NORTHWEST TERRITORIES

PUBLIC UTILITIES BOARD

IN THE MATTER OF

NORTHWEST TERRITORIES POWER CORPORATION

2016-2019

GENERAL RATE APPLICATION - PHASE I

EVIDENCE OF JANAKI BALAKRISHNAN, M.A.Sc, P. Eng. ENVISION, Community Development and Consulting Services

Submitted on behalf of:

Northern Territories Federation of Labour

March 13, 2017

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TABLE OF CONTENTS

Page No.

1. Self-Identification and Qualifications 7.

1.1 Name, Occupation and Business 7.

1.2 Educational and Professional Qualifications 7.

2. Representation 7.

3. Return on Rate Base 8.

3.1 Return on Equity 8.

3.2 Recommendations 11.

4. Tariff, Sales and Revenues 11.

4.1 Tariff Sales and Revenue - Discussion 11.

4.2 Recommendations 14.

5. Revenue Requirement 14.

5.2 Government Subsidy 17.

5.3 Recommendations 18.

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7. Reliability and Quality of Services 31.

7.1 SAIDI and SAIFI 32.

7.2 CAIDI 32.

7.3 NUL Supply Point 33.

7.4 Momentary Interruptions 33.

7.5 Recommendations 34.

8. Rate Base 34.

8.1 Snare Zone - North Slave Protective Relay Upgrades 34.

8.1.1 Snare Zone - North Slave Protective Relay Upgrades - Discussion 34.

8.1.2 Recommendations 37.

8.2 Thermal Zone - Gameti Engine Plan Replacement & Plant Heat Recovery 37.

8.2.1 Thermal Zone - Gameti Engine Plan Replacement & Plant Heat Recovery - Discussion 37.

8.2.2 Recommendations 40.

8.3 Snare Zone - Jackfish T10 Refurbishment and Jackfish T3 Replacement 40.

8.3.1 Snare Zone - Jackfish T10 Refurbishment and Jackfish T3 Replacement - Discussion 40.

8.3.2 Recommendations 43.

8.4 Snare Zone - Snare Falls Mechanical Overhaul 43.

8.4.1 Snare Zone - Snare Falls Mechanical Overhaul - Discussion 43.

8.4.2 Recommendations 44.

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8.5 Snare Zone - Snare Forks Hydro Unit Overhaul 45.

8.5.1 Snare Zone - Snare Forks Hydro Unit Overhaul - Discussion 45.

8.5.2 Recommendations 46.

8.6 Thermal Zone - Coleville Lake Modular Plant 47.

8.6.1 Thermal Zone - Coleville Lake Modular Plant 47.

8.7 Thermal Zone - Jean Marie Engine Replacement 49.

8.7.1 Thermal Zone - Jean Marie River Engine Replacement - Discussion 49.

8.7.2 Recommendations 50.

8.8 Taltson Zone - Fort Smith Distribution System Upgrade 50.

8.8.1 Taltson Zone - Fort Smith Distribution System Upgrade - Discussion 50.

8.8.2 Recommendations 50.

8.9 Corporate Head Office - IMH Metering Upgrade and Taltson Zone - 51.

Fort Smith IMH Metering Upgrade

8.9.1 Corporate Head Office - IMH Metering Upgrade and Taltson Zone - 51.

Fort Smith IMH Metering Upgrade Discussion

8.9.2 Recommendations 54.

8.10 General Review Comments on the Capital Projects 54.

8.10.1 General Review Comments on the Capital Projects - Discussion 54.

8.10.2 Consideration for New Hydroelectric Power Generation 56.

8.10.3 Consideration for a New Strategy Investing in Solar Energy 58.

8.10.4 Recommendations 60.

9. Low Water Levels 61.

9.1 Low Water Levels - Discussion 61.

9.2 Recommendations 62.

10. Conclusions 63.

11. Appendices

Appendix A- CV and Qualifications of Janaki Balakrishnan

A-1: CV of Janaki Balakrishnan

A-2: Summary of Experiences Related to the Electricity Industry and Public Utilities

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A-3: List of Relevant Courses Attended

A-4: List of Northern Projects attended by Janaki Balakrishnan

Appendix B - Prepared Tables by Janaki Balakrishnan

B-5: - Schematic Diagram showing the existing Snare, Bluefish and Jackfish electricity system, prepared

by J. Balakrishnan

Appendix C - Reports

C-1: Creating a Brighter Future: A Review of Electricity Regulation, Rates and Subsidy Programs in the

Northwest Territories, Electricity Review Panel, September 2009 (excerpt)

C-2: - Northwest Territories Power Corporation, Report of NTPC Review Panel, January 2010 (excerpt)

C-3: - North Slave Resiliency Study – Final Report, Manitoba Hydro International, March 2016 (excerpt)

C-4: A Review of Cost Pressure Facing the Northwest Power Corporation, Ostergaard Consulting Group,

March 2012 (excerpt)

C-5: - A Greenhouse Gas Strategy for the Northwest Territories, 2011-2015, NWT Environmental and

Natural Resources (excerpt)

C-6: - A Vision for the NWT Power System Plan, NT Energy, December 2013 (excerpt)

Appendix D - Other Documents

D-1: Aboriginal Affairs and Northern Development Canada, Intervention Evidence to the NTPC GRA

2014/15 Phase II, Letter to Public Utilities Board from C. Wells, Director, Giant Mine Remediation

Project, August 21, 2015.

D-3: - Handout for Public Forum event re High Power Costs, guest speaker Robin Rickman of Terrestrial

Energy.

D-4: - “NTPC won’t pay for surge damage”, Kassina Ryder, News/North NWT, February 27, 2017

D-5: - “$45,000 of diesel burned per day”, C. Punter, Northern News Services Online, January 23, 2015

D-6: - NWTAC Resolution RA-16-12-07, Reduced Power Rate for Municipalities

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D-7: - Pictures of a universal penstock assembly and a picture of Bluefish Penstock assembly obtained

from Bluefish Redevelopment Study – Yellowknife, NT RFP No. 21604

D-8: - “California shop’s new generators for N.W.T. power plant 1 year behind schedule”, Guy

Quenneville, CBC News, March 2, 2017, online: http://www.cbc.ca/news/canada/north/nwt-power-plant-

generator-behind-schedule-1.4005957

D-9: “All-season road to Whati, N.W.T., gets federal gov’t funding”, Mark Rendell, CBC News, January

11, 2017

D-10: NWT alternative energy subsidies grow along with demand—not enough some say., Kate Kyle, CBC

News, December 28, 2015. online: http://www.cbc.ca/news/canada/north/alternative-energy-subsidies-nwt-

1.3378754

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NORTHWEST TERRITORIES POWER CORPORATION

2016-2019 GENERAL RATE APPLICATION - PHASE I

EVIDENCE OF JANAKI BALAKRISHNAN, M.A.Sc, P. Eng.

1. Self-Identification and Qualifications

1.1 Name, Occupation and Business

I am Janaki Balakrishnan. I am the Principal of ENVISION, Community

Development and Consulting Services. ENVISION is a sole proprietorship operated in the

Northwest Territories. The business is presently located at 5023 48th

Street, Unit 4, Yellowknife

with a mailing address of PO Box 1064, Yellowknife, X1A 2 N4.

1.2 Educational and Professional Qualifications

My qualifications are attached as Appendix A. I completed a B.Sc. in Engineering

(Electrical Power) from the University of Moratuwa, Sri Lanka, in 1975. I possess a M.A.Sc. in

Electrical Engineering (Power) from the University of Toronto, which I obtained in 1987.

I am a professional engineer specialized in electrical engineering (power) licenced

to practice in Northwest Territories, Nunavut, Yukon (to be renewed), and the province of

Ontario. Having been a member of the Institute of Electrical and Electronic Engineers (IEEE), an

international professional organization, in recognition of professional standing, I was promoted

to Senior Member of IEEE in 2008.

2. Representation

I am appearing on behalf of the Northern Territories Federation of Labour

(NTFL).

NTFL was founded in 1980 and is chartered by the Canadian Labour Congress

(CLC), the largest democratic and popular organization in Canada with more than 3 million

members. NTFL is constituted to consist of organizations affiliated to or chartered by the CLC.

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The jurisdiction of the NTFL is within the political and geographical boundaries of the

Northwest Territories and Nunavut.

The officers of NTFL are elected on a geographical basis. In the Northwest

Territories geographical divisions are Dehcho - South Slave, comprised of 13 territorial

communities, Tłįchǫ - Sombe K’e, comprised of 7 territorial communities and 4 mining

communities, and Sahtu/Inuvik, comprised of 13 communities.

NTFL has more than 10,000 affiliated members in over a dozen unions in the

Northwest Territories and Nunavut.

One of the purposes of NTFL is to promote the interests of its affiliates and

generally to advance the economic and social welfare of the workers in the Northern Territories

and Nunavut.

3. Return on Rate Base

As described in Chapter 7 of the GRA 2016-19 Phase I, the Return on Rate Base

reflects the cost to Northwest Territories Power Corporation (“NTPC”) in maintaining capital, to

finance assets in service. The Return on Rate Base in each year includes long-term debt to

finance the work-in progress, capital lease, interest rate and Return on Equity. NTPC is

proposing a 8.50% Return on Equity (ROE) applied to the hydro zones, Snare and Taltson.

3.1 Return on Equity

In setting the proposed ROE, NTPC’s emphasis on an ‘industry appropriate’

ROE in comparison to southern utilities is problematic because it does not recognize the unique

challenges faced in the north. NTPC is situated in an entirely different environment than

southern utilities, with harsh weather conditions, dispersed communities with a lack of

transportation infrastructure and other facilities, and a much lower density of population.

Moreover, the NWT electricity system cost sharing and rate structure demand a community by

community or zone by zone consideration, unlike in southern provinces where the largest area is

connected by one grid.

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ROE is a measure of how well a company uses investments to generate earnings

growth. NTPC claims that most generating facilities were constructed in the 1970s or 1980s,

with a few even older. NTPC has worked to use or upgrade existing assets and plants to meet

current service requirements. This requires investment in the aging infrastructure. Presently,

capital investments are mostly towards overhauls and refurbishments of the existing old assets.

NTPC’s business operations and functions are divided into Snare Hydro, Taltson

Hydro and Thermal (Diesel & Gas) zones. In the past, the Thermal zone was considered the

highest cost zone due to the cost of the fuel type, and was exempt from ROE.

The report released in September 2009, titled “Creating a Brighter Future: A

Review of Electricity Regulation, Rates and Subsidy Programs in the Northwest Territories” was

presented with 39 recommendations (excerpt attached as Appendix C-1). It recommended

moving away from the rate base/rate of return model for communities in the Thermal Zone

served by NTPC as the method for calculating revenue requirements, and that this be replaced

with a cost of service model. This was recommended as it would eliminate the “profit” aspect

that existed in the revenue calculations. In Decision 16-2010 the Board ordered the adoption of

the recommendations. Thermal Zone Revenue Base has become limited to the cost of service and

interest expenses only. Hydro zones, with no cost of fuel for primary generation were exempted

and were expected to provide ROE. The Hydro Zones were able to acquire or lease generation

assets from mining industry, and mining industry customers provided reasonable revenue

generation.

The Report of the NTPC Review Panel released in January 2010 (excerpt attached

as Appendix C-2) presented NTPC Earnings and Dividends. It summarizes, between 1989 and

2001, the GNWT, including Nunavut, was paid $54 million in dividends. Since division of

territories, $30 million was paid in dividends to the GNWT.

But now, the Giant mine and Con mine in the Snare Hydro Zone have stopped

operating, and the Giant mine remains as an industrial customer for remediation purposes only.

This has resulted in the revenue of Snare Hydro Zone being reduced considerably. Further, Snare

Hydro Zone faces additional challenges due to low water flow and deteriorating infrastructure

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and assets. Establishing a revenue base to reach the expected ROE has become impossible

without an increase in rates.

ROE of the hydro zone has been decreasing from almost 11.5% in the mid-1990s,

to 6.3% in 2013/14, 0.5% in 2014/15 and (0.8%) in 2015/16. I have prepared a table to illustrate

this, using data obtained from NTPC’s 2015 Report of Finances Revenue Requirement and ROE

Reconciliation, distributed as information for Interim Rate Application 2016/17, and NTPC’s

2015/16 Report of Finances Revenue Requirement and ROE Reconciliation, distributed as

information for GRA 2016-19 Phase I. I have assumed the 2015 Report was prepared using data

from the years 2013/14 and 2014/15.

Table 3.1

2015 Report of Finances ($000s) 2015/16 Report of Finances ($000s)

Description

2014 2014 2015 2014/15 2015/16 2015/16

Approved Actual Actual Actual Forecast Actual

Total Revenues* 105,613 102,208 101,559 101,663 101,449 101,511

Earnings 6,750 5,003 554 384 (613) (682)

Revenue Requirement 105,613 102,208 101,559 101,663 101,449 101,511

Common Equity Rate

Base 79,414 788,886 80,720 83,414 84,818 87,111

Return on Common

Equity 8.5% 6.3% 0.7% 0.5% (0.70%) (0.80%)

* Total Revenues include GNWT power sales contribution and other revenues

including government contributions.

ROE has been steadily declining. In order to maintain an ‘acceptable’ ROE, the

rates have been continually increased.

Debt/Equity ratio is a measure of viability and ROE is a measure of profitability.

In reality, NTPC is struggling for viability, hampered by old assets and limited revenue

generation, while dealing with low water level conditions and increasing debt. NTPC cannot

continually increase rates to achieve an ‘industry appropriate’ ROE when faced with these

fundamental issues. Keeping costs low, increasing efficiency, and seeking alternate revenue

sources are all elements that can increase ROE, and NTPC needs to demonstrate what it is doing

to improve in these areas. It is unfair to continually place the burden on the ratepayer. It is

suggested that it is not appropriate at this time for NTPC to be seeking a ROE. Instead, an

approach similar to that used in the Thermal Zones should now be used in the Hydro Zones.

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Investment should be made in new and existing assets to improve the corporation’s viability, and

gradually improve its position to, in future, reduce the revenue requirement and rates, while still

achieving a reasonable ROE.

3.2 Recommendations

NTPC should adopt the same approach to ROE in the Snare and Taltson Hydro

zones to ROE as that used in the Thermal zone by dropping it and moving away from the rate

base/rate of return model.

NTPC should focus on investment on new assets that will yield greater revenue

with less operating costs. These investments will typically be new hydro generations of

affordable moderate sizes in various communities.

4. Tariff, Sales and Revenues

4.1 Tariff Sales and Revenue- Discussion

NTPC is the main generator and transmitter of power in the NWT. NTPC

provides electricity at the retail level in 25 communities and at the wholesale level in two

locations. In retail communities, 19 are served primarily by diesel generation, 4 are primarily by

hydro generation, Norman Wells is supplied by purchased power and Inuvik is supplied by a

combination of diesel and liquefied natural gas (LNG) generation. NTPC also has begun

supplying part of the load of Fort Simpson and Coleville by solar power.

NTPC provides bulk power from hydro generation to two wholesale customers,

NUL (YK) in Yellowknife and NUL (NWT) for distribution in to Hay River, Enterprise and

Katlo’odeeche First Nation (Hay River Reserve). NTPC supplements diesel power to NUL (YK)

as needed, whereas NUL (NWT) provides its own supplemental diesel power as required.

