5.0 reference: application, volume i, chapter 5, heritage ... · the generation environmental...

British Columbia Utilities CommissionInformation Request No. 1.5.54 Dated: 23 January 2004British Columbia Hydro & Power AuthorityResponse issued 20 February 2004

Page1

British Columbia Hydro & Power Authority Revenue RequirementsApplication 2004/05 and 2005/06

5.0 Reference: Application, Volume I, Chapter 5, Heritage Contract

1.5.54 Page 5-49, 5-50, Section 9.5.2: Please explain the Water Rental InterimOrder Remissions F2005. What change to operations drove the increasein costs and the resulting Remissions? Did the $3.5 million Remissioncover all costs? Please explain why there were no Water Rental InterimOrder Remissions for F2006? When does BC Hydro anticipate thatWater Use Plans will be complete? Can BC Hydro quantify to any degreethe anticipated increase in costs for each of the next five years resultingfrom additional implemented Water Use Plans?

RESPONSE:Prior to and during the development of Water Use Plans the Provincial WaterComptroller authorised interim orders on operations that resulted in loss ofenergy values to BC Hydro. These orders are called interim because they will bereplaced by a change in operations that is the outcome of the WUP process.Where they did result in reduced energy value, those reductions are remitted backto BC Hydro.

The change to operations under the interim orders (referred to above) resulted inincreased costs because the value of water from an energy generationperspective was reduced in order to support fish habitat.

Interim order remissions covered forecast average costs associated with foregoneenergy value.

By F2006 it is expected that interim orders will be replaced by new orders, underour licenses, implementing the operating conditions proposed in Water Use Plans.

Please also see BC Hydro’s response to BCUC IR # 1.5.53 for further information.


Page1



1.5.55 Page 5-50, Lines 8 through 17: Given that the Water Comptroller has todate provided offsetting remissions against water rentals to BC Hydro forinterim orders where there is a net loss in the value of energy, whatmechanisms exist to insulate customers from revisions to water licencesthat would reduce the amount or value of deliverable Heritage Electricity?

RESPONSE:Please see BC Hydro’s response to BCUC IR # 1.5.53.


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1.5.56 Page 5-51, Table 5-30: Provide Table 5-30 back to F2001.

RESPONSE:Please see BC Hydro’s response to BCUC IR #1.5.10.


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1.5.57 Page 11-15, Section 2.2.7: The completion of Water Use Plan projectappears to be in F2006. Explain what, if any, ongoing costs are forecastin F2005, F2006, and beyond F2006 for maintenance and execution ofthe plans, and identify where those costs will reside.



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1.5.58 -53, Schedule 5-2: Regarding Note 2, is the load forecast alsobased on a 60 year weather record?

RESPONSE:No, the energy load forecast is prepared using a rolling 10-year average of heatingdegree days. The peak load forecast is based on an average, over 30 yearsending in 1994, of the annual coldest or minimum of the daily averagetemperatures. The daily average temperature is the average of the daily maximumand minimum temperatures. A review of the policy on design temperature iscurrently underway.

Please see BC Hydro’s responses to BCUC IR # 1.4.15, 1.17.3 and 1.38.3 for furtherinformation.


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1.5.59 Page 5-53, Schedule 5-2: Please explain why the 321 GWh indicated onSchedule 5-2 for Hydro Not Simulated appears to differ from the sum ofthe energy capabilities for those plants in Tables 5-18 through 5-20 of 266GWh.

RESPONSE:The 321 GWh of Hydro Not Simulated from Schedule 5-2 on Page 5-53 consists of: 266 GWh from Aberfeldie, Elko, Falls River, Shuswap, Spillimacheen, and

Walter Hardman; and 55 GWh of Resource Smart additions that are not simulated over a range of

historical inflows.


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5.60 Reference: None

1.5.60 Page 5-54, Schedule 5-3: Provide the complete plans and reports(Facility Asset plans, RCM, HER and EMS) for the GM Shrum and SevenMile facilities.

RESPONSE:The Facility Asset Plans for Peace River Generation and the Seven MileGenerating Facility are provided on the enclosed CD-ROM. Peace RiverGeneration includes both the GM Shrum and Peace Canyon generating facilities.Equipment Health Ratings (E.H.R.) are included in the Asset Plans. The FacilityAsset Plan for Peace River Generation has minor redacting to protect BC Hydro’sinterests in matters currently in litigation or under negotiation.

The Generation Environmental Management System Manual (EMS) and Aspectlists, and the Reliability Centred Maintenance files, for both GM Shrum and SevenMile are also provided on the enclosed CD ROM.

DRAFT

FACILITY ASSET PLAN

Fiscal 2004/05

PEACE RIVER GENERATION

GENERATION

CONFIDENTIAL

BC hydro

Plan accepted on this day of 2004

Dawn FarrellExecutive Vice President

Date

R. FernandesGeneral Manager

Date

J. PoweskaGM Shrum Plant Manager

Date MA McLennanPeace Canyon Plant Manager

Date

"If\f\A T_....__.

Appendices

Facilty Asset PlanPeace River Generation

DRAFT

TABLE OF CONTENTS

EXECUTIVE SUMMARY ......................................................................................................................

PURPOSE............................................................................................................... .SUMMARY............................................................................................................... .

STRATEGIC CONTEXT .......................................................................................................................

1 PRODUCTS & SERVICES

..................... ......................................................................

2 BUSINESS SUMMARY................................................................................................Operational.........

""'"'''''' ...................................... """"'" .................... ........

Sustainabilty and Community Summary................................................... 73 Maintenance Summary ......,.......... ........... .... ............ ............. ....... ........... ..... 94 Dam Equipment Summary ..................................................................... 115 Equipment Summary.

............. .... ................ ................ ............... """"'" .....

ALIGNMENT WITH GENERATION PLAN ..............................................................................

GENERATION MANDATE .....

................................................... .............. ....................

IMPROVEMENT OPPORTUNITIES........

""""""""""""""""""""""""""""""'''''''''' .

LIFE CYCLE PLAN.. ...

....................... ....................................... ............ ............. .......

PERFORMANCE ................................................................................................................................

FINANCIAL EFFICIENCY.......................................................................................... .OPERATIONAL EFFICIENCY..................................................................................... .ENVIRONMENTAL STEWARDSHIP

""""""'"'''''''''''' ...... .... .............. .......... ............... .

SOCIAL & COMMUNITY CONTRIBUTION.................................................................... .4.4

RISKS ......... .............. ........ ............

.................................................. .... ........... ....... ......... ... ......... ......... .

PROJ ECTS

.................. ............................. .....................

ERROR! BOOKMARK NOT D EFIN ED.

Appendix A: Management Team

Appendix B: Water Use Plan Program

')nnA 1........... -tO"


DRAFT

EXECUTIVE SUMMARY

1 PURPOSE

This document is a compilation of key data from a variety of sources in Generation. The data is included inorder to set context for the management strategies detailed in the document. The Plant Manager and theBusiness Planning Manager prepare the document. It is intended to be used on a quarterly basis tomeasure progress of initiatives designed to implement strategies. The Asset Plan is also intended toassist in making investment decisions.

Major Management Issues

Replacement of old , unreliable or inefficientequipment in an orderly manner while maintainingreliability and maximizing availability.

Management Strategy

Replacement of GMS 1-8 runners , rewinding GMS4 and G7 stator; repairing or replacing PCN

stators and replacing GMS Exciters, protectionDC and control s stems.

First Nations lawsuits claiming impacts on theirwa of life.

2 SUMMARY

In-service Year 1968 1980

"""'--"'-"'''''-''''''-''-'-'' ''''-'

'''''''''-''''''''''''""...............................................m__,_,,,............."',"..........n".....................m......................,...."".,,'''''''''''''''''''''''','''''_'.__m....................

--_.

9gTY-.__.._._....._._.__._-_.._..__......

.............-......... ....._---_...._......._ .._._........- ..._- !\_ ...._._..._......_....

Maximum SustainableGenerating Capacity - MW 2 730

....

..Er D-.

g.... _..

9.9.t:.

!!.

!i.9n2......-

........-........-.........

Historic Annual Av. Plant Gen(From Making The Connection)

-=G..

_..................._.._..__..__.._....._........_............................................... ._-_..........-................-.......--....__...

?1.11..........-.................Average Generation in Previous

_.....

?y.r

.... ................._......_._...........-._._._-_......_............................._.__

:L4.. QJ.....................-......-..........................

!?? ......._._._._._......

700

""","'..............................................................

Net Book Value ($Milions)2003 Mar 31

._...... .........................................-...__... ...........

"',''''','...........m.__m...........--.....-........-"...,...-"""","'''''...........m..._.......--........

f!! !f!!!gy';_._..._.._......._..._.....................

...............

Unit Cost Of ProductionI.M-"hJ......._..._-_.._._..........__..__..._..

......................................--.----....."

'''''''',',''''......m..........._m...............................,."..."...............................

..................

1..

?:. ..._..__...__...._.............................

1_.

?.: -----_._.....

Unit Cost of Production based on Generation October Pro Forma Income Statement.

2004, January 12Page 1

GMS


DRAFT

G = Good , F = Fair, P = Poor, U = Unsatisfactory

Generator""""""''''''''''''''''''''''''--'''"'',,''''''..........__m.......... ....n"..

,.........................

.......m.......................

""----"""..-".... ..............--.....-.-.

...m..............",...",.....

................................

moo_u___",.".....'""'mm._.m......................",,

Turbine

Exciter

'''''''''-''''''''''''''''......-.................................-..'---........ mm._m.....m..........

""..""""'''''''''''''- ................................. ..-..-........",-."" ...........-...................

...m..____.-...."""..

.....

"',",','",'.....m........

................................... ..--........."'''."........."'''''-''''''''''''''''"..''''''''''''''''''''''''''''''''''''''''''""""""""""""""'"

Governor

m'''''N._um..........

.......-.-....-..... .-.....-...-..........-........-....................................... .................-..... ............. .....-.....................-................................. ...-.......................... ...........................-. .................................. ................................ ...................... .................-... ................---......................_....._..........._.......................................-..................-...................... ... ..................-.-............ .................................... ._...._.._........... ..............-.--.--..

Transformer

.............-...---........-...-..-.............-........-............-......... ..............................-.. ......-.-................. ..-.......

Circuit BreakerCoated Structures

IntakesSpillwayCCBSwyd BuildingsCranes

Notes:Generators: 1-4 to be rewound beginning in 2006. G7 stator has failed and will be replaced in early 2004

G6 poor rating due to condition of polesTurbines: 1-5 to be replaced beginning in 2006. G8 to be replaced in 2004Exciters: G3 , 4 , & 7 to be replaced in 2004Transformers T2 to be replaced in 2004

.................... ....................-.........................................

! Fairi Good

I Fair! Good! Poor

Generator

Notes

Plans to replacestators beginning in2006

""""''''''''''''''''''-'''''-''''''-''''''''.......-...-.............................--............- ..................-......-...... ...............-..-....... ................-...."...... ................................. ""''''''''-''-'''---'''''-'''''''''''''''''''''''''''''''''''''-''''""",,,.....

Based on condition of

....

I.!:EQ.!Q_

_..__._-_............................................-.-....-..........__. ..._._.......

E..........._....

.._......................

F..__......

!....

9?!

~~~~ ......_..

Due to suspectoperation of Power

_...~~~ !:_.._..._-_....._...__......_..._------_._.!!_...

...n......_

'=__....._............

\L......................

\:...................

r._....

Governor

""""""""'-"-"""""""""'''-''''''''''''''''-''''''''''''''..........-......-................... ....................--. ..........-...............--...................... ............................... ..............-.-.-.. ...........-......................................................................................-.

Transformer

................................................................. ..,-

......,.ri_...........................................................

.............-...-........-.".--...-...................................................... ......--.......--........

Circuit BreakerCoated Structures

IntakesSpillwayCCBCranes

I Fairi Fairi Good! Good



DRAFT

Forced Outage Factor "''''

...........................................

t'M.. ..............

............ ....

!!:p.r.2 in.9..... ,.....

..... ..,

!!:p.r.2 in,9.,..Number of Forced

.......................

9..

~~~

9..

!:!

,(!tt..............

?........... ....

!!:p.r.2

.... ...... ...... ........ ......



DRAFT

STRATEGIC CONTEXT

PRODUCTS & SERVICES

EnergyAv Gen in Previous 3yrs -Heav LoadAv Gen in Previous 3yrs -Li ht LoadTotalHistoric Annual Av PlantGeneration - Heav LoadHistoric Annual Av PlantGeneration - Li ht LoadTotal

Fleet ServicesMaximum SustainableGeneratin Ca acitCa acit FactorStora e

Ancilary Transmission ServicesVolta e Su ortS nchronous CondenseBlack Start

GWh 109

GWhGWh

5,492601

GWh 619

GWhGWh

606225

730

39,471

Y/NMvar/hrs 321 ,480

FlexibiltyBase Load (1)

Load FactorinSwinAGC

External ServicesTransmissionColumbia TreatWater SalesFlood ControlFish Flow ReleaseFish Flow Studies

Intangible ServicesRecreation

Pro ortion YrPro ortion YrPro ortion Yr

Y/N

1/4

3/4

$ 000Y/NY/N

$ 000

N/AN/A

eo Ie 000

(1) Base Load units stay on line predominately and only vary load with inflow.(2) Load Factoring units turn on in high load hours and off in light load hours.(3) Swing Plant is used to meet increase or decrease in demand in steps throughout the day.(4) AGC plant adjusts output continually to meet incremental demand change.



DRAFT

Av Gen In Previous 3yrs -Heav LoadAv Gen in Previous 3yrs -Li ht LoadTotalHistoric Annual Av PlantGeneration - Heav LoadHistoric Annual Av PlantGeneration - Li ht LoadTotal

Fleet ServicesMaximum SustainableGeneratin Ca acitCa acit FactorStora e

Ancilary Transmission ServicesVolta e Su ortS nchronous CondenseBlack Start

Typical UseageBase Load (1)

Load FactorinSwinAGC

External ServicesTransmissionColumbia TreatWater SalesFlood ControlFish Flow ReleaseFish Flow Studies

GWh 219

GWhGWh

1 ,403622

GWh 834

GWhGWh

277111

700

Y/NMvar/hrs

Pro ortion YrPro ortion YrPro ortion Yr

Y/N

1/4

3/4

$000Y/NY/N

$ 000

N/AN/A

$30 (WUPStudies

AdditionalIntangible Services

Recreation eo Ie 000




DRAFT

BUSINESS SUMMARY

GM Shrum (GMS) generating station is located on the Peace River, approximately 25 km west ofHudson s Hope, approximately 100 km from the Alberta border. GMS began operation in 1968. GMS iscategorized as a Large asset. GMS provides approximately 25% of BC Hydro s total annual hydrogeneration. Historically GMS has provided average annual generation of approximately 13 225 GWh.

Peace Canyon (PCN) generating station is located on the Peace River, approximately 7 km south ofHudson s Hope, approximately 100 km from the Alberta border. PCN began operation in 1980. PCN iscategorized as a Large asset. PCN provides approximately 6% of BC Hydro s total annual hydrogeneration. Historically PCN has provided average annual generation of approximately 3 111 GWh.

1 OPERATIONAL

GM Shrum and Williston Reservoir are BC Hydro s largest generating station and storage facility. Storagecapacity of Williston Reservoir will continue to be utilized to meet domestic market obligations as well asincrease revenues from energy trading opportunities. The GMS and PCN units are operated as swingunits for much of the year. From January to March/April there are flow controls on PCN to minimizedamage from ice formation downstream of the dam.

Operation of GMS and PCN is balanced with operations at the Revelstoke (REV) and Mica (MCA)facilities , to balance the two major storage reservoirs on the BC Hydro system. In addition , GMS providesAGC for approximately half a year, predominately from April - July. There are no restrictions on GMSstarts/year or on time between start and stop.

Both stations are manned. Operators at GMS control both stations around the clock.

Operation of the Peace River Generation (PRG) plants will be coordinated with other BC Hydro faciltiesand outside markets to optimize the total benefits to the Province.

Five-year performance is summarized for the plant as follows:

GMS

po""",,

Forced Outaqe Factor (%)

Forced OutaQe Count (#) 4.4

The major reason for the increased FO factor in F2002 was a fault in a 500kv bushing on a generatortransformer

PCN

Forced Outaqe Factor (%)

Forced Outaae Count (#)



DRAFT

2 SUSTAINABILITY AND COMMUNITY SUMMARY

Environmental Issues: Environmental issues in Peace River Generation are managed through anEnvironmental Management System (EMS). Through the EMS processes , environmental issues arereviewed every year and objectives and targets for performance are developed for priority issues.Significant improvements have been achieved in oil management. Other environmental issues covered bythe EMS include pollution control in general (water, soil , and air quality), vegetation managementreservoir dust and debris management, and fish and wildlife issues.

Strategies to address these environmental issues and risks include:

Peace Willston Compensation Program: The Peace Williston Fish and Wildlife CompensationProgram (PWFWCP) was set up in 1988 to mitigate the impacts of the creation of Williston andDinosaur Reservoirs , allowing for the conservation and enhancement of fish and wildlife in thewatersheds. Projects under this program include stocking fish in barren lakes , studying populations ofpriority species of fish and wildlife , and habitat enhancements.

Peace Region Water Use Plan: The Peace WUP has been agreed to by all parties to the process andhas been submitted to the Provincial Government for approval. The program was designed to applyoperating parameters to the daily operations of the generating facilties and other measures in order toaddress water use issues relevant to the Peace River watershed.

Environmental and Social Issues Program: The environmental and social issues program in the PeaceGeneration area addresses compliance and due diligence issues, such as public safety andenvironmental permit monitoring, and also deals with any emerging items that affect local and regionalcommunities. The program for the upcoming fiscal year will focus on developing a public safetymanagement plan , further implementation of the environmental management system , dust control anddebris management, relationship building with local First Nations , visitor centre and tour guideprogram , and any newly emerging issues that require community relationship building.

Water Qualiy: The District of Hudson s Hope draws a component of its drinking water from the PeaceRiver and any changes in water quality could have a direct impact on the community s drinking water.A protocol has been developed with the District to inform them as soon as possible of any conditionsthat might have an impact on water quality, to ensure that their water supply is switched to wells. Thedomestic water facilities at both hydro-electric plants have been replaced and modernized.

Social Issues: There are a wide variety of social issues associated with the Peace facilities andBC Hydro has been addressing concerns and ideas that are brought up by local communities andindividuals. BC Hydro also tries to maximize local benefits from its facilties by local hiring (e.g. tourguideprogram , construction project hires), a scholarship program for local high school students, its donationsand outreach programs , and the grants-in- lieu of tax paid to the municipalities and school districts in theareas where it operates.

Strategies for dealing with these social issues and risks include:

Public and Employee Safety: The Peace Area will be developing Public Safety Management Plans tocomprehensively address hazards arising from the facilities and their operations. Numerous measuresare already undertaken to manage risks associated with public safety hazards and the plan willcomplement these measures.



DRAFT

Project Consultations: Due to recent court decisions and the new consultation guidelines set out bythe Province, BC Hydro wil be proactive and develop constructive relationships with First Nationswhere projects are being planned affecting their traditional territories.

Recreation: Wiliston and Dinosaur Reservoirs are used for recreational activities such as boating,fishing, widlife viewing, and guiding. BC Hydro contributes to providing boat launch ramps andrecreation sites around the reservoirs. There are few formal , managed recreation sites associatedwith the reservoir and river. The sites on Dinosaur Reservoir were constructed by BC Hydro but arecurrently managed by the District of Hudson s Hope. The Alexander Mackenzie Landing RecreationSite near Mackenzie is managed by BC Hydro. Further sites may be built as a result of the WUP.

Remin ton Ene,. Law Suit

Visitor Centre Operations: Both the Bennett Dam and Peace Canyon Visitor Centres playa major rolein the regional economy as one of the very few major tourist destinations in the area. Operating thevisitor centres also represents a major contribution to seasonal employment in the community ofHudson s Hope.

Heritage Conservation: In 2003 BC, Hydro undertook an overview survey of archaeological resourcesin the Finlay Arm area of Williston Reservoir. Based on the report recommendations, BC Hydro islooking at developing an archaeological management plan for Williston Reservoir. BCHydro isapproaching heritage conservation in co-operation with local First Nations. For example, up to 10 TsayKeh band members were trained and hired for the 2003 study.

Mackenzie Water Levels: The community of Mackenzie has been lobbying for years to have the waterlevels in the water licence changed to better protect the interests of the local community and itssawmil and pulp mil industry. A change in water licence levels would have significant impacts on theoperating flexibility of the Peace generating system , and effective and proactive communications andrelationship building with the community is crucial to manage this critical issue. The issue was debatedat the Water Use Plan table and the consultative committee came to a consensus , recommending anadaptive management plan.

Ice Management in the Peace River: Downstream communities, such as the Town of Peace River andSunnyvalley in Alberta can be affected by ice jams and flooding related to ice break-up or freeze-up.BC Hydro has been operating in consultation with Alberta Environment to test operating regimes thatmanage the flood risk to these communities.

Emerging issues with communities in the watershed: Emerging issues are numerous. They range inscope from concerns over water levels in the river and reservoirs (both seasonal and long-term), thepotential development of Site C , socio-economic impacts of holding Site C Lands over many yearsand expectations as to what BC Hydro s social responsibilties should be as a Crown Corporation. ThePeace Williston Advisory Committee includes representatives from each community in the watershedand meets regularly. The committee is informed about new issues arising for BC Hydro and providesvaluable feedback about a variety of topics.



DRAFT

3 MAINTENANCE SUMMARY

Equipment condition , market conditions and availability of crews influence maintenance activities.

Preventative Maintenance (PM): The PM strategy at PRG is to conduct annual overhauls toinspect equipment. PM is driven by equipment manufacturer recommendations , which areentered into the PassPort Work Management softare tool. PassPort alerts PRG of whichparticular pieces of equipment are recommended for inspection each year. The maintenanceinstructions for use by crew are also driven by manufacturer recommendations. The timing of theoverhauls differs each year depending on the inflow conditions and market conditions. PMdetermines the current condition of the equipment.

Condition Based Maintenance (CB): The maintenance activities required for each piece ofequipment are dependent on the condition of the equipment, as identified in PM. CB is the workrequired on the equipment given its current condition; the CB mandate is to support PM.

Corrective Maintenance (CO): CO is a reactive approach to maintaining equipment. CO occurswhen equipment maintenance is required which has not been previously identified through PM.

In the future, the equipment investment strategy is expected to differ for each asset category and will beinfluenced by the Equipment Health Rating (EHR). Further, the equipment maintenance strategy, isexpected to be driven by Reliability Centered Maintenance (RCM) efforts.

Major equipment-related action items for PRG in the upcoming year include:

Investment Planning: Confirm & complete work required for fiscal 2005 and identifyopportunities to improve future spending forecasts.

Specific Projects include:

Replacement of GMS G8 runner

Rewind of GMS G7 stator

Installation of 4 new GMS exciters

Installation of 3 new GMS transformers

Upgrade of PCN powerhouse bridge cranes

Fire Risk Reduction at PCN

Structural upgrade of PCN GeneratorsRefer to Section 6 for a more comprehensive capital list.

. PM Maintenance; Complete PM maintenance as per Passport schedule

. CO Maintenance: Maintain CO maintenance spending

CB Maintenance: Maintain CB maintenance spending

Reliabilty: Reduce number of forced outages.Increase project management effciency: Increase percentage of work completed on time and onbudgetCosts: Maintain percentage of annual budget spent on maintenance. Reduce G&A by 5% inF2005 and F2006 (relative to F2004 budget)

EHR: Complete the equipment health ratings for each of the major equipment items.

RCM: Implement reliability centered maintenance requirements to enable a comprehensivepreventative maintenance program.

Outages for plant maintenance will be coordinated to minimize impacts to the BC Hydro system as well asmaximize participation in energy trading opportunities.



DRAFT

Maintenance costs are summarized in the following table:

GMS

Total Maintenance Dollars($ 000) 728

PCN

Total Maintenance Dollars($ 000) 939



DRAFT

2.4 DAM & EQUIPMENT SUMMARY

The W.A.C. Bennett DamThe WAC. Bennett Dam is 183 m (600 ft) high by 2040 m (6700 ft) long earthfill embankment damlocated on the Peace River in north-eastern BC about 21 km (13 miles) west of Hudson s Hope. The damretains Williston Lake , the largest reservoir in BC Hydro s system.

The dam was completed in November 1967 and reservoir impoundment started in the spring of 1968 , witha maximum level (EI 672. 1 m) reached for the first time in July 1972.

The dam is a zoned embankment consisting of a wide impervious central core zone supported on bothsides by granular shell material. The dam has an upstream slope of 2.5H:1V and a downstream slope of2H:1V with seven horizontal benches , each having an average width of 3.5 m (12 ft). The internaldrainage system consists of an internal chimney drain downstream of the core zone and a horizontalblanket drain placed under the downstream shell. A narrow transition and a filter zone are located betweenthe chimney drain and the core. The drainage collection system in the earthfil dam is divided into fourzones, separated by "splitter dikes . Weirs through an automated system measure flows from each of thezones.

Extensive foundation surface preparation and foundation grouting was carried out during construction anda system of drainage tunnels and drainholes was constructed beneath the dam and in the abutments.Some of the grouting was done from a grouting culvert located beneath the dam core at the bas of theformer river channel. The drainage tunnels are connected to this culvert.

In 1996 two sinkholes were discovered in the dam. They were subsequently repaired in 1997 andextensive surveillance utilzing automatic and manual data collection continuously monitors theperformance of the dam. Daily and weekly inspections are carried out by on-site personnel with support ofspecialists from the office of the Director of Dam Safety. The performance of the dam is reviewed yearlyby a specialist independent consultant.

Peace Canyon DamPeace Canyon Dam is located on the Peace River, 23 km downstream of WAC. Bennett Dam and 6 kmupstream from the town of Hudson s Hope. Completed in 1980 , Peace Canyon Dam consists of a 61 high by 325 m long concrete gravity dam spanning the original river channel and a 21 m high by 200 mlong earthfill saddle dam on the right abutment. The left portion of the concrete dam contains four powerintakes and penstocks to serve the four unit, 700 MW powerhouse located at the toe of the dam. The rightportion of the concrete dam contains six radial gated spilway bays with flip buckets and a plunge poolwhich has developed from the operation of the spillway.

The reservoir (Dinosaur Lake) between the WAC Bennett Dam and Peace Canyon Dam is relativelysmall. Williston Reservoir/GM Shrum Generating Station provides flow regulation. Dinosaur Lake provideslimited short-term storage for load factoring purposes only.

The 3.5 Mile Slide is a 20,OOOm3 overburden and bedrock slide located on the left bank of Dinosaur Lakereservoir about 6 km upstream of the dam. A wave runup study indicated that if the slide failed rapidly, thedam would not be overtopped. However, public safety could be impacted by runup of the wave at thecampground located about 1 km upstream of the dam. The slide is monitored on a regular basis and thefrequency of surveys increased at times of high rainfall and sustained reservoir drawdowns.



DRAFT

5 EQUIPMENT SUMMARY

Equipment is summarized in the following table as per the draft Technical Prescription Summary Reportfrom the Equipment Health Rating project (from Passport, EHR, or other sources as appropriate):

G = Good, F = Fair, P = Poor, U = Unsatisfactory

1968 1993 Replace in 2008

Governor 1968 Electronic Gov Maintaininstalled 1997

Generator 1968 Stator rewind 2008

Excitation System 1968 Replaced in 2003 Maintain

Unit P&C 1968 Replace in 2006

Unit 02Turbine 1968 1991 Replace in 2009








Excitation System 1968 Replace in 2004







DRAFT

Excitation System 1969 Maintain




Generator 1969 Stator rewind 1996 Maintain



Unit 06Turbine 1971 Re laced in 2003 MaintainGovernor 1971 Replace iin 2011

Generator 1971 Rewound in 1995 Maintain



Unit 07Turbine 1972 Replaced in 2002 Maintain

Governor 1972 Replace in 2010

Generator 1972 Failed in service Oct Rewind in 20042003



Unit 08Turbine 1972 Replace in 2004


Generator 1972 Stator rewind in 1998 MaintainExcitation System 1972 Replace in 2004


Unit 09Maintain

Turbine 1974

Governor 1974 Re lace in 2011



DRAFT

Generator 1974 Maintain



Unit 10Turbine 1980 Maintain





AC Station Service 1968 MaintainDC Station Service 1968 Re lace 2005-Circuit Breakers 1968 MaintainWater Passages

Penstock 1968 MaintainPenstock Coatin s 1968 Maintain

Substation 1968 MaintainS illwa 1968 MaintainReservoir 1972 Debris RemovalPowerhouse

Lights 1968 Powersmart upgrade Maintainin 1990

Fire Protection 1968 MaintainHVAC 1968 raded in 1992 MaintainOil Containment CCB storage tanks in Maintain

1995Transformers in 1999

PCN Unit 01Turbine 1980 Maintain

Governor 1980 Maintain


Excitation System 1980 Replace Power SystemStabilizer

Unit P&C 1980 Maintain

Unit 02



DRAFT

Turbine 1980 Maintain















AC Station Service 1980 MaintainDC Station Service 1980 MaintainCircuit Breakers 1980 MaintainWater Passages

Penstock 1980 MaintainPenstock Coatin s 1980 Maintain

Substation 1980 MaintainS illwa 1980 MaintainReservoir 1980 Debris removal , 3.5 mile slid

monitorinPowerhouse

Lights 1980 Powersmart upgrade Maintain1991

Fire Protection 1980 raded in 2003-HVAC 1980 MaintainOil Containment N/A Maintain



DRAFT

ALIGNMENT WITH GENERATION PLAN

GENERATION MANDATE

The Energy Policy states that the mandate of the generation business is to manage the heritage assetsmake efficiency improvements at existing faciliies and provide energy and capacity to the domesticmarket while maximizing trade revenue potential and investment return to the Province

Both W. C. Bennett Dam/GM Shrum Generating Station and Peace Canyon Generating Station areclassified as Heritage Resources.

IMPROVEMENT OPPORTUNITIES

Upgrade Gross Capacity of GMS Units from 265 or 275 MW to 300 MW , if this occurs the increases willbe communicated to O&EP for consideration in system optimization.Powersmart lighting upgrades being investigated.

LIFE CYCLE PLAN

1. Recommended path - Continue to operate the assets in the most efficient, socially responsibleand environmentally conscious manner possible. Individual equipment will be replaced orupgraded as they wear out or new technology makes economic sense. Replace all majorcomponents before they fail in service. GMS is initiating a rerunnering project and a stator rewindproject. PCN is initiating a major unit upgrade.

2. General timing of activity. See section 6 for Major Projects.



DRAFT

PERFORMANCE

FINANCIAL SUMMARY

GMS

OMA 707 651 10,793 10,612 1 0,486

Ca ital 780 23,511 266 133 084

PCN

OMA 981 995 060 312 323

Ca ital 375 846 031 625 512

Note 1 Capital Plan as of October 2003.



DRAFT

2 OPERATIONAL SUMMARY

GMS

Safet

Number of incidents

Lost time Hours

Plant Performance

Forced outa e factor N/A

Number of ForcedOuta es/Unit # 3. 2.4 2.2 2.

Average FO duration for 2003/04 includes G7 winding failure. Unit OOS Oct 15 until Q1 of F005.

PCN

Safet

Number of incidents

Lost time Hours

Plant Performance

Forced outa e factor N/A

Number of ForcedOuta es/Unit 2.4

ENVIRONMENTAL STEWARDSHIP SUMMARY

GMS & PCN

Water use Plan (WUP)Develo ment

Reportable EnvironmentalIncidents

N/A



DRAFT

SOCIAL & COMMUNITY CONTRIBUTION SUMMARY

First Nation Grievances



DRAFT

RISKSEquipment: The failure of major generating equipment causes unplanned outages , which result inloss of generation revenue for PRG. In addition, there are safety and environmental risksassociated with certain equipment. The major equipment concern at PCN is the structural integrityof the generators. Negotiations between BC Hydro , with the assistance of world recognizedgenerator design engineers , are ongoing the original equipment manufacturer, Mitsubishi.A major project has been initiated for the repair or replacement of the PCN stators. The first unitinstallation is scheduled for F2007 and completion in F2010. Until this project is complete, thereis higher than normal risk of major economic loss associated with the operation of thesegenerators. Life safety risks have been mitigated by limiting access to unsafe areas.

