ML17291A676
| ML17291A676 | |
| Person / Time | |
|---|---|
| Site: | Columbia, 05000406, Washington Public Power Supply System, Satsop  |
| Issue date: | 12/31/1994 |
| From: | Counsil W, Halvorson C, Parrish J WASHINGTON PUBLIC POWER SUPPLY SYSTEM |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| GO2-95-044, GO2-95-44, NUDOCS 9503080229 | |
| Download: ML17291A676 (136) | |
Text
o (ACCELE;RATED RIDS PROCESSIi Q~~'l, pC REGULATORY XNFORMATION DISTRIBUTION SYSTEM (RIDS)
ACCESSION NBR:9503080229 DOC.DATE: 94/12/31 NOTARIZED: NO DOCKET FACXL:50-397 WPPSS Nuclear Project, Unit 2, Washington Public Powe 05000397 50-460 WPPSS Nuclear Project, Unit 1, Washington Public Powe 05000460 STN-50-508 WPPSS Nuclear Project, Unit 3, Washington Public 05000508 AUTH. NAME AUTHOR AFFILXATION HALVORSON,C.M. Washington Public Power Supply System COUNSIL,W.G. Washington Public Power Supply System goPo PARRXSH,J.V. Washington Public Power Supply System RECIP.NAME RECIPIENT AFFILIATION
SUBJECT:
"Washington Public Power Supply Sys 1994 Annual Rept." W/
950302 ltr.
DISTRXBUTXON CODE'004D TITLE: 50.71(b) Annual Financial Report COPIES RECEIVED:LTR g ENCL Q SIZE:
NOTES:Standardized Plant. 05000508 App for permit renewal. Requested exp date 890701.
RECIPIENT COPIES RECIPXENT COPIES ID CODE/NAME LTTR ENCL XD CODE/NAME LTTR ENCL PD4-2 LA 1 1 ONDD LA 1 1 PD4-2 PD 1 1 ONDD PD 1 1 CLIFFORD,J 1 1 MENDONCA,M 1 1 INTERNAIi. FQE CENTER 01 1 1 EXTERNAL: NRC PDR 1 1 YiOTE TO ALL"Rl DS" RECIPIENTS:
r PLEASE I<ELp Us TO RrDvcr'ASTEI CONT<c rHE DOCUMENT CONTROL DESK, ROOM Pl-37 (EXT. 504-2083 ) TO ELIXIIVATEYOUR NARC PRO%I DISTRIBUTION LISTS I'OR DOCUMENTS YOU DON "I'LED!
TOTAL NUMBER OF COPIES REQUIRED: LTTR 8 ENCL 8
4j WASHINGTON PUBLIC POWER SUPPLY SYSTEM PO. Box 968 ~ 3000 George Washington Way ~ Richland, Washington 99352-0968 ~ (S09) 372-5000 March 2, 1995 G02-95-044 Docket Nos: 50-460 50-397 50-508 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Mail Station Pl-37 Washington, D.C. 20555 Gentlemen:
Subject:
NUCLEAR PROJECTS 1, 2, & 3 ANNUALFINANCIALREPORT Enclosed for your information, as required by 10 CFR 50.71(b), are three copies of the Washington Public Power Supply System's 1994 Annual Report.
Should you have any questions or desire additional information regarding this matter, please call me or D. W. Coleman at (509) 377-4342.
Sincerely,
. V. Parrish (Mail Drop 1023)
Vice-President, Nuclear Operations AGC/ml
Enclosure:
Washington Public Power Supply System Annual Report 1994 CC: LJ Callan - NRC RIV JW Clifford - NRC w/o MM Mendonca - NRC w/o KE Perkins, Jr. - NRC RIV, Walnut Creek Field Office NS Reynolds - Winston & Strawn w/o DL Williams - BPA/399 w/o NRC Site Inspector - 927N 95030S0229 941231
.0 70062 PDR ADOCK 05000397 I PDR
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5'o-3'F 7 os/ f
- NOTICE-OFFICIAL THE ATTACHED FILES ARE RECORDS OF THE INFORMATION BRANCH.
RECORDS MANAGEMENT TO YOU THEY HAVE BEEN CHARGED PERIOD AND FOR A LIMITEDTIME MUST BE RETURNED TO THE
~a4MAf& RECORDS & ARCHIVES SERVICES NOT SECTION, T5 C3. PLEASE DO OUT SEND DOCUMENTS CHARGED OF THROUGH THE MAIL. REMOVAL DOCUMENT ANY PAGE(S) FROM BE FOR REPRODUCTION MUST REFERRED TO FILE PERSONNEL.
- NOTICE-
1%4 Bmsl
Ã(OFl Financial and Operating Highlights
'Meeting the Challenge' Carl M. Halvorson
'Setting a Foundation for Success' William G. Counsil Executive Board 4-5 The Supply System 6.11 Board of Directors 12 and Committees Financial Information 13-36 Meeting the Challenge
9 .r s a
FINANCIALAND OPERATING HIGHLIGHTS For the yeor ended June 30, 1994 (Oollors in millions)
BONDS OUTSTANDING Amount*/Weighted Average Coupon Rate WNP-1 amount
~4
$ 2,246.3 ELl52
$ 2,406.3 QfhKE
-6.6%
weighted average 6.2% 6.6% -6.1ok variable $ 153.3 $ 0.0 NA average rate 2.4% NA NA WNP-2 amount $ 2,612.2 $ 2,507.4 4.29o weighted average 6.1% 6.6% -7.6%
WNP-3 amount $ 1,738.4 $ 1,868.1 -6.9%
weighted average 6.0% 6.1% -1.6%
variable $ 202.1 $ 0.0 NA average rate 2.4% NA NA
'Excludes Compound Interest Bond Accretion INVESTMENT PERFORMANCE K3223 GtEUGE Income $ 50.1 $ 46.8 7.1%
Average Balance $ 894.2 $ 839.2 6.6%
~
Rate of Return 5.6% 5.6% 0.0%
I NUCIEAR PROJECT NO. 2 ~ I PACKWOOD lAKE PROJECT EU2% QlhblGE
~
OPERATING STATISTICS EU224 FYl292 QkhblGE Total production costs * $ 155.9 $ 138.6 12.5% $ 0.4 $ 0.3 33.3%
Net generation (millions of kWh) 7,288.8 6,129.7 18.9 lo 65.6 65.8 -0.39o Cost in mills/kWh 21.4 22.6 -5.3% 6.7 4.4 52.3%
Plant availability 79.5% 68.8 lo 15.6% 90.0% 100.0/o -10.0%
Plant capacity 76.6% 63.7 /o 20.3% 27.3% 27.3 lo 0.0%
'Indvdes operotion ond mointenonce costs per FERC report
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lectric utilities have experienced many significant two projects (more than 1,200 megawatts each). Termina-changes in recent years. Energy shortages, increasing tion brings to a close more than a decade of the Supply costs, additional regulatory pressures, and the heightened System preserving the two plants as future energy demand for electricity, have challenged the industry to resources for the region.
move toward more cost-competitive and customer- Termination also ends certain provisions of contracts oriented operations. between the Supply System and BPA for the two projects The rapid emergence of competing energy providers and abandons the possibility of the Supply System and resources also is challenging established energy completing either of the projects as commercial power providers to become more flexible and innovative in plants for BPA. Termination does not, however, affect their relations with their customers. the Supply System's ability to continue net billing for These factors challenged the Supply System and its ongoing debt service and termination costs from BPA.
em p loyees durin g fiscal ear TheSu ppy S ystemfurthe r 1
1994 in the operation of its pursued this year its proposal two generating facilities- to construct and operate a the 1,112-megawatt Plant 2 combustion turbine-powered nuclear power plant and the electrical generating complex Packwood Lake Hydroelectric at the WNP-3 power plant site Project and in the preserva- in western Washington State.
tion of two partially complete In October 1993, BPA signed nuclear projects, WNP-1 and an agreement with the Supply WNP-3. System authorizing us to As one of the Pacific AHQgq> proceed with preliminary Northwest's largest electrical development work for the energy resources, Plant 2 natural gas-fueled power plant.
staff helped the region's elec- We continued oursuccess-tricity users surmount several ful bond refunding program energy hurdles this year by during the year with a series significantly improving its of four bond sales that operating performance and increased present value sav-providing the region with ings to $ 1.62 billion. This nearly 7.4 million megawatt- means a significant reduction hours of electricity. in debt service payments by During a year when the the Supply System.
Pacific Northwest continued The program's thirteenth, to experience. drought condi- and most recent issue of tions and resulting increased $ 662 million in bonds were pressures on its hydroelectric sold in January 1994 at a true system, Plant 2's increased interest rate of 5.31 percent.
generation was acclaimed by its customer, the Bonneville The refinancing program continues to increase BPA's Power Administration (BPA), for saving them millions of competitive position by providing substantial debt service dollars in avoided outside power purchases. savings, dollars that are ultimately saved by the ratepayers The Supply System's responsiveness to BPA was served by the federal power marketing agency.
illustrated in May 1994, when our Board of Directors Whether it's Plant 2 operations, the future of WNP-1 acknowledged BPA's recommendation and approved a and WNP-3, or refinancing activity, the Supply System resolution to terminate the Supply System's two partially willcontinue to rely on the ingenuity and resourcefulness complete nuclear power plants, WNP-1 and WNP-3. After of its employees to confront the challenges in today' thorough study, Board members concluded that there was competitive energy marketplace.
little regional support for bringing on line either of the Carl M. Halvorson Executive Hoard Chairman plight 2
uccessful organizations establish appropriate goals Commission (NRC). In the NRC's most recent assessment and objectives and focus on efforts that will achieve the of Plant 2 performance, which covered the period from desired outcome. The Supply System focused during fiscal March 1, 1993, through March 31, 1994, the NRC noted year 1994 on improving Plant 2 operations. Our success our implementation of numerous improvement initia-showed our customer, the Bonneville Power Administra- tives and described Plant 2 performance as improved. The tion (BPA), that we are committed to providing the Pacific Systematic Assessment of Licensee Performance (SALP)
Northwest with a reliable and cost-competitive supply of report includes NRC evaluations in four functional areas electricity. including plant operations, maintenance, engineering, In today's economic environment, reliability and cost- and plant support.
effectiveness are crucial. In the nuclear industry, both We place considerable emphasis on meeting the must be accomplished without sacrificing safety. This NRC's expectations and requirements, and maintain an year, Plant 2 performed remarkably well, as evidenced by open and candid communications link with NRC a record 257-day run and a representatives.
significant increase in electri- Measuring up to commu-cal generation. Coupled with nity expectations continues other improvements, these to be a top priority for the accomplishments enabled the Supply System and its employ-Supply System to meet its goal ees, many of whom are of generating electricity at a involved in civicgroups, chari-regional cost of 37 mills (3.7 table organizations, education cents) per kilowatt-hour. committees, youth activities, When the cost of power was and more. This volunteer calculated from an industry work and participation in perspective, it was 21.4 mills communityactivitiesdemon-per kilowatt-hour, about one strates the Supply System's mill (0.1 cents) over budget. commitment to the public I attribute Plant 2's im- power concept of improving proved operatingperformance the quality of life in those to a shift in philosophy for the communities of which we are organization. In years past, a part.
the Supply System tended And that commitment to over commit itself to a extends beyond the local com-whole host of challenges munities. The Supply System and opportunities. The result- continues tosupportstateand ing strain on our resources local taxing districts with an-sometimes led to mediocre nual generation tax payments performance. Our intent this made on the wholesale value year, and in years to come, of the electricity generated by is to better control our Plant 2. This year alone, the commitment of resources so Supply System paid the state we can concentrate on improving Plant 2 operations treasurer $ 2.8 million the to the point that we are recog- highest payment made since nized as an industry leader. Plant 2 began operating in To that end, we have implemented several new initia- 1984. The stategeneral fund and fund for schools, as well tives. In correlation with the Supply System's strategic as counties, cities, fire protection districts, and library objectives, a new Plant 2 Business Plan outlines specific districts within 35 miles of Plant 2, share these dollars.
work initiatives and identifies senior management spon- More than $ 18.7 million in generation taxes have been sors and key managers who are accountable for achieving paid by the Supply System to the state of Washington the desired results. We also developed and distributed a during the past 10 years.
series of Standards for Success that provide each of our As our perception that we can excel becomes firmly 1700 employees with expectations and values to guide their day-to-day work activities. rooted, those dedicated to building the future of the Complementing the nuclear utility industry's high Supply System will take the steps necessary to ensure our standards are the expectations of the Nuclear Regulatory continued success.
William G. Counsil Managing Director page 3
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page 6 Plant 2 operations during fiscal year 1994 clearly efficiently the power plant converts heat energy into demonstrated the progress being made by the Supply electrical energy. In INPO's September 1993 report, System to improve the plant's overall performance and Plant 2 used an average of 9,916 BTUs to generate one reliability. Operational improvements are producing kilowatt-hour of electricity. The industry average for increased electrical generation and lowering the cost of boiling water reactors is 10,351 BTUs. Plant 2's success power produced by the 1,112-megawatt nuclear plant in thermal efficiency sets a standard for performance for Pacific Northwest ratepayers. that can be achieved in all aspects of plant operations.
Plant staff in recent years have refocused their Overall operating performance during fiscal year attention and efforts to improving procedures, plant 1994 demonstrated that increased emphasis on irn-systems, equipment, and work practices that have proving Plant 2 operations is producing results that direct impact on plant safety and reliability. The benefit BPA and electricity users throughout the re-objective is to maintain Plant 2 in a safe and efficient gion. With a record production of nearly 7.4 million operating mode and minimize problems that in the megawatt-hours of electricity, Plant 2 was able to past tended to interrupt plant opera- provide BPA with 765,000 mega wa tt-tions. hours, or the equivalent ofone month, An exceptional year of operation more generation than planned by BPA.
for Plant 2 is evidence that this objective The extra month of generation pro-is being met. Plant 2 this year achieved vided by Plant 2 saved BPA, and ulti-a capacity factor of 76.6 percent, repre- inately regional ratepayers, about $ 20 senting considerable improvementover million that otherwise would have past years and nearing the Supply been spent to purchase power from ll iZ;iii'l;itii iiiiiilliiiii i iiQitiiiilli1lljiltii outside the region.
System's capacity factor goal of 80 per- ] i el'%4li>iJ cent. Capacity factor is the ratio of On average, Plant 2 provides BPA energy actually produced to the energy with more than 11 percent of its firm that could have been produced had the power load. This generation has helped plant operated continuously at its rated TheInstitnte for 'PA in its continued struggle with capacity during the same time period. Nnclear Power Operations with the effect of a regional drought The Supply System's customer, the (INP0), and other pressures on the Pacific Bonneville Power Administration (BPA), in a snniniary Northwest's hydroelectric system.
also reported that for the period from ofthernialperforniance ~
Plant 2's generation of 6.7 million March 1993 through March 1994, for the nation's megawatt-hours of electricity during Plant 2 achieved a capacity factor of 31 boiling water BPA's fiscal year, Oct. 1, 1993, through 80.2 percent, the highest ever in any reactor plants, listed Sept. 30, 1994, provided the federal 12-month period. agencywith about 400,000megawatt-Washington Pnblic Contributing to an improved Power Snpply s liours, or two and one-half weeks, more capacity factor was a 257-day record generation than BPA anticipated. That Plant 2 generating run which ended with the extra electricity was enough to power as the best start of plant's annual maintenance about 25,000 Pacific Northwest homes.
and refueling outage on April 26, in tiie Plant 2 also was recognized by 1994. Registered as the longest period united States BPA as placing fourth among the of continuous electrical generation in in this category. agency's 33 regional generating facili-the plant's nine-year operating ties for highest generation during fed-history, the 257-day run surpassed 0 eral fiscal year 1994. Grand Coulee the plant's previous record of 203 Dam at 17 million megawatt-hours, days, set in 1990. Chief Joseph Dam at 9.6 million Plant 2 continued to maintain an exce llent ther- megawatt-hours, and John Day Dam at 8.3 million mal efficiency, or heat rate, throughout the year T>>e megawatt-hours, were theonly facilities thatgenerated Institute for Nuclear Power Operations (INPO) in a more electricity than Plant 2, which is the Federal summary of thermal performance for the n ation's31 Columbia River System's largest single-generator boiling water reactor plants, listed Plant 2 as the best in facility.
the United States in this category. Calculate dinBritish The Supply System is proud of this year' Thermal Units (BTUs), thermal efficiency is ameasure achievements and intends to continue improving of the plant's efficiency in converting heat e nergy into Plant 2 operations and maintaining the plant as a electrical energy. The smaller the number, the more cost-effective regional resource in succeeding years.
page 7
Situated in the Gifford Pinchot National Forest amidst Washington's Cascade Mountain range, the Supply System's Packwood Lake Hydroelectric Project this year celebrated 30 years of economic, reliable electricity generation.
Dry weather conditions and lower than average water flow into Packwood Lake this year were less of a cause for celebration for the Supply System's first operating power plant. Packwood's generation during fiscal year 1994 totalled 65,600 megawatt-hours.
Although a year with normal precipitation results in Packwood generating about 84,000 megawatt-hours, high water years have seen production rise to more than 100,000 megawatt-hours.
Only four full-time employees have been sta-tioned at the Packwood Project since it went into operation in 1964. While the plant is designed to operate in a somewhat automatic mode, operators with knowledge and experience in electrical, mechani-cal, instrumentation and power plant operations are required to assure continued safe and reliable opera-tions. Any major repair work is typically scheduled for October each year, when the Project is shut down for its annual maintenance outage.
Among the various maintenance activities com-pleted during this year's outage, Packwood staff repainted the 191-foot-tall surge tank which accepts water from Packwood Lake as it is channeled through two tunnels and around a mountain in a 22,000-foot pipeline.
Electrical energy from the Packwood Project is distributed by the Bonneville Power Administration (BPA) for use by 12 Public Utility Districts (PUDs) in Washington state. Packwood supplies enough electricity to meet the annual needs of nearly 4,000 Pacific Northwest residences.
In addition to low-cost electricity, the utilities that are participants in the project receive funds each fall when revenues gained from the Packwood Project exceed costs. This year, more than $ 1 million in revenue was distributed to Packwood participants under power sales contracts based on member purchasers'ower allocation shares.
page 8
Dual Purpose Concept Conrbustion Turbine Proposal The Supply System in January 1994 pro- The Supply System has responded to the posed a concept that involves using Plant 2 region's recent call for low-capital-intensive and WNP-1 to dispose of the nation's stockpiled projects to meet growing electricity needs.
weapons-grade plutonium while providing the One response is a proposal to construct twin Pacific Northwest with competitively priced elec- combined cycle combustion turbine power tricity. The partially complete WNP-1 is situated plants at its Satsop site, located 30 miles west about one mile from Plant 2, both within the of Olympia, the capitol of Washington state.
federal government's Hanford Site. Fueled by natural gas, the combustion The concept addresses the United States'eed turbine plants would each have a generating to use readily available and technologically capacity of 227 megawatts. Plans are to proven means to reduce worldwide supplies of construct both plants on 20 acres that were this fissile material. used to store construction materials for two of the Supply System's partially complete nuclear power plants. Several site conditions make these projects advantageous to poten-tial purchasers. They include an existing connection to the regional power transmis-sion grid, its close proximity to a natural gas line, its license for electric generating facili-ties, and its location in western Washington, where the need for additional generation is the greatest.
One of the combustion turbine units is committed to the Bonneville Power Administration's (BPA's) resource contin-gency program. The program involves BPA acquiring resource options like the Satsop combustion turbine to reduce the time it takes to bring new electric generating S
resources on line when needed. While two
~ <<L r other proposed combustion turbine projects are included in BPA's resource options, BPA is not obligated to call for completion of any or all of the projects unless the power is needed and the resource is deemed to be the most cost-effective and timely option available.
The Supply System is working to identify The Department of Energy is evaluating a power purchaser for the second combustion several possible disposal methods, and in turbine unit by marketing the plant to the spring of 1996 is expected to determine regional utilities and other potential the most desirable and cost-effective means of customers.
plutonium management and disposition.
page 9
The Supply System entered into Plant 2's 10th annual refueling and maintenance outage with a com-prehensive and highly detailed plan for completing the large volume of work required to prepare the power plant for another successful operating cycle. Early into the outage, a problem with a number of electrical modules in the plant's containment building caused outage workers to devote considerable time and atten-tion to test and replace a significant number of modules.
Although much time and attention was devoted to this issue, Supply System staff worked hard to minimize its impact on other critical work tasks. The electrical module problem was estimated to add about 18 days onto the original 60-day outage schedule.
Extra time also was needed for plant staff and outage workers to resolve several other issues that arose during the outage's extensive maintenance and inspec-tion activities. The unplanned work involved detailed analysis of a crack detected in one of the jet pump sensing lines, which serves to maintain accurate mea-surements of reactor coolant flow; the overhaul of control rod mechanisms; repair of two valves in the reactor shutdown cooling system; and replacement of dozens of aged electrical relays. The additional outage tasks delayed Plant 2 restart activities until July 26 three weeks beyond schedule.
While challenged with unexpected work activity, plant staff remained committed to successfully com-pleting the work originally scheduled to ready the plant for safe, reliable operation. Among the outage work accomplished this year was the replacement of 156 of the reactor plant's 764 nuclear fuel assemblies; the inspection of the reactor vessel and associated piping systems; work on the plant's 20 jet pumps, which are used to sustain reactor coolant flow; replacement of several valves in containment used to control atmospheric conditions; and inspection of the main electrical generator.
The individuals involved in outage work activity each demonstrated a sense of dedication and the ability to work as a team toward a common goal. That goal is to improve Plant 2 performance and reliability to the point that it routinely will operate continuously from the end of one annual outage to the beginning of the next one. By doing so, the region's ratepayers will receive the best possible return on their investment in Plant 2.
page 10
New Plant 2 Sinnrlator After years of working to develop a highly accurate training tool for Plant 2 reactor opera-tors, the Supply System this year received its new Plant 2 simulator. Designed as a full-scale, computerized replica of the Plant2control room, the new simulator accurately mimics plant con-ditions and enables reactor operators to get hands-on training in an environment that duplicates the appearance and operation of the actual Plant 2 control room instrumentation.
The simulator replaces Plant 2's original simulator, which in 1988 was determined to need improvement tomeetincreasinghighstan-dards of performance required by the Nuclear Regulatory Commission (NRC) for training and examining reactor operators throughout the nuclear industry.
BOARD EXECUTIVE OI'IRECTORS BOARD COMMITTEES Pietnrerl front left: Administrative and Public Responsibility Parker L. Knight (Vice President) Committee Vera Claussen, Chairman Commissioner Skamania County PUD Mark Crisson Ray Foleen Beverley Cochrane Fitzgerald Paul J. Nolan Commissioner Bob Royer Franklin County PUD Carl M. Halvorson, Ex Officio Roger C. Sparks (President) Audit, Legal and Finance Committee Commissioner William D. Scott, Acting Chairman Kittitas County PUD Vera Claussen Paul J. Nolan Don Carter Carl M. Halvorson, Ex Officio Deputy City Manager City of Richland Operations and Construction Committee Parker L. Knight, Chairman Dan G. Gunkel Mark Crisson Commissioner Ray Foleen Klickitat County PUD William D. Scott Carl M. Halvorson, Ex Officio William G. Kuehne Commissioner Ferry County PUD Arne Torget (Assistant Secretary)
Commissioner Wahkiakum County PUD Robert Graves Commissioner Benton County PUD Sentedr William D. Scott Commissioner Chelan County PUD Absent fran> photo:
Roberta P. Bradley Superintendent Seattle City Light Darrel Bunch Commissioner Okanogan County PUD Vera Claussen (Secretary)
Commissioner Grant County PUD Mark Crisson Superintendent Tacoma Public Utilities pnge 22
o o 'NNUAL REPORT, .
.. FIhfANCIAIINFORMATION" WASHINGTON PUBLIC IOWER SUPPLY SYSTEM I
Management Report on Responsibility- ~
for Financial Reporting Kl:
gg Audit, Legal and Finance Committee . ~
Chairman's Letter
-r "Independent A'uditors'eport Ialance Sheets tD
, Statements of Operations gg Statements of Cash Flows g
Outstanding Long-Term-Debt Debt-Ser0ice, Requirements =
Notes to Financial Statements h r lh 13
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I P l
I MANAGEMENTREPORT ON RESPONSIIqLITY FOR FINANCIALREPORTING -~
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The management-of the Supply System is responsible for preparing the accompanying.finaricial
- statements and for their. integrity. The statements were prepared in, accordance with g'enerally accepted -*
, accounting principles applied on a consistent basis, and include amounts that-are based. on management's best estimates and judgments.,
A The financial statements have been audited by Deloitte R Touche LLP, the Supply. System's indepen-dent auditors. Management.has made available to Deloitte R Touche LLP all financ'ial records and'related data, and believes,that all Jepresentations made to-Deloitte R Touche LLP during its audit were valid and appropriate.
.Management has established and maintains internal control procedures that provide reasonable .
assurance as to theintegrity and reliability of, the financial statements,-the protection of. assets from unauthorized use or disposition, and the prevention and detection of fraudulent financial reporting. These q control procedures provide for appropriate division of responsibilityand are documented by written'policies and procedures. 'I The Supply. System maintains an ongoing internal auditing program that provides for independent "assessment-of the effectiveness of internal controls, and for, recommendations of possible improvements thereto. In addition, Deloitte Rnouche LLP has considered the internal control structure in order to determine
,their auditing procedures for the purpose of 'expressing an opinion on the financial statements. Management has cbnsidered recommendations made by the internal auditor and Deloitte R'Touche LLP concerning the
.control procedures and,has taken appropriate action to resp'ond to the recommendations. Management
'elieves that, as of June 30, 1994, internal control.procedures'are T adequate.
ll E
r W. G. Counsil - --
- J..D. Perko Managing Director I Chief Financial Officer l
A UDIT, LEGAL AND FINANCE COMMITTEE CHAIRMAN'SLETTER
.The Executive Board's Audit, Legal and Finance Committee is composed of three independent directors. Members of the Committee are William D. Scott, Acting Chaiiman; Vera Claussen; Paul J..Nolan; Carl M. Halvorson, Xx, Officio. The Committee held seventeen meetings during the fiscal year ended
'nd June 30, 19+4. "
,- f" The Committee oye'rsees the Supply System's financial reporting process on beh'alf of the Executive Board. fn fulfillingits responsibility, the Committee discussed with the internal auditor and the independent auditors the overall scope and sppcific plans for their respective audits, and review'ed the Supply System's
~
financial statements and the adequacy of the Supply Systenf's internal controls.
" The Committee met regularly with the Supply System's internal auditor and independent auditors to discuss the results of their examinations', their evaluations of the Supply System's internal controls, and the overall-quality'of the Supply System's financial reporting. The'rpeetings were designed to facilitate any private,comm'unication with the Committee desired by the internal auditor o'r independent auditois.
9 I
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'Pilliam D." Scott Acting Chairman, Audit, Legal and Finance Committee P
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I/DEPENDENT A UDITORS'EPORT ..
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II h' Executive Board
'Washington Public Power Supply'ystem I Richland; Washington . y. ~
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h We have audited the accompanying individual balance sheets of Washington Public Power Supply
-System's. (the Supply. System) Nuclear Project No. 2,.Packwood Lake'ydroelectric Project; Hanford ~
'enerating Project, Nuclearf Project No. 1, Nuclear'Project No.G,"and Nuclear Projects Nos. 4 and S as ofJune-
- '30, 1994, and-the reiated statements of operations and cash flows for the year then ended. These'financial sta'tements are. the responsibility of the~Supply System's management Our responsibility. is t'o express an
.opinion on the financial statements based on our,audits. I We conducted oui audits"in accordance with generally accepted auditing standards. Those standards .
=
require that we plan and perform the audit to obtain reasonable assurance about whether'the financial
-statements are free, of material misstatement An'audit includes examining,.op a test basis, evidence supporting*the amounts and'disclosures in the financial-statements. An audit also inclucies assessing the ..
accounting prin'ciples used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our au'dits.provide a reasonable. basis for our opinion.
In our opinion, s'uch financial statements present fairly, in all material respects,;the financial position .
of the Supply System's individual projects at June 30; 1994, and the results of their operations and chsh flows
. for the year then ended in 'conformity with gen'erally accepted accounting principles.
.'s discussed-in Note F to the financial. statements, NucleapPr6jects.Nos'. 1'and 3'are involved-in
'isputes concerning costs shared with Nuclear Projects Nos. 4 and 5. The ultimate amount of Additional costs,,
ifany, to be borne by Nuclear Projects Nos. 1 and 3 due to this'matter is presently indete'rminable. As further
'iscussed in Notes A and F, the Supply System's'Board has authorized the terminatiop of Nuclear Projects.
Nos. 1 and 3 and the ultimate utilization of these projects is uncertain.
~,~ski& ', . tm)ebs. J.J.P .
Sea'ttle, 'Washington h September-1@1994 f ~
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"h s BALANCESHEETS s/
As ofJunc'.30, 1994 Dollars in thousands i
NUCLEAR PACKWOOD HANFORD ~= NUCLEAR NUCLEAR
. LAKE GENERATING, NUCLEAR'ROJECT
. PROJECT PROJECT PROJECTS 4
No. 2 .PROJECT PROJECT" NO. 1 No. 3',NOS; 4/S" ASSET'S a
I l
s UTILITYPLANT (NOTE B)
In service.: ~-,
Allowance for depreciation
$ 3,302,506 1,010,584
$ 12,520 8 949 13,637 $
1;580 807 5,011
'2,291,922 3,571 '8,626 773 I*
'I
'E Nuclear fuel, net of accumulated amortization 118,804 Construction work in progress 116,677 2,236,260 2(449,467,'15,956 Less joint owners'hare 2,527,403 ss 3,571 2,244,886 1,834,284 E
RESTRICTED ASSETS (NOTE B)
~
Special funds Cash .
Investments
- Accounts receivable
~I --,
7s AI 45,695 290 4 1 / . 143,708
,257 1,113 17,081
$ 136 9,816
~ 1,471 6,3/7 =
1-Duefromotherprojects" '
419 2 19,217 Due fiom other funds 654 Prepayments and other 38 77-Debt service funds Cash , . -59 6 139 -~141
. Irtvestments 165,817 721 217,036 179,521 46,016 211,578 1,018 1 363,068 204,906 75,187
/ ~ - s LONG-TERM
'ECEIVABLE(NOTE B) ' -$ 0 230 CURRkÃP ASSETS Cash ~. "
3,170 6 *22 360 765 Investments '- . 22,931 1,034 "',203 9,239 8,024
-Accounts receivable 6,407 224 - .2.
Due from other projects, - '
27 5 163 Due from other funds 28,083 22'1g
'7,372 6,399 .-
Materials,an'd supplies, . 50,853 I Prepayments'ai)d other 1,804 -1 1 /
Nuclear fuel held for sale 81,604',900 11,652 h Plant R equipment held for sale 113 275 1,288 -
12,131 118,740 26,840 DEFERRED CHARGES "
. Costs in excess of billings ~~ 3,571 Unamortized regulatory studies 16,736 Unamortized debt expense 19,161 10 24'35 20,296 Other deferred debits
- 749 748 35,897 . 3I581 25,584 21;044 s
I TOTALASSETS $ 2,938,383 $ 9,458 ,
$ 12,132 $ 2,752,278,$ 2,087,074 '75,187 System's ownership shat'e (Note A)
- Supply Project recorded on liquidation basis a
See notes to financial statements I 16 s
NUCLEAR PACKWOOD 'ANFORD'UCLEAR NUCLEAR, NtICLEAR PROJECT NO. 2 C,
" LAKE PROJECT.
GENERATING PROJECI NO. I
'ROJECT
-PROJECT NO.3' PROJECTS NOS. 4/5"
-LIABILITIES DEFICIENCY IN ASSETS $ (4,161,106)
~ BILLINGS,IN EXCESS. OF COSTS $ 225;944 $ 5,233 $ 262,204'47,081, LONG-TERM DEBT-(NOTE E) <
Revenue bonds payable,
'Unamortized discount on bonds =net
- DEBT IH DEFAUL'P, CURRENTLY
-,'7,916 2,689,895
.111 385 2,578,510, 39 7,877 2,399,640 34 017 2,365,623 1,958,692 -
2,347,120 388 428 V
PAYABLE-(NOTES E O')
Revenue bonds payable', , 2,155,755 Sub~ordinated revenue notes '19 237 2174992-LIABILITIES='AYABLEFROM
-RESTRICTED ASSETS (NOTE B)
Special funds Accounts payable and accrued
'xpenses = - 25,600 6,846 =3,142 ;, 4,083
. Due to other projects 40 19,102 8,489 Due to other/unds, 56,703 19,076 Debt "service funds interest payable -'kcrued 99 71,211 47,741 -2,039,215
'ccounts payable = 9,514
- Due to other funds,. 11 380 8 297-- <<- 7053 53 683 8120 105 470 . 77 038 2061 301
...3
(
OTHER NONCURRENT LIABILITIES ~ 13,281 6 CURRENT LIABILITIES Current maturities of long-term debt, ',515 220 16,900 Accountspayable and accrued
'.'51 expe,nses '3,153 --, 6,733 (5)
Due to participants 4,71'3 1,012 2,081 4 268 Due to other projects 584 5 -163 66,965 . 1 3886,896 18 981 ~ 4 263 DEFERRED CREDITS--
Deferred gain 'on. redemption of revenue bonds 67 COMMITMENTS (NOTE F)
AND'ONTINGENCIES 1
TOTAL'LIABILITIES $ 2,938,383 $ 9,458'12,132 $ 2,752,278 $ 2,087,074 $ - 75,187 A
)
h 17
l, I r JI STATEMENTS ,OF'Oi ERATIONS For the'year e>ided June 30, 1994 Dollars lrt thousands s I
I 4 ~
NUCLEAR PACKWOOD HANPORD NUCLEAR- NUCLEAR PROJECT," LAKE
".. NO. 2 PROJECI"'UCLEAR GENERATING PROJECT i PROJECT-No'0 PROJECTS PROJECT i 'NO. I os 4/s" REVENUES $ 583,217 $ 1,677'PERATING OPERATING, EXPENSES "(
v Nuclear fuel ~
- *=-, 29,652 Fuel disposal fee s' 6,8.69 Decommissioning'epreciation 5,197'107,092 and amortization 438 Operations and maintenance 134,064 ,891 ~ g
,Administrative Er general 43,594 108 Generation,tax 3,015 1 Total operating expenses- 329,'483 '1,438 .
NET OPERATING REVENUES . 253 734 239 OTHER INCOME R,EXPENSE
'on-operating revenues - net $ (117) .'362,245 $ 231,797 $ 2,840 Investment income, 16,774 68 278 20,508 10,211 1,964 ),
Interest expense and W*
discount amortization (171,11]) (307) (153,228) '121,058)
(195,977) .