Table 2.1 of the NTPC’s GRA 2016-19 Phase I indicates a reduction in the

wholesale Snare zone sales from 168,170 MWh to 165,147 MWh from 2013/14 Actual to

2014/15 Actual. Table 2.2 indicates the wholesale Snare zone sales forecast is further reduced to

163,417 MWh. Presumably the forecasted wholesale sales should include anticipated sales to

new developments in the Snare zone, including a government office building, Union of Northern

workers building, Chateau Nova hotel, Stanton Territorial Hospital Renewal project and

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residential homes. The GRA 2016-19 Phase I does not explain how new projects’ contribution to

the customer growth, system sales and revenue of wholesale customers was reflected in

calculating sales forecasts.

For example, the North Slave Resiliency Study – Final Report, March 2016

prepared for the Government of Northwest Territories was tabled on June 8, 2016 by the then

Minister of Public Works and Services (excerpt attached as Appendix C-3). In section 2.1.1 Base

Case Load Forecast on page 23 of the Study, Stanton Hospital was included with a forecast

incremental consumption of approximately 2.6 GWh/year starting from 2019, presumably due to

the Stanton Territorial Hospital Renewal project. The existing Stanton Hospital building will be

operated for another purpose, which would likely become a different customer in the future.

In schedule 2.0 of the GRA 2016-19 Phase I, the Snare zone industrial system

sales was 7,680 MWh in 2014/15 Actual, which was reduced to 6,120 MWh in 2015/16 Actual.

The industrial sale is presumed to relate to the Giant mine remediation. This project was

expected to have an increased load in the future, but the sales dropped by almost 1,500 MWh.

NTPC does not state the reason for the large decrease. In Aboriginal Affairs and Northern

Development Canada (AANDC) Intervention Evidence to the NTPC GRA 2014/15 Phase II

(Appendix D-1), AANDC indicated that a proposed rate increase could lead to peak shaving by

the company, by scheduling automated equipment to operate at off peak times, in an attempt to

reduce the costs of the project. It may be that in a response to increased rates the implementation

of peak shaving has decreased the sales total.

It is unclear, whether in developing sales forecasts the NTPC keeps abreast with

new developments in the zones and possible large and industrial customers and their

requirements. It is my belief that NTPC needs to adequately investigate the reasons for the

decline in sales with sizable energy consumption customers.

In Table 2.2 of the GRA 2016-19 Phase I indicates that sales related to

streetlights in the Snare Zone will drop from 138 MWh in 2014/15 Actual to 70 MWh in

2016/17 (Forecast). The GRA 2016-19 Phase I indicates that street lighting sales in the Thermal

zone will decrease to reflect the conversion of street lights. The GRA 2016-19 Phase I did not

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indicate that there will be a similar plan in the Snare zone for street lighting sales to drop, or state

any other reason for the decrease.

In GRA 2016/19 Phase I Schedule 2.2-1: Load Forecast Illustration for

Representative Sample of Communities, it shows the total sales to residential customers of Fort

Smith in 211/12 Actual to 2014 2014/15 Actual was in the range of 10,000 – 11,600, higher than

to the residential customers Inuvik, which was only in the range 7,700 – 8,500. The average

number of customers in Inuvik was around 1,400, which is more than the around 1,000 in Fort

Smith. This resulted in lower usage per customer (UPC), in Inuvik than in Fort Smith.

This discrepancy may be due to differences in energy conservation programs,

home structures, lifestyles, or daylight hours between the two communities. However, a further

possibility is that Inuvik customers, who rely on government subsidy, are using less energy to

ensure they remain within the Thermal Zone subsidy limit.

The myth that subsidies act as a disincentive to conservation has been dispelled

(Appendix C-2, Report of NTPC Review Panel, p. 46). Energy usage may be lowered by two

conceptually distinct strategies, energy conservation and energy curtailment. Energy

conservation reduces the usage of the consumer while retaining the same benefit or effect to the

consumer. For example replacing an appliance such as a washing machine with an equivalent

lower consumption appliance will provide the same benefit to the ratepayer. In contrast, energy

use curtailment as a method of energy usage reduction can result in negative impacts to the

consumer. For example, turning off lights, using low wattage bulbs, unscrewing a bulb or two

where multiple are installed, or limiting the use of household appliances, can result in various

negative outcomes such as vision problems, growth of mold in dark rooms and houses, unhealthy

food, and lack of cleanliness.

More than desk top studies on temperature normalization and similar studies and

applications, practical survey within the community and information gathering is required, to

reach a realistic forecast. Survey within the community as to the methods of energy reduction

actually used and the effect of increased rates should be undertaken to reach a realistic forecast

of demand. An increase in rate may result in the use of further energy curtailment techniques by

the consumer, lowering energy usage and ultimately NTPC’s revenue.

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Table 4.1 on page 22 of the report “A Review of Cost Pressure Facing the

Northwest Power Corporation” issued in March 2012 (attached as Appendix C-4) indicates that

most of the cities in the southern provinces had electricity rate increases that exceeded the

consumer price index (CPI). However, the Yellowknife and Inuvik monthly bills in April 2011

were almost double the third highest range bills in the southern cities.

4.2 Recommendations

NTPC should have a thorough review of the proposed rate increases and see how

it will impact NWT communities, more than considering rate increases as the primary way to

reduce shortfalls in every Test year and in every community.

NTPC should conduct surveys and data gathering to obtain a clear perspective of

communities on the understanding of rates and satisfaction/dissatisfaction on the existing rates

and proposed rates.

NTPC, while promoting conservation of energy, should keep promoting large and

industrial customers with amicable agreements to get connected to the system to increase

revenue.

5. Revenue Requirement

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5.2 Government Subsidy

The GNWT has made a substantial commitment to subsidize ratepayers (refer to

Board Decision 7-2016). However, NTPC should not rely on government subsidy indefinitely,

but should be working on ways to lower and stabilize the rates such that government subsidy is

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no longer required. Diversion of GNWT funds results in a cost to the ratepayers as those funds

could be spent on other socio-economic programs to benefit their communities.

5.3 Recommendations

NTPC should find ways to reduce the revenue requirement other than increasing

the rates to meet shortfalls.

NTPC should find ways to reduce the rates such that GNWT funds and subsidies

are directed to other projects and programs to improve the socio-economics of communities and

households.

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7. Reliability and Quality of Services

The GRA 2016-19 Phase I- Appendix C is a report on Reliability and Quality of

Services. NTPC indicates in the Executive Summary that outage reporting practices at NTPC

have been evolving in the past five years. NTPC follows the CEA guidelines for outage

categorization and calculation methodologies.

NTPC identifies the Most Prominent Events (MPEs) using guidelines developed

by the Institute of Electrical and Electronics Engineers (IEEE), under the methodology IEEE 2.5

Beta method. Although, this method recommends using five years of historic data to establish a

baseline for identifying MPEs, three years of historic data is considered the minimum acceptable.

NTPC baselines for MPE identification were calculated in 2012 using three years of available

historic data, which was a smaller data set. Further, additional restrictions were applied to

prevent outages within the control of NTPC being identified as an MPE.

NTPC states that it has currently established an upper threshold of a System

Average Interruption Frequency Indicator (SAIFI) of 10 for each isolated system in its service

area. SAIFI is a measure of the average number of times that a system customer experiences an

outage during the reporting period. System Average Interruption Duration Indicator (SAIDI) is a

measure of the total duration of all interruptions for an average customer during the reporting

period.

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The IEEE Standard 1366-2003-2.5 Beta Methodology is suitable for utilities that

experience major events or MPEs and utilities that undergo Interruption Events frequently. The

Tables of Service Continuity Results contained in the GRA 2016/19 Phase I report are based on

records of sustained interruptions greater than or equal to 1 minute duration.

7.1 SAIDI and SAIFI

NTPC established an upper SAIFI threshold of 10 for each isolated system, but

did not indicate why this threshold was selected or whether this is on par with other utilities. .

There are 19 communities on isolated systems served by NTPC on the Diesel / Gas system. In

accordance with the NTPC’s set threshold, these communities should experience a maximum of

190 service interruptions. Table 3 of Appendix C of the GRA 2016-19 Phase I indicates that

Diesel / Gas systems experienced 151 Interruption Events by Loss of Supply only, and

experienced 179 in total. This is close to the threshold limit. The total of 179 means on average

there is an Interruption Event almost every other day in any one of the communities served by

NTPC. This frequency would heavily impact NTPC’s operation and maintenance costs. Further,

the frequency of interruptions has a significant impact on ratepayers within these communities.

In addition, the Hydro Systems experience another total of 20 Interruption Events,

which again increases the cost of operation and maintenance of NTPC.

In Table 1, 2 and 3 the total number of Interruption Events was provided as 223 in

all locations, 20 in Snare and Taltson systems and 179 in Diesel / Gas systems respectively.

Altogether 24 Interruptions Events are not accounted for.

7.2 CAIDI

The IEEE defines CAIDI (Customer Average Interruption Duration Index) as

equal to SAIDI divided by SAIFI:

CAIDI = SAIDI /SAIFI

Using the values in Tables 1, 2, and 3 of Appendix C of the GRA, CAIDI for loss

of supply interruptions is calculated as 1.993 and 0.351 for Snare/Taltson and Diesel/Gas

respectively. This means that it will take an average of 1.993 hours to resume electricity after

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interruption due to loss of supply to a customer on the Snare or Taltson system, and 0.351 of an

hour for a customer on a Diesel / Gas system. However, the probability of Interruption Events

due to Loss of Supply of customers on Diesel / Gas systems is almost 85%, whereas the same is

only 25% for customers on the Snare and Taltson systems.

Considering the significant territorial hardships and living conditions of the

communities in NWT, SAIDI, SAIFI and CAIDI need to be improved considerably.

In the Snare system generation cause Loss of Supply Interruptions are less

significant than transmission cause Loss of Supply Interruptions (Tables 6 and 7 in Appendix C

of the GRA 2016-19 Phase I, respectively). This indicates that protective systems in the Snare

zone require review and upgrades accordingly to improve service continuity in the Snare system.

Diesel / Gas systems generation cause Loss of Supply Interruptions occur every year and for

variety of reasons as listed in the report. The frequency of interruptions suggest NTPC needs to

consider replacing Diesel/Gas systems with modernized protective systems and effective standby

systems or alternative generation systems, preferably hydro.

7.3 NUL Supply Point

NTPC provided 5 years history of Service Continuity Results for NTPC Supply to

NUL (YK) customers on the Snare system and NUL (NWT) customers on the Taltson system.

Correctly identifying the causes and contributions of interruptions will assist in the future efforts

to improve SAIDI and SAIFI.

7.4 Momentary Interruptions

NTPC has not provided records of interruptions of duration less than 1 minute.

Such interruptions, particularly when more than one take place consecutively within a short

duration, can still have severe impacts, including damage to or loss of appliances and other

electronic equipment. This results in additional expenses to the ratepayer. Momentary Average

Interruption Frequency Index (MAIFI) can be used to measure such interruptions.

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The frequency of service interruptions has caused concern in communities,

particularly as rates continue to increase. Concerned community members have arranged for

community presentations on alternative energy sources (see attached Appendix D-3).

A news item in the February 27, 2016 issue of News/North NWT indicated a

recent incident due to power surge in Ulukhaktok, a far remote community in the NWT, caused

issues with the business of NTPC (Appendix D-4).

7.5 Recommendations

NTPC must correctly identify and evaluate the reasons for service interruptions,

and prioritize a reduction in SAIDI and SAIFI. This will relieve NTPC of additional operation

and maintenance costs relating to service interruptions, and reduce the impact to the ratepayer.

NTPC should introduce the measurement of MAIFI in order to target and improve

interruptions of less than 1 minute, which while of short duration may have significant impacts

on the ratepayer.

8. Rate Base

A few selected capital projects listed in Chapter 11 Rate Base and major projects

in the appendices have been reviewed and commented upon with recommendations.

8.1 Snare Zone - North Slave Protective Relay Upgrades

Project Summary Reference: Chapter 11, pages 11-12, 11-20 and 11-28 and

Appendix B Business Cases: 2014/15 business cases, on pages B-51 to B-56

8.1.1 Snare Zone - North Slave Protective Relay Upgrades - Discussion

Snare Zone - North Slave Protective Relay Upgrades project was opted to replace

obsolete relays with multifunction relays in order to resolve critical issues with the existing

system, including frequent and extensive power outages. This has had an impact on operating

costs, revenue and customer confidence.

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The major benefits of the project would have been, as outlined in the Business

case:

- improved stability and reliability of the system;

- additional information gathered to detect the cause of outages;

- remote accessibility to head office staff to shorten duration of outages;

- improved relay response time; and

- reduction in operational cost as less time will be spent calibrating the relays

In spite of the critical nature of the project, the incomplete project was deferred to

manage changing priorities and budget constraints. As such the project was not completed and

only 25% of relays have been installed. Relays are to be replaced going forward on an as needed

basis. There was no information provided whether the project’s schedule and targets changed due

to redirection of resources. The project summary did not provide details of priorities that may

have over ridden this project.

It was a four year project intended to start in the 2013/14 fiscal year with an

estimated capital spending of $638,975 in total, including overhead and IDC. The following table

was prepared using the data in NTPC’s Construction Work-in Progress (CWIP) Continuity

Schedule 11.6 and the updated information on 2015/16 Actual based on the Annual Report on

Finances (AROF).

Table 8.1.1.1

North Slave Protective Relay Upgrades - Present Stage

Budget

Year

Annual

Budget

Estimate

Opening

CWIP

Balance

Forecast Actual

Spend Variance

Closing

CWIP

Balance

Total

Capital

Spend

Capital

Additions

2013/2014 638,975 9,000 484,000 484,000 0

2014/2015 1,107,000 492,000 176,000 176,000 416,000

2015/2016 1,285,000 253,000 423,000 169,000 254,000 172,000 169,000 299,000

2016/2017 467,000

36,000 0

Total 3,497,975 926,000 829,000 829,000 715,000

Total un-spent as per budget 2,668,975

- 36 -

Neither the project summary nor the GRA 2016-19 Phase I provided where and

how the unallocated $2,668,975 budgeted for in the project was reallocated. Further, there was

no mention of how the closing balance of $172,000 will be planned for in addition to the $36,000

forecast.

Opening and Closing Construction Work-in Progress (CWIP), were not reported

completely, and it is difficult from the information presented to determine the correlation

between the actual spent amount and these balances. There was no information related to cost

allocation of project spending on each item listed in the estimates of design and

construction/purchasing provided in the business case and percentage completed. There was no

information provided as to how much and out of which fund the remaining relays will be

replaced as needed basis.

Moreover, the business case presented an estimated average percentage rate

increase o.878% of rate impact on the completion of project as planned and budgeted. As there

are changes to the project, variances to the business case rate impact were prepared as presented

below in the table.

Table 8.1.1.2

Business case -Variances on Rate Impact

North Slave Protective Relay Upgrades

Project Characteristics Base Estimate Actual Variance

Assumptions

Capital Cost $3,499 $829 ($2,670)

Amortization Period (Approx. years) 47 47

Amortization Rate 2.15 2.15

GRA Approved Return on Rate Base 7.18% 7.18%

Revenue Requirement Impacts

Amortization Expenses $75 $18 ($57)

Return on Rate Base $251 $60 ($192)

Sub Total: Revenue Requirement Increase $326 $77 ($249)

Less: O&M Savings

- 37 -

Total Revenue Requirement Impact $326 $77 ($249)

Snare Zone Revenue Requirement $37,174 $37,174 $37,174

Average Percentage Rate Increase 0.878% 0.208% -0.670%

The percentage rate increase of 0.878% has reduced to 0.208%, which should be

reflected in the proposed rates of the GRA 2016-19 Phase I.

