CMOPS and the WSCC SPTF shall review the role and authority of the 

WSCC Coordinating Centers in facilitating load restoration and develop 

recommendations as appropriate for improved performance. (December 

1996) 

c. Each island's utilities shall determine and report to CMOPS regarding any 

other factors that delayed the recovery of frequency and recommend 

corrective measures. (December 1996) 

22. Conclusion: Protective relays on critical lines appeared to have operated properly 

with the exception of the Merwin-St. Joluts 115-kV line, which was tripped by a 

malfunctioning zone I KD relay. 

Recommendation: PAC shall investigate this relay misoperation, take corrective 

action and report to CMOPS. (November 1996) 

23. Conclusion: The Keeler SVC tripped 1.5 seconds after the COl separation by 

undervoltage relaying. LDWP similarly lost PDCI Converters I and 2 at Sylmar 

when their cooling systems tripped after the Sylmar voltage dropped to 0.68 pu. 

LDWP also lost SVCs at Adelanto and Marketplace because of low voltage. 

Recommendation: 

a. BPA shall investigate and correct the problem that tripped the Keeler SVC 

and shall report its fmdings and actions to CMOPS. (March 1997) 

b. LDWP shall investigate and correct the problems causing the loss of the 

Sylmar DC auxiliary systems and system SVCs and report its findings to 

CMOPS. (March 1997) 

c. Under the direction of CMOPS, all WSCC members shall review their own 

SVCs and any other critical, voltage-sensitive power system equipment to 

determine if they may have similar problems and implement corrections as 

required. (March 1997) 

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24. Conclusion: The PDCI power levels fluctuated substantially in response to 

changing AC voltage. 

Recommendations: 

a. BPA and LDWP shall determine and report to CMOPS as to whether the 

HVDC response, including the actions of protection systems that reduced the 

DC capacity, was appropriate ami/or contributed to the severity of the 

disturbance and shall talce action as appropriate. (December 1996) 

b. The WSCC ISG shall review and report to CMOPS as to whether the PDCI 

response during the oscillations was a contributing source of negative 

damping and reduced synchronizing power and malce appropriate 

recommendations. (December 1996) 

25. Conclusion: LDWP manually blocked the PDCI due to the uncontrolled loss of 

equipment and an excessive (I ,000 MV AR) converter reactive power draw from 

the AC system at Sylmar. This ma.y have contributed to manual load shedding in 

the Southern Island. 

Recommendation: LDWP shall assess and report to CMOPS the appropriateness 

of interrupting imports through the PDCI while in a low frequency island and 

correct procedures if necessary. (October 1996) 

Status: The LDWP senior load dispatcher was fully aware of the implications of 

blocking a source of import power into a low frequency island when he made the 

decision to do so. The LDWP dispatcher decided to block the PDCI because he 

believed the excessive reactive power demand at Sylmar, coupled with the 

uncontrolled loss of PDCI equipment over the previous ten minutes (and the 

perceived threat of additional uncontrolled loss of equipment) was a greater 

threat to the security of the island than was the loss of the power being 

imported. 

26. Conclusion: WAPA lost the two Glen Canyon-Flagstaff-Pinnacle Peale 345-kV 

lines when the Pinnacle Peak 345/230-kV transformers opened due to 

overexcitation. The Glen Canyon end of the lines subsequently opened due to 

high voltage resulting from the line charging of the open-ended lines. The 

transformer overexitation condition lasted for nearly two hours, resulting in the 

unavailability of Glen Canyon generation, though it was critically needed as a 

resource during recovery from the disturbance. 

Recommendation: 

a. W APA shall test the transformer overexcitation relays, review relay settings, 

implement appropriate corrective measures and report to CMOPS. (October 

1996) 

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b. W APA shall investigate and repon to CMOPS regarding the cause of the 

lines that tripped, isolating the Glen Canyon plant from the power system, 

and implement appropriate corrective measures. (October 1996) 

27. Conclusion: The first COl line was restored at 1818 PAST, but schedules on this 

path were not resumed until the hour ending 2100 PAST. The delay hampered 

load restoration effons in the Nonhero California Island. (Remaining 

interconnections were also restored in this period.) 

Recommendation: PG&E and BPA shall determine and repon to CMOPS the 

cause of the delay in resuming scheduling and take appropriate action. (October 

1996) 

28. Conclusion: Several control centers including APS, W AMP, TEP, TNP, and SRP 

lost their Energy Management Systems (EMS) during the disturbance. The 

Uninterruptible Power Supply (UPS) at APS failed and the EMS was down for 

just over an hour. TNP lost its EMS computer, apparently due to alarm 

management problems. SRP lost its EMS three times during the disturbance. 

W AMP lost its EMS due to failure of its backup power supply system. It also 

lost communications, and PG&E was unable to contact W AMP to request 

additional generation. USPN lost its SCADA system at Grand Coulee, 

hampering effons to control local circuit breakers and other critical facilities. 

Additionally, PAC lost its Portland EMS due to UPS failure, but continued 

operations through its back up control center. 

Recommendation: The WSCC EMS Work Group and utilities that experienced 

trouble with their control centers shall determine and report to CMOPS the 

causes of these failures and take appropriate corrective action. (December 1996) 

29. Conclusion: Within 30 minutes after the disturbance began, the WSCC office 

was receiving calls from news media reponers demanding information about the 

disturbance. The WSCC Staff was unable to provide answers, not having been 

notified that a disturbance was in progress. Dispatchers were receiving calls 

directly from the news media, distracting them from system operations. The 

media representatives had reponedly received the dispatchers' phone numbers 

from the utility's security personnel and/or from other utilities. A significant 

problem during emergencies is phone calls unrelated to determining the problem 

and restoring the system. 

Recommendation: 

a. The four Coordinating Centers shall develop procedures to notify WSCC staff 

no more than ten minutes after a major disturbance is confirmed and provide 

known information. (October 1996) 

b. WSCC members shall develop and implement procedures for reponing 

system disturbance information on the WSCC Communication System within 

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thirty minutes to allow all parties to assess conditions and develop an optimal 

response to the disturbance. (October 1996) 

c. All member systems shall have policies in place to ensure dispatch phone 

numbers are not revealed to the: public or news media without prior 

permission of the utility. (October 1996) 

d. CMOPS shall develop a requirc:ment within MORC specifying the minimum 

technical and executive resources which will be available 24 hours per day 

for system emergencies. (December 1996) 

e. All WSCC members shall provide their operating management's (up to 

Council Representatives) cellular phone numbers and home phone numbers to 

the WSCC staff for use in coordinating the collection and dissemination of 

information regarding large scale system disturbances in the WSCC region. 

In addition, the WSCC staff shall compile a list of control center phone 

numbers. (October 1996) 

f. The WSCC staff shall implement procedures to issue its initial press release 

to the members within thirty minutes of notification and to the media within 

one hour of notification of a large scale system disturbance in the WSCC 

region. (October 1996) 

g. The WSCC staff shall have at least one cellular phone and a pager to be 

monitored continuously for use in coordinating the reporting of information 

regarding major system disturbances in the WSCC region. (October 1996) 

h. The WSCC staff shall develop contingency plans for coordircating disturbance 

reporting information in the event the WSCC office is impacted by a 

disturbance. (June 1997) 

30. Conclusion: Analysis of this disturbance was impeded by the lack of dynamic 

information at key points on the system, such as on the Midway-Vincent tie, 

west of Borah, the NEJSE cut plane, and other lines most likely to be involved in 

islanding or voltage collapse. 

Recommendation: The WSCC SPTF shall review the need for improved 

dynamic monitoring at key points and critical potential separation points in the 

system and shall make recommendations, including the time frame for 

implementation. Dynamic records shall be time tagged and include both preand/post-disturbance data. Key data shall be monitored to improve system 

security. (June 1997) 

31 . Conclusion: In response to this disturbance, utilities' energy traders, generation 

operators, and transmission operators found it necessary to coordinate closely to 

restore the system. As members restructure to comply with FERC Order 889, 

such close coordination may be limited. 

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Recommendation: The WSCC OC shall assess the potential impact of FERC 

Order 889, Standards of Conduct, on coordination between generation 

marketers/owners and transmission operators during disturbances and make 

appropriate recommendations to improve the coordination of system restoration. 

(March 1997) 

32. Conclusion: The July 2 and August 10 disturbances emphasize the need for 

timeliness in the disturbance report recommendation resolution process. 

Examples of recommendations made as a result of previous disturbances that 

continue to be factors in more recent disturbances include the recommendations 

relating to controlled islanding, criteria for multiple contingencies, criteria for 

relay failures, and coordination of underfrequency load shedding. 

Recommendation: The WSCC Board of Trustees shall implement policies as 

needed to ensure that critical disturbance report recommendations are completed 

expeditiously. This includes ensuring adequate manpower and capital resources 

are available to implement these recommendations. (January 1997) 

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III. PREDISTURBANCE CONDITIONS 

Most utilities had high Saturday loads as a result of hot summer temperatures in most 

of the western states prior to the disturbance. Flows on significant paths are listed in 

the following table. 

Path Rating Flows 

Canadian Intertie between BCHA and 2,300 2,300 MW North to South 

BPA 

California-Oregon Intertie *4,800 4,350 MW North to South 

Midpoint--Summer Lake 1,500 600 MW East to West 

Pacific DC Intertie (at converter 2,850 MW North to South 

station) 3,100 

Midway-Vincent 3,000 1,380 MW North to South 

East of Colorado River Path 7,365 3,225 MW East to West 

Northeast/Southeast Path 1,700 1,058 MW North to South 

Schedulin g lilillt was 4/4U MW oue to the o p eraun g nomo gr am p re p ared alter the 

July 2 disturbance. 

Transmission lines out of service: 

I. The Big Eddy-Ostrander 500-kV line lripped at 1406 PAST. 

2 At 1452, the John Day-Marion 500-kV line tripped. Both the Big Eddy· 

Ostrander and John Day-Marion outages were caused by the lines flashing over 

to trees. 

3. The John Day-Marion outage also forced out the Marion-Lane line due to system 

configuration (circuit breaker 4365 out of service). 

Prior to these outages, the lines noted above were lightly loaded. The Big EddyOstrander 500-kV line directly serves the Portland area. The John Day-Marion 500-

kV line supports the PortJand area from the south via the Marion-Pearl 500-kV line. 

In addition to these outages, the Keeler 500/230-kV transfonner was out of service for 

tap changer modifications and breaker replacement at Keeler. As a result, the Keeler 

+1-300 MV AR Static VAR Controller (SVC) was limited in its ability to support the 

500-kV system. 

In the WiUamette Valley region, BPA had two 500-kV circuit breakers out of service 

for replacement: CB 4365 at Marion and CB 4322 at Keeler. The Allston terminal of 

the 115-kV St. Helens-Allston line was open due to the degraded thennal capability of 

this 115-kV line. Its use has been limited to radial operation. Generation at The 

Dalles was at reduced levels due to a 64 percent spill requirement for tish measures. 

Prior to the disturbance, no voltages or line loadings were in violation of established 

limits. 

27 

Percent 

of rating 

100 

91 

40 

92 

46 

44 

62 
109 

IV. DETAILED DESCRIPTION 

DESCRIYfiON OF DISTURBANCE 

At 1548 PAST on August 10, 1996, a major disturbance hit tbe Western 

Interconnection, forming four islands. Conditions prior to the disturbance were marked 

by high summer temperatures (near or above 100 degrees) in most of tbe region, by 

heavy exports (well witbin known limits) from the Pacific Northwest into California 

and from Canada into tbe Pacific Northwest, and by the loss of several 500-kV lines 

in Oregon. 

The COl North-to-South power flow was within parameters established by recent 

studies initiated as a result of the July 2 disturbance. The flow on the COl totaled 

approximately 4,350 MW; tbe power order on the PDCI was 2,848 MW. 

EARLIER LINE OPERATIONS 

At 1401 PAST, the Big Eddy-Ostrander 500-kV line relayed three-pole when it flashed 

to a tree. The PGE terminal of the Big Eddy-McLoughlin 230-kV line relayed and 

reclosed for this fault close to the Ostrander end. The Big Eddy-Ostrander line tested 

good and was returned to service at 1403. At 1406, the Big Eddy-Ostrander line 

relayed single-pole (A-phase), reclosed, tripped three-pole, and stayed out of service. 

PGE's terminal of the Big Eddy-McLoughlin 230-kV again relayed and reclosed. The 

500-kV line had flows of 90 MW with 130 MV ARs into the Big Eddy bus and 86 

MVAR into the Ostrander bus. Around 1410, BPA SCADA logged low voltage 

alarms from Alvey (236-kV), Slatt (529-kV), Big Eddy (236-kV), and Vantage (239-

kV). This low voltage was corrected by shunt reactor switching at the Grizzly 500-kV 

bus and by shunt capacitor switching at tbe Alvey 230-kV busses. At 1446, the 

Vantage 500/230-kV transformers were lowered one tap, bringing the Vantage bus 

voltage to 240-kV. 

At 1452:37, the John Day-Marion 500-kV line relayed, reclosed, and tripped to 

lockout for a C-phase fault when it flashed over to a tree near Marion (tower 122/1). 

Due to Marion power circuit breaker (PCB) 4365 being out of service, this line outage 

also forced out the Marion-Lane 500-kV line. The John Day-Marion line tested bad at 

1456. When it tripped, the John Day-Marion line was carrying 248 MW to Marion 

with 207 MV AR into the John Day bus and 35 MV AR into the Marion bus. The 

Marion-Lane line was carrying 330 MW and 105 MV AR. Following the loss of tbese 

lines, tbe Big Eddy bus alarmed at 235 kV and Slatt at 529 kV. Voltage control 

switching involved transformer tap changes at Allston and Big Eddy and the 500-kV 

shunt capacitors at Ostrander. At 1517, S1att alarmed for below voltage schedule at 

529 kV, as did Hanford at 525 kV. 

28 
110 

INITIATING EVENTS 

At 1542:37, fifty minutes after the John Day-Marion line fault, the Keeler-Allston 500-

kV line, carrying 1,300 MW toward Keeler and 110 MV AR into Allston, tripped after 

flashing to a tree near Keeler. At the time, the current flow was 1 ,406 amps. The 

summer rating of this line is 2,900 amps. This also forced the Pearl-Keeler line out of 

service due to the Keeler 500/230-kV transformer being out of service. At this point, 

there were five 500-kV line segments out of service, removing several hundred MV AR 

of reactive support from the system and increasing the reactive requirement as other 

lines picked up the power flow from the lost lines. BPA SCADA systems received 

many voltage alarms in the mid-Columbia basin. McNary 500-kV bus, at 519 kV, 

dropped to 506 kV. The 230-kV bus alarmed at 237 kV (alarm set for 238 kV). 

Vantage was at 520 kV and the COl was 533-kV at Grizzly and Malin. Twenty and 

thirty seconds later, the Ross-Lexington 230-kV line alarmed at I ,235 amps (I ,050 

amp rating) and the Allston-Trojan line alarmed at I ,400 amps (I ,315-amp emergency 

rating). BPA dispatchers requested maximum reactive power boost from John Day 

and The Dalles within one minute of the Keeler-Allston trip. Loading on the PGE 

Trojan-St. Marys and Trojan-Rivergate 230-kV lines increased from approximately 325 

MW each (780 A) to 560 MW each (1,400 A, 106 percent of the PGE 1,315 A 

emergency rating). Loading on BPA's Ross-Lexington 230-kV line increased from 

approximately 330 MW (790 A) to 487 MW (1,237 A, 115 percent of its 1,070 A 

rating). Prior to the Keeler-Allston trip, the thirteen McNary generating units were 

producing 860 MW and 260 MV AR. 

While the BPA system voltage situation was being assessed (BPA dispatchers were 

considering the possibility of COl schedule reductions), the Keeler-Allston line was 

tested from Allston and found bad at 1544 PAST. BPA dispatchers then called 

Washington Nuclear Power (WNP) Unit 2 (and other plants), requesting maximum 

reactive boost. Boardman coal plant responded dynamically to the loss of the KeelerAllston 500-kV line, increasing its reactive output to 157 MV AR at Slatt, but backed 

down to 78 MV AR, by operator intervention, after approximately 30 seconds. At 

1545 PAST, PGE reported to BPA overloads in the Rivergate area. 

At 1545, BPA SCADA recorded the McNary 230-kV bus as receiving 347 MV AR 

from McNary and Hermiston was receiving six MV AR from the transmission system. 

Coyote Springs was taking seven MV AR from the McNary-Slatt 500-kV line. WNP 

Unit 2 was supplying 200 MV AR to the Ashe 500-kV bus. The John Day substation 

was receiving 408 MVAR from the John Day powerhouse. Big Eddy was receiving 

77 MV AR total from The Dalles. The McNary generating units had boosted their 

reactive output from 260 MVAR to 475 MV AR (which was over their maximum 

sustained MV AR output for that power level) immediately following the KeelerAllston trip. 

At 1547:29, approximately five minutes aftt:r the 500-kV line trip, the PacifiCorp 

Merwin-St. Johns 115-kV line tripped due to a zone I KD relay malfunction. (The 

time stamp noted is from PAC's Portland Area Dispatch SCADA system. This system 

is not satellite synchronized, therefore, the exact time of the line trip and its place in 

the sequence of events are not known.) The line had been carrying 86 MW toward St. 

' 29 
111 

Johns prior to the disturbance. Merwin and Yale generation was 82 MW, and Swift 

generation was 207 MW. There were 12 MW flowing from Cardwell to Merwin. The 

generation connected to this line did not trip and remained connected to the Longview 

area. 

At 1547:36, the Ross-Lexington 230-kV line tripped after sagging too close to a tree 

and flashing over. This also forced the outage of PacifiCorp's generation at Swift 

(207 MW) connected to this line. The two Trojan 230-kV lines, now loaded to 150 

percent of their emergency ratings, were the only west side ties between Portland and 

the 500-kV system to the north. There was also a 115-kV line from the north to 

Astoria, down the coast, that does connect back to the Willamene Valley. 

The McNary units boosted their reactive output to 480 MV AR, then to 494 MV AR. 

They held this level for a short time, then began tripping. Two units tripped at 

1547:40, followed by four more units four seconds later dropping the frequency to 

59.9 Hz. At 1547:49, another unit tripped, followed eight seconds later by another 

unit, and another unit fifteen seconds after that. At 1548:47, two units tripped and, at 

1549, the last two units tripped. The McNary unit trips the result of erroneous 

operations of a phase unbalance relay in the generator exciters. Relay replacement is 

in progress. Following the loss of the McNary units, the Boardman Plant was 

supplying 275 MV AR to Sian in response to collapsing voltage while in constant 

excitation mode. 

POWER OSCILLATIONS BEGIN 

Following the generation loss at McNary, the power system began experiencing a mild 

oscillation. Grand Coulee, Chief Joseph and John Day began picking up the lost 

generation. When McNary generation had dropped to approximately 350 MW, the 

oscillation became negatively damped. Forty-five seconds after the Ross-Lexington 

line trip, the Malin 500-kV Shunt Capacitor Group 3 was automatically switched in. 

This raised the voltage, but the 0.224 Hz system oscillations continued to increase. 

Five seconds later, BPA's Eastern Control Center (ECC) SCADA operator switched in 

a 115-kV shunt capacitor group at Walla Walla. SCADA at BPA's Dittmer control 

center was receiving line load fluctuating alarms. 

The PDCI also began to fluctuate in response to the AC voltage. The PDCI power 

controller maintains the power level by adjusting current without exceeding a 3,100 

ampere DC line current limit. If the current reaches this limit, the power level 

necessarily reduces as the AC voltage declines. The PDCI response during the 

oscillation indicates that system inertia synchronizing power was reducing (decreasing 

DC power while the AC power was increasing). At 1548:51, when the AC system 

oscillations had increased to approximately 1,000 MW and 60 kV peak-to-peak at 

Malin, the voltage collapsed. At this point, the PDCI power level changed enough to 

initiate the DC Remedial Action Scheme (RAS) level 1 ten-second sliding window 

algorithm. This RAS action closed Shunt Capacitor Group 4 at Malin and inserted the 

Fort Rock series capacitors on all three 500-kV lines south of Grizzly. At the same 

time, the Buckley-Grizzly line opened at Buckley via zone 1 relay action. 

30 
112 

Within the next two to three seconds, the ties between northern California and 

neighboring systems, and between Arizona/New Mexico/Nevada and Utah/Colorado 

opened due to out-of- step and low voltage conditions. 

OBSERVA TIONSIINTERTIE INSTABILITY 

The loss of the Keeler-Allston 500-kV line at 1542:37 overloaded the 230-kV lines 

into the Portland area and led to the loss of the Ross-Lexington 230-kV line at 

1548:36. Power shifting east of the Cascades led to additional reactive demands in the 

McNary area and consequent tripping of all thirteen units at McNary. Finally, 

growing oscillations reached a level that tripped all three lines of the COl in just over 

one minute. 

Factors which may have contributed to the severity of the disturbance include: 

Reduced reactive margin at McNruy and other power plants is not alarmed to 

the BPA dispatcher. Additionally, low side reactive power output is not 

available on control center monitors. Either of these items would have 

indicated a problem before loss of the Keeler-Allston line. 

Protective systems at McNary are designed to transfer regulator control from 

dynamic automatic mode to manual mode after boosting above the maximum 

excitation limit for a specific length of time. The unit is supposed to stay 

connected to the line after this operation but erroneous protective relay 

actions tripped the units off line. 

Other units in the McNary area were operating on constant power factor 

control rather than voltage control, preventing these units from providing 

needed reactive support (Coyote Springs and Hermiston Generation). 

Reactive power limits used on USCE generators are more restrictive than 

those used in planning and operating simulation studies. 

Some power system stabilizers (to damp system oscillations) were not 

operational at The Dalles (five units on line, three without PSS) and John 

Day (13 of 16 units on line, four without PSS) due to plant control problems. 

The present PDCI response to system swings at high current output and low 

AC source voltages. 

The Dalles generation was at a low level (300-400 MW, five of 22 units on 

line) due to spill requirements for fish migration. 

AGC systems responded to the loss of McNary generation by picking up 

most of the generation at plants farther north. This effectively increased the 

length of transmission circuits between Northwest generation and Southwest 

loads. 

31 
113 

This disturbance has indicated the need to identify strategies that will protect against 

COl instability for the more severe, unforeseen events such as loss of transmission 

into the Portland area. It also highlights the need for continued vigilance to ensure that 

all equipment can be operated to its full rating or to the fullest extent possible and that 

planning and operational simulation studies correctly represent system limitations. 

CALIFORNIA-OREGON INTER TIE SEPARATION 

One-and-a-half cycles after the Buckley-Grizzly trip, the Malin voltage had reached 

315 kV, and the Malin-Round Mountain No. 2 and No. 1 500-kV lines were tripped 

by the traveling wave relay switch-into-fault logic at 1548:52.632. (This 

underreaching-impedance type logic is supervised by a specified low voltage level that 

has been reached for a period of time and no traveling wave detection. These were the 

same relays that operated for the July 2 disturbance.) The Joss of the two Malin-Round 

Mountain lines caused the AC RAS to initiate brake insertion and Low generator 

dropping. One cycle later, the AC RAS High generator dropping algorithm operated. 

Shortly after Malin-Round Mountain lines tripped, the John Day-Grizzly No. 1 500-kV 

line tripped at John Day, the Chief Joseph dynamic brake inserted, and the John DayGrizzly No. 2 500-kV line tripped. Seventy milliseconds after the Malin-Round 

Mountain No. 2 line tripped, the Captain Jack-Meridian 500-kV line tripped. At the 

same time, voltage started to decay at the Vincent substation in southern California 

and units at Chief Joseph and Grand Coulee tripped via RAS action. Forty 

milliseconds later, the Grizzly-Malin No. 2 line opened at Grizzly, followed in 24 

milliseconds by the Grizzly-Captain Jack 500-kV line opening at Grizzly. Less than 20 

milliseconds after that, the Captain Jack-Olinda line opened at Captain Jack, 

completing separation of the California-Oregon lntertie (COl). The North island 

frequency rose to 60.9 Hz dropping to 60.4 Hz within two seconds where it remained 

for about fourteen minutes. The frequency crossed 60Hz three minutes later. 

