BC hydro REGENERATION sm Janet Fraser Chief Regulatory Officer Phone: 604-623-4046 Fax: 604-623-4407 [email protected]December 2, 2011 Ms. Alanna Gillis Acting Commission Secretary British Columbia Utilities Commission Sixth Floor - 900 Howe Street Vancouver, BC V6Z 2N3 Dear Ms. Gillis: RE: Project No. 3698622 British Columbia Utilities Commission (BCUC) British Columbia Hydro and Power Authority (BC Hydro) Amended F2012 to F2014 Revenue Requirements Application (F12-F14 RRA) Attached as Exhibit B-13 is BC Hydro's presentations from its Workshop held on December 1, 2011. For further information, please contact Fred James at 604-623-4317 or bye-mail at [email protected]. Yours sincerely, (10< et = Chief Regulatory Officer af/rna Enclosure (1) Copy to: BCUC Project No. 3698622 (Amended F12-F14 RRA) Registered Intervener Distribution List. British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3 www.bchydro.com B-13
Transcript
BChydro REGENERATION s m Janet Fraser Chief Regulatory Officer Phone: 604-623-4046 Fax: 604-623-4407 [email protected]
December 2, 2011
Ms. Alanna Gillis Acting Commission Secretary British Columbia Utilities Commission Sixth Floor - 900 Howe Street Vancouver, BC V6Z 2N3
Dear Ms. Gillis:
RE: Project No. 3698622 British Columbia Utilities Commission (BCUC) British Columbia Hydro and Power Authority (BC Hydro) Amended F2012 to F2014 Revenue Requirements Application (F12-F14 RRA)
Attached as Exhibit B-13 is BC Hydro's presentations from its Workshop held on December 1, 2011.
For further information, please contact Fred James at 604-623-4317 or bye-mail at [email protected].
Yours sincerely,
. ~~--~ (10< et = Chief Regulatory Officer
af/rna
Enclosure (1)
Copy to: BCUC Project No. 3698622 (Amended F12-F14 RRA) Registered Intervener Distribution List.
British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3 www.bchydro.com
B-13
markhuds
BCH 2012-2014 Revenue Requirements
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December 1 Workshop: • Amended F2012 to F2014 Revenue
Janet Fraser - Chief Regulatory Officer Fred James - Manager, Regulatory - Rates and Finance Wafi Kassam - Manager, Finance Bryan Hobkirk - Regulatory Advisor Wayne Taylor - Consultant John Duffy - Manager, DSM Planning Lyle McClelland - DSM Business Advisor Renata Kurschner - Director, Generation Resource. Dave Bonser - Engineer, Generation Resource
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Agenda 9:00 - Welcome and Workshop objectives 9:10 - Overview and Presentation of Amended Application 9:20 - 10:20 – Review of Amended Costs/Revenues
10:20 Coffee Break (20 minutes) 10:40 – Amended Appendix A – Financial Schedules 11:00 – New Appendix II – F12 & F13 DSM Expenditures
12:00 – Lunch (90 minutes) 1:30 – Generation Marginal Cost Model presentation 3:00 – Concluding remarks and wind-up
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Workshop Objectives
Amended F12-14 RRA Provide an overview of the Amended F2012 – F2014 Application. Describe how information is organized and presented. Highlight areas of change from March 2011 Application. Answer questions as to what information is in the Amended F2012 – F2014
Application.
DSM Provide overview of F12 & F13 DSM Expenditures New Appendix II. Generation Marginal Cost Model (MCM) Provide description of the MCM, its purpose and design.
Presentation of Amended Information
• Original Application material presented in the Amended Application
as filed in March 2011.
• Amended and new material presented as grey shaded text or grey shaded tables.
• New grey shaded tables (with actual F11 data) also denoted by letter designation. eg. New Table 4-A
• New appendices titled: i.e. New Appendix BB.
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Presentation of Amended Information
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Presentation of Amended Information
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Presentation of Amended Information
The Amended Application, in Chapter 5 reflects the impact of the following changes :
DCEO Business Group reorganization, T&D Transformation- Initial Phase, Workforce reductions for Phase 1 & 2– 450 FTE reductions, Addition of 100 new front line operational FTEs, New outsourcing agreements.
The new Safety and Environment management structure and other
organizational changes have not been fully implemented and therefore are not completely reflected in the Amended Application. Section 5.2.2.4
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Presentation of Amended Information
The impact of the following changes are reflected at the KBU level: DCEO reorganization – discussion of DCEO KBUs transferred to other
Business Groups is reflected in italics in new Business Group section, Sections 5.2.2.2, 5.5 and 5.7.
• BC Hydro’s Initial Response to Government Review
Recommendations – October 2011 – New Appendix CC
• Uniform System of Accounts – New Appendix DD
• F12/F13 DSM Expenditures – New Appendix II
• Auditor General Report on Deferral Accounts – New Appendix GG
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Requested Order - Amendments
• Final average rate increases of 8 per cent for F2012 and 3.91 per cent for each of F2013 and F2014.