..Maintenance of projects in i S
extended construction delay, (4,902) (3,944)
Maintenance of plant held for disposition (161)
Termina'tion and asset disposition expenses (8,442)
'ther J 2,872 (1)3,332) (18,081)
NET REVENUES BEFORE EXTRAORDINARYITEM 102,269 .0 0 53,291 98,925 ~" (199,615)
C EXTRAORDINARYITEM ~ [t Loss on bond refunding (Note E), (102,269) , (53,291) (98,925)
~
Gain'on write-off of liabilities (Note F) , 189,519 INET REVENUES 0 $ " 0, $ 0 '$ ' $
$ - (10,096)
I F
I r -3 C
Supply System's ownership share (Note A)
".Project recorded, on a liquidation basis See notes to financial statements 18
1 STATSAfZNTS OJF CASH I'LOWS For the year ended June 30, 1994 Dollars ln thousands NUCLEAR PACKWOOD HANFORD NUCLEAR NUCLEAR NUCLEAR PROjECT NO. 2 LAKE PROJECT GENERATING PROJECT" PROJECT NO. I NO. 3'OS.
PROJECT PROJECTS CASH FLOWS FROM OPERATING AND OTHER ACTIVITIES Operating revenue receipts $ 358,537 $ 2,746 Cash payments for operating expenses (193,530) (967)
Non-operating revenue receipts $ 166,327 $ 129,010 $ 2,797 Cash payments for maintenance of 4/P'ASH projects in extended congtruction delay (3,210) (4,989)
Cash payments for other expenses 572 (118) (1,092) (1,533) (9,601)
Distributions of operating and non-operating surplus (1,105) (592) 592 Net cash provided/(used) by operating and other activities 165,579 674 (710) 162,617 122,488 (6,804)
FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES Proceeds from bond refundings 888,505 510,418 1,007,388 Refunded bonds escrow requirement (854,694) (512,942) (994,857)
Bond issuance costs paid (7,833) (7,874) (9,135)
Capital and nuclear fuel acquisitions (52,035) (566) 1,094 Cash payments for deferred programs (3,802)
Interest paid on revenue bonds (161,024) (305) (156,512) (102,577)
Principal paid on revenue bond maturities (14,413) (304) (35,050) (31,545)
Net cash used by capital and related financing activities (205,296) (620) (0) (202,526) (129,632)
CASH FLOWS FROM INVESTING ACTIVITIES Purchases of investment securities (1,115,837) (8,333) (13,080) (839,802) (668,437) (238,399)
Sales of investment securities 1,137,989 8,204 13,525 845,666 665,917 239,478 Interest on investments 18,355 63 262 21,228 10,255 482 Receipts from sales of nuclear fuel 13,141 Net cash provided/(used) by investing activities 40 507 66 707 40 233 7 735 1 561 NET INCREASE/(DECREASE) IN CASH 790 (12) (3) 324 591 (5,243)
CASH AT JUNE 30, 1993 2,446 25 25 432 1,428 5,380 CASH AT JUNE 30, 1994 (NOTE B) $ 3,236 $ 13 $ 22 $ 756 $ 2,019 $ 137 Supply System's ownership share (Note A)
- 'roject recorded on a liquidation basis See notes to financial statements 19
STATEMENTS OI'ASH I'LOWS (continued)
For the year ended /une 30, 1994 Dollars ln thousands NUCLEAR PACKWOOD HANPORD NUCLEAR NUCLEAR NUCLEAR NO 3'OS. 4/S" PROjECT LAKE GENERATING PROJECT PROJECT PROJECrs NO. 2 PROJECT PROJECT" NO. I RECONCILIATION OF NET OPERATING REVENUES TO NET CASH PROVIDED BY OPERATING AND OTHER ACTIVITIES CASH FLOWS FROM OPERATING AND OTHER ACTIVITIES Net operating revenues $ 253,734 $ 239 Adjustments to reconcile net operating revenues to cash provided by operating activities:
Amortized revenues (224,680) (418)
Depreciation and amortization 132,613 428 Decommissioning 5,197 Other 2,872 Change in operating assets and liabilities:
Accounts receivable (4,637) 140 Materials and supplies (6,425)
Prepaid and other assets (1,311) (1)
Due from/to other projects, funds and participants (1,110) 255 Accounts payable 9,326 . 31 'I Non-operating revenue receipts $ 166,327 $ 129,010 $ 2,797 Cash payments for maintenance of projects in extended construction delay (3,210) (4,989) 0 Cash payments for other expenses (118) (1,092) (1,533) (9,601)
Distributions of non-operating surplus (592) 592 0 0 Net cash provided/(used) by operating and other activities $ 165p579 $ 674 $ (710) $ 162,617 $ 122,488 $ (6,804)
System's ownership share (Note A)
" Supply Project recorded on a liquidation basis See notes to financial statements 20
QpTSTANDZV'G LONG-TERMX7$ BX's of June 30, 1994 Dollars in thousands TRUE INITIAL SERIAL DATE INTEREST OFFERING COUPON OR TERM SERIES OF SALE COST (A) PRICES RATE MATURITIES AMOUNT NUCLEAR PROJECT NO. 2 REVENUE BONDS 1973 6-26-73 S.65~!o 100 5.70~/o 7-1-2012 $ 110,450 110 450 1976A 11-18-76 5.86 (B) 5.50-5.75 7-1-94/2000 29,400 100 6.00 7-1-2007 44,815 99.50 6.00 7-1-2012 60,990 135,205 1981A 9-4-81 14.67 100 14.375 7-1-2001 30,000 59.958 8.25 7-1-2003 100,000 130,000 1990A 3-15-90 7.77 99.75 7.25 7-1-2003 73,705 97.125 7.25 7-1-2006 35,790 109,495 1990B 6-7-90 7.69 94.135 7.00 7-1-2012 200,840 200,840 1990C 11-1-90 7.84 (B) 7.00-7.50 7-1-97/2003 204,870 (B) (C) 7-1-04/2005 18,054 222 924 1991A 9-26-91 6.81 (B) 5.40-6.60 7-1-96/2005 135,260 90.375 6.00 7-1-2012 105,940 (B) (C) 7-1-06/2007 13,431 254 631 1992A 10-2-92 6.19 (B) 4.65-6.30 7-1-96/2009 193,360 97.230 6.25 7-1-2012 66,780 98,875 6.30 7-1-2012 50,000 (B) (C) 7-1-2010/2011 9,084 319,224 1993A 5-20-93 5.76 (B) 3.75-6.00 7-1-1995/2010 208,230 96.404 5.75 7-1-2012 42,105 250 335 1993B 7-15-93 5.64 (B) 3.60-5.65 7-1-95/2008 122,825 100 5.55 7-1-2010 51,000 97.775 5.625 7-1-2012 43,455 217 230 (A) Based on original issue (B) Various prices (C) Compound Interest bonds (D) Excludes amounts due July 1,1994 (E) Includes amounts due July 1, 1994 (F) The estimated fair value shown has been reported to meet the disclosure requirements of SFAS 107 and does not purport to represent the amounts at which these obligations would be settled.
21
OUTSTANDING LONG-TERMDEBT (continftecl)
As ofJune 30, 1994 Dollars In thousaruts TRUE INITIAL SERIAL DATE INTEREST OFFERING COUPON OR TERM SERIES OF SALE COST (A) PRICES RATE MATURITIES AMOUNT NUCLEAR PROJECT NO. 2 REVENUE BONDS (Continued) 1994A 1-27-94 5.319 o (B) 3.00-6.00o/o 7-1-95/2011 $ 556,85S 100 5.40 7-1-2012 100,200 100 (C) 7-1-2009 4,776 661 831 Compound interest bonds accretion 86 195 Revenue bonds payable $ 2,698,410 (D)
Esti)nated fair value at June 30, 1994 $ 2,661,627 (F)
PACKWOOD LAKE PROJECT REVENUE BONDS 1962 3-20-62 3.66 99.425 3.625 3-1-2012 6,171 1965 11-4-65 3.76 100.5 3.75 3-1-2012 1,965 Revenue bonds payable $ 8,136 Estinrated fair value at June 30, 1994 $ 6944 (F)
NUCLEAR PRO ECT NO. 1 REVENUE BONDS 1989A 9-14-89 7.76 100 6.80-7.30 7-1-94/2002 27,525 98.185 7.00 7-1-2004 27,385 99.017 7.50 7-1-2007 62,105 97.759 7.50 7-1-2011 116,195 82.083 6.00 7-1-2017 95,110 328,320 1989B 12-7-89 7.44 100 6.70-7.25 7-1-96/2003 31,095 98.375 7.00 7-1-2005 2,100 100 7.40 7-1-2009 5,180 98.553 7.125 7-1-2016 41 070 79 445 1990A 3-15-90 7.73 (B) 6.60-7.60 7-1-94/2005 70,375 92.75 7.00 7-1-2011 56,770 81.75 6.00 7-1-2017 55,635 182,780 (A) Based on original issue (B) Various prices (C) Compound interest bonds (D) Excludes amounts due July 1, 1994 (E) Includes amounts due July 1, 1994 (F) The estimated fair value shown has been reported to meet the disclosure requirements of SFAS 107 and does not purport to represent the amounts at which these obligations would be settled.
22
TRUE INITIAL SERIAL DATE INTEREST OFFERING COUPON OR TERM SERIES OF SALE COST (A) PRICES RATE MATURITIES AMOUNT NUCLEAR PRO ECT NO. 1 REVENUE BONDS Continued 1990B 6-7-90 7.75% (B) 7.00-7.20% 7-1-99/2003 $ 24,495 97.979 7.25 7-1-2009 72,770 98.913 7.'25 7-1-2012 56,000 153 265 1990C 9-27-90 7.85 (B) 7.00-7.75 7-1-94/2003 160,075 99.50 7.75 7-1-2008 22,085 182 160 1991A 9-26-91 7.02 (B) 5.40-6.80 7-1-94/2008 51,360 98.375 6.875 7-1-2017 92,965 144,325 1992A 10-2-92 6.51 (B) 3.80-6140 7-1-94/2011 56,440 99.375 6.50 7-1-2015 137,820 98 6.25 7-1-2017 78,815 273 075 1993A 5-20-93 5.86 (B) 2.90-7.00 7-1-94/2008 215,485 100 5.75 7-1-2011 80,000 99.75 6.05 7-1-2012 35,705 96.306 5.75 7-1-2013 37,970 96.566 5.70 7-1-2017 176,180 545 340 1993B 7-15-93 5.64 (B) 3.00-7.00 7-1-94/2010 94,825 98.138 5.60 7-1-2015 94,885 189 710 1993C 9-10-93 5.47 (B) 2.70-5.30 7-1-94/2010 25,840 100 5.40 7-1-2012 66,400 98.166 5.375 7-1-2015 75,650 167,890 1993-1A 12-15-93 NA NA Variable 7-1-94/2017 153 330 153,330 Revenue bonds payable $ 2,399,640 (E) 1993A 5-20-93 4.975 100 4.70 7-1-1995 16,900 NOTES 16 900 Revenue bonds/notes payable $ 2,416,540 Estimated fair value at /une 30, 1994 $ 2,462,100 (F) 23
OUTSTANDING LONG-TERMDEBT (continf led)
As ofJune 30, 1994 Dollars in thousands TRUE INITIAL SERIAL DATE INTEREST OFFERING COUPON OR TERM SERIES OF SALE COST (A) PRICES RATE MATURITIES AMOUNT NUCLEAR PROJECT NO. 3 REVENUE BONDS 1989A 9-14-89 7.43% 100 6.80-7.309o 7-1-94/2002 26,705 (B) (C) 7-1-2003/2014 18,668 84.75 6.00 7-1-2018 54,570 99 943 1989B 12-7-89 7.39 100 6.50-7.15 7-1-94/2001 81,080 (B) (C) 7-1-2004/2014 71,321 98.375 7.00 7-1-2005 85,690 100 7.40 7-1-2009 29,235 98.533 7.125 7-1-2016 76,145 79.755 5.50 7-1-2017 62,560 79.525 5.50 7-1-2018 65,905 471 936 1990B 6-7-90 7.57 (B) 6.50-7.25 7-1-94/2000 117,040 (B) (C) 7-1-2001/2010 39,210 98.923 7.375 7-1-2004 55,920 212,170 1991A 9-26-91 6.97 (B) 5.40-6.80 7-1-94/2008 50,040 97.75 6.75 7-1-2011 20,790 94.552 6.50 7-1-2018 66,065 136,895 1992A 10-2-92 4.86 100 3.80-5.10 7-1-1994/1998 12,345 12,345 1993B 7-15-93 5.64 (B) 3.00-7.00 7-1-94/2010 146,465 97.775 5.625 7-1-2012 28,295 98.138 5.60 7-1-2015 49,095 98.058 5.60 7-1-2018 37,795 97.719 5.70 7-1-2018 20,605 282 255 1993C 9-10-93 5.47 (B) 2.70-7.50 7-1-94/2010 183,445 100 5.40 7-1-2012 105,000 (B) (C) 7-1-2013/2018 25,248 98.166 5.375 7-1-2015 188,355 99.5 5.50 7-1-2018 20 805 522 853 (A) Based on original issue (8) Various prices (C) Compound interest bonds (D) Excludes amounts due July 1, 1994 (E) Includes amounts due July 1, 1994 (F) The estimated fair value shown has been reported to meet the disclosure requirements of SFAS 107 and does not purport to represent the amounts at which these obligations would be settled.
24
TRUE INITIAL SERIAL DATE INTEREST OFFERING COUPON OR TERM SERIES OF SALE COST (A) PRICES RATE MATURITIES AMOUNT NUCLEAR PROJECT NO. 3 REVENUE BONDS (Continued) 1993-3A 12-15-93 NA NA Variable 7-1-94/2018 $ 202,140 200, (40 Compound interest bonds accretion 406,583 Revenue bonds payable $ 2,347,120 (8)
Estimated fair value at June 30, 1994 $ 1,985,595 (9) 25
BEST-SERVICE REQUIREMENTS As of/une 30, 1994 Dollars ln thousands NUCLEAR PROJECT NO. 2 PACKWOOD LAKE PROJECT FISCAL PRINCIPAL INTEREST TOTAL PRINCIPAL INTEREST TOTAL YEAR 6/30/94 Balance* $ 972 $ 0 $ 972 $ 116 $ 99 $ 215 1995 8,515 155,993 164,508 333 293 626 1996 51,643 155,722 2071365 347 281 628 1997 68,390 153,296 221,686 367 269 636 1998 72,050 149I283 221 333 387 255 642 1999 120,375 144,980 265,355 422 241 663 2000 131,390 136,978 268,368 473 226 699 2001 168,235 127,944 296,179 498 208 706 2002 92,835 116,371 209,206 523 190 713 2003 212,190 1,10,467 322,657 548 171 719 2004 158,249 107,591 265,840 573 151 724 2005 115,395 111,007 226,402 598 130 728 2006 131,896 93,684 225,580 623 108 731 2007 165,470 86,216 251,686 648 86 734 2008 192,780 64,100 256,880 674 62 736 2009 189,086 59,365 248p45l 572 37 609 2010 202,629 52,718 255,347 274 16 290 2011 166,750 41,673 208,423 122 6 '128 2012 363,365 21,904 385,269 38 2 40 2013 2014 2015 2016 2017 2018 Adjustment" 86,195 (86,195)
$ 2,698,410 $ 1,803,097 $ 4,501,507 $ 8,136 $ 2,831 $ 10,967
- Bond account balances less accrued Investment income.
Adlustment for compound interest bonds accretion; compound interest bonds are reflected at their face amount less discount on the balance sheet 26
NUCLEAR PROJECT NO. 1 NUCLEAR PROJECT NO. 3 NUCLEAR PROJECTS NOS. 4/5 FISCAL PRINCIPAL INTEREST TOTAL PRINCIPAL INTEREST TOTAL PRINCIPAL TOTAL YEAR 6/30/94 Balance* $ 40,930 $ 71,211 $ 112,141 $ 40,735 $ 47,740 $ 88,475 $ 0$
1995 60,400 147,641 208,041 41,760 101,648 143,408 2,174,992 2,174,992 1996 46,565 144,701 191,266 47,475 99,327 146,802 1997 50,770 142,092 192,862 36,490 96,563 133,053 1998 53,020 139,117 192,137 34,555 94,524 129,079 Refer to Note F urutcr Nuclear Projects Nos. 4 and 5 1999 67,275 135,965 203,240 68,150 92,615 160,765 Termination, Bond Default, 2000 71,325 131,737 203,062 73,025 88,247 161,272 and Litigation and Nuclear 2001 76,105 127,203 203,308 71,585 90,107 161,692 Projects Nos. 4 and 5 Bridge and Termination Loans 2002 75,705 122,205 197,910 76,257 86,234 162,491 2003 66,375 117,220 183,595 78,522 84,568 163,090 2004 78,065 113,019 '191,084 62,396 96,206 158,602 2005 70,345 108,016 178,361 63,621 94,365 157,986 2006 87,770 103,463 191,233 64,457 92,640 157,097 2007 93,630 97,693 191,323 59,381 92,903 152,284 2008 100,135 91,265 191,400 61,196 91,181 152,377 2009 104,070 84,282 188,352 63,648 88,827 152,475 2010 111,285 77,352 188,637 66,117 86,461 152,578 2011 135,355 70,067 205,422 84,464 75,450 159,914 2012 144,565 61,213 205,778 98,062 71,717 169,779 2013 156,210 52,609 208,819 95,410 74,630 170,040 20H 165,535 43,397 208,932 98,355 71,817 170,172 201'5 175,530 33,534 209 p064 129,220 41,108 170,328 2016 186,925 23,424 210,349 133,834 36,663 170,497 2017 198,650 11,848 210,498 142,027 28,643 170,670 2018 149,796 21,047 170,843 Adjust>neat" 406,582 (406,582)
$ 2,416,540 $ 2,250,274 $ 4,666,814 $ 2,347,120 $ 1,538,649 $ 3,885,769 $ 2,174,992 $ 2,174,992 27
/-
C v
, NOTES TO FINANCIALSTATEMENTS 'a =/
C r ~ . 1
'I
/ C V
NOte A - General . ~ " .-and-substantially all.of the utility plant. assets have been sold..
Eighty-eight project participants in Nu'clea'r Projects'Nos. 4 and 5.
'/ I were originally obligated/by contract to pay annual costs of The Washington, public Power Suppiy System (Supply System),.a Nuclear Projects=Nos. 4 and 5, including debt service, wiiether or-municipal coiporatibn and joint operating agency of the State of . not the projects were completed. However, these contracts were Washington, was organized in 1957. It is empowered to finance, declared htvaIId. Nuclear Project No. 4 Is, whollY-owned Qy the
, acquire, construct and operate facilities for the.generation and, SuPPIYSystem. Nuclear Project No.5 is jointlY-owned,90per~cent
'transmission Iof electric power. On June 30, 1994i its membership b) the SupPIY System and 10 Percent by.PacifiCoip (see.Not<F-
/ /
consisted, of 10 puMic utiiitydistricts and the cities of Richland,
~
Nuclear Projects Nos. 4 and 5 Termination, Bond Default, and
/
Seattle, and Tacoma. All members own and operateelectricsys- ' " g h tems within th+etate of Washington. The. Supply System has no . Each Supply Systqm pqoject'is financed and acc'ounted for as a
-'axing authority... - - =; 'tility system separate from all other "current or future with the exception of Nuclear Projects Nos.
projects, 4 and 5 which are SUPPLY SYSTEM I'ROJECTS '
l
~ '.",, 'treated. as one utilitysystem.,'
The Supply System operates Nuclear Project-No. 2;a 1,120 MWe All electrical energy produced by Supply. System projects is deliy-(DER net) generating plant Completed in 1984, and the Packwood Lake Hydroelectric project (pack(vood), a 27.5 MWc plant corn-cred to electrical distribution facilities owned and as part of the Federal Columbia River poweiSystem. BpA In turn operatedby BPA
'/
pleted in 1964. "
~> distributes tlic electricity.to electrl'cal utility systems throughout
'The Hanfoid Generating Project-(HQP), an'860 MWe plant,~
~
theNorthwest,includingpartlcigantsinSupplySystemProjects,
-..previous
-Previouslyusedby uctsteam romt e epartmento Energy s productsteamfromtheDepartmentofEner-/s for ultlmatedlstr!bution toconsumeD. BPAisobllgatedbylaw to yuse y-pro ~-
not 0 crated since the shutd wn of tile N Reacto in'1987 As a-acquisition and-BPA s other costs. See Note E, Security- Nuclear
- result of the Secretary of Energy's decision to place tlie N-Reactor P<<jects~Nos. 1, 2 and 3, for disa ssion of BPA's obligationsgvith .
in permanent shutdown, tiie Suppiysystem has evaiuatedalferna- resPect to N0ciear Prolects Nos. I', 2 and 3. BPA has no obligations - ~
tfveenergyusesforthepiantandanticipateseventuaitermination wit resPect to uc ear rojccts os. an of HGP and subsequent removal and site restoration (see Note F-
.sanford Generating Project). =-emote B - Summary of SignificantAccounting
. Nu'clear
,. "Policies
- W Project'No. 1, a 1,250 MWe plant, is $ 5 percent complete i and has been in an extended construction delay status since 1982.;
BASIS OFJCCOUHTllVG Nuclear Project No. 3, a 1 2403vIWe plant,.is 75 percent complete.
and has been In an extended construction delay status since 19tj3. -
Tlie Supply System has'adopted accounting policies and practices On May33, 1994, the Supply System's Board of Directorsadopted 'hat are in acco'rdance wi'th generallyaccepted accounting prin-resolutlonstermlnatingNuclearprojcctsNos. Iand3.TheSupply 'iples Applicable h to governmental utilities. Accounts are maln-system has enteredgntoan agreement with the Bonneville. Power taincd in accordance with the uniform system of accounts of the Adminis(ration (BPA) to provide continued fundin'g for th<exlst- Federal Energy Regulatory Commission. Separate funds and books ing preservation programs, -including the maintenance of'all- of account are maintained for each utility system. Payment of federal and,state licenses and permits until January 13, 1995, or obligations of one utility system with funds of another utility, such other date as may.be mutually agreed upon by BPA and the, system is prohibited, and would constitute violation of bond
/ /
Supply Systein (see Note. F - Nuclear Projects 'Icos. 1 and 3 . resolution covenants..'
Project No.1 is wholly-owned by the ~ /'erminatibn)~Nuclear Supply System. Nuclear Project No. 3 is jointIy.owned, 70percent-
~
by the Supplysystem>>d 30 P<<<<nt /"by four.invest<<-owned Utlllt t't d att original tiis stated i Pl tlln service cost.t Plant I is deprqciated t d
, Utility plant I utilities (PaciflCorp, Portland General Electric Company, Puget b the by t i ht I th straight'-line, tl estimated th d over the method ti t d useful f I lives li of the
- Sound Power R Light ICompany,"and. The Washington Water I'"
various classes I off plant. 0 Power Company).
' 'uring tlie normal construction phase of,a project, the Supply Nuclear Projects Nos. g and 5)vere terminated in January 1982; st,s .t l. all System's policy li is. to t capitalize Il costst. relating I ti t the to th project,t l *
/ / '/
/ 28 ,
'I
/ 0 /
r )
t
- T
'I
~
~ P si r ~
p i
~
including interest expense (net of interest income), and adminis- Supply System will receive'equivalent quantities of uranium in trative and general expense. " .
future years, Additionally, the Supply System receLyes usage fees
'M value I in I anticipation I t off for the transferred uranium. Tliese'xchange agreements'have HGP has been reduced to its net realizable project termination in fiscal f aI year. 1995 (see ( N Note F - H f Hanford d,.been Secured by bank letters of credjt at current market value,
- adjusted'semiannually. Thecostof this uranium, $ 29.9 million, ls Generating Project).
P j )
included iiIthe carrying amount of Nuclear Project No. 2 Nuclear Because of the extended delay ofJ uclear Projects Nos:1 and 3, tlie, Fuel. The contract value of the uranium, $ 39.7 million, is Inc~uded SUPPly System discontinued caPItalidng intereSt exPense and: in theciar ingamountof NuclearprojectNO. 1 Nuclear Fuel Held preservation costs. Interest exp'ense, termination expenses and
~ asset disposition costs for Nuclear Projects Nos. 4 and 5 are charged 'o current operations. RESTRICTED ASSETS NUCLEAR FUEI,,:, t
~
In accordance with project'bond resolutions, rejated agreements, oi state law, separate restricted funds'have been established<for All.expenditures related to tlie Purchase of nuclear fuel are each rojea. Tlie assets help In these fu'nds are restricted for caPltallzed and carried at cost.,When tile fuel ls Placed In the 'eclfic,uses including construction, debt service, capital addl-reactor,thefuelcostisamortizedtooperatlngexpenseonthebasls tlons extraordlna; 0-eration and maintenance termination of quantity of heat produced for generation of electric energy.
~ Accumulated nuclear fuel amortization as of June 30, I994 for Nuclear Pioject No. 2 is $ 94 million. Current period operating, LONG.TERiM RECEIygBLES expense foi Nuclear Project No.2 includes a cliarge fdr future spent nuciear fuei storage and dispo'saI to be Provided by DOF in,= Long-term receivables include minimum guaranteed amounts V
accordance with the Nuclear Waste policy Act of 1982, and a pertainlngtofuturediscountsforcertaingoods,andservicestobe' charge. by DOE forclean-up of its nucjear enrichment faclllties, ln - provided to Nuclear Project No. 2 as tile result of a litigation accordance with the Energy Policy Act of 1992. No provision has been made for additional storage and disposal costs which may,be incurred by the Supply System prior to the transfe'r of spent fuel to .,
DOE. Estimated Nuclear Proje'ct,No. 2 decdmmissionlng cdsts are ac-I On October 28, 1993, the Supply System's Executive Board de- cruedbasedoncurrentfundingrequirements.Monthlypayments .
,clared Nuclear project No. 1's nuclear fuel reload uranium to be are made into a sinking fund which, withaccumulatedIntcrest, is
'f excess to the current needs of the project and approved the sale or " 'xpected tobeadequate to fund decommissioning costs at the end other disposal of such uraniUm. On December 15, 1993,-the the 40-year plant operating life. Decommissioning costs are
'l Supply System executed a contract with Nuxeco Trading Corpora-, currently estimated at $ 357 million (in 1987 dollars). Payments to tiontoselltheexcessreloaduranium(approximately R6mlllion the;decommissioning fund for the year ended June 30,~.1994 KgUasUF6).Asaresultofthissale,theSupplySysteinreducedthe aggregated $ 3.1.million and the balance of the fund at June30, book value of the, uranium for financia reporting purposes from 1994 was $ 25.6 million.
$ 183.9 million to a contract value of $ 52.8 million.
NATLRIALSAND SUPPLILS On July 28, 1994, the Supply System's Executive Board declared the Nuclear projects Nos. 1 and 3 uranium acquired for nuclear 'aterials and supplies are valued at cost', using weighted-average fuel to be surplus:and excess to the'needs of the projects and r
. methods.
authorized the sale of all Nuclear Project No..1's uranium hexafiouride and enriched uranium product and Nuclear ProJect . P?NANCING EXPENSE, BOND DISCOUNT, AND
'o.3'suranium.Asaresultofthlsdecision,theSupplySystemhas ., DEFERRED GAIN ~
'/ I reduced the book value of nuclear fuel for financial reportmg, '1 Financingexpense,b nddiscbunts,anddeferred'gaqnonredemp-PurPoses from $ 79.6 million to a market value of $ 41.9 million f t f b d t d ove th t and from $ 34.8 million t'o a market value, of $ 11.7 million for respective bond issues.
Nuclear Projects Nos.,1 and 3, respectively. This amount has to Nuclear Fuel Held lor Sale. - been'eclassified
) REGULATORy STUDIES certain exchange agreements;the Supply System can trans-n'nder Expenses associated with regulatory studies for Nuclear Project fer to third parties approximately 3.2,million pounds of Nuclear J4o. 2@re deferred and amortized by the straight.line method over No. 1 uranium (equivalent U,O~) and 2 million pounds of 'roject
~ the estimated operating life,of the plant.
Nuclear Project No. 2 uranium (equivalent U,OJ. In return, the 1 III 29-
'or c
T F s If
)f e t
- r sr / r e
'I I
) ) )
f A J .
F s
)
f CURRENT MATURITIESOF REVCNUL BONDS,< (liability) or as costs in s
eifcess of billings,(asset), as appropriyte.
Such amounts will be recognized as revenues, or costs, during Current maturities of revenue bonds payable from restricted assets
.are reflected'in gng-Term Debt. Current maturities of bonds for.
'hich fuiids have not yet been restriCted are reflected in Current 'TATEMENTS OF CQSH1 LOIVS Liabilities.
purposes of the statements of cash flows, cash Includes F
,FAIR VALUEOF FINANCIALINSTRUMENTS unrestricted and.restricted.scash.balances. Short-term, highly-liquid investments are,not considered cash equivalents.
~ t '-, The-fair value of financial Instruments has'been estimated using available market information and appropriate valuation method-'ote C - Cash and'Investjnents:
ologies. Considerable judgment Is requiied in interpreting market not,, maintained; Cash'nd inves'nts for each utility system are seParately,-
~data to-develop fair value estimates and such estimates are necessarily indicative of the amounts that could be reaflzed in current market exchange. The.following methods and assump-a, 4 The SuPPIY System's dePosits are insured by federal '1 dePosltory insurance or through tlie Washington Public-Deposit F
tlons were us'ed to estimate the fair value of each of the following',- 'rotcctloii Commission. Supply System investment policies limit
-'financial instruments g " inv'estment authority to obligations of the United Sta'tes Treasury,'r Cash,.a'ccounts receivable, accounts payable arid accrued cx-penses, other noncurrent liabilities and due to and pants,'other projects'and other, funds: The carrying'amount approximates fair value.
Investments and revenue bonds pa)iablc: The fair value isbased on from'partici-Federal National Mortgage Associationgederal Home Juan Banks; Farm Credit System and Federal Home Loan Mortgage Corpora-tion,'as well - as",repurchase agreements. Collateral for* repurchase
~ agreements must beauthorizedinvestments
~, investinent policiesr The Supply System did not invest in repurn F chase agreements during fiscal year 1994.Allinvestments are held'.-
under Supply System
,quoted market prices for such instruments or similar instruments. In the Supply system's name by safekeepingagents, custodians, or
<'51ie fair value of revenue bonds payablc'currently in default is not determinable due to litlgatfon contingencies.
Investments a'e stated at-amortized cost and include accrued interest. The Supply System's investments are categorized below
'I to give'an indication of the types and amounts of investments With the exception of Nuclear Projects Nos. 4 and 5, the Supply held by each project at year-cnd.', ',
System recovers, through various agreements, actual cash requlre-FV ments for operations and debt service for ea'cl) projcctover the life I N0te 9 'etj I emejjt Qenefjts, )t of that project~Accordingly, thc Supply'System recognizes rev-Substantlally all Supply System full-time employees participate in enues equal to operating costs for each, period. No net'income or the statewide local government Public Employees'etirement
,loss is recognized, and no equity is accumulated.
System (PERS). PERS is a'contributory multi-employer cost;shar-
'fhe'difference between cumulative revenues received and cumu- ing retirement system.established by the Washington State Legis-f " )
lati'veoperatlngcostsisrecordedaseitherbillingsinexcess ofcosts -
lature and,'administered by the State of Washington through the,.
s
)- F II, INVESTMENTS U.S'. Gov't, U.S. Gov't, Carrying'=-
.(Dollars in thousands) Sccuntlcs 'gencies
'ote)856'ccrued Interest Amount NUCLEAR PRO ECTNO. 2 Amortized cost Fair value ' ' W
$ 152,249
.> 147200 a
.; $ 78,954 78 656
$ 231,203 225
$ 3,240 $ 234,443 PACKWOOD LAKE PROJECT r - te Amortized cost "" - 2,045 ' " '- 2,045 -0;.
F 2,045
- - a . e Fair value 2 044 ' 2 044 HANFORD GENERATING PROJECT Amortized cost Fair value ~
NUCLEAR PROJEGT NO. 1
- ~.. . '
" 8,204 8 199
=
F 8,204 8199
- -0= ',204
=
Amortized
'Fair value cost, ": t
",16$ ,483 246 206
, ~
202;166, 133 769, 365,649
~ 379 975 ~
4,334 369,'983
- NUCLEAR'PROJECT)NO. 3 Amortized cost ) 82,588 119,575 I
202,163 - ' 2;463 204,626.
Fair valuet 77 566 119 587 -197 153
~ Amortized cost '
Fair value '~,
NUCLEAR PROJECTS. NOS. 4/5 .-', .
~
..) '4,154>>
~
54,167 -
e 30 30 54,197,
.54,184
~ .
1,63K
" . 55,832 30-
h '1 4, ~
1
'I 1,
~
~ 4 r I ~
- p / / r
/
Department Ihf Retirement Systems. For the year ended June 30, State of Washington's Junc 30, 1993 compreh'ensive 'annual fi-4 1994, the Supply Systems payroll covered under PERS was $ 94 . nancial report.
million, rePresenting 94 Percent of total Payroll.,
r ~ in addition to the pension berlefits available through'PERS, the',
PERS contains two plans". Plan I members (employed on or before . ~, Supply System offers postemployment life insurance benefits to
. September 30, 1977) may retire with fullbcneflts at age 60 with at. rctirees who are eligible to recclv'e pensions under PERS Plan I and least five years ofcredited service,'at age 55 with 25 years of service, Plan Ii. Currently, 18& retlrees are eligible to receive lifcinsurance
/ 4 or, upbn reaching 30 years of service, regardless of age. Plan II , benefits and 141 retirces have elected to partldpate in this insur-me'mbers (employed after September 30, 1977) may retire with full ' ance. The, life insurance benefit Is equal to the employee's annual benefits at age 65 with at least fiyeyearsof credited service, or with rate of salary at retirement for non-bargaining unit employees and .
J I' actuarially reduced benefits at age 55 with 20years of service. The, onchalfoftliecmplqyce'san'nualrateofsalaryatretlrement, with annual pension b'eneflts are generally based on'a percentage of . a. minimum benefit of $ 22,000, for bargaining unit employee's.
ffnal average salary. p h
', '",r= 'etirees contribute $ 6.60 per $ 1,000 of coverage II, annuallyifor'life'Required insurance,and theSupplySystemfundsthedeathbenefitclaims employer contributions for both plans and PERS
. employee contributions, are determined each biennium by the Legislature. Employee, contribution rates for, Plan I are established At the.time each employee retlresl the Supply System accrues a 1
by legislative statute. Employer rAtes for Plan.i are not necessarily, liabilityfor the actuarial present value of estimated claims, net of adequate.to fully fund the system. The employer and employee - retiree contributions. The total liabilityrecorded at June 30,.1994 1
contribution rates for Plan li are developed by the Office of State was $ 2.6 million for these bene/its.