PDCI RESPONSE 

During the disturbance, the PDCI experienced several power reductions. Prior to the 

disturbance, the power order at Celilo was 2,848 MW north to south with all valve 

groups and converters in operation. There were three power dips during the 

disturbance. The first power dip was at 1548:52 caused by an AC voltage reduction at 

Celilo. The DC voltage dropped from 500 kV to 315 kV in response to the fluctuating 

AC voltage. After the COl separated, the AC voltage returned to normal and the DC 

power recovered. 

The second power dip, at 1548:54, was caused by an AC voltage reduction at Sylmar 

resulting from the power swing following the opening of the CO I. Sylmar reports AC 

voltages as low as 0.65 pu. The DC voltage dropped as low as 286 kV during this 

period. There were also commutation failures at Sylmar during this time. The 

voltage-dependent current limit switched on for a short period to ramp the current 

orders in both poles to 550 amps. The DC power level reached zero for a short period 

then recovered when the Sylmar AC voltage increased. 

32 
114 

The third power dip on the DC occurred at 1548:58. It was also caused by AC 

voltage reduction at Sylmar. Sylmar Converters I and 2 blocked when the valve 

cooling systems tripped off due to the low AC voltage. Sylmar Valve Group 5 also 

blocked at this time, possibly due to loss of cooling flow in the test thyristor valve in 

that group. At 1549:01, Sylmar Valve Group 7 blocked. Celilo Valve Groups 5 and 7 

and Converter I blocked in order to match the pole 3 operating voltage allowed by the 

remaining Sylmar operating configuration. Following this, the DC power level slowly 

recovered (as the Sylmar AC voltage recovered) to about 1,534 MW. 

At 1605:12.4, Sylmar AC Filter Bank 4 relayed due to blown fuses probably caused 

by high harmonic current resulting from reduced voltage operation after the loss of the 

other valve groups. No action was taken to replace the lost reactive power from AC 

Filter Bank 4 because Sylmar's Reactive Power Controller had tripped off at 1548:54 

due to low voltage. At this point the PDCJ was drawing an estimated 1,000 MV AR 

from the 230-kV AC system at Sylmar. The LDWP senior load dispatcher, concerned 

about the excessive reactive power draw and the sequential uncontrolled loss of 

equipment over the previous ten minutes, ordered the PDCI to be manually ramped 

down and blocked. The PDCI ramp began at 1606:19 and the PDCI was blocked at 

1612. 

NORTHERN ISLAND DETAILS 

This island consisted of Oregon, Washington, Idaho, Montana, Wyoming, British 

Columbia, Utah, Colorado, Western South Dakota, Western Nebraska, and Northern 

Nevada. This island was formed following the separation of the COl and out-of-step 

tripping on the Northeast/Southeast boundary. 

Shortly after the Captain Jack-Oiinda line opened, the Malin south bus differentials 

operated to deenergize the PAC 500/230-kV transformer. The Grizzly-Summer Lake 

line (and Ponderosa tap) relayed. All remaining lines on the Oregon section of the 

COl were tripped between John Day and Malin. The loss of the 230-kV connection at 

Malin subsequently led to the loss of the BPA Malin-Warner 230-kV line as well as 

PAC connections between Meridian and Redmond. The Lapine-Chiloquin 230-kV, 

Lapine-Fort Rock 115-kV, Lapine-Midstate Electric 115-kV, Pilot Butte-Lapine 230-

kV, Redmond-PacifiCorp 115-kV (Prineville) and 230-kV (Pilot Butte) circuits tripped 

at 1550. 

At 1548, three Columbia Aluminum Company feeders at Harvalum tripped by 

undervoltage relay within the plant, and 279 MW of load was lost. Also at 1548, 

three Northwest Aluminum Company feeders were tripped at Harvey, again by 

undervoltage relay within the plant, interrupting 154 MW of load. All six feeders 

were restored at 1633. 

PAC lost about 450 MW of load, interrupting service to 154,000 customers in portions 

of southern and central Oregon, and northern California. Power was restored between 

1620 and 1701. 

33 
115 

MPC Colstrip Units 3 and 4 (750 MW each) tripped by ATR at 1548:53.622; Unit I 

(320 MW) tripped 27 ms later (also by ATR). IPC's CJ Strike Unit 3 (29 MW) 

tripped at 1549 due to exciter problems. Strike was restored at 1614. Colstrip Units 1 

and 3 were restored at 1656 and 1707. Unit 4 was restored at 04:29 on August 11. 

In BCHA's area, three Independent Power Producer (IPP) units were tripped on 

overfrequency at 1549. They were McMann Units 1 and 2 (90 MW) and NWE Unit 1 

(70 MW). At approximately the same time, a 500-kV cable circuit between the 

Malaspina and Dunsmuir substations tripped on overvoltage (trip setting of 571.5 kV 

with a 250-millisecond delay). 

BPA's SVC at Keeler tripped at 1548:58.251 when the cooling system tripped on 

undervoltage. The SVC controller was reset at 1549. The section lockout relays were 

reset at 1823 and disconnects closed at 1835. The Keeler SVC was back in service at 

1945. 

About one-and-a-half seconds after COl separation, the BCHA and MPC 

interconnections with BPA began large oscillations due to the NE/SE out-of-step 

separation. 

The BCHA-BPA tie flows ramped from 2,300 MW to zero (export small amount to 

Canada) two minutes after the disturbance. At 1554, a 100-MW flow increase into 

BCHA was observed. After 1554, BCHA began exporting about 1,000 MW to the 

Northwest, following the loss of the BCHA-Alberta tie which was carrying 1,230 MW 

into Alberta at the time. The frequency stayed high in the Northern Island (about 60.4 

Hz for 14 minutes, crossing 60Hz after 17 minutes, dipping as low as 59.95 Hz, then 

rising to 60.04 Hz for the next 50 minutes). Despite having no direct schedules to 

California, BCHA cut schedules by 600 MW to reduce island frequency. 

At 1628:50, the frequency dipped from 60 Hz to 59.9 momentarily, overshooting to 

60.04 then recovering to 60 Hz. 

NORTHERN ISLAND RESTORATION 

The 230-kV Ross-Lexington line was restored at 1626; the Keeler-Allston 500-kV line 

was restored at 2057; the John Day-Marion and Marion-Lane 500-kV lines at 2250. 

The Big Eddy-Ostrander 500-kV line remained out of service overnight. 

The Chief Joseph 230-kV powerhouse lines that were tripped by RAS action were 

energized at 1557. 

McNary powerhouse was back on line in twenty minutes. 

Restoration on the Oregon portion of the COl began at 1552 and was completed at 

1657. The Grizzly terminal of the Round Butte line was opened at 1550. The John 

Day-Grizzly line and Grizzly north bus were returned to service at 1553. The GrizzlyCaptain Jack line was energized briefly but was opened again due to high bus voltage. 

Many shunt reactors were then switched around the system to alleviate the high 

34 
116 

voltages. The John Day-Grizzly No. 2 line and the Grizzly south bus were returned to 

service at 1607. The Grizzly-Malin No. 2 line was closed at 1608, energizing the 

Malin north bus. The Malin-Captain Jack No. 1 line and Captain Jack south bus were 

returned to service at 1611. The Malin No. 2 reactor would not stay closed and 

cycled at various times until the SCAD A operator locked it out at 1632. At 1617, the 

Grizzly-Summer Lake line was energized and the line reactor placed in service. At 

1628, the Captain Jack PCB 4986 was closed, energizing the PAC Meridian line. At 

1643, the Summer Lake PCB 4958 was closed, energizing the PAC line to Midpoint, 

and immediately thereafter, the Midpoint PCB 544A was closed, returning the line to 

service. At 1648, the Malin PCB 4019 was closed, energizing the PAC 500/230-kV 

transformer, but it tripped free on phase discordance. At 1651, Malin energized to 

Summer Lake through PCB 4576. The PAC Summer Lake-Malin 500-kV line was 

returned to service by closing PCB 4576 at Malin and PCB 4957 at Summer Lake, at 

1651 and 1652 respectively. At 1653, Malin PCB 4019 was closed by the local 

operator, energizing the PAC 500/230-kV lransformer at Malin. At 1657, the GrizzlyCaptain Jack 500-kV line was returned to service. This placed two lines in service 

from John Day to Grizzly and three lines from Grizzly to Malin and Captain Jack, 

ready to close to Round Mountain and Olinda. 

At 1701, there were two complete bays at Grizzly. At 1702, the Captain Jack north 

bus was hot and two bays completely restored. At 1703, the ring bus at Summer Lak• 

was closed up. At 1704, the Buckley-Grizzly 500-kV line was in service. At 1708, a 

third bay was complete at Grizzly. At 1707, the John Day bays were completely 

restored. At 1707, the frrst complete bay was restored at Malin. At 1712, Grizzly 

PCB 5040 was closed to Round Butte. At 1749, the Fort Rock series capacitors wen 

bypassed. 

At 1813, Captain Jack PCB 4980 was closed, energizing the line to Olinda. The 

closure of the Captain Jack-Olinda 500-kV line at 1818 completed the first tie to the 

Northern California Island. At 1829, Malin PCB 4064 was closed, energizing the 

Round Mountain No. I line. The remaining circuit breaker to complete the bay was 

closed at 1830. The Malin-Round Mountain No. 2 line remained out of service until 

0708 on August II for insulator repairs. The last Captain Jack bay was restored at 

1836. 

The PDCI was restored to operation in 010 + 010 configuration at 1747, continuing 

through stages to full configuration of 311 + 311 at 1831. 

BPA and PAC 115-kV and 230-kV circuits in Central Oregon were restored at 1628. 

PAC load in southern and central Oregon 1md northern California was restored by 

1701. 

In the following islands, restoration of customer service was impeded due to the large 

amount of thermal generation that tripped off line during the disturbance and the fact 

that it took almost an hour to restore system frequency to 60 Hz. 

35 
117 

NORTHERN CALIFORNIA ISLAND DETAILS 

This island was formed following out-of-step conditions and low voltages between 

Midway and Vincent two seconds after COl separation and following separation from 

Sierra Pacific at 1548. 

At 1548:54.7 PAST, the Midway-Vincent No. 1 and No. 2 500-kV lines opened. Just 

prior to this action, the 500-kV bus voltage at Vincent was at 40 percent of normal. 

The Midway-Vincent No. 3 500-kV line tripped 65 milliseconds later. Line 2 tripped 

via channel C phase comparison relay, line 1 tripped via channel C out-of-step relay, 

and line 3 tripped via channel M out-of-step relay. Voltage was collapsing at about 

7.5 kV/cycle just prior to these trips. These trips separated northern California from 

southern California. 

During this same time frame, the Drum-Summit No. I and No. 2 115-kV lines tripped, 

separating PG&E from SPP. 

The Olinda 500/230-kV transformer tripped on over voltage at 1549:47.366. The 

Tracy 500/230-kV transformer tripped by over voltage relay at 1549:51.899. 

Frequency within the Northern California Island dropped to 58.3 Hz eight minutes into 

the disturbance. The underfrequency load shedding program within this island tripped 

all 10 blocks of load, representing approximately 50 percent of the northern California 

load. Numerous generating units tripped, including Diablo Canyon Units 1 and 2 

(2,164 MW) at 1548.55.141 and 1548.55.405; Moss Landing Units 6 and 7 (1,474 

MW) at 1551:47.420 and 1552:17.536; Morro Bay Units 1, 2, 3, and 4 (749 MW) at 

1550; Contra Costa Units 6 and 7 (670 MW) at 1556; Hunters Point Unit 2 (10 MW) 

at 1550; Pit No. 1 Powerhouse Unit 1 at 1547, and Pit No.7 Powerhouse Unit 7 (13 

MW) at 1552. CDWR generation totaling 929 MW was lost at 1550, 1555 and 1557 

due to the Table Mountain-Thermalito 230-kV 1, 2, and 3 lines relaying. The most 

likely cause was the No. 2-230 kV line sagging into a pine tree, flashing over and 

causing a fire. The fire spread to cause flashovers on the No. 1 and 3-230 kV lines. 

The Diablo Canyon units were tripped due to loss of synchronism, by directional 

instantaneous overcurrent relays looking into the unit step-up transformers. The units 

appeared to be stable with the remaining system until the Midway-Vincent lines 

relayed. Moss Landing Unit 7, Morro Bay Unit I, and Contra Costa Units 6 and 7 

relayed by loss of field. Moss Landing Unit 6 relayed due to volts/hertz 

overexcitation and regulator voltage balance. Morro Bay Unit 3 relayed due to 

undervoltage and Morro Bay Unit 4 by underfrequency. High voltage occurred on the 

500-kV and 230-kV system; the North and South ties opened; and load was tripped. 

This high voltage, along with low frequency, contributed to the tripping of units. 

Volts/hertz relays primarily at Moss Landing and Contra Costa overrode other 

excitation protection and played a major role tripping the units. 

In all, the Northern California Island lost 7,937 MW of generation and 11,602 MW of 

load (representing approximately 2.9 million customers) during the disturbance. 

36 
118 

In addition to automatic load shedding in the island, the Fresno area manually reduced 

80 MW of load to help recover system frequency at 1554. At 1556:03, the PG&E 

frequency dropped to 58.3 Hz due to the loss of generation in the island. The last two 

blocks (blocks 9 and 10) of underfrequency load were shed. An automatic protection 

scheme at Martin Substation operated to separate San Francisco from the Northern 

California Island when frequency declined to 58.3 Hz. 

After the initial swing, when the frequency dropped to 58.5 Hz, frequency rapidly 

overshot to 60.7 Hz and fluctuated slightly above 60Hz for over three minutes. Some 

of PG&E's load began automatically restoring after three minutes. (The PG&E load 

shedding program is designed to restore load in three to six minutes after frequency 

returns to near 60Hz.) Over the next five minutes, as load was automatically restored 

and additional generation was tripped, frequency further declined to 58.3 Hz so that 

the load that had been automatically restored was tripped again. Frequency then 

returned to slightly above 59.0 Hz, where it began to stabilize. By 1600, 4,320 MW 

of load had been restored on the PG&E system. At 1607, frequency returned to 59.5 

Hz where it stayed for approximately 75 minutes. At 1722, PG&E dispatchers 

manually shed load to bring the frequency back to normal. The low frequency in the 

Northern California Island prevented a parallel from being made with the Northern 

Island. From 1722 to 1732, PG&E manually shed 2,524 MW of load in Blocks 9 and 

10. These blocks were restored by 2037. 

Pit units were restored at 1641 and 1651. liunters Point No.2 was paralleled with the 

system at 1755. 

At 1818, the COl was reestablished when the Captain Jack-Oiinda line was closed. 

The Malin-Round Mountain No. I line was restored at 1829. The Malin-Round 

Mountain No. 2 line remained out of service because of damaged insulators. At 1843, 

Contra Costa Unit 6 was synchronized to the system. 

Connections to southern California were restored at 1847 when the Midway-Vincent 

No. I and No. 3 lines were restored. The Midway-Vincent No.2 line was closed at 

1848. 

The 115-kV ties to Sierra Pacific were restored at 1915. Morro Bay Unit 2 was 

paralleled at 2000. 

By 2154, 91 percent of the PG&E customers were restored with all customers restored 

by 0100 on August II. Morro Bay Units l and 3 were paralleled, respectively, at 

2301 and 2318. 

Moss Landing Unit 6 paralleled at 04: II on August II, while Unit 7 was paralleled at 

1800 on August II. Diablo Canyon Unit 2 was returned to service at 1431 on August 

15, Unit I at 0410 on August 16. 

Underfrequency detection on UPS at Western's control center in Folsom switched 

conununication, computer and SCADA equipment from the AC power feed to DC 

power (batteries). At 1614, the UPS failed because of low battery voltage interrupting 

37 
119 

power to the communication, computer and SCADA equipment. The emergency 

generator was not designed to startup on underfrequency and it didn't switch on 

undervoltage due to high AC voltage in the island. Losing their SCADA at 1614 

prevented Western from switching out 800 MV AR of 500 kV shunt capacitors at 

Olinda and Tracy, exacerbating high voltage in the island. At 1655, equipment was 

bypassed to restore AC power to critical equipment and at 1715, the UPS was 

restored. 

SMUD lost 1,000 MW and 160,586 customers during the disturbance. Most of the 

load was automatically shed by underfrequency relay, but 384 MW was manually 

shed. Load restoration was completed at 2103. 

SOUTHERN ISLAND DETAILS 

This island consisted of southern California, Arizona, New Mexico, southern Nevada, 

Northern Baja California, and El Paso, Texas. This island was formed due to out-ofstep conditions and low voltage between Midway and Vincent and out-of-step 

conditions on the Northeast/Southeast boundary. Generation totaling 13,497 MW was 

tripped, along with 15,820 MW of load (4.2 million customers). 

By 1548:54.938, separation of the NFJSE boundary (TOT2) including the HesperusWaterflow 345-kV, Lost Canyon-Shiprock 230-kV, Glen Canyon-Sigurd 230-kV, 

Glade Tap-Durango 115-kV, Red Butte-Harry Allen 345-kV, and Pinto-Four Corners 

345-kV lines, was complete, with all lines tripping due to out-of-step conditions. 

Frequency in this island dropped to approximately 58.5 Hz, triggering underfrequency 

load shedding. In this island, key generating units tripped, including Palo Verde No. 1 

and No.3 (2,493 MW), all three Navajo units 2,130 MW), Mohave Unit 2 (642 MW), 

Four Corners Unit 5 (762 MW), Cholla Unit 1 (107 MW), Coronado Unit 2 (357 

MW), all Glen Canyon units (700 MW), Ormond Beach Unit 2 (689 MW), Encina 

Units 4 and 5 (323 MW), South Bay Unit 1 (92 MW), Etiwanda (318 MW) and 200 

MW of Phoenix area generation. 

At 1549, Intermountain Unit I (854 MW) tripped due to a sub-synchronous resonance 

protective relay operation (the SSR relay operated in response to commutation failures, 

not SSR). The Intermountain-Adelanto HVDC southern Transmission System (STS) 

ramped down by the appropriate amount in response to the unit trip. Several minutes 

later, Intermountain Unit 2 ramped down by approximately 200 MW due to boiler 

instability. Again the STS ramped down by the appropriate amount in response. 

Units at Scattergood (at 1555) and Haynes (at 1549) in the LDWP control area were 

also tripped as well as many other smaller units at numerous locations across the 

Southern Island. 

The three Navajo units tripped when a potential transformer on a series capacitor 

failed. The resulting fire and smoke caused a phase-to-phase fault on the NavajoMcCullough 500-kV line. Four seconds before this, the Navajo-Moenkopi line had 

tripped on out-of-step. Loss of these two lines left only the Navajo-Westwing line to 

38 
120 

carry power from the three Navajo units and it tripped on out-of-step, leaving the units 

isolated. 

At 1549, the 345-kV Pinnacle Peak terminal of the Glen Canyon-Flagstaff-Pinnacle 

Peak I and 2 lines opened, initiating the RAS to trip four units at Glen Canyon, 

leaving three units generating 300 MW. The 345-kV voltage at Glen Canyon was 506 

kV, tripping the east bus. Ten minutes later, the WAUC dispatch center at Montrose 

was ready to parallel at Flagstaff but the W ALC dispatch center in Phoenix was 

unable to close the Pinnacle Peak 345/230-kV transformer breakers because the relay 

was still detecting an overexcitation condition. An operator had to be called out. 

At 1617, the 230-kV Glen Canyon-Navajo, Kayenta-Navajo and Kayenta-Shiprock 

lines relayed, islanding the three units at Glen Canyon. 

At 1621, the Glen Canyon-Navajo-Kayenta line was energized, but a phase shifter 

differential operation at Glen Canyon sent a transfer trip signal to Navajo. 

At 1632, Glen Canyon unit 4 was put on line to provide station service. At 1633, the 

west bus relayed on overvoltage. Unit 6 was placed on-line at 1633. At 1640, the 

Glen Canyon-Navajo line was energized and the Glen Canyon east bus was energized 

one minute later. At 1644, the Flagstaff terminals of the Glen Canyon and Pinnacle 

Peak lines were opened in preparation for a return to service. 

At 1750. the 345-kV Glen Canyon-Flagstaff No. 2 line was energized to Flagstaff and 

the Flagstaff bus was energized two minutes later. One minute later, the Glen 

Canyon-Flagstaff No. l line was in service, as well as the Flagstaff-Pinnacle Peak No. 

I 345-kV line. The Flagstaff-Pinnacle Peak No. 2 line was in service at 1756. 

All Glen Canyon units were rerurned to service by 1752. 

At 1606:47, an additional 1.400 MW of manual load shedding was implemented by 

SCE at Valley 115-kV, Villa Park 66-kV and Chino 66-kV substations to help restore 

system frequency. 

The frequency in the Southern Island remained below 60 Hz for over an hour. SRP 

manually shed 216 MW of load (after tripping 1,444 MW by underfrequency 

relaying). 

As the frequency in the Southern Island began to recover and several key units in the 

Southem Island returned to service, system load restoration began at 1657. The 

frequency returned to normal at 1655 PAST. 

At 1847, twenty-nine minutes after the Northern California Island sync:hronized to the 

Northem Island, Midway-Vincent 500-kV lines No. l and No.3 were paralleled at 

Vincent, reestablishing the 500-kV tie between PG&E and SCE and reconnecting the 

Southem and Northern California Islands .. At 1848, Midway-Vincent No.2 was 

rerurned to service. Between 1850 and 1857, starting with the Four Corners-Pinto 

39 
121 

345-kV line, the NFJSE lines were returned to service, completely restoring the WSCC 

bulk power transmission system. 

By 2142, all the load shed in the Southern Island during the disturbance had been 

restored. 

Major unit restoration began with Coronado Unit 2 at 1730, followed by Ormond 

Beach Unit 2 at 1915, Springerville Unit I at 2131, and Navajo Unit I at 2215. Palo 

Verde Unit 3 returned to service on August 11 at 1756 and Unit 1 was synchronized 

at 0454 on August 12. Navajo Unit 3 was the last of the major units to be restored, 

returning to service at 0608 on August 12. 

40 
122 

ALBERT A ISLAND DETAILS 

At 1554, approximately five minutes after the Northern Island separated from the rest 

of WSCC, the BCHA to Alberta interconnection (138-kV and 500-kV) tripped, 

separating the Alberta system from the Northern Island. At the time of the separation, 

the interconnection was supplying I ,230 1\IW to Alberta. The 138-kV tie tripped on 

transformer overcurrent and the parallel 500-kV tie tripped on undervoltage. Governor 

action in response to high frequency caused the loading on this interconnection to 

increase from 400 MW to I ,230 MW prior to the lines tripping. Frequency in the 

Alberta Island dipped to 59.0 Hz. In this island, 146 MW of generation was tripped 

and 968 MW of load was lost by underfrequency load shedding, affecting 192,000 

customers. Alberta resynchronized with British Columbia at 1629. All load was 

restored by 1739. 

Detailed data for each system are included in Appendices I through 4. 

V. SEQUENCE OF EVENTS 

See Appendix 5 

41 
~ 

N 

VI. DISTURBANCE EVALUATION CHECKLIST 

DIST\!RBANCE CATEGORY 

1. Power System Facilities 

2. Relaying Systems 

3. System Monitoring, 

Operating, Control, and 

Communications 

FacUlties 

4. Operating Personnel 

Perfonnance 

5. Operallonol Planning 

6. System Reserve and 

Generation Response 

DEFINITION 

The existence of sufficient 

physical facilities to provide a 

reliable bulk power supply 

system. 

Delocllon ol bulk power supply 

parameters that are outside 

nonnal operating limits and 

activation of protection devices 

to prevent or limit damage to the 

system. 

Ability of dispatch and control 

facilities to monitor and control 

operation of the bulk power 

supply system. Adequacy of 

communicalion facilities to 

provide Information within and 

between control areas. 

Ability of system personnel to 

react property to unanticipated 

circumstances which require 

prompt and decisive aclion. 

Study ol near term (daily, 

weekly. seasonal) operating 

conditions. Application of resuhs 

to system operation. 

Ability ol generation or load 

management equipment to 

maintain or restore system 

frequency and tie line flows to 

acceptable levels fonow;ng 

system disturbance. 

