BRITISH COLUMBIA UTILITIES COMMISSION BRITISH COLUMBIA ... · 5/23/2017 · Matthew Ghikas ....
Transcript of BRITISH COLUMBIA UTILITIES COMMISSION BRITISH COLUMBIA ... · 5/23/2017 · Matthew Ghikas ....
Matthew Ghikas
Direct 604 631 3191 Facsimile 604 632 3191
May 23, 2017 File No.: 301539.00014/14797
BY ELECTRONIC FILING British Columbia Utilities Commission 6th floor, 900 Howe Street Vancouver, BC V6Z 2N3 Attention: Patrick Wruck Commission Secretary and Manager Regulatory Services
Dear Sirs/Mesdames:
Re: Project No. 3698869 - BC Hydro F2017 - F2019 Revenue Requirements Application -BC Hydro’s Final Submission
I enclose for filing BC Hydro’s Final Submission in the Fiscal 2017 – Fiscal 2019 Revenue Requirements Application proceeding.
Yours truly,
FASKEN MARTINEAU DuMOULIN LLP [original signed by Matthew Ghikas]
Matthew Ghikas
MTG/pmw Enc.
340 Pages
301539.00014/91303997.1
BRITISH COLUMBIA UTILITIES COMMISSION
IN THE MATTER OF THE UTILITIES COMMISSION ACT
R.S.B.C. 1996, CHAPTER 473
and
BRITISH COLUMBIA HYDRO AND POWER AUTHORITY
FISCAL 2017 – FISCAL 2019 REVENUE REQUIREMENTS APPLICATION
Final Submissions of BC Hydro
May 23, 2017
FASKEN MARTINEAU DUMOULIN LLP: Attn: Matthew Ghikas and Chris Bystrom [email protected]; [email protected] (604) 631-3131
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TABLE OF CONTENTS
PART ONE: INTRODUCTION AND OVERVIEW .................................................................................................... 1
A. INTRODUCTION ........................................................................................................................... 1
B. SUBMISSION OVERVIEW AND KEY POINTS ................................................................................. 2
PART TWO: COMPREHENSIVE EVIDENTIARY RECORD AND REGULATORY PROCESS ........................................... 4
PART THREE: LEGAL FRAMEWORK HAS IMPLICATIONS FOR COMMISSION’S DETERMINATIONS ........................ 6
A. INTRODUCTION ........................................................................................................................... 6
B. 2013 10 YEAR RATES PLAN: RATE CAPS AND RATE SMOOTHING ............................................... 7
C. MANDATED RECOVERY OF SPECIFIED COSTS ............................................................................. 8
(a) Costs to Provide Reliable Electricity Service and Finance the Business are
Recoverable .................................................................................................................... 8
(b) Costs for Completed Extensions, Past Electricity Purchase Agreements and Smart
Meter and Infrastructure Program Are Recoverable ..................................................... 9
(c) Mining Customer Payment Plan................................................................................... 10
D. EXEMPTIONS AND COST RECOVERY FOR SPECIFIED PROJECTS, PROGRAMS,
CONTRACTS AND EXPENDITURES ............................................................................................. 11
E. MINISTER’S MANDATE LETTER SETS PRIORITIES FOR THE TEST PERIOD .................................. 11
F. BURRARD THERMAL GENERATING STATION IS ADDRESSED IN LEGISLATION .......................... 12
G. PARAMETERS ON DEMAND-SIDE MANAGEMENT EXPENDITURE SCHEDULE APPROVAL ........ 13
(a) Limitations on the Commission’s Order ....................................................................... 14
(b) Directions Regarding Financial Treatment ................................................................... 14
(c) Factors that Must be Considered by the Commission Under Section 44.2(5.1) .......... 15
(d) Rate Impacts Are a Key Consideration in the Demand-Side Management Plan
Public Interest Assessment .......................................................................................... 16
H. CONCLUSION AND REQUESTED FINDING ................................................................................. 18
PART FOUR: BC HYDRO IS MEETING THE CHALLENGE OF THE 2013 10 YEAR RATES PLAN ................................. 19
A. INTRODUCTION ......................................................................................................................... 19
B. BC HYDRO HAS INTENSIFIED ITS COST CONTROL EFFORTS ...................................................... 19
(a) BC Hydro’s Steps Before the Test Period ..................................................................... 20
(b) BC Hydro’s Additional Steps in Response to Reduced Forecast Revenues
Associated with Lower Load Growth Rate ................................................................... 21
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C. BC HYDRO IS FOCUSSING ON KEY PRIORITIES DURING THE TEST PERIOD ............................... 23
D. CONCLUSION AND REQUESTED FINDINGS ................................................................................ 25
PART FIVE: LOAD AND REVENUE FORECASTS ARE REASONABLE ..................................................................... 26
A. INTRODUCTION ......................................................................................................................... 26
B. COMMISSION AND GOVERNMENT ENDORSED THE LOAD FORECAST METHODOLOGY .......... 27
C. LOAD FORECAST BASED ON ROBUST METHODOLOGY AND APPROPRIATE INPUTS ................ 28
(a) Residential Sector Forecast Methodology ................................................................... 28
(b) Commercial and Light Industrial Sector Methodologies .............................................. 31
(c) Large Industrial Sector Methodology ........................................................................... 33
(d) Load Forecasting Methodology Accounts for Uncertainty in a Reasonable Manner .. 40
(e) Residential and Commercial / Light Industrial Forecasts Are Not Sensitive to
AMPC’s Suggested Changes in Economic Assumptions ............................................... 41
D. LNG LOAD FORECASTED IN A TRANSPARENT MANNER SUITABLE FOR THE NASCENT
INDUSTRY .................................................................................................................................. 41
E. LOAD FORECAST IS SUBJECT TO MULTIPLE LEVELS OF INTERNAL REVIEW .............................. 43
F. BC HYDRO UPDATED THE LOAD FORECAST TO REFLECT SIGNIFICANT DEVELOPMENTS ......... 43
G. ACTUAL SALES HAVE CLOSELY TRACKED THE MAY 2016 LOAD FORECAST .............................. 44
(a) Less than One Per Cent Variance During First Full Year of the Test Period ................. 44
(b) 2018 Integrated Resource Plan Will Include an Updated Load Forecast ..................... 46
H. RECENT DEVELOPMENTS REINFORCE REASONABLENESS OF THE LOAD FORECAST ................ 46
(a) Continuity in Key Drivers of Residential and Commercial / Light Industrial Sales ....... 46
(b) Positive Developments in the Large Industrial Sector ................................................. 47
(c) Low Carbon Electrification Load is Incremental to the May 2016 Load Forecast ........ 51
(d) Discounting the Load Forecast Based on Past Variances Would Be Unreasonable..... 54
I. RESPONSE TO AMPC’S TWO “CONCERNS” ABOUT THE MAY 2016 LOAD FORECAST .............. 56
(a) May 2016 Load Forecast Accounts for Price Elasticity in Industrial Sector ................. 56
(b) BC Hydro’s Test Period Growth Assumptions for the Oil and Gas Sector Are
Reasonable ................................................................................................................... 60
J. VARIANCES FROM THE LOAD FORECAST ARE CAPTURED IN REGULATORY ACCOUNT ............ 61
K. REVENUE FORECAST IS INDUSTRY STANDARD AND CONSISTENT WITH PAST PRACTICE......... 62
L. CONCLUSION AND REQUESTED FINDINGS ................................................................................ 62
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PART SIX: FORECAST COST OF ENERGY ........................................................................................................... 64
A. INTRODUCTION ......................................................................................................................... 64
B. FORECAST COST OF ENERGY REFLECTS HOW BC HYDRO PLANS AND OPERATES THE
SYSTEM ...................................................................................................................................... 65
(a) BC Hydro’s Energy Studies Are Robust and Designed for BC Hydro’s System ............. 65
(b) Appropriate Assumptions Regarding Electricity Purchases During Test Period .......... 67
C. REGULATORY ACCOUNTS ENSURE CUSTOMERS PAY ACTUAL COST OF ENERGY ..................... 72
(a) Cost of Energy Accounts Capture Both Load and Price-Related Variances ................. 73
(b) BC Hydro is Amenable to Deferring Electricity Purchase Agreement Accounting
Classification Variances ................................................................................................ 74
(c) Actual Cost of Energy Unaffected By Commission’s Determination of Forecast ......... 75
D. MANDATED COST RECOVERY FOR EXISTING ELECTRICITY PURCHASE AGREEMENTS .............. 75
(a) Direction No. 7 Covers Much of the Increase in Forecast Cost of Energy ................... 76
(b) BC Hydro Has Reduced Purchase Commitments Under Existing Agreements ............ 77
E. COMMISSION WILL REVIEW RENEWED AGREEMENTS ............................................................. 78
F. STANDING OFFER PROGRAM IS LEGISLATED ............................................................................ 80
G. CONCLUSION AND REQUESTED FINDINGS ................................................................................ 81
PART SEVEN: OPERATING EXPENSES .............................................................................................................. 82
A. INTRODUCTION ......................................................................................................................... 82
B. BC HYDRO LIMITED THE ANNUAL AVERAGE INCREASE IN BASE OPERATING COSTS ............... 83
C. BC HYDRO HAS AN EFFECTIVE OPERATING COST PLANNING APPROACH ................................ 85
(a) Top-Down / Bottom Up Iterative Operating Cost Planning ......................................... 85
(b) BC Hydro Tracks Progress Against Budget ................................................................... 87
D. INITIATIVES ARE IMPROVING HOW BC HYDRO OPERATES ....................................................... 87
(a) Smart Metering and Infrastructure Program Delivers Net Benefit to Ratepayers ...... 87
(b) Work Smart Program Introduces Process Improvements ........................................... 89
(c) Workforce Optimization Yields Optimal Mix of Internal and External Resources ....... 91
E. BUSINESS GROUP FTEs AND COSTS REFLECT RESTRAINT AND PRIORITIZATION ...................... 94
(a) BC Hydro Identified Savings Across the Corporation ................................................... 94
(b) Cost Increases Are Required to Support Key Priorities ................................................ 95
(c) Training, Development and Generation Business Group............................................. 96
(d) Transmission, Distribution and Customer Service Business Group ........................... 100
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(e) Capital Infrastructure Project Delivery Business Group ............................................. 103
(f) Operations Support Business Group .......................................................................... 106
(g) BC Hydro Has Maintained Consistent Performance Targets While Managing
Operating Costs .......................................................................................................... 109
(h) Maintenance Program Prioritization and Efficiencies................................................ 111
F. BC HYDRO’S COMPENSATION PROGRAM IS REASONABLE ..................................................... 112
(a) BC Hydro Has Limited Increases in Management and Professional Compensation .. 112
(b) Unionized Employees Compensated at Market Median Based on Total Rewards .... 114
(c) BC Hydro Introduced Strategies to Manage and Reduce Overtime .......................... 115
G. INSOURCING OF ABSBC FUNCTIONS HAS NO MATERIAL EFFECT ON TEST PERIOD
REVENUE REQUIREMENTS ...................................................................................................... 115
H. CONCLUSION AND REQUESTED FINDINGS .............................................................................. 117
PART EIGHT: CAPITAL EXPENDITURES AND ADDITIONS ................................................................................ 118
A. INTRODUCTION ....................................................................................................................... 118
B. BC HYDRO HAS A WELL-DEFINED CAPITAL PLANNING PROCESS ............................................ 119
(a) Step 1: Top-Down Strategic Direction and Capital Program Parameters .................. 120
(b) Step 2: Bottom-Up Planning and Portfolio Development by Asset Category ............ 122
(c) Step 3: Collaborative Prioritization Within Corporate Investment Framework ........ 124
(d) Senior Management and Board Review .................................................................... 126
(e) Capital Planning Is Integrated With Capital Delivery ................................................. 127
C. BC HYDRO REDUCED CAPITAL FORECAST TO REMAIN ON TRACK WITH THE 2013 10
YEAR RATES PLAN .................................................................................................................... 127
(a) BC Hydro Achieved a Material Reduction in Forecast Capital Expenditures and
Additions .................................................................................................................... 127
(b) BC Hydro Identified Reductions Across All Asset Categories Without Undue
Impacts on Asset Health, Reliability or Ability to Deliver on Strategic Objectives .... 129
D. PLANNED PROJECTS ADDRESS SHORT AND LONG-TERM REQUIREMENTS ............................ 136
(a) BC Hydro Has Provided Project-Specific Information ................................................ 136
(b) BC Hydro Will Adhere to Applicable Project Approval Requirements ....................... 137
(c) Site C Clean Energy Project Costs Will Be Reviewed in a Future Proceeding ............ 139
E. BC HYDRO DELIVERS CAPITAL PROJECTS EFFICIENTLY AND EFFECTIVELY .............................. 140
(a) Clear Organization and Accountabilities For Project Delivery ................................... 140
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(b) BC Hydro Has in Place Proper Governance, Oversight and Project Management .... 146
(c) BC Hydro Has Delivered its Capital Portfolio On Budget ........................................... 147
F. VARIANCE ACCOUNTS WILL BE IN PLACE ................................................................................ 147
G. CONCLUSION AND REQUESTED FINDINGS .............................................................................. 148
PART NINE: DEFERRAL AND OTHER REGULATORY ACCOUNTS ....................................................................... 149
A. INTRODUCTION ....................................................................................................................... 149
B. EXISTING ACCOUNTS SHOULD BE CONTINUED ...................................................................... 150
C. MAJORITY OF ACCOUNTS ARE APPROVED FOR TEST PERIOD AND DO NOT REQUIRE
CHANGES ................................................................................................................................. 151
D. OTHER ACCOUNTS SHOULD BE CONTINUED – SOME “AS IS” AND SOME WITH SCOPE
CHANGES ................................................................................................................................. 153
E. BC HYDRO IS PROPOSING APPROPRIATE RECOVERY MECHANISMS FOR ACCOUNTS
WITH NO ONGOING MECHANISM OR WITH CHANGES IN SCOPE .......................................... 160
(a) Rock Bay Remediation Recovery Mechanism ............................................................ 162
(b) Non-Current Pension Costs Regulatory Account (Proposed to be renamed the
Pension Costs Regulatory Account) Recovery Mechanism ........................................ 163
(c) First Nations Cost Regulatory Account Recovery Mechanism ................................... 165
F. INTEREST ON REGULATORY ACCOUNT BALANCES RECOGNIZES BC HYDRO’S CARRYING
COSTS ...................................................................................................................................... 167
G. CONCLUSION AND REQUESTED FINDING ............................................................................... 170
PART TEN: OTHER REVENUE REQUIREMENTS ITEMS ..................................................................................... 171
A. INTRODUCTION ....................................................................................................................... 171
B. REVENUE REQUIREMENTS REFLECTS APPROPRIATE DEPRECIATION RATES .......................... 171
(a) Commission Has Already Approved Almost All Depreciation Rates .......................... 171
(b) Proposed Depreciation Rates for the Burrard Facility Are Appropriate .................... 171
C. PRESCRIBED CAPITAL STRUCTURE, RETURN ON EQUITY AND INTEREST COST
RECOVERY ............................................................................................................................... 174
(a) Dividend Subject to a Specified Minimum Debt/Equity Ratio ................................... 174
(b) Return on Equity Must Yield Specified Distributable Surplus .................................... 175
(c) BC Hydro’s Interest Costs Are Recoverable ............................................................... 176
D. CONCLUSION AND REQUESTED FINDINGS .............................................................................. 177
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PART ELEVEN: TRANSMISSION REVENUE REQUIREMENTS ............................................................................ 178
PART TWELVE: DEMAND-SIDE MANAGEMENT ............................................................................................. 179
A. INTRODUCTION ....................................................................................................................... 179
B. BC HYDRO’S SIGNIFICANT AND BROAD INVESTMENT IN DEMAND-SIDE MANAGEMENT ..... 181
(a) BC Hydro’s Broad Investment in Demand-Side Management ................................... 181
(b) Portfolio Includes Measures for Low Income Households, Rental Accommodation
and Schools ................................................................................................................ 187
(c) Portfolio Provides Significant Energy And Capacity Savings And Other Benefits ...... 190
(d) The Portfolio Promotes British Columbia’s Energy Objectives .................................. 193
(e) BC Hydro Manages to Program Budgets and Responds to Changing
Circumstances ............................................................................................................ 195
C. CONTINUATION OF MODERATION STRATEGY IS APPROPRIATE ............................................. 197
(a) BC Hydro Assessed Three Plan Alternatives .............................................................. 197
(b) The Rate of Growth in Demand for Electricity has Slowed ........................................ 199
(c) Proposed Demand-Side Management Plan Keeps BC Hydro On Track to Meet
2013 10 Year Rates Plan Targets ................................................................................ 200
(d) Demand-Side Management Plan Achieves the 66 Per cent Target in the Clean
Energy Act .................................................................................................................. 201
(e) Provides Customers with Broad Access to Programs and Substantial Bill Savings
Opportunities ............................................................................................................. 202
(f) Moderation Strategy Results in Limited Missed Opportunities ................................. 202
(g) BC Hydro Maintains the Ability to Ramp Up When Additional Resources are
Needed ....................................................................................................................... 203
D. BC HYDRO’S CHANGES TO THE DEMAND SIDE MANAGEMENT PLAN ARE IN THE
PUBLIC INTEREST ..................................................................................................................... 206
(a) Responding to Expanded Energy Management Scope and Changing Customer
Needs and Expectations ............................................................................................. 207
(b) Productivity Improvements and Service Enhancements ........................................... 210
(c) Use of Cost Effectiveness Screens to Prioritize Spending .......................................... 211
(d) Discontinuing Some Programs is Reasonable ............................................................ 212
E. CODES AND STANDARDS ACTIVITIES ARE COST EFFECTIVE .................................................... 217
(a) BC Hydro’s Significant Support for Codes and Standards .......................................... 218
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(b) Cost-Effective Under Various Tests ............................................................................ 221
(c) Reasonable Approach to Determining Savings .......................................................... 221
F. CAPACITY FOCUSED DEMAND SIDE MANAGEMENT IS IN THE PUBLIC INTEREST .................. 223
(a) Capacity Focused Pilot Activity Overview .................................................................. 223
(b) Capacity Focused Demand-Side Management Is a Potential Lower Cost Capacity
Resource for Base and Contingency Resource Planning ............................................ 225
(c) Capacity Focused Demand-Side Management Can Alleviate Local Constraints ........ 228
(d) Capacity Focused Demand-Side Management is Part of a Cost-Effective Portfolio .. 229
(e) BC Hydro is Proceeding Prudently with its Capacity Focused Pilots .......................... 230
(f) Pilots are Necessary to Assess Capacity Focussed Demand-Side Management ........ 231
(g) Advancement of Capacity Focused Demand-Side Management is Supported by
Customers, Government, System Needs and BC Hydro’s Priorities .......................... 237
(h) Conclusion regarding Capacity Focused Demand-Side Management ....................... 239
G. BC HYDRO IS ADDRESSING MARKET BARRIERS IN NON-INTEGRATED AREAS AND FIRST
NATIONS COMMUNITIES ........................................................................................................ 239
(a) BC Hydro is Addressing Barriers to Participation In Existing Programs ..................... 240
(b) BC Hydro is Investing in Pilot Activities to Improve Access ....................................... 240
(c) Work with Specific First Nations Communities .......................................................... 245
(d) Past Discussions and Desire for Ongoing Process ...................................................... 246
(e) Increase in Reporting Not Required ........................................................................... 247
H. THE DEMAND-SIDE MANAGEMENT PLAN IS COST-EFFECTIVE UNDER THE DEMAND-
SIDE MEASURES REGULATION ................................................................................................ 248
(a) Summary of the Requirements of the Demand-Side Measures Regulation .............. 249
(b) Test Results Presented in Accordance with Requirements of Demand-Side
Measures Regulation ................................................................................................. 250
(c) Test Results Demonstrate Cost Effectiveness ............................................................ 251
(d) Supporting Initiatives Are Part of Cost Effective Tools and Portfolio ........................ 252
(e) Capacity Focused Demand-Side Management is Part of a Cost-Effective Portfolio .. 253
(f) Evidence filed in Information Requests Supports Cost Effectiveness Test Results ... 253
I. BC HYDRO’S EVALUATION, MEASUREMENT AND VERIFICATION PROCESSES ARE
GUIDED BY INDUSTRY STANDARDS AND PROTOCOLS AND ARE NEUTRAL AND
UNBIASED ................................................................................................................................ 254
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(a) Planned Evaluation, Verification And Measurement Activities Guided by Industry
Best Practice ............................................................................................................... 255
(b) Neutral and Unbiased Verification and Evaluation .................................................... 257
J. CONCLUSION AND REQUESTED FINDINGS .............................................................................. 258
PART THIRTEEN: CONCLUSION AND ORDER SOUGHT ................................................................................... 260
A. ADJUSTMENTS TO THE ORDERS SOUGHT IN THE APPLICATION............................................. 260
B. RESTATED FORM OF ORDER.................................................................................................... 263
C. RATES ARE JUST AND REASONABLE AND DEMAND-SIDE MANAGEMENT PLAN IS IN
THE PUBLIC INTEREST.............................................................................................................. 264
APPENDIX A: EVIDENCE IN SUPPORT OF CAPITAL PROJECTS ADDRESSED IN INFORMATION REQUESTS
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PART ONE: INTRODUCTION AND OVERVIEW
A. INTRODUCTION
1. At the outset of this proceeding, BC Hydro expressed its desire to ensure that the
public and the British Columbia Utilities Commission (“Commission”) would have a meaningful
opportunity to review BC Hydro’s revenue requirements for the test period.1 The evidence
filed, and the process undertaken by the Commission, have provided that opportunity. BC
Hydro has been transparent in discussing its operations and pragmatic in responding to
questions from participants. The Application, BC Hydro’s responses to information requests
and the Rebuttal Evidence provide a comprehensive evidentiary basis for determing this
Application.
2. BC Hydro’s evidence makes a compelling case for granting the approvals sought
in the Application, which are generally outlined in Chapter 1 of the Application2, but with some
revisions during the process that are identified in Part Thirteen of this Final Submission. A
revised form of Final Order is also included in Part Thirteen. The requested permanent rate
increases of 4 per cent in fiscal 2017, 3.5 per cent in fiscal 2018, and 3 per cent in fiscal 2019
reflect the rate caps specified in Direction No.7 to the British Columbia Utilities Commission
(“Direction No. 7”).3 The forecast revenue requirements, a portion of which is being
transferred to the Rate Smoothing Regulatory Account for recovery in the final years of the
2013 10 Year Rates Plan, reflect BC Hydro’s significant effort to manage and control costs in
order to deliver on the 2013 10 Year Rates Plan. The forecast revenue requirements in the test
period represent BC Hydro’s reasonable cost of investing to meet system requirements and
providing safe and reliable service to customers.
1 Exhibit B-4; Exhibit B-11.
2 See Exhibit B-1-1, section 1.7, p.1-43 through 1-46.
3 Direction No. 7, as amended by Order in Council Nos. 539 and 590, was issued pursuant to Section 3(1) of the
Utilities Commission Act. Direction No. 6 had prescribed BC Hydro’s rate increases for fiscal 2015 and fiscal 2016. These directions are included in Appendix C to the Application.
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3. BC Hydro’s requested demand-side management expenditure schedule, totalling
$361.1 million4 over the test period, is in the public interest. It reflects a modernized and more
cost-effective Demand-Side Management Plan that continues broad demand-side management
and is responsive to changing system needs and the 2013 10 Year Rates Plan. At the same time,
BC Hydro retains the ability to ramp up demand-side management in the future, as needed.
4. Granting the approvals sought will position BC Hydro to deliver on the 2013 10
Year Rates Plan, balancing customers’ interests in both low rates and investment in safe and
reliable service.
B. SUBMISSION OVERVIEW AND KEY POINTS
5. This Final Submission is organized around the following key points:
Part Two: The Commission is well positioned to determine the issues based on a
complete evidentiary record that has been tested by Commission Staff and many
interveners.
Part Three: Rate caps, directions mandating cost recovery, and other aspects of
the legislative framework circumscribe the Commission’s discretion in this
proceeding and support BC Hydro’s requested orders.
Part Four: BC Hydro is investing in important near-term priorities and long-term
requirements while controlling costs to keep rates low and predictable. In this
way, BC Hydro is advancing the dual objectives of the 2013 10 Year Rates Plan.
Part Five: BC Hydro’s Load Forecast and Revenue Forecast are reasonable, being
the product of robust, established methodologies and reliable inputs.
4 As a result of a shift in timing in BC Hydro’s forecast expenditures for the Thermo-Mechanical Pulp program, BC
Hydro’s proposed section 44.2 demand-side management expenditure schedule for the test period has been reduced by $13.9 million, from a total of $375 million to a total of $361.1 million. See BC Hydro’s response to BCUC IR 2.314.3.
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Part Six: BC Hydro’s forecast Cost of Energy is driven primarily by costs
associated with Energy Purchase Agreements pre-dating fiscal 2017, for which
cost recovery is mandated. The Commission will conduct public interest reviews
of future Electricity Purchase Agreements under section 71 of the Act. The Cost
of Energy Deferral Accounts ensure that customers only pay the actual cost of
energy.
Part Seven: BC Hydro’s forecast operating expenses reflect careful prioritization
to address safety, reliability and other strategic objectives, and also BC Hydro’s
extensive efforts to control costs.
Part Eight: BC Hydro has planned forecast capital spending in the test period to
balance the objectives of funding needed investments in safety, reliability and
other strategic objectives, and keeping rates low and predictable.
Part Nine: Many of BC Hydro’s deferral and other regulatory accounts have been
previously approved by the Commission and are required by Direction No. 7. BC
Hydro’s proposals to extend, modify, apply interest or establish recovery
mechanisms for some accounts are just and reasonable.
Part Ten: The most significant Other Revenue Requirement Items flow from the
legislative framework and prior Commission orders.
Part Eleven: BC Hydro’s Transmission Revenue Requirement reflects the revenue
reasonably required for the safety and reliability of the transmission system.
Part Twelve: The proposed demand-side management expenditure schedule is
in the public interest. It enables broad and cost-effective demand-side
management, while recognizing the reduced rate of demand growth in the short-
term and the need to meet the rate targets of the 2013 10 Year Rates Plan.
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PART TWO: COMPREHENSIVE EVIDENTIARY RECORD AND REGULATORY PROCESS
6. The Commission is well positioned to determine the issues based on a complete
evidentiary record that has been tested by Commission Staff and many interveners.
7. BC Hydro filed a large amount of evidence supporting its requested orders. BC
Hydro’s Application contained a significant amount of information about BC Hydro’s business
and revenue requirements. It provided context, including discussion of past work to reduce
costs and the implications of the 2013 10 Year Rates Plan.5 It explained the legislative
framework and how it impacts BC Hydro’s revenue requirements and rates.6 The Application
described BC Hydro’s load and revenue forecasting methodologies7, planning and budgeting
processes, and cost control and oversight mechanisms. BC Hydro identified its key priorities for
the test period, and the benefits and costs of pursuing those priorities.8 BC Hydro also
described a number of specific steps being taken to remain on track to meet the objectives in
the 2013 10 Year Rates Plan.9 BC Hydro supplemented the Application with: (i) approximately
60 responses to information requests posed by interveners in the BC Hydro Rate Design
Application proceeding10; and (ii) additional information on capital projects in a format desired
by Commission Staff.11 BC Hydro responded to more than 3400 information requests from
multiple parties in the first two rounds, 2,144 in round one12 and 1,288 in round two.13 It filed
Rebuttal Evidence and responded to additional 268 information requests on its Rebuttal
Evidence.
5 E.g., Exhibit B-1-1, Application, Chapter 1.
6 E.g., Exhibit B-1-1, Application, Chapter 2.
7 E.g., Exhibit B-1-1, Application, Chapters 3 (Load and Revenue Forecasts) and 4 (Cost of Energy).
8 E.g., Exhibit B-1-1, Application, Chapters 5 (Operating Expenses) and 6 (Capital Expenditures and Additions).
9 E.g., Exhibit B-1-1, Application, Chapters 1, pp. 1-16 through 1-18.
10 Exhibit B-5, pp. 1-2.
11 Exhibit B-6.
12 Exhibits B-8, B-9, B-9-1, B-9-1-1, B-9-2, B-10, B-10-1.
13 Exhibit B-13, B-14, B14-1, B14-1-1, B-14-2, B-15, B-15-1, B-15-2, B-15-3.
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8. Commission Staff cited the quality of BC Hydro’s written evidence in expressing
the view that the Application could be addressed in its entirety in a written proceeding.14 The
Commission Panel echoed this assessment in its January 27, 2017 procedural order Reasons for
Decision:
First, the Panel agrees with BC Hydro that the quality and breadth of the evidence on the record is a significant consideration in deciding whether or not an oral hearing is required. To date in this proceeding, the Panel notes the high quality and depth of the evidence on the record. The Panel also notes there were approximately 2,100 IRs in the first round and a further 1,300 in the second round.
The Panel recognizes that BC Hydro has taken a pragmatic approach to answering IRs. Further, for the most part, the interveners have focused their IRs on the three year test period, and have generally proceeded consistently with the legislative parameters which, as pointed out by BC Hydro at PC No. 2, allowed it to focus its efforts on the matters that are important to the Application.15
9. The 17 interveners in this process included several individuals, representatives of
all three major customer segments, environmental groups, customers in non-integrated areas,
the union representing a significant portion of BC Hydro employees, and a group representing
Independent Power Producers.
10. The remainder of this Final Submission outlines why the evidence makes a
compelling case for granting the approvals sought in the Application.
14
Procedural Conference No. 2 Transcript, p.373. 15
Exhibit A-18, Reasons for Decision for Order No. G-7-17, pp.7-8.
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PART THREE: LEGAL FRAMEWORK HAS IMPLICATIONS FOR COMMISSION’S DETERMINATIONS
A. INTRODUCTION
11. Chapter 2 of the Application details the regulatory and legal framework, which
has a number of implications for the Commission’s determinations in this proceeding. In this
Part of the Final Submission, BC Hydro highlights several points:
First, rate increases are capped during the test period, and the balance of BC
Hydro’s revenue requirements must be transferred to the Rate Smoothing
Regulatory Account.
Second, the Commission must allow BC Hydro to recover a number of specified
costs included in BC Hydro’s forecast revenue requirements.
Third, the Clean Energy Act has exempted from provisions of the Utilities
Commission Act a number of projects, programs, contracts and expenditures
that are reflected in BC Hydro’s revenue requirements in the test period.
Fourth, the Minister’s Mandate Letter sets out priorities for the test period.
Fifth, regulations address the re-purposing of the Burrard Facility and recovery of
associated costs.
Sixth, there are legislated parameters around the Commission’s public interest
review of BC Hydro’s demand-side management expenditure schedule.
12. Certain directions relating to Cost of Energy, operating expenses, capital and
demand-side management are also addressed in later parts of this Final Submission.
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B. 2013 10 YEAR RATES PLAN: RATE CAPS AND RATE SMOOTHING
13. The 2013 10 Year Rates Plan, described in Chapter 1 of the Application, balances
the objectives of keeping rates low and predictable and funding needed investments.16
Direction No. 7 implements components of the 2013 10 Year Rates Plan in part by (i) capping
the rates during the test period at 4 per cent in fiscal 2017, 3.5 per cent for fiscal 2018 and 3
per cent in fiscal 2019, and (ii) directing that the balance of BC Hydro’s forecast revenue
requirements in these years be recorded in the Rate Smoothing Regulatory Account. Direction
No. 7 provides:
9 (1) When regulating and setting rates for the authority for F2017, F2018 and F2019, under sections 4, 5, 6, 7, 9 (2), 10 (3) and 11 of this direction, the commission must not allow the rates to increase by more than 4% in F2017, 3.5% in F2018 and 3% in F2019, on average, compared to the rates of the authority immediately before the increase.
(2) If the base line rate change exceeds 4% in F2017, 3.5% in F2018 or 3% in F2019, the commission must order the authority to defer to the rate smoothing regulatory account the amount that is determined by subtracting the amount in paragraph (b) from the amount in paragraph (a)
(a) the forecast revenue that the authority would have earned under a base line rate change, and
(b) the forecast revenue that the authority is expected to earn under this direction.
14. BC Hydro’s forecast revenue requirements and forecast additions to the Rate
Smoothing Regulatory Account are summarized in Table 1-8 of the Application (the amounts
will be updated in BC Hydro’s compliance filing to reflect developments during the
proceeding).17 In the absence of the caps, BC Hydro would have proposed an 8.9 per cent
increase for fiscal 2017, 5.0 per cent for fiscal 2018 and 3.0 per cent for fiscal 2019.18 The case
16
Exhibit B-1-1, Application, p. 1-16. 17
Exhibit B-1-1, Application, p. 1-45. 18
Exhibit B-1-1, Application, p. 1-17.
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for approving the forecast revenue requirements, and for approving rates at the level of the
caps, is demonstrated by BC Hydro’s significant efforts to manage and control its costs and
deliver on the 2013 10 Year Rates Plan covering fiscal years 2015 to 2024. BC Hydro has
remained on track with the 2013 10 Year Rates Plan despite forecasting approximately $3.5
billion less customer revenue over that period compared to the assumptions at the time the 10
Year Rates Plan was announced.19 BC Hydro`s efforts extend to all areas of the corporation,
including Cost of Energy, operating expenses, capital, and financing costs. Those efforts are
described throughout the evidence, and are highlighted in this Final Submission.
C. MANDATED RECOVERY OF SPECIFIED COSTS
15. The Commission must, by virtue of various regulations, allow BC Hydro to
recover a number of specified costs that are reflected in BC Hydro’s revenue requirements.
(a) Costs to Provide Reliable Electricity Service and Finance the Business are
Recoverable
16. Direction No. 7 directs the Commission to allow BC Hydro to recover costs
incurred to provide reliable electricity service and finance its operations. Section 4(1) states in
part:
4 Subject to section 7, in regulating and setting rates for the authority, the commission must ensure that those rates allow the authority to collect sufficient revenue in each fiscal year to enable the authority to
(a) provide reliable electricity service,
(b) meet all of its debt service, tax and other financial obligations, …
17. The costs associated with “provid[ing] reliable electricity service” include the
Cost of Energy, operating costs and capital costs addressed, respectively, in Chapters 4, 5 and 6
of the Application. Section 4(b) of Direction No. 7 addresses BC Hydro’s interest expense, tax
19
Exhibit B-1-1, Application, pp.1-1 and 1-2.
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expense, Net Income and return on equity, all of which are addressed in Chapter 8 of the
Application.
(b) Costs for Completed Extensions, Past Electricity Purchase Agreements and
Smart Meter and Infrastructure Program Are Recoverable
18. In addition to the broader cost recovery requirements in section 4 of Direction
No. 7, section 11 includes more specific prohibitions on disallowing costs. Section 11 states:
11 When setting rates for the authority under the Act, the commission must not disallow for any reason the recovery in rates of the costs that were incurred by the authority or Powerex Corp. in consequence of decisions of either with respect to
(a) the construction of extensions to the authority’s plant or system that come into service before F2017,
(b) energy supply contracts entered into before F2017,
(c) the Rock Bay settlement,
(d) the First Nations settlements,
(e) the California settlements,
(f) the Burrard costs, and
(g) the costs deferred to the SMI regulatory account.
19. BC Hydro’s Application reflects the above costs applicable to the test period.
The costs related to (a) the construction of extensions to the authority’s plant or system that
come into service are included in amortization expense in Appendix A, Schedule 7.0. Any
related Contributions are shown in Appendix A, Schedule 11.0, and any related Finance Charges
are included in Appendix A, Schedule 8.0.
20. Cost related to energy supply contracts are included in Appendix A, Schedule 4.0.
BC Hydro’s response to BCUC IR 1.18.2 demonstrates that on average over the test period, 97
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per cent of the energy purchased from Independent Power Produces relates to energy supply
contracts entered into before fiscal 2017 that are recoverable by virtue of Direction No.7. The
confidential version of that response translates that volume to a cost of energy.
21. The recovery of costs related to items (c) to (g) over the test period are included
in Appendix A, Schedules 2.1 and 2.2 in the regulatory account in which the costs were deferred
(e.g., recovery of costs related to California settlements are included in recovery amounts
shown for the Trade Income Deferral Account, Burrard costs as defined in Direction No. 7 are
included in the recovery amounts shown for the Non-Heritage Deferral Account).
(c) Mining Customer Payment Plan
22. The Direction to the British Columbia Utilities Commission Respecting Mining
Customers20 directs the Commission to permit BC Hydro to establish the Mining Customer
Payment Plan. Under the Plan, qualifying mining customers can temporarily defer payment of a
portion of their electricity bills. The load associated with mining customers that remain in
operation, and the related revenues BC Hydro receives from these customers, benefit all
customers.21 The net effect of the Mining Customer Payment Plan program as it relates to
interest is a reduction in forecast finance charges in each year of the test period because
forecast interest income from unpaid amounts exceeds forecast interest costs related to the
program.22
23. No amounts receivable from customers participating in the Mining Customer
Payment Plan Program have become impaired; therefore, there have been no amounts
deferred to the Mining Customer Payment Plan Regulatory Account.23
20
Order in Council No. 123, dated February 29, 2016, is included in Appendix C of the Application. 21
Exhibit B-15, BCOAPO IR 2.142.1. 22
Exhibit B-15, BCOAPO IR 2.142.1; Exhibit B-9, BCUC IR 1.145.2. Section 3(3) directs the Commission to “allow the authority to recover in rates, over a period determined by the authority, the amounts in the [Mining Customer Payment Plan Regulatory Account]”.
23 Exhibit B-10, BCOAPO IR 1.42.1.
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24. In fact, commodity prices have increased to the point where mining customers
participating in the Mining Customer Payment Plan program have been required to make some
repayments of their unpaid balances in recent months.24
D. EXEMPTIONS AND COST RECOVERY FOR SPECIFIED PROJECTS, PROGRAMS,
CONTRACTS AND EXPENDITURES
25. Section 7 of the Clean Energy Act exempts a number of projects, programs,
contracts and expenditures from the requirement to obtain Commission public interest
approval. The exemption includes the Standing Offer Program, Mica Units 5 and 6, Revelstoke
Unit 6, and the Northwest Transmission Line. The reasonable costs (i.e., amortization or
expense) associated with those projects, programs, contracts and expenditures that affect the
test period revenue requirements are recoverable by virtue of section 4(c) of Direction No. 7.
E. MINISTER’S MANDATE LETTER SETS PRIORITIES FOR THE TEST PERIOD
26. The Minister’s March 14, 2016 Mandate Letter, included in Appendix D of the
Application, sets a number of priorities for the test period. It states in part:
Government provided the following mandate direction to BC Hydro under the Hydro and Power Authority Act:
Provide reliable, affordable, clean electricity throughout British Columbia, safely. To achieve this mandate, BC Hydro is directed to take the following strategic actions:
Continue to implement the 2013 10 Year Rates Plan to keep electricity rates low and predicable by optimizing resources and advancing its Revenue Requirements and Rate Design Applications.
Deliver your overall capital plan portfolio on time and on budget to maintain the reliability of the system, support British Columbia’s economic growth and meet the needs of customers.
24
Exhibit B-14-2, BCUC IR 2.197.3 (Revised).
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Deliver the Site C project on time and on budget and ensure First Nations and local communities have the ability to participate in economic development opportunities arising from the construction of the project.
Work with Clean Energy BC to identify further opportunities for clean energy producers in British Columbia.
Improve customer satisfaction by providing timely and responsive service and exploring innovative energy conservation solutions such as load curtailment rates.
Implement the five-year safety plan to ensure the safety of your workforce and the public.
27. BC Hydro’s priorities for the test period, which are discussed in Part Four below,
reflect the Minister’s directives. They have implications for operating expenses, capital, Cost of
Energy, and demand-side management expenditures, which are addressed later in this Final
Submission.
F. BURRARD THERMAL GENERATING STATION IS ADDRESSED IN LEGISLATION
28. Mr. Landale’s primary focus in this proceeding has been the Burrard Thermal
Generating Station. In his procedural submission, Mr. Landale indicated that he will be
“petitioning the commission Panel to recommend to the British Columbian Government the
removal of the BTP [Burrard Thermal Plant] and the BTGP [Burrard Thermal Generating Plant]
and the new BSCP [Burrard Synchronous Condense Facility] from the three noted pieces of
Legislation and Directions.”25 BC Hydro submits that the Commission’s jurisdiction is defined by
existing legislation. It does not include advising Government on amendments to legislation in
the manner desired by Mr. Landale. The Commission confirmed this point in procedural Order
No. G-7-17.26
25
Exhibit C 15-8. 26
Exhibit A-18, p.12: “The Panel agrees with BC Hydro that the Commission’s jurisdiction is defined by the existing legislation and it does not include advising Government on amendments to legislation in the manner desired by Mr. Landale.”
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29. The existing legislation addresses the re-purposing of Burrard Thermal
Generating Station and rate treatment. Direction No. 7 provides that:
The Commission must grant permission to BC Hydro under section 41 of the
Utilities Commission Act to cease operating those portions of Burrard Thermal
Generating Station that are not required for transmission support services;
The Commission “must, in regard to the non-heritage deferral account, allow the
authority to … (ii) defer to that account the Burrard costs”; and
The Commission “must not disallow for any reason the recovery in rates of the
costs that were incurred by the authority…in consequence of decisions of either
with respect to…the Burrard costs”.
30. On December 29, 2016, the Commission approved BC Hydro’s application under
section 41 of the Utilities Commission Act for permission to permanently cease operating those
portions of Burrard Thermal Generating Station that are not required for transmission support
services.27
31. Mr. Landale’s submissions on depreciation rates for the Burrard Facility assets
are addressed in Part Ten of this Final Submission.
G. PARAMETERS ON DEMAND-SIDE MANAGEMENT EXPENDITURE SCHEDULE APPROVAL
32. BC Hydro filed its demand-side measures expenditure schedule pursuant to
subsection 44.2(1)(a) of the Utilities Commission Act. The Utilities Commission Act places
parameters on the Commission’s discretion to make orders regarding a demand-side
management expenditure schedule, directs the financial treatment of the expenditures, and
sets out factors that must be considered when reviewing BC Hydro’s proposed expenditure
schedule.
27
Order No. G-198-16.
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(a) Limitations on the Commission’s Order
33. Subsection 44.2(3) of the Utilities Commission Act provides that the Commission
must accept an expenditure schedule if the Commission considers that making the
expenditures referred to in the schedule would be in the public interest, or reject the schedule.
Alternatively, the Commission may accept or reject a part of the expenditure schedule.
34. The Commission recently commented on the extent of its discretion when
accepting or rejecting a demand-side measures expenditure schedule in its March 28, 2017
Report to the Government of British Columbia on the Impact of BC Hydro and FortisBC’s
Residential Inclining Block Rates. As stated in the report, section 44.2 does not provide the
Commission with the authority to direct BC Hydro to file a demand-side management
expenditure schedule, make additions to a demand-side management expenditure schedule or
change the design of a particular demand-side management program. BC Hydro agrees with
this interpretation.28
(b) Directions Regarding Financial Treatment
35. The financial treatment of BC Hydro’s demand-side measure expenditures are
also subject to directions from government, as follows:
Recovery in rates of the expenditures on the Thermo-Mechanical Pulp Program
is required by the Direction to the British Columbia Utilities Commission
Respecting the Authority’s TMP Program.29 In addition, this direction specifies
that thermal-mechanical pulping program costs are to be deferred to BC Hydro’s
Demand-Side Management Regulatory Account. The Commission must
28
Exhibit B-9, BCUC IR 1.167.3. 29
B.C. Reg. 139/2015. This Direction is reviewed in Chapter 2 of the Application and a copy is provided in Appendix CC.
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therefore accept the $41.9 million30 included in the proposed expenditure
schedule for this program.
Pursuant to Direction No. 7, BC Hydro’s development, implementation and
administration costs for demand-side measures are recorded in the Demand-
Side Management Regulatory Account and amortized over 15 years.31
36. Given the directions above, this Final Submission does not address further the
expenditures on the Thermo-Mechanical Pulp Program or the financial treatment of BC Hydro’s
expenditures on demand-side measures.
(c) Factors that Must be Considered by the Commission Under Section 44.2(5.1)
37. Section 44.2(5.1) of the Utilities Commission Act requires the Commission to
consider a number of factors in determining whether to accept BC Hydro’s proposed demand-
side measures expenditure schedule. The factors, and where each is addressed in the evidence
and this Final Submission, are outlined below:
The interests of persons in British Columbia who receive or may receive service
from BC Hydro: This is an overarching consideration, which is addressed by BC
Hydro’s evidence in Chapter 10 of the Application and supporting Appendices,
responses to information requests and this Final Submission.
British Columbia’s energy objectives, as set out in section 2 of the Clean Energy
Act: Addressed in Section 10.3.6 of the Application, related responses to
information requests, and Part Twelve of this Final Submission.
An applicable Integrated Resource Plan approved under section 4 of the Clean
Energy Act: Addressed in Section 10.3 and Appendix BB of the Application,
30
Exhibit B-14, BCUC IR 2.314.3 updated the expenditures on the Thermo-Mechanical Pulp program forecast for the test period. BC Hydro’s compliance filing will reflect the update.
31 Exhibit B-9, BCUC IR 1.183.4.1.
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related responses to information requests, and Part Twelve of this Final
Submission below.
The extent to which the demand-side measures are cost effective within the
meaning prescribed by the Demand-Side Measures Regulation: Addressed in
Sections 10.3.7 and 10.4.4 of the Application, related responses to information
requests, and Part Twelve of this Final Submission below.
(d) Rate Impacts Are a Key Consideration in the Demand-Side Management Plan
Public Interest Assessment
38. BC Hydro’s proposed Demand-Side Management Plan has been modernized and
continues the moderation strategy recommended in the 2013 Integrated Resource Plan for
three more years. The moderation strategy is important to achieving the objectives of the 2013
10 Year Rates Plan as it avoids a cumulative rate impact of approximately 2.7 per cent by the
end of the fiscal 2020 to fiscal 2024 period compared to the outlook forecast in the 2013
Integrated Resource Plan.32 Customer rate impacts and the 2013 10 Year Rates Plan are
relevant to the public interest, and must be considered by the Commission in assessing the
proposed demand-side management expenditure schedule.
39. The Shareholder’s Letter of Expectations33 provides direction to BC Hydro to
“continue to implement the 10 Year Plan to keep electricity rates low and predictable by
optimizing resources and advancing its Revenue Requirements and Rate Design Applications.”34
Aspects of the 2013 10 Year Rates Plan are also required by Directions No. 6 and No. 7, as well
as Order in Council No. 590.35 Specific actions by Government to achieve the 2013 10 Year
Rates Plan include Order In Council Nos. 095, 589 and 590, concerning BC Hydro’s dividend
32
Exhibit B-15, CEC IR 2.143.3. 33
Exhibit B-1-1, Appendix D. 34
Exhibit B-15, BCSEA IR 2.64.1. 35
Exhibit B-15, BCSEA IR 2.64.1.
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payable to the Province and the amount of BC Hydro’s distributable surplus.36 Given the
obligations on BC Hydro and the substantial policy and legal direction from Government in
support of the 2013 10 Year Rates Plan, the 2013 10 Year Rates Plan must be a consideration in
the Commission’s public interest determination.
40. The Commission is also obligated under section 44.2 of the Utilities Commission
Act to take into consideration B.C. Energy Objectives, which include the objective “to ensure
the authority’s rates remain among the most competitive charged by public utilities in North
America.”37 This objective is reflected in BC Hydro’s Service Plan.38 The 2013 10 Year Rates
Plan dovetails with this objective.
41. The public interest determination is distinct from the ratepayer impact measure
or “RIM” test regarding the cost-effectiveness of demand-side measures. The Demand-Side
Measures Regulation precludes the Commission from determining that a proposed demand-
side measure is not cost effective on the basis of the result obtained by using the ratepayer
impact measure test. Likewise, BC Hydro does not use the ratepayer impact measure test in
assessing cost-effectiveness.39 However, the Commission has previously found that “the rate
impact from demand-side management spending is a relevant consideration for the public
interest….”40
42. The consideration of rate impacts and the 2013 10 Year Rates Plan supports the
proposed Demand Side Management Plan, which mitigates the rate impacts from the level of
spending in the outlook included in the 2013 Integrated Resource Plan.41 This is discussed
further in Part Twelve of the Final Submission.
36
Exhibit B-1-1, Appendix C; Exhibit B-2; Exhibit B-15, BCSEA IR 2.64.1. 37
Clean Energy Act, section 2(f). 38
Exhibit B-1-1, Appendix E, pp. 9-10. 39
Exhibit B-10, BCSEA IR 1.32.3. 40
British Columbia Utilities Commission Decision, In the Matter of FortisBC Inc. 2012-2013 Revenue Requirements and Review of 2012 Integrated System Plan, August 15, 2012, p. 133.
41 Exhibit B-15, CEC IR 2.143.3.
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H. CONCLUSION AND REQUESTED FINDING
43. The Commission should find that BC Hydro’s Application and requested orders
reflect the governing regulatory and legal framework, the 2013 10 Year Rates Plan, directions to
allow cost recovery, and the Minister’s Mandate Letter.
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PART FOUR: BC HYDRO IS MEETING THE CHALLENGE OF THE 2013 10 YEAR RATES PLAN
A. INTRODUCTION
44. The 2013 10 Year Rates Plan balances the objectives of keeping rates as low as
possible and funding needed investments.42 The Minister’s Mandate Letter directs BC Hydro to
continue to implement the 2013 10 Year Rates Plan to keep electricity rates low and
predicable.43 Direction No. 7 implements aspects of the 2013 10 Year Rates Plan. The
framework contemplates (i) capping rates during the current test period, (ii) recording the
excess revenue requirements above the amounts permitted by the rate caps in the Rate
Smoothing Regulatory Account, (iii) reducing the Rate Smoothing Regulatory Account balance
to zero by fiscal 2024, and (iv) low and predictable rate increases after the test period, such that
BC Hydro is targeting an average of 2.6 per cent in the remaining five years of the Plan.44 BC
Hydro is on track to achieve these outcomes45, despite lower forecast revenues associated with
the emergence in 2015 of a slower rate of load growth. BC Hydro remains on track to meet the
objectives of the 2013 10 Year Rates Plan as a result of:
First, BC Hydro’s intensified efforts to manage costs; and
Second, prioritizing spending in the test period in a manner consistent with the
Minister’s Mandate Letter.
B. BC HYDRO HAS INTENSIFIED ITS COST CONTROL EFFORTS
45. The forecast revenue requirements for the test period reflect BC Hydro’s efforts
over a number of years to manage costs. BC Hydro continued and intensified those efforts
beginning in 2015 in response to the lower than anticipated load growth rate.
42
Exhibit B-1-1, Application, p. 1-16. 43
Exhibit B-1-1, Application, Appendix D. 44
BC Hydro’s response to Exhibit B-15, BCSEA IR 2.64.1 outlines legal mechanisms underlying the 2013 10 Year Rates Plan.
45 Exhibit B-10, AMPC IR 1.1.1; AMPC IR 1.1.6; NIARG IR 1.1.1; Exhibit B-9, BCUC IR 1.124.11.
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(a) BC Hydro’s Steps Before the Test Period
46. Chapter 1 of the Application describes how BC Hydro implemented all of
Government’s Core Review recommendations by March 2014. The steps included:46
reducing operating costs by $391 million over a three-year period;
reprioritizing capital expenditures; and
eliminating approximately 800 positions mainly from non-operational functions,
and adding approximately 150 positions to operational front-line functions, for a
net reduction of approximately 650 positions.47
47. In the years leading up to this test period, BC Hydro also:
reduced the number of executive and senior managers by 10;
implemented a process to improve efficiency and enhance internal control over
key business functions;48
reduced planned capital expenditures from an average of approximately $2.1
billion per year to $1.7 billion per year (not including the Site C Clean Energy
Project);49
eliminated a further 341 non-operational positions;50 and
terminated or deferred 27 Electricity Purchase Agreements with Independent
Power Producers (“IPPs”) since 2013, thereby reducing electricity purchase
commitments by $2.1 billion.51
46
Exhibit B-1-1, Application, p.1-25. 47
Exhibit B-1-1, Application, p. 1-14. 48
Exhibit B-1-1, Application, p. 1-15. 49
Exhibit B-1-1, Application, p.1-16. 50
Exhibit B-1-1, Application, p.1-16.
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(b) BC Hydro’s Additional Steps in Response to Reduced Forecast Revenues
Associated with Lower Load Growth Rate
48. BC Hydro took a number of additional steps in the months leading up to filing the
Application in response to reduced forecast revenues associated with a lower forecast load
growth rate:
Limited base operating cost increases: BC Hydro limited forecast base operating
costs (before sustainment costs related to the Smart Metering and Infrastructure
program) to an annual average of 1.2 per cent over the test period.52 Operating
cost control is discussed below in Part Seven.
Prioritized and Reduced Forecast Capital Expenditures and Additions: BC Hydro
re-prioritized capital expenditures and additions. BC Hydro cancelled some
growth projects and delayed others to later years when the load will have
increased to the point that they will again be required. This exercise resulted in
a $381.2 million reduction in planned capital expenditures and a $392.5 million
reduction in planned capital additions over the test period.53 Part Eight below
addresses how BC Hydro achieved these reductions, while continuing to provide
for necessary reinvestment.
Reduced dismantling costs: Delay and cancellation of capital projects has
enabled BC Hydro to reduce its forecasted operating costs related to dismantling
of existing facilities slated for replacement by $70 million over the test period.54
51
Exhibit B-1-1, Application, p.1-16. 52
Exhibit B-1-1, Application, p.1-22. The costs and benefits associated with Smart Meter and Infrastructure Project are accounted for separately. The Smart Metering and Infrastructure project also creates additional energy cost reductions that are not captured in operating costs, resulting in an overall net positive benefit to ratepayers.
53 Exhibit B-1-1, Application, p.1-26.
54 Exhibit B-1-1, Application, p.1-26.
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Optimizing energy portfolio: BC Hydro re-examined its energy portfolio.
Fourteen of BC Hydro’s existing Electricity Purchase Agreements with IPPs are
expiring by the end of fiscal 2019. Consistent with the approved 2013 Integrated
Resource Plan, BC Hydro continues to assume renewal of 50 per cent of the
energy and capacity contributions from biomass Electricity Purchase Agreements
and 75 per cent from the run-of-river hydroelectric Electricity Purchase
Agreements. Renewal of Electricity Purchase Agreements with existing facilities
has the long term benefit of delaying future more costly greenfield resources.
