VU/Jc/ Joanna S ofield C hief R egulatory O fficer (F11 R R A ) R - - PDF document

B C hydro m

FO R G EN ER ATIO N SONMLKJIHGFEDCBA

Joanna S ofield C hief R egulatory O fficer P hone: (604) 623-4046 Fax: (604) 623-4407 bchyd roregulatorygroup@ bchydro.com

A pril 7, 2010 M s. E rica M . H am ilton. C om m ission S ecretary B ritish C olum bia U tilities C om m ission S ixth Floor - 900 H ow e S treet V ancouver, B C V 6Z 2N 3 D ear M s. H am ilton: R E : P roject N o. 3698592 B ritish C olum bia U tilities C om m ission (B C U C ) B ritish C olum bia H ydro and P ow er A uthority (B C H ydro) Fiscal 2011 R evenue R equirem ent W orkshop P resentation B C H ydro encloses as E xhibit B -3 its presentation from the W orkshop held on A pril 7, 2010. For further inform ation, please contact G uy Leroux at 604-623-3696. Y ours sincerely,

VU/Jc/

Joanna S ofield C hief R egulatory O fficer c. B C U C P roject N o. 3698592 (F11 R R A ) R egistered Intervener D istribution List.

C olum bia and P ow er

333 D U n'Sm lJir

VarlC O lJVer B C V6B 5R 3

B-3 BC HYDRO 2011 REVENUE REQUIREMENTS

EXHIBIT

F2011 REVENUE REQUIREMENT APPLICATION

WORKSHOP APRIL 7, 2010

F11 RRA Workshop April 7, 2010 2

PRESENTATION AGENDA

• 1. Introduction
• 2. Overview of the F11 RRA
• 3. F11 Revenue Requirement Summary
• Cost of Energy
• Operating Costs
• Capital-related Costs
• Subsidiary Net Income
• Deferral Account Rate Rider
• Revenue Shortfall
• 4. Capital Additions
• 5. Return on Equity
• 6. Regulatory Schedule

F11 RRA Workshop April 7, 2010 3

OVERVIEW: ORGANIZATION OF APPLICATION

Executive summary

• 1. Application overview
• 2. Performance measures and benchmarking
• 3. Load and revenue forecast
• 4. Cost of energy
• 5. Operating costs
• 6. Capital expenditures and additions
• 7. Deferral and other regulatory accounts
• 8. Other revenue requirement items
• 9. Status of RRA directives and commitments

Appendices

F11 RRA Workshop April 7, 2010 4

OVERVIEW: APPROVALS SOUGHT

The Application covers a one-year test period (F2011)

• Across-the-board rate increase of 6.11 per cent
• Increase in the Deferral Account Rate Rider to 4.0 per cent
• Acceptance of expenditures for energy conservation rates
• Various Regulatory Account orders including some to mitigate the rate

increase

F11 RRA Workshop April 7, 2010 5

OVERVIEW: RATE INCREASE MITIGATION MEASURES

• Reduction in operating cost budget (excluding non-current pension

costs)

• 4 per cent Deferral Account Rate Rider rather than 5 per cent
• Smoothing the initial rate impact of the Waneta Transaction
• Refunding in F2011 the entire balance of the Total Finance Charges

and the Net Employment Cost Regulatory Accounts, and recovering the balances in the ROE Adjustment and Pension Regulatory Accounts over five years

F11 RRA Workshop April 7, 2010 6

F2011 REVENUE REQUIREMENT SUMMARY

Exhibit B-1, Table 1-1, page 1-2

($ million) F2010 RRA F2011 Plan Increase Impact

• n Rates

Cost of Energy 1,225.5 1,203.0 (22.5)

• 0.75%

Operating Costs Current Operating Costs (excl PEB) 644.8 599.6 (45.2)

• 1.50%

Non-current PEB - Pensions (51.4) 21.2 72.6 2.41% Non-current PEB - Other 42.0 30.0 (12.0)

• 0.40%

Deferred Operating Costs 179.4 302.9 123.5 4.11% Taxes 178.1 180.7 2.6 0.09% Amortization 422.5 505.6 83.1 2.76% Finance Charges 498.5 482.5 (16.0)