CONTRIBUTING FACTOR IN CAUSING 

THE DISTURBANCE, INCREASING ITS 

SEVERITY, OR HINDERING 

RESTORATION? (YES OR NO) 

No 

Yes 

Yes 

Yes 

Yes 

Yes 
~ ..., 

DISTURBANCE CATEGORY DEFINITION 

7. Preventive Maintenance A program of routine Inspections 

and tests to detect and correct 

potential equipment failures . 

8. Load Relief The Intentional disconnection of 

customer load In a planned and 

systematk: manner k> restore the 

balance between available 

power suppty and demand. 

9. Restoration 

10. Special Protac11on 

Systems 

11. System Planning 

12. Other 

Ordarty and effective procedures 

to quickty reestabtlsh customer 

service and rutum lhe Uui~ 

power supply system to a 

reliable condition. 

Use of rCJiays to wtlate 

controlled separation and 

generator tripping to prevent a 

widespread blackout 

Comprehensive planning work 

utilizing appropriate planning 

criteria to provide a reliable bulk 

power suppty system. 

Any oth&r factor no! Us lad above 

wh"h was significant ln causing 

the disturbance, making the 

disturbance more severe or 

adversely affedlng restoration. 

CONTRIBUTING FACTOR IN CAUSIN

THE DISTURBANCE, INCREASING IT

SEVERITY, OR HINDERING 

RESTORATION? (YES OR NO! 

Yes 

Yes 

Yes 

Yes 

Yes 

Yes 
125 

VII. EXIDBITS 

Summary of Plots and Figures: Very good information was obtained from the Portable 

Power System Monitor (PPSM) at Dittmer and other locations on the power system to help 

reconstruct the events of the disturbance. A selection of plots is provided showing some of 

the key events described. PPSM scaling may be in error on some plots. Subtract 5 seconds 

from time scale to match sequence of events timing. 

Exhibit I Response to loss of Keeler-Allston (Dittmer PPSM) 

Shown in Exhibit IA are step changes in line flows in the northwest resulting from outage of 

the Keeler-Allston line. Exhibit 18 includes voltage at Slatt (near McNary) showing 

reduction in voltage. Also shown is response on COl as indicated by PG&E Olinda MW. 

Oscillation is lightly damped. 

Exhibit 2 Response to loss of Ross-Lexington (Dittmer PPSM) 

Exhibits 2A -2F show the Northwest response on selected lines and generators to the RossLexington trip. Exhibit 2D illustrates the reduction in power at McNary resulting from 

sequential tripping of all 13 units. All figures show the system oscillation of 0.224 Hz which 

began at the time of loss of Ross-Lexington and initial tripping of McNary units and becomes 

more negatively damped (unstable) as additional units are tripped. Exhibit 2A shows that 

voltage at Malin drops lower on successive swings until the COl opens. Exhibit 2F shows a 

detailed plot of the initial response following loss of the Ross-Lexington line before the system 

oscillation began to grow. 

Exhibit 3 DC Schedule-Actual (Dittmer PPSM) 

This figure shows the response of the PDCI at the time of COl separation. Dynamic swings 

on the PDCI resulted in initiating PDCI remedial actions. Also initiated is the PDCI algorithm 

to automatically change schedules to actuals intended to minimize impact of a monopole 

outage on the COl initiated by swings on the PDCI. 

Exhibit 4 CO!and Midway-Vincent Separations (PG&E DSM) 

Shown are the responses for the North Tie (Malin-Round Mountain I and 2) and the South Tie 

(Midway-Vincent). Outage of the South Tie occurs very soon after loss of the North Tie 

(approximately 2 seconds) as a power reversal occurs to support the northern California area. 

Exhibit 5 Table Mountain response at time of separation (PG&E DSM) Exhibit SA shows 

Table Mountain voltage and frequency. Exhibit 58 shows MW and MY AR flows at Table 

Mountain. Exhibit SC shows a detailed plot of the system oscillation. 

Exhibit 6 - McNary MY AR (USCE McNary recorder) 

This Exhibit shows the initial plant loading of 260 MY AR followed by an increase to over 

360 MY AR after loss of the Keeler-Allston and Ross-Lexington lines. 

Exhibit 7 - SCE Island frequency (SCE recording) 

This figure shows the frequency decline in the Southern Island following the disturbance. 

Exhibit 8 - Diagram with northwest sequence of events. 

Exhibit 9 - Map showing islands formed and sequence of significant events leading to 

separation. 

Exhibit 10- BCHA-Alberta power transfer, frequency plots for Alberta, and BPA 

frequency/time error plots. 

Exhibit 11 - PG&E frequency plot, indicating unit tripping and load shedding times. 

Exhibit 12 - WSCC Interchange Diagram and Supplemental Line Aow Report; Hour Before 

Disturbance 

44 

36 -0 69 - 97 - 5 
l26 

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Me>n~or Location. DITTMER SPA SYSTEM CONTROL CENTER ·- X-Axis Unns • Seconds 

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127 

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Monitor Location • DITTMER BPA SYSTEM CONTROL CENTER·- X-Axis Unrts • Seconds 

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o.o 10.0 20.0 30.0 o110.o so.o eo.o 7o.o ao.o eo.o 100.0 110.0 

Monitor Location • DITTMER BPA SYSTEM CONTROL CENTER- X·Aida Unle • Seconda 

TlmeCliFinlo.taf'olni•08·1().M 15M7m05s.OOOOOO Exhibit 20 
132 

Tale'a Name • SlicaOOITT 08-10.118 16h47m10.- P~ 5 a1 5- Pm1..:1 81151116 

"" Channal•s ·acomo~ 230 kV . e .. .Hy 

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MonHor Location • Orrn.4ER BPA SYSTEiol CONTROL CENTER- X-Axis UnMa • Seconds 

TlmeoiFiniOalaPolni•08· 10.11815h47m05s .OOOOOO Exhibit 2E 
133 

Tille's-• -.ootTT Oe-1C>G8 1&M7m10.-.._ 1 at 1-P-.ciet171116 

Clwnnell 0- SIMI-3 

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512. 

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508. 

506. 

504 

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IJ\. . .&lVI • .JJ n.~ 

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Generation MW - MW 

h 

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000_ Channel j44 Os1rander Hanford Line Load MW MW 

-

-· 

-

-1240.000-

·1250.000-

-1260.000-

-1270.000-

-1280.000--

-

- ·1290.000- ...... ./' - -1300.000-

-1450.000- Channel U3 - Van1aae~Schultz Una Load MW - MW 

-1500.000-~ ~ 

v V'-\..."" ~ All . 'W 

-1550.000-

-1600.000-

-1650.000-

- - -1700.000- 2850.00Q-Channel jJS PG&E Mahn Sum MW MW 

2800.000-

.2750.000-

2700.000-

2650.000-

2600.000-

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2500.000-

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Monhor Loc:o1ion • DITTMER BPA SYSTEM CONTROL CENTER- X·Axis Unb • Seconds 

Tma o1 Am Data Point- 08-10-96 15h47".!25s . . 896141 

Exhibit 2F 
134 

Tltle'a- • 6-0DITT 08-1G-M 11ih47m1oa- P~~ge 1 c1 1 - Pt1nled 81151116 

1200. 

1000. 

800. 

600. 

400. 

200. 

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Channel e30 - 1 nws> "'-""' o:nn kV MW.- MW 

~ ~-I' ~ 

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1750.000 

1500.000 

1250.000 

1000.000 

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3500.000; Channel 135- PG&E Mahn Sum MW- MW 

v 

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3000 000~ _;;;;;::.r;f?\71 2500 000~ 

2000 000il-----+-----+-----~~--~----~----~----~--~~----~--~ 

1500 000~1-----+-----+-----~~--l------~----~----~--~~----~--~ 

1000 000~~1 ------r---~~--~~---1-----1----~-----1----~----~-----4 

500 000~~----+-----+-----+-~--l------~----~----~--~~----~--~ 

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1500.000 

1250.000 

1000.000 

-

-

-

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soo.ooo250.000 

-

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-

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500.000-

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1 

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, ......... , ................ ""'"'""'l'"'tl"'l'""'"'t'''''" 11 11" ' '"''1' 11 '"'"1'" 11111 '1 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 110.0 100.0 

t.lonhor Locallon • DITTMER BPA SYSTEM CONTROL CENTER - X·Axls Unks • S-.:onds 

lme ol First Dala Poln1.•08·1G-116 1!;M8rn2<ia .. 1-463011 

Exhibit 3 
135 

PGLE FOKS-B 

1!5:46:41 SAT 08/10/1996 

NORTH TIE 

109 

p 

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• 

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SOUTH TIE 

p 1101 0 . . . . . Ill ----------·-·-·---·----"--- . . . . . . . . . • 101 -·-···:·-··-··.:·-··--· ......... : ····-·-· .. ,,.,_,; ......... · ......... : .......... -····· ..... ,,,_;._ 

r . . . . . . . . --. --··":"·--···~·--. -··:---··:······-· ·-:-~·~,-~---:-~-···-·:··-~···-····:······-~-·-·":"·-···· 

-899 . ...;..__;·--" . . K . . . . . . . . . . . 

"' ···-·":"-·~·--··':'---!'----. --.-~-~--. ---=--~·· . . . . . . . . . . -1899 . . . . . . . . . . . ··---------·--·-·-··-·-··------·- . . . . . . . . . . --!-·······~--·--0.:··········:···-·-·i··-·-··:---··-: -··i ··-:--:----:----:--:--:----:---:---·~·----·i·-:- . . . -2099 

-10 10 30 50 70 90 110 130 150 170 190 

Secollcls 

Exhibit 4 
rn 

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kV 

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.s: .. o 

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.. ~:r;.&., 

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Table Mountain 500kV Frequen

.. ._ ... Time 
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Power Flow Into Table ~ounta

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Frequency Spectrum 01/10/De NorU.••.t Dl•turbe.-

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139 

Exhibit 6 
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1 • 1406 

2 . 14S2 

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5- 15-47

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7. 1548

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1- 1548
142 

Exhibit 9 

Significant Events Leading to System Separation 

Map Showing Sequence of System Separation 
" u 

143 

SEQIJENCf Of $\!;NIFlCANT EVINTS • AUGUST 10, 1"6 

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144 

Sequence of Significant Events 

August 10, 1996 

Islands Formed August 10, 1996 
145 

Exhibit 10 

BCHA-Aiberta Power Transfer 

Frequency Plots for Alberta 

BPA Frequencyffime Error Plots 
2.0 

,: : 

1t 

-

-tCD 

146 

Allf .. 1h WSCC DIAIIII••ca 

A1Mna.8C12D1l vw.'•OU:CII 

: : ! 

-

! 

-, ... rExhibit 10 
147 
148 

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:j 

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149 

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150 
151 

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EXH IBIT 11 
152 
153 

Form Rev. 11-1 -93 

I. East of 

* 

* 

* 

2. Northwe 

* 

* 

* 

* 

* 

* 

* 

3. NE/SE B 

4. Total 

* 

* 

5. Total 2 

6. Total 4 

** 

** 

1996 

OPERATING SUPPLEMENTAL LINE FLOW REPORT 

the Colorado River 

Nava ·o-McCullouah 500 kV 

Moenkon i-*Eldorado 500 kV 

Palo Verde-Devers 500 kV 

Palo Verde-North Gila 500 kV 

Libertv-Mead 345 kV 

NETTED TOTAL (E to W) 

st of the Colorado River 

McCullouah-Victorville #I 500 kV 

McCullouah -Victorville #2 500 kV 

Hoover-Vi cto rville 287 kV 

Eldorado-Luao 500 kV 

Eldorado-Luao #I 230 kV 

Eldorado-Luao #2 230 kV 

Mohave-Luao 500 kV 

J. Hinds-*Devers 230 kV 

NETTED TOTAL (E to W) 

oundary Break Point 

Pinto-*Four Corners 345 kV 

Lost Canvon-Shiorock 230 kV 

Duranao-Shiorock 115 kV 

Waterflow-San Juan 345 kV 

Siaurd-Glen Canvon 230 kV 

Red Butte-Harry Allen 345 kV 

NETTED TOTAL (N to S) 

A' 

Bears Ears-Bonanza 345 kV 

Hayden -Artesia 138 kV 

Meeke r-Southwest Ranaelv 138 kV 

NETTED TOTAL (E to W) 

A 

Lost Canvon -*Shiorock 230 kV 

Duranao- *Shiorock 115 kV 

Waterflow-*San Juan 345 kV 

NETTED TOTAL (From Tot 2A) 

A (Wyoming) 

Dave Johnston-Diffi culty 230 kV 

Riverton-Wvooo 230 kV 

Soence-Mu st ana 230 kV 

NETTED TOTAL (N to S) 

Saturday 

August 10 

1500 PAST 

714 

856 

922 

0 

-177 

2,315 

333 

322 

21 

477 

15 

15 

662 

39 

1,884 

416 

159 

-28 

333 

151 

279 

1, 310 

357 

29 

-12 

374 

159 

-28 

333 

464 

NA 

NA 

NA 

373 
154 

7. West of Taft 

* Taft-Bell 500 kV 121 

* Taft-Dworshak 500 kV 1112 

NETTED TOTAL (E to W) 1,233 

8. Four Co rners Area 

* Four Corners-MoenkoRi 500 kV 1075 

* Four Corner~-Cholla #1 & #Z 345 kV 991 

NETTED TOTAL (E to W) 2,066 

9. South o f Table Mountain 

* Table Mountain -Vaca Dixon 500 kV 1380 

* Table Mountain-Tesla 500 kV 1327 

NETTED TOTAL (N to S) 2,707 

10. Other lows 

11. 

** 

+ 

* 

* 

N. Gila-!mgerial Valler 500 kV 

Devers-Valler 500 kV 

MidRoint-Summer Lake 

Phase Shifters Check if 

A. Saturdar -- 1500 PST BrRassed 

Lost Canyon -S hiprock 230 kV 

Waterflow-San Juan 345 kV 

Sigurd-Glen Canyon 230 kV 

Pinto-Four Corners 345 kV 

Red Butte-Harry Allen 345 kV 

Billings-Yellowtail 161 kV 

Billings-Yellowtail 230 kV 

Crossover-Yellowtail 230 kV 

Metered end. 

In stantaneous re ading. 

755 

228 

628 

Phase Schedule Actua 1 

Angle __1!1tl.._ --'1:!tl_ 

+I 159 --1- 454 333 

----:;:s 

+3 

--31 

515 ~ 110 

_+_!_ 

_+_!_ _.:l_lQ_ __ 74_ 

0 

All readings assumed positive unle ss prefixed by a minus (-) siQn. Positive shows power flow from the termi na 1 1 i sted on the 1 eft 1.Q the termi na 1 1 i sted on the right. 

Negative indicates power flow fro~ the terminal li sted on the right to the 

terminal listed on the left. 

Refer any quest ions on thi s report to Larry Harmon, WSCC Staff (801) 582 -0353. 
155 

Appendix 1 

Customers Affected and Load Lost 
ISLAND 

NORTHERN 

CALIFORNIA 

SOUTHERN 

NORTHERN 

ALBERTA 

156 

Summary of Load Lost and Customers Interrupted 

August10, 1996 

FIRM INTERRUPTIBLE I TOTAL CUSTOMERS I (MWI (MW) I LOADIMWI 

11,302 i 300 11,602 ' 2,892,343 

15,231 589 15,820 I 4,195,972 

1.791 308 2,099 209,858 

761 207 968 I 191 ,904 

TOTAL 29,085 1,404 30,489 7,490,077 

Page 1 of 5 

Appendix 1 

ENERGY 

IMW-rninl 

388,017 

1,975,864 

95,075 

24,888 

2,483,844 
157 

Northern California Island Appendix 1 

TIME MW- I MEMBER FIRM INTERRUPTIBLE TIME REASON NUMBER OF MINUTl (MW) (MW) INTERRUPTED CUSTOMERS RESTORED LOAD LOST 

CDWR Pump load 598 1548 RAS N/A N/A N/A 

MID 162 1548:56 underfrequency 31,000 2002 40,986 

NCPA 273.1 1548 disturbance 4,405 1700 

2,005 1800 

65,500 2100 

PG&E 300 1547:52:00 59.75 Hz 120 2042 88,840 

5700 <-Block 1-6 30% 1547:55:00 59.3-58.7 Hz 2.000,000 1552:25:00 25,650 

1900 <-Blocks 7 & 8 (10%) 1554:00:00 58.5 Hz 1559:30:00 8,550 

1737 <-Block 9 & 10 (partial 1556:03:00 58.3Hz 494,128 1800:33:00 7,817 

SMUD 72.80 N/A 1548:55:00 undertrequency 18,697 1550:57:00 146 

72.80 N/A 1551 :51 :00 manual shed 18,697 1959:29:00 18,017 

54.52 N/A 1548:55:00 underfrequency 8.559 2052:11 :00 16,534 

56.10 N/A 1548:55:00 underfrequency 12,470 2036:38:00 16,143 

37.40 N/A 1548:55:00 undertrequency 6,720 2027:27:00 10,415 

38.66 N/A 1548:55:00 underfrequency 7,114 2055:10:00 11 ,839 

65.73 N/A 1548:55:00 underfrequency 8,575 2026:50:00 18,273 

50.65 N/A 1548:66:00 underfrequency 6,111 2106:07:00 16,065 

74.56 N/A 1548:56:00 underfrequency 10,269 1549:39:00 56 

74.56 N/A 1549:42:00 underfrequency 10,269 2019:29:00 20,112 

42.80 N/A 1548:66:00 underfrequency 9,154 1549:40:00 32 

42.80 N/A 1552:20:00 manual shed 9,154 2103:26:00 13,314 

54.10 N/A 1548:66:00 underfrequency 8.n3 1653:35:00 3,495 

54.10 N/A 1713:52:00 manual shed 8.n3 2010:35:00 9,562 

33.19 N/A 1548:66:00 underfrequency 7,151 2100:29:00 10,337 

62.26 N/A 1548:66:00 underfrequency 10.546 1549:05:00 

62.26 N/A 1555:01 :00 manual shed 10,546 2011 :28:00 15,, __ 

79.06 N/A 1548:66:00 underfrequency 19.003 1631:12:00 3,340 

79.06 N/A 1736:18:00 manual shed 19,003 2001 :44:00 11 .503 

23.67 N/A 1548:66:00 undertrequency 3.514 1549:23:00 12 

23.67 N/A 1552:20:00 manual shed 3,514 1615:28:00 547 

49.66 N/A 1555:02:00 underfrequency 12.212 1636:12:00 2,037 

52.51 N/A 1557:55:00 underfrequency 13,009 1637:57:00 2,100 

52.51 N/A 1735:44:00 manual shed 13,009 2012:17:00 8,217 

47.99 N/A 1557:54:00 underfrequencv 10,872 1600:40:00 132 

48.07 N/A 1557:54:00 underfrequency 11,565 1600:40:00 132 

62.50 N/A 1557:54:00 underfrequency 8.953 1600:41 :00 172 

62.50 N/A 1758:04:00 underfrequency 8,953 2000:41 :00 7.663 

TOTAL 11,302 300 2,892.343 388,017 

Page 2 of 5 

36-069 -- 97 - 6 
158 

Southern Island Appendix 1 

FIRM INTERRUPTIBLE TIME NUMBER OF TIME MW· 

MEMBER REASON MINUTES IMW) IMW) INTERRUPTED CUSTOMERS RESTORED LOAD LOST 

I>PS 2000 60 1548 underfrequency 300,000 2030 350.000 

BURB 100 1548 underfreq relay 28,948 17« 11600 

CFE 249 15-49 underlreguencv 116,552 by 1713 17,019 

<0 15-49 undertr.Q~nc:y 1 1615 1,0<0 

15 1552 undemoouoncv 10,662 1650 870 

14 1553 underftequenc:y 9 ,526 1658 910 

46 155-1 undMfrequency 14,<04 bv1658 2.616 

26 1555 undomoouoncv 5,606 bv1&15 1.288 

5 1802 undomoouoncv 4,765 bv1659 195 

EPE 400 0 15-49 u 150,000 1804 49,5110 

FARM 13.7 15-49,20 ---- 4,n8 bv1834 5.256 

GLEN 103 0 1548 ~lcod ..... 45,100 1746 1215-4 

19 0 11501 ullcod ..... 10,11150 11526 475 

13 0 1601 m.nualtrip 4 ,882 1628 351 

LDWP 1320 undomoouoncv 575,000 by 17'38 182400 

MWD 110 1551 undomoouoncv 2142 38,610 

103 1551 

- 1557 618 

77 1551 

- 1612 1,617 

NEVP 1514 1548 underfr~uency 159.000 by 2125 

30 1548 uncterfrequency 1 2125 10,110 

oxcc 53 53 1549:20 p4on11rip 1625 2312 

PAS!\ 95 HE 1700 undertr.quency 1830 

PECT 12 15-48 undertreq_ relay 1811 300 

10 15-48 underfreq. RillY 1613 250 

1 1548 unOerhq_ AMy 1818 30 

16 15-48 ......_ ..... , 17'34 1696 

12 1548 unoerfraq. rW 1812 288 

1 1548 underfreq. relly 1 1518 30 

11 15-48 

......_ __ 1 1n4 1186 

46 15-48 ......... _ 1 1559 528 

PNM 15-48 undomoquonc:y 2.300 11508 1<0 

1604 underfrequenc:y 6.970 1834 3110 

11504 ·-- 19,144 1638 1,734 

11504 ·-- 6.3n 1642 304 

15-48 17,857 1830 2.058 

15-48 un<Mmoouoncv 35,846 1834 U06 

15-48 unMI'fr~u.nc:y 25.n7 1645 4,088 

1548 undemoquoncy 8,812 1709 1.-482 

11504 und41tfrequency 6,144 1n3 1.580 

1604 underfraquency 4,990 1733 1,246 

1548 underfrl!lquency 4,753 1734 2.438 

15-48 underfrequency 1,111 1750 

1604 undeffrequency 384 1812 -128 

1548 undetfrecluencv 1,3110 1832 856 

15-48 sensitive loads Nil\ . 17<0 Nil\ 

SCE 4,480 1549 undltrlrequency 1800000 by 1655 689,023 

56 1830 manuat 21 00 8 ,400 

1,463 1606-1612 manual by1n5 117.301 

SDGE 860 Nil\ 1548 UF load shedding 462,438 1658 93,9&1 

SRP 1700 15-Ul:59 loosal!l"- 243.000 21<0 292,500 

TEP 367 15-47 undemoouoncv 116,241 bv1820 32.252 

13 15-47 loosal_.mon 7 2008 3,367 

TID 24.2 15-48 undeffrOQuoncv 5,059 1730 4,<04 

15.8 1548 underfrequency 3,341 1747 3 .1« 

16.2 1557 underlrequencv 3 .570 1756 3.364 

TNP 63 1549:52 loss of line 1 1703 4,599 

VERN 48 1549 underfTeQueflCV 900 1142 5,424 

WI\LC 5 1548:58 1 1819:39:00 755 

20 1549:04 underfreQuency 1 1658:o9:00 1380 

7 1549:1-4 undetfrequency 1 1621 :42:00 224 

2 1549:14 underlrequency 1 1937:24:00 216 

70 1549:14 1 1602:<40 :00 910 

TOTAL 15,231 589 4.t95.9n , ,975,864 

Pane 3 or s 
159 

Northern Island Appendix 1 

FIRM NUMBER OF TIME MW- I INTERRUPTIBLE TIME MEMBER (MW) (MW) INTERRUPTED REASON CUSTOMERS RESTORED MINUT. 

LOAD LOST 

BCHA 10 1551 uf load shed 223( 1615 21 

BPA 294 147 1548 1 1633 14.098 

80 80 1548 1 1633 7.408 

e 0 ? 1 288 

12 0 ? 1 432 

24 1550 ? 1 1627 864 

4 0 ? 1 152 

195 65 1548 ~relay 1 1635 12,220 

COPO 10 1548 undefvcftaae 1 1648 6,000 

OOPO None None 

IPC 320 0 1549 bkMn line fuses, 3517 1603 to 1822 2,680 

motor contacts 

dropping out etc. 