Dam Safety: Previous sinkhole occurrences have highlighted the need to fully understand theongoing performance and to continue close monitoring of the WAC Bennett Dam. Catastrophicfailure of the WAC Bennett Dam could result in considerable financial loses due to lost generationat both GMS and Peace Canyon , loss of life , environmental damage, and third party losses. Inaddition , seismic risks have been identified for Peace Canyon Dam. Failure of Peace Canyoncould result in financial losses due to lost generation , loss of life, environmental damage, and thirdparty losses.

Dam Safety Strategy: Major action items relating to dam safety for GMS in the upcoming yearinclude:

. WAC Bennett Dam: Improvements to the dam s seepage monitoring capability and rip rapare underway. Additional investigations are continuing to assess the dam s ongoingperformance.

Peace Canyon Dam: Previous studies have identified risks associated with the damperformance under earthquakes. Work is planned to address the seismic performance ofthe concrete dam and implement a number of risk reduction measures.

The current capital forecast includes $1.7M for dam safety investigations and improvements atWAC Bennett Dam for F2005. The five-year forecast is $13. 7M.

The current capital forecast includes $0.8M for dam safety investigations and improvements atPeace Canyon Dam for F2005. The five-year forecast is $1.4M.

Environmental: BC Hydro operates within an ever-changing regulatory environment. The approvaland implementation of the Water Use Plan would address some regulatory compliance risks. Newand emerging legislation , such as the Federal Species at Risk Act can have wide-reachingimplications and could lead to significant restrictions in the way the systems are operated.

Social: There are a number of areas that pose risks to BC Hydro. Several First Nations in thewatershed have filed writs against BC Hydro. Negotiations are underway to improve the businessrelationships with those bands and to address the underlying issues. Should these negotiationsfail , litigation could lead to court proceedings. Another lawsuit was filed by Remington Energyrelated to alleged damages to its pipeline incurred from the 1996 spill.

Beginning in the year 2000 , BC Hydro undertook a water use planning process for the Peace areaand many issues that have been brought forth by stakeholders and First Nations over the yearswere addressed in the consultative process. Should WUP approval and implementation not goahead as planned, partners in the process may seek other routes to assert their interests thatcould potentially lead to operating restrictions and increased cost to BC Hydro.

The application of the Heritage Conservation Act to BC Hydro operations is currently beinginvestigated. Should the act apply, compliance could require extensive expenditures.



DRAFT

PROJECTSMajor projects planned at PRG include:

GMS - Units 1-5 Runner 119 125 016 9,423 241 248 667 248 553ReolacementPCN - Generator Structural 274 750 578 077 554 014Upgrade G1-

GMS - Units 6-8 Runner 046 349ReolacementGMS - Protection Upgrades 252 065 272 642 237

GMS - WAC Bennett Dam 160 100 851 290 691 220RioRaoGMS G1 - 4 Rewind 105 167 314 3,457 3,457

GMS G7 Re-wind 2,493 3,465

GMS - Exciter Replacement 500 824G1-GMS - PAD Negotiations(SpendinQ Not Available)GMS -Control Systems 211 1590 1664 998ReolacementGMS - Unit 8 Capacity 431 135 708IncreaseGMS 0 Exciter Replacement 666 250Units 9&10GMS - Governor 378replacement Units 6-PCN - Unit Transformer 105 827 093ReplacementPCN - Fire Risk Reduction 029 383

GMS - Transformer 229 200ReplacementPCN- Powerhouse Crane 239UpqradeWiliston First NationsNegotiations (Spending notavailable)


DRAFT

FACILITY ASSET PLAN

Fiscal 2003/04

GM SHRUM GENERATING FACILITY

ApPENDICES

2004 , January 12

DRAFT

ApPENDIX A: MANAGEMENT TEAM

Ron Fernandes General Manager (250) 783-5001

Terry Peressini Business Planning Manager (250) 783-5004

Darrell Perreault Technical Services Manager (250) 783-5125

Ulrike Bergmann Environment and Social Issues Manager (250) 783-5006

Morgan McLennan PCN Plant Manager (250) 783-7401

Mark Poweska GMS Plant Manager (250) 783-5002

Drew Kendrick GMS Maintenance Engineer (250) 783-5028

Darin Thompson GMS Operations Manager (250) 783-5003

2004, January 12Appendix A

Page 1

DRAFT

ApPENDIX B: WATER USE PLAN PROGRAM

In the Water Use Plan Development Program , BC Hydro wil , with broad public consultation , review all of itsgeneration and storage operations and prepare Water Use Plans that provide clarity to all interested partieson the boundaries within which BC Hydro may operate. Water Use Plans will reflect a balance of theeconomic, environmental and social values associated with the water resources at the local , regionalprovincial and federal levels.

The Development program consists of three components: program management, which oversees themanagement of BC Hydro s Water Use Plan Program; water use plan development for each watershedproject following the Water Use Plan Guidelines; and regulatory approval which implements the water useplans through revisions to BC Hydro s licensing. The steps in the guidelines are:

The Development Steps in the Guidelines are:

Step 1 Initiate a WUP process for the particular facilityStep 2 Scope the water use issues and interestsStep 3 Determine the consultative process to be followed and initiate it

Step 4 Confirm the issues and interests in terms of specific water use objectives

Step 5 Gather additional information on the impacts of water flows on each objective

Step 6 Create operating alternatives for regulating water use to meet different interests

Step 7 Assess the tradeoffs between operating alternatives in terms of the objectives

Step 8 Determine and document the areas of consensus and disagreement

Step 9 Prepare a draft WUP and submit it to the Comptroller for regulatory review

Step 10 Review the draft plan and issue a provincial decision

Step 11 Review authorized WUP and issue a federal decision.

Following Federal acceptance of the plan , the WUP program implementation is initiated in response torevised orders from the Comptroller of Water Rights.

2004, January 12Appendix 8

Page 1

Draft SEV Asset Plan - Feb 18 2004 v9.doc

FACILITY ASSET PLANFiscal 2004/05

SEVEN MILE GENERATING FACILITY

GENERATION

CONFIDENTIAL

Plan accepted on this _____ day of ________________, 2004

Dawn Farrell DateExecutive Vice President

Chris Dahl Date Willi Friml DatePlant Manager General Manager

Facility Asset Plan Seven Mile (SEV)

DRAFT

TABLE OF CONTENTS

1 EXECUTIVE SUMMARY.......................................................................................... 21.1 PURPOSE................................................................................................................ 21.2 SUMMARY............................................................................................................... 2

2 STRATEGIC CONTEXT........................................................................................... 32.1 PRODUCTS & SERVICES........................................................................................... 32.2 BUSINESS SUMMARY ............................................................................................... 4

2.2.1 Operating Summary..................................................................................... 42.2.2 Sustainability & Community Summary ...................................................... 42.2.3 Maintenance Summary ................................................................................ 52.2.4 Equipment Summary ................................................................................... 6

3 ALIGNMENT WITH GENERATION PLAN............................................................... 93.1 GENERATION MANDATE ........................................................................................... 93.2 IMPROVEMENT OPPORTUNITIES ................................................................................ 93.3 LIFE CYCLE PLAN .................................................................................................... 9

4 PERFORMANCE ................................................................................................... 104.1 FINANCIAL SUMMARY............................................................................................. 104.2 OPERATIONAL SUMMARY ....................................................................................... 104.3 ENVIRONMENTAL STEWARDSHIP SUMMARY ............................................................. 10SOCIAL & COMMUNITY CONTRIBUTION SUMMARY ........................................................... 11

5 RISKS .................................................................................................................... 12

6 PROJECTS ............................................................................................................ 14

Appendices

Appendix A: Management Team

Appendix B: Water Use Plan Program

Facility Asset PlanSeven Mile (SEV)

DRAFT

August 2003Page 2

1 EXECUTIVE SUMMARY

1.1 PURPOSE

This document is a compilation of key data from a variety of sources in Generation. The data isincluded in order to set context for the management strategies detailed in the document. ThePlant Manager and the Business Planning Manager prepare the document. It is intended to beused on a quarterly basis to measure progress of initiatives designed to implement strategies.The Asset Plan is also intended to assist in making investment decisions.

1.2 SUMMARY

Major Management Issues Management Strategy

EHR supports assessment of high risk in generatorcondition

Generator re-wedging may be required

Business Development has identified opportunity toimprove efficiency

Runner replacement for units 1-3

Operating Statistics

In-service Year 1979

Category LargeMaximum SustainableGenerating Capacity -MW 804Historical Annual Av.Plant Gen (from Makingthe Connection withoutSEV Unit 4) – GWh 3,102 Energy Capability (withSEV Unit 4) – GWh 3,523Average Generation inPrevious 3 years – GWh 2,614

Equipment HealthRating G1 G2 G3 G4 Plant Performance

F2003 5 Yr Trend

Circuit Breaker F F G G

Commercial Performance: Exciter U U U N/A Forced Outage Factor (%) 0.05 Constant

Generator P P P N/A Number of Forced Outages/Unit (#) 3.7 Constant

Governor F F F G Availability (%) 90.7 Constant

Transformer F F F N/A

Turbine F F F G

G = Good, F = Fair, P = Poor, U = Unsatisfactory


DRAFT

August 2003Page 3

2 STRATEGIC CONTEXT

2.1 PRODUCTS & SERVICES

Table 1 provides a summary of products and services provided by SEV.

Products & Services Unit AverageAnnual

PerformanceEnergy

Av Gen in Previous 3yrs -Heavy Load GWh 1,801Av Gen in Previous 3yrs -Light Load GWh 813Total GWh 2,614Historic Annual Av PlanGeneration – Heavy Load GWh

2,474

Historic Annual Av PlanGeneration - Light Load GWh 628

Total GWh 3,102Fleet Services

Maximum SustainableGenerating Capacity MW 810Capacity Factor % 48Storage est m3 (x106) 45.1

Ancillary Transmission ServicesVoltage Support y/n YSynchronous Condense y/n YBlack Start y/n Y

Typical UseageBase Load (1) Proportion Yr 1/10Load Factoring (2) Proportion Yr 9/10Swing (3) Proportion Yr 0AGC (4) Y/N Y

External ServicesTransmission N/AColumbia Treaty N/AWater Sales N/AFlood Control NFish Flow Release Y/N YFish Flow Studies $ 000 $20

Intangible ServicesRecreation People/yr 21,400



DRAFT

August 2003Page 4

2.2 BUSINESS SUMMARY

Seven Mile Generating Facility (SEV), is located on the Pend d’Oreille River, in the WestKootenays of British Columbia. It is upstream of Waneta Dam and downstream of BoundaryDam, both of which are owned by private companies.

SEV is categorized as a Large asset. SEV provides approximately 7% of BCH’s total annualhydro generation and is the fourth largest Hydroelectric generating station. With the addition ofUnit 4 SEV is now forecast to provide average annual generation of 3,523 GWh.

The following represents a description of Seven Mile:

2.2.1 OPERATING SUMMARY

SEV follows the Boundary dispatch; Boundary is a peaking plant. Further, SEV is dispatchedon a year round basis to maximize the combined energy value of the available water supply atSeven Mile Dam and Waneta Dam. Spill is avoided at Waneta Dam. There is always enoughwater to run at least one unit at full load. In the spring freshet all 4 generating units areavailable and operating thereby minimizing or eliminating any spill.

2.2.2 SUSTAINABILITY & COMMUNITY SUMMARY

− Water Use Plan (WUP): The WUP was completed in F2004. Consultative committeereport has been written and has been submitted to the Water Controller. The WUPdoes not restrict facility operations. There will be some additional monitoring costs.

− Environmental Management System: the environmental management system (EMS)was designed to identify interactions between generation and the environment; thesystem would also identify the risks and consequences of the interactions. A largecomponent of EMS is documentation of the improvement process in regards toenvironmental management. There have been some difficulties in implementing thisprocess. New EMS procedures should be in place by F2005 that will alleviate some ofthese issues.

− Avoid Spills at Waneta: minimizing spills at the downstream Waneta project is a licenserequirement. Spills at the downstream Waneta project can have an impact on the whitesturgeon spawning and hatching, particularly in June, July and August. Spills will bereduced in the future as Waneta is planning on adding an additional unit within the next10 years.

− Recreation: operate SEV in the most efficient manner possible for generation whilebeing sensitive to the public use of the reservoir and surrounding area, including theBuckley Campground and Picnic Area and a Viewpoint.

− First Nations: SEV lies in the claimed territory of the Ktunaxa and Okanagan Nations.The Ktunaxa are involved in the treaty process, the Okanagan are not. Both FirstNations raised concerns about the construction and operation of the facility during theWUP process. Care must be taken to address First Nations' expectations before andduring operations and maintenance.

− Wildlife/Fisheries Issues: The Columbia Fish and Wildlife Program manages white taildeer, cougars and bats in the area around SEV. Fisheries projects include Salmo RiverBull trout and Rainbow trout stream fertilization related to the installation of Unit 4.

− −


DRAFT

August 2003Page 5

2.2.3 MAINTENANCE SUMMARY

The following table summarizes maintenance costs since F2001 and forecasts costs forSEV GS in this year and next.

Maintenance Category Fiscal2001

Actual

Fiscal2002

Actual

Fiscal2003

Actual

Fiscal2004 Plan

Fiscal2005 Plan

Total Maintenance Dollars($ 000) $1,096 $740 $1,006 $1,407 $1,885


DRAFT

August 2003Page 6

2.2.4 EQUIPMENT SUMMARY

The following table summarizes the equipment information for Seven Mile GS, as per the draftTechnical Prescription Summary Report from the Equipment Health Rating project.

G = Good, F = Fair, P = Poor, U = UnsatisfactoryCondition Major

EquipmentCNO Year

EHRLetterGrade

Other

LastOverhaul

Expected InterventionActivity

Unit 01 1979 2003Circuit Breaker F Routine maintenance and

possible 230 KV SF6 BussReplacement/Refurbishmentwithin 10 years at anestimated cost of $4.3M.

Exciter U Various EHR activitiessumming $190k over the nexttwo years. Investigationneeded to determine benefitsof replacement.

Generator P Routine maintenance and re-wedge in two to five years ata cost estimate at $527k.

Governor F Replace the governor speedswitch and hydraulic oil withintwo years at an estimatedcost of $65k.

Transformer F Routine maintenance andtransformer cooling testactivities at unidentified costs.

Turbine F Routine maintenance andreplace the turbine within 5years at a cost of $6.1 million

Unit 02 1979 2002Circuit Breaker F Routine maintenance and

possible 230 KV SF6 BussReplacement/Refurbishmentwithin 10 years at anestimated cost of $4.3M.

Exciter U Routine maintenance andvarious EHR activitiessumming $190k over the nexttwo years. Investigationneeded to determine benefitsof replacement.


Governor F Routine maintenance andreplace the speed switch in


DRAFT

August 2003Page 7

Condition MajorEquipment

CNO Year

EHRLetterGrade

Other

LastOverhaul


two years at a cost of $50k.Transformer F Routine maintenance and

transformer cooling testactivities at unidentified costs.


Unit 03 1979 2002Circuit Breaker G Routine maintenance.Exciter U Various EHR activities

summing $190k over the nexttwo years. Investigationneeded to determine benefitsof replacement.


Governor F Routine maintenance andreplace the speed switch intwo years at a cost of $50k.

Transformer F Routine maintenance andtransformer cooling testactivities at unidentified costs.


Unit 04 2003 2003Circuit Breaker G Routine maintenance.Exciter N/A Routine maintenance.Generator N/A Routine maintenance.Governor G Routine maintenance.Transformer N/A Routine maintenance.Turbine G Routine maintenance.

AC Station Service 1979 2003 Routine maintenance.DC Station Service 1979 2003 Routine maintenance.Water Passages 1979 2003

Penstock Routine maintenance.PenstockCoatings

Routine maintenance.

Surge Tower N/ASurge TowerCoatings

N/A

Pipeline N/APipeline Coatings N/A

Substation 1979 2003 Routine maintenance andpossible 230 KV SF6 BussReplacement/Refurbishment


DRAFT

August 2003Page 8

Condition MajorEquipment

CNO Year

EHRLetterGrade

Other

LastOverhaul


within 10 years at anestimated cost of $4.3M.

Dam 1979 2003Spillway Routine maintenance after

Dam Safety Projectcompletes in F2006.

Dam Structure Routine maintenance afterDam Safety Projectcompletes in F2006.

Reservoir Routine maintenance.Powerhouse 1979 1979 PH Roof Replacement

expected within 2 years at anestimated cost of $375K.

Lights Routine maintenance.Fire Protection Routine maintenance.

HVAC Routine maintenance.Oil Containment Routine maintenance.


DRAFT

August 2003Page 9

3 ALIGNMENT WITH GENERATION PLAN

3.1 GENERATION MANDATE

The Energy Policy states that the mandate “of the generation business is to manage theheritage assets, make efficiency improvements at existing facilities and provide energyand capacity to the domestic market while maximizing trade revenue potential andinvestment return to the Province”.

3.2 IMPROVEMENT OPPORTUNITIES

Improvement opportunities for Seven Mile GS include:

o Unit 1: incremental energy opportunity of 27GWh annually as a result of turbinereplacement. This work is planned for completion in F2008.



3.3 LIFE CYCLE PLAN

SEV practices a component-replacement strategy, where single or multiple components that arethe direct cause of faults are replaced over time. The financial analysis provided in Section 5reflects expected financial performance given a just-in-time replacement approach. The planincludes the effects of replacing the turbines on Units 1, 2 and 3.


DRAFT

August 2003Page 10

4 PERFORMANCE

4.1 FINANCIAL SUMMARY

2002/03Actual($ '000)

2003/04Target($ '000)

2003/04Forecast($ '000)

2004/05Target($ '000)

2005/06Target($ '000)

OMA 1,570 1,681 1,500 2,057 2,097

Capital 52,500 39,000 24,400 24,500 3,000

Capital includes Dam Safety, Resource Smart and Sustainability and Aboriginal Relationsinvestments.

4.2 OPERATIONAL SUMMARY

Area of Focus Measure2002/03Actual

2003/04Target

2003/04Forecast

2004/05Target

2005/06Target

Safety

Medical Aids # 0 0 0 0 0

Disabling Injuries # 0 0 0 0 0

Plant Performance

Availability % 91 N/A N/A 95.0 95.0

Forced outage count including failedstarts (per/unit) # 3.7 2.4 3.5 2.2 2.1

The Kootenay Generation Area did not set targets for individual plant outage rates in F2004.

4.3 ENVIRONMENTAL STEWARDSHIP SUMMARY


2003/04Target

2003/04Forecast

2004/05Target

2005/06Target

Water use Plan (WUP) Development

Steps(See

AppendixB) 0 N/A 10 11 N/A

Environmental# of

incidents 2 0 1 0 0

The Seven Mile water use plan, was submitted to the Water Comptroller in February F2003.

There has been 1 environmental incident in or near water. The quantity of oil reaching thewater was very small and is believed to have leaked from a vehicle in the parking lot.


DRAFT

August 2003Page 11

SOCIAL & COMMUNITY CONTRIBUTION SUMMARY


2003/04Target

2003/04Forecast

2004/05Target

2005/06Target

First Nations Grievances

New FirstNationsGrievances 0 0 0 0 0

Recreation Sites # of Visitors 21,409 N/A 22,000 N/A N/A

Major social-related action items for SEV system in the upcoming year include:o Recreation: operate SEV in the most efficient manner possible for generation

while being sensitive to the public use of the reservoir and surrounding area,including the Buckley Campground and Picnic Area and a Viewpoint.

The annual OMA cost of managing social issues at SEV is estimated to be $10k per year.


DRAFT

August 2003Page 12

5 RISKS

Risk rating was prepared independently by each region for each project in the F2005 capitalplan. Generations' approach is to first complete projects across the Fleet, which have thehighest latent risk.

The major risks at Seven Mile are:

− Dam Safety: previous studies have identified risks associated with the dam'sperformance under earthquakes. Dam Safety Improvements were initiated in F2002 toaddress these seismic deficiencies. To improve the seismic performance of the dam,the work includes dam anchoring, spillway gate reliability upgrades, and site systemupgrades.

− The anchoring work was completed in F2003. Work is underway on the spillway gateimprovements and general dam safety equipment upgrades, with expected completion inF2006.

Figure 1: Illustration of Latent Risks at Seven Mile


DRAFT

August 2003Page 13

− Environmental:

• reservoir fluctuation causing potential stranding• entrainment• bank erosion on left bank


DRAFT

August 2003Page 14

6 PROJECTS

Forecast Capital Expenditures ($ 000 - Loaded) Expenditure Title F2005 F2006 F2007 F2008 F2009 F2010 F2011 F2012 F2013 F2014

SEV – Dam Safety Improvements 24,016 2,300 - - - - - - - -

SEV - G1/G2 230KV Bus Replacement(Breaker, CT & CV

- - - - - 4,315 - - - -

SEV - Replace unit 1 P&C - - - - - - 1,054 - - -

SEV - Replace Unit 2 P&C - - - - - - 1,054 - - -

SEV - Replace unit 3 P&C - - - - - - - - 1,054 -

SEV - Replace unit 2 excitation system - - - - - - 632 - - -

SEV - Replace unit 1 excitation system - - - - - - - 632 - -

SEV - Replace unit 3 excitation system - - - - - - - 632 - -

SEV - Replace dam drainage &instrumentation

- - - - - 422 - - - -

SEV - Power House Roof Replacement 374 - - - - - - - - -

SEV - Unit 3 Stator Rewedging - - 527 - - - - - - -

SEV - Unit 1 Stator Rewedging - - - 527 - - - - - -

SEV - SEV Unit 2 Stator Rewedging - - - - 527 - - - - -

SEV - Replace debris boom - - 190 9 9 8 8 8 7 7

SEV - Replace station service DC(Batteries)

- - 122 - - - - - - -

SEV - Replace AH14 Air Supply Fan(Big Bertha)

- - - - - - 63 - - -

SEV - Tools and Work Equipment 44 42 42 42 42 42 42 42 42 42


DRAFT

August 2003Page 15

Expenditure Title F2005 F2006 F2007 F2008 F2009 F2010 F2011 F2012 F2013 F2014

SEV - Dam - Replace Block JointSealant

- - 211 - - - - - - -

SEV - Intake Gantry Crane ControlsUpgrade

- - - - 158 - - - - -

SEV - Recoat Draft Tube Gates - - - - - 158 - - - -

SEV - Replace Air Conditioners - 3 -One Adjacent to Each Unit

- - - 158 - - - - - -

SEV - 2B1 Bus Replacement - 105 - - - - - - - -

SEV - Recoating Gantry Crane, Intakeon Dam

- - - - - - - - - 105

SEV - Recoating Tailrace Gantry - - - - 158 - - - - -

SEV - Access Road - Rebuild Slough - - 105 - - - - - - -

SEV - Tailrace Gantry Crane Controls - - - - - 53 - - - -

SEV - Air compressor Systems - - - - 211 - - - - -

SEV - Infer-red Camera 105 - - - - - - - - -

SEV - Units 1 to 3 Turbine Upgrade 5 531 1,083 3,240 6,547 6,835 - - - -

Totals

24,639

3,053

2,280

3,976

7,651

11,833

2,853

1,315

1,103

155

FACILITY ASSET PLAN

Fiscal 2003/04

SEVEN MILE GENERATING FACILITY

APPENDICES

Appendix APage 1

APPENDIX A: MANAGEMENT TEAM

Name Title Telephone

Chris Dahl Plant Manager (250) 367-6226

Willi Friml General Manager (250) 365-4552

Alan Pattinson Business Planning Manager (250) 365-4558

Appendix BPage 1

APPENDIX B: WATER USE PLAN PROGRAM

In the Water Use Plan Development Program, BC Hydro will, with broad public consultation, reviewall of its generation and storage operations and prepare Water Use Plans that provide clarity to allinterested parties on the boundaries within which BC Hydro may operate. Water Use Plans willreflect a balance of the economic, environmental and social values associated with the waterresources at the local, regional, provincial and federal levels.

The Development program consists of three components: program management, which overseesthe management of BC Hydro’s Water Use Plan Program; water use plan development for eachwatershed project following the Water Use Plan Guidelines; and regulatory approval which.

The development steps in the Guidelines are:

Step 1 Initiate a WUP process for the particular facilityStep 2 Scope the water use issues and interestsStep 3 Determine the consultative process to be followed and initiate itStep 4 Confirm the issues and interests in terms of specific water use objectivesStep 5 Gather additional information on the impacts of water flows on each objectiveStep 6 Create operating alternatives for regulating water use to meet different interestsStep 7 Assess the tradeoffs between operating alternatives in terms of the objectivesStep 8 Determine and document the areas of consensus and disagreementStep 9 Prepare a draft WUP and submit it to the Comptroller for regulatory reviewStep 10 Review the draft plan and issue a provincial decisionStep 11 Review authorized WUP and issue a federal decision.

Following Federal acceptance of the plan, the WUP program implementation is initiated in responseto revised orders from the Comptroller of Water Rights.

Generation Environmental Management System Manuali

Date Issued: 2004-01-13

GENERATION

ENVIRONMENTAL MANAGEMENT SYSTEMMANUAL

DECEMBER 2003

Generation Environmental Management System Manualii


Table of Contents

TABLE OF CONTENTS................................................................................................................. II

INTRODUCTION..........................................................................................................................III

DEFINITIONS AND ABBREVIATIONS.............................................................................. IVJob Titles and Acronyms Defined............................................................................................ ivKey Terms in the EMS Manual.................................................................................................v

EMS MANUAL PROCEDURES ............................................................................................. 11.1 IMPLEMENTATION OF ENVIRONMENTAL POLICY ...................................................... 1

2.1 ENVIRONMENTAL ASPECTS AND IMPACTS................................................................ 2 Figure 2.1. Annual Environmental Planning Process....................................................... 4 Work Instruction 2.1A. Risk Ranking of Impacts .............................................................. 5 Work Instruction 2.1B Test for Significance .................................................................... 92.2 LEGAL AND OTHER REQUIREMENTS......................................................................... 122.3 SETTING OBJECTIVES AND TARGETS....................................................................... 142.4 ENVIRONMENTAL PROGRAMS ................................................................................... 15

3.1 STRUCTURE AND RESPONSIBILITY ........................................................................... 16 Figure 3.1 Environmental Management Structure – Generation ................................... 173.2 TRAINING, AWARENESS AND COMPETENCE ........................................................... 18 Needs Assessment – Work Instruction 3.2 .................................................................... 203.3 INTERNAL COMMUNICATION AND REPORTING ....................................................... 23 Figure 3.3 Process Improvement Form.......................................................................... 253.4 EXTERNAL COMMUNICATION ..................................................................................... 263.5 DOCUMENTATION AND DOCUMENT CONTROL ....................................................... 28 Table 3.5. Generation EMS Document Control Register ............................................... 303.6 OPERATIONAL CONTROLS......................................................................................... 323.7 EMERGENCY PREPAREDNESS AND RESPONSE..................................................... 343.8 CONTRACTOR MANAGEMENT .................................................................................... 36 Figure 3.8 Managing the Environmental Requirements of Capital and OMA Work...... 37

4.1 MONITORING AND MEASUREMENT ........................................................................... 384.2 NON-CONFORMANCE, CORRECTIVE AND PREVENTIVE ACTION.......................... 394.3 RECORDS MANAGEMENT............................................................................................ 41 Table 4.3 Generation EMS Records Summary............................................................. 424.4 EMS AUDITS and OPERATIONAL ENVIRONMENTAL REVIEWS............................... 45

5.1 MANAGEMENT REVIEW................................................................................................ 47

APPENDIX A: EMS ROLES & RESPONSIBILITIES ...................................................... 49KBU MANAGERS.................................................................................................................. 49PLANT MANAGERS ............................................................................................................. 51DEPARTMENT MANAGERS ................................................................................................ 54ENVIRONMENTAL AND SOCIAL ISSUES MANAGERS (ESIMs)....................................... 57MANAGER, SUSTAINABILITY AND ABORIGINAL RELATIONS........................................ 60(EMS REPRESENTATIVE) ................................................................................................... 60GENERATION EMPLOYEES................................................................................................ 62

Generation Environmental Management System Manualiii


Introduction

The Generation Line of Business at BC Hydro has established an EnvironmentalManagement System (EMS) to improve the environmental management of the unit. TheEMS is also intended to help BC Hydro meet the requirements of the EnvironmentalCommitment & Responsibility (ECR) Program of the Canadian Electricity Association(CEA). Participation in the ECR program, a requirement for all CEA members, meansmaking a commitment to continuous environmental improvement as an integral part ofgood business performance. The requirement includes having an EMS consistent withISO 14001, an international standard for EMS.

The International Organization for Standardization released the ISO 14001 standard inJanuary 1997. It has been broadly accepted as the framework for the development ofenvironmental management systems around the world. An ISO 14001-consistent EMS ismade up of five components:

• Policy• Planning• Implementation and Operation• Checking and Corrective Action• Management Review

The standard also requires “continuousimprovement” of the EMS with the linearrelationship of the parts starting at Policy,progressing through Management Review andback to Policy. This manual describes the procedures Generation uses to support eachof these EMS components. This manual explains the procedures used to meet the requirements of the ISO 14001standard and, with the exception of the Burrard Generating Station, applies to all ofGeneration. A number of procedures in the manual require participation from otherBC Hydro business units outside the direct control of Generation. These are noted in theresponsibility tables and cross-referenced in the procedures. Currently the Burrard Generating Station is exempt from these procedures because ituses a separate EMS independent from the rest of Generation. The Burrard GeneratingStation is currently registered by a third-party Registrar. Plans are being developed tointegrate the three thermal plants (Burrard, Prince Rupert and Fort Nelson) into a singleISO 14001 registration.

Generation Environmental Management System Manualiv


DEFINITIONS AND ABBREVIATIONS

APPROVED BY: Executive VP, Generation

Job Titles and Acronyms Defined

Department Manager • a manager who reports to a KBU or PlantManager (includes ESIMs, MOSs, TechnicalService Manager, Strategic Issues Manager,etc.)

EMS Aspects Administrator • person responsible for maintaining and updatingthe EMS Aspects/Impacts Database. This personfalls within Strategic Issues, Sustainability andAboriginal Relations

Environmental Representative • appointed person who will assist in managing theenvironmental requirements of new work orproject

ERRC • Environmental Regulatory Relations Coordinator

ESIM • an Environmental and Social Issues Managerreporting to a Regional General Manager andOperations and Energy Purchasing KBUs

Generation EnvironmentalManagers

• includes all of the following managers:• Manager, Sustainability & Aboriginal Relations• Manager of Regulatory Relations• Manager of Strategic Issues• Manager of Sustainability Resources• Technical Advisor, Policy• Managers, Environmental and Social Issues

(Regions and Operations & EnergyPurchasing)

KBU Manager • a manager (having environmental responsibility)who directly reports to the VP GenerationManagement (e.g., Operations and EnergyPurchasing, Regional General Managers)

Plant Manager • a facility Manager who reports to a RegionalGeneral Manager

Regional General Managers • KBU Managers, including those of Peace RiverGeneration, Coastal Generation and ColumbiaRiver Generation

Generation Environmental Management System Manualv


Key Terms in the EMS Manual

Audit • an audit is the systematic, documentedverification process of objectively obtaining andevaluating evidence to determine whether thesubject matter conforms to the audit criteria

Audit Findings • statements in a report that indicate where anactivity or a response does not meet the intent ofthe regulations or internal policies, proceduresand best management practices

Document • a document is composed of dynamic information,often providing instruction on how to carry out anactivity

Document Control • the method (either paper-based or electronic) bywhich all documents associated with an EMS(ISO 14001) are maintained, including but notlimited to: dating of current versions of relevantEMS documents and procedures; destruction ofobsolete documents or procedure copies that arenot required for legal and/or knowledgepreservation; periodic review/approval of relevantdocuments and procedures; and the location ofthe most current documents and procedures

EMC • Environmental Management Committee

EMS Aspects/ImpactsDatabase

• a catalogue of operational and maintenanceactivities and their associated environmentalaspects, impacts, operational controls andlegislation for Generation facilities

EMS Audit • a systems “conformance” audit used to verify theimplementation of an EMS and to determine howwell the EMS is functioning, in accordance withgoverning standards such as ISO 14001

Environment • the surroundings in which an organizationoperates, including air, water, land, naturalresources, flora, fauna, humans, and theirinterrelations. The environment in this contextextends from within an organization’s location tothe global system.

