March 17, 2011 Ms. Erica M. Hamilton Commission Secretary British - - PDF document

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March 17, 2011 Ms. Erica M. Hamilton Commission Secretary British - - PDF document

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BC H YDRO R EVENUE R EQUIREMENTS F2012 F2014 E XHIBIT B-2 Joanna Sofield Chief Regulatory Officer Phone: 604-623-4046 Fax: 604-623-4407 bchydroregulatorygroup@bchydro.com March 17, 2011 Ms. Erica M. Hamilton Commission Secretary

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SLIDE 1

British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3 www.bchydro.com Joanna Sofield Chief Regulatory Officer Phone: 604-623-4046 Fax: 604-623-4407 bchydroregulatorygroup@bchydro.com

March 17, 2011

  • Ms. Erica M. Hamilton

Commission Secretary British Columbia Utilities Commission Sixth Floor – 900 Howe Street Vancouver, BC V6Z 2N3 Dear Ms. Hamilton: RE: Project No. 3698622 British Columbia Utilities Commission (BCUC) British Columbia Hydro and Power Authority (BC Hydro) F2012 to F2014 Revenue Requirements Application (F12-F14 RRA) Workshop Presentation BC Hydro encloses as Exhibit B-2 its presentation from the Workshop held on March 16, 2011. For further information, please contact Janet Fraser at 604-623-4176 or by e-mail at bchydroregulatorygroup@bchydro.com. Yours sincerely, (for) Joanna Sofield Chief Regulatory Officer

ab/ma

Enclosure (1) Copy to: BCUC Project No. 3698622 (F12-F14 RRA) Registered Intervener Distribution List. B-2 BC HYDRO – REVENUE REQUIREMENTS F2012‐F2014 EXHIBIT

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SLIDE 2

F2012 to F2014 Revenue Requirements F2012 to F2014 Revenue Requirements

March 16 Workshop

1

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SLIDE 3

Agenda

  • Welcome and Introductions
  • Workshop Objectives (5min.)

Workshop Objectives (5min.)

  • Overview of Application;
  • Chapter 1 – Overview (10 min.)
  • Chapter 2 - Rate Management (10 min.)
  • Chapter 3 - Load and Revenue (10 min.)
  • Chapter 4 - Cost of Energy (10 min.)
  • Chapter 5 - Operating Costs (20 min.)

Ch 6 C i l E di (15 i )

  • Chapter 6 - Capital Expenditures (15 min.)
  • Chapter 7 - Deferral and Other Regulatory Accounts (10 min.)
  • Chapter 8 - Other Revenue Requirement Items (10 min.)
  • Chapter 9 – OATT (5 min )

Chapter 9 OATT (5 min.)

  • Chapter 10 - Status of Directives (15 min.)
  • Other Appendices (10 min.)
  • Appendix A - Financial Schedules

2

  • Wrap-Up
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SLIDE 4

Introductions

  • Janet Fraser, Director of Regulatory
  • Guy Leroux, Manager of Regulatory Business Analysis

Guy Leroux, Manager of Regulatory Business Analysis

  • Wafi Kassam, Manager of Financial Forecasting and Planning
  • Wayne Taylor, Consultant
  • Ian Webb, Legal Counsel

Ian Webb, Legal Counsel

  • Andrea Banks, Senior Regulatory Specialist

3

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SLIDE 5

Workshop Objectives

  • Provide an overview of the Application

Provide an overview of the Application

  • Describe how information is organized and presented
  • Describe how financial schedules tie into the written sections
  • Highlight areas of focus

Highlight areas of focus

4

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SLIDE 6

What’s included in the Application

  • What is in the Application

What is in the Application

  • Description of BC Hydro’s business activities, business challenges, and

cost drivers.

  • Support for the rate increases and other approvals requested

Support for the rate increases and other approvals requested

  • Improvements made as a result of stakeholder feedback

What is not in the Application What is not in the Application

  • Request for CPCN or CPCN-like facility approvals
  • Rate Design
  • IRP/DSM
  • USoA

5

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SLIDE 7

Application Overview (Chapter 1)

Outlook for F12 to F14 (section 1.3) Presentation of Information (section 1.4) Presentation of Information (section 1.4) Organization of Application (section 1.5) Evidentiary Update (section 1.6) Approvals sought (section 1.7) Approvals sought (section 1.7)

6

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SLIDE 8

Approvals Sought (section 1 7) Approvals Sought (section 1.7)

  • DSM dealt with separately starting in July (s.1.7.1)

DSM dealt with separately starting in July (s.1.7.1)

  • Rate increases including smoothing mechanism (s.1.7.2)
  • 9.73% increase in each of the next three years
  • DARR remains at 2.5%
  • Depreciation rates change (due to IFRS componentization) (s.1.7.3)
  • Majority of Regulatory Accounts remain (s.1.7.4)
  • IFRS Regulatory Accounts (s.1.7.5)