MPC None None 

PSPL No Puget food lost. System load was: 2321 MW@ 1500 PAST ond 2302 MW 1600 PAST. 

SCL N/A 

SNPO NA 

SPP 243 1548:53.14 low voltage due to ~orminan1; Cuslomet' 4,000 

out-of-step swing possibly •• many as dependen1, from (approximate 

50,000' 1 to 45 minutes number) 

TCL 41 1548 open tieline 1 2000 10,332 

TSGT 27.1 1548 voltage swings 1 1730 2,764 

46.6 1548 vo~swings 100 1604 559 

USPN 6 1548 loss of ine 1 1724 576 

WAUC 20 1548 lost bus 1641 

16 1548 lost bus 1709 · 

WAUM No interruptions occurred 

PAC 450 0 1548 154,000 1701 32,358 

WWPC No WWP loocl was interrupted due to this disturbance. 

TOTAL 1790.7 308 209,858 95,075 

Page 4 of 5 
160 

Alberta Island Appendix 1 

FIRM INTERRUPTIBLE TIME NUMBER OF TIME MWMEMBER REASON MINUTES (MW) (MW) INTERRUPTED CUSTOMERS RESTORED LOAD LOST 

TAUC 39 1654 underfrequency 1 1703 351 

38 1654 underlrequef19' 1 1739 171 

42 1654 underfrequency 1 1600 277 

83 1649 underfrequency 1 1700 91 

1654 underlrequency 1 1658 2 

1654 unde<frequency 1 1703 81 

9E 1654 underlrequency 50, 1730 316! 

1 1654 underlrequency 1 1700 64 

1654 underfrequency 1 1700 2 

1 1654 underlrequency 1 1700 1_02 

1 1654 underlrequency 65QC 1713 :2§§ 

1654 underfr~ ~ 1722 196 

1 1654 underfrequency 360C 1729 350 

1654 underfroquency 180 1708 7 

1654 underfrequency 108C 1656 

1 1654 underlrequency 500C 1717 3~ 

1 1654 underlrequency 500C 1714 280 

1 1654 underlrequency 57 1720 41 

11 1654 underfrequency 39C 1715 231 

1( 1654 underlrequency 3601: 1656 20 

9E 1654 underlrequency 1 1720 247 

1 1654 underfrequency 650 1703 162 

1 1654 underlrequency 540C 1718 360 

2: 1654 underlrequency 900C 1704 250 

3E 1654 underlrequency 13C 1717 828 

5 1654 underlrequency 1 1730 1!!(l 

1 1654 underlrequency 430C 1700 72 

1654 underlrequency 21 1724 180 

20C 1654 underlrequency 2500C 1730 120C 

1CX 1654 underlrequenc:y 3791 1712 180 

TOTAL 761 207 191 ,904 24,888 

Page 5 of 5 
161 

Appendix 2 

Generation Lost 
~ 

Alberta 

Alberta 

Alberta 

Alberta 

Alberta 

Alberta 

Northern 

Northern 

Northern 

Northern 

NOf1hern 

Northern 

Northern 

Northern 

Northern 

Northern 

Northern 

Northern 

Northern 

MEMBER 

TAUC 

TAUC 

TAUC 

TAUC 

TAUC 

TAUC 

BCHA 

BCHA 

BCHA 

BPA 

BPA 

BPA 

BPA 

BPA 

BPA 

BPA 

BPA 

BPA 

BPA 

Nortnern iBPA 

Northern IBPA 

Northern IBPA 

Northern IBPA 

Northern IBPA 

Northern IBPA 

Northern IBPA 

Northern IBPA 

Northern I BPA 

Northern IBPA 

Northern IBPA 

Northern IBPA 

Northern IBPA 

Northem IBPA 

Northern I BPA 

UNIT NAME 

A7«>sGen1tHRM 

Cawl!y Ridi!JUS Wind 

Dickson O.m 

Dreyton Velley Power 

E~ Riwr Power 

Weldwood 

AberfeldieGt 

Mc~nn G1 ·2 (IPP 

NWEGt (IPP' 

BonnevihFI 

Chief Jos,eph 1 

Chief~l7 

Chief'~2 

Chi.t'~ph4 

Chief Joseph 5 

Chief.Jowph 6 

Chiet'_~7 

Chief.JoMph 8 

~ 

LOSCCreeecl 

LostCteef(2 

McN~ry_~ 

McNary10 

McNery11 

McN.fv 12 

McNe_~ 4 

McN.ry2 

McNary3 

McNary4 

IMcNa_ry_li 

Me~ 

McNooy 7 

Mc.NIIry8 

McNa_ryJ 

Generation Tripped- August 10, 1996 

OUTPUT JUST UNIT 

BEFORE I CAPACITY I SPINNING I REACTIVE 

DISTURBANCE AT TI--E TIME RESERVE OUTPUT 

(MW) (JN{) (MW) IMVAR 

87 

16.5 

6 

150 

18.5 

• 10.61 10.6 

21 21 

901- 90 

10 15 

72 83 

1061 110 

751 83 

73 

2£ 

74 

73 

73 

~ 

22 

26 

66 

.. 

.. 

.. 

.. 

66 

.. 

66 

66 

66 

66 

66 

66 

63 

~ 

63 

63 

63 

~ 

24.5 

24.5 

66 

80 

80 

80 

60 

.. 

66 

.. 

66 

66 

80 

80 

80 

83 

11 

10 

11 

9 

10 

10 

____! 

2.5 

,. 

,. 

14 

14 

14 

,. 

14 

Page 1 of 5 

-12 

"' 

311 

38 

311 

311 

38 

38 

38 

38 

38 

38 

38 

38 

REACTIVE 

CAPABILITY 

(M\/AR) 

70 

....... ~ 

-50.+<42 

-60. +55 

.so. +42 

-50. +42 

-50 -t42 

-50. +42 

-50. +42 

-SO, -t42 

-30, +20 

~ 

-5. +10 

-SO, •20 

-60, +20 

-60. •20 

-60, +20 

-60.+20 

-60, +20 

-«1. +20 

-60, •20 

-60. +20 

-60, •20 

-60. •20 

-60, +20 

-60. +20 
Generation Tripped- August 10, 1996 

OUTPUT JUST UNl 

BEFORE CAPACITY SPINNING REACTIVE REACTIVE 

DISTURBANCE AT THE TIME RESERVE OUTPUT CAPABILITY 

ISLAND MEMBER UNIT NAME MW\ (MW\ rMWl MVAA fMIIAA 

No<1hem EWEB SmithCrto« 0.9 

Non hem GCPO PEC 4 4 0 0 0 

No<1hern GCPO Warwpum7 80.5 0:2 15 24.7 25 

Northern GCPO WaMPUm II 89.6 92 2.4 24.5 25 

Northern IPC CJ Sbike Unit 13 29 30 1 10 +15 

Northern IPC CINrlaka 2 2 0 0 1 

Northern IPC Milner.:! 1 0 0 0 

Northern MPC 1~1 320 320 0 4DMV 60MV 

Northern MPC .,_;p3 750 750 10 80MV 200MV 

Northern MPC Col01rio4 750 750 10 100MV 2001<V 

Northern PAC Blundol 22 23 1 nho 19 

Northern PAC IBovlo 37 eo 43 nlo 25 

Northern PAC COPC0115 33 65 322 

"'' 35 

No<1hern PAC Prospec:t115 37 so 19 

"'' 23 

Northern PAC ..... 207 240 33 

"'' 100 

No<1hern PGE ;,_,_ 10 10 0 0 0 

Northern PGE stone c.- 10 10 0 0 

Northern SCL Gen165 2 2.7 0 

Northern SCL Gen166 2 2.7 0 

Northern TCL EBC 4.8 SCBIO •• 1 1 0 0 

Northern TCL PEC 86.0 SC810 •• 1 1 0 0 

Northern TCL Wvnoochee f71 1 12 11 0 

Northern SPP VerdiHo.<cko 2.1 2.1 0 0.1 

Northern SPP St.mpede, Hydro 0.4 0.4 0 0 non SPPCo 

Northern SPP W•shoet1.Hvdro 0.9 0.9 0 0 

Northern SPP W•shooll2, Hvdro 0.9 0.9 0 0 

Northern SPP C1ilhness Geothermal 9.1 0.1 0 0 IPP 

Northern USPN Grand Coulee G14 105 11 3 • 12 

Northern USPN GrMd eou... G15 105 113 • 12 

No<1hern USPN GninciCouleiG18 105 113 • 12 

Northern USPN G,.nd Coulel G 17 105 113 • 12 

Northern USPN Grand Coulel G10 105 113 • 12 

Northern USPN Gr11nd Coulee G23 750 770 20 50 

Northern USPN Grand Cou1e1 G8 105 113 8 12 

Northern USPN Gtlind CouiMG7 105 113 • 12 

Northern USPN Gt"lnd Cou6M G8 105 113 • 12 

Northern USPN Gr"lndCouiMG8 105 113 • 12 

Northern USPN Rozo 7.3 13.1 6.3 4 

Northern USPN Gr..., Springs 1 12 +51-

N. Cal. CDWR S1n Luts 7 27 27 0 1 42 

N. Cal. COWR Hya01 ,., 141 0 18 18 

N. Cal. COWR Hyol2 132 132 0 17 17 

N. Cal. COWR Hvd3 138 141 3 21 21 

N.Cal. COWR 4 127 132 5 22 22 

N. C CDWR Hyot5 138 141 22 22 

Pag... ...rS 
ISLAND MEMBER I UNIT NAME 

N. Cal. COWR 1~6 

N. Cal. 

N."Cit CDWR IThermalilo 1 

CDWR Thermalito 2 

N. Cal. 

'N.Cal CDWR ITMnnalito 3 

CDWR Thennalito o4 

N. Cal 

N.Cai CDWR IThermalitoO.m 

MID Stone Drop 

N. Cal 

N'"Cal. MID 'Woodland NCPA~Sunset 

N. Cal. PG&E I Conn Coslll· 6 

N. Cal. PG&E !Contra Costa· 7 

N. Cal PG&E IDillblo~'!YO!I·1 

N. Cal. 

~ 

PG&E ltMblo Caron. 2 

PG&E Hunws Point · 2 

N. Cal. PG&E (Morro S.v • 1 

N. Cal. (PG&E 

N. Cal. IPG&E 

N. Cal IPG&E 

N. Cal. IPG&E 

f..~ C<!! !PG&E 

N. Cal IPG&E 

N. Cal !PG&E 

Mono S.y • 2 

Mono Bay. 3 

Morro9av -4 

Moss Und_!!lg_· 8 

Moss Landing · ? 

Pit1-1 Hydro 

Sunsel (SCE) • AIH CPS 

IlPPS 

,.., • .,,..., ,..,.,..,.,.,~,...v 

N Cal PG&E (AREAQF'S f IPP'S 

OIL-RECOVERY· AREA 

N. Cal PG&E laPS /IPP'S 

N. Cal. (PG&E 

N. Cal. (PG&E 

N. Cal. (SMUO 

N. Cal. ISMUO 

N. Cal. ISMUO 

N. Cal WAPA 

N. Cal IWAPA 

Southern lAPS 

Southern lAPS 

Southern lAPS 

Southern lAPS 

Southern lAPS 

Southern I APS 

Southern lAPS 

Southern lAPS 

Southern lAPS 

Southem lAPS 

CO-GENERA liON -

AREA Of'S /IPP'S 

t--tMns 1 Hvdro 

Cimino 1 

RobbsPMk 

Union Valley 

Folsom 

....... 

Chol~ 1 

Four Comer.~ 5 

Nl~1 

Navejo2 

Navajo 3 

Ocotillo GT2 

OcotiloST2 

Pak>Verde 1 

Palo Verde 3 

Wnt Phoenix GT 2 

Generation Tripped -August 10, 1996 

! BEFORE CAPACITY SPINNING 

I OUTP\JtJOST l.lJNIT DISTURBANCE AT THE TIMEI RESERVE 

IMWl _lMWl IMWl 

127 

1! 

27 

132 

~ 

35 

271 35 27 35 

0.22 0.22 

46.5 

2t E. 11 

~ ~ 

3301 330 

1076 

1088 

10 

36 

•• 333 

335 

738 

73€ 

13 

212 

138 

621 

1158 

10 

107 

762 

719 

700 

""' 

110 

1223 

1270 

20 

1082 

1093 

85 

163 

163 

338 

338 

739 

?3S 

56 

212 

138 

621 

1158 

75 

25 

46.7 

110 

7<0 

750 

150 

750 

55 

110 

1270 

1270 

55 

~ 

• 

~ 

10 

75 

127 

118 

•3 

71 

15 

43.7 

50 

35 

REACTIVE 

OUTPUT 

(MVAR) 

" 

0 .5 

121 

102 

.,. 

·20 

61 

52 

170 

- 1 

9 .4 

1 65 .

o.• 

... 

... 

25 

-5 

·2 

·2 

156 

12. 

Page 3 of 5 

REACTIVE 

CAPABILITY 

(MVAR) 

" .!! 

13 

.!! 

13 

15 

150 

150 

195 

1~ 

45 

70 

70 

168 

168 

340 

:;.;o 

27 

31 

, .. 

719 

100 

246 

19 

38 

.17 

., 

19 
Generation Tripped -August 10, 1996 

ou UT JUST UNIT 

BEFORE CAPACITY SPINNING REACTIVE REACTIVE 

DISTURBANCE AT THE TIME RESERVE OUTPUT CAPABIUTY 

ISLAND MEMBER UNTNAME (MN) (MN) (MN) 111/AA (MVAA. 

Southern CDWR Alamo 1 10 18 8 0 5 

Southern CDWR om c.n..., 1 42 60 18 0 35 

Southern CDWR Devil CMyon3 42 60 38 0 37 

Southem CDWR Devi1Canvon4 42 .. 38 0 37 

South•rn CDWR Si on1 8 II 3 0 NIA 

Southern CFE PJZ-Ulll a2 155 12 38 60 

Southern EPE Newm.nNo. 1 56 74 18 7 56 

Southern EPE RioG...ndeNo. S 108 1.00 32 II .. Southern FARM Animn 1 3 3 0 

Southern FARM -2 3 3 0 

Southe<n GLEN Grrnon~ 14 .. 30 5 20 

Southe<n GLEN Gf'llvsonf5 II .. 33 5 20 

Southern LDWP Ho...-3 1.00 230 30 

Southern LDWP lnlennountain1 539 539 0 

Southem LDWP Mohlve 2 ISO ISO 0 

Southern LDWP S-3 220 220 0 

Southern MWD Co<ono ... 2.8 1.5 

Southern MWD Covot.Cree« I 3.1 1.8 

Southern MWD 

·- 12 23.9 12 

Southern MWD Foothill1 &2 8.8 9.1 4.8 

Southern MWO 

..... _ 4.5 4.9 3.3 

Southern MWD 

- u 7.9 

Southern MWD RedMourain 4.5 5.9 

Southern MWD S1n Dim.s 8.4 9.9 

Southern MWO 5 lwdiC.~n 6.2 8.6 

Southem MWD Ternnc~~l 2.1 2.8 1.8 

Southem MWD Venke 4.4 10.1 

Southem MWO Yort. Uncki 4.3 5.1 

Soul hem NEVP ClllrktO 85 85 0 36 60 

SO<them NEVP Clark!5 .. 60 0 36 

"" Southom NEVP 

""'"'" .. .. 0 36 

"" South em NEVP Clllrtt9 85 85 0 38 80 

Southern NEVP IMoiavo2 111 Ill 0 

"'' Southern NEVP Ou•lifrina FIIC.IIities 305 305 0 84 lOS 

Soulhem NEVP Sun PNk3 70 70 0 35 

"" Southern NEVP SunP•II:.t 70 70 0 35 

"" Southe!m OXGC Olc:bow Geothermal 53 53 0 8 30 

Southern SCE ChinllAke 93 93 0 

Southern SCE "'- 36 38 0 

Southern SCE ElwanOI.t 318 320 2 1.00 

Southern SCE !- 48 48 0 

Southern SCE 

-- 91 91 0 

Southern SCE 

- 36 38 0 

Soul hem SCE Mohovo2 842 790 48 350 

~· SCE Ormond Beech 2 689 750 .. .... Page .. .~t 5 
ISLAND 

SOUthern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

Southern 

MEMBER 

~ 

SCE 

SCE 

SCE 

SCE 

SCE 

SDGE 

SDGE 

SDGE 

SDGE 

SRP 

SRP 

SRP 

SRP 

SRP 

SRP 

TEP 

TEP 

TEP 

UNIT NAME 

"""-

Pop,...., 

s~ 

Te,_ 

Westwlnd-Sawest 

Encin11 5 

EnciNI.C 

NaYIII Tr.lning Center QF 

Yuma Cog.n Assoc. OF 

~UIFR.3 

Co<onodo 2 

............ , ~ 

MormonFiat2 

StewalrtMount.in 

Irvington 2 

~ 

~~-2 

Southern iTiD iHickmllh PH li 

Southern I TID I Hickmlln PH 12 

Southern lWALC lDavil Unit No.2 

Southern IWALC !Hoover N-2 

Southern IWALC l HOO\Ief N-3 

Southern lWALC 

Southern IWAMP 

Southern WAMP 

Southern WAMP 

Southern WAMP 

Southern WAMP 

Southern IWAMP 

Southern IWAUC 

Southern IWAUC 

Southern WAUC 

Southern WAUC 

Southern IWAUC 

Southern WAUC 

Southern WAUC 

TOTAL 

Hoover N-8 

Folsom Unit 1 

FobomUnit2 

Folsom Unit3 

Nimbus Unit1 

Stampede Unit 2 

Shasta Unit 2 

Glen C.nyon 1 

Glen Canyon 2 

Glen Canyon4 

Glen C.nyon 5 

Glen C.nyon 6 

Glen C.nyon 7 

Glen C.nyoo 8 

Generation Tripped- August 10, 1996 

OUTPUT JUST UNIT 

201 20 

.. 51 -45 

1221 122 

381 38 

205 33lJ 

118 300 

22 22 

511 51 

17<41 181 

3571 350 

101 10 

10 11 

391 -47 13 13 

30 82 

332 385 

3811 385 

0.5 

0.5 

... 

100 

100 

0 (condensing) 

50 

~ 

50 

_!_ 

0.6 

120 

102 

135 

102 

135 

102 

135 

135 

0.5 

0.5 

51 

130 

130 

130 

50 

~ 

50 

0.65 

126 

167 

167 

1£ 

167 

167 

1£ 

167 

125 

182 

52 

53 

30 

30 

130 

65 

32 

~ 

32 

65 

B. 

32 

REACTIVE 

OUTPUT 

MVAA 

99 

53 

25 

28 

0.5 

1.9 

~ 

.. 

-2 

12 

10 

.!Q 

5 

10 

REACTIVE 

CAPABILITY 

MVAA 

170 

130 

76 

210 

~ 

7.5 

27 

82 

210 

210 

+18,-18 

+30, -30 

+30, -30 

+30, -30 

63 

~ 

63 

73 

55 

45 

~ 

45 

55 

~ 

45 

Note: Shared units are reported by plant operator and are not Included in the data of other participants. 

Page 5 of 5 
167 

Appendix 3 

Transmission Lines Tripped 
TRANSMISSION LINES TRIPPED-- AUGUS

NOMINAL 

LINE NAME VOLTAGE TIME REASON FOR TRIP 

(KV) TRIPPED 

MEMBER 

Northern California Island 

CDWR OR-TH-TMI1 230 1555 frre 

OR-TM 12 230 1550 qround rela 

OR-TH TM#3 230 1557 fire 

NCPA Midway-Sunset 230 1548 disturbance 

PG&E Round Mountain 12-Malin 500 1548:52:00 voltaae collapse 

Round Mountain t:1-Malin 500 1548:52:00 voltaoe collaose 

Round Moutain-Malin Total voltaoe collaose 

Midwav-Vincent tl-1 500 1548:54:00 volt90e collaDse 

Midwav-Vincent 11'2 500 1548:54:00 voltaae collaDse 

Midwa -Vincent 13 500 1548:54 00 volt90e collaDse 

Midway-Vincent 

Drum-Summit #1 115 1548 out-of-step 

Drum-Summit 12 115 1548 out-of-step 

Spaulding-Summit 60 1548 out-of-step 

Southern Island 

APS Four Corners-Pinto 345 1548 54415 out-of-step 

Nava·o-Westwina 500 1548 58 803 out-of-steo 

Nava·o-Westwina 500 1548:54:825 out of-steD 

Nava·o-McCuUouah 500 1548:58:496 fault 

North Gila-lmoerial Valley 500 1548:54:576 out-of-steo 

Palo Verde-Devers 500 1548 54 639 out of step 

FARM Glade-OuranQo 115 1549:20 RAS 

Shiprock-Hood Mesa 115 1549:20 RAS 

Shi rock-Animas 115 1549:20 RAS 

Ber in-GaUeaos 115 1549 20 RAS 

LDWP Nava·o-McCullough 500 1549 

Celilo-S lmar +/-500 DC 1549 

NEVP Harry Allen-Red Butte 345 1548:49.00 underfrequencv 

OXGC Oxbow Geothermal "T-Line" 220 1550:45 olant trio 

PEGT SorinQer-Bravo Dome 115-kV 115 1548 underfrequencv relav 

PNM SA-Blackwater 345 1549 04 00 hi h voltaGe 

SCE Vincent-Westwind-Wilderness 230 1549 00 00 underfr-;;-uen-;; 

'--- Midway-Vincen~ ~1- - 500 1548:55:00 out-of-steo 

Page 1 of 6 
TRANSMISSION LINES TRIPPED-- AUGUS

NOMINAL 

LINE NAME VOLTAGE TIME REASON FOR TRIP 

(KV) TRIPPED 

MEMBER 

Midway-Vincent 112 500 154855.00 out-of-step 

Midwa -Vincent #3 500 1548:35:00 out-of-step 

Palo Verde-Devers 500 154855:00 out-of-step 

Control-Silver Peak #A 55 1550 00:00 out-of-step 

Control-Silver Peak #8 55 1550:00:00 out-of-step 

SDGE North Gila-Imperial Valley 500 1548 out-of-step 

SRP Brand ow-Ward 230 1549:08 00 misoperation 

TNP Hidal a-Playas 115 15480000 underfreQuencv 

MD '11-lvanhoe 115 1549 52:00 underfrequency 

WALC Pinnacle Peak-Flagstaff #1 345 154948 xfrmr overexcitation 

Pinnacle Peak-Flagstaff tr2 345 1549:48 xfrmr overexcitation 

WAMP Folsom-Roseville 230 1548:57 00 overvoltage 

WAUC Hesperus-Waterftow 345 15:48:54.936 out-of-step 

Shi rock-Lost Canyon 230 1548 54.703 out-of-step 

Glade Tap-Durango 115 15 4854.938 out-of-step 

Glen Canvon-Si!1urd 230 154853.708 out-of-step 

Glen Canyon-Flagstaff #1 and #2 345 1549 45.271 xfrmr overexcitation 

Northern Island 

BCHA 5L94 CBK-LGN 525 1554 undervoltage 

786L NTL-Coleman 138 1554 overcurrent 

777L NTL-LLC 138 1554 overcurrent 

5L31 MSA-OMR 525 1549 overvoltage 

BPA Big Eddy-Ostrander 1 500 8/10 1406 tree: tree 

John Dav-Marion 1 500 8/10 1452 unknown: unknown 

power system 

condition: forced 

Marion-Lane 1 500 8/10 1452 (confi uration) 

Keeler-Allston 1 500 8/10 1542 tree: tree 

power system 

condition: forced 

Pearl-Keeler 1 500 8/10 1542 (confi uration) 

Ross-Lexington 1 230 8/10 1547 tree:tree growth 

PageL nf 6 
TRANSMISSION LINES TRIPPED-- AUGUS

NOMINAL 1 

TIME I 

LINE NAME I VOLTAGE I TRIPPED REASON FOR TRI

(KV) 