• Setting of the DARR at 2.5 per cent effective April 1, 2011 and continuing until at least April 1, 2014 (F2015).
• Approval of amended OATT rates effective April 1, 2011, 2012 and 2013.
• Deferral of increase in net Cost of Energy since March 2011 Application.
• Deferral of actual implementation costs of new outsourcing arrangements.
• Refunds of credit balances in regulatory accounts at the end of F11.
• Change in amortization period for past and future DSM costs to 15 years.
• Acceptance of DSM expenditure schedule for F12 and F13.
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Summary of Reductions
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$ million Total F12 – F14
Business Group Operating Cost Reductions -163
Increase in Forecast of Powerex Net Income -136
Higher PTP Allocation to Powerex -39
Impact of Lower Interest Rates -161
Reduction in Forecast taxes -14
Increase in Forecast Miscellaneous Revenues -26
Refund of Credit Balances in Regulatory Accounts -27
Other -10
Impact of Reductions in Forecast Capital Additions -54
Impact of Lower Actual F2011 Capital Additions -61
Impact of Change to DSM Amortization Period -101
Impact of Reductions in Forecast DSM Expenditures -7
Impact of Lower Actual F2011 DSM Expenditures -19
Total -819
Lower Operating Costs
• Reductions of net $163 million from March Application.
• Reductions from three different streams:
Workforce reductions Outsourcing Other operating cost reductions
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Operating Cost Reductions
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Operating Cost Reductions
Higher Trade Revenue
• Increased Powerex net income by $136 million over three years (F12-F14).
• Increase is a reflection of average Powerex net income over last five years.
• Powerex net income also reflects withdrawal of proposed change to PTP charges (additional $39 million).
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Lower Interest Rates
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Other revenue adjustments
• Reduction in forecast taxes ($14 million).
• Increase in forecast miscellaneous revenues ($26 million).
• Refund of credit balances in regulatory accounts ($27 million).
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Capital Additions – Presentation of IFRS Impact in Application and Amended Application
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Application: • F12-14 Capital expenditures and additions were presented in CGAAP, • IFRS impacts on amortization, IDC, rate base, ROE were separately shown in
Schedule 18, to reflect BC Hydro’s transition to IFRS.
Amended Application : • F12-14 Capital expenditures and additions shown on Schedule 13 are
presented in IFRS. • This reduces capital expenditures by $541 M and reduces capital additions by
$393 M over test period. See sections 6.3.2, 6.3.5.
• IFRS impacts on amortization, IDC, rate base, ROE are removed in Amended Schedule 18, and recognized through Amended Schedule 13 – Capital Expenditures and Additions.
Change in presentation has no impact on the revenue requirements over test
period.
Capital Additions – Reductions from Application – Section 6.3.5)
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New Table 6-C Capital Addition Reductions – Amended F12-F14 RRA
New Table 6-C presents the transition of F12-14 Capital Additions, from the original Application which was presented in CGAAP, to the Amended Application which is presented in IFRS. Also Includes:
• Changed circumstances: new information or project cost updates since Application • Risk based deferrals: project or program deferrals or re-prioritization • Managed reductions: includes cost management activities • See Section 6.3.5 for further discussion, New Table 6-D for list of projects & programs impacted.
Amended Appendices I and J
• Amended Appendix I - updated to reflect amended capital expenditures, with amended variance explanations.
• Amended Appendix J – updated to reflect change in project information, in service date, and total project cost forecasts.
• All updated or amended information is grey-shaded.
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DSM Impacts on Amended F12-14 RRA Revenue Shortfall
• Impact of change to DSM Amortization period from 10 to 15 Years -
($101) million reduction, see Appendix II, section 1.3.4
• Impact of reductions in forecast F12-14 DSM Expenditures - ($7) million reduction, see New Appendix II, section 3.3
• Impact of lower Actual F2011 DSM expenditures - ($19) million reduction, see New Appendix II,1.2
• Further discussion at DSM session on New Appendix II
Other Updates in Amended F12-14 RRA
• F12-14 Load Forecast, • F12-14 Revenue Forecast, • F12-14 Cost of Energy Forecast.
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Amended Load Forecast - (Section 3.2.2)
•Application - Energy Sales Forecast based on August 2010 Update of 2009 Load Forecast •Amended F12-14 RRA – based on March 2011 Update of December 2010 Load Forecast •December 2010 Load Forecast included in New Appendix FF, to present forecast methodology.
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Changes between Application and Amended Application due to: •Increase in load – primarily revised forecast for industrial customers •Decrease in DSM savings due to change in rate assumptions •Change in assumed real rate increases used in forecast (price elasticity) •See section 3.2.2 for further discussion
Amended Table 3-1 Energy Sales Forecast F2012 to F2014
•Reasons for change to forecast domestic revenues are similar to change in forecast domestic energy sales •See Section 3.3.3 and Amended Schedule 14.0, Appendix A for further details
New Table 3-F F2012-F2014 Domestic Revenues
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Amended F2012-14 Cost of Energy (Section 4.1.3)
Amended Table 4-1 Cost of Energy Summary
•The increase in forecast Cost of Energy over F12-14 is due to increases in forecast load, increases in forecast IPP supply and revised outage schedules. •Amended Schedule 4.0 provides further detail on forecast energy costs and sources of supply.