IFRS Regulatory Accounts (s.1.7.5)

  • Interest Rate based on current fiscal year (s.1.7.6)
  • Baselines for Regulatory Accounts (s.1.7.7)
  • GMS Unit 3 costs to NHDA

GMS Unit 3 costs to NHDA

7

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SLIDE 9

Cost Structure Changes (s.1.3.3)

  • BCTC Integration (s.1.3.3.1)
  • Nature View and Transition to International Financial Reporting Standards

Nature View and Transition to International Financial Reporting Standards (IFRS) (s.1.3.3.2)

  • Other Cost Structure Changes (s.1.3.3.3)

8

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SLIDE 10

Approach to Presentation of Information

NSA Nature BCTC NSA-12

Column 16 17 18 19 = 16 to 18

F2011 Including BCTC for 12 Months Cost of Energy 1,415.1 (19.3) (71.8) 1,324.0 Operating Costs 946.2 59.1 62.5 1,067.8 Taxes 182.3 0.0 0.9 183.2 Amortization 519.4 (13.8) 16.8 522.4 Finance Charges 500.9 2.8 2.8 506.5 Return on Equity 586.5 0.0 1.9 588.4 Non-Tariff Revenue (44.6) (28.9) (8.2) (81.7) Inter-Segment Revenue (50.8) 0.0 (4.9) (55.6) (0.0) 0.0

9

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SLIDE 11

Table 1-1 F2012 to F2014 Revenue Requirements – Gross View (s.1.3.2)

Schedule

F2011 F2012 F2013 F2014 ($ million)

Reference

NSA-12 Plan Plan Plan F2012 F2013 F2014

1 2 3 4 5 = 2 - 1 6 = 3 - 2 7 = 4 - 3 1

Cost of Energy

1.0 L1

1,324.0 1,118.3 1,104.6 1,192.7 (205.6) (13.7) 88.0 Increase From Prior Year

2

Operating Costs

1.0 L2

1,067.8 1,409.9 1,498.1 1,422.4 342.1 88.2 (75.7)

3

Taxes

1.0 L3

183.2 187.8 199.6 211.7 4.6 11.8 12.1

4

Amortization

1.0 L4

522.4 608.5 646.8 667.2 86.1 38.3 20.5

5

Finance Charges

1 0 L5

506 5 603 7 710 7 811 6 97 1 107 1 100 9

5

Finance Charges

1.0 L5

506.5 603.7 710.7 811.6 97.1 107.1 100.9

6

Return on Equity

1.0 L6

588.4 610.5 583.5 625.1 22.1 (27.0) 41.6

7

Non-Tariff Revenue

1.0 L7

(81.7) (73.0) (70.0) (72.8) 8.7 3.0 (2.9)

8

Inter-Segment Revenue

1.0 L8

(55.6) (26.1) (27.4) (28.5) 29.5 (1.3) (1.1) g ( ) ( ) ( ) ( ) ( ) ( )

9

Deferral Account Transfers

1.0 L12

(160.8) 47.4 56.3 67.8 208.2 8.9 11.4

10

Other Regulatory Account Transfers

1.0 L16

(426.1) (702.9) (576.5) (350.5) (276.8) 126.4 226.0

11

Subsidiary Net Income

1.0 L19

(153.0) (70.4) (76.3) (85.7) 82.6 (5.8) (9.5)

12

Other Utilities Revenue

1.0 L20

(17.6) (14.2) (14.6) (15.1) 3.3 (0.4) (0.5)

13

Deferral Rider Revenue

1.0 L21

(113.9) (90.2) (98.4) (108.4) 23.6 (8.2) (10.0)

14

Less Revenue at F2011 Rates

1.0 L26

(3,183.6) (3,289.2) (3,269.5) (3,283.1) (105.6) 19.7 (13.7)

10

15

Revenue Shortfall

1.0 L27

(0.0) 319.9 666.9 1,054.2 319.9 347.0 387.3

16

Rate Increase

1.0 L28

9.73% 9.73% 9.73%

17

Deferral Account Rate Rider

1.0 L29

2.50% 2.50% 2.50%

18

Net Bill Increase

1.0 L30

10.13% 9.73% 9.73%

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SLIDE 12

Table 1-2 F2012 to F2014 Revenue Requirements – Current View (s.1.3.2)

Schedule

F2011 F2012 F2013 F2014 ($ million)