ActuarytofullyfundthesystemThemethodsusedtodetermine ~
During fiscal years 1994 and 1993,, pension costs for Supply 4
I thecontributionrequlremcntswereestabllsh'edundcrstatestatute. System employees and postemployment jlfe insurance benefit As of December 31; 1992 (the latest actuarial valuation date), the costs for retlrees were calculated and allocated to each project. - ..
-pension beneflt obligation of PERS, which Is the actuarial present based on direct labor dollars. Approximately 93 and 92pcrccntof-4 4 value of credited projected benefits adjusted'for the-effects of all such costs were allocated to Nuclear Project No. 2 during fiscal 14
~
projected salary increases, was $ 9.758 billion and the value of net . years 1994 and 1993, xespectively.
assets available to satisfy present;and future pension benefit. "
obligations was $ 8.344 billion. The pension benefit obligation Is, - N0t+ E a standardized measure which enables readers of financia state-4 I 0>~g Te<m D<bt Except for Nuclear Projects Nos. 4 and 5, which were rinanced ments to assess the funding status of eaclgsystem and progress together as one utility system, each Supply-System, project is made in accumulating sufficient assets to.pay benefits when due',
4 financed separately. Thc resolutions of the Supply System autho-and,to make comparisons with other,retirement systems. The rizlnglssuanceofrevenuebonds for eachprojectprovldcthatsuch standardized disclosure method is independent of the actuarial bonds are payable solely from the revenues of that project.
funding method used to determine,contributions.-
During the year ended June 30, 1994, the Supply System issued
'Supply System contributions for the year ended June-30, 1994, ~
7 4 billion in net-billed bonds forNuclear Projects,Nos. 1, 2 and
.$ 2.4 expressedbothlndollaramountsandpercentagesofcurrent-year
/ I' V 3 to refundd $ 2.131 2 billion I off outstanding b d with dl bonds I h an average covered payroll, are shown ln table below.
'nterest rate of 6.36 percent. The net proceeds of the new Issuhes I
The Supply System'sI actuarially determined employer contribu. ' were deposited In separate irrevocable trusts under thc control ofq requirement represents approximately 2.1 percent of the
/'ion escrow agents to provide for all future debt service payments on total for all employers coverc(I by PERS. " ~ .,the refuntled bonds. As a result, the refunded bonds areconsidered s ~
Historicai trend information showing PERSI progress In-accumu- -to be deleased and the liabilitylor those bonds has been,removed.
lating sufficient assets to pay benefits when due is presented in the from long <<rm debt" r
Although the advance iefundings resulted in the recognition of an plan I pjan 11 accounting loss for thcycar ended June 30, 1994, the change ln the
'ate Rate Amount
~, ', '," Amount "
aggregate debt service payments for Nuclear Projects Jatos. 1 2and Employer. Contributions. /' '-','3 and changes to debt service rcselve fund balances resulted In an Actuarially determined '. economic gain of $ 74.5 million, $ 68.3 million, and $ 116.4 mil-requlrement, 7.4196 $ 986,041 7.41% $ 5,976,341 h lionrespectively. The range of the economic gain for the variable System'contrIbutions 7.5696 $ 1,005,622 7.5696 $ 6 098 816 . rate debt (Series 1993 1A/3A) as defined by Statement No. 7 of the Governmental Accounting Standards Board'Is $ 51.5 million to hhtctuartally determined requirement '.00%'798,239 5.20% $ 4,193>924 $ (58.8) million and $ 71.2 million to'$(80.6) million fof Nuclear Actual em lo ee " projects Nos. 'lhand 3r respectively.
contributions l 6.00% $ 798,239 4.98% $ 4,0i4,852
'ixed at 6.0096 h
'I r i 4 h
4 31 4
'1 1
d FISCAL YEAR 1994 BOND REF UNDINGS (Dollars ln Thousands)
'Scric 3223II Sclics1223G ' hlLScrics Size of Issue /- $ 189,710 $ 167,890>> $ 153,330 $ 510,930 Amount of bonds refunded 175,075 137,240'7,732 32,870'clllx12~
153,330 465,645 Accounting loss ' 21/660 3,899 r .53,291 Reduction In aggregate debt service ~
22,015 ',058 61,943 Size of Issue $/19/43S. $ 661,83f Amount of bonds refunded 203,175 558,785 761,960
. Accounting loss 7,161 39,600'881,266 95,'108 102,269 Reduction in aggregate debt service 11,808 =51,408 of $ '282,25S $ 522,853, '202,140 ' $ 1,007,248 Size
/ Issue
/
Amount of. bonds refunded 268,63S '32,455 202,140 903,230 Accountlug
'r loss 7(897 /r . 85,474 ~
r 5,554,.>>-= 98,925
'Reduction In aggregate debt service '17r 663 20,222 - 82,467
/ '4,582'nnual "Variable,rate assumed at 4.5 percent rate for reduction, in aggregate debt service:,,
I ,t In prior fiscal years, theSupply System defeased certaiq,revenue " .that project participants and BPA are obligated to make such
/
bonds by placing the proceeds.of new bonds in'irrevocable trusts r payments whether or not the projects are completed, operable, or to provide for all future debt service payments on the old bonds. operating and.nojwithstanding thc suspension, intcriuption, ~
the trust account"assets and the liability for'the 'nterference,reductionorcurtallmentoftheprojects'output. The .. 'ccordingly, defcased bonds are not included in the-financial.statements.. validity-of thc net-billing agreements was challenged in Novem-Including theflscalycyr1994defcasenicnts, approximately $ 708.7 ber 1982:In May 1983, the U S. District Court of Oregon declared
$ 890.7 million,'and $ 685.6mllllonofbondsoutstandlng .that the net-billing agreements werc binding, and this
'as
'illion, decision're considered defeased at June 30, 1994 for Nuclear Projects Nos.: upheld on appeal.
I OnMay13/1994, theSuppiySystem'sj oardof Dliectorsadopted A summary of ffscal year 1994 Series 1993B, 1993C, 1993-IA/3A resolutionstcrminatingNuclearProjectsNos.land3,TheNuclear.
1994A bond refundings by project'is presented above.- ProjectS Nos. -1 and 3 project agreements and the net-billing e'nd
~
=
The Su I 'S stem cx ccts to-continue the refundln of hl h-
--. agreement',exceptforcertainsectionswhlchrelateonlytobllllngr interest bonds when economicafly feasible. ~,,r . Processes.and.accrued liabilities and obligations under the net-billingagreements, ended upon termination of thc.projects. The Outstancjing revenue bonds of the various projects as of June'30, Supply System has entered into an agreement with BPA to provide 1994, arc presented 6n pages 21 thro'ugh 25, and debt service continued funding for the existing preservation program until requirements for these b'onds are presented on pages 26 through 27.
/ january,1995 and forcontinuation of thc preIent'-budget ap-STYL+p0ECSpOSN+Proval,billing P
and Payment Processes. ithrcsPect to Nuclear Project No. 3 the ownership,agreement among the Supply-Sys-
/
Project participants and five investor-owned utilities for Nuclear 1 tem, Pu'get Sound"POwer gr Light Company, PaciflCoip, Portland >,
Project No.1 have Purchased all of the Project caPabllity of r 'eneral Electric ComPany and The Washington Water Powei Nuclear Projects /'
Nos. 1 and 2 and the Supply System's 70 peic4nt Company remains in effect following termination.
ownership share'of project capability of-Nuclear Project No. 3.
' SECURITY - jVUCLLARPROJECTS N5S. 4AND 5 '
'BPA has In tuin acquired the entire project capablllty from the project participants under cbntracts 'referred'to as nct-billing agreements.;Under the nct-billing agreemcnts for each of the ~"
In connection
~1 enue y
'h ji with th d ffor Nuclear'Projects bonds, N I p thc1ssuancc 1 s cc off the N 4 I Nos.
fl generating 4'and facfliflcs rev-ti facllltlcs 5; the Supply System pledged the revenues to be derived under participants'agreements System their Pro rata share of total annual costs of thc resPective tllltl operating ith 88 utilities I i ll In t The ti principally. I the N th th Northwest. Th'ith dcbtservicconbondsrelatin toeachproject, participants'greemenis provided that each participant pay Its'occts,includin and BPA.ln turn Is. obligated to Pay-the ParticiPants identical respective share of annual costs, including debt service on the
='bonds, wyether or not the.projects werecompieted,operabie, or
=- BPA power sales agreements.'The net-billing agreements provide
' i 4I 32: /' llr
h J
i J
J II i')
~
operpting and notwithstanding the suspension, interruption, January 13, 1995, or.sucIi other date as may be mutually-agreed interference, reduction or curtailment of the projects'utput. 'pon.byBpAandtheSupplySystem. TheSupplySystemandBpA payments from the participants for Nucle'ar projects Nos. 4 and 5 executed post termination agreements for Nuclear projects Nos. 1 termination costs and debt service were due beginning on January j and ) on June 14, 1994,"in which BPA agreed to continue funding 25, 1983's a~suit of a ruling by the Washington State Supreme for preservation of the projects to evaluate alternative uses for and declaring the participants'greemerits invalid, payments . to facilitate the marketing of the projects until January 13, 1995. 'ourt due.under the participants'gieements were not made and an
- event of default, as defined in the bond resolution; occurred on Tl t t d t I ti f tl 's as July22, 1983(see Note F-Nuclear Projects Nps.4and5 Termlna= ., relate only to billing process~ and accged liabilities and,obliga-:
- ..tions. The post termination agreement provides for an assured SECURITY - IIANFORD GENERATING PROJECT, the present budget approvat, billing and payment processes. Tlie SP
. It was initially.intended that Nuclear project No. 1 be constructed Ownership agreement among the'-Supply System, I"uget Sound
'I~
next to HGP to provide the. energy source to operate the project * ',Power Sr Light Company,. PacifiCorp, Portland General Electric j
- when DOE,ceased operation of the N-Reactor. To allow for Companyand The Washington Water Power Companyremalns
/
construction of Nuclear Project No. 1, it would have been neces- in effect following termination.
sary to shut down HGP on'October 31, 1977, Because studies at .c that time indicated that generating respurces in the PacifleNprtli. -s COST SHARING LITIGATION west ~voujd be inadequate in the late 1970s and early 1,980s, tiie N
NuclearI d4 f b Projects Nos. 1and4areofsubstantiallythesamedesign-I B Supply System and BPA deterrrjjned that HGP should. be kept and are referred to as "twin units." Nuclear Projects Nos. 3.and 5 (
'p avajjabjeforppwerpioductjon.Therefore,theNucjearPrtjjectNo. ~ '
I "t I units are also"twin jt off substantiallythe b t tj ll th same design.
d As costst off 1 net-billing, exchange and piojectagreements were amended to hi /
architect/engineer services, construction management services, provide for the separation of Nuclear Project No. 1 from HGP.,
'I certain common equipmentused in theconstruction oftiyinunlts
-The amended agreemtnts provided for the payment of all HGP and other costs incurred by the. supply System benefited both l
debt service costs, net of investment'income, by Nuclear project- units, it was concluded that those costs should be shared by the t
No. 1participants, beginning July 1, 1980;regardless of continued, twin units, The Supply System allocated such shared costs on the operation of the N-Reactor, and'that other costs, to'the extent not basis of respective benefit to the projects involved in accordance otherwIse provided for, be treated as Nuclear. project No. 1 costs> withapollcystatementadoptedbytheSupplySystem's Executive with HGP haying a first claim on. the. revenues of that project. ~ - Cpnimittee.
4 In Aujust 1982, the Participants'ommittee far Nuclear Projects pROJLCT
'os.'4 and 5, on behalf of the project participants, demanded that the Supply System reallocate $ 161 million, plus interest, in shared Under power sales agreements, 12 ptiblic utility districts have -
costspreviouslypaidbyNuclearprojectsNos.4 and 5,based ona purchasedalloftheprojectcapabilityofpackwood. Thepurchas- i'evlsed formula, for sharing'of costs which it prepared;, The ers are obligated to pay annual costs of the project, including debt demand indicated this was not tire, total extent of claims which E I service, whether or not the project is operable,'until,outstanding could bemade by the Nuclear Projects Nos. 4 and 5 participants, bonds arepaM or provjsion is made for the retirement In accor- The investorowned utilities(IOUS) owning 30percentof Nuclear dance with provisions of the bond resolution. Project No. 3 asserted t jurat they, are entitled to set off the amounts r
owed by the Supply System on bridge and termination loans made Note P - Commitments and Contingencies for Nuclear Projects Nos.4 and 5 ln1981, totallng$ 12 mijjionpjus interest, against any cost-sharing reallocation obligation.
NUCLEAR PROJECTS NOS. I AND3 TER/jIINATION In ()ctober 1982, the Supply System filed a complaint for declara-
, fn April'1982, the Supply Systein commenced a construction delay tory judgment In Federal District Court for Western Washington, of Nuclear project No 1, and ln July 19jj3, lt commenced a naming-the participants jn Nuclearprojects Nos, 1,2,3> 4and5,
'onstruction delay of Nuclear project Np,3.'On May 13, 1994, tile BPA, the four IOUs owning shares ofNuclear project No. 3, and the Supply Sysfem's Board of Directors adopted a resolution term jn'at-; bond fund trustees for Nuclear projects Nos. 1 and 3 as defendants, ing Nucjear projects Nos. 1 and 3. Additionally, the. Board pf and asked the court tp declare the rights,and obligations of the Directors recommended'to the Executive Board that the Supply parties with regard to the allocation of costs among the projects.
-.Certain other claims have been flie as part of this action. In May
. System enter into an agreement with BpA to provide contin'ued, funding for the existing preservation programs, including the maintenance of all federal and state licenses and permits until I
's " 1983,thedourtdesjgnatedBPAasthepjaintiffandajjotherpartjes defendants. The case is captioned c
33
1 J
I In June 1983,'Chemical Bahk intervened as'bond fund trustee on t
j The Supply System executed agreements in September. 1985 to
~
behalfof the Nuclear Projectspfos.,4 and 5bondholders. CQhemical c= '
settle the construction delay claims viith BPA'and with each of the Bank alleged that the Supply System's allocations of costs among IOUs otvnlng shares of Nuclear project No. 3. A number of. the the twinned proJects were improper and that repay'ment to the,nuclear ProJect No. 3 participants have opposed the settlement JC Nuclear projectd Nos. 4 and'5 bond fund was required for 'such . and dismissal of'claims. In October 1985, the participants filed costs allegedly improperly allocated. pleadings in the U.S. District Court assertlngichallenges to the in May 1939, the District Court ruled that the cost agocatlon . Nuclear ProjectNo.3settlementagreementsbetweenBPAandthe
\
procedures used werc improper and tiiat Chemical gank has a iien . 'OUs. None of the agreements executed, by the SuPPIY Sy)tern has ."
I At inanamountofanyfundswhlchmaybedetermlnedlnthefuture -been challenged. Howeerr the Pleadingsfiled by some Partlci-
.tohavebeenlmproperlyexpendedasaresultofcostsmisallocated pantsalsolncludeclalmsagalnstthesupplysystem,theIOUsand
.toNuclMIProjectsNps.4andS.Thecourtstatedthatanyenforce-'PA unrelated to tile validltyof tllesettlemeng. In July~986,-the Ii nient of the lien must await resolution of the issue of whether ~ district court dismissed the claims challenging BPA's authority to pl there was any improper agocation. In October 1990,'the "District enter into the Nuclear Project No. 3 settlement agreements With ruled that the Nuc fear Projects Nos.4 and 5 gong Resoiution the IOUs and staYed all other claims relating to or arjsing out of the 'ourt required theapplicatlon ofcost allocation principles'similar to tliose construction delay or the settlement., ~ ~ ~
r espoused by Chemical Bank. The court stated tha't bec'ause such An original proceeding also was filed in the-U.S. Court ofAppeals
~
piinciples were not applied, Nuclear Projects Nos. 4"and 5 appar- for the Ninth Circuit, challenging BpA's settlements with the
)
ently bore moie than tlieir fafr and equitable sin're of construction IOUs; In January 1989, the Court of Appeals rejected all statutory .
costs. The court granted Chemical Bank's motion'or an account- ~ -
cliallenges to BPA's settlements 'affirmed BPA's authority to enter ing of all uses ofbond proceeds of Nuclear'projectsNos. 4 and 5.'
\ the settlements, and dismissed other claims, including claims
~e Supply System and other parties in the case appealed this against thQ IOUs and the SuPPIY System', for lack of, jurisdiction order to the U.S. Court of Appeals for the Ninth Circuit, and In InMay1989,theDistrictCourtdlsmissedtheclaimsofallbutnlne r" February 1992, the Court of Appeals reversed both the May 1989 of the Nuclear ProJect No. 3 participants against the Supply and October 1990 rulings. The Court of Appeals upheld the System, BPA and the IOUs relating to or arising out of the
.proportional cost sharing method implemented by the Supply- construction delay of Nuclear project No. 3 or the settlement, System's Policy Statement, reversed the lower court's finding of a,pursuant to a stipulation of the parties. No action has been taken, I
lien on misallocated funds, and remanded the case to the District, by tfiese nine non-stipulating'participants since. the May 1989 Court for resolution of the remaining issues in "accordance with -
district court ruling.< 'i the Court of Appeals'ecision.
The four IOUs owning 30 Jpercent of Nuclear project No."3 also Prior to the reversal, counsel for Chemical JIank had publicly 'iledcomplaintslnstatecouitsin King County, Washington,and estimatedthepotentialrecoveryforNuclearprojectsNos.4and5 Multnomah County',-Oregon, in May 1983 seekjng declarative, at up to $ 1 billion, including interest. Ifa judgment were awarded in favor of Chemical Bank and costs previously allocated to 'o. and equitable relief and damages because of the Nucleaf project 3 construe'tion delay as claimed by them In tu~upplg I Nuclear projects Nos. 4 and 5 werc allocated to other Supply J
=
The case'is 'still in the discovery phase and in April 1994 a>>
settlement master was assigned to the'case~he order appointing .
i'o ~II,~LIILThese cases were flied as a precaution against any System projects, such amounts would be treated as constructiondetermination that the Federal District Cdurt lacked jurisdiCtion
'costs of such projects. -
try the Nuclear project No. 3 construction delay claims. The r/
WashlngtoncasewasdismissedwithoutprejudiceinMarch1992, Proceedings in the Oregon case are stayed bY stiPulation of the
~
the settlement master provides that all communications with the'arties. The Parties have agreed,to dismiss the Oregon cas'e after C.
settiement master be kepf confidential and that the parties may
~
final dismissal of the parallel'claims in tire Federal Court and the I, .*q fina'i dismissal of anY claims challenging the Nuclear Project No.
1 not disclose any information reiatlng to the status of settlement.~ JE activities. 3 Settlement Agreements.
The Supply System'is unable tp predict the 'putcpine pf this c if the settlement aSreements between BPA and tiie IOUs are litigation.
~ - determined to be Invalid or unenforceable, the IOUs might renew
.their'lalnt that they, are entitled to rescission of the Nuclear NUCLEARPROJECTNO.3DELAYLITIGATION Project.No. 3 ownershipagreement. However, the.lOUs Jiave agreed In their settlement agreements with tjie Supply System not In July and'August/983, the four IOUs owning 30 Percent of -toassertanycialmagainst theSupplySystemformoneydamages, Nuclear Project No,3 filed dalms against BPA, the SuPPIY System restitution or in'unct've rel'ef
.and the Nuclear Project No.'3 participants assert'ing that they The Supply System is unable to predict what results willbe ff ed ddamages suffered ma lt off tile as a result I extended t ti n dde fay off I d d construction wjth respect to these claims.
reached'uclear Project No. ~. )
/ /
<34
I r r I It
-t
- II r
't GLNERATING PROJECT I-contract, and sought monetary damages, rescission and restitu-'
I'ARPOON@)
'GP, completed in 1966, previously used by-product steam froin,. tlon. The lawsuits sought'to recover the bondholders'nvestment DOE's N-Reactor, and has not operated since the shutdown 1
of the,'n t.
the principal amount. of $ 2.25 billion, plus unspecific) dam-In 1987r The fedeial gov'ernment's,decision to place, the ages, interest, costs and attorneys'-fees. '-'Reactor
/ \
N-ReactorfnPermanentshutdowneliminatedtheN-Reactor'asan =,
In $ eptember 1988, the Suppiv System's Executive Board ap-energy source for HGP The Supply System has evaluated alterna- proved an agreement to settie tlie securI)les litigation.'The agree-I tlveenergyuses for theplant tonoavall Current'optlonslnclude 'ent called for the Supply System to consen't'to entO of a a transfer to DOE for removal and site restoration, or removal and ~
. Judgment on tlie contract claim on theNuciear Projects Nos g and
,site restoration by'the SuPPly Systein. At this time, it is unknown 5 bonds brought on behalf of bondholders. pll other "claims i
what the eventual disposition of HGP willbe. The Supply System against fhe Suppiy System were to be-dismissed with prejudice.
has reduced the assets of HGP to their net realizablevalue and has The ainount of the judgment was to equai the aggregate unpaid ~
accrued for the estimated cost of removal and siterestoration;; 'rincipal'amount o(the Nuclear projects Nos. 4 and 5 bonds and Certain preservation costs of IfGp have been funded by DOEsince 'ccrued 'I tt interest thereon at'the time the judgment was entered...
tt
. 1989under a supplementalagreementbetween the Supply System -Recourse for satisfaction of the judgment was expressly limited to andiDOF This agreement expired June 30, 1992. preservation' the funds and assets of the Supply System pledged to secure the costs were funded by Nuclear project No. 1 between June 30', 1992 ~ Nuclear projects Nos. 4 arid 5 bonds. The settlement, agreement I'nd September 30, 1993, at,which time preservation of physical
- provided that judgment would be entered upon final judgment or 1
assets was discontinued. final settlement of all suits covered by the settlement.
r r All, other defendants In the securities litigation and the State. of
. Washington, a nonparty, settled aA of tlie claims against them for BOND DEFA ULT, AlVDLITIGATION aggregate payments of more than $ 850 million. All of the settle-In Janu'ary 1982, th' Supply System's Nuclear projects Nos. 4 and ments were approved by the District Court on September 5,1989.
'Stere terminhted prior "to completion. The Supply System I
had, The court found that the settlemerits were binding on all Nuclear previouslyissued $ 2 25 billion of bonds to pay costs of the projects. projects Nos. 4 and 5 bondholders in the litigation. On February I
'he particjpants'greements (discussed In Note E - Security-
~
4, 1992, the Court of Appeals affiimed, in its entirety, the settle-menf of those claims; and a petition for certiorari,was denied by
-.d Projects Nos. 4 andd 5)SJ provided d tnat <I I n eachh paitlcipant pay .'Nuclear the'U.S." Supreme Court on November 2, 1992.
its respective share of the debt ser'vice'on the bonds and termina-tioncostsbeginningJanuary25,1983.ln1983,andagalnin1984,, Accordingly, the District, Court's ruling now permanently bars the Washington State Supreme Court ruled that Washington 'Cliemlcal Banl" and )II Nuclear projects Nos;,4 and 5 bond municipal utilities did not have statufory authority to enter Into ~ purchasers and bondholders'rom commencing, prosecuting, or the participants'greements, thus invalidating the agreements. continuing any action'against the Supply System'arising out of or This decision became Anal when'the U.S. Supreme Court denied relating to the allegations or subject matter of the securities' a writ oF certiorari.. I
'itigation. Howeverbased on the terms of the Supply System's settlement.With Chemical Bank, the ruling does'ot preclude On O July 1983 the Z2 1983, J 1 22, I Supply 5 I System 5 k acknowledged I d d thatj it could ld h~ b-
' Cliemlcal Bank from continuing with tlie cost-sharing litigation not pay.Nuclear ProJects p N 4 andd 5 obligations Nos. bil I as they became described abo'ye.
due. This was an event of default under the Nuclear Projects Nos.,
In March 1994, Nuclear Projects'Nos. 4 and 5 received a $ 2.8 mil-and 5 bond resolution. On July 25, 1983, Chemical Bank, as I t bond fund trustee, demanded that all remaining project funds be lion settlement as a rqimbursemeqt to the Bond Fund Reserve transferred to it for holding in a special account. On Aujust 18, = Accountandrecorded thereimbuisementasnonoperatingrevenue.
1983, Chemical'Banl declared the principal of all Nuclear Projects' Nos. 4 and 5 revenue bondsgnd lnteres't accrued thereon to be due lVUCLEAR PROJECTS NOS. 4AlVD 5 IIR1DGL AND d bl" I di
'- ~ TERMINATION-LOAN)
.Beginning ln 1983, a number of lawsuits were filed by and on 'n I late 1981, 68 Nuclear Projects Nos. 4 a'nd 5 participants and behalf of purchasers and holders of Nuclear proJects Nos. 4 and 5 others loaned the Supply System $ 60 million to pay project costs bonds ("the securities litigation"). The defendants named ln the until an alternative source of financing could be found. / None was I
lawsuits included the Supply System, lts member utilities, Nuclear - Sound, and after the projects were terminated in January 1982, 42-projects Nos. 4 and 5 participants, BpA; the architect/enqineek <
= Nuclear projects Nos. 4 and-5 participants loaned the Suppjy and tiie lead underwriters for Nuclear projects Nos. 4 and 5 and the. Systeni additional amounts of approximately'$8 million to pay I
Supply System's former bond counsel, special counsel and finan-' terminatlonjost's. The first set of loanstwere called bridge loans, lt cial advisor. The lawsuits alleged violations of federal and state and the second termination loans: All of theseloans.were subor-kecuritles lavI, fraud, misrepresentation, negligence and breach of 'inate'o the'$2.25 billion. of bonitos payable, and were payable I
(
,35"4 r /
r
,1 '1 II ~g r
1 r gr solely from the revenues of Nuclear Projects Nos. 4 and 5. The OTIIER LITIGATIONAIVD COhfhIIThfENTS I
Supply System defaulted on all of the loans at the same time. it The Supply System is involved in various claims, legal actions and defaulted on Nuclear Projects Nos. 4 and 5 bonds in 1983. C contractual commitments not mentioned above as both plaintiff Most of the lenders have sued the SuPPIYSYstem and all but~three and a defendant and ln certain claims and contracts arising in the of the. suits (those brought by certain investor. owned utilities) 'ormal course of business. Although some suits, claims and have been reduced to judgment. The Washing'ton State SuPreme commitments'are significant in amount, final disposition is has held that the terms of the loins limited the source of 'eterminaMe. In the opmion of management, the outcome of not'ourt recovery to funds and assets of Nuclear Proiects Nos.,4 and 5. Due such Iitfgatlon, claims or commitments wIII not have a material to tlie exPlration of the.statute'of limitations, the SuPPIY System adverse effect on the financial positions of the projects or the wroteoff$ 46.2millionofprinciPaland$ 114.5millionofaccrued Supply System as a whofe. The estimated cost of the projects, interest for bridge/termlnatlon loans during the Year ended June however, may either be increased or decreased-as.a result of the 30, 1994. Interest on these loans in the amount of approximately outcoine of these inatters
$ 65.3 million remains accrued and unpaid at June-30, 1994.
NUCLEAR PROJECTS IVOS. 4AIVD5 SITL RESTORATION IIVTER-PROJECT. CLAlhIS AGAINSTREVENUES AND OTIILRASSLTS No provisions have been made'for site restoration of, Nuclear
~
i 'Projects Nos. 4 and 5, which is governed by the site certification Some creditors of Nuclea'r Projects Nos. 4 and 5 have attempted,
".agreement betwe'en the Supply System and the State of Washing-andothershavethreatened toattempt, toobtaln paymen~ from ton I andd regulatioris I i d adopted d dbby the W hi h Washington Energy E F lll Facility thePhyslcal assets of other projects of the SuPPI) System or from S. .
Site E I ti Evaluation Councilil (EFSEC)
C EFSEC and, d with h respectt to N I t Nuclear the revenues pledged as security for the Supply System bond~
project N P No,4, the I Ilease agreement with p It is not known at this h DOE.
issued in connection witji,and revenues Pledged for th<payment ' time what h actions i s willillbe b necessary to comply with these require-ofcostsof sucllotherprojects Sdchcredltorsincludeprdentand '
ments, Because B tl the site tlf t agreement for Nuclear Project it certification former holders of. the Nuclear Projects Nos. 4 and 5 bonds and No. 1-also covers Nuclear Project No. 4, and the agreement foi otliers who'may assert claims ln tire future against the Supply ' '
N I Nuclear Project P No. I '
N 3 also'covers Nuclear I Project P No. SEFSEC 5 EFSEC System and/or its projects.
might assert that Nuclear Projects Nos. 1 and 3 are obligated to pay "The Supply System had retognlzed certain Nuclear projects Nos. the cost of site restoration for Nuclear project) Nos. 4 and 5: Such 4 and 5'contract claims as accrued expenses. At June30, 1994, the. costs are estimated to'be in thegange of $ 31 to $ 54 million (In Supply System wrote off all contract claims, $ 23.4.million and January 1994 dollars).;
$ 5.5 million for Nuclear Projects Nos. 4 and 5, respectively, due to the expiration of the statute of limitations. JVUCLEAR LICENSING AND 1NSURANCE 1
The Supply System's management-and legal counsel are of the -
The Supply System, is a licensee of the Nuclear Reg latory Com-opinionthatsuchcreditorswillonlybeabletorealizeuPonthenet mission and is.subject'to routine licensing and user, fees, to 1
assets of Nuclear Projects Nos.4 and 5 and willnot beable to realize 'etrospectivepremiumsfor nuclear liabllitylnsurance, and to license uPon anY net assets or future revenues of the SuPPI) System and/ modification, suspensio'n,,or revocation or civil penalties In the event of violations of various regulatory and license requirements.
IVUCLEARPROJECT NO. 5 TLRMIIVATIO/VCLAlhf - T e rice Anderson Act cu<<entiy P<<>>des <<r nu<<ear liability 1 g insurance over $ 9.1 billion per incident,,which is covered by a'n August 1983; paclfiCorp, owner of 10 percent of Nuclear project NotS< filed a courtterclaim in 'sserting .,
combination bf commercial nuclear Insurance and mandatory industry self;insurance. The Supply System-ha's purchased the that termination of Nuclear project No. 5 was a breach of the ownership agreement between PacifiCorp and the Supply System.
PacifiCorp seeks damages In an unspecified amount. Such amount
's maxlmumcommerclalinsuranceavailableof$ 200million,which the first layer of protection.-The second layer of protection is provided throughamandatoryindustryself-insuiance plan ivherein I
, =, .would presumably be approximately $ 150 million, and could be each. licensed nuclear facility required to participate In the plan a general claim against assets of the Supply System. Actions on ~ . 'currently113) maybeassessedup to $ 79.275 million per Incident, that claim have been stayed since 1983. The SupplySystem is subjecttoamaximumannualassessmentof$ 10niillionperyear..
unable to predict the outconie of this Iitigatioii, bu+counkel is of Nuclear property damage and decontamination liability insur-the opinion that a successful claim against assets of other than 1
ance requirements are met through a combination of commercial Nuclear Projects Nos; 4 and 5 Is remote.
nuclear insurance policies purchasedbytheSupplySystemand BPA; I ~ v l Thetotalam'ountofinsurancepurchased lscurrently$ 1.2 billion. The deductible for this coverage is $ 10 million per occurrence.
36-
,rs For the r ended June 30, 1994 BOND RATINGS - SUPPLY SYSTEM %1224, EU222 Fitch Investor Service, Inc. AA AA Moody's Investors Service, Inc. (Moody's) Aa Aa Standard and Poor's (S R P) AA AA VARIABLERATE LETTER OF CREDIT HANKS hKQQZS Long Term Series 1993-1A/3A-1 A+ Aa3 Series 1993-1A/3A-2 A+ Al Series 1993-1A/3A-3 AA Aa2 Short Term Series 1993-1A/3A-I A-1 VMIG1 Series 1993-1A/3A-2 A-1 VMIG1 Series 1993-1A/3A-3 A-1+ VMIG1
WASIIINOTON PUBLIC POWER 4N SUPPLY SYSTEM 3000 George Washington Way, RO.Box 968, Richland, Washington 99352 (509) 372-5000 94020S
ENERGY EAWERCSY NORTH WEST 9 RF Kpccllmcc
'able of Contents if j,4 c l t 1 Operating Highlights i.,~E' X23 "-'Executive Board 4-5 Pursuing, Excellence
~l,+~
g) 6-7 Nuclear Operations 8-11 Business Initiatives 12 Board of Directors 13-36 Financial Highlights The southern flank ofMt. Rainier, at 14,410 feet the highest mountainin the Pacific Northwest, as seen from Packwood Lake. The lakeis the source of water for Energy Northwest's 27-megawatt hydroelectric plant.
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Darrel Bunch Oon Carter Rudi Bertschi Commissioner Deputy City Manager for (Vice Chairman)
Okanogan County PUD Utilities and Physical Services. Consultant Okanogan, WA City of Richland, WA Economic &Technical Analysis Group Seattle, WA Louis H.Winnard Chairman Consultant Windsor, CA
Vera Claussen Edward E."Ted" Coates John Cockburn Dan Gunkel Roger Sparks (Assistant Secretary) (Secretary) Retired Commissioner Commissioner Commissioner Retired Bank Executive Klickitat County PUD Kittitas County PUD Grant County PUD UtilityExecutive Seattle, WA Goldendale, WA Ellensburg, WA Ephrata, WA Tacoma, WA
EIWERCSY NORTH WEST 9'zr~wxg EpcctL'em.
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)I 1 Executive Board Chairman Louis H. Winnard Chief Executive Officer J.V. Parrish After four decades of doing business as the Washington Public Power Supply System, sometimes marked by turbulence and turmoil, we are ready to enter the new millennium with a new name: Energy Northwest. This change signifies the end of one era of our journey,and the beginning of a new one in our pursuit of excellence.
We are not fleeing from our past. Rather, we are running toward our future.
Five years ago our journey almost ended prematurely. Plant 2, our sole operating nuclear generating station, was over staffed, overpriced, and under-productive. The cost of power was too high, at 3.34 cents per kilowatt-hour, to be competitive. The plant was unreliable, worker radiation exposure was too high,and our staff was wasting far too much time trying to keep the plant running, rather than operating it reliably. We were faced with a clear choice: cut costs and increase reliability, or terminate the plant.