BC Hydro expects to negotiate lower energy prices upon renewal of Electricity
Purchase Agreements because these IPPs will have recovered much or all of their
initial capital investment during the initial contract term. In its Electricity
Purchase Agreement renewal negotiations, BC Hydro will consider the IPP’s
opportunity cost, the electricity spot market, the cost of service for the IPP
(including fibre supply costs for biomass facilities) and other factors such as the
attributes of the energy produced and other non-energy benefits.55
Reduced cost of demand-side management: In June 2015, BC Hydro initiated a
process to modernize and improve the cost-effectiveness of its demand-side
management programs. Given the reduction in the rate of growth of demand
for electricity in the short-term and the objectives of the 2013 10 Year Rates
Plan, BC Hydro has reduced its overall level of planned demand-side
management expenditures.56 BC Hydro has eliminated or modified programs
that are not as cost-effective or are less aligned with customer expectations and
system needs, while retaining or expanding programs that align well with new
priorities. The average cost of its demand-side management programs has been
reduced to $22/MWh. At the same time, BC Hydro has maintained broad
customer access to conservation programs and remains on track to meet the
55
Exhibit B-1-1, Application, p.1-26 and 1-27.
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Clean Energy Act target to offset at least 66 per cent of incremental demand
from 2008 to 2020 through conservation. BC Hydro also retains the capability to
acquire further demand-side management electricity savings in the future should
those savings be required.57 BC Hydro discusses demand-side management in
greater detail in Part Twelve of this Final Submission.
Debt management strategy: BC Hydro introduced a debt management strategy
for future debt that is expected to yield savings of approximately $45 million
over the three-year test period.
49. AMPC’s evidence characterized the Application as reflecting “welcome and
material efforts by BC Hydro to control costs, find efficiencies and meet the capped rate
increases imposed by government’s ’10-year rate plan’, which built upon the detailed findings
of the panel of Deputy Ministers who reviewed BC Hydro in 2011.”58
C. BC HYDRO IS FOCUSSING ON KEY PRIORITIES DURING THE TEST PERIOD
50. BC Hydro has prioritized its investments in the test period, focussing on
reliability, load growth, customer, safety and security requirements. These priorities are
summarized below, together with an indication of how the priorities align with the Minister’s
Mandate Letter:
Maintaining, refurbishing and replacing aging assets: BC Hydro’s aging energy
generation, transmission and distribution infrastructure is under pressure, as
many facilities need to be replaced or refurbished. The average age of BC
Hydro’s electric generation facilities is more than 45 years. Approximately
400,000 transmission and distribution assets require refurbishment or
replacement within the next 10 years. It is necessary to invest in critical
infrastructure as it approaches end of life to maintain safe, reliable and cost-
57
Exhibit B-1-1, Application, p.1-28. 58
AMPC Evidence, p.3.
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effective service.59 BC Hydro’s investments are aligned with the Minister’s
Mandate Letter priority of: “Deliver your overall capital plan portfolio on time
and on budget to maintain the reliability of the system, support British
Columbia’s economic growth and meet the needs of customers.”60
Meeting customer expectations: BC Hydro is implementing a multi-faceted
Customer Strategy designed to enhance customer interaction with BC Hydro. It
involves a series of internal and external improvements such as bills that are
easier to read, the deployment of mobile and web-based platforms, and
customer-focussed staff training.61 BC Hydro’s investments are aligned with the
Minister’s Mandate Letter priority of: “Improve customer satisfaction by
providing timely and responsive service ...”.62
Addressing localized capacity constraints: BC Hydro has identified capacity
constraints as a result of increasing customer load in Northeast B.C., Metro
Vancouver and the Okanagan.63 Capital investments in system reinforcements
have increased BC Hydro’s revenue requirements during the test period, but are
required to sustain reliable service for customers in growing regions of the
province.64 BC Hydro’s investments are aligned with the Minister’s Mandate
Letter priority of: “Deliver your overall capital plan portfolio on time and on
budget to maintain the reliability of the system, support British Columbia’s
economic growth and meet the needs of customers.”65
59
Exhibit B-1-1, Application, p.1-7. 60
Exhibit B-1, Application, Appendix D. 61
Exhibit B-1-1, Application, section 5.5.1.1. 62
Exhibit B-1-1, Application, Appendix D. 63
Exhibit B-1-1, Application, p. 1-11. 64
Exhibit B-1-1, Application, p. 1-11. Specific investments include the Fernie Substation Upgrade (page 59, Appendix J), South Surrey Reinforcement (page 60, Appendix J) and Wellington Substation (formerly Nanaimo Area Substation) (page 38, Appendix J).
65 Exhibit B-1-1, Application, Appendix D.
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Investing in safety: BC Hydro is in the bottom quartile of Canadian utilities in
terms of safety. That performance must improve in the near-term. BC Hydro is
introducing safety-related measures during the test period to eliminate injuries
and “near-misses”.66 The goal is to create and maintain an injury-free workplace
and improve regulatory compliance in the management of safety risk.67 BC
Hydro’s investments are aligned with the Minister’s Mandate Letter of
Expectations priority of “Implement the five-year safety plan to ensure the safety
of your workforce and the public.”68
51. BC Hydro provided in Chapters 5 and 6 of the Application additional information
on how it is funding these priorities during the test period. Chapters 5 and 6 also discussed the
internal processes, governance and controls in place for BC Hydro’s initiatives and investments.
The evidence is addressed in Parts Seven and Eight of this Final Submission.
D. CONCLUSION AND REQUESTED FINDINGS
52. The Commission should find that BC Hydro has taken appropriate and significant
steps to manage costs and focus on important priorities during the test period, given the
context of the 2013 10 Year Rates Plan and the Minister’s Mandate Letter of Expectations. The
Commission will review BC Hydro’s rates and revenue requirements and deferral account
balances for fiscal 2020 to fiscal 2024 in future proceedings, making it unnecessary for the
Commission to make findings at this time regarding BC Hydro’s progress towards achieving the
2013 10 Year Rates Plan rate targets for years after the test period.69 BC Hydro expects to file
its next revenue requirements application prior to fiscal 2020.
66
Exhibit B-1-1, Application, section 5.7.6; BC Hydro’s Service Plan metrics in Appendix FF and Attachment 4 of Exhibit B-1-1.
67 Exhibit B-1-1, Application, p. 5-157.
68 Exhibit B-1-1, Application, Appendix D.
69 BC Hydro is not requesting approval of a recovery mechanism for the Rate Smoothing Regulatory Account in this
Application. In a future revenue requirements application, BC Hydro will propose to recover the balance of the Rate Smoothing Regulatory Account in rates. BC Hydro’s proposal will enable uniform forecast rate increases over the fiscal 2020 to fiscal 2024 period, and will ensure that the recovery of the Rate Smoothing Regulatory
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PART FIVE: LOAD AND REVENUE FORECASTS ARE REASONABLE
A. INTRODUCTION
53. BC Hydro’s Load Forecast and Revenue Forecast are described in Chapter 3 of
the Application, and in a number of responses to information requests. BC Hydro’s Load
Forecast for the test period is an input into the forecast Cost of Energy and the Revenue
Forecast.70 The Revenue Forecast is, in turn, used to determine the revenue shortfall under
current rates.71 BC Hydro addresses in this Part why the Commission should find that the Load
Forecast and Revenue Forecast for the test period are reasonable. The evidence supports the
following findings, each of which is addressed below:
First, BC Hydro’s core Load Forecast methodology has been in place for many
years, has been endorsed by Government in the 2013 Integrated Resource Plan
and by the Commission in prior applications, and is consistent with the
Commission’s resource planning Guidelines.
Second, BC Hydro uses a robust methodology and appropriate inputs to forecast
sales for each major customer segment, and addresses forecasting uncertainty.
Third, BC Hydro’s adoption of a different methodology for the nascent LNG
sector makes sense given the relatively small number of potential projects,
transparency, the difficulty of assigning probability weightings, and the fact that
forecasted LNG loads have little impact in the test period in any event.
Fourth, BC Hydro updated its Load Forecast in May 2016 to account for
significant developments.
Account is such that there is zero balance in this account by the end of fiscal 2024. Exhibit B-10, McCandless IR 1.3.2.
70 Exhibit B-1-1, Application, p.3-1.
71 Exhibit B-1-1, Application, p.3-2.
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Fifth, the actual results from the first full year of the test period were well within
1 per cent of BC Hydro’s May 2016 Load Forecast, reinforcing the soundness of
the methodology and the appropriateness of the forecast for rate-setting during
the test period.
Sixth, the reasonableness of the May 2016 Load Forecast for rate setting in the
current test period is also reinforced by continuity in key drivers of Residential
and Commercial load, as well as emerging commodity price factors, the removal
of PST on electricity, and new low carbon electrification policy considerations
that tend to have an upward influence on the load forecast.
Seventh, BC Hydro’s Rebuttal Evidence (to AMPC) demonstrated that: (a) the
May 2016 Load Forecast incorporates appropriate consideration of price
elasticity; and (b) the test period load forecast is insensitive to changes in
upstream oil and natural gas loads (which are driven by existing projects and
those already under construction) and LNG sector loads.
Eighth, Direction No. 7 mandates that load-related variances in the Cost of
Energy continue to be captured in the Non-Heritage Deferral Account.
Ninth, BC Hydro has used an appropriate Revenue Forecast methodology,
consistent with the approach used in the past.
B. COMMISSION AND GOVERNMENT ENDORSED THE LOAD FORECAST METHODOLOGY
54. BC Hydro’s Load Forecast is the output of what is, at its core, the same
methodology used for the 2013 Integrated Resource Plan and prior load forecasts filed with the
Commission. The Commission has examined BC Hydro’s Load Forecast methodology in several
proceedings.72 The Commission accepted the results flowing from the methodology in the 2008
72
The Load Forecast has been before the British Columbia Utilities Commission in the following processes: 2003 Vancouver Island Generation Project – Certificate of Public Convenience and Necessity Application, 2006
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Long-Term Acquisition Plan Decision.73 Government concluded as part of its 2011 review of BC
Hydro that the forecasting process is well-planned and generates reliable results.74 BC Hydro’s
response to BCUC IR 1.2.2 demonstrates the high degree of continuity in the Load Forecast
methodology, apart from some discrete and incremental refinements and the decision to
forecast LNG loads separately (discussed below).75 The methodology is consistent with the
Commission’s resource planning Guidelines.76
C. LOAD FORECAST BASED ON ROBUST METHODOLOGY AND APPROPRIATE INPUTS
55. At a high level, the Load Forecast is developed by summing the electricity sales
forecasts from BC Hydro’s main customer groups (Residential, Commercial / Light Industrial and
Large Industrial including LNG),77 deducting demand-side management savings78 and potential
impacts of future rate increases.79 The evidence establishes that BC Hydro’s models are
tailored to each major customer sector, link load to the key load drivers80, and incorporate data
from appropriate sources.
(a) Residential Sector Forecast Methodology
56. The Residential sector currently represents about 34 per cent of BC Hydro’s total
domestic sales.81 The central equation in estimating the Residential sales forecast is the product
Vancouver Island Call for Tenders Electricity Purchase Agreements, 2006 Integrated Electricity Plan, 2008 Long-term Acquisition Plan and 2008 LTAP Evidentiary and the Updated Fiscal 2009 and Fiscal 2010 Revenue Requirements Application.
73 Decision July 27, 2009, p.54.
74 Exhibit B-1-1, Application, p. 3-3.
75 See also: Exhibit B-1-1, Application, pp. 3-2 and 3-3; Exhibit B-10, AMPC IR 1.2.1 and 1.2.2.
76 Exhibit B-1-1, Application, section 3.2.
77 Exhibit B-1-1, Application, p. 3-4.
78 Exhibit B-1-1, Application, p. 3-4.
79 Exhibit B-1-1, p. 3-4 ; Exhibit B-10, AMPC IR 1.3.1, 1.3.2, 1.3.12.
80 Exhibit-10, CEC IR 1.14.1.
81 Exhibit B-1-1, Application, p.3-6.
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of the number of accounts times the average use per account.82 BC Hydro’s approach to
forecasting the number of accounts and use per account, summarized below, generates
reasonable results.
Average Use Per Account
57. BC Hydro uses a Statistically Adjusted End Use Model to estimate average
residential use per account. The model is used by approximately 60 different utilities and
organizations throughout North America. It continues to be supported by the model’s
developer.83
58. The main drivers of the Residential Statistically Adjusted End Use models are
economic variables (disposable income and population), temperature variables (heating and
cooling degree days), average appliance stock efficiencies and shares of end uses.84
Temperature inputs are based on historic data. The base year share of residential appliances is
based on BC Hydro’s 2014 Residential End Use Survey. Forecasts of share and average
appliance stock efficiency are from the 2015 U.S. Energy Information Administration projections
for the Pacific region, which are also generally applicable to British Columbia.85 BC Hydro’s
response to AMPC IR 1.6.1 provided the specific coefficients used in the Residential Statistically
Adjusted End Use models. The models are statistically sound and have very high measures of
goodness of fit or R-squared and R-squared adjusted statistics.
59. BC Hydro adjusts its load forecast to avoid double-counting the savings reflected
in the average efficiency forecast from the U.S. Energy Information Administration data and BC
Hydro’s demand-side management forecast.86 The necessary adjustments are small. BC Hydro
82
In each region, the residential sales forecast is calculated as: Average use per account x total ending number of accounts + electric vehicle sales + estimates to adjust for overlap in codes and standards.
83 Exhibit B-1-1, Application, p. 3-7.
84 Exhibit B-15, BCOAPO IR 2.108.3.
85 Exhibit B-9, BCUC IR 1.2.1; Exhibit B-15, BCOAPO IR 2.109.1, AMPC IR 2.22.6.
86 Exhibit B-9, BCUC IR 1.2.1; Exhibit B-15, CEC 2.134.2, CEC IR 2.136.1.
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continues to examine the possibility of developing its own residential stock and flow model that
would make these small overlap adjustments moot.87
Residential Accounts
60. BC Hydro develops the Residential account forecast for various dwelling types
(single family dwelling/duplex, row, apartments, and other). It is based on a forecast of housing
starts provided by an external expert, Robert Fairholm Economic Consultant.88 Although BC
Hydro does examine other housing start forecasts, such as the Canada Mortgage and Housing
Corporation (CMHC) forecasts, the Fairholm forecast has several advantages:
We use the Robert Fairholm Economic Consultant projection because we require a projection of housing starts over a 20-year period by building type for the various regions of our service area including the Lower Mainland, Vancouver Island, the North Region and the South Region. In addition to housing starts, Robert Fairholm provides a comprehensive forecast of all major economic drivers from the regional models that are included in the residential and commercial sector load forecasting models.
The Canada Mortgage and Housing Corporation does forecast provincial housing starts but does not provide a long-term comprehensive regional economic forecast.89
61. Electricity sales to the Residential sector tend to be relatively steady, since they
are driven by the relatively stable population growth and general economic trends. Past
variances in sales from year to year have tended to be modest,90 and the larger fluctuations are
mainly due to weather. BC Hydro addresses weather-related variability by preparing the
Residential sales forecast on a temperature normalized basis. “Normal” temperature is defined
as a ten-year rolling average of monthly heating and cooling degree days. BC Hydro has been
87
Exhibit B-15, AMPC IR 2.21.1. 88
Exhibit B-9, BCUC IR 1.2.1. The Robert Fairholm Economic Consultant projection reports are attached to BC Hydro’s response to BCUC IR 1.5.1 (Exhibit B-9-1-1 and B-9-2).
89 Exhibit B-10, CEC IR 1.15.3. The algorithm used by Robert Fairholm is a standard approach used in economic
forecasting: AMPC IR 1.4.2 (Revised) input-output models. 90
Exhibit B-9, BCUC IR 1.4.3.
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using a ten-year rolling average for at least 15 years. FortisBC Inc. (electric) also uses a ten-year
rolling average, and more utilities are moving from a longer (30-year) rolling average to a ten-
year period.91
Residential Electric Vehicle Load
62. Electric vehicle load associated with non-commercial use is added to the
Residential forecast. BC Hydro has developed its own electric vehicle load forecasting model.
Further details regarding the electric vehicle load methodology are provided in BC Hydro’s
response to AMPC IR 1.13.1. BC Hydro’s response to AMPC IR 2.13.1 also demonstrates that BC
Hydro’s electric vehicle model predicts rational results under different sensitivities (e.g.,
predicts more vehicles and more load when vehicle subsidies are increased). Electric vehicle
load is small during the test period, given the early stage of the market for electric vehicles.92
63. BC Hydro has not yet assessed the implications of the Climate Leadership Plan on
BC Hydro’s electric vehicle energy and capacity forecasts, as details on these policies continue
to be announced. New information will be considered as part of BC Hydro’s 2018 Integrated
Resource Plan.93
(b) Commercial and Light Industrial Sector Methodologies
64. BC Hydro’s Commercial / Light Industrial sector currently represents about 36
per cent of BC Hydro’s total domestic electricity sales.94 The methodologies employed to
forecast Commercial / Light Industrial loads are effective because they are tailored to reflect
the drivers of load.
91
Exhibit B-1-1, Application, p.3-6. 92
Exhibit B-1-1, Application, p.3-12. 93
Exhibit B-15, AMPC IR 2.12.1; AMPC IR 2.13.4; AMPC IR 2.13.5. 94
Exhibit B-1-1, Application, p.3-7.
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Commercial
65. BC Hydro uses four commercial Statistically Adjusted End Use model projections
for accounts greater than 35 kW and lower than 35 kW to forecast Commercial sales. Similar to
the Residential Statistically Adjusted End Use models, the commercial models use 10 years of
historical data and generally share the same structure as the Residential Statistically Adjusted
End Use models.95 The model drivers are: historical actual billed sales; forecasts of average
efficiencies of commercial end-use equipment; billing days; normalized temperature
projections; and, economic projections for retail sales, employment and commercial GDP
output. BC Hydro uses U.S. Energy Information Administration forecasts of average efficiency
and shares of end uses of electricity. Robert Fairholm Economic Consultant provides the
economic forecasts.96
66. The Commercial electric vehicle load, and the small adjustment to avoid double-
counting the impact of codes and standards, are addressed in the same way as the Residential
forecast.97
67. Similar to the Residential sector, load growth in the Commercial sector tends to
be steady as it is driven by growth in population and general economic trends.98 Actual
Commercial loads have tended to track the forecasts produced by BC Hydro’s commercial
models.99 The current eight commercial models are statistically sound and have respectable
measures of goodness of fit (R-square and R-squared adjusted statistics) and in sample accuracy
(mean absolute percentage error, which measures accuracy over the estimation period).100
95
Exhibit B-9, BCUC IR 1.2.1. 96
Exhibit B-1-1, Application, p.3-7 and 3-8; CEC IR 1.17.2. The coefficients of the models used to develop the commercial sales forecast are provided in BC Hydro’s response to AMPC IR 1.6.1.
97 Exhibit B-9, BCUC IR 1.2.1.
98 Exhibit B-1-1, Application, p.3-7.
99 Exhibit B-9, BCUC IR 1.4.3.
100 Exhibit B-10, AMPC IR 1.6.1.
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Light Industrial
68. The Light Industrial sales are the sum of sales for coal, wood, oil and gas and
other industrial loads connected at the distribution level.101 Light Industrial loads represent
only 20 per cent of the Commercial / Light Industrial sector load, and a relatively small portion
of BC Hydro’s overall load.
69. BC Hydro incorporates information from a variety of sources when forecasting
sales for coal, wood, and oil and gas. Sources include various key business groups within BC
Hydro (such as Key Account Managers, Interconnections, and Distribution Planning), third-party
consultants, private subscription services, and publicly available information.102 The models
incorporate commodity price projections.103 There is a strong relationship between real GDP
for British Columbia and Light Industrial loads other than coal, wood, and oil and gas; therefore,
BC Hydro uses a regression model and GDP forecasts obtained from the provincial government
and Robert Fairholm Economic Consultant.104
(c) Large Industrial Sector Methodology
70. BC Hydro’s Large Industrial sector currently represents about 27 per cent of BC
Hydro’s total domestic sales.105 The main industries included in the Large Industrial sector are
oil and gas, mining and forestry. This Large Industrial sector is the most volatile and difficult to
forecast, given the variability in drivers of the forecast (e.g., external commodity markets) and
events such as large customer attrition.106 However, BC Hydro’s methodology accounts for
these factors in an appropriate manner and BC Hydro is using reasonable data inputs.
101
Exhibit B-10, CEC IR 1.17.2. 102
Exhibit B-10, CEC IR 1.17.2; BCOAPO IR 1.19.1. 103
Exhibit B-10, AMPC IR 1.9.1. 104
Exhibit B-10, CEC IR 1.17.2. The Robert Fairholm Economic Consultant projection reports are attached to BC Hydro’s response to BCUC IR 1.5.1.
105 Exhibit B-1-1, Application p.3-9.
106 Exhibit B-10, CEA IR 1.4.3.
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71. As the oil and gas, mining and forestry industries were the focus of information
requests, BC Hydro addresses them below.
General Large Industrial Methodology
72. As in past years, BC Hydro derived the expected Large Industrial load growth, as
well as lower and upper bounds, by using inputs such as third party commodity forecasts for
each subsector with individual facility assessments.107 The methodology, in general, uses the
following forecasting equation: production X intensity X probability weighting.108 Forecasting in
this manner recognizes the key economic drivers of Large Industrial loads, and uncertainty
facing individual large industrial customers.
73. Production estimates reflect commodity outlooks and market projections for
specific types of products produced by BC Hydro’s customers (e.g., natural gas, ore or
newsprint). BC Hydro developed a range of forecasts for each industrial sub-sector considering
(i) an assessment of the current state of the global economy, (ii) a range of projected outcomes
for British Columbia’s major global trading partners who purchase exports, and (iii) supply and
demand balance outlooks of major commodities for each subsector, including a projected range
of future commodity prices.109 BC Hydro elaborated:
In the development of the May 2016 Load Forecast, BC Hydro reviewed a range of consultant reports and various information sources to understand what factors were driving the commodity market supply demand fundamentals. These reviews were undertaken for global economics as well as for our major large industrial sectors.
The review of the sectors gave BC Hydro a view of what the current commodity prices were driven by, when the commodity markets that are generally in a downturn would likely recover and to what price. The review also provided a range of possible outcomes based upon differing third party views of the
107
Exhibit B-10, CEC IR 1.16.1; BCUC IR 2.200.3. 108
Exhibit B-9, BCUC IR 1.2.1. 109
Exhibit B-1-1, Application, p.3-9 and 3-10.
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commodity markets, which led to the development of lower and upper range commodity price forecasts.110
74. There is a long list of third party sources that informed BC Hydro’s sector
forecasts.111 The commodity price forecasts are presented in BC Hydro’s response to AMPC IR
1.9.1. The Fairholm economic forecast is not an input into the Large Industrial sales forecast, as
the loads have a more direct relationship with commodity prices than broad-based domestic
economic drivers. In fact, industrial load assumptions are an input of the Fairholm analysis.112
75. BC Hydro performs individual facility assessments to determine intensity (i.e.,
kWh/unit of production) and probability weightings. BC Hydro estimates intensity using
historical data and information provided by BC Hydro’s Key Account Managers about how
customers operate their equipment and specific product lines over the short-term.113
Probability weights represent the risk assessment of future production expansion or
contraction (for existing customers) or the likelihood of project start-up (in the case of new
customers). The probability weightings applied to an individual customer reflect market
information from consultants, Key Account Managers, interconnections staff, and other
research from public sources. Factors that inform probability weightings include:114
the stage in the connection process for the customer;
the status of the customer’s regulatory/approval permits and project financing;
BC Hydro’s ability to meet the customer’s requested in-service date;
the market outlook for the customer products;
110
Exhibit B-10, CEC IR 1.16.1. 111
Exhibit B-10, CEC IR 1.16.1. 112
Exhibit B-9, BCUC IR 1.5.1. 113
Exhibit B-9, BCUC IR 1.2.1; CEA IR 2.44.1. 114
Exhibit B-9, BCUC IR 1.2.1. An example of how this analysis is applied is included in the response to BCUC IR 1.10.1.
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credit and financial viability of the customer;
electricity cost impacts on the customer’s operations; and
the likelihood of the customer taking electricity supply from BC Hydro.
76. Key Account Managers are well positioned to provide information about existing
customers. Key Account Managers are responsible for understanding their customers’ industry,
production processes and business economics. The information that BC Hydro obtains through
its Key Account Managers is combined with information from industry experts, industry news
(subscription) services and BC Hydro’s Load Forecast group’s industry knowledge to form an
overall load assessment.115
77. The Transmission Voltage Customer Interconnection Data Form, which each new
customer load requesting service must complete, is an important source of information about
new customer loads. The customer provides the funds for the study required to interconnect,
and it is in the customer’s interest to provide accurate information.116
78. BC Hydro addresses uncertainty in the three major resource-based large
industrial subsectors (oil and gas, mining and forestry) by developing mid, low and high
forecasts for each of these sub sectors. The most likely projection of commodity prices informs
the mid forecast and the associated probability weightings.117
Large Industrial: Oil and Gas Subsector
79. The oil and gas sector includes sales to oil and condensate pipelines, oil
refineries, gas pipelines, and upstream gas producer and processor loads situated in Northeast
British Columbia.118 It does not include electric loads for LNG facilities that have requested
115
Exhibit B-15, CEA 2.44.3. 116
Exhibit B-15, CEA 2.44.3. 117
Exhibit B-14-2, BCUC IR 2.197.3 (Revised). 118
Exhibit B-1-1, Application, p.3-11; BCOAPO IR 1.19.1.
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electricity service, which (as discussed later in this Part) are forecasted separately. BC Hydro’s
approach of undertaking a probabilistic assessment of load associated with upstream oil and
gas, summarized below, accounts for uncertainty in load growth.119 BC Hydro has a
considerable degree of confidence in the test period load forecast for this sector, since 90 per
cent of the oil and gas sector load during the test period is attributed to either existing or new
projects which are currently under construction.120
80. Customer requests for electricity service reflect the customer’s specific plant
compression and processing requirements.121 BC Hydro considers electricity service requests
for new or expanded gas production and processing facilities by applying probability weightings
associated with: (i) the probability the facility will be built and operated to the requested
service levels; and (ii) the probability the facility will take electricity service from BC Hydro
rather than self-supplying its energy requirements.122
81. In assigning facility start-up probability weightings, BC Hydro considers a number
of facility-specific factors (e.g., the project’s stage of development) and market assumptions
(supply, demand, price).123 Various key business units within BC Hydro provided customer-
specific input.124 BC Hydro’s market forecasts in this sector were prepared using reliable third
party data sources, including published information from:
Subscription services: PIRA Energy Group, Bloomberg New Energy Finance
Services, Wood Mackenzie and IHS Inc.;
B.C. Ministry of Natural Gas Development;
B.C. Oil and Gas Commission;
119
Exhibit B-1-1, Application, p.3-11. 120
Exhibit B-20, Rebuttal Evidence, pp.22-23; Exhibit B-14-2, BCUC IR 2.197.3 (Revised). 121
Exhibit B-10, CEABC IR 1.21.4; 1.21.6; 1.21.7. 122
Exhibit B-10, CEC IR 1.20.2. 123
Exhibit B-10, CEC IR 1.20.2. 124
Exhibit B-10, CEC IR 1.20.2.
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National Energy Board;
U.S. Energy Information Administration;
RBN Energy; and
Natural gas industry companies (corporate presentations, annual reports and
news releases).
82. BC Hydro’s market assessments for gas are tempered in that they reflect an
expectation that low cost U.S. natural gas suppliers will suppress market prices in the short-
term. Prices for natural gas liquids are also expected to remain flat in the short-term, but are
sufficient for producers in the Montney region to proceed with plant construction projects to
supply gas liquids.125 All of the incremental oil and gas load growth during the test period
reflects North American demand, and is independent of any British Columbia LNG
development.126
83. The aggregated probability-weighted loads are reflected in the sales projections
provided in BC Hydro’s response to CEA IR 1.21.1. As stated above, 90 per cent of the oil and
gas sector load during the test period is attributed to either existing or new projects which are
currently under construction. These projects are not dependent on the development of B.C.-
based LNG projects.127 As discussed in Section H of this Part, the Climate Leadership Plan and
the recent removal of PST on electricity also have the potential to favourably impact loads in
this sector. The upcoming 2018 Integrated Resource Plan will account for new information on
North American gas and liquids prices over the longer term, as well as the development of
British Columbia LNG projects and initiatives under the Climate Leadership Plan that could
affect the years beyond the test period.
125
Exhibit B-1-1, Application, p. 3-17. 126
Exhibit B-9, BCUC IR 1.8.1. 127
Exhibit B-20, Rebuttal Evidence, pp.22-23; Exhibit B-14-2, BCUC IR 2.197.3 (Revised).
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Large Industrial: Mining Subsector
84. Commodity prices are the primary driver of energy sales in the mining sector. As
was the case with the oil and gas subsector, BC Hydro relied on consultant studies,
subscription-based market information and various other publicly available reports to develop
its mining sales forecast. BC Hydro’s mining industry consultants include
PricewaterhouseCoopers and P&E Mining Consultants. BC Hydro also used Consensus
Economics price forecast data and a variety of publicly available information, including:
B.C. Ministry of Finance February 2016 Budget;
World Bank Global Economic Prospects January 2016 report and database;
GFMS Surveys (Annual Surveys for Gold, Copper and Base Metals); and
Public mining company information and other reports on various websites.
Various Key Business Units within BC Hydro provided customer-specific input.128
85. As discussed in Section H below, some commodity prices have improved since BC
Hydro completed the May 2016 Load Forecast.
Large Industrial: Forestry Subsector
86. The Forestry sector is comprised of pulp and paper, wood and chemical loads. It
represents approximately half of BC Hydro’s Large Industrial sales.129 Sales to the pulp and
paper sector depend on global pulp prices, exchange rates, fibre supply, the demand for pulp
products, and the capacity and cost competitiveness of pulp and paper mills. Sales to sawmills
are dependent on the U.S. housing market, exchange rates and the availability of wood. Sales
to the chemical sector are linked to kraft pulp mills and the opportunity for exports.130
128
Exhibit B-10, CEC IR 1.21.1. 129
Exhibit B-1-1, Application, p.3-10 and 3-11. 130
Exhibit B-1-1, Application, p.3-10 and 3-11.
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87. As with other sub-sectors, BC Hydro’s assessment of the forestry industry is
based on external and internal sources. External sources and production forecasts are provided
in BC Hydro’s response to BCOAPO IR 1.19.2. Various Key Business Units within BC Hydro
provided customer-specific input.131
88. As discussed in Section E below, the May 2016 Load Forecast already accounts
for challenges facing the pulp and paper sector in recent years as a result of reduced paper
usage and dropping Thermal Mechanical Pulp prices.132 The recent removal of PST on
electricity also has the potential to favourably impact loads in this sector.
(d) Load Forecasting Methodology Accounts for Uncertainty in a Reasonable
Manner
89. BC Hydro accounts for uncertainty in its overall Load Forecast so that its revenue
requirements reflect expected values given the available information, and are neither
aggressive nor conservative. BC Hydro’s methodology accounts for uncertainty in two ways:
First, BC Hydro conducts a Monte Carlo simulation to produce both a
probabilistic peak demand and an energy load forecast. The Monte Carlo
simulation model generates a probability band around the mid total gross
requirements forecast for each year of the forecast. The simulations are used to
derive low and high forecasts. For planning purposes, BC Hydro uses the mid
forecast, which represents the most likely expected outcome of load and
drivers.133 BC Hydro’s use of the mid forecast is consistent with the
Commission’s resource planning Guidelines.134
131
Exhibit B-9, BCUC IR 1.2.1. 132
Exhibit B-10, BCOAPO IR 1.19.2. 133
Exhibit B-10, CEC IR 1.14.1. The high and low load forecast range is provided in section 3.2.2, Table 3-2 of the Application.
134 See section 7 of the Commission’s Resource Planning Guidelines, which require the use of the most likely scenario: http://www.bcuc.com/Documents/Guidelines/RPGuidelines_12-2003.pdf
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Second, as discussed above, for large industry or region-specific forecasts that
involve unique drivers and include a high degree of uncertainty, BC Hydro
reviews the underlying drivers and constructs high and low Large Industrial
electricity demand projections.135
(e) Residential and Commercial / Light Industrial Forecasts Are Not Sensitive to
AMPC’s Suggested Changes in Economic Assumptions
90. AMPC requested that Robert Fairholm Economic Consultant assess the impact of
LNG and oil and gas production and Site C Clean Energy Project assumptions on the Residential
and Commercial / Light Industrial sector load forecasts (the two sectors that use the Fairholm
analysis as an input). The Fairholm analysis showed that changing the assumptions in the
manner AMPC had suggested would have little impact on the domestic sales forecast during the
test period (or otherwise).136
D. LNG LOAD FORECASTED IN A TRANSPARENT MANNER SUITABLE FOR THE NASCENT
INDUSTRY
91. BC Hydro has reflected the development of the LNG export industry in the Load
Forecast. Instead of developing mid, high and low LNG sales forecasts, BC Hydro used:
publicly announced in-service dates; and
publicly announced volumes, for which BC Hydro has service requests.137
This approach makes sense in the context of the LNG industry. Segregating LNG load increases
transparency for a sector of particular interest to the public. The small number of proponents
135
Scenarios developed for the Load Forecast are detailed in the Large Industrial Class section of the Application. Exhibit B-1-1, Application, pp. 3-9 – 3-11.
136 Exhibit B-15-2, AMPC 2.2.1 (Revised), p.4; Exhibit B-21, BCUC 3.342.2.2.1
137 Exhibit B-14, BCOAPO IR 2.141.1; Exhibit B-1-1, page 3-5 – 3-6.
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that are proposing to electrify from the grid (FortisBC Energy Inc., LNG Canada and Woodfibre
LNG) precludes confidential aggregation of a probabilistic Load Forecast.138
92. FortisBC Energy Inc.’s Tilbury Expansion Phase 1 is the only LNG Facility with an
in-service date during the test period, and it will use natural gas for liquefaction.139 Announced
delays in other LNG projects that are expected to add significant electric loads do not affect the
Load Forecast for the test period. Their in-service dates were already after the test period at
the time BC Hydro had prepared its May 2016 Load Forecast.140
93. BC Hydro’s Load Forecast for the test period is also unaffected by the eDrive rate
announced in November 2016, given the absence of significant forecasted LNG-related electric
load during the test period. The potential impact on BC Hydro’s load and revenues is beyond
the test period:
The eDrive rate may result in further LNG loads and higher revenues in the long-
term, but there is considerable uncertainty as to quantity and timing.
Government has not yet indicated when the new eDrive rate will be
applicable.141 The eDrive rate is only one of many factors that LNG proponents
must consider in making a final investment decision.
The eDrive rate is lower than the rate LNG facilities would otherwise pay for
service. If initiatives like the eDrive rate that promote Climate Leadership result
in decreased revenues or increased costs to BC Hydro, then Government has
committed to taking further actions so that the objectives of the 2013 10 Year
Rates Plan continue to be met.142 The Minister’s November 3, 2016 letter to BC
138
Exhibit B-1-1, Application, p. 3-5. 139
The forecast sales to the three LNG plants that have requested electricity service from BC Hydro are shown on line 9 Schedule 14.0 of the Application. The forecast of revenues associated with these LNG plants are shown on line 19 of Schedule 14.0.
140 Exhibit B-9, BCUC IR 1.7.2; 1.7.3; Exhibit B-9, AMPC IR 1.9.3.2 and 1.9.3.6.
141 Exhibit B-14, BCUC 2.203.2.
142 Exhibit B-9, BCUC IR 1.7.2
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Hydro is attached to the response to BCUC IR 1.7.2. Government subsequently
elaborated that it would consider at a later date whether and what actions may
need to be taken to address any impact of reduced revenues on the 2013 10
Year Rates Plan.143
E. LOAD FORECAST IS SUBJECT TO MULTIPLE LEVELS OF INTERNAL REVIEW
94. The inputs and resulting forecasts are subjected to successive internal reviews.
The methodology and input assumptions are reviewed annually by the Manager of the Load
Forecasting team and the Director of Energy Planning. The forecast and key underlying
assumptions are then reviewed and approved in succession by the Manager of the Load
Forecasting team, the Director of Energy Planning, and the Senior Vice President of the
Corporate Affairs Key Business Unit. The forecast is presented to BC Hydro’s Executive Team
and Board of Directors for final review.144 These internal reviews provide an additional level of
comfort around the May 2016 Load Forecast.
F. BC HYDRO UPDATED THE LOAD FORECAST TO REFLECT SIGNIFICANT DEVELOPMENTS
95. BC Hydro monitors the load forecast, tracking variances by customer sector on a
monthly basis. Management reports on a quarterly basis to the Customer Service, Operations
& Planning Committee of the Board of Directors.145 In response to significant developments in
the mining and LNG sectors, BC Hydro delayed filing the Application and updated the Load
Forecast. The May 2016 Load Forecast reflected the developments in the mining and LNG
sectors and also updated information on loads for other industry sectors. The May 2016 Load
forecast, while continuing to predict long-term load growth across all three customer sectors,
yielded a lower growth rate compared to the 2013 Integrated Resource Plan.146
143
Exhibit B-15, AMPC IR 2.6.5. 144
Exhibit B-14, BCUC IR 2.193.1. 145
Exhibit B-14, BCUC IR 2.193.1. 146
Exhibit B-1-1, Application, p.3-1.
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G. ACTUAL SALES HAVE CLOSELY TRACKED THE MAY 2016 LOAD FORECAST
96. The actual results from the first full year of the test period tracked BC Hydro’s
May 2016 “mid” Load Forecast within one per cent, reinforcing the appropriateness of the Load
Forecast for rate-setting during the test period.
(a) Less than One Per Cent Variance During First Full Year of the Test Period
97. The table below shows the fiscal 2017 variance (i.e., actual billed sales from fiscal
2017 compared to forecast sales during that period) for each major customer class. The total
billed sales147 variance over the first full year of the test period for all customer classes was only
(0.3) per cent on a temperature normalized basis.148 The results were well within the
uncertainty bands in BC Hydro’s Load Forecast.
147
Monthly billed sales represent customer consumption billed during the month. Since most customers are billed on a two month cycle a portion of the billed consumption relates to previous months and a portion to the current month. For further explanation of billed and accrued sales please refer to BC Hydro’s response to BCOAPO IR 2.112.1.
148 Exhibit B-22, CEABC IR 3.46.2. BC Hydro subsequently corrected two typographical errors in the table in CEABC IR 3.46.2. The table in this Final Submission reflects the corrected values.
Fiscal 2017 Actual vs Forecast Domestic Energy Sales
(F2017 Forecast is per May 2016 Load Forecast)
Actual Forecast
Sector
F2017 BILLED
ACTUALS
F2017 BILLED
FORECAST Difference % Difference
GWh GWh GWh %
Actual Residential Sales 17,989 18,031 (42) -0.2%
Temperature Normalized
Residential Sales 17,952 18,031 (80) -0.4%
Commercial 14,572 14,486 86 0.6%
Light Industrial 4,275 4,349 (74) -1.7%
Irrigation and Streetlights 312 301 10 3.5%
Large Industrial 13,235 13,323 (88) -0.7%
LNG 0.32 57 (57) -99.4%
Other Utilities 1,370 1,310 60 4.6%
Actual Total Domestic Sales 51,753 51,858 (105) -0.2%
Temperature Normalized Total
Domestic Sales 51,715 51,858 (143) -0.3%
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98. The Residential sector was (0.4) per cent on a temperature normalized basis,
based on fiscal 2017 actual billed data.149
99. There was a positive variance in the Commercial sector of 0.6 per cent. Below
forecast sales to the oil and gas sector drove the small negative variance in the Light Industrial
segment; however, indications for oil and gas are positive, as described later.150
100. The total Large Industrial sector variance from fiscal 2017, excluding LNG, was
(0.7) per cent. The Large Industrial variance, including LNG, was (-1.1).151 In terms of the break
down of that Large Industrial variance, the most up to date information on the evidentiary
record in this proceeding is billed sales from the first 10 months of the test period. Most Large
Industrial subsectors tracked close to forecast or above forecast over the first 10 months of the
test period. The largest positive variances within the Large Industrial sector were in metal and
coal mining. Most of the negative variance is in the oil and gas sector. The positive variances
significantly offset the negative variances.152
101. BC Hydro submits that any comparison of actual results and BC Hydro’s forecast
for the purpose of testing the reasonableness of using the May 2016 Load Forecast for rate
setting should be performed for all sectors in aggregate. It is inevitable with unbiased
forecasting that some sectors will have higher than expected consumption, while others will
have lower than expected consumption. BC Hydro uses the aggregated forecast for total
system planning purposes and total cost of energy assessments, which allows for offsetting
impacts in different sectors. BC Hydro submits that an overall Load Forecast variance of (0.3)
per cent over the first full year of the test period reinforces the reasonableness of using the
May 2016 Load Forecast to set rates.
149
Exhibit B-22, CEABC IR 3.46.2. 150
Exhibit B-22, CEABC IR 3.46.2. 151
Exhibit B-23 corrected the value provided in Exhibit B-22, CEABC IR 3.46.2 for the Large Industrial sector. 152
Exhibit B-14-2, BCUC IR 2.197.3 (Revised).
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(b) 2018 Integrated Resource Plan Will Include an Updated Load Forecast
102. Some Parties focussed on the forecast load after the current test period.153 The
Commission’s determinations in this proceeding should address the test period, one-third of
which has passed already with actual results closely tracking the May 2016 Load Forecast. BC
Hydro will, as the Commission acknowledged in its January 27, 2017 procedural order,154
update its forecasts for the 2018 Integrated Resource Plan. BC Hydro will also use the best
available information when it makes operational decisions and files Electricity Purchase
Agreements with the Commission under section 71 of the Utilities Commission Act.155
H. RECENT DEVELOPMENTS REINFORCE REASONABLENESS OF THE LOAD FORECAST
103. Updating the Load Forecast late in the regulatory process was impractical given
the amount of work involved156; however, BC Hydro provided a lengthy analysis of emerging
external factors in its revised response to BCUC IR 2.197.3.157 The economic drivers of sales in
the Residential and Commercial/Light Industrial sectors remain consistent with the May 2016
Load Forecast. The indications for the Large Industrial sector are more positive now than in
May 2016. Overall, BC Hydro’s analysis confirms the appropriateness of using the May 2016
Load Forecast for the test period.
(a) Continuity in Key Drivers of Residential and Commercial / Light Industrial Sales
104. Electricity sales to the Residential and Commercial sector tend to be relatively
steady because they are driven by population growth and general economic trends. Any large
fluctuations in Residential sales from year to year are mainly due to weather, and these
153
See for instance, Exhibit B-9, BCUC IR 1.11 series. 154
Exhibit A-18. 155
Exhibit B-14, BCUC IR 2.208.1. 156
Exhibit B-14-2, BCUC IR 2.197.3 (Revised). A load forecast update requires a detailed and comprehensive review of all relevant factors and drivers across each of the major customer segments, including a detailed review of market fundamentals for each of the main large industrial sectors. Focussing on a subset of changed circumstances could bias the results.
157 Exhibit B-14-2.
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fluctuations are addressed in the forecasting process through temperature normalization.158
Commercial / Light Industrial sector sales are largely centered in the Lower Mainland, and tend
to move in-step with the provincial GDP.159 This stability is reflected in the fact that the average
variance in the Residential sector and Commercial / Light Industrial sector actuals over the past
two fiscal years have been only 1.0 per cent and 0.1 per cent, respectively.160 The key
economic assumptions used to develop the Residential and Commercial / Light Industrial sales
projections over the test period continue to be reasonable.
105. Projected GDP growth has increased since May 2016. The table below shows the
real provincial GDP growth projection as of September 2016 compared to the GDP growth
forecast used in the May 2016 Load Forecast.161
106. Using the more recent GDP projection would increase total domestic sales on
average over the test years, but only by a small amount (approximately 13 GWh). The newer
information supports the use of the May 2016 Load Forecast to set rates in the test period.162
(b) Positive Developments in the Large Industrial Sector
107. At the time of the May 2016 Load Forecast, BC Hydro’s major Industrial
subsectors had been experiencing dropping commodity prices for several years. Prices for
natural gas, copper, metallurgical coal and Thermal Mechanical Pulp have since increased.
158
Exhibit B-1-1, Application, 3-6. 159
Exhibit B-9, CEABC IR 1.4.3. 160
Exhibit B-9, BCUC IR 1.4.3. 161
Exhibit B-15, CEC IR 2.133.3; Exhibit B-9, BCUC IR 1.5.2. 162
Exhibit B-1-1, Application, p. 3-4.
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Commodity prices are higher relative to the prices reflected in the May 2016 “mid” Load
Forecast and the associated probability weightings. Higher commodity prices (other things
being equal) have an upward influence on the Load Forecast.163 Current indications regarding
BC Hydro’s oil and gas and mining customers are positive.
Oil and Gas Sector Developments
108. The most up to date evidence on the record regarding the oil and gas subsector
load variance was related to the first ten months of the test period. At that time, there was a
negative load variance in this subsector, two-thirds of which (108 GWh) was attributable to low
production rates from customers impacted by low gas prices. However, 90 per cent of the
forecast oil and gas sector load during the test period is attributed to either existing projects or
new projects that are currently under construction.164 Natural gas prices have also been
increasing, as depicted in the figure below. Negative variance customers have informed BC
Hydro that they expect to increase production to forecasted levels.165
163
Exhibit B-14-2, BCUC IR 2.197.3 (Revised). 164
Exhibit B-20, Rebuttal Evidence, pp.22-23; Exhibit B-14-2, BCUC IR 2.197.3 (Revised). 165
Exhibit B-14-2, BCUC IR 2.197.3 (Revised).
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109. Large new loads are proceeding as forecasted.166 The oil and gas sector load
growth expected between now and the end of the test period is associated primarily with
projects currently under development by Veresen Midstream. Most of the Verasen Midstream
projects are already well advanced and are the subject of agreements with BC Hydro.167 Other
oil and gas sector projects that have made electricity service enquiries continue to advance.168
110. AMPC asked several information requests about the sensitivity of the upstream
oil and gas sector to the progress of LNG projects, since two projects (FortisBC’s Tilbury
Expansion Phase 2 and LNG Canada) were deferred. In the May 2016 Load Forecast, the in-
service dates for these two projects were already outside of the test period. The mid
forecasted upstream oil and gas load during the test period assumed that electrified gas
production is driven by supply to North American developments via British Columbia exports,
not LNG facilities built in British Columbia for exporting offshore. As a result, the test period
load forecast for upstream oil and gas is not sensitive to the timing of LNG developments.169
Mining Sector Developments
111. The most up to date evidence on the record regarding the metal and coal sector
variances was for the first ten months of the test period. At that time, there was a positive load
variance, reflecting the increased market price of both copper and metallurgical coal relative to
what is reflected in BC Hydro’s May 2016 “mid” Load Forecast.170 In fact, commodity costs had
increased to the point where mining customers participating in the Mining Customer Payment
Plan program have been required to make some repayments of their unpaid balances in recent
months.171 There is ample evidence that “a continuation of the current higher copper and
166
Exhibit B-14-2, BCUC IR 2.197.3 (Revised). 167
Exhibit B-14-2, BCUC IR 2.197.3 (Revised). BC Hydro filed some of the specific project information confidentially, but most appears in the public version.
168 Exhibit B-14-2, BCUC IR 2.197.3 (Revised).
169 Exhibit B-9, BCUC IR 1.8.1, AMPC 2.18.1 and BCUC IR 2.197.3.
170 Exhibit B-14-2, BCUC IR 2.197.3 (Revised).
171 Exhibit B-14-2, BCUC IR 2.197.3 (Revised).
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metallurgical coal price environment could create opportunities for producers over and above
what is reflected in the mid Load Forecast.”172 Examples cited by BC Hydro included:
A continuation of the current higher copper price environment could lead to the
re-start of Huckleberry Mine; and
One of the three idled Northeast coal mines on distribution voltage was recently
restarted and a second mine is expected to re-open during fiscal 2018.173
112. The recent removal of PST on electricity improves the economics of electricity-
intensive mining.
Forestry Developments
113. The forestry sector (wood, pulp and chemical) tracked within one per cent of
forecast over the first ten months of the test period, and it is reasonable to expect this will
continue.
114. The largest subsector in the forestry sector is pulp and paper. The pulp and
paper sector has been challenged for a number of years as a result of reduced paper usage and
dropping Thermal Mechanical Pulp prices. These trends were already reflected in the
preparation of the May 2016 Load Forecast. BC Hydro stated:
We feel we have reasonably addressed any weakness in this sector with the probability assessments reflected in the May 2016 Load Forecast. While any individual closures can result in a deviation from forecast load timing, our assessment is that most of the reduction in this sector has taken place and any additional closure risks are already reflected in the May 2016 Load Forecast.174
115. Thermal Mechanical Pulp prices have increased relative to those assumed in the
May 2016 “mid” Load Forecast and BC Hydro “expect[s] this to have a stabilizing effect on the
172
Exhibit B-14-2, BCUC IR 2.197.3 (Revised). 173
Exhibit B-14-2, BCUC IR 2.197.3 (Revised); Exhibit B-9, BCUC IR 1.4.3. 174
Exhibit B-9, BCOAPO IR 1.19.2.
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pulp and paper sector forecast through the test period.”175 Increasing Chinese demand for
Thermal Mechanical Pulp used in folding box boards is supporting current markets. Little
incremental capacity is expected in the next few years. The following graph shows that prices
have been gradually increasing as incremental Thermal Mechanical Pulp capacity has been
absorbed into the markets.176
116. The recent phase-out of PST is also a favourable development in this sector. It is
equivalent to a 7 per cent reduction in electricity costs. BC Hydro`s analysis demonstrated that
the cost of inputs have a particularly favourable impact on thermo-mechanical pulp mills, as
they have higher electricity costs as a percentage of their operating costs.177
(c) Low Carbon Electrification Load is Incremental to the May 2016 Load Forecast
117. The Province’s August 2016 Climate Leadership Plan identified potential for
electrification in the transportation sector, expanding BC Hydro’s demand-side management
programs to include investments that reduce greenhouse gas emissions, and the electrification
175
Exhibit B-14-2, BCUC IR 2.197.3 (Revised), page 31. 176
Exhibit B-14-2, BCUC IR 2.197.3 (Revised). 177
Exhibit B-20, Rebuttal Evidence, pp.19-20.
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of natural gas production, processing and transmission.178 There is currently no load associated
with low carbon electrification in the May 2016 Load Forecast. In terms of the test period,
implementation of the Plan will (other things being equal) have an upward impact on BC
Hydro’s future load projections.179
118. BC Hydro’s paper entitled “Low Carbon Electrification Potential”, which is
attached to the response to BCUC IR 2.197.3, provides an overview of the various elements of
low carbon electrification and the potential implications for BC Hydro’s load. BC Hydro’s
evidence is that the electrification initiatives contemplated in the Climate Leadership Plan have
not been fully developed, and their impact on electricity load growth is not yet known.
However, “the directional impact is clear, and a number of studies and analyses provide an
indication of the potential for increased low-carbon electrification in BC.”180 Analysis carried
out for the provincial government and released to BC Hydro indicated that these initiatives
could increase electricity load by up to 6,500 to 7,000 GWh/year by 2030.181
119. BC Hydro is working toward having electrification programs in place during the
test period, which was not contemplated at the time of the May 2016 Load Forecast. BC Hydro
explained its electrification initiatives for the oil and gas sector:
For gas processing facilities in the Peace Region, BC Hydro has been in active discussions with its customers and the Canadian Association of Petroleum Producers regarding a potential framework that would consist of a fixed incentive per MW. In return for the incentive, BC Hydro would also retain ownership of a share of the offsets that arise from the projects.
The application process under which customers would submit the projects for consideration is expected to be similar to the existing process for conservation projects under BC Hydro’s demand-side management programs. Projects will be submitted and reviewed by BC Hydro’s engineering personnel for
178
Exhibit B-14-2, BCUC IR 2.197.3 (Revised), Attachment A, p.1; Exhibit B-15, CEC IR 2.130.11. 179
Exhibit B-22, CEABC IR 3.183.4. 180
Exhibit B-14-2, BCUC IR 2.197.3 (Revised), Attachment A, p.1. 181
Exhibit B-14-2, BCUC IR 2.197.3 (Revised), Attachment A, p.2.
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reasonableness and if approved, an incentive agreement would be signed by the customer and BC Hydro.
An electrification incentive program may result in increased load over and above that estimated both in the test period and beyond.182
120. CEABC’s evidence elaborated on the extent of the growth in the Montney region
production, citing Oil and Gas Commission data. CEABC noted the opportunity for BC Hydro to
electrify production given the energy intensity of the production processes for natural gas
liquids.183 BC Hydro expressed general agreement with the data that CEABC had presented in
this regard.184 The attachment to BC Hydro’s response to BCUC IR 2.197.3 outlines the
opportunities and potential incremental demand associated with low carbon electrification.
121. Mining is also a potential target for new electrification. BC Hydro has initiated
work internally and with mining companies to examine the potential for electrification. BC
Hydro identified replacing diesel as being the primary mining opportunity, e.g., replacing diesel-
powered haul trucks with electrically powered trucks or other electrically powered equipment
to transport ore or coal. The work is, however, at a “very early stage” and BC Hydro has not
developed estimates of potential load.185
122. The recent removal of PST on electricity improves the economics of low carbon
electrification. It equates to a 7 per cent reduction in electricity costs.186
123. BC Hydro is not proposing to revise the May 2016 Load Forecast upward for the
test period as a result of low carbon electrification, since the timing of the programs and the
resulting low carbon electrification is still uncertain. Deferral accounts would capture load-
182
Exhibit B-14-2, BCUC IR 2.197.3 (Revised), Attachment A, p.9. 183
CEABC Evidence, p.7. 184
Exhibit B-20, Rebuttal Evidence, p.30. 185
Exhibit B-14-2, BCUC IR 2.197.3 (Revised), Attachment A, p.12. 186
Exhibit B-20, Rebuttal Evidence, p.19.
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related variances associated with higher than forecast electrification load. Incremental load
from low carbon electrification will be reflected in the 2018 Integrated Resource Plan.187
(d) Discounting the Load Forecast Based on Past Variances Would Be
Unreasonable
124. Some information requests inquired about the impacts of reducing the May
2016 Load Forecast by specific percentages derived from the amount of past variances.188 BC
Hydro submits that such an approach would be arbitrary and unsupported by the evidence. BC
Hydro’s methodology should be used to forecast load for the test period.
