Please confirm MH s position on rate increases relative to IFF07-1: a) Takes March 2007 rate increase of 2.25% as a given.

(1)

PUB/MH II-1

Reference: IFF07-1 Section 4.0 to 10.0

Please confirm MH’s position on rate increases relative to IFF07-1: a) Takes March 2007 rate increase of 2.25% as a given.

ANSWER:

IFF07-1 incorporates the 2.25% March 1, 2007 rate increase in General Consumers’ Revenue at approved rates as per Board Order 20/07. Manitoba Hydro acknowledges that this rate increase is still subject to final approval by the PUB.

(2)

PUB/MH II-1

Reference: IFF07-1 Section 4.0 to 10.0

Please confirm MH’s position on rate increases relative to IFF07-1:

b) Proposes annual increase of 2.9% from 2009 through 2018 to maintain a constant debt-equity ratio of 78:22

ANSWER:

IFF07-1 assumes annual rate increases of 2.9% in 2009 through 2018 in order to provide context for the rates that are the subject of this Application. The magnitude of future rate applications will depend upon financial and other circumstances at that time.

(3)

PUB/MH II-1

Reference: IFF07-1 Section 4.0 to 10.0

Please confirm MH’s position on rate increases relative to IFF07-1: c) Offers a high probability risk scenario which:

• Would require additional 1.2% over three years to cover capital expenditure escalation (of $100 M/year).

• Would require additional 0.9% over 2010-2012 to cover severe one-year drought.

ANSWER:

(4)

PUB/MH II-1

Reference: IFF07-1 Section 4.0 to 10.0

Please confirm MH’s position on rate increases relative to IFF07-1:

d) Offers two alternatives on debt/equity of 75:25 would require either:

• Additional 0.6% increase (3.59% year total) 2010-2018. Or

• Additional 3.7% increase 2010-2012 (6.6% year total) and 0% increases - 2013-2018 to achieve by 2011/12.

ANSWER:

Annual electricity rate increases of 3.5% from 2009/10 to 2107/18 are projected to enable the achievement of the 75:25 debt/equity target by 2017/18. To achieve 75:25 by the 2011/12 target date, rate increases of 6.6% per year would be required from 2009/10 to 2011/12.

(5)

PUB/MH II-2

Reference: PUB/MH I-4 WLP Agreement

a) Please provide the valuation utilized in determining WLP financial interest in the Wuskwatim GS and explain how the cost escalations related to the project impact the ownership interest of the WLP partners?

ANSWER:

A complete economic and financial evaluation of the Wuskwatim project was filed with the Clean Environment Commission, April, 2003.

The two Limited Partners would invest equity in the project by subscribing for units worth, in total, 25% of the total capital. The analysis to date assumes that the Nisichawayasihk Cree Nation will subscribe for a 33% share of these units. The Nisichawayasihk Cree Nation is required to make an initial cash downpayment of not less than $1 million at the project commitment date and would finance the balance of its investment during construction through loans from Manitoba Hydro. Upon the in-service of Wuskwatim G.S., the Nisichawayasihk Cree Nation would be required to provide an additional cash equity payment (referred to, in conjunction with the $1 million downpayment, as the cash component of its investment). The balance (the financed component) would be provided by Manitoba Hydro. The minimum cash component and maximum financed component are governed by an agreed upon formula.

Based on the Wuskwatim G.S. cost assumptions included in IFF07-1, the PDA requires that the Nisichawayasihk Cree Nation make a total cash equity payment of $34 million for a 33% share of the units and Manitoba Hydro would lend Nisichawayasihk Cree Nation $68 million for the financed component of its units in the Partnership. Manitoba Hydro would be required to invest $207 million for its 67% share of the units. The balance of the capital requirements will be financed by debt.

(6)

PUB/MH II-2

Reference: PUB/MH I-4 WLP Agreement

b) Based on the current cost to construct of $1.6 billion, please confirm the required equity investment of the WLP partners.

ANSWER:

(7)

PUB/MH II-2

Reference: PUB/MH I-4 WLP Agreement

c) Given the current ownership structure of WLP, please explain how much NCN will require to invest to acquire 33% beneficial ownership of WLP?

ANSWER:

(8)

PUB/MH II-2

Reference: PUB/MH I-4 WLP Agreement

d) Please explain who is responsible for servicing the debt related to the project and indicate on which balance sheet the debt will reside.

ANSWER:

Manitoba Hydro’s actual borrowings made during the construction of the Wuskwatim G.S. will reside on Manitoba Hydro’s balance sheet. An intercompany receivable will be recorded on Manitoba Hydro’s balance sheet and a corresponding intercompany payable will be recorded on the Wuskwatim Power Limited Partnership’s balance sheet.

(9)

PUB/MH II-2

Reference: PUB/MH I-4 WLP Agreement

e) Please provide the formula and demonstrate the determination of the $41.5 million amount to be financed by MH.

ANSWER:

The maximum financed component provided to the Nisichawayasihk Cree Nation by Manitoba Hydro is calculated as follows:

Total equity in the Partnership: Project cost x 25% = $189 million Maximum financed component: Total equity x 22% = $41.58 million

The $41.58 million amount filed with the CEC in 2003 was based on projected total equity for the WPLP of $189 million.

(10)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

a) Please provide a detailed description of the agreed methodology and an illustrative example of how the revenue from the Wuskwatim Generating Station will be determined in a given year and allocated to WLP.

ANSWER:

Manitoba Hydro will purchase all of the energy generated by the Wuskwatim generating station from the limited partnership at rates that are based on the value of the power in the export market. On peak generation will be priced based upon the rolling average price throughout the year of long term export and/or import transactions. Similarly, off peak generation will be priced based upon opportunity transactions. Any market-related fees or expenses paid by Manitoba Hydro are netted out from the average transaction price calculations. Actual Wuskwatim generation will be adjusted for transmission line losses and the resulting revenue is subject to a 3% fee for specified risks retained by Manitoba Hydro.

(11)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

b) Please illustrate how the revenue to be assigned to the Wuskwatim project (GWh and export sale rates) over the next 20 years will cover project-specific annual finance, depreciation, and OM&A costs.

ANSWER:

(12)

For year ending March 31: 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 REVENUES Net Revenue 0 0 0 0 39 94 100 105 110 115 120 EXPENSES Finance Expense 0 0 0 0 37 82 81 81 80 79 77 Operating Expense 0 0 0 0 22 38 38 38 38 38 38 0 0 0 0 59 119 119 119 118 117 115

Net Income (Loss) 0 0 0 0 (20) (25) (19) (13) (7) (2) 5

Average Generation (GWh) 0 0 0 0 556 1,515 1,515 1,515 1,515 1,515 1,515

For year ending March 31:

2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 REVENUES Net Revenue 125 131 135 139 142 144 147 152 155 159 163 EXPENSES Finance Expense 75 73 70 69 67 66 65 63 62 61 59 Operating Expense 38 39 39 39 39 39 39 39 40 39 39 113 111 109 107 106 105 104 103 102 100 98

Net Income (Loss) 12 19 26 32 36 39 43 49 54 59 65

Average Generation (GWh) 1,515 1,515 1,515 1,515 1,515 1,515 1,515 1,515 1,515 1,515 1,515

PROJECTED OPERATING STATEMENT FROM IFF07-1 WUSKWATIM POWER LIMITED PARTNERSHIP

(13)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

c) Please define the incremental costs of Wuskwatim after in-service to MH on an annual basis; include the forecast incremental energy generated (GWh) and $ revenues gained by MH on an annual basis for the next 20 years.

ANSWER:

Assuming that the Nisichawayasihk Cree Nation subscribes for a 33% share of the units in the Partnership, the incremental cost or benefit of Wuskwatim to Manitoba Hydro would essentially be 67% of the net income or loss shown in PUB/MH II-3(b).

(14)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

d) Please explain how the transmission charge to recover depreciation, interest and operating costs related to incremental facilities to serve Wuskwatim will be determined.

ANSWER:

There will be no transmission charge to recover depreciation and interest for the incremental facilities. Wuskwatim Power Limited Partnership will be charged the actual cost incurred for operating and maintaining the incremental facilities.