Here is what has been accomplished since 1995: We generate about 10 percent of Bonneville's firm power, and provide the federal agency with the
~
Lowered the cost of power from 3.34 cents per flexibilityto operate the river system in a way kilowatt-hour to 2.26 cents in fiscal 1999 and that balances the competing needs of fish met the market test benchmark established by protection, flood control, irrigation, transportation the Bonneville Power Administration. and recreation.
This added flexibilityhas been instrumental in
~
Cut the plant budget from $ 232 to $ 158 million. Bonneville's resurgence as the region's preferred electricity provider. A few years ago critics pre-
~
Downsized our staff by 36 percent while cutting dicted the demise of Bonneville. They said BPA was overtime expenditures from $ 10.9 million in too expensive, too bureaucratic, and would be fiscal 1994 to $ 1.5 million in fiscal 1999. unable to meet its fish-recovery obligations without large increases in the wholesale price of electricity.
~
Reduced worker radiation exposure, a key They said Bonneville was doomed. Utilities began indicator of safety and efficiency, by 67 percent. searching for other, lower-cost sources of power.
But the critics were wrong.
Increased reliability and availability, rather than Bonneville tightened its belt and cut the continued drastic budget reductions, will ensure a wholesale price of electricity sold to its public strong future for Plant 2 and Energy Northwest. power customers by 20 percent. Customers that a Reducing the price of power is still a key goal (the few years ago were scrambling to abandon BPA fiscal 2000 target is 2.15 cents a kilowatt-hour), but now are competing fiercely for their share of low-increased generation is the principle tool we will cost BPA power.
use to achieve our goal. BPA's progress has also been helped by Energy The budget is only one side of the cost equation. Northwest's bond refinancing program. Early A recent report by an independent consultant planning paid off handsomely as we, with commissioned by the Bonneville Power Administra- Bonneville's cooperation, took advantage of tion praised our cost-cutting efforts, with one favorable credit ratings and low interest rates, caveat: continued cost-cutting could hurt the thereby cutting the average interest rate on billions reliability of our nuclear station and actually of dollars in outstanding bonds nearly in half since increase the cost of its power. A number of U.S. 1989, from 10.5 percent to 5.3 percent.
nuclear utilities have made that very mistake. We The result: Northwest consumers will save $ 1.83 don't intend to follow their example. billion over the life of the bonds.
We are following the industry in making a major This Annual Report details other ways in which change in Plant 2's operating cycle. This year was we are supporting Bonneville and our member the first time in its 15-year history that Plant 2 was public power utilities. Among them is our not refueled in the spring. Refueling was put off Packwood Hydroelectric Project, one of three of the until September as we transition the plant from an region's "green" resources marketed by BPA.
annual to a 24-month refueling schedule. This We also hold two licenses on combustion transition will result in a relatively small increase in turbine sites in Western Washington and are fuel costs, but it will be more than offset by in- marketing energy services to public power utilities creased generation, reliability and availability. statewide. We are also embarking on several new Here is why that is important: In the past, when business initiatives that will diversify our operations Plant 2's power output wasn't needed as the runoff and cut the overhead costs charged to Plant 2.
from mountain snowpacks powered the region's These new endeavors, coupled with the chang-numerous hydroelectric generators, it made sense ing face of Plant 2, convinced our Executive Board to shut the plant down every spring. that a new name for the organization was needed.
That is no longer the case. They selected Energy Northwest because in two The Bonneville Power Administration has words it says who we are, where we are and what warned the region that, under certain circum- we do.
stances, the Pacific Northwest might see a shortfall We belong to the Northwest because we'e a of up to 7,000 megawatts of electrical capacity in public power agency, created by the people. We the winter of 2001. belong in the Northwest because our roots are here.
Generation in the Northwest hasn't met the We'e going to stay in the Northwest because pace of increasing demand and, even more trou- ratepayers in the region made an investment in bling, is the possibility of removing existing hydro- us over the years. Now they are collecting the electric resources. Hydropower no longer is bounti- dividends on that investment: energy services and ful, nor is it cheap. Fish protection measures have inexpensive power.
increased the cost of running the Northwest's hydro The entire Energy Northwest team of employ-system tremendously while fish passage and ees, management and its governing boards pledge spawning regimens have cut generation. their best efforts to continue to serve the future But Plant 2 doesn't hurt fish, and fish protection best interests of our owners the Northwest measures don't impact Plant 2.When the water is ratepayers.
low in the Columbia River system, we generate vast amounts of power. When the water is high, but the dams are forced to spill huge amounts of water to help migrating salmon, we continue to produce power.
OPERATIONAL HIGHLIGHTS Energy Northwestis on ajourney; ajourney to excellence that began in 1995 when the cost ofpower from Plant 2 was not competitive at 3.34 cents a kilowatt-hour.
By reducing costs andincreasing reliability, Plant 2 delivered electricity to the Bonneville Power Adminis-tration in fiscal year 1999 at a price 2.26 cents a kilowatt-hour thatis competitive with other available resources.
ElllER&Y NORTH NfEST Decry~/xge(~ 8/ls axdA~vz/(a$ /li Getting to this point of the journey was difficult. have dramatically altered the way hydroelectric Gaining control of costs required setting priorities, dams are operated. More water for fish means less fixing problems in the plant and motivating the water to run turbines.
staff to realize its potential. Second, the booming Northwest economy has Innovative ways were found to give employees caught up with the power surplus the region has incentives to take ownership for plant performance. enjoyed for the past two decades.'tilities that a Energy Northwest employees are paid a portion of few years ago were turning away from BPA and their compensation in the form of incentive looking for lower-cost suppliers are now flocking payments based on meeting key Plant 2 cost and back to the federal marketing agency.
efficiency goals. The concept is simple: If Plant 2 Third, the incremental cost to Bonneville of runs well and remains within budget, employees running Plant 2 the cost for fuel, generation taxes are rewarded at the end of the year. If the plant fails and contributions to the federal spent fuel fund-to meet its goals, some or all of the incentive are about a half-cent a kilowatt-hour. In the spring payment is forfeited. of 1999, Bonneville could have realized millions of With budgets down and reliability up Energy dollars in additional revenue if Plant 2 had been Northwest is continuing to look for ways to de- operating.
crease the cost of power. This year's major initiative Plant 2 was not refueled this spring for the first is transitioning Plant 2 from an annual to a 24- time in its 15-year operating history. The plant was month refueling cycle. shut down, not for refueling, but to conserve fuel to Plant 2 was the last of the nation's nuclear meet the high power demand in the summer.
power plants still on a 12-month refueling cycle. Refueling was put off until September, when Most plants operate on an 18-month cycle and enough fuel was loaded in the reactor to run the about 20 percent run two years before refueling. plant non-stop until the spring of 2001.
Because Plant 2 is nestled among some of the Changing to a 24-month refueling cycle will greatest hydroelectric dams in the world, the increase fuel costs somewhat, but the expense will nuclear station has always followed the ebb and be relatively small compared to the benefits. And flow of the Columbia River system. In the past, each Plant 2 already has among the lowest fuel costs in spring when water was high, the region was awash the industry. Last year Energy Northwest had the with hydropower. Bonneville would meet the lowest costs for conversion and enrichment services region's needs while selling huge amounts of and beat out all other boiling water reactors in its surplus power in the West Coast market for less cost for fuel fabrication services.
than a cent per kilowatt-hour. Moving to a 24-month fuel cycle is expected to save between $ 100 million and $ 'I20 million over the life of Plant 2. The transition will cost about $ 22 million but, if Plant 2 skips an outage every other spring, the yearly average price for its power is likely to drop because the plant will generate more electricity over the two-year period. And, by skipping every other outage, Plant 2 will save about
$ 15 million for each one missed.
Another initiative that is expected to help reduce the cost of power from Plant 2 is a plan to From left: partner with the Omaha Public Power District (OPPD) to establish a service company that will use shared resources to provide centralized support functions to Plant 2 and OPPD's Fort Calhoun Station.
Vice President, Operations Support/PIORodtri/ebring The objective of the service company is to lower Vice President, Generation/Plant General Manager Greg Smith costs by identifying efficiencies and sharing Vice President/General Counsel AIMouncer common services with OPPD's 514 megawatt Vice President, Adminsitration/Chief Financial Officer Jerry Kucera pressurized water reactor located about 25 miles Vice President, Resource Development Jack Baker north of Omaha, Nebraska.
Then it made sense to have Plant 2 off line and Plant 2 has come a long way in its pursuit of refueling. The plant simply couldn't compete with excellence. It has developed into a valued resource hydropower during the spring runoff. that is a counterpoint to the Pacific Northwest's The situation is different now, for three reasons. traditional reliance on low-cost hydroelectric First, efforts to restore runs of endangered salmon dams.
Y2Kreadiness certified Energy Northwest certified to the Nuclear Regula-tory Commission on July 1 that Plant 2is ready to meet the new millennium without plant safety and reliabilityconcerns.
Tests at Plant 2, confirmed byindustry testing, showed that nuclear plant safety systems are not date-driven and willnot be compromised by Y2K computerissues. No nuclear facilityin the nation has found a Y2Kproblem that would prevent operation or keep safety systems from safely shutting down the plant and maintainingitin a safe condition.
A Nuclear Regulatory Commission audit team visited Plant 2in January and came away impressed with preparations for anyissues the year 2000 may pose.
ENERGY NORTH WEST Exergizi xg t4 xm Pal'l'mxi zm, Energy Northwest's Y2K readiness team spent policy, which went into effect in March, most about $ 6 million over two years testing and instances of non-compliance that in the past would updating plant systems to ensure they were Y2K have been treated as level IV violations are instead ready. Overall, Energy Northwest spent about $ 17 treated as non-cited violations, provided the million on testing and upgrades. One benefit to licensee takes corrective actions.
this effort was upgrades made to application systems, including moving from a mainframe to a Packwood Hydroelectric Project goes green client-server environment. Energy Northwest's 27-megawatt Packwood Lake Hydroelectric Project is one of three regional Spent fuel storage contract signed generating projects marketed as "green power" by Energy Northwest's Executive Board approved a the Bonneville Power Administration on behalf of its
$ 25 million contract in May for a spent nuclear fuel Environmental Foundation.
dry-storage system to Holtec, International. The The foundation is made up of the Renewable contract provides for the design, licensing, Northwest Project, the Northwest Energy Coalition, fabrication, and furnishing of an independent spent and the National Resource Defense Council. The fuel storage installation. environmental groups have teamed with Bonneville Plant 2 is expected to run out of storage space in a unique arrangement to market "green power" in its spent fuel storage pool, located on the top from Packwood, the Idaho Falls Hydroelectric floor of the Reactor Building, after its spring 2003 Project and a Wyoming wind farm.
refueling outage. Energy Northwest has paid more Northwest consumers voluntarily pay a premium than $ 80 million into a for this green power, with most of the extra revenue federal nuclear waste going to the foundation to finance future environ-fund, but the U.S. mental projects. If all the output from Packwood is Department of Energy sold by BPA as "green,"the foundation stands to has announced an gain about $ 750,000 a year. Energy Northwest and indefinite delay in taking its Packwood participants stand to gain up to control of spent fuel from $ 300,000 a year.
the nation's nuclear Another benefit to Packwood may come down the road. The project is up for relicensing in 2010.
lJ Qk ~ %@I power plants.
't The recognition of Packwood as environmentally friendly could pay future dividends during the relicensing process Applied Process Engineering Laboratory The Applied Process Engineering Laboratory (APEL) celebrated its first anniversary in April.The
$ 6 million lab, located in a former Energy Northwest warehouse in Richland, exceeded projections for tenants and revenue in its first year.
The lab is the only high-tech business incubator of its kind in North America. It will create jobs in the The project includes design, licensing Northwest and address some of the most vexing and fabricating 22 canisters and casks to environmental problems facing the planet, such as meet Plant 2's needs for spent fuel disposal of toxic wastes. APEL is a joint venture of storage through 2010 with options to Energy Northwest, the Port of Benton, the City of meet the plant's future needs. Included Richland, the Pacific Northwest National Laboratory, are auxiliary equipment for loading, sealing and the U.S. Department of Energy and others.
moving the canisters and casks to the storage site, After a year of operation, APEL hosts a diverse and engineering support for required storage site array of technologies, from a waste vitrification pilot evaluation. plant to chemical warfare detection devices to a robotic arm used to remove debris from Regulatory reform becoming a reality underground nuclear waste storage tanks.
The Nuclear Regulatory Commission has made substantial strides towards regulatory reform.
A major element in the reform is a change to the enforcement policy to expand use of non-cited violations at nuclear power plants. Under the new
Hometown Connections To expandinto theenergyservicesindustry, Energy Northwest last year became a marketing affiliate of Hometown Connections, a subsidiary of the American Public Power Association. Hometown Connectionsis a collection ofservices designed to make local public power retailing utilities more competitive by using combined buying power to leverage better arrangements from vendors. Energy Northwestis marketing such services and products as customer surveys, customerinformation software, advanced meter-reading products, surge protection, workshops and energy services.
Energy Northwestis selling a wide variety of products and services offered by APPA's subsidiary directly toits 13 member utilities and other public power systemsin the Northwest. Hometown Connec-tions uses the market leverage of the nation's 2,000 public power systems to negotiate better financial and service arrangements from vendors than utilities can obtain on their own.
EiWER&Y NORTH WEST Ep KKC6KQ dent AdPPZdKf Satsop Redevelopment Project the City of Richland have banded together to assess Energy Northwest continues to work with the the economic development potential of the project Satsop Redevelopment Project (SRP) following the site.
transfer of most of the assets and real estate Energy Northwest is supporting this initiative, associated with terminated Nuclear Projects 3 and 5 both for its potential to stimulate the local economy for economic development in Grays Harbor County, by attracting industry to the project site,and in coastal Washington State. because of the substantial cost of site restoration. A The Bonneville Power Administration provided 1995 site restoration plan, updated in June,esti-about $ 25 million to take over the site. That is far mates that WNP-1/4 site restoration costs could run less than if Energy Northwest had retained owner- as high as $ 100 million. This cost would be included ship and was required, under terms of its in the Bonneville Power Administration's rates and Energy Facility Site would be borne by the region's electric ratepayers.
Evaluation Council license, to return the New Business Initiatives site to its natural state. Energy Northwest is pursuing several new In return, the SRP business initiatives to diversify the organization as assumed liabilityfor the well as reduce the costs of operating Plant 2.
site. Because of the A contract was signed this spring with a complex nature of past contractor on the U.S. Department of Energy's ownership contracts, Hanford Site to provide instrument calibration reaching a transfer services that will mean about $ 1 million in new agreement business for the utility.Other new business initiatives being investigated include:
~
Supporting the development and deployment of new cost-effective renewable energy technologies, including a wind project to provide green power to regional utilities;
~
Supporting development and deployment of new cost effective distributed generation technolo-gies, including establishing a Center for Energy Innovation in Renewable and Distributed Genera-tion Technologies to provide financial, technical and business planning support to clients with new technologies;
~
Developing new or acquiring existing thermal was a complex matter, generation projects to benefit members and other requiring time and public power entities; great attention to detail. However, all parties have ~
Providing hydroelectric facility engineering, agreed Energy Northwest would retain ownership technical, modification and maintenance services to of the sites projected for two natural gas-fired the Federal Columbia River Power System and combustion turbines now licensed, but not yet built. public power agencies in the Northwest;and Additional acreage was obtained for two more ~
Participating in the development and operation combustion turbine units. One of the 245-mega- of a public power/public purpose communications watt plants is committed to the Bonneville Power network serving a variety of needs across the Administration for operation by Energy Northwest. Northwest by making use of the dark fiber that The other, if built, would be operated by Energy Bonneville has built on 2,000 miles of its transmis-Northwest to meet the emerging energy needs of sion system.
the West.
Benton Redevelopment Initiative The feasibility of a similar arrangement is being investigated for Energy Northwest's terminated Nuclear Projects 1 and 4 in Benton County in southeast Washington. The Port of Benton, Benton County, Benton County Public UtilityDistrict and
(left to right)
Robert Graves (President)
Commissioner, Benton County PUD Darrel Bunch (Assistant Secretary)
Commissioners Okanogan County PUD mrs'u Charles Buennagel Commissioner, Wahkiakum County PUD James Todd (Alternate)
Seattle City Light Beverley Cochrane (Vice President)
Commissioner, Franklin County PUD Roger Sparks Commissioner, Kittitas County PUD Vera Claussen (Secretary)
Commissioner, Grant County PUD Dan Gunkel Commissioner, Klickitat County PUD Don Carter Deputy City Manager for Utilities and Physical Services, City of Richland Parker Knight Commissioner, Skamania County PUD Dale Bly (Alternate)
Commissioner, Ferry County PUD Tom Casey Commissioner, Grays Harbor County PUD Not pictured: Mark Crisson Director of Utilities,Tacoma Power
. FINANCIALOPERATING HIGHLIGHTS For the year ending/rme 30, 1999 (Dollars in tttilliorts)
NUCLEAR PROJECT NO. 2 OPERATING STATISTICS FY 1999 FY 1998 FY 1997 FY 1996 FY 1995 Total production costs* $ 111.4 $ 119.1 $ 119.5 $ 133.3 $ 139.9 Net generation (millions of kWh)** 6,975.0 7,502.0 6,965.3 7,703.6 6,942.7 Cost in cents/kWh* 1.60 1.59 1.72 1.73 2.02 Plant availability*** 76.3% 77.9% 83.7% 79.7% 75.0%
Plant capacity**** 71.9% 71.9% 60.0% 61.3% 67.9%
Regional cost of power cents/kWh***** 2.26 2.20 2.46 2.56 3.34 PACKWOOD LAKE PROJECT FY 1999 FY 1998 FY 1997 FY 1996 FY 1995 Total production costs* $ 0.2 $ 0.3 $ 0.4 $ 0.1 $ 1.0 Net generation (millions ofkWh) 89.8 98.4 123.1 125.4 60.7 Cost in cents/kWh* .23 .25 .33 .09 1.63 Plant availability*** 91.4% 92.2% 88.5% 90.1% 60.0%
Plant capacity**** 37.3% 37.4% 51.9% 51.9% 22.9%
INVESTMENT PERFORMANCE FY 1999 FY 1998 CHANGE Income $ 39.9 $ 41.8 - 4.5%
Average Balance $ 659.0 $ 627.6 + 5.0%
Rate of Return 6.05% 6.65% - 9.0%%uo BONDS OUTSTANDING FY 1999 FY 1998 CHANGE PROJECT -1 fixed $ 2,081.9 $ 2,137.3 -2.6o/o weighted average 5.8% 5.8% 0.0o/o variable $ 134.5 $ 138.7 -3.0o/o average rate 3.2% 3.6% -11.1o/o PROJECT-2 fixed¹ $ 2,207.8 $ 2,335.1 -5.5o/o weighted average¹¹ 5.6% 5.6% 0.0o/o variable $ 120.9 120.9 0.0o/o average rate 3.2% 3.7% -13.5o/o PROJECT-3 fixed ¹ $ 1,573.1 $ 1,605.6 -2.0%
weighted average¹¹ 5.7% 5.7% 0.0"/o variable $ 184.9 $ 185.6 -0.4%
average rate 3.2% 3.6% 1 1o/o PACKWOOD fixed $ 6.3 $ 6.7 -6.0%
weighted average 3.7% 3.7% 0.0%
Ercchrdcs compounrl interest bonds accretion.
¹¹ Errchrctes compounri interest bonds.
Inclurles operating, maintenance, aiul lirel amortization '**'lantcapacity factoris the ratio ofthe actual enngy costs per FERC repoit. prodrrct ton on'r a gi mr pniod of time to lhe rnardmum includes BPA ccononric dispatch gnicration (millions ofkiVA)credit of 0; 532; 1,150.9; 1,759.2t nn<l 480 in "*" niergy productioir cnpability.
Regional cost ofporrrcr uses n broader measure of cost FY 1999, FY 1998, FY 1997, FY 1996 nnd FY 1995, rcspcctisely. and is prinrarily rised by BPA aml the Supply Systnn Plant avnilabitity is defined as the mtlo ofthe sum of to crsrhrate cost competitiveness.
source hours nnd resene slmt clown hours to total period honrs.
13
MANAGEMENTREPORT ON RESPONSIBILITY FOR FINANCIALREPORTING The management of Energy Northwest is responsible for preparing the accompanying financial statements and for their integrity. The statements were prepared in accordance with generally accepted accounting principles applied on a consistent basis, and include amounts that are based on management's best estimates and judgments.
The financial statements have been audited by PricewaterhouseCoopers LLP, Energy Northwest's independent accountants. Management has made available to PricewaterhouseCoopers LLP all financial records and related data, and believes that all representations made to PricewaterhouseCoopers LLP during its audit were valid and appropriate.
Management has established and maintains internal control procedures that provide reasonable assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition, and the prevention and detection of fraudulent financial reporting. These control procedures provide for appropriate division of responsibility and are documented by written policies and procedures.
Energy Northwest maintains an ongoing internal auditing program that provides for independent assessment of the effectiveness of internal controls, and for recommendations of possible improvements thereto. In addition, PricewaterhouseCoopers LLP has considered the internal control structure in order to determine their auditing proce-dures for the purpose of expressing an opinion on the financial statements. Management has considered recommenda-tions made by the internal auditor and PricewaterhouseCoopers LLP concerning the control procedures and has taken appropriate action to respond to the recommendations. Management believes that, as of June 30, 1999, internal control procedures are adequate.
J. Vic Parrish G.J. Kucera Chief Executive Officer Vice President, Administration/
Chief Financial Officer AUDIT, LEGALAND FINANCE COMMITTEE CHAIRMAN'SLETTER The Executive Board's Audit, Legal and Finance Committee is composed of five independent directors. Mem-bers of the Committee are John F. Cockburn, Chairman; Rudi Bertschi; Vera Claussen; Roger Sparks; and Louis Winnard, Ex Officio. The Committee held 12 meetings during the fiscal year ended June 30, 1999.
The Committee oversees Energy Northwest's financial reporting process on behalf of the Executive Board. In fulfillingits responsibility, the Committee discussed with the internal auditor and the independent accountants, the over-all scope and specific plans for their respective audits, and reviewed Energy Northwest's financial statements and the adequacy of Energy Northwest's internal controls.
The Committee met regularly with Energy Northwest's internal auditor and independent accountants to discuss the results of their examinations, their evaluations of Energy Northwest's internal controls, and the overall quality of Energy Northwest's financial reporting. The meetings were designed to facilitate any private communication with the Committee desired by the internal auditor or independent accountants.
John . Cockburn Chairman, Audit, Legal and Finance Committee 14
. Report of Independent Accountants To the Executive Board of Energy Northwest In our opinion, the accompanying individual balance sheets and related statements of operations and comprehensive income and of cash flows present fairly, in all material respects, the financial position of Energy Northwest Nuclear Project No. 1, Nuclear Project No. 2, Nuclear Project No. 3 and Packwood Hydroelectric Project at June 30, 1999, and the results of each of their operations and each of their cash flows for the year then ended in conformity with generally accepted accounting principles. These financial statements are the responsibility of Energy Northwest's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assess-ing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
The Year 2000 inforination, shown as required supplementary information on page 35, is not a required part of the basic financial statements but is supplementary information required under Technical Bulletin 98-1, as amended, issued by the Governmental Accounting Standards Board, and we did not audit and do not express an opinion on such information. Further, we were unable to apply to the information certain procedures prescribed by professional standards because the disclosure criteria specified by Technical Bulletin 98-1, as amended, are not sufficiently specific and, therefore, preclude the prescribed procedures from providing meaningful results. In addition, we do not provide assurance that the Projects are or will become year 2000 compliant, that the Projects'ear 2000 remediation efforts will be successful in whole or in part, or that parties with which the Projects do business are or will become year 2000 compliant.
Pm~mk<dia~p~
Portland, Oregon September 10, 1999 15
BALANCESHEETS rtsofJune30, l999 (Dollarsin thousands)
NUCLEAR PACKWOOD NUCLEAR NUCLEAR PROJECT LAKE PROJECT PROJECT NO.2 PROJECT NO. I¹ NO.3¹ hSSLTS UTILITYPLANT (NOTE B)
In service S 3,465,569 S 12,895 1,047 Allowance for depreciation (1,520,069) (10,865) (504) 1,945,500 2,030 543 Nuclear fuel, net of accumulated amortization 123,924 Construction work in progress 7 931 2 077 355 2 030 543 RESTRICTED ASSETS (NOTE B)
Special funds Cash 2,916 4 S 2,704 2,957 Available-for-sale investments 28,248 295 80,246 18,312 Accounts and other receivables 62,642 363 13 Due from other projects 1,819 Prcpayments and other 9 Debt scrvicc funds Cash 49 10 205 501 Available-for-sale investments 146,745 756 203,452 181,932 Other reccivablcs 1,585 1,030 1,096 242 185 I 065 289 828 204 811 LONG-TERM RECEIVABLES (NOTE B) 30 070 CURRENT ASSETS Cash 331 2 921 77 Available-for-sale investments 33,614 505 21,237 17,324 Accounts and other rcccivablcs 7,336 325 8 24 Due from participants 180 51 72 Due from other projects 2,575 181 9 1,574 Due from other funds 24,589 45 24,781 16,885 Materials and supplies 58,296 Prepayments and other 959 31 74 Nuclear fuel held for sale 9,304 Plant 8; equipment held for sale 9.515 127 880 I 089 65,826 36.030 DEFERRED CHARGES Costs in excess of billings 3,018 1,933,882 1,675,059 Unamortized debt expense 15,679 5 19,561 14,462 Other deferred charges I 15 680 3 023 I 953 443 I 689 521 TOTALASSETS S 2,493,170 S 7,207 S 2,309,097 S 1,930,905
¹ Project recorded on a liquidation basis See notes to financial stateinents 16
~ 8ALA1VCESHEETS As ofJune 30, l999 (Dollars in Ihousands)
NUCLEAR PACKWOOD NUCLEAR NUCLEAR PROJECT LAKH PROJECT PROJECT NO.2 PROJECT No. Ill NO.3'IABILITIES BILLINGS IN EXCESS OF COSTS S 27,625 UNREALIZEDINVESTMENT LOSSES (287) $ (1,206) S (357)
LONG-TERM DEBT (NOTE E)
Rcvenuc bonds payable 2,254,875 S 6,016 2,216,430 2,159,635 Unamortized discount on bonds - net (33,373) (20) (9,678) (284,154)
Unamortized loss on bond rcfundings (53,954) (61,151) (20,413) 2,167,548 5,996 2,145,601 1,855,068 LIABILITIES-PAYABLE FROM RESTRICTED ASSETS (NOTE B)
Special funds Accounts payable and accrued expenses 66,124 8 76,679 4,078 Due to other funds 22,438 12 19,875 15,290 Debt service funds Accrued interest payablc 378 77 61,134 42,594 Due to other funds 2,151 33 4,906 1,595 91,091 130 162,594 63,557 OTHER NONCURRENT LIABILITIES 8,368 CURRENT LIABILITIES Current maturities of long-term debt 142,630 310 Accounts payable and accrued expenses 49,137 141 12,182 Due to participants 1,616 577 1,392 455 Due to other projects 5,442 716 198,825 1,028 2,108 12,637 DEFERRED CREDITS Dcferrcd gain on rcdcmption of revenue bonds 48 48 COMMITMENTSAND CONTINGENCIES (NOTE F)
TOTAL LIABILITIES $ 2 493 170 $ 7 207 $ 2 309 097 $ I 930 905 17
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME For the >ear ended June 30, l999 iIJollars in thousands)
NUCLEAR PACKWOOD NUCLEAR NUCLEAR PROJECT LAKE PROJECT PROJECT NO.2 PROJECT NO.I ii NO.3 oil OPERATING REVENUES $ 401,980 $ 1,185 OPERATING EXPENSES Nuclear fuel 23,978 Fuel disposal fee 6,613 Decommissioning 10,299 Dcprcciation and amortization 105,212 348 Operations and maintenance 95,354 566 Administrative & general 27,437 91 Generation tax 2,442 19 Total operating expenses 271,335 1,024 NET OPERATING REVENUES 130,645 161 OTHER INCOME & EXPENSE Non-operating revenues S 139,319 S 99,553 Investment income 16,077 63 13,753 10,375 Gain/(loss) on current bond redemption (924) 17 (376)
Intcrcst expense and discount amortization (144,525) (241) (134,310) (111,199)
Plant preservation and termination costs (5,145) (18,956)
Site Restoration (13,800) 25,500 Write offassets and liabilities 29 (5,241)
Write offMOX Fuel (763)
Fuel set tlcment cost recovery 13 193 Joint owners'hare of costs 176 Other (523) (39) 168 NET REVENUES $ 0 S 0 S 0 S 0 OTHER COMPREEIENSIVE INCOME:oo Net revenue S 0 S 0 S 0 $ 0 Unrealized holding investment losses arising during period (611) (1,206) (358)
TOTAL COMPREHENSIVE INCOME (LOSS) $ (611) $ 0 S (1,206) S (358)
Energy ¹rthuest s onnershtP share (¹te A) e u As described in ¹te B Prjeeet nvorded on a liquidation basis See notes to financial sta(entents 18
. STATEMENTS OF CASH FLO1VS For she>n'ar ended June 30, l999 (Dollars ln thousands)
NUCLEAR PACKWOOD NUCLEAR NUCLEAR PROJECT LAKE PROJECT PROJECI'O.2 PROJECT NO. I ll NO.3 o ll CASH FLOWS FROM OPERATING AND OTIIER ACTIVITIES Net operating revenues $ 130,645 S 161 Adjustmcnts to reconcile nct operating revenues to cash provided by operating activities:
Cash received in excess of costs 24,120 (330)
Dcprcciation and amortization 127,647 346 Decommissioning 6,773 Other (509)
Change in operating assets and liabilities:
Accounts receivable (673) (229)
Materials and supplies (1,069)
Prepaid and other assets (69)
Due from/to other projects, funds and participants 8,949 947 Accounts payablc (6,082) 93 Non-operating revenue rcccipts $ 181,128 S 168,893 Cash payments for preservation and termination expenses (877) (13,989)
Cash payments for other expenses 217 Nct cash provided by operating and other activities 289,732 988 180,251 155,121 CASH FLOWS FROM CAPITALAND RELATED FINANCING ACTIVITIES Payment for bond issuance and financing costs (548) (855) (190)
Hanford Generating Project funds transferred to NP-I 9,612 Capital and nuclear fuel acquisitions (25,279)
Cash payments for deferred programs (121)
Interest paid on revenue bonds (132,375) (241) (127,491) (86,227)
Principal paid on revenue bond maturities (131,965) (383) (59,490) (34,036)
Net cash used by capital and related financing activities (290,288) (624) (178,224) (120,453)
CASH FLOWS FROM INVESTING ACTIVITIES Purchases of investmcnt securities (1,147,762) (5,976) (802,926) (618,413)
Sales of investment securities 1,133,298 5,553 785,494 576,267 Interest on investments 16,482 60 13,507 9,766 Receipts from sales of plant assets 193 654 Nct cash nosingprovided(used) by investing activities 2,018 (363) (3,732) (31,726)
NET INCREASE(DECREASE) IN CASEI 1,462 (1,705) 2,942 CASH AT JUNE 30, 1998 1,834 15 5,535 593 CASH AT JUNE 30, 1999 (NOTE IJ) $ 3,296 S 16 S 3,830 S 3,535 Enrsgp liorsh rmnrrship shore P'osr d) ii pro/rrs rrrordrd on a Ilquidorion hosis Srr nosrs so Jinonriai ssasrmrnis 19
OUTSTANDINGLONG-TERMDEBT As ofJune 30, l999 (Dollars in Thousands)
SERIAL COUPON OR TERM RATE MATURITIES AMOUNT 1990A 7.25% 7-1-2006 $ 35,790 1990C 7.00-7.50 7-1-2000/2002 122,260 (A) 7-1-2004/2005 18,054 140,314 1991A 6.25-6.60 7-1-2000/2004 90,415 (A) 7-1-2006/2007 13,431 103,846 1992A 5.45-6.30 7-1-2000/2009 129,785 6.25 7-1-2012 14,525 6.30 7-1-2012 50,000 (A) 7-1-2010 1,359 195,669 1993A 5.10-6.00 7-1-2000/2010 165,810 5.75 7-1-2012 42,105 207,915 199313 5.00-5.65 7-1-2000/2008 86,295 5.55 7-1-2010 51,000 5.625 7-1-2012 43,455 180,750 1994A 4.30-6.00 7-1-2000/2011 524,835 5.40 7-1-2012 100,200 (A) 7-1-2009 4,776 629,811 1996A 5.00-6.00 7-1-2000/2012 205,630 1997A 5.00-6.00 7-1-2000/2012 204,095 199713 5.00-5.50 7-1-2000/2011 74,925 1998A 4.50-5.75 7-1-2000/2012 229,115 (A) Compound interest bonds (II) Excludes amounts due July I, 1999 which were paid as of June 30, 1999 (C) Includes amounts duc July I, 1999 (0) The estimated fair value shown has been rcportcd to meet thc disclosure requirements of Statcmcnt of Financial Accounting Standards (SFAS) 107 and does not purport to represent the amounts at which these oblinations wouM be settled 20
- OUTSTANDINGLONG-TEIOfDEBT As ofJune 30, 1999 Pbllars ln 77rousands)
SERIAL COUPON OR TERM RATE MATURITIES AMOUNT 1997-2A-1,2 Variable 7-1-2000/2012 $ 120,865 Compound interest bonds aeon tion 68,780 Rtnvnue bonds pa>vtble $ 2,397,505 (B)
Estimated fair value at June 30, l999 $ 2,545,418 (D) 1962 3.625% 3-1-2012 $ 4,791 1965 3.75 3-1-2012 1,535 Rmvnue bonds pa>able $ 6,326 Estimated fair value at June 30, l999 $ 5,968 (D) 1989A 7.10-7.30 7-1-1999/2001 $ 10,380 1989B 7.00-7.15 7-1-1999/2001 14,855 7.125 7-1-2016 41,070 55,925 1990A 7.25-7.50 7-1-1999/2002 27,690 1990B 7.00-7.20 7-1-1999/2003 24,495 7.25 7-1-2009 72,770 97,265 1990C 7.25-7.75 7-1-1999/2003 95,765 1991A 6.20-6.60 7-1-1999/2004 22,080 1992A 5.30-6.25 7-1-1999/2007 13,140 6.25 7-1-2017 68,015 81,155 (A) Compound interest bonds (8) Excludes amounts due July I, 1999 which were paid as of June 30, l999 (C) Includes amounts due July I, 1999 (D) Thc estimated fair value shown has bccn reported to mcct thc disclosure requirements of SEAS l07 and does not purport to represent thc amounts at which these obligations would bc settled 21
OUTSTANDINGLONG-TERMDEBT As ofJune 30, l999 (Dollars in 7bousands)
SERIAL COUPON OR TERM SERIES RATE MATURITIES AMOUNT 1993A 4.75-7.00o/o 7-1-1999/2008 $ 162,710 5.75 7-1-2011 80,000 6.05 7-1-2012 35,705 5.75 7-1-2013 37,970 5.70 7-1-2017 176,180 492,565 19938 4.75-7.00 7-1-1999/2010 74,030 5.60 7-1-2015 94,885 168,915 1993C 4.25-5.30 7-1-1999/2010 19,505 5.40 7-1-2012 66,400 5.375 7-1-2015 75,650 161,555 1993-1A-1,2,3 Variable 7-1-1999/2017 134,505 1996A 5.00-6.00 7-1-1999/2012 351,890 19968 5.00-6.00 7-1-1999/2005 29,970 1996C 5.00-6.00 7-1-1999/2015 90,460 5.50 7-1-2017 24,860 115,320 1997A 4.75-6.00 7-1-1999/2008 20,905 19978 5.00-5.125 7-1-1999/2017 255,990 1998A 4.50-5.75 7-1-1999/2017 94,555 Revenue bonds papzble $ 2,216,430 (C)
Esdmaied fair value ai June 30, 1999 $ 2,285,305 (D)
(A) Compound interest bonds (8) Excludes amounts due July I, 1999 which were paid as of Junc 30, 1999 (C) Includes amounts duc July I, l999 (D) The estimated fair value shown has been reported to meet the disclosure requirements of SFAS 107 and does not purport to rcprescnt thc amounts at which thcsc obligations would be settled 22
> OUTSTANDINGLONG-TERMDEBT As ofJune 30, /999 (Dollars ln Thousands)
SERIAL COUPON OR TERM SERIES RATE MATURITIES AMOUNT 1989A 7.10-7.30/o 7-1-1999/2001 S 10,070 (A) 7-1-2003/2014 18,668 28,738 198913 7.00-7.15 7-1-1999/2001 56,125 (A) 7-1-2004/2014 70,580 7.125 7-1-2016 76,145 5.50 7-1-2017 62,560 5.50 7-1-2018 65,905 331,315 19908 7.20-7.25 7-1-1999/2000 48,200 (A) 7-1-2001/2010 38,685 7.375 7-1-2004 55,920 142 805 1991A 6.20-6.60 7-1-1999/2004 24,775 19938 4.75-7.00 7-1-1999/2010 114,755 5.625 7-1-2012 28,295 5.60 7-1-2015 49,095 5.60 7-1-2017 37,795 5.70 7-1-2018 20,605 250,545 1993C 4.25-7.50 7-1-1999/2010 155,265 5.40 7-1-2012 105,000 (A) 7-1-2013/2018 25,248 5.375 7-1-2015 188,335 5.50 7-1-2018 20,805 494,653 1993-3A-3 Variable 7-1-1999/2018 25,420 1996A 5.00-6.00 7-1-1999/2009 32,110 1997A 4.75-6.00 7-1-1999/2018 111 480 199713 5.00 7-1-2002 4,075 (A) Compound interest bonds (IJ) Excludes amounts due July I, 1999 which were paid as of June 30, l999 (C) Includes amounts due July I, l999 (D) The cstimatcd fair value shown has been rcportcd to meet the disclosure requirements of SFAS l07 and does not purport to represent the amounts at which thcsc obligations would bc settled 23
OUTSTANDINGLONG-TERMDEBT ds ofJune 30, 1999 (Dollars in Thousands)
SERIAL COUPON OR TERM SERIES RATE MATURITIES AMOUNT 1998A 4.50-5.125o/o 7-1-1999/2018 S 152,620 1998-3A Variable 7-1-1999/2018 159,500 Compound intctcst bonds accretion 401,599 Revenue tends paJvtbte S 2,159,635 (C)
Estimated fair value at June 30, l999 S 2,120,028 (0)
(A) Compound interest bonds (II) Excludes amounts duc July I, 1999 which were paid as of Junc 30, 1999 (C) Includes amounts due July I, l999 (D) The estimated fair value shown has bccn reported to meet the disclosure requirements of SFAS l07 and docs not purport to reprcscnt the amounts at tvhich these obligations would be settled 24
'EBT SERVICE REQUIREMENTS rrs ofJunc 30, l999 (Dollars ln lrrousands)
NUCLEAR PROJECT NO. 2 PACKWOOD LAKE PROJECT FISCAL YEAR PRINCIPAL INTEREST TOTAL PRINCIPAL INTEREST TOTAL 6/30/99 Balance:* S - S 378 S 378 S 155 S 77 S 232 2000 142,630 127,427 270,057 473 226 699 2001 178,580 119,206 297,786 498 208 706 2002 96,750 108,480 205,230 524 190 714 2003 155,225 102,989 258,214 548 171 719 2004 163,609 106,211 269,820 573 151 724 Balance Through 2012 1,591,931 502,027 2,093,958 3,555 447 4,002 Ajd usrmcnr ua 68 780 68 780 0 S 2.397.505 S 997.938 $ 3.395.443 S 6.326 S 1.470 S 7.796 NUCLEAR PROJECT NO. 1 NUCLEAR PROJECT NO. 3 FISCAL YEAR PRINCIPAL INTEREST TOTAL PRINCIPAL INTEREST TOTAL 6/30/99 Balance:* $ 70,355 S 61,134 $ 131,489 $ 66,275 $ 42,594 $ 108,869 2000 83,395 123,009 206,404 76,940 85,787 162,727 2001 84,255 118,083 202,338 74,950 86,787 161,737 2002 79,635 112,668 192,303 78,457 82,994 161,451 2003 70,280 107,709 177,989 80,057 81,837 161,894 2004 81,710 103,760 185,470 63,311 94,095 157,406 Balance Through 2017 1,746,800 788,417 2,535,217 2018 1,318,046 944,761 2,262,807 Adjusrmcnr au 401,599 (401,599)
S 2,216,430 S 1,414,780 $ 3,631,210 S 2,159,635 S 1,017,256 S 3,176,891
~ Bord Bund Account baisnces kss accrued inrestment income
~s Ad)ustmenl lor Compound Interest Bonds accretion: Compound Interest Bonds am rencctcd at theit lsco amount less discount on the hrdance sheet 25
NOTES TO FINANCIALSTATEMENTS terests was transferred to Energy Northwest. The finan-;
cial affect of the termination of the ownership agreement NOTE>> A - GE>>NERAL was a write-off for Nuclear Project No. 3 of a $ 3.7 mil-lion receivable from the joint owners.