Reference

NSA-12 Plan Plan Plan F2012 F2013 F2014

1 2 3 4 5 = 2 - 1 6 = 3 - 2 7 = 4 - 3

Increase From Prior Year

1

Cost of Energy

3.0 L53

1,138.5 1,177.2 1,195.9 1,286.7 38.6 18.7 90.8

2

Operating Costs

3.0 L54

766.3 754.8 958.3 1,108.8 (11.5) 203.4 150.5

3

Taxes

3.0 L55

183.2 187.8 199.6 211.7 4.6 11.8 12.1

4

Amortization

3.0 L56

532.0 597.0 660.4 716.3 65.1 63.4 55.9

5

Finance Charges

3.0 L57

362.0 530.7 609.0 686.0 168.8 78.3 77.0

6

Return on Equity

3.0 L58

599.7 614.2 577.8 614.1 14.5 (36.4) 36.3

7

Non Tariff Revenue

3 0 L59

(81 7) (73 0) (70 0) (72 8) 8 7 3 0 (2 9)

7

Non-Tariff Revenue

3.0 L59

(81.7) (73.0) (70.0) (72.8) 8.7 3.0 (2.9)

8

Inter-Segment Revenue

3.0 L60

(55.6) (26.1) (27.4) (28.5) 29.5 (1.3) (1.1)

9

Subsidiary Net Income

3.0 L61

(129.3) (49.0) (54.1) (61.3) 80.3 (5.1) (7.2)

10

Other Utilities Revenue

3.0 L62

(17.6) (14.2) (14.6) (15.1) 3.3 (0.4) (0.5)

10

Ot e Ut t es e e ue

3.0 L62

(17.6) (14.2) (14.6) (15.1) 3.3 (0.4) (0.5)

11

Deferral Rider Revenue

3.0 L63

(113.9) (90.2) (98.4) (108.4) 23.6 (8.2) (10.0)

12

Less Revenue at F2011 Rates

1.0 L26

(3,183.6) (3,289.2) (3,269.5) (3,283.1) (105.6) 19.7 (13.7)

13

Revenue Shortfall

1.0 L27

(0.0) 319.9 666.9 1,054.2 319.9 347.0 387.3 11

14

Rate Increase

1.0 L28

9.73% 9.73% 9.73%

15

Deferral Account Rate Rider

1.0 L29

2.50% 2.50% 2.50%

16

Net Bill Increase

1.0 L30

10.13% 9.73% 9.73%

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SLIDE 13

Revenue Requirement Components (s.1.3.4)

Cost of Energy, 29% Return on Equity, 14% Finance Charges, 14% Operating Costs, 22% Taxes, 5% Amortization, 16%

12

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SLIDE 14

Rate Increase Drivers (s.1.3.5)

9.0% Finance Charges 5 1% 5.9% Amortization Operating Costs g 3 6% 4.1% 5.1% F12 F14 R t S thi Cost of Energy Amortization 1.9% 3.6% Subsidiary Net Income F12-F14 Rate Smoothing 0.8% 1.2% Taxes Non-Rate Revenue 13 0.4% 0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 10% Return on Equity

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SLIDE 15

Rate Management (Chapter 2)

  • Rate Increases Forecast Table 2-2

Rate Increase Forecast Approved Plan Forecast (%) F2011 F2012 F2013 F2014 F2015 Rate Increase 6.11 9.73 9.73 9.73 6.95 Credit per NSA (January to March 2011) (4.71) 0.00 0.00 0.00 0.00 Rate Rider 3.53 2.50 2.50 2.50 2.50 Net Annual Bill Impact 7.29 10.13 9.73 9.73 6.95 Cumulative Bill Impact 7.29 18.16 29.66 42.28 52.17

  • Rate Management (section 2 3)
  • Rate Management (section 2.3)

14

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SLIDE 16

Rate Management (Chapter 2)

  • Regulatory Account Balances (s.2.3.2) Table 2-3

End of Year Balance

Schedule

F2011 F2012 F2013 F2014 End of Year Balance

Schedule

F2011 F2012 F2013 F2014 ($ million)

Reference

Forecast Plan Plan Plan

1 2 3 4

Deferral Accounts

1

Heritage Deferral Account

2.1 L26

268.9 299.2 279.9 256.8

2

Non-Heritage Deferral Account

2.1 L27

401.4 378.7 354.4 325.0

3

Trade Income Deferral Account

2.1 L28

208.7 196.9 184.2 169.0

4

Total 879.0 874.9 818.5 750.8 Capital-Like Accounts

5

Demand-Side Management

2.2 L135

526.3 637.0 766.8 916.3

6

Site C

2.2 L139

107.1 238.3 411.4 531.9

7

Future Removal & Site Restoration

2.2 L140

(136.5) (102.2) (81.4) (60.3)

