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Stave Fa& Project - Powerplant Replacement

Project Implementation Phase

i Business Case

January 1995

Stave Falls Project - Powerplant Replacement

Table of Contents

Executive Summary

1 .O Introduction

2.0 Alternatives Considered

2.1 Introduction 2.2 BaseCase 2.3 Major Issues 2.4 wer bwes 2.5 Dkcussion of Alternatives 2.6 Multiple Account Evaluation 2.7 Recommendation

3.0 Configuration

3.1 Introduction 3.2 3.3 Multiple Account Evaluation 3.4 Recommendation

Determining optimal MW and number of units

4.0 Layout, major equipment and other replacement decisions

References

Appendices

A B C

' D E F G H

I

6 7 10 17 21 24 25

26 26 27 28

30

See accompanying document Detailed listing of Rehabilitative work and cost estimate Abandonment Alternative Preliminary Cost Estimate Powerplant Layout Switchyard Location and Type Corporate Safety Memos Seismic deficiency memo Powerplant Replacement Project Economic Evaluation to Optimize the Unit Size, October 26, 1994 Fire 8z Emergency Services Fire Safety Review

Executive summary

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This Business Case summarizes the work done to provide the financial analysis for the various alternatives available for the aging Stave Falls powerplant.

The need to either rehabilitate, replace or abandon the Stave Falls powerplant has been recognized and studied since the late 1960's.

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Stave Falls is the oldest powerplant in the BCH electric system that has yet to undergo major rehabilitation. It is a 5 unit 52.5 MW powerplant where the average age of the generating units is 77 years old. Based on information gathered from other utilities these generating units are 20-30 years beyond their expected life and are no longer reliable. The units are hydraulically inefficient, maintenance costs are excessive and the powerplant fails to comply with several current environmental, safety, fire and building codes.

Forecast energy demands indicate that Stave Falls would continue to play an important role in providing economical energy to the Lower M a a d .

The various options, of replacement, rehabilitation or abandonment, available for this aging powerplant were analyzed using financial and multiple account evaluations. These analyses demonstrate that the rehabilitation alternatives are preferable on a tangible B/C ratio basis and that replacement is preferable once the intangible benefits of reliability, environmental, economic development and social impacts are considered. Replacement provides increased reliability, \ beneficial environmental impacts such as improved oil containment and ability to better meet the needs of stakeholders, 639 man years of work of which 95% will be met locally and opportunties for public safety and recreation.

The &!j-.sis s-iipp~rtt it@iceziieiit of ihe existing 5 unit 52.5 3Tw' powerpiant with a 2 unit 30 M W powerplant. When comparing the replacement alternatives the 2 x 45 MW Unit replacement provides an incremental B/C ratio of .8 and makes a significant contribution to the socio-environmental benefits. .

The proposed replacement powerplant would develop about 365 G W y r . energy, which is about 80 GWh more than the existing plant and about 90 MW of capacity, about 38 MW of additional capacity. The additional energy is gained through improved hydraulic efficiency and better utilization of water which is now spilled. This represents a 27% increase in generation over the existing powerplant. This energy would cost approximately 1.89CkWh and compares fzvourable to the cost of other power 2t BCH at %bout 2.3C/kWh

Adverse impacts of the project during construction and resulting operation of the new powerplant would be fully mitigated.

If approval for the implementation phase is obtained, prior to June 15, 1995, an in service date for Unit 1 is October 1999 and for Unit 2 is December 1999 can be achieved. Approval is subject to BCH and government regulatory approval.

Stave Falls Implementation

1 1. Introduction

i

The Stave Falls Generating Station is located approximately 65 kms east of Vancouver and supplies electricity to the local municipalities of Maple Ridge and Mission. The existing powerplant contains 5 generating units with a total nameplate capacity of 52.5 MW where the average age of the electrical generating units is 77 years.

In 1991, a feasibility study was completed that considered the options of rehabilitation and replacement for Stave Falls. The study concluded that replacement of the powerplant with a two 60 MW configuration was the preferred alternative as it would be economically, operationally and environmentally superior to rehabilitation. The tangible benefitkost ratio, estimated at this time, for the replacement alternatives considered ranged from 1.6 to 2.0. The study also recommended that the Project Definition or Prelimimy Design phase should commence.

In February 1993, BCH’s Board of Directors approved a CAR for $2.8 million to proceed with the first part of the Project Definition phase of the Stave Falls powerplant replacement. Under this stage of the Project Definition phase the optimal capacity of the powerplant replacement was determined, regulatory requirements were defmed, support for an Energy Project Certificate (EPC) was prepared and the final EPC was submitted in November of 1994.

One of the achievements of this phase was determining that the ~pt;m-m c~fig,mtion wiis two 45 ?vfW generating units rather than two 60 MW Units, as previously recommended. This decision reduced the capital cost of the project by about $60 million and optimized the capacity of the powerplant. The economics were recalculated, and a benefitkost ratio of approximately 2.0 still confirmed that replacement was the preferred option.

Part two of the Project Definition phase involved obtaining licensing, regulatory approvals and preparing a project plan for the Project Implementation phase. The EPC has been submitted for regulatory review and approval for the Stave Falls Project - Powerplant Replacement is now being sought.

In conjunction with approval for replacement of the powerplant, approval of enhancement opportunities at Stave Falls is being sought. Enhancement opportunities under consideration involve recreation, public safety and environmental opportunities ranging from $1.0 million to $2.6 million in cost. After considering benefits, costs, and critical

Wendy v i Donkelaar, C.A. 13 January 1995

Stave Falls . Implementation

values the $1.0 million enhancement package is being recommended for approval. Refer to Appendix A for further details.

The existing Stave Falls powerplant is inefficient. Forecast energy demands indicate that the Stave Falls powerplant will continue to be an important project in providing energy to the Lower Mainland. The inherently inefficient and aged Stave Falls powerplant, as it exists today, will not be able to contribute to the increasing demand for energy over the next 20 years. The powerplant has advanced in age to the point where maintenance costs are excessive and continued service is unreliable. In addition, the powerplant does not comply with current frre, safety, environmental and design standards.

In order to address these issues the Business Case has been divided into three Levels of decision making. Level I summarizes the decisions that led to the selection of the powerplait replacement. Level II then addresses the decision to replace, made in Level I, and assesses the optimal configuration. Once the optimal configuration has been determined Level 111 summarizes how decisions where made to optimize layout, major equipment purchases and similar choices.



2. Alternatives Considered

Stave Falls has been studied since the 1960’s. It is the oldest plant in the BCH electric system that has yet to undergo a major rehabilitation or replacement. Other powerplants of that era within BCH, Manitoba Hydro, Ontario Hydro and other countries have typically been redeveloped (see section 2.2).

1

Given the future forecast energy requirements for the Lower Mainland, Stave Falls will need to be able to operate efficiently and reliably in order to meet those demands.

In its present state, Stave Falls is inefficient, unreliable and cannot meet the future forecast energy demands for the Lower Mainland. In order to address these issues the alternatives of rehabilitation, replacement and abandonment have been considered. . -

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2.1 Introduction

The Stave Falls Generating Station is located approximately 65 kms east of Vancouver and supplies electricity to the local municipalities of Maple Ridge and Mission. It is the central project in the three station Alouette-Stave Falls- Ruskin hydroelectric development which has a total nameplate capacity of 166.1 MW.

The frrst stage of development at Stave Falls commenced in 1909 and included the construction of an intake, dam and spillway structures. Units 1 , 2 and 3 were then installed in 1911, 1912 and 1916 respectively. The second phase of dmAopment kclidded raising the e x k e g intake, dam and spiiiway structures to their present height and the installation of Unit 4 in 1922, and Unit 5 in 1925.

The existing Stave Falls powerplant contains 5 generating units with a total nameplate capacity of 52.5 MW where the average age of the electrical generating units is 77 years old.

The age, generally poor condition, and the increasing amount and frequency of maintenance required prompted an Engineering Assessment of the facilities in 1981/82. This report (Report No. H1522) concluded that either rehabilitation or redevelopment would be econoniie and reeommended that further studies be conducted at the feasibility level.

A feasibility study was completed in 1984 that considered replacement, rehabilitation and abandonment alternatives. This study (Report No. H1620) concluded that either rehabilitation or replacement were economic, but that the benefithost ratio and the net annual benefits were higher for the rehabilitation

Wendy van Donkelaar, C.A. 13 January 1995


alternative. 'Abandonment would be costly, provides no economic returns as all of the benefits from the present site would be lost and thus, is not an attatractive alternative. Also identified in the study was a detailed listing of the rehabilitative and dam safety work (see Appendix B) required to make the plant operable for 30 year period and to secure dam structures for the passage of the Probable Maximum Flood.