Organization Each Energy Northwest project is financed and accounted Energy Northwest, a municipal corporation and joint op- for as a utility system separate from all other current or erating agency of the State of Washington, was organized future projects.
in 1957. It is empowered to finance, acquire, construct and operate facilities for the generation and transmission All electrical energy produced by Energy Northwest of electric power. On June 30, 1999, its membership con- projects is ultimately delivered to electrical distribution sisted of 10 public utilitydistricts and the cities of Richland, facilities owned and operated by the Bonneville Power Seattle, and Tacoma. All members own and operate elec- Administration (BPA) as part of the Federal Columbia tric systems within the State of Washington. Energy North- River Power System. BPA in turn distributes the elec-west is exempt from federal income tax. Energy North- tricity to electric utility systems throughout the North-west has no taxing authority. west, including participants in Energy Northwest projects, for ultimate distribution to consumers. Participants in Energy Northwest Projects Energy Northwest projects consist of 104 publicly-owned utilities and rural electric cooperatives located in the west-Energy Northwest operates Nuclear Project No. 2, a 1,153 ern United States who have entered into net-billing agree-MWe (Design Electric Rating, net) generating plant com- ments with Energy Northwest and BPA for participation pleted in 1984, and the Packwood Lake Hydroelectric in one or more of Energy Northwest projects. BPA is Project (Packwood), a 27.5 MWe generating plant com- obligated by law to establish rates for electric power which pleted in 1964. Energy Northwest has obtained all per- will recover the cost of electric energy acquired from mits and licenses required to operate Nuclear Project No. Energy Northwest and other sources as well as BPA's other 2 including a Nuclear Regulatory Commission (NRC) op- costs. See Note E, Security - Nuclear Projects Nos. 1, 2 erating license which expires in December 2023. and 3, for discussion of BPA's obligations with respect to Packwood operates under a fifty-year license from the Nuclear Projects Nos. 1, 2 and 3.
Federal Energy Regulatory Commission (FERC) that ex-pires on February 28, 2010. NOTE B -
SUMMARY
OF SIGNIFICANT AC-COUNTING POLICIE>>S Nuclear Project No. 1, a 1,250 MWe plant, was placed in extended construction delay status in 1982, when it was Basis of Accounting 65 percent complete. Nuclear Project No. 3, a 1,240 MWe plant, was placed in extended construction delay status in Energy Northwest has adopted accounting policies and 1983, when it was 75 percent complete. On May 13, 1994, practices that are in accordance with generally accepted Energy Northwest's Board of Directors adopted resolu- accounting principles. Accounts are maintained in ac-tions terminating Nuclear Projects Nos. 1 and 3 (see Note F cordance with the uniform system of accounts of the
- Nuclear Projects Nos. 1 and 3 Termination). In fiscal FERC. Separate funds and books of account are main-year 1999 the assets and liabilities of Hanford Generating tained for each utility system. Payment of obligations of Project were consolidated into Nuclear Project No. 1. The one utility system with funds of another utility system is Hanford Generating Project site is being restored and all prohibited, and would constitute violation of bond reso-funding requirements are net billed obligations of Nuclear lution covenants.
Project No. 1. Nuclear Project No. 1 is wholly-owned by Energy Northwest. Nuclear Project No. 3 was jointly- Pursuant to statement No. 20 of the Governmental Ac-owned, 70 percent by Energy Northwest and 30 percent counting Standards Board (GASB), "Accounting and Fi-by four investor-owned utilities until fiscal year 1999. In nancial Reporting for Proprietary Funds and Other Gov-fiscal year 1999 the ownership agreements were termi- ernmental Entities That Use Proprietary Fund Account-nated and the ownership of real and personal property in- ing," Energy Northwest has elected to apply all Financial
~ Accounting Standards Board statements and interpreta- useful lives of the various classes of plant, which range tions except for those that conflict with or contradict GASB from five to 40 years.
pronouncements. Specifically, Statement of Governmen-tal Accounting Standard No. 7 and No. 23 conflict with During the normal construction phase of a project, En-Statement of Financial Accounting Standard No. 125. As ergy Northwest's policy was to capitalize all costs relat-such, the guidance under Statement of Governmental Ac- ing to the project, including interest expense (net of inter-counting Standard No. 7 and No. 23 is followed. Such est income), and related administrative and general ex-guidance governs the accounting for bond defeasances and pense.
refundings.
Nuclear Projects Nos. 1 and 3 have been reduced to their SFAS No. 130, "Reporting Comprehensive Income," de- net realizable values due to termination. -A loss on the fines comprehensive income during the applicable period write-down of Nuclear Projects Nos. 1 and 3 was recorded as a change in equity of a business enterprise from trans- in fiscal year 1995 and is included in Cost in Excess of actions and other events and circumstances from nonowner Billings. Plant and equipment held for sale includes sources. SFAS No. 130 requires that an enterprise report management's best estimate of the net realizable value of all components of comprehensive income in the period in the remaining inventories, buildings, equipment, tools, which the enterprise recognizes these components. materials and consumables, common and operational spares, moveable equipment and land. Interest expense, Components of comprehensive income are net income and termination expenses and asset disposition costs for other comprehensive income. Net income includes in- Nuclear Projects Nos. 1 and 3 have been charged to op-come from continuing operations, discontinued operations, erations.
extraordinary items and cumulative effects of changes in accounting principles. Other comprehensive income in- Internal Service Fund assets are shared by all projects and cludes foreign currency translations, adjustments of mini- they are allocated to each project's balance sheet based on mum pension liability and unrealized gains or losses on direct labor cost incurred.
certain investments in debt and equity securities.
Nuclear Fuel For the year ended June 30, 1999 Energy Northwest's only item of other comprehensive income was unrealized gains All expenditures related to the purchase of nuclear fuel, and losses on investments as detailed in Note C Cash including interest, are capitalized and carried at cost. When and Investments. the fuel is placed in the reactor, the fuel cost is amortized to operating expense on the basis of quantity of heat pro-The preparation of Energy Northwest financial statements duced for generation of electric energy. Accumulated in conformity with generally accepted accounting prin- nuclear fuel amortization (the amortization of the cost of ciples necessarily requires management to make estimates nuclear fuel assemblies in the reactor used in the produc-and assumptions that directly affect the reported amounts tion of energy) is $ 90 million as of June 30, 1999 for of assets and liabilities and the disclosure of contingent Nuclear Project No. 2. Current period operating expense assets and liabilities at the date of the financial statements for Nuclear Project No. 2 includes a charge for future spent and the reported amounts of revenue and expenses during nuclear fuel storage and disposal to be provided by the the reporting period. Actual results could differ from these Department Of Energy (DOE) in accordance with the estimates. Certain assets and incurred expenses are allo- Nuclear Waste Policy Act of 1982. Current operations cated to the projects based on specific allocation methods only includes a small charge for escalation of the clean-and management considers the allocation methods to be up of DOE enrichment facilities. The Enrichment Clean-reasonable. up Assessment was costed years ago and a payable is charged when annual assessments are paid. Energy North-Utility Plant west is currently planning to utilize dry cask storage until the national repository is available. No provisions have Utility plant is stated at original cost. Plant in service is been made in fiscal year 1999 for additional storage and depreciated by the straight-line method over the estimated disposal costs which may be incurred in the future by 27
Energy Northwest prior to the transfer of spent fuel to Decommissioning Power Reactors." As provided in this.
DOE. rule, each power reactor licensee is required to report to the NRC the status of its decommissioning funding for Energy Northwest has entered into an agreement to trans- each reactor or share of reactor it owns. This reporting fer enriched uranium to General Electric Company in ex- requirement began on March 31, 1999 and reports are re-change for equivalent amounts of uranium at reload en- quired every two years thereafter. Energy Northwest sub-richments in future years and usage/loan fees. Energy mitted its initial report to the NRC on March 26, 1999.
Northwest has transferred approximately 240,966 pounds of UF6 and 113,503 SWU of Nuclear Project No. 2 ura- Energy Northwest's current estimate of Project 2 decom-nium. The exchange agreement has been secured by an missioning costs is approximately $ 340 million (in 1998 irrevocable letter of credit issued in the amount of the re- dollars). This current estimate is based on the NRC mini-placement value of the loaned uranium product, adjusted mum amount required to demonstrate reasonable finan-semiannually. The cost of the loaned uranium, $ 19 mil- cial assurance for a boiling water reactor with the power lion, is included in the carrying amount of Nuclear Project level of Project 2. The estimate continues to be based on No. 2 Nuclear Fuel. the NRC report (NUREG-1307) revised and published annually which provides regional adjustment factors which Until June 30, 2002 Nuclear Project No. 2 has an option are applied to a formula for estimating decommissioning to purchase the remaining fuel at Nuclear Project No. 1 costs that are acceptable to the NRC.
for $ 9.3 million plus escalation.
The funding plan requires annual deposits through fiscal Restricted Assets year 2024, the estimated end of commercial operation of Nuclear Project No. 2. The plan for annual deposits calls In accordance with project bond resolutions, related agree- for incremental increases of 4% per year. The plan as-ments, or state law, separate restricted funds have been sumes that such deposits will grow at a 2% real rate of established for each project. The assets held in these funds return and that the Project willbe placed in a 60 year safe are restricted for specific uses including construction, debt storage until 2085, at which time decontamination and service, capital additions, extraordinary operation and dismantlement willbe initiated. Over the life of the fund, maintenance, termination, decommissioning and deposits and the earnings related to the reinvestment claims.
workers'ompensation thereof, are expected to provide sufficient funds to cover the cash flow requirements to decommission Nuclear Long-Term Receivables Project No. 2. This plan will be reexamined every year and modified to assure that the projected fund balance Long-term receivables include minimum guaranteed complies with the then current estimates and NRC require-amounts adjusted annually pertaining to future discounts ments. Payments to the decommissioning fund have been for certain goods and services to be provided to Nuclear made since January 1985, and the balance of cash and Project No. 2 as the result of a litigation settlement and investment securities in the fund as of June 30, 1999 to-subsequent revisions. taled approximately $ 62.6 million. Since July 1990 these amounts have been held and managed by BPA in an exter-Decommissioning nal decommissioning trust fund in accordance with NRC requirements. Because it is held by BPA, the balance sheet Energy Northwest established a decommissioning fund for reflects a receivable from BPA for $ 62.6 million.
Nuclear Project No. 2 and moneys are being deposited each year in accordance with an established funding plan. Materials and Supplies The NRC has issued rules to provide guidance to licens- Materials and supplies are valued at cost, using weighted-ees of operating nuclear plants on decommissioning the average methods.
plants at the end of each plant's operating life. In addi-tion, in September 1998, the NRC approved and published its "Final Rule on Financial Assurance Requirements for 28
.Financing Expense, Bond Discount, and Deferred Gain participants, other projects and other funds. The fair val-and Losses ues of investments and revenue bonds payable have been estimated based on quoted market prices for such instru-Financing expenses and bond discounts are amortized over ments or based on the fair value of financial instruments the terms of the respective bond issues using the bonds of a similar nature and degree of risk.
outstanding method.
Revenues In accordance with the Statement of Governmental Ac-counting Standard No. 23 effective for periods after June Energy Northwest accounts for revenue on an accrual ba-15, 1994, losses on debt refundings have been deferred sis and recovers, through various agreements, actual cash and amortized as a component of interest expense over requirements for operations and debt service for each the shorter of the remaining life of the old or new debt. project over the life of that project. Accordingly, Energy The balance sheet includes the original deferred amount Northwest recognizes revenues equal to expenses for each less recognized amortization expense and is included as a period. No net income or loss is recognized, and no eq-reduction to the new debt. uity is accumulated.
Current Maturities of Revenue Bonds The difference between cumulative billings received and cumulative expenses is recorded as either billings in ex-Current maturities of revenue bonds payable from re- cess of costs (liability) or as costs in excess of billings stricted assets are reflected iq Long-Term Debt. Current (asset), as appropriate. Such amounts will be recognized maturities of bonds for which funds have not yet been as revenues, or expenses, during future operating periods.
restricted are reflected in Current Liabilities.
Concentration of Credit Risk Accounts Payable Financial instruments which potentially subject Energy Accounts payable and accrued expenses include payroll Northwest to concentrations of credit risk consist of avail-and benefits related accruals for Nuclear Project No. 2 of able-'for-sale investments, accounts receivable, other re-
$ 16.6 million. Nuclear Project No. 2 includes a Personal ceivables, long-term receivables and costs in excess of Time Bank accrual of $ 10.6 million. Packwood includes billings. Energy Northwest invests exclusively in U.S.
an accrual for FERC Administrative charges of $ 21,600. Government securities and agencies. Energy Northwest's Nuclear Project No. 2 includes an accrual for $ 2.6 million projects accounts receivable and costs in excess of bill-for Arbitrage Rebate and $ 19.2 million for operating and ings are concentrated with project participants and BPA capital expenses. through the net billing agreements. See Note E, Security
- Nuclear Projects Nos. 1, 2, and 3 and Security - Packwood Fair Value of Financial Instruments Lake Hydroelectric Project. The long-term receivable is with a large and stable company which Energy Northwest The fair value of financial instruments has been estimated considers to be financially strong. Other receivables are using available market information and certain assump- secured through the use of letters of credit and other simi-tions. Considerable judgment is required in interpreting lar security mechanisms or are with large and stable com-market data to develop fair value estimates and such esti- panies which Energy Northwest considers to be financially mates are not necessarily indicative of the amounts that strong. As a consequence, Energy Northwest considers could be realized in a current market exchange. The fol- the exposure of the projects to concentration of credit risk lowing methods and assumptions were used to estimate to be limited.
the fair value of each of the following financial instru-ments. Statements of Cash Flows Financial instruments for which the carrying value is con- For purposes of the statements of cash flows, cash includes sidered a reasonable approximation of fair value include: unrestricted and restricted cash balances. Short-term, cash, accounts receivable, accounts payable and accrued highly liquid investments are not considered cash equiva-expenses, other noncurrent liabilities and due to and from lents.
29
NOTE C - CASH AND INVESTMENTS for the benefit of the individual Energy Northwest projects, by safekeeping agents, custodians, or trustees.
Cash and investments for each utility system are sepa-rately maintained. Energy Northwest's deposits are in- Investments are classified as available-for-sale and are sured by federal depository insurance or through the stated at fair value with unrealized gains and losses ex-Washington Public Deposit Protection Commission. cluded from earnings and reported on the balance sheet as Energy Northwest resolutions and investment policies unrealized investment gains/(losses). Available-for-sale limit investment authority to obligations of the United investments at June 30, 1999 are categorized below to give States Treasury, Federal National Mortgage Association an indication of the types and amounts of investments held and Federal Home Loan Banks. Allinvestments are held by each project at year end. (See table below)
AVAILABLE-FOR-SALEINVESTMENTS (Dollars in Thousands)
Amortized Cost Unrealized Gains Unrealized Losses Fair Value Nuclear Project No. 2 U.S. Government Securities $ 64,556 S 318 S <392> S 64,482 U.S. Govcrnmcnt Agencies 144 638 197 <710> 144 125 Total $ 209.194 $ 515 S <1.102> $ 208.607 Packwood Lake Project U.S. Government Securities $ 1,556 S 0 $ 0 S 1,556 U.S. Govcmmcnt Agencies 0 0 0 0 Total 5 1.556 0 5 0 5 1.556 Nuclear Project No. I U.S. Government Securities S 37,147 S 204 $ <335> S 37,016 U.S. Government Agencies 268 994 86 267 919 Total S306,141 $ 290 $ <1.496> $ 304.935 Nuclear Project No. 3 U.S. Government Securities $ 24,348 S 103 $ <137> $ 24,314 U.S. Government Agencies 193.578 159 <483> 193,254 Total $ 217,926 5 262 $ <620> $ 217.568
< I Year 1-5 Years 6-10 Years > 10 Years TOTAI.
Nuclear Project No. 2 U.S. Govcrnmcnt Securities $ 9,062 S 26,031 $ 14,634 $ 14,755 $ 64,482 U.S. Government Agencies S 92.218 S 26 769 $ 8,864 S 16,274 S 144.125 Maturities at Fair Value S 101.280 S 52,800 S 23.498 $ 31,029 S 208.607 Packwood Lake Project U.S. Government Securities $ 1.556 S 1.556 Maturitics at Fair Value 5 1.556 $ 1.556 Nuclear Project No. I U.S. Government Securities S 10,374 $ 24,447 $ 0 $ 2,195 S 37,016 U.S. Government Agencies $ 217,328 S 38,658 S 11,487 $ 446 S 267,919 Maturities at Fair Value 5 227,702 5 63,105 5 11,487 5 2,641 5 304,935 Nuclear Project No. 3 U.S. Govemmcnt Securities $ 4,929 S 15,430 S 3,955 S 0 $ '24,314 U.S. Government Agencies S 150.280 $ 30.866 $ 9,912 $ 2,196 $ 193.254 Maturities at Fair Value $ 155,209 S 46,296 S 13,867 $ 2,196 $ 217,568 30
NOTE D - RETIREMENT BENEFITS Plan 2 members may retire at age 65 with five years of service, or at age 55 with 20 years of service, with an al-Substantially all full-time and qualifying part-time em- lowance of two percent per year of service of the average ployees participate in one of the following statewide re- final compensation. Plan 2 retirements prior to 65 are tirement systems administered by the Washington State actuarilly reduced. There is no cap on years of service Department of Retirement Systems, under cost-sharing credit and a cost-of-living allowance is granted, capped at multiple-employer defined benefit public employee retire- three percent annually.
ment plans. The Department of Retirement Systems (DRS), a department within the primary government of Funding Policy the State of Washington, issues a publicly available com-prehensive annual financial report (CAFR) that includes Each biennium, the state Pension Funding Council adopts financial statements and required supplementary informa- Plan 1 employer contribution rates needed to fully amor-tion for each plan. The DRS CAFR may be obtained by tize the total costs of the plan. Employee contribution writing to: Department of Retirements Systems, Admin- rates for Plan 1 are established by statue at six percent and istrative Services Division, P.O. Box 48380, Olympia. WA do not vary from year to year. The employer and em-98504-8380. The following disclosures are made pursu- ployee contribution rates for Plan 2 are set by the director ant to GASB Statement No. 27, Accounting for Pensions of the Department of Retirement Systems based on rec-by State and Local Government Employers. ommendations by the Office of the State Actuary to con-tinue to fully fund the plan. Allemployers are required to Public Employee's Retirement System (PERS) contribute at the level established by state law. The meth-Plans 1 and 2 ods used to determine the contribution rates are established under state statute in accordance with chapters 41.40 and Plan Description 41.45 RCW.
PERS is a cost-sharing multiple-employer defined ben- The required contribution rates expressed as a percentage efit pension plan. Membership in the plan includes: of current year covered payroll, as of June 30, 1999 were:
elected officials; state employees; employees of the Su-preme, Appeals, and Superior courts (other than judges in PERSPlan 1 PERS Plan 2 a judicial retirement system); employees of legislative Employer 7 32%x 7.32%"
committees'ollege and university employees not in na-tional higher education retirement programs; judges of Employee 6.00% 4.65%
district and municipal courts; non-certificated employees of school districts; and employees of local government.
The PERS system includes two plans. Participants who ":The employer rates do not include the employer admin-joined the system by September 30, 1977 are Plan 1 mem- istrative expense fee currently set at 0.18%.
bers. Those joining thereafter are enrolled in Plan 2. Re-tirement benefits are financed from employee and em- Both Energy Northwest and the employees made the re-ployer contributions and investment earnings. Retirement quired contributions. Energy Northwest's contributions benefits in both Plan 1 and Plan 2 are vested after comple- for the years ended June 30 were:
tion of five years of eligible service. PERSPlan I PERS Plan 2 Plan 1 members are eligible for retirement at any age after 1999 $ 718,527 $ 4,697,392 30 years of service, or at age 60 with five years of service, 1998 $ 754,672 $ 4,513,332 or at age 55 with 25 years of service. The annual pension is two percent of the average final compensation per year 1997 $ 776,582 $ 4,486,119 of service, capped at 60 percent. Ifqualified, after reach-ing age 66 a cost-of-living allowance is granted based on In addition to the pension benefits available through PERS, years of service credit and is capped at three percent an- Energy Northwest offers post-employment life insurance nually. benefits to retirees who are eligible to receive pensions under PERS Plan I and Plan II. One hundred thirty-six 31
retirees have elected to participate in this insurance. En- bonds were not called or had not matured at June 30, 1999 ~
ergy Northwest's Board of Directors in 1994 approved for Nuclear Projects Nos. 1, 2 and 3, respectively.
provisions which continued the life insurance benefit to retirees at 25 percent of the premium for employees who Outstanding revenue bonds of the various projects as of retire prior to January 1, 1995 and charged the full 100 June 30, 1999, are presented on pages 5 through 9, and percent premium to employees who retired after Decem- debt ser vice requirements for these bonds are presented ber 31, 1994. The life insurance benefit is equal to the on pages 20 through 25.
employee's annual rate of salary at retirement for non-bargaining employees retiring prior to January 1, 1995. Energy Northwest expects to continue the refunding of The cost of coverage for employees who retired after Janu- higher interest rate bonds when economically feasible.
ary 1, 1995 is $ 2.33 per $ 1,000 of coverage. Employees who retired prior to January 1, 1995 contribute $ .58 per Security - Nuclear Projects Nos. 1, 2 and 3
$ 1,000 of coverage while the Energy Northwest pays the remainder. Premiums are paid to the insurer on a current Project participants have purchased all of the project ca-
. period basis. pability of Nuclear Projects Nos. 1 and 2 and 3. BPA has in turn acquired the entire project capability from the At the time each employee retires, Energy Northwest ac- project participants under contracts referred to as net-bill-crues a liability for the actuarial value of estimated future ing agreements. Under the net-billing agreements for each premiums, net of retiree contributions. The total liability of the projects, project participants are obligated to pay recorded at June 30, 1999 was $ 2 million for these ben- Energy Northwest their pro rata share of total annual costs efits. of the respective projects, including debt service on bonds relating to each project, and BPA in turn is obligated to During fiscal year 1999, pension costs for Energy North- pay the participants identical amounts by reducing west employees and post-employment life insurance ben- amounts due to BPA by participants under BPA power efit costs for retirees were calculated and allocated to each sales agreements. The net-billing agreements provide that project based on direct labor dollars. Approximately 95 project participants and BPA are obligated to make such percent of all such costs were allocated to Nuclear Project payments whether or not the projects are completed, op-No. 2 during fiscal year 1999. erable or operating and notwithstanding the suspension, interruption, interference, reduction or curtailment of the NOTE E - LONG-TERM DEBT projects'utput.
Each Energy Northwest project is financed separately. The On May 13, 1994, Energy Northwest's Board of Direc-resolutions of Energy Northwest authorizing issuance of tors adopted resolutions terminating Nuclear Projects Nos.
revenue bonds for each project provide that such bonds 1 and 3. The Nuclear Projects Nos. 1 and 3 project agree-are payable solely from the revenues of that project. All ments and the net-billing agreements, except for certain bonds issued under Resolution Nos. 769, 640 and 775 for sections which relate only to billing processes and accrued Nuclear Projects Nos. 1, 2 and 3, respectively, have the liabilities and obligations under the net-billing agreements, same priority of payment within the projects. The vari- ended upon termination of the projects. Energy North-able rate debt issued for Nuclear Projects Nos. 1, 2 and 3 west entered into an agreement with BPA to provide for is subordinate to the bonds stated above. continuation of the present budget approval, billing and payment processes. With respect to Nuclear Project No.
In prior fiscal years, Energy Northwest defeased certain 3, the ownership agreement among Energy Northwest, revenue bonds by placing the proceeds of new bonds in Puget Sound Power & Light Company, PacifiCorp, Port-irrevocable trusts to provide for all future debt service land General Electric Company and The Washington Wa-payments on the old bonds. Accordingly, the trust account ter Power Company was terminated in fiscal year 1999.
assets and the liability for the defeased bonds are not in- The ownership of all real and personal property interests cluded in the financial statements, in accordance with was transferred to Energy Northwest.
GASB No. 7 and No. 23. Approximately $ 1,313.3 mil-lion, $ 1,214.9 million and $ 739.2 million of defeased 32
.Security - Packwood Lake Hydroelectric Project Project No. 3 Owners Committee declare the termination of the Project. The Owners Committee voted unanimously Energy Northwest and BPA signed an agreement which to terminate the Project in June 1994. Since that date, became effective on October 1, 1996 for the period Energy Northwest has been planning for the demolition through July 1, 2001, and states that BPA willpay Energy of the Project and restoration of the site under its obliga-Northwest in exchange for the project's total output of tions to the State of Washington ifno bona fide purchase electric capacity and energy delivered from the project. offers are received. Funding for the Project has contin-BPA willpay 17.5 mills per kWh for the first 86,750 mega- ued for administrative efforts associated with termination watt hours delivered to the interconnections and 5 mills and planning of demolition activities for the Project. Pres-per kWh for any energy delivered to the interconnections ervation activities have been continued for certain high-in excess of 86,750 megawatt hours during the fiscal year. value assets to maximize the return on their expected re-In addition, BPA pays to Energy Northwest their Lewis sale. In February 1999, Energy Northwest entered into a County PUD No. 1 transmission costs and Energy North- transfer agreement with the Satsop Redevelopment Project west receives generation credit for spill requested by BPA: to transfer the real and personal property at the site of Packwood is now a "certified resource" in BPA's envi- Nuclear Project No. 3 and Nuclear Project No. 5. For ronmental foundation pool. When Packwood's genera- further discussion, see information contained under tion is marketed as "green" power, a stipend of 2.5 mills ("Nuclear Project Nos. 1, 3, 4, and 5 Site Restoration" ).
per kWh will be received from BPA. The Packwood par-ticipants are obligated to pay annual costs of the project Inter-Project Claims Against Revenues and Other Assets including debt service, whether or not the project is oper-able, until the outstanding bonds are paid or provision is Some creditors of Nuclear Projects Nos. 4 and 5 have at-made for the retirement in accordance with provisions of tempted, and others have threatened to attempt, to obtain the bond resolution. payment from the physical assets of other projects of En-ergy Northwest or from the revenues pledged as security NOTE F - COMMITMENTSAND CONTINGENCIES for Energy Northwest bonds issued in connection with, and revenues pledged for the payment of costs of, such Nuclear Project No. 1 Termination other projects. Such creditors include present and former holders of the Nuclear Projects Nos. 4 and 5 bonds and On May 13, 1994, Energy Northwest's Board of Direc- others who may assert claims in the future against Energy tors adopted a resolution terminating Nuclear Project No. Northwest and/or its projects.
- 1. Since that date, Energy Northwest has been planning for the demolition of Nuclear Project No. 1 and restora- Energy Northwest's management and legal counsel are
'ion of the site recognizing the fact that there is no market of the opinion that such creditors willonly be able to real-for the sale of the Project in its entirety and to date no ize upon the net assets of Nuclear Projects Nos. 4 and 5 viable alternative use has been found. Funding for the and will not be able to realize upon any net assets or fu-Project has continued for administrative efforts associ- ture revenues of Energy Northwest and/or its other ated with termination and planning of demolition activi- projects.
ties for the Project. Preservation activities have been con-tinued for certain high-value assets to maximize the re- Nuclear Projects Nos. 1, 3, 4 and 5 Site Restoration turn on their expected resale. At this time, the eventual disposition of the Project is unknown. Energy Northwest Site restoration requirements for Nuclear Projects Nos. 1, has reduced the assets to their estimated net realizable 3, 4 and 5 are governed by site certification agreements value and has accrued for the estimated cost of removal between Energy Northwest and the State of Washington and site restoration. and regulations adopted by the Washington Energy Facil-ity Site Evaluation Council (EFSEC), and additionally for Nuclear Project No. 3 Termination Nuclear Projects Nos. 1 and 4, by a lease agreement with DOE. Energy Northwest submitted a site restoration plan On May 13, 1994, Energy Northwest's Board of Direc- for Nuclear Projects Nos. 1, 3, 4 and 5 to EFSEC on March tors adopted a resolution requesting that the Nuclear 8, 1995, which complied with EFSEC requirements to 33
remove the assets and restore the sites by demolition, tion obligation to bring the site into suitable condition ~
burial, entombment, or other techniques such that the sites for transfer. This obligation is estimated to cost $ 10.5 pose minimal hazard to the public. EFSEC approved En- million in addition to the $ 15 million transferred to the ergy Northwest's site restoration plan on June 12, 1995. SRP and a formal Request for Proposal is being prepared In its approval, EFSEC recognized that there is uncertainty to complete the specified work. Each estimate has been associated with Energy Northwest's proposed plan. Ac- recorded as Accounts Payable and accrued expenses. En-cordingly, EFSEC's conditional approval provides for ad- ergy Northwest will retain ownership of the combustion ditional reviews once the details of the plan are finalized. turbine property.