125. Variances in the Large Industrial sector are the main reason for variances in the
Load Forecast in recent years;189 temperature normalized variances in the Residential sector
and Commercial / Small Industrial sectors have been small.190
126. The variances in the Large Industrial sector were tied to significant and
prolonged drops in commodity prices and operational events affecting significant customers
(e.g., the dam breach at Mount Polley Mine).191 Commodity prices and developments in world
markets are inherently difficult to predict, such that the opinions of third-party authorities
relied upon by BC Hydro often differ. Facility-specific developments that occurred in recent
years could not reasonably have been foreseen. BC Hydro elaborated:
BC Hydro believes that its approach to forecasting large industrial load remains appropriate and that past variances have resulted from unforeseen circumstances that would have been difficult, if not impossible, to predict.
That said, BC Hydro continually looks for ways to improve our forecasting methodology. For example, for the May 2016 forecast BC Hydro expanded and improved on external expert sources in providing intelligence in the pulp and
187
Exhibit B-14-2, BCUC IR 2.197.3 (Revised), Attachment A, p.1. 188
Exhibit B-14, BCUC IR 2.202.2; BCUC IR 2.202.1; BCUC IR 2.202.1.1. 189
CEABC points to 18%, 17%, 13% and 10% industrial variances in their preamble to CEABC IR 1.4.1. 190
Exhibit B-14, BCUC IR 2.199.1; Exhibit B-9, BCUC IR 1.4.3. 191
Exhibit B-9, BCUC IR 1.4.3; Exhibit B-10, CEABC IR 1.4.1; Exhibit B-14, BCUC IR 2.200.4.
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paper, oil and gas, mining, chemical and LNG markets. BC Hydro will continue to rely upon these sources.
There is uncertainty in any load forecast, more so in the industrial sector due to the inherent uncertainty in its drivers which are dependent upon actions and policies in countries that trade with B.C. BC Hydro manages the uncertainty in our forecast by developing a high and low band around the forecast and uses these forecasts in establishing long term plans, including contingency plans.
It is BC Hydro’s experience that it is very difficult to forecast economic downturns and upturns where there is a significant shift in a commodity cycle. The consultants that produce the commodity price and industry outlooks can all demonstrate a range of outcomes. In terms of the recent cycle of lower than forecast large industry loads, the length of the down cycle was unforeseen and there were plant closures for other reasons like water availability that compounded the situation. BC Hydro expects that, as is currently being seen, commodity prices will recover and associated load growth is expected to occur.192
127. The developments that occurred in past years to cause a forecast variance
cannot reasonably be extrapolated to the test period. Commodity prices are improving. Large
Industrial customers that have already shut down are reflected in the May 2016 Load Forecast
and cannot be the source of a potential negative variance. As discussed above, the actual load
in the first full year of the test period has tracked the May 2016 Load Forecast. There are a
variety of favourable external factors that support the forecast. BC Hydro’s response to CEC IR
2.6.1 indicated that there is a less than 10 per cent chance that all the major sector loads would
simultaneously decline by 10 per cent.
128. BC Hydro has appropriately accounted for uncertainty in the Load Forecast by
providing a high and low band around the mid-level projection. BC Hydro uses the high and low
band in long-term planning, including contingency planning.193
192
Exhibit B-14, BCUC IR 2.200.2. 193
Exhibit B-14, BCUC IR 2.200.2.
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I. RESPONSE TO AMPC’S TWO “CONCERNS” ABOUT THE MAY 2016 LOAD FORECAST
129. AMPC, in its evidence, identified “concerns” relating to how BC Hydro’s load
forecast methodology accounts for price elasticity in the industrial sector, and BC Hydro’s
growth assumptions for the natural gas and LNG sector.194 As discussed below, BC Hydro’s
Rebuttal Evidence demonstrated that: (a) the May 2016 Load Forecast incorporates appropriate
consideration of price elasticity; and (b) the test period load forecast is insensitive to changes in
natural gas and LNG sector loads.
(a) May 2016 Load Forecast Accounts for Price Elasticity in Industrial Sector
130. AMPC’s evidence focused on BC Hydro’s application of an explicit elasticity factor
of -0.05 to all customer classes. AMPC characterized BC Hydro’s current forecast as reflecting a
“one size fits all” approach to price elasticity, using only high level estimates of the impact of
electricity cost considerations “that are workable for rate classes with thousands of smaller
customers” but not Transmission Service Rate customers.195 AMPC recommended
incorporating in the forecasting process an additional “feedback” step once customers know
the rate implications. BC Hydro explained in its Rebuttal Evidence that it already accounts for
industrial customer price elasticity over and above the explicit elasticity factor.
Explicit -0.05 Elasticity Factor Based on Expert Evidence
131. BC Hydro explained the basis for the explicit -0.05 elasticity factor in its response
to CEABC IR 3.46.1. It stated in part:
BC Hydro’s assumption of -0.05 is based on the direct testimony of Dr. Ren Orans as contained in our 2008 Long-term Acquisition Plan (LTAP) Application to the BCUC. Dr. Orans, who is an expert on the subject matter of price elasticity, recommended BC Hydro assume a -0.05 reduction in load before demand-side management savings from rate increases under a flat design (i.e., rate impacts). In conjunction with this, Dr. Orans also recommended BC Hydro use -0.1 to
194
AMPC Evidence, p.6. 195
AMPC Evidence, p. 8; see also BCSEA AMPC IR 5.1.
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determine the overall savings from both conservation rates and general rate increases.
Adopting Dr. Orans’ recommendations simplifies BC Hydro’s previous process that used short- and long-term price elasticities which avoids double counting of rate-induced conservation and codes and standards and demand-side management program-induced conservation. This evidence was tested through responses to Information Requests and cross examination. The BCUC accepted BC Hydro’s load forecast and methodology for the purpose of its review of the 2008 LTAP.
132. Dr. Orans had identified how a -0.05 factor falls within the range of factors
identified in studies. Also, as discussed below, BC Hydro’s industrial load forecast methodology
considers cost of electricity and its impact on its large industrial customers beyond the explicit
elasticity assumption of -0.05.196
Customer-Specific Viability Assessment Accounts for Electricity Costs
133. As described above, BC Hydro conducts customer-specific reviews to assess the
viability of large industrial customers. In the case of the pulp and paper sector forecast, BC
Hydro performs an even more granular analysis, examining each product line within every pulp
and paper facility. BC Hydro’s assessment of closure risk accounts not only for commodity
market conditions and commodity prices, but also plant and equipment and the customer’s
operating cost profile. Electricity cost is part of a customer’s operating cost profile. The cost of
electricity takes on greater significance when BC Hydro is assessing electricity-intensive
industrial customers. BC Hydro explained:
We are cognizant that operations at the margin in terms of profitability are more exposed to fluctuations in their operating cost profile. BC Hydro pays particular attention to customers facing closure risk. For instance, our customer probability assessments more closely consider security and cost of fiber supply, global supply and demand of product lines, price forecasts, expectations of major equipment failure, ownership appetite for reinvestment and potential for product line conversions.
196
Exhibit B-22, CEABC IR 3.46.1.
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…
Customers assessed to be on the profitability margin – whether due to increases in electricity costs, commodity prices or some other factors – are assigned a higher probability of closure. This, in turn, reduces the load forecast for that customer and the overall load forecast. For example, the projected decline in BC Hydro’s pulp and paper sector load is largely a function of increased probability of production shut down for a number of existing product lines at certain pulp and paper facilities. The probability based approach captures the risk exposure and the stepwise nature in demand for that particular sector because the probability assessments are supported by analysis on the mill lines and the product line markets.197
134. BC Hydro analyzed the impact of the recently announced phase-out of PST on
electricity to provide an indication of how industrial customers would respond to electricity
price increases. PST, like electricity costs, is a cost of production for industrial customers. The
phase-out of PST is equivalent to a 7 per cent reduction in electricity costs. The analysis
demonstrated that the cost of inputs in the production process are reflected in the May 2016
Load Forecast, with the impacts being specific to each mill. Thermo-mechanical pulp mills
demonstrate the greatest sensitivity, as they have higher electricity costs as a percentage of
their operating costs; in some instances there was a reduction in the probability risk of mill
closure by as much as 10 percent over the next ten years. Kraft mills were less responsive,
which one would expect given their self-generation capability.198 Appendix A to the Rebuttal
Evidence provided further information on the PST analysis and the findings.
135. BC Hydro’s response to APMC IR 1.3.2 demonstrated the sensitivity of a generic
metal mining customer to rate increases in the context of the expected price forecast for
copper.
197
Exhibit B-20, Rebuttal Evidence, pp.18-19. 198
Exhibit B-20, Rebuttal Evidence, pp.19-20.
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Additional “Feedback” Step is Unnecessary
136. AMPC has not developed a specific alternative methodology for accounting for
elasticity,199 but did recommend an additional “feedback” step once electricity rates are known.
BC Hydro submits that incorporating AMPC’s recommended additional “feedback” step at this
time is unnecessary for three main reasons.
137. First, part of AMPC’s rationale for this additional step was that “important
resolution and ‘feedback’ is lost by using a ‘one size fits all’ price elasticity of -0.05…”.200 BC
Hydro has explained above that the industrial forecast accounts for elasticity beyond the
common elasticity factor.
138. Second, there is even less value in additional “feedback” in the context of the
2013 10 Year Rates Plan. BC Hydro’s rate increases are capped for the test period, and the caps
have been known to customers for some time. The 2013 10 Year Rates Plan also includes the
target of average annual rate increases of 2.6 per cent over fiscal 2020 to fiscal 2024. BC Hydro
has stated that, based on the approvals sought in this Application, it is on track to meet the
target.
139. Third, Large Industrial load is tracking close to forecast after one full year of the
test period (-0.7) even without an additional “feedback” step. Even that modest negative
variance is primarily associated with the upstream oil and gas sector for the reasons described
above, rather than the “energy intensive and trade exposed” industries like pulp and paper and
mining about which AMPC express concern.
140. The elasticity factor, combined with probability weightings that account for
impacts of production input costs, have been a component of BC Hydro’s load forecasting for a
number of years. They were a part of the load forecasts underlying the 2008 Long-Term
Acquisition Plan and the 2013 Integrated Resource Plan. Most recently, the May 2016 Load
199
BCSEA-AMPC IR 5.3. 200
BCSEA-AMPC IR 2.3.1.
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Forecast and BC Hydro’s most recent Load Resource Balance (found in Chapter 3 of the
Application) underpinned the Akolkolex and Soo River Electricity Purchase Agreements.201 BC
Hydro’s load forecasting methodology continues to be effective in producing a reasonable load
forecast.
(b) BC Hydro’s Test Period Growth Assumptions for the Oil and Gas Sector Are
Reasonable
141. AMPC stated that “for rate-setting purposes, the forecast that BC Hydro has
presented is quite bullish concerning natural gas production and LNG exports.”202 In other
words, AMPC’s argument is the opposite of CEABC’s argument (CEABC’s main thesis in its
evidence is that BC Hydro is understating oil and gas sector load). There are several answers to
AMPC’s argument, which reinforce the reasonableness of BC Hydro’s forecast.
First, 90 per cent of the oil and gas sector load during the test period is
attributed to either existing customers or new projects currently under
construction. These projects are unrelated to development of LNG projects in
British Columbia.203
Second, while the fluidity of the global natural gas market results in uncertainty
in growth projections over the long-term, the market assessment underlying BC
Hydro’s assessment of specific customer requests for electricity service is based
on various credible sources. AMPC did not offer any alternative forecast based
on reliable sources.204
201
Exhibit B-20, Rebuttal Evidence, p.27. 202
AMPC Evidence, p.10. 203
Exhibit B-20, Rebuttal Evidence, pp.22-23; Exhibit B-14-1, BCUC IR 2.197.3 (Revised). 204
Exhibit B-20, Rebuttal Evidence, pp.22-23. AMPC’s response to NIARG-AMPC IR 2.1, 2.2 and 2.3 states “AMPC’s evidence does not recommend a specific downward adjustment to BC Hydro’s natural gas and LNG load forecast.”
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Third, AMPC’s argument that BC Hydro’s forecast is “bullish” was based on a
misapplication of the Fairholm economic analysis used in the May 2016 Load
Forecast. The sensitivity analysis referenced by AMPC actually demonstrated
that economic impacts are relatively insensitive to the range of natural gas
production values used in the load forecasting methodology.205
Fourth, AMPC’s argument is based on a mistaken impression about the
magnitude of the “knock-on” or “multiplier” effect in the Fairholm economic
forecast. AMPC is correct that the overall forecast load is increased by the effect
of the incremental economic activity associated with discrete new large loads
(e.g., natural gas production and LNG export terminals). However, BC Hydro
demonstrated that removing the impacts of LNG from the Fairholm economic
forecast would have an insignificant impact on the overall provincial economy
and sales forecasts over the test period.206
142. AMPC, despite its critique of the oil and gas sector forecast, concedes that
“AMPC members are not better suited than BC Hydro to make forecasts about the oil and gas
and LNG sectors.”207 BC Hydro submits that its own established methodology, which is
supported by industry, customer and third-party information, produces reasonable results.
J. VARIANCES FROM THE LOAD FORECAST ARE CAPTURED IN REGULATORY ACCOUNT
143. As described in Part Six below, Direction No. 7 mandates that load-related
variances in the Cost of Energy continue to be captured in the Non-Heritage Deferral Account.
205
Exhibit B-20, Rebuttal Evidence, p.24; Exhibit B-21, BCUC IR 3.341.1; BCUC IR 3.342.2.2.1. 206
Exhibit B-20, Rebuttal Evidence, p.27; Exhibit B-21, BCUC IR 3.341.1; BCUC IR 3.342.2.2.1. 207
NIARG-AMPC IR 2.1-2.3.
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K. REVENUE FORECAST IS INDUSTRY STANDARD AND CONSISTENT WITH PAST PRACTICE
144. The Revenue Forecast is based on fiscal 2016 rates approved by Commission
Order No. G-48-14 and the energy sales forecast, less demand-side management.208 It excludes
the proposed rate increases sought in this Application and the impact of any future rate
structure changes.209 This is the same approach BC Hydro has used previously and is typical.
There were relatively few information requests on the Revenue Forecast. The Commission
should find that the Revenue Forecast is reasonable.
145. Commission-approved regulatory accounts ensure that customers receive credit
for actual revenues in any event. The following revenue variances are recorded in regulatory
accounts:
All variances from the domestic energy revenue forecast are recorded in the
Heritage Deferral Account or the Non-Heritage Deferral Account;210 and
Revenue variances from Miscellaneous Revenues related to: (i) external
transmission sales under the Open Access Transmission Tariff,211 and (ii)
gains/losses on intercompany transactions related to Commodity Risk212 are
recorded in the Non-Heritage Deferral Account.
L. CONCLUSION AND REQUESTED FINDINGS
146. The evidence outlined in this Part supports BC Hydro’s Load Forecast and
Revenue Forecast for the test period. The Commission and Government have endorsed the
core elements of BC Hydro’s Load Forecasting methodology. The May 2016 Load Forecast is
208
Exhibit B-1-1, Application, p.3-24. 209
Exhibit B-1-1, Application, p.3-24. 210
Exhibit B-9, BCUC IR 1.13.1. Domestic revenue variances other than revenues related to Seattle City Light and the Skagit Valley Treaty, are deferred to the Non-Heritage Deferral Account. Revenue variances related to Seattle City Light and the Skagit Valley Treaty are deferred to the Heritage Deferral Account. Revenue variances from Surplus Sales (Appendix A, Schedule 4.0, Line 6) are also deferred to the Heritage Deferral Account.
211 Exhibit B-1-1, Application, Appendix A, Schedule 15.0, Line 6.
212 Exhibit B-1-1, Application, Appendix A, Schedule 3.1, Line 22.
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supported by a full year of actual results (fiscal 2017) and a variety of favourable external
developments. The Revenue Forecast methodology, which was not a focus in this proceeding,
reflects past practice and is industry standard. The Commission should find that the Load
Forecast and Revenue Forecast for the test period are reasonable. The Load Forecast for years
following the test period will be updated in the 2018 Integrated Resource Plan.
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PART SIX: FORECAST COST OF ENERGY
A. INTRODUCTION
147. BC Hydro’s Cost of Energy forecast is summarized in Table 4-1 from the
Application, inserted below:213
148. The evidence establishes the following points regarding BC Hydro’s forecast Cost
of Energy, each of which is discussed in this Part:
First, BC Hydro has forecasted the Cost of Energy for the test period using a
methodology that reflects how the system is planned and operated.
Second, any variances from the forecast Cost of Energy are captured in deferral
accounts, such that customers only pay for BC Hydro’s actual Cost of Energy.
Third, the increase in the forecast Cost of Energy in the test period is driven
primarily by costs associated with Energy Purchase Agreements pre-dating fiscal
2017, for which cost recovery is mandated.
Fourth, the forecast Cost of Energy reflects reasonable assumptions about future
or renewed Electricity Purchase Agreements, but the actual Cost of Energy
213
The components of Cost of Energy are set out on pages 4-2 and 4-3 of the Application. Appendix K provides an explanation of in the Cost of Heritage and Non-Heritage Energy for fiscal 2015 and fiscal 2016. Appendix A, Schedule 4 shows the Cost of Energy component of the Revenue Requirements Model.
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recovered from customers will reflect the outcome of the Commission’s future
public interest reviews of individual Agreements.
Fifth, the only new Independent Power Producer supplies forecast during the
test period, apart from one potential co-generation facility, are associated with
the legislated Standing Offer Program.
B. FORECAST COST OF ENERGY REFLECTS HOW BC HYDRO PLANS AND OPERATES THE
SYSTEM
149. BC Hydro’s financial forecasting of the Cost of Energy is prepared using the same
Energy Study models that BC Hydro uses to inform operational decisions on system storage,
thermal dispatch, and purchases and sales of market electricity.214 The Cost of Energy forecast
is the expected value (i.e., average) of the distribution of possible outcomes from an Energy
Study that considers a range of inflows, market prices, and loads.215 Using the Energy Studies
to forecast Cost of Energy gives the forecasts a level of rigour, and ensures consistency in
assumptions.
(a) BC Hydro’s Energy Studies Are Robust and Designed for BC Hydro’s System
150. BC Hydro’s Energy Studies are the product of proprietary decision support
models developed for the characteristics of the BC Hydro system.216 A key feature of the
Energy Study models is the explicit modeling of decision-making in light of uncertainty in future
inflows, market prices and loads.217
214
Exhibit B-1-1, Application, p.4-6. 215
Exhibit B-10, BCOAPO IR 1.25.3. Exhibit B-1-1, Application, section 4.2.2. 216
Exhibit B-1-1, Application, p.4-5. 217
Exhibit B-1-1, Application, p.4-6.
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151. BC Hydro’s Energy Study models optimize the operation of hydro and thermal
generating resources to meet domestic load and operating constraints and maximize the net
benefits from market sales.218 Energy Studies consider a broad range of factors, including:
the Load Forecast, net of demand-side management savings, including the range
of values based on temperature variability;
the seasonal shape of resources under contract to BC Hydro;
the range of inflow conditions on the Peace and Columbia River basins;219
the range of market prices for both gas and electricity;220 and
the range of supply expected from all of BC Hydro’s Heritage Resources other
than those in the Columbia and Peace River basins.221
152. The Energy Study methodology is described in detail in the operational
document entitled “Energy Studies Modelling”, which was filed as part of BC Hydro’s response
to BCUC IR 1.15.1.
153. BC Hydro uses an Energy Study horizon that includes five full fiscal years,222 and
then extracts the results for the test period. It is important to model a period longer than the
test period to yield reasonable outputs. The five year period used as the Energy Study horizon
balances the need for accurate short to medium range forecasts (one to three years) with the
218
Exhibit B-10, FortisBC IR 1.1.1. 219
See Exhibit B-1-1, Application, section 4.3.2.1. 220
Section 6 of the Clean Energy Act, and the Electricity Self-Sufficiency Regulation obligate BC Hydro to be self-sufficient based on average water conditions from Heritage resources and its mid load forecast. Planning to average expected conditions results in years where BC Hydro has net surplus sales or net market purchases, depending on a number of factors including customer loads, market prices and system conditions and constraints. Market sales and purchases are thus important considerations in optimizing BC Hydro’s portfolio. See Exhibit B-1-1, Application, section 4.3.2.2, and Exhibit B-10, MoveUP IR 1.14.1.
221 Exhibit B-1-1, Application, p.4-6.
222 More specifically, the horizon starts from the current month out to the end of a calendar year such that five fiscal years are included.
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need to insulate the model results from the impact of boundary conditions.223 BC Hydro also
explained that the use of a shorter time horizon is more likely to introduce a bias in forecast
Cost of Energy relative to actual costs that could give rise to accumulations in the Cost of
Energy Variance Accounts.224
(b) Appropriate Assumptions Regarding Electricity Purchases During Test Period
154. Parties inquiring about Cost of Energy in information requests tended to focus
on the Cost of Non-Heritage Energy, and in particular BC Hydro’s Energy Study assumptions for
electricity purchases from IPPs. IPPs and long-term Electricity Purchase Agreements represent
about 25 per cent of BC Hydro`s electricity supply.225 The forecast Cost of Energy associated
with IPPs and long-term Electricity Purchase Agreements (after accounting adjustments for
capital leases) represents approximately 29 per cent of BC Hydro’s revenue requirements
during the test period.226 BC Hydro submits that it has used appropriate Energy Study inputs
for IPPs already in operation, under contract and nearing completion, renewals and new supply.
Modelling IPPs Under Contract and in Operation
155. BC Hydro models IPPs already under contract and in operation using reasonable
assumptions reflecting the dispatchable or non-dispatchable nature of the resource.227
The majority of IPP contracts are modelled as non-dispatchable resources in
Energy Studies. The forecast for those resources is based on historical
generation, which includes periods in which BC Hydro has exercised rights to
request an Independent Power Producer to reduce or cease energy deliveries for
specified periods.228
223
Exhibit B-10, FortisBC IR 1.1.2. 224
Exhibit B-10, FortisBC IR 1.1.2; 1.1.1.2.3. 225
Exhibit B-1-1, Application, Appendix A, Schedule 4.0. 226
Exhibit B-1-1, Application, p.4-20. 227
Exhibit B-10, BCOAPO IR 1.25.2.1. 228
Exhibit B-10, BCOAPO IR 1.25.2.1.
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The Island Generation Project is modelled as a dispatchable facility and its
forecast reflects an optimal dispatch schedule based on system reliability and
market opportunities.229
156. The historical track record allows BC Hydro to make reasonable forecasts of the
Cost of Energy for existing IPPs under contract.
Modelling IPP Projects About to Reach, or Just Beginning, Commercial Operations
157. BC Hydro forecasted the Cost of Energy for new IPP projects that are about to
reach, or are in the early stages of, commercial operations by applying the contractual price to
forecast volumes.230 The contractual price is known, as is the contracted volume. BC Hydro
adjusted the contracted volume to discount for uncertainty, given the absence of a track
record:
Prior to achieving one full fiscal year of commercial operation, BC Hydro forecasts the volume of energy based on the contracted energy in the Electricity Purchase Agreement. This amount is adjusted at various stages of the project to account for the three key areas of uncertainty:
(i) The likelihood that the IPP will achieve commercial operation;
(ii) When the IPP will achieve commercial operation; and
(iii) The volume of energy deliveries from the IPP project once it achieves commercial operation.
BC Hydro’s assessment of these uncertainties is informed by regular communications with the IPPs with respect to their project development and BC Hydro’s experience that the actual volume of energy deliveries have historically been lower than the IPP estimate.231
229
Exhibit B-10, BCOAPO IR 1.25.2.1. 230
Exhibit B-9, BCUC IR 1.17.5. 231
Exhibit B-9, BCUC IR 1.17.5.
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Modelling Potential Electricity Purchase Agreement Renewals
158. There are a total of 14 Electricity Purchase Agreements whose initial contract
term will have expired prior to the end of fiscal 2019 and which BC Hydro has the the right to
terminate. Thirteen of the 14 Electricity Purchase Agreements are connected to the integrated
grid; the other one is in the Non-Integrated Area.232 The forecast Cost of Energy in the test
period reflects Electricity Purchase Agreement renewal assumptions in line with the 2013
Integrated Resource Plan and BC Hydro’s expectation that Agreements can be renewed on
terms that are more favourable to BC Hydro.
159. Recommended Action #4 from the 2013 Integrated Resource Plan is to optimize
BC Hydro’s portfolio of Independent Power Producer resources to reduce near-term costs while
maintaining cost-effective options for long-term need.233 Achieving this recommended action
requires BC Hydro to look beyond the test period and consider how a renewal will contribute to
meeting long-term system need, for both energy and capacity, in a cost-effective manner over
the renewal contract term.234 BC Hydro explained:
In determining the amount of energy and capacity BC Hydro plans to procure from the renewal of IPP Electricity Purchase Agreements, BC Hydro does not focus on a particular test period. Rather, BC Hydro considers how a renewal will contribute to meeting long-term system need, for both energy and capacity, over the renewal contract term to determine cost-effectiveness which may, or may not, include the applicable test period.
In evaluating the renewal of an Electricity Purchase Agreement, BC Hydro accounts for the type or location of the facilities associated to Electricity Purchase Agreement renewals, among other factors, in the calculation of our opportunity cost. In this calculation we make adjustments to reflect specific project characteristics such as time of delivery, losses to the Lower Mainland, dependable capacity and portion of energy considered firm, where appropriate.
232
Exhibit B-9, BCUC IR 1.18.2. In BC Hydro’s response to MoveUP IR 1.8.3 BC Hydro provided a list of these agreements including the expected termination or contract expiry dates for each Electricity Purchase Agreement. See also: CEC IR 1.32.1.
233 CEC IR 1.32.1.1 (Confidential).
234 Exhibit B-15, BCUC IR 2.194.4; Exhibit B-9, BCUC IR 1.15.2.
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Electricity Purchase Agreements are filed, as required, with the British Columbia Utilities Commission under Section 71 of the Utilities Commission Act. The British Columbia Utilities Commission considers the overall benefit of the contract over its term to ratepayers, including but not limited to the test period when BC Hydro is forecast to be in surplus.235
160. The Cost of Energy forecast assumes that: (i) about 50 per cent of the energy and
capacity contributions from expiring biomass Electricity Purchase Agreements will be renewed;
(ii) about 75 per cent of the energy and capacity contributions from expiring run-of-river
Electricity Purchase Agreements will be renewed.236 The renewal assumptions are applied to
aggregate energy and capacity volumes rather than to the number of contracts.237 The number
of contracts to be renewed is unknown until renewal agreements are reached with the
counterparties.238 BC Hydro elaborated:239
For both bioenergy and run-of-river resources, BC Hydro’s renewal assumptions are estimates of the likelihood of being able to renew contracts, at mutually agreeable pricing that is cost-effective for BC Hydro, considering that a number of these projects’ generating facilities could be 20 years or older at the expiration of their original Electricity Purchase Agreement. Moreover, for biomass, our estimate for these renewals was further informed by our understanding of the reduced long-term certainty of available fibre supply. These assumptions were made using the best information available at the time.
161. BC Hydro expects to achieve significant savings during the test period from
terminating and renewing (as forecast) some Electricity Purchase Agreements. Forecast
renewal costs for the test period are set out in the Confidential response to BCUC IR 1.18.2.240
BC Hydro quantified the expected termination savings in the Confidential response to CEC IR
1.32.1.1.
235
Exhibit B-9, BCUC IR 1.15.2. 236
Exhibit B-1-1, Application, p.4-22. 237
Exhibit B-9, BCUC IR 1.18.1. 238
Exhibit B-9, BCUC IR 1.18.1. 239
Exhibit B-10, CEC IR 1.41.1. 240
The assumed forecast cost is provided in line 14 of BC Hydro’s response to BCUC IR 1.18.2.
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162. The forecast cost for IPP Renewals is not a “target” price for IPP renewal energy.
The energy price for each Electricity Purchase Agreement renewal is a negotiated term. BC
Hydro negotiates with IPPs having regard to an estimate of the IPP’s cost of service (including a
rate of return), BC Hydro’s opportunity cost, the IPP’s opportunity cost, the 2013 10 Year Rates
Plan, and system benefits and support characteristics (if applicable).241 The renewed
agreements will be subject to Commission review, as discussed later.
163. BC Hydro expects the unit cost of IPP energy associated with renewed Electricity
Purchase Agreements to be lower than existing contracts. The forecast Cost of Energy reflects
this expectation. BC Hydro’s confidential response to BCUC IR 2.209.1 provides further details
on renewal price assumptions for particular types of projects.
164. Changes in the level of renewals would not have a material impact on the
revenue requirements during the test period, given that these Electricity Purchase Agreements
represent only a small portion of BC Hydro’s supply portfolio. The forecast Cost of Energy
reductions are small, even assuming no renewals of biomass or run-of-river Electricity Purchase
Agreements. The three-year average impact on the revenue requirements during the test
period would range from approximately 0.2 to 0.4 per cent before accounting for revenue
offsets from surplus sales to market.242
Modelling New IPP Supply Resources
165. BC Hydro is not planning any new power acquisitions from IPPs in the test period
apart from: (i) resources acquired under the Standing Offer Program, including the Micro-
Standing Offer Program; and (ii) the potential acquisition of electricity from one co-generation
facility.243 The price under the Standing Offer Program is based on the most recent BC Hydro
241
Exhibit B-15, CEC IR 2.144.5. 242
Exhibit B-10, CEC IR 1.41.2. 243
Exhibit B-1-1, Application, section 4.4.2.3, page 4-18; CEC IR 1.30.3; BCUC IR 1.15.2.
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call for power.244 BC Hydro is undertaking a pricing review for the Standing Offer Program to
reflect the declining cost of technology and changing system needs.245
Cost of Energy in Non-Integrated Area
166. All 14 communities in the Non-Integrated Area have BC Hydro diesel generation
resources. BC Hydro also has Electricity Purchase Agreements with non-thermal IPP generating
facilities in six of these areas. BC Hydro currently purchases approximately one-third of the
energy supplied in these areas from IPPs.246
167. Zone II was critical of BC Hydro’s pricing for IPP generation in the Non-Integrated
Area, suggesting that BC Hydro is requiring the price of IPP generation to be too low. In Non-
Integrated Area communities where there is or could be a technically viable IPP resource to
displace or offset BC Hydro diesel generation, such IPP generation is cost-effective when its
purchase price is no more than BC Hydro’s avoided costs. BC Hydro’s avoided costs are
generally its fuel costs for diesel generation. Capital costs and operating costs associated with
BC Hydro’s diesel generation facility are generally not avoidable (the facilities must be in place
for reliability purposes in all 14 communities), and so are not considered in IPP pricing.247
C. REGULATORY ACCOUNTS ENSURE CUSTOMERS PAY ACTUAL COST OF ENERGY
168. The two Cost of Energy Variance Accounts capture any variances between what
the Commission determines to be BC Hydro’s forecast Cost of Energy and the actual Cost of
Energy. The accounts ensure that ratepayers only pay the actual Cost of Energy.
244
Exhibit B-10, AMPC IR 1.14.2. 245
Exhibit B-10, AMPC IR 1.14.2 246
The Non-Integrated Cost of Energy is shown on line 39 of Appendix A Schedule 4.0. The forecasted purchase volumes and costs from IPPs in Zone 1B and Zone II are set out in the response to NIARG IR 1.8.3 (Confidential).
247 Exhibit B-10, Zone II IR 1.18.1.
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(a) Cost of Energy Accounts Capture Both Load and Price-Related Variances
169. The Commission approved the Heritage Deferral Account and Non-Heritage
Deferral Account in 2004.248 The Non-Heritage Deferral Account initially captured only price-
related variances, but the Commission subsequently approved the deferral treatment of net
load-related variances as well.249 Since 2009, the Cost of Energy impacts related to net
variances in price and load have been captured in the Cost of Energy deferral accounts.250 The
attachment to BC Hydro’s response to BCUC IR 1.129.3 illustrates how the net load variance
simplifies to the gross cost of energy deferral less the domestic revenue variance.
170. Direction No. 7 affirms the ongoing use of the Commission-approved Heritage
Deferral Account and Non-Heritage Deferral Account. It also mandates that load-related
variances in the Cost of Energy continue to be captured in the Non-Heritage Deferral Account.
Section 7 provides in part:
7 When regulating and setting rates for the authority, the commission
(a) must allow the authority to continue to defer to the heritage deferral account the variances between the actual and forecast heritage payment obligation,
(b) must allow the authority to continue to defer to the trade income deferral account the variances between actual and forecast trade income,
(c) must, in regard to the non-heritage deferral account[251], allow the authority to
(i) continue to defer to that account the variances between actual and forecast cost of energy arising from differences between actual and forecast domestic customer load, and …
248
Order G-96-04, Reasons for Decision, section 4.5 of the reasons that accompany that order. 249
Order No. G-16-09. 250
Exhibit B-9, BCUC IR 1.129.3. Also, the preamble to BCUC IR 1.129.3 (with two corrections identified in BCUC 2 278.1) recounts the history of the approvals.
251 Direction No.7 defines the "non-heritage deferral account" as meaning “the Non Heritage Deferral Account established under commission order G-96-04 and the direction in section 4.5 of the reasons that accompany that order.”
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171. The Commission’s prior approvals to defer non-load related variances to the
Non-Heritage Deferral Account were for continued use, and thus BC Hydro does not require
specific approvals for the test period. In past revenue requirements applications, BC Hydro
needed approval to continue to defer the load related variance for each test period. As a result
of Direction No. 7 mandating the deferral of load-related variances, the Commission should
grant its approval for ongoing use for this purpose beyond the test period.252
(b) BC Hydro is Amenable to Deferring Electricity Purchase Agreement Accounting
Classification Variances
172. In fiscal 2015 and fiscal 2016 BC Hydro included the deferral of $22.8 million and
$31.0 million respectively into the Non-Heritage Deferral Account for the benefit of ratepayers.
The deferrals to the Non-Heritage Deferral Account related to both a change in the required
accounting treatment of the Electricity Purchase Agreements, and the timing of when the
facilities reached commercial operation (i.e., when they started to produce electricity relative
to the planned starting date). BC Hydro did not request a directive to defer cost variances
related to Electricity Purchase Agreements classified as finance leases in this Application, since
BC Hydro was not anticipating any variances related to accounting classification or commercial
operation date timing. However, BC Hydro subsequently became aware that the commercial
operation dates for the two new fiscal 2017 Electricity Purchase Agreement finance leases have
been delayed and have caused variances in fiscal 2017. These variances are favourable
variances and, unless recorded in a regulatory account, would be to the account of the
shareholder. BC Hydro indicated in its response to BCUC IR 1.131.3 that it would not be
opposed to a directive requiring the deferral to the Non-Heritage Deferral Account of all test
period variances attributable to Electricity Purchase Agreements classified as finance leases
that would not be transferred to existing regulatory accounts pursuant to existing orders. BC
Hydro has deferred favorable variances in fiscal 2017 based on this approach, which benefitted
ratepayers.
252
Exhibit B-9, BCUC IR 1.131.1.
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173. BC Hydro requests that, if the Commission issues such a directive, that it be
reassessed in the next revenue requirements application as a new IFRS leasing standard will be
in effect for fiscal 2020. The new leasing standard, and related interpretations and guidelines
are not yet finalized. Accordingly, it is not yet possible to determine the impacts of the new
standard.253
(c) Actual Cost of Energy Unaffected By Commission’s Determination of Forecast
174. The Commission’s determination in this proceeding as to the forecast Cost of
Energy affects the variances captured in the Cost of Energy Variance Accounts during the test
period, but does not affect what BC Hydro (and, ultimately, ratepayers) will pay for energy.254
As described below, the actual Cost of Energy is influenced by the cost of Heritage Resources
and both past and future Electricity Purchase Agreements. Recovery of costs associated with
existing Electricity Purchase Agreements pre-dating fiscal 2017 is mandated, and the
Commission will review future Electricity Purchase Agreements, as required, in section 71
applications.
D. MANDATED COST RECOVERY FOR EXISTING ELECTRICITY PURCHASE AGREEMENTS
175. The main driver of forecast increases in the cost of IPP energy during the test
period is higher cost IPP projects achieving commercial operation under Electricity Purchase
Agreements predating fiscal 2017.255 Cost recovery is mandated for these Electricity Purchase
Agreements. BC Hydro has nevertheless taken steps to reduce purchase commitments, and
thus reduce energy costs, under existing Electricity Purchase Agreements.256
253
Exhibit B-9, BCUC IR 1.134.2. 254
Exhibit B-15, BCUC IR 2.208.1. 255
Exhibit B-1-1, Application, p.4-24. 256
Exhibit B-1-1, Application, pp.3-42, 3-43.
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(a) Direction No. 7 Covers Much of the Increase in Forecast Cost of Energy
176. As of May 1, 2016, there were 127 active Electricity Purchase Agreements in
respect of IPP projects on the integrated system. Twenty-two of the 127 projects are expected
to achieve commercial operation during the test period.257 The addition of new IPP resources
will increase the unit cost of IPP energy, as depicted in Appendix A, schedule 4 of the
Application, Line 20. BC Hydro explained:
The increase in unit cost from IPPs over the test period is primarily attributed to an increase in the number of IPPs achieving commercial operation and delivering energy to BC Hydro during the test period. As these new resources are added, those contract prices are higher than the average, the average unit cost for the IPP portfolio will increase. Annual price escalation provisions included in Electricity Purchase Agreements also increase the unit cost to some degree.258
177. Direction No. 7 directs the Commission to allow BC Hydro to recover the Cost of
Energy associated with Electricity Purchase Agreements that predate fiscal 2017. Section 11 of
Direction No.7 provides, in part:
11 When setting rates for the authority under the Act, the commission must not disallow for any reason the recovery in rates of the costs that were incurred by the authority or Powerex Corp. in consequence of decisions of either with respect to
…
(b) energy supply contracts entered into before F2017, …
178. All 22 of the projects coming in to service during the test period are the subject
of Electricity Purchase Agreements that pre-date fiscal 2017, and are thus covered by section
11.259
257
Exhibit B-9, BCUC IR 1.17.4. 258
Exhibit B-9, BCUC IR 1.17.2. 259
Exhibit B-9, BCUC IR 1.17.4.
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179. In the response to BCUC IR 1.18.2 (Confidential), BC Hydro provided a
breakdown of IPP renewals as a proportion of total IPP resources included in the Cost of Energy
forecast for the test period. The relevant information is found on lines 13 and 14 of the table in
that response. The information provided demonstrates that the vast majority of the forecast
Cost of Energy is covered by section 11(b), such that the Commission must permit BC Hydro to
recover those costs in rates.
(b) BC Hydro Has Reduced Purchase Commitments Under Existing Agreements
180. BC Hydro’s IPP purchases serve long-term needs, and system supply exceeds
load requirements in the near-term. BC Hydro has reduced purchase commitments under
existing Electricity Purchase Agreements with IPPs by negotiating termination, deferral and/or
downsizing where the project has not reached commercial operation. BC Hydro described in
section 3.4.3.5 of the Application that, as a result of such agreements with IPPs reached since
the 2013 Integrated Resource Plan, BC Hydro has reduced Electricity Purchase Agreement
commitments by $2.1 billion.260 The $2.1 billion in reduced purchase commitments is already
reflected in the forecast Cost of Energy.
181. BC Hydro was asked whether it can displace the purchase/renewal of additional
higher cost IPP energy with additional demand-side management. BC Hydro explained that it
would not displace IPP energy with additional demand-side management acquisitions, as IPP
purchases are part of a balanced approach to acquiring resources and are aligned with
Government policy:
The Recommended Actions of the approved 2013 IRP and as further informed by the 2013 10 Year Rates Plan offer a balanced approach to acquiring resources, are consistent with the Clean Energy Act and its 16 Energy Objectives, and have a letter of support from the Minister for the Demand Side Management Plan (please refer to BC Hydro’s response to CEC IR 2.175.1 for further details).
260
Exhibit B-9, BCUC IR 1.17.3.
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With BC Hydro’s approach of following the Integrated Resource Plan Recommended Actions and the Demand Side Management Plan after fiscal 2015 and fiscal 2016 (the years highlighted in Demand Side Management Recommended Action #1), if BC Hydro was to acquire less energy in one category that would not necessarily result in an increase in the other. BC Hydro’s actions with regards to Electricity Purchase Agreement renewal and demand side management are designed to maintain a presence in the markets consistent with the Clean Energy Act, objectives 2(d) to use and foster the development in British Columbia of innovative technologies that support energy conservation and efficiency and the use of clean or renewable resources; 2(h) to encourage the switching from one kind of energy source or use to another that decreases greenhouse gas emission in British Columbia; 2(k) to encourage economic development and the creation and retention of jobs; 2(l) to foster the development of first nation and rural communities thought the use and development of clean or renewable resources; and the 2013 IRP.261
E. COMMISSION WILL REVIEW RENEWED AGREEMENTS
182. As discussed above, the forecast Cost of Energy reflects assumptions about
future acquisition of energy from Independent Power Producers, but the assumptions are
neither targets nor budgets. BC Hydro is not seeking approval of specific Electricity Purchase
Agreements in this proceeding. BC Hydro will file any new or renewed Electricity Purchase
Agreements (apart from those agreements exempted by regulation, such as the Standing Offer
Program) with the Commission for review under section 71 of the Act.262 By virtue of the two
Cost of Energy deferral accounts described above, the actual costs recovered from customers
will reflect only the Electricity Purchase Agreements accepted by the Commission under section
71.
183. The Commission’s section 71 review of each Electricity Purchase Agreement is a
public interest assessment. Section 71 sets out a number of factors that the Commission must
consider in the context of its public interest review:
261
Exhibit B-15, CEC IR 2.147.1. 262
Exhibit B-9, BCUC IR 1.3.1.
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(2.21) In determining under subsection (2) whether an energy supply contract filed by the authority is in the public interest, the commission, in addition to considering the interests of persons in British Columbia who receive or may receive service from the authority, must consider and be guided by
(a) British Columbia’s energy objectives,
(b) an applicable integrated resource plan approved under section 4 of the Clean Energy Act,
(c) the extent to which the energy supply contract is consistent with the requirements under section 19 of the Clean Energy Act,
(d) the quantity of the energy to be supplied under the contract,
(e) the availability of supplies of the energy referred to in paragraph (d),
(f) the price and availability of any other form of energy that could be used instead of the energy referred to in paragraph (d), and
(g) in the case only of an energy supply contract that is entered into by a public utility, the price of the energy referred to in paragraph (d).
184. In the context of a section 71 review, the Commission considers the overall
ratepayer benefit of the Electricity Purchase Agreement over its term, having regard to the
Load Forecast.
185. BC Hydro has signed new Electricity Purchase Agreements for two of the 13
expiring IPP projects in the integrated area (Akolkolex and Soo River).263 BC Hydro submitted
these agreements to the Commission on September 15, 2016, and the Commission recently
accepted them in Order E-1-17.264
263
Exhibit B-9, BCUC IR 1.18.2. In BC Hydro’s response to MoveUP IR 1.8.3 BC Hydro provided a list of these agreements including the expected termination or contract expiry dates for each Electricity Purchase Agreement.
264 Exhibit B-9, CEC IR 1.30.3.
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186. The Load Forecast data filed in support of future section 71 applications may or
may not be the same load forecast data submitted as part of this Application or as part of the
Akolkolex and Soo River applications.265 BC Hydro updates its Load Forecast regularly based on
more current information.
F. STANDING OFFER PROGRAM IS LEGISLATED
187. As discussed above, apart from the potential acquisition of electricity from one
co-generation facility, the only new power acquisitions during the test period are under the
Standing Offer Program (including the Micro-Standing Offer Program).266 The Standing Offer
Program is a requirement under section 15(2) of the Clean Energy Act. New Electricity Purchase
Agreements that fall within BC Hydro’s Standing Offer Program are exempt from section 71 of
the Utilities Commission Act.267 In addition, the Commission must allow BC Hydro to recover
Standing Offer Program energy costs.268 As stipulated by the 2007 Energy Plan, the contract
price offered is based on BC Hydro’s most recent BC Hydro call for power.269 The Government-
approved 2013 Integrated Resource Plan set an energy volume target of 150 GWh/year.270
188. BC Hydro is optimizing the Standing Offer Program and Micro-Standing Offer
Program so that they reflect future system needs, consider recent advancements in technology,
and are aligned with the 2013 10 Year Rates Plan.271 Any Cost of Energy savings during the test
period that result from this optimization will be captured in the Cost of Energy deferral
accounts.
265
Exhibit B-15, BCUC IR 2.195.4. 266
Exhibit B-10, CEC IR 1.30.3; Exhibit B-1-1, Application, .p. 4-18. 267
Clean Energy Act, s.7. 268
Clean Energy Act, s.8. 269
Exhibit B-10, AMPC IR 1.14.2. 270
Exhibit B-15, CEC 2.170.1. 271
Exhibit B-9, BCUC IR 1.17.3. Exhibit B-1-1, Application p. 4-18
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G. CONCLUSION AND REQUESTED FINDINGS
189. BC Hydro’s forecast Cost of Energy is based on a sound methodology and
reasonable assumptions. The Commission should find that BC Hydro’s forecast Cost of Energy
for the test period, the vast majority of which is associated with Heritage Resources and energy
purchase agreements with IPPs that are covered by Direction No.7,272 is reasonable. The
Commission’s determination on the forecast, while necessary for rate setting purposes, will not
impact the actual Cost of Energy paid by customers that is “trued up” using existing deferral
accounts. BC Hydro is not requesting approval for any Electricity Purchase Agreements in this
Application, so the Commission should not make any determinations on the appropriate
renewal terms. BC Hydro will be filing with the Commission any renewed Electricity Purchase
Agreements, as required, under section 71 of the Act.
272
BCUC IR 1.18.2 (Confidential).
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PART SEVEN: OPERATING EXPENSES
A. INTRODUCTION
190. Following the 2011 Government Review and the announcement of the 2013 10
Year Rates Plan, BC Hydro limited average annual increases in base operating expenses to 1.8
per cent between fiscal 2013 and fiscal 2016. As most of BC Hydro’s base operating costs are
subject to inflationary pressures, limiting the rate increase to this level required careful
management and effort to find efficiencies.273 BC Hydro’s forecast revenue requirements for
the test period reflect continued fiscal discipline and support for important priorities and
customer service, consistent with the 2013 10 Year Rates Plan and the Minister’s Mandate
Letter. The following points, established in this Part, demonstrate the reasonableness of BC
Hydro’s forecast operating expenses:
First, the forecast increase in base operating costs excluding previously incurred
and deferred sustainment costs relating to the Smart Metering and
Infrastructure Program sustainment costs averages only 1.2 per cent annually
over the test period.
Second, BC Hydro has used an effective operating cost planning process to
identify required operating expenditures, cost savings and efficiencies.
Third, BC Hydro is undertaking a number of initiatives to improve how the
company operates, including Smart Metering, Work Smart and Workforce
Optimization.
Fourth, the planned operating costs and Full Time Equivalents (“FTEs”) for each
of BC Hydro’s four Business Groups reflect BC Hydro’s emphasis on cost
containment and specific priorities while maintaining performance.
273
Exhibit B-1-1, Application, p. 5-1.
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Fifth, BC Hydro’s employee compensation program is reasonable and cost-
effective. BC Hydro has limited increases to Management and Professional
salaries and those salaries remain below market comparables. Unionized
employees are compensated consistently with the market on a total rewards
basis. BC Hydro has implemented strategies to manage and limit overtime.
191. BC Hydro has also addressed in this Part the repatriation of work currently
outsourced to Accenture Business Services of British Columbia Limited Partnership (ABSBC),
which is expected to be beneficial to customers but have an immaterial impact on BC Hydro’s
test period revenue requirements.
B. BC HYDRO LIMITED THE ANNUAL AVERAGE INCREASE IN BASE OPERATING COSTS
192. BC Hydro limited the forecast average annual increase in base operating costs
excluding sustainment costs related to the Smart Metering and Infrastructure Program to 1.2
per cent over the test period.274
193. BC Hydro’s base operating costs are summarized in Table 5-5.275 In terms of
illustrating BC Hydro’s ongoing efforts to contain operating costs, the trend in base operating
costs excluding sustainment costs related to the Smart Metering and Infrastructure Program is
more meaningful than year-over-year changes in total operating costs shown on Table 5-6 of
the Application.276 Two factors distort the trend in forecast operating expenses during the test
period:
First, the sustainment costs related to the Smart Metering and Infrastructure
Program are not new costs; rather, the cost classification has changed. Smart
Metering and Infrastructure sustainment costs were also incurred before the
test period and were deferred to the Smart Metering and Infrastructure
274
Exhibit B-1-1, Application, p. 5-1. They are forecast to increase by $11.7 million in fiscal 2017, $2.1 million in fiscal 2018 and $11.9 million in fiscal 2019.
275 Exhibit B-1-1, Application, p. 5-19.
276 Exhibit B-1-1, Application, p. 5-24.
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Regulatory Account pursuant to Commission orders277 and Direction No. 6.278
These sustainment costs are no longer being deferred and are included in the
operating costs of the various business groups. The costs are also necessary to
achieve the net benefits (revenue and load reduction benefits) of the Smart
Metering and Infrastructure Program.279
Second, BC Hydro’s forecast operating expenditures include IPP capital leases
(long-term contracts)280 and ineligible capital overhead.281 These amounts are
significant during the test period, specifically: $131.1 million in fiscal 2017;
$188.9 million in fiscal 2018; and, $202.0 million in fiscal 2019.282 IPP capital
leases and ineligible capital overhead are excluded from base operating costs
because (i) they are driven by accounting rules, and (ii) can vary significantly
from year to year, either by way of an increase or decrease in operating costs.283
BC Hydro explained why capital overhead costs are removed from calculating
base operating costs in its response to CEABC IR 1.2.2.
277
Commission Order Nos. G-77-12A and G-48-14 collectively covered the period spanning fiscal 2012 to fiscal 2016.
278 See section 3(l).
279 Exhibit B-1-1, Application, p. 5-1. The sustainment costs related to Smart Metering and Infrastructure are forecast to decline over the course of the test period ($22.1 million in fiscal 2017, decreasing by $1.4 million in fiscal 2018 and decreasing by $0.1 million in fiscal 2019). Exhibit B-10, CEC IR 1.42.3.
280 Exhibit B-1-1, Application, p. 4-23, Exhibit B-10, CEC IR 1.71.3: There are currently two Energy Purchase Agreements treated as capital leases. The increase in fiscal 2018 and fiscal 2019 is due to two new Energy Purchase Agreements that will be treated as capital leases, and that are beginning commercial operations in late fiscal 2017. In fiscal 2019, capital lease costs decrease due to one of the current Energy Purchase Agreements reaching the end of its contract at the end of fiscal 2018.
281 Please see Exhibit B-9, BCUC IR 1.37.1 for a further explanation of BC Hydro’s calculation for eligible capital overhead and the impact of ineligible capital overhead.
282 Exhibit B-1-1, Application, Table 5-6, p. 5-24.
283 Exhibit B-1-1, Application, p. 5-18. See also Exhibit B-10, CEABC IR 1.2.1.
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C. BC HYDRO HAS AN EFFECTIVE OPERATING COST PLANNING APPROACH
194. BC Hydro uses an effective operating cost planning process to identify required
operating expenditures, cost savings and efficiencies. BC Hydro tracks its performance and
manages to budget.
(a) Top-Down / Bottom Up Iterative Operating Cost Planning
195. BC Hydro used its top-down / bottom-up iterative operating cost planning
process to produce the planned operating costs for the test period.
196. Two top-down considerations drove the planning process:
BC Hydro’s priorities: BC Hydro focused on investments aligned with BC Hydro’s
updated vision, key goals and priorities. The priorities are set by BC Hydro’s
Executive Team. They form the basis for the annual Service Plan, which is
approved by the Executive Team and the Board of Directors.284
The 2013 10 Year Rates Plan: BC Hydro is managing its overall costs to stay
within the 2013 10 Year Rates Plan. Its operating cost framework maintains
fiscal discipline while also providing the flexibility to support important priorities
and improve service. BC Hydro continues to seek opportunities to reduce
expenditures.285
197. The bottom-up element of the planning process required each business group to
evaluate cost pressures and savings opportunities.286 The initial review by business groups was
followed by an iterative process involving the Executive Team, senior management, and
business group teams:
284
Exhibit B-1-1, Application, page 5-7. Exhibit B-14, BCUC IR 2.193.1. 285
Exhibit B-1-1, Application, page 5-7. Exhibit B-14, BCUC IR 2.193.1. 286
Exhibit B-1-1, Application, page 5-7.
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Executive Team members met with their leadership teams to discuss their
budgeting requirements, considering BC Hydro’s priorities and the 2013 10 Year
Rates Plan as noted above. They reviewed cost pressures and savings
opportunities.
Leadership teams for each business group then worked with their broader teams
to examine potential cost pressures and savings in more detail. They undertook
this work with consideration of current operational needs based on forecast
work plans and resourcing requirements.
The business group leadership teams consulted iteratively with their respective
Executive Team member, in conjunction with Finance Directors, to identify
initiatives associated with BC Hydro’s mission and key priorities, cost pressures
and savings opportunities.287
Items identified in the preceding step were consolidated and reviewed by the
Finance Directors and the Executive Vice-President, Finance & Business Services
and Chief Financial Officer. The purposes of the review were to align budgets
with the direction from the Executive Team and to consider how potential
operating cost amounts would fit within the 2013 10 Rates Plan framework.
The Executive Team reviewed preliminary budgets.
Once the budget was approved by the Executive Team, the Board of Directors
approved the annual base operating cost budget.288
198. As described in more detail later in this Part, the top-down / bottom-up iterative
process yielded significant cost savings to help offset these pressures.
287
Exhibit B-9, BCUC IR 1.39.5 and Exhibit B-14, BCUC IR 2.193.1. 288
Exhibit B-14, BCUC IR 2.193.1.
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(b) BC Hydro Tracks Progress Against Budget
199. BC Hydro oversees progress against budget through financial and management
reporting.289 Managers receive monthly reporting outlining their monthly and year-to-date
costs. The managers, working with Finance and business group leadership, must quantify and
explain variances, identify any expected challenges in meeting annual targets, and implement
actions to remain on-track.290 The Executive Team reviews monthly and year-to-date financial
results, including operating costs and variances, for all Key Business Units and business groups.
They examine opportunities throughout the organization to address emerging cost pressures
and to identify cost savings and efficiencies.291 These controls and processes will play a key role
in keeping BC Hydro on track with planned operating expenses.292
D. INITIATIVES ARE IMPROVING HOW BC HYDRO OPERATES
200. BC Hydro has undertaken, and is undertaking, initiatives to improve how the
company operates. The initiatives include the Smart Metering and Infrastructure Program, and
two company-wide efficiency and improvement programs - the Work Smart program and
Workforce Optimization Program.293 BC Hydro has also improved its management of IBEW
overtime.