Environmental Aspect • component of an organization’s activities that caninteract with the environment

Generation Environmental Management System Manualvi


Environmental Commitmentand Responsibility (ECR)

• program of the Canadian Electricity Association

Environmental ComplianceMeasure (ECM)

• the number of externally reportable andpreventable environmental incidents. Thismeasure is used to track environmentalperformance and is a subset of incidentscaptured by the Environmental IncidentReporting system.

Environmental IncidentReporting (EIR)

• a communications tool (defined by the EIRStandard) used to document environmentalincidents. An Environmental Incident is anoccurrence that causes environmental damage;adverse effect(s) on fish, wildlife or otherenvironmental resources; adverse publicity; orlegal action with respect to violation of statutes.

Environmental Management • those elements of the overall managementfunction of an organization (including planning)that develop, implement and maintain itsenvironmental policy and objectives

Environmental ManagementSystem (EMS)

• the organizational structure, responsibilities,practices, procedures, processes and resourcesfor implementing and maintaining environmentalmanagement

Environmental Objective • overall environmental goal, arising from theenvironmental policy, that an organization setsitself to achieve, and which is quantified wherepracticable

Environmental Performance • measurable results of an EMS, related to anorganization’s control of environmental aspects,based on its policy, objectives and targets

Environmental Policy • a statement by an organization of its intentionsand principles in relation to its overallenvironmental performance that provides aframework for action and for the setting of itsenvironmental objectives and targets

Environmental Target • detailed performance requirement, quantifiedwhere practicable, applicable to the organizationor parts thereof, that arises from theenvironmental objectives and that needs to beset and met in order to achieve those objectives

Environmental Training • a process of communicating the required

Generation Environmental Management System Manualvii


teachings or learnings associated with aspecified topic. Environmental training canconsist of either awareness or competencytraining. Awareness training is non-technical,used to communicate policies and high-levelawareness. Competency training is highlytechnical in nature, and involves the review oftechnical components associated with thetraining topic. Training can consist of workshops,lectures, videos, or direct training by peers,supervisors, or managers, external courses andone-on-one communication.

GMC • Generation Management Committee

ISO 14001 • a series of standards from the InternationalOrganization of Standardization onenvironmental management

Key Business Unit (KBU) • Generation KBUs include: Peace RiverGeneration, Coastal Generation, Columbia RiverGeneration, Business Development Operationsand Energy Purchasing, Human Resources,Dam Safety, Comptroller’s Office, Sustainabilityand Aboriginal Relations

Legal and Other Requirements • the collection of laws such as Acts, Regulations,Guidelines, Standards and By-laws, as enactedby any federal, provincial, municipal or territorialgovernments, that specifically apply to theregulation of the business entity within thatjurisdiction; and the collection of non-regulatoryitems, such as industry codes of practice,operating permits, agreements with publicauthorities, internal company policies orrequirements or any other non-regulatoryguideline to which the organization subscribes

Management Review • the opportunity for management levels to reviewthe EMS progress and its effectiveness, to lookat the need for changing the environmentalpolicy, or the objectives as they are reached, andas global and/or local environmental prioritiesand local business priorities shift. It must be acomprehensive review conducted at least once ayear.

Monitoring and Measurement • Monitoring is the process of maintaining regularsurveillance. Measurement is the process ofcomparison against a known standard applicableto an EMS, whereby an organization must

Generation Environmental Management System Manualviii


document what and how it will monitor itsactivities that could result in a significantenvironmental impact.

Needs Assessment • the process of evaluating the current stateagainst that which is desired or required

Non-conformance • refers to deficiencies in the EMS, which may varyin severity depending on their nature. As theEMS begins to fail, non-conforming performanceissues may also become evident. Examplesinclude: system compliance deficiencies;objectives and targets missed; incidents andaccidents; ineffective procedures; and otherelements of the EMS not performing to thespecification (ISO 14001).

Operational Controls • documented operating procedures, equipmentand specific controls designed and intended toavoid or minimize environmental impacts. Theseinclude written procedures such asEnvironmental Practices (EPs), WasteManagement Standards, Best ManagementPractices (BMPs) System Operating Orders(SOOs), Local Operating Orders (LOOs) andmaintenance instructions.

Operational EnvironmentalReview (OER)

• used to determine an organization’s compliancewith laws and regulations and assess relatedoperational and maintenance practices asrequired by the Regions

Record • static information that provides evidence of thecompletion, or lack of completion, of an activitysuch as monitoring or training

Generation Environmental Management Manual

PRINTED VERSIONS ARE NOT CONTROLLED. REFER TO THE ONLINE MANUAL FOR CURRENT INFORMATION.


1

EMS MANUAL PROCEDURES

1.1 IMPLEMENTATION OF ENVIRONMENTAL POLICY

APPROVED BY: Executive Vice-President, Generation

PURPOSEThis procedure will be used to implement and communicate the EnvironmentalResponsibility Policy to Generation employees.

Generation supports and implements BC Hydro ’s Corporate Policy Statement:Environmental Responsibility (http://w3.bchydro.bc.ca/corporate_policies/envresp.html.The Corporate EMS includes procedures for revising the policy and for externalcommunication.

The evaluation of the suitability of the Policy (to Generation) is addressed annually inprocedure: Management Review 5.1.

PROCEDURE1. KBU Managers will ensure that the policy is adhered to and displayed at appropriate

locations at facilities and offices routinely occupied by Generation employees. Thepolicy will also be communicated through EMS Awareness training programs andnew employee orientation material.

2. Department Managers will periodically solicit feedback from their employees on thesuitability of the policy and forward this information to the Manager, Sustainabilityand Aboriginal Relations.

3. The Executive Vice-President will issue an annual message to all Generation staffon Generation’s commitment to conforming to the policy.

This message may be in the form of an e-mail, bulletin, poster or other means ofcommunication.

RECORDS• relevant training records• copy of annual message from Executive VP Generation• department meeting minutes

CROSS-REFERENCE• Management Review procedure (5.1)• Internal Communication and Reporting procedure (3.3)• Corporate EMS Policy Procedure

http://w3.bchydro.bc.ca/corporate_policies/envresp.html




2

2.1 ENVIRONMENTAL ASPECTS AND IMPACTS


PURPOSETo identify and prioritize environmental impacts associated with Generation’s activities,products and services over which it can be expected to have an influence. Generationwill identify significant aspects1 and use these to set environmental objectives andtargets. Programs will be established, where appropriate, to deliver performanceconsistent with these objectives and targets. Generation’s annual environmentalplanning process is depicted in Figure 2.1.

PROCEDURE1. Establish and maintain the EMS Aspect/Impacts Database

KBU Managers will ensure that environmental impacts associated with their KBUactivities and responsibilities are identified and ranked for significance. Operatingand maintenance risk will be ranked as described in EMS Work Instruction 2.1-A andtested for significance according to EMS Work Instruction 2.1-B.

2. Environmental Management of New Work Departmental Managers (including Plant and Project Managers) will assess allprojects and new work for potential environmental aspects, impacts and regulatoryrequirements. New or modified aspects/impacts resulting from projects will becomepart of the Environmental Aspect/Impact Review (see Figure 2.1). Refer to EMSProcedure 3.8 Contractor Management, which addresses internal and externalcontract work.

3. Environmental Aspect/Impact ReviewESIMs will (at minimum) annually review and revise impact rankings (including anynew impacts) for each operating unit in their area of responsibility using WorkInstructions 2.1-A,B. This review will consider changes to operating practices andfacilities (e.g., from projects and installation of new technology), public and staffcomments, new legislation, environmental performance, and business risk toGeneration. ESIMs will submit modifications to the EMS Aspect/Impact database nolater than the end of September each year to the EMS Aspects/Impacts DatabaseAdministrator. The EMS Aspects/Impacts Database Administrator will submit asummary report of the significant aspects and impacts to the Sustainability andAboriginal Relations Manager.

4. Generation Environmental Risk ReviewSustainability and Aboriginal Relations Manager will ensure that theenvironmental risks (based on operating and maintenance significant aspects andimpacts, and other information) are assessed and incorporated into the setting ofGeneration’s Strategic Objectives and Performance Measures on an annual basis(see Figure 2.1).

1 Activities we do or control that can have an impact on the environment




3

RECORDS• EMS Aspects/Impact Database – the aspects, impacts, risk scores and operational

controls• Aspect/Impact Reviews – in the form of meeting minutes, notes, edited reports, etc.• Quarterly Environmental Reports• Situation Analyses – Environmental and Business• Management meeting minutes – Board of Directors, GMC, EMC, EMS Management

Reviews, etc.• Semi-annual Update on Recently Enacted and Pending Environmental Regulatory

Initiatives (Legislation Matrix)

CROSS-REFERENCE• Setting Objectives and Targets procedure (2.3)• Environmental Programs procedure (2.4)• EMS Work Instruction 2.1-A, Risk Ranking of Impacts• EMS Work Instruction 2.1-B, Test for Significance• Contractor Management procedure (3.8)




4

Figure 2.1. Annual Environmental Planning Process

Annual Environmental Planning Process

EnvironmentalRisk Review

Generation StrategicEnvironmentalObjectives &Performance

Measures

KBU EnvironmentalObjectives & Targets

Budget ProcessCapital & OMA

EnvironmentAspect/Impact

ReviewSeptember

December –February

Changes toFacilities, Ops. &Maintenance

Environmental Performance

New Legislation

Maintain OperatingControls

GMC Business DirectionSituation Analyses

Performance

Board of Director Priorities

Public Opinions

New Legislation

Annual EMS Management Review

EnvironmentalProgram

Implementation

CorporateStrategic

Objectives




5

Work Instruction 2.1A. Risk Ranking of Impacts

Background

ISO 14001 defines a significant aspect as one that has a significant impact on theenvironment. Annex A in ISO 14001 and ISO 14004 (the document designed to provideguidance to organizations implementing ISO 14001) both point to a risk based approachto determining significance.

An initiative of the Generation EMS project (1998-99), environmental aspects andimpacts were identified for 12 distinct operating units, based on geographic proximity orwatershed links, and management structure and responsibility.

1. Peace River (PCN, GMS)2. Upper Columbia large plants (MCA, REV)3. Upper Columbia small plants (SHU, WHN, WGS)4. West Kootenay (KCL, SEV, DDM, HLK)5. East Kootenay (SPN, ELK, ABF)6. Bridge River (SON, BR1, BR2, LAJ, TRZ)7. Fraser Valley (ALU, SFL, RUS, WAH, LB1, LB2, COQ, RM)8. North Vancouver Island (JHT, LAD, SCA, Salmon, Quinsam, and Heber Diversions,

PUN)9. South Vancouver Island (JOR, ASH)10. North Coast (FLS)11. South Coast (CMS, DSY, COM)12. Prince Rupert Gas (RPG)

In keeping with BCH policy on risk management, Generation’s EMS uses a simple riskassessment approach to define the risk of aspects. The risk ranking process isdesigned to consistently assess the probability of an environmental nonconformance,and the consequences of potential events.

This risk ranking process was used by EMS Implementation teams at each facility, withthe assistance of members of the EMS team and consultants. All aspects and rankinginformation is documented in Generation’s EMS database, and will be maintained byGeneration Sustainability – Systems according to EMS Procedure 2.1 EnvironmentalAspects and Impacts.

Risk ranking is required as part of Generation’s Test for Significance, described in EMSWork Instruction 2.1-B. Together, these procedures allow us to separate the

R I S K R A N K I N G O F I M P A C T S

W O R K I N S T R U C T I O N

2 . 1 - A

Note: Currently UnderReview!




6

environmental aspects of our business into two populations of risk: significant and notsignificant.

Methodology

This risk assessment model, illustrated by the risk ranking tables at the end of thissection, uses weighted scoring to help assess the relative risks of the environmentalaspects.

Risk is a measure of human injury, environmental damage, economic loss or loss ofbusiness reputation, that takes into account both the incident, likelihood and the severityof the consequences.

The formula for calculating risk scores includes Exposure, Likelihood and Consequence

Risk = Probability (E x L) x Consequences (C1+C2+C3+C4)

Because an aspect may have multiple impacts, it will have several risk scores, one foreach of its impacts.

1. Exposure represents the frequency of the activity with an aspect.1

2. There is always the Likelihood or chance that an incident or nonconformance willoccur and result in an impact. Likelihood is considered in light of all the operationalcontrols currently in place for the aspect being assessed.

3. The Consequences are the potential damages should the impact occur. There arefour broad categories of Consequences:

• Environmental Impacts (C1)• Safety Impacts (C2)• Business Impacts (or financial losses) (C3)• Company Reputation/Public Opinion Impacts (C4)

Consequences are also considered in light of the operational controls currently inplace for the aspect.

Each Consequence is scored separately in order to recognize differences betweenrisks that, for example, may have high business impacts but no significant safetyimpacts.

The lowest possible score is zero and the highest possible score is 10,000. Risk is zerowhen Exposure is zero.

1 For example, an aspect is the potential for oil to spill from a transformer during oil change-out,exposure is the frequency which the oil is changed, and the number of transformers in thesystem. The likelihood is the potential for the impact to occur, in this case: oil contamination.




7

Addressing Uncertainty

Risk ranking does not account for uncertainty regarding any of the scores contributing tothe overall total. This can be addressed as follows:

1. Score each risk three times to reflect low, mid-range and high estimates. Usually, amid-range estimate is all that is required.

2. Formulate 3 sets of rankings for low, mid-range and high estimates. 3. Do rankings vary significantly among the 3 sets of estimates? If not, then no further

effort is required. If there is wide variation, additional effort will be required to reduceuncertainty.

Do not make up scores that are not on the risk ranking tables, for example anaverage between two scores.

Addressing Subjectivity

This risk assessment process provides the “quantitative” aid that helps us rank andorder our significant aspects or impacts. The scores simply represent opinionsregarding the severity of consequences and the probability of occurrence; subjectivitycan affect the values assigned to scores. It must be stressed that the process isdesigned to distinguish high risk aspects of our work, not to assess the absolute degreeof risk associated with a particular aspect.

Subjectivity can be reduced by having a multidisciplinary team conduct the scoring. Theteam should have a balance of perspectives which is why representation frommanagement, finance, engineering, safety, environment, legal, and operations isrecommended. In some cases, the participation of external stakeholders can add bothvalue and transparency to the process.

Scoring can be conducted in two ways. Individual scores may be averaged to reflect thegroup score. In a group with polarized opinions, however, this approach may not besatisfactory. A second approach is to have the group reach consensus on each scoreassigned. This second approach will likely take more time but the effort invested inreaching consensus will pay dividends in promoting ownership of the results.




8




9

Work Instruction 2.1B Test for Significance

Background

ISO 14001 defines a significant aspect as one that has a significant impact on theenvironment. Annex A in ISO 14001 and ISO 14004 (the document designed to provideguidance to organizations implementing ISO 14001) both point to a risk based approachto determining significance.

Environmental aspects and impacts were identified for 12 distinct operating units, basedon geographic proximity or watershed links, and management structure andresponsibility.

1. Peace River (PCN, GMS)2. Upper Columbia large plants (MCA, REV)3. Upper Columbia small plants (SHU, WHN, WGS)4. West Kootenay (KCL, SEV, DDM, HLK)5. East Kootenay (SPN, ELK, ABF)6. Bridge River (SON, BR1, BR2, LAJ, TRZ)7. Fraser Valley (ALU, SFL, RUS, WAH, LB1, LB2, COQ)8. North Vancouver Island (JHT, LAD, SCA, Salmon, Quinsam, and Heber Diversions,

PUN)9. South Vancouver Island (JOR, ASH)10. North Coast (FLS)11. South Coast (CMS, DSY, COM)12. Prince Rupert Gas (RPG)

Each operating unit then used a simple risk assessment approach to assign a risk scoreto each impact of their environmental aspects.

This risk ranking process, based on assessing the probability and consequences ofimpacts, is described in EMS Work Instruction 2.1-A

Aspects and risk ranking information is documented in Generation’s EMS database, andwill be maintained by Generation Sustainability – Systems according to EMS Procedure2.1 Aspects and Impacts.

Once aspects were assessed for risk, the following Test for Significance was applied toproduce a list of significant aspects for each operating unit and for Generation and willbe used for any newly identified aspects.

T E S T F O R S I G N I F I C A N C E

W O R K I N S T R U C T I O N

2 . 1 - B

Note: Currently UnderReview!




10

The objective of this test is to derive a manageable number of significant aspects and toensure the results are appropriate across Generation.

Methodology

The test of significance uses an excel macro program to order the list of ranked aspectsfor each operating unit. The EMS database administrator, in Generation Sustainability,is responsible for applying this test and distributing controlled lists of significant aspects.

File: “Significance Test-Nov 19’99xls.xls”

The following describes the steps that are encoded in the macro to produce the list ofsignificant aspects.

List for Operating Units

1. The list of aspects is ordered from highest to lowest for the operating unit. (note:An aspect may have multiple impacts, each having a risk score. The highestranking impact will represent the aspect’s score.)

2. The top 15 unique aspects, based on the risk ranking, will be consideredsignificant for the operating unit. If the number of aspects is less than 15, thenthe entire list will be considered significant.

3. If there is a tied score at the 15th aspect, it can be broken using the followingordered criteria:

a) highest Likelihood Scoreb) highest Probability Scorec) highest Environmental Consequenced) highest Safety Consequencee) highest Business Consequencef) highest Public Opinion/Company Reputation Consequenceg) ESIM or Env. Coordinator decision

List for Generation

1. Significant aspects from each operating unit are combined and ordered from highestto lowest, according to risk score.

2. The top 30 unique aspects are considered significant for Generation. If the numberof aspects is less than 30, then the entire list will be considered significant.




11

3. If there is a tied score at the 30th aspect, it can be broken using the following orderedcriteria:

a) highest Likelihood Scoreb) highest Probability Scorec) highest Environmental Consequenced) highest Safety Consequencee) highest Business Consequencef) highest Public Opinion/Company Reputation Consequenceg) ESIM or Env. Coordinator Decision

This test does not address the arbitrary nature of selecting the top fifteen and thirtyaspects. However, it does offer a greater likelihood that every operating unit will haveone or more significant aspects on the list at the Generation level.




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2.2 LEGAL AND OTHER REQUIREMENTS


PURPOSEThis procedure will be used to identify and maintain access to legal, permit and otherrequirements applicable to Generation’s activities, products and services. Theserequirements will also be considered in setting objectives, targets and programs.

PROCEDURE1. The Corporate EMS Procedure for Legislation identifies a series of steps to identify

and track legal and other requirements for BC Hydro , These can be found at: http://w3/sustainability/tools/ems/pdf/p_legislation.pdf. (See “Overview of Procedure”diagram, Steps 1 – 6.) The Manager, Sustainability and Aboriginal Relations isresponsible for ensuring that these are implemented in Generation.

The Environmental Regulatory Relations Coordinator (ERRC) will ensure that:

Step 1: pending Environmental Regulatory Initiatives and other emergingrequirements are identified

Step 2: a preliminary review of the pending initiative is conductedStep 3: an action plan is developed if requiredStep 4: the appropriate level of management, which may include the

Environmental Management Committee (EMC), approves the action plan Step 5: the action plan is implemented (may require internal and external actions)Step 6: timely information on the interpretation and application of the regulatory

initiative is provided to Generation’s KBU Managers

For Steps 2 – 6, the ERRC will collaborate with applicable Environmental Staff.

2. Manager, Regulatory Relations, Sustainability and Aboriginal Relations ensuresstrategies or actions are developed to address new and/or changed legal or otherrequirements.

3. ERRC maintains an information system of all relevant legislation that applies toGeneration and semi-annually advises Generation KBU Managers on emerginglegislation and changes to legislation.

Legislation is kept within the Environmental Legislation website:http://w3/sustainability/tools/mwelr/

An update on recently enacted and pending environmental regulatory initiatives(Legislation Matrix) is produced semi-annually and distributed to BC HydroExecutives, EMC, and other environmental and sustainability managers.

http://w3.bchydro.bc.ca/sustainability/tools/ems/pdf/p_legislation.pdf

http://w3/sustainability/tools/mwelr/




13

4. Generation KBU Managers shall communicate changes to legal and otherrequirements to their staff and managers as applicable and ensure that the legal andother requirements pertaining to their area of responsibility are met.

5. Department Managers must ensure that environmental permits, approvals andother local requirements (e.g., by-laws) pertaining to their area of responsibility areaccessible or hard copies are filed appropriately and kept up-to-date.

RECORDS• permits, licenses and approvals• EMS Aspects/Impacts Database – legal and other requirements component• Sustainability Environmental Legislation website

(http://w3/sustainability/tools/mwelr/)• Semi-annual Update on Recently Enacted and Pending Environmental Regulatory

Initiatives (Legislation Matrix)

CROSS-REFERENCE• Identification of Aspects and Impacts procedure (2.1)• Setting Objectives and Targets procedure (2.3)• Internal Communications and Reporting procedure (3.3)• Corporate EMS Procedure: Legislation


http://w3/sustainability/tools/mwelr/





14

2.3 SETTING OBJECTIVES AND TARGETS


PURPOSEGeneration will develop and maintain documented environmental objectives and targetsat each relevant management level. They are developed in consideration of significantaspects and impacts, legal and other requirements, technological options, financial,operational and business constraints, the views of interested parties, and theEnvironmental Responsibility policy.

Generation will ensure environmental objectives and targets provide a framework for thedevelopment of environmental programs that deliver performance consistent with thepolicy.

PROCEDURE1. Based on the Generation Environmental Risk Review, the Manager, Sustainability

and Aboriginal Relations ensures that environmental strategic objectives andperformance measures are developed for the coming fiscal year(s). These can be amixture of one-year, two-year, five-year, etc., as appropriate.

Once approved by Generation Management Committee (GMC), the Manager,Sustainability and Aboriginal Relations must communicate the new strategicobjectives and performance measures to the Department Managers (note order ofevents, Figure 2.1).

2. Department Managers with ESIMs will set departmental objectives and targets forthe coming fiscal year based on their aspect/impact review and Generation’sStrategic Objectives from Step 1 above. These will be submitted to the Manager,Sustainability and Aboriginal Relations prior to the budgeting process, whichoccurs annually between December and February.

RECORDS• Environmental Aspects/Impacts Review• Generation Strategic Objectives and Performance Measures• departmental objectives and targets

CROSS-REFERENCE• Implementation of Environmental Policy procedure (1.1)• Environmental Aspects and Impacts procedure (2.1)• Management Review procedure (5.1)




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2.4 ENVIRONMENTAL PROGRAMS


PURPOSEThis procedure is used to establish and maintain environmental programs for achievingGeneration’s strategic objectives, and departmental objectives and targets.

PROCEDURE1. KBU Managers shall ensure that environmental management programs are

established to achieve environmental objectives and targets. Program approval willbe secured through the budgeting process (Figure 2.1) and records of decisions anddeferrals maintained. KBU Managers will ensure that environmental programs aremodified to address new or modified activities, as required.

2. Department Managers must ensure that environmental programs are documentedthrough the budgeting process, managed through core processes and linked toFacility Asset Plans.

RECORDS• department Environmental Programs (within internal work management records)

CROSS-REFERENCE• Setting Objectives and Targets procedure (2.3)• Internal Communication and Reporting procedure (3.3)• Management Review procedure (5.1)




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3.1 STRUCTURE AND RESPONSIBILITY


PURPOSEThis procedure explains the responsibilities of all Generation managers in implementingthe EMS.

PROCEDURE1. The Generation Environmental Management structure is illustrated in Figure 3.1. The

Executive Vice-President of Generation has the ultimate responsibility forGeneration’s EMS.

2. The KBU Manager must ensure that the EMS is implemented throughout their areaof responsibility, including ensuring that all requirements are met and maintained.

For example: the KBU/ Regional General Manager could delegate the ESIM to co-ordinate an EMS committee, comprising key individuals within theRegion/Department, to meet regularly and manage the EMS at theRegion/Department level.

KBU/Regional General Managers could track delegated EMS responsibilities in amatrix/table for their area.

3. The EMS Representative for Generation is the Manager, Sustainability andAboriginal Relations and is responsible for:

• ensuring that EMS requirements are established in accordance with the ISO14001 Standard

• reporting on the performance of the EMS to the Executive Vice President,Generation

4. All Generation Employees have specific EMS roles and responsibilities. These aredefined as necessary for the functioning of the EMS throughout this manual andsummarized by job title in Appendix A. Specific responsibilities at the staff level willgenerally be defined at the Regional/Departmental level.

RECORDS• delegation of tasks/responsibility (where applicable)




17

Figure 3.1 Environmental Management Structure – Generation

Executive VPGeneration

KBU Managers Regional GeneralManagers

Department Managers

Environmental &Social Issues

Managers (ESIM)

• Peace River Generation• Coastal Generation• Columbia River Generation• Operations & Energy

Purchasing• Dam Safety• HR/Communications• Business Development• Controller’s Office• Sustainability &

Aboriginal Relations

Environmental Management Structure –Generation

Generation Employees

Environmental &Social Issues

Manager (ESIM)

Delegation ofresponsibility

PlantManagers




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3.2 TRAINING, AWARENESS AND COMPETENCE


PURPOSETo ensure that employees whose work may create a significant impact on theenvironment are appropriately trained, aware and competent to perform their duties inconformance with applicable environmental policies and procedures.

PROCEDURE1. Define Training Needs

The ESIMs and Department/Plant Managers, in consultation with theEnvironmental Education Coordinator, will assess the environmental competencyand training needs of each job function in their area of responsibility.

EMS Work Instruction 3.2 can be used to assess environmental competency andtraining needs.

Environmental Education Coordinator will develop environmental trainingprograms for job functions in the Environmental Training Matrix for Generation (seehttp://w3/g/environment/ppa/matrix.xls) and ensure these training programs areavailable and kept up-to-date.

2. Plan Training Department/Plant Managers will develop an annual training plan for employeesbased on the Environmental Training Matrix and the individual training needs of eachemployee.

Environmental training requirements identified by a needs assessment can beachieved through formal training programs, on-the-job training, personal study (CD-ROM training), etc.

Managers will annually (during the budgeting process) identify formal trainingrequirements with the Environmental Education Coordinator. EmployeeDevelopment Plans should be taken into consideration.

3. Deliver and Record TrainingDepartment/Plant Managers will ensure that training is completed according to theirannual training plan and the records of formal training are entered into PeopleSoft.

http://w3/g/environment/ppa/matrix.xls




19

4. Evaluate the Effectiveness of Training The effectiveness of training and the environmental competency of employees willbe evaluated through the auditing process (per EMS Procedure: EMS andCompliance Audits 4.4).

5. New Employee OrientationDepartment /Plant Managers will ensure that environmental orientation is providedto new employees (new hires, rehires, transfers) so that they have the requiredenvironmental competency to perform the assigned task (see EnvironmentalOrientation Training checklist (add url) and local orientation guides).

RECORDS• completed New Employee Environmental Orientation Checklists• annual Training Plans for each department• training records

CROSS-REFERENCE• EMS and Compliance Audits procedure (4.4)• Environmental Training Matrix – Generation

http://w3/td/environment/ems_eot.html

http://w3/td/environment/ems_eot.html




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Needs Assessment – Work Instruction 3.2

IntroductionAccording to EMS Procedure 3.2, Training, Awareness and Competence, theEnvironmental Education Coordinator will assess the education and training needs ofeach job function annually (prior to each management review).

Needs Assessment ProcessNeeds assessment is a process of gap analysis. This is comprised of four distinctoperations:

1. Measure the current state of skills, knowledge and abilities.2. Measure the required level of skills, knowledge and abilities.3. Identify needs by measuring the gap between the current state and the

required levels.4. Prioritize the needs.

1. Measure the Current State of Skills, Knowledge and AbilitiesThe measurement of the current state of skills, knowledge and abilities is based onthese aspects:

• the results of previous needs assessments• the results of prior monitoring• review and evaluation of current training offerings• results of skills and knowledge reviews

Review the results of previous needs assessments

Needs assessments identify a larger body of need than can ever be immediatelyaddressed within the constraints of available resources. The review of previousneeds assessments is performed to identify unresolved needs and ensure thatoutstanding issues are re-evaluated in light of current priorities.

Review the results of prior monitoring

The results of prior monitoring include, but are not limited to, EMS audit findings,regulatory compliance checks, non-conformance reports and management reviews.

Review of current training offerings

This portion of the process is managed through a review of current training offerings.This review includes evaluating the effectiveness of the programs and examining thecontent covered by the programs. Input gathered from personal interviews assistswith the evaluation of the effectiveness of current initiatives.




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Skills and Knowledge Review

Personal interviews (individual or small group) are used to evaluate current levels ofknowledge and ability. The interview also provides an opportunity for gatheringinformation on perceived training needs and to evaluate the effectiveness of currentand past training initiatives.

2. Measure the Required Level of Skills, Knowledge and AbilitiesPersonal interviews (individual and small group) are used to complete the followingNeeds Assessment Chart, specifically the Required Skills (best practices) andResources sections, for each job function in Generation.

3. Identify Needs by Measuring the Gap Between the Current State and theRequired LevelsAll data gathered to this point is reviewed in order to:

• Identify the gaps between the current state and the required state ofknowledge and skills. These gaps form one part of the needs to beaddressed; those identified in the interviews (perceived needs) form theother.

• Identify opportunities to satisfy needs using existing programs (may requirepromoting the awareness of existing education opportunities) and updateEnvironmental Training Matrix.

• Identify if the outstanding needs can be resolved through training andeducation.

4. Prioritize the Needs IdentifiedOnce the current needs that can be addressed through training and/or educationare identified, the last portion of the process is to prioritize those needs.

Prioritization guidelines:A. Support of existing/training programs (reviews, refreshers, updates)B. Redesign existing training/education programs (programs originally targeted

to one audience redesigned to be applicable to another)C. New programs with legislated requirementsD. New programs supporting strategic initiatives or new policiesE. New programs that address the greatest risk

F. New programs that address the largest audience




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NEEDS ASSESSMENT CHART

JOB FUNCTION (check one)

Administrative PositionsApparatus TechsCivil TechsContractorsEngineering TechsGeneral Trades

Human ResourcesManagerial StaffMtl Handlers/StorekeepersMechanicsOperators

Protection TechsRM PlannersSenior EngineersSteam OperatorsTelecontrol TechsTour Guides

ACTIVITY ASPECTREQUIREDSKILLS/BESTPRACTICES

RESOURCESCERTIFICATIONNEEDED

LEGALREQUIRMT’S NOTES*

*can include comments on perceived needs and past training initiatives




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3.3 INTERNAL COMMUNICATION AND REPORTING


PURPOSETo ensure effective communication and reporting among all the levels of Generation onthe elements of environmental management.

PROCEDURE1. Routine Environmental Communication

All Generation Employees will conduct communications regarding the environmentalaspects of their work using the telephone, intranet sites, e-mail, verbal discussions,pre-jobs, tailboards, notice boards and other tools (e.g., internal newsletters, memos,etc.), and through management and staff meetings.

2. Suggestions for ImprovementEmployees are encouraged to make suggestions [via e-mail, in person, at staffmeetings, Part 1 of the Process Improvement (PI) form, etc.] to help Generationcontinuously improve its environmental performance. The Department Manager isresponsible for ensuring that opportunities for suggestions are documented on PIForms (see Figure 3.3) to ensure suggestions are appropriately acted upon. TheDepartment Manager will ensure that the originator is informed of the outcome.

Assistance, as required, can be obtained from Sustainability and AboriginalRelations.

3. Environmental Incident Reporting (EIR)Employees must immediately report environmental incidents to the supervisor ormanager at the site of the incident. The supervisor or manager will ensure that theEIR is completed and distributed appropriately (per EIR Standardhttp://edmssappp1/env_incident_rpt/).

Manager, Strategic Issues, Sustainability and Aboriginal Relations ensures thatEIRs are evaluated to identify incidents that contribute to the ECM environmentalperformance indicator.

4. Operating RecordThe Operating Record is an electronic Exchange (Outlook) address (OperatingRecord), available for Employees to record information related to hydroelectricfacility operations, that has the potential to affect operational aspects and impacts.The Exchange address is managed by ESIM, Operations and Energy Purchasing,who tracks and evaluates the information recorded on a regular basis. Sensitive orcritical environmental issues identified via the Operating Record are summarized forreview by the Operations and Energy Purchasing Management Committee to provideguidance where required. The Operating Record assists the Manager, Operations




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and Energy Purchasing in maintaining the Commercial Resource Optimization(CRO) decision process.