Based on current estimates for site restoration, Energy Other Litigation and Commitments Northwest has accrued liabilities of $ 59.8 million for Nuclear Project No. 1 and $ 10.5 million for Nuclear Project Energy Northwest is involved in various claims, legal ac-No. 3. Funding for these liabilities will be provided by tions and contractual commitments not mentioned above BPA. No source of funding has been identified for site and in certain claims and contracts arising in the normal restoration of Nuclear Project No. 4 which is located ap- course of business. Although some suits, claims and com-proximately one-half mile from Nuclear Project No. 1. mitments are significant in amount, final disposition is Energy Northwest believes that although Nuclear Project not determinable. In the opinion of management, the out-No. 1 has no legal obligation to fund Nuclear Project No. come of such litigation, claims or commitments will not 4, it is possible that claims may be asserted against Nuclear have a material adverse effect on the financial positions Project No. 1 to pay the costs of site restoration for Nuclear of the projects or Energy Northwest as a whole. The fu-Project No. 4. Energy Northwest currently estimates that ture annual cost of the projects, however, may either be the cost of site restoration for Nuclear Project No. 4 is increased or decreased as a result of the outcome of these
$ 38.9 million. matters.
During 1995, a group from Grays Harbor County, Wash- Nuclear Licensing and Insurance ington, which is interested in economic development, formed the Satsop Redevelopment Project (SRP). The Energy Northwest is a licensee of the Nuclear Regula-Satsop Redevelopment Project introduced legislation with tory Commission and is subject to routine licensing and the State of Washington under Senate BillNo. 6427 which user fees, to retrospective premiums for nuclear liability passed and was signed by the Governor of the State of insurance, and to license modification, suspension, or re-Washington on March 7, 1996. The legislation enables vocation or civil penalties in the event of violations of local governments and Energy Northwest to negotiate an various regulatory and license requirements.
arrangement allowing such local governments to assume an interest in the site on which Nuclear Project No. 3 and The Price Anderson Act currently provides for nuclear Nuclear Project No. 5 exists for economic development liabilityinsurance of over $ 9.51 billion per incident, which by transferring ownership of all or a portion of the site to is covered by a combination of commercial nuclear in-local government entities. This legislation also provides surance and mandatory industry self-insurance. Energy for the local government entities to assume regulatory re- Northwest has purchased the maximum commercial in-sponsibilities for site restoration requirements and con- surance available of $ 200 million, which is the first layer trol of water rights. of protection. The second layer of protection is provided through a mandatory industry self-insurance plan wherein In February 1999, Energy Northwest entered into a trans- each licensed nuclear facility required to participate in fer agreement with the Satsop Redevelopment Project to the plan (currently 108) may be assessed up to $ 88.095 transfer the real and personal property at the site of Nuclear million per incident, subject to a maximum annual as-Project No. 3 and Nuclear Project No. 5. The real prop- sessment of $ 10 million per year.
erty was actually transferred on August 12, 1999. As part of the agreement Energy Northwest transferred Nuclear property damage and decontamination liability
$ 15 million to the SRP and the SRP agreed to assume insurance requirements are met through a combination regulatory responsibility for site restoration. Energy of commercial nuclear insurance policies purchased by Northwest has agreed to accept a demolition and restora-, Energy Northwest and BPA. The total amount of insur-
..ance purchased is currently $ 1.06 billion. The deductible with the grid.
for this coverage is $ 10 million per occurrence.
The cost or consequences of a material incomplete or Required Supplemental Information untimely resolution of the Year 2000 problem could ad-versely affect future operations, however, any costs re-
"Year 2000" (Unaudited) lated to such results would remain obligations of the project participants and BPA as discussed in Note E, Se-Energy Northwest was ready for the year 2000 by July 1- curity - Nuclear Projects Nos. 1, 2, and 3.
six months before the millennial deadline. This effort con-sumed the effort of at least 16 men and women for a year and a half - as well as costing Energy Northwest $ 17.6 million.
Energy Northwest first addressed year 2000 issues in 1996, when replacement and upgrading major business computer and software programs began. In January of last year the Year 2000 Project was formally launched - an examina-tion of all computer systems and software programs used in and around Plant 2. More that 2,200 embedded sys-tems were identified. Some were not time or calendar sen-sitive, and hence left alone. Some were easily fixed. Many were replaced. No computer or software problems have been found that would have presented nuclear safety is-sues problems that would have incapacitated emergency systems or prevented continued operation of the plant.
In May 1998, the Nuclear Regulatory Commission issued a letter to all commercial nuclear plants, ordering that they establish year 2000 programs and report in writing by July 1 of this year. Energy Northwest reported by the deadline that Plant 2 was ready for the year 2000.
Contingency plans were prepared. External risks have been identified and a multi-discipline team formed to ad-dress them. Examples of contingency plans include stock-piling consumables such as diesel fuel for emergency generators in case there are potential supplier disrup-tions. There will also be extra staffing during sensitive time periods.
As for the actual move into the year 2000, suggestions from the Western Systems Coordinating Council, which recommends standards for an electrical grid covering 14 western states and two provinces, have been followed.
Plant 2 will be at 80 percent power as the clock ticks to-ward midnight. This posture has been communicated to Bonneville for integration into the Western Systems Co-ordinating Council's contingency plan. At 80 percent, Plant 2 will be in a position to rapidly increase power in case there is a problem with other generating stations or 35
CURRENT DEBT RATINGS (Unaudited)
ENERGY NORTHWEST (Long-Term)
Fitch IBCA, Inc. AA- Stable Moody's Investors Service, Inc. (Moody's) Aal Standard and Poor's Rating Services (S & P) AA- Stable VARIABLERATE DEBT MHH>KS Letter of Credit Banks Bank of America Long-Term ~ AA- Aa2 Short-Term A-I+ P-I Morgan Guaranty Trust Company Long-Term Short-Term A-I+ P-I Bond Insurance (Long-Term)
MBIAInsurance Corporation AAA Bank Credit Facility (Short-Term)
Credit Suisse First Boston A-I+ P-I 36
NUREG-0892 Supplement No. 3 Safety Evaluation Report related to the operation of WPPSS Nuclear Project No. 2 Docket No.60-397 Washington Public Power Supply System U.S. Nuclear Regulatory, Commission Offic of Nuclear Reactor Regulation May 1983 fO<<~
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ABSTRACT This report, Supplement No. 3 to the Safety Evaluation Report (SSER 3) for Washington Public Power Supply System's application for a license to operate WNP-2 (Docket No. 50-397), located in Benton County, Washington, approximately 12 miles north of Richland, Washington, has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Commission. This supplement reports the status of certain items that had not been resolved at the time of publication of the Safety Evaluation Report and Supplements No. 1 and 2.
WNP-2 SSER 3
TABLE OF CONTENTS
~Pa e ABSTRACT.
1 INTRODUCTION AND GENERAL DISCUSSION..
- 1. 1 Intr oducti on. 1-1 1.7 Summary of Outstanding Items. 1-1 1.8 Confirmatory Issues 1-3 1.9 License Conditions.. ~ 0 ~ ~ ~ ~ ~ ~ 1" 5 2 SITE CHARACTERISTICS 2-1 2.5 Geology, Seismiology, and Geotechnical Engineering...... 2-1 2.5.1 Basic Geologic and Seismic Information........... 2-1
- 2. 5.1. 3 Volcanic Hazards.. 2-1 3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, AND COMPONENTS...... 3-1 3.5 Missile Protection. 3-1 3.5.1 Missile Selection and Description........ 3-1 3.5.1.1 Internally Generated Missiles (Outside Containment)........... 3 1 3.5.1.2 Internally Generated Missile (Inside Containment)....... 3-1 3.5.2 Structures, Systems, and Components To Be Protected from Externally Generated Missiles..... 3 2 3.9 Mechanical Systems and Components....................... 3-3 3.9.3 ASME Code Class 1, 2, and 3 Components, Component Supports, and Core Support Structures............ 3-3 3.9.3. 1 Loading Combinations, Design Tran sients, and Stress Limits................ 3-3
- 3. 10 Seismic and Dynamic qualification of Seismic Category I Mechanical and Electrical Equipment..... ~ .... 3-4
- 3. 10. 1 Seismic and Dynamic qualification'.......'.....,... 3-4
- 3. 10. l. 1 Plant Generic Findings 3" 5 3.10.1.2 Specific Issues 3-5 3~ 10. 1. 3 Summary. 3-5 WNP-2 SSER 3
TABLE OF CONTENTS (Continued)
~Pa e 3.10.2 Operability qualification of Pump and Values..... 3-6 3.10.2.1 Generic Findings 3-6
- 3. 10.2.2 Specific Concerns 3-7
- 3. 10.2.3 Summary......................... 3-8 3.11 Environmental qualification of Electrical Equipment Important to Safety and Safety-Related Mechanical Equipment.. 3-8
- 3. 11. 1 Introduction.......... 3-8
- 3. 11. 2 Background. 3-9
- 3. 11. 3 Staff Evaluation. 3-9
- 3. 11.3. 1 Completeness of Equipment Important to Safety . ~ . 3-10
- 3. 11.3.2 qualification Methods 3-11
- 3. 11.3.3 Service Conditions 3-12
- 3. 11.3.4 Outstanding Equipment......... 3-14
- 3. 11.4 qualification of Equipment. 3-14
- 3. 11.4; 1 Electrical Equipment in a Harsh Environment 3-14
- 3. 11.4.2 Environmental qualification Audit..... 3-14
- 3. 11.4.3 Environmental qualification of Mechanical Equipment 3-16 3.11. 5 Conclusions 3-17 Appendix 3D. 3-18 4 REACTOR.
4.2 Fuel System Design. 4-1
- 4. 2. 3 Design Evaluation. 4-1 4.2.3. 1 Fuel System Damage Evaluation........... 4-1 4.6 Functional Design of Control Rod Drive System........... 4-4 7 INSTRUMENTATION AND CONTROL .... 7-1 7.3 Engineered Safety Features Systems 7-1 7.3.2 Specific Findings 7-1
- 7. 3. 2. 4 Standby Service Mater System............ 7-1 WNP-2 SSER 3 vl
TABLE OF CONTENTS (Continued)
~Pa e 7.6 All Other Instrumentation Systems Required for Safety... 7-1 7.6.2 Specific Findings..... ~ ................ 7-1
- 7. 6. 2. 3 Rod Block Monitor...... 7-1 9 AUXILIARY SYSTEMS........ 9"1 9.5 Other Auxiliary Systems....... 9-1
- 9. 5. 1 Fire Protection Program..... 9-,1 9.5.1.5 General Plant Guidelines.......... 9-1 9.5.1.6 Fire Detection and Suppression.... 9-2 9.5.1.8 Summary of Deviations from BTP CMEB 9.5-1.............. 9-5 9.5.1.9 Conclus1on........................ 9"5 9.5.8 Emergency Deisel Engine Combustion Air Inta ke and Exhaust System..... 9"5 13 CONDUCT OF OPERATIONS........................................ 13-1
- 13. 1 Organization Structure of Applicant.................... 13-1
- 13. 1. 1 Management and Technical Support Organization. 13-1 13.1.1.1 General....,.... ~ 13 1 APPENDIX A CHRONOLOGY APPENDIX B BIBLIOGRAPHY APPENDIX E NRC STAFF CONTRIBUTORS MNP-2 SSER 3 V11
1 INTRODUCTION AND GENERAL DESCRIPTION
- 1. 1 Introduction In March 1982, the Nuclear Regulatory Commission staff (hereinafter referred to as the NRC staff) issued its Safety Evaluation Report (NUREG-0892) regarding the application by the Washington Public Power Supply System (hereinafter=referred to as the applicant or WPPSS) for a license to operate the Washington Public Power Supply System Nuclear Project Number 2 (hereinafter referred to as WNP-2 or facility), Docket 50-397. The NRC staff Safety Evaluation Report (SER) on WNP-2 was issued in March 1982. Supplement No. 1 (SSER 1) to the SER was issued in August 1982 and included the staff evaluation of the WNP-2 geology and seis-mology. SSER 2, which was issued in December 1982, addressed several outstand-ing licensing issues as well as the report of the Advisory Committee on Reactor Safeguards (ACRS) to the Chairman of the NRC on the WNP-2 operating license (OL) application. This report is Supplement No. 3 to the Safety Evaluation Report.
The purpose of this supplement is to provide the results of the NRC staff's review of additional information submitted by the applicant in regard to outstanding issues identified in Sections 1.7, 1.8, and 1.9 of SSER 2.
Each section of this supplement is numbered and titled to correspond to the sections of the SER and the supplements that have been affected by the NRC staff's additional evaluation and, except where specifically noted, does not replace the corresponding'ection of those documents. Appendix A is a continuation of the safety review chronology and lists additional documents used in this supplement. Appendix B is an updated bibliography. Appendix E is a list of principal contributors to this supplement.
Copies of this SER supplement are available for inspection at the NRC Public Document Room, 1717 H Street, NW, Washington, D. C., and at the Richland City Library, Swift and Northgate Streets, Richland, Washington. Single copies may be purchased from the sources indicated on the inside front cover.
The NRC Project Manager assigned to the operating license application for WNP-2 is Dr. Rajender Auluck. Dr. Auluck may be contacted by calling (301) 492-9778 or writing:
Dr. Rajender Auluck, P.E.
Division of Licensing U.S. Nuclear Regulatory Commission Washington, D.C. 20555 .
1.7 Summar of Outstandin Items In Section 1.7 of the SER, SSER 1, and SSER 2, the NRC staff identified out-standing items that were not resolved at the time of issuance of those documents.
In this supplement, the NRC staff discusses the resolution of a number of these items. The outstanding items list in Section 1.7 of the SER is reproduced WNP-2 SSER 3
below, with the current status of each item. For items discussed in this sup-plement, the specific section is identified. The resolution of the remaining outstanding items will be discussed in future supplements to the SER.
Item Status Section(s)
(1) Geology and seismology Resolved (2) Internally generated missiles Resolved 3.5.1 (3) Tornado-missile protection for Resolved 3.5.2 diesel generator (DG) exhaust (4) Turbine missiles Awaiting further information (5) Component supports Resolved (6) Equipment qualification Awaiting further 3.10, 3.11 information (7) Condensation oscillation and chugging Resolved load specifications (8) Pressure interlocks on emergency core Resolved cooling injection valves (9) Modification of automatic Awaiting further depressurization system logic information (10) Standby service water system Resolved 7.3.2.4 instrumentation and control (I8C) design (11) Engineered safety feature reset Resolved control (12) Remote shutdown syst'm I8C design Resolved (13) Control system failures Awaiting further information (14) Adequacy of stati on el ectr i c Resolved distribution system (15) equality group classification for the Resolved DG auxiliary systems (16) Diesel engine cooling heater preheat Resolved (17) Diesel 'engine lube oil system's ability Resolved
'to preclude dry starting WNP-2 SSER 3 1-2
Item Status Section s (18) Blockage of the DG combustion air Resolved 9.5.8 intake and exhaust system (19) Shift support supervisor training program Resolved (20) Administrative procedures: Resolved limitation on working hours (21) Criteria for testing hot pipe Resolved containment penetrations (22) Emergency planning program (offsite) Awaiting further information (23) Control room design review Under review (24) Anticipated transients without scram Combined with (ATWS) confirmatory item 15 (25) Gener al Design Cri teri on (GDC) 51 Resolved (26) TMI II.E.4.2 (operability of purge Under review valves only)
(27) TMI II.K.3.28, qualification of Resolved accumulators on automatic depressurization system (ADS) valves (28) Pipe break in the boi ling water Resolved reactor (BWR) scram system (29) Steam bypass from a stuck open Awaiting further wetwell-to-drywell vacuum breaker information (30) Heavy load handling system Under review, (31) Sprinkler and standpipe system Resolved 9.5. 1 (32) Organizational changes Resolved 13. 1. 1 (33) Cable separation criteria Resolved
- 1. 8 Conf irmator Issues In Section 1.8 of the SER, SSER 1, and SSER 2, the NRC staff listed confirmatory items that were not resolved at the time of issuance of those documents. That list is reproduced and updated below.
WNP-2 SSER 3 1-3
Item Status Section (1) Break 1 ocati on Awaiting further information (2) Preoperational testing of snubbers Under review (3) Reactor internals analysis under faulted Under review conditions (4) Hydrodynamic loads Under review (5) Class 1 fatigue evaluations for the Resolved 3.9.3.1 safety/relief valve (SRV) discharge piping and downcomers (6) Method for combining dynamic responses Resolved 3.9.3.1 (7) Design of component supports Awaiting further information
,(8) Systems drawings for inservice testing Resolved (9) Fuel rod mechanical fracturing Under review (10) Fuel assembly structural damage from Under review external sources (11) Fuel rod bowing Resolved 4.2.3.1 (12) Overheating of gadolinia fuel pellets Under review (13) Automatic restart capability for reactor Awaiting further core isolation cooling (RCIC) system information (14) Modification to prevent spurious Awaiting further isolation of RCIC system information
-(15) Emergency procedures review Awaiting further information (16) ADS, low pressure cooling system (LPCS), Awaiting further and low pressure coolant injection information (LPCI) setpoint (17) RCIC system Awaiting further information (18) SRV position indications Awaiting further information (19) Addi ti ona1 ace i dent moni tori ng Awaiting further instrumentation information MNP-2 SSER 3
Item Status Section (20) Rod block monitor Resolved 7.6.2.3 (21) Mitigating core damage training Awaiting further information (22) Assurance of engineered safety Under review features (ESF) functioning and safety-related system operability status (23) General plant guidance--building Resolved 9.5.1.5 design (24) Design-basis volcanic ash Resolved 2.5.1.3 1.9 License Conditions Section 1.9 of the SER, SSER 1, and SSER 2 listed several probable license conditions. The updated list of these conditions is as follows:
Item Section (1) Ultimate heat sink (2) Channel box deflection Deleted (4. 2. 3. 1)
(3) Effects of high-burnup fission gas release on loss-of-coolant accident (LOCA) analysis (4) Inadequate core cooling (ICC) instrumenta-tion analysis (5) Conditions for operations beyond cycle 1 (6) IE Bulletin 80-06, "Engineered Safety Features Reset Control" (7) Post-accident sampling (8) Relocations of engine-mounted controls (9) Conformance of diesel generator fuel oil Deleted system (10) BWR startup or operating experience (ll) Physical security (12) Prohibition of operations with partial feedwater heating (13) Remote shutdown system WNP-2 SSER 3 1-5
2 SITE CHARACTERISTICS 2.5 Geolo Seismolo and Geotechnical En ineerin 2.5.1 Basic Geologic and Seismic Information
- 2. 5. 1. 3 Vol cani c Hazar ds
- 2. 5. 1. 3. 1 Ashfal 1 In the SER-OL, Supplement No. 1 (SSER-1) Appendix G, the staff and the United States Geological Survey (USGS) indicated that the FSAR estimates of the uncompacted thickness of ashfall and the rate of fall fell short of more recently developed estimates by the USGS based on experience with the May 18, 1980 Mt. St. Helens eruption. In accordance with the Standard Review Plan (SRP)
(NUREG-0800), Section 2.5. 1, concerning operating license reviews, all new infor-mation on the regional and site geology developed after issuance of the construc-tion permit (CP) SER must be included and evaluated in the determination of site suitability and design criteria. The applicant, therefore, was asked to evaluate the ashfall considerations discussed in the following paragraphs.
Although the compacted design thickness chosen (7.4 cm or 3 inches) was con-sidered conservative, the uncompacted thickness was based on earlier estimates of 20% to 40% compaction of loose ash. As was pointed out by the USGS (SSER-l, page G-ll), a compaction factor of up to 75% was measured for the May 18, 1980 Mt. St. Helens eruption. Although the validity of this latter figure had not been determined when SSER-1 was written, it was considered prudent to use a more conservative estimate than 20%%u'o 40% -somewhere between 50%%u'o 60%. This higher estimate would result in a maximum of 18.5 cm (7.4 inches) of loose ash.
The rate of ashfall for a 20-hour period, based on the earlier FSAR percent compaction estimates of 0.37 cm/hr (0. 15 inch/hr) would result from the compacted thickness of 7.4 cm (3 inches). Therefore a higher rate based on the more recent uncompacted ash estimates was suggested, the average being 0.92 cm/hr (0.36 inch/hr) and the maximum l. 1 cm/hr (0.44 inch/hr) for the Katmai volcano rate.
Based on these differences between the applicant's estimates on the one hand, and those of the NRC staff and the USGS on the other, the applicant committed to set up a task force to evaluate and recommend a plan to incorporate the new information.
In a letter dated October 4, 1982, the applicant evaluated the WNP-2 plant sys-tems and equipment with regard to operability and reliability during a design-basis ashfall. The more conservative values of maximum compacted (3-inch) and uncompacted (7.4-inch) ashfall thicknesses and the average and maximum rates (0.35 inch/hr and 0.44 inch/hour, respectively) were used, coincident with loss of offsite power for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. As a result of this analysis, the applicant proposed several plant procedures and equipment modifications to ensure that the WNP-2 SSER 3 2-1
plant could operate safely and achieve safe shutdown following a desi'gn-basis ashfall.
The NRC staff has reviewed the submittal and concludes that the applicant has adequately addressed the consequences of the volcanic event and that the proposed plant procedures and equipment modifications will provide adequate assurance of safe plant operation and shutdown 'following such an event. This resolves con-firmatory item 24.
WNP-2 SSER 3 2-2
3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS, AND COMPONENTS 3.5 Missile Protection 3.5. 1 Missile Selection and Description 3.5.1. 1 Internally Generated Missiles (Outside Containment)
In the SER, the NRC staff stated that the FSAR analysis did not include the air accumulators and the gas bottles as potential missile sources. Furthermore, the applicant had indicated that a new FSAR Section 3.5. 1. 1 would be provided to
.reflect a more complete analysis. The applicant provided the revised analysis by Amendment 27 to the FSAR. The revised analysis included air accumulators and gas bottles as potential missile sources.
The primary means of providing protection to safety-related equipment from damage resulting from internally generated missiles is through the plant physical arrangement. Safety-related systems are physically separated from nonsafety-related systems, and redundant components of safety-related systems are physically separated so that potential missiles could not damage both trains of safety-related equipment. Stored spent fuel is protected from damage by internally generated missiles by the fuel pool walls and by pre-venting the location of high-energy piping systems or rotating machinery in the vicinity of new or spent fuel.
The applicant provided an evaluation of potential missile sources on the basis that a single failure could result in their becoming potential missiles. The evaluation indicated that there were no credible potential missile sources, including air accumulators and gas bottles, that could cause adverse effects on safety-related systems and components, except for the motor-generator set.
The applicant has installed a barrier that the NRC staff considers adequate to prevent any internally generated missile from the motor-generator set from damaging the nearby safety-related cables and cabinets. The staff reviewed the applicant's assumptions and evaluation for potential missiles outside contain-ment and agrees with the conclusion that adequate protection is provided.
the above, the NRC staff concludes that the design of the facility is Based on in conformance with the requirements of General Design Criterion (GDC) 4 as it relates to protection against internally generated missiles and is, therefore, acceptable with respect to internally generated missiles outside containment.
The design of the facility for providing protection from such internally generated missiles meets the applicable acceptance criteria of SRP 3.5. l. 1.
(NUREG-0800).
- 3. 5. 1. 2 Internally Generated Missiles (Inside Containment)
In the SER, the NRC staff noted that the applicant's analysis of potential missiles and the effects of the internally generated missiles was not complete.
The applicant has provided a revised analysis by Amendment 27 to the FSAR. The E
NNP-2 SSER 3 3-1
revised analysis includes missile characteristics, trajectory, and impact area, as applicable. The NRC staff has reviewed the results of the applicant's missile analysis for internally generated missiles inside containment and agrees with the conclusion that unacceptable damage to safety-related equipment will not occur; thus the requirements of GDC 4 are satisfied with respect to such missiles.
The staff has reviewed the adequacy of the applicant's design to maintain the capability for a safe plant shutdown and to prevent unacceptable radiological release in the event of internally generated missiles inside containment.
Based on the above, the staff concludes that the design is in conformance with the requirements of GDC 4 as it relates to protection against internally gen-
"erated missiles inside containment; therefore, this aspect of the plant s design is acceptable. The design of the facility for providing protection from internally generated missiles meets the applicable acceptance criteria of SRP 3.5. 1.2 (NUREG-0800). This finding, together with the finding in Sec-tion 3.5. 1. 1 above, resolves outstanding issue 2.
3.5.2 Structures, Systems, and Components To Be Protected from Externally Generated Missiles In the SER, the staff stated that except for the diesel generator exhausts, the safety-related structures, systems, and components were acceptably protec-ted from tornado missiles. Regarding the diesel generator exhausts, the NRC staff was concerned that the diesel exhaust openings of one of the two engineered safety feature (ESF) diesels might be blocked by tornado-borne missiles (e. g., utility poles). Each ESF diesel has two exhaust openings. The applicant stated that, with one diesel exhaust opening blocked, the correspond-ing diesel would not accept its required load. Assuming a single failure in the redundant diesel (failure to start), neither diesel would be available in the case of a loss of offsite power resulting from a tornado.
As guidance in evaluating the site for the source(s) of such missiles, the NRC staff used SRP 3.5. 1.4 (NUREG-0800), which states that a utility pole should be considered as a missile source at elevations up to 30 feet above all grade levels within 1/2 mile of the facility structure. For this plant, the exhaust openings are more than 30 feet above grade; however, there is a bluff due south of the diesel generator building. The NRC staff was concerned that this area might be used as a lay down area and that utility poles or other con-struction materials might be stored there.
The NRC staff recommended that the applicant provide administrative control over the bluff. In a submittal dated July 23, 1982, the applicant stated that it was extremely improbable that a tornado would lift a utility pole and trans-port it to the diesel generator building. The applicant provided a limited probabi listic risk assessment (PRA) to support this statement that indicates that the probability of a tornado generating a utility pole missile that would plug one of the ESF diesel generator exhausts at the same time the redundant diesel ~enerator would fail to start from an independent cause is on the order of 10-~ per year.
The NRC staff has reviewed the applicant's PRA. Based on this NRC staff review, and on the NRC staff's independent determination of the tornado fre-quency at the WNP-2 site, the staff finds that the probability of a utility WNP-2 SSER 3 3-2
pole missile plugging one diesel generator exhaust at the same time the second diesel generator fails to start is very low. The NRC staff has also examined the site terrain and concludes that the possible sources of missiles are limited. Further, between the bluff and the diesel exhausts are six forced draft cooling towers and a pumphouse. A utility pole lifted from the bluff would have to traverse a very limited path between the intervening cooling towers to reach the- diesel exhaust openings. The NRC staff, therefore, con-cludes, based on the low probability, that there is reasonable assurance that missiles resulting from a tornado will not prove to be a danger to the diesel generator exhausts. The NRC staff concludes that conformance to the require-ments of GDC 4 has been demonstrated in that, through the use of probabilistic risk assessment, there is'easonable assurance that tornado missiles will not endanger the diesel generator exhausts, and, therefore, the risk to the public is acceptable. This resolves outstanding issue 3.
3.9 Mechanical S stems and Com onents 3.9.3 ASME Code Class 1, 2, and 3 Components, Component Supports, and Core Support Structures 3.9.3. 1 Loading Combinations, Design Transients, and Stress Limits In SER Section 3.9.3. 1, the NRC staff stated that the applicant committed to demonstrate that a square root of the sum of the squareF-(SRSS) combination of dynamic responses for WNP-2 achieves the 84%%u'onexceedence probability level.
The staff has reviewed the information in the following referenced documents:
Bouchey, 1983; Bouchey, 1982a; GE SMA 12109.01-R001; and NEDE-24010-P (see Appendix B). In Bouchey, 1983, the applicant performed a study that included 96 samples of combinations of dynamic responses resulting from safety/relief valve (SRV) discharge and seismic loadings. ,The results of the study indicated that the nonexceedence probabilities (NEPs) of SRSS combination of responses at selected sample locations are at or exceed 50K, and the NEPs of 1.2 SRSS are at or exceed 85K. Based on a review of this study and information in Bouchey, 1982a; GE SMA 12109.01; and NEDE-24010-P, the NRC staff has determined that the SRSS method for combining dynamic responses is applicable to the WNP-2 nuclear plant and satisfies the requirements of "Methodology for Combining Dynamic Responses," NUREG-0484, Revision 1 (July 1981). This resolves confirmatory item 6.
In the SER, the NRC staff also stated that the applicant committed to perform a plant-unique American Society of Mechanical Engineers "Boiler and Pressure Vessel Code (ASME Code),Section III, Class 1 fatigue evaluation for the SRV discharge pipings and downcomers. The NRC staff has reviewed the information on the fatigue analysis on these lines described in the WNP-2 Design Assessment Report dated January 21, 1983. The fatigue evaluation of 24- and 28-inch downcomer lines and all 18 SRV lines in the wetwell air volume was performed using ASME Code,Section III, Class 1 rules. The results of these analyses indicated that the maximum fatigue usage factor for both downcomers and all .18 SRV lines was below ASME Code-allowable limits. The NRC staff finds that the applicant's evaluation satisfies the ASME Code, Section III, Class 1 fatigue evaluation requirement and is acceptable. This resolves confirmatory item 5.
The NRC staff contracted with the Energy Technology Engineering Center to perform an independent analysis of the main steam relief line 10" MS(18)-2 SRV WNP-2 SSER 3 3-3
analysis verified that the piping system me't the applicable ASME Code accept-ance requirements. The, detailed results of this analysis are documented in the Energy Technology Engineering Center report, "WPPSS No. 2 Confirmatory Piping Analysis," dated July 6, 1982 and its attachment dated November 2, 1982.
- 3. 10 Seismic and D namic uglification of Seismic Cate or I Mechanical and Electrical E ui ment'.
- 10. 1 Seismic and Dynamic gualification The staff evaluation of the applicant's program for qualification of safety-related electrical and mechanical equipment for seismic and dynamic loads consists of (1) a determination of the acceptability of the procedures used, standards followed, and the completeness of the program in general, and (2) an audit of selected equipment items to develop the basis for the staff judgment on the completeness and adequacy of the implementation of the entire seismic and dynamic qualification program. The Seismic gualification Review Team (SgRT) consists of NRC staff engineers and personnel from the Idaho National Engineering Laboratory (INEL, EG8G). The SgRT has reviewed the equipment dynamic qualification information in FSAR Sections 3.9.2 arid 3. 10 and visited the plant site on November 16 through November 19, 1982 to determine the extent to which the qualification of equipment as installed at WNP-2 meets the current licensing criteria as described in Institute of Electrical and Electronics Engineers (IEEE) Standard 334-1975; RGs 1.92 and l. 100; and SRP 3. 10.
Conformance with these criteria is required to satisfy the applicable portions of GDC 1, 2, 4, 14, and 30, as well as Appendix B to 10 CFR 50 and Appendix A to 10 CFR 100. A representative sample of safety-related electric and mechanical equipment, as well as instrumentation, included in both the nuclear steam supply system (NSSS) and the balance of plant (BOP) scopes of review, was selected for the audit. The plant site visit consisted of field observa-tions of the actual final equipment configuration and its installation. This was immediately followed by the review of the corresponding test and/or analysis documents that the applicant maintains in his central files.
Observing the field installation of the equipment is required to verify and validate equipment modeling employed in the qualification program. Based on the audit, the SgRT concluded the applicant has properly implemented the seis-mic and dynamic qualification program. However, some concerns, both plant generic and equipment-specific remain; these are delineated in Subsec=
tions 3. 10. 1. 2 and 3. 10. 1. 3. These concerns must be satisfactorily resolved before fuel loading. The plant generic concerns are more significant, in that they apply to all safety-related equipment and potentially can affect a large number of components and systems. The applicant must develop an acceptable approach and plan to resolve the plant generic findings.
The audit identified the need to provide additional information on certain plant generic findings as well as to clarify the details of qualification for some pieces of equipment. These findings are summarized below.
WNP-2 SSER 3 3-4
3.10.1.1 Plant Generic Findings A unique feature of the containment design is that the reactor building founda-tion is not integral with the. containment foundation. Hydrodynamic loads inside containment are included in, the qualification of equipment. Outside containment, but inside the reactor building, hydrodynamic loads are not considered, because the unique design of containment is alleged to attenuate these loads. The staff review in this area is continuing and will be completed in additional meetings with the applicant.
Mhen the valve operator BOP-12 was qualified, an assumed g value was used.
Later, in the as-built and as-installed condition, an analysis confirmed that the g value used in the qualification was indeed adequate. This is also the case with other equipment in this category as far as loads are concerned. The applicant indicated that a procedure is in place to verify assumed g values for each case. For the motor operator, the g value was confirmed to be adequate.
The applicant is to confirm the adequacy of all assumed g values and inform the NRC in writing of the results when this confirmation is completed.
The motor control center was qualified through single frequency, biaxial input tests. The motor control center has more than one natural frequency below 33 Hz. This technique, in the absence of adequate justification, is not accept-able. The applicant is to review the cases in which single frequency tests have been used in spite of the presence of multiple natural frequencies of the system within the range of 33 Hz. In each case, the applicant is to provide a justification for single frequency testing.
All safety-related equipment should be qualified and installed before fuel loading. At the time of the audit, some safety-related equipment remained to be qualified and installed. Before fuel loading the applicant must state in writing that all (100%) of the plant safety-related equipment is qualified and installed.
- 3. 10. 1. 2 Speci fic Issues Pressure Switch BOP-14 The panel on which this item is mounted was qualified by test. The test con-sisted of multifrequency, multi-axis, random inputs. Test Response Spectra (TRS) from these tests enveloped the initial Required Response Spectra (RRS).
Subsequently, based on further investigation, the RRS were changed, with the result that the TRS did not envelope the RRS in different regions. An effort was made to analyze this apparent inadequacy based on the natural frequency of the system. From this analysis, the lowest natural frequency of the system is
'estimated as 7.5 Hz. One unenveloped region is around 6.5 Hz, which is too close to the system frequency. As a result, the adequacy of the qualification test is in doubt. The applicant is to justify his present qualification or requalify the equipment.