Since the 1984 feasibility study was issued, all of the dam safety work has been completed, Turbine runners 1,2 and 3 have been overhauled and turbine runner 4 was overhauled, ahead of schedule, as it failed in service. The majority of the rehabilitative work has not been implemented and turbine '

runner 5 has not been overhauled.

At the request of Lower Mainland Production the assessment methodology and conclusions of the 1984 Feasibility study were reviewed to determine if there was any reasonable doubt as to whether rehabilitation should continue at Stave Falls. By comparing the alternatives over equal project lives, making the alternatives "like for like" comparisons and including the costs of bringing the present building up to code it was concluded that replacement was the preferred option and that the Feasibility and Preliminary Design Studies should be undertaken.

A Feasibility Study completed in late 1991 considered the options of a 30 yr. rehabilitation and 60 MW or 120 MW replacement alternatives. The 15 yr. base case rehabilitation was not evaluated in this study but is considered in subsequent evaluations. Replacement, with two 60 MW units, was shown to be economically, operationally and environmentally superior to the other &irn~VZS.

Given the close proximity of Stave Falls to the province's major load centre and the 20 year electricity forecast requirements the powerplant plays an important role now and in the future of the Electric System. The generating units at Stave Falls are beyond their useful lives, do not operate efficiently and no longer operate reliably. Maintenance requirements are excessive and the plant fails to comply with several fire, safety, environmental and engineering design standards. Reliable service will not continue if the plant is left in its present condition.

2.2 BaseCase

In order to properly evaluate the viable alternatives for the Stave Falls powerplant a base case must be developed. The base case is the minimum acceptable operating condition for Stave Falls and exists if Stave Falls can supply reliable power. This base case will be used to make incremental B/C


Stave Falls ImDlementation

I comparisons to and evaluation of the other alternatives.

The intake, dam, spillway, generating units and related equipment were constructed over a period from 1911 to 1922. The units have an average age of 77 years. Stave Falls began operation in 1912 and thus has been operating for 82 years.

Other powerplants of the same era, within BCH, such as Buntzen Lake and Jordan River have been redeveloped. Buntzen Lake began operation in 1903 and was redeveloped in 1951. Jordan River, a powerplant which commenced operation in same year as Stave Falls, was redeveloped in 1971. These powerplants were redeveloped after operating for 50-60 years.

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Aberfeldie, the next oldest plant in the BCH system, has been operating for 72 years. It is a much m e r plm-witb a-Qgacity a€ ;approxjmately 5 MW and was built approximately 10 years after Stave Falls when, based OE discussions with project team members, considerable improvements to the technology of equipment had been made.

Other public utilities within Canada were contacted. The City of Nelson, B.C. a private utility was also contacted. In addition, a literature search was conducted in order to determine if BCH's redevelopment approach was reasonable. Both Manitoba Hydro and Ontario Hydro were contacted because these utilities operate similar older plants.

Based on discussions with Bernie Osiowy and Jack Heidrick of Manitoba Hydro, on 12 and19 December 1994, major rehabilitations of powerplants are

yet but turbines have been replaced after approximately 50 years. Ontario Hydro just recently replaced the Big Chute powerplant after 82 years of service.

..-a uuueii&cil after 50 yem. Manitoba Hyciro has not replaced any powerplants

The City of Nelson runs a small powerplant with four generators. These generators were installed over a period from 1906 to 1948. Units 1 and 2 have been non-operational since 1975/76. Based on discussions with Mike Amos, on 10 January 1995, a fifth unit is being added to the side of the old powerhouse and the intention is to run unit 5 and unit 4 (unit 4 is the youngest unit installed in 1948). Mike Amos confirmed that the City of Nelson had beec spending a lot of money on the aging Units and that 50 years is approximately the useful life a turbinelgenerator.

A Swedish article written by Sven Aadersson (Chief Engineer Stora Power) entitled "Refurbishment and Modernization of Hydro Plants" developed the following guidelines for plant refurbishment and modernization:



Buildings 60 - 100 y r ~ . Reservoirs, dams 80 - ? yrs. Turbines 30 - 60 yrs. Generators 25-40 yr~. Transformers 50-60 yrs. Electrical equip. 15 -25 yr~.

Jack Hendrik, of Manitoba Hydro, provided some additional material on expected life of equipment. This material prepared by Black & VetcWMotor Columbus, Associates estimated the expected life of Francis turbines to be 30- 40 years.

An article in the April 1994, International Water Power & Dam Construction, "New options for old projects" outlined the approach taken by Quebec Hydro. Quebec Hydro a large number of generating stations that have passed the 50 year mark and they concluded that "the useful span of a plant's facilities is set at around 25 years for upgrading and rehabilitation and 50 years for new construction.

The Swedish study defined refurbishment and modernization as activity that was c h a r a c t e d by the fact that the entire plant or major portion of it may be replaced or undergo extensive rebuilding.

The existing Stave Falls powerplant is inefficient, beyond its useful life and costly to maintain. Future energy forecasts for the Lower Mainland indicate that an efficient reliable power supply is required. Status quo at Stave Falls will not ensure that reliable power is supplied due, primarily to, the age of the equipmeat.

A 15 yr. breakdown maintenance rehabilitation option was considered as an approach to ensure that reliable power is supplied. Under this alternative a significant allowance has been included to cover equipment failure but a significant amount of risk still exists that equipment failures can lead to an unreliable power supply.

Under this scenario, the powerplant would be approximately 100 years old when it is replaced. Based on comparisons to other utilities, BCH's own experience and the Swedish study BCH would be extending the life of its generating equipment at least 60% beyond the average.

The 15 yr. rehabilitation alternative is considered to be the minimum amount of work that can be performed at Stave Falls to keep it operational. Even if this work is performed, significant operating risks are being accepted. The 15 yr. rehabilitation will be used as the base case for comparison as anything less is unacceptable.



2.3 Major Issues

Given that status quo is not a viable alternative, there are a number of major issues that need to be addressed, when considering viable courses of action, at Stave Falls. These issues are discussed below.

Stave Falls as a supply of future electricity

Stave Falls is located next to the provinces’ major load centre, generates about 285 G W y r .

The 1992 Electricity Plan identifies probable energy load growth of 1,097 GWyear over a 20 year period. The Electricity Plan identifies a number of demand-side (eg. Power Smart , Load Mazlagement, a. ) and supply-side (eg. Resource Smart, IPPs, etc.) options and assesses these options based on minimizing the social costs.

To meet that projected growth, Resource Smart projects (efficiency improvements to existing hydroelectric facilities) were identified to provide 860 G W y r . Of this 860 GWyr . , the redevelopment of Stave Falls was included in the plan to provide 80 G W y r . at about 1.89ClkWh. The replacement of Stave Falls is one of the most economical manners in which to provide energy.

In March of 1994, Resource Planning completed an Integrated Resource Plan for Stave Falls. This plan considered on-site and off-site uptions for supplying the energy currently supplied by Stave Falls. The on-site options considered were the two rehabilitation (15 and 30 yr.) and the replacement alternatives. The off-site options considered replacing the energy and capacity presently supplied by Stave Falls with an off-site resource or combination of resources.

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Based on the Integrated Resource Plan, it was concluded that replacing the powerplant is the lowest cost option in which to best serve the needs of the province. Replacement represents an increase over existing energy generation. Continuing to operate Stave Falls in its present condition ignores the future demands for electricity and wastes 27% of f m energy every year.

Ez&ting plant’s inefficiencies

The generating units at Stave Falls are twin runner, horizontal shaft, Francis units that were installed over a period between 1911 and 1925. These turbines operate at a low efficiency and a low level of reliability.



Plant efficiency was first measured in 1928. Tests were conducted in conjunction with the 1991 Feasibility study on units 1 and 5 in order to establish the present generating efficiency. These tests confirmed that the 1928 results still held true, that overall plant efficiency has not significantly degraded since 1928 and that the overhaul of turbine #1 has not significantly increased its generating efficiency.