MEMBER I I 

power system 

condition: instability 

Bucklel Grizzl~ 1 I sool 8/10 1S48 I zone 1 

power system 

condition: RAS 

Chief Josee:h PH-Chief Joseeh Sub 1 I 23ol 8/10 1s•8 1 initialed 

power system 

condition: RAS 

Chief Joseeh PH-Chief Joseeh Sub 2 I 23~ 8/10 1S48 1 initiated 

power system 

condition· RAS 

Chief Joseph PH-Chief Joseph Sub 5 50 8110 15-48 initiated 

power system 

Ca ~a n Jack-Malin ~ sec eJ~c ,54e condition: instabi!:! 

power system 

~ 

Captain Jack-Malin 2 (PacifiCorp) 8/10 1548 condition: instability 

power S)lstem 

condition: instability 

(SFT -

Captain Jack-Meridian 1 (PACW) soo 8/10 1S48 underimpedance) 

power system 

Grizzl -Capt1in Jack 1 soc 8/10 1S48 condition: instabilit 

power system 

Grizzl -Malin 2 (PG&E) soo 8/10 1548 condition: instabilit 

power system 

Grizzl -Round Butte 1 (PG&E) soo 8/10 1548 condition: instabilit 

Grizzly-Ponderosa Section of Grizzly- power system 

Summer Lalte 1 soo 8110 1S48 condition: instabi lit 

power system 

John Day-Grizzl 1 soc 8110 1S48 condition: instabiht 

power system 

John Day-Grizzly 2 soc 8/10 1S48 condition: instabilit 

Page 3 of 6 
TRANSMISSION LINES TRIPPED-- AUGUS

NOMINAL I 

LINE NAME I VOLTAGE TIME I 

(KV) TRIPPED REASON FOR TRI

MEMBER I I 

Captain Jack-Oiinda 1 (WAPA) I sool 8/10 1548 I co:d~~:~:~~~~:~itit 

power system 

condition: instability 

Malin- Round Mountain 1 (WAPA) I saal 8/10 1548 I under:!:~ance) 

power system 

condition: instability 

(SFT- 

Malin-Round Mountain 2 (PACW) 500 8/10 1548 underimpedance) 

power system 

500 8110 1548 condition: instabiht 

115 8110 1548 

power system 

Ponderosa-Grizzl 5001230 8/10 1548 condition: instabilit 

Ponderosa-Summer Lake Section of 

Grizzl -Summer Lake 1 500 8/10 1548 material failure 

power system 

Summer Lake-Malin 1 PACW 500 8/10 1548 condition: instabilit 

power system 

condition: forced 

Converter 1 Ta~ of Celilo-S:tlmar PL 3 I 1oool s11o 1548 1 1 configuration l 

power system 

condition: forced 

Valve Grou~ 1 Ta~ of Celilo-S:tlmar PL 3 I 1oool 811o 1548 I ( confiQuration 1 

Pag• of6 
TRANSMISSION LINES TRIPPED-- AUGUS

I 

NOMINAL 

LINE NAME VOLTAGE TIME REASON FOR TRIP 

(KV) TRIPPED 

MEMBER 

power system 

condition: forced 

Valve Group 7 Tao of Celilo-Svlmar PL 3 1000 8/10 1548 confiquration 

power system 

condition: forced 

(configuration)- via 

La Pine-ChiiQuin 1 (PACW) 230 8/10 1550 KFalls trip 

power system 

condition: forced 

La Pine-Fort Rock 1 115 8/10 1550 (conf1 uration) 

power system 

condition: forced 

La Pine 1-Midstate E Coop 115 8/10 1550 (configuration) 

Redmond 1 -Prineville PP&L 115 8/10 1550 zone 3- three phas

Redmond 1-Pilot Butte PP&L 230 8/10 1550 CBTI 

power system 

condition: forced 

La Pine 1-Pilot Butte E PACW) 230 8/10 1550 (configuration) 

power system 

condition: forced 

Valve Group 2 Tap of Cetito-Svlmar PL 4 1000 8/10 1604 (confi uration) 

power system 

condition: forced 

Valve Group 8 Tap of Ce!ilo-Sylmar PL 4 1000 8/10 1606 (confi uration) 

power system 

condition: forced 

Converter 2 Tap of Celilo-Svlmar PL 4 1000 8/10 1607 (confi uration) 

power system 

condition: forced I Vaive Group 2 Tap of Celiio-Svimar PL 4 1000 8/10 1608 ( confi uration' 

power system 

condition: forced 

Valve Group 6 Tap of Celilo-Svlmar PL 4 1000 8/10 1609 ( confi uration) 

Page 5 of 6 
TRANSMISSION LINES TRIPPED-- AUGU

NOMINAL 

LINE NAME VOLTAGE TIME REASON FOR TR

(KV) TRIPPED 

MEMBER 

power system 

condition: forced 

Valve Group 3 Tap of Celilo-S lmar PL 3 1000 8110 1610 (configuration) 

power system 

condition: forced 

Valve Group 4 Tap of Celilo-S lmar PL 4 1000 8/10 1610 (confiquration) 

power system 

condition: forced 

Valve Group 5 Tap of Celilo-S lmar PL 3 1000 8/10 1610 {configuration) 

transfer trip from 

IPC Midpoint-Summer Lake 500 1548:53.412 Summer Lake 

SPP North Truckee-Summit #133 line 120 1548:55 out-of-step 

California-Summit !¥:102 line 120 1548:55 out-of-step 

Truckee-Tahoe Donner 11607 line 60 1548:55 out-of-step related 

Silver Peak-Control #501 line 55 1548:56 out-of-step related 

Silver Peak-Control #502 line 55 1548:56 out-of-step related 

TSGT Hesperus-Waterflow at Hesperus 345 1548:54.934 out-of-step 

Hesperus-Montrose, both ends 345 1548:54.962 zone 1 

TTRASfrom 

Montrose-Nucla at Montrose 115 1549:49 Montrose 

Lost Canyon-Shiprock at Lost Canvon 230 1549 50 out-of-step 

Lost Canvon-C02 at Lost Canvon 115 1549 56 zone 1 

USPN Green Sprinas/Lone Pine 69 1548 PAST N/A 

TAUC 1201l-TransAitlto BCHvdro 500 1654 undervaltage 

Natal-TransAHa 138-kV Tie 138 1654 avercurrent 

'--- 9l913l1913L-Sundance to Mitaue 240 1659 RAS overvoltage 

Page n 'lf 6 
174 

Appendix 4 

Abnormal Conditions 
NCPA 

PG&E 

SMUD 

175 

Northern California Island 

ABNORMAL SYSTEM CONDITIONS 

1. Abnormal system conditions that may have contributed to the occurrence or impact of 

the disturbance, especially reactive devices that were out of service or limited in 

response capability. 

Abnormal Conditions 

None 

Vaca-Oixon-Tesla 500-kV line series capacitor bank segment #2 at Vaca-Dixon 0/S 

Los Banos-Midway t:1 ~kV line series capacitor bank segment #1 at Los Banos 0/S 

Midway-Vincent ;111 5CXJ-kV line series capacrtor bank segment #11 at Midway 0/S 

Midway-Vincent 13 500-kV line series capacitor bank segment #1 at Midway 0/S 

None 

2. Abnormal system conditions that adversely impacted system restoration. 

Abnormal Conditions 

NCPA None 

PG&E None 

SMUD None 

Page 1 of 4 

Appendix 4 
APS 

BURB 

EPE 

GLEN 

OXGC 

PNM 

SDGE 

TNP 

WALC 

APS 

BURB 

EPE 

GLEN 

NEVP 

OXGC 

PASA 

PNM 

SDGE 

SRP 

TNP 

WALC 

176 

Southern Island 

ABNORMAL SYSTEM CONDITIONS 

1. Abnormal system conditions that may have contributed to the occurrence or impact of 

the disturbance, espec1ally reactive devices that were out of service or limited in 

response capability. 

None 

None 

None 

None 

None 

None 

Abnormal Conditions 

SOG&E's electric system was operating normally pri,:Jr to the disturbance 

Normal 

None 

2. Abnormal system conditions that adversely impac:ted system restoration. 

ECC building UPS failed 

EMS down from 1548 to 1652 

Frequency decay 60 Hz to 58.55 Hz 

Frequency remained below 59 Hz for 20 minutes. 

None 

None 

Abnormal Conditions 

The phase angle was swinging on the Harry Allen line and would not allow us to 

close back with Utah until LDWP closed the NavaJo-McCullough line 

None 

System unstable for approximately one hour and could not restore load. 

Breaker and control problems prevented normal automatic restoration after frequency recovered 

3,258 additional MW/min. of outage time and 17,369 custom.,. affected by 1hese problems 

None 

Loss of 10 RTUs at distribution substations. loss of the EMS tnree times, slow EMS response time 

Appendix 4 

Loss of EMS computers at 1556:18; apparentty due to alarm management problem. This limited response to manual controls 

Not applicable 

Page 2 of 4 
BCHA 

csu 

DOPD 

IPC 

MPC 

PSPL 

SCL 

SNPD 

TCL 

TSGT 

WALM 

WAUM 

WWPC 

177 

Northern Island 

ABNORMAL SYSTEM CONDITIONS 

1. Abnormal system conditions that may have contributed to the occurrence or impact of 

the disturbance, especially reactiVe devices that were out of service or limited in 

response capability. 

Abnormal Conditions 

Reactive equipment out of service for maintenance 

Burrard G2 automatic voltage regulator (+140/·90 MVAR) 

lNG 2RX2 on forced outage (-125 MVAR) 

GM Shrum 500-kV line shunt reactor (-122 MVAR) 

Williston 500-kV line shunt reactor (-122 MVAR) 

Reactive equipment out of service (but available for manual switching) for voltage support during 

high exports 

Kelly Lake, two 500-kV shunt reacto"' (-122 MVAR each) 

Nicola, two 500-kV shunl reacto"' (-122 MVAR each) 

Ashton Cr, one 500-kV shunt reactor (-122 MVAR) 

MDN (autcrvar off), 230-kV shunt reactor (-200 MVAR) 

CW and CY cap banks off line for repair, 102.5 MVAR 

None 

Brady 5012 synchronous condenser out of service for control rebuild (+72 to -31 MVAr) 

Copperfield (Oxbo¥1-Lolo line) series capacitors out. 

Brownlee Unit *4 off for annual maintenance (1 00 MVA) 

Lower Salmon Unit t:1 off for installation of automation equipment (21 MVA) 

Hunt shunt capacitor C 131 out to repair lightning damage to air break swttch (54 MVAr) 

CJ Strike UM 11 off for maintenance (30 MVA) 

MPC system was normal 

Transmission lines out of service before system event: 

Shuffleton·Lakeside 115--kV out of service for road work relocation 

Fairwood·Cedar Falls 115--kV out of service for maintenance 

Whidbey·Greenbank 12 115--kV out of service for road work relocation 

Bremerton· SPA Kltsap (Navy line) 11S-kV out of service due to Nave work 

Sedro Woolley tap--SPA Monroe/Snohomish 2JO..kV out for line rebuild 

None 

None 

None 

None 

SCAOA failed at time of initial spike. Restored SCAOA at 1644. No breakers in abnormal position. 

None 

None 

2. Abnormal system condftions that adversely Impacted system restoration. 

Abnormal Conditions 

BCHA LGN S 3522 CB failed to close to synch with 

CBK on 5L94 at 1623. Second try at 1629 successfully 

tied TAUC to BCHA 

DOPD None 

EWEB Alarms overloaded the EMCS to the point it became dysfunctionaL Generators esperienced wide swings in 

Mlf!land MVR before stabilizing 

PSPL COfl'l'1lllf11:s from Dispatcher on shift during system event: 

#1 Poor communtcation between companies!!! Didn't find out the North-South ties had tripped 

for sure for about one hour. Key contacts didn't communicate because, they didn't 

know they should , didn't have the time, or a~lled the "MOng companies. 

12 Someone took control of the Mid-Columbia generation which would not allow AGC to work. 

Generation could not be towered manUIIIIy even by the dispatchers in charge of the plants. 

13 After running schedules for 45 minutes some companies declared the schedule 0 (zero) for 

all hour. This is not real time operation and doesn't reflect the true state of the system. Example: 

!fat 1745 PAST a 300 MW schedule is cut it should show225 M'W for the hour natO (zero). 

Companies in the middle of a market transaction did not need to be called at first. In and out 

wheeling can be adjusted after the fact since it is just an accounting function and doesn't effect 

generation/deviation. 

14 The sheer number of schedules makes orderty emergency response intolerable. The company 

in the middle of energy transfers got notified and was expected to call the energy provider 

when it is not that company's responsibility. 

SNPD Nothing to report 

TSGT None 

WAUM None 

WWPC None 

Page 3 of 4 

Appendix 4 
178 

Alberta Island 

ABNORMAL SYSTEM CONDITIONS 

1. Abnormal system conditions that may have contributed to the occurrence or impact of 

the disturbance, especially reactive devices that were out of service or limited in 

response capability. 

Abnormal Conditions 

TAUC None 

2. Abnormal system conditions that adversely impacted system restoration 

Abnormal Conditions 

TAUC None 

Page 4 of 4 

Appendix 4 
179 

Appendix 5 

Sequence of Events 
AUGUST 10, 1196 WSCC DISTURBANCE-SEQUENCE 

EVENT_~ I MEMBE~_I TIME (PAST) I EVE~T 

0 t REVISED 9J5J96.--.090

---,---r- --~ . . . -i·.- ·---· - PREDISTURBANCEEVEN

.,-- . ••. A. 14:01:29.B2t 500-KV BIG EDDY4!TRANDER 1LG FAULT, RELAYEDSP:-uN

. . _ __ TRIP: TREE IN LINE 

j

ffiE ,. 01 29 879 2~~ MCLOUGLIN·BIG EDDY TRIP AT.MCLO. " .... " __ ·LiN ONLY, 

___ --- BPA 14:06:33.528 soo-KV BIG EDDY-OSTRANDER 1LG FAULT_;' RELAYED SPRE

______ i ... _ _ _____ AFT~~~-~~"!_~~R; RELAY MISCOOROINATION-FIXED 

7 BPA 14:06:39.769 500-KV BIG EDDY-OSTRANDER 1LG FAULT RE-lAYED 3 POL

3 ePA -- 14:03:35.878 ~~::E~L:!EBA:f~~ :~~ io~~~;~~~AJ~~N-FIXED 

.ffi. E.. 14:06_:33~ 2:»..KV MC-LOU.GLIN --eiGE.ooY TRtP .. AT'. MCLO·u· GuN.· o. N. L v.: 

I 

6 1BPA 14:06:35 KEELER SVC ALARM 

8 BPA 1.4:13:08.370- GRizi:iYRfACTOR30PEN 

.--" BPA 14:52:37.156 500-KV JOHN DAY-MARioN 1lG FAULT; TRIPS TO LoCKouT

MARION DUE TO PCB OUT OF SERVICE AT MARION, TREE IN 

1_Q ~--~ful_A __ +~:52:37_271 11 BPA 14:56:43.953 JOHN DAY-MARION MANUAL TEST FROM jQH-NDA_'f.:..B;&,-0 

. iCHIEF-:JOEBRAKE LBO A~25 CiPERATEBYRELAY--

12 IBPA loe:-«.2 - - -~CAPTA"t'NjACK.:OLINDALiNE-FAULT DETeCTOR PU:...iJNKNC

--t~~icc.oo:'C~"'.-s;;K OP"'E-E;~"'~-R"'K;.,_~EEco~"'~-;~R~"~~-~'OC-~G"'l"'~~"-~K:

MAINTENANCE. UNSUCCESSFUL TEST_ AT 15:44:01.292,_1_~~

15 42 37 ECC REPORTS COLUMBIA BASIN VOLTAGE LOVV 

15 45 - --- PoE-REPORTS THEiR 2JOSYsTEM AROUND RIVERGATE IS 

1547 - - GRAN0coulef~E-2HOURS 

f-- e§i} -- ~; ~i2s :~;:~~N~S; ~~~~gRf1~;e~INf RELAYS ~0 ZO~ MAL

--1547 38 ~~:~ ~~eL~ ~~~t;s:;:~~~d~~=i. DROPS PACIFICo

SWIFT TREE IN LINE FAULT STARTED SMALL FIRE 

-~ IBPA 15 47 36 MCNARY TRIPS 117 MN (2 UNITS 

1

------- 21 --~ ~L__ 1~~--~~-Frr_J~I~~~!~~{!_!!!II_!I~ _ 

___ 2'? 1~!'.1\ _ 15.47.4<4 ~CNARY TRIPS 75 MW (1 UNIT) 

__ _J~------ I -------

13 BPA 15:42:03.131 

--;~- -- -t~1f ~~::i::~ ~:T~~ ;::a~EUN~~) 5975HZ PG&E DROPS F-70 CUSTOM 

25 115:47:55___ isvsTEMFREQuENCY59~To58.-7HZ. PG&E DROPS lJNDE

i !THROUGH6 

NORTHERN ISLAND LOAD LOST 422 MW FIRMn271N.T, 6. ~

GRAND COULEE G14- G18 TRIP 525 MW GEN DROP_. _ 

GRAND COULEE 023 --750 MW GEN DROP - - 

GRANO COULEE G6-G9TR!P -420 MW GEN DROP ---

GREENSPRINGS6MWLOS50FSTATIONSERVICE 

810-5EQ4.XLS Page 1 of 14 
AUGUST 10, 1tH WSCC DISTURBANCE-SEQUENCE 

EVENT tl MEMBER TIME (PAST) ' EVENT 

-- ~~::: =~r:~R R~~~~ r6 ~~ FI~MW·15Q,txXJCUSTOM

31 lJSPN -- ~- GREEN SPRINGS/LONE PINE 69-KV LINE TRIP 

.34 . 0 15:48 NORTHERN ISLAND LOAD LOST 320 MW; 3,517CUSTOM~

~ 35 L[:MiP __ 1S:48 LOAD SHED -1320 MW G 58.5 _ -

-·· _1~:~ ____ tsOun-iERN J.§!:ANO LOAD LOST 1328 MW;_~~~,7qc:J ~~T_Q

T -450 MW, 154 txXJ CUSTOM

I PAC 

I 38 f'GiE --- CAPTAIN JACK-OLINOA500-KV LINE RELJ 

-~ 39~ -- PG&E 15:48:5-4.7 oRUM:SuMMI'T 1ft -1 15-KV LINE TRiPPED --""'----

- ·- -40 - PG&e ---- oRuM.suMMifG--:i1s-KV LINE TRIPPED (NORTHERNCAL.iF

_ ~~:54.7 NEVADA - ---

41 PG&E 15:48 N. CALIFORNIA LOAD LOST - 21,705 MW FIRM; 600 I NT; 494 

42 PSNM 15:48 ----- - - -- ------ -- - -- - - - -- - --- 

~~ ---f 48 - - - -- SOUTHERN ISLAND LOAD LOST"'=" 21"MW~ CUSTOM

=- :u~~=~:! :s.~~~~~~::~~~~:~~A:~~~

15:48 I ALBERTA I 1tW RUNBACK VW 

r>LOST -7611 - - V INT; 

115 ~ 

~ 

~ 

~ 

·~ 

JoAviS-tiM 

ESWING 

frN; TRIP BY GEN VOLTAGE A

.. --

~ =~ ~A~ 15:48 TRI-STATEC&TNUCL.AUNITS1 2 ~4RELAYEDVVH\bE 

6:!?-----~- 15:48:08 MCNARYT~ 

d--~~ --__ 1!i:48:21.659 MAliN 500--KV SHUNT C~P GROUP 3 PCB --4182 AUTOMATIC 

62 SDGE 15:-48:22 NORTH GILA·IMPERIAL VAllEY 500-KV LINE RELAYED 

J SDGE 15:48:30 GAS TURBINE UNOERFREQUENCY START 

~ ·-· . ~~ 8 ~~~~~~~ :~~ t~~~~~;~~~~~"~~"'T~R~AS~-A00"'"'T

If--- ~ 

1S:48:.a.812 CAPTAIN JACK POWER RATE RELAY EXPORT TRANSMIT 

: HARRY ALLEN--REO BUnE 346--KV LINE TRIP -OUT -OF -SJ!

TOGGLING VOLTAGE ALARMS AU OVER BPA SYSTEM 

TABlE MT. MSC IS CLOSED BREAKER 672 suCCE.SSFUli Y. 

F

-·- -~[1!! Q~I MATEl 430 ~~t'!<JMINAL) 

~ __ =~~~~ !~ =~.~~' ?,l ~.~f! .. ocm ... ;.~~...<:>~ H!~ l~J

74 {SQG.KV MALIN SHUNT CAP GRP 41NSE~TED BY CELI LO RAS 

810-SEQ.._ Page 14 
AUGUST 10, 1198 WSCC DISTURBANCE-SEQUENCE 

EVENT # I MEMBER TIME(PAST) EVENT 

15:48:52_487 500-KV FORT ROCK SERIES CAPS INSERTED BY CEULO RA

BUCKLEY ~If~ Q~IZZl Y tfN£!.R~ 3-~!fASE <WtrffiN Z

DITTMER RECEIVES lOS BANOS POWER RATE RELAY SIGN

CEULQ OC-RASBiOSE~NOOWAlGORITHIM L

MAl.IN; GRlZZLY...SUMMER LAKE ~ AlliN AT 15 48 52 ~20 

FOUR CORNERS EASTERN RAS SEP. SIGNAL REC\1·- ·- 

MALIN-RDMT2 SWITCH-INTO-FAULT OP~~~t1S (UNDERIMP

MAliN-RDMT 1 SWITCH-IHTO-FAUL T OP ~!!~TES (UNOERIM

:~ ~= ~~~~~~T:.KA':~~~~~~

IS OPENED. MALIN VOLTAGE PRIOR TO TfUP APPROX. 170 K

FAULTST~(;;QFIREf.51PUI . --

~N DAY-GRIZZLY N0.1 OPEN AT JOHN DAY; OP~!!_~J:.G

RAS-ACA DYNAMIC BRAKE ALGORITHIM OPERATE 

+''"';-;>;>£ .... £ ~fliD MOUNTAIN 1 UNE .Of.EN AT~.... ---

_115:41:52.141 ~ JOHN DAY..QIUZZL~i!9: 2 OPEN AT GR#h'f; ~~AT JOH

r • ., .......... .,._... CHIEF JOE. BRAKE INSERT A595 

CHIEF JOe PH 6 OPEN 

CAPTAJN JACK-MERIOIAN OPEN AT.CAPT-AiN JACK (PCB -"

. .!..~ l"r" 115:48_ :52.74!__ CHIEF JOE BR~KE LBO A-425 gr.;fiATE BY_~. LAY 

101 _WAMP 15:48:52.744 OliNDA RECEIVES SPA RAS Lll 

. ..... -~ -- 15 48~ f00R CORNERS RAS SIGNAL RECEMD -

15:41:52.767 .•.. OUNOA TERMINAL: CAPTAIN JACK OPEN V\A RAS (COl NCiN 

. CALIFORNIA) 