• 0.53%

Return on Equity 451.5 608.9 157.4 5.24% Non-Tariff Revenue (39.9) (44.6) (4.7)

• 0.16%

Inter-Segment Revenue (64.8) (47.6) 17.2 0.57% Regulatory Account Transfers (199.2) (352.2) (153.0)

• 5.09%

Subsidiary Net Income (200.9) (153.0) 47.9 1.59% Other Utilities Revenue (16.6) (18.2) (1.6)

• 0.05%

Deferral Account Rider Revenue (15.3) (127.6) (112.3)

• 3.74%

Less Revenue at F2010 Rates (3,054.1) (3,007.4) 46.7 1.55% Revenue Shortfall 0.0 183.7 183.7 6.11% Rate Increase 6.11%

F11 RRA Workshop April 7, 2010 7

F2011 RR SUMMARY: COST OF ENERGY

Cost of Energy F2009 F2010 F2010 F2011 F2009 F2010 F2010 F2011 Actual RRA Forecast Plan Actual RRA Forecast Plan Hydroelectric (water rentals) 44,348 47,041 41,126 47,852 309.7 339.1 303.7 372.9 IPPs and Long-Term Commitments 8,374 9,277 8,140 10,145 543.0 627.6 547.2 737.7 Market Electricity Purchases 5,020 1,091 2,516 732 272.6 59.6 87.1 27.0 Domestic Transmission

• 107.8

104.4 91.1 85.3 Natural Gas for Thermal Generation 312 260 609 356 47.3 39.2 44.9 41.1 Surplus Sales

• 196
• 99
• 835

(9.7) (6.8) 0.0 (39.3) Net Purchases (Sales) from Powerex

• 65

213 2,445

• 1,619

(25.8) 19.9 99.9 (45.0) Non-Integrated Area 116 115 110 116 24.0 26.5 20.8 23.6 Other

• 13.9

16.0 15.9 (0.3) Total 57,909 57,898 54,946 56,748 1,282.8 1,225.5 1,210.7 1,203.0 Volume (GWh) Cost ($ million) Derived from Exhibit B-1, Appendix A, Schedule 4.0

F11 RRA Workshop April 7, 2010 8

F2011 RR SUMMARY: OPERATING COSTS

Current Operating Costs F2009 F2010 F2010 F2011 ($ million) Actual RRA Forecast Plan Operating Costs by Business Group Corporate (Excl Non-Current PEB) 166.0 165.1 176.4 170.4 EARG 136.0 147.4 129.4 131.2 CC&C 90.8 88.8 87.3 85.1 Transmission 97.6 95.9 96.1 96.1 Field Operations 139.5 160.3 142.7 140.5 F09/F10 RRA Adjustments 0.0 (19.4) 0.0 0.0 Subtotal 629.9 638.1 631.8 623.3 Non-Current PEB - Pension (44.6) (51.4) 34.2 21.2 Non-Current PEB - Other 27.1 42.0 26.8 30.0 Regulatory Account Transfers 36.2 6.7 (58.3) (23.7) Total Current Operating Costs 648.6 635.4 634.5 650.8

Exhibit B-1, Table 5-3, page 5-6

F11 RRA Workshop April 7, 2010 9

F2011 RR SUMMARY: CAPITAL-RELATED COSTS

• Capital-related costs include amortization, finance charges, and ROE
• Overall F2011 rate increase impact is 7.47 per cent
• Lower interest rates provide an offset to what would otherwise be

higher capital-related costs

• Capital additions will be discussed later

F11 RRA Workshop April 7, 2010 10

F2011 RR SUMMARY: SUBSIDIARY NET INCOME

Exhibit B-1, Appendix A, Schedule 1.0

($ million) F2009 Actual F2010 RRA F2010 Forecast F2011 Plan Powerex Net Income 243.9 199.0 (54.3) 152.0 Powertech Net Income 1.2 1.9 0.7 1.0 Total 245.1 200.9 (53.6) 153.0 Subsidiary Net Income