8

Smart Metering & Infrastructure

2.2 L152

30.4 140.5 326.4 458.7

9

Total 527.2 913.6 1,423.3 1,846.6 N C h Li biliti Non-Cash Liabilities

10

First Nations Provisions

2.2 L137

303.5 316.0 328.5 340.9

11

Environmental Provisions

2.2 L156

317.4 312.5 307.6 301.4

12

IFRS Pension

2.2 L158

0.0 0.0 855.0 810.0

13

Total 620.9 628.5 1,491.2 1,452.3 Rate Smoothing Accounts

14

First Nations Costs

2.2 L136

95.1 95.8 95.8 95.8

15

Waneta

2.2 L155

30.0 40.0 25.0 15.0

16

IFRS PP&E

2.2 L157

0.0 186.0 341.5 475.2

17

F12-F14 Rate Smoothing

2.2 L159

0.0 138.6 128.8 0.0

18

Total 125.1 460.4 591.1 586.0 Forecast Variance Accounts

19

Foreign Exchange Losses (Gains)

2.2 L141

(98.8) (101.6) (100.3) (98.4)

20

Storm Restoration

2.2 L143

(5.0) (5.3) (5.5) (5.8)

21

Total Taxes

2.2 L149

(13.3) (13.9) (14.6) (15.4)

22

Amortization on Capital Additions

2.2 L150

2.1 2.2 2.3 2.4

23

Total Finance Charges

2.2 L151

(1.9) (1.9) (1.9) (1.9)

24

Non-Current Pension Cost

2.2 L154

68.5 51.4 34.2 17.1

25

Total (48.4) (69.1) (85.8) (102.0) Other Regulatory Accounts

26

Pre-1996 Contributions

2.2 L142

58.7 67.3 74.8 81.1

15

27

Procurement Enhancement (closed)

2.2 L144

38.5 34.7 30.8 27.0

28

Capital Project Investigation (closed)

2.2 L145

52.6 47.5 42.4 37.2

29

GM Shrum 3

2.2 L146

43.3 0.0 0.0 0.0

30

F2010 ROE Adjustment (closed)

2.2 L147

45.1 33.8 22.6 11.3

31

Home Option Purchase Plan

2.2 L153

18.0 24.0 27.0 28.2

32

Total 256.3 207.3 197.5 184.8

33

Total 2,360.1 3,015.6 4,435.8 4,718.6

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SLIDE 17

Load and Revenue Forecast (Chapter 3)

Energy Sales Forecast (s.3.2) based on August 2010 forecast will update in EU Table 3-1 Energy Sales Forecast F2012 to F2014 (s.3.2.2)

F2011 F2011 F2012 F2013 F2014 (GWh) Forecast NSA-12 Plan Plan Plan

1 2 3 4 5

Domestic Energy Sales

1

Residential 17,680 17,365 17,893 17,720 17,438

2

Light Industrial and Commercial 17,842 18,247 17,869 17,555 17,230

3

Large Industrial 13,164 14,153 14,228 14,656 15,377

4

Other 1,937 2,029 2,080 2,116 2,142

5

Total 50,623 51,794 52,071 52,046 52,187

5

Total 50,623 51,794 52,071 52,046 52,187

16

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SLIDE 18

Revenue Forecast (s.3.3)

Revenue Forecast - F2012 to F2014 (Appendix A, Schedule 14.0)

F2011 F2012 F2013 F2014 NSA-12 Plan Plan Plan Domestic Revenues ($million) ( )

10

Residential 1,338.0 1,382.4 1,371.9 1,353.2

11

Light Industrial and Commercial 1,214.6 1,192.9 1,170.5 1,148.0

12

Large Industrial 579.1 616.1 624.0 660.7

13

Irrigation 4.0 4.8 4.8 4.9

14

Street Lighting 28.2 28.1 28.3 28.6

15

New Westminster & Tongass 19.1 19.6 19.8 20.0

16

Fortis 44.2 45.2 46.3 47.1

17

Seattle City Light 17.6 14.2 14.6 15.1

18

F11 Credit Rider (43.8) 0.0 0.0 0.0

19

SMI Impact 0.0 0.1 3.8 20.7

20

Subtotal 3,201.1 3,303.4 3,284.1 3,298.2

21

Revenue from Deferral Rider 113.9 90.2 98.4 108.4

22

Total 3 315 0 3 393 7 3 382 5 3 406 7

22

Total 3,315.0 3,393.7 3,382.5 3,406.7

24

Deferral Account Rate Rider 2.50% 2.50% 2.50% Average Revenues ($/MWh)

25

Residential 77.1 77.3 77.4 77.6

26

Light Industrial and Commercial 66 6 66 8 66 7 66 6

26

Light Industrial and Commercial 66.6 66.8 66.7 66.6

27

Large Industrial 40.9 43.3 42.6 43.0

28

Irrigation 51.3 52.5 52.5 52.5

29

Street Lighting 129.7 127.2 127.2 127.2

30

New Westminster & Tongass 43.4 43.7 43.7 43.7

31

Fortis 45.1 44.9 44.7 44.5

32

Seattle City Light 56.5 45.7 47.2 48.6 17

32

Seattle City Light 56.5 45.7 47.2 48.6

33

Total (Excluding Misc Rev) 64.0 65.2 65.0 65.3

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SLIDE 19

Cost of energy (Chapter 4)