Refer to Operating Record Guidelines for more information.

5. Quarterly Environmental ReportingSustainability and Aboriginal Relations produces a Quarterly Environmental Report(QER) to meet the requirements of the Corporate EMS and to review environmentalperformance of Generation Lines of Business. The following information must beincluded in the QER:

• Environmental Incidents• Environmental Indicators (Environmental Compliance Measure – ECM)• Operational Environmental Reviews (Compliance Audits)• EMS Audits (completion of)• Responses to Environmental Regulation• Strategic Environmental Objectives• Environmental Expenditures

Department Managers must submit requested information by the end of eachquarter to Manager, Strategic Issues, Sustainability and Aboriginal Relations.

The Manager, Sustainability and Aboriginal Relations ensures that theinformation is compiled from the departmental reports into a Generation level QERfor submission to the GMC and VP, Corporate Sustainability.

RECORDS• record of environmental communication within department• Environmental Incident Report database (maintained by BC Hydro )• Operating Record• Quarterly Environmental Report (Generation)

CROSS-REFERENCE• Environmental Incident Reporting http://edmssappp1/env_incident_rpt/• Non-Conformance Corrective and Preventive Action – Procedure 4.2




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Figure 3.3 Process Improvement Form

Part 1 (To be completed by any employee, contractor, or supplier)Description of non-conformance or opportunity for improvement:

Immediate corrective or investigative action taken:

Who discovered non-conformance or opportunity for improvement?

Contact Name: Date:

Environmental Incident Report Initiated? No Yes Identifier #:

Note: Respond only to validated complaints for non-conformances with external parties

Part 2

Received by Immediate Supervisor (Name): Date:Forwarded to ESIM (date): MOS (date): GenEnv Mgr (date): Other (date):Major non-conformance? No: Yes:Root cause of non-conformance:

Corrective & Preventive Action Plan (CAP):

Person responsible for implementation of CAP:Date corrective/preventive action is to be completed:

CAP Completed:Sign-off by Responsible Manager: Date:

Route completed forms to Sustainability & Aboriginal Relations (Strategic IssuesManager), ESIM and local PI file.




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3.4 EXTERNAL COMMUNICATION


PURPOSEThis procedure is used to respond to, track and document communications from thepublic on Generation’s environmental aspects and impacts or the Generation EMS. Theinformation will be used to facilitate the consideration of public concerns during EMSreviews and planning.

“The public” includes representatives of government agencies, non-governmentorganizations, and/or other interested parties or individuals.

Communications can include relevant complaints, inquiries or other comments onGeneration’s environmental aspects and impacts or EMS. They may come from sourcessuch as phone calls (direct or forwarded by ABS Call Centres or other LoB staff), letters,e-mail, faxes and stakeholder consultations.

PROCEDURE1. All employees are responsible for informing their supervisors/managers of

communications from the public related to environmental aspects and impacts or theEMS.

2. Department/Plant Managers must ensure all relevant external environmentalcommunication is documented, including the date of the communication(s), whospoke to whom, what was discussed and what action was taken.

Relevant communication can be documented using a log-book, an appropriatehard-copy form or any tool that is appropriate to existing procedures in theDepartment/Plant.

Given the complex nature and variety of communications received from externalparties, it is ultimately each Department/Plant Manager’s (or their delegate’s)professional judgment that will determine if a communication is relevant andrequires documentation. In making a judgment, the following criteria should beconsidered:

• Is it related to Generation’s activities with existing or potential impact onthe environment? or

• Is it related to Generation’s plans and programs with environmentalcontext?

3. Department/Plant Managers must ensure that the communication records (thedocumentation of the relevant communication) are filed according to the RecordsManagement procedure.

4. Department/Plant Managers must ensure that relevant external communication intheir department/plant is addressed in consultation with Corporate




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Communications/Public Affairs and summarized for Generation’s AnnualManagement Review meeting.

RECORDS• record of communication

CROSS-REFERENCE• Internal Communication and Reporting procedure (3.3)• Records Management procedure (4.3)• Management Review procedure (5.1)• Corporate EMS: External Communication procedure




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3.5 DOCUMENTATION AND DOCUMENT CONTROL


PURPOSEGeneration will use this procedure to control all documents1 required by the GenerationEMS to ensure that:

• they are listed in the document control register• they are periodically reviewed and revised as necessary and approved for

adequacy by authorized Generation personnel• current versions of documents are available and listed at all locations where

activities essential to the effective functioning of the Generation EMS areperformed

• obsolete documents are promptly removed from all points of issue and points ofuse

• any obsolete documents retained for legal or knowledge preservation purposesare appropriately identified

This procedure attempts to ensure that controlled documents are not altered, amendedor distributed without authorization, and that all controlled documents are regularlyreviewed and are up-to-date.

PROCEDURE1. The Manager, Sustainability and Aboriginal Relations will ensure that the

Generation EMS Document Control Register (see Table 3.5) is maintained and thatother documents required by the Generation EMS (e.g., Corporate documents andplant documents) are identified.

2. The person/group listed in the “Reviewed By” column of the Generation EMSDocument Control Register will review and revise (if necessary) all documentsrequired by the Generation EMS, according to the specified review frequency foreach document. Any changes to a controlled document will result in a new versionclearly differentiated from the original by date of revision.

3. The person/group listed in the “Distributed By” column of the Generation EMSDocument Control Register will ensure that all documents required by the EMS areavailable and obsolete documents are removed. If an obsolete document is to beretained for legal/knowledge purposes, it must be filed in a separate location fromthe current version.

1 A document is composed of dynamic information, often providing instruction on how to carry out an activity. See Table 3.5 for examples.




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4. Each Plant/Department Manager must maintain a Local EMS Document ControlRegister for their department to list the specific documents (spill response plansemergency response plans, local operating orders, spill response cards, etc.).

The Local EMS Document Control Register must contain the following:• Title of document (description is optional)• Current version in use• Responsibilities for reviewing, updating, approving as necessary• Responsibilities for ensuring only current versions are available (i.e.,

replacing obsolete documents)

RECORDS• Local Document Control Register• Generation EMS Document Control Register (Table 3.5)

CROSS-REFERENCE• Operational Controls procedure (3.6)• Corporate Document Control Register for documents maintained by Corporate

Generation Environmental Management Manual – Draft 2



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Table 3.5. Generation EMS Document Control Register

Document Developed By Reviewed By Approved By Distributed By Location Reviewfrequency

Generation EnvironmentalManagement SystemManual & associatedforms

Manager,Sustainability &AboriginalRelations –Strategic Issues

ESIMs, Manager,Sustainability &Aboriginal Relations

Executive VP,Generation

Manager,Sustainability &Aboriginal Relations– Strategic Issues

Intranet Annually

EMS Aspects Database Manager,Sustainability &AboriginalRelations –Strategic Issues

ESIMs, Sustainability& AboriginalRelations Managers

Manager,Sustainability &AboriginalRelations


Manager,Sustainability &AboriginalRelations –Strategic Issues

Annually

Environmental Practices GenerationSustainabilityManagers

ESIMs, Sustainability& AboriginalRelations Managers


Sustainability &Aboriginal RelationsManagers

Intranet As required

Operational Controls (e.g.,LOOs, SOOs, Oil SpillResponse Plans,Recreation OpportunitiesInventory Manuals, etc.)

As defined byresponsiblemanager (seeLocal DocumentControl Register)

As defined byresponsible manager(see Local DocumentControl Register)

As defined byresponsiblemanager (seeLocal DocumentControl Register)

As defined byresponsible manager(see Local DocumentControl Register)

As defined byresponsiblemanager (seeLocal DocumentControlRegister)

As required

Generation Audit Program Manager,Sustainability &AboriginalRelations –Strategic Issues

ESIMs, Manager,Sustainability &Aboriginal Relations



Intranet Annually

Environmental TrainingMatrix – Generation

EnvironmentalEducationCoordinator

ESIMS, Sustainability& AboriginalRelations Managers


EnvironmentalEducationCoordinator

Intranet Annually

Generation EmergencyPlans

PSEP ProgramManager

Program Engineer,Generation SafetyManager

ProgramEngineer,Generation Safety

EmergencyPreparedness PlanAdministrator

Per distributionlist

Every 6months

Generation Environmental Management Manual – Draft 2



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Document Developed By Reviewed By Approved By Distributed By Location Reviewfrequency

Manager




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3.6 OPERATIONAL CONTROLS


PURPOSEThis procedure is used to establish and maintain effective operational control1procedures to ensure that the environmental policy, objectives, targets and legal or otherrequirements can be met.

PROCEDURE1. Establish and Implement Operational Controls

Plant/Department Managers are responsible for the establishment of OperationalControls for all Generation’s activities and facilities that are related to:

• significant environmental aspects/impacts• non-significant aspects/impacts that could become significant in the absence

of an operational control

2. Communication of Operational ControlsDepartment/Plant Managers must ensure that approved operational controls arecommunicated and available to employees and contractors.

This can be achieved through on-the-job training, supervision, regular tailboardmeetings, etc.

3. Review of Operational Control ProceduresOperational control procedures must be reviewed for effectiveness at pre-determinedtime intervals (responsibility and frequency is defined in the Generation and LocalEMS Document Control Registers – EMS Procedure: Documentation and DocumentControl procedure 3.5) and revised as necessary.

All of the following should be taken into account when assessing the ongoingsuitability of the operational controls:

• incidents and non-conformances • public concerns• employee feedback• new activities/services on site• new legislation/changes to legislation• new environmental aspects• performance of the operational control

1 Operational controls are documented operating procedures, equipment and specific controls that are designed and intended toavoid or minimize environmental impacts. These include: written procedures, such as Environmental Practices, Best ManagementPractices, Waste Management Standards, Local and System Operating Orders and maintenance instructions; and equipment, suchas oil/water separators, spill kits, emission controls, monitoring systems, computerized control systems, etc.




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4. Maintenance of Operational Control EquipmentKBU Managers will ensure that physical Operational Controls (i.e., equipment andcomputerized controls) related to the area’s significant aspects and impacts aremaintained through the computerized maintenance management system (Passport).

RECORDS• revisions to operational controls• Generation and Local EMS Document Control Registers• Passport Maintenance Management System Records

CROSS-REFERENCE• Environmental Aspects and Impacts procedure (2.1)• Setting Objectives and Targets procedure (2.3)• Legal and other Requirements procedure (2.2)




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3.7 EMERGENCY PREPAREDNESS AND RESPONSE


PURPOSEThis procedure is to ensure that Generation has emergency plans that:

• prevent or mitigate the environmental impacts of emergencies1 or accidents,• are reviewed and revised to ensure they are up-to-date, and• are tested periodically to ensure effectiveness.

PROCEDURE1. Maintenance of Facility-Level Emergency Plans

Generation maintains emergency plans at each facility and/or generating area in theform of Power Supply Emergency Plans (PSEPs), Spill Response Plans and/or LocalOperating Orders (LOOs). Responsibilities for the maintenance of these emergencyplans are contained within the Local EMS Document Control Register.

2. Review of Environmental Components of Emergency Plans Regional General Managers will ensure that the environmental components of allemergency plans, spill response plans and LOOs are reviewed and revised, perLocal EMS Document Control Register or following any accident, and will ensure thatthe plan is appropriate and relevant to current significant environmental aspects.

3. Reporting Emergencies Refer to the individual emergency document for reporting emergencies withenvironmental consequences and EMS Procedure 3.3: Internal Communication andReporting procedure, Environmental Incident Reporting.

4. Investigating EmergenciesRefer to EMS Procedure 4.2: Non-conformance, Corrective and Preventive Action forinvestigating emergencies with environmental consequences.

5. Testing of Emergency ProceduresRegional General Managers will ensure emergency procedures are tested asspecified in the emergency response plans, where feasible. Records of tests must beretained.

1 An emergency is a large-scale event involving company facilities or operations that may endanger life, property, the environment orthat may seriously affect normal Plant operations. It requires immediate actions outside the scope of Standard Operating Procedures.




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RECORDS• annual review of emergency plans• records of tests of emergency plans• Environmental Incident Reports

CROSS-REFERENCE• Local EMS Document Control Register• Records Management procedure (4.3)• Internal Communication and Reporting procedure (3.3)• Non-conformances, corrective and preventive action procedure (4.2)




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3.8 CONTRACTOR MANAGEMENT


PURPOSETo ensure that environmental impacts associated with contract work are identified andminimized, and that applicable environmental controls and performance standards arecommunicated to contractors.

These procedures apply to all work involving internal and external contractors, contractoremployees, and subcontractors, including BC Hydro ’s Construction Business Unit(CBU) and BC Hydro employees working at sites other than their normal work location.

PROCEDURE.

1. Plant/Department/Project Managers, in consultation with an EnvironmentalRepresentative will follow the environmental requirements for managing capital andOMA work when working with contractors. See Figure 3.8 and the following websitefor links to checklists and guidelines:http://w3.bchydro.bc.ca/sustainability/tools/bmp/work_admin/contract/pdf/pfc.pdf

2. Major non-conformances are addressed as described in EMS procedure 4.2: Non-conformance, Corrective and Preventive Action.

3. Maintain records of all contractor management activities in the project file.

RECORDS• environmental screening checklist• environmental management plans (where required)• record of communication with contractors (for example, Contractor Environmental

Orientation Record)• record of monitoring environmental performance of contractors (for example,

Contractor Monitoring and Inspection Checklist)• feedback of contractors’ overall performance in CPIS (Contractor Performance

Information System)

CROSS-REFERENCE• Non-conformance, Corrective and Preventive Procedure (4.2)• BC Hydro Best Management Practices,

http://w3.bchydro.bc.ca/sustainability/tools/bmp/work_admin/contract/pdf/pfc.pdf




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Figure 3.8 Managing the Environmental Requirements of Capital and OMA Work




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4.1 MONITORING AND MEASUREMENT


PURPOSETo monitor and measure, on a regular basis, the key characteristics of Generationactivities that can have a significant impact on the environment.

PROCEDURE1. Plant/Department Managers must ensure that, within their area of responsibility, all

environmental monitoring activities related to significant aspects and impacts areestablished and documented, and that monitoring records are maintained.

These records should include the following information:• parameter monitored• frequency• responsibility• file location of monitoring records

2. Plant/Department Managers will ensure that monitoring activities within their areaof responsibility are reviewed annually. This is done to ensure that these activitiesare adequate to measure the key characteristics of Generation’s significant aspectsand impacts.

3. Plant/Department Managers will ensure that equipment used to monitor significantaspects is calibrated and that calibration records are maintained. This may becarried out through the computerized maintenance management system (Passport)or by other means.

For example, equipment not covered by Passport should have a calibration programdetailing frequency of calibration, management of records and responsibility forconducting calibrations.

RECORDS• monitoring activity records• calibration records

CROSS-REFERENCE• Environmental Aspects and Impacts procedure (2.1)




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4.2 NON-CONFORMANCE, CORRECTIVE AND PREVENTIVE ACTION


PURPOSETo ensure that Generation can identify, respond to and correct non-conformances, andminimize the likelihood of future non-conformances. This will reduce the potential liabilitywith respect to legal and other requirements, and provide the basis for continuousimprovement of environmental performance and the EMS.

Some examples of non-conformances include: 1) environmental incidents (e.g.,unauthorized operations or spills), 2) equipment failures that impact the environment, 3)record deficiencies, 4) not following documented procedures and, 5) operational controldeficiencies.

PROCEDURE1. Identification of Non-Conformances and opportunities for improvement

Non-conformances will be identified by all Generation Employees through:• EMS audits• Operational Environmental Reviews (OERs)• management reviews• operational inspections and maintenance activities• incidents and near-incidents, including emergency situations• relevant internal and external complaints• monitoring and measurement• direct observations• employee suggestions

2. Determining Major or Minor Non-ConformancesThe responsible manager, in consultation with Environmental Specialists, will decideif the non-conformance is major or minor, based on criteria outlined in the box below.

Major Non-Conformance

A non-conformance is major if one or more of the following apply:• can cause a significant impact on the environment• can cause a regulatory investigation and/or legal action against BC Hydro (e.g.,

regulatory violation)• failure in a core element of the Environmental Management System

Non-conformances that are not major (as defined by the criteria above) will be deemedminor.




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3. Response to Major Non-ConformancesStep 1. Any employee, contractor or supplier who discovers a major non-conformance must take immediate action to prevent further impact on theenvironment. This immediate action may include, but is not limited to, the following:

• shutting down an activity• removing equipment from service• notifying the responsible manager or BC Hydro contact of the non-

conformance

Step 2. The responsible manager must fill in an Environmental Incident Report(EIR) if required and other documentation relevant to the area.

Step 3. The responsible manager, in conjunction with the ESIM will initiatecorrective and preventive action and a root cause analysis. Results will bedocumented in the original Environmental Incident Report or the ProcessImprovement (PI) Form (see Figure 3.3).

4. Response to Minor Non-Conformances and need for process improvementThe responsible manager may need to fill out an Environmental Incident Report(EIR) and other documentation relevant to the area if deemed necessary. He/she willthen decide on what corrective and preventive action (e.g., process improvement) isrequired, and document this in the original EIR or on a PI form.

5. Follow-up and CommunicationThe Plant/Department Manager will ensure that all approved corrective andpreventive actions are implemented and amend operational controls as necessary.

The Plant/Department Manager will communicate results of system improvementsand Corrective Action Plans to relevant employees to demonstrate follow-up andcontinuous improvement of the EMS.

RECORDS• Environmental Incident Reports (EIRs)• Process Improvement (PI) Forms (see Figure 3.3)• Corrective Action Plans (if required)• documentation of root cause analysis (if required)

CROSS-REFERENCE• Internal Communication and Reporting procedure (3.3)• Emergency Preparedness and Response procedure (3.7)• Records Management procedure (4.4)• Root Cause Analysis guide (to be developed)




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4.3 RECORDS MANAGEMENT


PURPOSETo properly identify, maintain and dispose of environmental records1. These recordsserve as evidence of a functioning environmental management system and Generation’senvironmental performance.

PROCEDURE1. The requirements for generating records are detailed in each procedure in this EMS

manual and are summarized in the Generation EMS Records Summary Table 4.3.These records will be maintained in the plant/department file systems.

2. Plant/Department/Project Managers must ensure that all environmental records(as required by the EMS procedures) are effectively filed so that they are retrievableand protected against damage or loss.

3. Plant/Department Managers will develop a Departmental Records Control List thatidentifies all environmental management records kept in their file system. The list(see example below) must include, at a minimum, the following information:

• name of the record• location (area/department file number)• responsibility for maintaining the record• retention time

Example of a section of a Departmental Records Control List

Record File location Responsibility GenerationFrequency

Retention Time

Quarterlyenvironmental report

EMS 200.4 ESIM Quarterly Permanent

Annual aspects review EMS 200.1 ESIM Annual Permanent

Permits, licenses andapprovals

EMS 200.6 ESIM As required Permanent

EMP EMS 200.5 Project Manager As required Permanent

Job Tailboards H&S 150.2 Project Manager As required Permanent

1 A record is static information that provides evidence of the completion, or lack of completion, of an activity, such as an

environmental incident report, training course, etc.




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RECORDS• departmental Records Control List

CROSS-REFERENCE• all Generation EMS procedures contain reference to required records

Table 4.3 Generation EMS Records Summary

REQUIRED RECORD EMS Procedure Generated andmaintained by

GenerationFrequency

RETENTIONTIME

Policy communication from VP tostaff

1.1 Implementation of EnvironmentalPolicy

VP, Generation Annually 5 years

Environmental Aspects Review 2.1 Environmental Aspects andImpacts

ESIM Annually 5 years

EMS Aspects Database 2.1 Environmental Aspects andImpacts

2.2 Legal and Other Requirements

EMS AspectsDatabaseAdministrator

As required 5 years

New and changed environmentallegislation

2.2 Legal and Other Requirements EnvironmentalRegulatory RelationsCoordinator

Semi-annually 10 years

Generation objectives and targets 2.3 Setting Objectives and Targets Manager,Sustainability andAboriginal Relations

Annually 10 years

Region/department objectives andtargets

2.3 Setting Objectives and Targets ESIMs Annually 5 years

Region/department environmentalprograms

2.4 Environmental Programs ESIMs Annually 5 years

Delegation of EMStasks/responsibility

3.1 Structure and Responsibility KBU and RegionalGeneral Managers

As required 2 years

Region/department training plans 3.2 Training, Awareness andCompetence

Plant/DepartmentManager

Annually 2 years

Training records 3.2 Training, Awareness andCompetence

Managers As required Permanent

Draft - new employeeenvironmental orientation trainingchecklist

3.2 Training, Awareness andCompetence

Managers As required 5 years

Quarterly Environmental Reports –Generation

3.3 Internal Communication andReporting

Manager, StrategicIssues, Sustainabilityand AboriginalRelations

Quarterly 5 years




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GenerationFrequency

RETENTIONTIME

Environmental Incident Reports 3.3 Internal Communication andReporting

3.7 Emergency Preparedness andResponse

4.2 Non-conformance, Corrective andPreventive Action

Plant/DepartmentManagers

As required Permanent

General region/departmentenvironmental communications(employee suggestions, tailboards,meetings, etc.)

3.3 Internal Communication andReporting


As required 5 years

Public Affairs and externalcommunications (e.g., ECRT)

3.4 External Communication Plant/DepartmentManagers

As required 5 years

Generation and local DocumentControl Registers

3.5 Documentation and DocumentControl


As required 2 years

Operational Control Revisions 3.6 Operational Controls Plant/DepartmentManagers

As required 5 years

Records of test of emergencyplans

3.7 Emergency Preparedness andResponse


As required 5 years

Emergency Plan Reviews 3.7 Emergency Preparedness andResponse


Annually 5 years

Record of communications withcontractors in project files (e.g.,contractor orientation, tailboards,inspections)

3.8 Contractor Management Project Managers As required 2 years

Monitoring activity records 4.1 Monitoring and Measurement Plant/DepartmentManagers

As required Permanent

Instrument, equipment, computerelectronics calibration andmaintenance

4.1 Monitoring and Measurement Plant/DepartmentManagers

As required 5 years

Process Improvement (PI) Forms4.2 Non-conformance Corrective andPreventive Action ESIM As required 5 years

Corrective Action Plans4.2 Non-conformance Corrective andPreventive Action

4.4 EMS and OER Audits

ESIM

ESIM

As required 5 years

Permanent

Records Control List 4.3 Records Management Plant/DepartmentManagers

As required 5 years

Generation’s Four-year AuditProgram

4.4 EMS and OperationalEnvironmental Reviews

Manager, StrategicIssues, Sustainabilityand AboriginalRelations

4 years Permanent

EMS and OER Audit Reports 4.4 EMS and OperationalEnvironmental Reviews

Manager, StrategicIssues, Sustainabilityand Aboriginal

Annually Permanent




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GenerationFrequency

RETENTIONTIME

Relations

Management Review Meetings 5.1 Management Review Manager, StrategicIssues, Sustainabilityand AboriginalRelations

Annually Permanent




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4.4 EMS AUDITS and OPERATIONAL ENVIRONMENTAL REVIEWS


PURPOSEThis procedure will be used to:

• determine if the Generation EMS conforms to the requirements of ISO 14001;• assess whether the EMS is being properly implemented and maintained;• periodically evaluate compliance with environmental legislation and regulations

and assess the related operational and maintenance practices; and• provide results of the audit plan for the Annual Generation EMS Management

Review.

PROCEDURE1. Develop Audit PlansThe Manager, Sustainability and Aboriginal Relations, in consultation with ESIMs orequivalent, prepares a four-year audit plan as well as a specific annual plan andpresents these plans to Generation Management Committee (GMC) for approval.

This plan must include both EMS Audits and Operational Environmental Reviews(OERs). ISO 14001-registered components of Generation’s EMS will require annualaudits as a condition of registration.

2. Conduct AuditsThe Plant/Department Manager, in consultation with the ESIM, is responsible forensuring that all EMS audits and OERs listed in the audit plan are carried out andconducted in accordance with standard practices [see BC Hydro Environmental AuditProgram (BCHEAP) guidelines, ISO 19011]. Strategic Issues, Sustainability andAboriginal Relations will provide assistance and advice where necessary.

3. Corrective Action PlanThe Manager of the business unit audited must ensure that a Corrective Action Planis prepared based on the findings and recommendations of the EMS Audit or OER. TheCorrective Action Plan must include the following:

• action(s) to be taken to address the findings• responsibility for each action• target completion date of each action

Corrective Action Plans must be prepared within 60 days of receiving the final auditreport.




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4. Communication and Follow-up The Manager, Sustainability and Aboriginal Relations will oversee the EMS auditplans for Generation to ensure the objectives of the program are met.

Reporting on all Corrective Action Plans will occur through the quarterly reportingprocess, following EMS Procedure: Internal Communication and Reporting 3.3 and EMSProcedure: Management Review 5.1.

RECORDS• EMS Audit reports • Operational Environmental Review (OER) reports• Generation’s Annual and Four-Year Audit Plans• Corrective Action Plans

CROSS-REFERENCE• Non-conformance, Corrective and Preventive Action procedure (4.2)• Internal Communication and Reporting procedure (3.3)• Management Review procedure (5.1)• BC Hydro Environmental Audit Program (BCHEAP)




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5.1 MANAGEMENT REVIEW


PURPOSEGeneration will use this procedure to:

• review the overall effectiveness, suitability and adequacy of the EMS relative toGeneration business practices (e.g., audit results), BC Hydro policy, changingcircumstances (e.g., laws, new technology), and the views of interested parties;and

• review actual environmental performance and determine how well thecommitments to the prevention of pollution and continuous improvement arebeing met.

PROCEDURE1. Plant/Department Managers (representatives) with KBU Managers and Executive

VP, Generation must conduct an Annual Management Review prior to the annualbusiness planning and budgeting process to ensure that appropriate resourceallocation decisions can be made with respect to desired levels of environmentalperformance (see Figure 2.1).

2. The Manager, Sustainability and Aboriginal Relations will schedule and chair themeeting, prepare the agenda and ensure meeting minutes are recorded. (See boxbelow for possible agenda items.)

Annual Management Review Agenda

Review performance results• review status of performance measures (e.g., Generation Sustainability Scorecard)• review progress in meeting environmental objectives, targets and programs

Evaluate Generation’s EMS• review Audit Plan results and associated Corrective Action Plans• assess adequacy of environmental policy• assess process improvement actions

Changes to Generation’s Operating Environment• assess changes to applicable legislation and regulations• assess external stakeholder feedback• assess changes to strategic direction

Decisions on Future Direction• make recommendations regarding setting new environmental objectives and targets• decide on other environmental actions or initiatives as appropriate for continuous

improvement




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RECORDS• Management Meeting Minutes – Board of Directors, GMC, EMC, EMS Management

Reviews, etc.• Quarterly Environmental Reports

CROSS-REFERENCE• Implementation of Environmental Policy procedure (1.1)• Legal and Other Requirements procedure (2.2)• Setting Objectives and Targets procedure (2.3)• Environmental Programs procedure (2.4)• Internal Communication and Reporting procedure (3.3)• External Communication procedure (3.4)• Non-Conformance, Corrective and Preventive Action (4.3)• EMS Audits and OERs procedure (4.4)




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APPENDIX A: EMS ROLES & RESPONSIBILITIES

KBU MANAGERS

General• understand the EMS and your role in supporting it

• ensure effective implementation of the EMS and continuous improvement inenvironmental performance in your Area

• ensure employees conduct their work within the framework of the EMS andparticipate in its improvement

• provide sufficient resources to maintain an effective EMS

• ensure employees comply with environmental regulations and defined environmentalprocedures (i.e., Environmental Practices, EMS procedures)

Policy1.1 Implementation of Environmental Policy• ensure the policy is adhered to and displayed at appropriate locations at facilities

and offices routinely occupied by Generation employees

Planning2.1 Environmental Aspects and Impacts• ensure that environmental issues (aspects) associated with your responsibilities are

identified and ranked for significance2.2 Legal and Other Requirements• communicate changes to legal and other requirements to staff and managers as

applicable and ensure that the legal and other requirements pertaining to their areaof responsibility are met

2.4 Environmental Programs• ensure that environmental programs are established to achieve environmental

objectives and targets

• ensure that environmental programs are modified to address new or modifiedactivities as required

Implementation and Operation 3.1 Structure and Responsibility• ensure that the EMS is implemented throughout your area of responsibility, including

ensuring that all requirements are met and maintained

3.6 Operational Controls• ensure that physical operational controls (i.e. equipment and computerized controls)

related to the area’s significant aspects and impacts are maintained through thecomputerized maintenance management system (Passport)

3.7 Emergency Preparedness and Response




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• ensure that the environmental components of all emergency plans, spill responseplans and LOOs are reviewed and revised per Local EMS Document ControlRegister or following any accident

• ensure that the plan is appropriate and relevant to current significant environmentalaspects

• ensure that emergency procedures are tested as specified in the emergencyresponse plans, where feasible, and ensure that test records are filed

Checking and Corrective Action

4.2 Non-conformance, Corrective and Preventive Action• ensure that non-conformances within your area of responsibility are identified and

addressed4.4 EMS Audits and Operational Environmental Reviews• ensure that a Corrective Action Plan is prepared within 60 days of receiving the final

audit report, based on the findings and recommendations of the audit

5.1 Management Review• conduct annual Management Review with KBU Managers and VP Generation prior

to annual business planning and budgeting process




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PLANT MANAGERS


• ensure effective implementation of the EMS and continuous improvement inenvironmental performance in your area




Planning2.1 Environmental Aspects and Impacts• ensure that all projects and new work are assessed for potential environmental

aspects, impacts and regulatory requirements Implementation and Operation 3.1 Structure and Responsibility• ensure that the EMS is implemented throughout your area of responsibility, including


3.2 Training, Awareness and Competence• assess the environmental competency and training needs of each job function in

your area of responsibility, in consultation with the Environmental EducationCoordinator

• develop an annual training plan for employees based on the Environmental TrainingMatrix and the individual training needs of each employee

• ensure that environmental orientation is provided to new employees

• ensure that training is completed as set out in annual training plan and that trainingrecords are entered into PeopleSoft

3.3 Internal Communication and Reporting• ensure that all reported incidents are documented in the Environmental Incident

Reporting (EIR) system and distributed appropriately3.4 External Communication• ensure that all relevant external environmental communication is documented

• ensure that a communication record is filed and that relevant external feedback isaddressed in consultation with Corporate Communications/Public Affairs andsummarized for Generation’s Annual Management Review meeting

3.5 Documentation and Document Control• maintain a Local Document Control Register for your Plant/Department




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3.6 Operational Controls• ensure that operational controls are established for all activities/services that are

related to significant environmental aspects or those that could become significant inthe absence of an operational control

• ensure that approved operational controls are communicated and available toemployees and contractors

• ensure that operational controls are reviewed and updated as necessary (checkDocument Control Registers)

3.7 Emergency Preparedness and Response• ensure that the environmental components of all emergency plans, spill response

plans and LOOs are reviewed and revised per Local EMS Document ControlRegister or following any accident

• ensure that the emergency plan is appropriate and relevant to current significantenvironmental aspects

• ensure that emergency procedures are tested as specified in the emergencyresponse plans, where feasible, and ensure that test records are filed

3.8 Contractor Management• follow the environmental requirements for managing capital and OMA work when

working with contractors. See Figure 3.8• maintain records of all contractor management activities in the project file

Checking and Corrective Action 4.1 Monitoring and Measurement• ensure that environmental monitoring activities related to significant aspects in your

area/department are established and documented and that monitoring records aremaintained

• annually review the monitoring activities to ensure adequacy

• ensure equipment used to monitor significant aspects is calibrated and associatedrecords are maintained

4.2 Non-conformance, Corrective and Preventive Action• ensure that non-conformances within the area of responsibility are appropriately

identified and addressed

• ensure that all corrective and preventive actions are implemented and amendoperational controls as necessary

• communicate results of system improvements and Corrective Action Plans torelevant employees, as necessary

4.3 Records Management• develop a Departmental Records Control List that identifies all environmental

management records kept in the area file system.