Based OR the tests conducted in conjunction with the 1991 Feasibility study the overall plant efficiency is approximately 70 % . This overall low plant efficiency is primarily driven by the basic design and operating characteristics of the turbines. When the turbines were initially set in place the turbines were set high relative to the tailwater level; thus, all of the head cannot be utilized when the units are operating. In order to utilize the full head available the units would need to be taken out, the areas beneath the turbines would need to be excavated, the penstocks lengthened and the units reset in place. Based on discassions with Dennis Moore (Design Engineer, Hydroelectric Engineering) this type of rehabilitation is costly and would also result in the loss of generation during the replacement.

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Normal plant efficiency, based on discussions with Don McLellan (Senior Mechanical Engineer, BCH), for new plants is approximately 93-94% and 90- 91 % for older plants. Stave Falls’ turbines are operating at 20-24% less efficiency than other p!mts at BCH due primarily to the basic design and operating characteristics of these units.

Units 1 to 4 had serious cavitation erosion problems on the runners. This cavitation is kept reasonably under control since the runners were overhauled. Unit 5’s runners are nmde of cast iron, cavitation problem rn scrims and have not been successfully repaired. One of the blades on unit 5 dropped off and has been bolted back in place. These runners are in poor condition and would require replacement if unit 5 is to be kept in service.

Units 1-4 governor operations are sometimes erratic due to ingress of dirt in the high pressure oil systems. Unit 5’s high pressure oil system is in poor condition and spare parts can no longer be obtained. As a result of the

. cavitation problems and the oil systems, all 5 units must be operated continuously at a fixed load or shut down; thus, the turbines can not be operated to match load or at the optimal efficiency level. This is an inefficient manner in which to operate the turbines.

Excessive msintenance

,.. - . -.\

For the purposes of this analysis excessive maintenance will be defined as above normal plant expenditures. Maintenance totals have been taken from the

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BMS planning system and include only expenditures on generation. These expenditures exclude PMSI (Production Maintenance Strategic Initiative) special funding.

PMSI special funding has been excluded because it is a 5 year funding project for overdue maintenance. Under this special funding request, powerplant redevelopment work was not considered and only minimal funds were allocated to overdue maintenance projects at Stave Falls. Other plants in the electric system used PMSI funding for work such as generator rewinds, penstock work and transformer repairs. Including PMSI maintenance funding would distort the comparison as Stave Falls was virtually excluded from these types of preventative maintenance as it was assumed that it would be replaced or rehabilitated in the near future.

Stave - - Falls . - . did - - - receive a simicant amount of PMSI ingemental funding for emergency repairs. This finding can be tracked by the BMS p!&g system and amourits may or may not be included in the totals used for the powerplants that have been compared.

An attempt has been made to compare Stave Falls to other "like" plants. Comparison is complicated y the fact that there are no other plants in the BCH system of the same a P , with the same equipment and of similar capacity. Three powerplants, Ruskin, La Joie, and John Hart, were chosen for comparative purposes.

Outlined below are the total maintenance costs by plant by year and the related cost per unit to maintain. The cost per unit is being used for purposes of c~;;rl;z-kon a- tobid C G ? ~ ma9 be deceptive as the-nmber of units maintained at each powerplant varies.

Stave Falls/Ruskin

Ruskin, the downstream plant from Stave Falls, is a high flow, moderate head plant with the first 2 units going into service in 1930 and the third unit following in 1950. There are 3 Francis turbine units with a total capacity of 105.6 M W . Although Stave Falls and Ruskin are not of the same era or the same size these two plants face similar operating conditions with similar equ'p I ment.



Ruskin Year StaveFalls StaveFalls Maintenance Cost/unit/yr. Maintenance

1991/92 $ 963,000 $ 192,600 $ 338,300

1992193 $ 1,114,100 $ 222,800 $ 608,300

Expenditures Expenditures

1993194 $ 990,900 $ 198,200 $ 603,700

1994/95 $1,123,700 $ 224,700 $ 1,122,100

Total $4,191,700 $838,300 $2,672,400

Ruskin Cost/unit/yr

$ 112,700

$ 202,700

$ 201,200

$ 374,000

$ 890,800

Based on discussion with Rick Williams, Stave Falls Production Field manager, Ruskin accumulated some common expenses for the Stave Falls- Alouette-Ruskin area and two small substations. In addition some r- ent work was done at Ruskiit. TBe R u s h fnaidenaRce totals have been adjusted for these discrepancies in order to improve comparability.

When all of these factors are taken into consideration the costs per unit to maintain Ruskin is at least comparable to the cost per unit to maintain Stave Falls. Ruskin is a more efficient, 'clean', and well maintained facilitiy.

Stave Falls/ La Joie

La. Ioie powerplant is a single unit plant completed in 1956. The Francis unit turbine has a capacity of 22 MW. La Joie is being included in order to compare the cost of maintaining a more 'modem' plant. Both Stave Falls and La Joie use similar equipment and both are high flow moderate head plants.

Over the period 1991 to 1995 the actual and planned maintenance expenditures on a per unit basis at Stave Falls were 37% higher than those experienced at La Joie. In total, maintenance expenditures per unit were approximately $330,000 higher at Stave Falls over a 5 year period.



On a yearly per unit basis, the maintenance expenditures at Stave Falls exceed those at La Joie by 28 to 49% or by a range of $65,000 to $113,000.

Stave Falls/ John Hart

. John Hart powerplant is a six unit 126 MW plant completed in 1953. Major renovations on the dam, surge towers and powerhouse have just recently been completed. The powerplant utilizes vertical shaft Francis unit turbines and has been included as the equipment and operating conditions are similar to Stave Falls.

Over fhc period 1991 to 1995 the actual and planned maintenance expenditures on a per unit basis at Stave Falls were 43% higher than those experienced at John Hart. In tolal, maintenance expenditures per unit were approximately $381,000 higher at Stave Falls over a 5 year period.

On a yearly per unit basis, the maintenance expenditures at Stave Fails exceed those at La Joie by 26 to 58% or by a range of $54,000 to $137,000.

Mahitenance expenditures at Stave Falls are excessive when compared to "like" plants. Based on discussions with Rick Williams, Stave Falls Production Field manager, Stave Falls has relied heavily on PMSI incremental funding to respond to emergency repairs in the recent past. Incremental PMSI funding was distributed to Production areas to spend on an as needed basis and was generally used for emergency repairs.

Incremental funding for the years 1992193 -1994/95 was approximately $250,000 per year. Without this funding and with the pressure to reduce OMA expenditures by 1 - 2% it is expected that the condition at Stave Falls will continue to deteriorate; maintenance will remain excessive and reliability will suffer.



Stave Falls Ruskin La Joie

Cener Zcrs 18 10 7

Transformers 2 1 0

Total ' 20 11 7

#units 5 3 1

Annual .8 .7 1.4 faultslunit

Reliability . .

Sob Hart

28

0

29

6

.9

For purposes of this analysis, reliability is the capability of the system to satisfy, throughout its lifetime the requirements placed on it. In order to assess this, a comparison has been made of the number of generator and transformer disturbances, the number of callouts and the ratio of corrective to preventative maintenance.

The information on number of transformer and generator disturbances has been gathered from statistics kept by the P&C department over a 5 year period from 1991 to 1994. The ratio of corrective to preventative maintenance was gathered from the Production Facilities Maintenance System (PFMS) over a 5 year period. The information on number of callouts has been gathered via discussions with station supervisors.

.__ _ _ - A like for like comparison can not be made as there are no other plants in the BCH system of the same age, same capacity with the same equipment. Approximately 7 powerplant were initially considered for comparative purposes. Eventually 3 powerplants, Ruskin, La Joie, and John Hart, were chosen for comparative purposes.

System Disturbance Reports - 1990 through 1994

Based on the above information Stave Falls is as reliable as similar plants. The System Disturbance Reports only gather information on disturbances that occur for equipment which is monitored. There are many other types of disturbances that contribute to unreliability .

In 1994, the faults per unit at John Hart significantly decreased to .l/yr. This reduction in annual faults is due to a significant amount of modernization of instrumentation.



Based on discussions with Dennis Deyagher the La Joie disturbances typically are generator trips caused by line faults rather than generator problems. The transmission line from La Joie to the Lower Mainland experiences a relatively high number of faults.

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Maintenance Work Completed

In order to generally assess the effort spent on emergency maintenance versus preventative maintenagce a comparison has been made of the ratio of maintenance completed to the annual maintenance due (or planned via PFMS).