(a) Smart Metering and Infrastructure Program Delivers Net Benefit to Ratepayers
201. The Smart Metering and Infrastructure Program is a foundational step in
modernizing BC Hydro’s electricity system. It allowed BC Hydro to replace existing customer
meters with Smart Meters and upgrade the technology and telecommunications infrastructure.
The Program provides information that will allow BC Hydro to operate its system more
289
Exhibit B-14, BCUC IR 2.193.1. 290
Exhibit B-14, BCUC IR 2.193.1. 291
Exhibit B-14, BCUC IR 2.193.1. 292
Exhibit B-15, NIARG IR 2.9.2. 293
Exhibit B-1-1, Application, p. 5-16.
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effectively. It will also provide better information to customers.294 The Smart Metering and
Infrastructure Program yields incremental revenue and load reduction benefits,295 resulting in
an overall net positive benefit to ratepayers.
202. BC Hydro completed the Smart Metering and Infrastructure Program in fiscal
2016, on time and under budget. The Smart Metering and Infrastructure Program had an
approved budget of $930 million, but was implemented for $779.2 million. As of March 31,
2016, and as contemplated in the Smart Metering and Infrastructure Business Case,296 all
sustainment activities related to the implemented Smart Metering and Infrastructure
technologies were integrated into the business groups to which they relate.297
203. The SMI Completion Report, which BC Hydro filed during the proceeding for
inclusion as Appendix P to the Application, assessed the overall costs and benefits of the SMI
Program. BC Hydro filed several responses to information requests with financial information
about the Program, including ongoing sustainment costs, FTEs, incremental operating costs,
savings and net impacts in the test period.298 The bottom line is that Smart Meters have
delivered $235 million in benefits to customers in the first five years. The Program is projected
to deliver $1.1 billion in benefits (net-present value) by fiscal 2033.299
204. BC Hydro’s decision to take back responsibility for meter reading from Accenture
in 2016 did not affect Smart Metering and Infrastructure Program sustainment costs.300 The
294
Exhibit B-1-1, Application, p. 5-8. 295
Exhibit B-10, CEC IR 1.42.3. 296
Exhibit B-1-4, Application, Appendix P. 297
Exhibit B-1-1, Application, p. 5-8. 298
BC Hydro’s response to CEC IR 1.42.3 outlines the benefits of the SMI program for the test period. BC Hydro’s response to BCUC IR 2.214.3 provides a detailed breakdown of the fiscal 2017 incremental operating and maintenance costs from the Smart Metering and Infrastructure sustainment activities for all five key business units. See also Exhibit B-15, CEC IR 2.152.1 and Exhibit B-10, CEC IR 1.59.1.
299 Exhibit B-10, Zone II IR 1.6.3.
300 Exhibit B-14, BCUC 2.247.1.
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FTEs engaged in meter reading are included within the Customer Services FTE forecasts, with
the increase in internal labour costs being offset by a reduction in Accenture contract costs.301
(b) Work Smart Program Introduces Process Improvements
205. BC Hydro has implemented a Work Smart program for continuous process
improvement. It has delivered a variety of benefits, and will continue to do so during the
remainder of the test period.
Work Smart is Based on “Lean” Principles
206. The Work Smart program is based upon Lean principles, a business philosophy
focused on the needs of the customer (internal and/or external). The Work Smart program
includes streamlining work and identifying and eliminating non-value added activities. It
engages employees and leaders across BC Hydro to identify potential initiatives.302 The
program delivers business value by reducing variation, waste and cycle time, while promoting
the use of work standardization and flow.303
207. A Work Smart team, comprised of of two dedicated FTEs and approximately 0.2
additional FTEs, manages the program.304 The Work Smart team, sometimes in association with
third-party service providers, guides employees throughout the process improvement cycle. It
helps to identify processes that can be improved and helps business units design and
implement future processes.305 The team consults with management and the Executive Team
on a regular basis, reporting on planned and completed initiatives, as well as future plans.
208. BC Hydro identified the planned fiscal 2017 Work Smart initiatives and described
the expected benefits in its response to BCUC IR 1.32.4. Planning for fiscal 2018 commenced in
301
Exhibit B-14, BCUC 2.247.1. 302
Exhibit B-9, BCUC IR 1.32.4. 303
Exhibit B-1-1, Application, p. 5-13. 304
Exhibit B-9, BCUC IR 1.32.5. 305
Exhibit B-9, BCUC IR 1.32.5.
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November 2016, and planning for fiscal 2019 will commence in November 2017. As part of the
planning process, BC Hydro is considering additional ways to enhance Work Smart and its
benefits across the organization beyond process-specific initiatives.306
Modest Investment is Required to Achieve Significant Work Smart Benefits
209. The Work Smart initiatives involve only modest investment. Any fees paid to
third-party service providers facilitating Work Smart initiatives are paid from existing budgets.
The benefits are expected to, at minimum, offset these costs.307 The benefits are as follows:
Work Smart’s key measure of success is capacity hours gained. Capacity hours
gained measures the difference between the work effort of a process before the
Work Smart initiative is undertaken and after implementation of the Work Smart
recommendations.308 BC Hydro estimated annual 22,500 capacity hours gained
as at the end of fiscal 2016.309 Further initiatives are underway and will continue
through the test period.310
Other Work Smart benefits include improved customer service, worker safety,
and regulatory performance.311 BC Hydro cited the example of a recent initiative
regarding its process for safety incident investigations. The initiative improved
BC Hydro’s ability to meet updated WorkSafe BC reporting requirements and
timelines. It also streamlined processes, which will reduce the burden on front
line workers and enhance BC Hydro’s ability to share and learn from safety
incidents.312
306
Exhibit B-9, BCUC IR 1.32.4. 307
Exhibit B-9, BCUC IR 1.32.4.1. 308
Exhibit B-14, BCUC IR 2.193.1. Please also refer to BC Hydro’s response to BCUC IR 2.213.2 for more information regarding the calculation of capacity hours gained.
309 Exhibit B-9, BCUC IR 1.32.3.
310 Exhibit B-9, BCUC IR 1.32.4.
311 Exhibit B-9, BCUC IR 1.32.3.
312 Exhibit B-9, BCUC IR 1.32.3.
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(c) Workforce Optimization Yields Optimal Mix of Internal and External Resources
210. The Workforce Optimization Program, launched in July 2015, is directed at
ensuring that BC Hydro’s resourcing model includes the right mix of internal and external
resources.313 A contractor workforce is replaced with internal employees where substitution
can improve business outcomes and/or produce demonstrable financial savings.314
Workforce Optimization Program Targets Cost Savings
211. BC Hydro described the Workforce Optimization Program in section 5.3.1.3 of
the Application. Business Groups identified areas where cost and/or risk could be reduced, or
outcomes improved, by shifting work from external contractors to internal employees. Each
opportunity was brought before the Executive Team for review and approval. BC Hydro
evaluated each potential internal position to ensure the benefits of moving that work in-house
outweighed any potential disadvantages, including the loss of flexibility. The approved
positions represented work that is anticipated to be steady and ongoing, where the value of
contractor flexibility is low.315
212. At the end of October 2015, approximately 170 FTEs had been approved for hire
through fiscal 2019 with offsetting reductions in the use of external resources. Approximately
70 per cent of these positions relate to capital construction (to be performed by the Capital
Infrastructure Project Delivery Business Group) or the Technology Key Business Unit (within the
Transmission, Distribution and Customer Service Business group).316
313
Exhibit B-1-1, Application, p. 5-15. 314
Exhibit B-9, BCUC IR 1.52.3. 315
Exhibit B-10, CEC IR 1.45.2. 316
Exhibit B-10, BCOAPO IR 1.9.1. Exhibit B-10, CEC IR 1.44.1.
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Workforce Optimization Has Reduced Forecast Costs in the Test Period
213. Increased labour costs associated with hiring more FTEs will be more than offset
by a reduction in contractor costs.317
214. The operating cost increase associated with the 170 FTEs related to Workforce
Optimization is approximately $1.2 million.318 Operating costs are impacted by hiring FTEs to
replace contractors working on capital projects because, unlike contractors, BC Hydro
employees working on capital projects spend some of their time on internal, non-project
related activities (e.g., general training) that cannot be capitalized. The operating cost impacts
have been reflected in BC Hydro’s operating budgets in this Application.319
215. The financial benefits of the program are primarily capital savings as the majority
of optimization opportunities pertain to resources executing capital work.320 Capital labour
savings as a result of these hires more than offset the operating cost increases. Expected net
savings over the three years of the test period total $3.7 million, $6.2 million and $6.6 million,
respectively.321
216. Hiring additional FTEs will also improve BC Hydro’s ability to manage capital
contracts, thereby reducing project delivery risk.322
317
Exhibit B-9, BCUC IR 1.52.2, 1.52.3. 318
Exhibit B-9, BCUC IR 1.33.3. Exhibit B-14, BCUC IR 2.212.1: 170 FTEs were approved under the Workforce Optimization Program up to October 31, 2015. This breakdown was provided to maintain consistency with the budgeted FTEs and associated dollar impacts found elsewhere in the Application. By December 31, 2015, as the Workforce Plan (Appendix F) was being finalized, a total of approximately 200 FTEs had been approved through Workforce Optimization. The approximately 30 incremental FTEs approved in November and December 2015 (which are not reflected in the budget targets found in the Application) represent additional employees in the Aboriginal Relations, Environmental Risk Management, Technology and Field and Grid Operations key business units.
319 Exhibit B-1-1, Application, p. 5-16. The operating cost increases are driven primarily by the addition of Project Delivery resources in fiscal 2017 and fiscal 2018 as noted on page 5-119, lines 10 to 12 of the Application.
320 Exhibit B-1-1, Application, p. 5-16.
321 Exhibit B-9, BCUC IR 1.33.5. Fiscal 2016 savings attributable to Workforce Optimization were immaterial due to the scheduled timing of recruitment of the 170 positions through Fiscal 2019.
322 Exhibit B-9, BCUC IR 1.33.3.
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Controls Are in Place to Manage Workforce Optimization
217. BC Hydro has established controls and processes for managing the Workforce
Optimization Program:
Business groups identify opportunities where costs and/or risk can be reduced or
outcomes improved by shifting work from external contractors to internal FTEs.
As requests for changes in FTEs under the Workforce Optimization Program are
identified, the requesting Key Business Unit must identify the FTEs as well as the
associated financial impact323 (i.e., increase in labour costs and related savings in
contractor costs).
Requests are then reviewed by the Human Resources Lead, Finance Director and
the Executive responsible for the Key Business Unit.324
Approved requests are tracked by Finance, and budget adjustments are made
during the planning cycle to reflect the financial impacts provided in the
request.325
Monthly reporting provides an overview of activity in the Program. This
reporting includes approved and pending requests, associated financial and FTE
impacts, and positions filled to date. The reporting is reviewed by Human
Resources, Finance and the Executive Team to monitor the progress and the
overall impact of the Program.326
323
Exhibit B-14, BCUC IR 2.193.1. 324
Exhibit B-14, BCUC IR 2.193.1. 325
Exhibit B-14, BCUC IR 2.193.1. 326
Exhibit B-14, BCUC IR 2.193.1.
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E. BUSINESS GROUP FTEs AND COSTS REFLECT RESTRAINT AND PRIORITIZATION
218. BC Hydro sought out significant savings and efficiencies to mitigate cost
increases. It looked at all areas of the organization. BC Hydro prioritized spending and is
focussed on performing to the expectations of customers.
(a) BC Hydro Identified Savings Across the Corporation
219. Savings and efficiencies of $33.2 million are planned in fiscal 2017. These savings
are expected to continue throughout the test period, with minor additional savings in fiscal
2018 and fiscal 2019. The savings in fiscal 2017 include the following: 327
(a) $15.0 million in the Transmission, Distribution and Customer Service Business
Group.328 The annual savings are associated with an initiative targeting, for
instance: inspections frequency optimization, technology functional reviews,
work coordination and optimization, customer service cost savings
improvements, vegetation management tools implementation and trouble
response process improvements.
(b) $7.0 million related to the partial decommissioning of the Burrard Thermal Plant
and its conversion to operating as a synchronous-condense facility. The savings
are primarily related to labour.
(c) $6.9 million of savings in various other areas including consultants, donations
and sponsorships, property lease savings and the cancellation of BC Hydro’s
membership in the Canadian Electricity Association.
(d) $4.3 million in company-wide savings from ongoing efforts to find cost savings
and efficiencies.
327
Exhibit B-1-1, Application, p. 5-20. 328
Exhibit B-1-1, Application, p. 5-20, Exhibit B-9, BCUC IR 1.39.6.
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(b) Cost Increases Are Required to Support Key Priorities
220. Cost increases during the test period are required to support key priorities,
initiatives and ongoing operations. The Application presented cost increases in the following
four categories:329
(a) Unavoidable costs – this category includes primarily mandatory fees imposed by
third-parties, as well as expenditures related to labour (including BC Hydro’s
collective agreements with its unions, as well as increases for management and
professional staff).
(b) Capital-driven – this category includes costs related to BC Hydro’s capital
program. Cost increases are required both at the front-end of projects (e.g.,
planning and other pre-capitalization phases – these expenditures are referred
to as capital project investigation costs) and the back end (e.g., maintenance on
constructed assets).
(c) Initiatives – this category includes costs related to initiatives that are not
expected to be permanent expenditures. For example, BC Hydro is investing in
its Customer Strategy in fiscal 2017, but these expenditures will not be required
in future years and accordingly are reduced as appropriate.
(d) Other cost pressures – this category includes all other cost pressures, including
storm restoration costs, expenditures related to technology, as well as capital
overhead adjustments.
221. The process that BC Hydro undertook to identify cost pressures and savings
opportunities followed the process described above and in section 5.2.2 of the Application.
More specifically, each business group evaluated cost pressures and savings opportunities
within their respective scope. The process in each business group was overseen by the
329
Exhibit B-1-1, Application, pp. 5-20 to 5-23.
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respective Executive Team member(s) within that business group.330 There was then an
iterative review process at the Executive Team level. The Executive Team oversaw the process,
including challenging proposed cost increases, confirming proposed savings and efficiencies,
and ultimately approving the resulting planned operating costs proposed in the Application.331
222. BC Hydro’s planned FTEs, including overtime and Site C Clean Energy Project
FTEs, are 6,296 for fiscal 2017, 6,344 for fiscal 2018 and 6,365 for fiscal 2019.332 BC Hydro’s
total FTEs increase is about 1 per cent each year, from fiscal 2016 actual FTEs, in fiscal 2017 and
fiscal 2018 Plan and less than 1 per cent in fiscal 2019 Plan.333 Overall, planned FTEs at the end
of the test period, when compared to fiscal 2016 actual FTEs, are higher in capital, and lower in
operating and deferred. This reflects BC Hydro’s focus on its capital program.334 The FTE
numbers, particularly in the area of capital, should also be considered in the context of the
Workforce Optimization program; the program involves replacing contractor workforce with BC
Hydro employees where it makes sense to do so from a cost and risk perspective.
223. The planned operating costs and FTEs for each of BC Hydro’s four Business
Groups reflect BC Hydro’s emphasis on cost containment and specific priorities.
(c) Training, Development and Generation Business Group
224. The forecast operating costs for the Training, Development and Generation
Business Group in the test period are increasing as a result of necessary investments in specific
assets, compensation, and training; however, the forecast reflects careful prioritization.
330
As described in Appendix K of the Application, the business groups work together to meet the annual operating cost target for BC Hydro. When business groups encounter unforeseen or unavoidable costs, the other business groups examine their programs for opportunities to reduce costs to offset these additional costs. This minimizes the variance to the overall corporate target. Detailed Key Business Unit and Business Group variance commentaries were provided is response to BCUC IR 2.226.1.1.
331 Exhibit B-9, BCUC IR 1.39.5.
332 Exhibit B-1-1, Application, p. 5-24.
333 Exhibit B-1-1, Application, p. 5-26.
334 Exhibit B-1-1, Application, p. 5-27.
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Necessary Investments During the Test Period
225. Operating costs in the Training, Development and Generation Business Group
are increasing by $5.1 million in fiscal 2017 primarily due to budget transfers required to fund
maintenance work program changes, the delivery and development of training, unavoidable
costs for Standard Labour Rate increases, crane remediation, civil maintenance program, and
contractor cost escalation in relation to maintenance costs at Mica.335 Operating costs are
projected to increase by $2.8 million in fiscal 2018 due to the implementation of the civil
maintenance program336 and the Standard Labour Rate increase.337 In fiscal 2019, operating
costs are planned to increase by $7 million compared to fiscal 2018 as a result of the operation
and redevelopment of the John Hart Generating Station and the Standard Labour Rate
increase.338
226. FTEs in the Training, Development and Generation Business Group from fiscal
2017 to fiscal 2019 are planned to remain constant.339 However, FTEs are decreasing by 79 FTE
in fiscal 2017 compared with 2016 actual FTEs.340 These decreases are due to the change in
operations at the Burrard Facility and apprentice and trainee requirements.341 Training and
Development FTEs had been higher than forecast for fiscal 2015 and fiscal 2016 in order to
address expected organizational attrition and resource needs. Planned FTEs for the test period
are lower than the fiscal 2016 actual FTE level.342
335
Exhibit B-1-1, Application, p. 5-47. 336
Exhibit B-1-1, Application, p. 5-41. Corrective and condition-based civil maintenance is now prioritized in the same way as all other corrective and condition-based maintenance. Over the test period and beyond, BC Hydro will allocate additional budget to implement the preventive maintenance civil inspection tasks and condition-based repairs expected from these tasks. Exhibit B-10, CEC IR 1.53.2: There will be additional regularly scheduled preventative maintenance tasks occurring which will lead to an increase in proactively identified condition based work.
337 Exhibit B-1-1, page 5-47.
338 Exhibit B-1-1, Application, p. 5-47.
339 Exhibit B-1-1, Application, p. 5-48.
340 Exhibit B-1-1, Application, p. 5-48. Exhibit B-9, BCUC IR 1.47.1.
341 Exhibit B-1-1, Application, p. 5-48. Exhibit B-9, BCUC IR 1.47.1.
342 Exhibit B-9, BCUC IR 1.47.1.
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227. A number of information requests dealt with BC Hydro’s strategy for maintaining
generation assets. The strategy prioritizes work that provides the greatest overall benefit, with
a related effect on the forced outage factor. These two topics are addressed in further detail
below.
Prioritizing Investment in Generation Assets
228. The Generation Strategic Asset Management Plan recognizes the need to
prioritize investments that provide the greatest overall benefit. BC Hydro is following that
approach in the test period, focusing investment on Key facilities, which represent 90 per cent
of the Heritage energy produced by BC Hydro. BC Hydro is limiting investments in the smaller
Available Energy facilities, namely the five facilities that account for less than 0.5 per cent of BC
Hydro’s average annual generation.
229. In the case of Strategic facilities, which produce approximately nine per cent of
BC Hydro’s average annual energy, BC Hydro is continuing to refurbish or replace equipment
assessed by the Equipment Health Rating methodology as being in Poor or Unsatisfactory
condition or, alternatively, to implement strategies to mitigate the risk of equipment failure.343
230. BC Hydro has employed the same strategy for the lower priority Available Energy
facilities for over a decade: operate and maintain these facilities with limited proactive and
minimal reactive capital investment until the condition of the facility is such that a significant
level of investment would be required to restore or continue operations. At that point, a unit
or the facility as a whole may be taken out of service indefinitely.344 The strategy for the
Available Energy facilities is consistent with the Generation Strategic Asset Management
Plan.345 As a result of their small contribution to the system, these facilities are considered to
be a lower priority.346
343
Exhibit B-9, BCUC IR 1.48.6. 344
Exhibit B-9, BCUC IR 1.48.5. 345
Exhibit B-9, BCUC IR 1.48.5.1.1. A description of each of the facilities and any issues they may have was provided in BC Hydro’s response to BCUC IR 1.48.5.3. The annual maintenance costs for preventive
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231. Although BC Hydro has placed multi-year investment limits on levels of capital
investment, it is still performing regular inspection and maintenance at Available Energy
facilities to keep them safe and inform investment and operating decisions. In addition, BC
Hydro has protection and monitoring systems on assets that trigger automatic actions (such as
shutdown of a generating unit) should a fault occur. Overall, BC Hydro is maximizing the value
of the existing assets by operating and maintaining them as long as it is safe and economic to
do so.347
232. BC Hydro’s investment strategy in generation assets is reflected in the forced
outage factor results.
Overall Forced Outage Factor Result of Prioritizing Investments in Generation Facilities
233. The overall BC Hydro forced outage factor results are derived without assigning
weight to the relative importance of facilities within BC Hydro’s generation fleet. The major
driver of the increase in BC Hydro’s overall forced outage factor is the Available Energy
facilities, in respect of which BC Hydro is deliberately limiting investment due to their small
contribution to overall system generation.348 By contrast, the Service Plan documents a
favourable rolling five-year Average Forced Outage Factor target for Key Facilities (representing
90 per cent of BC Hydro’s average annual energy) of 2.0 for fiscal 2017 and fiscal 2018 and 1.8
for fiscal 2019, based on past performance and the focused investments that are planned in the
test period.349 Over the next ten years, BC Hydro expects the forced outage factor at these
maintenance, condition based, corrective and facility maintenance were provided in BC Hydro’s response to BCUC IR 1.48.5.4. Total maintenance spending for fiscal 2012 through to fiscal 2017 has remained steady. Total maintenance spending for the test period is planned to increase with additional funding primarily for civil maintenance.
346 Exhibit B-9, BCUC IR 1.48.5.7.
347 Exhibit B-9, BCUC IR 1.48.5.
348 Exhibit B-9, BCUC IR 1.45.7: The data in Appendix U shows the average forced outage factor for all generating facilities in aggregate (i.e., Key, Strategic and Available Energy) and shows an increasing trend from fiscal 2007 to fiscal 2016.
349 Exhibit B-14, BCUC 2.230.4.
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facilities to decrease (improve) slightly.350 Similarly, the trend in the five-year rolling forced
outage factor at Strategic facilities, which produce approximately nine per cent of BC Hydro’s
average annual energy, is expected to begin to improve when the John Hart Generating Station
replacement and Ruskin Generating Station redevelopment come into service.351
(d) Transmission, Distribution and Customer Service Business Group
234. Operating costs for the Transmission, Distribution and Customer Service similarly
reflect inflationary pressures and BC Hydro’s efforts to counteract cost increases with
productivity and efficiency improvements.
Planned Investments and Savings Achieved
235. Transmission, Distribution and Customer Service Business Group operating costs
are forecast to increase by $20.6 million in fiscal 2017 from fiscal 2016 Plan. Operating costs in
fiscal 2018 and fiscal 2019 are planned to remain relatively constant as cost increases for labour
are offset by savings in other areas.352 The increase in fiscal 2017 from fiscal 2016 Plan is
primarily due to:353
Operationalization of Smart Metering and Infrastructure, which totals $23.0
million net of savings (Smart Metering and Infrastructure costs were previously
being recorded in a deferral account during the Program’s implementation stage.
The costs must now be recorded as operating costs as the Program is complete);
$2.0 million in Standard Labour Rate increases;
$1.0 million in postage and printing increases;
350
Exhibit B-10, CEC IR 1.52.3. 351
Exhibit B-10, CEC IR 1.52.3. 352
Exhibit B-1-1, Application, p. 5-66. A more detailed explanation of operating costs was provided in the individual
Key Business Unit descriptions.
353 Exhibit B-1-1, Application, p. 5-65.
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$2.4 million in Western Electricity Coordinating Council and Peak Reliability fees;
$5.2 million in capital-driven costs primarily due to additional Technology capital
project investigation costs;
$1.5 million for the Customer Strategy; and
$1.8 million in other cost pressures.
236. These increases have been partially offset by $16.3 million in productivity and
efficiency savings.354
237. FTEs are increasing by 12 from fiscal 2016 actual FTEs to fiscal 2017 Plan. The
increase is mainly due to additions under the Workforce Optimization Program, Contract
Management and Technology. Those additions are partially offset by a decrease of 25 FTEs in
Smart Metering and Infrastructure as the Project is operationalized and FTEs are integrated in
various other Key Business Units.355
238. Information requests related to the Transmission, Distribution and Customer
Service Business Group focussed on (i) Technology Key Business Unit operating costs, (ii)
additional cost savings identified by BC Hydro after the filing of the Application, and (iii) the
Asset Health Index. BC Hydro addresses these topics further below.
Technology Key Business Unit Operating Cost Increase Largely Driven By Smart Metering
239. The majority of the incremental costs and FTEs in the Technology key business
unit - $25.6 million and 25 FTEs - are required to support the operationalization of the
technology, infrastructure, and network implemented by the Smart Metering and Infrastructure
Program.356 The incremental costs and FTEs are needed for:357
354
Exhibit B-1-1, Application, p. 5-66. 355
Exhibit B-1-1, Application, p. 5-66. 356
Exhibit B-9, BCUC IR 1.26.1.
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New business capabilities to allow billing from automated reads, remote
disconnect and reconnects of meters, field metering and data analysis work,
increased outage management capability, and advanced connectivity to meters;
Software and hardware maintenance and support for new systems and devices,
and also the integration between existing systems;
The sustainment of the metering telecommunications network critical to the
communication of data from meters back to network applications and
databases;
New servers and storage required to maintain the smart metering infrastructure,
and to support meter configuration and management; and
Enhanced security required to protect against internal or external cyber threats,
and to maintain compliance to NERC-CIP and other security standards.
240. The costs are part of the overall investment that BC Hydro must make to achieve
net benefits for customers in the form of increased revenues and load reduction benefits.358
Application Included a “Placeholder” Amount for Additional Cost Savings
241. At the time the Application was filed, BC Hydro had identified cost saving
initiatives with high level savings estimates totalling $15 million. BC Hydro continued with this
work after the Application was filed as project plans were established, including more in depth
analytical reviews of the initiatives. The additional work resulted in increased estimated savings
of approximately $19 million per year. The additional $4 million was applied to the $4.3 million
company-wide savings described on page 5-20 of the Application.359 In other words, the
357
Exhibit B-9, BCUC IR 1.26.2. 358
Exhibit B-10, CEC IR 1.42.3. 359
Exhibit B-9, BCUC IR 1.51.2. The $19 million in annual sustainable savings have been removed from business group budgets and are reflected in the table in BC Hydro’s response to BCUC IR 1.50.3. Exhibit B-10, BCOAPO IR 1.33.1. See also, Exhibit B-15, BCOAPO IR 2.75.1 and Exhibit B-15, BCOAPO IR 2.75.2 and 2.75.3.
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proposed revenue requirements already account for these savings because they had been
included in the Application as a “top-down” requirement, with the composition still to be
identified.
Asset Health Index Has Improved Investments and Maintenance
242. BC Hydro’s decision to adopt the Asset Health Index360 for Transmission and
Distribution assets361 in 2013 has not impacted expected maintenance or capital expenditure
levels. The Asset Health Index is, however, allowing BC Hydro to better analyze risk, prioritize
investments and optimize life cycle costs.362
243. The adoption of the Asset Health Index has improved the Preventive
Maintenance (PM) standards review process by making the information more readily
available.363 BC Hydro’s expectations for Corrective Maintenance (CO) are based on historical
levels of expenditures. Corrective Maintenance is reactive and the level may change as the
Asset Health Index improves or deteriorates.364 The effectiveness of Condition Based
Maintenance (CB) and the capital replacement programs has improved with a more accurate
view of the condition of assets, such that the highest priority assets are addressed within the
targets of the 2013 10 Year Rates Plan.365
(e) Capital Infrastructure Project Delivery Business Group
244. The Capital Infrastructure Project Delivery Business Group’s operating costs and
FTEs are driven by the priorities of delivering capital projects on time and on budget, and
360
The Asset Health Index methodology uses condition, performance, age and a survival curve to determine the remaining life of the asset, which is then used to derive the Asset Health Index.
361 Exhibit B-9, BCUC IR 1.53.5.
362 Exhibit B-9, BCUC IR 1.53.10. In response to BCUC IR 1.53.8 BC Hydro provided comparative Asset Health Index information at year-end for fiscal 2014 to fiscal 2016 for Transmission and Distribution asset classes. See also Exhibit B-14, BCUC 2.238.1.
363 Exhibit B-9, BCUC IR 1.53.10.
364 Exhibit B-9, BCUC IR 1.53.10.
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continuing to improve the way BC Hydro operates, including building trusting and mutually-
beneficial relationships with First Nations.366
Planned Costs and FTEs
245. Operating expenditures for the Capital Infrastructure Project Delivery Business
Group, which was formed in fiscal 2016, include transferred-in costs of $48.7 million that were
previously reflected in the fiscal 2016 Plan in other business groups.367 There is an increase of
$7.6 million in fiscal 2017 Plan compared to the initial costs transferred-in when the business
group was formed.368 The increase primarily relates to Capital Project Investigations costs and
capital project dispute resolution costs, partially offset by a reduction in property lease costs.369
From fiscal 2017 to fiscal 2018, operating expenditures decrease by $4.5 million primarily due
to a planned reduction of capital project dispute resolution costs. From fiscal 2018 to fiscal
2019, operating expenditures remain relatively constant.370
246. FTEs in Capital Infrastructure Project Delivery are planned to increase by 144
FTEs in fiscal 2017 compared to fiscal 2016 actual FTEs, 32 FTEs in fiscal 2018 compared to fiscal
2017 and 10 FTEs in fiscal 2019 compared to fiscal 2018.371 The primary drivers for the increase
in FTEs are the Workforce Optimization Program and the delivery of BC Hydro’s capital plan, in
particular the Site C Clean Energy Project.372
As stated in section 5.3.1.3 of the Application, efforts have been underway to
contain headcount since fiscal 2011. In areas of the business where there was
growth, particularly in capital programs, there was an increasing reliance on
366
Exhibit B-1-1, Application p. 5-112. 367
Exhibit B-1-1, Application, p. 5-116. 368
Exhibit B-1-1, Application, p. 5-116. 369
Exhibit B-1-1, Application, p. 5-116. 370
Exhibit B-1-1, Application, p. 5-116. A breakdown of the Business Unit Support costs was provided in Exhibit B-9, BCUC IR 1.56.1.
371 Exhibit B-1-1, Application, p. 5-116.
372 Exhibit B-1-1, Application p. 5-116.
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external resource providers. Workforce Optimization involves identifying ways
to decrease costs and risk by adjusting internal and external resource mix with
regards to the long-term resource requirements. The addition of FTEs in the
Generation and Transmission Engineering key business unit and the Project
Delivery Key Business Unit to offset the use of external resources will result in
capital savings. It will also improve BC Hydro’s ability to manage capital
contracts, thereby reducing project delivery risk. Total savings associated with
these changes from fiscal 2017 to fiscal 2019 is $4.8 million.373
There were unfilled positions in the Capital Infrastructure Project Delivery
business group in fiscal 2015 and fiscal 2016, which are now being filled. The
unfilled positions were primarily within the Site C Clean Energy Project Key
Business Unit. When the fiscal 2015 and fiscal 2016 FTE plan numbers were
established, BC Hydro had expected that the Site C Clean Energy Project would
have reached the Implementation Phase earlier than it did. As a result, the FTEs
ramped up later than originally planned. BC Hydro is filling vacancies on the Site
C Clean Energy Project, so smaller variances are expected during the test period.
In some cases, recruiting processes are being extended due to the need to find
experienced, qualified resources and relocate them to site.374 The cost of FTEs
working on the Site C Clean Energy Project, which is capitalized, does not impact
the revenue requirements in the test period.
BC Hydro is Investing in Aboriginal Relations
247. BC Hydro’s Aboriginal Relations department plays an important role for BC
Hydro. The department addresses project consultation requirements and is responsible for
relationships and communication.375
373
Exhibit B-9, BCUC IR 1.57.3. 374
Exhibit B-9, BCUC IR 1.57.1. 375
Exhibit B-10, Zone II IR 1.11.1, 1.11.4, Exhibit B-15, Zone II IR 2.31.1.
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248. BC Hydro has relationships with First Nations across the Province. BC Hydro has
extensive existing infrastructure and a number of planned projects. First Nations are also often
BC Hydro customers, suppliers and employees. BC Hydro is focused on strengthening its
relationships with First Nations, particularly where BC Hydro has had past impacts and where
BC Hydro has a need for additional infrastructure.376
249. BC Hydro’s employment and business opportunities for First Nations reflect its
focus on relationship building. In fiscal 2017, BC Hydro supported over 140 Aboriginal
candidates in preliminary and prerequisite training initiatives and has hired 47 Aboriginal
employees (a combination of 14 full or part-time regular hires and 33 temporary roles,
including youth hires and other work experience positions). First Nations are also directly
employed on capital projects. For example, at the Site C Clean Energy Project, there are
approximately 200 individuals that self-identify as Aboriginal currently working on the project.
BC Hydro also looks for opportunities for First Nations to provide services through community-
owned businesses or partnerships. In fiscal 2016, BC Hydro issued contracts for $126 million to
123 Aboriginal businesses.377
(f) Operations Support Business Group
250. The Key Business Units included in the Operations Support Business Group
provide enterprise-wide support services.378 BC Hydro has continued to fund important
initiatives, including safety activities, while identifying other areas for operating savings.
Planned Investments and Savings Achieved
251. Planned operating costs have increased by $12.9 million in fiscal 2017, compared
to fiscal 2016 Plan. The increase is primarily related to $22.4 million in IFRS ineligible capital
376
Exhibit B-10, CEC IR 1.68.1, 1.68.2. 377
Exhibit B-10, CEC IR 1.68.3. 378
Exhibit B-1-1, Application, p. 5-132.
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overhead being phased into operating expenses over a 10-year period,379 $3.8 million in capital-
driven maintenance related to the increase in the size and aging of the vehicle fleet, $5.0
million in initiative costs for Safety, and $6.4 million for category management, inventory
obsolescence, capital overhead changes, and Standard Labour Rate increases.380 These
operating costs are partially offset by savings and efficiencies of $6.2 million, a $5.6 million
decrease in capital leases and net budget transfers to other business groups of $11.8 million.381
252. Planned Operations Support FTEs are decreasing by 17 in fiscal 2017 due to
labour efficiencies realized with the centralization of support services and changes to demand-
side management programs. The FTEs will remain relatively constant in fiscal 2018 and fiscal
2019.382
BC Hydro’s Investment in Safety
253. There were a number of information requests on BC Hydro’s safety investments.
Safety is one of BC Hydro’s core values. BC Hydro has prioritized funding towards safety
activities to meet regulatory safety requirements and to mitigate hazards to employees.383
254. Actual and planned expenditures from fiscal 2014 to fiscal 2019 have
increased.384 Safety Operating costs will increase by a $4.3 million in fiscal 2017 and remain at
that level for fiscal 2018 and fiscal 2019. This increase relates to (i) $5.0 million of additional
funding to implement Safety Improvement Projects that address the four remaining BC Hydro
Safety Taskforce recommendations, (ii) comply with regulatory arc flash and confined space
requirements set out by WorkSafe BC, and (iii) build corporate systems and tools supporting
379
Please refer to Application, section 5.7.9. See also Exhibit B-10, CEABC IR 1.2.2. 380
Exhibit B-1-1, Application, p. 5-135. 381
Exhibit B-1-1, Application, p. 5-136. 382
Exhibit B-1-1, Application, p. 5-136. 383
Exhibit B-9, BCUC IR 1.61.1. 384
Exhibit B-9, BCUC IR 1.61.1.
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excellence in Safety (e.g., Field Access to Safety Information).385 The increase is being funded
by reductions in the general operating budgets of the other business groups.386
255. Safety, Security, and Emergency Management will increase by seven FTEs in
fiscal 2017 compared to fiscal 2016 actual FTEs. Two more FTEs are planned in fiscal 2018.
These additions are related to the Workforce Optimization Program and will replace
contractors supporting Capital work.387
256. It is difficult to draw within-year correlations between safety spending and safety
performance due to the lagging relationship between safety improvement project delivery and
safety performance. However, BC Hydro’s safety investments have shown or have begun to
show improved safety performance over time.388 BC Hydro’s past investments in safety have
resulted in improvements in these metrics: 389
(a) Employee Fatality and Serious Injury;
(b) Lost Time Injury Frequency and All Injury Frequency;
(c) Near Miss Reporting; and
(d) Timely Completion of Corrective Actions.
257. In fiscal 2016, as BC Hydro completed safety projects that address high hazard
work as discussed above, it began identifying initiatives to reduce lost time injuries and injuries
requiring medical aid (both of which are captured by the All Injury Frequency metric) and
improve its Near Miss Reporting.390 BC Hydro is optimistic that its investments in safety will
build on its past successes.
385
Exhibit B-1-1, Application, p. 5-168. 386
Exhibit B-9, BCUC IR 1.61.1. 387
Exhibit B-1-1, Application, p. 5-168. See also, Exhibit B-9, BCUC IR 1.61.5. 388
Exhibit B-9, BCUC IR 1.61.2. 389
Exhibit B-9, BCUC IR 1.61.2. 390
Exhibit B-9, BCUC IR 1.61.2.
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Savings from Change in Canadian Electricity Association Membership
258. One of the areas BC Hydro identified for savings was its membership in the
Canadian Electricity Association. The fees paid by BC Hydro to the Canadian Electricity
Association for 2015 membership were approximately $0.7 million. 391 BC Hydro will continue
to be a member, albeit with a reduced scope. The expected cost savings are in the order of
$350,000 annually.392 BC Hydro will retain many of the benefits from core Canadian Electricity
Association activities.393
(g) BC Hydro Has Maintained Consistent Performance Targets While Managing Operating Costs
259. BC Hydro is, despite the efficiencies and cost savings being achieved, maintaining
consistent targets for its performance measures between fiscal 2016 and fiscal 2017:
SAIDI and SAIFI: Consistent with industry practice, BC Hydro projects its
reliability targets based on historical performance and changes in operational
conditions and constraints, such that the targets are achievable and aligned with
strategic goals. BC Hydro’s current reliability target projections are based on
over ten years of historical reliability performance, with adjustments based on
operational inputs, such as capital investments, maintenance expenditure, and
vegetation strategy. As such, the projected targets for annual reliability
performance metrics may not follow a simplistic linear trend into the forecast
years.394
Targeted expenditures for reliability initiatives have reversed the fiscal 2002 to
fiscal 2011 SAIFI and SAIDI worsening trends. The improving trends for fiscal
2012 to fiscal 2016 are shown in the charts provided in response to BCUC IR
391
Exhibit B-9, BCUC IR 1.40.2. 392
Exhibit B-9, BCUC IR 1.40.3. 393
Exhibit B-9, BCUC IR 1.40.4. See also BCUC IR 1.40.5 and 1.40.6. 394
See also Exhibit B-10, CEC IR 1.4.4.
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1.45.3. These improving trends were the result of investments in areas such as
distribution automation, where the automation of reclosing and switching
devices enables faster fault isolation and outage restoration.395
Key Generating Facility Forced Outage Factor: There were no capital additions
in Key facilities in fiscal 2016 that resulted in improved reliability. Therefore, the
Key facility Forced Outage Factor target for fiscal 2017 is the same as fiscal
2016.396
CSAT Index: BC Hydro continues to maintain a minimum threshold target of 85
per cent for its Customer Satisfaction Index so that BC Hydro has strong
customer support. The reliability component of the Customer Satisfaction Index
remains stable, and indicates that customers are satisfied with the current level
of reliability that BC Hydro is providing.397 Benchmarking results to date
demonstrate BC Hydro compares well to both non-electric utility service
providers and other electric utilities. Further, as discussed on page 2-14 of the
Application, due to changing customer expectations of service, BC Hydro
believes it will have to do more to maintain Customer Satisfaction Index at the
current level.398
Progressive Aboriginal Relations Designation: BC Hydro is striving to maintain
Gold designation, the highest standing in the program, through a reapplication
process which involves a comprehensive review by an external verifier hired by
the Canadian Council for Aboriginal Business.399
395
Exhibit B-9, BCUC IR 1.45.3. See also Exhibit B-9, BCUC IR 1.45.1 and Exhibit B-10, CEC IR 1.3.2, 1.3.3, 1.3.3.1. For further information about SAIDI and SAIFI, please refer to BC Hydro’s response to CEC IR 1.4.4.
396 For further information about Key Generating Facility Forced Outage Factor, please refer to BC Hydro’s response to CEC IR 1.4.8.
397 Exhibit B-15, BCOAPO IR 2.79.1.
398 See also Exhibit B-10 CEC IR 1.4.9.
399 See also Exhibit B-10, Zone II IR 1.11.7, 1.11.8.
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260. BC Hydro’s performance targets reflect its expectation of providing a high level
of service while managing operating costs.
(h) Maintenance Program Prioritization and Efficiencies
261. BC Hydro continues to optimize Preventive Maintenance standards and prioritize
Condition Based Maintenance.400 The approach balances the need to invest in maintenance
and customers’ interest in low and predictable rates, as contemplated in the 2013 10 Year
Rates Plan.
262. Preventive Maintenance consists of planned maintenance, including inspections
and condition assessments, initiated through standards (Transmission and Distribution assets)
or maintenance instructions (Generation assets). The planned preventive maintenance
program is a high priority, and BC Hydro has not reduced planned preventive maintenance to
meet the rate targets of the 2013 10 Year Rates Plan. However, BC Hydro continues to review
the standards and maintenance instructions on a regular basis to optimize reliability and
lifecycle cost.401
263. Condition Based Maintenance work consists of repairs or replacements of
defective or damaged components. All Condition Based Maintenance is prioritized by
considering the component’s condition, criticality, and overall risk to the system. The outcome
of the prioritized analysis determines if a defective or damaged component is addressed in the
current year, deferred to future years, or addressed under a sustaining capital investment.402
264. BC Hydro is identifying opportunities to become more efficient at preventive
maintenance. As discussed in BC Hydro’s response to BCUC IRs 2.211.1 and 2.211.2, BC Hydro
revises preventive maintenance standards and instructions to ensure the efficiency of
maintenance. BC Hydro reduces inspection frequency when it can determine from the data
400
Exhibit B-9, BCUC IR 1.24.2. 401
Exhibit B-9, BCUC IR 1.24.2. 402
Exhibit B-9, BCUC IR 1.24.2.
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gathered during maintenance that there is little or no associated incremental risk. For example,
the optimization of the maintenance of feeder protection systems using digital relays reduced
expenditures by $126,000 per year. BC Hydro also assesses new procedures, technology, tools
or materials to reduce the cost of maintenance. One such area involves investigating inspection
techniques using Unmanned Aerial Systems (drones) to improve the efficiency of inspections.403
F. BC HYDRO’S COMPENSATION PROGRAM IS REASONABLE
265. BC Hydro’s average labour cost increase is forecast to be $7.5 million per year
through the test period.404 BC Hydro’s compensation program is reasonable. As described
below, BC Hydro has limited increases to Management and Professional salaries and they
remain below market comparables. Unionized employees are compensated consistently with
the market on a total rewards basis. BC Hydro has implemented strategies to manage and limit
overtime.
(a) BC Hydro Has Limited Increases in Management and Professional Compensation
266. Salary increases have been limited in recent years for Management and
Professional employees due to a manager salary freeze policy implemented by the Public Sector
Employers Council. Over the test period, it is expected that Management and Professional
salaries will only increase by 1.5 per cent per year.405 Management and Professional salaries
will remain below market comparables.
Limited Increases in Management and Professional Compensation for Several Years
267. BC Hydro elected not to provide Management and Professional employees
increases in fiscal 2011 and fiscal 2012. Its decision was consistent with the wage freeze for
403
Exhibit B-14, BCUC 2.211.3.1. 404
Exhibit B-10, CEC IR 1.47.2. 405
Exhibit B-10, CEC IR 1.49.5.
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unionized employees those years and reflective of the economic downturn that resulted in
lower salary growth in the market. A manager salary freeze policy was implemented for the BC
Public Sector later in fiscal 2013 after a 2 per cent increase had occurred. The manager salary
freeze policy remains in effect; however, modest and targeted increases have been provided to
employees in on an exception basis and approved by the Public Sector Employers Council.406
268. Management and Professional increases for the test period will depend on
factors such as budget constraints, labour market conditions, and Public Sector Employers
Council guidelines. BC Hydro forecasts that Management and Professional salaries will increase
by 1.5 per cent per year over the test period, slightly below the forecast union wage increase of
1.9 per cent per year over the test period.407
269. Only Directors and Executives, representing approximately 3 per cent of total
Management and Professional and Executive employees, have a salary holdback program. The
purpose of the salary holdback program is to focus leadership on key objectives, incent
performance and put pay at risk based on results achieved. Performance plans are set at the
start of each fiscal year for both corporate and individual performance.408 The targets set for
the corporate measures align with the targets set in the BC Hydro Service Plan.409 The
maximum holdback is 10 per cent for Directors and the Chief Executive Officer, and 20 per cent
for all other Executives.410 Performance plans are set at a level that is not easily attained; in
fiscal 2016, only 10 per cent of employees received the full salary holdback award for the
individual component.411
406
Exhibit B-15, CEC IR 2.149.2. 407
Exhibit B-10, CEC IR 1.47.1. 408
Exhibit B-14, BCUC IR 2.227.3 and 2.227.4. 409
Exhibit B-9, BCUC IR 1.34.9. See also Exhibit B-14, BCUC IR 2.227.2. 410
Exhibit B-10, CEC IR 1.48.5. 411
Exhibit B-14, BCUC IR 2.227.4.1 and 2.227.5.
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Below Market Compensation
270. BC Hydro participates annually in salary surveys conducted by Towers Watson
and Mercer to assess how Management and Professional compensation rates compare to
market. Compensation rates for benchmark jobs are compared to the median rates in the
survey.412 BC Hydro’s market assessment conducted last year showed that, overall:
Electric utility job salaries are 15 per cent below market rates, and are 25 per
cent below market rates on a total cash (salary plus short-term incentive pay)
basis; and
General industry job salaries are at market, but are seven per cent below market
rates on a total cash basis.413
271. The gap on a total rewards basis is only partially offset by time off and BC
Hydro’s pension program.414
272. BC Hydro has not purchased Executive market data in recent years because
Executive salaries have been frozen since 2009. The last Executive market comparison showed
that, even before the freeze, salaries were 29 per cent below market rates.415
(b) Unionized Employees Compensated at Market Median Based on Total Rewards
273. BC Hydro participates annually in salary surveys conducted by Towers Watson
and Mercer to assess how its MoveUp wage rates compare to market rates. Based on the last
market assessment conducted in fiscal 2016, overall MoveUp wages are 10 per cent below
market rates.416 For IBEW jobs, BC Hydro compares wage rates directly from collective
412
Exhibit B-10, CEC IR 1.49.5. Exhibit B-15, BCOAPO IR 2.73.1: The Management and Professional compensation rate comparison provided in BC Hydro’s response to CEC IR 1.49.5 did not include Executive positions.
413 Exhibit B-10, CEC IR 1.49.5.
414 Exhibit B-10, CEC IR 1.49.5.
415 Exhibit B-15, BCOAPO IR 2.73.2.
416 Exhibit B-15, BCOAPO IR 2.73.3.
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agreements of other Canadian electric utilities. Based on the last market assessment
conducted in fiscal 2017, overall IBEW wage rates are nine per cent below market rates.417
While BC Hydro trails the market compared to the median wage rate, previous benchmarking
has shown that BC Hydro is approximately at market on a total rewards basis when the value of
time off and pension programs are taken into account.418
(c) BC Hydro Introduced Strategies to Manage and Reduce Overtime
274. Field and Grid Operations and Generation Operations have the majority of IBEW
employees at BC Hydro, and thus incur the majority of IBEW overtime worked. These two Key
Business Units have field responsibility for the safe operation, isolation, maintenance,
restoration, and capital construction support for the generation, transmission and distribution
systems in BC Hydro. There are a number of circumstances in which incurring overtime makes
good business sense; however, both Key Business Units have implemented a number of
strategies to manage and reduce IBEW overtime.419 The initiative is working. Although
overtime labour costs increased from fiscal 2015 through fiscal 2019, the overtime hour FTEs
are declining. The trend reflects BC Hydro’s improved overtime management.420 BC Hydro
requires the additional overtime costs forecast for the test period to efficiently operate,
maintain, upgrade and expand the electrical system.421
G. INSOURCING OF ABSBC FUNCTIONS HAS NO MATERIAL EFFECT ON TEST PERIOD REVENUE REQUIREMENTS
275. On March 30, 2017, by Order No. G-50-17, the Commission directed BC Hydro to
“to provide information regarding the termination of the Accenture Business Services of British
Columbia Limited Partnership (Accenture) contract and the impact, if any, to the calculation of
the revenue requirements and the forecast additions to the regulatory accounts.” BC Hydro
417
Exhibit B-15, BCOAPO IR 2.73.3. 418
Exhibit B-15, BCOAPO IR 2.73.3. 419
Exhibit B-9, BCUC IR 1.34.8. 420
Exhibit B-14, BCUC IR 2.224.1. 421
Exhibit B-14, BCUC IR 2.224.4.
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provided the requested information in its Rebuttal Evidence, demonstrating the rationale for
the repatriation and the limited impact on the test period revenue requirements.
276. The primary rationale for repatriation is one of acquiring greater operational
flexibility. BC Hydro explained:
For context, since the initial outsourcing ABSBC has provided a scope of services defined within its contract, and in accordance with a series of Service Level Agreements that establish performance levels. BC Hydro and its customers benefitted by having a fixed price for services provided, with a price that declined over time in real terms, while ABSBC had a financial incentive to continue to drive efficiencies. This model of outsourcing worked very well throughout the contract because BC Hydro’s business requirements were constant, and so ABSBC was able to focus on maximizing the efficiency of meeting the Service Level Agreements.
The downside to an outsourced contract model is that operational changes can be difficult to implement. As business requirements evolve with changes in technology and customer expectations, these adjustments in work and scope require a detailed assessment of the impact on the service provider’s operations and approval of a change order to the contract, often resulting in additional costs to BC Hydro. This process can take time, and can also present challenges in piloting new processes so that the benefits and impacts can be measured before committing to a permanent change. Additionally, in an outsourced model, when resource savings can be obtained from a change, the two parties typically share in any savings rather than the full savings being realized by the owner.
Repatriating the primary customer functions (i.e., the contact centre, billing and collections) will allow us to be more flexible in making operational changes that improve customer experience or provide cost savings.422
277. BC Hydro considered a number of non-financial considerations423, and did
perform an assessment of costs and benefits. The confidential materials provided to the Board
of Directors, which are attached to the BC Hydro’s response to CEC IR 3.186.1, provide more
422
Exhibit B-21, BCUC IR 3.347.1. See also: Exhibit B-21, BCUC IR 3.347.1.1; BCUC IR 3.347.2; Exhibit B-22, CEC IR 3.186.3; NIARG IR 3.30.6.
423 Exhibit B-22, CEC IR 3.186.4.
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details regarding BC Hydro’s analysis. The NPV of the repartriation of services is provided in the
confidential response to CEC IR 3.187.7.
278. BC Hydro has appropriate governance structures in place to manage the
transition.424 BC Hydro explained that it expects only a modest favourable impact on the test
period revenue requirements of $0 to $2 million.425 As such, BC Hydro is not requesting a new
regulatory account or seeking to use an existing regulatory account for the deferral of costs or
savings related to the termination of the Accenture contract.426
H. CONCLUSION AND REQUESTED FINDINGS
279. The Application, which is based on forecast base operating cost increases
averaging only 1.2 per cent annually over the test period, reflects BC Hydro’s continued focus
on operating cost containment and investment in key priorities consistent with the 2013 10
Year Rates Plan. The Commission should find that BC Hydro’s has taken appropriate steps to
manage operating expenses. The forecast operating expenses for the test period are
reasonably required for BC Hydro to continue delivering safe and reliable electricity service and
appropriate customer service.
424
Exhibit B-21, BCUC IR 3.348.1. 425
Exhibit B-20, Rebuttal Evidence, p.52. 426
Exhibit B-20, Rebuttal Evidence, p.52. See also, Exhibit B-21, BCUC IR 3.346.3.
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PART EIGHT: CAPITAL EXPENDITURES AND ADDITIONS
A. INTRODUCTION
280. BC Hydro has, in this proceeding, filed more evidence on its forecast capital
expenditures and additions than in any prior revenue requirements proceeding. BC Hydro’s
planned capital expenditures and additions for the test period are addressed in Chapter 6 of the
Application, and are summarized in Tables 6-2 and 6-4, respectively.427 Various appendices to
the Application provide detailed information on BC Hydro’s planned capital investments and
specific projects and programs.428 BC Hydro responded to approximately 575 information
requests on its capital investments. The evidence demonstrates that BC Hydro’s planned
capital investments in the test-period are aligned with the 2013 10 Year Rates Plan. BC Hydro
has made significant reductions to the forecast expenditures and additions, while making
appropriate capital investments in reliability, safety, customer service, and to sustain the
existing assets and meet load growth.429
281. The following points, each of which is addressed in this Part, support BC Hydro’s
forecast capital expenditures and additions for the test period:
First, BC Hydro’s forecast capital expenditures and additions for the test period
are the outcome of a well-defined planning process that considers BC Hydro’s
system requirements, strategic priorities and rate impacts.
Second, in response to reduced forecast revenues associated with lower than
anticipated load growth rate, BC Hydro reassessed its capital forecast in light of
427
Capital expenditures do not impact rates until the project is placed into service and they become capital additions. Thus, only the forecast capital additions, and not the forecast capital expenditures, affect the revenue requirements in the test period. Exhibit B-1-1, Application, p. 6-3.
428 Appendix G to the Application is an updated fiscal 2017 to fiscal 2026 10 Year Capital Forecast. Appendix I provides capital addition information for Technology projects and programs greater than $2 million, and other projects greater than $5 million, with both capital expenditures and capital additions in the test period. Appendix J describes projects with planned total capital expenditures of greater than $20 million and with capital expenditures in the test period.
429 Exhibit B-14, BCUC IR 2.260.3.
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current information and reduced both forecast capital expenditures and
additions for the test period by almost $400 million.
Third, BC Hydro’s forecast capital expenditures and additions, including the
projects and programs explored in information requests (discussed in Appendix
“A” to this Final Submission), address system requirements and BC Hydro’s
priorities.
Fourth, the accountable organizational groups within BC Hydro use established
processes to deliver capital projects and programs, and BC Hydro has a track
record of delivering its capital projects and programs on budget.
Fifth, an existing regulatory account, which BC Hydro is proposing to continue,
will capture any annual variances between the forecast and actual amortization
of capital additions.
B. BC HYDRO HAS A WELL-DEFINED CAPITAL PLANNING PROCESS
282. BC Hydro has a well-defined capital planning process. As depicted in the figure
below and described starting in section 6.3.3 of the Application, the planning process involves
(a) top-down direction, including overarching targets and strategic objectives, (b) bottom-up
portfolio development by asset category, (c) collaboration among business groups and a
consistent approach to capital investment prioritization across BC Hydro, (d) senior
management and Board oversight, and (e) integration with the organizational groups
responsible for project and program delivery. BC Hydro’s application of this planning process
has aligned the short and long-term capital investments with overarching strategic objectives,
including adherence to the 2013 10 Year Rates Plan.430
430
Exhibit B-1-1, Application, p. 6-10.