~::::;:~:~~~ ·-- ~~~J~~=YG~:eo~:NA!~~:TH~~ ~=~~~~B 

02.714 - - --·

~~ :'::~ ~:~::;: ~~! ~~~~~~~XC::H~~~~~~~~~30

B1D..SEQ4.XLS 

15:48:52.793 

15:48:52.8CXI 

15:48:52.800 

15:48:52.805 

15:48:52.807 

- 

FJ.ge3of 14 
AUGUST 10, 1891 WSCC DISTURBANCE-SEQUENCE 

I ct I TIUII: ID.II.CTI EVENT 

EVENT# MEMBE .• ····-~···-·· 

113 PG&E 

114 BPA 

~ APS 

116 PG&E 

117 SPA 

116 ~---

1-19 BPA 

~ SPA 

121 SPA 

15:48:52.815 

15:48:52.824 

15:48:52.831 

15:48:52.838 

15:48:52.855 

15:48:152.878 

1~~48:52.812 

15:48:152.915 

15:48:52.919 

MALIN-ROUND MT.~ 500-KV LINE OPEN ENDED, 3 POLE, AT 

OBSERVED AT ROUND MT. TERMINAL INITIALLY 

MALIN PCB -4011 TRIP (CAPJ2/SOBUS); DROPS PACIFICORP 

~~~~~~~EDR:::~:~: ~~;:~. ~~;:::VC,LE","AT'"M;;cA;oL

IS NO RELAY ACTIVITY OBSERVED AT ROUND MT. TERMINA

RAS·ACB_._!_trrf__BTIE SEPARATION, BRAKE, ALGORITHIM OP

GRIZZLY ..SUMMER LAKE OPEN AT GRIZZLY; OPEN AT SUMM

ROUND BUTTE GENERATION REMAINS CONNECTED TO GR

GRJZZLY TRIPS AT 15:50:27.690 

MALIN 230-KV PCB 1L 1 TRIP (PACW 5001230 Bt<) TRIP 

MAUN·WARNER 230-KV CPCB 1L 12 OPEN) 

RAS-ACA SENDS GEN DROP TO RRPH,-CHJO, WLPH WAPH

~ ti::J:~:::J.£.ZJOI IMALINSHUNTCAPSGROUPS3&40PEN --- 15:48:53 ROUND MT.·TABLE MT.II2 500-KV UNE OPEN ENDED AT RO

-- - :=:~--'""· -·· MALIN-SUMMER LAKE OPENS AT SUMMER LAKE; SEPERAT

I 122 ' SPA ~- ·- ----- 123- PG&E 

124 PAC 

r··--·- 125-

126-

127 

-~ 129 

130 

~ 132 

133 

~ 35 

- 136 . 

137 

t---H~- -~,:w141 -142-

------,--;i3 

~ 7 

810-SEQ. 

TERMINAL OPENS AT 53.251. 500-KV BUS AT MALIN, SUMM

DEAD. ALL 500 BREAKERS AT MALIN AND SUMMER LAKE A

t,pc--- 1.... ....... ...... I MIDPOINT -SUMMER LAKE TRIP AT MIDPOINT (TRANSFER TR

SPA 15:48:53.500 CELILO 500 AC CONVERTER 1 & 2 DC [)()II.JN TO 0 MW 

MPC 15:48:53.122 

~-- 15:48:53.641 

COLSTRIP 3 & 4 RELAYED OFF LINE 

COLSTRIP 1 RELAYED OFF LINE 

15:48:53.708 

TSGT 15:48:54 

~~~ LDWP -~ 15:48:54.300 

APS 15:48:54.415 

~~ 15:48:54.4315 

SRP 15:48:54.578 

SCEISRP 15:48:54.822 

SCE - 15:48:54.700 

SCE 15:48:54.700 

WAUC 15:48:54.703 

PG&E 15:48:54.765 

·~ 

GLEN CANYON-SIGURD 230-KV LINE RELAYED BY OUT -OF-S

HESPERUS-MONTROSE 3-45-KV LINE TRIPPED AT MONTROS

CEULO 230 AC CONVERTER 3 & 4 DC OOWN TO 290 MW 

SYLMAR CONVERTER STATION- REACTIVE POW"ER CONTR

FOUR CORNER-PINTO ~LINE TRIPPED BY OUT ~-STE

WEST PHOENIX GT2 TRIP BY UF 

NORTH GILA-WPERIAL VALLEY TRIP 

PALO VERDE DEVERS 500 TRIP AT PALO VERDE; Jl:j)_E~-~

MIOWAY·VINCENT 1 TRIP OUT -OF-STEP 

MIDWAY-VJNCENT 2 Tftjp OUT -OF-STEP 

SHIPROCK-LOST CANYON 230-KV LINE RELAYED. OUT -OF-S

MIDWAY-VINCENT 113 500-KV UNE TRIPPED DUE TO VOLTAG

CAUFORNIA NON SEPARATED FROM SOUTHERN CALIFORN

NAVAJO~NKOPI500 TRIP AT NAVAJO; AT MOENKOPI~ 

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P•ge 14 
194 

PREPARED STATEMENT OF RANDALL W. HARDY 

Introduction 

Chairman Doolittle and Members of the Subcommittee, I am pleased to 

appear before you to discuss the August 10 power outage. I am Randall W. 

Hardy, Administrator of the Bonneville Power Administration (Bonneville). 

Today, I will discuss the reliability of the western transmission grid and 

Bonneville's reliability record. I will then briefly describe the events 

surrounding the August 10 outage, and the remedial actions taken to 

immediately restore the system. I will close with a summary of the 

institutional and technical changes we have made on our own and in 

conjunction with other utility groups to prevent a recurrence of the outage, 

and to assure dependable delivery of power as the electric utility industry is 

opened to competition . 

Reliability and the Western Interconnected System 

The Western Interconnection, which includes Alberta and British Columbia in 

Canada, provides power to a land area equivalent in size to more than half 

the contiguous land area of the United States. It serves a population of 59 

million, or 24 percent of the United States' population . The grid has a larger 

service territory with lower population than the rest of the United States. 

That means it holds more circuit miles of transmission line than other parts 

of the United States . 

Over the last four years of record, only one-third of the outages in North 

America have taken place among utilities belonging to the Western Systems 

Coordinating Council (WSCC). Of the 1 04 major system events in the last 

four years of record, 35 took place on the western grid and eight took place 
195 

on Bonneville's system. Customers lost power in about half (or 16) of the 

events on the western grid. 

Other than July 2 and August 10, there have been four outages directly 

related to high-voltage intertie transmission lines linking the Northwest to 

California in the last five years. One was caused by the Northridge 

earthquake in December 1994. Only the August 10 outage was related to 

Bonneville. 

Bonneville, Pacific Gas & Electric (PG&E), Southern California Edison (SCE), 

the U.S. Bureau of Reclamation (Bureau), Portland General Electric (PGE), 

PacifiCorp, and the City of Los Angeles built the direct-current (DC) and the 

first two alternating-current (AC) intertie lines in the late 1960s for less than 

$500 million. Upgrades to the DC line and a third AC line have since been 

added for about $1.2 billion. The four legs of the intertie can transmit up to 

7.9 million kilowatts, nearly enough power to serve the entire Los Angeles 

area. 

Since the completion of the first intertie nearly 30 years ago, these lines 

have been saving southern California consumers an average of $1 million a 

day by taking advantage of the diversities of the electrical use and 

generation of the interconnected regions on the west coast. For example, 

- the intertie transports inexpensive surplus Columbia River hydropower to 

California in the spring and summer, displacing electricity generated in 

plants fired by fossil fuels. In the first 10 years alone, the kilowatt-hours 

shipped south on the intertie displaced the equivalent of about 203 million 

barrels of oil. Power sold north on the intertie during the winter and offpeak hours helps California utilities operate powerplants at an optimum 

uniform level. 

2 
196 

The exchange of electricity between the Northwest and California has also 

provided environmental benefits , starting w ith a landmark 1991 agreement. 

These exchanges have cut emissions ;n the Los Angeles Basin during the 

smoggiest times of the year, the equivalent of taking some 5,000 cars off 

the highways. In exchange, the Northwest is able to provide better flows 

for Columbia River salmon when the exchange power is returned from 

California. 

Along with financial and environmental benefits, the intertie has improved 

reliability for interconnected systems . It enables utilities to help each other 

during system emergencies and to solve daily operating problems . 

Including the intertie, the U.S. has invested some $4.2 billion to build the 

region's high-voltage transmission system . For nearly 60 years, Bonneville's 

charter as a Federal agency was to electrify the Northwest and make many 

of the investments that were necessary to create an integrated system. 

Bonneville provided the redundant capacity, and the computers, 

communications and protection controls so the Northwest power and 

transmission systems could be coordinated as if they were one utility, 

leading to economies of scale for all Northwest utilities. Bonneville offered 

other utilities access to the Federal transmission system without charging an 

interconnection fee . One third of our transmission business volume is in 

providing wheeling for others. Bonneville's Federal transmission system 

includes 15,000 circuit miles of transmission line. Bonneville provides 

nearly half of the electricity consumed in the Pacific Northwest and about 

four-fifths of the region 's high voltage transmission capacity. 

The provision of rel iable transmission service has been a priority second only 

to safety at Bonneville . By developing the Pacific Northwest electric grid on 

a single utility basis, regional electric utilities are better able to coordinate 

3 
197 

maintenance and operation. This has given the Federal Columbia River 

Power System a history of exemplary reliability . 

Independent reviewers have consistently given Bonneville high marks . 

According to a May 1996 WSCC audit, Bonneville is a well-operated system, 

that consistently operates its system in compliance with all North American 

Electric Reliability Council (NERC) and WSCC reliability criteria. Despite the 

August outage, Bonneville made NERC's honor roll for achieving 96.8 

percent compliance with its generation control reliability criteria. 

Bonneville's reliability criteria have been more stringent than other entities in 

its service territory because Bonneville provides the backbone upon which 

other utilities built their systems. As measured by nationally recognized 

standards, Bonneville's record for outage frequency and duration has ranked 

better than the national average for the past decade. 

This reliable and interconnected system has served the region well. It 

withstood' cold snaps in February 1989 and December 1990 without any 

outages. In February 1996, Portland and parts of western Oregon and 

Washington were faced with the threat of massive flooding. Working with 

the Army Corps of Engineers, Bonneville used the grid to greatly reduce the 

threat by pulling back on hydro generation and pulling in other sources of 

power. 

Bonneville continuously reassesses its systems to make improvements. 

Bonneville works cooperatively with other regional utilities to avoid problems 

before they happen. For example, Bonneville worked with four utilities in 

the Seattle area to mitigate a potential voltage collapse. Using system 

studies and growth projections, planners and engineers increased energy 

4 
198 

conservation, installed voltage support equipment and built a new 

substation to neutralize a situation before a problem could occur. 

Bonneville has assisted Los Angeles by helping restore Sylmar after fires and 

an earthquake damaged the facility between 1993 and 1995. Sylmar is the 

southern terminus for the DC intertie. It is jointly owned by the Los Angeles 

Department of Water & Power (LADWP), Southern California Edison (SCE), 

and a number of other utilities . We provided technical and engineering 

expertise, project management assistance, innovative high voltage field 

testing expertise and spare parts for Sylmar. We sent crews, equipment, 

highly specialized diagnostics and high-voltage test equipment in response 

to emergency requests from LADWP. Despite short turn-around and 

hazardous site locations, work was completed without incident, and the 

DC intertie was restored to full capacity in a stairstep plan, months ahead of 

initial estimates. Support continues today with a wide range of technical 

exchanges, spare part supplies, and joi'lt operations and maintenance 

shared among Bonneville, LADWP and SCE. 

Bonneville and the utilities_ in Seattle and Los Angeles can· sometimes be 

seen as competitors in the power business market. Yet in both cases, all 

who were involved demonstrated a truE! team spirit. 

We need to foster that same spirit as we seek remedies for the outages we 

experienced this summer. The outages of July 2 and 3 that started in Idaho 

show that weak links, wherever they exist, can lead to complications for all 

who depend on the west coast transmission system . They illustrate the 

need for a better understanding of the voltage support problem among all 

utilities taking part in the western grid. Bonneville used the WSCC report on 

the July 2 and 3 outages to examine and improve its system. It actively 

implemented the recommendations from the report . For example , 

5 
199 

monitoring was instituted on a 500-kilovolt power line feeding the intertie, 

as well as the intertie itself, to make sure simultaneous transfers were 

accomplished at safe and prudent levels. Power flowing on the intertie 

was reduced. Bonneville and other utilities formed a group to study 

conditions leading to voltage collapse on the intertie. Bonneville 

incorporated voltage collapse scenarios into its dispatcher training. The 

August 1 0 intertie outage occurred despite restrictions set after the July 2 

outage. 

Events Precipitating the August 1 0 Outage 

On August 10 we saw some of the most unusual circumstances the region 

has seen in two decades. High water in the Columbia River system 

combined with triple-digit temperatures to create unprecedented demand for 

inexpensive hydropower. 

At the time of the disturbance, the AC intertie was carrying 4217 

megawatts, well below the 4500 megawatts limit. A little over half, or 

about 2400 megawatts, were coming from Bonneville. One third was 

coming from other intertie owners, PGE and PacifiCorp. The remainder was 

being transferred for other Northwest utilities. 

Let me correct a misunderstanding. Some have asserted that Bonneville 

may have not cut schedules once the initial problems started on the system 

in order to gain commercially. Nothing could be further from the truth. Our 

system dispatchers are not given commercial information on power or 

transmission transactions being carried out on the grid, whether on August 

10 or any other time. The transmission system operators' focus is on 

operating the physical system for safe and reliable service. They would not 

and could not have operated on August 1 0 to maximize Bonneville's 

6 
200 

commercial gain at the expense of reliability, because our operators' 

responsibil~ty is only to dispatch. Information about commercial operations 

reside with scheduling, a separate function that does not control 

transmission system operations. 

At 2:06p.m., hot weather caused Bonneville's Big Eddy-Ostrander 500, 

kilovolt line to sag into a tree . Bonneville immediately notified PGE through 

the normal channels . About 45 minutes later, the same happened to the 

John Day-Marion 500-kilovolt line. The outage of these two east-west lines . was not considered critical at the time because the lines were carrying light 

loads. About al) hour later, the heavily loaded Allston-Keeler 500-kilovolt 

line sagged into a tree and relayed. Notification of this line outage was 

transmitted to PG&E by Bonneville over the new WSCC inter-utility data 

computer system . These events resulted in a loss of voltage support, 

particularly in North-Central Oregon, at the head of the intertie. Initially 

generation at McNary Dam sought to offset this problem by increasing 

voltage support. But within five minutes, all generating units at the Corps 

of Engineers' (Corps) McNary Dam shut down, dropping nearly 700 

megawatts in 70 seconds. Growing oscillations then caused the tripping of 

the AC intertie lines. It is critical to understand that while the initiating 

event for both the August 1 0 and July 2 outages was transmission line 

contact with trees, it appears that the more substantive problem is the lack 

of voltage support, due to the configuration of the power system . 

In the following days, the loss of generating units due to the outage and 

record-setting loads in California created an emergency situation . In 

response to the emergency, California Governor Wilson directed state 

agencies to reduce energy use. PG&E employed all generators available, 

curtailed power to large industries and farms, and called for voluntary 

restrictions at homes and businesses. 

7 
201 

Bonneville worked with the Corps, the National Marine Fisheries Service and 

others to gain a temporary waiver of spill requirements for endangered 

salmon at The Dalles Dam. A run of endangered fall Chinook salmon was 

migrating downstream. The region's dams had heavy demands to meet 

Northwest power needs during the heat wave. Bonneville was able to gain 

the support and cooperation needed to support a declaration of emergency 

for California, shift the timing as well as volume of spills for endangered 

salmon, and request and obtain increased power generation at The Dalles 

Dam by 700 megawatts to provide stable power down the intertie. The 

Dalles was chosen because it is nearest the northern end of the intertie and 

would reduce stress on the transmission system . This agreement meant 

generating more power at four other dams, releasing more water for salmon 

right after the emergency and extending the length of time water would be 

spilled for fish - all at a cost of more than $400,000. 

Without these quick actions, portions of California faced the threat of 

radditional widespread power outages with the potential to threaten the 

health and safety of millions of customers. PG&E and the California Public 

Utility Commission expressed great appreciation for these efforts . Western 

utilities and suppliers have a responsibility to each other as partners in an 

interconnected grid. Each system should do all it can minimize the impacts 

of separation and take actions to ensure the fastest possible restoration . 

Immediately after the outage occurred, Bonneville began working with other 

utilities to restore the system . As a precaution, the intertie was limited to 

only two-thirds of its scheduling capacity. Bonneville set interim operating 

procedures for the intertie with PG&E and SCE. Together, we determined 

what outages should be reported, how quickly they should be reported, how 

to ensure safe operating conditions and limits, and how to resolve issues. 

8 
202 

Along with other Northwest utilities, we set conservative operating limits on 

transmission paths along the western corridor. Crews installed additional 

remedial action schemes on the AC intertie at the California-Oregon border 

to activate voltage support more quickly . To date, Bonneville has foregone 

about $2 million in transmission revenues due to these restrictions on the 

intertie. 

We have reviewed our vegetation management program and developed a 

plan for improvement. We are currer.tly implementing the plan's 46 

recommendations which will improve all aspects of our vegetation 

management from planning to implementation . 

Bonneville immediately expanded its vegetation management program . 

Within days, more than 2, 700 trees were pruned or cut. Brush was 

removed from about 1,200 acres. Nearly 2,300 miles of transmission line 

were patrolled by foot and by air. Over the past two years, budgets to 

control vegetation under power lines lllcreased from $2.5 million to $3 

million. Budgets will increase again, by another $1 .5 million over the next 

three years. 

The Corps and Bonneville quickly reviewed equipment at McNary Dam. 

Bonneville transmission system operators factored in limitations for the 

Corps' generating plants on the mainstem ·of the Columbia to eliminate 

voltage stability risks . Dispatchers heightened their awareness of system 

vulnerabilities and improved communi cations with neighboring utilities. 

Changes and Innovations to Safeguard the Transmission System 

In the three months since the outage, Bonneville has put in motion a number 

of technical and institutional changes to further strengthen the system . 

9 
203 

These changes both fortify the system against such unusual events as the 

conditions experienced on August 10, and safeguard against new demands 

placed on the grid by changes in the industry and new constraints on 

Columbia River hydro generation. We have ten initiatives underway to 

prevent or limit system disturbances and respond more quickly to potential 

emergencies . 

Fourteen industry experts are taking part in a "blue ribbon panel" to review 

a system-wide study of voltage support on the Bonneville transmission grid. 

The study is a collaboration between Bonneville and other west coast 

utilities to identify any deficiencies in voltage support and determine 

corrective measures . It will review the power system, including generators 

and generator controls, for voltage and dynamic stability. Nominations for 

the panel came from NERC, WSCC, EPRI and several western utilities . The 

panel will receive study results and recommendations on November 20, 

provide an evaluation by December 6, and conclude its work by January 31, 

1997. 

Etfective October 1, Bonneville combined dispatchers, system operation and 

technical staff to create a single transmission planning and operations staff. 

This will improv~ coordination between short term or operational study 

efforts, long term or planning studies, and the real-time dispatch of the 

power system . We also integrated naturai resource and realty specialists 

with transmission line maintenance staff. This will strengthen right-of-way 

maintenance and vegetation management. In addition, responsibility for 

overall right-of-way maintenance has been specifically assigned to 

transmission line maintenance foremen. 

Our vice presidents in transmission are meeting weekly with me, the Deputy 

Administrator, Chief Operating Officer, senior transmission managers, and 

10 
204 

manager for Federal Hydro Projects to receive briefings and set direction on 

reliability issues: 

We plan to expand the wide-area measurement system (WAMS} . This 

technology was developed in cooperation between Bonneville, the 

Department of Energy, Western Area Power Administration, the Bureau of 

Reclamation, the Pacific Northwest National Laboratory, and thH Electric 

Power Research Institute (EPRI} . It can bring us the measured information 

needed to model and control the power system's dynamic performance. It 

uses global positioning satellites to precisely synchronize the measurement 

of power system quantities over very large distances. WAMS was 

instrumental in diagnosing the August 10 disturbance . We need to add 

other areas of the western system to WAMS to gain the breadth of view 

needed to improve system reliability. 

We are also improving power system operational and dispatcher screening 

tools for assessing system capabilities and limitations, which should reduce 

the potential for outages. We are finding ways to better identify and plan 

for a variety of load, generation and transfer conditions. 

We have added ·new scenarios, system problems, resolution techniques and 

emergency coordination actions to dispatcher training . Dispatchers have 

long had training on voltage collapse scenarios; now they have a simulation 

of the August 10 disturbance. We will clarify dispatching procedures to 

facilitate emergency schedule readjustments and coordination among control 

centers. Operators are now more sensitive to voltage fluctuations and what 

they need to do to respond. 

We worked with the Corps to modify exciter controls on the generators at 

McNary Dam . Technical experts from the WSCC agree that the 

II 
205 

modifications are appropriate to ensure the generators do not trip during 

disturbances, except to prevent damage to equipment. Tests confirm the 

results. Consistent with WSCC recommendations, we have taken 

immediate steps to improve communication and coordination with the 

Corps, instigating joint meetings every two weeks on system design and 

planning . We will work with groups who own other power generators to 

retune power system stabilizers as a way to offset undamped system 

oscillations . We will work with the other utilities who own the DC intertie 

to reactivate modulators that can help dampen system oscillations. We will 

identify and put in place other automatic controls to prevent loss of the 

intertie. 

Operators automatically will notify PG&E and other WSCC utilities of all 

outages, both planned and unplanned, on 500-kilovolt and key 230-kilovolt 

lines . Dispatchers will call if any outage would reduce the operating 

capacity of the intertie. They will warn PG&E dispatchers about major 

storms moving through the Northwest, with a notice if the storm forced 

lines out of service . 

Overall policy recommendations 

Bonneville is taking actions to implement all the recommendations in the 

WSCC preliminary report applicable to Bonneville, as well as taking actions 

that go beyond the recommendations in the report. We believe these ' 

actions will significantly reduce, but not eliminate, the potential for another 

separation of the Northwest-Southwest interties . In fact, it was recognized 

at the time the interties were constructed that the potential for separation 

cannot be eliminated. As the WSCC report notes, there are circumstances 

in the Southwest which may have adversely affected the extent of the 

outage. The WSCC report identifies the need for additional study and action 

12 

3 6 - 069 - 9 7 - 8 
206 

to resolve these issues. Because we cannot guarantee that another intertie 

separation will not occur in the future, we urge the Southwest parties to 

implement the recommendations of the WSCC report in order to minimize 

the impact of any future disturbance. 

Meanwhile, changes in the industry are placing new demands on the 

transmission grid. Open transmission access is producing new or 

accentuated flow patterns across the entire transmission network. While 

complying with deregulation initiatives to separate power marketing from 

transmission, Bonneville is encouraging all utilities to: 

• Require all control area operators to join NERC and regional reliability 

councils . 

• Better coordinate generation and transmission operations where critical 

for ensuring system reliability . 

• Establish criteria for new power gEmerators to make sure they meet the 

reliability needs of the transmission system. 

Establish standards for formal certification for transmission and generator 

control and protection equipment w make sure equipment is set and 

operated according to WSCC guidelines, and is depicted correctly in 

power system network studies . 

Investigate the formation of stronH regional grid operators that have 

adequate responsibility and authority for transmission .reliability. Having 

I 

one grid operator increases the re!)ion's ability to overview the entire 

transmission system and its interconnections efficiently. Bonneville 

believes that this independent grid operator (IGO) should not only plan, 

price and schedule, it should also direct transmission control and 

dispatch, with incentives for both efficiency and reliability . A grid 

operator must be alert to the types of changes deregulation will bring . It 

must: be responsive to the needs of the public it serves, and operate for 

13 
207 

the common good. A Northwest IGO must be a reliable partner for 

California . 

Conclusion 

Bonneville is taking actions to implement all the recommendations in the 

WSCC preliminary report applicable to Bonneville, as well as taking actions 

that go beyond the recommendations in the report. We believe these 

actions will significantly reduce, but not eliminate, the potential for another 

separation of the Northwest-Southwest interties . We have been intensively 

seeking out the ·causes of the problem and believe we are on a path to 

resolving the issues which are at the core of this outage. 

As events move forward, Bonneville will do everything in its power to 

identify reliability issues and take corrective actions, and to work with other 

utilities to restore confidence in the west coast transmission system. We 

believe vigilance in these matters will ensure that we will deliver safe and 

reliable transmission service well into the future as we have in the past. 

Mr. Chairman, this concludes my statement . .I would be pleased to address 

any questions from the Committee. 

14 
208 

PREPARED STATEMENT OF JOHN E. VELEHRADSKY 

Mr. Chairman and distinguished members of the Subcommittee, I am John 

Velehradsky, Director of Engineering and Technical Services, North Pacific Division, 

U.S. Army Corps of Engineers. I am pleased to be here today representing Mr. Martin 

Lancaster, the Assistant Secretary of Army for Civil Works. In my current position, I am 

responsible for technical direction of the planning, design, construction, operations, 

readiness and real estate activities associated with Corps of Engineers water resource 

management activities in the Columbia River basin. In my testimony, I will briefly 

describe the Corps hydroelectric generation facilities in the Northwest and how they are 

managed. I will address the outage of August 10,1996, as it relates to the Corps 

operations and management. I will also explain the actions that the Corps is taking 

since the incident to help this multi-jurisdictional power system respond to such 

abnormal occurrences. 