(15)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

e) Please identify the incremental facilities which will support Wuskwatim. ANSWER:

The main incremental facilities that support Wuskwatim generation include:

1. Two 137.14 km 230 kV single-circuit steel tower transmission lines from Herblet Lake to Wuskwatim Switching Station

2. One 45.15 km 230 kV single-circuit steel tower transmission line from Birchtree to Wuskwatim Switching Station.

3. New 230 kV air-insulated station at Birchtree with 4-230 kV circuit breakers. The existing line between Thompson and Kelsey will be sectionalized into the new station and the new Birchtree-Wuskwatim line and new Birchtree SVC will be terminated here.

4. 150 Mvar static var compensator (SVC) to be installed in Birchtree station.

5. New 230 kV gas-insulated station at Wuskwatim with 8-230 kV circuit breakers. The three lines to the Wuskwatim generating station, two lines to Herblet and one line to Birchtree will terminate here.

6. Protection upgrades at Kelsey and Thompson associated with the line sectionalizing work.

7. Three 1.18 km 230 kV lines between the Wuskwatim GS and the Wuskwatim switching station.

8. Three 20 Mvar shunt reactors to be installed in the Herblet Lake station.

9. One 165 km 230 kV single-circuit steel tower transmission lines from Herblet Lake to the Pas Ralls Island station.

(16)

10. Breaker and protection additions at The Pas Ralls Island and Herblet Lake stations associated with the new line terminations.

(17)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

f) Please indicate the facilities being advanced to accommodate Wuskwatim, the period of advancement and describe how the charge related to those facilities will be determined.

ANSWER:

The facilities required for the Herblet Lake – Rall’s Island line include:

• One 165 km 230 kV single-circuit steel tower transmission lines from Herblet Lake to the Pas Ralls Island station.

• one 20 Mvar reactor at Herblet

• associated breakers and protection at Herblet and the Pas Ralls Island stations.

Originally, the Wuskwatim Facilities preceded the reliability need date for the Herblet Lake-Ralls Island line. Consequently, the Interconnection and Operating Agreement required the WLP to pay for the cost to construct the line. The WLP would be refunded the actual cost on the date the line would be placed in-service for reliability needs. Due to delays in the Wuskwatim schedule, the reliability need data and the date the line is needed for Wuskwatim coincide. Therefore, there will be no advancement charges.

(18)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

g) Please indicate the amount identified as periodic major capital expenditures which fall outside the forecast period

ANSWER:

(19)

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Other Capital Expenditures * 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.191 0.000 0.000

2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Other Capital Expenditures * 0.000 0.000 0.211 3.089 0.000 0.000 0.000 0.233 0.000 0.000 0.000

* In-service cost of other periodic capital expenditures related to the Wuskwatim GS

PROJECTED ONGOING CAPITAL EXPENDITURES FROM IFF07-1 WUSKWATIM POWER LIMITED PARTNERSHIP

(20)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

h) Please indicate the amount of reserves annually during the forecast period that will be required to fund the periodic major capital expenditures, based on the forecasts assumptions utilized and major capital expenditures currently identified.

ANSWER:

Annual reserves to fund periodic major capital expenditures have not been forecasted. The General Partner Board of Directors of the Wuskwatim Power Limited Partnership will determine any reserves to be set aside once the project is in-service.

(21)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

i) Please elaborate on all parameters beyond the debt to equity ratio to be utilized to determine the portion of profits that may be distributed as dividends.

ANSWER:

All cash in excess of that needed to maintain the 75:25 debt/equity ratio after the allocation of any amounts to be held in reserve or for anticipated expenses is available as potential distributions. No distributions can be made if the debt ratio exceeds 75%, rounded to the nearest full percentage point.

(22)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

j) Please explain what limits in place for the cash call and dividend advances which can be loaned by MH.

ANSWER:

The cash call credit facility has no pre-set limit. The PDA limits the dividend credit facility to four times the amount of Taskinigahp Power Corporation’s (TPC) own cash invested as at the first anniversary date of Wuskwatim’s in-service date net of any amounts already used to repay cash call loans. TPC is the investment vehicle used by Nisichawayasihk Cree Nation.

(23)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

k) Please provide an illustrative example of dividend advances and cash call advances assuming full equity participation of the parties under scenarios where in a year the generating station has a net loss, has a net profit of $1million, $5 million and $10 million.

ANSWER:

The availability of dividend and/or cash call advances is not directly linked to net income or loss, but to the debt/equity ratio. If the amount of cash in excess of that needed to maintain the debt/equity ratio would result in an available distribution to NCN of less than what could be made available under the dividend credit facility, advances would be available up to the level necessary to top up the distributions to the maximum level of the loan advances. If cash investments from the partners are necessary to maintain the debt/equity ratio, advances would be available to TPC in order to allow it to meet its proportionate share of the cash call.

(24)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

l) Please explain how the examples under (j) would vary if the debt to equity ratio was at or below 75:25

ANSWER:

The process in (j) would be the same if the debt ratio were lower than 75%, except that the cash call facility would not be required or available.

(25)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

m) Please provide the calculation of the current and forecast financing rate to be charged to NCN on amounts advanced or forecast to be advanced, including the amount of the risk premium.

ANSWER:

The financing rate applied to NCN on amounts advanced or forecast to be advanced up until project completion are as follows in the PDA:

Manitoba Hydro’s short term Canadian borrowing cost for the month + one percent risk premium

(26)

PUB/MH II-3

Reference: PUB/MH I-4 WLP Operations

n) Please explain how the risk premium was determined. ANSWER:

(27)

PUB/MH II-4

Reference: PUB/MH I-18 (a)

Please file the most current financial statements for: i. Wuskwatim Power Limited Partnership; and ii. 4985371 Manitoba Ltd.

ANSWER:

i. Wuskwatim Power Limited Partnership financial statements cannot be released without the approval of the Board of the Wuskatim Power Limited Partnership. This matter will be tabled at the next meeting of the Limited Partnership Board.

ii. The financial statements of 4985371 Manitoba Ltd. has been included in Appendix 14.

(28)

PUB/MH II-5

Reference: PUB/MH I-20 Equivalent Full Time Employees

a) Please provide a schedule of equivalent full time employees for the years 2004/05 through 2008/09.

ANSWER:

(29)

PUB/MH II-5, part (a)

EQUIVALENT FULL TIME EMPLOYEES - BY BUSINESS UNIT

2004/05 2005/06 2006/07 2007/08 2008/09

Actual Actual Actual Forecast Forecast

President & CEO

Public Affairs 32 30 30 33 32 General Counsel 24 25 26 23 23 Administration 23 24 25 28 28 79 79 81 84 83 Corporate Relations Corporate Planning 10 11 12 13 13 Aboriginal Relations 44 54 59 68 68 Purchasing 42 44 45 48 47 Administration 14 16 16 17 14 110 125 132 146 142

Finance & Administration

Information Technology Services 350 364 336 316 315 Treasury 17 16 15 16 16 Financial Planning & Corporate Risk Management 9 11 11 17 17 Human Resources 169 164 161 160 160 Gas Supply 20 20 19 19 19 Rates & Regulatory Affairs 22 19 19 23 22 Corporate Controller 174 177 171 184 186 Corporate Facilities 68 69 68 74 77 Corporate Safety & Health 31 29 26 25 24 Administration 8 9 11 14 13

868

878 837 848 849

Power Supply

Power Planning 32 32 31 47 48 Power Projects Development 39 41 51 61 60

HVDC 266 228 232 242 242

Generation North 233 213 211 217 216 Generations South 496 461 459 462 461 Engineering Services 163 162 176 199 211 Power Sales & Operations 79 84 83 86 87 New Generation Construction 13 14 25 71 101 Administration 23 131 137 152 152

1,344

1,366 1,405 1,537 1,578

Transmission & Distribution

Research & Development 5 3 2 2 2 Transmission System Operations 341 346 363 360 362 Transmission Planning & Design 243 233 232 249 249 Transmission Construction & Line Maintenance 270 276 274 288 288 Distribution Planning & Design 243 236 240 254 250 Distribution Construction 427 449 454 469 470 Apparatus Maintenance 388 394 398 424 424 Administration 37 44 42 51 51

1,954

(30)

PUB/MH II-5, part (a)

EQUIVALENT FULL TIME EMPLOYEES - BY BUSINESS UNIT

2004/05 2005/06 2006/07 2007/08 2008/09

Actual Actual Actual Forecast Forecast

Customer Service & Marketing

Industrial & Commercial Solutions 48 49 51 55 58 Customer Service Operations 1,050 1,073 1,041 1,039 1,059 Consumer Marketing & Sales 198 219 227 228 235 Business Support Services 164 163 165 165 167 Administration 51 47 47 49 54

1,511

1,551 1,531 1,536 1,573

(31)

PUB/MH II-5

Reference: PUB/MH I-20 Equivalent Full Time Employees

b) For each of the years 2004/05 through 2006/07 please separate employees into fulltime vs. construction as set out in the annual report.