This information was gathered from Production’s KPI reporting. Under the KPI reporting system, powerplants such as Stave Falls and La Joie have been rolled up into other headquarters. For the purposes of this comparison the headquarter results will be used. -. -

Stave Falls and Ruskin completed about 60% of the maintenance work that was planned. John Hart completed approximately 75% of the planned maintenance work and La Joie, as part of the Bridge River headquarters, completed 90% of planned maintenance.

Production’s goal is to complete 90% of the planned maintenance work. Powerplants such as Stave Falls are unable to meet this standard as maintenance time is spent performing corrective repairs rather than planned preventative maintenance.

c&lG.d&

At Stave Falls there are approximately 10 callouts per month. The callout can involve anywhere from 1 to 7 individuals. There are approximately 6 callouts per month at Ruskin. A callout at Ruskin typically involves 1 to 3 individuals and is typically of less duration than a callout at Stave Falls. Callouts at John Hart average 2-3 per month and typically involve only 1 individual. There is approximately 1 callout per month at La Joie involving usually 1 individual.

Based on the above information, Stave Falls experiences significantly more callouts per month than the other powerplants.

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2.4

Stave Falls ImDlement ation

Other Issues

Environmental

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Of all the other issues, the lack of compliance to environmental standards, specifically the containment of oil within the powerhouse and switchyard facilities, is the most signifcant.

At Stave Falls, the tailrace deck serves as the switchyard and there are 6 oil filled circuit breakers holding approximately 400 gallons. of oil each located on the tailrace deck. The tailrace has 40 drain holes and several of the drain holes lead directly into the water. The powerhouse contains oil filled and oil insulated transformers and various oil storage tanks. Any spills in the powerhouse would drain into drainage holes that eventually lead to the tailrace water. A failure of any oil containing equipment would result in oil being discharged into the tailrace.

The tailrace flows directly into Hayward Lake. Hayward Lake serves as the domestic water supply for 25-30 homes in the community of Ruskin and for the Ruskin dam. Hayward Lake is also a recreational site with approximately 110,000 visitor days of use in 1993 ( Stave Falls Recreation and Public Safety Studies by Life Space Designs Ltd.). Depending on the size and timing of an oil spill, the spill could reach the spawning and rearing habitat for chum salmon located below the Ruskin powerhouse. In addition, an assortment of waterfowl and wildlife would be impacted by a spill.

BCH has been studying the issue of oil containment since 1990. At that time, Stave Falls was ideztified as Pavhg a high perceived em~iroxmieatd risk. In 1992, the Oil Containment Working Group surveyed 16 of the high environmental risk stations and determined that 9 generating stations, including Stave Falls, had severe environmental consequences.

The 1992 study, "An Overview Survey of the Environmental Consequences of Oil Spills at Selected Generating Stations" made a number of recommendations for the Stave Falls generating station. Since the 1992 study, Kilborn Engineering Pacific Ltd was hired to prepare an Oil Spill Containment Evaluation. This evaluation, completed in March of 1993, recommended that approximately $177,000 of containment work be undertaken.

Based on discussions with Rick Williams, Stave Falls Production Field manager, none of the remedial work recommended in the Kilborn study has been undertaken; but, it is planned to perform $50,000 - $80,000 of remedial work that will plug the drainage holes which presently drain into the tailrace. In the last 2 years there have been 4-5 oil spills that have reached the tailrace water. One of those spills involved about 700 gallons of transformer oil.



Sections 36(3) and 78.2 of the Fisheries Act generally state that "no person shall deposit or permit the deposit of deleterious substances of any type in water frequented by fish" and that "any officer, director or agent of a corporation committing an offense under this act is liable". Penalties range from $300,000 to $1,OOO,OOO and imprisonment terms are from 6 months to 3 years.

Section 10 of the Waste Management Act covers spill prevention and reporting. Fines for contravention of the Act are up to $l,O00,000 and can be imposed where an offense occurs for more than one day, for each day that the offense occurs.

WCB . .. .

Peter Ficzycz (Corporate Safety-Industrial Hygienist, BCH) and Gerry Fletcher (Co-ordinator, Occupational Safety & Health, Lower Mainland Production, BCH) inspected the powerplant on 13 December 1994 and provided a memo on his findings. This memo is attached in Appendix F and is summarized below:

Industrial Health and Safety Regulations (I. H. & S. regulations) 13.37, 13.41, 13.45, 13.47, 25.01, 24.03 and 25.05 requirements for ventilation and engine exhaust of the entrance to the powerhouse were trucks are parked inside.

I.R.& S. iegulstks 12.01 md 12.05 for provision of emergency shower facilities and spill containment of harmhl substances in the Telecontrol Battery room.

Section 5 of the Occupational Environment Regulations for general shop lighting.

I. H. & S. regulations 8.36, 8.38, 8.40, 8.58, 8.62, 8.62, 8.68, 8.70, 8.78 for reasonable access and guarding of the Electrical Shop Mezzanine.

I. H. & S. regulations 8.04, 8.08, 8.10 regulations for structural columns that are in disrepair.

I. H. & S. regulations 4.02 and 12.01 for spill containment in the switchyard.

I. H. & S regulations 13.37, 13.41, 13.45, 13.47, 13.55, 17.02, 17.03,



17.05, 19.03, 19.07, 19.09 and 19.13 for the provision of ventilation, containment, make up air, visibility and enclosure of operations in the Mechanic's and Welding shops.

Powerhouse elevator has been condemned and the access issue has not been followed up.

I. H. & S. regulations 8.02, 56.02, 56.04, 56.06, 30.14, 8.68, 8.70, 8.38, 8.50 for the strength of structures & equipment, conformity to standards, guardrail specifications, arrangement of work area and fmed ladder design in the Powerhouse generator penstock area.

I. H. & S regulations 16.02, 16.04, 16.06-16.40, 16.104 and 22.14 for the guarding of equipment, guarding of energized l i e s and machinery location on the Powerhouse floor.

I.H. & S. regulations 35.01-35.27, 4.02, 12.01 for the control of asbestos wrapped cables in the Fan Gallery Area.

1. H. & S. regulations 13.21, 13.25-13.35 for noise control requirements in the Powerhouse.

It is estimated that it wouid cost between $500,000 - $1,000,O00 to comply with the above violations.

Fines for these violations range from $5,000 - $10,000. Being fined would be a minor part of the cost as BCH would then be required to comply. Ignoring these violations is not camisieiit with BCH's csq~iate cjbjzctive of beimg me of the most progressive employers in BC because the long run health and safety of employees is not being considered.

Building Code

In 1993, PBK Engineering Ltd. was retained by BCH to undertake a seismic review of the Stave Falls powerhouse. Outlined below are the deficient elements of the building ranked in order from most to least deficient:

Element DemandlCaDacity ratio

Main roof Lower roof

2.34 1.78


. .


Lower east shear wall 1.28 Elevator core 1.10 Lower west shear wall 1.03

Demandcapacity ratios in excess of 1.00 are considered deficient. This deficiency implies that if a 11475 earthquake occurred the steel in the building would yield but not fail; thus, the building would not collapse. The building may or may not require repairs after the earthquake.

Since the 1993 study the elevator shaft has been shut down but no other work to remedy the seismic deficiency has been undertaken. It is estimated that’the cost of upgrading the building to meet current seismic standard would be approximately $425,000 (see Appendix G).

Fire Safety

Don Delcourt of BCH Fire and Emergency Services toured the Stave Falls Generating Station in December of 1994. Stave Falls does not meet the most basic Fire and Life Safety standards for Hydroelectric Generating plants. Outlined below are the general deficiencies found at Stave Falls. The memo prepare by Don Delcourt is attached in Appendix I.

1) Tnere are no fire detection or signalling systems installed in the plant.

2)

3)

Exit facilities are very poor.

There is little or no emergency lighting suitable for exit facilities.

4) There are no fire rated separations between floors or areas in the plant.

5 ) High hazard areas are not separated. .

6) Combustible construction material is used in the Shops, West end of the transformer bay, offices and lunchroom.

7) Non-frre rated steel trusses are used in portions of the roof structure. In the event of a fue these trusses would quickly fail.

8)

9)

There are no automatic Fire Suppression systems installed in the plant.

The plant lacks any code requirements for manual fire fighting.

10) A number of hazardous areas exist in the plant that create a significant risk of fire, such as uncontrolled storage of flammables.



2.5

Based on discussions with Don Delcourt and Wayne McCleod of BCH Fire and Emergency services when the plant was built in the early 1900's there were no Fire and Life Safety standards and compliance would require either replacement of the building or a complete renovation where floors, walls and sections of the roof were replaced. It is estimated that at a Prrinimum $3-$4 million would need to be spent just to provide adequate fire protection.