The Corps of Engineers operates and maintains 21 hydroelectric projects in the 

Western Systems Coordinating Council (WSCC) service area. The WSCC is an 

association of 91 power systems in 14 western States, two Canadian Provinces, and 

part of one Mexican State that promotes electric system reliability and provides a forum 

for coordinating the operating and planning activities of its members. The maximum 

generation capacity at the 21 Corps dams is 12,937 Megawatts which represents 

approximately 24.5% of the hydropower capacity in the Northwest. One of these 21 

Corps projects is at the McNary Dam located about 292 miles upstream from the mouth 

of the Columbia River and near Umatilla, Oregon. As a result of the voltage depression 

in the system on August 10, the generators at McNary tripped off in order to protect the 

equipment. 

Power generated at the Corps projects is marketed and transmitted to customers 

by another Federal agency, the Bonneville Power Administration. Many factors affect 

how these dams and reservoirs are managed to produce power. The Columbia River 

Treaty regulates how water and power are traded between the U.S. and Canada, and 

the Pacific Northwest Coordination Agreement specifies how power is produced and 

shared among regional utilities. There are also many non-power uses for the Columbia 

River that affect how the Corps facilities are operated. The dams and reservoirs that 

the Corps operates are multipurpose projects that balance the demand for hydropower 

with other legitimate uses for the water including navigation, flood control, water supply, 

recreation, and fish passage. All of these factors are considered in the development of 

operation plans for the reservoirs in the Columbia River system. 

The Columbia River and its tributaries are home to salmon and sturgeon that 

annually migrate the rivers moving past the series of dams that have been constructed 

in their path. During critical fish passage periods, from April through August, water 

control and hydropower operations are managed to avoid jeopardy to salmon and 

sturgeon that are protected under the Endangered Species Act, and to mitigate impacts 

to other important fish and wildlife resources. To facilitate fish migration, extra releases 
209 

of water are allowed to bypass the generators at carefully timed intervals. This activity 

requires close coordination among the Corps water managers, Bonneville Power 

·Administration's dispatchers, and power plant operators. 

Following the power disturbance that occurred on August 10, 1996, the WSCC 

released findings concerning the July 2-3 and August 10, 1996, disturbances. The 

Council's findings as they relate to Corps operations are paraphrased as follows: 

The power system experienced depressed transmission system voltage prior to McNary 

tripping; 

The McNary generators tripped off sooner than would have been expected ba~ed on 

power system studies. 

The level of generator voltage (reactive) support available in the Hanford area was 

inadequate to prevent system collapse; and 

The North American Electric Reliability Council recommendations in "Survey of Voltage 

Collapse Phenomena" need to be implemented. 

After this incident, the Corps performed its own assessment of the performance 

of the generation equipment. We found that the McNary units performed as originally 

commissioned by the manufacturer. During the period of depressed transmission 

system voltage just prior to the system shutting down, McNary provided voltage support 

above machine design capacity for about five minutes. Eventually, however, this was 

insufficient to overcome the losses elsewhere in the system and the generators tripped 

off. 

The 13 McNary generating units shut down in a self-protective mode in response 

to the major voltage depressions that were occurring in the transmission lines. The 

automatic tripping of the McNary generators is a safety measure that protects the 

equipment during such abnormal fluctuations in voltage. 

While we found that equipment performance was generally consistent with our 

expectations, we also learned that the power system voltage in the McNary area was 

depressed below any level anticipated placing a higher than expected demand on the 

McNary units. As a result, the McNary units tripped off sooner than we had expected. 

We do not know that, had the units stayed on line a few minutes longer, the ultimate 

result of the incident would have been any different. 

Although the tripping of the McNary units was only one of the problems 

associated with the outage, we have identified a few improvements we can make that 

will help us respond if we are faced with a similar event in the future. These measures 

2 
210 

respond to the WSCC's findings and recommendations and our program for improving 

the availability of generation and equipment reliability. We are making some 

adjustments to the McNary and other units that will improve their response to an 

impending voltage collapse in the system. We are improving coordination among 

Bonneville Power Administration, WSCC, and the Corps to assure that everyone 

involved is aware of the capability of the Corps equipment in operation. 

These measures that the Corps is taking will not by themselves prevent a future 

incident.like the one we just experienced. But they will assure that the Corps operated 

and maintained facilities are more responsive to the power system's future 

requirements. Together with steps that can be taken by other players in this power 

network, the whole system will be more reliable. 

Mr. Chairman, this completes my testimony. I would be happy to respond to 

questions. 

3 
211 

PREPARED STATEMENT OF P. GREGORY C ONLO.r..· 

RECOMMENDATIONS FOR IMPROVING ELECTRIC 

SYSTEM RELIABILITY IN THE WEST 

Statement of the Ho n . P. Gregory Conlon, 

President, California Public Utilities Commission 

before the Water and Power Resources Subcommittee 

of the U.S. House of Representatives Committee on Resources concerning "Issues and Recommendations 

Concerning the August 10, 1996 Bonneville/Western 

U.S . Power Outage . " 

Los Angeles, California 

November 7, 1996 

As recently documented in the Western Systems Coo rdinating 

Council's (WSCC) Report of October 18, 1996, at 3:48p . m. on Saturday, August 10, 1996, in the western United States, Canada, 

and Mexico, 7 . 5 million customers lost their electric service for 

up to nine hours. As explained in the WSCC Report, a combination 

of problems, not just a si'ngle incident, precipitated the 

cascading grid outage. In the hours before the disturbance, 

three 500-kV lines were forced out of service. Two of the outages 

(Big Eddy-Ostrander, John Day-Marion) were caused by flashovers 

(trees coming into contact with power lines as the lines sagged 

under heavy transfers of power and over 100 - degree ambient 

temperatures); the other outage (Ma~:ion-Lane) resulted from an out-of-service circuit breaker. These substantial events occurred when the Allston-Rainer line was out - of-service due to 

degraded capability of line hardware. And more generally other 

lines and equipment were out-of-service or at reduced capability 

due to maintenance activity . At the same time, the Dalles 

hydroelectric facility was only operating five of 22 generators 

due to fish mitigation requirements . Although operating near its limits, the system perfo rmed 

adequately up to this point . Then came the proverbial straw that 

broke the camel's back, when Bonneville Power Administration 

(BPA) evidently was operating in violation of WSCC reliability 

criteria and a single contingency triggered the subsequent 

cascading outage. (WSCC Report, p. 8, Conclusion 1.) 

At 3:42p.m., the heavily loaded Keeler- Allston 500-kV line 

sagged too close to a tree and flashed over. From this point 

additional lines were overloaded . The outage might have been 

mitigated if not for the failure of other equipment. At 3:47 

p . m. the St . Johns-Merwin line tripped due to a faulty relay, 

contributing to the loading of other lines. Another flashover 

(the fifth that day) caused an outage and loss of 207 MW of 

generation from the Swift plant, increasing the need for voltage 

support from the McNary generating units which were already at their maximum. The McNary units began tripping (due to excitation equipment problems), and voltage oscillations began . These oscillations were a major factor in the Pacific Intertie 

separation and subsequent islanding of the WSCC system . Although no firm estimate exists of the total cost o f the 

outage, it is not improbable that it was on the order of tens-ofmillions of dollars, both in lost revex;me t o ele.ctric utilities 
212 

and, more importantly, in real costs associated with the loss of 

service and the attendant consequences including closure of 

commercial establishments, congestion and accidents on roadways, 

and loss of production capabilities. Consequences ranged from 

lost sales to the increased risk of injury and death. 

Following the outage, the Pacific Intertie's North to South 

rating was lowered from 4, 750 l'IW to 3, 200 MW. The WSCC is 

currently reviewing methods for reliably operating the Intertie at higher limits. This issue needs to be resolved in a timely 

manner before next spring. California has suffered already from not being able to draw fully on Pacific Northwest imports during 

the late part of this past summer. The situation needs to be 

rectified before the spring of 1997. 

The WSSC should be thanked for providing an excellent report on the August 10, 1996 outage. The WSCC and its committees are continuing that investigation and we look forward to additional 

information and conclusions. The WSCC Report shows that much has 

been done to ensure the reliability of the interconnected western grid. But the outage -- and what we have learned from it -- is 

evidence of the remaining work that needs to be done to avoid recurrence of cascading power outages on the western grid. 

The WSCC Report summarizes by stating, " ... the disturbance 

could have been avoided, in all likelihood, if contingency plans 

had been adopted to mitigate the effects of the Keeler-Allston 

500-kV line outage. Inadequat•~ tree-trimming practices, 

operating studies, and instructions to dispatchers also played a 

significant role in the disturbance." (WSCC Report, p. 6). 

Probably adding to the problem was the failure of critical 

equipment (relays, conductor hardware, generation control) that 

also played a major role in both the outage and the time needed to restore service. The WSCC Report also found that some of the 

system was operating in suboptimal condition. For example, some power system stabilizers were not operating due to plant control 

problems (WSCC Report, p. 32). 

The WSCC Report also concluded: 

"The July 2 and August 10 disturbances 

emphasized the need for timeliness in the 

disturbance report recommendation resolution 

process. Examples of recommendations made as a result of previous disturbances that 

continue to be factors in more recent disturbances include the recommendations 

relating to controlled islanding, criteria 

for multiple contingencies, criteria for 

relay failures, and coordination of 

underfrequency load shedding." (WSCC Report, 

p. 27, Conclusion 32.) 

This particular conclusion highlights the need for enforceable 

reliability standards. We cannot afford a system where problems, once identified, continue to exist, creating costly outage after 

outage. The reliability of the transmission system is only as 

strong as its weakest link. 

It is clear that the western grid is very robust and can tolerate a wide range of significant disturbances. It is also 

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213 

clear that the grid is vulnerable . On August lOth, after a series of transmission outages and generation failures, the 

system collapsed. Existing mitigation measures and protective 

equipment failed to stem the collapse of the system. Reliability must be increased through a variety of steps recommended below. 

Analysis of the August lOth disturbance is ongoing. However, we can draw the following conclusions from the WSCC's r e cent 

report on the outage: 

First, maintenance of the existing grid is of extreme importance and has not been adequately addressed by many of the 

transmission- owning utilities. The report details the many 

instances of inadequate tree-trimming practices and equipment 

failure. 

Second, operating standards evidently are not adequate . The 

WSCC Report notes that BPA had been "unknowingly" operating in 

violation of the WSCC Minimum Operating Reliability Criteria 

before the August lOth outage . (WSCC Report, p. 4.) For 

example, there was a July 13, 1996, incident that included a flashover to a tree on the Pearl-Keeler 500-kV line, an incident 

that also had included failure on the Allston-St.Helens 115-kV 

Line due to the failure of degraded conductor hardware. Although 

the incident did not lead to a cascading outage" ... it should 

have served as a warning prior to the August 10 outage and led to further technical analysis" (WSCC Report, p. 4). 

Third, communication and coordination both between control area operators and within control areas were apparently 

inadequate . (WSCC Report, p . 14, Conclusion 8, p . 20, Conclusion 

17, and p . 25, Conclusion 30.) · Information on the status of 

critical elements within the western grid must be communicated to all control area operators immediately following an outage and 

back-up communications systems must be set up to allow c ritical 

information to continue to be transferred in emergency 

conditions. 

BPA did not report the three 500-kV line outages experienced 

in the one-and-a-half hours prior to the disturbance to o the r control area operators (WSCC Report, p . 14 ). Such information, if 

communicated to other control area operators, may have allowed 

them to take mitigating actions that would have prevented the 

problem from getting· out of hand . 

There is evidence as well to suggest that communication and 

coordination within control areas could be improved. Rapid and 

effective responses from various generating entities is 

especially critical in situations like the August lOth 

disturbance. It is hoped that there will be enhanced 

communication and coordination between BPA (the control area operator) and the generator operators (Corp of Engineers and the 

Bureau of Reclamation) . Also, in many cases, utility data 

gathering systems and communication facilities with generation and transmission operators were disrupted and could not be used. 

(WSCC Report, p. 24, Conclusion 28.) 

Based on these findings, I make the following 

recommendations to maintain adequate reliability in the future 

and avoid repetition of cascading events like the ones precipitating the August lOth outage. 

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214 

RECOMMENDATIONS: 

1. Inspection, maintenance, and testing of transmission 

facilities should be strengthened. In California, I am personally recommending the implementation of periodic 

inspections by Commission staff of the 230·-kV and 500-kV 

system and reviews of utility line-patrolling and tree- trimming records. 

2. Operating procedures and training of operating personnel 

need to be reviewed and strengthened. Operators need to know how to·recognize critical conditions and what 

specific steps to take to preclude cascading outages. 

Systematic risk management must occur. Circumstances 

involving low probability of occurrence nevertheless need to be identified if there is a risk of significant 

regional consequences. 

3. Adequate communication procedures and redundant systems must be in place to assure communication between control area operators and entities within and outside of their 

control area. Information about the real time operation 

of the grid must be accessible. This may require 

additional dynamic monitoring devices. Procedures must be adopted that clearly identify what information must be 

shared and the method of transferring that information. 

4. I believe that system reliability requires enforceable 

standards and rules. As the electric utilities industry 

becomes more competitive, the need for enforceable 

standards will increase. To ensure compliance, violation 

of standards should trigger sanctions that outweigh any cost savings that can be gained by avoiding 

implementation of necessary standards. 

This was the second major outage due to cascading effects of 

the interconnected grid to occur this past summer. A third 

widespread outage may have been narrowly averted on July 3rd, 

1996, when operators at Idaho Power Company shed approximately 

600 MW of their own load when flashover occurred on the same transmission line as the previous day. This action was taken in 

response to problems that occurred on other systems. 

As competition increases, we cannot continue to count on voluntary actions by utilities in response to disturbances caused 

by third parties if those actions have adverse financial impacts on their shareholders or impact provision of service to their customers. Regional, mandatory standards should be established. 

There is a clear need to create mechanisms to impose penalties on entities that fail to operate within established standards. 

Violation of those standards should be subjected to enforceable 

sanctions. Effective penalties would need to exceed the cost of 

failure of compliance with t:t.e standards, or may otherwise be 

considered part of the cost of doing business. Users of the grid 

would need to be in compliance or face the consequences "'hen they 

are not. 

-4-
215 

State regulatory agencies have an important role to play. 

State commissions perform environmental review and set line 

construction standards, perform inspections, and enforce safety 

requirements. Reliability standards within each control area and 

utility are inexorably tied to inter-control area standards, such as those set by the WSCC. Each of these elements is 

intrinsically related to reliability and the physical 

transmission system. Tree-trimming, for example, involves 

reliability and safety concerns that cannot be separated . Flashovers affect both the reliability of the grid and public 

safety. We cannot afford to wait for yet another failure before we move to a system of mandatory compliance with regional 

reliability standards. As you know, California is a "three 

strikes and you're out" state. I firmly believe that we cannot afford another major outage, the third strike. 

State agencies acting in coordination with other states that are imposing standardized requirements, can inspect and test both 

the physical system (tree trimming, relays, maintenance) and also 

verify that grid users adhere to uniform operational and 

communication procedures . . I personally would recommend a region-wide Independent 

System Operator (ISO) as a natural vehicle for maintaining system 

reliability and setting and enforcing regional reliability 

standards. Perhaps in the not too distant future we may be 

operating the western grid under one ISO, in which case the 

entire responsibility for the grid operation and reliability will rest with one entity. In California, the recently enacted 

Assembly Bill 1890 provides that the ISO in California, once established, will play an integral part in creating and adopting 

reliability standards. As ISOs develop and assume control area operator functions, the number of control area operators will 

decrease, consolidating responsibility for system reliabilit'y. 

Eventually the entire western grid should be controlled by one ISO. 

While ISOs are developing, interim measures are necessary to enforce region-wide standards. The California Legislature has 

suggested the use of an interstate compact, where California will 

join other western states in an agreement requiring the region's 

electric utilities, both public and investor-owned, to adhere to 

enforceable standards and pro1ocols to protect the reliability of 

the region's electric supply . An interstate compact may 

1. On September 23, 1996, Governor Wilson signed Assembly Bill 

1890. A.B. 1890 addressed regional reliability concerns by 

including Section 359 : 

"It is the intent of the Legislature that California enter into a compact with western region states. That compact 

should require the publicly and investor-owned utilities 

located in those states that sell energy to California 

retail customers, to adhere to enforceable standards and 

protocols to protect the reliability of the interconnected 

regional transmission and distri~ution sy~tems." 

-5-
216 

require congressional approval as stipulated by Article 1, 

Section 10 of the United States Constitution. Because the 

participation of Canadian and Mexi can utilities are desirable, 

eventually an international treaty may be necessary as well. 

I have recently sent a letter to members of the Committee on Regional Power Cooperation (copy attached), asking them if they 

would work with California in establishing regional reliability 

standards through entering into a regional compact ·or some other 

vehicle for cooperation. Another possibility would be to coordinate the actions of the western states, Canadian, and 

Mexican regulatory agencies in an effort to enforce u ni versally 

applied standards and protocols. Each state or province, on its 

own, would require compliance· with uniform standards (such as those adopted by WSCC or NERC ) , and implement its own pro gram for 

enforcing those standards. Models for this type of action include 

the Western Interstate Energy Board or coordination of ratemaking 

for multistate utilities. An additional alternative would be to utilize t he existing 

regional reliability council (WSCC ) , to functionally perfo rm as an entity that both sets and enforces regional standards. For 

this to occur, at least four changes would need to be made in the 

existi ng WSCC structure: 

1 . Mandatory membership of all grid owners in the WSCC would 

need to be implemented; 

2. Participation of representatives from state and 

provincial regulatory agencies on an ex-officio basis at both WSCC and NERC would have to be provided. Because of 

the limited budgets of many of the agencies, membership 

should be provided without cost . The WSCC and NERC should 

pro-actively seek regulatory agency participation at all 

levels of the WSCC and NERC organizations . The WSCC 

recently has included the Utility Commissi ons of 

California, Oregon and New Mexico to bec ome ex - offi cio 

members of the WSCC ; 

3. The WSCC would need to implement enforceabl e standards 

that carry contractually required sanctions for non- compliance. Those sanctions, like state-imposed 

sanctions, would have to exceed the cost of a v oiding the 

standards to be effec tive. Methods to verify compliance 

would have to be implemented; and 

4 . The WSCC would need to increase its staff t o test and 

evaluate grid users' c ompliance with the standards. 

Finally, market mechanisms may provide opportunities t o efficiently increase grid reliability . One such mechanism is to unbundle ancillary services, specifically identifying vo ltage 

support as a separately priced service. There are many ways that 

voltage support can be provided: additional generators, 

capacitors, large synchronized electrical motors and de-watered 

hyd·roelectric generation . Separate pricing of voltage support 

should encourage exploration of cost-effective alternative 

methods for providing this important reliability service. 

-6-
217 

Moreover, once prices for unbundled services are identified, customers can choose service on an interruptible basis, knowing 

the market value of their choice . The system today primarily uses generation as the sole 

mechanism to provide for voltage support. Future market-driven 

options, on the other hand, can help ensure a more versatile and 

reliable grid with reliability functions being provided by customers as well as providers. 

Reliability is the responsibility of all, grid users, 

utilities, control area operators, reliability councils, state regulatory agencies, federal agencies, and even customers (as we move to an unbundled electric market) . As competition increases, 

it will provide both challenges and opportunities. We look 

forward to working with each of these groups to ensure an 

efficient and reliable electric system . 

Attachment 

- 7-
tf.~rryory Qlunlon PRESIDEN1. 

October 17, 1996 

~ 

WJ 

Jubltc ~tlittra Qlommiooion STATE o=- CAUFOI=<NIA 

505 VAN NESS AVENUE 

SAN FRANCISCO, CALIFORNIA 94102 

Dear Fellow Members of the Committee on Regional Power Cooperation: 

TEL:(4151 703·2440 

f"AX 1""15) 70.3·2532 

Assembly Bill (AB)1890, just signed by Governor Wilson, declares the Legislature's intent that 

California join the other western states in an interstate C0!11pact requiring the region's electric 

utilities, both public- and investor-owned, to adhere to enforceable standards and protocols to protect 

the reliability of the region's electric supply. Article 1, Section 10 of the US Constitution requires 

congressional approval of any interstate compacts. Thus, any compact that we develop may require 

federal legislation. Two months ago, the California Public Utilities Commission, with 

commissioners from several other states also attending, held an informal inquiry into the August 10 

blackout. We were all very concerned about the ability of the current voluntary system to maintain 

the reliability of the western region's electric grid. 

We are therefore inviting you to work together with us to develop solutions to any reliability 

problems that may exist. This work is trans--national, imofar as our electric systems are already 

substantially interconnected with those in Canada and Mexico. By committing itself to an inter-state 

compact, California has committed itself to a major and historic task, which will require sustained 

and coordinated effort by not only all of the western states, but Canada and Mexico as well. Indeed, 

the ultimate results of our efforts may well be an international treaty on regional electric 

coordination. 

Our Commission has already begun the dialogue necessary to pursue these regional goals. 

Commissioner Fessler has raised the issue in Mexico with Energy Secretary Heroles and the 

members of Mexico's Comision Reguladora Energia, as well as with Mr. Roland Prittle, Chairman 

of the Canadian National Energy Board. Canadian provinces are active in WRT A, and conversations 

with Canadian officials should be pursued actively at both the provincial and federal levels. It was 

the suggestion of the chairs of the State Cornnrissions of Arizona, New Mexico and California that 

WRT A actively seek out Mexican participation. At the same time as these initiatives have been 

pursued, we have begun to contact other state agencies and legislative staff within California. 

We also believe that there are a number of other steps that we could take to improve reliability, short 

of the adoption of an interstate compact or international treaty. One option may be to establish a 

group similar to the regional operating committee that currently oversees US West's 

telecommunications operations in the Western United States. Another option may be the adoption 
Committee on Regional Power Cooperation 

October 17, 1996 

Page Two 

219 

of a uniform electric reliability code, adopted by each jurisdiction. For example, that code 

might require conformance to standards set by the Western Systems Coordinating Council 

(WSCC). 

In this connection, we note that AB 1890 authorizes the Independent System Operator to seek 

authority from the Federal Energy Regulatory Commission to penalize transmission owners or 

operators that violate operational rules. Further, our Commission has already initiated a proceeding 

to set and enforce reliability standards for distribution systems and tree-trimming practices for some 

control areas. We already have set enforceable measures for system-wide reliability within some 

investor-owned control areas. 

Finally, as we work to make our system enforceable we must continue to make improvements in our 

current voluntary system. We are heartened by WSCC 's plans to appoint security coordinators, to 

provide them with information on the western system in real time, and to authorize them to order 

emergency responses by member utilities. We do wonder whether this effort will receive adequate 

resources to function fully, or whether additiomil effort would yield an additional level of security. 

In any case, appointing security coordinators alone may not be enough to prevent outages like the 

one many of us experienced August 10, which was caused in large part by multiple transmission line 

failures due in tum to inadequate tree trimming. Although WSCC has called upon members to 

review their tree-trimming practices, we are not sure that this is enough to guarantee a coordinated 

approach throughout the West; as the recent outages have shown, the system is no stronger than its 

weakest links. 

These observations suggest that we can improve reliability by taking systematic steps. First, our 

region, including Canadian provinces and Mexican st;tes, must evaluate the risks to the electricity 

system in a systematic way, considering that various combinations of extreme weather and other 

conditions, however unlikely, sometimes do occur. The WSCC and its member utilities have done 

considerable work in this area; but we wonder whether increased effort and international 

cooperation, along with the increased computing power now available, might yield additional 

insights. Second, we need to adopt cost-effective operation and maintenance standards that deal with 

these risks. Finally, we need to make sure that the region's institutions have the resources and 

mandates to find and publicize failure to follow these standards. 

Pursuing such voluntary measures will not only improve the reliability of the system while we work 

toward an interstate compact, but also make that compact far more efficient once we achieve it. 

We hope you find this prospect as exciting as we do. 
Committee on Regional Power Cooperation 

October 17, 1996 

Page Three 

220 

Given the importance and interest in system reliability you may wish to raise these issues with your 

Governor's Office when you return from this conference. This issue may also benefit from 

discussion at the next Governor's conference. 