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Overview of BC Hydro’s Capital Planning Process
283. The three major steps in the process, oversight and integration of planning and
delivery, are discussed further below.
(a) Step 1: Top-Down Strategic Direction and Capital Program Parameters
284. The 2013 10 Year Rates Plan, the 10 Year Capital Plan prepared in 2014 and
strategic priorities articulated by the executive team have provided top-down guidance for the
level of investments in each of the key capital asset categories. There is overlap and
consistency among these sources of guidance. The top-down guidance is reflected in the
Tra
nsm
issio
n &
Distrib
utio
n
Ge
ne
ratio
n
Pro
pe
rtie
s
Te
ch
no
lo
gy
Oth
ers
Business Unit Prioritization of
capital plans based on Joint
Review of Risk and Value
Bottom Up
Planning
Collaborative
Review for
Consistency
Strategic Objectives, including
Priorities, Performance Objectives
and Targets
BC Hydro 2013 10 Year Rates Plan
BC Hydro 10 Year Capital Forecast
Top Down PlanningG
uid
elin
es
Outcomes: Consolidated F17-F19 RRA Capital PlanUpdated 10 Year Capital Forecast F17-F26
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capital investments for the test period, and the updated fiscal 2017 to fiscal 2026 10 Year
Capital Forecast in Appendix G of the Application.431 In particular:
2013 10 Year Rates Plan: BC Hydro is holding capital investments in the test
period to a level that will allow BC Hydro to remain on track to achieve the rate
targets in the latter years of the 2013 10 Year Rates Plan and still achieve its
investment objectives.432
10 Year Capital Forecast prepared in 2014: BC Hydro’s 10 Year Capital Forecast
prepared in 2014 aligned with the 2013 10 Year Rates Plan.433 It established
high-level targets for annual capital expenditures, and identified strategic
projects and programs for the ten-year period. Some movement of expenditures
between years is expected, and annual targets are adjusted to account for new
information (including system requirements, project timing and how BC Hydro is
tracking against the 2013 10 Year Rates Plan). The key objective, which BC Hydro
is on track to achieve, is to remain within the parameters of the 2013 10 Year
Rates Plan.434
Strategic priorities: BC Hydro’s executive team has articulated business
priorities.435 The planning and delivery of the forecast capital expenditures for
fiscal 2017 to fiscal 2019 is aligned with the following priorities:436
Operating prudently and efficiently, providing safe, reliable, affordable,
and clean electricity, now and in the future;
431
Exhibit B-1-1, Application, pp. 6-10 to 6-11. The 10 Year BC Hydro Capital Plan was renamed the 10 Year Capital Forecast in fiscal 2016.
432 Exhibit B-1-1, Application, p. 6-11.
433 Capital expenditure portfolios for each of the key capital asset categories are prepared annually and consolidated to provide an annual updated 10 Year BC Hydro Capital Forecast.
434 Exhibit B-1-1, Application, p. 6-11.
435 Exhibit B-1-1, Application, p. 6-11.
436 Exhibit B-1-1, Application, p. 6-9.
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Adhering to BC Hydro’s 2013 10 Year Rates Plan, and successfully
expanding, upgrading and sustaining BC Hydro’s aging assets, to support
the province’s growing economy and population, and to meet customers’
evolving needs; and
Undertaking ongoing engagement and building effective relationships
with First Nations and stakeholders.
BC Hydro’s priorities for the test period align with the Minister’s Mandate Letter,
as discussed in Part Three above.
(b) Step 2: Bottom-Up Planning and Portfolio Development by Asset Category
285. The second major step in the planning process is for the business units within BC
Hydro that have accountability for capital planning to develop ten-year capital investment
portfolios for each of the main asset categories (i.e., Generation, Transmission and Distribution,
Technology, Properties and Fleet). The asset category portfolios are developed in alignment
with top-down guidance and targets. They must also account for the issues, risks and
opportunities associated with the assets and infrastructure of the respective asset category.437
These asset category portfolios are considered collectively in the collaborative prioritization
exercise (step 3) discussed later.438
286. The portfolio development processes for the asset categories, which have been
used in the development of capital expenditure and additions forecasts for the test period, are
as follows:
Generation capital planning: The Application, starting at page 6-23, describes BC
Hydro’s capital planning process for generation assets. Generation asset
Sustainment capital planning is based on Generation’s Facility Asset Planning
437
Exhibit B-1-1, Application, p. 6-17. 438
Exhibit B-1-1, Application, p. 6-11 and 6-12.
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process.439 Generation facility asset plans summarize the issues, risks and
opportunities faced by a specific facility and outline the proposed long-term
investment strategy that is believed to offer the best value at a specific time.440
The facility asset plans are combined and used in the process for the preparation
of the BC Hydro’s 10 Year Capital Forecast. BC Hydro Generation has
determined the need for, and timing of, Growth capital investments with
reference to the 2013 Integrated Resource Plan, which informs the need for and
timing of such investments.441
Transmission and Distribution capital planning: The capital planning process for
transmission and distribution assets is described in the Application, starting at
page 6-33. The planning process involves four main steps. The first step is to
identify system and asset needs that should be considered for remediation. The
second step is to manage the identified needs to plan efficient and optimal
solutions, which is a task performed by cross-functional teams of planners. The
third step is to study the needs in detail, either individually or in bundles, and
identify technically feasible alternatives for the project or program. The fourth
step is for the projects and programs to be consolidated in a single transmission
and distribution capital investment portfolio, together with programs and
projects in the delivery process. The Transmission and Distribution planning
process feeds into, and aligns with, the planning process used for the
preparation of the BC Hydro’s 10 Year Capital Forecast.442
Technology capital planning: The Technology capital planning process is
described in the Application, starting at page 6-42. The Technology planning
process aligns with the planning process used for the preparation of the BC 439
Exhibit B-1-1, Application, p. 6-23. 440
Exhibit B-9, BCUC IR 1.74.1. 441
Exhibit B-1-1, Application, p. 6-27. Growth projects in Generation are limited to Heritage Assets as defined by the Clean Energy Act.
442 Exhibit B-1-1, Application, p. 6-33 to 6-36.
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Hydro’s 10 Year Capital Forecast. The Technology planning process establishes
high level targets for annual capital expenditures and identifies projects and
programs to support business initiatives and ongoing business and IT service
requirements. The process is designed to select a portfolio of investments based
on BC Hydro’s business needs and current information.
Properties capital planning: The Properties capital planning process is described
in the Application, starting at page 6-47. BC Hydro bases its Properties capital
planning on an assessment of the health of existing assets and a determination
of operational requirements that cannot be met by the existing asset
portfolio.443
Fleet capital planning: The Fleet capital planning process is described in the
Application, starting at page 6-49. BC Hydro plans to sustain reliable operations,
minimize total asset lifecycle costs, ensure the fitness of assets for evolving work
purposes, and limit safety and operational risks by meeting safety and other
regulatory requirements.444 Fleet identifies and ranks vehicles for replacement
using asset information (asset age/remaining life, mileage, maintenance costs,
utilization rates, observed downtime frequency), input from vehicle
maintenance staff regarding asset condition, and end-user input on asset
condition, criticality and operational requirements. User groups also identify the
need for upgraded or additional fleet assets to meet work requirements.445
(c) Step 3: Collaborative Prioritization Within Corporate Investment Framework
287. The third major step in the planning process is to apply BC Hydro’s Corporate
Investment Framework to all asset categories. Projects within each asset category receive a risk
or value score based on project characteristics, risks and benefits. The score provides guidance
443
Exhibit B-1-1, Application, p. 6-48. 444
Exhibit B-1-1, Application, p. 6-49. 445
Exhibit B-1-1, Application, p. 6-50.
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within the respective asset category capital portfolio as to which projects should proceed in the
planning period under consideration (e.g., test period) and which projects can be delayed.446
The consistent application of BC Hydro’s corporate investment framework allows for
comparable assessment of diverse types of investments using common criteria and defined
ranges. BC Hydro’s consolidated capital forecast is the product of this prioritization process.
288. BC Hydro’s Corporate Investment Framework also recognizes that some
investments are non-discretionary and should not be considered for delay.447
289. BC Hydro’s Corporate Investment Framework includes a capital allocation risk
matrix to assess risk-based investments. (Risk-based, as opposed to value-based, investments
represent approximately 97 per cent of BC Hydro’s capital investments.448) The matrix is based
on BC Hydro’s corporate risk matrix, augmented with (a) supplemental criteria to capture the
impacts of a diverse set of investments across BC Hydro, and (b) additional consequence and
likelihood levels to provide more differentiation among investments.449
290. Equipment Health Rating and Asset Health Index ratings are key inputs in the
capital allocation risk matrix. The ratings, which are tools for assessing the reliability risk of
deferring an investment related to asset replacement, account for the likelihood and
consequence of asset failure. Assets with an Equipment Health Rating of Poor or
Unsatisfactory, or an Asset Health Index rating of Poor or Very Poor, are considered to have a
higher likelihood of failure. There will be higher risk associated with delaying the investment to
address the condition of the asset.450 BC Hydro’s assessment of the consequence of asset
failure is informed by the criticality of the asset and the length of time it would take to restore
446
Exhibit B-1-1, Application, pp. 6-12 to 6-14. See also Exhibit B-10, CEC IR 1.75.1. 447
Exhibit B-10, CEC IR 1.76.1. 448
Exhibit B-10, CEC IR 1.76.1. Risk-based investments address corporate risks. A value-based investment provides economic benefits such as cost reductions or avoided future costs, and/or provides qualitative benefits such as improved service quality or alignment with business goals.
449 Exhibit B-9, BCUC IR 1.64.1.
450 Exhibit B-9, BCUC IR 1.64.4.
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the asset to service after failure.451 Assets at end-of-life that do not have an Equipment Health
Rating or Asset Health Index are assessed using the other criteria within the enterprise-wide
prioritization framework.452
291. Value-based capital expenditures are evaluated under the corporate investment
framework by measuring the economic benefits associated with those investments. The
evaluation accounts for impacts on cash flows (e.g., increased revenue, cost savings) and “soft”
benefits (e.g., productivity gains or avoided costs). BC Hydro discounts “soft” benefits by 75
percent in recognition that they are less certain and more difficult to quantify and verify.453
The outcome is a value score that can be considered in tandem with other capital projects and
programs.454
292. The forecast capital expenditures and additions for the test period reflect the
consistent application of BC Hydro’s corporate investment framework. In response to
information requests, BC Hydro provided supporting documentation regarding the Corporate
Investment Framework and examples of how BC Hydro applied the Corporate Investment
Framework.455
(d) Senior Management and Board Review
293. BC Hydro senior management have significant involvement in the annual capital
planning process, both at the stage of portfolio development and in the development of the
consolidated capital forecast. For example, the capital expenditure portfolio developed by a
business unit during its annual bottom-up planning process is reviewed by the business unit’s
senior management to ensure the portfolio meets the objectives, strategies and priorities of
the capital asset category. BC Hydro’s executive team and Board of Directors review the 10
451
Exhibit B-9, BCUC IR 1.64.4. 452
Exhibit B-9, BCUC IR 1.64.6. 453
Exhibit B-9, BCUC IR 1.64.3. 454
Exhibit B-9, BCUC IR 1.64.3; BCUC IR 1.64.1; Exhibit B-1-1, Application, pp. 6-12 to 6-13. See also Exhibit B-10, CEC IR 1.75.1 for the specific calculation to determine the value score.
455 E.g., Exhibit B-10, BCOAPO 1.36.1 and 1.36.2; Exhibit B-15, BCOAPO 2.77.1.
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Year Capital Forecast to ensure that it meets BC Hydro’s overall business objectives, provides a
consistent and appropriate management of risk and targets, and is aligned with the 2013 10
Year Rates Plan.456
(e) Capital Planning Is Integrated With Capital Delivery
294. BC Hydro’s capital planning process is integrated with the capital delivery
function. Processes and governance structures are in place so that projects are scoped to meet
business requirements and are planned for release with the appropriate resource analysis and
availability. The project delivery processes and integration with the capital planning function
are described in section 6.4 of the Application.457
C. BC HYDRO REDUCED CAPITAL FORECAST TO REMAIN ON TRACK WITH THE 2013 10
YEAR RATES PLAN
295. BC Hydro’s forecast capital expenditures and additions for the test period both
reflect reductions of almost $400 million, in response to the reduced rate of forecast load
growth (discussed in Part Four of this Final Submission). BC Hydro achieved the reductions by
re-examining the portfolio in light of new information, and it avoided undue impacts on asset
health, reliability or BC Hydro’s ability to deliver on strategic objectives. BC Hydro is, as a result
of the capital reductions and BC Hydro’s other efforts, on track to meet the 2013 10 Year Rates
Plan rate targets and make necessary capital investments.458
(a) BC Hydro Achieved a Material Reduction in Forecast Capital Expenditures and Additions
296. In Spring 2016, BC Hydro identified that a significant reduction in the forecast
fiscal 2017 to fiscal 2019 capital expenditures and additions was a necessary component of BC
Hydro’s response to a lower rate of forecast load growth. BC Hydro reduced planned capital
456
Exhibit B-1-1, Application, p. 6-14 and 6-15. 457
Exhibit B-1-1, Application, p. 6-9. 458
Exhibit B-1-1, Application, p. 6-15 and Chapter 1, section 1.5.4.
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expenditures for the test period by $381.2 million and reduced planned capital additions by
$392.5 million.459 This represented approximately 5.0 and 6.8 per cent of the forecast capital
expenditures and additions, respectively, for the test period.
297. Table 6-5 from the Application summarized the composition of the reductions:
298. The Attachment to BC Hydro’s response to BCUC IR 1.73.1 listed and described
all projects greater than $20 million (greater than $5 million for Information Technology
projects) that had been part of the initial capital investments but were delayed or cancelled to
achieve the reductions. BC Hydro achieved the reductions in expenditures and additions
primarily by delaying, not cancelling, investments.460
299. In the context of the capital planning process, BC Hydro’s response to the
emergence of a lower forecast load growth rate is an illustration of the operation of the “top
down” guidance of the 2013 10 Year Rates Plan. BC Hydro’s capital prioritization framework
was also incorporated where possible, with prioritization decision based on the impact of
459
Exhibit B-1-1, Application, p. 6-15. 460
Exhibit B-1-1, Application, p. 6-15.
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delaying or cancelling the investments, including financial, reliability, safety, environmental,
and reputational risks.461
(b) BC Hydro Identified Reductions Across All Asset Categories Without Undue
Impacts on Asset Health, Reliability or Ability to Deliver on Strategic Objectives
300. Achieving a reduction of this magnitude required BC Hydro to identify reductions
across all asset categories, as summarized in Table 6-5 above. The most significant reductions
were in Generation, Transmission and Distribution, Technology and Properties. The Site C
Clean Energy Project does not affect BC Hydro’s revenue requirements in the test period, and
thus was not a target for reductions in the test period. BC Hydro summarizes below how it
achieved the reductions in the main asset categories. The evidence demonstrates that BC
Hydro captured the available opportunities to reduce forecast capital expenditures and
additions for the test period without undue impacts on asset health, reliability or BC Hydro’s
ability to deliver on strategic objectives.
Generation Reduction
301. Generation reduced planned capital expenditures by $200.7 million and planned
capital additions by $17.3 million over the test period. The majority of the reductions were
achieved by delaying projects in the sustaining capital portfolio.462
302. BC Hydro’s primary Generation planning objective remained protecting the
reliability of the key facilities that produce 90 percent of BC Hydro’s average annual energy,
followed by the strategic facilities that produce 9 percent of average annual energy. BC Hydro
also considered safety, financial, reputational and environmental risks.463 In order to achieve
461
Exhibit B-1-1, Application, p. 6-15. 462
Exhibit B-1-1, Application, p. 6-16. 463
Exhibit B-1-1, Application, p. 6-16.
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reductions while also protecting the reliability of the key generating facilities, BC Hydro delayed
projects across the portfolio.464
303. BC Hydro considered that delaying capital investments in system assets has the
potential to result in other costs. BC Hydro estimates incremental maintenance costs of up to
$2 million over the test period due to the delay of Generation sustaining capital portfolio
projects. This increase relates to corrective and condition-based maintenance; preventive
maintenance costs will not change. BC Hydro is prioritizing condition-based and corrective
maintenance to manage within existing budgets.465 BC Hydro submits that the Generation
savings have been achieved without subjecting the company or customers to unreasonable risk.
Transmission and Distribution Reduction
304. Transmission and Distribution reduced planned capital expenditures by $99
million and planned capital additions by $167.2 million over the test period. BC Hydro’s
evidence demonstrates that it has made the reductions that are reasonable in the current
circumstances given asset health and reliability considerations.
305. BC Hydro considered expenditures for delay based on risk assessments.466 BC
Hydro’s primary objective was to protect customer reliability.467 For this reason, BC Hydro
primarily targeted transmission portfolio expenditures for delay.468 The majority, but not all, of
the transmission system has multiple transmission lines supplying an area simultaneously. The
built-in redundancy results in the transmission system being more tolerant to equipment
failures. Failures of a single piece of equipment, in most cases, do not result in customer
outages. By contrast, the distribution system is largely operated without redundant supply
464
Exhibit B-10, CEC IR 1.77.2. 465
Exhibit B-9, BCUC IR 1.73.2. 466
Exhibit B-1-1, Application, p. 6-16. 467
Exhibit B-1-1, Application, p. 6-16. 468
Exhibit B-9, BCUC IR 1.73.5.
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sources. There are more opportunities for equipment failures to result in outages that impact
customers.469
306. The planned delays will have some impact on asset health compared to the
original plan.470 Ongoing capital investments are required to maintain asset health.
Deteriorating asset health will eventually result in deteriorating reliability, but the relationship
between asset health and system reliability is not straightforward. Asset failures may not cause
customer outages where the system has built-in redundancy, and there are many other causes
of customer outages besides asset failures.471
307. BC Hydro expressed its expectation that the reduction in sustainment
expenditures will not, in and of itself, necessitate higher levels of sustainment expenditures on
Transmission and Distribution assets in the future. However, BC Hydro acknowledges that the
risk does exist at the planned level of investment. BC Hydro stated that the current level of
investments will “test” BC Hydro’s ability to further optimize the overall portfolio asset health
in the future.472
308. BC Hydro will minimize reliability risk by:
Monitoring Asset Health and targeting investments to critical assets and the
highest asset risks:473 The new Asset Health Index methodology, together with
summary ratings for transmission and distribution assets, are provided in
Appendix S of the Application. BC Hydro manages end-of-life expenditures to
maximize the life cycle value of the transmission and distribution assets. This
normally means performing proactive end-of-life replacements. However, “run
469
Exhibit B-9, BCUC IR 1.73.5. 470
Exhibit B-1-1, Application, p. 6-16. 471
Exhibit B-14, BCUC IR 2.256.1.1. 472
Exhibit B-9, BCUC IR 1.73.6; BCUC IR 1.76.1; BCUC IR 1.76.2. See also Exhibit B-15, BCOAPO IR 2.79.1. 473
Exhibit B-9, BCUC IR 1.76.2; BCUC IR 1.73.6.
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to failure” is used to minimize the life cycle costs in some cases where the
impacts associated with asset failure are low.474
Monitoring system reliability to determine whether the level of sustaining
investments needs to be adjusted:475 BC Hydro will look to maintain satisfactory
SAIDI and SAIFI scores. The SAIFI and SAIDI metrics are indicators of reliability at
the overall system level. They indicate, respectively, the average frequency of
interruption and average duration of interruption that an average customer on
the system experiences.476 BC Hydro will monitor changes in the Customer
Satisfaction Index associated with system reliability, which could indicate that
asset health has been reduced below an acceptable level. 477
309. BC Hydro submits that the Transmission and Distribution reductions have been
achieved without subjecting the company or customers to unreasonable risk. BC Hydro will
continue to report on system reliability and asset health in future revenue requirement
applications. System reliability and asset health will also be used to support the level of
sustaining expenditures in future test periods. The effectiveness of the current level of
sustainment expenditures will inform future requirements, which will be under review as part
of future revenue requirement applications.478
Technology Reduction
310. Technology reduced planned capital expenditures by $75.5 million and planned
capital additions by $25.8 million over the test period. This represented reductions of 23 per
cent and 8 per cent, respectively.479 BC Hydro achieved the Technology reductions by
474
Exhibit B-1-1, Application, p. 6-30. 475
Exhibit B-9, BCUC IR 1.76.2. BCUC IR 1.73.6 476
Exhibit B-14, BCUC IR 2.256.1. 477
Exhibit B-14, BCUC IR 2.256.1.1. 478
Exhibit B-14, BCUC IR 2.256.2. 479
Planned capital expenditures of $325.3 million in the test period were reduced by $75.5 million, or23 per cent. Planned capital additions of $305.0 million in the test period were reduced by $25.8 million, or 8 per cent.
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reprioritizing Technology projects based on appropriate value and risk reduction criteria.
Despite the reduction in the forecast capital investments, safety and security considerations
remain paramount and BC Hydro is able to maintain existing assets and support key business
initiatives.
311. In considering reductions to the Technology capital plan for the test period, BC
Hydro had three priorities:
Maintain key programs such as cyber security and safety: Projects that reduce
cyber security risk or are required for NERC Critical Infrastructure Protection
(CIP) compliance have high value in BC Hydro’s prioritization exercise. Similarly,
projects that reduce safety risk to employees are valued highly.480
Maintain and sustain current IT assets and services and make appropriate
investments in foundational platforms: Maintaining current information
technology assets and services at existing performance and reliability levels is
necessary to keep pace with business changes and to manage operational risks.
Implementing and maintaining foundational platforms, including both hardware
and software is required to reliably and cost-effectively support BC Hydro’s
business operations.481
Support the implementation of strategic business initiatives: This priority
includes the implementation and maintenance of specialized business
applications such as Transmission and Distribution’s Strategic Asset Management
system, Generation’s Construction and Contract Management and Commercial
Management system, Customer Service’s BCHydro.com website and portal, and
Properties’ facilities management system.482
480
Exhibit B-10, CEC IR 1.79.1. 481
Exhibit B-10, CEC IR 1.79.1. 482
Exhibit B-1-1, Application, pp. 6-40 and 6-41.
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312. During the test period, capital expenditures of $35.6 million are planned for 25
Technology projects in the Customer category. Based on a current assessment of these 25
projects, approximately $18.6 million of the $35.6 million can be attributed to making it easier
for customers to do business with BC Hydro, and $17.0 million will be to provide more stable
and reliable systems.483 The capital expenditures related to improvements to cyber security are
forecast to be approximately $11.4 million during the test period.484
313. The reduction in Technology capital expenditures and additions was attributable,
in large measure, to delaying or cancelling asset refresh or enhancement programs related to
applications and telecommunications, and reprioritizing system resilience programs to an as-
needed basis.485 BC Hydro provided a description of the implications of information technology
projects deferred beyond the test period in its response to BCUC IR 1.114.9.
314. There were limits on the types of investments that could be delayed.
Investments to address BC Hydro’s aging and end of life information technology infrastructure
could not be deferred without increased risk of cyber security breach, information technology
systems performance issues and increased support costs.486 The current refresh program is in
line with standard business practices. BC Hydro refresh periods for servers, storage and
network devices are based on when product vendors cease to provide software support for the
hardware including security patches. Extending the refresh beyond that time risks exposing
infrastructure to a security breach.487
315. The practice of timing an infrastructure refresh to coincide with the end of
software support allows BC Hydro to minimize risks and avoid escalating support costs. Support
costs increase as the hardware ages. An infrastructure refresh often results in reduced support
costs. In addition, once the product vendors cease to provide software support, the only
483
Exhibit B-10, CEC IR 1.92.1. 484
Exhibit B-10, CEC IR 1.96.1. 485
Exhibit B-1-1, Application, pp. 6-16 and 6-17. 486
Exhibit B-15, CEC IR 2.157.1. 487
Exhibit B-15, CEC IR 2.157.1.
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recourse to a problem with the hardware is a complete refresh. This results in additional costs
for emergency support and possible business disruption.488
316. In an information request CEC asked about the effect of undertaking SAP
upgrades every two years instead of annually. SAP is BC Hydro’s core enterprise application
platform and hosts many critical business processes, and should be kept current.489 BC Hydro
does not expect that a bi-annual upgrade strategy would result in net cost savings relative to an
annual upgrade strategy. Cost efficiencies (e.g., project management, regression testing) would
be approximately offset by increased costs resulting from higher overall complexity and delays
in being able to access beneficial new SAP functionality.490
317. Technology planning is an ongoing process because technology needs, costs,
risks and available resources change. Plan revisions reduce investment risk because timely
adjustments are made in order to optimize the plan under changing conditions. Plan revisions
will not increase the risk to the ratepayers provided that the plans remain within the overall
targets of the 2013 10 Year Rates Plan.491 In light of the dynamic nature of BC Hydro’s
information technology portfolio, BC Hydro may achieve the reductions by other means.492
Properties Reduction
318. Properties reduced planned capital expenditures by $77.5 million and planned
capital additions by $177.1 million over the test period. BC Hydro delayed and reduced the
scope of building development projects at field facilities. BC Hydro prioritized investments
considering risk, safety, code and operational requirements, and the availability of mitigation
strategies to enable the continuation of service. Building improvement expenditures to sustain
488
Exhibit B-15, CEC IR 2.157.1. 489
Exhibit B-10, CEC IR 1.95.2. 490
Exhibit B-10, CEC IR 1.95.2. 491
Exhibit B-9, BCUC IR 1.78.2. 492
Exhibit B-1-1, Application, pp. 6-16 to 6-17.
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existing facilities were prioritized and maintained where possible.493 BC Hydro submits that the
savings have been achieved without subjecting the company and customers to unreasonable
risk.
D. PLANNED PROJECTS ADDRESS SHORT AND LONG-TERM REQUIREMENTS
319. The forecast capital expenditures and additions, after the significant reduction
and re-prioritization that BC Hydro has undertaken, include a variety of projects that are
integral to providing safe, reliable, environmentally sound and cost-effective service. BC Hydro
will adhere to the applicable guidelines for CPCN or section 44.2 reviews of individual projects.
The Site C Clean Energy Project was exempted from the CPCN requirement by legislation, the
Project is not affecting rates in the test period, and the Commission will review Project
expenditures in a future proceeding.
(a) BC Hydro Has Provided Project-Specific Information
320. BC Hydro’s Application included a significant amount of project-specific
information. In addition to the narrative and summary information in Chapter 6, BC Hydro
provided in Exhibit B-6 capital addition information for Technology projects and programs
greater than $2 million, and other projects greater than $5 million.494 Appendix J described
projects with planned total capital expenditures of greater than $20 million and with capital
expenditures in the test period. There were many project-specific information requests.
Appendix “A” to these submissions summarizes the evidence on the projects that received the
greatest attention in information requests. BC Hydro’s evidence demonstrates that there are
compelling reasons for pursuing these projects within the context of the 2013 10 Year Rates
Plan, and that BC Hydro is managing them prudently.495
493
Exhibit B-1-1, Application, p. 6-17. 494
Among other things, Exhibit B-6 included a revised Appendix I that corrected typographical errors and included additional information requested by Commission Staff.
495 Exhibit B-14, BCUC IR 2.260.3. Exhibit B-1-1, Application, p.6-14 and section 2.3.6.2.
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(b) BC Hydro Will Adhere to Applicable Project Approval Requirements
321. A number of information requests asked whether BC Hydro will file a CPCN or
section 44.2 application for specific projects identified in the Application. BC Hydro’s response
to BCUC IR 1.66.1 identified those projects for which BC Hydro would be filing an application,
based on its 2010 Capital Project Filing Guidelines.496 However, the Commission is addressing
prospective project approval requirements in the pending Capital Expenditure and Projects
Review proceeding. BC Hydro will follow the applicable guidelines.
322. Under the existing Capital Project Filing Guidelines, BC Hydro will file either a
CPCN or expenditure schedule (section 44.2) application for projects where the authorized cost
estimate497 exceeds one of three expenditure thresholds:
$100 million for generation and transmission (including Substation Distribution
Asset (SDA) components) projects;
$50 million for distribution and building projects; and
$20 million for information technology and telecommunication projects.498
323. Under the current Guidelines, the determination of whether to apply for a CPCN
or file an expenditure schedule under section 44.2 depends on whether the project is an
“extension” to BC Hydro’s existing plant or system. One outcome of the Capital Expenditures
and Projects Review proceeding will be to clarify when a project is an “extension” requiring a
496
Exhibit B-9, BCUC IR 1.66.1. 497
Exhibit B-9, BCUC IR 1.66.1; see also BCUC IR 1.68.2. The authorized cost estimate is the requested funding for a project, inclusive of all contingencies and reserves, and based on a fixed scope and in-service date. This is the appropriate cost estimate to use as a threshold because it is the amount that is reviewed and signed-off by BC Hydro’s Board of Directors and is the amount that BC Hydro has committed to spend.
498 Exhibit B-9, BCUC IR 1.66.1.
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CPCN.499 In the intervening period, the distinction between extensions and non-extensions is of
little practical significance from the perspective of the legal test, transparency and consultation:
CPCNs and expenditure schedules are subject to a public interest test.
As set out in the Guidelines, BC Hydro will file the same information in support of
its projects under section 44.2 as it would for a CPCN application.500
BC Hydro will, in both cases, comply with its duty to consult with First Nations
where its activities could adversely impact Aboriginal rights and title, and
accommodate those interests where appropriate. BC Hydro engages with First
Nations regarding its 10 Year Capital Forecast, and looks for early opportunities
to incorporate feedback. BC Hydro continues to engage with First Nations to
address any issues or concerns that arise, irrespective of the type of Commission
approval being sought.501
BC Hydro also consults on the capital investments with environmental regulators
and stakeholders such as community groups to identify their issues and
concerns, and consider how the concerns might be addressed in the capital
plan.502
324. The new Commission-approved capital project filing guidelines that flow from
the Capital Expenditures and Projects Review proceeding could differ from the current
Guidelines.503 BC Hydro would adhere to the Commission’s directions in that proceeding.
499
Exhibit B-9, BCUC IR 1.66.1. BC Hydro’s current Capital Project Filing Guidelines provide examples of what BC Hydro considers to be “extensions”.
500 Exhibit B-9, BCUC IR 1.66.1.
501 Exhibit B-9, BCUC IR 1.66.1; see also Exhibit B-10, CEC IR 1.87.1.
502 Exhibit B-9, BCUC IR 1.66.1; Exhibit B-1-1, Application, sections 5.7.5.9, 6.4.3.2 and 6.4.3.3.
503 Exhibit B-10, CEC IR 1.86.4.
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325. In light of the pending Capital Expenditure and Projects Review proceeding, BC
Hydro submits that the Commission should avoid addressing the content of potential
Guidelines in this Revenue Requirements proceeding.
(c) Site C Clean Energy Project Costs Will Be Reviewed in a Future Proceeding
326. The Site C Clean Energy Project was exempted from section 45 of the Utilities
Commission Act by the Clean Energy Act. The Site C Clean Energy Project is not driving BC
Hydro’s revenue requirements in the test period:
Past Project costs and related interest costs are held in the Site C Regulatory
Account that will begin to be recovered in rates only once the Project goes into
service.
There are minimal forecast operating expenses associated with the Site C Clean
Energy Project during the test period.
The forecast capital costs and interest during construction incurred during the
test period are accounted for as Work in Progress. They only begin to impact BC
Hydro’s revenue requirements when the Project goes into service (when they
become “capital additions”).
327. BC Hydro has, in the interest of transparency, included in the Application the
forecast expenditures and interest during construction related to the Site C Clean Energy
Project; however, BC Hydro is not seeking approval or endorsement of those forecast
expenditures. The Commission will review the Project at a future date to determine how costs
are recovered from rates.504 The Commission, in its scoping decision of September 7, 2016,
acknowledged BC Hydro’s willingness to be practical in responding to information requests, but
504
Exhibit B-4, p. 7.
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also acknowledged the existence of a better forum for assessing Site C Clean Energy Project
costs.505
E. BC HYDRO DELIVERS CAPITAL PROJECTS EFFICIENTLY AND EFFECTIVELY
328. One of BC Hydro’s priorities, consistent with the Minister’s Mandate Letter, is to
deliver the capital program on time and on budget.506 The accountable organizational groups
within BC Hydro use established processes to deliver capital projects and programs, and BC
Hydro has a track record of delivering its capital portfolio on budget (projects delivered
between fiscal 2012 to fiscal 2016 were 0.18 per cent under budget in aggregate).507
(a) Clear Organization and Accountabilities For Project Delivery
329. BC Hydro’s capital investments are delivered by accountable organizational
groups that are structured and positioned to implement capital projects and programs in an
efficient and timely manner.508 Approximately 70 per cent of the $7.6 billion in capital
expenditures planned in the fiscal 2017 to fiscal 2019 test period will be delivered by the Capital
Infrastructure Project Delivery Business Group, with the balance delivered by the originating
Business Groups.509 These groups and the processes used to deliver the capital portfolio
effectively are summarized below.
Capital Infrastructure Project Delivery Group Delivers Complex Projects Effectively
330. The Capital Infrastructure Project Delivery Business Group, formed in February
2015, is typically responsible for delivering more complex Generation and Transmission and
505
Order No. G-144-16, Reasons for Decision, p.2. “Generally speaking, other than those noted above and clarified by BC Hydro, there were no major disagreements among the parties regarding scoping. The Panel endorses BC Hydro’s assessment of scope, subject to the comments made by interveners as described above.”
506 Exhibit B-1-1, Application, p. 2-4.
507 Exhibit B-1-1, section 2.3.6.2, see also Exhibit B-9, BCUC IR 1.55.1 and Exhibit B-10, CEC IR 1.8.4 and BCOAPO IR 1.15.1
508 Exhibit B-1-1, Application, p. 6-51.
509 Exhibit B-1-1, Application, p. 6-52.
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Distribution capital projects greater than $1 million. The group has a number of processes and
practices to coordinate planning and delivery for products of this size and complexity, including
the Project and Portfolio Management practices, the project lifecycle, project initiation and
management and resourcing.
331. The execution of Generation and Transmission and Distribution projects in
excess of $1 million generally requires analysis of multiple design alternatives, and multiple
methods of execution. The Capital Infrastructure Project Delivery Business Group includes
Engineering, Aboriginal Relations and Environmental Risk Management, whose functions are
critical elements in delivering projects.510 All projects managed by Capital Infrastructure Project
Delivery use the Integrated Project and Portfolio Management solution.511 BC Hydro assigns a
Project Manager to each project, who is accountable for leading the planning, execution, and
close-out of the project.512
332. BC Hydro’s move to centralized delivery functions in the Capital Infrastructure
Project Delivery Business Group was accompanied by other process enhancements to improve
project delivery. BC Hydro has, for instance:
Enhanced the way it works and manages issues in the strategic areas of
Aboriginal relations, stakeholder engagement, safety, environment, and
community engagement with respect to delivery of capital projects and
programs.513 Some of the key enhancements made by BC Hydro include: 514
Engaging First Nations earlier on capital projects and facilitating higher
levels of engagement throughout the project life cycle;
510
Exhibit B-1-1, Application, p. 6-52. 511
Exhibit B-1-1, Application, p. 6-52. 512
Exhibit B-1-1, Application, p. 6-53. 513
Exhibit B-9, BCUC IR 1.119.4. 514
Exhibit B-9, BCUC IR 1.119.4.
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Becoming more proactive in engagement with communities, property
owners and other stakeholders; and
Identifying environmental risks earlier in the project life cycle and using
recently developed programs to manage a project’s progression through
the environmental permitting processes.
Improved the procurement process for major equipment and services by
adopting multi-year category planning. BC Hydro also engages with major
equipment manufacturers and suppliers at an early stage to help develop the
right procurement strategies for work identified in the capital forecast.515
333. The success of BC Hydro’s project management approach was shown in 2016
when BC Hydro received a maturity rating of 91 per cent out of a possible 100 per cent, placing
BC Hydro in the top-tier of organizations globally that had undergone an Organizational Project
Management Maturity Model Assessment. Subsequent to the assessment, BC Hydro was
recognized by the Project Management Institute by receiving the global award for the Project
Management Office of the Year for 2016.516
Groups Responsible for Effective Smaller Generation and Transmission and Distribution Project Delivery
334. The capital project delivery work managed within the Generation and
Transmission and Distribution Business Groups typically relates to capital investments less than
$1 million in cost or investments with lower complexity and risk. Departments within these
Business Groups are accountable for capital programs and projects delivery.
Transmission and Distribution Program and Contract Management is responsible
for the delivery of the majority of recurring capital and maintenance work
programs on BC Hydro’s transmission and distribution systems. The group will
515
Exhibit B-9, BCUC IR 1.119.4. 516
Exhibit B-9, BCUC IR 1.119.4.
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deliver close to $1 billion of BC Hydro’s capital expenditures over the test period.
This work includes Distribution Programs, Distribution Projects, Transmission
Programs, Vegetation and Access Management Programs, and Contract
Management.517 The Program and Contract Management group applies Project
and Portfolio Management concepts in addition to “factory production
management” concepts where a repeatable framework can be used to execute
low complexity projects.518
Transmission and Distribution Customer Services and Distribution Design will
deliver close to $440 million of BC Hydro’s capital expenditures over the test
period. The group provides all the technical design services and project
management for customer-driven “new connections” work under 5 MW. More
complex work over 5 MW, or customer projects presenting higher risk are
managed by a major projects group, supported by Distribution Design technical
services.519 Customer Services and Distribution Design follows a process of
designing to standards, with engineering support where required. It uses a
simplified project management structure that involves standardized work order
packages, with environmental, heritage, safety and job planning processes and
checklists.520
Generation Operations will deliver approximately $54 million of BC Hydro’s
capital expenditures over the test period. Generation Operations manages
projects that have low complexity and that typically have a total cost of less than
$1 million. These capital investments are typically like-for-like replacements
where there are limited or no alternatives to evaluate.521
517
Exhibit B-1-1, Application, pp. 6-68 to 6-69. Exhibit B-9, BCUC IR 1.119.4. 518
Exhibit B-9, BCUC IR 1.119.4; Exhibit B-1-1, Application, pp. 6-68 to 6-69. 519
Exhibit B-1-1, Application, p. 6-69. 520
Exhibit B-1-1, Application, p. 6-69. 521
Exhibit B-1-1, Application, p. 6-70.
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Effective Technology Capital Investment Delivery
335. The Technology Group will deliver close to $250 million of BC Hydro’s capital
expenditures over the test period. The Technology Group uses a framework called Information
Technology Delivery Standard Process to aid managers, service providers and project teams in
delivering projects. The framework uses a project lifecycle model consistent with BC Hydro’s
Project and Portfolio Management Practices, using the standard phases but with uniquely
defined stages.522
336. BC Hydro has initiated a number of improvements in information technology
capital planning and management since 2012:
First, BC Hydro added resources to support project control functions and related
oversight activities.523
Second, BC Hydro updated and improved Information Technology Delivery
Standard Practices and Information Technology Project Management to include
standard project phases and gates, with allowance for tailoring to accommodate
the unique requirements of information technology projects of various sizes and
complexity.524
Third, BC Hydro has improved project estimation, scheduling and business cases
through the development and use of standard templates and tools.525
Fourth, BC Hydro has established a standard onboarding program for Technology
project managers to promote consistency.526
522
Exhibit B-1-1, Application, p. 6-70. 523
Exhibit B-9, BCUC IR 1.119.4. 524
Exhibit B-9, BCUC IR 1.119.4. 525
Exhibit B-9, BCUC IR 1.119.4. 526
Exhibit B-9, BCUC IR 1.119.4.
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Fifth, BC Hydro uses formal portfolio management to track the approximately
120 information technology projects that are active at any given time. BC Hydro
introduced a monthly project dashboard to report on status and assess project
health against key indicators, both at the individual project and portfolio level.527
Sixth, BC Hydro established the Technology Planning and Performance team to
coordinate and manage capital planning activities.528
Seventh, BC Hydro expanded its portfolio management practice to increase its
ability to evaluate, prioritize and improve capital investment decisions.529
337. BC Hydro has validated its progress through annual quality assurance reviews.530
Effective Properties Capital Investment Delivery
338. The Properties Group will deliver $260 million of BC Hydro’s capital expenditures
over the test period. The delivery of Properties’ capital projects is managed in an integrated
manner, using both internal Properties resources as well as external parties. Properties’ Capital
Delivery processes align with the standard BC Hydro project lifecycle for managing projects,
whereby projects progress through the four phases of delivery: Initiation, Identification,
Definition, and Implementation.531
339. Properties requires formal gate approvals at the end of key stages in the project
lifecycle. At each stage, management must re-confirm that the proposed project continues to
align with business drivers and that the project is delivering on key project objectives relating to
cost, schedule, and scope.532
527
Exhibit B-9, BCUC IR 1.119.4. 528
Exhibit B-9, BCUC IR 1.119.4. 529
Exhibit B-9, BCUC IR 1.119.4. 530
Exhibit B-9, BCUC IR 1.119.4. 531
Exhibit B-1-1, Application, p. 6-71. 532
Exhibit B-1-1, Application, p. 6-71.
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(b) BC Hydro Has in Place Proper Governance, Oversight and Project Management
340. BC Hydro has implemented several governance structures and processes to
provide additional oversight of the capital delivery processes across BC Hydro, including:533
The Capital Projects Committee of the Board of Directors.
The Capital Delivery Management Committee (now replaced by the Executive
Team Capital Sub-committee).
The Capital Delivery Management Committee Working Team, which is composed
of managers and directors responsible for managing assets, managing resources
and delivering capital projects. It also includes finance support staff. The
Working Team primarily focuses on the near-term, managing to the fiscal budget
and identifying any capital portfolio realignment needed to meet financial and
resource constraint limits.
Project Accountability Meetings (for Project Delivery Managed Projects) provide
a forum for the oversight of all projects greater than $50 million, and projects
under $50 million where there is the risk of significant delays or cost increases.
Project Management Meetings (for Capital Infrastructure Project Delivery
Managed Projects) serve as gates to review and determine if a project is ready to
progress to the next stage of its lifecycle.
The executive team and the Customer Service, Operations and Planning
Committee and Capital Projects Committee of Board of Directors, which provide
oversight of the Technology Group capital processes.534
533
Exhibit B-1-1, Application, pp. 6-54 to 6-57. 534
Exhibit B-1-1, Application, p.6-45.
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(c) BC Hydro Has Delivered its Capital Portfolio On Budget
341. BC Hydro has a successful track record of delivering its capital projects on budget
on an overall portfolio basis. BC Hydro uses a capital delivery performance measure to evaluate
financial performance in delivering capital projects. The measure examines capital projects put
into service during a rolling five-year period, comparing the actual project costs to the original
amount at the first full implementation phase funding. BC Hydro publishes the results of this
measure in its annual Service Plan.535 From fiscal 2012 to fiscal 2016 BC Hydro completed 563
capital projects, with capital expenditures totalling $6.5 billion. These projects in aggregate
were delivered $11.7 million or 0.18 per cent under budget.536 At the individual project level,
69 per cent were delivered under budget.537 The capital projects included in this performance
measure include Generation, Transmission, Smart Metering and Infrastructure, and Properties.
For Properties, only projects with in-service dates in fiscal 2016 are included as these projects
were added to the performance measure in fiscal 2016.538
F. VARIANCE ACCOUNTS WILL BE IN PLACE
342. The effect of higher or lower than forecast amortization of capital additions in a
given year is captured in the Amortization of Capital Additions Regulatory Account and the
Total Finance Charged Regulatory Account. The variances are recovered in future rates.539 BC
Hydro is proposing to continue using those accounts.
343. Actual capital additions in each year of the test period can be expected to vary
from forecast due to updated in-service dates (which affects the year the addition is recorded)
or cost or scope changes. This is typical as projects advance. In the event that unforeseen
projects emerge in between capital planning periods, BC Hydro expects to manage those
535
Exhibit B-15, CEC IR 2.158.1. 536
Exhibit B-1-1, section 2.3.6.2, see also Exhibit B-9, BCUC IR 1.55.1 and Exhibit B-10, CEC IR 1.8.4 and BCOAPO IR 1.15.1
537 Exhibit B-10, CEC IR 1.86.3.
538 Exhibit B-15, CEC IR 2.158.1.
539 Exhibit B-14, BCUC IR 2.260.1.
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changes, for the most part, through redirection from within the individual business unit’s
capital portfolio plans.540
344. BC Hydro will inform the Commission of material changes to the scope, schedule
and cost projections of its capital projects listed in Appendix I of the Application by providing an
updated Appendix I in conjunction with the work that BC Hydro will undertake to update its 10
Year Capital Forecast. BC Hydro will consult with Commission Staff to determine the scope of
the update.541 BC Hydro has also made a number of commitments to file either CPCN or
section 44.2 applications for specific capital projects.542
G. CONCLUSION AND REQUESTED FINDINGS
345. The evidence demonstrates, and the Commission should find, that the forecast
capital expenditures and additions for the test period are appropriate. The capital forecast is
the product of a well-defined planning process. BC Hydro has accounted for the dual objectives
of the 2013 10 Year Rates Plan. BC Hydro is investing to meet reliability, safety and customer
requirements. At the same time, BC Hydro’s efforts to reduce the forecast capital expenditures
and additions is helping to keep rates as low as possible. BC Hydro is well positioned with
appropriate organizational structures, processes and oversight to deliver its capital plan on
budget.
540
Exhibit B-9, BCUC IR 1.64.7. 541
Exhibit B-14, BCUC IR 2.260.1. 542
Attachment 1 to BCUC IR 2.260.4 shows the commitments BC Hydro has made in this Application to filing with the Commission as anticipated filings. Exhibit B-14, BCUC IR 2.260.2.
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PART NINE: DEFERRAL AND OTHER REGULATORY ACCOUNTS
A. INTRODUCTION
346. Regulatory accounts are commonly used in the utility industry, and have been
used by BC Hydro for many years.543 The Commission has approved 28 deferral or regulatory
accounts for use by BC Hydro, which are listed in Table 7-9 of the Application.544 In this
Application, BC Hydro is not requesting approval for any new regulatory accounts,545 and many
of BC Hydro’s existing regulatory accounts will continue unchanged. BC Hydro’s regulatory
account-related requests, which are summarized in Table 7-9 of the Application,546 are: (i) to
continue or change the scope of some existing regulatory accounts; (ii) to establish appropriate
recovery mechanisms for some regulatory accounts; and (iii) to continue to apply interest to
balances in a number of regulatory accounts, and to initiate the application of interest on one
regulatory account. The following points, each of which is addressed in this Part, establish that
BC Hydro’s proposals are just and reasonable:
First, BC Hydro’s approved deferral and regulatory accounts do not need to be
revisited.
Second, BC Hydro is not requesting to change the scope of the majority (19) of
its 28 deferral and regulatory accounts.
Third, the accounts that BC Hydro is requesting to continue or modify the scope
will continue to serve appropriate regulatory functions and promote fairness.
543
Exhibit B-1-1, Application, p. 7-3. 544
Exhibit B-1-1, Application, p. 7-50. 545
BC Hydro recognizes that some requested changes to the scope of accounts are material and could be considered akin to a new account. For example, in Exhibit B-14, BCUC IR 2.283.1.1, BC Hydro notes that the Dismantling Cost Regulatory Account could be considered a request for a new regulatory account.
546 Exhibit B-1-1, Application, p. 7-50.
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Fourth, BC Hydro has proposed principled recovery mechanisms for its
regulatory accounts, which will enable the recovery of account balances over a
reasonable time.
Fifth, BC Hydro’s request to record interest on balances in some regulatory
accounts recognizes that BC Hydro incurs carrying costs, and mirrors the
approved treatment for other regulatory accounts that attract interest.
347. With the existing and proposed recovery mechanisms in place, BC Hydro
forecasts that the total balance in the regulatory accounts at the end of the test period will be
reduced by approximately 40 per cent at the end of the 2013 10 Year Rates Plan period.547
B. EXISTING ACCOUNTS SHOULD BE CONTINUED
348. All of BC Hydro’s 28 deferral or regulatory accounts have been previously
approved by the Commission. All but two accounts548 have been approved for ongoing use
over the test period, including many that are required by section 7 of Direction No. 7. All of BC
Hydro’s approved accounts continue to serve well-recognized objectives of regulatory accounts,
and there is no change in circumstance that would warrant discontinuing an account. The
exception to this over the test period is the Minimum Reconnection Charges Regulatory
Account, which was required to capture a one-time impact and which BC Hydro is proposing to
discontinue after the balance is fully amortized in fiscal 2017.549
349. Once a regulatory account is approved, it is beneficial and appropriate for it to
continue to fulfill its purpose as originally approved, until a change is warranted. The approach
of allowing approved accounts to continue on terms previously approved by the Commission is
beneficial as it:
provides more certainty to both the utility and ratepayers;
547
Exhibit B-9, BCUC IR 1.124.1. 548
The Amortization of Capital Additions Regulatory Account and the Total Finance Charges Regulatory Account. 549
Exhibit B-1-1, Application, p. 7-27.
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reduces the potential rate volatility that could result from frequent changes to
regulatory accounts;
reflects the fact that the need for and nature of most regulatory accounts
remains consistent over time; and
is more efficient.550
350. BC Hydro received information requests questioning whether some approved
accounts met (i) the five criteria related to whether a risk is controllable or non-controllable
discussed on page 7-10 of the Application, and (ii) BC Hydro’s proposed materiality threshold of
a net income impact of greater than $10 million in a fiscal year discussed on page 7-16 of the
Application.551 The five criteria and the $10 million materiality threshold were not
contemplated to apply to whether an established regulatory account should be continued to be
used. BC Hydro’s proposed materiality threshold of a net income impact of greater than $10
million in a fiscal year is a measure of the financial risk that BC Hydro would be prepared to
bear before it requested a new regulatory account, based on the assumption that existing
regulatory accounts would continue. If existing accounts cannot be assumed to continue, then
BC Hydro’s financial risk would increase and the $10 million threshold proposed in respect of
proposed new regulatory accounts would need to be revisited and lowered. It would therefore
be unfair and inappropriate to apply that threshold to existing accounts.552
C. MAJORITY OF ACCOUNTS ARE APPROVED FOR TEST PERIOD AND DO NOT REQUIRE
CHANGES
351. BC Hydro is proposing no change in scope for the majority (19) of its accounts.
There are 13 deferral or regulatory accounts that are approved for use over the test period for
550
Exhibit B-9, BCUC IR 1.125.2. 551
Exhibit B-9, BCUC IR 1.134.3; Exhibit B-14, BCUC IR 2.280.1.1. 552
Exhibit B-9, BCUC IR 1.134.3; Exhibit B-14, BCUC IR 2.280.1.1.
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which BC Hydro is not requesting any changes. This represents 68 per cent of the fiscal 2017
starting deferral balance.553 In addition, there are six other regulatory accounts approved for
use over the test period, for which BC Hydro is not proposing any changes in scope.554 In total,
these 19 deferral or regulatory accounts represent 78 per cent of the fiscal 2017 starting
deferral balance.555
352. As summarized in the following table, these regulatory accounts approved for
ongoing use (a) continue to serve the same rationale that had justified the original Commission
approval, and (b) in many cases, are backed by Direction No. 7.
Approved Deferral and Regulatory
Accounts
Account Objective that Continues to Be
Served
Backed by
Direction No. 7
Variance Accounts
1
2
3
4
5
6
7
8
9
10
Non-Heritage Deferral Account556
Trade Income Deferral Account
Storm Restoration Costs
Rock Bay Remediation
Arrow Water Systems
Real Property Sales
Minimum Reconnection Charges557
Mining Customer Payment Plan
Foreign Exchange Gains/Losses
Debt Management
Variance accounts defer for recovery in a
future period differences between
forecast and actual costs or revenues.
Accounts address material costs over
which BC Hydro has little control, and that
are subject to variability.558
Yes
Yes
Yes
Yes
Benefit Matching Accounts
11 Demand-Side Management Benefit matching accounts better match Yes
553
Calculated based on fiscal 2016 actual balances shown on Table 7-2 of Application (p. 7-6). 554
For these accounts, BC Hydro is proposing additions to the account in accordance with its scope and Direction No. 7 (Rate Smoothing), discontinuance following recovery of the balance (Minimum Reconnection Charge) or continuing on an ongoing basis a recovery mechanism (Storm Restoration Costs, Rock Bay Remediation, Arrow Water Systems, and SMI).
555 Calculated based on fiscal 2016 actual balances shown on Table 7-2 of Application (p. 7-6).
556 Exhibit B-1-1, Application, pp. 7-17 to 7-20. For clarification of the scope of this account, see the preamble of BCUC IR 1.129.1, which is correct aside from minor references noted in BC Hydro’s response to BCUC IR 2.278.1 (Exhibit B-14).
557 BC Hydro is proposing that this account be closed, upon recovery of the balance in the account in fiscal 2017 rates (Exhibit B-1-1, Application, p. 7-27).
558 Exhibit B-1-1, Application, pp. 7-10, and 7-11 and relevant part of Section 7.5; Exhibit B-9, BCUC IR 1.148.1 (Storm Restoration Costs); 1.147.2 (Arrow Water Systems); 1.145 series (Mining Customer Payment Plan).
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12
13
14
Pre-1996 Contributions in Aid of
Construction
SMI
Capital Project Investigation Costs
costs with benefits for customers, thereby
supporting intergenerational equity for
current and future ratepayers.559
Non-Cash Provisions
15
16
First Nations Provisions
Arrow Water Systems Provision
Accounts required to establish a non-cash
provision regulatory account. Creates a
regulatory asset to match an accounting
liability that is required under the
accounting standards, prior to the actual
expenditure of the funds.560
Rate Smoothing
17 Rate Smoothing This account was created to keep rate
increases as gradual and predictable as
possible, by spreading costs that occur in
the earlier years of the 2013 10 Year Rates
Plan over the later years of the Plan. In
accordance with Direction No. 7, BC Hydro
is requesting approval of additions to the
Rate Smoothing Regulatory Account for
fiscal 2017 to fiscal 2019. BC Hydro is on
track to reduce the balance of this
account to zero by fiscal 2024, as
required by the 2013 10 Year Rates
Plan.561
Yes
IFRS Transition Accounts
18
19
IFRS Pension
IFRS Property, Plant and Equipment
IFRS transition accounts to defer the
impact of a required change in the
accounting treatment of costs to ensure
proper recovery of those costs.562
D. OTHER ACCOUNTS SHOULD BE CONTINUED – SOME “AS IS” AND SOME WITH SCOPE
CHANGES
353. For the remaining nine deferral or regulatory accounts not listed in the table
above, BC Hydro is proposing the following types of changes:
559
Exhibit B-1-1, Application, p. 7-12 and sections 7.5.14, 7.5.18, 7.5.19, and 7.5.20; Exhibit B-9, BCUC IR 1.146.1 (SMI); BCUC IR 1.151.1 (Capital Project Investigation Costs).