8.1.2 Recommendations

Although, Snare Zone - North Slave Protective Relay Upgrades project did not

require Board’s approval as its budget did not exceed the threshold of $5 million, the total

budget was considerably high. Further, the need for the project was critical with respect to

reliability and to reduce operation and maintenance cost. Any deviation from the project and

diversion of large amount of funds from this project for other purpose needs to be reported and

detailed information provided pertaining to the project status, including future plan on

implementation and capital management needs to be supplied.

As indicated in each step of the review, any missing information needs to be

supplied and more clarity is needed for complete review and to provide further

recommendations.

8.2 Thermal Zone - Gameti Engine Plant Replacement & Plant Heat Recovery

Project Summary Reference: Chapter 11, page 11-16 and Appendix B Business

Cases: 2014/15 business cases, page B-23.

8.2.1 Thermal Zone - Gameti Engine Plant Replacement & Plant Heat Recovery -

Discussion

This project entailed replacing the CAT 3306 diesel generator with a more

efficient unit and upgrading the heat exchanger on the G1 – CAT C10 generator at the Gameti

power plant. This project was necessary to meet the PUB required firm capacity (RFC)

requirements and to ensure the power plant was able to continue to meet the power demands of

the community.

- 38 -

NTPC’s decision in selecting the option of installing a used diesel generator is

questionable considering the increased cost compared to the budget and the option of installing a

new generator.

The option to purchase a new unit was available at only $200,000 additional cost

than buying a used diesel generator. The rational that was applied in the selection of used diesel

option was that it would lower the capital cost of the project. But, the completion of the project

has resulted in $1,277,000 project cost, which is $327,000 more than the budget. The project

budget included $49,000, an 11% contingency in Year 2, for installation of the unit.

Table 8.2.1.1

Gameti Engine Replacement & Plant Heat Recovery

Option Used Diesel Gen Set New Gen set

Year Budget Actual Variance Budget Possible

Saving

2013/2014 350,000

2014/2015 550,000

Total 900,000 1,277,000 327,000 1,100,000 177,000

The variance exceeded the savings that the project expected to have by not

considered a new unit at a budget of $1,100,000. Generally, a new unit has added benefits,

primarily warranty and supplier services, which were not considered in the business case. The

project summary stated NTPC had been able to identify a suitable used diesel generator. There

was no information provided on how, whose, where and why. It is concerning how capital

project management policies, procedures and rationale assisted in selecting a used diesel

generator, instead of a new diesel generator, and managing capital funds on the project.

The business case presented an estimated average percentage rate increase

o.137% of rate impact on the completion of project as planned and budgeted. As there are

changes to the project, variances to the Business rate Impact were prepared and presented below

in the table.

- 39 -

Table 8.2.1.2

Business case -Variances on Rate Impact ($000)

Gameti Engine Replacement & Plant Heat Recovery

Project Characteristics

Used Gen Set

Variance

New Gen Set

Base

Estimate Actual

Base

Estimate Saving

Assumptions

Capital Cost $900 $1,227 $327 $1,100 $127

Amortization Period (Approx. years) 25 25 25

Amortization Rate 4.04 4.04 4.04

GRA Approved Return on Rate Base 4.87% 4.87% 4.87%

Revenue Requirement Impacts

Amortization Expenses $36 $50 $13 $44 $5

Return on Rate Base $44 $60 $16 $54 $6

Sub Total: Revenue Requirement

Increase $80 $109 $29 $98 $11

Less: O&M Savings

Total Revenue Requirement Impact $80 $109 $29 $98 $11

Thermal Zone Revenue Requirement $58,418 $58,418 $58,418 $58,418 $58,418

Average Percentage Rate Increase 0.137% 0.187% 0.050% 0.168% 0.019%

A variance of $327,000 added to the project capital cost, which results in a

$13,000 increase in amortization and $16,000 increase in return on rate base, totalling $29,000 in

Revenue Requirement. Rate impact variance has been calculated with the same $58,418 of

Thermal zone revenue requirement, as the GRA 2016-19 Phase I revenue requirement may be

subject to changes. The estimated average percentage rate increase of 0.137% has increased to

0.187%.

If a new generator has been installed, with a cost saving of $127,000, $5,000 in

amortization and $6,000 in Return on Rate Base would have been saved in the Revenue

Requirement and average percentage rate increase would have been reduced by 0.019%. In

addition, a new project would have saved on operation and maintenance (O&M) cost, at least in

the first few years of warranty period. Therefore, it is necessary to monitor the O&M cost of the

used diesel generator in order to determine the full effect.

- 40 -

8.2.2 Recommendations

NTPC should monitor the O&M costs in the first few years of operation of the

used diesel generator set installed in Gameti and report on same. Further, NTPC should report on

the risks and mitigation strategies applied in the selection of the used generator set over

investing in a new generator set.

8.3 Snare Zone - Jackfish T10 Refurbishment and Jackfish T3 Replacement

Project Summary Reference: Chapter 11, pages 11-21 and 11-22 and Attachment

B of the 2015/16 business cases on page B-78 and on page B-72 for T10 and T3 respectively.

8.3.1 Snare Zone - Jackfish T10 Refurbishment and Jackfish T3 Replacement -

Discussion

The Jackfish T10 Refurbishment project involves the complete refurbishment of

the T10 transformer at the Jackfish power plant. The T10 transformer located at a Jackfish

substation was damaged in 2013 resulting in the CAT plant at Jackfish becoming effectively

disconnected from the Yellowknife grid.

NTPC provided the cost estimate of Jackfish T10 Refurbishment in Appendix B

Business Cases, under 2015/16 business cases on page B-78.

Replacement of the T3 transformer is required at the Jackfish power plant to

increase the plant’s capacity, add transformer redundancy, continue to meet RFC

requirements and provide long term planning options. The new transformer will provide

flexibility to install future modular units (in addition to the 5-6MW planned) or to

connect battery renewable systems. The total project spending of $1.220 million was

slightly below the original total budget of $1.281 million.

NTPC also provided cost estimates of Jackfish T3 Replacement of the same

project in Appendix B Business Cases, under 2015/16 business cases on page B-74.

- 41 -

While there is demonstrated need for both projects, I have concerns with how the

capital projects information is presented, retained and distributed for review, and how the

projects are carried out.

The Jackfish T10 Transformer Refurbishment information was scheduled as a

three year project starting in 2013/2014, where most of the work would have been completed.

The project information did not provide an option to purchase a new transformer for comparison

purposes. The estimate indicated one only one cost of $52,000 forecast disbursement for

transformer in 2015/16, which does not indicate what work was planned then. The total project

spending of $0.489 million was above the original total budget of $0.447 million, which caused

an increase of $42,000 in capital cost and associated increases in amortization expenses, return

on rate base in revenue requirement and added impact on rate increase. The estimate did not have

an amount for contingency.

The following table was prepared using the data in NTPC’s Construction Work-in

Progress (CWIP) Continuity Schedule 11.6 and the updated information on 2015/16 Actual

based on the Annual Report on Finances (AROF).

Table 8.3.1.1

Jackfish T10 Transformer Refurbishment

Year Annual

Budget

Opening

CWIP

Balance

Actual

Spend Variance Total

Capital

Additions

2013/2014 345,000 0 348,000 3,000 348,000

2014/2015 26,000 348,000 24,000 (2,000) 24,000

2015/2016 76,000 373,000 118,000 41,000 118,000 490,000

Total 447,000 490,000 43,000 490,000 490,000

Neither the project summary nor the business case of Jackfish T10 Transformer

Refurbishment stated the size of the transformer. It was assumed from the T3 Transformer

Replacement project that the T10 is also 16 MVA.

The Jackfish T3 Transformer Replacement information provides an estimate with

very minimal information. The estimate does not include an item for the price of the transformer.

It was recognized that the project was planned to connect future replacement of Mirrlees. When

- 42 -

different objectives are integrated in a project, more clarity is required to differentiate the costs

associated with key items of the project, such as transformer replacement and connection to

future replacement of Mirrlees. Instead, the project could have been presented in two parts, one

for replacement of transformer and the other as connection to future replacement of Mirrlees.

NTPC’s Construction Work-in Progress (CWIP) Continuity Schedule 11.6 and

the updated information on 2015/16 Actual based on the Annual Report on Finances (AROF)

provided information Jackfish T3 as in the table below.

Table 8.3.1.2

Jackfish T3 Transformer Replacement

Year Annual

Budget Forecast

Actual

Spend Variance Total

Capital

Additions

2015/2016 1,281,000 1,220,000 1,220,000 (61,000) 1,220,000 1,220,000

Total 1,281,000 1,220,000 1,220,000 (61,000) 1,220,000 1,220,000

The outcome where forecast and actual spent amount are the same is unlikely and

raises concern about the records. Further, Jackfish T3 Transformer Replacement was planned to

connect the future replacement of Mirrlees at Jackfish plant. The Mirrlees project is delayed as

Jackfish T3 Replacement project could not be completed as described in the business case

(Appendix D-8).

The Jackfish T10 Refurbishment and Jackfish T3 Replacement projects present a

good opportunity for NTPC to compare to make an assessment of the benefits and costs of

refurbishment versus replacement of a transformer. It is recognized that there would be

variations at the site conditions from project to project. However, maintaining these records will

help in the future to make judgements for future projects, not only within NTPC, but also for

review of future GRAs. More importantly, such records will avoid the situation that occurred in

Gameti Engine Plant Replacement & Plant Heat Recovery, where selection of used diesel

generator set ultimately cost more than a new diesel generator set.

- 43 -

8.3.2 Recommendations

Project information should be provided accurately to reflect the installation or

implementation status at site as well as capital planning and spending.

Similar projects or projects with common elements should be easily comparable

for future planning projects as well as for other purposes.

When projects at the same location have different scopes, planning and

implementing separately would allow more clarity of the projects, managing capital funds and

asset allocation and accounts for amortization and net salvage. However, NTPC should keep the

overhead at a minimum by managing the projects simultaneously and allocating resources

accordingly.

8.4 Snare Zone – Snare Falls Mechanical Overhaul

Project Summary Reference: Chapter 11, page 11-29 and Appendix B Business

Cases, 2016/17 business cases on page B-147.

8.4.1 Snare Zone – Snare Falls Mechanical Overhaul -Discussion

Snare Zone – Snare Falls Mechanical Overhaul project involves the mechanical

overhaul of the 7.4 MW generator and turbine assembly at unit 1 of the Snare Falls

Hydro Generation facility. The Snare Falls unit has been operating at 53% of rated

capacity since March 2015. The overhaul of Snare Falls is expected to create efficiency

gains, minimize the potential for future lube or grease spills into watersheds, and provide

reliable generation. Considering the age of hydro plants that are operated by NTPC, this situation

may not be limited to Snare Falls Hydro Generation facility Unit 1 only.

As read from the business cases, most of the Snare hydro system assets have

surpassed or are reaching the end of life and a few continuously undergo repairs, overhaul and

refurbishment. Therefore, it is difficult to understand why NTPC ruled out an investigation of

the cost of Replacement with a New Generating Unit in the project planning. Any information

gathered would be useful at another instance. Further, it provides comparison for buying new

versus overhaul in project planning.

- 44 -

This project is estimated with $4.2 million fuel cost, which was 36% of the $10.5

million budget project. On the direction of Board, the capitalized fuel cost was reviewed for the

reasons outlined in the decision and revised to $3.7 million. This is a typical project where diesel

generation fuel costs as back up in hydro plants overhauls and refurbishment play a significant

role. This project will have a rate impact of estimated Average Percentage Rate Increase of 2.5%

at 2013/14 Snare Revenue Requirement. More than 30% of the rate increase will be contributed

by the fuel cost (refer to Board Decision 16-2015).

8.4.2 Recommendations

Other options should be available as back up than diesel generation to keep the

rates under control. NTPC needs to improve the efficiencies of existing hydro power plants and

also to increase the capacity of hydro power plants. This would reduce fuel cost by having hydro

plants as the backup for any overhaul and refurbishment of hydro power plants.

During project planning, all possible options should be considered and

investigated, including pricing of new hydro plants or new equipment of hydro plants for future

consideration.

8.5 Snare Zone – Snare Forks Hydro Unit Overhaul

Project Summary Reference: Chapter 11, page 11-40 and Appendix D as part of

the Snare Forks Major Project Application.

8.5.1 Snare Zone – Snare Forks Hydro Unit Overhaul - Discussion

Snare Zone – Snare Forks Hydro Unit 1 Overhaul is a major project of budget

$7.867 million that requires permit application approved by the Board.

The history of Snare Forks Unit 1 raises concern. It was indicated that the unit

was of 1928 vintage design and obtained from Ontario Hydro. It was not indicated whether the

unit was used or new when installed. If a used generator, it was not clear what the age was at the

time of purchase and whether this corresponded to the design vintage. The turbine runners were

replaced in an overhaul in 1986/87, which was 10 years after the installation. Background

information also states that Snare Forks Unit 1 has not had any major overhauls in the past 10 to

- 45 -

15 years. This implies that there was another overhaul 15 years later within the last 40 years of

operation. This project proposes a third overhaul. It should be clarified whether this is the typical

frequency of overhauls carried out on hydro generation plants. Further, the exciters were

upgraded within the last 5 years.

The primary deficiency has been stated as turbine running clearances and vertical

unit alignment and is considered major. As mentioned in the Background on page D-8 of

Appendix D GRA 2016-19 Phase I, the Snare Forks units operate in isochronous mode to

support the frequency of the North Slave Electrical System. This operation controls the speed of

the unit by way of controlling the water flow to the turbines by wicket gates. It is similar to a

load following operation, where the generation capacity varies with the load. This causes start

stop cycles. Hydro generation units are typically designed for such operation. In this case,

turbine experiences start stop cycles often, which strains the turbine components. Unless the

units are designed to operate in modes with frequent intermittent start stop cycles, the strain on

turbine components could lead to further wear and tear.

The background information and the deficiencies identified state that a wicket

gate is bent. As understood from the document, the bent wicket gate causes more water leakage.

Wicket gate also gets damaged more when shut down takes place. This also results in more wear

on the break.

It appears that the conditions of wicket gate and the turbine are contributing to

each other and as such both are primary issues.

In the Need for Project on page D-7, the third paragraph states, “(t)he failure of

one of the Snare Forks units would mean the loss of 3.5MW. As understood, these units are

generally not run at full capacity because of the need to provide frequency control. In addition, to

avoid spilling, Snare Rapids would be reduced by 1MW and Snare Falls and Snare Cascades

would be reduced by 0.5MW each. This results in a loss of 5.5MW.” In order to assess the

project, more clarity is required with respect to spilling, including the associated impacts and

possible ways to limit spill and maximize hydro generation.

- 46 -

In the Need for Project it further states in paragraph 4, “Snare Forks Hydro Units

are the preferred units to support the North Slave Electrical System frequency due to their most

downstream location and the size of the headpond. If other units are used at other plants, it will

impact the water management of the two river systems, which will lower hydro-electric

generation and require more diesel generation to replace it.”

Having not provided an option for replacement of the hydro units does not allow

for a cost benefit analysis or economic evaluation of the life cycle. Reasoning is required for not

including an option of replacement, because hydro plant overhauls and repairs one after the other

result in high diesel generation fuel costs, and in turn higher electricity rates.

It is assumed that the amortization period was considered 60 in alignment with the

existing plant, which had passed 40 years already. Confirmation is required from NTPC.