- 3. 10. 1. 3 Summary Based on the SgRT audit findings as well as on submittals from the applicant, with the exception of the concerns mentioned, the staff concludes that an MNP-2 SSER 3 3-5
appropriate seismic and dynamic qualification program has been defined and substantially implemented. This provides adequate assurance that such equip-ment will function properly during and after the excitation from vibratory forces imposed by the safe shutdown earthquake.
Resolution of the specific and generic pl'ant items as they progress will be reported in a future supplement to the SER.
- 3. 10. 2 Operability qualification of Pumps and Valves To ensure that the applicant has provided an adequate program for qualifying safety-related pumps and valves to operate under normal and accident condi-tions, the NRC staff performs a two-step review. The first step is a review of FSAR Section 3.9.3.2 for the description of the applicant's pump and valve operability assurance program against SRP 3. 10. Because the information in the FSAR is general and not sufficient to evaluate the applicant's overall pump and valve operability qualification program, the Pump and Valve Operabil-ity Review Team (PVORT) also conducts an onsite audit.
The onsite. audit includes a plant inspection to observe the as-built configura-tion and installation of the equipment, a discussion of the system in which are located and of the normal and accident conditions under which the component must operate, and a review of the qualification documentation (stress reports, test reports, etc.).
The two-step review is performed to determine the extent to which the qualifi-cation of equipment, as installed, meets SRP 3. 10, as well as GDC 1, 2, 4, 14, and 30 and Appendix B to 10 CFR 50.
The onsite audit for WNP-2 was performed November 16 to 19, 1982. A repre-sentative sample consisting of seven valves and three pumps was chosen for.
review. The sample included both NSSS and BOP equipment. During the review, a number of concerns were raised. Some of these concerns were satisfactorily resolved by the applicant during the audit either by supplying additional information or by providing additional commitments, as appropriate. The remaining concerns and generic findings are summarized below.
- 3. 10.2. 1 Generic Findings No generic operability concerns resulted from the evaluation of the WNP-2 qualification program for pump and valve operability.
The results of reviewing the document packages for the unannounced components indicate that the applicant has a good central file system from which he can retrieve documents in a relatively short time, as required by SRP 3. 10. This conclusion was further substantiated after a review of the applicant's quality assurance filing system.
The PVORT was given an orientation lecture on the WNP-2 computer-based main-tenance and surveillance program by the supervisor of maintenance. The pro-gram appears to be very comprehensive and incorporates many excellent features.
Some of these include: (1) performing maintenance on all components before pre-operational testing; (2) integrating all pertinent qualification WNP-2 SSER 3 3-6
information (e.g., aging information for age degradable parts) into the main-tenance program, and (3) analyzing subcomponents upon removal to aid in deter-mining changes in replacement schedules. In keeping with the third idea, the applicant is voluntarily participating in the Nuclear Plant Reliability Data System (NPRDS).
The NRC staff concludes that the WNP-2 supply system equipment qualification group is dealing with the equipment qualification issue in a positive manner, and the results of the group's efforts are evident in the applicant's pump and valve operability assurance program.
- 3. 10. 2. 2 Specific Concerns Su ression Pool Outlet Valve HPCS-V-15 Hi h Pressure Core S ra Suction Isolation Valve During plant walk-down, reviewers observed that the horizontal clearance between the actuator and an adjacent pipe restraint was possibly too small, so that it might affect the operability of the valve under dynamic loads. A review of the documentation revealed that the valve was originally qualified to the interim piping criteria. When the final piping analysis was completed and compared to the interim load, a review by the applicant found that the loads for this component exceeded those calculated using the interim criteria.
The valve is currently being reanalyzed to the loads specified by the final piping analysis.
Confirmation that the valve has been requalified to the new loads must be provided to the staff before fuel load. In addition, the applicant must provide justification that clearance between the valve actuator and the adjacent pipe restraint will not affect valve operability during dynamic loads.
Rockwell 26-inch Globe Valve MS-V-22C Main Steam Isolation Valve During the valve inspection, NRC staff reviewers found: (1) the accumulator was not installed, (2) the installed solenoid valves were not qualified for the environment, and (3) the valve was scheduled to be completely disassembled for cleaning. These problems .were discussed with the startup engineer, and was determined that the valve, as viewed, was obviously not ready for operation.
it The valve, which had been on site for a number of years (the valve was built in 1973), was to be completely refurbished before testing. This refurbishing would include installation of environmentally qualified solenoid valves.
The documentation review revealed that the qualification of the assembly for operability under accident conditions was based on two analyses by Rockwell, RAL-2006, Revision 1, and RAL-1002, Revision 2. A test report (RAL-1004, Revision 0) was also provided for a similar valve (a 20-inch Rockwell Model 1612Y). RAL-1004 stated that the valve had operated with a 0.820-inch deflection. An analysis of the WNP-2 valve calculated a maximum deflection of only 0.270 inches. In addition, it was learned that a seismic test on a similar actuator for a Rockwell 24-inch valve was being reviewed by General Electric to determine if the results of that test could be used to qualify the WNP-2 actua-tor by similarity. The engineer in charge of power ascension testing commented WNP-2 SSER 3 3-7
on the operability of the valve assembly under design conditions.'e stated that the valve is to be tested (closed against flow) at three different power levels--approximately 30% 50K, and 85K. In addition, all the main steam isolation valves (MSIVs) will be closed simultaneously at 100K steam flow. A complete report on the results of the power ascension tests will be avail'able 3 months after completion of the tests.
Although MS-V-22C is presently not operable, the NRC staff's findings indicate that adequate plans are in place to ensure that the valve assembly will be qualified for operability before the power ascension tests. The power ascen-sion tests will then verify operability under normal plant conditions. How-ever, the applicant must provide the results of the ongoing review of a Rockwell seismic test on a similar 24-inch actuator before fuel load. In addition, confirmation that the solenoid valves for the actuators on all MSIVs have been replaced with qualified units must be provided before fuel load.
The qualification program for the safety-related pumps and valves was not complete for a number of components at the time of the audit. In addition to responding to the concerns addressed above, the applicant should provide a schedule for completion of this program.
- 3. 10. 2. 3 Summary The staff will complete its review when the applicant has provided the required information as stated above and has documented the completion of his pump and valve operability program. The documentation required to close each of the open items addressed in this report is discussed above. Satisfactory resolu-tion of all the open items discussed must be accomplished before fuel load.
A final evaluation of the pump and valve operability program will be performed following satisfactory resolution of the open items discussed above as well as notification that the pump and valve operability assurance program has been completed for all safety-related pumps and valves. The staff will report on the results of its final evaluation of the applicant's program in a future.
supplement to the SER.
- 3. 11 Environmental uglification of Electric E ui ment Im ortant to Safet and Safet -Related Mechanical E ui ment
- 3. 11. 1 Intr oducti on Equipment that is used to perform a necessary safety function must be demon-strated to be capable of maintaining functional operability under all service conditions postulated to occur during its installed life for the time it is required to operate. This requirement, which is embodied in GDC 1 and 4 and in Sections I I I, XI, and XVII of Appendix 8 to 10 CFR 50, i s applicable to equipment located inside as well as outside containment. More detailed require-ments, and guidance relating to the methods and procedures for demonstrating this capability for electrical equipment have been set forth in 10 CFR 50. 49, "Environmental qualification of Electric Equipment Important to Safety for Nuclear Power Plants," and NUREG-0588, "Interim Staff Position on Environmental qualification of Safety-Related Electrical Equipment." NUREG-0588 supplements IEEE Standard 323 and various NRC Regulatory Guides and industry standards.
MNP-2 SSER 3 3-8
- 3. 11. 2 Background NUREG-0588 was issued in December 1979 to promote a more orderly and systematic implementation of electrical equipment qualification programs by industry and to provide guidance to the NRC staff for use in ongoing licensing reviews.
The positions contained in this se'ction provide guidance on (1) how to establish environmental service conditions, (2) how to select methods that are considered appropriate for qualifying equipment in different areas of the plant, and (3) other areas such as margin, aging,. and documentation.
In February 1980, the NRC requested certain near-term operating licence (OL) applicants to review and evaluate the environmental qualification documentation for each item of safety-related electric equipment and to identify the degree to which their qualification programs comply with the staff positions described in NUREG-0588. IE Bulletin 79-01B, "Environmental gualification of Class 1E-Equipment," issued January 14, 1980, and its supplements dated February 29, September 30, and October 24, 1980, established environmental qualification requirements for operating reactors. This bulletin and its supplements were provided to OL applicants for consideration in their review.
A final rule on environmental qualification of electric equipment important to safety for nuclear power plants became effective on February 22, 1983.. This rule, Section 50.49 of'0,CFR 50, specifies the requirements to be met for demonstrating the environmental qualification of electrical equipment important to safety located in a harsh environment. In accordance with this rule, equip-ment for WNP-2 may be qualified to the criteria specified in Category II of NUREG-0588.
The qualification requirements for mechanical equipment are principally con-tained in Appendices A and B of 10 CFR 50. The qualification methods defined in NUREG-0588 can also be applied to mechanical equipment.
In response to the above requirements, the applicant has provided equipment qualification information in letters dated January 14, 1982, September 15, 1982, and January 31, 1983 to supplement the information in FSAR Section 3~ 11.
The following subsections evaluate the adequacy of the WNP-2 environmental qualification program for electric equipment important to safety as defined in 10 CFR 50.49 and for safety-related mechanical equipment. The staff review, includes an evaluation of the completeness of the list of systems and equipment to be qualified, the criteria which they must meet, the environments in which they must function, and an assessment of the qualification documentation for the equipment. It is limited to electric equipment important to safety within the scope of 10 CFR 50.49, and safety-related mechanical equipment. Equipment required to mitigate scram discharge volume (SDV) breaks as described in NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping," will be evaluated separately.
3.11.3 Staff Evaluation The staff evaluation of the applicant's environmental qualification program included an onsite examination of electrical equipment, audits of qualification documentation, and a review of the applicant's submittals for completeness and WNP"2 SSER 3 3-9
acceptability of systems and components, qualification methods, and accident environments. The criteria described in SRP 3. 11 (NUREG-0800) and NUREG-0588, Category II, form the basis for the staff evaluation of the adequacy of the applicant's qualification program. Revision 1 of NUREG-0588 was utilized to clarify staff positions as required.
The staff performed an audit of the applicant's qualification documentation and installed electrical equipment on February 15 through 17, 1983. The audit consisted of a review of 10 files containing equipment qualification docu-mentation. The staff's findings during the audit are discussed in detail in Section 3. 11.4.2 below. Mechanical equipment environmental qualification was also reviewed.
- 3. 11.3. 1 Completeness of Equipment Important to Safety The applicant was directed to (1) establish a list of systems and components that are required to prevent or mitigate a loss-of-coolant accident (LOCA) or a high-energy line break (HELB) and (2) identify components needed to perform the functions of safety-related display instrumentation, post-accident sampling and monitoring, and radiation monitoring.
The applicant's systems list for the environmental qualification program was compared to FSAR Table 3.2;l. Omissions from the harsh environment program were adequately justified by the applicant. Appendix 30, appended to this section, lists the systems identified and their safety function.
Based on information in the applicant's submittal, the staff has verified and determined that the systems included in the applicant's submittal are those required to achieve or support: (1) emergency reactor shutdown, (2) contain-ment isolation, (3) reactor core cooling, (4) containment heat removal, (5) core residual heat removal, and (6) prevention of significant release of radioactive material to the environment.
The applicant has identified the equipment required by NUREG-0737, "Clarification of TMI Action Plan Requirements," but the qualification status has not been established for all items. Before an operating license is granted, the appli-cant should identify the qualification status for all TMI Action Plan equipment.
For any TMI Action Plan equipment not yet installed and that will not be installed prior to operation, a description of the plans for qualification, including the schedule for completion of qualification, must be submitted.
(All TMI Action Plan equipment currently installed or that will be installed before operati'on must be qualified, or justifications for interim operation provided before an operating license is issued, in accordance with 10 CFR
- 50. 49. )
To comply with 10 CFR 50.49, the following information must be submitted by the applicant before an operating license for MNP-2 can be granted:
(1) A list of all nonsafety-related electrical equipment, located in a harsh environment, whose failure under postulated environmental conditions could prevent satisfactory accomplishment of safety functions by the safety-related equipment. A description of the methods used to identify
'4NP-2 SSER 3 3-10
this equipment must be included. The nonsafety-related equipment iden-tified must be included in the environmental qualification program.
(2) A statement that all safety-related electrical equipment in a harsh environment,'s defined in the scope of 10 CFR 50.49, is included in the list of equipment identified in the September 1982 submittal.
(3) A list of all post-accident monitoring equipment currently installed, or that will be installed before plant operation begins, that is specified =as Category 1 and 2 in Revision 2 -of RG 1.97 and is located in a harsh environment. The equipment identified must be included in the environmental qualification program.
- 3. 11.3.2 qualification Methods
- 3. 11.3.2. 1 Electrical Equipment in a Harsh Environment Detailed procedures for qualifying safety-related electrical equipment in a harsh environment are defined in NUREG-0588. The criteria in NUREG-0588 are also applicable to other equipment important to safety as defined in 10 CFR 50.49. Type testing of equipment in a sequence consisting of pre-aging (thermal, radiation, and mechanical), seismic and dynamic loading, and exposure to LOCA/
HELB conditions (where applicable) is the prefer red method of qualification.
However, in a number of cases the applicant has extrapolated partial test data to establish the equipment qualfication. The staff has reviewed this analysis and finds the approach to be adequate except as noted in this report.
- 3. 11.3.2.2 Safety-Related Mechanical Equipment in a Harsh Environment Although ther e are no detailed requirements for mechanical equipment, GDC 1 and 4; Sections III and XVII of Appendix 8 to 10 CFR 50; and SRP 3. 11, Revision 2, contain the following requirements and guidance related to equip-ment qualification:
~
Components shall be designed to be compatible with the postulated environ-mental conditions, including those associated with LOCAs.
Measures shall be established for the selection and review for suitability of application of materials, parts, and equipment that are essential to safety-related functions.
~
Design control measures shall be established for verifying the adequacy of design.
~
Equipment qualification records shall be maintained and shall include the results of tests and materials analyses.
The staff review is concentrated on materials that are sensitive to environ-mental effects (for example, .seals, gaskets, lubricants, fluids for hydraulic systems, and diaphragms). qualification documentation was reviewed by the staff to verify conformance with the above criteria. The results of the staff review are in Section 3. 11. 4. 3 below.
WNP-2 SSER 3 3-11
- 3. 11.3.3 Service Conditions NUREG-0588 defines the methods to be utilized for determining the environmental conditions associated with LOCAs or HELBs, inside or outside of containment.
The review and evaluation of the adequacy of these environmental conditions are described'elow. The staff has reviewed the qualification documentation to ensure that the qualification conditions envelop the, conditions established by the applicant.
- 3. 11.3.3. 1 Temperature, Pressure; and Humidity Conditions Inside the Primary Containment The applicant provided the LOCA/main steamline break (MSLB) profiles used for equipment qualification program submittals. The peak values in the drywell resulting from these profiles are as follows:
Maximum Maximum pressure, tern erature F LOCA/MSLB 340 45 100 The staff has reviewed these profiles and finds them acceptable for use in equipment qualification; i.e., there is reasonable assurance that the actual pressures and temperatures will not exceed those profiles anywhere within the specified environmental zone (except in the break zone).
- 3. 11.3.3.2 Temperature, Pressure, and Humidity Conditions Outside the Primary Containment The applicant has provided the temperature, pressure, and humidity conditions associated with HELBs in the secondary containment. The staff has used a screen-ing criterion of saturation temperature at the calculated pressure to verify that the parameters identified by the applicant are acceptable. The applicant should indicate that the postulated environmental conditions associated with moderate-energy line breaks are no more severe than the conditions associated with high-energy line breaks.
- 3. 11.3. 3. 3 Submer gence The maximum submergence level established by the applicant in the environmental qualification program is 12 inches above the drywell floor. The applicant has stated that there are no exposed connections or equipment located between the diaphragm floor and the top of the downcomer vent pipes inside the wetwell, except for the wetwell level system, which-is totally enclosed in watertight conduit.
The effects of flooding on equipment located in the reactor building have been evaluated to ensure that safe shutdown can be achieved. All impacted equipment will either be protected, relocated, or qualified.
The applicant should indicate that any equipment important to safety that could be subjected to flooding will not affect the safety function of any other equip-ment or system and will not mislead the operator.
MNP-2 SSER 3 3-12
3.11.3.3.4 Demineralized Water Spray A demineralized water spray could be used inside primary containment to mitigate the effects of an accident. Spray impingement on affected equipment has been evaluated by the applicant and has been included in the qualification program.
- 3. 11. 3.3. 5 Aging NUREG-0588, Category II delineates two aging-program requirements. Valve operators committed to IEEE Standard 382-1972 and motors committed to IEEE Standard 334-1971 must meet the Category I requirments of NUREG-0588. This requires the establishment of a qualified life, with maintenance and replace-ment schedules based on the findings. All other equipment must be subjected to an aging program that identifies aging-,susceptible materials within the component.
In addition to the above, a maintenance/surveillance program should be implemented to identify and prevent significant age-related degradation in electrical and mechanical equipment. The applicant has committed to follow the recommendations in RG 1.33, Revision 2, "equality Assurance Program Requirements (Operation),"
which endorses American National Standard ANS-3.2/ANSI N18.7-1976, "Administra-tive Controls and equality Assurance for the Operational Phase of Nuclear Power Plants," as noted in SER Section 17. This standard defines the scope and content of a maintenance/surveillance program for safety-related equipment. Provisions for preventing or detecting age-related degradation in safety-grade equipment are specified and include (1) utilizing experience with similar equipment, (2) revising and updating the program as experience is gained with the equip-ment during the life of the plant, (3) reviewing and evaluating malfunctioning equipment and obtaining adequate replacement components, and (4) establishing surveillance tests and inspections based on reliability analyses, frequency and type of service, or age of the items, as appropriate. The applicant must commit to implementation before an operating license is granted.
- 3. 11.3.3.6 Radiation (Inside and Outside Containment)
The applicant has provided values of the radiation levels postulated to exist following a LOCA. The accident radiation environments in primary containment .
have been defined according to Section II.B.2 of NUREG-0737 and NUREG-0588, Revision 1. For this review, the staff has assumed that the values provided have been determined in accordance with the prescribed criteria. The staff review determined that the values to which the equipment was qualified enveloped the requirements identified by the applicant, except as noted in Section 3.11.4.2 below.
The radiation service condition specified by the applicant for primary contain-ment are: 7. 0 x 10~ rads in the drywell; 9 x 10~ rads in the wetwell; and 3.7 xlO rads in the suppression pool. In the secondary containment,: required values of up to 1.2 x 10 rads gamma were used in the evaluation of equipment in areas exposed to recirculating fluid lines. These values are acceptable for use in the qualification of equipment.
In addition the applicant was directed to evaluate any possible radiation-induced damage to solid state devices and the effect of beta radiation on WNP-2 SSER 3 3-13
equipment important to safety. The applicant has indicated that an investiga-tion is under way and corrective action will be taken as required.
- 3. 11.3.4 Outstanding Equipment For items not having complete qualification documentation, the applicant must provide a commitment for corrective action and schedules for completion. For items that will not have full qualification before an operating license is .
granted, analyses must be performed in accordance with paragraph (i) of 10 CFR 50.49 to ensure that the plant can be operated safely pending completion of environmental qualification. These analyses must be submitted for consideration before the granting of an operating license.
In his list of equipment, the applicant has identified a manual control switch, General Electric type CR 2940. This switch has recently been identified as having failed after exposure to radiation aging. The applicant should review the specific use of this switch in the plant and ascertain that this equipment is suited for its application.
The applicant also has stated that the required minimum operating time margin of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> was not applied in certain specific cases. The specific equipment should be identified by the applicant for staff review.
- 3. 11.4 qualification of Equipment The following subsections present the staff assessment based on the applicant's submittal, audits of documentation at the plant site, information in the NRC Equipment qualification Data Bank, and previous staff evaluations of equipment in other plants.
- 3. 11.4. 1 Electric Equipment in a Harsh Environment The applicant has committed to completing several analyses important to the validity of the equipment qualification program, as stated in Section 3. 11. 3. 3. 6 above. The applicant has also committed to provide an updated Environmental Equipment gualfication Report to reflect any changes in the qualification status and information provided to the staff. Because of these expected revisions, Appendices 3A, 3B, and 3C, which would normally list the equipment items and their qualification status, will not be included in this SER. These appendices will be provided in a future supplement after the revised submittal is reviewed.
- 3. 11. 4. 2 Environmental qualification Audit The staff, with assistance from EG8G Idaho, Inc., performed an audit of the applicant's qualification files on February 15 through 17, 1983. The audit consisted of a review of 10 files containing information regarding the quali-fication status of the equipment. There were a number of exceptions taken with the findings of the applicant regarding the qualification status of the equipment. Based on the results of the audit, the staff has determined the following:
MNP-2 SSER 3
For 3 of the 10 items reviewed that were classified by the applicant as qualified, the required accuracy had not been developed and compared with the demonstrated accuracy during testing. These itmes should be reclassified as not fully qualified until the demonstrated accuracy under accident conditions is shown to envelop the required accuracy. The staff may select several pieces of equipment for detailed review of the resolution of this item before licensing.
(2) Modifications to installed transmitters resulting from IE Bulletin 80-16 had not been considered in the evaluation of the qualification information.
Although the applicant satisfactorily addresses the effects of these modi-fications, he should address how changes to other equipment items resulting from IE Bulletins, Circulars, and Information Notices have been or will be evaluated for their impact on qualification.
(3) For the same transmitter, the applicant determined by the Arrhenius equa-tion that an "0-ring" sealing the electronics housing had an expected life of 40 years. However, the applicant was unable to address the type and frequency of surveillance to be performed to determine if unanticipated age-related degradation is occurring. Recent information has revealed that a failure was observed during qualification tests of Rosemount trans-mitters as a result of the inability of the seal to prevent steam ingress into the electronics housing. Based on this, the staff will not accept analysis in lieu of testing to address the effects of age-related degrada-tion on the seals of any equipment containing susceptible electronic components, unless there are valid reasons to the contrary (environmental conditions, etc.).
One other file, for a level switch, did not contain aging data to support a calculated life of 40 years and only selected pages of a referenced test report were included in the file. The complete test report was provided at the end of the audit but was not made part of the qualification file.
A cursory review of the report revealed that maintenance was required at 1- and 5-year intervals to obtain a 40-year life. The applicant did not address these requirements.
Because aging was addressed exclusively by analysis in the majority of the files reviewed, the applicant should describe the approach that will be taken to account for material degradation.
(4) During the plant walk-down it was noted that flexible conduit connected to electrical equipment had not been included in the environmental qualifi-cation program. Failure of this conduit under accident conditions could permit steam to enter sealed portions of instruments and cause equipment failures. This item should be added to the program and qualified for the postulated environments.
Also noted during the walk-down were several instances where the installed equipment was not representative of the tested equipment, specifically An electronics housing for a transmitter did not contain a threaded metal plug for sealing but instead used a plastic insert intended only to protect the threads. The insert does not provide leaktight WNP-2 SSER 3 3-15
integrity and could permit steam from a high-energy line. break to enter the housing.
~
A pressure switch was described as being sealed with RTV silicone
.rubber at the lead wire entrance cavity to exclude moisture from the device internals during .qualification tests. This type of sealing was not evident at plant installation, and the applicant could not determine if the same type of sealing was provided in the installed configuration.
Because of the discrepancies identified, the applicant should reeva'luate the adequacy of the plant walk-down performed before the staff's audit.
From the information in the qualification files on installed equipment and the results of the staff's walk-down, it is apparent that environmental qualification concerns were not adequately addressed. The staff will review the applicant's approach to the resolution of this item prior to licensing.
{5) One item that could be exposed to elevated temperatures and 100%%uo'elative humidity from a high-energy line break was qualified by evaluation of tests for individual components in the device; type testing of the assembled device had not been utilized as required by NUREG-0588. Although addi-tional review by the applicant established that the item, a transformer, was not required to function during line break conditions, other equipment in the program may have been similarly reviewed and considered to be qualified. The applicant indicated during the audit that all other equipment has been qualified for steam conditions by type testing. To verify this, the staff will review the applicant's revised list of equip-ment and compare qualification methods with those described in the staff's Equipment qualification Data Bank.
(6) During the plant walk-down and review of the qualification files, it was evident for one item that traceabi lity and similari.ty between the tested piece of equipment and the installed equipment was not established. The applicant has not demonstrated conclusively that the material data reported in the files apply to the component materials of the installed equipment.
The applicant should review the qualification program and establish that all data reported are applicable.
- 3. 11.4.3 Environmental qualification of Mechanical Equipment Three mechanical equipment qualification files were reviewed by the staff.
In general the same comments made for electrical equipment apply to the mechanical equipment. qualification is based on analysis to a great extent, especially to demonstrate radiation and aging resistance. For example, radia-tion resistance of the "0-rings" on a "qualified" air operator on the main steamline is achieved by a vague referenced statement that in one test the "seals perform acceptably." Similarity of material compound and similarity of application were not demonstrated. For another material, the required radia-tion dose was not enveloped by the reported qualification dose. A replacement interval was not specified to justify the lower value.
WNP-2 SSER 3 3" 16
The applicant should review the mechanical equipment qualification files to ascertain tHat all deficiencies are removed. The staff may select additional pieces of equipment for detailed review. Additionally, the applicant shou'Id submit the results of his review for all safety-related mechanical equipment located in a harsh environment. For any equipment that will not be demon-strated fully qualified before an operating license is granted, justification for interim operation should be submitted, along with proposed corrective actions and a schedule for completion.
- 3. 11. 5 Conclusions On the basis of its review, the staff finds that the applicant must provide the required information, identified above, to demonstrate full compliance with 10 CFR 50.49 and all applicable regulations. The qualification information should be provided to allow sufficient tipe for staff review and approval before an operating license is issued. The staff's evaluation wi')') be addressed in a future supplement.
WNP-2 SSER 3 3-17
APPENDIX 3D SAFETY-RELATED SYSTEMS IN THE ENVIRONMENTAL QUALIFICATION PROGRAM A. Emer enc Reactor Shutdown Reactor Protection System Average Power Range Monitor Local Power Range Monitor System Control Rod Drive System B. Primar Containment Isolation Containment Instrument Air System Isolation Valves in the following systems:
RRC Hydraulic Control Main Steam'ystem Reactor Feedwater System Reactor Recirculation System High Pressure Core Spray System Low Pressure Core Spray System Standby Liquid Control System Residual Heat Removal System Reactor Core Isolation Cooling System Containment Atmosphere Control Containment Supply Purge System Containment Exhaust Purge System Reactor Closed Cooling System Reactor Water Cleanup System Equipment Drain System Floor Drain System Containment Instrument Air System Process Instrumentation System Control Air System Fuel Pool Cooling System Traversing In-Core Probe System C. Reactor Core Coolin (Short Term High Pressure Core Spray System Low Pressure Core Spray System Main Steam System Residual Heat Removal System Containment Instrument Air System Standby Service Water System WNP-2 SSER 3 3-18
D. Containment Inte rit Containment Atmosphere Control System Containment Return Air System Containment Vacuum Breaker System Residual Heat Removal System Standby Service Water System E. Core Residual Heat Removal Residual Heat Removal System Standby Service Water System Prevent Release of Radioactive Material Standby Gas Treatment System Main Steam Leakage Control System Standby Service Water System Leak Detection System Miscellaneous Drain System Reactor Building Exhaust Air System (Reactor Building Isolation)
Reactor Building Outside Air System (Reactor Building Isolation)
WNP-2 SSER 3 3-19
4 REACTOR 4.2 Fuel S stem Desi n 4.2.3 Design Evaluation 4.2.3. 1 Fuel System Damage Evaluation (4) External Corrosion and Crud Buildu Waterside Corrosion Corrosion problems associated with stainless steel cladding in boiling water reactors (BWRs), together with a desire to improve neutron economy, led to a change some years ago from stainless steel to Zircaloy cladding material, which has good resistance to the hot water and steam environment encountered under typical BWR operating conditions (Garzarolli et al., 1978). In several recent cases, however, cladding failures have been associated with external "waterside" corrosion (GE Projects Division Memorandum, 1979, and Manry, 1981),
and these occurrences have been characterized by GE as "crudinduced local corrosion failure" (NEDE-24343-P). The corrosion is reportedly associated with a variably high copper concentration in the core coolant water and a minor anomaly in the Zircaloy cladding metallurgy (Charnley, 1979; Engel, 1980; Smith, 1980; Smith, 1981; and DelGeorge, 1980). The source of the copper contamination in the affected plants appears to be the copper-bearing main condenser tubes (DelGeorge, 1980). All the plants affected have copper alloy condenser tubing. It is notable also that virtually all the BWR waterside corrosion failures have involved gadolinia burnable poison rods.
The NRC staff has been following this issue generically, and in a recent meeting with the staff, GE identified (Tokar, 1982) what were believed to be some factors responsible for the corrosion, failures and stated that a change had been made in the manufacturing process to ensure that such fai lures will not occur in newly manufactured fuel bundles. GE's presentation provided an explanation of the problem, and the solution appears plausible (ibid).
Further documentation on this subject has been provided in a recent letter from the applicant (Bouchey, 1982c). This letter confirmed that all susceptible cladding will be eliminated from the WNP-2 environment. The staff, therefore, concludes that this issue should be considered resolved for WNP-2.
Crud Bui ldu The buildup of a corrosion film and a crud layer on the outer surface of a fuel rod during irradiation causes gradual flow reductions and impedes heat transfer to the coolant. The effects of crud buildup on flow are discussed in SER Sec-tion 4. 4. 5. As indicated in Section 2. 4. 2. 2 of NEDE-24011, GE calculates the cladding surface temperature using the cladding surface heat flux at a given
axial position of a fuel element in conjunction with an overall cladding-to-
, coolant film coefficient that is taken to represent the combined effects of crud and oxide resistances and a liquid film resistance based on the Jens-Lottes wall superheat equation (Jens and Lottes, 1951). The impact of high cladding temperatures, such as decreased yield strength and reduced cladding thickness due to oxidation, was considered in GE's design evaluation (NEDE-24011). GE's methods for analyzing the effects of oxidation and crud on fuel cladding temperatures were reviewed and approved in connection with NEDE-24011, and the NRC staff, therefore, finds that approach acceptable for WNP-2.
(5)'imensional Chan es Channel Box Deflection Boiling water reactor (BWR) fuel channels provide structural stiffness for the fuel assemblies and distribute the coolant flow between the assemblies and channel bypass regions. The channels are subject to time-dependent, permanent dimensional changes (i.e., deflections) that result from irradiation, creep, and stress-relaxation effects. The resultant bulge (resulting from long-term creep) or bow (resulting from differential irradiation-induced axial growth) reduces the size of the gap available for control blade insertion. Channel box deflection is thus a phenomenon that can limit channel life because of the potential adverse effects on the ability of the control blades to move freely.
In a generic topical report (NEDE-21354-P), General Electric (GE) describes a channel lifetime prediction method and a backup recommendation for periodic channel deflection measurements that consist of settling friction tests. Upon consideration of the factors involved, the NRC staff concluded that the settl-ing friction tests or an acceptable alternative (such as channel dimensional deflection measurements) should be performed, and in a memorandum (Rubenstein, 1981) the staff outlined a method that could be used to resolve the channel box deflection issue f'r several near-term'WR operating license applications, including WNP-2. Basically, the staff advocated a multistep procedure that had been proposed bv the Zimmer applicant. The key ingredient of the Zimmer plan was a commitment to (1) perform some control rod settling friction tests, which would provide an exact profile of control rod drive friction versus position at refueling outages, or (2) make some actual channel dimensional measurements.
Several plants agreed to the Zimmer proposal. Subsequently, the BWR Licensing Review Group (LRG-II) submitted a position paper (Holtzscher, 1982) on channel box deflection that incorporated several of. the same features as the Zimmer proposal (the settling friction test was simplified). The LRG-II position was approved (Rubenstein, 1982) for the LRG-II plants (i.e., River Bend and Perry),
and a letter (Schwencer, 1982) was sent to WPPSS indicating the NRC staff's position on this issue at that time.
In response to the Schwencer letter, WPPSS stated (Bouchey, 1982b) that a channel management program for WNP-2 has been initiated that includes the following features:
(1) Compiling complete operating history records for each channel. Data to be collected include channel location, orientation of welded sides, exposure, and control history.
4-2
(2) Compiling complete analytical history records for each channel including fast fluence (>/MeV) and flux gradient history.
(3) Heasurement of post-operation channel box deflection.
Items 1 and 2 are consistent with the Zimmer and LRG-II proposals. The main difference in the WPPSS program lies in the emphasis on channel box deflection measurements. WPPSS proposes to measure channel box deflection after each refueling outage for selected channels that are discharged to the spent fuel pool. The reuse of discharged channels (the nominal design lifetime of BWR fuel channels is one fuel assembly lifetime, which currently is about 4 or 5 years) would be determined based upon those measurements as compared to predetermined criteria. Other items to be addressed in this program include development of channel manufacturing history data and analytical prediction capability.
In support of its proposed channel management program, WPPSS referred to some recently available data from Commenwealth Edison measurements that indicate that major channel bowing may be a strong function of channel manufacturing history rather than location of the channel within the core. The Commonwealth Edison data alluded to in the WPPSS letter are probably the same as that des-cribed in detail in a recent Electric Power Research Institute (EPRI) report (EPRI NP-2483) on a rather exhaustive study funded by EPRI. As indicated in the Bouchey letter (1982b) (and in Section 4 of the EPRI report), the Common-wealth Edison data indicate that prime candidates for channel bowing are those manufactured from mismatched halves; i.e., channels manufactured from two pieces of stock material not from the same original batch. It is notable that Car Tech channels avoid this potential problem because the channels are made by rolling and welding single sheets of material. The GE fabrication process, on the other hand, does not preclude use of unmatched halves. WPPSS has ident-ified which of the WNP-2 channels are manufactured from mismatched halves (75 out of 764) and has set up special plans to manage the use of these channels to minimize potential bowing. Those measures will include taking advantage of core locations that are not adjacent to control blades and identifying locations of minimal exposure and fast flux tilt. In addition, WPPSS is proposing to take a number of operational actions to monitor channel distortion in the core, including scram time and rod notch testing prior to startup after each reload.
For control rods that fai 1 those tests, the settling friction test described in Section 4.4.2 of NEDE-21354-P would be performed.
The above described channel box management program committed to by the applicant for WNP-2 reflects the latest state-of-the-art information on this issue and is supported by results of a comprehensive study funded by EPRI. Based on the information from that study, the NRC staff concludes that the proposed program is eminently sound and that its implementation by WPPSS wi 11 provide adequate assurance that channel box deflection will not become a problem in WNP-2. This removes the need for potential license condition 2.