560 Exhibit B-1-1, Application, p. 7-12 and sections 7.5.21 and 7.5.22; Exhibit B-9, BCUC 1.142.2 (First Nations Provisions) and BCUC IR 1.147.4 (Arrow Water Systems Provision).
561 Exhibit B-1-1, Application, section 7.5.24.
562 Exhibit B-1-1, Application, pp. 7-13 to 7-14 and sections 7.5.25 and 7.5.26.
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to continue the existing scope on an ongoing basis for two regulatory accounts;
reduce the scope of two regulatory accounts; and
expand or change the scope for five regulatory accounts.
354. The following table summarizes BC Hydro’s requests to continue or change the
scope of its deferral and regulatory accounts, and the rationale for the requests.
Name of
Regulatory
Account
BC Hydro’s
request:
Continue, change
scope, rename
Rationale for Account Extension and/or Scope Change
Continuance of Existing Scope on an Ongoing Basis
20 Amortization of
Capital Additions
Continue approved
scope on an
ongoing basis
The Amortization of Capital Additions Regulatory Account was
originally approved by Commission Order No. G-16-09. On
page 191 of its Decision, the Commission stated: “The most
effective solution to ensuring that amortization charges
collected in revenue requirements for the test period
appropriately reflect the capital assets that are actually utilized
for the benefit of ratepayers during the same test period is to
establish a new regulatory account.” Pursuant to Order No. G-
16-09, deferred variances relate only to the amortization of
capital additions planned during the test period, and do not
relate to the amortization of existing assets. This account has
been approved in subsequent decisions for each test period.
There continues to be significant variability between actual and
planned capital additions due to timing and cost, and there is a
resulting impact on amortization. This account should therefore
be continued on an ongoing basis.563
21 Total Finance
Charges
Continue approved
scope on an
ongoing basis
The Total Finance Charges Regulatory Account was originally
approved by Commission Order No. G-16-09 and has been
continued in subsequent decisions. There is continuing
uncertainty regarding interest rates and the amount of debt
incurred. The table in BCUC IR 1.135.4 shows significant
variances between actual and plan amounts (in both dollar and
percentage terms), and significant variances between years.
The Heritage and Non-Heritage Deferral Accounts are not a
563
Exhibit B-1-1, Application, p. 7-21 and 7-52; Exhibit B-9, BCUC IR 1.134.3 and 1.134.4; Exhibit B-14, BCUC IR 2.280.4.2. The table in the response to BCUC IR 1.134.3 shows significant variances between actual and plan amounts (in both dollar and percentage terms), and significant variances between years.
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substitute for this account. This account should therefore be
continued on an ongoing basis. 564
Scope Reduction
22 Heritage
Deferral Account
Exclude variances
related to First
Nations
negotiations costs
The Heritage Deferral Account is required by section 7(a) of
Direction No. 7 and Order No. G-48-14 approved its use on an
ongoing basis. The proposed scope reduction is warranted
because First Nations negotiation costs are more predictable
and controllable than other factors such as water inflow levels
and market prices. BC Hydro therefore believes it should bear
the risk on variances between forecast and actual First Nations
negotiation costs, consistent with the treatment of other
controllable First Nations-related costs.565
23 First Nations
Costs
BC Hydro to bear
risk associated
with variances in
First Nations
negotiation costs
The First Nations Costs Regulatory Account was first approved
by Order No. G-53-02, and Direction No. 7 requires it to
continue. The account will capture differences arising from
variances between forecast and actual (i) lump sum settlement
payments and (ii) annual settlement payments.
However, BC Hydro is proposing to reduce the scope of the
account to exclude the recovery of variances between forecast
and actual First Nations negotiation costs. BC Hydro is
proposing that actual negotiation costs be deferred to this
account, and actual negotiation costs be amortized, but that
any variance between forecast and actual annual negotiation
costs be to the account of the shareholder.566
BC Hydro
believes it should bear the risk of variances between forecast
and actual negotiation costs, as it is better positioned to
forecast negotiation costs than other costs captured in the
account.567
Expansion or Other Change in Scope
24 Asbestos
Remediation
(proposed to be
renamed the
Remediation
Regulatory
Account)
Expand to include
variances between
forecast and actual
polychlorinated
biphenyl (“PCB”)
compliance costs
Rename to
“Remediation
The Asbestos Remediation Regulatory Account was originally
approved by Order No. G-7-13. Order No. G-48-14 approved
the account on an ongoing basis pursuant to Section 7(f) of
Direction No. 7, which allows BC Hydro to continue to defer to
the Asbestos Remediation Regulatory Account the variances
between actual and forecast asbestos remediation costs.
Consistent with the treatment of other environmental
remediation costs (i.e. asbestos and Rock Bay remediation
costs), BC Hydro is proposing to defer variances in PCB
564
Exhibit B-1-1, Application, pp. 7-22 and 7-52; Exhibit B-9, BCUC IR 1.135.2, 1.135.3, and 1.135.4. 565
Exhibit B-1-1, Application, p. 7-19 and 7-51; Exhibit B-9, BCUC IR 1.128.4; Exhibit B-14, BCUC IR 2.277.4 566
Exhibit B-9, BCUC IR 1.141.2; Exhibit B-14, BCUC IR 2.287.4. 567
Exhibit B-1-1, Application, p. 7-33 and 7-34; Exhibit B-9, BCUC IR 1.128.4 and BCUC IR 1.141.2.
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301539.00014/91303997.1
Regulatory
Account”
compliance costs.
Similar to asbestos remediation costs, BC Hydro incurs costs
annually to comply with PCB regulations. PCB costs, similar to
asbestos costs, can differ from forecast due to the timing and
scope of work undertaken. As shown in the table in the
response to BCUC IR 1.137.4, there have been material
variances between forecast and actual amounts (in both dollar
and percentage terms), and significant variances between
years. Specifically, the variances between forecast and actual
PCB costs for fiscal 2012 through fiscal 2016 were ($5.0)
million, ($7.4) million, ($6.5) million, ($4.5) million and $0.6
million, respectively.568
.
BC Hydro’s request is that actual remediation costs will be
deferred to this account each year, and forecast remediation
costs will be amortized from this account each year. In this
way, BC Hydro’s proposal will result in the variance between
forecast and actual asbestos and PCB remediation costs
remaining in the Remediation Regulatory Account.569
25 Environmental
Provisions
As actual PCB
compliance costs
are deferred to the
Remediation
Regulatory
Account, that the
Environmental
Provisions
Regulatory
Account be
reduced by an
equal amount
The Environmental Provisions Regulatory Account was
approved by Commission Orders No. G-88-10 and No. G-7-13.
The account is for the liability recognized by BC Hydro in its
financial statements in respect to (i) costs to comply with PCB
regulations, (ii) Rock Bay remediation costs and (iii) asbestos
remediation costs. As actual asbestos and Rock Bay
remediation costs are deferred, this account is reduced by an
equal amount. In prior fiscal years, as PCB expenditures were
incurred, the Environmental Provisions Regulatory Account was
also reduced by an equal amount.570
As BC Hydro is now proposing to defer the actual costs
associated with compliance with PCB regulations to the
Asbestos Remediation Account (to be renamed the
Remediation Regulatory Account), the account will continue to
be drawn down as these amounts are transferred to the
Remediation Regulatory Account. The effect of this is a
transfer of the PCB costs from the Environmental Provisions
Regulatory Account, with no change in the total end of year
568
Exhibit B-9, BCUC IR 1.137.4; Exhibit B-14, BCUC IR 2.282.2 and 2.282.2.1. 569
Exhibit B-1-1, Application, pp. 7-25, 7-26, 7-43 and 7-53; Exhibit B-9, BCUC IR 1.137.3. 570
Exhibit B-9, BCUC IR 1.138.5.
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balance of the Environmental Provisions Regulatory Account,
and no change to BC Hydro’s revenue requirements.571
26 Non-Current
Pension Costs
(proposed to be
renamed the
Pension Costs
Regulatory
Account)
Expand to include
the operating cost
portion of current
service pension
cost variances and
use the five-year
average of past
discount rates
when forecasting
pension costs 572
Rename as the
“Pension Costs
Regulatory
Account”
The Non-Current Pension Costs Regulatory Account was
approved for non-current pension cost variances in Orders No.
G-16-09, G-77-12A, and G-48-14. Order No. G-48-14 approved
the ongoing deferral of non-current pension cost variances as
required by section 7(g) of Direction No. 7. Order No. G-148-
15 approved the deferral of the fiscal 2016 variance on the
operating portion of current service pension costs due to a
change in the actuarial discount rate. For the test period and
on an ongoing basis, BC Hydro is requesting the Non-Current
Pension Costs Regulatory Account be renamed the Pension
Costs Regulatory Account, and be expanded to include all
variances between the forecast and actual operating cost
portion of current service pension costs.573
This proposal is
appropriate as these costs are difficult to forecast. Variances
have been frequent and material, and determined by factors
not within BC Hydro’s control. In conjunction with this request,
BC Hydro is also proposing to use the five-year average of past
discount rates when forecasting pension costs. Together, the
proposals will mitigate the volatility in pension expense and
ensure customers only pay actual pension expense.574
It is appropriate to defer the operating portion of current
service pension cost variances as they meet the criteria for new
variance accounts set out in section 7.3 of the Application,
including the materiality threshold in section 7.4 of “a net
income impact of greater than $10 million in a fiscal year.” In
short, pension costs are difficult to forecast and vary frequently
and materially due to factors outside of BC Hydro’s control.575
The table in response to BCUC IR 1.140.6 shows significant
variances between actual and plan amounts (in both dollar and
percentage terms), and significant variances between years.
The operating cost portion of variances exceeded $10 million in
fiscal 2016 and fiscal 2017.576
Over the last five fiscal years,
changes in the discount rate have been the primary reason for
571
Exhibit B-1-1, Application, pp. 7-43 and 7-60; Exhibit B-9, BCUC IR 1.138.5. 572
Current service pension costs relate to pension post-employment benefits and other post-employment benefits. Exhibit B-1-1, Application, pp. 7-29 and 7-30; Exhibit B-9, BCUC IR 1.140.5 and BCUC IR 1.140.7.
573 Exhibit B-9, BCUC IR 1.140.6.
574 Exhibit B-1-1, Application, section 7.5.12; Exhibit B-14, BCUC IR 2.294.3.
575 Exhibit B-14, BCUC IR 2.294.3.
576 Exhibit B-9, BCUC IR 1.140.6 and 1.140.17; Exhibit B-14, BCUC IR 2.293.6.
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variances in current service pension costs. Discount rates are
not within BC Hydro’s control, and have ranged from
6.12 per cent to 3.51 per cent from fiscal 2011 to fiscal 2016. A
one per cent change in the discount rate results in an
approximately $30 million impact to current service pension
costs.577
For example, in fiscal 2016 the discount rate
accounted for $28.7 million or 78 per cent of the $36.9 million
variance.578
Two of the three other factors contributing to
variances are also out of BC Hydro’s control: inflation, and
mortality rates.579
While BC Hydro has control over variances
related to assumptions in changes in its workforce, this has
been a relatively small factor over the last number of years. BC
Hydro cannot readily break down the variance due to this
factor, but the sum of the variances due to all factors other
than the discount rate was $0.8 million or less in a given year
over fiscal 2011 to fiscal 2016.580
Given the material and frequent variances due to factors
outside of BC Hydro’s control, BC Hydro’s proposal to defer
these variances is appropriate. It will reduce volatility in
operating costs, customer rates, and actual net income, and
will ensure that ratepayers, over time, will pay only the actual
costs incurred.
In conjunction with BC Hydro’s proposal to defer the operating
portion of current service pension cost variances, BC Hydro is
proposing to forecast pension costs using a five-year historical
average of actual discount rates. This methodology is objective
and will reduce volatility that can occur if discount rates vary
significantly from year-to-year. A five-year average approach
matches the approach used for forecasting other items that are
volatile, uncontrollable and for which there is no other
reasonable basis to forecast, such as Storm Restoration Costs
and Trade Income.581
The calculation and recognition of actual
pension costs will continue to be done in accordance with
International Accounting Standard 19; however, International
577
Exhibit B-9, BCUC IR 1.63.6; Exhibit B-10, BCOAPO IR 1.43.1. 578
Exhibit B-14, BCUC IR 2.293.1 579
Exhibit B-9, BCUC IR 1.140.6 Exhibit B-14, BCUC IR 2.293.2.1. 580
Exhibit B-14, BCUC IR 2.293.1. 581
Exhibit B-9, BCOAPO 1.43.1; Exhibit B-14, BCUC IR 2.294.3.
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Accounting Standard 19 does not provide guidance on
forecasting pension costs.582
A forecast methodology based on
market forecast interest rates as a proxy to forecast discount
rates would still result in variances between forecast and actual
pension costs, and would result in increased volatility in the
pension cost forecast compared to BC Hydro’s proposed
methodology. BC Hydro expects that over time its proposed
methodology will result in reduced volatility, especially in
periods where discount rates rise and fall.583
27 Site C Include Site C
Clean Energy
Project costs that
cannot be
capitalized, on an
ongoing basis
The Site C Regulatory Account was approved by Order No. G-
146-06 and subsequent Commission orders to defer costs
related to the Site C Clean Energy Project not eligible for
capitalization. BC Hydro commenced capitalization of costs
related to the project starting in January 2015. While most
project costs can be capitalized, some (e.g., certain legal costs)
cannot. The rationale for this account, of matching costs and
benefits, continues to apply to any costs related to the project
that are not eligible for capitalization.584
Pursuant to section 8 of the Clean Energy Act, the Commission
must set rates that allow BC Hydro to collect sufficient revenue
in each fiscal year to enable it to recover BC Hydro’s costs
related to the Site C Clean Energy Project. BC Hydro’s proposed
approach will ensure that BC Hydro will be able to recover
project costs that may not be eligible for capitalization, and
ensure that ratepayers only pay the actual amount of these
costs.
28 Future Removal
and Site
Restoration
(proposed to be
renamed the
Dismantling Cost
Regulatory
Account)
Rename, and
change purpose to
capture
dismantling cost
variances.
The Future Removal and Site Restoration Regulatory Account
was originally approved by Order No. G-96-04 due to a change
in the accounting rules for dismantling costs. Prior to the
change, BC Hydro accrued a provision for future dismantling
costs. After the change, the provision was not required, but BC
Hydro had accrued a large sum for future dismantling costs.
Rather than attributing this balance to the shareholder, the
Future Removal and Site Restoration Regulatory Account was
created to draw down the accrued amount as actual
dismantling costs were incurred in fiscal 2005 and future years.
The balance in the Future Removal and Site Restoration
Regulatory Account was drawn down to zero in the first quarter
of fiscal 2017. BC Hydro is therefore now including its forecast
582
Exhibit B-14, BCUC IR 2.289.1 and 2.294.2. 583
Exhibit B-14, BCUC IR 2.294.3. 584
Exhibit B-1-1, Application, pp. 7-35 to 7-36.
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dismantling costs in its revenue requirements effective for
fiscal 2017. BC Hydro is proposing to use the regulatory
account to capture the variance between forecast and actual
dismantling costs.585
It is appropriate to defer variances between plan and actual
dismantling costs as it meets the criteria set out in section 7.3
of the Application, and the materiality threshold in section 7.4
of “a net income impact of greater than $10 million in a fiscal
year.” First, actual dismantling costs are expected to differ
from forecast amounts due to timing: dismantling work often
occurs based on capital project schedules, which can change.
Second, emergency dismantling of assets is sometimes
required. Third, the full scope and cost of dismantling activities
is not known until the dismantling activities are completed.
Fourth, as shown in the table in response to BCUC IR 1.139.3.1,
the variances between actual and planned dismantling costs for
fiscal 2012 through fiscal 2016 were ($14.1) million, ($4.5)
million, $11.2 million, ($2.2) million and ($7.0) million,
respectively. Variances to plan in dismantling expenditures
have exceeded $10 million in two of the last five fiscal years.
These material variances are also possible in the future.586
Finally, BC Hydro’s proposal is warranted as it will result in this
account achieving the same result as it has in the past, by
ensuring that ratepayers only pay for actual dismantling costs.
E. BC HYDRO IS PROPOSING APPROPRIATE RECOVERY MECHANISMS FOR ACCOUNTS
WITH NO ONGOING MECHANISM OR WITH CHANGES IN SCOPE
355. BC Hydro has recovery mechanisms in place for many of its accounts.587
However, BC Hydro requires approval of recovery mechanisms for ten regulatory accounts as
listed in Table 7-9 of the Application under the column “Requested Changes to Recovery
Mechanism”. For these regulatory accounts, the Commission has only approved the
amortization of specific amounts from the accounts in prior fiscal years, or BC Hydro has
proposed a change to the scope as discussed in the section above.
585
Exhibit B-1-1, Application, p. 7-36 to 7-38; Exhibit B-9, BCUC IR 1.139.2. 586
Exhibit B-1-1, Application, p. 7-37; Exhibit B-9, BCUC IR 1.139.3.1; Exhibit B-14, 2.283.1.1. 587
For instance, Commission Order No. G-48-14 approved the recovery mechanisms for BC Hydro’s Cost of Energy Deferral Accounts and the Demand-Side Management Regulatory Account, on an ongoing basis. The mechanism approved for the Cost of Energy accounts is mandated by Direction No. 7, section 10(3).
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356. BC Hydro’s proposed recovery mechanisms are set out in the discussion of the
relevant accounts in Section 7.5 and summarized in Table 7-9 in the Application. BC Hydro
clarifies that for the Storm Restoration Costs, Amortization of Capital Additions and SMI
Regulatory Accounts, BC Hydro’s proposed recovery mechanisms include the recovery of the
forecast interest charges each year. As noted in Table 7-8 of the Application, these three
regulatory accounts attract interest; however, the recovery of this interest was not explicitly
referred to in section 7.5 or Table 7-9. The recovery of the interest on these accounts,
however, is reflected in BC Hydro’s revenue requirements as shown in Appendix A of the
Application and detailed in BC Hydro’s responses to information requests.588 The recovery of
interest in these accounts is consistent with the treatment of other interest-bearing regulatory
accounts.
357. BC Hydro’s proposed recovery mechanisms reflect the principles for recovery
mechanisms set out in Table 7-4.589 The relevant principles are as follows:
Cash variance accounts: to minimize intergenerational inequity, the balance in
the accounts should be recovered in the subsequent test period.
Non cash variance accounts: should be recovered over the remaining period of
the associated asset or liability (e.g., remaining service life of employees or
remaining term of debt issuances).
Benefit matching accounts: to achieve intergenerational equity, the recovery
period should match the future benefit period of the expenditure.
358. Granting the requested approvals on an ongoing basis will align with these
principles, and improve regulatory efficiency and enhance the predictability of rate impacts.590
588
Exhibit B-1-1, Appendix A, Financial Schedules; Exhibit B-9, BCUC IR 1.124.11, p. 4-5 of 7 (re SMI); Exhibit B-14, BCUC IR 2.276.1, p. 1 of 11 (re Storm Restoration Costs); and Exhibit B-14, BCUC IR 2.276.1, p. 2 of 11 (re Amortization of Capital Additions).
589 Exhibit B-1-1, Application, p. 7-15.
590 Application, pp.7-15 and 7-16.
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359. BC Hydro’s proposed recovery mechanisms that were the subject of information
requests are discussed below.
(a) Rock Bay Remediation Recovery Mechanism
360. Order No. G-48-14 approved the deferral of actual Rock Bay costs incurred in
fiscal 2014 and later years, pursuant to section 7(e) of Direction No. 7. Pursuant to Section
11(c) of Direction 7, the Commission cannot disallow the recovery of the Rock Bay costs.
361. BC Hydro is proposing to amortize forecast Rock Bay costs over the test period
consistent with its approach to other cash variance accounts. Specifically, BC Hydro’s recovery
mechanism request for this account is as follows in Table 7-9:
The closing fiscal 2016 balance in the account be recovered over the fiscal 2017
to fiscal 2019 test period;
Effective starting in fiscal 2017, and on an ongoing basis, the forecast interest
charged to the Rock Bay Remediation Regulatory Account each year be
amortized from this account in each year; and
On an ongoing basis, the forecast account balance at the end of a test period is
to be recovered over the next test period.
362. Together, BC Hydro’s proposals will result in the variance between forecast and
actual Rock Bay remediation costs being recovered over each subsequent test period.591 This
proposal is consistent with the appropriate principles for the recovery of cash variance
accounts and will ensure that customers only pay for actual Rock Bay remediation costs.
591
Exhibit B-1-1, Application, p. 7-22 to 7-23; Exhibit B-9, BCUC IR 1.136.1 and Exhibit B-10, BCOAPO IR 1. 47.1.
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(b) Non-Current Pension Costs Regulatory Account (Proposed to be renamed the
Pension Costs Regulatory Account) Recovery Mechanism
363. BC Hydro’s requested recovery mechanism for the Non-Current Pension Costs
Regulatory Account is set out in section 7.5.12 and line 14 of Table 7-9 of the Application. BC
Hydro is proposing to continue the existing treatment whereby the balance in the Non-Current
Pension Costs Regulatory Account is amortized over the Expected Average Remaining Service
Life of the active employee group (EARSL) as determined by BC Hydro’s actuary.592 BC Hydro’s
EARSL is currently 12 years as determined by BC Hydro’s actuary.593
364. The recovery of pension expense over the EARSL is appropriate for the following
reasons:
The amortization period matches the underlying attribute associated with the
costs. These pension costs relate to BC Hydro’s active employee group, and the
proposed amortization period (EARSL) matches the expected service life of these
employees.594
This matching will also minimize intergenerational inequity as the amortization
period matches the period of benefit to ratepayers (i.e., EARSL).595
The amortization period (currently 12 years) smoothes any related volatility in
rates due to variances in current service costs, which have been as high as $22.1
million in recent years.596
365. Consistent with the above, BC Hydro’s recovery requests include the following:
592
Exhibit-14, BCUC IR 2.296.2. 593
Exhibit B-9, BCUC IR 1.140.8. 594
Exhibit B-9, BCUC IR 1.140.8; Exhibit B-14, BCUC IRs 2.296.3 and 2.296.3.1. 595
Exhibit B-14, BCUC IR 2.296.3. 596
Exhibit B-14, BCUC IR 2.296.3.1.
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The portion of the forecast account balance at the start of a test period related
to the variances transferred to the account during the previous test period be
amortized over a period of time based on the expected average remaining
service life of the active plan members at the start of the test period;
The actuarial gain which is forecast to be transferred to the Pension Costs
Regulatory Account in fiscal 2017, as a result of using the forecast discount rate
of 4.38 per cent, be amortized, beginning in fiscal 2018, over a 12-year period,
which is the currently expected average remaining service life of the active plan
members at the beginning of fiscal 2018;
The portion of the actual or forecast account balance at the start of the test
period related to variances between its actual and forecast non-current pension
costs for the fiscal 2015 to fiscal 2016 test period, be amortized over the 12-year
period ending in fiscal 2028, which is the currently expected average remaining
service life of the active plan members at the beginning of the fiscal 2017 to
fiscal 2019 test period; and
The portion of the actual or forecast account balance at the start of the test
period related to variances between its actual and forecast non-current pension
costs for the fiscal 2011 to fiscal 2014 test period, continue to be amortized over
the remaining years of the 13-year period ending in fiscal 2027, which was the
period of time based on the expected average remaining service life of the active
plan members at the beginning of the fiscal 2015 to fiscal 2016 test period.597
366. As noted above, BC Hydro’s proposals include the recovery over 12 years of the
operating cost portion of the variance between fiscal 2017 forecast current service costs and
actual current service pension costs. While it is unusual for a variance during a test period to be
known at the time an Application is filed, the operating cost portion of the current service
597
Exhibit B-1-1, Application, p. 7-31.
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pension cost variance in fiscal 2017 was known at the time of drafting the Application due to
the timing of the Application.598 The fiscal 2017 variance should be treated the same as all other
variances, and should be amortized based on the same principle as other balances in the
account for the reasons discussed above.
367. BC Hydro’s requested recovery mechanism is consistent with the appropriate
principles for the recovery of non-cash variance accounts and will ensure that customers only
pay for actual pension expense.
(c) First Nations Cost Regulatory Account Recovery Mechanism
368. Order No. G-48-14 directed BC Hydro to amortize specific amounts from the First
Nations Costs Regulatory Account and the accrual of interest, as required by section 3(g) of
Direction No. 6 and section 7(i)(i) of Direction No. 7, respectively. BC Hydro is requesting
recovery of amounts that are consistent with amortization required by Direction No. 6, and that
will establish an ongoing recovery mechanism based on sound principles consistent with past
Commission approvals.
369. BC Hydro is requesting approval to recover settlement costs related to the three
First Nations included in the definition of “First Nations settlements” in section 1 of Direction
No. 7. Section 11 of Direction No. 7 requires the Commission to allow recovery of these costs.
370. BC Hydro is also requesting approval to recover lump sum settlements related to
two First Nations that are not included in the definition of “First Nations settlements” in section
1 of Direction No. 7.599 BC Hydro explained that it did not explicitly identify these two lump sum
settlements in its Application as they were included in the amortization in fiscal 2015 and fiscal
2016:
598
Exhibit B-1-1, Application, p. 7-31; Exhibit B-9, BCUC IR 1.140.17 and Exhibit B-14, BCUC IR 2.297.11. 599
Exhibit B-9, BCUC IRs 1.141.4.1, 1.141.7, 1.141.10 and the Confidential versions of these responses in Exhibit B-9-1.
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…the fiscal 2015 and fiscal 2016 amortization amounts in the First Nations Cost Regulatory Account that were specified in Direction No. 6 included amortization related to these two settlements. Since we are requesting recovery of the same lump sum settlements that were included in the amounts previously approved for fiscal 2015 and fiscal 2016, we overlooked the need to specifically identify recoveries of these two settlements in our Application...600
371. BC Hydro provided a detailed account of these lump sum settlements in its
responses to information requests, some of the details of which are confidential.601
372. BC Hydro’s specific recovery requests are summarized as follows:
Return to ratepayers of fiscal 2016 balance related to variance from specific
fiscal 2015 and fiscal 2016 amounts: The actual transfers to the First Nations
Costs Regulatory Account in fiscal 2015 and fiscal 2016 were different from the
specific amortization amounts in Commission Order No. G-48-14 as required by
Direction No. 6. This variance resulted in BC Hydro recording higher
amortization than what would have resulted if amortization had been calculated
on actual transfers. BC Hydro proposes to refund this difference in amortization
in fiscal 2017 to the benefit of ratepayers.602
Recovery of past settlement payments and negotiations costs consistent with
Direction No. 6 and approved 10-year amortization period: BC Hydro is
requesting amortization of settlement payments and negotiations costs from the
First Nations Cost Regulatory Account that are consistent with the amounts
amortized pursuant to Order No. G-48-14 and Direction No. 6, and which reflect
an amortization period of 10 years.603 For example, for settlement payments
and negotiation costs incurred prior to fiscal 2015, BC Hydro proposes an
600
Exhibit B-14, BCUC IR 2.287.9. 601
Exhibit B-9, BCUC IRs 1.141.4.1, 1.141.7, 1.141.10, and 1.142.4, and the confidential versions of these responses in Exhibit B-9-1; Exhibit B-14, BCUC IRs 2.287.9 and 2.287.9.1 and confidential versions of these responses in Exhibit B-14-1.
602 Exhibit B-1-1, Application, p. 7-33.
603 Exhibit B-1-1, Application, pp. 7-32- and 7-33, (ii) and (iii).
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amortization period of eight years beginning in 2017, as amounts were
amortized from the account for fiscal 2015 and fiscal 2016 in accordance with
Order No. G-48-14, leaving eight years remaining of the proposed ten-year
amortization period. A ten-year amortization period is consistent with the
amortization period for actual negotiation costs and approved settlement costs
directed by Commission Order No. G-53-02.604
Ongoing lump sum and settlement payments: BC Hydro is requesting approval
of ongoing amortization of forecast lump sum payments based on a 10-year
amortization period605 and amortization of forecast annual settlement payments
in the forecast year of payment.606 BC Hydro is requesting that any variance
between forecast and actual lump sum and annual settlement payments be
recovered in the subsequent test period.607 This is consistent with the recovery
mechanism for cash variance accounts.
Recovery of interest: BC Hydro is proposing to amortize forecast interest on the
account each year, and then recover any variance between actual and forecast
interest in the subsequent test period, on an ongoing basis.608
373. BC Hydro’s proposed recovery mechanisms are consistent with past Commission
orders, and the appropriate principles. They should be approved as requested.
F. INTEREST ON REGULATORY ACCOUNT BALANCES RECOGNIZES BC HYDRO’S CARRYING
COSTS
374. Section 7.6 of the Application explains that it is generally appropriate for
regulatory account balances to attract interest at BC Hydro’s weighted average cost of debt in
604
Exhibit B-1-1, Application, p. 7-34. 605
Exhibit B-1-1, Application, 7-34, (iv). 606
Exhibit B-1-1, Application, p. 7-35, (vi). 607
Exhibit B-1-1, Application, p. 7-35, (ix). 608
Exhibit B-1-1, Application, p. 7-35, (vii), (Viii), and (x).
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recognition that BC Hydro incurs carrying costs. For example, BC Hydro provided the following
explanation for recording interest on variance account balances:
For cash variance regulatory accounts that arise from a direct cash outlay by BC Hydro, the related interest costs are generally included as part of the regulatory accounts. BC Hydro incurs financing charges to carry amounts that were paid in cash but not recovered in rates in the same test period. For some accounts, the interest cost may be immediately expensed from the regulatory account to rates, rather than being deferred and amortized for recovery in future rates.
Variance regulatory accounts such as energy deferral accounts also attract interest because BC Hydro does not forecast variances in the accounts and therefore must fund the variances. In the case of lower than forecast revenues, BC Hydro incurs debt which results in finance charges.609
375. As shown in Table 7-8 of the Application, most of BC Hydro’s regulatory accounts
already attract interest calculated based on BC Hydro’s weighted average cost of debt.610 These
regulatory accounts should continue to attract interest in accordance with past Commission
approvals. (There are a some cases noted by BC Hydro where regulatory accounts do not, and
should not, attract interest. For instance, the balances in the Total Finance Charges Regulatory
Account should not attract interest because interest costs are already part of total finance
charges.)
376. BC Hydro’s interest rate proposals relate to regulatory accounts where the
Commission has not already approved the application of interest on an ongoing basis or, in one
case – the Future Removal and Site Restoration (proposed to be renamed the Dismantling Cost
Regulatory Account) – where the Commission has not previously approved the account to
attract interest. These proposals are summarized below:
The Commission previously approved the application of interest for the Asbestos
Remediation Regulatory Account, Rock Bay Remediation Regulatory Account,
609
Exhibit B-1-1, Application, p. 7-47. 610
Exhibit B-1-1, Application, p. 7-48 and 7-49.
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and First Nations Costs Regulatory Account.611 BC Hydro is proposing to
continue the same treatment on an ongoing basis. Section 7(h(i) of Direction No.
7 requires the recording of interest on the First Nations Cost Regulatory Account.
BC Hydro also clarifies that it is proposing that the Storm Restoration Costs,
Amortization of Capital Additions and SMI Regulatory Accounts should continue
to attract interest. As noted in Table 7-8 of the Application, these three
regulatory accounts attract interest; however, the proposal for these account to
continue to attract interest was not explicitly referred to in section 7.5 or Table
7-9. The attraction (and recovery) of the interest on these accounts, however, is
reflected in BC Hydro’s revenue requirements as shown in Appendix A of the
Application and detailed in BC Hydro’s responses to information requests.612 The
application (and recovery) of interest in these accounts continues to be
appropriate for these accounts.
BC Hydro is proposing that the Future Removal and Site Restoration (proposed
to be renamed the Dismantling Cost Regulatory Account) now attract interest
because it has transitioned from a benefits matching account to a cash variance
account. In prior years, the balance in the account was a provision that was
drawn down as actual dismantling expenditures occurred. As discussed above,
now that this provision has been exhausted, BC Hydro is proposing that the
account be renamed to the Dismantling Cost Regulatory Account, and that
variances between forecast and actual dismantling expenditures be deferred to
this account. Consistent with this proposal, the account should now attract
611
Exhibit B-1-1, Application, Table 7-8, starting on p. 7-48. 612
Exhibit B-1-1, Appendix A, Financial Schedules; Exhibit B-9, BCUC IR 1.124.11, p. 4-5 of 7 (re SMI); Exhibit B-14, BCUC IR 2.276.1, p. 1 of 11 (re Storm Restoration Costs); and Exhibit B-14, BCUC IR 2.276.1, p. 2 of 11 (re Amortization of Capital Additions).
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interest consistent with the approved treatment of other cash variance
accounts.613
377. The application of interest to regulatory accounts recognizes that BC Hydro
incurs carrying costs and should be approved.
G. CONCLUSION AND REQUESTED FINDING
378. The Commission has already approved BC Hydro’s regulatory accounts in prior
proceedings, and the majority of those approvals contemplated the ongoing use of the
accounts. BC Hydro’s requests in this Application align well with the objectives underlying prior
approvals, and are beneficial for ratepayers. The Commission should find that BC Hydro’s
proposals are just and reasonable.
613
Exhibit B-9, BCUC IR 139.3 and Exhibit B-14, BCUC IR 2.298.4.
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PART TEN: OTHER REVENUE REQUIREMENTS ITEMS
A. INTRODUCTION
379. Chapter 8 of the Application addresses Other Revenue Requirements Items.
Chapter 8 gave rise to relatively few information requests, with the exception of Mr. Landale’s
interest in the Burrard Facility depreciation rates. BC Hydro underscores two points in this Part
of the Final Submission:
First, BC Hydro’s forecast revenue requirements are based on appropriate
depreciation rates, including with respect to the Burrard Facility.
Second, BC Hydro’s forecast revenue requirements reflect legislative direction
regarding capital structure, return on equity, and interest costs.
B. REVENUE REQUIREMENTS REFLECTS APPROPRIATE DEPRECIATION RATES
380. BC Hydro’s forecast revenue requirements are based on appropriate
depreciation rates, including with respect to the Burrard Facility.
(a) Commission Has Already Approved Almost All Depreciation Rates
381. BC Hydro’s revenue requirements are based on depreciation rates previously
approved by the Commission, other than for certain property, plant and equipment at the
Burrard Facility.614 No party challenged by way of information requests or intervener evidence
how BC Hydro has applied the Commission-approved depreciation rates.
(b) Proposed Depreciation Rates for the Burrard Facility Are Appropriate
382. BC Hydro’s proposed depreciation rates for the Burrard Facility are set out in
Table 8-1 of the Application. BC Hydro submits that, for the reasons detailed in BC Hydro’s
evidence and summarized below, the proposed depreciation rates for the Burrard Facility
614
Exhibit B-1-1, Application, pp.8-1 and 8-2.
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should be approved. Mr. Landale is the only party who has challenged the Burrard Facility
depreciation rates thus far, and his arguments on this point are without merit.
Burrard Facility Depreciation Rates Reflect Accounting Standards
383. The assets not required for synchronous condense operation have been fully
depreciated. All remaining assets currently at the facility are required to perform and support
the synchronous condenser functions. BC Hydro provided a list of the assets that, while not
physically involved with the synchronous condenser function, are needed to support that
function.615
384. BC Hydro followed the applicable accounting standards and used a standard
approach for developing depreciation rates for the Burrard Facility. BC Hydro classified assets
into homogeneous groups of assets by the type/nature of the asset (e.g., Transformer) and
useful life. The proposed depreciation rates reflect the remaining assets after the change in use
of the Burrard Facility.616 BC Hydro’s approach was consistent with the methodology used to
develop the Burrard Facility depreciation rates specified in Direction No. 7 for fiscal 2015 and
fiscal 2016.617
BC Hydro’s Answer to Mr. Landale’s Arguments Regarding Burrard Facility
385. Mr. Landale’s primary issue appears to be that he was unable to verify the
accuracy of the depreciation rates for the Burrard Facility because he was “denied access” to BC
Hydro’s Process Flow Diagrams, Pneumatic and Instrumentation Diagrams and single line
diagrams.618 Mr. Landale’s skepticism about BC Hydro’s depreciation approach should be given
615
Exhibit B-21, BCUC IR 3.343.2. Mr. Landale referenced a Loader/Backhoe as an anomoly, but it is used for maintaining the yard and access roads.
616 Rebuttal Evidence, p. 32; Exhibit B-21, BCUC IR 3.343.1.
617 Rebuttal Evidence, p. 32.
618 Landale Evidence, paras. 7.6, 7.7, 7.11 and 8.6.
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no weight. Mr. Landale is neither an accountant, nor a depreciation expert.619 BC Hydro
explained in its Rebuttal Evidence (and had similarly explained to Mr. Landale in a meeting with
him) that the documents Mr. Landale had requested are not informative for the depreciation
analysis:
No, they are not informative for the depreciation analysis. The diagrams requested by Mr. Landale are prepared for the purpose of detailing operational processes, piping and instrumentation connections, and showing simplified electrical connections. They would not assist Mr. Landale or the Commission in understanding the asset classification for depreciation purposes. There is no direct correlation between the diagrams and the classification of assets in the financial system. Asset classes used for financial purposes are comprised of multiple individual assets, summed to provide an asset class depreciation rate.620
386. Mr. Landale, despite his desire to, in effect, audit the depreciation rates and
asset classes using facility diagrams, admitted that “on the whole BC Hydro follows these
overarching principles and definitions prescribed in the USoA [the Commission’s Uniform
System of Accounts]”621, and that the depreciation rates “appear consistent with accepted
accounting practices”.622 BC Hydro submits that it has provided ample support for the
proposed Burrard Facility depreciation rates.
387. Mr. Landale also advances a legal argument. He appears to interpret Direction
No. 7 as only permitting recovery of Burrard Facility costs if they are physically located “at” the
Burrard Facility. There are two answers to Mr. Landale’s argument.
First, the clear purpose of Direction No. 7 is to direct the Commission to allow BC
Hydro to recover the costs of Burrard Facility assets over a reasonable period of
time fixed by the Commission. Mr. Landale’s approach of parsing the wording of
619
Mr. Landale stated in his response to BCSEA-Landale IR 8.1, for instance: “Regrettably, I do not have the faintest idea what is appropriate. I have presented evidence that challenges the validity of the assets in Table 8-1. Their depreciation disposition is for others to determine. Others meaning BC Hydro’s professional engineers signature, the accountants valuation, and the Commissions “due diligence”.”
620 Exhibit B-20, Rebuttal Evidence, p.33-34.
621 Landale Evidence, para.7.3.
622 Landale Evidence, para. 8.6.
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Direction No. 7 in isolation from the broader legislative purpose runs counter to
accepted principles of statutory interpretation.
Second, BC Hydro’s right to recover the undepreciated value of the Burrard
Assets does not hinge on the wording of Direction No. 7. A fundamental
component of the judicially-recognized (and Commission-recognized) regulatory
compact is that utilities are entitled to an opportunity to earn a return on, and
the return of, invested capital.623 The Commission must fix appropriate
depreciation rates to allow BC Hydro to recover capital invested in the Burrard
Facility. The standard method for fixing depreciation rates is to reflect the
expected life of the assets.
388. BC Hydro will address any further arguments from Mr. Landale in its Reply
Submission. BC Hydro underscores, however, that the selection of the Burrard Facility
depreciation rates does not have a material impact on its revenue requirements during the test
period.624
C. PRESCRIBED CAPITAL STRUCTURE, RETURN ON EQUITY AND INTEREST COST
RECOVERY
389. BC Hydro’s forecast revenue requirements reflect legislative direction regarding
capital structure, return on equity, and interest costs.
(a) Dividend Subject to a Specified Minimum Debt/Equity Ratio
390. Heritage Special Directive No. HC1 specifies dividend payments to Government
relevant to the test period:
623
The Commission has addressed the regulatory compact in its various cost of capital decisions, citing the leading case of Atco v. Alberta Utilities Commission.
624 Exhibit B-21, BCUC IR 3.343.1.
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The dividend payable for fiscal 2017 must equal 85 per cent of BC Hydro’s net
income, provided that such a payment will not cause BC Hydro’s debt/equity
ratio to exceed 80:20.625
For fiscal 2018 and subsequent years, the dividends payable by BC Hydro will be
reduced by $100 million per year from the dividend payable in the immediately
preceding fiscal year until it reaches zero. The dividend payable will thereafter
remain at zero until BC Hydro achieves a debt/equity ratio of 60:40.
391. BC Hydro’s forecast for the dividend payable for fiscal 2017 was $271 million, as
set out in the financial schedules included in Appendix A of the Application. BC Hydro’s forecast
for fiscal 2018 and fiscal 2019 reflects the legislated mechanism for reducing the dividend.
(b) Return on Equity Must Yield Specified Distributable Surplus
392. BC Hydro’s allowed net income, referred to as “distributable surplus”, is
determined by Order in Council No. 590.626 OIC No. 590 repealed section 4(d) of Direction No.
7 and set specific amounts for the distributable surplus to be earned in each year of the test
period and beyond. The Commission must allow BC Hydro to collect sufficient revenue in a
fiscal year to achieve an annual rate of return on deemed equity that would be necessary to
yield a distributable surplus of: (i) $684 million in fiscal 2017; (ii) $698 million in fiscal 2018; and,
(iii) $712 million in fiscal 2019 and subsequent fiscal years.
393. The evidence regarding the annual rate of return on deemed equity required to
achieve the distributable surpluses prescribed in Order in Council No. 590, which is subject to
625
OIC No. 589, issued on July 28, 2016 (see Exhibit B-2, Attachment No. 1), amended section 3 of Heritage Special Directive No. HC1 by adding the requirement that the dividend payable for fiscal 2017 (payable by June 30, 2017) must be “an amount not less than $259 million”. The amendment did not affect BC Hydro’s forecast revenue requirements over the test period, as the forecast exceeded the minimum amount.
626 OIC No. 590 was issued on July 28, 2016. A copy is included as Attachment No. 2 to Exhibit B-2.
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change based on the updates completed as part of BC Hydro’s compliance filing) is shown in the
table below.627
$ million Reference F2017 Plan
F2018 Plan
F2019 Plan
Mid-Year Deemed Equity A Appendix A, Sch. 9.0, line 44
5,783.0 6,023.3 6,343.4
Return on Equity B OIC 590 684.0 698.0 712.0
Annual Rate of Return on Deemed Equity (%)
C=B/A Calculated 11.83% 11.59% 11.22%
The Return on Equity calculated pursuant to OIC No. 590 is slightly lower than the amounts in
Appendix A, Schedule 9, line 47 only because as the amounts set by OIC 590 do not include
decimal places, whereas BC Hydro’s forecast of the distributable surplus was made to the first
decimal place. BC Hydro will update its financial schedules for these minor reductions in its
compliance filing following the Commission’s Decision in this proceeding.628
(c) BC Hydro’s Interest Costs Are Recoverable
394. Finance charges, discussed in section 8.4 of the Application, represent the cost of
BC Hydro’s debt portfolio. They are largely comprised of interest charges on BC Hydro’s
debt.629 BC Hydro’s forecast Weighted Average Cost of Debt for each of the test years was
derived in Schedule 8.0 of the Application, Lines 48 to 59.630
395. As described in section 5.1.3 of the Application, BC Hydro has implemented a
Debt Management Strategy, which includes the use of interest rate hedges on future debt
issuances, to lock in historically low interest rates.631 The initiative will produce significant
savings for customers.
627
Exhibit B-9, BCUC IR 1.153. 1. 628
Exhibit B-2. BCUC IR 1.153.1. 629
Exhibit B-1-1, Application, p.8-7. 630
Exhibit B-9, BCUC IR 1.154.5. 631
Exhibit B-14, BCUC IR 2.193.1.
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396. BC Hydro’s ability to recover its cost of debt is not at issue in this Application for
two reasons. First, the Commission’s authority to approve public utility debt issuances does not
apply to BC Hydro by virtue of the British Columbia Hydro and Power Authority Act.632 The
Commission recently stated in this regard:
In the Panel’s view, given BC Hydro’s exemption from section 50(1) of the UCA, it is not appropriate for the Commission to provide guidance or direction with regard to the issuance of securities. The inappropriateness arises because if the Commission has no jurisdiction to approve or deny an issuance of a security, it cannot guide or direct that BC Hydro issue or not issue a security.633
397. Second, section 4(b) of Direction No. 7 provides that the Commission must allow
BC Hydro recover sufficient revenue to meet all of its debt service, tax and other financial
obligations.
398. In prior years, the Commission has directed BC Hydro to record in a regulatory
account any differences between forecast and actual finance charges. BC Hydro’s request to
extend this treatment addresses interest rate uncertainty and ensures that customers only pay
BC Hydro’s actual financing charges.634
D. CONCLUSION AND REQUESTED FINDINGS
399. The Commission should find that BC Hydro’s depreciation rates, including those
for the Burrard Facility, are appropriate. Also, the forecast revenue requirements reflect the
legislative direction regarding capital structure, return on equity, and interest costs.
632
The British Columbia Hydro and Power Authority Act, section 32(7)(x) states that the Utilities Commission Act, except for certain sections applies to BC Hydro. Section 50 (1) of the Utilities Commission Act does not apply to BC Hydro.
633 Order No. G-42-16.
634 Exhibit B-1-1, Application, p.7-22.
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PART ELEVEN: TRANSMISSION REVENUE REQUIREMENTS
400. This Part addresses the Transmission Revenue Requirements, which are the
subject of Chapter 9 of the Application. The Transmission Revenue Requirement includes the
costs associated with BC Hydro’s Open Access Transmission Tariff (“OATT”) related assets, i.e.,
the transmission lines and high-voltage station equipment that are used to provide
transmission service under the OATT. The following facts demonstrate the reasonableness of
the Transmission Revenue Requirement and rates:
First, the cost of service methodology used to derive the Transmission Revenue
Requirement is based on cost causation and is consistent with past practice.635
Second, the calculation of the OATT rates is consistent with the design of the
OATT rates previously approved by the Commission for BC Hydro and British
Columbia Transmission Corporation.636
Third, the difference between the proposed fiscal 2017 and fiscal 2018 rates and
the interim fiscal 2017 and fiscal 2018 OATT rates approved by the Commission
in Order No. G-40-16 and Order G-46-17, respectively, is appropriately recovered
through a one-time charge to Transmission Customers.637
401. BC Hydro’s Transmission Revenue Requirement reflects the appropriate level of
revenue required to maintain a safe and reliable transmission system.
635
Exhibit B-1-1, Application, page 9-2, line 19-23. The methodology remains consistent with that previously used by BC Hydro and the British Columbia Transmission Corporation and the British Columbia Utilities Commission’s 1998 Decision accompanying Order No. G-43-98 related to BC Hydro’s Application for Approval of Wholesale Transmission Services.
636 Exhibit B-1-1, page 9-15, line 19-22.
637 Fiscal 2017 Rates approved by the BCUC are outlined on page 9-20 of Exhibit B-1-1.
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PART TWELVE: DEMAND-SIDE MANAGEMENT
A. INTRODUCTION
402. This Part addresses BC Hydro’s demand-side management expenditures. BC
Hydro is seeking acceptance pursuant to section 44.2 of the Utilities Commission Act of the
demand-side management expenditure schedule set out in Table 10-1 of the Application, as
described in more detail in Table 10-7 and Chapter 10 of the Application, and as amended in BC
Hydro’s response to BCUC IR 2.314.3. The legal framework applicable to demand-side
management expenditures is included in Part Three of this Final Submission.
403. The proposed demand-side management expenditure schedule includes a total
of $361.1 million in spending over the test period.638 The expenditure schedule includes
funding for Codes and Standards, Rate Structures, Programs, capacity focused pilots, and
supporting initiatives. It reflects a modernized and more cost-effective Demand-Side
Management Plan that continues broad demand-side management and is responsive to
changing system needs and the 2013 10 Year Rates Plan. BC Hydro retains the ability to ramp
up in the future, as needed. The expenditure schedule is in the public interest and should be
accepted as filed.
404. The following points, each of which is demonstrated in this Part, support a
finding that BC Hydro’s expenditure schedule is in the public interest:
First, BC Hydro is making significant investments in a broad range of demand-
side management initiatives that provide significant energy and capacity savings
and other benefits, and promote British Columbia’s Energy Objectives.
638
As a result of a shift in timing in BC Hydro’s forecast expenditures for the Thermo-Mechanical Pulp program, BC Hydro’s proposed section 44.2 demand-side management expenditure schedule for the test period has been reduced by $13.9 million, from a total of $375 million to a total of $361.1 million. See BC Hydro’s response to BCUC IR 2.314.3. BC Hydro’s compliance filing will reflect the reduced expenditures attributable to the Thermo-Mechanical Pulp program.
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Second, BC Hydro manages the performance of the Demand-Side Management
Plan in a comprehensive manner that includes tracking performance metrics,
identification of risk and mitigation, and regular management oversight and
reporting.
Third, it is appropriate to extend the moderation strategy recommended in the
2013 Integrated Resource Plan for three more years, in light of the reduced rate
of growth of demand for electricity in the short-term, the requirements of the
2013 10 Year Rate Plan and other factors.
Fourth, the changes to the Demand-Side Management Plan reflect (i) an
expanded energy management scope and changing customer needs and
expectations, productivity improvements and service enhancements, and (ii) the
cancellation or reduction of some programs that are not as cost effective, have
served their purpose, did not result in missed opportunities and/or had
transitioned to more cost effective opportunities to achieve savings.
Fifth, Codes and Standards is a cost effective demand-side management tool.
Sixth, Capacity Focused Demand-Side Management is a critical investment and
part of a cost-effective portfolio;
Seventh, BC Hydro is addressing barriers in non-integrated areas and First
Nations communities.
Eighth, the Demand-Side Management Plan is cost effective under the Demand-
Side Measures Regulation.
Ninth, BC Hydro’s Evaluation, Measurement and Verification Processes are
guided by industry best practices and are neutral and unbiased.
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B. BC HYDRO’S SIGNIFICANT AND BROAD INVESTMENT IN DEMAND-SIDE MANAGEMENT
405. BC Hydro is proposing significant investment in a broad range of demand-side
management initiatives. BC Hydro’s portfolio includes measures for low income households,
rental accommodations and school and post-secondary education, which are areas identified in
adequacy section in the Demand-Side Measures Regulation. It also provides significant energy
and other benefits, and advances British Columbia’s energy objectives. BC Hydro will manage
this broad portfolio in a flexible manner, based on changing circumstances.
(a) BC Hydro’s Broad Investment in Demand-Side Management
406. BC Hydro’s proposed Demand-Side Management Plan includes an average of
$125 million in expenditures in each year of the test period. Table 10-7 of the Application,
reproduced below for reference, summarizes the extent of BC Hydro’s proposed investment in
various components of the portfolio. It highlights the breadth of BC Hydro’s Demand-Side
Management Plan.
Fiscal 2017 to Fiscal 2019 Demand-Side Management Expenditure Summary ($ million)
F2017 Plan
F2018 Plan
F2019 Plan
F2017-F2019 Total
Codes and Standards 4.7 4.8 4.9 14.5
Rate Structures 1.2 1.0 1.2 3.5
Programs
Residential 13.1 11.8 13.0 37.9
Commercial 43.9 29.9 25.7 99.4
Industrial 26.7 28.8 27.4 82.9
Thermo-Mechanical Pulp 0.0 55.8639
0.0 55.8
Total Programs 83.7 126.3 66.0 276.0
Capacity Focused Demand-Side Management
10.0 14.2 14.4 38.6
Supporting Initiatives 14.0 14.2 14.2 42.4
Total 113.7 160.6 100.7 375.0
639
The timing of spending on the Thermo-Mechanical Pulp project was updated in BC Hydro’s response to Exhibit B-14, BCUC IR 2.314.3. BC Hydro will reflect these changes in its compliance filing following the Commission’s decision in this proceeding.
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407. The main components of the Demand-Side Management Plan, as outlined in
Table 10-7 above, are summarized below:
Codes and Standards focus on transforming the marketplace for energy efficient
practices and products by supporting government implementation of changes to
energy efficiency requirements in building codes and product and equipment
standards.640
Rate Structures are the design of electricity rates to provide more economically
efficient price signals to customers that encourage conservation.641
Programs deliver information, access to efficient technology and services,
technical assessment and support, and financial assistance to all customer
classes. They address barriers to cost effective energy efficiency and
conservation.642 BC Hydro is providing customers with access to one or more
demand-side management program offers.643
Capacity Focused Demand-Side Management consists of load curtailment and
demand response pilot initiatives. The pilots are aimed at determining the
dependability of targeted capacity savings, to defer the need for pump storage
generation capacity and upgrades to local facilities.644
Supporting Initiatives provide a foundation of awareness, engagement and
other conditions to support the success of the Demand-Side Management Plan’s
tools and initiatives.645
640
Exhibit B-1-1, Appendix V, p. 1. 641
Exhibit B-1-1, Application, pages 10-40 to 10-43. 642
Exhibit B-1-1, Application, pages 10-40 to 10-43. 643
Exhibit B-9, BCUC IR 1.176.5. 644
Exhibit B-1-1, Application, pages 10-40 to 10-43. 645
Exhibit B-1-1, Application, pages 10-40 to 10-43.
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408. A more detailed description of the initiatives included in the Demand-Side
Management Plan is provided in Appendix V of the Application.
409. BC Hydro discussed below how it has designed the Demand-Side Management
Plan to provide broad access, BC Hydro’s efforts to address market barriers, the breadth of
opportunities available to customers, and the significant savings that will be realized by
customers.
Broad Access By Design
410. BC Hydro developed and designed its Demand-Side Management Plan to
maintain broad access, as reflected in Table 10-5 of the Application. BC Hydro begins by
considering the market opportunities and needs across its entire customer base. BC Hydro then
identifies any barriers that may be preventing customers from undertaking actions on their own
(e.g., affordability, accessibility, availability, awareness or acceptability of the energy efficient
option).646 BC Hydro then develops programs from the bottom up so that they are broadly
applicable to customer segments that experience similar barriers. Budgets for each program
are derived based on what is required to reduce the key customer barriers for the segment that
is being targeted. Programs are typically available to customers in all regions.647 Further, BC
Hydro uses average electricity savings and cost per participant to perform financial modeling
and to determine if a program design is cost effective. While some customers will save more
electricity than others, and some customers and regions are more expensive to serve than
others, using average savings and costs allows BC Hydro to continue to serve a broad range of
customers and regions.648
646
Exhibit B-10, NIARG IR 1.3.1. 647
Exhibit B-10, NIARG IR 1.3.1. 648
Exhibit B-10, NIARG IR 1.3.1. Note, however, that BC Hydro determines the incentive levels for larger projects on a case-by-case basis. This process is described in detail in BC Hydro’s response to Exhibit B-9, BCUC IR 1.187.2 regarding the Industrial Leaders in Energy Management Program.