ANSWER:

Please see the following schedules.

Note that these schedules do not agree to the amounts shown in the annual report because the annual report amounts represent staff levels as at March 31 of the fiscal year, whereas these schedules represent total staff levels throughout the year including staff changes, and seasonal and overtime requirements.

(32)

EQUIVALENT FULL TIME EMPLOYEES - ANNUAL RESULTS BY DIVISION FOR THE YEAR ENDING MARCH 31, 2005

Operating & Direct Total

Administrative Construction

PRESIDENT & CEO

Public Affairs 32 - 32 General Counsel & Corporate Secretary 23 1 24 Administration 23 - 23

78

1 79

CORPORATE RELATIONS

Corporate Planning Division 6 4 10 Aboriginal Relations 26 18 44 Purchasing Department 42 - 42 Administration 13 1 14

87

23 110

FINANCE & ADMINISTRATION

Information Technology Services 280 70 350 Treasury 17 - 17 Financial Planning & Corp Risk Mgmt 8 1 9 Human Resources 169 - 169 Gas Supply 19 1 20 Rates & Regulatory Affairs 22 - 22 Corporate Controller 170 4 174 Corporate Facilities 68 - 68 Corporate Safety & Health 28 3 31

Administration 8 8

789

79 868

POWER SUPPLY

Power Sales & Operations 71 8 79 Power Planning 21 11 32 Power Projects Development 21 18 39 HVDC 211 55 266 Generation North 224 9 233 Generations South 461 35 496 Engineering Services 102 61 163 New Generation 2 11 13 Administration 23 - 23 1,136 208 1,344

(33)

EQUIVALENT FULL TIME EMPLOYEES - ANNUAL RESULTS BY DIVISION FOR THE YEAR ENDING MARCH 31, 2005

TRANSMISSION & DISTRIBUTION

Research & Development 5 - 5 Transmission System Operations 297 44 341 Transmission Planning & Design 120 123 243 Transmission Construction & Line Mtce. 170 100 270 Distribution Planning & Design 194 49 243 Distribution Construction 187 240 427 Apparatus Maintenance 357 31 388 Administration 31 6 37

1,361

593 1,954

CUSTOMER SERVICE & MARKETING

Industrial & Commercial Solutions 38 10 48 Customer Service Operations 896 154 1,050 Consumer Marketing & Sales 166 32 198 Business Support Services 158 6 164 Administration 50 1 51

1,308

203 1,511

(34)

EQUIVALENT FULL TIME EMPLOYEES - ANNUAL RESULTS BY DIVISION FOR THE YEAR ENDING MARCH 31, 2006

Administrative Construction PRESIDENT & CEO

78

1 79

CORPORATE RELATIONS

97

28 125 FINANCE & ADMINISTRATION

Information Technology Services 282 82 364

Treasury 16 - 16

Financial Planning & Corp Risk Mgmt 9 2 11 Human Resources 164 - 164 Gas Supply 20 - 20 Rates & Regulatory Affairs 19 - 19 Corporate Controller 169 8 177 Corporate Facilities 69 - 69 Corporate Safety & Health 29 - 29 Administration 9 - 9

786

92 878 POWER SUPPLY

Power Sales & Operations 77 7 84 Power Planning 20 12 32 Power Projects Development 22 19 41

HVDC 186 42 228 Generation North 201 12 213 Generations South 439 22 461 Engineering Services 100 62 162 New Generation 2 12 14 Administration 124 7 131 1,171 195 1,366

(35)

EQUIVALENT FULL TIME EMPLOYEES - ANNUAL RESULTS BY DIVISION FOR THE YEAR ENDING MARCH 31, 2006

TRANSMISSION & DISTRIBUTION

1,376

605 1,981 CUSTOMER SERVICE & MARKETING

1,327

224 1,551

(36)

EQUIVALENT FULL TIME EMPLOYEES - ANNUAL RESULTS BY DIVISION FOR THE YEAR ENDING MARCH 31, 2007

Administrative Construction PRESIDENT & CEO

80

1 81

CORPORATE RELATIONS

101

31 132 FINANCE & ADMINISTRATION

Information Technology Services 296 40 336

Treasury 15 - 15

Financial Planning & Corp Risk Mgmt 10 1 11 Human Resources 161 - 161

Gas Supply 19 19

Rates & Regulatory Affairs 19 - 19 Corporate Controller 167 4 171 Corporate Facilities 67 1 68 Corporate Safety & Health 26 - 26

Administration 11 11

791

46 837 POWER SUPPLY

Power Sales & Operations 80 3 83 Power Planning 21 10 31 Power Projects Development 24 27 51

HVDC 198 34 232 Generation North 196 15 211 Generations South 434 25 459 Engineering Services 100 76 176 New Generation 4 21 25 Administration 130 7 137 1,187 218 1,405

(37)

EQUIVALENT FULL TIME EMPLOYEES - ANNUAL RESULTS BY DIVISION FOR THE YEAR ENDING MARCH 31, 2007

TRANSMISSION & DISTRIBUTION

1,395

610 2,005 CUSTOMER SERVICE & MARKETING

1,290

241 1,531

(38)

PUB/MH II-5

Reference: PUB/MH I-20 Equivalent Full Time Employees

c) Please explain the major changes since 2004/05 in EFT employees for: i. Corporate Relations - Aboriginal Relations

Please include a general description of the positions added by type of job classification.

ANSWER:

Changes have been made since 2004/05 to strengthen the capacity of the Aboriginal Relations Division to act as the focal point for the management of all internal and external Aboriginal issues including policy development. From 2005 to 2006, positions increased by nine and from 2006 to 2007, positions increased by five. General position descriptions are explained below:

• Manager - to oversee the assessment of strategic corporate interests related to current and evolving Aboriginal issues and to develop and refine relevant corporate policies. • Staff Officer - to assist with the administration of the Hydro Northern Training and

Employment Initiative.

• Environmental Specialist - i) to provide policy, planning and technical advice and support to other corporate units in managing Aboriginal issues requiring an integrated corporate response ii) to support the planning, implementation and monitoring of the Waterways Management Program, and iii) to support negotiated solutions to adverse effects of existing and future projects.

• Administrative Officer - i) to support the development and refinement of policies relevant to Aboriginal interests in Manitoba Hydro’s purchasing, employment, training and future development activities, ii) to assist with implementation of the Aboriginal cultural awareness strategy and community relations, and iii) to provide support for the delivery of various community relations activities.

• Utility Worker - to perform general labourer duties associated with the alleviation of adverse effects and to assist in the management of material and equipment involved in the delivery of northern field programs.

(39)

PUB/MH II-5

Reference: PUB/MH I-20 Equivalent Full Time Employees

c) Please explain the major changes since 2004/05 in EFT employees for: ii. Power Supply - Administration

ANSWER:

As per Manitoba Hydro’s response to PUB/MH I-20(b), the changes in Power Supply - Administration EFT employees have been detailed. For new positions, the following job classifications have been added:

2005 vs 2006 - 9 new positions

• 9 Trades Trainees - trainees in the electrical, mechanical and operating trades, which rotate within generation, HVDC and thermal stations.

• 6 Trades Trainees - see above description. 2007 vs 2008 - 17 new positions

• 17 Trades Trainees - see above description. 2008 vs 2009 - no new positions

(40)

PUB/MH II-5

Reference: PUB/MH I-20 Equivalent Full Time Employees

c) Please explain the major changes since 2004/05 in EFT employees for: iii. Customer Service &Marketing - Consumer Marketing & Sales

ANSWER:

As per Manitoba Hydro’s response to PUB/MH I-20(b), the changes in Customer Service & Marketing - Consumer Marketing & Sales EFT employees have been detailed. During this period, the following job classifications have been added:

Manager, Marketing & Sector Sales – provides oversight and direction for staff and other resources and is responsible for a number of marketing initiatives, customer education, and dedicated Power Smart sales.