Ignoring these violations places the employees at a high level of risk in the event of a fire.

Discussion of alternatives

There are several alternatives available at Stave Falls and these alternatives are outlined below:

€5 year Rehabilitation

' he 15 year rehabilitation is a breakdown maintenance alternative where the absolute minimum in work would be undertaken and large allowances have been included in order to address equipment failures as they happen.

The work would include any necessary safety, fire and environmental standards work and any work that is necessary to keep the plant running reliably. Work associated with aesthetics, deluge systems, turbine overhauls, switchyard replacement and modernization would be deferred until the powerplant is replaced.

A significant amount of risk that the expenditures made during the 15 year rehabilitation will not maintain the present level of reliability at Stave Falls exists. Addressing equipment failures as they happen only increases the cost of those failures, lengthens the duration of the outage as most parts cannot be obtained without significant lead times, and given the age of the equipment does not rule out the possibility that complete replacement would be required. All of these factors will reduce the reliability of the plant.

Under this alternative, the 15 year rehabilitation work would be followed directly by a redevelopment. At the time of the redevelopment the generating equipment would be approximately 100 years old; well beyond its expected life of about 60 years.

Undertaking the 15 year rehabilitation scenario will delay the supply of an additional 80 G W y r at 1.89CKWh to the Lower Mainland. During that 15 year period the reliability of the plant will not improve, maintenance will continue to be excessive and the minor issues of environmental, safety, fire and building code violations will not be addressed.

~-

Wendy van Donkelaar, C.A. 13 Ja&ary 1995


The NPV of this alternative is estimated at $90.7 million. This estimate is made at an overview level and based on past experience with rehabilitation work the risk of under estimating the cost is higher than for new construction. Contingencies, to address this, have been built into this estimate; however, repairs made on an as needed basis especially to older equipment are typically more expensive than anticipated.

A 15 year rehabilitation is a breakdown maintenance scenario that delays addressing the issues of power supply to the Lower Mainland, efficiency, reliability and excessive maintenance.

30 year Rehabilitation

The 30 year rehabilitation would involve the rehabilitation or replacement of all components in the existing power facilities in order to bring them up to current standards and enable the plant to continue in service for a period of 30 years. After 30 years the power facilities would be replaced.

This work would involve upgrading and rehabilitation of structural, mechanical and electrical work in the powerhouse and replacing the existing switchyard and related ancillary equipment. A complete listing and estimate of this work is included in Appendix B. This list was compiled by members of the project team and the estimates are at an overview level.

The estimated NPV of this alternative is $85.9 million. These costs are developed at an overview level, are not as precise 2s prelidmry desi@ stzge estimates and are likely to be understated.

This work would bring the plant up to fire, safety, environmental and building code standards but would not improve the plant efficiency or reliability to any significant extent. The generating units would continue to operate as they currently do. The approximately 27% energy gain would notbe achieved. One factor in the reliability of the plant is a function of the age of the turbines and replacement of the turbines is the only way to resolve this issue. Due to the cost, the turbines would not be replaced under this alternative.

Eventually, load forecast for the Lower Mainland would dictate that additional energy be supplied. Based on the Resource Smart Energy Gains (June 1992) replacing Stave Falls is one of the most economical means, at about 1,89 C/kWh (updated to 1994), in which to meet the future energy needs of the province.



Rehabilitation is a measure that will extend the life of the plant but would not address the issues of plant inefficiency, reliability and supply of additional energy and capacity to the load centre.

Replacement

Replacement would involve the construction of new power intakes, power conduits, powerhouse and switchyard along with the related ancillary equipment. Other associated work would include access roads and temporary construction facilities. The existing transmission line between Stave Falls powerplant and Ruskin powerplant may require upgrading depending on the replacement option chosen. The existing powerplant would be taken out of service after construction of the new powerplant.

There are a number of replacement alternatives to consider but these will be addressed in Level 11 of the Business Case.

Under this alternative more efficient turbines would be installed and the issues of plant efficiency and reliability would be resolved. The new structure would comply with current fire, safety, environmental and building codes. This alternative has an estimated NPV of $78.4 million and would take 4% years to complete.

All of the issues identified with the existing plant would be resolved and the enhancement opportunities outlined in Appendix A could be undertaken.

Abandonment

Abandoning the plant altogether would result in the loss of both capacity (52.5 Mw) and energy (285 GwWyr.). This energy will need to be supplied from elsewhere.

Abandoning would have a NPV of approximately ($144.6) million (see Appendix C - Abandonment Alternative Preliminary Cost Estimate). The $60 million in work would involve substation and transmission improvements; decommissioning of the powerhouse, power intakes & penstocks; a new switchyard; Blind Slough downstream channel improvements and automation of the Blind Slough spillway and operating facility.

This alternative does not address the issues of inefficiency, loss of energy and loss of capacity. Eventually due to future load forecasts BCH will need to replace the lost capacity and energy or purchase it from elsewhere.


J

. .


2.6 Multiple Account Evaluation

As part of the 1991 Feasibility study an economic analysis of the alternatives of rehabilitation and redevelopment were considered. Four redevelopment alternatives were considered: a 1 x 60 MW configuration, a 2 x 30 MW configuration, a 2 x 60 M W configuration and a 1 x 120 M W .

The economic analysis was prepared in accordance with the "The Cost of New Electricity Supply in British Columbia"(CONES), dated December 1990. Benefits were calculated for the value of fm energy, secondary energy and capacity contributed. Two analysis were then run , one with a 15% environmental credit and one without the environmental credit. The environmental credit was given to reflect the positive environmental impacts obtainable from a new project.

A sensitivity ana!~& was performed on the values for f m and secondary energy by varying the values by f20%, on the long term value of capacity by varying the values by *20%, and on the discount rate by a range of f2%. The sensitivity analysis determined that the economically optimal alternative was not sensitive to the firm and secondary values of energy. The economically optimal alternative is sensitive to the long term value of capacity and the discount rate; however, in all cases redevelopment was preferable to rehabilitation.

~-

The economic analysis prepared at this time did not measure some of the operational, system, social and environmental benefits. It was prepared in accordance with the CONES and the memorandum titled "Economic Studies fcx Hydmeiectric Projects"

Since that study, various scenarios have been analyzed. For the purpose of these alternatives a comparison of the 2 x 4 5 . W (optimal) redevelopment, the 15 and 30 year rehabilitation and abandonment is included. Sensitivities have been run on the cost of rehabiliation and the value of energy, the most reasonable case, where rehabilitation costs have been increased by 50% and CONES values for energy have been used, has been selected and a multiple account evaluation of that scenario has been included.

Changes the values for energy by +/- 20% had no impact on the decision alternative chosen. Changes the cost of rehabilitation did impact the decision, although even when the estimate is understated the intangible benefits of reliability, environmental and others attained with replacement significantly outweigh the benefits from rehabilitation.

This information has been updated to the 1994 CONES and is in 1993 $'s and is summarized in the attached multiple account evaluation.


Multiple Account Evaluation Rehabilitation Alternatives

15 yr. Rehabilitation

'rown - Financial NPV

c- (P v) Construction costs Transmission costs OMA costs Taxes System storage costs Adandonment Lost firm energy Lost secondary energy

Excess maintenance costs Lost capacity

Total Cost

Tangible Benefits Firm Energy Secondary Energy Capacity CMA savings Avoided cost of replacement

Total Benefits

Tanglble NPV over 77 years

BenefiUCost ratio

Incremental BenefiUCost ratio

Rest of Government - Financial NPV

Local Government - Financial NPV

I :ustomer Service

Consumer Surplus or Summary statement

Environmental External cost or summary statement

Economic development Incremental income or summary I- statement

Social Summary statement

$129,444 $10,034 $44,801

$184,279

$93,568

2.03

Nh

1 28 million is pmpertyhhod taxes.

iales tax appr. 5.4 - $1 .4 million

i .4 million

4s in situation for the customer. Firm mergy reliability improved for the We fi the rehab. New poweplant will iltimately be needed. Units have an average age of 77 years.

Improvements would include oil xntainment work. Automated 3perational capabilities of powerplant will avoid Hayward Lake fluctuations 50% of the time.

220 person years of work, 95% of work wsed in the region.