• ensure that all environmental records are effectively filed so that they are retrievableand protected against damage or loss




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4.4 EMS Audits and Operational Environmental Reviews• ensuring that all EMS audits and OERs listed in the audit plan are carried out and

conducted in accordance with standard practices, in consultation with ESIM

• ensure that a Corrective Action Plan is prepared within 60 days of receiving the finalaudit report, based on the findings and recommendations of the audit

5.1 Management Review • conduct annual Management Review with KBU Managers and Executive VP,

Generation prior to the annual business planning and budgeting process




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DEPARTMENT MANAGERS


• ensure effective implementation of the EMS and continuous improvement inenvironmental performance in your area




Policy1.1 Implementation of Environmental Policy• periodically solicit feedback from employees on the suitability of the environmental

policy

Planning2.1 Environmental Aspects and Impacts• ensure that new projects are assessed for potential environmental aspects, impacts

and regulatory requirements

2.2 Legal and Other Requirements• ensure that environmental permits, approvals and other local requirements (e.g., by-

laws) pertaining to your department are accessible or hard copies are filedappropriately and kept up-to-date

2.3 Setting Objectives and Targets• set department objectives and targets for the coming fiscal year based on aspect

review and Generation’s Strategic Objectives

• submit department level objectives and targets to Manager, Sustainability andAboriginal Relations prior to the budgeting process

2.4 Environmental Programs• ensure that environmental programs are documented through the budgeting process

and managed through core processes Implementation and Operation 3.1 Structure and Responsibility• ensure that the EMS is implemented throughout your area of responsibility, including





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3.2 Training, Awareness and Competence• assess the environmental competency and training needs of each job function in

your area of responsibility, in consultation with the Environmental EducationCoordinator

• develop an annual training plan for employees based on the Environmental TrainingMatrix and the individual training needs of each employee

• ensure that environmental orientation is provided to new employees

• ensure that training is completed as set out in annual training plan and that trainingrecords are entered into PeopleSoft

3.3 Internal Communication and Reporting• ensure employee suggestions for improvement are discussed and communicated up

or back to the source of the suggestion, as appropriate

• ensure that all reported incidents are documented in the Environmental IncidentReporting (EIR) system and distributed appropriately

• submit requested environmental information for Quarterly Environmental Reportingto Strategic Issues Manager, Generation Sustainability and Aboriginal Relations bythe end of each quarter

3.4 External Communication• ensure that all relevant external environmental communication is documented

• ensure that a communication record is filed and that relevant external feedback isaddressed in consultation with Corporate Communications/Public Affairs andsummarized for Generation’s Annual Management Review meeting

3.5 Documentation and Document Control• maintain a Local Document Control Register for your Department

3.6 Operational Controls• ensure that operational controls are established for all activities/services that are

related to significant environmental aspects or those that could become significant inthe absence of an operational control

• ensure that approved operational controls are communicated and available toemployees and contractors

• ensure that operational controls are reviewed and updated as necessary (checkDocument Control Registers)

3.7 Emergency Preparedness and Response• assist managers with reviewing environmental components of all emergency plans

(e.g., LOO), and/or testing emergency procedures, as required

3.8 Contractor Management• follow the environmental requirements for managing capital and OMA work when

working with contractors. See Figure 3.8• maintain records of all contractor management activities in the project file

http://w3.bchydro.bc.ca/sustainability/tools/bmp/work_admin/contract/extcontractors.shtml







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Checking and Corrective Action4.1 Monitoring and Measurement• ensure that environmental monitoring activities related to significant aspects in your

area/department are established and documented and that monitoring records aremaintained

• annually review the monitoring activities to ensure adequacy

• ensure equipment used to monitor significant aspects is calibrated and associatedrecords are maintained

4.2 Non-conformance, Corrective and Preventive Action• ensure that non-conformances within the area of responsibility are appropriately

identified and addressed

• ensure that all corrective and preventive actions are implemented and amendoperational controls as necessary

• communicate results of system improvements and Corrective Action Plans torelevant employees, as necessary

4.3 Records Management• develop a Records Control Register that identifies all environmental management

records generated in the area/department

• ensure that all environmental records are effectively filed so that they are retrievableand protected against damage or loss

4.4 EMS Audits and Operational Environmental Reviews• ensure that all audits/reviews listed in the audit program are conducted, in

consultation with ESIM

• ensure that a Corrective Action Plan is prepared within 60 days of receiving the finalaudit report, based on the findings and recommendations of the audit

5.1 Management Review • conduct annual Management Review with KBU Managers and Executive VP,

Generation prior to annual business planning and budgeting process




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ENVIRONMENTAL AND SOCIAL ISSUES MANAGERS (ESIMs)

General• provide leadership, direction and coordination on environmental and social activities

as required, for your KBU or Region

• understand the EMS and your role in supporting it

• participate in the development and improvement of the EMS

• manage all environmental issues within the framework of the environmentalmanagement system

Policy1.1 Implementation of Environmental Policy• assist managers with raising awareness, communicating, developing ideas for

improvement, soliciting feedback or applying the policy in their area, as necessary

Planning2.1 Environmental Aspects and Impacts• review and revise aspect ranking for each activity in your area of responsibility using

work instructions 2.1 A-B for the applicable Region/Department on an annual basis

• submit annual aspects modifications no later than September 30 of each year to theEMS Aspects Database Administrator

• forward new or updated aspects to EMS database Administrator, as required

• assist managers with assessing all project and new work for potential environmentalaspects, impacts and regulatory requirements

2.2 Legal and Other Requirements• assist managers in ensuring the environmental permits, approvals and other local

requirements pertaining to the area, are accessible or hard copies are filedappropriately and kept up-to-date

2.3 Setting Objectives and Targets • assist department managers in establishing environmental objectives and targets

2.4 Environmental Programs• assist managers in documenting and managing environmental programs

Implementation and Operation 3.1 Structure and Responsibility• oversee the delivery of Generation EMS requirements in the KBU




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3.2 Training, Awareness and Competence• participate in assessing the environmental competency and training needs of each

job function

• assist managers with developing annual training plans for employees

3.3 Internal Communication and Reporting• assist managers with day-to-day environmental communications

• assist managers with communication requirements, such as employee suggestionsfor improvement, completing Environmental Incident Reports, and area quarterlycommunication requirements

3.4 External Communication• assist managers with documenting and filing all relevant external environmental

communication, where necessary

• assist managers in addressing external feedback

3.5 Documentation and Document Control• assist managers with the development and review of the Local Document Control

Register(s) in their KBU

3.6 Operational Controls• assist managers with establishing operational control for activities/services related to

significant environmental aspects

• assist managers with communicating operational controls and ensuring that they areavailable to employees and contractors

• assist managers with reviewing and revising applicable operational controls, asnecessary (see applicable Local Document Control Register)

3.7 Emergency Preparedness and Response• assist managers with reviewing environmental components of all emergency plans

(e.g., LOO), and/or testing emergency procedures, as required

3.8 Contractor Management• assist managers with evaluating environmental aspects of new work/projects

Checking and Corrective Action4.1 Monitoring and Measurement• assist managers with establishing, documenting and recording environmental

monitoring activities related to significant aspects in their Region/Department

• assist managers with annually reviewing the monitoring activities to ensureadequacy

• assist managers with calibrating and maintaining equipment used to monitorsignificant aspects




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4.2 Non-conformance, Corrective and Preventive Action• assist managers in appropriately identifying and addressing non-conformances, as

required

• assist managers in ensuring that corrective and preventive actions are implemented

• assist managers in communicating results of system improvements and CorrectiveAction Plans

4.3 Records Management• assist managers with developing a Records Control Register for the

area/department, and filing environmental records

4.4 EMS Audits and Operational Environmental Reviews• assist manager with ensuring that all audits/reviews listed in the audit program are

conducted

• assist managers with preparing a Corrective Action Plan based on the findings andrecommendations of the audit

5.1 Management Review • assist the management team to conduct an annual Management Review with KBU

Managers and Executive VP, Generation prior to annual business planning andbudgeting process




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MANAGER, SUSTAINABILITY AND ABORIGINAL RELATIONS(EMS REPRESENTATIVE) General• support BCH vision for environmental performance and sustainable operations

• provide leadership, direction and coordination on environmental management forGeneration

• ensure that the tools and processes for integrating environmental issues into thebusiness planning framework (EMS) are developed, communicated andimplemented

• ensure that EMS is implemented, maintained and continuously improved acrossGeneration

Policy1.1 Implementation of Environmental Policy• obtain feedback from Department Managers on the suitability of the environmental

policy

Planning2.1 Environmental Aspects and Impacts• obtain a summary report of significant aspects and impacts from the EMS

Aspects/Impacts Database Administrator

• ensure that the environmental risks are annually assessed and incorporated into thesetting of Generation’s Strategic Objectives and Performance Measures

2.2 Legal and Other Requirements• ensure that legal and other requirements are tracked in Generation

• through the Regulatory Relations Manager ensure that strategies or actions aredeveloped to address new and /or changed legal or other requirements

• with assistance from the Environmental Regulatory Relations Coordinatorcommunicate changes to legal and other requirements to staff and managers, asapplicable

2.3 Setting Objectives and Targets• ensure environmental strategic objectives and performance measures are developed

for the coming fiscal year(s)

• communicate the new strategic objectives and performance measures to KBUManagers, including Regional General Managers, Operations and EnergyPurchasing and Plant/Department Managers




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Implementation and Operation3.1 Structure and Responsibility• ensure that EMS requirements are established in accordance with the ISO 14001

Standard

• report on the performance of the EMS to the Executive Vice-President, Generation

3.2 Training, Awareness and Competence• through the Environmental Education Coordinator develop environmental training

programs in the Environmental Training Matrix for Generation and ensure thesetraining programs are available and kept up-to-date

• through the Environmental Education Coordinator participate in assessing theenvironmental competency and training needs of each job function

• through the Environmental Education Coordinator assist managers with developingannual training plans for employees

3.3 Internal Communication and Reporting• ensure that quarterly environmental information provided from the

Regions/Departments is compiled into a Generation-level QER for submission to theExecutive VP, Generation and Corporate Sustainability

• through the Manager, Strategic Issues ensure that EIRs are evaluated to identifyincidents that contribute to the ECM environmental performance indicator

3.4 External Communication• compile all relevant external environmental communication for Generation’s Annual

Management Review meeting

3.5 Documentation and Document Control• ensure that the Generation EMS Document Control Register is maintained and that

other documents required by the Generation EMS are identified

Checking and Corrective Action4.4 EMS Audits and Operational Environmental Reviews• prepare an annual and four-year Audit Program, in consultation with ESIMs and

present plans to GMC for approval

• oversee the EMS audit plans for Generation

5.1 Management Review • ensure that an EMS Management Review meeting is conducted annually

• schedule and chair the meeting, prepare the agenda and ensure that meetingminutes are recorded




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GENERATION EMPLOYEES General• understand the EMS and your role in supporting it

• participate in the improvement of the EMS

• when carrying out your work, consider all environmental issues within the frameworkof the EMS

Policy1.1 Implementation of Environmental Policy

• maintain awareness of the Policy

• implement the Policy as it applies to your work

Planning2.1 Environmental Aspects and Impacts• know the significant aspects of operational activities related to your work that could

impact the environment and how to address them 2.2 Legal and Other Requirements

• maintain awareness of and observe regulatory and other applicable requirements,and adhere to prescribed operational controls and recommended work practices

Implementation and Operation 3.3 Internal Communication and Reporting• communicate environmental concerns and suggestions for improvements to

immediate managers and within peer group as necessary

• immediately report environmental incidents to your supervisor or manager

3.4 External Communication• communicate external inquiries related to the environment to your supervisor or

manager as appropriate

3.6 Operational Controls• perform work in conformance with applicable operational controls as directed by your

manager

• provide recommendations for new controls/changes in existing controls as necessary

3.7 Emergency Preparedness and Response• participate in and understand your role in emergency preparedness and responding

to emergencies, as assigned by your Manager




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3.8 Contractor Management• follow contractor management procedures and ensure that contractors working

under your supervision are aware of the environmental requirements of the work

Checking and Corrective Action4.2 Non-conformance, Corrective and Preventive Action• identify, record and respond to non-conformances and opportunities for improvement

associated with your work

• advise your immediate supervisor or manager of non-conformances

List of Aspects (Seven Mile) 1/5

Activity Aspect Impact Risk RankingAccess Roads O&M: eg. construction, bank stabilization, snow removal, snow storage application of salt (snow/ice management) contamination of soil, surface water, and ground water 95Access Roads O&M: eg. construction, bank stabilization, snow removal, snow storage spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 255Air Blast (SF6) CB O&M escape of SF6 air contamination eg. odour, smoke 1525Air Blast (SF6) CB O&M generation and/or disposal of aerosol cans contamination of soil, surface water, and ground water 2Air Blast (SF6) CB O&M generation and/or disposal of waste desiccants contamination of soil, surface water, and ground water 7Air Blast (SF6) CB O&M generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Air Magnetic CB O&M use of detergents contamination of soil, surface water, and ground water 63Batteries O&M generation and/or disposal of waste batteries contamination of soil, surface water, and ground water 1Batteries O&M generation and/or disposal of waste batteries contamination of soil, surface water, and ground water 63Batteries O&M spill and/or disposal of acid or electrolyte contamination of soil, surface water, and ground water 105Big Valves and Gates O&M: eg. resurfacing runoff from pressure washing contamination of soil, surface water, and ground water 2Big Valves and Gates O&M: eg. resurfacing spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 8Big Valves and Gates O&M: eg. resurfacing generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 14CGI bus O&M escape of SF6 air contamination eg. odour, smoke 1525Compressed Gas Insulated Switchgear O&M escape of SF6 air contamination eg. odour, smoke 1525Compressed Gas Insulated Switchgear O&M generation and/or disposal of aerosol cans contamination of air and soil 2Compressed Gas Insulated Switchgear O&M generation and/or disposal of waste desiccants contamination of soil, surface water, and ground water 7Compressed Gas Insulated Switchgear O&M generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Compressors, Fans, and Blowers O&M generation and/or disposal of aerosol cans contamination of air and soil 2Compressors, Fans, and Blowers O&M spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 8Compressors, Fans, and Blowers O&M generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Compressors, Fans, and Blowers O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 31

Compressors, Fans, and Blowers O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 35Compressors, Fans, and Blowers O&M use of detergents contamination of soil, surface water, and ground water 63Compressors, Fans, and Blowers O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Cranes and Hoists O&M: eg. resurfacing generation and/or disposal of carbon brush dust air contamination eg. odour, smoke 2Cranes and Hoists O&M: eg. resurfacing generation and/or disposal of aerosol cans contamination of air and soil 2Cranes and Hoists O&M: eg. resurfacing runoff from pressure washing contamination of soil, surface water, and ground water 2Cranes and Hoists O&M: eg. resurfacing spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 8Cranes and Hoists O&M: eg. resurfacing use of detergents contamination of soil, surface water, and ground water 63Cranes and Hoists O&M: eg. resurfacing generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Cranes and Hoists O&M: eg. resurfacing spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 293CVT O&M runoff from pressure washing contamination of soil, surface water, and ground water 2CVT O&M spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 8CVT O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105CVT O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 135Dam O&M: eg. resurfacing generation and/or disposal of aerosol cans contamination of air and soil 2Dam O&M: eg. resurfacing spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 8Dam O&M: eg. resurfacing generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105

data last updated: Dec 2002


Activity Aspect Impact Risk Ranking

Diesel Engines O&Mgeneration of emissions from internal combustion engines air contamination eg. odour, smoke 1

Diesel Engines O&M generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Diesel Engines O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 31Drainage sump (with oil separator) O&M generation and/or disposal of solid wastes contamination of soil, surface water, and ground water 7Drainage sump (with oil separator) O&M generation and/or disposal of special wastes contamination of soil, surface water, and ground water 14

Drainage sump (with oil separator) O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 35Drainage sump (with oil separator) O&M escape of contaminated water contamination of soil, surface water, and ground water 195Drainage sump (without oil separator) O&M generation and/or disposal of solid wastes contamination of soil, surface water, and ground water 7Drainage sump (without oil separator) O&M spill and/or disposal of mercury contamination of soil, surface water, and ground water 14Excitation System O&M generation and/or disposal of carbon brush dust air contamination eg. odour, smoke 2

Fire Protection O&M: eg. resurfacing spill and/or disposal of dry chemical contamination of air, soil, surface water, and ground water 3Fuel Storage Tank (above and below ground) O&M: eg. dispensing, refilling, resurfacing removal of vapours air contamination eg. odour, smoke 6Fuel Storage Tank (above and below ground) O&M: eg. dispensing, refilling, resurfacing spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 20Generator Braking O&M generation and/or disposal of solid wastes contamination of soil, surface water, and ground water 3Generator Braking O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) removal of vapours air contamination eg. odour, smoke 3Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) generation and/or disposal of aerosol cans contamination of air and soil 2Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) runoff from pressure washing contamination of soil, surface water, and ground water 2Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) generation and/or disposal of paint rags contamination of soil, surface water, and ground water 3Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 31Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) use of detergents contamination of soil, surface water, and ground water 63Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 8Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing spill and/or disposal of mercury contamination of soil, surface water, and ground water 20



Activity Aspect Impact Risk RankingGovernor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 31Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 35Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing use of detergents contamination of soil, surface water, and ground water 63Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Grounding transformers O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105HVAC System O&M escape of ozone depleting substances air contamination eg. odour, smoke 14HVAC System O&M generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14HVAC System O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Land Management application, or, spill and/or disposal of pesticides contamination of soil, surface water, and ground water 5Land Management establishment and dispersal of noxious weeds degradation of habitat 1825Operations Activities - Downstream of Control Structure Shut down allows fish to move into draft tube 59

Operations Activities - Downstream of Control Structure Shut downchange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 194

Operations Activities - Downstream of Control Structure Synchronous condensechange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 243

Operations Activities - Downstream of Control Structure Increase spillchange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 615

Operations Activities - Downstream of Control Structure Increase generationchange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 2050

Operations Activities - Downstream of Control Structure Shut down diminished recreational use 32Operations Activities - Downstream of Control Structure Decrease generation diminished recreational use 650Operations Activities - Downstream of Control Structure Increase spill displacement of fish/ova from preferred habitat 548Operations Activities - Downstream of Control Structure Shut down fish/ova stranding through habitat dewatering 131Operations Activities - Downstream of Control Structure Shut down habitat degradation (aquatic, terrestrial, riparian) 131Operations Activities - Downstream of Control Structure Increase spill habitat degradation (aquatic, terrestrial, riparian) 548Operations Activities - Downstream of Control Structure Decrease generation habitat degradation (aquatic, terrestrial, riparian) 1825Operations Activities - Downstream of Control Structure Start up injury to fish in draft tube due to pressure shock wave 248Operations Activities - Downstream of Control Structure Increase spill public safety 3Operations Activities - Downstream of Control Structure Decrease generation public safety 548Operations Activities - Downstream of Control Structure Shut down reduced aesthetics (visual, odor, noise) 99Operations Activities - Downstream of Control Structure Decrease generation reduced aesthetics (visual, odor, noise) 1625Operations Activities - Downstream of Control Structure Shut down reduction in productivity 131Operations Activities - Downstream of Control Structure Decrease generation reduction in productivity 1625Operations Activities - Upstream of Control Structure Increase reservoir elevation bank erosion 1225

Operations Activities - Upstream of Control Structure Decrease reservoir elevationbarriers to fish passage (velocity, debris, tributary access, man-made) 1450



Activity Aspect Impact Risk Ranking

Operations Activities - Upstream of Control Structure Increase reservoir elevationchange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 1450

Operations Activities - Upstream of Control Structure Decrease reservoir elevationdamage to private and public land (erosion, flooding, stranded water intakes, flooded wells) 735

Operations Activities - Upstream of Control Structure Increase reservoir elevationdamage to private and public land (erosion, flooding, stranded water intakes, flooded wells) 850

Operations Activities - Upstream of Control Structure Decrease reservoir elevation diminished recreational use 1625Operations Activities - Upstream of Control Structure Start up fish entrainment 885Operations Activities - Upstream of Control Structure Increase generation fish entrainment 2950Operations Activities - Upstream of Control Structure Decrease generation fish entrainment 3550Operations Activities - Upstream of Control Structure Increase reservoir elevation habitat degradation (aquatic, terrestrial, riparian) 850Operations Activities - Upstream of Control Structure Decrease reservoir elevation habitat degradation (aquatic, terrestrial, riparian) 1225Operations Activities - Upstream of Control Structure Decrease reservoir elevation public safety 1815Operations Activities - Upstream of Control Structure Decrease reservoir elevation reduced aesthetics (visual, odor, noise) 475Operations Activities - Upstream of Control Structure Decrease reservoir elevation reduced commercial navigability (depth, debris hazards) 435Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer generation and/or disposal of aerosol cans contamination of air and soil 2Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer runoff from pressure washing contamination of soil, surface water, and ground water 2Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer generation and/or disposal of waste desiccants contamination of soil, surface water, and ground water 7Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 8Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 135Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings removal of vapours air contamination eg. odour, smoke 13Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings generation and/or disposal of aerosol cans contamination of air and soil 8Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings runoff from pressure washing contamination of soil, surface water, and ground water 2Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings generation and/or disposal of paint rags contamination of soil, surface water, and ground water 3Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 23Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 31Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 38



Activity Aspect Impact Risk RankingPrime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings use of detergents contamination of soil, surface water, and ground water 117Regulators O&M runoff from pressure washing contamination of soil, surface water, and ground water 2Regulators O&M generation and/or disposal of waste desiccants contamination of soil, surface water, and ground water 7Regulators O&M spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 8Regulators O&M generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Regulators O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Regulators O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 135Reservoir Management collection and/or disposal of reservoir debris air contamination eg. odour, smoke 50Reservoir Management generation and/or disposal of solid wastes contamination of soil, surface water, and ground water 21Reservoir Management generation and/or disposal of leachate contamination of soil, surface water, and ground water 51Reservoir Management spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 135Sewage Treatment Plant O&M escape of sewage effluent contamination of soil, surface water, and ground water 5Shops O&M generation and/or disposal of aerosol cans contamination of air and soil 2Shops O&M generation and/or disposal of metal wastes contamination of soil, surface water, and ground water 8

Shops O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 35Shops O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 45Shops O&M use of detergents contamination of soil, surface water, and ground water 63Shops O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Site Construction and Maintenance: eg. resurfacing, janitorial, lighting tube and ballast changes runoff from pressure washing contamination of soil, surface water, and ground water 2Site Construction and Maintenance: eg. resurfacing, janitorial, lighting tube and ballast changes spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 45Site Construction and Maintenance: eg. resurfacing, janitorial, lighting tube and ballast changes use of detergents contamination of soil, surface water, and ground water 63Site Construction and Maintenance: eg. resurfacing, janitorial, lighting tube and ballast changes spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 105Site Construction and Maintenance: eg. resurfacing, janitorial, lighting tube and ballast changes spill and/or disposal of mercury contamination of soil, surface water, and ground water 750Unwatering sump O&M spill and/or disposal of mercury contamination of soil, surface water, and ground water 14

Vehicle O&Mgeneration of emissions from internal combustion engines air contamination eg. odour, smoke 2

Vehicle O&M generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 14Vehicle O&M spill and/or disposal of antifreeze contamination of soil, surface water, and ground water 81Vehicle O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Vehicle O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 135Volatile Storage Area O&M spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 8Volatile Storage Area O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 11Volatile Storage Area O&M storage of incompatible products contamination of soil, surface water, and ground water 53Wicket Gates O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 1250


List of Aspects (G.M. Shrum) 1/5

Activity Aspect Impact Risk RankingAccess Roads O&M: eg. construction, bank stabilization, snow removal, snow storage

generation and/or disposal of vegetation debris (e.g., burning) air contamination eg. odour, smoke 14

Batteries O&M generation and/or disposal of waste batteries contamination of soil, surface water, and ground water 18Batteries O&M spill and/or disposal of acid or electrolyte contamination of soil, surface water, and ground water 83

Boom O&Mgeneration and/or disposal of vegetation debris (e.g., burning) air contamination eg. odour, smoke 645

Braking System O&M: Oil Management (replace, filter, transport, storage) generation and/or disposal of brake dust contamination of air and soil 14Braking System O&M: Oil Management (replace, filter, transport, storage) generation and/or disposal of oily rags contamination of soil, surface water, and ground water 9Braking System O&M: Oil Management (replace, filter, transport, storage) generation and/or disposal of metal wastes landfill depletion 9Bulk Oil CB O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 9Bulk Oil CB O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 495Bus O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 5Bus O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 9Compressors, Fans, and Blowers O&M generation and/or disposal of waste desiccants contamination of soil, surface water, and ground water 105Compressors, Fans, and Blowers O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 175Compressors, Fans, and Blowers O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 250Compressors, Fans, and Blowers O&M generation and/or disposal of waste desiccants contamination of soil, surface water, and ground water 525Cranes and Hoists O&M: eg. resurfacing spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 75Cranes and Hoists O&M: eg. resurfacing generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 76Cranes and Hoists O&M: eg. resurfacing generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Current Transformers (Oil filled) O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 175

Current Transformers (Oil filled) O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Current Transformers (Oil filled) O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 1025CVT O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 18CVT O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 33

CVT O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250DC Equipment O&M spill and/or disposal of mercury contamination of soil, surface water, and ground water 375DC Equipment O&M spill and/or disposal of mercury special waste storage depletion 77

Diesel Engines O&Mgeneration of emissions from internal combustion engines air contamination eg. odour, smoke 53

Diesel Engines O&M generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 18Diesel Engines O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 53Diesel Engines O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 660

Drainage sump (with oil separator) O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 13Drainage sump (with oil separator) O&M escape of contaminated water contamination of soil, surface water, and ground water 1625Fire Protection O&M: eg. resurfacing spill and/or disposal of dry chemical air contamination eg. odour, smoke 5Fire Protection O&M: eg. resurfacing spill and/or disposal of mercury contamination of soil, surface water, and ground water 38

data last reviewed: Dec 2002


Activity Aspect Impact Risk RankingGenerator Cooling O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 10Generator Cooling O&M fish entrainment fish mortality 2650Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) generation and/or disposal of carbon brush dust air contamination eg. odour, smoke 98Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) generation and/or disposal of aerosol cans contamination of air and soil 325Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) runoff from pressure washing contamination of soil, surface water, and ground water 9Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) generation and/or disposal of metal wastes contamination of soil, surface water, and ground water 13Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 46Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) use of detergents contamination of soil, surface water, and ground water 75Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) generation and/or disposal of oily rags contamination of soil, surface water, and ground water 105Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 725Generators O&M: bearing mtce, Oil mgmt (replace, filter, transport, storage) disposal of epoxies, glues/resins contamination of surface water, and ground water 45Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 5Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 36Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 100Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing generation and/or disposal of oily rags contamination of soil, surface water, and ground water 175Governor and/or Permanent Magnet Generators O&M: eg. oil management (replace, filter, transport, storage), accumulator, resurfacing generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Grounding transformers O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 53

Grounding transformers O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Grounding transformers O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 315HVAC System O&M escape of ozone depleting substances air contamination eg. odour, smoke 16HVAC System O&M spill and/or disposal of antifreeze contamination of soil, surface water, and ground water 3HVAC System O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 16Machine Shop Equipment O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 175

Machine Shop Equipment O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Machine Shop Equipment O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 420



Activity Aspect Impact Risk RankingMachine Shop Equipment O&M generation and/or disposal of aerosol cans landfill depletion 325Manometers O&M spill and/or disposal of mercury contamination of soil, surface water, and ground water 420

Officegeneration and/or disposal of personal and office waste landfill depletion 315

Oil filled reactors O&M generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 46Oil filled reactors O&M generation and/or disposal of waste filter media contamination of soil, surface water, and ground water 53Oil filled reactors O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 175

Oil filled reactors O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Oil filled reactors O&M generation and/or disposal of waste desiccants contamination of soil, surface water, and ground water 525Oil filled reactors O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 1025

Operations Activities - Downstream of Control Structure Increase spillchange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 136

Operations Activities - Downstream of Control Structure Speed-no-loadchange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 545

Operations Activities - Downstream of Control Structure Synchronous condensechange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 1629

Operations Activities - Downstream of Control Structure Increase generationchange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 2425

Operations Activities - Downstream of Control Structure Start upchange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 2715

Operations Activities - Downstream of Control Structure Decrease generation fish entrainment 26Operations Activities - Downstream of Control Structure Increase spill fish entrainment 226Operations Activities - Downstream of Control Structure Speed-no-load fish entrainment 1178Operations Activities - Downstream of Control Structure Shut down fish/ova stranding through habitat dewatering 24Operations Activities - Downstream of Control Structure Decrease generation fish/ova stranding through habitat dewatering 885Operations Activities - Downstream of Control Structure Start up injury to fish in draft tube due to pressure shock wave 26Operations Activities - Downstream of Control Structure Increase spill public safety 3Operations Activities - Downstream of Control Structure Decrease generation reduction in productivity 11Operations Activities - Upstream of Control Structure Decrease reservoir elevation air contamination eg. odour, smoke, dust 470Operations Activities - Upstream of Control Structure Decrease reservoir elevation bank erosion 65

Operations Activities - Upstream of Control Structure Decrease reservoir elevationbarriers to fish passage (velocity, debris, tributary access, man-made) 243

Operations Activities - Upstream of Control Structure Increase reservoir elevationchange in water quality - (tgp, tss, turbidity, temp, oxygen, mercury bio-methylation) 340

Operations Activities - Upstream of Control Structure Maximum reservoirdamage to private and public land (erosion, flooding, stranded water intakes, flooded wells) 73

Operations Activities - Upstream of Control Structure Increase reservoir elevationdamage to private and public land (erosion, flooding, stranded water intakes, flooded wells) 87

Operations Activities - Upstream of Control Structure Decrease reservoir elevationdamage to private and public land (erosion, flooding, stranded water intakes, flooded wells) 145

Operations Activities - Upstream of Control Structure Decrease reservoir elevation diminished recreational use 93

Operations Activities - Upstream of Control Structure Maximum reservoirdisruption to riparian/streamside wildlife (e.g. nesting birds, beavers) 10



Activity Aspect Impact Risk RankingOperations Activities - Upstream of Control Structure Speed-no-load fish entrainment 1178Operations Activities - Upstream of Control Structure Start up fish entrainment 2425Operations Activities - Upstream of Control Structure Increase generation fish entrainment 3925Operations Activities - Upstream of Control Structure Increase reservoir elevation habitat degradation (aquatic, terrestrial, riparian) 163Operations Activities - Upstream of Control Structure Start up public safety 1808Operations Activities - Upstream of Control Structure Decrease reservoir elevation reduced aesthetics (visual, odor, noise) 145

Operations Activities - Upstream of Control Structure Decrease reservoir elevation reduced commercial navigability (depth, debris hazards) 87

Operations Activities - Upstream of Control Structure Maximum reservoir reduced commercial navigability (depth, debris hazards) 160Operations Activities - Upstream of Control Structure Decrease reservoir elevation reduction in productivity 153Penstock O&M spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 46Power Intake Gates O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 53Power Intake Gates O&M generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 76Power Intake Gates O&M spill and/or disposal of methyl hydrate contamination of soil, surface water, and ground water 150Power Intake Gates O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 735Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer runoff from pressure washing contamination of soil, surface water, and ground water 18Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 46Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer generation and/or disposal of oily rags contamination of soil, surface water, and ground water 175Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 315Power Transformers O&M: oil management (replace, filter, transport, storage), tap changer generation and/or disposal of waste desiccants contamination of soil, surface water, and ground water 525Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings generation and/or disposal of metal wastes contamination of soil, surface water, and ground water 5Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings generation and/or disposal of oily rags contamination of soil, surface water, and ground water 53Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 76Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 100Prime Mover O&M: eg. shear pin, oil management (replace, filter, transport, storage), resurfacing, bearings dewatering of water passages fish mortality 938Regulators O&M generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 46Regulators O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 175

Regulators O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Regulators O&M generation and/or disposal of waste desiccants contamination of soil, surface water, and ground water 525Regulators O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 1025Reservoir Management collection and/or disposal of reservoir debris air contamination eg. odour, smoke 480



Activity Aspect Impact Risk RankingReservoir Management spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 275Reservoir Slope Maintenance bank stabilization contamination of soil, surface water, and ground water 36Sewage Treatment Plant O&M escape of sewage effluent contamination of soil, surface water, and ground water 2125Shops O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 175

Shops O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Shops O&M generation and/or disposal of aerosol cans contamination of soil, surface water, and ground water 325Shops O&M generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 549Site Construction and Maintenance: eg. resurfacing, janitorial, lighting tube and ballast changes bank stabilization contamination of soil, surface water, and ground water 36Site Construction and Maintenance: eg. resurfacing, janitorial, lighting tube and ballast changes use of detergents contamination of soil, surface water, and ground water 425Site Construction and Maintenance: eg. resurfacing, janitorial, lighting tube and ballast changes generation and/or disposal of solid wastes contamination of soil, surface water, and ground water 1900Spillway Gates O&M: eg. resurfacing generation and/or disposal of oily rags contamination of soil, surface water, and ground water 18Spillway Gates O&M: eg. resurfacing spill and/or disposal of paints/coatings contamination of soil, surface water, and ground water 32Spillway Gates O&M: eg. resurfacing spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 69Spillway Gates O&M: eg. resurfacing generation and/or disposal of sandblasting waste contamination of soil, surface water, and ground water 76

Tanks O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Tanks O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 1095Unwatering sump O&M spill and/or disposal of mercury contamination of soil, surface water, and ground water 188VHF General generation and/or disposal of waste batteries contamination of soil, surface water, and ground water 10Voltage Transformers (Mag. Core) O&M generation and/or disposal of oily rags contamination of soil, surface water, and ground water 175

Voltage Transformers (Mag. Core) O&M generation and/or disposal of waste absorbent pads contamination of soil, surface water, and ground water 250Voltage Transformers (Mag. Core) O&M spill and/or disposal of fuel, oil, grease contamination of soil, surface water, and ground water 1025



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6.0 Reference: Application, Volume I, Chapter 6, Transmission

1.6.1 Page 6-23, Lines 19-20: The Application states that “Contingency plansare prepared to mitigate the system consequences of unanticipated assetfailures.”