There is not much information provided with respect to the following items:

- Consultants Lump sum – $105,000 for planning, whether included a detailed study

report and whether available to review

- Contingency - $25,000 (16.3%), unforeseen items associated with planning

- Fuel cost for type 5 and 6 jobs - $1,200,000 (17%) during construction, the difference

between 5 and 6 jobs and the breakdown and how those amounts were arrived at

- Contingency - $1,176,000 (16.7%) for construction, anticipated risks that would

amount to this total

8.5.2 Recommendations

The project indicates that overhauls and refurbishment of hydro plants in Snare

curtail hydro generation in Snare zone of other hydro plants as a domino effect. Some

geographical presentation showing locations of each plant would provide more clarity to

understand the concept and rationale.

- 47 -

In order to reduce the diesel generation fuel cost as back up and to compensate for

the reduction in hydro generation in Snare, a hydro plant independent of the Snare water source

needs to be sought to back up similar projects not curtailing hydro generation capacity.

Project information needs to be more detailed including data on vintage design

equipment. When such aging equipment and plants become unmanageable both by performance

and cost, timely planning is needed to look for alternative solutions than dealing with matters as

crisis management.

Project estimates and budgets require more detail, including anticipated risks and

risk management and mitigation strategy, particularly when large amounts are allocated as

contingency.

8.6 Thermal Zone – Coleville Lake Modular Plant

Project Summary Reference: Chapter 11, pages 11-18 and pages 11-25.

8.6.1 Thermal Zone – Coleville Lake Modular Plant

Thermal Zone – Coleville Lake Modular Plant project was a major project

approved by the PUB on March 10, 2015 in Decision 7-2015. The total project cost of $7.368

million exceeds the original total budget of $6.606 million. The Board approved purchase and

installation of 3 new modular diesel power plants, 135 kW solar PV and 225 kWh battery storage

estimated at $6.6 million net, with $1.3 million GNWT contribution.

NTPC stated that this project would address the poor condition of Coleville

Lake’s power plant, which has reached the end of life, while also introducing renewable

technology to meet approximately 20% of the community’s energy needs. NTPC indicated the

project’s original scope was limited to diesel plant, which was within the threshold required for a

project permit application. Later, a pilot of integrated solar energy in response to the GNWT

policy intentions with storage was incorporated in the same project.

According to the GRA 2016-19 Phase I, 2016/17 Forecast in Schedule 2.3,

Colville is a community of only 41 residential customers with annual energy sales of 224 MWh,

- 48 -

all non-governmental and general service customers of 1402 kW billed demand, and annual

energy sales of 320 MWh, governmental and non-governmental customers.

Solar Generation data obtained from Schedule 2.0 Summary of Generation, Sales

and Energy of the GRA 2016-19 Phase I and NTPC’s Annual Report of Finances (AROF) is

presented in the table below.

Table 8.6.1.1

Description 2014/15

Actual

2015/16

Actual

2016/17

Forecast

2016/18

Forecast

2016/19

Forecast

% of Total Generation 0.00% 0.04% 0.10% 0.10% 0.10%

Annual Energy Sales (MWh) 6 137 212 250 250

It is assumed that the data supplied as actual in 2014/15 and 2015/16 and the

forecast in 2016/17 apply to the Coleville Lake modular plant - solar PV project.

For the amount of capital contribution required, the beneficiary community of

Coleville is very small and the annual solar power generation and sales the NWT compared to

other types of generation is very insignificant. However, the rate impact will be very high. There

are other ways to achieve solar PV projects, as renewable energy, which are more effective and

fiscally reasonable.

NTPC’s Construction Work-in Progress (CWIP) Continuity Schedule 11.6 and

the updated information on 2015/16 Actual based on the Annual Report on Finances (AROF)

provided the same amounts for 2015/16 Forecast and 2015/16 Actual.

In Decision 7-2015, that Thermal Generation Community (TGC) and the Board

discussed concerns with this project, and the Board directed NTPC to address the prudence of the

actual and life cycle costs of the Colville Lake Replacement at the time of the next GRA. To date

no report has been presented by the NTPC.

Net Salvage has been an issue with the assets of NTPC power plants as stated in

the Depreciation Study in Appendix A. Disposal of assets costs more in the north. Today’s

capital investment should not become a liability in the future. Therefore, it is fair to re-consider

- 49 -

heavy weight bulky installations in remote small communities, unless a positive net salvage

value of the asset will be realized.

8.7 Thermal Zone – Jean Marie River Engine Replacement

Project Summary Reference: Chapter 11, page 11-15 and Appendix B Business

Cases 2014/15 business cases on page B-18.

8.7.1 Thermal Zone – Jean Marie River Engine Replacement - Discussion

Thermal Zone – Jean Marie River Engine Replacement project was carried out to

replace a Detroit D4-71 diesel generator (G1) at the Jean Marie River power plant and replace it

with a new 106 kW air cooled Deutz generator.

The project schedule was delayed by a year or two and the budget exceeded 40%.

Although it was stated in the project summary the budget was increased due to unforeseen issues,

the business case indicates that a future water treatment plant that required 38kW peak load

changed the project plan. Presumably, when the needs assessment of the project was performed,

the water treatment plant for Jean Marie River community planning and design must have been

underway. It is concerning that in the small community of Jean Marie River, it appears there was

a lack of coordination between NTPC and the community such that the water treatment plan was

not considered in the original planning of the NTPC project. A capital contribution provision by

performing a life cycle business case analysis would have determined whether the increased

budget will be paid off by the water treatment plant. It is not clear whether NTPC incorporates

such provisions to raise capital contribution from the GNWT.

Although the Concordance Table Summarizing PUB Information Requirements

and Business Case Information lists risks and mitigation strategies, more clarity is needed how

such risks are controlled by the NTPC management policies and procedures and how NTPC will

incorporate future community projects in its planning for future projects.

- 50 -

8.7.2 Recommendations

Development of a capital contribution policy and procedures along with economic

evaluation of life cycle will assist in raising funds from the GNWT or other authorities in

keeping the rates under control.

Timely coordination and planning of projects with communities would have

avoided the delay and unforeseen budget increases.

8.8 Taltson Zone – Fort Smith Distribution System Upgrade

Project Summary: Chapter 11, page 11-14.

8.8.1 Taltson Zone – Fort Smith Distribution System Upgrade - Discussion

The Taltson Zone – Fort Smith Distribution System Upgrade project consisted of

completing system reinforcement work on the Fort Smith Distribution line. The distribution

system was converted from 2.4 / 4.16 kV to 14.4 / 24.9 kV. The project was meant to reinforce

the distribution system capacity by the application of voltage conversion as described in the

project summary. In addition, an upgrade on McDougal Street from single circuit to double

circuit was carried out within the project. As this project was for reinforcement only, it did not

need to include expansion work with a planned additional capacity. But the project summary

states, “This work also permits the system to accommodate the addition of Interruptible

Electric Heat Load up to a maximum of 2.0 megawatts”. It is unknown whether the system

reinforcement work cost could have been lowered had the work which resulted in this benefit

had not been included in the scope of the project. There was no business case in the GRA 2016-

19 Phase I to clarify this matter further.

8.8.2 Recommendations

NTPC needs to provide information on how the Interruptible Electrical Heat Load

was considered into the project and how it will contribute to the project cost incurred to attain a

2MW additional capacity.

- 51 -

NTPC needs to provide information on, whether any foreseeable customers are

awaiting for forecast revenues from providing the interruptible electric service to act as an offset

to the revenue requirement for the system and provide a net benefit to the rate payers by way of

reducing the rates.

Consideration of a customer capital contribution policy and procedures along with

economic evaluation of life cycle will assist in such projects not affecting the rates.

8.9 Corporate Head Office – IMH Metering Upgrade and Taltson Zone – Fort Smith

IMH Metering Upgrade

Project summary: Chapter 11, page 11-43, Corporate Head Office – IMH

Metering Upgrade, pages 11-30 and 11-39 and Business Case, 2016/17 page B-122, Fort Smith

Metering Upgrade and Appendix E - Application for major project permit IMH Metering

Upgrade, revised and received on February 3, 2017.

8.9.1 - Corporate Head Office – IMH Metering Upgrade and Taltson Zone – Fort

Smith IMH Metering Upgrade Discussion

The Corporate Head Office - IMH Metering Upgrade project entails installing a 2-

way metering system in all of the communities the NTPC serves except Fort Smith

(separate project) and Jean Marie River (pilot project). The current automatic meter reading

system in the larger communities tends to fail, and the smaller communities currently use

standard meters. The purpose of the project is justifiable considering the technological

advancement in the utility metering and challenges faced in the North. However, there are

concerns with how the project is evolving.

The major concern of the IMH Metering project is the way it is proposed, as two

separate projects, Corporate and Fort Smith. It is understandable that Jean Marie River was a

pilot project and it was performed separately. As NTPC is planning a central call centre and

associated businesses, the metering project being performed as Corporate is justifiable. It is

recognized that there are significant issues with Fort Smith metering, which need to be resolved

soon. However, when the two IMH Metering projects are planned just a year apart, it is difficult

to understand why these projects are considered separately. If it is preferable that there be

- 52 -

community involvement in the project in Fort Smith project be, then other communities or the

respective zones should be consulted and provided the same opportunity for participation. It is

always good to provide opportunity for communities to become trained and engaged in projects,

even if it may cost slightly higher than a project fully managed and conducted by NTPC. These

are incentives that community ratepayers should benefit from. This is also way of building

community relationship with NTPC.

A comparison of the business cases shows that when the project is performed by

Fort Smith the payroll cost appears much higher than the collective cost shown in the estimate of

the Corporate project.

Table 8.9.1.1

Business Case - Construction Estimate

Corporate - IMH Metering Upgrade

Description 2017/18 -

2020/21

Payroll Regular $328,000

Payroll Overtime $0

Payroll Fringe Benefits $116,000

Meters $1,989,000

Computer Software $506,000

Contingency $663,000

Total $3,602,000

Business Case - Construction Estimate

Fort Smith IMH Metering Upgrade

Description 2016/17

Payroll Regular $31,000

Payroll Overtime $19,000

Payroll Fringe Benefits $11,000

Meters $411,000

Computer Software $55,000

Contingency $26,000

Total $553,000

- 53 -

This implies that Fort Smith will have a higher rate impact. In Table 3 – Sensitive

Analysis of the Fort Smith IMH shows an Average percentage Rate Increase of 0.74%, whereas

the Corporate IMH Metering Upgrade shows a 0.471% increase.

Information with detailed life cycle analysis of the project will assist in

understanding the project costs, implementation and planning. In the response of TGC.NTPC-58

Information Request, NTPC stated that there would be a total of approximately 8,700 meters

installed as part of the Intelligent Metering upgrade, with an additional 600 units purchased to

serve as spares. Units are expected to be installed in equal amounts per year for a total of 2,175

units per year. A plan setting priorities for the installation and distribution of the units in each

community would assist to provide insight into how the project is intended to evolve. It would be

unfortunate for this project to be stopped or delayed, as occurred with the North Slave Relay

installation project, not having given consideration for the challenges in North.

In the response of BR.NTPC-15 Information Request, NTPC stated the new

meters would allow for continuous meter monitoring in real-time. If a meter should stop sending

consumption data this would indicate a likely customer outage (e.g. tree on a section of

distribution line) and linemen can be dispatched to a precise location to resolve the problem,

substantially reducing the length of customer outages. It is an added advantage that this metering

project can contribute to improving reliability. However, it is not clear whether NTPC will

engage staff on duty for continuous monitoring. Although this is a two-way meter, no

information was supplied with respect to whether these meters will have provisions for Net

Metering and other types of distributed generation interconnections.

Meter costs in the Fort Smith estimate is $411,000, almost 21% of Corporate

estimate of $1,989,000. The number of meters required may not be proportionate. NTPC should

consider whether it is beneficial to split the projects by communities.

There is no indication of the status of each community, whether with manual or

automated meters. A list of communities by status, including the existing type and current

metering challenges, and the number of meters that will be replaced, will provide a greater

appreciation of the project. There is no information on the number of workers presently engaged

- 54 -

in manual reading in each community and how their positions or work will be effected in the

automated environment.

In the estimates, payroll, meters and software costs are included. There was a

contingency amount to 18% of the total estimate in the Corporate estimate and 5% of the total

estimate in the Fort Smith estimate. It would be proper to indicate the costs anticipated in the

contingency.

8.9.2 Recommendations

NTPC needs to review and re-evaluate the projects Corporate - IMH Metering

Upgrade and Talton Zone - Fort Smith IMH Metering Upgrade.

The project planning and implementation should consider priorities based on an

analysis of current community status and be conducted in phases to save costs.

Integrating active community participation in the project shall benefit both

communities and NTPC.

A presentation of an economic analysis of life cycle with project planning would

assist in further review and considerations.

Consideration of accommodating net metering and other types of distributed

generation projects in the metering upgrade will be beneficial for future developments.

8.10 General review comments on the Capital Projects

8.10.1 General review comments on the Capital Projects - Discussion

Having reviewed selected projects listed in the GRA 2016-19 Phase I, I

recognized there is a public need for many of the projects. However often it is unclear how the

project is planned, designed and implemented, including management of funds. Undoubtedly,

there is a considerable number of projects that adhered to the proposed schedule and budget, and

a few performed exceptionally well under the budget. Yet, these projects raise the question

whether those projects were estimated with a higher budget and longer schedule than required.

- 55 -

My projects review revealed that there is no consistency in the practices of

planning, preparation of estimates and budgets, and scheduling among projects. Estimates show

variations in similar scope of work projects. While one could argue, similar projects at different

communities create project differences, budgets and schedules should represent some relativity.

For example, Jackfish T10 Transformer Refurbishment and Jackfish T3 Transformer

Replacement are two different scope of work projects, but there are common elements and

connectivity in those two projects. If those projects do not identify those common elements, it

will neither promote improvement and effectiveness within NTPC nor facilitate an efficient

review process of the GRA.

There are no benchmark approaches or practices recognized in the submission of

project summaries, business cases, budgets and estimates, although a few templates are adopted

in the business cases. Some projects did not include contingency, whereas others did, but the

percentages varied. There was no information on what the contingencies were intended for,

which may vary from project to project. Percentages of overheads and IDC for the respective

year and variations from year to year were not provided. If not consistent, the rationale for those

variations was not identified.

Any investment on capital projects should yield results with higher efficiency

operating at the maximum output or rated capacity as necessary. Projects cannot be let to evolve

to manage new crises, but be planned and implemented to keep the infrastructure sustainable, to

provide reliable power and the cost of electricity affordable to customers. This may require

planning on new plants to meet and sometimes to exceed the required firm capacity of the

primary fuel, particularly in Snare. This is not reflected in Snare hydro projects and in most cases

the capacity of hydro generation suffered due to a hydro plant overhaul or refurbishment project.

Considering the costs of hydro plant and diesel plant overhauls and

refurbishments, associated diesel operation cost and the timing, NTPC should not only

investigate overhauls and replacements, but also investigate obtaining new plants as well.

Several projects were listed in Snare, Jackfish and North Slave of the Snare zone, which is the

largest generation/ transmission/ distribution infrastructure in the NWT and is comprised of the

oldest assets. Literally all the projects have been planned for overhaul, refurbishment or

- 56 -

replacement of assets. Some among those are heavily interdependent on the other existing plants

operation or has impacts with respect to reliability, diesel costs and environmental issues, among

others. For example, Snare Forks Unit 1 Overhaul depends on the diesel operation of Jackfish

plants to make up the loss of power. It also reduces the generation capacity of the other existing

hydro plants for water management in the area.

In the Snare Forks Unit I overhaul Summary of Business Case Rationale (page D-

12) it states, “In addition, hydroelectric infrastructure investments help to keep electricity rates

relatively affordable in the NWT”. The efforts on retention of such hydro plants call for recurring

investments in aging assets, the major part of which are expended on fuel costs.