30 w. R e h a b i l i n

($2,138

($85,909

$123,611 $9,577

$40,966

$174,154

$86,245

2.03

-2.11

26 million is propertylschool taxes.

iales tax appr. t .4 - $1.4 million

r .4 million

b in situation for the customer. Firm tnergy reliability improved for the life rf the rehab. New powerplant will iltimately be needed. Units have in average age of i7 years.

mprovements wwld include oil xntainment work. Automated prational capabilities of powerplant Mll avoid Hayward Lake fluctuations 50% of the time.

$06 person'years of work, 95% of work =.sed in the region.

Multiple Account Evaluation Replacement b Abandonment

Replacement I

( W S ) I

($88,406: ($3,477)

($10,773: ($36.300: ($3,19C)

1 'kwn - Financial NPV

costs (P v) Construction costs Transmission costs OMA costs Taxes System storage costs Adandonment Lost firm energy Lost secondary energy Lost capacity Excess maintenance costs

Total Cost

Tangible Benefits , Firm Energy

Secondary. Energy Capacity OMA savings Avoided cost of replacement

Total Benefk

Tangible NPV over 77 years

BenefitlCost ratio

Incremental BenefitKOst ratio \ st of Government - Financial NPV

sai Government - Financial NPV

istomer Service Consumer Surplus or Summary statement

wironmental External cost or summary statement.

zonomic development Incremental income or Summary statement

1

($6291

($142.765)

$150,579 $1 t ,684 $58,905

. . .

$221,172

$78,407

1.55

0.71

j 36.3 million is propertylschool taxes.

Sales taxes of appr. $1.3 - $2.3 million

6 .4 million

Abandonment ( W S )

I

($6,233:

( S S o , ~ ) ($150,579) ($1 1,684: ($58,909:

($287,405) I

$142,765

$142,765

0.50

NIP

Reliability of new powerplant ensures firm supply for 70 year life and more efficient use of the water resource for energy generation.

Future needs of customers must be supplied from another source.

Improvements would include oil containment work. Oppottunlty to stabilize Hayward Lake levels 90% of the time. Provides increased plant operating capability to meet probably future system and environmental requirements.

Opportunity to stabilize Hayward Lake would not be available.

ork based in the region.

Opportunity to enhance regional, public safety and environmental opportunities.

. .. .

Other Assumptions

1. Lost fm energy, lost secondary energy, lost capacity for the abandonment alternative is equal to the benefits from replacing the powerplant.

2. Excess maintenance costs is calculated as the PV of $19O,OOO over a 15 yr. period for the 15 yr. rehabilitation option, as the PV of $190,000 over a 30 yr. period for the 30 yr. rehabilitation option and as the PV of $190,000 over a 4 year period for the replacement option. The time frames of 15, 30 and 4 years would used to reflect the length of time that the original plant would remain operation.. The $190,000 is the difference between the average actual maintenance expenditures of about $1 milliodyr and the estimated OMA maintenance costs of $810,000.

. . .

Benefit Cost Analysis Sensitivities for the cost of Rehabilitation

BenefitKOst Analysis Sensitivities for the Value of Energy

Mutfpk Account Evalwtlon Two Unit Conflgur8Uonr

atsew Construction costs Transmission costs OMA costs TaXeS System stomge costs

Total Cost

Tangible Benefh Firm Energy Secondary Energy Capacity OMA savings

Total Benefii

Tanglblc NW over 77 years

BenentlCost ratlo

Incremental BeneMICost ratio

smwh

Incremental $/kwh

Lest of Government - Financial NPV

.oca1 Government -Financial NFW

$132.843 $10.329 $43,772

$186,944

$67,562

1 .m

(5102,350: $0

(S10,m w.Oo0: (U*W

(5lsO2se:

$132,843 $10,329 srnm

$213.447

$53,159

1.33

0.67

$0.013

$0.007

32 million in school taxedgrants in lieu water rental.

38 million in school taxadgrants in lieu

ales tax appr. $1 3 - $2.3 million

.4 million .4 million

44 million in school taxedgrpnts in lieu

ales tax appr. $1.6 - $2.6 m i l l i i

water rental. W a b f rentel.

Sales tax approx. $1- $2 million

.4 million

htomer Service unit configuration offers greater Two unit configuration offers greater it configuration offers greater

1 Summary statement Consumer Surplus or rational flexibilii and less spillage.

ration available during routine enance. maintenance.

operational f l db i l i i and less spillage.

Generation available during routine

MI flexibilii and less spillage.

ion available during routine

ling would be required to meet the flow requirements. 5sh flow requirements.

Spilling would be required to meet the Id be required to meet the I

avourable for general maintenance. Favourable for general maintenance. avourable for general maintenance.

mproves refloat debris problems. . uperiorto90MW. ' k mprwes refloat debris pdems.

pillage therefore improved public illage therefore impmved public pillage themfore i m p m d publii

Environmental External cost or summary statement.

reatest environmental bemefib

yward Lake and inmaso in the

and recreational M s . mewhat higher bendits.

mnomic development itional construction costs ddional construction costs Incremental income or summary statement. in adddiional benef~~s to local . ddditional benef* to local

iated with higher configurations

iers and labourers. and labourers.

iated with higher configurations

95% employment would be local. 5% employment would be local. % employment would be local.

Summary statement. recreation and public safely. Automation of the new plant would reduce fluctuations sw plant would reduce fluctuations mew plant would reduce fluctuation!

rd Lake and further enhance

Support for the calculation of Firm Energy, Secondary Energy, Capacity and Storage

using 1994 CONES in 1333 $'s

i

15 Year rehab. and replacement 2-45 MW powerplant

I Printing: (MA: Eval. summary) ( &B:cashRowsummaryl( ARC: Soc Semtik) (ND: Casts) (&E: Gorp Beoehts) 1

TOW Generation OMA Costs (6) $64,170 Total System Storage Costs (6) $21,657

$47,257 $1,096

PV of Generation Const Costs

3 $11$51 PV of Trmsmission Const Costs PV of Generation OMA Costs PV of System Storage Costs (6) $1,481 PV of Finn Energy (at LM) (GW.h) 3,228 PV of Secondary Energy (at LM) (GW.h) 358

(a) (6) (6)

Trms. Losses to Lower Mainland

. .

PV capacity Benefits PV Firm Energy PV Secondary Energy TOTAL PV OF BENEFITS TOTAL PV OF COSTS NET BENEFITS BENEFWCOST RATIO Internal Rate of Return Unit Cost of Firm Energy Unit Cost of Average Energy

0 6 ) $1 29,444 $1 0,034

$184,279 (6) (6)

$61,085 $1 23,194

(6) 3.02

(6)

ERR (U/kWh) 0.19 (e/kwh) 0.45

- -_ 1.001 - - ‘10er.all 200

4.00

11.00 1200 1900 14.00 15.00 16.00 17.00

20.00 21.00 P O 23.00

nm 28.00 a 0 0 Jo.00 31.00 3200 33.00 91.00 35.00 38.00 37.00 36.00 39. 00

41.00 4200

44.00 45.00 46.00 47.00 48.00

50.00 51.00 yo0 53.00 51.00 55.00 5800 57.00 5800 sB.00 Bo.00

6200 83.00 84.00 05.00 (lk00 87.00 68.00 8.00

71.00 7200

74.00 75.00 76.00 77.00 76.00 78.00 w.OO 81.00 8200 83.00 114.00 05.00

4o.m

e m

4om

8i.m

mm

7 a w

m.m m.m m.70 m.70 m.70 m.70 89.70 mm m.m 88.70 nom m.70 earn m.70 m.70 m.m m.70 mm 89.70 Sam m.m m.m m.70

m.70

m.70 88.70

m.m

s0.n w.m 89.m 88.70 m.70 m.m 8.70 m.70

mm mm m.70 89.70 88.m 88.70 m.70 m.m am

0.m a00 aw a00

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89.70

89.70

89.70

89.70

88.70

88.70

0.00 0.00

0.00

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328% 32850 32850 32850 328.50 32850 3a50 321w 321w 328.50 328.50 326.50 a 5 0 321wo 328.50 saay) 328.50 326.50 321w 32850 a 5 0 328.50 328.50 328.50 a% 328.50 326.50 328.50 328.50 328.50 328.50 328.50 328.50 Xa.50 3za50 328.50 328.50 328.50 328.50 328.50 32850 328.50 328.50 31A50 32850 328.50 328.50 328.50 328.50 328.50