It is expected that these plans would be prepared well in advance of needto address several likely contingency situations.

Please provide the following:

(a) A description of the contingency plans that have been preparedover the last ten years to mitigate the impact of major transmissionasset failures.

(b) A description of the approximate costs and benefits of thosecontingency plans that have had to be implemented over the lastten years.

RESPONSE:

The transmission system is designed to meet WECC/NERC performancestandards for typical contingencies. However, there have been occasions whenthere have been multiple equipment failures or situations arose that eitherconstrained the system or increased the risk of failure and contingency planswere prepared to deal with these. Some examples of the contingency plansprepared over the last ten years are:● CKY breaker replacement – bypass plans prepared to accommodate

adjacent breaker failure;● BRT T3 – contingency plans developed to cover loss of transformer for

long periods of time to avoid restrictions on generation;● 2L56 – Contingency plans developed and initiated to cover loss of

additional 230kV cables which supply the western area of Vancouver;● WLT T1/T2 – contingency plans developed to cover loss of the second

transformer due to lengthy outages required to repair the tap changers;and

● CSQ – contingency plans developed to cover the construction period toinstall the new 2L33 cable.

Development of such plans is a routine part of the outage scheduling.Other contingency plans have been developed to cover non-electrical events,such as Y2K and the potential for Fraser River flooding.

An emergency response manual outlines the restoration team structure andidentifies responsible individuals in the case of transmission line emergencies.


Page2


As part of BCTC’s approach to contingency planning, studies are conductedevery year to determine the secure and reliable operating limits of thetransmission system. The results of these technical studies are put intosystem operating orders and local operating orders, which provide guidanceto the operators on how to deal with contingencies that occur on the system.This information is supplemented by operator training aimed at increasing theknowledge and skill of the control room operators so that they can deal withboth expected and unexpected system disturbances. An Operating Guide isbeen prepared each year to identify the changes that have been made to thesystem and to provide information to the operators on how the systemoperation will be changed. In total, roughly $1.5 million to $2.0 million per yearis spent to study all contingencies, planned and unplanned.Vancouver Island provides an example of this kind of contingency planning. In1998 heavy snow damaged towers on the two 500 kV transmission linessupplying Vancouver Island. Contingency plans were developed to prepare forthe potential failure of the two lines and for repairs to the towers. These plansprovide guidance on how to operate the connections to Vancouver Island inthe event of failure of a major transmission connection to the Island.As another element of BCTC’s contingency plans, materials are maintained instock to repair:

• 5 km of 500kV lines;• 10 km of 230kV lines;• 5 km of 138kV lines;• 10 km of 69kV lines;• 8 km of wood pole H-frame for DC lines; and• cables, potheads and splices for underground and submarine

cables.BCTC also maintains trailers with tools and equipment for emergencyresponse; a 35 MW generator and heavy construction equipment are allmaintained in readiness.Particular elements of contingency planning can be quite costly. An exampleof a significant cost ($900k) to implement a contingency plan is 2L56, wherethe risks were high (probability of a second cable failure was high due toageing) and the consequence was significant (loss of supply to customersfrom Granville Street west to UBC). In this case, the cost of the contingencyplan offset the cost of construction of future projects.The total annual cost to maintain the transmission line material and equipmentrequired to respond to emergencies and to develop the contingency plans isapproximately $1 million. The emergency spare material replacement cost ofthe towers, special crossing conductors and the submarine cable spares is inthe order of $10 million.Costs of repair can be substantive and have run as high as $25 million (snowcreep repair on Vancouver Island lines). Other major events, which have hadsignificant cost, are as follows:


Page3


• Sansum Narrows conductor replacement (approx. 2km span of specialalloy conductor: $400,000;

• 5L32 mud slide (three 500kV towers destroyed): $2,900,000;• 1L210 138kV wood pole line rebuild due to forest fire (Louis Creek area):

$4,000,000; • 2L53 230 kV Cable stop joint failure: $1,000,000; and• 2L64 230kV Cable stops joint failure: $1,000,000.

The benefits of contingency plans are reduced outage time or outageavoidance on key lines. Some examples of reduced outage time due tocontingency plans include:

• 230kV cable replacement of damaged sections. Time of outage was 7 to10 days due to availability of cables and components.

• Vancouver Island 500kV supply - replacement of three towers destroyedby a mudslide. Outages of approximately five weeks were required toreplace three towers. Use of emergency stock eliminated potentialdelays; the delivery time for new towers would have been severalmonths.

• In 2003 approximately 15km of wood pole transmission line weredestroyed by a forest fire and were rebuilt in four weeks. The teamformed in accordance with the contingency plan was effective inaddressing all issues including temporary generation for isolatedcommunities.

The contingency planning process looks for alternatives not usually used innormal operation, for example:

• when the metro cable supply cables 2L39 and 40 failed earlier in thereplacement process than expected, contingency supply was arrangedthrough modifications to the underlying 60kV system;

• a 230kV by-pass for supply to the Sunshine Coast was arranged so thatjumpers could be placed to use the 500kV line and part of a speciallyconstructed 138kV line section in the event that both 500kV circuits toVancouver Island failed due to the Snow creep problem; and

• when a 230kV cable feeding Sperling substation in Vancouver failed thesystem was modified through 60kV backfeed and installation of anavailable step-up transformer to provide system security for that area.


Page1



1.6.2 Page 6-2, Section 3.2.8.1, Asset Condition/Health

The Application mentions that a qualitative asset condition evaluationsystem is used for transmission lines, stations and vegetation.

Please elaborate on the details of this evaluation system and explain howthe success of its application is measured. Was information whichemanated from this evaluation used in the preparation of the graph(Figure 6-1) on page 6-26? If yes, please explain how it was used. If no,please explain how the information for the graph was obtained.

RESPONSE:As noted in Chapter 6, Page 6-23, Section 3.2.3.1.2, the asset maintenance andinvestment process ensures that transmission assets are in good conditionthrough preventative and corrective maintenance and replacement. Specificmaintenance and replacement decisions, work plans and budgets are predicatedon regular inspections and review of asset condition.

The qualitative asset condition system mentioned in Chapter 6, Page 6-25, Section3.2.8.1 is a relatively recent system that was developed to provide a high levelindication of overall asset health for communicating to management. Thisinformation is displayed in graphical form on Page 6-26, Figure 6-1. The shadingcodes were developed to provide an indication of asset condition and areas whereexpenditures would be focused in the coming years.

Using vegetation as an example, the assessments are based on informationcollected during annual vegetation management patrols of the rights-of-way. Allcircuits are reviewed and an assessment is made on whether:

• the system is operating to plan and no work needs to be conducted for thecoming year (Moderate/Good);

• the circuit requires work within the next few years and the area should bemonitored (Fair); or

• imminent attention is required and this must be budgeted in the coming fiscalyear (Poor).

Similar analyses are carried out for the transmission line assets using anautomated mobile inspection process and for substation assets using a mobilecomputing system for collecting equipment inspection results. The information isused to formulate detailed workplans and budgets and then “rolled up” to createthe graph shown in Figure 6-1. A future asset management information systemwill include significantly enhanced methods for determining asset health,


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prioritizing projects, managing execution and completion of approved projectsand asset performance measurement.

Success is measured by an improvement in the condition of the assets over timeand a shift in the graph shown in Figure 6-1 from Poor or Fair to Moderate/Good.

In addition to the qualitative asset condition evaluation, a baseline audit iscurrently being undertaken to determine the condition of transmission assets.Based on that audit, BCTC intends to develop a multi-year plan.


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1.6.3 Page 6-4, Lines 16-17: Please describe and quantify the additional costsfor BCTC which were not part of BC Hydro’s previous transmission costs.

RESPONSE:The additional costs for BCTC which were not part of BC Hydro’s F2004transmission line of business costs are as follows:

● In F2005 an additional $5.4 million ongoing OMA cost was included to fund theongoing operation of BCTC. This is in addition to the $12.4 million included inF2004 OMA forecast, bringing the additional BCTC operating cost to $17.8million. Details are provided in Chapter 6, Page 6-44, Table 6-12.

● In F2005 the one-time OMA restructuring costs will decrease by $11 millionfrom F2004 as BCTC is established and operational.

● In F2005 there will be about $0.5 million additional depreciation and financecharges related to additional capital investment for BCTC establishment.These BCTC capital investments include office leasehold improvement andcomputer hardware and software associated with BCTC establishment.


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1.6.4 Pages 6-5 and 6-48, Lines 14 and 15: BCTC states that higher systemuse is acting to reduce transmission rates. Please describe how this useis occurring and how will BCTC forecast future use. Does this increasinguse also have additional costs (i.e. additional maintenance or sustainingcapital costs)? If possible, please quantify.

RESPONSE:

The increased use of the system is driven by increased short-term and long-termpoint-to-point (PTP) transmission contracts, growing domestic load, andadditional network resources being added by BC Hydro to serve domestic load. BCTC forecasts both long-term and short-term transmission uses in developingits PTP transmission revenue forecast. The long-term use is based on theexisting long-term contracts, which are expected to rollover upon expiration.Revenues from long-term contracts are at embedded cost rates and make upapproximately 60% of forecasted PTP revenues in F2005 and beyond. Long-termtransmission use has doubled since 2000 but is expected to remain constantbecause new long-term contracts may require Network Upgrades.The short-term use of the transmission system is dependent on market factorssuch as energy market prices and entry of new customers. BCTC forecasts ageneral increase over time in the use of short-term transmission services due tothe expected entry of new customers (IPPs, industrial loads and others) resultingfrom the Energy Plan. Short-term transmission prices are expected to remainrelatively low due to flat energy market prices.Because of the increased use of transmission capacity by wholesale customers,some transmission maintenance procedures have been altered to reduce the lossof transmission capacity during line maintenance. As such, the maintenancecosts are slightly higher for transmission lines due to increased use of energized(live line) maintenance work practices and the use of off-peak work hours (whichresults in higher labour costs). These factors have added approximately 2%($400,000) per year added line maintenance cost over the last three years. Further, there will be some additional maintenance costs due to an increase in thenumber of operations of some devices, such as circuit breakers and disconnectswitches, used to control voltages during heavy exports and imports. Thesecosts are estimated at $200,000 per year. This estimate assumes that the typical20-year maintenance expense of $200,000 per device, for 20 devices, will occur ina 10-year cycle instead of 20-year cycle. On an annualized basis, the incrementalcost becomes ($200,000/20 - $200,000/10) * 20 devices, or $200,000 per year.Increasing use also creates the need for additional capital costs. As noted inChapter 6, Page 6-13, Lines 12 to 17 and Page 6-66, Lines 13 to 24, capitalexpenditures (i.e., Grid Operations Upgrade Project) have been required to enablemarket operations to respond to increasing and more complex system use.Capital expenditures have also been required, as described on Page 6-63 and asquantified in Table 6-19, on Page 6-57 for the Lower Mainland Control CentreSupervisory Control and Data Acquisition (SCADA) system upgrade.


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1.6.5 Page 6-7, Table 6-1: Please describe BCTC’S asset retirementobligation.

RESPONSE:BCTC’s accounting for Asset Retirement Obligation (ARO) is described in Chapter2, Page 2-17, Section 3.7.3.

There are two ARO provisions at April 1, 2004. For BCTC, the ARO relates to theBurnaby Mountain System Control Center site clean up and restoration, forecastto be $1.0 M in 2008. For the BC Hydro Transmission line of business, the AROrelates to the future cost of removal of the submarine cables between themainland and Vancouver Island, which is forecast to be $20.0 M in 2008.

The annual ARO accretion is charged to OMA and set up as ARO provision. TheARO provision is the present value of the estimated $21.0 million future amount.

($ millions) F04 F05 F06Accretion Expense - 1.0 1.0ARO Provision 16.5 17.5 18.5


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1.6.6 Page 6-11, Lines 21, 22: BCTC states that the operations and controlinfrastructure is showing signs of strain limiting effective and reliableoperation. Please describe the signs and discuss whether theselimitations and problems pose any risk for the reliable transmission ofpower within B.C.

RESPONSE:

The operations and control infrastructure, which includes the existing controlcentres and associated Energy Management System (EMS) and SupervisoryControl and Data Acquisition (SCADA), is showing signs of strain in twelve areas,as described below. 1. Cyber Security

Improvements to existing computer security measures are either overlyexpensive or impractical with the existing system, and a more modern systemarchitecture is required.

2. ReliabilityThe EMS / SCADA system architecture and implementation do not meetpresent industry targets for hardware and software reliability.The risk is that failure of key hardware, software or other infrastructure resultsin the unavailability of essential systems to monitor, assess and control thetransmission system.

3. MaintainabilityThe control systems architecture requires a high maintenance effort withassociated high costs, work backlog and error rates.The risk to the transmission system is that needed improvements to thecontrol system that would improve the reliability and efficiency of thetransmission system are delayed.The second risk to the transmission system is that unexpected operations oftransmission equipment can result in equipment damage and loss of supply tocustomers.

4. FlexibilityThe present control infrastructure has difficulty integrating customfunctionality and implementing minor customizations to standard functionality.The risk to reliable transmission of power is that enhancements to the controlsystem that would improve the reliability and efficiency of the transmissionsystem are delayed.


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5. Data Access/IntegrationThe present control infrastructure has difficulty integrating the SCADA/EMSwith enterprise and business support systems.The risk to reliable transmission of power is that information from theEMS/SCADA system that could be used by other departments to improve thereliability of the transmission system is unavailable or is seldom used becauseof the difficult integration efforts.

6. ModernizationThe present control infrastructure does not meet present industry bestpractices for hardware and software. Improved usability for control room andshort-term planning staff is required to obtain intended benefits from theadvanced applications.The risk to reliable transmission of power is that the difficulty of using thepresent tools results in there being insufficient resources to fully utilize allapplications to minimize and mitigate risks to the transmission system.

7. Improved Vendor SupportThe vendor does not adequately support much of the present infrastructure atthe System Control Centre. Staying current with industry requirementsrequires implementing custom system changes.The risk to reliable transmission of power is that a large number of dedicatedstaff is required to support the infrastructure. Any problems with maintainingthis staff can result in delays of control systems changes that improve theefficiency and reliability of the transmission system.

8. Sustaining capital costsChanges in SCADA and system architecture currently must be duplicatedacross five control centre sites. Changes in AGC currently must be duplicatedacross two sites (SCC & SIC). Advanced applications are readily available onlyto SCC staff with only limited availability to LMC staff.The risk to reliable transmission of power is that limited sustaining capitalmust be used to maintain / improve multiple systems, which constrains whatcan be done for each system. This has long-term implications on the reliabilityof the control systems and as a result, the reliability of the transmissionsystem.

9. High support costsThe diversity of equipment at the various control centres leads to highermaintenance costs.The risk to reliable transmission of power is that limited funds for supportmust be used to maintain / improve multiple systems, which constrains whatcan be done for each system. This has long-term implications on the reliabilityof the control systems and as a result, the reliability of the transmissionsystem.


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10. Operating staff to handle absences (vacations, sickness, retirements, etc.)At the smaller control centres there is a limited pool of trained dispatchers tocover multiple simultaneous absences. Management staff at the smallercontrol centres have limited experienced backup available to cover for theirabsences.The risk to reliable transmission of power is that absences of staff can result inhigh demands of time from the remaining staff that can lead to increasederrors in operation of the transmission system.

11. Process standardizationDiverse equipment and local factors obstruct standardized processes acrossmultiple control centres. Equipment, procedures and training are notstandardized across all control centres.The risk to reliable transmission of power is that lack of standardizationdiverts resources from implementing industry best practices for operation toresolving process issues.

12. Staff communicationsPhysical distances inhibit simultaneous and consistent communicationsbetween operating staff. With modern technology, computers can nowcommunicate far better over remote distances than when the current controlcentre structure was developed (late 1960s). Inter-personal communications isnow the more restrictive limitation.The risk to reliable transmission is that resources are diverted fromimplementing industry best practices for operation to mitigating thecommunications issues.

British Columbia Utilities CommissionInformation Request No. 1.6.7 Dated: 23 January 2004British Columbia Hydro & Power AuthorityRevised Response issued 03 June 2004

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1.6.7 Page 6-20, Table 6-6: Vegetation Management. Please provide the lastfive years of expenditures for all transmission related vegetationmanagement programs. Please describe all new (post F2000)environmental regulations or First Nations requirements which haveincreased the cost of vegetation management and quantify wherepossible.

RESPONSE:The last five years of expenditures for transmission vegetation management are:

F2000 $10.4MF2001 $12.2MF2002 $12.3MF2003 $14.5MF2004 $17.9 M (forecast)

The cost increases from F2002 to F2003 reflect increased vegetation workvolumes. The cost increase from F2003 to F2004 is due to extraordinaryvegetation maintenance in the Southern Interior and increased vegetation workvolumes in other parts of the system. The cost drivers relating to environmentalregulations are discussed in BC Hydro’s response to BCUC IR # 1.21.1.

The majority of BC Hydro’s transmission rights of way traverse areas where FirstNations have asserted aboriginal rights or title claims. Also, there are portions ofthe rights of way on reserve land. Increasingly, BC Hydro is consulting with thesecommunities regarding proposed herbicide applications. The increased costsassociated with consultation are estimated to be $100K to $250K per year. Theresulting use of alternative vegetation management programs to replace the useof herbicides would increase future annual maintenance costs by approximately$2.2 million per year.


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1.6.8 Page 6-24. Please describe the quality assurance program that BCTCwill implement to determine if the condition assessment audits are beingperformed adequately. Please also describe any other quality assuranceprograms.

RESPONSE:

The Asset Performance Management and Quality Assurance group performs thefollowing functions:• gathers and maintains detailed information about the condition of

transmission assets;• provides direction and oversight of work to document deficiencies in asset

performance;• evaluates this data to determine the effectiveness of the work programs

including the scope, frequency and priority of repair or replacement required;• identifies issues that require monitoring; and• evaluates the performance of service providers and directs where in-the-field

activities need to be modified.

Quality Assurance activities centre around technical audits by observing and/orinspecting sample services provided to BCTC to ensure compliance andefficiency. The details of these programs are currently being designed and toolsare being developed.


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1.6.9 Page 6-28. Supply to Vancouver Island. BCTC states that severalinitiatives are underway to improve the reliability of supply to VancouverIsland. Please describe these initiatives.

Page 6-51, Table 6-18, 500 kV Cable Shore Cooling System upgrades.Please describe the nature of this project. Will this or any other initiativesincrease the firm transfer capability to Vancouver Island? If so, by howmuch?

RESPONSE:

Several initiatives are underway to preserve the reliability of supply to VancouverIsland as much as possible, including:

Addressing the challenges of aging infrastructure• Increased levels of underwater inspection and monitoring of the 500 kV and

HVDC submarine cables from the mainland;• Focused maintenance as described in Chapter 6, Page 6-34, Line 22 to Pages

6-35, Line 2.• Replacements and refurbishment of equipment at end-of-life including 500 kV

circuit breakers on the 500 kV Cheekye-Malaspina-Dunsmuir major supplysystem to the Island, circuit switchers at the 500 kV terminal stations, andreplacement of HVDC submarine cable sections.

• Enhanced training of dispatch personnel for handling system contingencies.

Investment in new technologies• Single pole tripping on the 500 kV and other remedial action schemes to help

prevent load shedding during certain system contingencies.The 500 kV Cable Shore Cooling System project involves an $820,000 upgrade ofthe shore-end submarine cable cooling system and a pilot installation of a real-time conductor temperature and current monitoring system on one of the six 500kV single-phase cables. The latter employs a fibre-optic cable sensing systemover the shore-end portion of the 500 kV cable to assess its thermal capability inreal time with greater precision. A decision will be made, based on the pilot,whether to extend the technology to additional cables. The technology, when fullyinstalled, will reduce the risk of possible cable damage when either 500 kV circuitis operated to provide short-time (e.g. 2-hour) thermal overload power transfercapacity.

The Cable Shore Cooling System initiative is not expected to increase the firmtransfer capability to Vancouver Island.


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1.6.10 Page 6-28, Section 3.2.8.2.2, Lines 12-26

The Application states that the final report of the WECC Compliance auditshowed that BC Hydro Transmission system did not measure up to all theplanning standards and operating standards that have been incorporatedin the WECC Reliability Management System. The Application alsostates that a mitigation plan has been prepared to resolve the operatingmeasure and planning measure.

Please file a copy of this mitigation plan, including a copy of the “fullydeveloped plan for mitigating capacity shortages”.

RESPONSE:

The following documents are attached: • 2003 WECC Compliance Enforcement Program Compliance Action Plan – 26

June 2003; and• 2003 WECC Compliance Enforcement Program Compliance Action Plan – 30

June 2003.As indicated in Chapter 6, Page 6-28, Lines 21-26, the WECC Compliance Auditconcluded that the transmission system met seven of eight planning standardsand five of the six operating standards.The Planning Standard non-conformance noted that some aspects of the under-frequency load shedding restoration program are not in service. When there is alarge load - resource imbalance on the power system, under-frequency relays tripload to restore this balance. At times, too many loads are shed causing an over-frequency condition. The mitigation plans calls for a load restoration program tobe put in place by December 2004.

The Operating Standard non-conformance was related to the lack of a writtenprocedure that can be executed by system operators to deal with capacity andenergy shortage in the Control Area. BCTC’s mitigation plan is to add aprocedure in the Emergency Response Plan and Measures Operating Order forcurtailing load in the BC Hydro system for generation capacity shortages. Thisprocedure is now in place, however it will not be fully documented until mid-year2004.

Assessment of NERC Compliance 2003

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System Plannng, Transmission - Strategic Asset Management Page 13

Assessment of l-"ERC Compliance 2003

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6.11 Reference: Page 6-28, Section 3.2.8.2.2, Lines 27-30

1.6.11 The Application mentions that the WECC conducts periodic operatingaudits of compliance to operating policies and standards. Also mentionedis the most recent WECC audit of BC Hydro’s transmission system,conducted in August 2001.

Please provide a copy of the final report on the August 2001 WECCoperating audit of the BC Hydro’s transmission system. Also provide adescription of the implementation details for the five follow-uprecommendations in the report.

Page 6-28. WECC compliance. Is WECC contemplating a number ofmaintenance standards for inclusion in its mandatory complianceprograms? If so, please describe these initiatives and the consequencefor BCTC.

RESPONSE:

Due to security reasons, the August 2001 WECC operating audit report cannot bereleased publicly. However, the report findings and recommendations aresummarized below.

1. The review team noted that BC Hydro/BCTC had some outstanding compliancereview and disturbance report recommendations that had not been resolved orreports had not been provided by BC Hydro to indicate the current status. Thereview team recommended that BC Hydro devote attention to getting alloutstanding log items resolved before the end of 2001 and provide appropriatenotification to WECC. Status: BCTC is actively working to resolve the two outstanding log itemsnoted above. These items are of a minor nature and have a minimum impacton the interconnection. These items are:

(a) BC Hydro was commended for scheduling both dynamic and statictests of its generating units. The static tests were scheduled to becompleted by the end of 1997 and the dynamic tests were scheduled tobe completed by the end of 1998. WECC’s recommended schedulecalled for completion of all unit testing by June 1, 1998 and encouragedBC Hydro to complete its tests by then.Status: To date tests have been completed on the larger generatingunits. BCTC will have a status update by March 31, 2004.


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(b) BC Hydro did not have a procedure for mitigating capacity shortages. Inthe absence of such a procedure, BC Hydro’s merchant function wouldrely on the market to relieve capacity shortages. The review teamrecommended that BC Hydro develop a formal procedure foraddressing capacity shortages.Status: This procedure is now in place. It will be formally incorporatedinto BCTC Emergency Response Plan and associated System OperatingOrders in early 2004.

2. BC Hydro had not accounted for all small generators in its control area for thepurpose of determining its operating reserve requirement. Even though thisgeneration is less than 100 MW total and is a small percentage of the total BCHydro control area generation, the review team recommended that it beincluded in BC Hydro’s operating reserve requirement calculation.Status: This item will be completed prior to the next WECC Compliance Reviewscheduled for Summer 2004.

3. The review team was informed that inadvertent exchange between BC Hydroand the Alberta system operator had not always gone smoothly. BC Hydroreported that this was a result of metering inconsistencies between BC Hydroand Alberta system operator. BC Hydro was working with the Alberta systemoperator to develop and implement a process and procedure to resolve thisissue, and the review team encouraged BC Hydro and the Alberta systemoperator to resolve the issue before the end of 2001.Status: Completed.

4. BC Hydro was not fully in compliance with WECC’s Off-nominal FrequencyLoad Shedding and Restoration Plan with respect to automatic and delayedrestoration to prevent frequency overshoot. BC Hydro reported that it was onschedule to implement this capability by December 2001. The review teamrecommended that BC Hydro adhere to this schedule.Status: Completed.

5. The responses to the neighbour system questionnaires were overall veryfavorable regarding BC Hydro’s operations. Only a few issues were raised thatsuggest additional communication occur between BC Hydro, BPA, and PPA.The review team recommended that BC Hydro initiate contact with BPA andPPA to resolve these issues.Status: Completed

Regarding inclusion of maintenance standards in the WECC mandatorycompliance program, BCTC is advised that the WECC compliance group iscurrently finalizing the content of the 2004 Compliance Program. This is expectedto be completed in March 2004.


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1.6.12 Page 6-38, Lines 7-9: Please describe the security rating standards formajor transmission lines. Do these standards resemble the originaldesign standards for these lines? Did the original design standardsrequire that line clearing be such that no danger trees should encroachthe transmission lines? If so, why have the original standards not beenmaintained?

RESPONSE:BCTC’s Transmission Line Security Ratings are shown in the table below. Theydescribe the vegetation and line maintenance and operating approach for targetoutage duration levels assigned to lines throughout the system.

The current vegetation management standards differ from the original standardsfor the initial construction and operation of these lines.

When the transmission lines were constructed, they were cleared beyond the legalright-of way easement. The original clearing was usually much wider due to thehigh risk of tree blowdown on newly cleared edges. Generally, the trees along theedges are not adapted to open growing conditions and are susceptible to winddamage. Complete security from any falling trees was usually provided for a tenyear period for new lines.

The original full security clearing width was not set up as a standard to which theline would be maintained on an ongoing basis. Rather, it was implementedbecause of the "one time" high blow down risk created by the newly clearededges. Generally, trees outside the legal right-of-way are allowed to re-grow, asthere are no rights obtained to maintain a fully cleared strip outside the right-of-way. The legal easement is narrow enough that some trees, when they havereached their full height, could strike the line if they fall. Hazard trees (trees withflaws) are removed outside the right-of-way.

Commencing in F2002, a limited edge tree program was initiated to address theworst performing circuits. Individual dead, dying or leaning trees that have thepotential to hit the line, as well as strips of trees that have become decadent orexposed due to development near the line, are identified for removal. To datethere has not been a fully funded program to deal with edge tree issues ontransmission lines.


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Transmission Line Security Ratings

Line Security Rating N(Very High)

A(High)

B(Medium)

C(Low)

Outages None Momentary(Recloses) < 4 Hours > 4 Hours

Strategy • No grow-ins

• No treescould fallwithinflashoverdistance

• No grow-ins• Falling tree

could brushagainst line

• Momentaryoutageacceptable,with no linedamage.


remains on line• Switching

allowsrestorationwithin 4 hours


remains on line• Switching

cannot beundertakenwithin 4 hours

Comments • Requirescreation ofdanger treestrip whereall trees areremoved

• Selecteddanger treeremovalneeded tomaintain Arating

• There is nodifferencebetween B &C. This is afunction ofrestoration(switching)time.

• There is nodifferencebetween B &C. This is afunction ofrestoration(switching)time.

Lines Strategy • No knowndefects thatcould causean outage

• Lightningcould causemomentaryoutage

• No knowndefects thatcould cause anoutage


• Some knowndefects

• Switchingallowsrestorationwithin 4 hours


• Some knowndefects

• Switchingcannot beundertakenwithin 4 hours


Comments • Defectsimpactingpublic safetyand duediligence mustbe corrected

• Defectsimpactingpublic safetyand duediligence mustbe corrected


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1.6.13 Page 6-39, Lines 11 and 12: When did the new Pest Management Actcome into effect? Will this cause any cost increases for BCTC or BCHydro? If so, please estimate the impacts. How did BC Hydro manageits herbicide programs before the new Act?

RESPONSE:The Integrated Pest Management Act (IPM Act) received Royal Assent on October23, 2003.

A proposed schedule of fees is set out in the IPM Act Regulations DiscussionDocument dated November 14, 2003. Fees for each of BC Hydro and BCTC couldbe as high as $20,000 per year for pesticide use notices, vendor’s license andservice license. Current fees are approximately $1,125 per year for both BCTCand BC Hydro.

In addition, the penalties for offences under the new Act will increase from amaximum of $2,000 to a maximum of $200,000.

There may be additional costs if the Ministry of Water, Land and Air Protectionrequires BCTC and BC Hydro to hire third party qualified monitors for pre-treatment and compliance assessments. At this time it is not clear whether BCTCand BC Hydro can use qualified internal staff to perform these functions.

Before the IPM Act came into effect, herbicide use was authorized by PesticideUse Permits, which were valid for a three-year term. Under the IPM Act, theauthorization will be a Pest Management Plan, which is valid for a five-year term.There will be additional staff time and costs associated with producing theseplans as opposed to permits. However, once the plans are filed with the Ministrythere will be a reduction in administrative requirements.


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1.6.14 Page 6-41. BCTC states that an additional 36 positions are required forasset management and corporate functions. Please describe the needfor these additions.

RESPONSE:The BCTC organization is built upon BC Hydro’s Transmission line of businesssupplemented by functions required for an independent transmission businessentity. The BCTC plan for F2005 reflects 326 Full Time Equivalents (FTEs) of which290 FTEs are funded by the established Transmission line of business budget and36 new positions for corporate and asset management functions are required.

Additional positions are needed for the following reasons:

The Transmission line of business organization did not include corporatefunctions, therefore, no positions were transferred from BC Hydro corporatefunctions to BCTC. Twenty-one positions were created to provide the corporatefunctions that were previously provided from outside the Transmission line ofbusiness organization. These positions are in Finance and Corporate Services(9), Legal (4), Rates and Regulatory (4), Communication (2) and HumanResources (2).

Fourteen new positions were added for strategic and investment planning,stakeholder relations, and technology to support the implementation of theEnergy Plan and to complete the organization’s structure as an independenttransmission company.

Previous Transmission line of business positions were reviewed andredeployed into the new System Operations and Asset Management (SOAM)group organization. A net increase of 1 position is required to address gaps inorganizational capability in the area of asset performance management andquality assurance.


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1.6.15 Page 6-49, Table 6-16: Sustaining capital plan. Please provide anexample of the reports used to justify particular projects in these plans,e.g., Power Transformers or Protection and control projects.