With respect to the Snare Falls major overhaul, before any amount respecting fuel

costs for replacement power incurred during the construction phase of this project is allowed to

be capitalized, the Board must be satisfied that NTPC acted prudently to minimize those costs.

Further, any significant portion of the total cost of the project and capitalization of such a large

fuel cost component may distort the construction costs of the project.

NTPC’s corporate strategic direction should extend to community affiliations to

initiate new projects that are worthy to invest on at this critical juncture. Information on two

considerations are presented below.

8.10.2 Consideration for new hydroelectric power generation

The proposed La Martre Falls Hydroelectric Development project represents an

example of the potential hydroelectric power generation that exists within the NWT. The La

Martre Falls Hydroelectric Development project would reduce dependence on fossil fuels,

stabilize and reduce energy rates and cost of living over time, create jobs and business

opportunities and an increase in associated social benefits, in a manner consistent with traditional

and cultural values. A feasibility study for the project was completed by the Tlicho Investment

Corporation, as referred to in “A Greenhouse Gas Strategy for the Northwest Territories”

(excerpt attached in Appendix C-5).

There is a strong argument for increasing hydroelectric power generation in the

NWT above the required firm capacity. At present, NTPC provides power to Yellowknife from

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the Snare River and Bluefish hydroelectric power facilities. The two hydro facilities are

becoming increasingly unreliable due to low water levels and overhaul and refurbishment costs

are escalating. Further, as noted any overhaul and refurbishment work in one plant is

interconnected with the other and does not allow for full potential of operation.

As a backup to the hydroelectric power, NTPC provides diesel power generation

at Jackfish power plant. This power is expensive and, with the continued use of old generators,

like Mirrlees, and temporary mobile/modular units as quick fixes on low water conditions, is

particularly costly to the environment. NTPC has received a positive Decision from the Public

Utilities Board to replace the Mirrlees generators with 5 – 2 MW modular generators. It is also

acknowledged that diesel generators are still required for backup. However, with the continued

challenges associated with low water levels, a growing share of power for the North Slave is

generated by diesel.

Investing in the La Martre Falls hydroelectric power facility is an alternative to

maintaining the power generation structure currently in place. It would provide hydro, a

renewable energy, to Whati which is currently served by a diesel power plant. Hydro would be

available for future industrial customers, and would provide a carbon free efficient energy source

as a backup to the increasingly unreliable Snare River power generation.

Particular attention should be given to the future industrial needs in Tlicho given

the recent announcement by the GNWT that it will fund the all-weather road construction from

Highway 3 to Whati (Appendix D-9). This project will improve the economic feasibility of

NICO mine and open up the region to further mineral exploration. The addition of a reliable,

clean and cost-effective power source would further improve the economic feasible of these

opportunities. Past experience has demonstrated advanced planning is required if industrial users

are to incorporate existing power supply options into their plans.

Investing in the La Martre Falls Hydro Project comes with a high initial capital

cost. However, the long-term benefits of this investment will ultimately be realized through

lower costs to the NTPC that should result in lower, or at least stable power rates for NWT, and

would reduce GHG emissions.

- 58 -

Looking ahead to the likelihood of a carbon tax, there will be additional economic

benefits associated with hydroelectric power generation. The federal government announced in

October 2016, that it would be moving forward with its plan to implement a $10 per tonne tax on

carbon emissions by 2018 that will grow to $50 per tonne by 2022. This new cost to diesel power

should be factored in to NTPC planning, with projects such as the La Martre Falls Hydroelectric

Power Facility being given further consideration.

A schematic diagram is attached as Appendix B-5 showing the existing Snare,

Bluefish and Jackfish electricity system, where Lac La Martre Hydro project could get

interconnected by a short transmission system.

8.10.3 Consideration for a new strategy investing in solar energy

NTPC has recently completed a capital project in Colville Lake, replacing the old

diesel generator and installing solar PV panels and a power storage battery bank. NTPC and

others have labelled this project a success for several reasons, including the facts that it has:

Increased the use of renewable energy,

It was a demonstration project that was successfully completed,

Colville Lake is one of the NWT’s more remote communities, and installing this

infrastructure presented numerous geographic and logistical challenges that were

overcome, and

It was completed close to its original budget (budget was $6.606 m, actual cost was

$7.368 m) and was able to take advantage of territorial and federal funding.

These are all legitimate reasons to label the project a success. Where the success

is less apparent is in the project’s economics and the cost of the project to NWT ratepayers. This

cost should have been given more weight in the final decision to move forward with the project.

NTPC project a 1% rate increase to the thermal region to compensate for the

increased costs associated with the investment in and provision of this solar energy. In its 7-2015

Decision, the Public Utility Board stated:

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“The Board notes the solar panels and battery storage components

of the project were undertaken at a cost of $3.2 million, with a

view to supporting the GNWTs Solar Energy Strategy that targets

expansion of solar generation in the NWT to 20% of annual peak

load by community.

While NTPC indicates it has chosen to incorporate the

solar/battery storage components as part of the project in response

to GNWT policy intentions, the Board considers such costs must

continue to be incurred wisely and prudently. … the life cycle cost

per kWh of solar output, in conjunction with battery storage, is

higher than the cost per kWh of diesel fuel displaced by the solar

generation, on an average cost basis. …

Accordingly, the Board direct NTPC to address the prudence of the

actual and life cycle costs of the Colville Lake plant replacement at

the time of the next General Rate Application.”

It remains unclear whether this prudence has been adequately demonstrated.

In its report A Vision for the NWT Power System Plan, dated December 2013, the

GNWT states that “If the [Colville Lake] hybrid system proves successful it will be an option for

other thermal communities in the NWT to consider”, but it is not evident that public investment

in solar PV energy in remote northern locations is economically sound (excerpt attached as

Appendix C-6).

In the same Vision report, the GNWT outlines the relative cost and benefits of

solar power versus other potential power sources, such as medium-sized hydroelectric power

generation. The report includes the following table:

Table 8.10.3.1

Type of

Investment

Economic

Impacts

Technical

Viability

Environmental

Performance

Social

Benefit

Cost of

Energy

($/MWH)

Installation

Cost ($/kW)

Solar PV NEGATIVE

Subsidy

required

MEDIUM

Intermittent

HIGH

No GHGs, small

footprint

HIGH

Renewable;

self

sufficiency

$590 - $830 $9,000 -

$14,000

- 60 -

Type of

Investment

Economic

Impacts

Technical

Viability

Environmental

Performance

Social

Benefit

Cost of

Energy

($/MWH)

Installation

Cost ($/kW)

Medium Scale

Hydroelectricity

POSITIVE

Varies

regionally

MEDIUM

Proven;

regional

HIGH

No GHGs

MEDIUM

Waterway

use

impacted

$85 - $135

+transmission

line

$9,000 -

$14,000

+transmission

interconnection

Clean energy and lower GHG emissions can be achieved through means other

than the solar PV installation in Colville Lake. And when factoring in economics, these other

means are made more attractive. Power from the new solar PV will cost an estimated $590-

$830/MWh —this is approximately 7 times higher than the equally carbon free energy potential

of a medium scale hydroelectric project where the cost is estimated at $85-135/MWh.

There are solar energy alternatives to the investment made in Colville Lake. For

example, individual residents and businesses in Yellowknife are investing in solar PV power

generation through the Alternative Energy Technologies Assistance Program and Arctic Energy

Alliance with subsidies from the territorial government. The savings in energy costs along with

the introduction of a Net Metering initiative has yielded high levels of satisfaction amongst

ratepayers at a minimal cost to NTPC and the government. From the perspective of economics,

the alternative energy subsidies are prompting private sector investment into power generation in

the territory (Appendix D-10).

8.10.4 Recommendations

NTPC needs improvement in project planning, design, estimation,

implementation and managing funds.

NTPC needs to develop standards, templates and bench marking for similar

projects.

Project options need to be investigated for viability. These investigations can also

assist in decision making concerning future projects.

- 61 -

Projects should be planned and designed to increase the amount of new assets in

the infrastructure.

As the lowest electricity rate is achieved through a hydro energy source, NTPC

should consider new medium and small size hydro plants in the NWT.

Renewable energy source projects should be small size pilot projects not affecting

the electricity rates and sustainability of NTPC.

NTPC should seek out increased community participation and collaboration in

small, medium and large projects.

9. Low Water Levels

9.1 Low Water Levels - Discussion

In the GRA 2016-19, NTPC indicates that low water levels in the Snare zone

have been an issue that impacted Operation and Maintenance costs, Revenue Requirement, Rates

and Reliability.

Low water levels in the Snare system are not a new problem. The “North Slave

Resiliency Study” report issued in March 2016, prepared for the GNWT by Manitoba

International Hydro (Appendix C-3) provides annual monthly mean inflows in the Big Spruce

Reservoir for the Snare System from 1950 to 2013 and 2014-2015 based on NTPC’s Snare

System level and flow data. The data demonstrates that low water levels in the Snare Zone are

cyclical and occur almost every 10 years. This information was available to NTPC and therefore

it is concerning that NTPC could not plan for this cyclical effect much earlier. The high costs

associated with dealing with the low water levels as a new crisis could have been mitigated if

they had been anticipated and adequately planned for. As the former Minister of Energy, NWT

stated in the January 23, 2015 issue of the Yellowknifer, investment in larger projects will

alleviate another potential shortfall in hydro production ( Appendix D-5). He also mentioned

there were concerns that Federal Government should increase the borrowing limit to enable such

a vision be implemented.

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Borrowing at the current level should not be used to bring the Return on Equity

(ROE) to 8.5%, and instead be invested in projects design to alleviate the impact of low water

issues.

NTPC’s request for a rate rider increase due to low water level has prompted

strong negative reaction from communities in the NWT, including criticism of the lack of

contingency plans to deal with low water levels. The Northwest Territories Association of

Communities (NWTAC) has called for the rate increase to be refused, and for the referral of

NTPC operations to the Auditor General of Canada for review (Appendix D-6).

Although investments are made on a few new capital projects and capital projects

of overhauls and refurbishment by the NTPC, it is unclear whether the investments provide the

maximum capacity and efficiency to alleviate the existing problems and to enhance the system.

NTPC needs to provide assurance how each investment improves the system and increases the

capacity and efficiency.

For example, the recently built Bluefish hydro plant has been installed with a

penstock assembly in deviation from the standard penstocks, which may experience higher head

loss. A picture of universal penstock assembly and a picture of Bluefish penstock assembly

obtained from Bluefish Redevelopment Study – Yellowknife, NT RFP No. 21604 are attached

as Appendix D-7 for comparison

9.2 Recommendations

NTPC needs to invest in planning for the low water level as a recurring, long term

problem. NTPC needs to review the water level history and emerge with viable solutions to

manage low water level in Snare.

NTPC should create a required firm capacity (RFC) with hydro plants in Snare

zone.

NTPC should initiate capital planning for new hydro projects before investing in

the aging infrastructures of existing hydro plants.

- 63 -

10. Conclusions

In spite of NTPC’s strategic direction, comprehensive capital planning process and

capital project management policies and procedures, the review of selected projects

reveals that NTPC needs to improve tremendously on project management, most

importantly for cost effectiveness to reduce the impact on rates, in addition to a few other

factors as set out in the recommendations of rate base.

NTPC’s constant defence on the low water levels in Snare is unacceptable as NTPC

failed to have a contingency plan recognizing this is a cyclical effect. Low water level

negatively impacted not only reliability and the environment, but also on capital

planning, fuel cost and eventually on the rates.

NTPC’s reliability report states that NWT is within the tolerable reliability indices level.

However, problems with reliability and increasing rates pushed the community of

Yellowknife to hold a forum to discuss on alternative energy sources. NTPC should

improve on reliability so that reduced operation and maintenance cost would reduce the

rate.

Regardless of the subsidy, communities may curtail on power usage to reduce their

electricity bills. Any further rate increase will negatively impact on the socio-economic

welfare of the communities rather than raising revenue for NTPC. Rather NTPC should

incorporate more large industrial customers to increase the revenue and reduce rates.

The GNWT, as shareholder, has made a considerable amount of contributions to NTPC’s

business operation in the last few years. Approved dividends from ROE have become

- 64 -

meaningless and been forgone. NTPC borrows $60 million dollar long term loan and will

reduce the sinking fund to invest on the capital projects. ROE is a measure of profitability

of a business. Evidently in this scenario profitability is not achievable.

NTPC should recognize that the customers have experienced the impact of electricity rate

hikes in the past including other difficulties. NTPC should avoid cross subsidization

among the zones, renounce the request of ROE of 8.5%, relieve the customers from rate

increases and focus on building the aging infrastructure to increase revenue and to reduce

the rates.

There are unknowns and irregularities within the information provided by NTPC that

prevent a constructive review of the GRA 2016-19 Phase I.

Intentionally Left Blank

Janaki Balakrishnan

Experiences related to electricity industry and public utilities

I have gained almost 40 years of experience in electrical engineering, in the electricity industry or

related to it, and public utility. The experiences were related to utilities of municipal, provincial,

territorial and national. The experiences include power generation, transmission and distribution. Power

generation experiences are of fossil fuel, renewable and clean energy sources, namely coal, diesel,

hydro, nuclear, solar, wind, bio-fuel, natural gas, fuel cell and small molten reactors. A few significant

projects and programs in various work places and other institutions are described to indicate the type of

responsibilities and involvement, which shall be comparable to some projects. programs and activities

listed in the General Rate Application of Northwest Territories Power Corporation (NTPC) 2016-19.

The most recent experience similar to NTPC was in 2012, when I was employed by Qulliq Energy

Corporation (Nunavut Power Corporation) comprised of 25 communities, all with diesel generation. I

was Manager, Electrical Section reporting to the Director of Engineering, who was former Director of

Engineering, NTPC. I managed 3 Engineers in Training, 1 Senior Electrical Technologist, 1 Electrical

Technologist and 1 CADD Person, including recruiting, coaching and training the staff.

My responsibilities were development of capital projects, preparation of 5 year budgets submitted for

internal approval and rate application, project reports and briefs, business economic evaluation,

tendering and inviting proposals, project planning, designing and implementation, including feasibility

and impact assessment studies, raising funds from Qulliq Energy Corporation (QEC) capital budget

allocation and federal agencies. Further, the responsibilities included development of policy, procedures

and guidelines documents on engineering and health and safety matters. Examples: Arc Flash Study and

Fire Resistant Clothing, and Joint Use of Utility Structure. I familiariazed with northern rules and

regulations, land use practices, impact assessments, contract law etc.. From time to time, I acted on

behalf of the Director of Engineering in his absence.

I attended proposed Iqaluit Hydro-electric project at Jaynes River – 10 MW or more and Armshow River

South – 6 MW or more, including a site visit by helicopter with consultants. The project was intended to

supplement growing demand of Iqaluit by renewable energy, the first hydro-electric project in Nunavut.

Iqaluit Hydro-Electric Project was proposed a few years ago and a partial feasibility study was

conducted. However, the project did not proceed due to lack of funds and other reasons and got

shelved. My work involved collection of almost a dozen of study reports, reviewing and learning the

entire project. I re-engaged consultants, Knight Piesold, following a regular RFP process. I organized and

reinitiated the project to complete the feasibility study, socio-economic impact assessment and

environmental assessment by meeting with stakeholders for land use permits and applying for impact

assessments. I also attended a session conducted on Public, Private, Partnership (P3) for seeking

opportunity for funding options for the project.