Cost of Energy Summary

F2011 F2012 F2013 F2014 F2012 I

Table 4-1 Cost of Energy Summary

F2011 F2012 F2013 F2014 ($ million) NSA-12 Plan Plan Plan

$ million Per Cent 1 2 3 4 5 = 2 - 1 6 = 5 / 1

Cost of Energy

1

Heritage Energy 499.7 413.1 376.5 354.3 (86.6)

  • 17.3%

2

Non-Heritage Energy 824.3 705.3 728.1 838.4 (119.0)

  • 14.4%

F2012 Increase g gy ( )

3

Total (Schedule 4.0, Line 18) 1,324.0 1,118.3 1,104.6 1,192.7 (205.6)

  • 15.5%

Cost of Energy, 29% Return on Equity, 14% gy, Finance Charges, 14% Amortization 16%

18

Operating Costs, 22% Taxes, 5% Amortization, 16%

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SLIDE 20

System Optimization

  • The Marginal Cost Model (MCM) suite is the primary set of tools used by

BC Hydro to coordinate its major reservoir operations with IPP purchases, BC Hydro to coordinate its major reservoir operations with IPP purchases, thermal generation and market purchases and sales.

  • The MCM suite is a set of in-house, proprietary models developed specifically

for the characteristics of the BC Hydro system. for the characteristics of the BC Hydro system.

  • A key feature of the MCM suite is the explicit modeling of decision-making

under uncertainty in future inflows and market prices.

19

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SLIDE 21

Forecast Cost of Energy for F2012 to F2014

S

($ million) F2011 F2012 F2013 F2014 NSA-12 Plan Plan Plan

Line Column 8 9 10 11

Schedule 4.0 in Appendix A

Line Column 8 9 10 11

Cost of Energy ($ million) Heritage Energy

1

Hydroelectric (water rentals) 323.5 360.1 372.1 379.2 y ( )

2

Market electricity purchases 148.3 43.3 23.6 28.1

3

Market Purchases to Non-Heritag 0.0 0.0 0.0 0.0

4

Natural gas for thermal generatio 37.3 34.9 50.1 54.4

5

Domestic transmission 15.7 15.1 15.1 15.1

6

Surplus Sales 0.0 (17.6) (55.5) (96.3) Oth (25 1) (22 7) (28 8) (26 2)

7

Other (25.1) (22.7) (28.8) (26.2)

8

Total 499.7 413.1 376.5 354.3 Non-Heritage Energy

9

Mkt Purchases From Heritage 0.0 0.0 0.0 0.0

10

Waneta (water rentals) 7 0 8 2 8 3 8 5

10

Waneta (water rentals) 7.0 8.2 8.3 8.5

11

IPPs and Long-Term Commitmen 710.4 689.8 712.3 871.0

12

New Capital Leases Under IFRS 0.0 0.0 (32.0) (66.8)

13

Non-Integrated Area 23.6 23.7 25.9 28.0

14

Gas & Other Transportation 13.3 14.5 12.6 11.5

15

Domestic Transmission 23.1 0.0 0.0 0.0

20

16

Net Purchases (Sales) from Pow 46.8 (30.9) 1.1 (13.8)

17

Total 824.3 705.3 728.1 838.4

18

Total Gross COE 1,324.0 1,118.3 1,104.6 1,192.7

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SLIDE 22

Forecast Cost of Energy for F2012 to F2014

Table 4-6 Energy being purchased under active EPAs

IPP and Long-Term Purchase Volumes

  • No. of

EPA F2010 A t l F2011 F t F2012 Pl F2013 Pl F2014 Pl (GWh) EPAs Actual Forecast Plan Plan Plan Pre-2000 EPAs 18 2,712 2,904 3,013 3,008 2,931 Island Cogeneration Plant 1 1,529 1,929 109 114 80 2000 Green RFEOI1 3 127 140 153 153 153 2001 Green Energy Call 13 613 692 715 715 715 2002 CBG Call2 2 227 287 295 295 208 2002/03 GPG Call3 7 354 614 637 637 639 F2006 Call (including Brilliant) 29 436 1,783 2,382 2,416 2,556 Alcan 2007 EPA 1 2,748 3,103 2,205 1,691 1,691 Bioenergy Call - Phase I RFP 4 141 352 503 538 538 2009 Clean Power Call 25

  • 24

245 1,429 Standing Offer Program 6 6 58 80 130 130 Forrest Kerr EPA * 1

  • Total

110 8,893 11,862 10,114 9,941 11,068

* Note: Forrest Kerr EPA project is expected to be operational in F2015.

  • 1. RFEOI – Request for Expressions of Interest.