Supervisory, Power Smart Sales – responsible for leading a team of dedicated Power Smart sales staff.

Staff Officers – responsible for identifying opportunities for energy efficiency including designing and delivering Power Smart Programs.

Marketing Programs Research Analysts – responsible for providing support for staff officers responsible for specific Power Smart programs.

Power Smart Sales Research Analysts – responsible for pursuing Power Smart sales opportunities with customers in the Commercial sector.

Planning & Evaluation Research Analysts – responsible for providing support activities in the development of Manitoba Hydro’s Power Smart Plan and evaluating the Power Smart Programs.

(41)

Administrative Representatives – responsible for providing various administrative tasks, including the day to day administration of various Power Smart Programs.

• Eight Staff Officers

• Eight Research Analysts

• One Manager Marketing & Sector Sales

• One Supervisor Energy Services & Sales

• Five Administrative Officers

2007 vs 2008 - no new positions

(42)

PUB/MH II-6

Reference: PUB/MH I-21(d) NERC Reliability Standards

a) Please indicate which NERC reliability standards MH currently does not comply with and discuss what steps are being undertaken to comply and the anticipated time frame for full compliance.

ANSWER:

(43)

PUB/MH II-6

Reference: PUB/MH I-21(d) NERC Reliability Standards

b) Please elaborate on what will be required as it relates to have a dedicated project team including the size of team, describe the investment in additional physical infrastructure and cyber security technology.

ANSWER:

Manitoba Hydro is working to meet the future requirements of the NERC Cyber Security Standards, according to the NERC compliance schedule. Manitoba Hydro does not have to comply with these standards at this time.

Manitoba Hydro has established a project team with a temporary dedicated staff of seven (7). The ongoing staffing requirement is two new permanent staff positions to manage the compliance of the Cyber Security Program.

(44)

PUB/MH II-7

Reference: PUB/MH I-23 (a),(d), Coalition/MH I-35

a) Please provide the CEF 02 which related to the IFF02-1. ANSWER:

(45)

Project

Total 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

NEW GENERATION and MAJOR TRANSMISSION PROJECTS

NEW GENERATION

BRANDON COMBUSTION TURBINE 182.9 20.1

WUSKWATIM GS LICENCING COSTS 33.2 35.2

GULL GS LICENCING COSTS 32.0 21.3 20.8

MAJOR TRANSMISSION

BIPOLE 3 PLANNING STUDIES AND LICENSING COSTS 0.7

RADISSON - RIEL -DORSEY + 500kV HVDC LINE 351.9 2.5 4.6 13.1 13.5 12.3 101.3 76.3 84.3 44.0

RIEL 230/500 kV STATION 96.3 0.6 6.3 5.5 8.0 24.2 30.3 21.4

NORTHERN AC TRANSMISSION SYSTEM REQUIREMENTS 29.7 1.0 13.2 14.4

PROPOSED NEW GENERATION/MAJOR TRANSMISSION CEF02-1 90.1 80.6 53.8 21.5 36.5 131.6 97.7 84.3 44.0

(IN MILLIONS OF DOLLARS ) FOR THE YEARS 2002/03 TO 2012/13

(46)

Project

Total 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

HVDC FACILITIES

HVDC BIPOLE RELIABILITY ENHANCEMENTS 56.0 -0.3

BIPOLE 1 MERCURY ARC VALVES STAGE 3 74.4 2.0 45.0 27.1

HVDC BIPOLE 2 THYRISTOR POLY PIPE REPLACEMENTS 5.4 -0.1

CONVERTER TRANSFORMER BUSHING REPLACEMENT 7.4 1.1 1.5

DORSEY BIPOLE 1 SYNCH CONDENSER BREAKER REPLACEMENT 6.9 2.8

BIPOLE 1&2 DC FILTER CAPACITOR REPLACEMENT 5.0 2.1

BIPOLE 1 VALVE HALL WALL BUSHING REPLACEMENT 10.7 1.0

BIPOLE I & 2 ELECTRODE LINE MONITORING 1.5 1.0 0.5

HVDC SYSTEM SWITCHGEAR UPGRADE 2.7 2.2 0.5

HVDC AUXILLIARY POWER SUPPLY 1.7 0.5 0.7

DORSEY SYNCHRONOUS CONDENSER REFURBISHMENT 7.6 1.3 1.1 1.2 1.2 1.4 1.4

BIPOLE 2 TRANSFORMER COOLING UPGRADE 6.8 4.4

DORSEY SYNC CONDENSER COOLER UPGRADE 2.6 0.9 1.7

HVDC SYST TRANSFORMER & REACTOR FP&P 5.9 4.1 1.8

HVDC BIPOLE 1 CHILLER REPLACEMENT 5.8 2.7 3.1

HVDC BIPOLE 1 ROOF REPLACEMENT 2.8 2.2 0.6

HYDRAULIC REHABILITATION

GREAT FALLS G.S. REHABILITATION 22.8 10.4 5.8 3.0 0.4

PINE FALLS G.S. REHABILITATION 21.9 0.5 1.4 7.4 7.3 0.6

LAURIE RIVER PLANT 1 AND 2 REHABILITATION 17.3 0.3 3.8 0.5 1.2 0.9 0.9

GRAND RAPIDS GS REHABILITATION 103.2 -2.0 5.0 1.3

JENPEG GS UNIT 1-6 OVERHAULS 32.7 0.3 0.3 3.9 8.0 6.2 5.0

POWER SUPPLY DAM SAFETY UPGRADES 15.4 1.9 2.1 2.2 2.2

WINNIPEG RIVER CONTROL SYSTEM 16.8 2.4 3.0

LIMESTONE OUTSTANDING WORK 12.1 0.2

WINNIPEG RIVER RIVERBANK PROTECTION PROGRAM 7.1 0.4 0.6 0.6 0.7 0.8

KETTLE GS - IMPROVEMENTS & UPGRADES 69.1 0.7 0.7 0.1 0.1 4.1

KELSEY GS IMPROVEMENTS & UPGRADES 75.5 1.6 6.4 10.6 16.0 18.3 19.2 2.5 0.9 -0.8

KETTLE ANNUNCIATION SYSTEM RENEWAL 1.7 0.2

NELSON RIVER CONTROL 6.0 2.0 2.0 2.0

JENPEG STAFFHOUSE SEWAGE TREATMENT 2.1 2.1

JENPEG G.S. KISKITTO CONTROL STRUCTURE DYKE REPAIR 2.4 2.4

POINTE DU BOIS GS IMPRVMTS & UPGRADES 421.3 2.2 5.6 41.1 52.8 54.4 29.3 28.7 29.3 29.9

(IN MILLIONS OF DOLLARS ) FOR THE YEARS 2002/03 TO 2012/13

ELECTRICITY CAPITAL EXPENDITURE FORECAST (CEF02-1)

(47)

Project

Total 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

THERMAL REHABILITATION

BRANDON GS UNIT 5 LICENCE RENEWAL 4.8 0.1 0.7 4.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

SELKIRK GS FUEL SWITCHING PROJECT 32.2 13.0

SELKIRK GS LICENCE RENEWAL 28.9 0.5 15.3 13.1 0.0

OTHER

200MW ONTARIO HYDRO SALE - SYNC COND CONVERSION 12.0 2.6 2.6 1.8 0.4

SITE REMEDIATION OF CONTAMINATED CORPORATE FACILITIES 13.0 1.3 0.9 0.9 0.9 0.9 0.9 1.0 1.0 0.1 1.0 0.3

OIL CONTAINMENT 16.0 1.0 2.0 1.4 0.7 0.6 0.7 0.6

FIRE PROTECTION PROJECTS 8.7 3.8 0.3

GENERATION TOWNSITE INFRASTRUCTURE 3.4

PLANNING STUDY COSTS 7.3 5.9 5.4 2.6 2.2 3.5 5.8 6.0 6.1 6.2 6.3

DOMESTIC ITEMS - POWER SUPPLY 10.9 11.1 11.4 11.5 11.8 12.1 12.4 12.7 13.0 13.1 13.6

WH DOMESTIC ITEMS - POWER SUPPLY 3.5 6.1 6.2 6.2 6.4 6.4 6.5 6.5 6.6 6.7 6.8

PROPOSED POWER SUPPLY CEF02-1 88.7 133.6 110.1 67.8 90.1 102.0 84.6 56.4 54.9 57.2 61.8

INTERCONNECTIONS

GLENBORO - RUGBY ND 230 kV TIE LINE 28.9 12.9 1.2 0.9

TRANSMISSION AND DISTRIBUTION

(IN MILLIONS OF DOLLARS ) FOR THE YEARS 2002/03 TO 2012/13

(48)