I prepared and submitted a successful funding proposal for Iqaluit Advanced Metering Infrastructure

(AMI) project, which raised 50% of $3.6 million dollars under the EcoENERGY Innovation (ECOII)

program from CanmetENERGY of NRCan for 3 years. The project was partly intended to reduce

consumption of fuel through demand management and reduce GHG emission.

Janaki Balakrishnan

The project was to assess and integrate smart grid technologies in to the Iqaluit electricity distribution

system. The project was planned as three parts:

a) Installing advanced automatic metering infrastructure (AMI) and software tools to compile and

aggregate data from customer loads to pursue peak load management strategies;

b) Installing sensors for monitoring transformer, distribution line loads and fault conditions for the

application of distribution automation and automatic system restoration; and

c) Studying tools for the optimization of the control strategy for diesel-hybrid generation plant.

Funding proposal involved responding to the questions of applications form and compiling information

related to description of Nunavut communities, existing electricity distribution system, what was aimed

out of the project, providing roles and responsibilities of individuals of QEC team on the project and

their qualifications and support letters from Government of Nunavut, City of Iqaluit etc.. Further, it

required planned activities in each phase and related estimated cost and a GANTT chart for project

schedule management. More importantly an economic evaluation for the forecasted life cycle period

was performed and presented to convince the project will payback and the rate of return of the

investment would be acceptable.

I attended projects of prefabricated modular design power plants in Qikiqtarjuak and Taloyoak of 4 x

5.5 kW each, which were intended to reduce construction efforts and time in the North, by

reassembling at the site. Similar plant was installed in Paulatuk, Northwest Territories, a few years ago.

The project was planned for medium term and long term installed capacities. As such, initial installation

was with 2x550 kW and 2x360 kW diesel generators, with a provision to upgrade with 4x550 kW in long

term on the same generator beds, making use of the prefabricated modular design.

This project participation involved working in collaboration with Gygax Engineering Associates Ltd.

(Prime consultant), Struthers Tech (electrical consultant), Tromont generator suppliers, mechanical

consultants and QEC mechanical staff and electrical staff. I took part in preparing electrical

specifications, reviewing and commenting entire tender specifications for the purchase of diesel

generators and electrical equipment installed in the modular power plant. Provided input in planning of

modular power plant, reviewed and commented on the design of modular power plant, in all aspect

civil, structural, electrical and mechanical, but primarily electrical. The design also involved suggesting

access routes for the delivery of diesel, collection of waste etc., while orienting the power plant

conveniently to suit the existing access roads or pathways in the community. I communicated with the

authorities to obtain permits for the use of land. I submitted application to Nunavut Impact Review

Board (NIRB) for the impact assessment.

As Manager, Electrical Section, QEC, took part in the QEC Iqaluit Main Plant Upgrade, Expansion

and Renovation performing various duties at various levels of the project. This required working

in coordination with the QEC operation and maintenance team, QEC mechanical section, SNC Lavalin

Consultants, Kudliq Construction, Guy Electric and specially assigned QEC Project Manager.

Janaki Balakrishnan

As part of this project, replacement of existing transformers, with 2 new 750 kVA, was a special and

critical sub-project. I inspected and confirmed transformers were delivered as per tender requirements.

Subsequently, I managed installation and changing connection to the newly installed transformers from

the existing transformers. This involved a planned power outage for a long period overnight, which was

conducted first time in QEC. It required specific efforts related to planning and implementation,

construction, media communication to the community, coordination and communication with QEC

Directors and Government of Nunavut at ministerial level. The sub-project involved establishing a team

of members of electrical and mechanical staff, operation and maintenance staff on shift duty and

supervisors, PLC staff, Kudliq Construction and Guy Electric, and following and adhering to the

construction schedule closely. It further required preparing operational sequence, guidance and

coaching of operation staff on duty at the time of outage. Businesses operations and community

assessment were other factor of choosing the time of outage minimizing businesses interruptions and

community inconveniences. The sub-project was completed successfully with minimum interruptions to

the City of Iqaluit. One glitch that caused a delay to the planned schedule allowed to determine the

deficiency in the power system and helped for future planning.

Other experiences are listed in the ascending order.

My career began as an in-plant trainee in the Sri Lanka Electricity Board, a National Public Utility, while

being an under graduate in 1973, having underwent training at a coal power station in the north and in

transformer workshops in the west of Sri Lanka,.

After graduation from the University of Sri Lanka, I was employed by the Mahaweli Development

Board, Sri Lanka in 1976 as Trainee Engineer (Electro-mechanical) to work in Ukuwela Hydro Power

Station assisting the Senior Engineer (Electro-mechanical). The work was related to Mahaweli river

diversion project, which facilitated the development of Sri Lanka in expanding electricity generation,

transmission and distribution, water supply and irrigation, and eventually settlement and resettlement

of people of Sri Lanka in the cities, towns, villages and remote areas. Ukuwela was down stream of main

diversion at Polgolla dam. Ukuwela Hydro Power Station work involved commissioning of hydro-power

generation plant consist of 2 generators of each 21.4 MVA, 12.5 kV, 300 rpm with turbine design head of

246 ft or 75 meter. During this period worked with contractors, Mitsubishi Electric Corporation, Japan

and Ingra, former Yugoslavia, and the Mahaweli Development Board Consultants, Sogreah, France and

the Engineers and Technical Staff of Sri Lanka Electricity Board. A few photos are attached of Ukuwela

hydro power station and penstocks, during commissioning are attached in Appendix 1. When

commissioned, the plant was handed over to the Sri Lanka Electricity Board, the national public utility.

Following that until early 1977, I was posted at Bowatenna diversion dam, a six radial dam project

installed by contractors Nippon, Japan. Dam channeled and diverted Mahaweli water, including Ukuwela

down stream water, for water supply and irrigation in the central part of Sri Lanka filling a few

lakes/reservoirs, new, existed and expanded. The spillways combined had a maximum discharge

capacity of 25,000 cu ft/s or 3,500 m3/s. Presently, Bowatenna has a 40 MW hydro power station too.

Janaki Balakrishnan

In 1977, I joined Sri Lanka Water Supply and Drainage Board under the Local Government as Regional

Electrical Engineer. In this capacity, responsible for planning, design, installation, commissioning,

operation and maintenance of water supply and treatment plants for cities, towns and villages, including

remote areas, of North Central, Northern and Eastern provinces. Remote water supply systems were of

diesel pumps and town and city electrically operated. Initiatives were taken to extent electricity to the

remote areas and convert diesel pumps to electrically operated systems. Water supply was a public

utility and clean drinking water supply was an essential service. The operation and functioning was

similar to electrical utility. Later in the absence of Regional Mechanical Engineer, became responsible for

electro-mechanical aspect of water supply and treatment plants, managing a staff of 70 at various

locations of different trades and occupations, served until 1980.

I began M.A.Sc. in Electrical Engineering (Power) in 1984 and completed in 1986. The degree program

included six courses, power system stability, power system control, power conversion, non-linear

circuits etc., including assignments and exams. In completion a written and oral presentation of a thesis

was submitted. The thesis was about determining losses in conductor arrays, similar to transmission

lines or electrodes of arc furnaces in a steel company, using computer analysis with the application of

finite difference method.

In 1987 to 1989, as Teaching Master at Centennial College and Seneca college taught courses for

electrical technologist and electrical technician programs, that included high school graduates and

adults on unemployment insurance for retraining. During that period, a tour of Pickering Nuclear Power

Station of then Ontario Hydro was arranged for the students.

Having worked for consulting engineers from 1989 to 1993, gained experience in electrical power

requirements and electrical service connections to residential, commercial, institutional and industrial

buildings and coordinated with electrical utilities. I also worked on projects of retrofit of lighting and

electrical systems to reduce electricity consumption.

In 1993, I was employed as an Engineer by Toronto Hydro, the largest municipal electricity distribution

company, a public utility, in Canada and served until 2011. Toronto Hydro served over 650,000

customers soon after amalgamation and at present 756,000 customers, comprised of considerable

number of residential, commercial, institutional and industrial customers. During the period of

employment, I gained extensive experience of a municipal distribution utility working in different

departments and sections and in coordination with transmission utility of 132 kV/27.6 kV systems,

former Ontario Hydro and present Hydro One.

As my first project in the Technical Support Services Department, I developed transformer load

management system in the Automated Mapping/Facility Management/ Geographical Information

System (AM/FM/GIS). It involved development of a computer program to calculate transformer loads

and populate and alert loads in the Computer Aided and Design and Drafting (CADD) system.

In Network Engineering Department, performed load analysis of network underground transformers

and planned and designed transformer and feeders management and contingency planning system.

Janaki Balakrishnan

In Engineering Studies, I researched and studied protective devices and prepared reports to the

management.

In Standards Engineering, I developed construction standards of underground distribution systems,

switchgears and enclosures and rooms, transformers, cables and cable joints of high voltage, 13.8 kV

and low voltages, 4 kV and 600 V. Construction Standards were developed in consultation and

collaboration with crews considering safety and other site and work related matters.

In System Planning, I worked with teams of Operation and Maintenance in planning and designing

distribution system to increase capacity and improve reliability, which involved voltage conversion from

600 V to 4KV and 4 kV to 13.8 kV systems.

I was hired to report to the Senior Manager of Customer Facilities Design and Construction in 1999,

when Toronto Hydro needed to focus on Electricity Industry restructuring in Ontario, which was

regulated by Ontario Energy Board (OEB). I was assigned as a team member of the Integration Program

of amalgamation of all six utilities in Greater Toronto Area, East York, Etobicoke, North York,

Scarborough, Toronto and York. The initial work involved in harmonizing Construction Standards and

Conditions of Service of all six utilities. I was awarded for the Leadership and Contribution to Toronto

Hydro’s Integration Program.

I learnt and familiarized Ontario Electricity Act, Ontario Energy Board Regulations and Codes,

Independent Energy System Operator (IESO) Rules and Regulations, formerly Independent Market

Operator (IMO) and other related matters. I was a team member of the Cost of Service Study (COSS) for

the amalgamated Toronto Hydro and determined minimum cost of service and average cost of service

of the distribution system of each utility, which were then harmonized to one Toronto Hydro and used

in determining the electricity rate. I was praised by the consultants, who audited the complete study

report and the application to be submitted to the Ontario Energy Board, when presented the innovative

approach of determination of minimum cost, which adhered closely to the computer analysis applied in

my M.A.Sc. thesis.

I investigated, applied and rolled out a newly introduced Business Economic Evaluation (BEM) model, an

excel Spreadsheet developed by a consultant, to determine Net Present Value (NPV), rate of return ratio

and payback period of capital projects. The model allowed determining customer’s capital contribution

requirement for new development, enhancement and expansion projects that required Toronto Hydro

service connection or upgrades. The developed program performed a life cycle analysis of cash flow,

considering a capital investment horizon and a revenue horizon.

In Investment Delivery, evaluated capital contribution of different classes of customers, residential,

commercial, institutional and industrial using the business economic model. Considering the size of

development and certainty revenue of revenue strategized the application of model accordingly. I was

part of the team lead by the Corporate Secretary and Lawyer in drafting and reviewing the agreements

of customer capital contribution in compliance with the regulations and codes of Ontario Energy Board.

The contracts were executed by the Senior Vice President and customer capital contribution was levied

Janaki Balakrishnan

as cash/cheque or letter of credit issued by a bank and collected by Treasury of Toronto Hydro, before

initiating the project.

As project leader established a backup control room at 60 Eglinton Ave E, coordinating a number of

personnel from various departments and sections, which included managers, supervisors and obtaining

approval from the Senior VP.

I prepared a report on 10 year load forecast for Toronto Hydro summarizing CanaData Annual

Construction Forecast 2004-2006, Ref. Reed Construction Data.

I was engaged in QA/QC implementation of Toronto Hydro construction. I developed a database of cut

permits for record management. The software was taken over by IT to incorporate in Ellipse, IT

Corporate application of Australian vendor and developer, Mincom.

In Investment Planning, my work involved station and distribution system capacity short term and long

term planning, protection and control, feeder reliability, load forecast and contingency studies. I

prepared and submitted a report on short term and long term planning of stations in East and West

Toronto. This work required analysing coincidental and non-coincidental peak loads and average loads

of stations and feeders utilizing the computerized load information system maintained by Hydro One,

the transmitter, who provided access to the system for Toronto Hydro.

I remodeled the Business Economic Model (BEM) for budget preparation of Investment Planning

Department.

In Capacity Planning, I was one of the lead Engineers of distributed generation (DG) projects and

attended applications and interconnections of various embedded generation micro, small, medium and

large sizes. The DG projects were under different programs, Toronto Hydro’s Net Metering, Ontario

Power Authority’s micro Feed-in-Tariff (FIT), Micro FIT, Renewable Energy and Clean Energy Standard

Offer Programs (RESOP and CESOP), and Independent Electricity System Operator’s Hourly Ontario

Energy Program (HOEP) and Demand Response Program applicable to various electricity rates and

settlement.

DG projects required consultation meetings with DG customers, development of application forms,

standards, connection diagrams, coordination with Ontario Power Authority in following time tables and

finalizing agreements, connection impact assessments for compliance, review of protection and

coordination and determination of DG penetration levels and not exceeding the limits decided by Hydro

One, the transmitter. DG projects also involved short term and long term capacity planning of stations

with respect to DG, feeder loading analysis and DG penetration, reliability issues with respect to

islanding, corresponding DG protection review in coordination with Hydro One. DG projects were of

solar, wind, gas, bio-fuel, bi-fuel, fuel cell etc. and the projects sizes varied from 1 kW to 10 MW.

I prepared the original Distributed Generation and Interconnection guidelines of Toronto Hydro in 2011

Janaki Balakrishnan

in compliance with the regulations and codes of Ontario Energy Board (OEB) and requirements of

Ontario Power Authority (OPA) and Independent Electricity System Operator (IESO). The report was

completed in consultation with the Corporate Lawyer and obtaining input from managers and

supervisors of various departments.

I assisted Supervisor and Manager in preparing responses for Toronto Hydro’s Rate Application

Intervention by Ontario Energy Board and other Intevenors.

In 2013, I was employed as Team Lead - Electrical in Williams Engineering Canada, Consulting

Engineering company in Yellowknife and managed over 100 projects in Northwest Territories and

Nunavut, while managing the staff, recruiting, coaching and managing. Management of projects

involved working in collaboration with architects, consultants, contractors and engineers and staff of

other disciplines in Williams Engineering. The clients were Government of Northwest Territories,

Government of Nunavut, Community Governments, Hamlets, and developers and owners of mines,

commercial and institutional businesses. Projects management included being Engineer-of-record,

planning, designing, estimating and monitoring progress and inspecting construction of projects.

Projects required obtaining new electrical services or upgrades and coordination with utilities,

installation of backup or emergency generators, ECO buildings and renewable and clean sources of

energy, such as solar PV and wood pellet bio-mass.

I also organized training sessions for electrical staff, including other stakeholders, contractors, GNWT TSS, Inspection staff etc. on CSA Electrical Code, Fire Protection and Life Safety system, final site inspection inviting instructors from the South. I attended a few seminars and conferences held by NAPEG and GNWT and visited mining sites.

From 2003 served as volunteer Energy Specialist/Consultant in TDND Canada, a charity international

development organization, operated with a mission of ‘Sustainable Development for Humanity’. I

conducted research and study of renewable and clean energy sources and projects for implementation

in developing countries. I also presented papers on various topics at different Canadian and

International Conferences and Symposiums, which are listed as follows:

In October 2008 ‘Fuel Cell: Today’s Technology as Alternative Energy’ at an International Symposium

on Engineering in a Climate of Change conducted by Ontario Society of Professional Engineers.