F11 RRA Workshop April 7, 2010 11

F2011 RR SUMMARY: REVENUE FROM THE DEFERRAL ACCOUNT RATE RIDER

• December 2009 balance was $586.0 million, up from September 2009

balance of $539.7 million

• Main contributors to the increase in Deferral Account balances in

F2010 have been: – Low trade income – Load variance

• 4 per cent rate rider provides $127.6 million in revenue in F2011

($ million) F2009 Actual F2010 RRA F2010 Forecast F2011 Plan Revenue from Deferral Account Rate Rider 14.0 15.3 29.5 127.6

Exhibit B-1, Appendix A, Schedule 1.0

F11 RRA Workshop April 7, 2010 12

F2011 RR SUMMARY: REVENUE SHORTFALL

Domestic Energy Sales (GWh) F2009 Actual F2010 RRA F2010 Forecast F2011 Plan Residential 17,861 16,967 17,378 17,296 Light Industrial and Commercial 18,265 18,586 17,859 18,021 Large Industrial 14,303 15,240 12,858 14,226 Other 1,887 1,829 1,905 2,006 Total 52,316 52,622 50,000 51,550 Domestic Revenues ($ million) F2009 Actual F2010 RRA F2010 Forecast F2011 Plan Residential 1,191.5 1,234.9 1,267.0 1,255.3 Light Industrial and Commercial 1,048.7 1,159.3 1,125.5 1,125.6 Large Industrial 479.0 576.5 468.6 537.4 Other 99.8 100.1 103.4 107.2 Total 2,819.0 3,070.7 2,964.4 3,025.6

Derived from Exhibit B-1, Appendix A, Schedule 14.0

F11 RRA Workshop April 7, 2010 13

F2011 RR SUMMARY: REVENUE SHORTFALL

Domestic Energy Sales

10,000 20,000 30,000 40,000 50,000 60,000 F2009 Actual F2010 RRA F2010 Forecast F2011 Plan GWh Other Large Industrial Light Industrial and Commercial Residential

Derived from Exhibit B-1, Appendix A, Schedule 14.0

F11 RRA Workshop April 7, 2010 14

CAPITAL ADDITIONS

F2011 ($ million) RRA Actual Difference RRA Forecast Difference Plan

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

Capital Additions

1

Hydroelectric Generation 308.2 274.8 (33.5) 245.4 1,042.5 797.1 497.6

2

Diesel Generation 13.3 0.5 (12.8) 14.3 10.9 (3.4) 10.5

3

Thermal Generation 12.6 16.6 4.0 10.3 16.8 6.5 10.1

4

Transmission Lines 511.6 406.4 (105.2) 397.4 351.9 (45.5) 369.2

5

SDA Substations 83.3 136.6 53.3 103.4 89.0 (14.4) 100.9

6

Distribution 372.9 317.7 (55.3) 398.9 487.6 88.8 436.6

7

Information Technology 44.4 42.4 (2.0) 42.1 72.0 29.9 92.4

8

Vehicles 24.0 25.2 1.2 21.8 43.6 21.9 26.4

9

Properties and Other Capital 79.1 45.2 (33.9) 97.1 74.4 (22.7) 100.8

10

Smart Metering and Infrastructure 0.0 0.0 0.0 0.0 4.0 4.0 54.3

11

HPOP Properties for Resale 0.0 0.0 0.0 0.0 49.0 49.0 (21.0)

12

Demand Side Management 112.1 94.9 (17.2) 138.2 144.8 6.6 184.4

13

Total 1,561.5 1,360.1 (201.4) 1,468.8 2,386.5 917.7 1,862.1 F2009 F2010

Exhibit B-1, Table 6-4, page 6-7

F11 RRA Workshop April 7, 2010 15

CAPITAL ADDITIONS: NET F2011 RATE IMPACT

($ million) F2010 Additions F2011 Additions Total Hydroelectric Generation 1.93% 0.92% 2.85% Diesel Generation 0.02% 0.02% 0.04% Thermal Generation 0.04% 0.02% 0.06% Transmission 0.17% 0.23% 0.40% Substations 0.63% 0.66% 1.29% Distribution 0.93% 0.83% 1.76% Information Technology 0.32% 0.41% 0.73% Vehicles 0.12% 0.07% 0.20% Properties and Other Capital 0.22% 0.24% 0.46% Smart Metering and Infrastructure 0.00% 0.04% 0.04% Demand Side Management 0.70% 0.28% 0.97% Total 5.07% 3.72% 8.80% F2011 Rate Impact