Project

Total 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

TRANSMISSION

NORTH CENTRAL MANITOBA PROJECT 17.5 0.1

HERBLET LAKE > THE PAS 230kV TRANSMISSION 46.9 0.0 0.4 0.9 1.0 1.6 7.2 20.0 15.8

WINNIPEG > BRANDON TRANSMISSION IMPROVEMENTS 31.4 0.0 1.2 2.7 3.9 4.3 19.4

FT. GARRY PERIMETER STN 66-12KV BANK REPL. 5.1 0.0 0.0 0.0 0.7 3.0 1.4

RIDGEWAY 230-66KV TRANSFORMER ADDITION 9.2 0.0 0.0 0.2 0.4 0.7 4.4 3.4

ST. VITAL TRANSFORMER ADDITION 8.6 0.0

DORSEY - ROSSER 230kV T/L IMPROVEMENTS 2.5 0.3 0.2

DORSEY > ST. VITAL 230kV AC TRANSMISSION 8.0 0.5

DORSEY > LAVERENDRYE > ST. VITAL 230kV TRANSMISSION 26.2 1.8

ROSSER > SILVER 230kV TRANSMISSION 30.2 0.3 2.5 7.5 13.5

NEEPAWA 230 -115kV STN 18.0 0.1 1.1 7.8 9.1

ROSSER > MCPHILLIPS 115kV TRANSMISSION IMPROVEMENTS 3.0 0.2 2.3 0.5

RICHER S. 230-66KV TRANSFORMER ADDITION 5.3 0.0 0.0 0.4 0.4 2.5 2.0

PINE FALLS > BLOODVEIN 115kV TRANSMISSION LINE 29.5 0.2 0.2 0.9 1.7 7.3 15.7 3.5

ST. VITAL > STEINBACH 230kV TRANSMISSION 22.7 0.3 0.4 0.7 3.4 4.2 13.7

RIDGEWAY - SELKIRK 230kV TRANSMISSION 25.3 0.0 0.0 0.7 2.3 3.5 4.0 4.8 9.9

SOURIS > PEMBINA VALLEY 230kV TRANSMISSION 32.6 0.6 0.9 1.4 1.5 12.0 16.1

WINNIPEG AREA TRANSMISSION REFURBISHMENT 8.9 3.3 0.3 0.9

DORSEY > US BORDER D602F 500KV AC T/L INSULATOR REPLACEME 8.0 1.0 BIPOLE 1 & 2 LINE SPACER DAMPERS REPLACEMENT 14.0 3.6

DORSEY BUS ENHANCEMENT 16.8 4.6 4.2 4.1

FLIN FLON AREA TRANSMISSION IMPROVEMENTS PHASE 1&2 21.6 -0.1 8.0 1.7

PINE FALLS - GREAT FALLS 115-66kV SUPPLY 10.6 3.0 4.5 2.1 1.0

SUBTRANSMISSION

JENPEG-NORWAY HOUSE 66kV LINE 15.7 2.9

RUTTAN > SOUTH INDIAN LAKE 66 kV LINE 18.1 0.8 1.4 1.6 0.0

CENTRAL SUPPLY > PIKWITONEI & THICKET PORTAGE 5.6 1.2

BIRTLE - ROSSBURN 66KV LINE 4.0 0.0 0.1 0.2 3.6

ST.BONIFACE PLESSIS Rd 115-24kV STATION 18.2 0.0 0.2 0.5

ROSSER - OAK POINT 115-24KV STATION 21.3 0.1 1.5 2.1 13.2 4.4

ROSSER - OAK POINT BANK 2 ADDITION 9.9 0.9 6.3 2.8

ST.BONIFACE PLESSIS Rd BANK 2 ADDITION 2.1 0.3 0.3 0.2

NEEPAWA - PLUMAS 66KV LINE 3.5 0.1 3.4

RESTON/GLENBORO CAPACITY INCREASE 7.0 1.3

ST. LEON 230-66KV TRANSFORMER ADD'N AND IPL EXPANSION 5.8 0.2 0.4

BRANDON CROCUS PLAINS 115-24kV BANK ADDITION 7.8 0.8 4.4 2.3 0.3

BRERETON LAKE STATION AREA 7.3 1.4 3.7 0.8 0.6 0.6 0.1

FT. GARRY PERIMETER STN 66-12KV BANK REPL. 5.1 0.7 3.0 1.4

(IN MILLIONS OF DOLLARS ) FOR THE YEARS 2002/03 TO 2012/13

(49)

Project

Total 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

DISTRIBUTION

VIRDEN AREA DISTRIBUTION CHANGES 16.7 1.0 1.4 1.8

DEFECTIVE RINJ CABLE REPLACEMENT 8.5 1.2 1.3 1.4 1.4 1.1

SHAMATTAWA NEW DIESEL GS & TANK FARM 16.1 8.2 1.5 0.4 1.7 0.7

COMMUNICATIONS

MICROWAVE RADIO REPLACEMENTS 158.3 33.7 26.5 15.9 35.0 11.2 3.7 1.1

OTHER

MAPINFO PROJECT 30.4 3.0 0.5

SITE REMEDIATION 10.2 0.4 1.0 2.3

OIL CONTAINMENT 6.1 1.2 0.8 1.6 1.1 0.2

DOMESTIC ITEMS - TRANSMISSION AND DISTRIBUTION 67.6 69.6 71.7 73.4 75.2 77.0 78.8 80.7 82.8 83.7 87.0

WH DOMESTIC ITEMS - TRANSMISSION AND DISTRIBUTION 5.0 8.9 9.0 9.0 9.2 9.2 9.4 9.4 9.6 9.8 9.8

PROPOSED TRANSMISSION AND DISTRIBUTION CEF02-1 159.0 141.1 133.7 159.7 123.2 111.9 136.0 159.8 134.7 125.3 102.0

DEMAND SIDE MANAGEMENT CAPITAL COSTS 11.5 17.7 22.4 19.2 16.5 12.5 12.2 12.3 12.1 7.7 7.8

AUTOMATIC METER READING IMPLEMENTATION 30.9 0.0 2.7 2.9 2.9 3.0 3.1 3.1 3.2

DISTRIBUTION PCB TESTING & TRANSFORMER REPLCMT 18.4 3.6 4.1 4.2 4.3 2.2

WINNIPEG DISTRIBUTION INFRASTRUCTURE REQRMNTS 6.7 0.4 2.2 2.3 1.8

DOMESTIC ITEM CS&M 46.7 49.3 50.3 51.6 52.8 54.0 55.4 56.9 58.2 58.8 60.9

WH DOMESTIC ITEM CS&M 3.6 6.2 6.4 6.4 6.5 6.5 6.6 6.6 6.8 6.9 6.9

PROPOSED CUSTOMER SERVICE & MARKETING CEF02-1 65.8 79.5 88.3 86.2 80.9 76.0 77.4 78.9 80.3 73.4 75.6

CUSTOMER SERVICE & MARKETING

(IN MILLIONS OF DOLLARS ) FOR THE YEARS 2002/03 TO 2012/13

(50)

Project

Total 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

CORPORATE BUILDING PROGRAM 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0

NEW HEAD OFFICE 75.0 2.0 13.0 25.0 25.0 10.0

CUSTOMER INFORMATION SYSTEM 21.0 4.3 16.7

HUMAN RESOURCE MANAGEMENT SYSTEM 15.4 6.8 5.0 2.9

ENTERPRISE GIS PROJECT 13.1 2.2 4.9 6.0

DOMESTIC ITEMS - FINANCE & ADMINISTRATION 20.5 21.3 21.8 22.4 22.9 23.5 24.0 24.5 25.1 25.4 26.2

WH DOMESTIC ITEMS - FINANCE & ADMINISTRATION 1.0 1.8 1.8 1.8 1.9 1.9 1.9 1.9 2.0 2.0 2.0

PROPOSED FINANCE & ADMINISTRATION 44.9 54.0 65.5 57.2 59.5 33.4 33.9 34.4 35.1 35.4 36.2

YEAR-END FORECAST VARIANCE 7.8 11.4 -17.9

TOTAL ELECTRICITY CEF02-1 440.8 477.3 451.5 392.4 390.1 472.7 429.6 413.8 348.9 291.2 275.6

FINANCE & ADMINISTRATION

(IN MILLIONS OF DOLLARS ) FOR THE YEARS 2002/03 TO 2012/13

(51)

PUB/MH II-7

Reference: PUB/MH I-23 (a),(d), Coalition/MH I-35

b) Please provide a table which compares the actual/forecast (CEF07-1) capital expenditures by major capital project for the fiscal years 2003 through 2013 with that forecast in CEF02, and explain the differences.