In 2008 ‘The Effects of Transformer Configuration on Distributed Generator Interconnection’ to

ICIIS2008 conference, conducted by IEEE Karaghpur section, West Bengal, India and IEEE Sri Lanka

section.

In 2007 ‘Fuel Cell Technology’ at the Third International Conference on Information and Automation for

Sustainability - ICIAfS 2007, conducted by IEEE Melbourne at Langham Hotel, Melbourne, Australia.

Chaired the session on “Fuel Cell and Renewable Energy”.

Janaki Balakrishnan

In 2007, ‘Fuel Cell Operation and Configuration’ at the Electrical Power Conference - EPC07, conducted

by IEEE Ottawa and Montreal Chapters in Montreal, Quebec, Canada. I also chaired the session on

“Renewable Energy and Distributed Generation”.

In 2007 ‘Distributed Generation Interconnection Protection’ at the International Conference on

Industrial and Information Systems - ICIIS2007, conducted by IEEE Sri Lanka section and Karaghpur

section, India. I chaired the session on “Renewable Energy and Distributed Generation”. I also served on

the International Advisory Committee of the conference.

In 2006, presented three (3) Papers on ‘Renewable Energy and Distributed Generation in Rural

Villages’, ‘Renewable Energy and Employment’ and ‘Biomass application in Distributed Generation’ at

the International Conference on Industrial and Information Systems - ICIIS2006, conducted by IEEE Sri

Lanka section and Karaghpur section, India. I also co-chaired the session on “Renewable Energy and

Distributed Generation”.

In 2006, arranged a tour of Fuel Cell – Compressed Gas Turbine hybrid project installation at the

Enbridge, Toronto site, a DG project which I was responsible for in Toronto Hydro, to the Professional

Engineers of Scarborough Chapter, Ontario.

Experience in testifying in Utility Proceedings

This is the first time I am testifying in person in Utility Proceedings.

I made a written submission in April 2016 on the Interim Rate Application 2016-17 by NTPC to the NWT

Public Utility Board (Board).

In the past, while working in Toronto Hydro assisted Regulatory Department, Cost of Service Study

Team, Managers and Supervisors in preparing reports, documents and responses for Cost of Service

Study and Electricity Rate Applications submitted to the Ontario Energy Board.

Experience in testifying in other Proceedings

I submitted a written testimony and appeared to testify in front of the Canadian Parliamentary Standing

Committee on Electoral Form on September 30, 2016.

In 1993 I submitted a written testimony and appeared to testify in front of the Ontario Parliamentary

Standing Committee of the Bill on Employment Equity introduced by the Ontario NDP Government.

In 1995 I submitted a written testimony and appeared to testify in front of the Ontario Parliamentary

Standing Committee of the Bill to Repeal Employment Equity by the Ontario Conservative Government.

In 1985 I served as an interpreter when refugee status claimants testified in front of the Adjudicators of

Refugees Board of the Canadian Immigration Department in Toronto.

Intentionally Left Blank

JANAKI BALAKRISHNAN - RELEVANT COURSES AND PROGRAMS ATTENDED

2015 NOV

- PACIFIC NORTHWEST ECONOMIC REGION (PNWER) LEGISLATIVE LEADERSHIP ACADEMY AND ECONOMIC LEADERSHIP FORUM (3 ½ DAYS), PARTNERED BY ITI, GNWT AND CONDUCTED PARTLY IN THE GNWT LEGISLATIVE BUILDING, YELLOWKNIFE

2015 NOV

- PMC – PROJECT MANAGEMENT CONFERENCE, DEPT. OF PUBLIC WORKS, GNWT

2015 FEB

- FINAL CONSTRUCTION INSPECTION OF FIRE PROTECTION AND LIFE SAFETY SYSTEMS, SIMPLEX

2014 NOV

- PMC – PROJECT MANAGEMENT CONFERENCE, DEPT. OF PUBLIC WORKS, GNWT

2014 FEB

- FIRE PROTECTION AND LIFE SAFETY SYSTEMS, CANADIAN STANDARDS ASSOCIATION

2013 JUNE

- ELECTRICAL CODE, CANADIAN STANDARDS ASSOCIATION

2013 APR

- CONSTRUCTION COST ESTIMATING (3 DAYS) – ELECTRICAL, RS MEANS

2013 JAN

- REED LEARNING, UK, “MANAGING DIFFICULT PEOPLE”, TWO DAY MANAGEMENT COURSE

2012 SEPT

- CANMETENERGY WEBINAR WORKSHOP ON REMOTE COMMUNITIES MICROGRID AND REMOTE COMMUNITY DEMONSTRATION PROJECTS AND ASSESSMENT

2011 DEC

- CONFERENCE/EXHIBITION OF SOLAR POWER (3 DAYS), TORONTO

2008 DEC

- SYMPOSIUM ON POWER, HIGH VOLTAGE AND ENERGY SYSTEMS (2 DAYS), IEEE SRI LANKA SECTION

2008 OCT

- SYMPOSIUM ON CLIMATE FOR CHANGE – OSPE, TORONTO

2008 JULY

- SYMPOSIUM ON ALTERNATE ENERGY AND GLOBAL SYNERGY, IEEE TORONTO SECTION

2008 MAY

- MANAGING ME – REAL WORLD SELF MANAGEMENT – DOUG HEIDEBRECHT

2007 DEC

- ARC FLASH SAFETY – ELECTRICAL SAFETY AUTHORITY (ESA), ONTARIO

2007 NOV

- WRITING DYNAMICS – MCLUHAN AND DAVIES COMMUNICATIONS INC.

2007 SEPT

- EFFECTIVE WRITING FOR ENGINEERS, ONTARIO SOCIETY OF PROFESSIONAL ENGINEERS

2006 NOV

- PROJECT ECONOMICS AND BUSINESS CASES - ASHER DRORY, UNIVERSITY OF TORONTO PROFESSIONAL DEVELOPMENT CENTRE

2006 OCT

- PROTECTION AND CONTROL AND AUTOMATION, SWITZER ENGINEERING LABORATORIES (SEL)

2005 NOV

- FINANCIAL LITERACY, PROJECT ECONOMICS AND STRATEGIC DECISION MAKING – ASHER DRORY, U OF T PROFESSIONAL DEVELOPMENT CENTRE

2005 OCT

- PROTECTION OF ELECTRICAL DISTRIBUTION SYSTEM – DR. W.H. KHELLA, P.ENG.

2005 SEPT

- POWER TRANSFORMER FORUM - THE ELECTRICITY FORUM TRAINING INSTITUTE

2005 JUNE

- RELIABILITY CENTRED MAINTENANCE I AND II - JAMES V. REYES-PICKNELL

1997 FEB

- COGENERATION I AND II – W.B.HARVEY, P.ENG.

1997 - MANAGEMENT SKILLS AND TECHNIQUES FOR NEW SUPERVISORS, CANADIAN MANAGEMENT CENTRE OF AMERICAN MANAGEMENT INSTITUTION

1997 - FUNDAMENTALS OF FINANCE AND ACCOUNTING FOR NON-FINANCIAL EXECUTIVES, CANADIAN MANAGEMENT CENTRE OF AMERICAN MANAGEMENT INSTITUTION

1997 - LEADERSHIP FROM WITHIN, CANADIAN MANAGEMENT CENTRE OF AMERICAN MANAGEMENT INSTITUTION

1995 - LABOUR RELATIONS AND NEGOTIATIONS, U OF T CONTINUING EDUCATION

1994 - INVESTIGATION AND LITIGATION, U OF T CONTINUING EDUCATION

1994 - EFFECTIVE PROJECT MANAGEMENT AND COMMUNICATION SKILLS, U OF T CONTINUING EDUCATION

All­season road to Whati, N.W.T., gets federal gov't funding97­km gravel road will be built using P3 ­ public­private funding model

By Mark Rendell, CBC News Posted: Jan 11, 2017 1:02 PM CT Last Updated: Jan 11, 2017 8:19 PM CT

The federal government has announced it will pay 25 per cent of the cost of building an all­season roadto Whati, N.W.T., through the P3 Canada Fund.

The announcement of funding for the long­anticipated road into the heart of the N.W.T.'s Tlicho territorywas made Wednesday in Whati.

Additional funding for construction of the 97­kilometre gravel road will come from the territorialgovernment, contingent on approval by the legislative assembly, as well as the private sector, using apublic­private partnership, or P3, funding model.  

The government hopes to attract that up­front private sector funding by guaranteeing a 25­yearoperations and maintenance contract to the winning bidder. 

The total anticipated cost of the project has not been announced, as the government is putting theconstruction contract out to tender for private companies to bid on, but it was previously estimated tocost around $150­million.

N.W.T. continues down $150M road to Whati

The Request for Qualifications will go out in February 2017.  

As it stands, the community with a population of around 500 is only accessible by vehicle for severalmonths a year, via an ice road that's becoming increasingly expensive and technically challenging tobuild.

Tlicho winter road­builders face 'challenges' this year, say N.W.T. officials

"The road to Whati will create a lot of opportunities. There will be work... the cost of living will be a littleless, and there's also opportunity for businesses," says Alfonz Nitsiza, chief of Whati.

"It will be cheaper to go in and out of the community," he adds.

"Right now to go out and take my wife out for a weekend to Yellowknife, for the return fare alone will beclose to $900… If we're to take a few groceries home, that's over a dollar a pound, so it adds up prettyquick."

The road is expected to extend ice road access to Wekweeti and Gameti, communities north of Whati,by up to a month each year.

It also will help provide access to Fortune Mineral's NICO project, a significant gold­cobalt­bismuth­copper deposit roughly 50 kilometres northeast of Whati.

Local labour

The GNWT will release the request for qualifications in February, which will begin the search forcontractors to build the road. The hope is to award the contract sometime next year. 

"Once they get [funding] they want to fast track it, and hopefully the construction starts, probably in thewinter of 2018," says Nitsiza.

"It will hopefully be done by three years after that. So we'll probably have a road maybe in the next fouryears."

"During the two to four year construction period you might have several hundred workers," says RussellNeudorf, deputy minister of transportation.

"After that the numbers will drop down to a lower number for the [Operations and Maintenance] work. Iwould estimate about 10 or 12 full­time workers on the road." 

The lead construction contractor that wins the P3 will likely be from outside the Tlicho region, saysNitsiza. However "there will be subcontracting, and we'll probably be part of the subcontracts."

There will be "milestones certain companies have to meet to ensure there's local involvement," confirmsNeudorf. 

"We'd like to see 100 per cent [local employment]." 

The construction is expected to involve building two to three temporary 150­person camps — only oneat a time — according to government documents.

NICO mine projectBeyond the short­term employment opportunities in road construction, the new road could help bringmore mining jobs for the region. NICO mine has already received a water licence and land use permit,and successfully undergone an environmental assessment.

Mackenzie Valley board approves NICO mine

Fortune Minerals is still lining up financing for the project, but the year­round access to nearby Whatipromised by the road will certainly change the economics of the project for the better, allowing suppliesand mining products to be trucked in and out.

"Their problem has been their inability to raise necessary levels of capital to move to the next step ofconstruction," explained N.W.T. Premier Bob McLeod. 

"We've been to China, Fortune Minerals has been part of our trade mission to China. Their expectationis with a road, it will help make it easier for them to access capital so they can move on to the next step."

The road project also comes at a time when cobalt, NICO's primary resource, is increasingly in demand,thanks to a rapidly growing market for cobalt­based lithium­ion batteries used in renewable energystorage and electric cars.

Tesla electric car demand energizes plans for N.W.T. lithium and cobalt mines

The prospect of a nearby mine is appealing to Nitsiza, who sees it as a source of employment for Tlichomembers as well as a source of revenue for the Tlicho government through impact benefit agreements.

"We have housing problems, and we talk about loss of language, culture, way of life... And it seemswe're never going to have enough money to fix these problems, so the only way to fix some of theseproblems is to get some sort of revenue coming in, and that means development," says Nitsiza.

"Self government is all about self­sustaining. We've got to pay our way."

Potential impactThe road proposal still has to undergo environmental assessment. In July 2016 the Mackenzie ValleyReview Board ordered that an assessment be completed prior to construction, in light of "evidence onthe record [that] indicates that the Tlicho All‐Season Road… might cause significant adverse biophysicaland social impacts and public concern."

Of particular concern is the potential effect the road could have on the already beleaguered caribouherds whose migration routes pass through the region.

"The developer has said that the road project will likely extend the season for winter roads to Wekweetiand Gameti. This may extend the seasonal access to the Bathurst and Bluenose caribou herds,potentially increasing mortality from hunting," the review board states in its decision. Furthermore, "theroad project might also cause barrier effects to caribou movements, in the form of linear impediments,and disturbance resulting from dust, noise, and reduced air quality."

The assessment goes on to suggest the road could lead to social changes — involving an increase incrime, drugs and alcohol — that "could adversely affect the health and well‐being of residents of Whatì."

For his part, Nitsiza says he's not overly worried about the road's potential impact on caribou or thecommunity's social fabric. The caribou tend to avoid the area where the road will be built, he says. Andalcohol prohibition has "really never worked."

"We find out through open discussion and talking to the youth in school, and working with them, it's theonly way to go. We live in a mainstream society now, and we have to adapt to a new way of life."

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JANAKI BALAKRISHNAN

Apt 4, 5023 48th Street , Yellowknife, NT X1A 1N4

Tel. Nos: (867) 669 0327 & (867) 873 2825 E-mail: janakib2011@gmail.com

Personal Profile:

Experienced Professional Engineer (Electrical), over 30 years, as Engineer, Researcher, Educator

and Leader, Supervisor and Manager in the electrical and water utility industries, customer and

consumer service businesses, consulting engineering and academia.