RESPONSE:Please see attached report.

ritish Columbia TransmissionCORPORATION

Transmission InvestmentJustification

TIJ # 55132

Description: Diesel Control Panel Replacement

Proiect Number: 03-2D.05/ 1103949 Capital Request: $2.3MPortfolio: Sustaining OMA Request:Program- Telecommunications Project Initiation: 1 April 2004

iective:Priority Rank: Risk Assessment: LowPortolio Manager: Jim Gurney (77466) Project Initiator: E. Vasquez (77422)

Business Owner J. Robertson (77419)

Value Proposition:

Invest $2.3M to upgrade diesel generator control panels at 42 mountaintop microwave repeaters, to:

Replace aged, uneliable and discontinued equipment.Achieve target of no reductions in transmission transfer capacity due to loss of microwavecommuncations attbutable to malfunction of diesel generator control panels , for 20 years.Avoid necessity to man any generating station or substation due to loss of microwavecommuncation attbutable to loss of microwave communication attributable to malfuction ofdiesel generator control panels, for 20 years.

Background:

The microwave system carres protection, control, remedial action scheme (RAS) signalling,telemetering, data and voice traffc for protection and operation of the electrc system and internalbusiness communications. Diesel generators are used to back-up AC supply to the mountain topmicrowave repeater sites to ensure uninterrpted operation. The diesel generator control panels arean integral component of the back-up power supply system. Access to repeaters is extremelydiffcult durng the winter months, therefore high equipment reliability is essential. The dieselcontrol panels monitor AC power and fuel tan levels, star up the diesel generators on loss of ACor on demand and initiate alars to Telecommunications Network Operations (TNO). If amicrowave repeater should fail on loss of AC power, transmission transfer capacity could bereduced by approximately 20%, line protection capability would be reduced and several substationsand generating stations would have to be manned continuously until communications is restored.

Existing diesel generator control panels at 42 sites are older than 35 years. The recommendedlifetime is 20 to 25 years. Vendors have discontinued support for equipment of this vintage andmaintenance personnel must patch together defective panels with non-standard pars. Diffcultiesthat arse when tryng to maintain and service this equipment include:

13 February 2004

Component and printed circuit cards have been discontinued by the vendors and canot bepurchased;Replacement pars are not available within the BC Hydro equipment spare pools;Documentation and drawings are not available within BC Hydro nor from the manufactuer, toassist maintenance personnel in trouble-shooting the panels effectively

As well, failures are occurng in service, and are expected to increase in the futue. Durng the last12 months there were 69 incidents of diesel generator control panel corrective work done.

New control panels have technology and additional fuctionality that were not available when theoriginal current panels were purchased. TNO can communcate with the new panels via ethernetmodule, hub and serial multi-port servers. Ths new fuctionality wil allow TNO to access the newdiesel control panels in real time to download or upload information, thus improving visibility ofproblems and improving overall reliability.

Cost Summary:

The total capital project cost is $2317K. Approximately $17K has been spent to date for thedefinition phase under Preliminar EAR 1103949 and $2300K is required to complete the project.Retirement costs are $205K. There are no incremental OMA costs.

Cashflow:

EAR 1103949 ESP# Proj Total F2004 F2005 F2006(DefnPhase)

Diesel Control Panel Replacement 03-20. 317K $17K 120K , 180KTotal ($K) 317K

Risks:

Project implementation risks are considered low.

Key Dates:

Program starCompletion

1 April 200431 March 2006

Value Realization:

We wil know we have been successful when:

Mountaintop microwave repeater sites at 42 locations have been upgraded with diesel controlpanels that have low risk of failure.There are no reductions in transmission transfer capacity attbutable to failure of dieselgenerator control panels, for 20 years.There are no instances requiring maning of generating stations or substations due to microwavefailure attrbutable to diesel control panel malfuction, for 20 years.

13 February 2004

Signed:

I am accountable for the value described in the value proposition.

Ed Vasquez / Program Definition Manager Date

I agree that the proposed investment aligns with BCTC' strategic framework andcontributes the described value to BCTC.

A. Katrichak / Portolio Manager Date

Reviewed by J.H. Gurney 13 February 2004

13 February 2004


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1.6.16 Page 6-50, Table 6-17: Are capital expenditures for IPP’s offset by thecontributions in aid of construction? If so, please explain the difference inthe 2006 plan. If not, how are these contributions accounted for and howmuch are they?

RESPONSE:As explained in BC Hydro’s response to BCUC IR # 1.8.5, capital expenditures forIPPs are not fully offset by contributions in aid of construction (CIA). CIA partiallyoffsets capital expenditures for IPPs and other transmission customers forconnection to the transmission grid. The $9 million CIA for F2006 is notexclusively from IPPs but also relates to other customer requested transmissionprojects.

Contributions in aid are accounted for as “Deferred Credits and Other Liabilities”and amortized at the same rate as the related capital asset.


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1.6.17 (a) Page 6-47, Lines 21-23: BCTC describes sustaining capital ascapital expenditures which extend the life of an asset by 20percent or more. Is this definition used universally in BCH? Whendid this definition come into effect? If the definition changed,please quantify the amount of sustaining capital which would havepreviously been classified as maintenance expenses under the olddefinition since F1994?

RESPONSE:

Chapter 6, Page 6-47, Lines 21-23 incorrectly stated the description of sustainingcapital as capital expenditures that “either extend the service life of an existingasset by 20 percent or more, or are new assets that replace an existing asset.”The correct definition of sustaining capital is provided below and is consistentwith that used by BC Hydro. Despite the use of an incorrect definition norestatement is required. The capital planning approach for “Sustaining” Capital vs. “Growth” Capital wasfirst implemented in F2003 to ensure emphasis is placed on sustaining thecapability of the existing electric system, which is approaching end of life. Thedefinition for Sustaining Capital established during the F2003 planning cycle,used universally in BC Hydro, is as follows:“Capital expenditures required to sustain/maintain existing assets. This includesensuring that assets retain their existing/design value in terms of productivecapacity and improving/enhancing assets to minimum standards for reliability,safety and environmental security. The drivers of sustaining expenditures include:● Reliability which includes but is not limited to: life extensions, end of life

replacements, system reinforcements (designed and implemented to meetexisting load)

● Risk mitigation● Regulatory compliance● Environmental compliance and improvements● Safety compliance and improvements● Social requirements.”The criteria for capitalization of BC Hydro assets has remained consistent fromF1994 to today. Section 5.01 in the 1994 Statement of Accounting Policy “criteriafor capitalization” has not changed from the current section 5.01.Sustaining capital is a planning approach first introduced in F2003 rather than achange in accounting definition. Therefore, there is no amount of sustainingcapital to quantify which would have previously been classified as maintenanceexpenses.


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1.6.17 (b) Page 6-50, Load Growth, Lines 12-14

The Application mentions that the capital costs include severalsignificant projects required to meet BC Hydro’s demand forNetwork Integration Transmission Service.

The first project mentioned involves an increase in the transfercapability from the Interior to the Lower Mainland.

Please provide details of the actual project or projectscontemplated to accomplish this, and the associated costs.

RESPONSE:The details of projects contemplated to increase transfer capability from theInterior to the Lower Mainland are derived from a WTS “Facilities Study for BCHydro Generation Line-of-Business NITS 2001 (2002/03 – 2020/21) Report No: SPA2003-01, August 2003”.

F2005 investment in the project is limited to preliminary and preparatory worknecessary to achieve the in-service dates identified by BC Hydro. The preparatorywork includes public consultation and formal investment evaluation.

Details of the projects and associated costs are as follows:

New 500 kV Transmission Line (5L83)

The 250 km 500 kV transmission circuit 5L83 would run between the Nicola andMeridian Substations. For approximately 75% of the route, the line would beparallel to either existing transmission line Circuit 5L41 or 5L82. For this sectionno new right of way is anticipated, with the exception of right-of-way widening dueto adverse terrain conditions. 5L83 would be 50% series compensated at or nearAmerican Creek Capacitor Station.

At Meridian, two new 500 kV circuit breakers equipped with single pole reclosecapability would be required, along with the associated apparatus for terminatingthe new line. Two existing circuit breakers and five disconnects would bereplaced as a part of this termination.

At Nicola, one new 500 kV circuit breaker equipped with single pole reclosecapability would be required, along with the associated apparatus for terminatingthe new line. One existing circuit breaker and three disconnects would bereplaced as part of this termination. There would also be a 123 MVAR line reactorat Nicola.

The planned in-service date is 2011 and the estimated total plant-in-service cost is$257 million.


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Ingledow, Meridian, and Nicola 500 kV Shunt Capacitor

500 kV, 250 MVAR switchable capacitor banks would be added at Ingledow,Meridian and Nicola Stations.

The planned in-service dates are 2007 and 2008, and the estimated total plant-in-service cost is $28 million.

Ingledow Static Var Compensator (SVC)

A SVC rated -200 to +300 MVARs would be added and connected to the IngledowStation 500 kV bus.

The planned in-service date is 2008 and the estimated total plant-in-service cost is$38 million.


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1.6.18 Page 6-50, Load Growth, Line 15

The Load Growth capital program in the Application includes a project to“replace the reactive capability of the Burrard Generating Station.”

Please reconcile this project with the information contained on page 5-40which indicates that in the near term, Burrard units 1, 2 and 3 will beutilized to provide VAR support for voltage support requirements on theBC Hydro transmission system.

RESPONSE:As indicated in Chapter 5, Page 5-40, BC Hydro has committed the reactivecapability of the Burrard Generating Station for the short term for voltage supportrequirements on BC Hydro’s transmission system.

Pending a decision on the long-term use of the Burrard Generating Station units,it is necessary to retain viable options for voltage support if these units areunavailable in the long term. The investments described in Chapter 6, Page 6-50are limited, in the test years, to preliminary and preparatory work necessary toimplement them in a timely fashion.


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1.6.19 Page 6 -50, Load Growth, Lines 20-23

The Application states that several substation upgrades are contained inthe growth capital plan, as well as a new substation construction.Amounts of $8.4 million and $78.0 million have been allocated for F2005and F2006 respectively.

Please provide details of the specific projects that will incur these costs.Your response should include cost allocations for each individual projectover the two test years.

RESPONSE:The costs referred to in Chapter 6, Page 6-50, Lines 20-23 are incorrect. The tablebelow identifies specific substation upgrades, with costs included in the“Stations” line in Table 6-17, where expenditures are planned in either of the twotest years.

($000) F2005 F2006Fort St. John - 138/25 kV Substation $706 $2,667Hope - 25 kV Conversion 5,000Langley Area - System Reinforcement 1,605 4,285Maple Ridge Area Capacity Increase 239 1,117Mission and Matsqui Area - 69 kV Reinforcement 10,000 7,308Mt. Pleasant Area Supply 2,700 6,301South Interior Mobile Substation 1,151 1,281Transformer replacements and additions (6 stations) 8,059 9,112Feeder and feeder section additions (17 stations) 11,935 7,881Transfer bus capacity increases (3 stations) 1,372 63Other (7 stations) 579 1,645 Total $43,346 $41,660

Page 6-51, Table 6-18 includes individual substation upgrade capital projectswhere total cost during the test years is forecast to exceed $2 million. Projectsforecast to have total expenditures exceeding $5 million during the test years aredescribed in more detail on Pages 6-53 to 6-56. The revisions described abovehave no effect on the rates in the test years.

The revisions described are primarily allocations between periods and have noeffect on the rates in the test years.


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1.6.20 Page 6-55, Line 16: Does BCTC budget for distribution capital projects?If so, how are these projects charged to BC Hydro?

RESPONSE:BCTC does budget for distribution voltage equipment within the substation fence.BCTC does not budget for other distribution capital. BC Hydro pays for alldistribution capital projects, as it is the owner of the facilities.


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1.6.21 Page 6-74. Congestion management costs. Please describe the natureof these costs.

RESPONSE:BCTC incurs congestion management costs to address transmission capacityissues as they arise. System operators use congestion management tools tomaximize transmission system capacity. The budget for Congestion Managementin F2005 and F2006 is $1.0 million. Congestion Management costs relate to:

● Contingency Reserves – as a member of the NWPP reserve-sharing group BCHydro is able to carry reserves at a lower level than otherwise specified by theWestern Electricity Co-ordinating Council (WECC). This enables the systemoperator to economically manage its control area responsibilities. As thesystem operator, BCTC can issue a call for reserves to other members of thepool should a contingency arise. The annual cost of reserve sharing variesdepending on number of instances that shared reserves are called upon. Priorto February 2003 reserve sharing could be settled in cash or in kind.Beginning February 2003 all instances of reserve sharing must be settled incash.

● Operating Agreements between Control Areas - beginning in F2001 BC Hydroentered into an agreement with ESBI Alberta (now the Alberta Electric SystemOperator - AESO) to partially fund AESO's Interruptible Load Remedial ActionScheme (ILRAS). Under ILRAS the AESO pays Alberta parties to be on stand-by to shed load if necessary to avoid system disturbances. The result is anincrease in the import capacity of the intertie between BC and Alberta. Theincreased capacity results in higher PTP transmission revenue and moreimport sales in Alberta than would otherwise be the case. The payments toAESO for the ILRAS vary depending on the market; in F2001 this payment wasapproximately $0.4 million. In recent years, the payment has generally rangedfrom $20k to $50k annually.

● Transmission Locational Credits (Boston Bar) – the Boston Bar IPP receives abonus payment, of up to 25% of the electricity payments made during the prioryear, for providing back-up services to the area. Boston Bar has atransmission connection to the grid and a small local diesel generator. Theload grew beyond the size of BC Hydro’s generator. Therefore, whenever theline is taken out for maintenance or if the line is forced out-of-service, some ofthe load would need to be interrupted. With the IPP running, the load ismaintained. A bonus payment is made to the IPP if its generation is on whenthe transmission line is out of service. The annual bonus payment made to theBoston Bar IPP is $0.3 to $0.5 million annually.


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7.0 Reference: Application, Volume 1, Chapter 8, Power Smart, CustomerCare and Energy Management

1.7.1 Page 8-18. Does BC Hydro anticipate any significant impacts tocustomer rates if the proposals for Stepped Rates are implemented? Ifso, please provide an estimate of those potential impacts and pleaseindicate to what degree potential impacts have been incorporated into theRate Application for F2005 and F2006.

RESPONSE:

Assuming the proposal for Stepped Rates and the appropriate access rules, whichmitigate the potential for rate/market price arbitrage, are approved, BC Hydrodoes not anticipate any significant impacts to customer rates from the proposedStepped Rates. However, BC Hydro has estimated that it will cost approximately$440,000 to implement the Stepped Rates proposal. This includes CBLcalculations as well programming changes to the transmission billing system,Lodestar.


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● Unscheduled Flow Mitigation – this is a WECC program that pays theoperators of certain phase shifting transformers to operate those devices insuch a way that congestion is reduced in the WECC. Within the WECC thereare several phase transformers that provide not only local benefits but can beused to reduce congestion on major WECC transmission paths. By operatingthose phase shifters in a certain way the congestion at the points ofinterconnection is reduced. BC Hydro is not compensated for its phaseshifters as its devices only provide a benefit locally. The cost of UnscheduledFlow Mitigation is $0.1 million to $0.2 million annually.


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8.0 Reference: Application, Volume I, Chapter 11, Capital Expenditures

1.8.1 Page 11-1, Table 11-1: Explain the reason and source of the differencesfor the “Retirements” line items in Capital Assets in Service andAccumulated Depreciation.

RESPONSE:For purposes of the continuity schedule in Chapter 11, Page 11-1, Table 11-1, the“Retirements” line item included write-downs of assets and reclassifications ofbalances between balance sheet accounts in addition to asset retirements. Thereasons for the difference between the “Retirements” line items in Capital AssetsIn Service and Accumulated Deprecation are as follows:

• Retirements of assets prior to end of life (the asset is not fully depreciatedwhen retired and as a result the original cost retired is greater than theaccumulated depreciation retired);

• asset write-downs are recorded as a reduction to the original cost of theasset with little or no reduction in the accumulated depreciation; and

• reclassifications between balance sheet accounts to correct errors fromprior periods (e.g. reclassification between Accumulated Depreciation andFuture Removal and Site Restoration).

Retirements and write-downs greater than $5 million over the period are shown inthe table below.

Description Excess of Original CostOver Accumulated

Depreciation ($ million)Write-down in value of Hat Creek land 5Write-down in value of Mobile Radio System 9Write-down in value of High Power Lab assets 8Retirement of Coursier Dam 5Retirement of Keogh Diesel Generating Station 7Write-down of PIMS Data Restructure 5Write-down in value of Westech Goodwill 5

Table 11-1 shows original cost retirements of $688 million and accumulateddepreciation retirements of $614 million. In reviewing the retirement informationfor the period, misclassification between unfinished construction write-offs andassets in-service retirements were identified for F2000 and F2003. In addition,Table 11-1 includes a restatement to the opening 1994 original cost andaccumulated depreciation balances for a correction in the accounting of BCHydro/BC Tel joint poles. Prior to F1996, contributions from BC Tel for joint ownedpoles were treated as contributions in-aid of construction. However, as the polesare jointly owned, not fully owned by BC Hydro, the contributions should havebeen treated as reductions in the original cost of the assets. A simplifyingassumption was used in restating the number for Table 11-1. The adjustment for


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March 31, 1995 of a reduction in the original cost of $100 million and a reductionin accumulated depreciation of $42 million was used for the previous two years.However, as contributions were received from BC Tel in F1994 and F1995, theactual adjustments for years prior to F1995 was lower. Revised continuityschedules reflecting the revisions identified above are below.


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The revised original cost and accumulated depreciation retirements are $712million and $614 million, respectively.


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1.8.2 Page 11-2, Table 11-2: Provide Table 11-2 back to F2002.

RESPONSE:BC Hydro capital expenditure information for F2002 and F2003 is provided in thetable below; however information is not presented in the identical categoriespresented in Chapter 11, Page 11-2, Table 11-2. Prior to the full implementation ofthe new Peoplesoft Projects module in F2004, BC Hydro captured capitalexpenditures in different categories. Data captured in the new Projects modulealigns with the business functions used for reporting assets in-service. Using thedata available, the information is presented in categories as similar as possible tothose in Table 11-2.

BC Hydro began segregating sustaining and growth capital in F2003 to increasethe focus on maintaining the health of existing assets as they approach end oflife. Sustaining and growth information was not recorded in financial systemsprior to F2004. The F2003 categories were based on manual processes.Information on sustaining and growth categories prior to F2003 is not available.

Capital ExpendituresF2002 and F2003 Actuals

Expenditure Category F2002 F2003($ Millions) Total Sustaining Growth Total

Generation Hydro 87 88 58 146Generation Thermal 63 6 76 82Transmission 93 88 68 156Distribution 154 49 121 170Computers 70 82 6 88Land & Buildings 11 4 0 4Surveys & Investigations (including Aboriginal Negotiations) 10 11 0 11Vehicles 10 14 0 14Power Smart 14 45 45Other 32 25 0 25Total Gross Expenditures 545 367 374 741CIA - Specific -16 -17CIA - Recurring -38 -45Total Net Expenditures 491 367 374 679

The estimated F2002 sustaining and growth capital expenditures on an aggregatebasis, as stated in the BC Hydro F2002 Annual Report, were $333 million and $198million (excluding Power Smart), respectively.


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1.8.3 Page 11-2, Table 11-2: Explain the difference shown for Generationrelated capital in this Table versus the Generation capital shown in Table5-7 on page 5-10, and show where any differences are allocated.

RESPONSE:The BC Hydro Generation capital shown in Table 5-7 in Chapter 5, Page 5-10 refersto the Heritage Resources. The Generation Hydro and Generation Thermal relatedcapital in Table 11-2 in Chapter 11, Page 11-2 includes forecast expenditures forthe Vancouver Island Generation Project (VIGP) and the Georgia Strait CrossingProject (GSX) which are not Heritage Resources. GSX and VIGP are included inGeneration Thermal (Growth) on Table 11-2.

The reconciliation is shown in the table below.

($ millions) F2005Plan

F2006Plan

Table 11-2 Generation Hydro Total 109 135 Generation Thermal Total 61 196

170 331Deduct GSX/VIGP (58) (193)Add non facility assets such as Surveys & Investigations andComputers 18 11Table 5-7 130 149


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1.8.4 Page 11-2, Table 11-2: Explain the decreasing nature of the line item“Surveys & Investigations (including Aboriginal Negotiations)” contrastedagainst earlier statements in the summary that forecast increasing costsdue to effects from Environmental programs and First Nations issues.

RESPONSE:The line item “Surveys & Investigations (including Aboriginal Negotiations)” inTable 11-2, Chapter 11, on Page 11-2 consists of Aboriginal Negotiations and DamDeficiency Investigations. It does not include any environmental costs.

Table 5-28, Chapter 5, on Page 5-45 includes spending on major capital projectsfor First Nations negotiations. The decreasing costs in Tables 5-28 and 11-2 reflectthat two major negotiations are expected to conclude over the next two years,Williston First Nations in F2005 and Peace Athabasca Delta in F2006. Theseforecasts do not include estimates for settlements. It is the settlement costs thatwill primarily drive the increasing costs relating to Management of First Nationsrelated issues. Non-capital costs associated with environmental and aboriginal relations programmanagement are part of General and Administrative costs. Environmental capitalrequirements typically form part of broader projects associated with Dam Safetyor Generation Facilities and are embedded in the cost of these projects.


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1.8.5 Page 11-2, Table 11-2: Provide the sources and explain the details of theline items “CIA -specific” and “CIA - Recurring”.

RESPONSE:The "CIA – Specific" item in Chapter 11, Page 11-2, Table 11-2 reflectscontributions from IPPs or other WTS customers for the capital costs ofinterconnecting to BC Hydro’s transmission grid in accordance with TariffSupplement No. 26. The customer is responsible for the direct assignment costswhich include substation upgrades for interconnection, metering, installation of atransfer trip, etc. The costs of network upgrades that benefit all customers arepaid for by BC Hydro to the extent that the present value of any future revenuestreams are sufficient to cover these capital costs as well as the present value ofestimated operating and maintenance costs. The customer is responsible for anyshortfall. CIA is not exclusively received from IPPs but can be received from anycustomer requested transmission project.

The "CIA – Recurring" item in Table 11-2 is categorized as sustaining and growth.Sustaining CIA – Recurring reflects contributions from municipalities forbeautification projects. Growth CIA – Recurring reflects contributions bycustomers for extensions and connection capital work in accordance with theExtension Policy (approved by the BCUC in 1998). It also reflects contributionsfrom IPPs for the costs of BC Hydro distribution facilities needed to interconnectthe IPP’s generator. Forecast sustaining and growth CIA for F2004 is expected tobe received from customer groups in the following percentages:

Sustaining CIABeautification 100%

Growth CIAResidential 62%Commercial 26%Industrial 11%Uneconomic Extension Allowance 1%

Beautification, extensions and customer connection recurring capital is budgetedat the regional level by type of work. The budget considers the load forecast(including net customer additions), local economic conditions and historical dataand trends. CIA associated with this capital work is budgeted based on historicaltrends of the ratio of contribution to construction costs. An estimate of CIA bycustomer type is not available for F2005 and F2006 as the plan is not developed atthat level of detail.


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8.6 Page 11-2, Table 11-2: Provide details of the “Computers” line item.

RESPONSE:The "Computers" line item in Table 11-2 on page 11-2 of the Application includesthe major IT initiative sustaining and growth expenditures shown in the tablebelow. As shown in Table 11-2, the majority of these expenditures are sustaining.

These IT initiatives are summarised below.

• Computer Network: Replacement of aging assets to ensure reliability.

• Enterprise Wide Applications: Enhancement of enterprise applications toimprove work management and supply chain operations.

Capital Expenditures Forecast, F2004 to F2006Description of "Computers" Expenditure Category($ millions)

By Initiative Grouping F2004 F2005 F2006

Computer network 9.9 18.7 16.1 Enterprise Wide Applications 12.4 5.0 8.0 PC / Desktop Software Refresh 3.0 7.0 5.2 Energy Trading and Risk Management 6.5 5.1 5.0 Customer Care 17.9 5.6 5.7 Payroll and Human Resources 0.2 2.7 3.0 Human Resources Scheduling 2.6 5.4 1.2 Knowledge Capture and Sharing 1.7 2.4 0.8 Generation Planning, Scheduling and Operations 8.4 6.7 6.1 Disaster Planning 1.7 2.8 1.0 Energy Demand Management 2.1 1.5 1.6 Asset and Project Management 0.1 0.6 0.1 Misc Small Projects 1.1 0.8 1.0 Total 67.4 64.3 54.4


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• PC/Desktop Software Refresh: Replacement of aging assets to ensurereliability.

• Energy Trading and Risk Management: Implementation of systems to enhancerisk management, reporting practices and market information systems.

• Customer Care: Enhance Customer Care System to improve customer service.

• Payroll and Human Resources: Upgrades to the Pay/HR application to continuereceiving support from the software vendor, to incorporate best practices andto move the package to BCH standard architecture to improve reliability.

• Human Resource Scheduling: Enhanced scheduling to improve customerresponse times and the utilisation of field resources.

• Knowledge Capture and Sharing: Implementation of systems to capture andorganise information as a mitigation strategy for BCH’s aging workforce.

• Generation Integrated Planning, Scheduling, Ops: Enhancement of systemsthat support planning, monitoring and optimisation of operations, assets andfacilities for long term profitability.

• Business Continuity: ongoing enhancement of business continuity planningand disaster recovery planning for business critical back-up systems.

• Demand Side Management: Affect reductions in demand by customers andincrease predictability of demand by customers resulting in operationalefficiencies.

• Portfolio Management: Implementation of systems to identify and optimise BCHydro’s portfolio of technology assets and projects to improve the overallvalue to the corporation.


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1.8.7 Page 11-3 and 11-4, Table 11-3: Provide details surrounding thecapitalization of Dam Deficiency Investigations instead of holding thesecosts in investigative accounts.

RESPONSE:Dam Deficiency Investigations are treated as deferred capital instead of expense,because the costs incurred contribute to the long term optimization of waterstorage in the reservoirs and related electricity generation.

Costs of the surveillance, periodic comprehensive dam safety reviews andidentification and prioritization of dam safety issues are expensed as incurred.

Once a potential or actual deficiency is identified, a Dam Deficiency Investigationis initiated to clearly define the problem through study and to develop options tomitigate the risk as required. The Dam Deficiency Investigation is an integral stepin assuring the future safe operation of the dams and associated works.

Capital projects arising from the investigations generally result in the installationof additional monitoring instruments, improvements to waterways orstrengthening of the dams.


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1.8.8 Page 11-7, Section 2.1.6: Provide greater details of the programs andtools that were implemented as part of this project, and the improvementsmade to modeling tools utilized to manage BC Hydro’s reservoirs.

RESPONSE:Further details of the four projects implemented as part of the Business TransitionProgram (BTP) in BC Hydro Generation, as described in Chapter 11, Page 11-7,Section 2.1.6, are as follows:

Asset Management (AM)The Asset Management project replaced a maintenance management (work order)system installed in the early 80's that was difficult to support and upgrade, andwas not year 2000 compliant.

The new system is Indus's PassPort product, which is integrated with BC Hydro’sPeoplesoft financial systems. The project involved installing the infrastructureand software to support the application and modifying BC Hydro Generation'sexisting equipment hierarchy, maintenance processes, job roles, and trainingprograms. The new system allows maintenance managementto be morecommercially focused, which was more difficult on the old system.

Operational Information (OI)The Operational Information system was implemented to capture real timeoperating data from generation plant equipment instrumentation and controlsystems. The data is available in real time, locally and remotely, for analysis anduse within the business to support more efficient dispatch, and commerciallyfocused maintenance planning and scheduling decisions.

The database application is OSIsoft's' PI (Plant Information) product.

Commercial Resource Optimization (CRO)This project enhanced existing modelling and forecasting tools used by BC HydroGeneration operations planners. The primary objective was to develop andcommunicate more accurate, comprehensive and timely data for planning andoperating the system.


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Further details of the CRO project include:

• A commercial software product called Hydstra/TSM was implemented forquality control and archiving of large volumes of hydrometric data. This waterresource data is required to manage and operate BC Hydro’s generationfacilities.

• A database application was implemented to provide a common store ofequipment performance data and flow control characteristic data for commonuse by models and support staff.

• Water basin runoff models were enhanced for several basins.

• Tools for short and medium term optimization were developed. The DynamicUnit Commitment and Loading program was developed to enhance BC Hydro’sability to provide optimum commitment (number of units of a plant generating)and optimum loading (the MW allocated to each unit of a plant). The Short-Term Optimization Model was enhanced to make it more realistic.

• The existing environment of mixed computer platforms and unconnectedmodels was converted into an integrated IT environment and decision supportsystem. An application was built to contain operating data for generationfacilities at a central location. This ensures that data used by models andplanners is the same for all users and is secure.

Commercial Management (CM)Commercial Management consists of a software tool and business processes thatimprove tracking of operations and communicate system-level information togenerating facility staff, such as market prices. In particular, CM allows:

• recording and tracking of operating instructions and approvals;

• communication by plants of the capabilities of their units in light of changedcircumstances so that optimal generation planning can be undertaken;

• planning, approving, and recording of generation unit outages;

• recording of instructions related to the release of water not related to thegeneration of power; and

• increased access to electricity market information for generating facility staff.


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1.8.9 Page 11-8, Lines 2 and 3: Provide the economic analysis that supportedthe decision to rehabilitate Burrard Unit 1. Please also explain the natureof the additional estimated cost of $14.7 million for the generating stationupgrade (per Table 11-3) beyond the $184.6 million spent up to March31, 2003.

RESPONSE:A net present value analysis was performed to determine if rehabilitating orreplacing Burrard Generating Station Unit 1 would provide benefits beyondoperating with 5 units only. Market opportunities, operating costs and the capitalcost associated with implementing each alternative were considered.

The costs to rehabilitate Unit 1 and return it to service was forecast to provide a10-year present value benefit of $16 million as compared to operating with 5 unitsonly. Replacement of Unit 1 had a higher present value cost of $6 million ascompared to operating with 5 units only. Therefore, the rehabilitation of Unit 1was selected.

Chapter 11, Page 11-4, Table 11-3 shows, for the Burrard Generating StationUpgrade, $199.3 million as the Estimated Cost at Completion. The spending toMarch 31, 2003 of $184.6 million excludes spending prior to April 1, 1994 (pleasesee Note 3 to Table 11-3). Of the $14.7 million difference between the twonumbers, $6.7 million was spent prior to April 1, 1994 and $8.0 million is forecastto be spent in F2004.

F2004 expenditures are for the following major tasks:• Boilers and Controls $3.6 million• Mandatory Health & Safety $2.3 million• Engineering & Project Management $1.5 million

Physical construction was substantially complete by October 31, 2003.Commissioning and testing and project documentation is forecast to continuethrough April 2004.


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1.8.10 Page 11-8, Lines 20 to 23: What specific improvements were made tothe units used for VAR support, and what criteria were used toeconomically justify the specific improvements in light of their dispatchsolely for VAR support?

RESPONSE:Burrard Generating Station Units 1 to 4 are capable of providing VAR support.Currently Units 1, 2 and 3 are operated solely in synchronous condense mode forVAR support.

The decision to operate 3 units only for VARs was made in late 2003 based on theforecast of the expected energy generation from the plant, which was minimal.The generation capability of G1, G2 and G3 has been put on long-term recall. Thedecisions to undertake the specific improvements on these units were made aspart of the Burrard Upgrade Project in the 1990’s.

The scope of the upgrade work for Units 1, 2 and 3 addressed only work requiredby the GVRD Air Permit issued in 1994 and other work to meet safety andenvironmental standards including asbestos removal. This work was necessaryto allow the units to be available for generation, if required. The GVRD Air Permitrequired annual reductions in emissions and required the installation of selectivecatalytic reduction (SCR) control technology on all 6 units between 1995 and 2000.

The expenditures specifically related to Units 1, 2 and 3 are $14.1 million, $18.2million and $18.2 million, respectively. The majority of these costs were for theinstallation of SCRs.


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1.8.11 Page 11-13, Line 18 to 23: Please provide the economic analysis for thereplacement of exciters on GM Shrum units 1-8.

RESPONSE:The GM Shrum generating station has ten exciters, one for each generator. Eightof ten exciters had exceeded their estimated useful lives and exciter failures werethe leading cause of forced or unplanned outages in 2001. This model was nolonger in production and there was a limited availability of spare parts. There wasa significant and increasing risk of collateral damage to the generators from in-service failures of the exciters. Lead times for delivery of exciter replacements isapproximately eight months.