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All Customers Have Access to Programs
411. The Demand-Side Management Plan provides a reasonable opportunity for all
customers to participate in one or more demand-side management program offers. Table 10-
10 of the Application, reproduced below, summarizes the availability of the demand-side
management tools and initiatives to different customer classes.
Table 10-10 Demand-Side Management Tools and Initiatives
Tools Initiatives
Codes and Standards
Product and Equipment Standards
Lighting
Residential appliances
Residential electronics
Commercial/Industrial Equipment
Building Codes
B.C. Building Code (Residential and Commercial)
City of Vancouver Building By-law (Residential and Commercial)
Codes and Standards Strategy
Technology Innovation
Sustainable Communities
Codes and Standards Investigation
First Nations Strategies
Residential New Construction
Rate Structures Residential Inclining Block Transmission Service
Programs Residential
Behaviour
Low Income
Retail
Home Energy Rebate Offer
Sector Enabling Activities
Commercial
Leaders in Energy Management, Commercial
New Construction
Sector Enabling Activities
Industrial
Leaders in Energy Management, Transmission
Thermo-Mechanical Pulp
Leaders in Energy Management, Distribution
Sector Enabling Activities
412. As explained in response to BCUC IR 1.176.5, the Demand-Side Management
Plan consists of broad programs and more targeted offers:
By providing a wide variety of offers to each sector, individual customers still have access to one or more demand-side management programs. For example, the offers within the commercial, distribution, and transmission Leaders in Energy Management programs provide broad opportunities for both custom energy saving projects, as well as for specific product technologies. In the
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residential sector, all customers have the opportunity to participate in the Behaviour Program, and customers can purchase retail products that are included within the Retail Program offer.
Our more targeted program offers, such as the Low Income Program, Thermo-Mechanical Pulp Program, the Home Energy Rebate Offer and the commercial New Construction Program provide additional opportunities for customers depending on their specific circumstances.649
Significant Bill Savings
413. The broad accessibility of BC Hydro’s demand-side management activities is
reflected in the substantial forecast bill savings for customers. Customers are forecast to save
$203.9 million in cumulative bill savings by participating in programs over the test period and to
save over $950 million over the fiscal 2017 to fiscal 2024 period. With the inclusion of savings
from Rate Structures and Codes and Standards, customers are forecast to save $568.7 million
on their electricity bills over the test period, and over $2.8 billion from fiscal 2017 to fiscal
2024.650
414. The savings are attributable to all customer classes. The table below shows that
the portfolio savings opportunity for each customer class is within plus or minus ten percent of
the proportion of electricity load expected for each group:651
Residential (%)
Light Industrial and Commercial (%)
Large Industrial (%)
Demand-Side Management Plan Savings652 43 28 30
BC Electricity load before DSM653 36 37 27
649
Exhibit B-9, BCUC IR 1.176.5. 650
Exhibit B-1-1, Appendix W, Table 8. 651
Exhibit B-14, BCUC IR 2.316.1.1. 652
Based on cumulative energy savings in fiscal 2019 as per Exhibit B-1-2, Appendix W, Table 1 on page 1 of 10. Light and Large Industrial groups account for 25 per cent and 75 per cent of the Industrial Sector’s energy savings.
653 Based on the electricity load in fiscal 2019 as per the Load Forecast for this Revenue Requirement Application.
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415. BC Hydro’s average energy savings as a per cent of retail sales from programs is
0.6 for fiscal 2017-2019, which is within the industry average energy of 0.7 percent and median
at 0.6 per cent. On a portfolio basis, BC Hydro’s average energy savings as a percentage of
retail sales are much higher than the industry average at 1.4 per cent.654
Efforts to Address Market Barriers and Access Hard to Reach Customers
416. BC Hydro’s demand-side management activities are also designed to address
market barriers and provide access to hard to reach customers.655 BC Hydro’s efforts to provide
access to hard to reach customers include, but are not limited to:656
Working directly with First Nations communities to facilitate ongoing demand-
side management activities and funding for a First Nations support position;657
Coordinating with agencies and non-profit organizations to reach the low income
community;
Funding an energy manager position at the BC Non-Profit Housing Association to
help reach renters; and
Increased training to the BC Hydro Alliance of Energy Professional members to
expand their support for small and medium size businesses.
417. BC Hydro takes steps to overcome barriers where participation has been low in a
particular program. For example, BC Hydro changed the Strategic Energy Management
Initiative eligibility requirements to increase participation in the Leaders in Energy
Management-Distribution Program targeting the industrial distribution class of customers. The
changes to the Strategic Energy Management Offers positions BC Hydro, through the Leaders in
654
Exhibit B-9, BCUC IR 1.176.2. 655
Exhibit B-1-1, Application, pp. 10-39 to 10-40 and Appendix V. 656
Exhibit B-9, BCUC IR 1.176.5.1. 657
For further details of examples of BC Hydro’s efforts in this regard see, e.g., Exhibit B-15, ZoneII IR 2.38.8.
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Energy Management programs, to partner with a range of industrial customers to help them
manage their energy and improve the efficiency of their facilities.658
(b) Portfolio Includes Measures for Low Income Households, Rental Accommodation and Schools
418. The Demand-Side Management Plan includes measures for low income
households, rental accommodations and school and post-secondary education. Although the
Demand-Side Measures Regulation requirements for such initiatives do not apply to BC
Hydro,659 the Demand-Side Management Plan would nonetheless meet the adequacy
requirements of the Regulation. This fact supports the reasonableness of BC Hydro’s
investment levels in the initiatives. The following describes the initiatives that are offered in
these areas.660
Low Income Households
419. The Low Income Program assists residents of low-income households, low-
income housing providers, and First Nations communities in reducing energy consumption.661
The Low Income Program is designed to overcome market barriers to adoption of more energy
efficient products, particularly affordability.
420. The Low Income Program has two components: Energy Savings Kits and the
Energy Conservation Assistance Program. The Energy Savings Kit is a package of basic energy
saving measures provided at no charge that can be installed by most homeowners or tenants
with limited or basic tools. The Energy Conservation Assistance Program provides low income
658
Exhibit B-14, BCUC IR 2.326.1. 659
Section 3 of the Demand-Side Measures Regulation applies to a demand-side management plan portfolio filed as part of a long term resource plan under section 44.1 of the Utilities Commission Act. Pursuant to section 32 of the Hydro and Power Authority Act, BC Hydro is exempt from section 44.1 of the Utilities Commission Act.
660 Exhibit B-10, BCSEA IR 1.36.2. Also see Exhibit B-9, BCUC IR 1.176.3.
661 Exhibit B-10, BCSEA IR 1.36.2. Exhibit B-1-1, Appendix V, page 11.
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residential customers with a free home evaluation, free installation of energy saving products
and education on how they can save energy.662
421. The design of the Low Income Program has incorporated feedback from the BC
Public Interest Advocacy Centre, Cooperative Housing Federation of BC, BC Non Profit Housing
Association, and Prince George Metis Housing Society. In response to feedback, BC Hydro
implemented a single income threshold used across the province, accepts alternative
documents for proof of income, and has removed the minimum consumption requirement for
participation in the Energy Conservation Assistance Program basic offer.663
422. In light of the expansion of the low-income household definition in the Demand-
Side Measures Regulation, BC Hydro:
adjusted income qualifications to match the higher income thresholds;
expanded communications into new marketing channels to target customers
who were not previously eligible for the program; and
adjusted policies to make it easier for all suites operated by non-profits and co-
operatives to participate.664
423. BC Hydro and its program partner, FortisBC, plan to undertake a number of
marketing and awareness initiatives to increase participation in the Low Income Program,
including:665
Partner with the Ministry of Social Development and Social Innovation to
promote the offers to clients;
Mail flyers to targeted customers;
662
Exhibit B-1-1, Appendix V, page 11. 663
Exhibit B-9, BCUC IR 1.176.4. 664
Exhibit B-9, BCUC IR 1.176.4.3. 665
Exhibit B-10, BCSEA IR 1.20.2.
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Online advertising;
Promote through the BC Hydro call centre;
Partner with other community service providers to raise awareness with clients
and host sign up events;
Promotion through Member of the Legislative Assembly offices;
Continue to fund outreach positions with the Energy Conservation Assistance
Program contractor to build awareness of the program offers and assist with the
application process, focusing on the non-profit housing providers, Aboriginal
housing providers and First Nations communities;
Fund energy manager and energy specialist positions at the BC Non Profit
Housing Association who assist non-profit housing providers to participate in the
offers; and
Fund community energy specialists (or champions) to promote the offers to First
Nations communities including the Great Bear Initiative focused on Coastal First
Nations, First Nation Energy and Mining Council and in some remote First
Nations communities.
424. BC Hydro expects annual participation in its Low Income programs to be
approximately 10,000 based on past performance. Program participation and targets reflect
expected levels of participation, and participation has not been limited.666
Rental Accommodations
425. BC Hydro offers programs available to rental accommodations. Renters with BC
Hydro accounts participate in the Behaviour program to develop energy efficient behaviours.
Fifty-five per cent of Energy Savings Kit participants are renters and 26 per cent of Energy 666
Exhibit B-10, BCSEA IR 1.20.2.
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Conservation Assistance Program participants are renters. Renters also participate in or benefit
from the Retail program, which assists customers with purchasing energy efficiency products
(e.g., appliances, consumer electronics and lighting technologies). In addition, BC Hydro funds
an energy manager position at the BC Non-Profit Housing Association. Since the facilities
owned by BC Non-Profit Housing Association members are all rental accommodation, the
addition of the Energy Manager support will enhance BC Hydro’s reach within the rental
market.667 The Energy Manager helps non-profit housing providers use incentives available
from all utilities to improve the energy efficiency of their rental properties.668
School and Post-Secondary Education
426. BC Hydro’s Public Awareness Supporting Initiative provides school education
programs across the province.669 BC Hydro will reach over 550,000 students over three years
with the Public Awareness Supporting Initiative. BC Hydro also partners with post-secondary
institutions and industry associations who develop and deliver new training and education
programs, through the Commercial Sector Enabling Initiative.670
(c) Portfolio Provides Significant Energy And Capacity Savings And Other Benefits
427. The Demand-Side Management Plan will result in significant energy and capacity
savings and other benefits.
428. A key benefit of demand-side management is energy and capacity savings.671 A
breakdown of forecasted energy and capacity savings from the Demand-Side Management Plan
is provided in Table 10-8 of the Application, which is reproduced below.
667
Exhibit B-9, BCUC IR 1.176.3. 668
Exhibit B-10, BCSEA IR 1.36.2. 669
Exhibit B-1-1, Application, Appendix V, p. 37. 670
Exhibit B-10, BCSEA IR 1.36.2. Exhibit B-1-1, Appendix V, p.24. 671
Exhibit B-1-1, Application, p. 10-34.
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Table 10-8 Cumulative Energy and Capacity Savings since Fiscal 2016
F2017 Plan
F2018 Plan
F2019 Plan
Codes and Standards 838 1,096 1,410
Rate Structures 166 192 200
Programs
Residential 83 108 137
Commercial 214 265 310
Industrial 301 373 455
Thermo-Mechanical Pulp 66 293 293
Total Programs 664 1,040 1,194
Total Energy (GWh) 1,668 2,327 2,804
Codes and Standards 182 234 283
Rate Structures 17 27 29
Programs
Residential 19 28 35
Commercial 21 34 41
Industrial 29 41 51
Thermo-Mechanical Pulp 8 10 35
Total Programs 77 113 161
Total Capacity (MW) 276 373 473
429. Other benefits associated with BC Hydro’s demand-side management
expenditures include:
Reduction to the revenue requirements: The programs in the Demand-Side
Management Plan are forecast to have a net levelized Utility Cost of $22
per MWh (fiscal 2016 value) and a net levelized Total Resource Cost of $41
per MWh (fiscal 2016 value). The Utility Cost and Total Resource Cost Tests
compare favourably to the long-run marginal cost of electricity (at $100
per MWh) and BC Hydro’s reference price as described in Chapter 3. The Utility
Cost of the demand-side management programs compared favourably to the
B.C. border sell price forecast, which is approximately $36 per MWh. Based on
these price forecasts, the Demand-Side Management Expenditures for programs
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(at a net levelized Utility Cost of $22 per MWh) will reduce BC Hydro’s revenue
requirements.672
Economic development benefits: The implementation of the Demand-Side
Management Plan will generate significant economic activity and jobs within the
province. These jobs include direct employment through the purchase of labour
and materials, spin-off jobs from business activity in the supply chain and the
spending of wages, and jobs created by the spending of demand-side
management related energy bill savings. Demand-side management actions
undertaken by customers also make them more competitive through the better
use of electricity, creating expanded economic development.673 These benefits
are not included in the Total Resource Cost benefit-cost analysis.674
Environmental Benefits: Demand-side management avoids the environmental
impacts associated with the construction of new electricity infrastructure
facilities. Additionally, the Demand-Side Management Plan is forecast to reduce
the province’s greenhouse gas emissions through customers reducing their
natural gas usage in concert with electricity usage. BC Hydro estimates that the
Demand-Side Management Plan will reduce B.C. greenhouse gas emissions by
approximately 1.3 million tonnes over the fiscal 2016 to 2024 timeframe over
the lifetime of the measures.675 BC Hydro’s response to BCSEA IR 2.56.1 provides
examples of how particular demand-side management initiatives reduce
greenhouse gas emissions. These are not included in the Total Resource Cost
benefit cost analysis.676
672
Exhibit B-1-1, Application, p. 10-34. 673
Exhibit B-1-1, Application, p. 10-35. Exhibit B-9, BCUC IR 1.185.1. 674
Exhibit B-9, BCUC IR 1.185.2. 675
Exhibit B-1-1, Application, p. 10-35; Exhibit B-10, BCSEA IR 1.35.1 to 1.35.3; Exhibit B-15, BCSEA IR 2.56.2. The emission savings come from initiatives where BC Hydro is not in partnership with FortisBC Energy Inc. and/or where FortisBC Energy Inc. is not already claiming these emissions.
676 Exhibit B-9, BCUC IR 1.185.2.
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Additional customer benefits: The projects undertaken by business customers to
reduce electricity consumption make them more competitive in their industries.
Demand-side management initiatives can help customers to reduce waste
generation or product losses, reduce maintenance costs in commercial and
industrial facilities, and extend equipment life. Quantifiable customer
non-energy benefits are included in the Total Resource Cost cost-benefit analysis
for demand-side management initiatives. Qualitative benefits, such as improved
comfort in homes, an enhanced environmental responsibility, or improved
customer control of energy management, are not included in the benefit-cost
analysis.677
(d) The Portfolio Promotes British Columbia’s Energy Objectives
430. The Commission must consider the British Columbia’s Energy Objectives
identified in the Clean Energy Act when considering whether to accept an expenditure schedule
pursuant to section 44.2 of the Utilities Commission Act. BC Hydro’s Demand-Side
Management Plan advances several of British Columbia’s Energy Objectives:678
To achieve electricity self-sufficiency: The Demand-Side Management Plan’s
forecast energy and capacity savings will contribute to BC Hydro maintaining
electricity self-sufficiency in 2016 and each year thereafter;
To take demand-side measures and to conserve energy, including the objective
of BC Hydro reducing its expected increase in demand for electricity by the year
2020 by at least 66 per cent: Demand-side management is forecast to reduce BC
Hydro’s increase in electricity demand in fiscal 2021 by approximately 106 per
cent (this topic is addressed further below in Part Twelve C. (d) of the Final
Submission);
677
Exhibit B-1-1, 10-36. 678
Exhibit B-1-1, pp. 10-27 to 10-28.
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To use and foster the development in British Columbia of innovative
technologies that support energy conservation and efficiency and the use of
clean or renewable resources: Demand-side management programs and the
codes and standards initiative will use and foster development of innovative
technologies supporting energy conservation;
To ensure BC Hydro’s rates remain among the most competitive rates charged
by public utilities in North America: The proposed reduction in the Demand-Side
Management Plan relative to the 2013 Integrated Resource Plan outlook reduces
rates (this topic is addressed further below in Part Twelve C. (c) of the Final
Submission);
To reduce B.C. greenhouse gas emissions: The Demand-Side Management Plan
is forecast to result in natural gas savings that will reduce B.C. greenhouse gas
emissions;
To encourage the switching from one kind of energy source or use to another
that decreases greenhouse gas emissions in B.C.: Codes and Standards support
local governments and developers in the creation of community wide energy
plans that encourage energy efficiency and decrease greenhouse gas emissions;
To encourage communities to reduce greenhouse gas emissions and use energy
efficiently: The B.C. Building Codes and City of Vancouver Bylaws initiatives
support communities to incorporate electricity efficiency into community energy
planning and implement energy efficiency policies and projects. BC Hydro will
also support First Nations communities in targeting energy efficient housing and
community buildings, and in developing and implementing energy efficient
housing policies and community energy plans; and
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To encourage economic development and the creation and retention of jobs:
BC Hydro’s current demand-side management efforts create significant
economic activity and jobs within the province.
(e) BC Hydro Manages to Program Budgets and Responds to Changing Circumstances
431. BC Hydro manages the performance of the Demand-Side Management Plan in a
comprehensive manner that includes tracking performance metrics, identification of risk and
mitigation, and regular management oversight and reporting. BC Hydro’s governance
structures are designed to ensure that the specific programs are achieving target energy
savings, manage costs and mitigate operational risks.679
432. BC Hydro develops leading and lagging key performance indicators for each
component of its portfolio and monitors performance. The primary performance metrics for
the Demand-Side Management Plan are energy savings and costs.680 If an initiative is not
performing as expected or if there is new information that could impact the initiative, BC Hydro
analyzes the issue, explores solutions and adjusts initiatives to mitigate the issue where
possible. BC Hydro also tracks how effective demand-side management initiatives are at
meeting customer expectations, and is in contact with manufacturers, retailers, and other trade
allies and partners to solicit feedback and gain insight into new opportunities.681 Performance
reporting, including expenditures versus budget, energy savings and key highlights, is reviewed
monthly by the management team.682
433. BC Hydro’s approach to demand-side management performance management is
informed by the identification and assessment of demand-side management related risks. For
each risk, BC Hydro develops mitigation measures at various stages, from the design of
679
Exhibit B-1-1, Application, section 10-7. 680
Exhibit B-1-1, Application, pp. 10-50 to 10-53. 681
Exhibit B-1-1, Application, pp. 10-50 to 10-53. 682
Exhibit B-1-1, Application, p. 10-55. Past reports are provided in Exhibit B-1-1, Application, Appendix Y and Exhibit B-2, Evidentiary Update.
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demand-side management initiatives through to their implementation and evaluation. Risks
are assessed and mitigated at the initiative level as well as at the portfolio level.683 In section
10.6 of the Application, BC Hydro describes the identified risks and mitigation for Codes and
Standards, Rate Structures, Programs and the portfolio as a whole.684
434. As part of its ongoing management of spending and savings, BC Hydro manages
demand-side management at the portfolio level, and seeks to balance the overall portfolio
performance taking into account over-performing or under-performing initiatives.685 As a
result, BC Hydro may reallocate funds from under-performing initiatives to maintain the overall
portfolio performance. BC Hydro explained:
While we do not actively seek to transfer budgets between programs, we do respond to marketplace circumstances that arise during the course of the year. This could result in the reallocation of incentive funds or a shift in program strategy to take advantage of the changing market.686
435. BC Hydro makes decisions on demand-side management expenditures over the
course of the test period based on the most recent and best information available at the time.
BC Hydro will proactively identify marketplace opportunities and may re-allocate funds or shift
a program strategy to take advantage of the changing market. To manage its portfolio
effectively, BC Hydro must have the ability to respond in a timely way to these changes.
Consequently, actual demand-side management expenditures may vary from the forecast
expenditures included in the Demand-Side Management Plan.687
436. Consistent with past practice, BC Hydro will explain any variances between its
Demand-Side Management Plan and actual expenditures in its demand-side management
683
Exhibit B-1-1, Application, pp. 10-43 to 10-44. 684
Exhibit B-1-1, Application, pp. 10-43 to 10-48. 685
Exhibit B-9, BCUC IR 1.167.6. 686
Exhibit B-9, BCUC IR 1.167.6. 687
Exhibit B-9, BCUC IR 1.167.6 and Exhibit B-14, BCUC IR 2.314.1.
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annual reports and future expenditure schedule requests filed with the Commission.688 BC
Hydro’s annual demand-side management performance reports provide information on
expenditures and energy savings for the fiscal year, variances from plan, overall Demand-Side
Management Plan performance and mitigation measures.689
C. CONTINUATION OF MODERATION STRATEGY IS APPROPRIATE
437. BC Hydro assessed three plan alternatives: the 2013 Integrated Resource Plan
Alternative, the proposed Demand-Side Management Plan, and a No Programs alternative. BC
Hydro’s proposed Demand-Side Management Plan reflects an extension of the moderation
strategy applied in fiscal 2014 to fiscal 2016. The moderation strategy is appropriate for several
reasons. In light of the reduced rate of growth of demand for electricity in the short-term,
additional demand-side management resources are not required in the short-term to meet
system needs or the 66 per cent B.C. Energy Objective in fiscal 2021. The Demand-Side
Management Plan mitigates rate increases relative to the 2013 Integrated Resource Plan
alternative, while maintaining broad customer access to conservation programs and with
limited missed opportunities. In the longer-term, the proposed Demand-Side Management
Plan has the flexibility to ramp up, when required.690
(a) BC Hydro Assessed Three Plan Alternatives
438. BC Hydro determined the appropriate level of demand-side management
expenditures using the assessment framework described in Section 10.3 of the Application.691
BC Hydro evaluated three plan alternatives:
The 2013 Integrated Resource Plan Alternative: This alternative included the
highest level of expenditures among the three alternatives. It was based on the
688
Exhibit B-9, BCUC IR 1.167.6 and Exhibit B-14, BCUC IR 2.314.1. 689
Exhibit B-1-1, p. 10-55. Past reports are provided in Exhibit B-1-1, Application, Appendix Y and Evidentiary Update, Exhibit B-2.
690 Exhibit B-10, BCSEA IR 1.31.1.1
691 See Exhibit B-10, BCSEA 1.2.1, Attachment 1, for the Board Briefing note on the proposed level of demand-side measure expenditures.
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outlook in the 2013 Integrated Resource Plan for fiscal 2017 to fiscal 2019,
updated to reflect new developments.692
The proposed Demand-Side Management Plan: The proposed alternative
reflects the continuation of the moderation strategy recommended in the 2013
Integrated Resource Plan. The moderation strategy results in the reduction in
expenditures compared to the outlook in the 2013 Integrated Resource Plan for
fiscal 2017 to fiscal 2019. On average, total demand-side management
expenditures under the proposed Demand-Side Management Plan are forecast
to be nine per cent lower than the 2013 Integrated Resource Plan Alternative
over the test period.693
The No Programs Alternative. This alternative is the lowest level of
expenditures based on cancelling all programs in fiscal 2017, allowing for a wind
down of program expenditures.694
439. BC Hydro evaluated the alternative plans against the attributes presented in
Table 10-5 of the Application including cost effectiveness, the 66 per cent of load growth target
in the Clean Energy Act, flexibility to ramp up programs, support for other BC Hydro or
Government initiatives, rate impacts and expenditure level, broad access and missed
opportunities.695 The delayed need for additional system resources also played an important
role in the plan selection.696 These attributes reflect multiple considerations of interest to BC
Hydro and ratepayers.
692
Exhibit B-1-1, Application, p. 10-21; Exhibit B-10, BCSEA IR 1.2.9. See Attachment 1 to BCSEA IR 1.2.9.1 for the details of the 2013 Integrated Resource Plan Alternative, which was modelled at the same level as the proposed Demand-Side Management Plan.
693 Exhibit B-9, BCUC IR 1.168.3.
694 Exhibit B-1-1, Application, p. 10-21.
695 As shown in Exhibit B-9, BCUC IR 1.169.1, the attributes in the framework are very similar to those used in the 2013 Integrated Resource Plan.
696 Exhibit B-10, BCSEA IR 1.31.1.1
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440. BC Hydro rejected the No Programs alternative. It would be contrary to the
public interest, particularly given its negative impact on customers. As stated in the
Application:697
The No Programs alternative has significant impacts to customers and BC Hydro’s strategic objectives because it does not provide customers with the opportunity to leverage technology and obtain the energy consumption insight necessary to optimize their energy consumption, reduce their bills and deliver benefits to BC Hydro and its customers. For this and other downsides of this alternative noted above, such as reduced flexibility to ramp up saving levels, the No Programs alternative was not selected.
441. There was no indication during the proceeding that any party supported the No
Programs alternative.
442. As the 2013 Integrated Resource Plan Alternative included higher levels of
program spending, it would result in more energy savings compared to the proposed Demand-
Side Management Plan. The 2013 Integrated Resource Plan Alternative therefore scored better
than the proposed Demand-Side Management Plan with respect to attributes six (Support for
BC Hydro or Government initiatives), nine (Impact on broad access to demand-side
management programs) and 10 (missed demand-side management opportunities).698 It was
nonetheless reasonable to adopt the proposed Demand-Side Management Plan due to
considerations outlined in the following sections.
(b) The Rate of Growth in Demand for Electricity has Slowed
443. The 2013 Integrated Resource Plan recommendation for beyond fiscal 2016 was
to “prepare to increase spending”. This recommendation, however, was based on the load
forecast and the load resource balances at the time.699 BC Hydro’s updated load forecast and
load resource balance in Chapter 3 of the Application shows delayed system needs compared to
697
Exhibit B-1-1, Application, p. 10-25. 698
Exhibit B-1-1, Application, p. 10-22. 699
Exhibit B-15, BCSEA IR 2.58.5.
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the forecast load resource balances in the 2013 Integrated Resource Plan.700 Existing resources
are sufficient to meet the demand for electricity in the short-term; the load resource balances
do not indicate a system need for more demand-side management resources over the test
period than has been proposed. A moderation strategy in these circumstances is generally
consistent with the moderation strategy recommended in the 2013 Integrated Resource Plan
for fiscal 2014 to fiscal 2016, when BC Hydro was also in a position where existing resources
were sufficient to meet the demand for electricity in the short term.701
444. The letter from the Minister of Energy and Mines expresses Government’s
support for the Demand-side Management Plan as a prudent and responsible evolution of the
demand-side management plan approved by Government as part of the 2013 Integrated
Resource Plan.702 The letter from the Minister should be given significant weight as a
demonstration of Government support for the Demand-Side Management Plan.703
(c) Proposed Demand-Side Management Plan Keeps BC Hydro On Track to Meet 2013 10 Year Rates Plan Targets
445. The proposed Demand-Side Management Plan mitigates rate impacts, assisting
BC Hydro in meeting the targets in the 2013 10 Year Rates Plan. BC Hydro discusses in Part
Three above why customer rate impacts and the 10 Year Rates Plan are relevant to the public
interest, and must be considered by the Commission.
446. The rate impact of the 2013 Integrated Resource Plan alternative would put
pressure on BC Hydro’s ability to meet the targets of the 2013 10 Year Rates Plan.704 The 2013
Integrated Resource Plan Alternative would result in an incremental annual rate increase of
approximately 0.5 per cent relative to the proposed Demand-Side Management Plan over the
700
Exhibit B-15, BCSEA IR 2.58.5. 701
Exhibit B-15, BCSEA IR 2.58.5. Exhibit B-1-1, p. 10-2. 702
Appendix BB of the Application. See Exhibit B-15, BCSEA IR 2.59.1 Public Attachment 1 for the briefing note sent to the Minister.
703 Exhibit B-9, Application, BCUC IR 1.167.2.
704 Exhibit B-9, BCUC IR 1.169.5.
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fiscal 2020 to fiscal 2024 period.705 The rate impact of 0.5 per cent would occur each year,
resulting in a cumulative impact of approximately 2.7 per cent by the end of the fiscal 2020 to
fiscal 2024 period.706
(d) Demand-Side Management Plan Achieves the 66 Per cent Target in the Clean Energy Act
447. The Demand-Side Management Plan meets the B.C. Energy Objective “to take
demand-side measures and to conserve energy, including the objective of BC Hydro reducing its
expected increase in demand for electricity by the year 2020 by at least 66 percent.”707 The
Demand-Side Management Plan is forecast to reduce BC Hydro’s increase in electricity demand
in fiscal 2021 by approximately 106 per cent.708 As the Demand-Side Management Plan is
forecast to exceed the 66 per cent target by a significant margin, no further expenditures are
required to meet the demand-side management policy objective set in the Clean Energy Act.
448. The steps and calculation to derive the 106 per cent reduction in electricity
demand are provided in response to BCSEA IR 1.28.1.709 As discussed in the Minister’s Letter in
Appendix BB of the Application, the Clean Energy Act energy objective has been measured
without load related to LNG facilities and in relation to BC Hydro’s mid load forecast, which is
BC Hydro’s methodology for calculating the 66 per cent.710 BC Hydro has also followed past
practice of including savings from Codes and Standards in meeting the objective of achieving at
705
Exhibit B-9, BCUC IR 1.169.5. A detailed explanation of the calculation of this impact is provided in response to Exhibit B-15, BCSEA IR 2.65.1.
706 Exhibit B-15, CEC IR 2.143.3.
707 Exhibit B-1-1, Application, Table 10-5 and p. 10-23; Clean Energy Act, section 2(c).
708 Exhibit B-1-1, Application, p. 10-27.
709 Exhibit B-10, BCSEA IR 1.28.1.
710 Exhibit B-9, BCUC IR 1.169.3.2.
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least 66 percent of load growth.711 However, BC Hydro would still exceed the 66 per cent target
without energy savings from Codes and Standards.712
449. As discussed in detail in BC Hydro’s Rebuttal Evidence, the policy direction in this
province has not been to pursue all cost-effective demand-side management available.713
Rather, BC Hydro has a variety of policy objectives that it must balance, including (amongst
others) the target of reducing growth in demand by 2020 by at least 66 per cent and the
objective of keeping BC Hydro’s rates amongst the lowest in North America. BC Hydro’s
Demand-Side Management Plan balances the multiple objectives.
(e) Provides Customers with Broad Access to Programs and Substantial Bill Savings Opportunities
450. As discussed above in this Final Submission, BC Hydro’s proposed Demand-Side
Management Plan maintains a broad range of measures and provides all customers with access
to bill savings opportunities. This is demonstrated above by how BC Hydro designs its Demand-
Side Management Plan to provide broad access and address market barriers, the breadth of
opportunities available to customers, and the significant savings that will be realized by
customers.
(f) Moderation Strategy Results in Limited Missed Opportunities
451. The reduction in demand-side management spending due to the moderation
strategy results in limited missed (or lost) opportunities. A missed opportunity refers to a time-
limited opportunity to cost-effectively improve energy efficiency that is lost for a period of time
if not acted upon when available.714 As between the 2013 Integrated Resource Plan Alternative
and the proposed Demand-Side Management Plan, BC Hydro estimates the foregone savings
711
Exhibit B-15, BCSEA IR 2.51.4. 712
Exhibit B-9, BCUC IR 1.178.2. In fact, excluding Codes and Standards savings would result in a higher percent calculation. This result occurs because the Codes and Standards savings would have to be recognized in the load forecast prior to demand-side management savings, reducing the incremental load growth included in the calculation of the 66% target. See Exhibit B-15, BCSEA IR 2.51.6.
713 Exhibit B-20, pp. 4-7.
714 Exhibit B-10, BCSEA IR 1.7.1.
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due to missed opportunities to be in the range of 10 to 30 GWh over the test period.715 This
represents only 0.5 to 1.5 per cent of total incremental electricity savings of the Demand-Side
Management Plan in the test period.716 Given the reduced rate in growth in demand and the
need to meet the targets in the 2013 10 Year Rates Plan, the limited extent of missed
opportunities due to the moderation strategy supports the choice of the Demand-Side
Management Plan.
(g) BC Hydro Maintains the Ability to Ramp Up When Additional Resources are Needed
452. An important feature of the Demand-Side Management Plan is that BC Hydro
retains the ability to ramp up expenditures in the future if resources are required. BC Hydro’s
ability to ramp up is preserved by the continuation of a broad range of program activities,
active communication with stakeholders and other activities.717
453. The breadth of initiatives in all three customer sectors allows BC Hydro to
maintain a market presence and preserve business relationships with trade allies and
customers. This provides flexibility to ramp up energy-focused demand-side management in
the future, or to do more in other areas of energy management.718 BC Hydro described the
following examples to illustrate this point:719
For example, the Leaders in Energy Management, Retail and Home Energy Rebate Offer Programs can each encompass a variety of demand-side management offers and technologies. By continuing to operate these programs, we are maintaining our business relationships with industry partners – the firms that deliver related goods and services – that would be involved in new or expanded offers in the future. The industry partners associated with each of the programs are as follows:
715
Exhibit B-10, BCSEA IR 1.7.1; Exhibit B-14, BCUC IR 2.313.1.2. 716
Exhibit B-10, BCSEA IR 1.7.1. 717
Exhibit B-10, BCSEA IR 1.30.3. 718
Exhibit B-10, BCSEA IR 1.30.1. 719
Exhibit B-10, BCSEA IR 1.30.1.
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Leaders in Energy Management Programs: consulting engineering firms,
commercial interior designers, equipment manufacturers and
distributors and electrical contractors;
Retail Program: manufacturers and retailers of equipment used in
residences; and
Home Energy Rebate Offer: home renovation contractors.
Another example is residential construction, where we continue our home builder education and training activities. Doing so maintains our business relationships with home builders and increases their readiness to respond to new BC Hydro offers in the future.
In the commercial and industrial sectors, we are continuing our focus on energy management and extending it to reach more customers. Energy management provides a foundation that will make it easier to ramp up in the future if necessary, by increasing the readiness of customers to respond to new offers or incentives. Relative to a customer without any energy management resources or experience, a customer with such resources or experience is more aware of their energy consumption and the opportunities to reduce it or change it in response to BC Hydro programs and offers.
By cultivating a network of engaged residential customers, the Behaviour Program establishes a platform that allows us to introduce a wide variety of offers directed at residential customers in the future.
By continuing our Public Awareness Supporting Initiative, we are maintaining a level of energy literacy and conservation awareness among our customers that will make them more responsive to new programs or offers in the future.720
454. BC Hydro has over 800 firms registered in its trade ally network and is working
with 26 retail partners that represent 259 store locations across British Columbia. These
relationships are important for effective delivery of demand-side management initiatives. BC
Hydro maintains these relationships by providing information, training and support to foster
knowledge of its programs and energy efficiency opportunities. BC Hydro is able to increase its
720
Exhibit B-10, BCSEA IR 1.30.1.
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engagement with this workforce to ramp up support as needed. This workforce strategy has
been successful in allowing the ramp up of program elements in the past.721
455. In its Rebuttal Evidence, BC Hydro re-affirmed its ability to ramp up:
A9. BC Hydro’s assessment of its ability to ramp up its programs and the future availability of the contractor base is realistic. BC Hydro’s estimate of the three to five years to “ramp programs up to IRP incremental GWh levels” was based on knowledge gained from operating demand-side management programs in B.C. for over 25 years. In particular, between 1998 and 2001, BC Hydro had minimal demand-side management spending, and discontinued its programs during that period. With the re-introduction of programs in 2002, BC Hydro experienced the challenges of rebuilding the trust, relationships and partnerships that are critical to the successful implementation of a demand-side management plan. It is based on this direct experience that BC Hydro provided in Table 10 5 of the Application its estimates that a “No Programs” alternative would take seven to ten years to rebuild trust and ramp up, and that the “Demand-Side Management Plan” alternative would take three to five years.
Based on BC Hydro’s direct experience in British Columbia, BC Hydro is taking the appropriate steps to maintain the ability to ramp up demand-side management levels if needed. These steps include the following:
• Maintaining relationships through the BC Hydro Alliance of Energy Professionals. As EFG has indicated, considerable effort needs to be invested in recruiting and training contractors so that there is capacity in the market. BC Hydro agrees, and continues to engage energy professionals through a variety of networking breakfasts, technical training, program knowledge sessions and quarterly newsletters distributed to over 1600 members. Our breakfast education and networking events are very well attended, typically drawing 250+ industry members;
• Continuing funding for the Energy Manager positions and Strategic Energy Management Plans to drive current project activity and identify future projects;
721
Exhibit B-10, BCSEA IR 1.12.1.
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• Ensuring that critical internal expertise and knowledge is maintained, including that of marketing, engineering, analysis, operations, and measurement and verification staff;
• Maintaining a balance of programs through the level of program activity that we are proposing in order to remain active across different markets sectors and associated trade allies;
• Retaining support initiatives to ensure that we retain relationships with key groups (e.g., municipalities, government standards agencies, trade allies, and customer groups); and
• Continuing to invest in general public awareness and education around energy conservation and energy efficiency through the Public Awareness Supporting Initiative. Refer to section 17 of Appendix V of the Application for further details.
As a result of these steps, we are confident that BC Hydro can ramp up activities to forecast 2013 Integrated Resource Plan levels over three to five years on average. BC Hydro would be able to ramp up some activities faster than this, while other activities would take towards the longer end of the three to five year range to ramp up.722
456. In short, BC Hydro’s ability to ramp up demand-side management activities in
the future supports the decision to continue the moderation strategy over the test period to
remain on track with the rate targets in the 2013 10 Year Rates Plan.
D. BC HYDRO’S CHANGES TO THE DEMAND SIDE MANAGEMENT PLAN ARE IN THE PUBLIC INTEREST
457. BC Hydro is continuing a similar suite of demand-side management initiatives as
outlined in BC Hydro’s Fiscal 2012-Fiscal 2014 Revenue Requirements Application, but has
changed and modernized the plan in several respects.723 BC Hydro’s Demand-Side
Management Plan reflects an expanded energy management scope and changing customer
needs and expectations. BC Hydro also incorporated process improvements and service
722
Exhibit B-20, pp. 12-13. 723
Exhibit B-14, BCUC IR 2.312.1.
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enhancements, which have reduced costs and made it easier for customers to participate in
programs. In line with the moderation strategy discussed above, BC Hydro prioritized
expenditures. BC Hydro discontinued or reduced some programs that are not as cost effective,
have served their purpose, did not result in missed opportunities and/or had transitioned to
more cost effective opportunities to achieve savings.
(a) Responding to Expanded Energy Management Scope and Changing Customer Needs and Expectations
458. BC Hydro has made modifications to its Demand-Side Management Plan to
reflect an expanded energy management scope and address changing customer needs and
expectations.724
459. As stated in the Application, “In the past, capacity savings have been viewed as
an associated benefit of conservation programs rather than a key objective on its own. The
2013 Integrated Resource Plan signaled a shift in this resource focus given changing system
needs.”725 The Climate Leadership Plan also signaled a shift, including discussion on how
demand-side management programs can take on an expanded role in climate leadership, help
customers understand their greenhouse gas emissions and provide investments that increase
efficiency and reduce greenhouse gas emissions.726 Consistent with the 2013 Integrated
Resource Plan and the Climate Leadership Plan, the Demand-Side Management Plan reflects an
expanded energy management scope. As illustrated in Figure 10-1 of the Application, energy
management refers to the expansion of demand-side management beyond energy efficiency
and conservation by potentially adding capacity-focused demand-side management and low
carbon electrification.727
724
Exhibit B-1-1, pp. 10-13 to 10-17 and pp. 10-37 to 10-41. BC Hydro has described the changes to its programs in response to BCUC IR 1.169.2.1, 1.184.2 and 1.184.6.2.
725 Exhibit B-1-1, p. 10-13.
726 Exhibit B-9, BCUC IR 1.177.1.
727 Exhibit B-1-1, Application, pp. 10-15 to 10-16; Exhibit B-9, BCUC IR 1.169.1.
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460. There has been an increase in information and communication tools and
technology available to both utilities and customers on energy consumption.728 Examples of
changing technology include: smart metering infrastructure, smart thermostats, building
management and process control systems, and the general growth in telecommunications
networks, sensor and machine to machine communications technology.729 Customers expect
to be able to use these tools to communicate with their utility.730
461. The Demand-Side Management Plan has been modified to reflect the expanded
energy management scope and changing customer needs and expectations in a number of
ways, including:
The Leaders in Energy Management Programs (commercial, distribution and
industrial) are increasing the focus on strategic energy management.731 Strategic
energy management takes a holistic approach to managing energy use,
equipping and enabling management and staff to impact energy consumption
through behavioral and operational change.732 Some examples are the Strategic
Energy Management Cohort offer, the Operational Energy Analytics offer, the
Energy Management and Targeting offer and the Energy Associates offer.733
BC Hydro is continuing to pursue capacity focused demand-side management to
determine how capacity savings can be acquired and relied upon over the long-
term, including testing of connected devices in homes and buildings to manage
energy use.734
728
Exhibit B-1-1, Application, p. 10-14. 729
Exhibit B-1-1, Application, p. 10-14. 730
Exhibit B-1-1, Application, pp. 10-14 to 10-15; Exhibit B-9, BCUC IR 1.169.1. BC Hydro’s understanding of customer expectations is informed by workshops, conferences, newsletters, industry associations, research, meetings and interactions with customers. See Exhibit B-10, BCSEA IR 1.3.6.1. Exhibit B-10, BCSEA IR 1.3.6.
731 Exhibit B-1-1, Application, Appendix V, pages 21, 28, 32 and 33.
732 Exhibit B-1-1, Application, p. 10-38.
733 Exhibit B-1-1, Application, pp. 10-13 to 10-17; Exhibit B-9, BCUC IR 1.169.1.
734 Exhibit B-1-1, Application, pp. 10-7 to 10-8; Appendix V, pp. 34-36.
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BC Hydro refined existing programs to take advantage of new information and
technology. For example, the residential Behaviour program is using information
on residential customer consumption to provide customers with insights on their
electricity consumption. A similar approach is also available to commercial
customers through the Continuous Optimization offer within Leaders in Energy
Management, Commercial. 735
462. Consistent with BC Hydro’s expanded energy management scope, Order in
Council Nos. 100 and 101 (issued by the Lieutenant Governor in Council on March 1, 2017)
enable BC Hydro to pursue cost effective electrification by setting out the regulatory treatment
of the costs of these initiatives.736 BC Hydro described its initial work in this area in a number of
responses to information requests.737 While Order in Council No. 101 requires the costs of low-
carbon electrification initatives to be deferred to the Demand-Side Management Regulatory
Account,738 these initiatives would not be “demand-side management” under the Clean Energy
Act.739 The proposed Demand-Side Management Plan does not contain low-carbon
electrification expenditures, other than the intitial exploration costs ($200,000) described in BC
Hydro’s response to BCUC IR 2.323.2. Consistent with Order in Council Nos. 100 and 101, these
costs are being deferred to the Demand-Side Management Regulatory Account. BC Hydro
confirmed that funding within the proposed demand-side management expenditure schedule
will not be allocated to low-carbon electrification initiatives.740 BC Hydro will file information
735
Exhibit B-1-1, Application, p. 10-38. 736
Exhibit B-22, CEA IR 3.47.1. 737
Exhibit B-9, BCUC IR 1.177.1; Exhibit B-10, BCSEA IR 1.39.2; CEABC IR 1.9.1. and 1.9.2; Exhibit B-14, BCUC IR 2.323.3; Exhibit B-14-2, BCUC IR 2.197.3 (Revised); Exhibit B-15, CEABC IR 2.35.1; BCSEA IR 2.55.1.3.
738 Exhibit B-20, p. 11. Order in Council No. 100 allows for the costs of low carbon electrification carried out under Order in Council No. 101 to be deferred to the Demand-Side Management Regulatory Account.
739 Exhibit B-22, BCSEA IR 3.67.7.
740 Exhibit B-22, BCSEA IR 3.67.3.
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on its low-carbon electrification iniatives in future applications as appropriate.741 BC Hydro
anticipates that the incremental revenue from these iniaitves will exceed the costs.742
(b) Productivity Improvements and Service Enhancements
463. The Demand-Side Management Plan incorporates productivity improvements
and service enhancements, reflecting BC Hydro’s company-wide objective to “Continue to
improve the way we operate.”743 Examples of these include:
Implementation of an enterprise management resource system over fiscal 2012
to fiscal 2014 to manage customer project processing, which has realized over
$1.5 million annually in savings;
Implementation of an automated payment system resulting in $70,000 in annual
savings;
Development of an online application and payment process for rebate programs
to make it easier for customers to participate in rebate programs; and
Implementation of a process review for custom projects designed to improve
timelines and reduce operational touch points, resulting in annual savings of
$420,000.744
464. In addition, BC Hydro’s coordination activities with FortisBC Energy Inc. and
FortisBC Inc. over fiscal 2014 and fiscal 2015 achieved operational savings of $4.5 million and
$5.4 million, respectively.745
741
Exhibit B-21, BCUC IR 3.340.1.1. 742
Exhibit B-21, BCUC IR 3.340.1. 743
Exhibit B-1-1, Application, sections 10.4 and 10.7.4. 744
Exhibit B-1-1, Application, p. 10-32. 745
Exhibit B-1-1, Application, pp. 10-54 to 10-55.
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(c) Use of Cost Effectiveness Screens to Prioritize Spending
465. BC Hydro used cost effectiveness screens to prioritize spending, resulting in a
more cost effective portfolio overall that reduces BC Hydro’s revenue requirements. The
prioritization is aligned with the 2013 10 Year Rates Plan.
466. BC Hydro developed the Demand-Side Management Plan considering cost
effectiveness as measured by two tests: the Total Resource Cost test and the Utility Cost
Test.746 BC Hydro explained the general purpose of these tests as follows:
The Total Resource Cost Test: In accordance with the Demand-Side Measures Regulation, BC Hydro uses the Total Resource Cost Test as a determinant of whether an individual demand-side management initiative and the demand-side management portfolio as a whole are cost effective. The Total Resource Cost Test helps BC Hydro to assess how the cost of demand-side management compares to the cost of other supply side resource options; and
The Utility Cost Test: For the purposes of determining the fiscal 2017 to fiscal 2019 demand-side management expenditures, BC Hydro also relied on the Utility Cost Test. This test is used to understand the impact of a demand-side management investment on BC Hydro’s revenue requirement.
467. In addition to the Total Resource Cost test at long-run marginal costs (consistent
with the Demand-Side Measures Regulation), BC Hydro used a Utility Cost Test with the B.C.
border sell price forecast as the avoided energy cost stream (which is approximately $36 per
MWh) in order to prioritize demand-side management investments. BC Hydro’s cost of
demand-side management would need to be less than the wholesale market price to pass the
Utility Cost Test filter using the B.C. border sell price forecast. The use of this filter ensured that
even surplus energy resulting from demand-side management would have a favourable impact
on BC Hydro’s revenue requirements.747
746
Exhibit B-1-1, Application, p. 10-19; Exhibit B-10, BCSEA IR 1.27.2; and Exhibit B-14, BCUC IR 2.312.2. 747
Exhibit B-1-1, Application, p. 10-19; Exhibit B-10, BCSEA IR 1.3.2. Exhibit B-14, BCUC IR 2.312.2.
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468. BC Hydro considered modifications to any demand-side management initiative
that did not pass the Total Resource Cost test at long-run marginal costs and the Utility Cost
Test at the value of $36 per MWh, with the exception of the demand-side measures initiatives
specified in section 3 of the Demand-Side Measures Regulation.
469. The programs and initiatives that did not pass the Utility Cost Test at the value of
$36 per MWh filter are set out in BC Hydro’s responses to BCUC IR 1.184.2 and BCOAPO IR
2.121.1. Only one program that did not pass this filter was cancelled (i.e. the Refrigerator Buy
Back Program), as it had served its purpose. This is discussed in the next section. Other
programs were modified to improve cost effectiveness. Details on the changes to programs
over the test period, including modifications due to the moderation strategy, are provided in
response to BCUC IR 1.169.2.1 and 1.184.6.1.748 The use of the cost effectiveness filters to
prioritize spending resulted in a more cost effective portfolio by eliminating or modifying less
cost effective elements.
(d) Discontinuing Some Programs is Reasonable
470. BC Hydro continues with a similar suite of demand-side management programs
as outlined in previous application, with the following exceptions:
The Industrial Load Displacement program was cancelled;
The Refrigerator Buy Back program was cancelled;
BC Hydro no longer offers direct incentives to builders through the New Home
program; and
The Medium General Service and Large General Service conservation rates were
cancelled as they are being amended pursuant to BC Hydro’s 2015 Rate Design
application.
748
Exhibit B-9, BCUC IR 1.184.6.1
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471. The cancellation of the Load Displacement program, Refrigerator Buy Back
program and incentives under the New Home program were the subject of information
requests in the proceeding. As discussed below, in each case the cancellation of the program or
incentives under the program was reasonable, considering the need to moderate spending,
cost effectiveness, missed opportunities and strategic opportunities.
Industrial Load Displacement Program Not a Lost Opportunity
472. The Industrial Load Displacement Program was cancelled as it did not represent
a lost opportunity.749 The Industrial Load Displacement program provided a capital incentive
and study funding for customers interested in pursuing customer-based generation projects.
The program was available to industrial, commercial and institutional customers that were able
to install generation projects greater than 100 kW.750
473. The cancellation of the Industrial Load Displacement program does not represent
a lost opportunity as the projects can be captured again in the future.751 Potential projects do
not generally represent lost opportunities for BC Hydro as these projects can potentially be
pursued by BC Hydro at a later date (resulting in flexibility to ramp up if needed). In addition, a
customer always has the option to install generation on-site to displace its load, provided it is
technically and financially viable.752 In these circumstances, the cancellation of the Load
Displacement program was a reasonable choice as part of the moderation strategy.
Refrigerator Buy Back Program Was Delivering Diminishing Returns
474. The Refrigerator Buy Back program did not pass the Utility Cost Test compared
to the market price filter753 and was cancelled as its savings were diminishing. The program
749
Exhibit B-1-1, Application, p. 10-39; Exhibit B-10, BCSEA IR 1.44.2 for analysis of the program. Also see BCUC IR 1.192.2.
750 Exhibit B-14, BCUC IR 2.315.2.
751 Exhibit B-1-1, Application, p. 10-39; Exhibit B-10, BCSEA IR 1.44.2 for analysis of the program. Also see BCUC IR 1.192.2.
752 Exhibit B-14, BCUC IR 2.315.2.
753 Exhibit B-9, BCUC IR 1.184.2.
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was successful in removing the least efficient refrigerators from households and educating
customers on the energy consumption levels of second refrigerators.754 While some cost
effective energy savings opportunities still remain,755 the Refrigerator Buy Back Program was
experiencing diminishing savings as second refrigerators are becoming more energy efficient.756
The cancellation of the Refrigerator Buy Back program was reasonable in the circumstances.
Transition from Incentives Under New Home Program to Codes and Standards
475. BC Hydro will no longer offer direct incentives to builders through the New
Home program. Instead of seeking to influence individual projects through incentives, BC
Hydro is focussing on codes and standards and other activities that can transform the
construction industry. BC Hydro’s Codes and Standards will support improvements to the
energy efficiency of new construction and the B.C. Building Code at a lower cost to
ratepayers.757 As discussed below, BC Hydro is maintaining a number of activities that were
previously under the New Home Program that support the development of new residential
building codes. The Codes and Standards budget includes funding to support activity in this
area.758
476. The incentives offered under the New Home Program have facilitated a
transition to a more cost effective strategy that supports builder education and codes and
standards development.759 As indicated in a recent evaluation of the New Home Program, free
ridership significantly increased over the period of the offer from a participant’s first application
to their last application. This suggests a growing number of the home builders participating in
the program changed their building practices over the period of the offer, and may not require
an incentive to continue to build homes to that level of energy efficiency.760 Consistent with
754
Exhibit B-10, BCSEA IR 1.5.1. 755
Exhibit B-10, BCSEA IR 1.5.2. 756
Exhibit B-1-1, Application, p. 10-39. 757
Exhibit B-1-1, Application, p. 10-39; Exhibit B-10, BCSEA IR 1.5.1; Exhibit B-15, BCSEA IR 2.60.8. 758
Exhibit B-14, BCUC IR 2.321.1.1. 759
Exhibit B-10, BCSEA IR 1.5.1. 760
Exhibit B-15, BCSEA IR 2.60.8.
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this evaluation, BC Hydro informally heard from past program participants that they continue to
build their new homes to the ENERGY STAR standard, having changed their building practices as
a result of participating in the program.761 The New Home evaluation concluded: “There is
evidence that the New Home program supported the process of transforming the new
residential construction market to higher levels of energy efficiency by changing builder
practices and increasing the number of energy-efficient homes built in BC.”762
477. BC Hydro’s Codes and Standards builds on the success of the New Home
program. It seeks to create a demand for more efficient new homes, by increasing awareness
and energy literacy among builders, developers, realtors and home buyers. For example, BC
Hydro is supporting the introduction and acceptance of the next level of building codes, either
through revisions to the B.C. Building Code and the Vancouver Building By Law, or through
adoption of the B.C. Energy Step Code at the local government level.763
478. BC Hydro is also taking a number of actions to encourage the development of
net zero buildings, such as:764
Raising awareness and increasing acceptance of new technologies and
construction practices through: workshops, showcase building projects and
training initiatives;
Working with the BC Building Safety Standards Branch, local governments and
other stakeholders to support the adoption of higher performance tiers once the
BC Energy Step Code has been adopted into the BC Building Act;
Working at the national level on advancing the provisions of the Model National
Energy Code for Buildings to facilitate incremental efficiency gains;
761
Exhibit B-14, BCUC IR 2.321.1. 762
Exhibit B-15, BCSEA IR 2.60.8, Attachment 1. 763
Exhibit B-10, BCSEA IR 1.19.1. 764
Exhibit B-14, BCUC IR 2.321.1.1.
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Developing roadmaps to near net zero commercial and residential building in
collaboration with the Pembina Institute and the Lighthouse Sustainable Building
Centre;
Participating in the Step Code Implementation Advisory Committee that
supports the implementation of the BC Energy Step Code and providing technical
and strategic assistance to local government and industry on the Step Code. This
assistance includes working with the following stakeholders:
Local governments to use appropriate policy and incentive tools to roll
out the Step Code in an orderly manner within their jurisdiction;
Provincial agencies to align the Step Code with other provincial initiatives,
including Climate Action Charter update, building energy benchmarking
and reporting;
Industry partners to ensure availability of appropriate training and skills
development for rolling out the Step Code;
Professional associations, including engineers, building officials, planners,
architects, and builders, to align the Step Code into professional training
and certification programs; and
National codes development bodies to align BC Step Code metrics with
national programs and codes.765
479. BC Hydro’s work on Codes and Standards can also limit missed opportunities due
to cancelling incentives under the New Home program, which are estimated at a maximum of
765
Exhibit B-14, BCUC IR 2.321.1.1.