ANSWER:

(52)

Table PUB/MH II-7 (b)

(in millions of dollars)

CEF-02 2003-13 Forecast CEF-07 2003-07 Actuals 2008-13 Forecast Difference Comments

New Generation & Transmission

Brandon Combustion Turbine 20.1 24.7 4.5

Wuskwatim Generation 68.4 1,279.5 1,211.1

CEF02 was only for the licensing of the Wuskwatim plant. The actuals and the CEF07 estimate include both the unamortized planning studies and licensing costs in addition to the costs associated with the construction of the plant.

Wuskwatim Transmission 0.0 280.0 280.0 New project.

Herblet Lake - The Pas 230 kV Transmission 46.9 95.2 48.3

Estimate updated for current market prices, in-service date deferred from October 2010 to August 2011, and an Optical Ground Wire (OPGW) fibre communications substitutes the Power Line Communications (PLC) system previously planned.

Keeyask Generating Station Licensing (formerly Gull GS Licensing

Costs Project) 74.1 269.7 195.6

More extensive consultations with First Nation partners and more complex environmental and engineering studies in preparation for the regulatory review process.

Conawapa Generating Station 0.0 395.8 395.8 New project, previously in planning studies.

Wind Generation 0.0 2.7 2.7

Kelsey Generating Station Improvements & Upgrades 74.7 183.8 109.1

The increase reflects increase in scope to rehab all 7 units and to combine the rerunnering and unit 5 rehab items, as well as current construction market conditions.

Kettle Generating Station Improvements & Upgrades 5.7 14.2 8.5 Expenditures for the 2003 - 2013 period advanced one year. Pointe du Bois Rebuild 273.2 303.2 30.0The increase reflects current work schedule and construction _{market conditions.} Pointe du Bois & Slave Falls Transmission 0.0 82.4 82.4New project. Transmission upgrades required as a result of

Pointe du Bois Rebuild project.

Planning Study Costs 57.3 36.0 -21.3

Contributing to this variance is the transfer of Conawapa studies in 2006 for $10.4 M as well as less actual spending in 2003-2007 than planned in CEF02.

Bipole 3 Licencing Costs 0.7 0.0 -0.7

Bipole 3 Western Route (formerly Radisson-Riel 500 kV HVDC Line) 351.9 230.0 -121.9In-service date was deferred from October 2010 in CEF02 to _{October 2017.}

Riel 230/ 500 kV Station 96.3 84.5 -11.8

In-service date was deferred from August 2008 in CEF02 to March 2014. Costs for the last year of the project are therefore not included in the CEF07 2003-2013 period.

(53)

Table PUB/MH II-7 (b)

Northern AC Transmission System Requirements 28.6 42.3 13.7

Expand project scope to include such items as rebuild of generator cross tip scheme, a spare Ponton Station transformer and additional costs for the technical difficulties incurred interfacing new equipment with existing scheme.

MB-ON Clean Energy Transfer Init-Phase 1 0.0 0.1 0.1

Demand Side Management - Electric 151.9 327.8 176.0Refine existing programs, add new programs and eliminate a number of programs to target savings of 2,759 GWh by 2018. New Head Office

New Head Office 75.0 278.1 203.1Reflects current approved scope, cost estimate, and work

schedule. Corporate Relations

Waterways Management Program 0.0 29.1 29.1 New project.

Power Supply

HVDC Bipole Reliability Enhancements -0.3 0.9 1.2

Bipole 1 Pole 2 Thyristor Valve Project 74.1 67.1 -7.0

HVDC Bipole 2 Thyristor Poly Pipe Replacement -0.1 0.4 0.5

Converter Transformer Bushing Replacement 2.6 3.3 0.7

Dorsey Bipole 1 Synch Condenser Breaker Replacement 2.8 3.0 0.2

BP1 DC Filter Capacitor Replacement 2.1 0.7 -1.4

Bipole 1 Valve Hall wall Bushing Replacement 1.0 1.3 0.3

Bipole 1 & 2 Electrode Line Monitoring 1.5 1.6 0.1

HVDC System Switchgear Upgrade 2.7 2.3 -0.4

HVDC Auxiliary Power Supply Upgrades 1.2 3.2 2.0

Dorsey Synchronous Condenser Refurbishment 7.6 26.5 18.9

Revised estimate reflects the repair of corrosion fretting on SC7Y, SC8Y and SC9Y, the removal of SC22Y, re-wedging, GEM80 PLC replacements, additional modification to the 600V transfer scheme for SC7Y, SC8Y and SC9Y, increased actual cost experience with the SC8Y refurbishment, addition of SC11Y refurbishment, vibration monitoring & controls upgrades; as well as modifications required to resolve excessive brush wearing problems.

BP1 Chiller 5.8 14.1 8.3

Dorsey ASEA Synchronous Condenser Cooler Upgrade 2.6 3.5 0.9

(54)

Table PUB/MH II-7 (b)

Bipole 2 Transformer Cooling Upgrade 4.4 4.3 -0.1

HVDC System Transformer & Reactor Fire Protection & Prevention 5.9 10.3 4.4

HVDC AC Filter PCB Capacitor Replacement 0.0 43.5 43.5 New project.

HVDC Transformer Replacement Program 0.0 51.7 51.7 New project.

Dorsey 230 kV Relay Building Upgrade 0.0 9.1 9.1 New project.

Dorsey EE Synchronous Condenser Glycol Cooler Upgrade 0.0 4.0 4.0 New project.

HVDC Stations Ground Grid Refurbishment 0.0 4.3 4.3 New project.

HVDC Bipole 2 230 kV HLR Circuit Breaker Replacement 0.0 9.4 9.4 New project.

HVDC Bipole 1 Pole Differential Protection 0.0 3.3 3.3 New project.

HVDC Bipole 1 By-Pass Vacuum Switch Removal 0.0 15.0 15.0 New project.

HVDC Bipole 2 Refrigerant Condenser Replacement 0.0 11.0 11.0 New project.

HVDC Bipole 1 Smoothing Reactor Replacement 0.0 31.8 31.8 New project.

HVDC - BP1 Converter Station, P1&P2 Battery Bank Seperation 0.0 3.2 3.2 New project.

HVDC Bipole 1 DCCT Transductor Replacement 0.0 11.7 11.7 New project.

HVDC BP1 & BP2 DC Converter Transformer Bushing Replace. 0.0 8.2 8.2 New project.

HVDC Bipole 2 Valve Wall Bushing Replacement 0.0 17.8 17.8 New project.

HVDC Bipole 1 CQ Disconnect Replacement 0.0 4.6 4.6 New project.

HVDC - BP2 Refurbish Thyristor Module Cooling Components 0.0 4.7 4.7 New project.

HVDC BP2 Smoothing Reactor Replacement 0.0 16.5 16.5 New project.

Great Falls Generating Station Rehabilitation 19.6 28.0 8.3

Pine Falls Generating Station Rehabilitation 17.2 45.0 27.8

Estimate revised to include amounts required for the electrical rehabilitation of the station which includes the replacement of potential transformers, synchronizers, annunciators, generator breakers, excitation and governor systems, step-up transformers and electrical back-up systems. In addition, the scope on Units 1 & 2 major overhaul project increased to include the electrical work and a deferral of the in-service date by one year due to delays in equipment purchases.