2 CBG Customer Based Generation 21

  • 2. CBG – Customer Based Generation.
  • 3. GPG – Green Power Generation.
slide-23
SLIDE 23

Forecast Cost of Energy for F2012 to F2014

C

IPP and Long-Term Purchase Costs ($ million) F2010 Actual F2011 Forecast F2012 Plan F2013 Plan F2014 Plan

Table 4-7 IPP and Long Term Purchase Costs

( ) Pre-2000 EPAs 173.0 176.9 183.6 188.9 186.0 Island Cogeneration Plant 119.5 137.6 62.4 60.4 57.7 2000 Green RFEOI 4.8 5.1 5.5 6.1 6.5 2001 Green Energy Call 33.6 37.8 39.6 40.0 40.4 2002 CBG Call 15.8 23.7 24.3 24.7 19.4 2002/03 GPG Call 19.4 33.9 36.2 36.6 37.1 F2006 Call (including Brilliant) 38.0 154.2 215.4 221.2 236.7 Alcan 2007 EPA 147.3 179.1 130.9 104.3 107.1 Bioenergy Call - Phase I RFP 15.5 37.1 52.9 57.5 58.5 2009 Clean Power Call

  • 2.2

30.7 178.8 Standing Offer Program 0.6 5.1 7.2 11.4 11.6 Total 567.4 790.5 760.2 781.8 939.8 Table 8-2 Impact of Capital Lease Accounting Treatment

  • f Six Qualifying EPAs

($ million) Appendix A Reference F2011 Forecast F2012 Plan F2013 Plan F2014 Plan 22 Change in cost of energy resulting from two EPAs that have been recognized as capital leases in F2011 4.0 L11 (48.9) (70.4) (69.6) (68.7)

slide-24
SLIDE 24

Review of F2011 (S.4.3)

As of September 2010, F2011 total system inflow energy equivalent was forecast at 83 per cent of normal, the lowest in the ensemble of 37 historic forecast at 83 per cent of normal, the lowest in the ensemble of 37 historic years currently used as the basis for the Cost of Energy forecast. The corresponding forecast Cost of Energy for F2011 is expected to be about $9 million less than the F11 RRA NSA, but about $174 million greater than $9 million less than the F11 RRA NSA, but about $174 million greater than F2010 actual Cost of Energy. The higher forecast Cost of Energy for F2011 relative to F2010 is primarily attributed to higher volumes of IPP contract deliveries and higher volumes of attributed to higher volumes of IPP contract deliveries and higher volumes of market electricity purchases due to the well below normal system inflow.

23

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SLIDE 25

Operating Costs

  • Cost classification and BCTC Integration
  • Planning Process
  • Operating Costs by Business Group

Return on Equity, 14% Cost of Energy, 29% Fi Ch 14% q y, % Finance Charges, 14% Operating Costs, 22% Taxes, 5% Amortization, 16%

24

,

slide-26
SLIDE 26

Operating Costs by Business Group

Table 5-1 Reconciliation of F11 RRA NSA Operating Costs to F11 RRA NSA-12 ($ million) Schedule 5.0 Reference Operating costs per the F11 RRA NSA 653.7 Column 16, Row 9 It 2 d 3 f BCTC I t ti ( ti 1 3 3 1) 62 5 C l 18 R 9 Items 2 and 3 of BCTC Integration (section 1.3.3.1) 62.5 Column 18, Row 9 Nature View reclassifications of costs (section 1.3.3.2) 38.3 Column 17, Row 9 S O C C F11 RRA NSA-12 Operating Costs 754.5 Column 19, Row 9

Table 5-3 ($ million) Schedule 5.0 Reference F11 RRA NSA 12 Operating Costs 754 5 Column 8 Row 9 F11 RRA NSA-12 Operating Costs 754.5 Column 8, Row 9 Add back $35 million NSA adjustment 35.0 Column 8, Row 8 Deduct non-current PEB costs (pension and

  • ther)

(51.2) Column 8, Rows 18 and 19

25

F11 Plan/carry forward before non-current PEB 738.3

slide-27
SLIDE 27

Operating Costs by Business Group

Table 5-4 Table 5 4

F2012 to F2014 Operating Costs

($ million) F2012 F2013 F2014

1 F11 Plan / carryforward plan before Non‐Current PEB costs (from Table5‐3)

738.3 773.3 778.2

2 Standard Labour Rate (SLR) ‐ current pension expense increase

10.5 1.7 1.7

3 Accounting reclassifications (see below)

24.5 (3.0) (0.3)

4

773.3 771.9 779.7

5 Savings/Efficiency: 6

BCTC Integration Savings (25.8) ‐ ‐

7

Savings from efficiency projects (4.6) (19.1) (19.2)

8

Productivity/Efficiencies (16.9) (5.7) (4.1)

9

A (47.3) (24.8) (23.3) Required cost increases:

10

Revenue Driven 1.3 0.6 0.5

11

Maintenance/Ageing Assets 18.4 10.5 6.0

12

Safety/Supervision 1.5 ‐ ‐

13

New Work 7.3 5.4 8.2

14

Cost Increases 1.6 0.1 0.2

15

Growth Driven 9.7 6.2 5.0

16

SLR increase (non‐pension piece) 10.9 9.8 8.8

17

Capital Overhead& Other (3 5) (1 6) (1 7)

17

Capital Overhead& Other (3.5) (1.6) (1.7)

18

B 47.3 31.0 27.0

19 Net increase

B ‐ A 0.0 6.3 3.7

20 Total before Non‐Current PEB costs

773.3 778.2 783.3

21 Non‐Current PEB Costs

56.8 59.3 53.6

22 Total before IFRS adjustments (Schedule 5.0, Line 9)

830.1 837.5 836.9

22 Total before IFRS adjustments (Schedule 5.0, Line 9)

830.1 837.5 836.9

23 IFRS adjustments

‐ (24.0) 4.9

24 Net Operating Costs (Schedule 5.0, Line 22)

830.1 813.5 841.8 Accounting Reclassifications:

25

Water License Requirements 3.2 (3.4) (0.7)

26

IPP Capital Lease 6.1 0.4 0.4

27

Capital Investigation costs capitalized in prior years 8.0 ‐ ‐

26

28

Procurement depts deferred in prior years 3.0 ‐ ‐

29

Interconnection billable studies recovery (cost increase incl above) 4.2 ‐ ‐

30

24.5 (3.0) (0.3)

slide-28
SLIDE 28

Operating Costs by Business Group Table 5-7 and 5-8 Table 5-7 and 5-8

Current Operating Costs by Business Group

F2011 F2012 F2013 F2014 ($ million) NSA-12 Plan Plan Plan

$ million Per Cent

F2012 Increase

1 2 3 4 5 = 2 - 1 6 = 5 / 1

Current Operating Costs

1

Generation 166.8 182.0 185.3 189.1 15.2 9.1%

2

Transmission & Distribution 364.2 380.0 390.4 402.8 15.8 4.4%

3

Deputy CEO Business Group 124.4 134.6 135.8 137.7 10.2 8.2%

4

Corporate Groups (excl PEB) 82.9 76.7 66.7 53.6 (6.2)

  • 7.5%

( ) ( )

5

Non-Current PEB - Pension 21.2 27.3 38.3 31.9 6.1 28.8%

6

Non-Current PEB - Other 30.0 29.5 21.0 21.7 (0.5)

  • 1.7%

7

F09/F10 RRA Adjustments 0.0 0.0 0.0 0.0 0.0 N/A

8

F11 RRA NSA Adjustment (35.0) 0.0 0.0 0.0 35.0

  • 100.0%

9

Subtotal (Schedule 5.0, line 9) 754.5 830.1 837.5 836.8 75.6 10.0%

10

Regulatory Account Transfers (5.0 L34) (23.6) 34.8 84.8 87.9 58.3

  • 247.6%

11

IFRS Impact (5.0 L37) 0.0 0.0 (24.0) 4.9 0.0 N/A

12

Total Current Operating (5.0 L38) 730.9 864.9 898.3 929.6 133.9 18.3%

FTE b B i G FTEs by Business Group

F2011 F2012 F2013 F2014 NSA-12 Plan Plan Plan

FTE Per Cent 1 2 3 4 5 = 2 - 1 6 = 5 / 1

FTEs by Business Group

1

Generation 1,433 1,413 1,413 1,413 (19)

  • 1.3%

F2012 Increase 27 , , , , ( )

2

Transmission & Distribution 4,010 3,865 3,865 3,865 (144)

  • 3.6%

3

Deputy CEO Business Group 601 656 661 586 55 9.2%

4

Corporate Groups 852 821 719 619 (31)

  • 3.7%

5

Total (Schedule 16.0, line 40) 6,895 6,756 6,659 6,484 (140)