0.00 0.00 0.00 0.00 0.00

0.00 0.00

0.00 0.00

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0.m

0.001 0.001 0.m o.m

a m a m zam 2RW

0.00 2S.W 2BW 28.80 a m abm zam

aam a m

am

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2860 2860 2Mo a m a m 36.50 3850 -M,so 3&50 3%.= 38.50 3850 zia.50 38.50 38.50 36.50 3850 36.50 3850 w 3850 38.50 38.50 s50 38.50 36.50 3850 36.50 38.50 36.50 38.50 36.50 38.50 3R50 3850 38.50 36.50 36.50 38.50 38.50 38.50 38.50 38.50 38.50 33.50 38.50 38.50 3850 3850 38.50 36.50 38.50 36.50 36.50 a.50 3854 38.50 38.m 38.50 38.50 0.00 0.00

0.00 0.00 0.00

0.00

0.m

0.m

0.m 0.m

0.m 0.00

a00 m-00

1961.00 4974.00

1-m 1110400

0.00 1 m . w

fsoC00 aw am am

aw 0.00

0.00 31200

4871.00 laB1y.o) WS38.Q) UOZILQ) 247w.03 8155.00

- 0.m- 0.00

0.00 0.00

0.00

aw

0.m 0.m 0.m 0.m aw 0.00 0.00 0.00

0.00 0.00 0. 00 0.00 0.00

0.00

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aw aw aw o.m 0.00 0.00 0.00

0. 00 0.00 0.00

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0.m o.m 0.m 0.00 0.00 0.00 0.00 0.00 0.m aw 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.W 0.00 0.00 0.00 0.00

0.00 0.00 0.00

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a00

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a00 am 0.00 0.00 0.m 0.m 0.00 am a00

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aw aw 0.00 0.00 0.00 0.m 0.m 0.00 0.00 0.00 0.00 aw aoo 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 o m 0.00 0.00

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o.m 0.m

am

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0.00 0.00 0.00

0.00 0.m

aw 0.m 1 aoo am

9244) 57.00 920.00 5t.00 op[100 57.00

opxx) 57.00 GQ0.00 57.00 OaRW 57.00 GQ0.00 57.00 920.00 57.00 -00 57.00

57.00 GQ0.00 57.00 -00 57.00 GQO.00 57.00 920.00 57.00 0p.00 51.00 920.00 57.00 920.00 57.00 920.00 57.00 0p.W 57.00 m00 57.00

euJ.00 37200 810.00- - 3T2oQ- -

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1110.00 810.00 810.00 810.00 810.00 810.00

810.00 810.00 810.00 810.00 810.00 810.00 810.00

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8io.w

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8io.m 8io.m

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0.00 0.00 0.00 0.00 0.m 0.m

m80 37200 37200 37200 37200 37200 37200 37200 37200 37200 37200 37200 37200 372.00 37200 37200 37200 372.00

37200 37200 37200 37200

37200 37200 37200 37200

372m

37200

372.00 m m 37200 372 00 37200 372.00 372.00 372.00 372.00 37200

37200

372.00 37200

37200 372.00 37200

37200

37200

37200

37200

37200

372.m

3nm

om 0.m

0.m 0.00

0.00 0.00 0.00

0.00

0.00 0.00

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0.m

m.00 208200 a00 om ._ 0.m 0.00 m.00 ao83.00 o.ml o.wl o.m 0.00 0.00 I 0.00 0.00

Ol&CONSlRucTION M S T S (Exc Gorp O H d IDC) : I S156.joD.00 I tll.844001

t

0

ao : a

P.v.cLpIcmcowTDuRy( P.V. FI(Y -Y P.V. SEc- -

TOT&

u u u u =6 L O u M p L 6 . M p L 6 M P. L O

Lo' L O L O M

L O M LO M L O L O L O M LO LO 6.0 L O L O L O L O L O L O L O L O 6.0 M L O L O L O L O L O L O LO L O L O L O L O L O L O L O M 6.0 L O L O L O ho KO 6.0 L O L O ho L O L O M L O 6.0 L O L O M L O L O L O L O 6.0 L O L O M L O L O L O 6.0 M L O M

ao

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am am am am

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am

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. am am am o.m om am am am am am am am am om

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I . 30 Year rehab. and reriacement 2-45 MW DowerDlant I r Rialing: (Alt A: Eval. Summary) (Alt B: Cashskw summary) ( ARC: Soc Bmetits) (An D: Costs) (An E Corp Btnelits)

Corporate Ov&eadRate 0.00% Total Project Life 76.00 (years) Origin Of Project Timeline 1 /Apr/l994 (d/m/y) End of Project Timeline 31 /Mad2070 (d/m/y)

Total Construction Cost (w/o OH) $1 93,312 Totd Construction Cost (inc OH) Total Generdon OMA Costs Totd System Storage Costs PV of Generation Const Costs PV of Trmsmission Const Costs PV of Generation OMA Costs PV of System Storage Costs PV of Firm Energy (at LM) PV of Secondary Energy (at LM)

$1 9331 2 $65,820 $1 6,932 $45,078

$346 + $1 1,401

$946 3,110 345

T m i s s i o n Region Name Lower Mainland Transmission Region Number Trans. Losses to Lower Mainland Availabilii of secondary Energy

20.0096

. - PV Firm Energy PV Secondary Energy TOTAL PV OF BENEFITS TOTAL PV OF COSTS NET BENEFITS BENEFWCOST RATIO Internal Rate of Return Unit Cost of Firm Energy Unit Cost of Amrag& Energy

24.m 25.00 28.00 27.00 28.00 2D.00 30.00 31.00 3200 33.00 31.00 35.00 36.00 37.00 36.00 39.00 40.00 41.00 4200 43.00 44.00 45.00 46.00 47.00 48.00 4a.m 50.00 51.W 5200 53.00 54.00

tS.00 57.00 58.00 50.00 0.00 61.00

S3.00

85.00 08.00 07.00 m.00 w.00 70.00 71.00 7200 73.00 74.00 75.00 78.00

78.00 79.00

81.00 8200 83.00 84.00 85.00 88.00 87.00

s.m

e m 64.00

n.w

e0.m

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419 Unit Cost of Average Energy

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2.7 Recommendation f The existing powerplant at Stave Falls is inefficient, unreliable and fails to

comply with several fire, safety, environmental and building code standards. Continuing to operate the powerplant, in its present condition results in a loss of approximately 27 76 of f m energy. Increasing future demand for energy in the Lower Mainland require that Stave Falls be able to operate efficiently and reliably.

The plant is aged, with the average age of the turbines being 77 years old. The age of the turbines contributes to the unreliability of the plant and overhauls can not address the issues of reliability or inefficiency, they can only ensure that the plant continues to operate:

Replacing the plant will address the issues of inefficiency and unreliability. Replacement will supply approximately 365 G W y r . of energy for 70 years through increased efficiency and better utilization of water which is now spilled. The additional energy will help to meet the future electricity demands of the Lower Mainland in an economical manner. In addition, the new plant would be constructed to meet safety, environmental, f r e and building code standards.

Undertaking a 15 year rehabilitation where maintenance would be performed on a breakdown basis does not resolve the current issues of inefficiency and excessive maintenance. This approach delays the replacement of the powerplant and due to the high risks involved does not ensure the reliable operation of the powerplant.

A 30 year rehabilitatim-with replacement of some of the major pieces of equipment will address the issues of reliability and excessive maintenance but can not resolve the basic design inefficiency of the powerplant. Replacing the turbines is the only way to resolve this inefficiency.

Abandoning the plant fails to address the future energy needs in the Lower Mainland &d results in a net loss of energy to BCH. This is not an economically viable option.

It is recommended that the powerplant at Stave Falls be replaced in order to address the deficiencies of the existhg plant a d to t&e advantage of the opportunity to gain additional energy and capacity at the lowest social cost.

Wendy van Donkelaar, C.A. 13 January 1995 Page 25


3. Configuration

During the feasibility stage it was concluded that the Stave Falls powerplant should be replaced. Once this decision was made, the optimal confguration for the powerplant needed to be determined.

Major equipment choices, plant layout and other significant decisions regarding the plant were addressed once the configuration was optimized.

3.1 Introduction

The first critical task of the Project Definition phase is to determine the optimal powerplant configuration. The Powerplant configuration report (Report No. €32752) documents the selection process and compares capacities spanning the range from a "like for like" replacement of the existing plant to complete hydraulic balance with the downstream Ruskin plant.