Sincerely, 

!?4~~~-~ . P. GregOry onion 

Presir\t /J 

~.da.--te~ Daniel Wm. Fessler 

Coordinating Commissioner on 

Electric Restructuring 
221 

FOLLOW-UP ADDRESS/OUTLINE PAGE 

1. P. Gregory Conlon, President 

2. California Public Utilities Commission 

505 Van Ness Avenue, Room 5200 

San Francisco, CA 94102 

3. (415) 703-1175 (Telephone # of Johfi L., Scadding, Advisor) 

4. Topical Outline: 

I. What happened on August 10, 1996 

A. Flashovers 

B. Hardware failure 

C. Operational Errors 

II. It could have been avoided 

A. Contingency plans 

B. Adequate maintenance 

III.We have seen these problems in earlier disturbances 

A. They have not been resolved 

B. Enforcement needed 

IV. Four recommendations for increased reliability 

A. Increased maintenance 

B. Better operating standards 

C. Better communications and coordination 

D. Standards must be enforceable 

V. Methods for implementing enforceability 

A. Regional ISO 

B. Interstate compact 

C. Modified reliability council 

D. Market forces 
PREPARF::D STATEMENT OF RJ.;Nz D. JENNINGS 

Testimony before the Water and Power Resources Subcommittee of the 

U. S. House of Representatives Committee on Resources 

November 7, 1996 

Page 1 

First let me say that I approach this hearing with a certain sense of humility in 

trying to suggest improvements to a system that is so complex. A lot of people are 

doing a lot of things to resolve problems identified this summer. I am not an engineer 

or electric reliability expert, but I hope to bring a new perspective to the discussions of 

this summer's outages. 

The two major western power outages this summer on July 2-3,1996 and August 

10, 1996 have left us with an interesting risk management problem. We won't be able 

to completely eliminate the outages, but we can develop reasonable risk management 

strategies that will reduce the possibility and impacts of future outages. In order to 

address this risk management problem we need to look at six aspects. They are: 

• The need for more and better quality information 

• The need for credible commitments to reliability 

• The need for better communication among utilities and others 

• The need for a clear delineation of responsibilities 

• The need to develop better damage control 

• The need for participation by all appropriate parties in the development of risk 

management solutions. 

Let me take each of these aspects and discuss them in depth. 

First, the need for more information relates to our need to better understand the 

western integrated electric grid under a wide variety of possible operating conditions. 

Rather than merely looking at likely single contingency scenarios, known as N-1 

scenarios, we need to have WSCC and utilities look at models of multiple 

contingencies, known as N-2, N-3, etc.; scenarios. 

Second, we need to elicit credible commitments to reliability from all participants 

in the interconnected grid. This should start with mandatory membership in WSCC or, 

at least, mandatory requirements to meet WSCC's minimum reliability standards. A 

perfonmance bond could be required as a sign of credible commitment and could be 

attached in case of failure to comply with reliability criteria. 

Since the two major western power outages this summer in July and August, we 

have heard over and over again that the safeguards built into the western 

interconnected grid worked as designed. The system islanded, power plants were 

tripped to prevent equipment damage, and loads were shed to help stabilize the 

system, thereby avoiding a complete shutdown of all western power generation. Yes, it 
223 

Testimony before the Water and Power Resources Subcommittee of the 

U. S. House of Representatives Committee on Resources 

November 7, 1996 

Page 2 

appears that the protective mechanisms worked~ an irreversible problem started 

the blackout. While it is important to improve the system in ways that will limit the 

damage from a system outage, it is far more important to take steps to avoid the 

conditions which led to the start of the outage. 

This brings me to a major concern that we in Arizona have. If, in fact, the NERC 

and WSCC criteria and requirements are appropriate, there still is a major problem 

ensuring that those standards are enforced. Unless there are some credible penalties 

or sanctions applied to those who fail to meet the standards or shirk their 

responsibilities, we will have a reliability system that works in theory, but not in fact. 

Enforcement and penalties can be handled in a number of ways. First, WSCC and 

other regional reliability councils could take on the responsibility of enforcement and 

penalties. Second, the federal government could take the responsibility. Finally, the 

various state PUCs could take on the enforcement and penalty responsibility; however, 

achieving uniformity among states might prove difficult. 

My preference would be to have WSCC perform this function. WSCC would 

monitor and measure compliance. Although NERC has the national responsibility for 

reliability, it is not staffed or prepared to take on an enforcement mission. Concerted 

State action might be much more difficult than having one entity in each region (WSCC 

and the other regional reliability councils) handle the enforcement of standards. 

Effective enforcement would only be possible if mandatory membership were 

made possible by FERC ruling or by federal legislation. States could require 

membership, but this would only work if each and every state made membership a 

requirement. 

Third, we need better communications among the participants in the western 

grid. It is very likely that if we had a better inter-utility communication system on August 

10 that the outage might have been avoided, or at least it might have given enough 

warning so that the resulting impact might have been reduced. We need a real-time 

disturbance alert mechanism so that operators on the integrated system can get early 

warning of problems which may affect their system operation. 

Fourth, we need to ensure that, as we move to a more competitive electricity 

market, there is a clear delineation of reliability responsibilities through either market 

mechanisms, through contracts, through state or federal regulations, through 

Independent System Operator mechanisms, or through WSCC requirements. 
224 

Testimony before the Water and Power Resources Subcommittee of the 

U. S. House of Representatives Committee on Resources 

November 7, 1996 

Page 3 

Fifth, we need to develop better damage control mechanisms. These could 

include better islanding methods. Arizona is a relatively small state, in terms of 

population and power usage, compared to our neighbor to the West. So, to the extent 

that California utilities and northwest utilities ignore potential problems on the western 

interconnected grid, the resulting outages will probably continue to have a major 

negative impact on Arizona's electric system. Whatever happens in the California 

power markets has a significant impact on all of the adjoining states. Since California is 

going to lead western states in the move toward restructuring and competition in the 

electric utility system starting in 1998, we hope that adequate care will be taken to 

ensure that all competitors in the California market meet reliability standards -- along 

with a fairly explicit and equitable load shedding protocol. It is my understanding that 

on July 3, 1996, the day after the big July 2, 1996 outage, a similar problem occurred. 

Idaho dropped load for the entire City of Boise, which kept the entire system from going 

down again. This incident and the smart and timely actions taken by Idaho operators 

should be proof that a load shedding protocol may limit the severity of outages. 

And finally, we need to encourage the participation of all appropriate parties in 

the process to develop solutions. In particular, the state PUC's need to be involved as 

honest brokers. A few years ago, it would have been unlikely for state regulators to be 

welcomed into this kind of problem-solving process, but times have changed. The 

participation of state PUC representatives in the various western RTGs has been 

beneficial and has opened new avenues of communication among the parties involved. 

We need to continue to work together in order to understand and solve this complex 

reliability problem. Indeed, PUC regulators bring a ground-level public interest 

perspective of concern for overall reliability and economic efficiency that individual 

market players may not necessarily bring. Without this broad perspective the narrower 

interests of market players may dominate reliability protocols. The regulators can help 

develop a balance between system reliability obligations of non-WSCC members 

without allowing WSCC members to inhibit the transition to competition under the guise 

of reliability. While this will be challenging, I and other regulators are ready to meet 

these challenges. 
225 

PREPARED STATEMENT OF E. JAMES MAClAS 

ISSUES AND RECOMMENDATIONS CONCERNING THE AUGUST 10, 1996 

BONNEVILLE/WESTERN U.S. POWER OUTAGE 

On August 10, 1996, the Western United States electrical grid experienced its 

second major disturbance in two months. In PG&E's opinion, the cause of both 

events was a lack of effective voltage management by exporting utilities. This 

lack of adequate voltage management caused a series of line and equipment 

failures to escalate into massive voltage collapse and grid instability in the 

Northwest. These instabilities, in turn·. led to widespread customer load 

shedding throughout the Western United States as other utilities' security 

systems operated automatically to stabilize the grid. 

Economic trends in the industry are driving usage of the grid to a greater extent 

than ever before. These forces are pushing many generators to maximize 

electrical output for sale to distant markets and retailers to reach further out, in 

search of low cost supplies. Recent enhancements to the regional grid and open 

access regulation now make this access to long distance supplies easier. These 

conditions are increasing regional flows to higher levels than have ever been 

seen before. This trend will continue. 

Higher regional flows and higher capacity operations, however, reduce the 

tolerance for error. The grid system is designed to handle these flows, but it 

requires diligent operations and disciplined adherence to detailed operating 

procedures. 

My analogy is driving on a winding road . With ideal weather conditions and at a 

speed well below the maximum limit, the driver feels safe and complacent even if 

the car's suspension is poor or the tires are bald and over-inflated. If weather 

conditions worsen and the driver goes at the speed limit, these same equipment 

conditions left uncorrected can lead to disastrous results. This is what happened 

to the western grid operations. 

On August 10, less than ideal operating conditions existed. Critical generating 

and switchyard voltage support equipment was either unavailable or 

experiencing operating problems. System operators failed to recognize early 

warning signs of voltage instability in their control areas. Further failure of 

unreliable equipment led to disastrous results. 

Why is voltage management so important? Voltage is the back pressure that 

allows electricity to flow across wires. To safely control the flow of electricity 

across a wire network, voltage has to be carefully managed at the generating 

source. at the consumption end, and at various locations along the path in 

between. The longer the distance between the generation source and the 

consumption end, the more difficult the challenge to maintain even voltage 

levels. Voltage support is provided by generating facilities and by reactive 

voltage support equipment located at substations. 
226 

CORRECTIVE ACTIONS 

PG&E's strategy to improve long-term ~Jrid reliability has three components. 

First, PG&E has taken immediate steps to better insulate PG&E customers from 

grid disturbances that originate outside our control area. These steps are 

immediate but provide only temporary improvement. Second, PG&E is also 

working with Western Systems Coordinating Council (WSCC) and North 

American Electric Reliability Council (NERC) to improve training , operation and 

monitoring of WSCC wide voltage management. And third, PG&E continues to 

pursue fundamental structural changes in the industry that will improve reliability 

operations while market forces drive economic improvements within the industry. 

Immediate Actions: 

1. PG&E and Bonneville Power Administration have reduced the amount of 

energy that can flow from Oregon into California at any time, by lowering the 

rating of the Pacific AC lntertie from 4500 MW to 3200 MW and the DC 

lntertie from 2990 MW to 2000 MW. This provides greater reliability to the 

grid by allowing Northwest in-area generation to provide voltage support for 

local loads, Canadian imports and California exports. Reducing electricity 

exports out of the Northwest providE!S greater redundancy on the lntertie 

wires and limits the amount of long distance energy available to California. 

2. PG&E has also increased communication with other utilities. This will help 

provide PG&E with potential warning of transient operations and give us an 

opportunity to take additional protective actions. 

Improving Regional Operations 

1 . WSCC has committed to review procedures and training for voltage collapse. 

The WSCC will review voltage management criteria and utility operator 

understanding of this criteria. Procedures and training will be enhanced. 

2. WSCC will determine compliance with all WSCC operating procedures, 

especially voltage management. This has already begun. 

3. The WSCC is working to establish four regional "Security Centers" (one of 

which will be PG&E) to exchange data, monitor system conditions for 

potential reliability problems and coordinate system restoration. 
227 

Industry Restructuring 

1. PG&E's restructuring proposal to Federal Energy Regulatory Commission 

(FERC) would separate and isolate reliable grid operation from the economic 

drivers of the competitive supply market. The Independent System 

Operation (ISO) will be solely responsible for reliable grid operation and will 

· have no economic interest in the market. Organizational separation of the 

ISO from the Power Exchange and other supply coordinators will ensure this 

reliability-only focus. 

2. ISO regional control would replace numerous utility-specific control points. 

Today's regional control is a patchwork of dozens of local utilities 

coordinating with each other. Regional ISOs are being considered to better 

monitor system conditions . 

3. ISO operating criteria should be mandatory with financial settlements. 

WSCC operating criteria are largely voluntary. There are very few 

enforcement consequences in the WSCC. The ISO will make procedures 

mandatory and will permiUrequire financial settlement where cost causation 

can be determined. 

Technology Tools 

1. Dynamic ratings are needed for transfer capabilities: Today's ratings are 

conservative, but they are developed on the basis of fixed assumptions of 

operating conditions and flow patterns. The future market will dictate 

frequent changes in generation patterns. Grid operators will need more 

dynamic analysis tools to better assess real time reliable operations. 

2. Real - time contingency analysis is needed: Today's operators rely on 

procedures and protective schemes that are based on a limited number of 

off-line power flow studies. Frequent changes in power flow patterns and 

heavy system utilization require the development of tools that will evaluate 

real-time conditions and alert operators to dangerous conditions. 
PREPARED STATEMEN'T OP MARciE L. EDWARDS 

WRITTEN STATEMENT FROM 

THE LOS ANGELES DEPARTMENT OF WATER AND POWER 

PRESENTED BY 

MARCIE L. EDWARDS 

DIRECTOR OF BULK POWER 

FOR THE HOUSE 

SUBCOMMITTEE ON WATER AND POWER RESOURCES 

OVERSIGHT FIELD HEARlNG ON 

"ISSUES AND RECOMMENDATIONS CONCERNING THE AUGUST 10, 1996 

BONNEVILLE/WESTERN U.S. POWER OUTAGE" 

THE HONORABLE JOHN T. DOOLITTLE, CHAIRMAN 

NOVEMBER 7, 1996 

Chairman Doolittle and Members of the Water and Power Resources Subcommittee: 

thank you for this opportunity to share the perspective of the Los Angeles Department of 

Water and Power on the Western Interconnection disturbance of August I 0, 1996. Like 

most other utilities in the Southwest, the Department experienced significant impacts of a 

disturbance originating a thousand miles away. Also like other utilities, the Department 

is committed to learning whatever we can from this event to maintain and improve the 

reliability of electric power supply in the Western United States. 

EFFECTS IN THE DEPARTMENT'S SYSTEM 

The disturbance essentially began at 3:42PM when the 500,000 volt transmission line 

between Keeler and Alston sagged into a tree. experienced an electrical flashover, and 

relayed. The power flowing on this line transferred to other weaker lines in the area, 

overloading them and causing the voltage in the area to decline. At 3:47PM, the 230,000 

volt Ross-Lexington line sagged into a tree and relayed. At the same time, units at 

McNary Power House began to trip off. The system became unstable, with growing 

voltage and power oscillations, and after approximately 75 seconds, oscillations grew to 

where the voltage on the California-Oregon Intertie lines reached the trip setting of relays 

protecting those circuits. The 4,300 MW which had been flowing into California from 

the Northwest instantly over those circuits sought a different path to California, through 

Idaho, Utah, and Arizona. This surge tripped numerous transmission lines in Arizona, 

Utah and Southern California, creating three electrical islands. A fourth island was 

created minutes later due to control actions in the Alberta system. 

The power swing resulting from the tripping of the three California-Oregon Intertie lines 

created severe undervoltage conditions in the Southern California area. Most of the 

Department's load and transmission facilities survived this undervoltage, with two 

notable exceptions: 
229 

Los Angeles Department of Water and Power Statement 

• The cooling systems on two solid-state converters on The Pacific High Voltage Direct 

Current (HVDC) Intertie tripped off due to the low voltage, causing the converters 

themselves to trip off as well. Additional mercury-arc valve groups may have also 

tripped off due to the low voltage. As a result, the Pacific HVDC Intertie, which was 

carrying nearly 2850 MW from the Pacific Northwest to Southern California, was 

partially disabled. In the minutes after the disturbance was triggered, the Pacific 

HVDC Intertie, in its weakened conditioned, became a threat to the security of the 

Southern California system and was intentionally de-energized at the Department's 

request. 

• Pumps at the Hyperion Waste Treatment facility tripped off due to the low voltage, 

causing partially treated sewage to be dumped into the Santa Monica Bay, forcing the 

closure of local beaches for a few days after the disturbance. 

Eleven generators serving Department load, including units in Utah, Arizona and 

Southern California, tripped off during the disturbance, mostly due to problems stemming 

from the power/undervoltage swing. Cut off from the power it had been importing from 

the Pacific Northwest, the entire southwest island, encompassing Arizona, New Mexico, 

parts of Baja California, and Southern California, experienced severe underfrequency 

(58.5 Hz). To stabilize the system and prevent additional loss ofload, approximately 

forty percent of the customers in this region were intentionally and automatically 

disconnected from the system. 

Department load dispatchers used energy from Castaic, a large hydro generating facility 

north of Los Angeles, to help stabilize the island. Approximately seventy minutes after 

the disturbance, the frequency had returned to near normal and utilities began to restore 

customer load. All of the Department's customers were restored to service by 5:30PM 

that evening. 

ISSUES 

The Department actively participated in the Western Systems Coordinating Council's 

investigation into the disturbance. Additionally, the Department conducted its own inhouse investigation into the performance of its system. These investigations brought 

forth a number of technical and social issues which contributed to the disturbance. 

I. INTERCONNECTION-WIDE RESPONSIBILITY FOR RELIABILITY 

Competition in the electric power industry promises to do for this industry what 

telephones, airplanes and even the Internet have done for society at large- effectively 

shrink the commercial distance between remote parts of the world. In the years ahead, 

consumers may be purchasing their energy from sources hundreds or thousands of miles 

away. As the commercial distance between suppliers and consumers on the 

Interconnected power system shrinks, it will be imperative for all entities deriving 

Page2 
230 

Los Angeles Department of Water and Power Statement 

economic benefit from the interconnected system to share in the responsibilities for 

maintaining system reliability. Such steps may include coordinating automatic protective 

load shedding and restoration, and generator underfrequency or undervoltage protection 

on an interconnection-wide basis, not just on a local or regional scale. The local or 

regional practices which have served us well in the past may not be enough to ensure 

reliability in the competitive future. 

2. SHARING TECHNICAL INFORMATION 

One of the concerns brought up in the investigation of the August I 0 disturbance was 

whether the Bonneville Power Administration had appropriately made notification of I) 

equipment previously out of service for maintenance; 2) three 500,000 volt transmission 

line outages which occurred in the hours before the disturbance was triggered at 3:42PM 

Pacific Advanced Standard Time. While system simulation studies will be necessary to 

determine the impacts these outages had on the initiation and severity of the disturbance, 

the fact that some utilities were not aware of these outages raises questions about the flow 

of information necessary to preserve reliability. The possibility of problems in one part 

of the interconnected system impacting other remote parts of the interconnected system, 

coupled with the additional stress competition may place on operating the existing 

system, increases the need for sharing technical information in a timely fashion. 

3. STUDYING AND MONITORING THE SYSTEM 

One of the most important factors in the August 10 disturbance was the failure to identify 

the severe potential impact of a single 500 kV transmission outage (the Keeler-Alston 

500-kV line) and implement operating guidelines to mitigate the impacts of that outage. 

Similarly, the failure to study, assess the impacts of, and develop mitigating guidelines 

for the loss of two 345-kV transmission lines out of Jim Bridger contributed directly to 

the July 2, 1996 Western Interconnection disturbance. Unusually favorable water 

conditions from a wet winter contributed to 1m usually high levels of Pacific Northwest 

hydro genoration, which in tum created unusual energy flow patterns in the Pacific 

Northwest- flow patterns which were considered unlikely. As a result, the system may 

have been operated in a state which had not been studied. 

The onset of competition may also create unusual energy patterns which may not have 

been previously seen or anticipated. Maintaining the reliability of the power system 

under changing conqitions will require intensifying efforts to accurately model and study 

the system under a wide variety of conditions. These efforts should include the 

following: 

Voltage collapse. A decade ago, simulation studies primarily focused on 

transient stability, and the ability of the system to survive the first ten or twenty 

seconds following the loss of an element. More recently, studies have focused 

also on voltage collapse, a phenomena which can occur in any time frame from a 

few seconds to several minutes. Studying and protecting against voltage collapse 

Page 3 
231 

Los Angeles Department of Water ond Power Statement 

must become a bigger concern, especially in light of the two Western Connection 

disturbances of 1996. 

Proper modeling of reactive power supplies. The increasing concern over 

voltage issues has brought fmward the need to properly model the reactive power 

capabilities of generating .units. The studies that were done to establish what were 

believed to be safe operating limits following the July 2 disturbance may have 

been overly optimistic in modeling the reactive capabilities of generating units, 

and did not model the uncontrolled loss of McNary units at high levels of reactive 

output though three McNary units did trip off during the July 2 disturbance. 

The North American Electric Reliability Council (NERC) has recommended establishing 

security centers - regional organizations which will oversee the reliable operations of 

sections of the interconnected system. Similarly, California has mandated that an 

Independent System Operator be established to reliably operate the bulk power 

transmission system. The demand for better, more comprehensive system studies, 

including, as it becomes more viable, real-time analysis of system security, will probably 

fall increasingly to these regional security centers. 

4. SOCIETAL AND ENVIRONMENTAL IMPACTS ON POWER SYSTEM 

OPERATION 

On August I 0, The Dalles, a large hydro generation station in the Pacific Northwest, was 

operating at reduced capability as part of a program to preserve salmon smolts in the area. 

This operation reduced the amount of real and reactive power and inertial support 

available to the Pacific Northwest transmission system, which was operating under 

stressed conditions at the time. 

Such environmentally constrained operations are becoming more commonplace, and are 

increasing impacting power system operations. For example, even though it contributes a 

very small portion of the total emissions affecting Southern California air quality, the 

Department altered the operation of its in-basin units, which provide real and reactive 

power support to the transmission system serving the City of Los Angeles, to comply 

with Rule 1135 imposed by the South Coast Air Quality Management District. It is a 

utility's obligation to comply with the societal and environmental constraints imposed to 

protect the common good. It is also true that in this energy-dependent society, reliable, 

economic electric service is also a significant part of the common good, worthy of equal 

consideration in the public debate. 

In summary, Mr. Chairman, the Department believes the major lessons to be learned from 

this disturbance are: 

Page4 
232 

Los Angeles Department of Water and Power Statement 

• the need for old assumptions to be put aside and for all parties deriving benefit from 

the interconnected system to work together to ensure the continued high degree of 

system reliability which we have previously enjoyed; 

• the need to increase the sharing of technical information even as there is a 

competition-directed move away from sharing commercial information; 

• the need to carefully and completely study a power system which is being operated as 

never before; 

• the need to consider the impacts of constraints imposed on the industry by external 

concerns. 

Thank you again for the opportunity to speak to these issues. 

Page 5 
233 

Los Angeles Department of Water and Power Statement 

SUPPLEMENTAL SHEET 

STATEMENT PRESENTED BY 

Ms. Marcie L. Edwards 

Director of Bulk Power 

Los Angeles Department of Water and Power 

Ill North Hope Street, Room 1255 

Los Angeles, California 90012 

(213) 367-0695 

Page 6 
234 

November 19, 1996 

The Honorable John T. Doolittle 

Cha1rman. Subcommittee on Water and Power Resources 

U S House of Representatives 

1324 Longworth House Office Building 

Wash1ngton. D.C. 20515 

Dear Mr. Doolittle: 

,·i'· 

I apprec1ated the opportunity to appear before your committee on November 7, 1996. 

As you requested, the information on our tree management practices is provided below: 

Edison has an inventory of approximately one million trees, of which 42,600 trees 

are in our high voltage transmission line rights-of-way. 

• We have a 12-month inspection cycle, which includes pre- and post-tree trimming 

inspection to assure adequate line clearances. 

• Our practice is to have a clearance of 40-feet plus 1-year's tree growth for 500 kV 

i1nes : and. 25-feet plus 1-year's tree qrowth for 220 kV lines. 

• The use of herbicides is currently lim•ted to weed abatement in substations and 

transmission rights-of-ways. However, herbicides are not used on U.S. Forest 

Service lands since use of herbicides have been restricted since 1984. 

Herbicides are not and have not been utilized in our vegetation management 

program, we rely on traditional tree trimming practices. 

Edison also utilizes a tree removal and replacement program to remove high growth 

and high maintenance trees that might affect our high voltage transmission lines. 

Gotng back at least 5-years , Ed ison has not had any tree caused outages on the 

220 kV or 500 kV transmission lines. 

I hope this information is helpful in your inquiry on reliability. Please let me know if we 

can provide additional information. 

Sincerely, 

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