  • 2.0%
slide-29
SLIDE 29

BREAK

slide-30
SLIDE 30

Capital Expenditures Table 6-1

F2011 F2012 F2013 F2014 ($ million) NSA-12 Plan Plan Plan

1 2 3 4 1 2 3 4

Capital Expenditures

1

Hydroelectric Generation 376.2 372.4 465.2 544.3

2

Diesel Generation 8.8 12.7 14.8 12.3

3

Thermal Generation 63.5 57.8 14.0 4.0

4

Transmission Lines 177.9 312.2 456.3 591.3

5

Transmission Substations 244.3 402.5 354.5 313.7

6

SDA Substations 129.1 0.0 0.0 0.0

7

Distribution 423.8 414.0 423.4 449.9 I f ti T h l 80 2 75 5 74 1 73 4

8

Information Technology 80.2 75.5 74.1 73.4

9

Vehicles 21.0 35.0 26.0 21.0

10

Properties and Other Capital 92.4 138.4 99.4 105.5

11

Smart Metering & Infrastructure 54.3 0.0 0.0 0.0

12

HPOP Properties for Resale (20 9) (20 9) (1 8) 0 0

12

HPOP Properties for Resale (20.9) (20.9) (1.8) 0.0

13

Demand Side Management 184.4 189.0 225.3 263.0

14 Total (Schedule 13.0, Line 14)

1,835.0 1,988.6 2,151.2 2,378.4

29

slide-31
SLIDE 31

Capital Additions Table 6-2

F2011 F2012 F2013 F2014 ($ illi ) NSA 12 Pl Pl Pl ($ million) NSA-12 Plan Plan Plan

1 2 3 4

Capital Additions

1

Hydroelectric Generation 497.6 325.4 358.6 266.9

2

Diesel Generation 10 5 11 5 15 8 15 6

2

Diesel Generation 10.5 11.5 15.8 15.6

3

Thermal Generation 10.1 151.9 11.6 3.1

4

Transmission Lines 77.7 252.5 518.9 695.5

5

Transmission Substations 228.3 290.0 191.6 159.6

6

SDA Substations 100.9 0.0 0.0 0.0

7

Distribution 436.6 243.7 321.6 386.4

8

Information Technology 105.3 52.2 52.6 46.1

9

Vehicles 26.4 46.3 28.3 22.3

10

Properties and Other Capital 115.3 165.5 80.9 124.6 S t M t i & I f t t 54 3 0 0 0 0 0 0

11

Smart Metering & Infrastructure 54.3 0.0 0.0 0.0

12

HPOP Properties for Resale (20.9) (20.9) (1.8) 0.0

13

Demand Side Management 184.4 189.0 225.3 263.0

14 Total (Schedule 13.0, Line 36)

1,826.5 1,707.1 1,803.3 1,983.0

30

slide-32
SLIDE 32

Capital Expenditures Reviewed by BCUC Table 6-3 Table 6 3

Particulars ($ million) BCUC Order No. Total Cost Accepted by Total Cost of Project per the BCUC Appendix I Hydroelectric Generation 1 Revelstoke Unit 5 C-8-07 280.0 250.0 2 G.M. Shrum Units 1-5 Turbine Replacement G-1-10 262.0 246.9–313.9 3 Mica 5/6 (Definition Phase Funding) G-69-09 30.0 700.0–800.0 4 Stave Falls Spillway Gates Replacement G-81-10 61.5 66.9–71.8 5 Hugh Keenleyside Spillway Gates Project G-177-10 90.2 90.7–102.5 Thermal Generation 6 Fort Nelson Resource Smart Upgrade G-75-09 140.1 139.8–154.6 Transmission 7 Vancouver City Central Transmission C-3-10 200.9 177.0–195.0 8 Columbia Valley Transmission Project C-5-10 154.1 132.0–209.0 Demand Side Management 9 Demand Side Management (F2009-F2011) G-91-09 418.0 382.1 31

slide-33
SLIDE 33

Deferral and Regulatory Accounts Chapter 7

  • Framework for Regulatory Accounts
  • Deferral Accounts

Deferral Accounts

  • Existing Regulatory Accounts
  • Planned Regulatory Accounts
  • Potential Regulatory Accounts

Potential Regulatory Accounts

32

slide-34
SLIDE 34

Other Revenue Requirement Items Chapter 8

  • Amortization Expense
  • Capital Structure

Capital Structure

  • Finance Charges
  • Return on Equity
  • Taxes

Taxes

  • Non-Tariff Revenues
  • Inter-Segment Revenues
  • Subsidiary Net Income

Subsidiary Net Income

  • Expenditures for Export
  • Allocation of Corporate Costs
  • Provisions and Other

Provisions and Other

  • Accounting Policy Issues
  • International Financial Reporting Standards (IFRS)

33

slide-35
SLIDE 35

Open Access Transmission Tariff

  • Transmission Revenue Requirement – costs attributed to transmission

business make up TRR – no change to pre-established methodology p g p gy

  • OATT Rates –Schedule 3.4
  • With the integration of BC Hydro and BCTC, BC Hydro is now responsible

for seeking approval of OATT rates.

  • The TRR is collected under the OATT through:
  • Network Integrated Transmission Service (NITS) charges.
  • Long-term and short-term PTP charges.

Ancillar Ser ices charges

  • Ancillary Services charges.

34

slide-36
SLIDE 36

Status of Directives and NSP Provisions (Chapter 10) Appendices Appendices

  • Chapter 10, Concordance Tables
  • Outstanding BC Hydro Directives and NSA Provisions
  • Outstanding BCTC Directives
  • Requests from Nov. 30 meeting

Appendices Appendices

35