Knowledge, Skills and Strengths:

Executive, Managerial and Business Administration

Projects and Programs Planning, Implementation and Management, including Northern

Research Planning, Implementation and Evaluation

Legislations, Regulations, Policy and Practices, including Northern

Teaching in Academic Institutions, Community Education and Development

Human Resources Management, including Unionized Labour

Financial Management and Business Economic Evaluations

Excellent Communication and presentation, oral and written

Innovative and versatile technology and computer applications

Quick learning and Self learning capacity

Areas of Expertise:

Sustainable development

Strategic Frame work and Economic Development

Economic Evaluation and Life Cycle Analysis

Proposals for projects and funding

Power Generation: Diesel Engine

Hydro power

Renewable, Solar and Wind

Bio-mass, Wood Pellet

Clean Energy, bi-fuel

Fuel Cell

Compressed Gas

Studying Integrated Small Molten Reactors (ISMR)

Power Distribution: Municipal in Toronto

Territorial in NWT and Nunavut

Interconnection of renewable and clean energy sources

Energy Management: Automated Advanced Metering system in Iqaluit, Nunavut

Time of use and Net Metering in Toronto

Regulatory programs, FIT, CHP etc. in Ontario

Educational Qualifications: M.A.Sc. in Electrical Engineering, University of Toronto, Ontario, June 1987

B.Sc. (Hons) in Electrical Engineering, University of Moratuwa, Sri Lanka

Awards and Scholarships: Employee of the month award in Williams Engineering in June, 2014

Awarded with an Honorary Doctorate for the outstanding performance in research and

community contribution by International University for Martial Arts, Sri Lanka in affiliation

2

with the Open International University for Complimentary Medicines, USA and New

International Karate Organization, Japan, March 2008

Circle of Employee Volunteers Award for the outstanding contribution to the Community by

Toronto Hydro Corporation, 2005

Award for the Leadership and contribution to Toronto Hydro’s Integration Program, 1999

(during electricity industry restructuring)

University of Toronto Open Fellowship, 1986

Ontario Graduate Scholarship, 1986

Professional Qualifications:

Licensed Professional Engineer (Electrical) in the Territories of Nunavut and Northwest since

2012, NAPEG

Licensed Professional Engineer (Electrical) in the Territory of Yukon since 2014

Licensed Professional Engineer (Electrical) in the Province of Ontario (Licensed is formerly

registered) since 1987, Professional Engineers Ontario (PEO)

Senior Member of Institute of Electrical and Electronic Engineers (IEEE)

Employment Experience:

Principal Consultant, ENVISION, Yellowknife, NWT

April 2015 - Present

Team Lead Electrical, Williams Engineering Canada Inc., Yellowknife, NWT

February 2013 – Jan 2015

Manager – Electrical Engineering, Qulliq Energy Corporation (QEC), Iqaluit, Nunavut

February 2012 – October 2012

Engineer - Toronto Hydro, Toronto, Ontario

May 1993 – Oct 2011

Project Engineer – Consulting Engineering Services, North York, Ontario

August, 1989 - May 1993

Teaching Master - Seneca College, North York and Centennial College, Scarborough

Jan. 1987 - May, 1989

Research Assistant/Graduate Student/Teaching Assistant - University of Toronto, Department of

Electrical Engineering, Ontario

Sept. 1984 - Nov. 1986

Regional Engineer (Electro/Mechanical) – Water Board, Government of Sri Lanka, Sri Lanka

Feb., 1974 - Dec., 1981

Manager (Part-time), 929 Medical Centre, Toronto, Ontario, 1996

Interpreter, Department of Immigration, Toronto, 1984 - 1986

Supervisor, H & R Block Income Tax Services, 1984 – 1986

3

Volunteer & Leadership Experience:

President, TDND Canada, Toronto, Ontario, Oct 2007 – Present

Member of the Board, Community Care Access Centre, North York, 1997-1999

President & Vice Chair, Council of Agencies Serving South Asians, Greater Toronto, 1996 - 99

Chair & Vice Chair, South Asian Women’s Centre, Toronto, 1994 - 1997

Vice Chair & Member of the Board, Alliance for Employment Equity, Ontario, 1995 – 1997

Chair, Vice-Chair & Secretary, PEO Willowdale / Thornhill Chapter, Ontario, 1991 – 1996

Executive Member, Professional Engineers Group, Toronto Hydro, Toronto, June 1994 – 1995

Member of Board of Health, East York 1989 - 1991

Consultant/Program Producer (Part-time), TV Tamil Inc., Scarborough, Ontario, 1998

Interests & Hobbies: Learning and exploring new and alternative technologies, community development, computer

application, solving problems and puzzles, volunteering, politics, meeting with people, reading,

skiing, kayaking, canoeing and T.V.

References: References will be provided on request.

Intentionally Left Blank

Prepared by Janaki Balakrishnan for own Reference – Submitted as Evidence in the GRA 2016-19 Phase I

Lac La Martre Falls (Proposed)

- 1 Genset, 6.5MW to Snare Grid

and Whati, relieve from diesel

- 1 Genset, 6.5 MW to NICO Mine, a

possibility

- 1 Genset, 6.5 MW, N-1 criteria

(North Slave Resiliency Report

indicated a study available for 13

MW at Lac La Marte)

Snare Rapids

2 Gensets, 8.0MW +

0.5MW

Snare Falls

1 Genset,

7.4MW?(7MVA)

Provision to connect

Emergency Genset

Snare Cascade

1 Genset, 4.3MW

Standby 225kVA

Diesel

Snare Forks

2 Gensets, 5.0MW +

5.0MW

Standby 150kVA

Diesel

Jackfish Grid

Substation

Substation

Substation

Substation

Substation

Bluefish – Old

powerhouse

1 Genset, G1 – 3.5MW

(nearing end of life)

Bluefish – Powerhouse

1 Genset, G2 – 4.0MW

Standby 150kVA Diesel

Frank Channel

Engine Module

1 Genset,

2.0MW

Frank Channel

Powerhouse

2 Gensets,

0.8MW +

0.7MW

Substation

Snare Falls Tie

Substation

- Ring Bus

Bluefish

Substation

Ingram Trail

Substation

Dettah Village

Substation

Yellowknife River

Substation

Niven Lake

Substation

Franklin Ave

Substation

Snare Rapid

Tie Point

Substation

Standby

Transmission??

Snare

Rapids

Camp

Distri.

Spillway

Substa-

tion

Jackfish Diesel Power Mirrlees 2 x 5.180 MW EMD 2 x 2.5 MW EMD 2 x 2.9 MW CAT 2 x 3.3 MW & Wajax?

 

1 

 

PO BOX 1500 YELLOWKNIFE NT X1A 2R3  

August 21, 2015 

 

Mr. Gordon Van Tighem  

Chair  

Public Utilities Board  

203 – 62 Woodland Drive 

HAY RIVER NT X0E 1G1 

 

RE: Northwest Territories Power Corporation 2014/15 Phase II General Rate Application  

 

Dear: Mr. Van Tighem,  

 

Please find Aboriginal Affairs and Northern Development Canada (AANDC) evidence for the Northwest 

Territories Power Corporation (NTPC) 2014/15 Phase  II General Rate Application (GRA).   The proposed 

significant  rate  increase  and  AANDC’s  participation  in  the  GRA  have  prompted  a  review  of  the 

reclamation  project’s  recent  power  usage  patterns.    A  significant  portion  of  the  cost  of  the  utility 

charges for the Project is related to electrical demand during peak times for the Utility, at an increased 

cost  per  kilowatt‐hour  (kWh).  The  peak  demand  for  the mine  could  be  reduced  (peak  shaving),  by 

scheduling automated equipment to operate at off‐peak times. 

Our preliminary  investigations have concluded  that  it  is  feasible  to avoid peak power usage at site as 

well as to significantly reduce our overall consumption of power. Peak power usage has negative cost 

implications for AANDC and also creates difficulties for NTPC to service other customers. 

Shaving the peak demand would reduce costs to the Project, and would potentially reduce the variable 

costs to NTPC, or allow the Utility to divert those resources to meet other customer demand. The fixed 

costs would still need to be distributed to the other customers. As NTPC’s proposed rate re‐structuring 

anticipates  revenues  from  the Project  that are well  in excess of cost  recovery,  the effect of  the peak 

shaving  could  significantly    decrease  the  enhanced  revenues  that  the  Utility  is  presently  projecting. 

Additionally,  AANDC  is  researching  the  feasibility  for  onsite  power  generation  to  further  reduce 

demands on the electrical system during these times. 

 

As  a  result of  the preliminary  investigations  to  the  feasibility of  reducing power use peak  times, we 

believe  that past patterns are not a reliable  indicator of our  future use – most of the changes we are 

investigating can be implemented quickly. As a result we recommend caution in setting rates based on 

existing peak usage patterns, and in particular in reliance on enhanced revenues driven by peak power use at an inflated RCC.While overall consumption should remain steady in the short term (0‐4 

2  

years) the distribution between peak and off peak times is likely to change significantly in the near term.  

A more precise estimate of anticipated demand will be available once AANDC complete its investigation.        

 

AANDC has also  reviewed  the  Information Request  (IR) Responses  filed by NTPC on August 10, 2015.  

These responses provide  little clarification on the questions raised, specifically  IR’s 1, 4 and 5.   AANDC 

will  be  seeking  clarity  on  these  questions  and  others within  the NWT Utilities  Board  Public Hearing 

process.   

 

If you have any questions regarding this letter, please contact Mr. Adrian Paradis, Regulatory Manager, 

by phone at (867) 669‐2425 or by e‐mail at adrian.paradis@aandc‐aadnc.gc.ca. 

 

 

Yours sincerely,  

 

  

 

Craig Wells 

Director  

Giant Mine Remediation Project  

 

Encl. 

 

c.c.: NTPC Phase II GRA Distribution List   

 

 

 

List of Projects in North, 2012-2014

Janaki Balakrishnan

Projects attended in North as Engineer of Record (EOR), Project Manager or in other capacities:

Nunavut

1. Iqaluit main power plant – expansion and upgrade

2. Iqaluit Hydro-power Feasibility Studies

3. Clyde River Data Monitoring for Wind Power

4. Qikiqtarjuak Pre-fab Power Plant

5. Taloyoak Pre-fab Power Plant

6. Funding proposal, 50% of $3.6 million for Iqaluit for Automated Advanced Metering

Infrastructure

7. Baker Lake Tank Farm Upgrade

8. Kugluktuk Water Treatment Plant Upgrade

9. Kugaaruk Water Treatment Plant

10. Iqaluit Broadcasting Corporation (IBC)

11. Rankin Inlet First Air Hangar

12. Kivalliq Region Visitors Centre

13. Qikiqtarjuak Visitors Centre

14. Kugluktuk Visitors Centre

15. Clyde River Hamlet Office

16. Iqaluit Inuksugait Plaza – Tenants Improvement – multiple phases

17. Iqaluit Inukshuk School Renovation and Upgrade – multi phases

18. Rankin Inlet Multi-purpose Building Office and Residential

19. Taloyoak Residential Units

20. Iqaluit Gasification Plant Demo Project

21. Iqaluit Ware Houses

22. Iqaluit Seniors Residence Upgrade

23. Iqaluit Modular Water Treatment Plant

24. GN Legislative Building upgrade

25. Cambridge Bay GN Building Evaluation

Northwest Territories

1. Yellowknife Eco Housing

2. Prince of Wales Northern Heritage Centre (PWCH) Museum – Exhibits Lights Upgrade

3. Prince of Wales Northern Heritage Centre (PWCH) Museum – Wood Pellet Boiler

4. Prince of Wales Northern Heritage Centre (PWCH) Museum – Kitchen Renovation

5. Yellowknife Community Centre Fire Pump Installation

6. GNWT Laing Building - Fire Protection and Life Safety System

7. GNWT SHM Building – Fire Protection and Life Safety System

8. GNWT Jean Marie – Fuel Station Upgrade

9. GNWT Wrigley - Fuel Station Upgrade

List of Projects

Janaki Balakrishnan

10. GNWT Aklavik Health Centre – Fire Protection and Life Safety System

11. GNWT Tsiigehtchic – Department of Environment Warehouse

12. GNWT ITI Storage Upgrade

13. GNWT Fred Henne Park Loop D

14. Fort Providence Health Centre

15. Behchoko Sportsplex

16. Behchoko Long Term Care

17. Dene Chief Drygeese Building Generator Installation

18. Hay River Ecole Boreale School – Renovation and Expansion

19. CBC North Air handling Units Upgrade

20. Ekati Mining Air Handling Units Upgrade

21. City of Yellowknife Council Chamber Renovation

22. Court House Renovation

23. Stanton Hospital Renovation

24. Elks House Renovation

25. Seniors Residential Building in - 4 Communities

26. Inuvik Singles Residential Building

27. Redcliffe Developments Residential Units

28. Yellowknife Granite Apt Building

29. Yellowknife Brewery Pub

30. Yellowknife Vet Clinic

31. RCMP Detachment Units Renovation

32. RCMP Detachment Units Generator Installation

33. RCMP Fire Protection and Life safety System Upgrade – 2 communities

34. Hay River – 17 Storey Bldg. 3 Capital Cres - Fire Protection and Life Safety System

Upgrade

35. Norman Wells Mackenzie School Wood Pellet Boiler

36. Norman Wells Air Terminal Building Wood Pellet Boiler

37. Norman Wells Combined Services Building Wood Pellet Boiler

38. Behchoko Water Treatment Plant Wood Pellet Boiler

39. BHP Plant Hazardous Level Investigation

40. Edzo Swimming Pool Upgrade

41. Courageous Lake Mining Camp Site Evaluation Report

Yukon

1. Govt. of Yukon - Service Offer Agreement for Consulting Engineering Services

2. F H Collins Technical Education Wing Upgrade – Fee proposal to KZA in Yukon

Intentionally Left Blank

Intentionally Left Blank

N.W.T. alternative energy subsidies grow along with demand — not enough some say

By Kate Kyle, CBC News Posted: Dec 28, 2015 2:00 PM CT Last Updated: Dec 28, 2015 2:00 PM CT

Energy­conscious residents in the Northwest Territories are calling on the new government to lead thecharge for alternative energy in the territory — such as solar, wind and biomass.

"Solar is there. We should be using it," says Yellowknife homeowner Mike Freeland, who says he'ssaved hundreds of dollars since he installed a five­kilowatt solar photovoltaic (PV) panel system on hishome in July.

Along with reducing Freeland's environmental footprint, Freeland says the goal is to "end up with verylittle or zero power bill at the end of the year."  

He admits the $28,000 project wouldn't have made sense without help from the territorial government,which offered a rebate of about $7,500 through its Alternative Energy Technologies Program. He says itcould take up to 11 years to recoup the $20,000 cost to himself.

Freeland is among 47 homeowners and businesses from across the territory who applied for alternativeenergy rebates this year.

"We have concerns about costs of diesel and electricity in Yellowknife. It's only going to go up," Freelandsays. 

"I would strongly encourage government to put more money into the same pot."

Growing demandThe government allocated roughly more than half a million dollars in total rebates to help buy andinstall solar systems, biomass boilers, and wood pellet stoves, according to the Arctic Energy Alliance— the not­for­profit that administers territory's alternative energy and efficiency rebate programs.

"Most of that funding was spoken for by the middle of August," says Louie Azzolini, the alliance'sexecutive director. To meet the demand, Azzolini says the territory committed an estimated $1.8 millionin supplementary money this fall for this and new initiatives over the next two years.

Azzolini says demand is growing because the economics make more sense. He cites net metering— the ability to sell surplus electricity back to the grid — and the decreasing costs of solar technology.

"Four years ago (applicants were) people who were philosophically oriented toward that particularenergy source. What I am seeing now are people who are interested in it purely from a financialbusiness standpoint," Azzolini says.

"It hits home with the user when they are looking at their bill and they realize the savings that aregenerated."

'Dabbling' instead of 'diving in'

According to the GNWT's last budget, by the end of this fiscal year, it will have spent just over $16million in energy initiatives aimed at reducing greenhouse gas emissions and the cost of living over thelast four years.

Commitments for 2015­16 include $200,000 for a wind energy feasibility project near Inuvik and anothernorth of Yellowknife near the Snare hydro system, as well as $1 million for wood pellet boilers in Tulitaand Fort Good Hope.

Former Weledeh MLA Bob Bromley says alternative energy subsidies are a start but people need to seea return on their investment faster. "Right now (the government has) been dabbling where they need tobe diving into it."

Bromley says the government has been good at equipping its own facilities with biomass boilers — 22since 2007 — helping the territory's biomass industry to mature.

"We are now finally, in a modest way, stepping out into the communities."  

As an example, Bromley cites the solar­diesel­battery project in Colville Lake.

The GNWT also funded more than 90 percent of a football­sized solar energy project in Fort Simpson,N.W.T., the largest in northern Canada.

But Bromley says more than two thirds of the territory's communities still rely mostly on diesel. Andby the end of this year, the territory will have spent close to $50 million over two years to offsetincreased diesel generation due to low water levels at territory's hydro facilities — a problem Bromleysays likely won't go away.

"The pain could have been a lot less had we adopted things a lot earlier."

Bromley says an Energy Efficiency Act — that would set territorial wide standards for private,commercial, government and public infrastructure — would also make a big difference.

That's something the last assembly was considering, but never passed into law. 

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