Exhibit B-1, Appendix L, Table 4

F11 RRA Workshop April 7, 2010 16

CAPITAL ADDITIONS: CAPITAL PROJECTS IN THE APPLICATION

BC Hydro’s capital projects are discussed in Chapter 6 and these appendices:

• Appendix I – List of Capital Projects Over $2 million
• Appendix J – Description of Capital Projects Over $5 million
• Appendix L – Rate Impact of Capital Projects

F11 RRA Workshop April 7, 2010 17

CAPITAL ADDITIONS: GENERIC RATE IMPACT

Asset example IT Distribution Transmission Generator Dam Amortization Period (Years) 10 30 40 50 100 Rate Impact (%) (Initial Full Year) 0.53 0.34 0.32 0.31 0.28 Revenue Requirement Impact ($ million) (Initial Full Year) 18 12 11 10 9

Exhibit B-1, Appendix L, Table 1

F11 RRA Workshop April 7, 2010 18

CAPITAL ADDITIONS: PROJECTS REVIEWED BY THE BCUC

BCUC Order $ million Hydroelectric Generation Aberfeldie Redevelopment C-2-07 94.0 G.M. Shrum DC System G-143-06 12.0 G.M. Shrum Stator Replacement (Units 3 and 4) G-143-06 46.0 G.M. Shrum Units 1-5 Turbine Replacement G-1-10 262.0 Mica 5/6 (Definition Phase Funding) G-69-09 30.0 Mica G1-G4 Stator G-143-06 78.0 Mica SF6 Gas Insulated Switchgear (GIS) G-38-10 180.6 Peace Canyon G1-G4 Stators G-143-06 67.0 Revelstoke Unit 5 C-8-07 280.0 Stave Falls Spillway Gates Replacement In progress 61.5 Waneta G-12-10 850.0 Thermal Generation Burrard Thermal Generating Station G-91-09 1.6 Fort Nelson Generating Station Upgrade G-75-09 140.1 Diesel Generation Toad River C-4-09A 2.3 Distribution and SDA Southern St'at'imc Communities In progress 12.1 Vancouver City Central Transmission In progress 27.2 Demand Side Management F2009-F2011 Implementation Phase Funding G-91-09 418.0 F2009-F2010 Definition Phase Funding for Capacity Related DSM G-91-09 0.6 Site C Stage 2 Definition and Consultation (F2009 and F2010) G-91-09 41.0 Total Expenditures 2,604.0

Exhibit B-1, Table 6-1, page 6-2

F11 RRA Workshop April 7, 2010 19

RETURN ON EQUITY (ROE)

• Affected by BC Hydro’s capital structure and the BCUC decision on

Terasen’s Rate of ROE (G-158-09): – Set Terasen’s 2010 allowed rate of ROE at 9.5% – Confirmed Terasen as the B.C. benchmark low risk utility

• Terasen pre-tax equivalent of 9.5% is 12.74%
• OIC 074 directed the BCUC to allow BC Hydro to earn an additional

1.63% in F2010, F2011, and F2012

• 12.74% + 1.63% = 14.37%
• Exhibit B-1 Appendix Q shows the calculation

F11 RRA Workshop April 7, 2010 20

REGULATORY SCHEDULE

ACTION DATE (2010) Workshop Wednesday, April 7 BCUC Information Request (IR) No. 1 Friday, April 16 Intervener IR No. 1 Thursday, April 22 BC Hydro Responses to IR No. 1 Thursday, May 13 Procedural Conference Tuesday, May 25 BCUC and Intervener IR No. 2 – Proposed Thursday, June 3

(BCUC Order No. G-47-10)