Fuel Rod Bowin A 1977 version of a GE fuel experience report (NEOE-21660-P) stated that BWR fuel operating experience, testing, and analysis indicate that there is no significant problem with rod bowing. The staff recently completed (Rubenstein, 4-3
1983) a review of a GE generic topical report (NEDE-24289-P) that is intended to update the GE rod bowing experience. On the bases of (1) the reported GE data base and GE's statement that "To date, no significant fuel rod bowing has been detected in GE BWR fuel assemblies" Lsic, excluding segmented-rod designs]
and (2) the NRC staff's calculations using other vendors'roprietary informa-tion, the NRC staff concludes that significant fuel rod bowing in GE BWR fuel is not anticipated and no operational penalties on GE BWR fuel are warranted at this time. If adverse rod bowing behavior (gap closures greater than 50K) is observed in GE-supplied fuel in the future, NRC should be notified to ascertain the need for critical power ratio penalties. This resolves confirmatory item 12.
4.6 Functional Desi n of Control Rod Drive S stem In the SER, the NRC staff stated that its review of the applicant's response to the'ffice of Analyses and Evaluation of Operational Data (AEOD) May 3, 1981 report entitled "Safety Concerns Associated with a Pipe Break in the BWR Scram System" was not complete. The NRC staff has completed its review of the appli-cant's submittal and the additional information provided by submittals dated December 9, 1982 and February 3, 1983. The results of the applicant's analysis indicated that the scram system pipe break identified in the AEOD report would not result in flooding of safety-related equipment and would not produce any adverse environmental effects. The applicant provided a discussion of the pro-cedure needed to isolate such a reactor coolant system leak and verified that the effects of the escaping reactor coolant would not prevent personnel from enter-ing the area and isolating the leak. Thus the applicant has adequately addressed the May 3, 1981 AEOD report concerns, and the NRC staff agrees with the applicant's conclusions.
Based on the above, the NRC staff concludes that the applicant has adequately addressed the concerns expressed by AEOD in its May 5, 1981 report. The design of the control rod drive system meets the applicable acceptance criteria of SRP 4. 6 {NUREG-0800). This resolves outstanding issue 28.
4-4
7 INSTRUMENTATION AND CONTROL 7.3 En ineered Safet Features S stems
- 7. 3. 2 Specific Findings 7.3.2.4 Standby Service Water System The standby service water (SSW) system was designed to use multiplexed signals to operate associated pumps and valves. The NRC staff raised several concerns regarding the use of multiplexing in this Class lE application. Of particular concern were the potential effects of electromagnetic interference (EMI) on the SSW multiplexer systems, and the inability to manually operate SSW system components remotely, independent of the multiplexer systems.
The applicant has since committed to implement design modifications that will remove all safety-related functions from the multiplexers. This will allow (1) the functioning of the SSW pumps and valves in 'the primary flow path with-out the multiplexer, and (2) manual initiation/control capability for SSW components from the control room, independent of the multiplexers. The multiplexers will remain operational, providing the operator with supple-mentary information fr'om the SSW pumphouse. Examples of this information are spray pond level and temperature, pump discharge pressures, and pump motor and bearing temperatures. Sufficient instrumentation independent of the multiplexers is provided in the control room to allow the operators to verify SSW system operability. This instrumentation includes valve position and pump running status lights, SSW flow through the RHR heat exchangers, and low flow alarms for the components served by the SSW system. The applicant plans to complete these modifications before fuel load.
The NRC staff has determined (based on its review of the SSW system as described and on supporting information provided in WPPSS letters G02-83-167 dated February 23, 1983, and G02-83-266 dated March 28, 1983) that the SSW system instrumentation and controls are acceptable. This resolves outstanding item 10.
The applicant will be required to submit the final drawings (electrical schematics) for the affected components for confirmatory review when the design modifications are completed. This resolves outstanding issue 10.
7.6 All Other Instrumentation S stems Re uired for Safet 7.6.2 Specific Findings
- 7. 6. 2. 3 Rod Bl ock Moni tor The NRC staff identified four concerns regarding the WNP-2 rod block monitor (RBM) function as stated in the SER. These are WNP-2 SSER 3 7-1
(1) The four flow monitors are interconnected by armored cable and shielded cables, and there are open spaces around the cables that penetrate fire barriers between redundant channels.
(2) Both RBM channels are connected by data buses that are enclosed in a metal shield and run along the top of the cabinet.
(3) The wiring of the RBM bypass switch may not satisfy the separation criterion (minimum separation of 6 inches).
(4) The RBM is a modified design and contains multiplexing circuitry that interfaces with the new reactor manual control system.
The WNP-2 RBM is identical to other RBM designs for which the above four concerns were identified and subsequently resolved. The applicant was to confirm that similar plant modifications to resolve these concerns have been implemented. The applicant has submitted information indicating that correc-tive actions to resolve these concerns have been or will be implemented as fol 1 ows:
(j.) As stated in the NRC staff's fire protection review (SER Section 9.5. 1),
the applicant has committed to inspect all fire barriers within the plant and to seal any unsealed penetrations with an approved fire resistant material with a rating equivalent to that of the barrier itself. Any deficiencies regarding the open spaces identified above will be corrected, according to the applicant's commitment. This resolution is acceptable to the NRC staff.
(2) The NRC staff reviewed the tests performed on the devices used to isolate the redundant RBM channels from each other in the Zimmer design and con-cluded that these devices provide adequate isolation. The applicant has indicated that these same devices are used in the WNP-2 RBM design.
Therefore, the NRC staff considers this item resolved.
(3) The applicant has stated that the wiring of the WNP-2 RBM bypass switch is being rerouted to provide acceptable separation. The NRC staff considers this item resolved.
(4) The multiplexing circuitry employed in the WNP-2 RBM and reactor manual control system processes and transmits information about reactor status, control rod position, rod block logic, and rod control logic through common electrical circuits. In earlier BWR designs this was accomplished by individual circuits. The new design has a self-testing capability to ensure that this information is being processed correctly. The NRC staff believes that the new multiplexing design is acceptable, provided this self-testing capability is, formally implemented through Technical Specifications. The Technical Specifications will require that this is done.
On the bases discussed above, the NRC staff has concluded that the WNP'-2 RBM is acceptable. This resolves confirmatory item,20.
WNP-2 SSER 3 7-2
9 AUXILIARY SYSTEMS 9.5 Other Auxiliar S stems 9.5.1 Fire Protection Program In the SER, two open items concerning fire protection were identified: verifi-cation of unlabeled fire doors, and deletion of a fire suppression system in fire areas.
By letters dated April 22, June 30, September 20, October 4, and October 5, 1982, the NRC staff received additional information concerning these open items.
In the SER, the NRC staff also stated that the applicant proposed to equip all manual hose stations in the plant with 150 feet of hose. At the request of the NRC staff, by letter dated January 28, 1983, the applicant agreed to modify the standpipe hose system to provide enough hose stations so that effective water streams can reach any area of the plant with a maximum of 100 feet of 1 1/2-inch hose, in accordance with Section C. 6. c of BTP CMEB 9. 5-1. By letter of March 4, 1983, the applicant proposed to deviate from the NRC staff guidelines by equip-ping hose stations in the reactor building with 150 feet of hose. This devia-tion was justified on the basis of water distribution system hydraulics, the capabilities of the plant fire brigade, and the cost and potential repercussions of a fire on safety-related equipment, SER Sections 9. 5. 1. 5(l), 9. 5. l. 6(3), 9. 5. l. 8, and 9. 5. l. 9 have been revised to reflect the results of the NRC staff evaluation of this information.
9.5. 1.5 General Plant Guidelines
( )
Fire areas are defined by walls and floor/ceiling assemblies. Walls that separate buildings and walls between rooms containing safe shutdown systems are 3-hour-fi re rated. Floor/ceiling assemblies are 1-1/2-, 2-, or 3-hour-fire-rated assemblies. In cases where the fire rating is less than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, the staff has evaluated the fuel loading and fire protection provided and found the fire rating acceptable. By letter dated December 9, 1981, the applicant has committed that all fire-rated walls and floors/ceilings will be qualified in accordance with ASTM E-119. Based on its review, the NRC staff concludes that the fire-rated walls and floor/ceiling assemblies are provided in accordance with the guidelines of Branch Technical Position (BTP) CMEB 9. 5-1, Section C.5. a," and are, therefore, acceptable.
By letter dated December 9, 1981, the applicant has also committed to provide 3-hour-fire-rated penetration seals. The penetration seals are verified by a 3-hour-fire test in accordance with the ASTM E-119 fire test procedure. Based on this, the NRC staff concludes that the fire seal ratings meet the guidelines of BTP CMEB 9.5-1, Section C.5.a, and, therefore, are acceptable.
WNP-2 SSER 3 9-1
Door openings in rated fire barriers are provided with labeled fire doors, except for several doors that are nonrated airtight doors. By letter dated April 22, 1982, the applicant provided additional information to verify that the airtight doors are similar in construction to labeled fire doors. The doors and frames are constructed of heavy gauge welded steel, with 2-1/4 inches of internal insulating material. The doors, when closed, will be able to withstand the anticipated fire exposure, represented by burning in situ and transient combustibles, and prevent the passage of smoke as well as convective and radiant heat as effectively as a labeled fire door. This resolves confirmatory item 23.
The applicant, in Amendment 19, has committed that the fire doors will satisfy the requirements of Appendix R to 10 CFR 50, Section N, which pertains to self-closing or administrative-cl'osing procedures. With the commitment the NRC staff finds that the fire doors meet the guidelines of BTP CMEB 9.5-1, and are, therefore, acceptable.
The applicant has provided 3-hour- and l-l/2-hour-fire door dampers in ducts penetrating fire-rated walls. Where duct penetrations have less than a 3-hour-fire rating, the NRC staff has evaluated the fuel loading and fire protection provided and found the fire rating acceptable. Based on its review, the NRC staff concludes that the fire doors and dampers will be provided in accordance with the guidelines of BTP CMEB 9.5-1, Section C.5. 1, and are, therefore, acceptable.
The use of plastic materials, in particular halogenated plastics, has been minimized. No flammable liquids (with the exception of the diesel generator oil day tanks covered in Section 9.5.4.2 of the SER) as defined by National Fire Protection Association (NFPA) Standard 30 are stored 'in the plant. The NRC staff finds that this conforms to the guidelines of BTP CMEB 9.5-1, Section C.5, and is, therefore, acceptable.
Interior walls and structural components, thermal insulation materials and components, and radiation shielding materials are noncombustible. Decontamin-able coatings and finish painting materials have a flame spread of less than
- 25. The NRC staff finds this to be within the guidelines of BTP CMEB 9.5-1, Section C.5.a, and, therefore, acceptable.
All high-voltage transformers located inside safety-related building areas are insulated or cooled with noncombustible liquid. There are no oil-filled transformers located within 50 feet of the exterior wall of a building containing safety-related equipment. This meets the guidelines of BTP CMEB 9.5-1, Section C.5.a, and is, therefore, acceptable.
9.5. 1.6 Fire Detection and Suppression (3) S rinkler and Stand i e S stems The wet pipe sprinkler system and standpipe hose system are connected to common risers from the underground water supply loop. Looped interior headers are provided. This design is in compliance with BTP CMEB 9.5-1, Section C.5.c, and is, therefore, acceptable.
WNP-2 SSER 3 9-2
The automatic sprinkler systems (wet pipe sprinkler systems, pre-action sprinkler system, and deluge water spray systems) are designed to the pro-visions of,NFPA Standards 13, "Standard for the Installation of Sprinkler Systems," and 15, "Standard for Mater Spray Fixed Systems."
The areas that are being equipped. with automatic water suppression systems are listed in FSAR Amendment 24.
By letter dated January 21, 1982, the applicant stated that 15 fire areas contain cables associated with redundant shutdown systems. To ensure post-fire shutdown capability, these cables must be protected. In FSAR Amendment 24, and in a letter dated October 4, 1982, the applicant revised this number from 15 to 10. The reduced number reflects the establishment of redundant shutdown capabilities in fire areas separate from those plant loca-tions originally identified as containing redundant safety divisions.
The following three areas will be completely protected by an automatic sprinkler system:
(1) cable spreading room (RC-ll)
(2) cable chase (RC-111)
(3) corridor (TG-1)
In the following seven areas, the applicant proposes to deviate from the staff guidelines to the extent that they require automatic fire suppression systems:
(1) remote shutdown room (RC-IX)
(2) switchgear room 82 (RC-XIV)
(3) general floor area (R-1) - elevation 471'-0" (4) general floor area (R-1) - elevation 501'-0" (5) general floor area (R-1) - elevation 522'-0".
(6) general floor area (R-1) - elevation 548'-0" (7) general floor area (R-1) - elevation 572'-0" ln lieu of an automatic sprinkler system, the applicant proposes to completely protect one safety division with a subliming and insulating coating that is capable of withstanding a 3-hour-fire exposure as defined in American Society for Testing and Materials (ASTM) Standard 119. The material has been demon-strated to protect the cable from visible fire damage and to maintain circuit integrity during fire exposure. The material is not adversely affected by a water hose stream and is capable of limiting temperature rise on the unexposed side to not more than 250'F above ambient, which is well below the temperature at which similar Institute of Electrical and Electronics Engineers (IEEE)-
qualified cabling began to fail in tests conducted independently for NRC at Underwriters'aboratories. The NRC staff concludes that this protection, coupled with the smoke detection systems in these areas, provides an equivalent level of fire safety to that achieved by the installation of a sprinkler system.
The NRC staff finds the deletion of automatic sprinkler systems in the proposed areas an acceptable deviation from Section C.6.c. of BTP CMEB 9.5-1. Therefore, the fire protection provided for these rooms is acceptable.
MNP-2 SSER 3 9-3
Manual hose stations are provided in stairwell enclosures throughout the plant except in containment. With the exception of the reactor building, all hose stations are equipped with 100 feet of 1.5-inch hose, in accordance with Section C.6.c of BTP CMEB 9.5-1. By letter dated March 4, 1983, the applicant proposed to deviate from the NRC staff guidelines by utilizing 150 feet of hose to protect all areas of the reactor building. One hundred feet of hose will be pre-connected to the hose outlets. The remaining 50 feet of hose will be connected only if required to suppress a fire in a remote area.
The configuration of the reactor building is such that it is possible to protect most of the floor area with 100 feet of hose. The remaining areas that necessitate the use of the additional 50 feet of hose contain the following systems:
Elevation 606'-10. 5" no safety-related equipment El evati on 572' train systems associated with the emergency core cooling system and the residual heat removal (RHR) heat exchanger Elevation 548' train systems associated with the RHR heat exchanger and-three motor-operated valves Elevation supply for the 522'ower RHR, reactor core isolation cooling (RCIC), and reactor water'leanup systems and the main .steam drain valve Elevation steam 501'ain isolation valve Elevation to motor-operated valves 471'HR piping valves and the dc power supply Elevations 441'nd 444' train systems associated with the RCIC and severe water systems and dc-operated valves Elevation 422'3" no safety-related equipment If a fire damages any of the above-listed equipment, an alternate capability exists in a separate fire area, or compensating actions could be taken, such as manual operation of valves. Consequently, there is no safety significance to the proposed deviation.
The plant water distribution system is capable of supplying hose streams in the reactor building with the required quantity of water and pressure (125 gpm, 65 psi) through 150 feet of hose. In addition, the plant fire brigade is capable of deploying the hose lines quickly enough to suppress postulated fires.
WNP-2 SSER 3 9-4
Based on the above evaluation, the NRC staff concludes the use of 150 feet of hose in the reactor building represents an acceptable deviation from Section C.6.c of BTP CMEB 9. 5-1. This resolves outstanding issue 31.
The applicant has not identified the seismic design of standpipe systems, which is recommended in BTP CMEB 9.5-1, Section C.6.c.(l). For plants for which construction permits were issued prior to July 30, 1976, the guidelines in Appendix A to BTP ASB 9.5-1 have no requirement for seismic design for standpipe systems. Therefore, this is an acceptable deviation from the guidelines of BTP CMEB 9.5-1, Section C.6.c.(1).
9.5. 1.8 Summary of Deviations from BTP CMEB 9.5-1 Five deviations from the guidelines of BTP CMEB 9.5-1 have been identified.
Those items have been approved, and they are (1) control room vent closure (2) seismic design of standpipe systems (3) floor drains in day tank room (4) deletion of a fire suppression system in the following seven plant areas:
remote shutdown room (RC-lX) switchgear room ¹1 (RC-XIV) general floor area (R-1) - elevation 471'-0" general floor area (R-1) - elevation 501'-0" general floor area (R-1) - elevation 522'-0" general floor area (R-1) - elevation 548'-0" general floor area (R-1) - elevation 572'-0" (5) the use of 150 feet of hose at hose stations in the reactor building
- 9. 5. 1. 9 Concl us i on Based on its evaluation, the NRC staff concludes that the fire protection pro-gram with the accepted deviations listed in Section 9.5. 1.8 above meets the guidelines of BTP CMEB 9.5-1 and GDC 3 and is, therefore, acceptable.
9.5.8 Emergency Diesel Engine Combustion Air Intake and Exhaust System As stated in the SER, the applicant had not adequately addressed potential blockage of the combustion air intake structure as a result of the design worst case dust storm and volcanic ashfall and blockage of the diesel engine exhaust stack as a result of severe meteorological events such as freezing rain, snow, dust storms, heavy rain, and volcanic ashfall. (The evaluation and acceptability of the tornado-missile protection for the diesel engine exhaust stack are addressed in Section 3.5.2 of this supplement.)
In letters dated August 5 and December 28, 1982, the applicant provided information on the capabilities of the diesel engine to operate under adverse meteorological conditions (snow, freezing rain, heavy rain, dust storms, and volcanic ashfall). The applicant stated that if any blockage did occur as a result of adverse meteorological conditions, the diesel engine air intake and
~ WNP-2 SSER 3 9-5
~
~
exhaust structures would only be partially blocked and engine operation would not be affected.. The NRC staff has reviewed the submitted information and concurs with the applicant.
Based on its review, the NRC staff concludes that the emergency diesel engine intake and exhaust system meet the requirements of GDC 2, 4, 5, and 17; meets the guidance of the cited RGs and SRP 9. 5. 8; can perform its design safety function; and meets the recommendations of NUREG/CR-0660 and industry codes and standards. It is, therefore, acceptable. This resolves outstanding issue 18.
WNP-2 SSER 3 9-6
13 CONDUCT OF OPERATIONS 13.1 Or anization Structure of A licant
- 13. 1. 1 Management and Technical Support Organization
- 13. l. 1. I,General The applicant has made organizational changes that establish the new positions of Director of Operations, Director of Support Services, and Director of Licens-ing and Assurance, reporting to the Managing Director.
Reporting to the Director of Operations will be the Director Power Generation, Director WNP-4/5 Termination Program, Director WNP-3 Program, Director WNP-2 Program, Director WNP-1 Program, and Director Technology. These directors formerly reported directly to the Managing Director, Washington Public Power Supply System (WPPSS). D. W. Mazur has been appointed to the position of Director of Operations. He has about 19 years of nuclear experience and was formerly the Director WNP-1/4 project.
The Director of Support Services picks up the functions of administrative, security, health physics, industrial safety, emergency preparedness, fire protection, and technical training support services. These functions, except for administrative, were formerly under the Director, Safety and Security.
J. W. Shannon has been appointed to the position of'irector, Support Services.
He has about 30 years of nuclear experience and was formerly the Director, Safety Security.
The Director, Licensing and Assurance will be responsible for licensing support, quality assurance, and nuclear safety assurance. Licensing support and nuclear safety assurance were formerly under the Director, Safety and Security., and quality assurance was a separate organizati.on. The Directors of Safety and Security and equality Assurance formerly reported directly to Managing Director, WPPSS. R. B. Glasscock has been appointed to the position of Director, Licens-ing and Assurance. He has about 24 years of nuclear experience and formerly was the Director, equality Assurance.
The NRC staff has reviewed these changes and finds that they meet the "Guidelines for Utility Management Structure and Technical Resources (NUREG-0731) and meet the criteria of SRP 13. 1. 1 (NUREG-0800). Therefore, the NRC staff concludes that the changes, are acceptable.
Figure 13. 1 has been revised to reflect the corporate reorganization. This resolves outstanding issue 32.
WNP-2 SSER 3 13-1
MANAGING DIRECTOR EXEC. ASSISTANT TECH. SPECIALIST DEPUTY MANAGIIIGDIRECTOR LEGAL INTERNAL AUDITING CtIIEF COUNSEL MANAGER LICENSING 8 PUBLIC AFFAIRS 8 CHIEF f!NANCIAL HUMAN RESOURCES OPERATIONS SUPPORT SERVICES ASSURANCE INFORMATION OFFICER DIRECTOR DIRECTOR DIRECTOR DIRECTOR DIRECTOR ACTING Figure 13.1 Washington Public Power Supply System organization
APPENDIX A CONTINUATION OF CHRONOLOGY WPPSS NUCLEAR PROJECT NO. 2 December 21, 1982 Issuance of SER Supplement No. 2.
December 23, 1982 Letter from applicant regarding request for additional information on fuel rod corrosion measures.
December 28, 1982 Letter from applicant regarding clarification of diesel generator capability to withstand severe meteorological events.
December 28, 1982 Letter from applicant regarding FSAR Section 8. 3.
December 29, 1982 Letter from applicant regarding SER confirmatory issue 17.
December 29, 1982 Letter from applicant regarding confirmatory issue 7.
January 7, 1982 Submittal of Amendment No. 27 to the FSAR.
January 10, 1983 NRC letter requesting additional information regarding standby service water multiplexer system.
January 13, 1983 Letter from applicant regarding qualifications of engineers assigned to the WNP-2 design reverification reviews.
January 17, 1983 Letter from applicant regarding visual examination acceptance criteria for reverification inspection of welded structures
((VI-09, r evi s i on 0).
January 18, 1983 Letter from applicant regarding Hanford Site Evacuation Time Assessment Study.
January 18, 1983 Letter from applicant regarding GDC 51 clarification.
January 20, 1983 Letter from applicant regarding plant verification program third TAA audit.
January 21, 1983 Letter from applicant regarding emergency plant coordination with the Yakima Indian Nation.
January 26, 1983 Letter from applicant regarding engineering evaluation of the sacrificial shield wall.
January 27, 1983 Letter from applicant regarding modifications to restricted area boundary.
WNP-2 SSER 3 A-1
February 1, 1983 Letter from applicant regarding control roots chiller installation deferral.
February 3, 1983 Letter from applicant regarding SRSS combination of dyna-mic responses confirmatory issue 6.
February 3, 1983 Letter from applicant regarding preservice inspection pro-gram scram discharge system.
February 3, 1983 Letter from applicant regarding response to NRC question 010. 066, NUREG-0803.
February 8, 1983 Letter from applicant regarding GDC 51 clarification.
February 8, 1983 Letter from applicant regarding additional information on the "out-of-roundness" of the containment.
February 9, 1983 Letter from applicant transmitting annual financial report.
February 14, 1983 Letter from applicant regarding addition of diesel starting air dryers.
February 15, 1983 Submittal of Amendment No. 28 to the FSAR.
February 23, 1983 Letter from applicant regarding control of heavy loads, revision 2.
February 23, 1983 Letter from applicant regarding:NRC question 010.068.
February 23, 1983 Letter from applicant regarding SER outstanding issue 10 standby service water instrumentation and control design.
February 25, 1983 Letter from applicant regarding solid waste management system, FSAR Section 11.4.
March 1, 1983 Letter from applicant regarding emergency plan implementa-tion procedures.
March 4, 1983 NRC letter regarding modifications to restricted area boundary.
March 8, 1983 Letter from applicant regarding new loads update, complete rewrite of FSAR Section 3.9.
March 9, 1983 NRC letter regarding fire hose-standpipe modifications.
March 15, 1983 Letter from applicant regarding pipe whip restraint installation.
March 16, 1983 NRC letter regarding turbine maintenance commitment for turbine missile issue.
WNP-2 SSER 3 A-2
March 18, 1983 Letter from applicant regarding draft Envirnmental Tech-nical Specifications.
March 21, 1983 Letter from applicant regarding rewrite of FSAR Sec-tions 4. 1 through 4.4.
March 23, 1983 NRC letter requesting additional information on SER con-firmatory issue 7.
March 23, 1983 Letter from applicant regarding project visual examina-tion acceptance criteria for reverification inspection of welded structures ((VI-09, revision 1).
March 23, 1983 Letter from applicant regarding emergency operating procedures generation package.
March 23, 1983 Letter from applicant regarding confirmatory issue 22--
assurance of ESF functioning (II. K. 1.5) and safety-related system operability status (II. K. l. 10).
March 28, 1983 Letter from applicant regarding control of heavy loads.
March 28, 1983 Letter from applicant regarding fuel rod corrosion measures.
March 28, 1983 Letter from applicant regarding closure of SER outstanding issue 10.
March 28, 1983 Letter from applicant regarding deferred shielding walls.
April 6, 1983 Letter from applicant regarding draft Technical Specifica-tion, revision 2.
April 13, 1983 NRC letter regarding staff evaluation of the BWR owners group response to TMI action plan, Item II. K.3. 18, "Modi-fications to Automatic Depressurization System Logic."
April 13, 1983 Letter from applicant regarding control of heavy loads.
April 14, 1983 Letter from applicant regarding control room design review, submittal of preliminary report.
April 14, 1983 Letter from applicant regarding physical security plan, Revision 3 and safeguards contingency plan, Revision 2.
WNP-2 SSER 3 A-3
APPENDIX B BIBLIOGRAPHY American Nuclear Society/American National Standards Institute, ANS-3.2/ANSl N18.7-1976, "Administrative Controls and equality Assurance for the Operational Phase of Nuclear Power Plants."
American Society of Mechanical Engineers, Boiler and Pressure Vessel Code."
American -Society for Testing and Materials (ASTM), Standard E-119.
Bouchey, G. D., WPPSS, letter to A. Schwencer, NRC, "Nuclear Project No. 2 Application of SRSS Rule for Steel Containment," July 28, 1982a.
---, letter to A. Schwencer, NRC, "Resolution of LRG-II Channel Box Deflection Issue," November 19, 1982b.
---, letter to A. Schwencer, NRC, "Request for Additional Information on Fuel Rod Corrosion Measures," December 23, 1982c.
---, letter to A. Schwencer, NRC, "Nuclear Project No. 2 SRSS Combination of Dynamic Responses," February 3, 1983.
Charnley, J. S., GE, letter to J. D. Coffman, NRC, "Presentation Slides--
December ll, 1979 meeting on Vermont Yankee Fuel," December ll, 1979.
DelGeorge, Comm Ed, letter to B. J. Youngblood, NRC, with LRG working paper response dated December 2, 1980, letter dated February 9, 1981.
Electric Power Research Institute (EPRI), EPRI NP-2483, J. A. Gorman and G. W.
Lipsey, "An Assessment of BWR Fuel Channel Lifetimes," July 1982.
Energy Technology Engineering Center, "WPPSS No. 2 Confirmatory Piping Analysis," July 6, 1982; attachment, November 2, 1982.
Engel, R. E., GE, letter to M. Tokar, NRC, "Corrosion Product Control,"
October 3, 1980.
Garzarolli, F. R., Von Jan, H. Stehle, "The Main Cause of Fuel Element Failures in Water Cooled Power Reactors," paper presented to the International Atomic Energy Agency Review, Erlangen, Germany, 1978.
General Electric Co., NEDE-21660-P, "Experience with BWR Fuel Through December 1976," July 1977.
NEDE-24010-P, ".Technical Bases for the Use of the SRSS Method for Combining Dynamic Loads for Mark II Plants," July 1977.
WNP-2 SSER 3 B-1
---, NEDE-24011, "General Electric Generic Reload Fuel Application, "May 1972.
---, NEDE-21354-P, "BWR Fuel Channel Mechanical Design and Deflection,"
September 1976.
---, NEDE-24343-P,
---, NEDE-21600-P,
---, NEDE-24284-P, "Assessment of Fuel Rod Bowing in General Electric Boiling Water Reactors," March 8, 1983.
---, Projects Division Memorandum, "Vermont Yankee Fuel Failure Status," Apri,l 1979.
---, SMA 12109.01-R001, "Study to Demonstrate the Generic Applicability of SRSS Combination of Dynamic Responses for Mark III Nuclear Steam Supply System and Balance-of-Plant Piping and Equipment Components," November 24, 1981.
---, Projects Division Memorandum,
Subject:
'cladding failure, April 6, 1979.
Holtzscher, D. L., Illinois Power Company, letter to Howard J. Faulkner, NRC, May 17, 1982.
Institute of Electrical and Electronics Engineers (IEEE), Standard 323.
---, Standard 334-1971.
---, Standard 344-1975
---, Standard 382-1972 Jens, W. A., and P. A. Lottes, Analysis of Heat Transfer Burnout, Pressure Drop, and Density Data for High Pressure Water," USAEC Report 4677, May 1951, Manry, M., Georgia Power, letter to J. P. O'Reilly, NRC, "Reportable Occurrence Report No. 50-321/1981-114, November 10, 1981.
National Fire Protection Association, Standard 13, "Standard for the Installa-tion of Sprinkler Systems."
---, 15, "Standard for Water Spray Fixed Systems."
30 Rockwell International, RAL-1002, Revision 2
---, RAL-1004, Revision 0
---, RAL-2006, Revision 1 Rubenstein, L. S., NRC, memorandum to R. L. Tedesco, NRC, "Resolution of Channel Box Deflection Issue for Near-Term BWR OLs," September 18, 1981.
WNP-2 SSER 3 B-2
---, memorandum to T. Novak, NRC, "Resolution of LRG-II Channel Box Deflection Issue (LRG-II Issue 3-CPB)," August 19, 1982.
---, memorandum to F. Miraglia, "SER on General Electric Fuel Rod Bowing Topical Report," March 8, 1983.
Schwencer, A., NRC, letter to R. L. Ferguson, WPPSS, "Resolution of LRG-II Channel Box Deflection Issue (LRG-II Issue 3-CPB)," September 22, 1982.
Smith, R. L., VYNPC, letter to NRR, NRC, November 21, 1980.
---, letter to NRR, NRC, February 5, 1981.
Tokar, M., NRC, memorandum for C. H. Berlinger, NRC, "GE Proprietary Presenta-tion on Waterside Corrosion of Gadolinia Fuel," October 13, 1982.
U. S. Nuclear Regulatory Commission, IE Bulletin 79-01B, "Environmental gualifi.cation of Class 1E Equipment," January 14, 1980; Supplements, February 29, September 30, and October 24, 1980.
-, IE Bulletin 80-16.
---, NUREG-0484, "Methodology for Combining Dynamic Responses," May 1980; Revision 1, July 1981.
---, NUREG-0588, "Interim Staff Position on Environmental qualification of Safety-Related Electrical Equipment," December 1975; Revision 1, July 1981.
---, NUREG-0731, "Guidelines for Utility Management Structure and Technical Resources," September 1980.
---, NUREG-0737, "Clarification of TMI Action Plan Requirements," November 1980.
---, NUREG-0800, "Standard Review Plan," July 1981.
---, NUREG-0803, "Generic Safety Evaulation Report Regarding Integrity of BWR Scram System Piping," August 1981.
---, NUREG/CR-0660, "Enhancement of Onsite Diesel Generator Reliability,"
February 1979.
WNP-2 SSER 3 B-3.
APPENDIX E NRC STAFF CONTRIBUTORS Supplement No. 3 to the SER is a product of the NRC staff. The following NRC staff members were principal contributors to this report:
Name Title Review Branch Rajender Auluck Project Manager Licensing Branch No. 2 Ina B. Alterman Geologist Geosciences John N. Ridgely Auxiliary Systems, Auxiliary Systems Engineer Yueh-Li C. Li Mechanical Engineer Mechanical Engineering Michael Tokar Reactor Engineer Core Performance Richard A. Kendall Reactor Engineer Instruments and (Instrumentation) Control Systems Dennis J. Kubicki Fire Protection Chemical Engineering Engineer Robert J. Giardina Reactor Systems Power Systems Engineer (Mechanical)
Frederick R. Allenspach Nuclear Engineer Licensee (Management Systems) qualification Robert J. Wright Mehanical Engineer Equipment qualification Jerry E. Jackson Mechanical Engineer Equipment qualification Armando Masciantonio Equi pment gual i fi cati on Equipment qualification Engineer WNP-2 SSER 3 E-1
NRC FQRM 335 1. REPORT NUMBER (Assigned by DDCl U.S. NUCLEAR REGULATORY COMMISSION (7 77) NUREG-0892 BIBLIOGRAPHIC DATA SHEET Supplement No. 3
- 4. TITLE AND SUBTITLE (Add Volume No.,ilappropriareJ 2. (Leave blank J Safety Evaluation Report related to the operation of WPPSS Nucleai Project No. 2 3. RECIPIENT'6 ACCESSION NO.
- 7. AUTHOR(S) 5. DATE REPORT CQMPI.E ILII MONTH YEAR 83
- 9. PERFORMING ORGANIZATION NAME AND MAILING ADDRESS (Include Zip Code/ DATE REPORT ISSUED Division of Licensing MONTH YEAR Office of Nuclear Reactor Regulation Nuclear Regulatory Commission 6. (Leave blank)
Washington, D. C. 20555 B. (Leave blank J
- 12. SPONSORING ORGANIZATION NAME AND MAILING ADDRESS (include Zip CodeJ 10, PROJECT/TASK/WORK UNIT NO.
Same as 9 above 11. CONTRACT NO.
- 13. TYPE OF REPORT PERIOD COVERED (/nc/usive dareSJ Supplement No. 3 to the Safety Evaluation Report
- 15. SUPPLEMENTARY NOTES 14. (Leave olankJ Pertains to Docket No. 50-397
- 16. ABSTRACT (200 words or less/
Supplement No. 3 to the Safety Evaluation Report on the application filed by Washington Public Power Supply System for a license to operate the WPPSS Nuclear Project No. 2, .located in Richland, Washington, has been prepared by the Division of Licensing, Office of Nuclear Reactor Regulation of the U. S.
Nuclear Regulatory Commission. This supplement reports the status of certain items that had not been resolved at the time of publication of the Safety Evaluation Report and Supplement Nos. 1 and 2.
- 17. KEY WORDS AND DOCUMENT ANALYSIS 17a. DESCRIPTORS 17b. IDENTIFIERS/OPEN ENDED TERMS IB. AVAILABILITYSTATEMENT 19. SECURITY CLASS (lhts repors/ 21. NQ. OF PA(iL'S Unl imi ted Unclassified 20, SECURITY CLASS (This pageJ 22PRICE Unclassified S
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