Laurie River Plants 1 and 2 Rehabilitation 7.6 5.9 -1.7

Grand Rapids G.S. Rehabilitation 4.3 15.9 11.6Estimate revised to reflect coordination of breakers and sync with unit 4 overhaul, unit 4 repairs, and unit 1 legal costs.

Jenpeg Generating Station Unit Overhauls 23.7 12.7 -11.0

In-service date was deferred from March 2012 in CEF02 to March 2015 in CEF07; thus, CEF07 reflects reduced spending compared to CEF02 for the period to 2013.

Kettle G.S. Unit Re-Wedging 0.0 0.1 0.1

Power Supply Dam Safety Upgrades 8.4 28.8 20.4

Project scope revised to include: weather warning systems at all plants; public early warning systems and dike rip rap

rehabilitation at Grand Rapids and Seven Sisters; spillway hoist replacement and 2,200v supply at Pointe de Bois; and extension of the basic program from 2008 to 2016.

(55)

Table PUB/MH II-7 (b)

Winnipeg River Control System 5.4 4.0 -1.4

Limestone G.S. Outstanding Work 0.2 0.0 -0.2

Winnipeg River Riverbank Protection Program 3.1 11.2 8.1

Kettle Annunciation System Renewal 0.2 0.1 -0.1

Jenpeg Staffhouse Sewage Treatment 2.1 2.3 0.2

Jenpeg GS Kiskitto Cntrl Str Dyke Repair 2.4 3.8 1.4

Nelson River Control 6.0 0.4 -5.6

Power Supply Hydraulic Controls 0.0 8.4 8.4 New project.

Slave Falls GS Creek Spillway Rehab 0.0 0.9 0.9 New project.

Slave Falls Generating Station Rehabilitation 0.0 95.8 95.8 New project.

Generating Station Roof Replacements 0.0 9.2 9.2 New project.

Great Falls Generating Station Unit 4 Major Overhaul 0.0 17.6 17.6 New project. Great Falls 115 kV Indoor Station Safety Improvements 0.0 11.6 11.6 New project.

Jenpeg Transformers Refurbish/Add Spare 0.0 3.4 3.4 New project.

Water Licenses and Renewals 0.0 26.9 26.9 New project.

Grand Rapids Generator Step-Up Transformer Refurbishment 0.0 11.3 11.3 New project.

Gen South PCB Regulation Compliance 0.0 4.3 4.3 New project.

Brandon Generating Station Unit 5 License Review 4.7 18.6 13.9

Estimate revised for timing, current market conditions, and to include the installation of the low nitrous oxide burners and continuous emissions monitoring equipment. The ash mitigation program was expanded to include ash cells.

Selkirk GS Ancillary Systems (formerly Selkirk GS Fuel Switching

Project) 13.0 10.3 -2.7 Project transferred from "Selkirk GS Fuel Switching Project".

Selkirk Generating Station License Review 28.9 14.2 -14.7

Scope reduced to cancel the installation of the cooling tower, and add tube replacements, intake fish screen and lube oil

modifications.

Brandon Unit 5 Rehabilitation 0.0 7.1 7.1 New project.

Selkirk G.S. Rehabilitation 0.0 10.2 10.2 New project.

Fire Protection Projects - HVDC 4.1 10.8 6.7

Halon Replacement Project 0.0 42.5 42.5 New project.

Power Supply Fall Protection Program 0.0 11.3 11.3 New project.

Oil Containment - Power Supply 7.0 19.8 12.8

Increase reflects deferred in-service date and increased scope to include encapsulation of oil filled transformers/smoothing reactors at HVDC stations and fast oil drain scheme. Estimate increased to include actual contract costs for the Dorsey containment building, and construction of collection area.

Generation Townsite Infrastructure 3.4 26.8 23.3

Scope increased to include Gillam housing: replacement of 40 doublewide trailers with RTM homes, retrofit of 66 corporate accommodations, addition of 32 new conventional housing units, and replacement of the Gillam shopping centre.

(56)

Table PUB/MH II-7 (b)

200MW Ontario Hydro Sale - Sync Condnsr 7.4 7.3 -0.1

Site Remediation of Contaminated Corporate Facilities 9.2 16.7 7.5

Scope increased to reflect the addition of assessment and remediation of historical sites, acquisition and disposal of corporate properties, and remediation of the 2 Mile and 8 Mile water channels previously in non-construction capital.

High Voltage Test Facility 0.0 25.6 25.6 New project.

Power Supply Security Installations Upgrades 0.0 11.6 11.6 New project.

Power Supply Sewer & Domestic Water System 0.0 13.8 13.8 New project.

Domestic Item - Power Supply 201.5 204.0 2.6

Transmission & Distribution

Glenboro - Rugby 230kV T/L 15.0 16.8 1.7

North Central Manitoba Project 0.1 0.3 0.2

Winnipeg - Brandon Transmission Improvements 31.4 12.8 -18.7

Estimate updated for current market prices as well as a reduction in duration for the construction of the Dorsey-Portage 230 kV line, in-service date deferred from October 2008 to October 2014, pushing much of the total budget past the 2013 fiscal year (CEF07 estimate is $40.0 M).

Transcona New 230 - 66 kV Station (formerly Ridgeway 230-66kV

Transformer Addition) 9.2 31.1 21.9

Project transferred from "Ridgeway 203-66 kV Transformer Addition". Increase reflects additional costs for site

improvements due to increase in site size, market price increases on equipment, and deferral of Stage 1 in-service from March to July 2010.

St. Vital Transformer Addition 0.0 1.4 1.4 New project.

Dorsey-Rosser 230kV Transmission Imprvmt 0.5 0.8 0.3

Dorsey-St Vital 230kV AC Transmission 0.5 0.8 0.3

Dorsey-LaVerendrye-St Vital 230kV Trnsms 1.8 5.6 3.8

Rosser-Silver 230kV Transmission 23.7 26.4 2.6

Neepawa 230 - 66 kV Station 18.0 20.8 2.8

Rosser-McPhillips 115kV Trnsmsn Improve 3.0 3.2 0.2

Richer S 230-66kV Transformer Addition 5.4 9.5 4.2

Pine Falls - Bloodvein 115 kV Transmission Line 29.5 5.8 -23.7

In-service date deferred from October 2011 to October 2014, pushing much of the spending beyond the 2013 fiscal year (CEF07 estimate is $34.1 M).

Ridgeway - Selkirk 230 kV Transmission 25.3 27.2 1.9

(57)

Table PUB/MH II-7 (b)

Transmission Line Re-Rating (formerly Wpg Area Transmission

refurbishment) 4.5 16.0 11.5

Program extended by five years to 2010 and expand scope to address work required beyond Winnipeg area and re-rating of lines K21W/K22W and V38R.

Dorsey-US D602F 500kV AC T/L Insultr Rpl 1.0 0.6 -0.5

Bipole 1 & 2 Line Spacer Dampers Replace 3.6 3.1 -0.5

Dorsey 230 kV Bus Enhancement 12.9 19.2 6.3

Flin Flon Area Transm Impr (Phase I) 0.0 -1.5 -1.5

Pine Falls - Great Falls 115 - 66 kV Supply 10.6 12.1 1.5

Flin Flon Area Transmission Improvements Phase 2 9.6 13.0 3.4

St Vital-Steinbach 230kV Transmission 22.7 0.0 -22.7In-service date deferred 11 years from October 2009 to October _2020.

Rosser Station 230 - 115 kV Bank 3 Replacement 0.0 5.8 5.8 New project.

Rosser - Inkster 115kV Transmission 0.0 5.1 5.1 New project.

Jenpeg-Norway House 66kV Sub-T/L 2.9 2.9 0.1

Ruttan-South Indian Lake 66kV Line 3.9 5.5 1.6

Central Supply - Pikwitonei & Thicket Portage 1.2 1.6 0.4

Birtle South-Rossburn 66kV Line 4.0 0.0 -4.0

St Boniface-Plessis Rd. 115-25kV Station 0.8 0.8 0.0

Rosser Oak Point 115-24kV New Station 21.3 0.0 -21.3In-service date deferred ten years from October 2010 to October 2020.