•BCH is proposing to defer $215.3 million related to the increase in forecast COE over test period, excluding the impact to COE of increased forecast energy sales and reclassification of 4 IPP Capital leases, •Deferred amount to be included in NHDA, See section 1.3.1.7.
Appendix II Chapter 1: Introduction Chapter 2: The Need for DSM Chapter 3: DSM Costs and Benefits Chapter 4: DSM Performance Management Attachment 1: Glossary of Terms and Acronyms Attachment 2: Load Resource Balance Attachment 3: Codes and Standards Overlap with DSM Attachment 4: Initiative Descriptions Attachment 5: DSM Plan Tables Attachment 6: Assumptions Attachment 7: DSM Evaluation, Measurement and Verification Attachment 8: Prior DSM Performance Reports submitted to the BCUC Attachment 9: BCUC Directives related to DSM
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Overview
Orders sought Need for DSM DSM expenditures DSM benefits Government review DSM amortization DSM performance management DSM risk management Productivity and process improvements
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Orders Sought (section 1.1)
Acceptance of the 2-year DSM expenditure schedule of $360.7 million as being in the public interest
Approval of a change in the amortization period for DSM
expenditures from 10 years to 15 years
F2012 ($ Million)
F2013 ($ Million)
2-Year Total ($ Million)
Programs 138.3 150.1 288.4
Rate Structures 5.5 4.7 10.2
Supporting Initiatives 31.1 31.0 62.1
Total 174.9 185.8 360.7
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Need for DSM (Figure II-2-1)
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
Firm
Ene
rgy
Capa
bilit
y (G
Wh)
Fiscal Year (year ending March 31)
Load Forecast Uncertainty Existing and Committed Resources Planned Resources
2010 Mid Load Forecast Before DSM* 2010 Mid Load Forecast After DSM*
Operating Planning
* including 3,000 GWh/yr of insurance starting F2021
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Closing the Load Resource Gap (Figure II-2-3)
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
Firm
Ene
rgy
Capa
bilit
y (G
Wh)
Fiscal Year (year ending March 31)
Load Forecast Uncertainty Existing and Committed Resources Planned Resources
2010 Mid Load Forecast Before DSM* 2010 Mid Load Forecast After DSM*
Operating Planning
* including 3,000 GWh/yr of insurance starting F2021
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Cost-Effectiveness (section 2.6)
DSM is a cost-effective alternative to new power supply and electricity infrastructure DSM programs $32/MWh BC Hydro’s Reference Energy Price $129/MWh
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Updated DSM Plan (section 3.2)
Continuing the same suite of initiatives from the 2008 LTAP, updated to reflect new information on costs, energy savings and plan performance
Avoided land and water impacts Reduced GHG emissions
Non-Energy Customer Benefits
Reduced maintenance costs
Alignment with B.C.’s Energy Objectives
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Government Review Recommendations (summary of Table II-3-6)
Recommendation BC Hydro Response
54 – Re-evaluate energy conservation programs
DSM Expenditures reduced $23 million
56 – Re-evaluate SMI in home display rebate program
The in-home display rebate program is being reviewed
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Persistence of DSM Program Savings (Figure II-3-4)
0
2
4
6
8
10
12
14
16
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F2002
F2003
F2004
F2005
F2006
F2007
F2008
F2009
F2010
F2011
F2012
F2013
F2014
F2015
Year
s
Historical Forecast
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Amortization of DSM Costs (section 3.7)
BC Hydro is requesting approval to change the amortization period of DSM costs from 10 to 15 years
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DSM Performance Management (Figure II-4-1)
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DSM Performance Tracking (Table II-4-3 extract)
DSM Program Key Performance Indicators
Leading Lagging
Residential Lighting •Participation of key retailers •Participants •Energy savings •Costs
Commercial New Construction
•Energy study agreements •Incentive agreements •Identified potential customer projects
•Energy savings •Costs
Industrial Power Smart Partner - Transmission
•Energy studies completed •Energy savings identified in completed energy studies •Energy manager agreements •Incentive agreements •Identified potential customer projects
•Energy savings •Costs
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Electricity Savings Confirmation – Large Projects (Figure II-4-2)
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Risk Mitigation (section 4.5)
Begins with identification and assessment of risks Risks are assessed and mitigated at the program, initiative, and
portfolio levels
Examples of risk mitigation tactics Codes and Standards: encourage government to expedite
enactment of regulations Rate Structures: redesign rate structures Programs: modify program designs to increase participation Portfolio: shift effort between initiatives or customer sectors
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Productivity Improvement (Figure II-4-3)
Num
ber o
f Pro
ject
s
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Process Improvements (section 4.6)
Internal and external focus Examples:
Development of Power Smart Partner Express
Integration of Renovation Rebate Program in LiveSmart BC