Three capacities (60, 90 and 120 MW) were selected on the basis of being representative of configurations which initially appeared to be physically and economically suitable for the site. These capacities were then studied from either a one or two unit perspective, These Energy Studies modelled the average daily operation of the powerplant in order to estimate fuln and secondary energy that could be generated and average reservoir operating characteristics (including spills) for each of the six alternatives.

Minimum user requirements were determined by camassing internal "end users 'I from System Operatioas, Production, Environmental Affairs, External Relations, Corporate and Strategic Planning, Engineering and Finance. These minimum user requirements were then developed into selection criteria which were then used in the multiple account evaluation to determine the optimal configuration.

3.2 Determining optimal M W and number of units

In determining the optimal capacity (MW) and number of units the following internal "end users" minimum requirements were developed:

1.

2.

Adherence to minimum operational requirements.

Achievement of maximum net benefits based on a multiple account evaluation with respect to the following:



a) Financial performance b) Customer service c) Environmental d) Economic development e) Social

The multiple account evaluation shall recognize in a quantitative manner, if possible, as well in a.qualitative manner, the following:

a) Superior alignment with the 5 corporate objectives and the Board's Strategic Plan.

b) Superior performance with respect to reduced fluctuation of Stave and Hayward reservoir levels.

c) Superior recreational and public safety long term benefits.

d) Superior operational performance with respect to maximizing generation, reliability, security and efficiency.

e) Superior utilization of the resource by minimizing spill where socio-economically justified.

f) Superior generation capability at minimum fish flow discharge.

3. An incremental B/C ratio of about 1.0 when using CONES avoided cost e c n n ~ d c pameters. If a cqacity kre=egt is n,t jl?stified en this basis, then the a B/C ratio of 2.0 would be required.

These objectives were achieved by first performing energy studies on the six alternatives and then measuring these results as part of the multiple account evaluation.

The energy studies model the average daily operations of the powerplant and include scheduled maintenance, forced outages, existing fish flow agreements and incremental effects on Ruskin generation.

3.3 Multiple Account Evaluation

The six powerplant replacement alternatives of 1 x 60 Nw, 1 x 90 M W , 1 x 120 M W , 2 x 30 M W , 2 x 45 MW and 2 x 60 MW, were evaluated using a multiple account evaluation in "Stave Falls Project Powerplant Replacement - Powerplant Configuration" (Report No. €32752). The non-financial issues such



as Customer Service, Plant Operation, Transmission system, Environmental, Economic development and Social were scored by the project team member most knowledgable about the issue. In addition, the rationale behind the scoring for each issue is discussed in section 6 of the report.

A decision tree was then developed to demonstrate how the alternatives were analyzed. A discussion of this analysis is included in section 7 of the Powerplant Configuration report.

For the purposes of this Business Case the information in the Powerplant Configuration report has been updated to the 1994 Cones report and is expressed in 1993 $'s. Sensitivity analysis have been run on these alternatives and a multiple account evaluation has been prepared using the most likely scenario.

. 3.4 Recommendation

Based on the findings in the Powerplant Configuration Report and with consideration for the operational, maintenance, electric system, environmental, social, recreational and economic factors, it is concluded that:

1.

2.

3.

Two unit configurations are operationally preferable. Two unit configurations offer increased energy production, reduced spillage, increased operational flexibility, reliability and security and reduce maintenance constraints.

The 2 x 30 MW and 2 x 45 MW configurations offer similar benefits. Under the multiple account evaluation though, the 2 x 45 MW codiguration is superior as it better utilizes the resource, provides better operational performance, provides opportunities for environmental and recreational improvements, does not require major additions to the local transmission system and delivers an attractive return on investment.

The 2 x 60 MW alternative is not financially justified when compared to the 2 x 45 MW alternative as the incremental B/C ratio is less than 1.0 and thus the incremental energy supplied is not justified. The 2 x 60 M W configuration would also require upgrading of the transmission system which would be more costly and have greater environmental impacts.



It is recommended that the Stave Falls powerplant be replaced with a 2 x 45 M W configuration.

Wendy van Donkelaar. C.A. 13 January 1995 Page 29

MulUpk Account Evdurtlon Slngk Unlt Conflguntlonr

COstSPV) Construction casts Transmission costs OMAmsk Taxes System storage costs

Total cost

Tangible Benefrts Finn Energy Secondary Energy CaPacW OMA savings

Total Benelii

Tanglble NPV over 77 years

BencflUCost ratio

Incremental BencMlCod ratio

$ikwh

Incremental tlkwh

:st of Government - Financial NPV

oca1 Government - Financial NPV

ales tax appmx. t.8 - $1.8 million ales tax appr. $ 1 - $ 2 milliin ales tax appr. $1.5 - $2.5 million

Consumer Surplus or Summary statement

nd higher spill freqency than

o generation available during routine generation available during routine Benerption available during routine

Unfavourable in terms of general maintenance as single unit plant.

rable in terms of general aintenam as single unit plant.

proves Moat debris problems.

ble in terms of general enance as single unit plant.

I R pmves refloat debris problems.

iated with higher configurations in adddtional benMits to local

ialed with higher configurations iated with higher wnfgurations statement. uit in adddiional benefis to local sult in addditional benefiis to local

uppliirs and labourers. l i i and labourers. lie= and labourers.

% employment would be local. % employment would be local. % employment wwld be local.

Social Summary statement.

Primary social beneffis would occur in recreation and public safely. Automation d the new plant would reduce fluctuations in Hay~nrd Lake.

Mutlplc Account Ev8lurtlon Two Unit ConRguratlonr

+sew Construction costs Transmission costs OMAwSts Taxes System storage costs

Total cost

Tangible Benefiis Firm Energy Secondary Energy Capacity OMA savings

Total Bensfits

Tanglblc NPV over TI years

BenefiVCost ratlo

Incremental BcncfltlCost ratio

wwh

lnncmcntai WkWh

(5102,350’ so

(t1o.m w.m (53.165

$132,843 $10.329 $70275

S213,447

$53,159

1.33

0.63

$0.013

$0.007

ales tax appmx. $1- 12 million ales tpx appr. $1.3 - $2.3 million ales tax oppr. $1.6 - $2.6 million

oca1 Government - Financial NPV

rnmary statement ration available during routine ration available during routine mtiin available during routine

ling would be required to meet the flow requirements. tbw requirements.

ling would be requid to meet the

vourable for general maintenance. rable for general maintenance. aMuraMe for ge~neral maintenance.

mproves refloat debris problems.

pillage therefom i m p d public illage therefore improved public pillage therefore impmvad public

enuironmental benefb. environmental benefm. External cost or summary resemior fluctuation on resemior fluctuation on

rd lake and increase in the

me or summary

employment would be local. % employment would be local. % employment would be local.

urnmaty statement.


4. Layout, major equipment, and other replacement decisions

Once the optimal plant capacity and confguration was determined the design team began to determine the optimal arrangement for and type of components to use. These decisions were made for items such as the location and type of intakes, location of the powerhcke, types of turbines, generators and transformers to use, the type and location of the switchyard and the transmission connections.

The methodology used by the design team for these decisions was to first produce a number of alternatives. These alternatives were then reviewed to determine which met the requirements and then usually two of the alternatives were assessed using multiple account evaluation and/or benefitlcost analysis.

The purpose of this section is to demonstrate that there is a solid process in place for decision making at this level. Instead of providing details on all of the decisions, summaries of the decisions made for the powerplant layout and the switchyard location and type are included in Appendix D and E.

Detailed information on these decisions and other decisions relating to fbe replacement alternative are available.


References

1. Stave Falls Project Redevelopment Feasibility Study, BCH Hydroelectric Engineering Division, December 1991, Report No. H2457 1

2. Stave Falls Project Powerplant Replacement Preliminary Design Report, BCH Project Muageaent, Engineering w-d Construction, September 1994, Report No. N2808

3. Stave Falls Project Powerplant Replacement -_ Powerplant Configuration Report, BCH Stave Falls Project team; March 1994, Report No. H2752

4. Stave Falls Project - Integrated Resource Plan - Multiple Account Evaluation Regional Alternatives, BCH Resource Planning, March 1994

5 . 1992 Electricity Plan, BC Hydro, December 1992

6 . The Cost of New Ekctricity Supply in British Co€umbia - 1994 Estimate of the Cost of Energy and Capacity Supply at the System Transmission Voltage Levei, BC Hydro Resource Planning, June 1994

7. Making the Connection - The BC Hydro Electric System and How it is Operated, BC Hydro, 1993

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