Rosser Oak Point Bank 2 Addition 9.9 0.0 -9.9In-service date deferred ten years from October 2010 to October 2020.

St Boniface-Plessis Rd Bank 2 Addition 0.8 1.5 0.7

Reston - Glenboro Capacity Increase 1.3 1.5 0.1

St Leon 230-66kV Trnsfmr Addn-IPL Expand 0.6 0.0 -0.6

Neepawa - Plumas 66 kV Line 3.5 0.0 -3.5

Perimeter South Station Distribution Supply Centre Installation 0.0 2.4 2.4 New project. Portage South 230 - 66 kV 2nd Transformer Addition 0.0 12.2 12.2 New project. Winnipeg Central District 66 kV Breaker Replacement 0.0 6.0 6.0 New project.

Harrow Station Bank 3 Installation 0.0 3.1 3.1 New project.

St. Boniface 66kV Line Burial & Salvage 0.0 4.5 4.5 New project.

Fort Garry Perimeter Stn 66 - 12 kV Bank Replacement 5.1 0.0 -5.1

Virden Area Distribution Changes 4.2 5.8 1.6

Defective RINJ Cable Replacement 6.5 6.6 0.2

Brereton Lake Station Area 7.1 7.5 0.4

Shamattawa New Diesel GS & Tank Farm 12.5 10.2 -2.3

Holland 8-25 kV Conversion and Distribution Supply Centre 0.0 4.3 4.3 New project.

Stony Mountain New 115 - 12 kV Station 0.0 5.0 5.0 New project.

(58)

Table PUB/MH II-7 (b)

Court Station Bank 1 Addition 0.0 4.9 4.9 New project.

Rover Substation Replace 4 kV Switchgear 0.0 12.7 12.7 New project.

Martin New Outdoor Station 0.0 28.1 28.1 New project.

Frobisher Station Upgrade 0.0 10.0 10.0 New project.

Burrows New 66 kV/ 12 kV Station 0.0 22.7 22.7 New project.

WCD U/G Network Transformer Replacement 0.0 3.9 3.9 New project.

Winnipeg Central District Oil Switch Project 0.0 1.7 1.7 New project.

William New 66 kV/ 12 kV Station 0.0 10.2 10.2 New project.

Waverley West Sub Division Supply - Stage 1 0.0 6.5 6.5 New project.

St. James 24 kV System Refurbishment 0.0 65.9 65.9 New project.

Ness Station Feeder Conversions 0.0 2.8 2.8 New project.

Transcona Area Distribution Conversion 0.0 4.4 4.4 New project.

Shoal Lake New 33 - 12.47 kV DSC 0.0 3.6 3.6 New project.

York Station 0.0 4.0 4.0 New project.

Brandon Crocus Plains 115-25kV Bank Addn 7.8 9.4 1.6

Communications 0.0 70.4 70.4

In CEF02 all communication items were grouped together in the "Microwave Frequency Displacement" project. Per CEF07, individual items have been segregated into their own projects.

Integration of System Control Centers 0.0 8.5 8.5 New project .

MAPINFO Project 3.5 2.6 -0.9

Microwave Frequency Displacement (formerly Microwave Radio

Replacements) 127.1 33.9 -93.2

Interlake Digital Microwave Replacement 0.0 19.7 19.7

Communication System - Southern MB (Great Plains) 0.0 20.7 20.7

Communications Upgrade Winnipeg Area 0.0 5.1 5.1

Pilot Wire Replacement 0.0 8.3 8.3

(59)

Table PUB/MH II-7 (b)

Trans Line Protection & Teleprotection Replacement 0.0 19.4 19.4 New project in CEF07.

Winnipeg Central Protection Wireline Replacement 0.0 8.0 8.0

Mobile Radio System Modernization 0.0 29.6 29.6

Cyber Security Systems 0.0 9.6 9.6 New project.

Site Remediation 3.7 10.2 6.4

Oil Containment 4.8 7.0 2.2

Station Battery Bank Capacity & System Reliability Increase 0.0 32.2 32.2 New project.

Red River Floodway Expansion Project 0.0 1.9 1.9 New project.

Fleet 0.0 80.4 80.4For 2002-03 this item was reclassified from Non-Construction _Capital.

Domestic Item - Transmission & Distribution Electric 945.8 948.0 2.2 Customer Service & Marketing

Automatic Meter Reading 20.8 18.0 -2.9

Distribution PCB Testing & Transformer Replacement 18.4 19.5 1.1

Winnipeg Distribution Infrastructure Requirements 6.7 14.9 8.2

Winnipeg Central District Underground Network Asbestos Removal 0.0 3.0 3.0 New project. Domestic Item - Customer Service & Marketing - Electric 664.3 646.9 -17.4

Decrease reflects less actual spending than planned for the fiscal years 2003 to 2007, with annual budgeted amounts remaining relatively constant.

Finance & Administration

Corporate Buildings 88.0 71.7 -16.3Decrease reflects reduction in spending for the fiscal years 2003 _{to 2007.}

Customer Information System 21.1 21.3 0.2

Human Resource Management System 14.7 15.7 1.0

Enterprise GIS Project 13.1 22.0 8.9

Workforce Management (Phase 1 to 4) 0.0 11.3 11.3 New project.

WorkSmart 0.0 5.4 5.4 New project.

Domestic Item - Finance & Administration 277.7 230.5 -47.2

Decrease reflects reduction in spending for the fiscal years 2003 to 2007, with annual budgeted amounts remaining relatively constant.

(60)

PUB/MH II-7

Reference: PUB/MH I-23 (a),(d), Coalition/MH I-35

c) Please plot on the chart OM&A Cost per customer similar to that provided the chart to part (d) assuming a growth in operating costs at the actual/forecast rate of Manitoba inflation for the years 1999 to 2017.

ANSWER:

(61)

M

anitoba Hy

dro

O

p

er

at

in

g & A

d

mi

nis

trat

iv

e

Ex

pense per Customer Grow

th

Based on Manit

oba Inflation

For t

he Y

ears 1999 to 2017

520 530 54 3 55 1 56 1 56 2 57 2 58 1 58 5 59 2 60 0 60 7 615 623 631 639 648 656 665

-100

200

300

400

500

600

700

199

9

200

0

200

1

200

2

200

3

200

4

200

5

20

06

200

7

200

8

200

9

201

0

20

11

20

12

20

13

20

14

20

15

201

6

201

7

(in dol

la

rs

) .

Manit

oba Hy

dro

(62)

PUB/MH II-7

Reference: PUB/MH I-23 (a),(d), Coalition/MH I-35

d) Please plot the yearly cost per customer target based on the Corporate Strategic Plan for each of the fiscal years 1999 to 2008.

ANSWER:

Manitoba Hydro started to calculate the yearly cost per customer target on the Corporate Strategic Plan in 2002.

(63)

M

anit

o

ba Hy

dro

Operat

in

g & Admi

nis

trat

iv

e

Ex

pense per Custom

er Grow

th

Based on the Corporat

e St

rat

e

gic Plan

For t

h

e Y

ears

2002 to 2008

570 60 0 600 584 600 612 64 0 597 57 0 565 591 609 626

520

540

560

580

600

620

640

660

2002

2003

2004

2

005

2006

2007

2008

(in dollars) .

M

anit

o

ba Hy

dro Actual

M

anitoba H

y

dro Target

(64)

PUB/MH II-7

Reference: PUB/MH I-23 (a),(d), Coalition/MH I-35

e) Please reconcile between the chart provided PUB/MH I-23(d) with the data provided in response to Coalition MH 1-35

ANSWER:

Other than some rounding differences, the table provided in response to PUB/MH I-23(d) reconciles to the table provided in the response to COALITION/MH I-35(c). The table provided in response to PUB/MH I-23(d) does not reconcile with the table provided in COALITION/MH I-35(a) because PUB/MH I-23(d) is based on IFF07-1 and COALITION/MH I-35(a) is based on IFF06-3.

(65)

PUB/MH II-7

Reference: PUB/MH I-23 (a),(d), Coalition/MH I-35

f) Please provide a chart with a supporting data table which plots the annual growth % in OM&A per Customer – Electric, the