The economic analysis for the replacement of exciters on GM Shrum units 1-8 wasto use a least cost approach, including lost opportunity revenues due to outages,to evaluate and compare alternatives. The replacement alternative was the leastcost option for each period considered, as shown in the table below.

Net Present Value ($ millions) 20 Years F2021

Alt #1: Exciter Replacement Program $10.0

Alt #2 – Do Nothing / Run to Failure $35.8

Alt #3 – Refurbish the Obsolete Exciters Not Economical

Alt #4 – Buy Two Spares and Run to Failure $18.7

The variable refurbishment options considered were only partial solutions to theobsolete excitation systems. Partially refurbished exciters would continue to bemore costly to maintain, would be less reliable, would continue to have forcedoutages and would have a shorter life than new exciters.


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1.8.12 Page 11-13, Line 18 to 23: Provide the economic evaluation supportingthe replacement of the generator transforms and the comparison to theoption of rewinding the transformers.

RESPONSE:The evaluation supporting replacement of the GM Shrum transformers isdiscussed in BC Hydro’s response to BCUC IR #1.5.41.

The economic analysis for the replacement of transformers at GM Shrum unitsused a least cost approach, including lost market opportunity, to evaluate andcompare alternatives, as summarized in the table below.

Net present values ($ millions) 20 YearsF2021

Replace 12 transformers over 3 years

(selected alternative) $18.6

Replace 12 transformers in F2001 $20.8

Hold 4 spares and run to failure $22.7

Just in time replacement $35.4

Rebuild the transformers (at end ofestimated useful life)

Noteconomical

The rebuild (rewind) option was considered uneconomic. The cost to rebuild wasestimated to be $0.5 to $1.0 million per transformer, and the resulting rebuilttransformers would have poorer reliability and a shorter life than newtransformers.


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1.8.13 Page 11-19, Section 2.2.18: Has the manufacturer of the original Micagenerators offered any economic assistance towards the resolution of theproblem? Are there any remedies available similar to those beingpursued as described in Section 2.2.19? If not, why not?

RESPONSE:The manufacturer of the original Mica generators paid BC Hydro $3 million andagreed to a warranty program in 1986 as part of a settlement with BC Hydro. BCHydro may still have valid claims in respect of these generators and isinvestigating that possibility. These possible claims are too uncertain at this timeto be included in BC Hydro’s forecasts for F2005 and F2006.


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9.0 Reference: Application, Volume II, Appendix J

1.9.1 Page 4, Table 6: Is the Net Storage Returns (Exchange Nets) otherwisecalled Non-Treaty Storage and are Net Storage Returns (Exchange Nets)the same as Plus Exchange (net) indicated in Volume I, Tab 4, Table 4-7.If it is Non-Treaty Storage, can receipt and return obligations drive surplussales and additional Powerex purchases?

RESPONSE:Net Storage Returns (Exchange Nets) is the same as Exchange (net).

Exchange (net) is comprised of net energy exchanges relating to the followingagreements:

● Non-Treaty Storage Agreement, with Bonneville PowerAdministration;

● Kootenay Canal Plant Agreement, with Aquila Networks Canada;● Keenleyside Entitlement Agreement, with Columbia Power

Corporation; and● other shorter-term treaty operating agreements.

Non-Treaty storage is not necessarily the largest component of Exchange net.These energy transfers have no corresponding monetary settlements.

As indicated in BC Hydro’s response to BCUC IR #1.2.20, there is no directrelationship between Exchange net and either surplus sales or Powerexpurchases.


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1.9.2 Page 4, Table 6: Given that Hydro generation was significantly up inF2003, was it Net Storage Returns that drove Net Purchase fromPowerex as indicated for F2003 in Table 6?



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1.9.3 Page 4, Table 6: Please explain Other Energy Purchases and NetPurchase from Powerex in Table 6 and the difference between the two.Was there an agreement similar to the present Transfer PricingAgreement in place during F2003 with the “exclusivity” clause? Pleaseexplain the difference in pricing between the two purchases indicated inTable 8.

RESPONSE:“Other Energy Purchases” in Appendix J, Page 4, Table 6 includes net marketpurchases made by Powerex at times when the Electricity Transfer Price is lessthan or equal to the Threshold Purchase Price (both as defined in the TransferPricing Agreement provided at Appendix K). This includes all transactionsexecuted pursuant to Section 5.2 of the Transfer Pricing Agreement. Thesepurchases are made to minimise the cost of meeting Heritage Energy obligations.

“Net Purchase from Powerex” includes market purchases made by Powerex forthe purpose of electricity trade – i.e. all transactions executed pursuant to Section6.1 of the Transfer Pricing Agreement.

The Transfer Pricing Agreement for F2003 was essentially the same as the currentagreement, the only significant difference was the allocation of transmissioncosts within B.C. The exclusivity clause still applied.

The pricing for the two purchases is identical – at the Electricity Transfer Pricespecified in the Transfer Pricing Agreement.

Normally, while the pricing provisions are identical, because “Other EnergyPurchases” transactions only occur when the Electricity Transfer Price is belowthe Threshold Buy Price, only the lowest cost market purchases will be allocatedto meeting Heritage Energy obligations. For example, if BC Hydro sets aThreshold Buy Price of $40/MWh, all net imports that occur when the ElectricityTransfer Price is less than $40/MWh will be to BC Hydro’s account. Net Importsthat occur when the Electricity Transfer Price is above $40/MWh will be allocatedto the Trade Account and will be set off against trade income. As a result theaverage cost of “Other Energy Purchases” for domestic will be lower than theaverage cost of “Net Purchase from Powerex” for trade.

However in F2003, Table 8 shows that Net Purchases from Powerex had a lowerweighted average cost than Other Energy Purchases. This reflects the differencein timing of the bulk of these purchase transactions. While overall marketpurchases volumes were relatively low during most of F2003 due to healthyWilliston Reservoir runoff conditions, significant market purchases werenecessary during Feb-Mar 2003 due to low Kinbasket Reservoir level conditions.There was little flexibility to delay purchases to a less expensive time, so theaverage purchase price for F2003 was relatively high. A greater portion of NetPurchases from Powerex occurred during the freshet when prices were lower.


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1.9.4 Page 5. Please rationalize Lines 13-16 against the annual averagemarket purchase rates set out in Volume I, Tab 2, Schedule A-9, Line 43which seem to indicate a significant downward trend.

RESPONSE:The statement in Lines 13-16 of Volume II, Appendix J, Page 5 refers to the generalincreasing trend in North American energy market prices over the period F1994 toF2003. This general trend is related primarily to continent-wide demand growthand supply-demand imbalances, but has very little relationship, for example, tosnowpack and reservoir conditions within BC

The market electricity purchases costs in Chapter 2, Page 2-49, Schedule A-9 arevery specific to BC Hydro’s domestic requirements in F2003 to F2006 and arerelated very much to reservoir and snowpack conditions during the period.

While overall market purchase volumes were relatively low during most of F2003due to healthy Williston Reservoir runoff conditions, significant market purchaseswere necessary during February and March 2003 due to low Kinbasket Reservoirlevel conditions. There was little flexibility to delay purchases to a less expensivetime, so the average purchase price for F2003 was relatively high. However, withsystem storage expected to recover gradually over the period to F2006,operational and marketing flexibility will be regained. Also, assuming continuedaverage inflows throughout this period, market electricity purchase requirementsare expected to decline. Therefore, BC Hydro will be able to time the reducedvolumes of market purchases to coincide with the least expensive market periods,thereby reducing average purchase costs.

Please also see BC Hydro’s response to BCUC IR #1.2.22.


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1.9.5 Page 5, Table 7: As indicated in Table 7, what is the BypassTransportation Agreement between Terasen and BC Hydro and does thisagreement extend, and impact customer rates, beyond F2003?

RESPONSE:The Bypass Transportation Agreement (BTA) between Terasen and BC Hydroprovides firm delivery of gas supply on the Terasen Coastal Transmission Systemto the six generating units at Burrard Generating Station for an annual fixeddemand charge of approximately $9.8 million. Approximately 7% of the gastransportation capacity is used to deliver gas to the Island Cogeneration Plant onVancouver Island under a capacity assignment agreement with Terasen Gas(Vancouver Island) Inc.

The term of the BTA agreement is 30 years from the service commencement dateof November 1, 1999. The agreement contains an early termination provisionexercisable at BC Hydro’s option on or after the tenth anniversary, i.e. November1, 2009. The exit fee on or after November 1, 2009 is the undepreciated net bookvalue of the incremental facilities (approximately $22 million) installed by Terasenon its Coastal Transmission System after the commencement of the agreementand which are required to provide firm transportation service to BC Hydro underthe agreement.


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1.9.6 Page 5, Table 8: Please provide the average cost of natural gas used atBurrard Thermal from F1994 through F2003. Please provide the monthlyforecast of gas prices to BC Hydro for Burrard Thermal for F2005 andF2006 used to establish Volume I, Tab 5, Table 5-2 and indicate fromwhere this forecast originates.

RESPONSE:The average costs of natural gas (approximate) for the Burrard Generating Stationfrom F1994 to F2003 are shown in the table below. The gas prices includeapplicable taxes.

Burrard Generation and Gas Cost

The main reasons for the substantial variation in annual gas commodity costs arethe amount of plant dispatch and the volatility in natural gas prices. The volatilityof gas prices is reflected in the unit dispatching cost for the Burrard GeneratingStation. Prior to 1998, BC Hydro operated the Burrard Generating Stationprimarily on "valley gas" procured under a 10-year agreement with BC Gas (nowTerasen). This seasonal gas was provided to the Burrard Generating Station at adiscount to the Sumas market index and resulted in a favourable gas price for theBurrard Generating Station during this period (e.g. $1-2/GJ). When the agreementexpired in September 1998, gas for the Burrard Generating Station was effectivelyprocured at full market price, and the dispatching cost increased accordingly.

In F2001 and F2002, there was a substantial increase in the gas price index atSumas resulting from the California energy crisis. However, because marketpower prices were also extremely high during this period, the Burrard GeneratingStation was dispatched despite the high gas prices, resulting in very high unitcosts ($5-10/GJ). The high unit cost in F2003 is explained by the low amount ofdispatch (110 GWh), rather than by high gas prices. Low dispatch results in apoor average heat rate due to short periods of operation.

For F2005 and F2006 forecast gas prices, please see BC Hydro’s response toBCUC IR #1.14.7.

Actual Actual Actual Actual Actual Actual Actual Actual Actual ActualFiscal Year 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Generation in GWh 3,248 3,812 3,502 428 1,378 3,177 1,312 3,974 2,731 110Unit Gas Cost $/GJ 1.44 1.76 1.45 1.97 1.15 2.27 3.29 9.14 5.24 6.69


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1.9.7 Page 5. Given the statement on the market on page 5, Lines 13-16, doesBC Hydro anticipate sales to Powerex out of thermal when market pricesexceed the variable thermal costs? What constraints are there to runningBurrard for export at times when it is surplus to the load requirements ofthe Integrated System and when the variable cost is less than theThreshold Sale Price?

RESPONSE:Under average water conditions, BC Hydro has not forecast any sales to Powerexfrom thermal generation, other than those from Fort Nelson. However, if marketprices exceeded variable thermal costs and surplus thermal capability wasavailable, the Transfer Pricing Agreement does contemplate that suchtransactions could occur.

There are no general constraints on running the Burrard Generating Station attimes when it is surplus to the load requirements of the Integrated System otherthan general constraints on plant dispatch in applicable licences and permits.However, BC Hydro has sole discretion on the dispatch of thermal generation andtherefore could establish such constraints that it considered appropriate at thetime.

In general, BC Hydro only establishes a Threshold Sale Price for the purposes ofselling Surplus Hydro Energy, and only after it has reduced all dispatchablethermal generation to minimum levels. This is only expected to occur during highstream flow years and it is unlikely that Burrard Generating Station would bedispatched under these conditions.

For example, when a Threshold Sale Price is set all net exports accrue to BCHydro whenever the Electricity Transfer Price is greater than the Threshold SalePrice. During these periods, if Powerex requests that Burrard Generating Stationbe dispatched because its variable cost is less than the Threshold Sale Price, allof Burrard Generating Station’s generation would accrue to the Trade Accountand Powerex would run the risk of spilling this energy from its Trade Account.


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1.9.8 Page 19. Please provide the status of RTO West and please elaborateon the statement on page 19, Lines 1-2 that “ …efforts in this regard willprotect and enhance that electricity trade value.” Are negotiations stillproceeding and if so when are they anticipated to be concluded? Whatare the major issues and/or stumbling blocks? The Commission directedAquila to enter into discussions with BC Hydro regarding an IndependentSystem Operator for B.C. What is the status of those discussions?

RESPONSE:Transmission access to the United States electricity markets is vital tomaintaining electricity trade value. Currently both Bonneville PowerAdministration (BPA) and BC Hydro (and in fact most transmission serviceproviders in the WECC) operate under a very similar tariff that for the most partmirrors FERC’s Order 888 Pro Forma Tariff. This helps to facilitate trade becausethe rules for purchasing wholesale transmission service are similar, whichreduces seams issues between the various transmission providers. However,even under these circumstances residual seams issues and barriers to trade exist.Issues such as rate pancaking, differing implementation of the tariff throughbusiness practices, requirements to reserve service across multiple systems,among others, all lead to transactional inefficiencies. FERC proposed RTOs, inpart, to bring natural market regions (such as the Western states and BritishColumbia) under a common set of commercial principles, and to improve theaccess to, and reliability of, transmission systems to foster and improve trade.

As the RTO most pertinent to the interests of BC Hydro and British Columbia, BCHydro and BCTC have been participating in the development of RTO West sincethe initiation of its collaborative process (shortly after the issuance of FERC’sOrder 2000) in order to have significant input into the market design concepts thatare being debated, and to further enhance British Columbia’s electricity trade inthe West.

BC Hydro participated directly as a “filing utility” (the group of utilities primarilyresponsible for the funding and development of the RTO proposal) with AvistaCorporation, Northwestern Energy, BPA, Idaho Power Company, Nevada PowerCompany and Sierra Pacific Power Company, Pacificorp, Portland General ElectricCompany, and Puget Sound Energy in the development of RTO West, includingthe submission of a major proposal to FERC defining the framework, marketdesign, and governance structure for RTO West in March of 2002 (the Stage 2proposal). BCTC has recently assumed the filing utility role from BC Hydropursuant to Article 10 of the Master Agreement.

More recently, the Stage 2 proposal has been the subject of stakeholder reviewand reappraisal in the Pacific Northwest and a new regional proposal that buildson the previous work is under active development. In mid-2003, the Regional


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Representatives Group (RRG), the stakeholder body formed for the purposes ofRTO West collaborative development, and representatives of state and provincialregulatory bodies were invited by the filing utilities to review and reconsiderregional solutions to transmission issues in the Pacific Northwest, includingelements of the Stage 2 proposal. A number of meetings were held over thesummer and fall of 2003, dedicated to defining transmission problems andsolutions and to developing a “framework” for solutions that “workable, cost-effective, and responsive to the region’s needs.”

The culmination of this work is the beginning of a new proposal that has, at itscentre, the establishment of an independent entity to provide services totransmission owners and operators across the region. A staged implementationframework is proposed to enable the independent entity to perform morefunctions or services over time. A narrative description of this draft proposalentitled “Narrative Description of RRG Platform Group Regional Proposal” wasposted on the RTO West website on December 24, 2003.

The proposal envisages that the independent entity will start with an initial set offunctions and services, and that it will progress to a targeted “end-state” that issimilar, albeit not identical, to the RTO West Stage 2 proposal, subject toconsultation with state and provincial government bodies and subject to specialgovernance provisions that are triggered at various stages. A full description ofthe proposal is set out in the narrative document.

The development and creation of an RTO in the Pacific Northwest is complex.There are many aspect of the proposal that require further study and work. Thenear term work primarily involves development of the proposal, rather than theresolution of “stumbling blocks” or “major issues”. The development of aprocess to take the proposal to completion, including definition of the steps andtiming, is currently under discussion in the RRG context.

No formal decision to participate in an RTO in the Pacific Northwest has yet beenmade by BCTC, BC Hydro or the other filing utilities. BCTC is participating in thedevelopment of the proposal on the premise that any participation by BCTC or BCHydro must provide for local control over transmission facilities in BC, mustprovide for local regulatory oversight over transmission services in BC, and mustbe in the best interests of British Columbia. Participation by BCTC or BC Hydro inRTO West or the RTO West regional markets is subject to the approval of thegovernment. BC Hydro and more recently BCTC have had a number of discussions with Aquilato explore the form and timing of the development of a single Independent SystemOperator for BC. The creation of BCTC pursuant to the provincial Energy Plan hasprovided the framework for more recent discussions. The timeframe forresolution should recognize that Aquila is currently undergoing a period oftransition related to the recent transaction. Aquila and BC Hydro/BCTC have alsocooperated in joint planning efforts such as the recent South Okanagan plan toachieve results that could not have been achieved unilaterally by either side.


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10.0 Reference: Application, Volume II, Appendix K

1.10.0 Pages 5 and 9, Definition 1.1.17: Please provide a list of these InterutilityAgreements. Clause 5.2. Please explain the qualifier leading off the firstsentence, “Except as provided by Interutility Agreements.” The definitionof Interutility Agreements seems to preclude purchases. What are theterms of those agreements that might drive sales or purchases?

RESPONSE:List of Interutility Agreements:● Kootenay Canal Plant Agreement, signed in 1972 with Cominco and West

Kootenay Power (now Aquila), and joined in 1996 by Columbia Basin PowerCompany, a joint venture between Columbia Power Corporation and theColumbia Basin Trust.

● Columbia River Treaty, signed in 1964 between Canada and the United Statesof America, and operating plans developed pursuant to the Treaty (BC Hydro isthe “Canadian Entity” under the Treaty).

● Columbia River Treaty operating agreements signed on an ongoing basis withthe U.S. Entity. Examples of these include: The Libby CoordinationAgreement; The Non-Power Uses Agreement; The Arrow Local Agreement;and various water swap agreements.

● Non-Treaty Storage Agreement, signed in 1990 with Bonneville PowerAdministration.

● Agreements under the Skagit Valley Treaty, signed in 1984 with the City ofSeattle.

● Interconnection and Exchange Agreement, signed in 1991 with BonnevillePower Administration and Powerex.

● Interconnection Agreement, signed in 1999 with TransAlta Energy Corporation.● Interconnection Agreement, signed in 1998 with ESBI Alberta.● Interconnection Coordination Agreement, signed in 1999 with TransAlta,

Kanelk and Powerex.● Exchange Agreement, signed in 1978 with Alcan.

None of the above agreements were established to purchase or sell transmission,capacity or energy for profit. In general they provide for and allow emergencysupport and optimized system operation through improved coordination.

The qualifier, “Except as provided by Interutility Agreements”, was added todocument the exclusion of these coordination-based power transferralagreements from the Transfer Pricing Agreement between Powerex and BC Hydro.


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11.0 Reference: Application, Volume 1, Chapter 6, p. 6-36

Preamble: Page 6-36 of the Application states that Transmission has 75,000wooden pole structures. It would seem reasonable to expect that wooden poleswould have a longer life in dry Interior locations than in wet coastal areas like theLower Mainland and Vancouver Island.

1.11.1 Please define Wet (e.g., the Lower Mainland and Vancouver Island) andDry (e.g., the remainder of the Province) locations that together cover thetotal number of Transmission poles in service, and state how manywooden poles Transmission currently has in service in each of Wet andDry locations.

RESPONSE:

BCTC does not have site specific identification of “wet” and “dry” locations.Therefore, BCTC has used the definition suggested in the question. The numberof wood pole structures in service in the Lower Mainland and Vancouver Island isapproximately 29,000 and the number of wood pole structures in the remainder ofthe Province is approximately 45,500 for a total of approximately 74,500structures.


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1.11.2 How many wooden poles does Transmission plan to replace in each ofF2005 and F2006 in each of Wet and Dry locations? What is the forecastaverage and total cost of such pole replacements in each of Wet and Drylocations?

RESPONSE:The following table shows planned replacements and forecast costs for F2005.

F2005Quantity Average Cost ($) Total Costs ($000)

LM and VI 300 $4,000 $1,200Remainder 380 4,700 1,800Total 680 3,000

BCTC does not have specific numbers for F2006 as the F2005 field test programwill identify requirements, however, the numbers have been fairly consistent inthe past and BCTC anticipates the program to be of a similar magnitude.


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1.11.3 Please explain how BC Hydro estimated the number of woodenTransmission poles that it plans to replace in F2005 and F2006.

RESPONSE:The pole replacement requirement is based on the field test program of theprevious year, which evaluates the condition of poles in service. Poles arereplaced based on their suitability for service.


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1.11.4 What is the age distribution of the wooden poles currently in Transmissionservice in each of Wet and Dry locations, and the average age of suchpoles that are expected to be replaced in F2005 and F2006?

RESPONSE:

The average age of the poles cannot be calculated directly, as the individual poleages have not been documented for the transmission system. Sincetransmission lines go from point-to-point with very few changes over time theservice age of a circuit is taken to represent the ages of the individual poles inthat circuit. The age distribution of the wood pole circuits in the system is:• Lower Mainland and Vancouver Island…….36.5 years• Remainder of Province……….……………….38.3 years

The average age of poles to be replaced will likely be higher than these numbersbut BC Hydro is not able to produce that specific statistic.


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1.11.5 For each of Wet and Dry locations, please explain the basis on which BCHydro and BCTC decide when a wooden Transmission pole needs to bereplaced, including on-site evaluation of the pole, and the age and othercriteria.

RESPONSE:Wood transmission poles are replaced based upon an established and well-definedcondition assessment and maintenance (Woodpole Test and Treat) program,irrespective of the climatic conditions. The age of a pole is used to define themaintenance inspection cycle, not as criteria for replacement.

The Woodpole Test and Treat program is executed by Certified Test and TreatApplicators. Certification is achieved by satisfying the requirements of the BritishColumbia Ministry of Water, Land and Air Protection and the BC Hydro Test and TreatCertification standard.

The Certified Applicators assess the condition of each pole below groundline, atgroundline and above groundline. External decay, if present, is removed and thecircumference of the pole is recorded. The pole is sounded (banged with a hammer)to determine the extent and location of internal decay. Holes are drilled into the polein the region of the internal decay to determine the effective shell thickness (theaverage radial thickness of the outer sound wood surrounding internal decay).

Minimum effective shell thickness and circumference values have been calculatedbased on engineering principles. In service poles must retain enough strength tosupport the attached conductors, insulators and other equipment, as well as wind,snow and ice loads. Assessed poles that do not meet the calculated minimumrequirements are replaced.

As defined in the Woodpole Test and Treat Standards, wood transmission poles areinitially inspected after 25 years in service. Subsequent inspections occur every 8years after the initial inspection until the pole is no longer serviceable. For example,a 38-year-old pole received its first inspection at age 25, its second inspection at age33 and its third inspection is scheduled for age 41, and so on.

During the course of their condition assessment inspection, the Certified Applicatorsalso look for visible signs of decay and deterioration at the upper portions of the pole,including pole tops and timbers (crossarms). Similarly, Power Line Techniciansperform routine visual inspections of the transmission line assets one or more timeseach year according to maintenance standards. Poles identified with upper or lowerbody concerns are subsequently inspected by a Power Line Technician utilizing abucket truck or by climbing (detailed condition inspection). Occasionally, the detailedcondition inspection results in a pole replacement (off test and treat cyclereplacement).


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1.11.6 For each of the Wet and Dry locations, what was the average age and theage distribution of wooden Transmission poles that BC Hydro replaced ineach of the past five years?

RESPONSE:

As explained in BC Hydro’s response to BCUC IR # 1.11.4, records are not kept ofindividual pole ages in the transmission system. Age estimates are based oncircuit service age rather than individual pole ages. Since transmission lines arepoint-to-point with very few changes over time, this approach does notsignificantly distort the pole age estimates. The average age of the poles in thesystem is as follows:• Lower Mainland and Vancouver Island……….36.5 years• Remainder of Province..………………………….38.3 years

The ages of replaced poles are assumed to be greater than the average, ingeneral, but this will be impacted significantly by local conditions. BCTC is notable to produce the specific statistic of age of poles to be replaced as its focus ison specific pole condition, not age.


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1.11.7 For each of the past five years, and for each of Wet and Dry locations,what was the average cost per pole and total cost of replacing woodenpoles in the Transmission System?

RESPONSE:

Wood poles are used for transmission structures with voltages of 69kV through to287kV. Wood pole structure configurations typically range from single self-supporting poles, to 3 pole guyed structures. In some cases 5 and 6 polestructures can be necessary. Topography and site access can significantly influence the cost of single pole, orstructure, pole replacements. Therefore, BCTC expects that pole replacementcosts could be up to $50,000.

BCTC’s total wood pole replacement program over the last 5 years has averagedapproximately $3,000,000 per year, split fairly evenly between wet and dry regions.This cost is inclusive of labour, materials, vehicles and equipment.


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1.11.8 For each of the past five years and each of Wet and Dry locations, whatwas the budget for wooden Transmission pole replacement and thevariance between budget and actual? Please explain the reasons for anysignificant variances.

RESPONSE:

The annually produced work program is based on the prior year’s Test & Treatprogram. The actual cost of this program has been consistently between $3million and $3.5 million annually, for a number of years. The actual expenditureon the program has been at approximately 85% of the program estimate for thefollowing reasons:• when more detailed site evaluations are done by the Manager and

Technologists responsible at some locations the existing pole will be stubbedrather than replaced, which considerably reduces the cost; and

• because of the number of site variables which cannot be addressed until thedetailed site work plan is developed the estimates have a significantcontingency provision, which on average, is in the order of 10% to 15%.


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12.0 Reference: Application, Volume 1, Chapter 7, Section 2.7, pp. 7-23and 7-24

Preamble: Pages 7-23 and 7-24 of the Application states that Distribution has876,000 poles and that the average life expectancy of poles is 40 years. It wouldseem reasonable to expect that poles would have a longer life in dry Interiorlocations than in wet coastal areas like the Lower Mainland and VancouverIsland.

1.12.1 Please define Wet (e.g., the Lower Mainland and Vancouver Island) andDry (e.g., the remainder of the Province) locations that together cover thetotal number of Distribution poles in service, and state how many woodenpoles Distribution currently has in service in each of Wet and Drylocations.

RESPONSE:BC Hydro Distribution does not currently define “wet” and “dry” areas andtherefore does not forecast on that basis. However BC Hydro does have regionalinformation and, based upon the BCUC demarcation of “wet” for the LowerMainland (LM) and Vancouver Island (VI) and “dry” for the remainder of theProvince, can provide the requested data. The number of wooden poles in LM andVI is 439,788 and the number of wooden poles in the remainder of the Province is435,850, for a total of 875,638 poles.


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1.12.2 How many poles does Distribution plan to replace in each of F2005 andF2006 in each of Wet and Dry locations? What is the forecast averageand total cost of pole replacements in each of Wet and Dry locations?

RESPONSE:BC Hydro Distribution replaces poles for a variety of reasons including upgrades,motor vehicle accidents, and end-of-life replacements (all quantity and costfigures provided in BC Hydro’s responses to BCUC IR # 1.12.2 through 1.12.7 arefor end-of-life pole replacements only). The following table shows planned polereplacements for F2005 and F2006, as well as average unit replacement cost andtotal replacement costs (BC Hydro Distribution does not forecast unit cost on aregional basis).

F2005 F2006Quantity Unit

Cost($)

Total Cost($000)

Quantity UnitCost($)

Total Cost($000s)

LM and VI 4300 N/A N/A 4400 N/A N/A Remainder 1300 N/A N/A 1400 N/A N/A Grand Total 5600 3,231 18,094 5800 3,301 19,144


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1.12.3 Please explain how BC Hydro estimated the number of Distribution polesthat it plans to replace in F2005 and F2006. Is there a direct link to thestatement on page 7-24 that 15 percent of the poles are older than theaverage life expectancy?

RESPONSE:BC Hydro Distribution estimates pole replacements based upon the WoodpoleTest and Treat, and Detailed Condition Assessment programs. There is no directlink between the number of poles planned to be replaced in F2005 and F2006, andthe percentage of poles older than the average life expectancy.


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1.12.4 Further to Figure 7-3 on page 7-24, what is the age distribution of thepoles currently in service in each of Wet and Dry locations, and theaverage age of poles that BC Hydro Distribution expects to replace?

RESPONSE:The age distribution of poles currently in service is as follows:

Pole Age <19 yrs 19-28 yrs 29-38 yrs 39-48 yrs >48 yrsLM and VI 179,902 91,286 73,834 60,054 34,712Remainder 160,085 130,196 101,370 39,853 4,346

Total 339,987 221,482 175,204 99,907 39,058

BC Hydro Distribution does not estimate the average age of the poles to bereplaced.


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1.12.5 For each of Wet and Dry locations, please explain the basis on which BCHydro decides when a Distribution system pole needs to be replaced,including on-site evaluation of the pole and the age and other criteria.

RESPONSE:For all locations in the Province, BC Hydro Distribution determines the need forpole replacements based upon the Woodpole Test and Treat, and DetailedCondition Assessment programs. The Woodpole Test and Treat program includesa periodic physical inspection of every pole utilizing core drilling, groundlineinspection, and visible above-ground decay. Detailed Condition Assessment iscompleted for poles identified for groundline reinforcement and include aresistograph measurement to determine appropriateness of life extensionalternatives.


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1.12.6 For each of the Wet and Dry locations, what was the average age and theage distribution of Distribution poles that BC Hydro replaced in each ofthe past five years?

RESPONSE:The average age and age distribution for poles replaced in LM and VI is asfollows:

Age DistributionAverage

Age<19 yrs 19-28 yrs 29-38 yrs 39-48 yrs >48 yrs

F2003 40 217 742 505 1917 1030F2002 39 213 545 546 1603 759F2001 39 206 390 636 1530 478F2000 37 234 371 480 1163 391F1999 38 115 278 547 1006 262

The average age and age distribution for poles replaced in the remainder of theProvince is as follows:

Age DistributionAverage

Age<19 yrs 19-28 yrs 29-38 yrs 39-48 yrs >48 yrs

F2003 30 145 454 330 282 38F2002 29 187 546 343 236 45F2001 28 202 420 289 237 33F2000 29 188 418 405 286 31F1999 30 146 321 320 248 11


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1.12.7 For each of the past ten years, and for each of Wet and Dry locations,what was the average cost per pole and total cost of replacing poles inthe Distribution System?

RESPONSE:The average per pole and total cost of replacing poles is shown in the table below:

Average and Total Pole Replacement CostLM and VI RemainderAverage Cost ($) Total Cost ($) Average Cost ($) Total Cost ($)

F1994 $13,966,800 $3,326,300F1999 $2,500 5,520,100 $2,271 2,375,900F2000 2,900 7,653,400 2,299 3,053,700F2001 2,900 9,396,500 2,301 2,717,500F2002 2,933 10,751,700 2,438 3,308,800F2003 3,053 13,465,700 2,854 3,565,000


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1.12.8 For each of the past five years and each of Wet and Dry locations, whatwas the budget for Distribution pole replacement and the variancebetween budget and actual? Please explain the reasons for anysignificant variances.

RESPONSE:The budget and actual expenditures and variance explanations for majorvariances are provided in the table below:

LocationBudget ($000s)

Actual ($000s)

Variance ($000s) Explanation

F1999 LM and VI 4,926.9 5,520.1 (593.2) Remainder 2,201.2 2,375.9 (174.7)

Total 7,128.1 7,896.0 (767.9) F2000 LM and VI 4,666.6 7,653.4 (2,986.8)

Remainder 2,563.0 3,053.7 (490.7)

Total 7,229.6 10,707.1 (3,477.5) Increased pole renewals identified through condition assessment. Additional funds were allocated to meet performance obligations.

F2001 LM and VI 5,672.3 9,396.5 (3,724.2) Remainder 3,236.6 2,717.5 519.1


F2002 LM and VI 11,012.1 10,751.7 260.4 Remainder 3,447.1 3,308.8 138.3

Total 14,459.2 14,060.5 398.7 F2003 LM and VI 7,852.4 13,465.7 (5,613.3)

Remainder 3,786.8 3,565.0 221.8


5.0 reference: application, volume i, chapter 5, heritage ... · the generation environmental...

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