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10 GWh per year.766 The City of Vancouver could make changes to the Vancouver Building
Bylaw in 2018, and the next update to the BC Building Code is expected in 2020. If the next
energy performance requirements align with Step 3 of the Step Code, they would be equivalent
to the performance incented by the New Home program. In the case of the City of Vancouver,
there would be only one year of missed opportunities. In the case of the BC Building Code,
there would be four years of missed opportunities.767 For this reason, the 10 GWh estimate of
missed opportunities from the cancellation of incentives under the New Home program should
be viewed as a maximum.
480. While incentives will no longer be offered, BC Hydro’s current approach is to
continue to invest in awareness, education, training, and promotional activities intended to
build industry capacity and foster demand for energy efficient new homes. Participation in
these activities is expected to increase as resources are redirected away from promoting
participation in the incentive program. In addition, these activities will now be more closely
aligned with other activities under Codes and Standards to promote compliance with the
existing codes and to adopt building practices consistent with the new B.C. Energy Step Code.
Overall participation in these market transformation activities is expected to increase as a result
of greater coordination and integration of efforts.768
481. In summary, given the success of the New Home program, a change in focus to
market transformation through Codes and Standards is a reasonable and cost effective
strategy.
E. CODES AND STANDARDS ACTIVITIES ARE COST EFFECTIVE
482. BC Hydro’s Codes and Standards activities in the Demand-Side Management Plan
are consistent with the 2013 Integrated Resource Plan Recommended Action 3: Explore More
766
Exhibit B-15, BCSEA IR 2.60.8. If the trend of free ridership noted above continued, the volume of missed opportunity savings due to cancellation of the program would be less than the estimated maximum of 10 GWh per year.
767 Exhibit B-15, BCSEA IR 2.60.9 and 2.60.11.
768 Exhibit B-10, BCSEA IR 1.19.2.
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Codes and Standards.769 Codes and Standards are a cost effective form of demand-side
management that focuses on transforming the marketplace through energy efficiency
requirements in (i) building codes and (ii) product and equipment standards.770 BC Hydro’s
approach to reporting savings under Codes and Standards is reasonable and appropriate. BC
Hydro is taking significant and effective action to support Codes and Standards and is prudently
managing its activities in this area. BC Hydro’s success and contribution has been explicitly
recognized by government bodies at all levels.
(a) BC Hydro’s Significant Support for Codes and Standards
483. BC Hydro’s strategy and approach to Codes and Standards is discussed in
Appendix V of the Application and supplemented with detailed information in response to
information requests, including in Exhibit B-9, BCUC IR 1.178.4, 1.178.5, 1.179.2.1, and
1.179.2.2 and Exhibit B-10, BCSEA IR 1.41.1 to 1.41.3. BC Hydro’s activities in support of codes
and standards include, for example:
BC Hydro undertakes activities and spending related to market research, cost
benefit analysis, funding for codes and standards development, aiding in market
transformation and compliance enhancement.771
BC Hydro’s consultation and participation on strategic committees with various
federal and provincial bodies allows BC Hydro to monitor reference codes and
standards and identify opportunities to advance their development and
adoption.772 This includes:
National bodies: BC Hydro works with Natural Resources Canada, the
National Research Council, and the Canadian Standards Association to
identify codes and standards opportunities and assist in their
769
Exhibit B-1-1, Application, pp. 10-9 to 10-10. 770
Exhibit B-1-1, Application, Appendix V, p. 1. Exhibit B-10, BCSEA IR 1.41.3. 771
Exhibit B-9, BCUC IR 1.179.2.1. 772
Exhibit B-9, BCUC IR 1.178.5
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development through: the Standing Committee on Energy Efficiency in
Buildings; the Standing Committee on Performance, Energy Efficiency &
Renewables; the Standing Committee on Performance, Energy Efficiency
& Renewables Resource Task Force; and the four Canadian Standards
Association Technical Committees responsible for developing
performance standards for electrical products.773
Provincial bodies: BC Hydro meets regularly with the Ministry of Energy
Mines, the Building Safety Standards Branch, the City of Vancouver, and
other local government officials. BC Hydro also participates in the BC
Building Code Modernization Advisory group, which reviews and makes
recommendations on the proposed regulatory changes to create a
modern, streamlined building regulatory system based on a uniform BC
Building Code. It takes part in coordination calls as part of the Pacific
Coast Collaborative to share best practices and coordinate performance
requirements for specific codes and standards, as applicable.774 BC
Hydro is working with the BC Building Safety Standards Branch to support
the development of the BC Energy Step Code, which outlines
performance tiers or “steps” toward higher performing buildings. BC
Hydro will support the adoption of higher performance tiers.775
BC Hydro sets targets and forecasts for each of its Codes and Standards Key
Performance Indicators.776 BC Hydro monitors the progress of Codes and
Standards savings against the targets. Success is based on staying on track with
773
Exhibit B-9, BCUC IR 1.178.5. 774
Exhibit B-9, BCUC IR 1.178.5. 775
Exhibit B-10, BCSEA IR 1.41.2. 776
Exhibit B-9, BCUC IR 1.180.2.
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the plan. In order to assess progress, BC Hydro monitors key milestone dates in
the adoption and introduction of regulations and building codes.777
484. BC Hydro has obtained reference letters from standards agencies and local
governments recognizing BC Hydro’s contribution to their Codes and Standards activities.778
The letters are from:
Director, Energy Efficiency Policy, B.C. Ministry of Energy and Mines;
Acting Executive Director, Minister of Natural Gas Development and Minister
Responsible for Housing;
Vice President, Electrical and Gas Product Standards, Canadian Standards
Association;
Senior Manager, Sustainability and District Energy, City of Richmond;
Deputy Director, Community Development, City of Vancouver;
Manager, Sustainability, City of Surrey;
Green Building Manager, City of Vancouver, Planning, Urban Design and
Sustainability; and
Director Equipment Division, Office of Energy Efficiency, Natural Resources
Canada.
485. The referenced letters testify to the significant level of influence of BC Hydro’s
activities in support of codes and standards.
777
Exhibit B-9, BCUC IR 1.180.1. 778
Exhibit B-10, BCSEA IR 1.10.1.4, Attachments 1 to 7; Exhibit B-15, Attachment 1 to BCSEA IR 2.51.1.
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(b) Cost-Effective Under Various Tests
486. Codes and Standards are a cost effective form of demand-side management. As
shown in Table 9 of Appendix W of the Application, Codes and Standards has a Total Resource
Cost test result of 6.5, a Utility Cost test result of 149.1 and a modified Total Resource Cost test
result of 7.6. Results greater than one indicate that benefits exceed costs. The Utility Cost
benefit cost ratio of 149.1, assuming 100 per cent of savings, means that the benefits are 149.1
times greater than BC Hydro’s costs.
487. The energy and capacity savings and customer and utility costs for Codes and
Standards are set out in Table 1, 2, 5 and 6 of Appendix W. The energy savings shown in
Appendix W of the Application are the estimated savings expected to result from the adoption
and enforcement of new building codes and product regulations that BC Hydro is supporting
through its Codes and Standards activities. These savings are netted off from BC Hydro’s load
forecast as part of the overall Demand-Side Management Plan.779
(c) Reasonable Approach to Determining Savings
488. The savings set out in Appendix W of the Application are conservatively
calculated. BC Hydro has identified each of the codes or standards it is supporting and the
expected savings from each.780 BC Hydro provides its assumptions for calculating savings from
Codes and Standards in Appendix V, p. 1. One of the key assumptions is compliance rates,
which reflect the percentage of the total affected market that BC Hydro expects to be
compliant with relevant codes and standards.781 Specific compliance rates are developed based
on expert opinion of BC Hydro staff, regulators, and industry representatives, and informed by
market studies and evaluations where available. BC Hydro’s compliance rate assumptions and
supporting studies and evaluations are provided in response to BCSEA IR 1.14.2.782
779
Exhibit B-9, BCUC IR 1.179.2. 780
Exhibit B-9, BCUC IR 1.179.2. 781
Exhibit B-10, BCSEA IR 1.14.1. 782
Exhibit B-10, BCSEA IR 1.14.2.
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489. There are many factors and parties influencing the development and
introduction of new codes and standards. BC Hydro is not claiming the incremental savings in
Appendix W are solely attributable to its efforts, or that codes and standards development
would not occur in the absence of BC Hydro’s work.783 Reporting all savings from codes and
standards, rather than an attribution of those savings, makes sense for two reasons.
First, reporting all savings expected from codes and standards allows the
demand-side management savings to align with BC Hydro’s load forecast,
producing load forecasts with and without demand-side management.784
Second, the significant time, effort and cost to quantify and defend an
incremental claim is not necessary.785 The Utility Cost benefit cost ratio of 149.1,
assuming 100 per cent of savings, means that the benefits of Codes and
Standards are 149.1 times greater than BC Hydro’s costs. As such, even if BC
Hydro’s direct contribution to codes and standards savings were only 1 per cent,
then the Utility Cost benefit/cost ratio would still be greater than one, meaning
BC Hydro’s expenditures in this area are cost effective.786 The evidence,
discussed above, suggests that BC Hydro’s contribution towards the success of
codes and standards savings in the province is significant.787
490. In summary, BC Hydro’s Codes and Standards is a cost effective form of demand-
side management. BC Hydro is taking significant and effective action to support codes and
standards. BC Hydro’s success and contribution has been explicitly recognized by government
bodies at all levels.
783
Exhibit B-9, BCUC IR 1.179.3. 784
Exhibit B-10, BCSEA IR 1.10.1 and 1.10.1.4. 785
Exhibit B-10, BCSEA IR 1.10.1 and 1.10.1.4. 786
Exhibit B-10, BCSEA IR 1.10.1 and 1.10.1.4. 787
Exhibit B-10, BCSEA IR 1.10.1 and 1.10.1.4.
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F. CAPACITY FOCUSED DEMAND SIDE MANAGEMENT IS IN THE PUBLIC INTEREST
491. BC Hydro’s capacity focused demand-side management pilot activities are a
critical investment in capacity resources that can provide significant benefits for ratepayers by
deferring the need for new pumped storage generation capacity and upgrades to local facilities.
BC Hydro’s pilot activities are informed by successful pilots and programs in other jurisdictions
to the extent that they have findings applicable to B.C. They are required to test the reliability
of potential programs for use in BC Hydro’s integrated resource plan. BC Hydro submits that
the expenditures on these activities are in the public interest and should be accepted.
(a) Capacity Focused Pilot Activity Overview
492. BC Hydro’s capacity focused demand-side management consists of two
components: (1) load curtailment pilot activities and (2) demand response pilot activities. The
pilot activities are supported by detailed evidence in this proceeding. As summarized below,
these pilot activities are conducting important testing of capacity resources for use on BC
Hydro’s system.
493. BC Hydro’s load curtailment pilot activities will provide an understanding of the
amount of available demand reduction based on the ability of large industrial customers to
respond to calls for demand reduction over a substantial duration.788 In fiscal 2015, BC Hydro
conducted a proof of concept trial with Catalyst Paper. Using the learnings from this trial, BC
Hydro then began a two-year pilot, which was open to all transmission customers through a
request for proposals process.789 The two-year pilot ended in April 2017, and BC Hydro will
now assess the reliability and performance of the pilot to determine whether to include it in the
contingency resource plan in the 2018 Integrated Resource Plan.790 The price incentive for the
pilot was reflective of BC Hydro’s long-run marginal cost of generation capacity at the time.791
788
Exhibit B-1-1, Application, Appendix V, pp. 34-35. 789
Exhibit B-14, BCUC IR 2.318.1.1. See Confidential Attachment BCUC IR 2.318.1.1 for the agreement with Catalyst Paper for the proof of concept trial.
790 Exhibit B-14, BCUC IR 2.317.3.
791 Exhibit B-21, BCUC IR 3.66.1.
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The business case for the load curtailment pilot is included as BCUC IR 2.318.1.1 Attachment
1.792 A draft report on the results on Year 1 of the load curtailment pilot is included as BCUC IR
2.319.2.1 Attachment 1.793 Historical and forecast expenditures on BC Hydro’s load curtailment
activities are provided in Table 4 of BC Hydro’s response to BCUC IR 2.319.2, and include $6.8
million and $1 million in fiscal 2017 and fiscal 2018, respectively (there are no forecast
expenditures in fiscal 2019). The total expected cost of the two-year pilot is $19.5 million.794
494. The demand response activities planned over the test period will test various
residential, commercial and industrial technologies and the effect of implementing these
technologies on the end user and the BC Hydro system.795 The initiatives planned for the test
period build on learnings from fiscal 2015 and fiscal 2016, and are described in response to
BCUC IR 2.317.3. The initiatives include: (i) residential demand response trials, testing
customer acceptance and performance using various emerging technologies; (ii) commercial
and industrial demand response trials, including use of customer-sided batteries, building
management system integration, smart charging of electric vehicles and automated demand
response; (iii) localized demand-side management pilots to test the ability of various
technologies to meet the needs of particular distribution assets and shift the timing of peak
demand; and (iv) investigations into connected home technology, testing customer acceptance
and adoption of centralized home hubs and supporting equipment that facilitates new ways for
customers to use energy in their homes.796 An example of a project plan for a demand
response pilot is included as Attachment BCUC IR 2.319.2.1 Attachment 2.797 Details on
historical and forecast expenditures on the demand response pilot activities is provided in Table
792
Exhibit B-14, BCUC IR 2.318.1.1 Attachment 1. 793
Exhibit B-14, BCUC IR 2.319.2. 794
Exhibit B-14, BCUC IR 2.317.3. 795
Exhibit B-1-1, Application, Appendix V, pp. 34-35. 796
Exhibit B-14, BCUC IR 2.317.3. Also see Exhibit B-9, BCUC IR 1.183.1 and 1.183.3. 797
Exhibit B-14, BCUC IR 2.319.2.1 Attachment 2.
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1, 2 and 3 of response to BCUC IR 2.319.2. Planned expenditures are $3.2 million, $13 million
and $14 million for fiscal 2017, fiscal 2018 and fiscal 2019, respectively.798
(b) Capacity Focused Demand-Side Management Is a Potential Lower Cost Capacity Resource for Base and Contingency Resource Planning
495. A key objective of the capacity focused demand-side management pilot activities
is to understand whether capacity focused demand-side management can be a long-term
resource that is sufficiently reliable for deferring generation resources.799 If confirmed reliable,
capacity focused demand-side management options could defer the need for higher cost
pumped storage facilities. Capacity focused demand-side managment could be used to meet
capacity gaps in BC Hydro’s base resource plan by fiscal 2029 or the larger capacity gaps in BC
Hydro’s contingency resource plans as early as fiscal 2019.800
496. The Province’s recent Climate Leadership Plan calls for 100 per cent of the new
electricity acquired by BC Hydro to be from renewable or clean sources. BC Hydro, however, is
running out of new low cost clean generation capacity. Revelstoke 5 and Mica 5 and 6 are
already in service, and the last opportunity to add a large hydro unit to an existing dam,
Revelstoke 6, is already included in BC Hydro’s resource planning stack.801 The next capacity
option is pumped storage, which has long lead times, high costs and comes in large increments:
…the next clean generation capacity option [after Revelstoke 6] would generally be pumped storage facilities which is a step increase in cost (estimated at $199/kW-year fiscal 2015$ including the cost of energy losses in the pump-generation cycle). BC Hydro has estimated the time to commit to and have a pumped storage facility constructed to be about 8 to 10 years. The installed
798
Exhibit B-14, BCUC IR 2.319.2 799
Exhibit B-9, BCUC IR 1.181.3. 800
Exhibit B-14, BCUC IR 2.317.2 and 2.317.3. 801
Exhibit B-14, BCUC IR 2.317.2.
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costs of a 1000 MW pumped storage facility is estimated at $1.27 billion and a 500 MW facility would be at least $0.64 billion ignoring economy of scale.802
497. Given the characteristics of pumped storage, it is prudent for BC Hydro to
explore and confirm the potential of capacity focused demand-side options that can be
available with shorter lead times, lower cost and smaller increments than pumped storage
facilities.803
498. In comparison to the cost of pumped storage noted above, the price of BC
Hydro’s Industrial Load Curtailment pilot was much lower, evaluated against the cost of a
single-cycle gas turbine.804
499. The value of capacity focused demand-side management as a capacity resource
must be considered in the context of both expected and contingency scenarios. In the expected
case, capacity focused demand-side management would be used to fill the capacity deficit
beginning fiscal 2029, and would be an alternative to pumped storage facilities (estimated at
$199/kW year fiscal 2015$). The net present value of the cost of pumped storage facilities to
fill the capacity deficit in fiscal 2029 over the next 15 years is $78 million.805 Capacity focused
demand-side management could also serve as a contingency resource option. BC Hydro
explained:
For a large gap scenario (10 per cent likelihood), BC Hydro would consider either small clean or gas options until a pumped storage facility could be available in fiscal 2025 which would result in the net present value of the cost over the next ten years of $568 million, and over the next 15 years of about $1.4 billion. The
802
Exhibit B-14, BCUC IR 2.317.3. As stated in this response: “The Climate Leadership Plan indicates that a single cycle gas turbine is no longer a preferred option to meet capacity needs and instead pumped storage is the expected marginal resource for long-term need.” Exhibit B-9, BCUC IR 1.81.3
803 Exhibit B-14, BCUC IR 2.317.3.
804 Exhibit B-21, BCUC IR 3.339.2.2 and Exhibit B-22, BCSEA IR 3.66.1
805 Exhibit B-9, BCUC IR 1.182.1.
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funding request of $38.6 million is about 7 per cent of the ten year estimate and about 3 per cent of the 15 year estimate.806
As BC Hydro emphasized in its responses to information requests, contingency resource
planning is prudent utility planning consistent with the Commission’s Resource Planning
Guidelines.807
500. The ability to procure capacity focused demand-side management in smaller
increments with shorter lead times than pumped storage provides not only potential savings,
but will assist BC Hydro in achieving other government policy objectives. Namely, capacity
focused demand-side management would help to avoid the need to rely on market purchases
(which is not consistent with the self-sufficiency requirement in the Clean Energy Act, and can
have reliability risk depending on the magnitude of reliance); or the use of gas resources (which
is inconsistent with the Climate Leadership Plan).808
501. Furthermore, capacity focused demand-side management produces benefits for
customers, who can participate in the programs and reduce their overall costs.809 This is an
important and direct benefit to customers. For example, industrial customers have been
proponents of the load curtailment pilot program as they see it as a means to mitigate the
impact of electricity rate increases. Industrial customers participated in the Industrial Electricity
Policy Review process and supported the review panel recommendation that BC Hydro develop
a load curtailment program.810 Consistent with this, AMPC’s intervener evidence states that the
load curtailment pilot programs are “important to industrial customers and should be
encouraged.”811 As discussed further below, customers have responded positively to the pilot
activity to date.
806
Exhibit B-9, BCUC IR 1.182.1. 807
Exhibit B-14, BCUC IR 2.317.2 and 2.317.3. 808
Exhibit B-14, BCUC IR 2.317.2. 809
Exhibit B-14, BCUC IR 2.317.2. 810
Exhibit B-14, BCUC IR 2.318.1.1 Attachment 1, Executive Summary, p. 5 of 12. 811
Exhibit C9-7, AMPC Intervener Evidence, p. 12.
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502. Given the significant potential benefits, BC Hydro’s capacity focused demand-
side management pilot activities are prudent investments for the development of capacity
options to be considered in the 2018 Integrated Resource Plan.
(c) Capacity Focused Demand-Side Management Can Alleviate Local Constraints
503. Capacity focused demand-side management results in dispatchable resources,
which can provide a reliable and direct reduction to peak demand on a system-wide or local
level.812 Capacity focused demand-side management thus offers the potential to remove
localized constraints and defer upgrades to substations and transmission and distribution
infrastructure.
504. BC Hydro explained the potential for this benefit as follows:813
Our system includes 306 substations throughout the province. Load growth is driving a need to expand the capacity of many of these substations and/or their connected transmission and distribution infrastructure. The cost of a single expansion is unique to the specific substation and connected transmission and distribution infrastructure as well as the load profile and can vary significantly. To the extent we can reduce peak loads on these substations, based on the nature of the customer base and load profile, we can defer capital investments and save millions of dollars. Deferrals of two, five or ten years can save progressively more money. If we assume that a single substation, along with connected transmission and distribution infrastructure costs are in the range of $10 million to $20 million, deferring this expenditure by five years results in a $2.2 million to $4.3 million savings. If BC Hydro could successfully defer these types of investments on a larger scale, it could save significant expenditures.
505. BC Hydro’s planned demand response initiatives include localized demand-side
management pilots to assess BC Hydro’s ability to shift the timing of the peak demand of a local
area so that it is not coincident with the system peak. BC Hydro plans to test different solutions
at a number of constrained substations, utilizing solutions tested in the residential, commercial
812
Exhibit B-10, BCSEA IR 1.6.1. 813
Exhibit B-14, BCUC IR 2.317.3.
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and industrial demand response trials.814 The potential benefit of capacity focused demand-
side management to reduce peak demand at a local level is anticipated to become increasingly
important as BC Hydro increases electrification and implements the 100 per cent new clean
electricity supply policy in the Climate Leadership Plan.815
506. BC Hydro submits that its capacity focused demand-side management pilot
activities are a good investment given the significant potential benefits associated with
deferring upgrades to local assets.
(d) Capacity Focused Demand-Side Management is Part of a Cost-Effective Portfolio
507. As discussed in the sections above, the rationale for proceeding with the pilot
activities is based on the need to test load curtailment and demand response programs and the
significant benefits of developing a capacity resource that can displace the need for pumped
storage generation capacity and local facility upgrades. As it is too early to assess the benefits
of the pilot activities,816 assessing the cost-effectiveness of the pilot activities on a stand-alone
basis using the Total Resource Cost or Utility Cost test cannot be done and would not be
appropriate. EFG takes a similar view, stating the following in response to BCUC-BCSEA IR
3.2:817
EFG would not expect that the capacity DSM spending would necessarily be a cost-effective investment based only on the savings achieved during the pilots. As a pilot initiative, there would be a greater emphasis on testing hypotheses and applying lessons learned to fully scaled future initiatives. An assessment of the value of the pilot would need to reflect not just the value of the capacity savings achieved in the pilot, but also the value and costs of the future capacity savings that would only be achieved as a result of the pilot. Alternatively, if the pilot demonstrates that such approaches are a poor use of ratepayer funds, then the assessment should include the savings from avoiding “bad” investments
814
Exhibit B-14, BCUC IR 2.317.3. This initiative accounts for $2.0 million in fiscal 2018 and $3.0 million in fiscal 2019, respectively, for a total of $5.0 million over the test period.
815 Exhibit B-9, BCUC IR 1.181.1.1.
816 Exhibit B-14, BCUC IR 2.320.2.
817 Exhibit C1-15.
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because of the learning done through the pilot. Because a pilot can provide information that can optimize future investments, it can be considered to be a good investment regardless of whether or not it is cost-effective based on the short-term results it achieves.
508. BC Hydro submits that the capacity focused pilot activities are a good investment
in the manner described by EFG.
509. While BC Hydro is unable to calculate whether the capacity focused pilots are
cost effective on a stand-alone basis,818 BC Hydro’s capacity focused pilots are part of a cost-
effective portfolio. As discussed below in this Final Submission, section 4(1) of the Demand-
Side Measures Regulation allows the Commission to assess cost effectiveness at the portfolio
level. The cost effectiveness of BC Hydro’s portfolio, calculated on the fiscal 2017 to fiscal 2019
demand-side management expenditures with and without the cost of capacity focused pilots, is
shown in the table below. As results greater than 1.0 are cost effective, the table demonstrates
the Demand-Side Management Plan remains cost effectiveness when it includes the costs of
the capacity focused pilots.819
Total Resource Cost Test (LRMC)
Utility Cost Test
(LRMC)
Modified TRC
(LRMC)
Total Portfolio without capacity focused pilots 3.4 8.5 4.1
Total Portfolio with capacity focused pilots 3.4 7.7 4.0
510. BC Hydro has not included any of the benefits from the capacity focused pilots
within the benefit cost ratios at the portfolio level shown above. The inclusion of any benefits
would improve the results for the total portfolio with capacity focused pilots.820
(e) BC Hydro is Proceeding Prudently with its Capacity Focused Pilots
511. BC Hydro’s approach to capacity focused demand-side management is to use
pilots to incrementally expand trials, technologies and customer segments as BC Hydro gains
818
Exhibit B-14, BCUC IR 2.320.2. 819
Exhibit B-14, BCUC IR 2.320.2. 820
Exhibit B-14, BCUC IR 2.320.2.
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experience with each technology and approach. BC Hydro’s pilot activities are informed by
successful programs in other jurisdictions,821 with each pilot designed to achieve specific goals
and objectives.822 BC Hydro develops business cases or project plans for each capacity focused
demand-side management pilot. A steering committee consisting of Directors and Senior
Managers with an interest in the outcome of the pilot will provide guidance to each of the
pilots.823 BC Hydro will manage capacity focused demand-side management to ensure the pilot
projects stay on track according to project objectives. If project objectives change or if they are
not being realized, BC Hydro management will make adjustments to individual initiatives and/or
the capacity focused demand-side management portfolio overall.824 Objectives will be
measured through analysis of electricity consumption data and or customer surveys, using
metrics such as actual load impacts and reliability of response.825
(f) Pilots are Necessary to Assess Capacity Focussed Demand-Side Management
512. The approach of using pilots to test capacity focused demand-side management
is a necessary step that is consistent with the industry approach.
The Value of the Pilots
513. Capacity programs have a real-time operational element that can be experienced
only through trials. Real experience is needed to understand how customers in British Columbia
respond to capacity programs. The customer experience through actual demand response
pilots is a critical component of the learning and has a direct influence on the customer
acceptance of innovative technologies and solutions and therefore capability.826 Pilot activities
are required:
821
Exhibit B-21, BCUC IR 3.339.2. 822
Exhibit B-20, p. 10. 823
Exhibit B-14, BCUC IR 2.319.2.1. 824
Exhibit B-9, BCUC IR 1.183.3. 825
Exhibit B-9, BCUC IR 1.181.1. 826
Exhibit B-9, BCUC IR 1.181.1.1.
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To gather information on the cost to customers of providing capacity, the
volume of capacity available and dependability of capacity.827
To understand the infrastructure and technologies required to measure real time
load reduction and how best to integrate those technologies into BC Hydro’s
systems.828
To understand the capability and willingness of customers to either adjust when
they would otherwise use energy (e.g., load shifting) or reduce their energy
demand for relatively short periods of time (e.g., peak shedding) in the case of
Demand Response, or longer periods of time in the case of Load Curtailment,
using various residential, commercial and industrial technologies. 829
To understand how to integrate demand response programs into BC Hydro’s
system and resource stack and how BC Hydro’s system operations team will
manage the various demand response events.830
To test the ability to use demand response to deal with localized capacity
constraints at the substation level. 831
To develop learning around integration elements from a program design,
contracting, measurement, communications, operations and integration
perspective.832
514. Alternative approaches, such as benchmarking, surveys or customer education,
would not provide enough information on their own to understand if capacity focused demand-
827
Exhibit B-9, BCUC IR 1.181.1. 828
Exhibit B-9, BCUC IR 1.181.1. 829
Exhibit B-9, BCUC IR 1.181.1. 830
Exhibit B-9, BCUC IR 1.181.1.1. 831
Exhibit B-9, BCUC IR 1.181.1.1. 832
Exhibit B-9, BCUC IR 1.181.1.1.
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side management can be relied upon for long-term planning needs (e.g., 2018 Integrated
Resource Plan).833
Pilot Programs Are Common in the Industry
515. BC Hydro’s use of pilot activities to advance its understanding of capacity
focused demand-side management is a common approach in the industry.834 The Navigant
study referenced by Commission staff in BCUC IR 1.181.2 refers to numerous pilot programs
carried out by utilities. Bonneville Power Authority, for example, completed four years of
technical and programmatic Demand Response pilots throughout the Pacific Northwest, before
launching commercial demonstrations as a next step to understand the contractual and
operational approaches to the acquisition of Demand Response.835 In the area of connected
home technologies, over 40 utilities are actively involved in testing, trialing, or reviewing the
performance of connected devices for demand-side management purposes.836 Localized
demand-side management is another area in which a number of electric utilities in North
America are investigating and investing in pilot projects.837
516. While pilots are common, there is a lack of experience in other jurisdictions of
programs deployed in a winter peaking hydro electric utility that could be applied to the B.C.
market.838 The nature of BC Hydro’s system winter peak and generation resource stack leads to
a unique capacity need.839 No other jurisdiction has run a pilot or program for the product that
BC Hydro requires to meet its system needs (36 days of curtailment of 16-hours per day).840 For
example, the number of hours targeted in the Bonneville Power Authority demonstration was
833
Exhibit B-9, BCUC IR 1.181.1.1. 834
Exhibit B-20, Rebuttal Evidence, p. 10; Exhibit B-21, BCUC IR 3.339.2. 835
Exhibit B-9, BCUC IR 1.181.2. 836
Exhibit B-9, BCUC IR 1.183.3. 837
Exhibit B-9, BCUC IR 1.183.3. 838
Exhibit B-9, BCUC IR 1.181.1.1. 839
See Exhibit B-15, BCOAPO IR 2.103.1. for a discussion of BC Hydro’s system requirements. See Exhibit B-22, CEC IR 3.180.1 for a discussion of the differences between BC Hydro’s capacity requirement and those of other jurisdictions. See also Exhibit B-21, BCUC IR 3.181.2.
840 Exhibit B-20, Rebuttal Evidence, p. 10.
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up to 120 hours per year. This is substantially less than the 576 hours BC Hydro targeted in the
Load Curtailment pilot.841 The uniqueness of BC Hydro’s system requirements demonstrates
the need for BC Hydro to carry out its own pilot activities.842
Past Successes With Pilots
517. BC Hydro’s pilot activities reflect a steady scaling up of activities as it learns from
its pilots. For example, having gained experience in the small scale testing of equipment, BC
Hydro is moving to larger scale community-based localized capacity focused demand-side
management activities in fiscal 2018 and fiscal 2019. New technologies are also introduced as
the pilot activities progress. In the residential sector, trials were introduced in 2017 for new
technologies such as electric vehicle charging and smart thermostats, and in 2018 and 2019
funding for connected home activities will be increased.843 As discussed below, BC Hydro pilot
activities to date have been successful and response from customers has been positive, which
provides a foundation for future activities.
518. BC Hydro’s capacity focused pilot activities have been successful to date and
have resulted in significant learnings.844 Four pilot programs were initiated over fiscal 2015 and
2016 to aid in program development: year 1 of the load curtailment pilot with large industrial
customers; commercial buildings at the University of British Columbia; residential water heaters
in Sidney; building management systems with commercial and light industrial customers.845 BC
Hydro’s response to BCUC IR 1.183.1 provides a detailed description of these activities and BC
Hydro’s learnings. They are summarized below.
519. BC Hydro described year 1 of the load curtailment pilot as follows:846
841
Exhibit B-9, BCUC IR 1.181.2. 842
Exhibit B-21, BCUC IR 3.339.2. 843
Exhibit B-14, BCUC IR 2.319.2. 844
Exhibit B-9, BCUC IR 1.183.1. 845
Exhibit B-9, BCUC IR 1.183.1. 846
Exhibit B-10, CEC IR 1.102.2.
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Year One was successful. BC Hydro released a Request for Proposal for up to 100 MW for 576 hours (36-days of 16-hours per day). The bids received totalled 126 MW. In order to stay within the $7.5 million budget the curtailment days were reduced from a 36-day to a 28-day curtailment period.
Customers were called for either a 27-day or 28-day curtailment period under a variety of scenarios, ranging from one-day curtailments to a two-week (six days per week) scenario simulating a winter cold snap. The tests demonstrated that the resource as a portfolio is generally reliable with an overall compliance of 97 per cent (based on events called) and 123 per cent delivery ratio (based on MW curtailed on average to MW requested). There were only two minor failures.
In aggregate, the group met its load reduction target with the exception of one day. One customer requested an opt-out day (allowed under the terms of the program), and increased their load thereby negating 50 per cent of the curtailment.
520. BC Hydro also learned from implementation issues, including issues related to
real-time customer performance feedback and the determination of a reference load. Further
information is provided in the report on year 1 of the load curtailment pilot, which is filed as
BCUC IR 2.319.2.1 Attachment 1.
521. BC Hydro’s demand response programs were also successful:
The pilot at the University of British Columbia indicated there was significant
flexibility in commercial buildings to provide capacity savings opportunities. The
pilot uncovered opportunities in the areas of building management system
adjustments to the operation of heating, ventilation and air conditioning
systems, lighting adjustments, fuel switching and lockout of non-critical devices.
BC Hydro learned about capabilities and limitations of some building control
systems and how to manage occupant comfort and seek non disruptive
opportunities. An experiment with the ice rinks yielded promising opportunities
for more event based curtailment.847
847
Exhibit B-9, BCUC IR 1.183.1.
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The residential demand response pilot project provided valuable knowledge
about the reliability of various communication channels available to trigger load
control devices and the deployment requirements to build, operate and manage
this type of resource. Feedback from participants was that the events were non-
disruptive to the occupants, and the majority of participants have returned for
subsequent test years. It also highlighted the opportunity to explore other non-
disruptive load management opportunities within residential homes, such as
smart electric vehicle charging, smart thermostats, energy storage, behavioural
programs and the role of targeted energy efficiency programs for permanent
peak reductions.848 The preliminary results of the water heater demonstration
show a demand reduction of approximately 0.5 kW per unit over the duration of
a demand reduction event, with 90 per cent of the participants responding to
the post-project survey rated their experience with this project “Excellent” (60
per cent) or “Good” (30 per cent).849
The commercial and industrial demand response pilot initiatives helped BC
Hydro understand customer acceptance and adoption. Many customers were
unsure of how to identify opportunities, what impacts it may have on their
business and how to manage occupant comfort. Customers also need significant
time to socialize these new concepts within their organization and to undertake
building management system reprogramming, controls installation and
procedure development in order to be prepared for event calls. More work
needs to be done in understanding customer support needs, recruiting a greater
breadth of commercial and industrial business types, and exploring how BC
Hydro can assist businesses to successfully participate with low risk to their
business operations.850
848
Exhibit B-9, BCUC IR 1.183.1. 849
Exhibit B-14, CEC IR 1.104.2. 850
Exhibit B-9, BCUC IR 1.183.1.
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522. Over the test period, BC Hydro will complete initiatives begun in fiscal 2015 and
2016,851 and extend its piloting activities to other areas to better understand the local benefits
that could be achieved by geographically targeted demand-side management and also to
understand how new potential demand response technologies perform.852
523. In summary, BC Hydro’s pilot activities are consistent with industry practices and
are yielding successful results.
(g) Advancement of Capacity Focused Demand-Side Management is Supported by Customers, Government, System Needs and BC Hydro’s Priorities
524. BC Hydro’s advancement of its capacity focused initiatives is supported by
customers and government, and are aligned with system needs and BC Hydro’s priorities.
525. Customer support to advance capacity focused demand-side management
beyond what was envisioned in the 2013 Integrated Resource Plan was expressed through the
Industrial Electricity Policy Review. The Industrial Electricity Policy Review Task Force noted in
its report: “Industrial stakeholders from different sectors stated that shifting industrial demand
from peak periods has a value to BC Hydro. Voluntary curtailment or setting up economic
incentives for industrial customers to shift their usage could help address BC Hydro’s projected
capacity constraint at potentially lower cost than constructing new projects.” 853
526. The Industrial Electricity Policy Review Task Force Recommendation Number 13
indicates: “BC Hydro should work with its industrial customers and the Commission to develop
options that take advantage of industrial power consumption flexibility, such as time of use
rates and interruptible rates.”854 The B.C. Government responded to the Industrial Electricity
Policy Review Task Force Recommendation with the following direction: “BC Hydro will
implement a voluntary load curtailment program with industrial customers starting in 2015.”
851
Exhibit B-9, BCUC IR 1.183.3. 852
Exhibit B-9, BCUC IR 1.183.3. 853
Exhibit B-14, BCUC IR 2.318.1.1. 854
Exhibit B-14, BCUC IR 2.318.1.1.
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This direction prompted BC Hydro to advance the timing of the load curtailment pilots in its
plans.855
527. Government has continued to demonstrate its support for BC Hydro’s capacity
focused demand-side management, as follows:
BC Hydro’s Shareholder Letter of Expectations direction is to improve customer
satisfaction by exploring innovative energy conservation solutions such as load
curtailment rates.856
The Minister’s letter of support for BC Hydro’s demand-side management plan
includes recognition of capacity focused demand-side management as part of
the plan.857
528. Similarly, one of BC Hydro’s company-wide priorities is to explore the full
potential of energy conservation, which includes capacity focused demand-side
management.858
529. Since implementing the pilot activities, BC Hydro’s customers have continued to
express interest in participating in the pilot programs. For example, year 1 of the load
curtailment pilot was oversubscribed859 and BC Hydro’s Sidney demonstration project for
residential, commercial and light industrial customers is oversubscribed and customer
satisfaction to date has been high.860
855
Exhibit B-14, BCUC IR 2.318.1.1. 856
Exhibit B-1-1, Appendix D. Exhibit B-9, BCUC IR 1.181.2. BC Hydro interprets the Shareholder Letter of Expectations direction to improve customer satisfaction by exploring innovative energy conservation solutions to broaden the focus and approach of its Demand-Side Management Plan across all customer sectors, including looking at capacity focused demand-side management.
857 Exhibit B-1-1, Application, Appendix BB.
858 Exhibit B-9, BCUC IR 1.181.2.
859 Exhibit B-14, BCUC IR 2.319.2.1 Attachment 1, p. 4.
860 Exhibit B-9, BCUC IR 1.181.2.
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(h) Conclusion regarding Capacity Focused Demand-Side Management
530. BC Hydro’s capacity focused demand-side management pilot activities are a
critical investment in capacity resources that can provide significant benefits for ratepayers by
deferring the need for new pumped storage generation capacity and upgrades to local facilities.
BC Hydro’s pilot activities are informed by successful pilots and programs in other jurisdictions
and are required to test the reliability of potential programs for use in BC Hydro’s integrated
resource plan. The pilot activities are part of a cost-effective portfolio and are supported by
customers, government, system needs and BC Hydro company-wide priorities. BC Hydro
submits that the expenditures on these activities are in the public interest and should be
accepted.
G. BC HYDRO IS ADDRESSING MARKET BARRIERS IN NON-INTEGRATED AREAS AND FIRST NATIONS COMMUNITIES
531. BC Hydro’s demand-side management programs all address barriers faced by
customers when pursuing energy efficiency solutions. However, customers in non-integrated
areas and First Nations communities may experience different or greater barriers to
participating.861 BC Hydro is taking a number of steps to address the barriers to participation in
conservation programs faced by customers in non-integrated areas and First Nations
communities.862 BC Hydro’s steps include (a) general efforts to address barriers to participation
in existing programs, (b) plans to pilot a number of different approaches and activities in non-
integrated areas and First Nations communities, (c) working directly with First Nation
communities, and (d) ongoing consultation activities. These activities are discussed in the
subsections below.
861
Exhibit B-10, Zone II IR 1.8.1. 862
Exhibit B-10, Zone II IR 1.8.1. Also see Exhibit B-23, BC Hydro’s response to Zone II IR 2.25.2 in BC Hydro’s 2015 Rate Design Application proceeding.
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(a) BC Hydro is Addressing Barriers to Participation In Existing Programs
532. Customers in non-integrated areas and First Nations communities are eligible for
BC Hydro’s existing programs and incentives.863 For example, the Low Income Program has
been delivered in over 80 First Nation communities and has expenditures of $7.8 million
planned for the test period based on expected participation (budget is not a constraint to
participation in the Low Income Program).864 BC Hydro takes steps to make its demand-side
management activities accessible to hard to reach customers, as described in Appendix V865 and
in its response to BCUC IR 1.176.5.1.866 A number of actions taken by BC Hydro with respect to
non-integrated areas and First Nations communities in particular are discussed below.
(b) BC Hydro is Investing in Pilot Activities to Improve Access
533. BC Hydro has undertaken a number of pilot activities in non-integrated areas and
First Nations communities in the past867 and is continuing pilot activities over the test period to
improve its programs and access to conservation opportunities in these areas.
534. BC Hydro’s pilot activities are part of its ongoing efforts to improve the way it
operates and serves its customers. BC Hydro pilots potential demand-side management
activities where there are new opportunities for customers to manage their electricity use and
reduce their bills. Such opportunities could include a new delivery approach, a new technology,
or a unique market barrier. BC Hydro applies learnings from pilot programs to adapt and
improve initiatives before deciding to move forward on a broader scale. Pilots help manage risk
863
Exhibit B-5, BC Hydro’s Responses to Zone II IR 1.5.2 and 1.5.3 and Exhibit B-23, 2.20.1 in BC Hydro’s 2015 Rate Design Proceeding.
864 Exhibit B-15, Zone II IR 2.36.7; Exhibit B-23, BC Hydro’s Responses to BCOAPO IR 2.330.10 and 2.332.1 in BC Hydro’s 2015 Rate Design Proceeding.
865 Exhibit B-1-1, Application, Appendix V.
866 Exhibit B-9
867 Exhibit B-15, Zone II IR 2.38.8.
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by providing the opportunity to identify and work through potential challenges prior to rolling
out a program offer on a broader scale.868
535. BC Hydro is planning to spend $2.1 million over the test period to trial a number
of different approaches to addressing barriers to demand-side management and energy
efficiency upgrades in non-integrated areas and First Nations communities.869 These activities
include the following as set out in response to Zone II IR 1.20.5:870
Support education and skills training to build energy literacy in the community:
Providing salary support and in-kind mentorship and training for a
Community Energy Champion position within the Band Administration.
This position champions energy conservation and assists community
members in managing energy use and costs.
Providing salary support to First Nations organizations (First Nations
Energy and Mining Council, Coastal First Nations – Great Bear Initiative)
to hire Community Energy Managers that provide training and support to
First Nations communities at the provincial and regional scales.
Having a dedicated BC Hydro staff resource on the Conservation and
Energy Management team that works with First Nations and remote
communities to provide conservation education and mentorship to Band
staff and Community Energy Champions.
Developing community energy management curriculum targeted at First
Nations (through Vancouver Island University’s First Nations Housing
868
Exhibit B-15, Zone II IR 2.38.7. 869
Exhibit B-15, Zone II IR 2.37.1. 870
Exhibit B-10
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Managers Certificate Program) and supporting First Nations Band staff to
take this training.
Providing financial support to First Nations Bands to hire temporary
employees that receive training to assist with the installation of basic
energy saving measures through the Energy Conservation Assistance
Program.
Exploring builder and trades training needs in First Nations and remote
communities in an effort to increase local capacity around the
construction and maintenance of energy efficient buildings.
Facilitate access to opportunity assessments and energy efficient upgrades for
homes:
By having BC Hydro staff and contracted resources (e.g., Community
Energy Managers, Program Delivery Agents) available to assist
communities in accessing our Energy Conservation Assistance Program.
Support the piloting of the installation of residential energy saving
measures deemed to be providing energy savings and other energy
management benefits to the customer, beyond those provided through
the Energy Conservation Assistance Program.
Support the development and implementation of energy efficient housing policy:
Collaborating with the B.C. Ministry of Energy and Mines to support
development and adoption of energy efficient housing policy in
interested First Nations communities.
Developing educational materials and policy templates to assist First
Nations in development and adoption of energy efficient housing policy.
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Supporting Community Energy Managers and Community Energy
Champions that can assist First Nations with energy efficient housing
policy development.
Support the development of community energy plans:
Conducting a scan of existing First Nations community energy plans to
determine the strengths and weaknesses of these plans in terms of the
direction they provide on demand-side management and looking at
options for improving or strengthening community energy planning in
First Nations.
Pilot a targeted Low Income Offer to First Nations communities:
Piloting an alternative delivery method for the Energy Conservation
Assistance Program, which allows interested communities to coordinate
and manage their own home energy retrofits and apply to BC Hydro for
rebates on eligible energy saving measures.
536. Details on these activities are provided in a number of BC Hydro’s responses to
information requests.871 For example, BC Hydro is taking specific action to increase
participation in the Energy Conservation Assistance Program, as the participation of non-
integrated communities in this program has been low.872 These actions include:873
Piloting an alternative delivery model for the Energy Conservation Assistance
Program based on providing rebates on eligible energy savings measures
purchased and installed by the community;
871
E.g., Exhibit B-10, Zone II IR 1.8.2. 872
Exhibit B-20, Rebuttal Evidence, pp. 45-46. 873
Exhibit B-20, Rebuttal Evidence, p. 46; Exhibit B-5 (Rate Design IRs), BCUC IR 2.25.1; Exhibit B-10, BCSEA IR 1.20.2, Zone II IRs 1.8.3, and 1.20.5; Exhibit B-15, Zone II IRs 2.36.14, 2.36.15 and 2.36.16.
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Investigating options to coordinate with other funding agencies to address issues
related to health and safety (which have been a barrier to access to the program
upgrades);
Providing financial support to First Nations Bands to hire temporary employees
that receive training to assist with the installation of basic energy saving
measures through the Energy Conservation Assistance Program; and
Facilitating access to opportunity assessments and energy efficient upgrades for
homes by having BC Hydro staff and contracted resources (e.g., Community
Energy Managers, Program Delivery Agents) available to assist communities in
accessing our Energy Conservation Assistance Program.
537. More detail on BC Hydro’s efforts in this regard is provided in responses to
information requests.874
538. BC Hydro’s goal is to learn from these activities in order to make improvements
to existing demand-side management programs and to develop new offers that support
conservation and energy management activities with First Nations and Non-Integrated Area
communities.875 BC Hydro expects that as a result of these approaches and activities,
expenditures in remote and First Nations communities will increase compared to past years.876
As shown in BC Hydro’s response to BCUC IR 3.345.1, BC Hydro’s direct expenditures in Non-
Integrated Areas are estimated to increase over the test period compared to fiscal 2014 to
fiscal 2016.877
874
Exhibit B-5 (Rate Design IRs), BCUC IR 2.25.1; Exhibit B-10, BCSEA IR 1.20.2, and Zone II IRs 1.8.3 and 1.20.5; Exhibit B-15, Zone II IRs 2.36.14, 2.36.15 and 2.36.16.
875 Exhibit B-15, Zone II IR 2.38.5.
876 Exhibit B-15, Zone II IR 2.36.7.
877 Exhibit B-21, BCUC 3.345.1.
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(c) Work with Specific First Nations Communities
539. BC Hydro efforts to improve access for hard to reach customers include working
directly with First Nations communities to facilitate ongoing demand-side management
activities and providing funding for First Nations support positions.878
540. BC Hydro dedicates resources to assist First Nations communities and Non-
Integrated Areas in gaining access to conservation opportunities. BC Hydro’s Aboriginal
Relations department assigns an individual as a primary point of contact for First Nations
communities where BC Hydro has significant projects under development or extensive
operations within their traditional territory. For interests and concerns related to electricity
service or energy conservation, this individual will engage the Customer Service or Conservation
Energy Management groups.879 Within the Customer Service group, BC Hydro offers First
Nations’ housing administrators and social assistance agents access to a specialized group of
call centre agents who manage multiple accounts on behalf of community members. In
addition, BC Hydro currently has a dedicated resource on the Conservation and Energy
Management team that works with non-integrated areas and First Nations communities to
advance demand-side management opportunities.880
541. Representatives of Kwadacha First Nation (Fort Ware) and Tsay Keh Dene Nation
filed evidence in this proceeding. The demand-side management funding for activities with
Kwadacha First Nation (Fort Ware) and Tsay Keh Dene Nation in fiscal 2017 and fiscal 2018 will
include:881
Hiring an Energy Champion to work for the Band;
Providing training and mentorship to the Energy Champion;
879
Exhibit B-10, Zone II IR 1.8.2. 880
Exhibit B-10, Zone II IR 1.8.2. 881
Exhibit B-15, Zone II IR 2.36.11.
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Delivering conservation education activities to community members;
Providing regular reports to the Bands to support them in assisting community
members in managing home energy use and costs;
Implementing home energy upgrades through a customized approach to the
delivery of the Energy Conservation Assistance Program;
Providing funding to support additional energy saving measures beyond those
provided through existing programs; and
Developing multi-year plans to guide future building energy upgrades and
conservation opportunities.
542. Regarding the development of the multi-year plan noted above, BC Hydro has
been supporting the development of a Community Energy Management Plan for the Tsay Keh
Dene First Nation since October 2016. Once completed, the plan will outline a multi-year
implementation plan for demand-side management activities in the community. The intent of
the plan is to understand what work is needed so BC Hydro can determine how best to support
it and allocate budget accordingly. Once the plan is finalized, BC Hydro will consider the
potential for multi-year funding as part of this process.882 BC Hydro expects that this plan will
help address some of the concerns of this community with respect to access to conservation
opportunities.
(d) Past Discussions and Desire for Ongoing Process
543. Discussions with representatives from First Nations and Non-Integrated Area
communities informed BC Hydro’s demand-side management activities. They resulted in
specific actions, such as the creation of a bulk application process to assist in accessing
882
Exhibit B-20, Rebuttal Evidence, p. 44.
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incentives through the Home Energy Rebate Offer,883 funding for a Community Energy
Facilitator Position with the Coastal First Nation and funding to support conservation
opportunities in the Kwadacha First Nation and Tsay Keh Dene Nation communities.884
544. BC Hydro has expressed its desire for an ongoing process for feedback, stating:
BC Hydro would benefit from gaining additional perspective of remote communities and First Nations. Therefore, we are interested in establishing an ongoing process that could include Non Integrated Area and Zone II interveners to incorporate ongoing feedback to improve the design, delivery and participation in our demand-side management programs.885
545. BC Hydro proposes to meet with Non-Integrated Area and Zone II interveners to
discuss what this process could look like, before developing a proposal for an ongoing
process.886
546. The activities described above will strengthen relationships with non-integrated
area communities and First Nations communities, creating a more open and transparent
exchange of information that will serve all parties.887
(e) Increase in Reporting Not Required
547. BC Hydro reports annually to the Commission on its demand-side management
activity. In Zone II’s responses to BCUC-Zone II IRs 2.1 and 2.2, Zone II requests that the
Commission require BC Hydro “to report annually on the implementation of its DSM programs
in Non-Integrated Area communities specifically, including a detailed analysis of the
effectiveness of each program and its plans (including funding and access) for future years in
883
Exhibit B-15, Zone II IR 2.36.10: “to assist the Skidegate Band in accessing incentives through the Home Energy Rebate Offer, we developed a bulk application process to make it easier for the Band to apply for rebates on behalf of all community members. This process is now in place for other Bands that might want to access program incentives on behalf of their community members.”
884 Exhibit B-15, Zone II IR 2.36.2.
885 Exhibit B-15, Zone II IR 2.36.2.
886 Exhibit B-22, Zone II IR 3.56.3.
887 Exhibit B-20, p. 47.
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those communities”.888 As the evidence reviewed above shows, BC Hydro is taking significant
steps to address market barriers in non-integrated areas and First Nations communities. BC
Hydro’s work will strengthen relationships and create a more open and transparent exchange
of information. For this reason, BC Hydro submits that increased reporting as requested by
Zone II is not required.
548. However, if the Commission would like annual information on BC Hydro’s
activities in Non-Integrated Areas, BC Hydro could add a line item to its Annual Report on DSM
Activities to reflect Non Integrated Areas activities to the extent that they are tracked
separately.889 As BC Hydro’s program are designed and managed as province-wide offerings,
many Non Integrated Area expenditures are not tracked separately.890
H. THE DEMAND-SIDE MANAGEMENT PLAN IS COST-EFFECTIVE UNDER THE DEMAND-SIDE MEASURES REGULATION
549. The Demand-Side Measures Regulation is complex and prescribes the manner in
which the Commission is to assess the cost effectiveness of demand-side management
expenditures. BC Hydro’s entire portfolio and all Codes and Standards, Rate Structures and
Programs (including costs of supporting initiatives) are cost effective under the Demand-Side
Measure Regulation as they pass (1) the standard total resource cost test; (2) the modified total
resource costs test prescribed by the regulation; and (3) with the exception of the Low Income
program, pass the utility cost test. Under section 4(1.8)(c) of the Demand-Side Measure
Regulation, the Low Income program cannot be considered not cost effective based on the
utility cost test.891 The following sections summarize the requirements of the Demand-Side
Measures Regulation and discuss in greater detail how the Demand-Side Management is cost
effective pursuant to those requirements.
888
Exhibit C17-9, Zone II Responses to IRs on Intervener’s Evidence. 889
Exhibit B-21, BCUC IR 3.345.2. 890
Exhibit B-10, Zone II IR 1.19.1 and 1.19.3. 891
Exhibit B-9, BCUC IR 1.175.2 and 1.175.2.1.
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(a) Summary of the Requirements of the Demand-Side Measures Regulation
550. Section 4 of the Demand-Side Measures Regulation specifies how the
Commission is to assess the cost effectiveness of demand-side measures filed under section
44.2 of the Utilities Commission Act. The requirements are described in the Application,892 and
the sections applicable to BC Hydro’s Demand-Side Management Plan are discussed here. For
all cost effectiveness tests, values of one or greater indicate cost effectiveness, meaning that
the benefits are equal to or greater than the costs.893
551. Subsection 4(1) of the Demand-Side Measures Regulation allows the Commission
to compare the costs and benefits of demand-side measures individually, as a group or as a
portfolio as a whole. However, certain measures, notably a public awareness program894 such
as BC Hydro’s Public Awareness Supporting Initiative,895 must be assessed for cost effectiveness
on a portfolio basis.
552. Subsection 4(1.1) of the Demand-Side Measures Regulation requires the
Commission to determine cost effectiveness by applying a modified version of the Total
Resource Cost Test. The modified Total Resource Costs must use the amount the Commission is
satisfied represents BC Hydro’s long run marginal cost of acquiring electricity generated from
clean or renewable resources in B.C. to quantify avoided electric energy costs and to quantify
avoided natural gas costs, and by increasing the total avoided cost benefits by 15 per cent.896
553. Section 4(1.5) of the Demand-Side Measures Regulation imposes a limit of 10 per
cent of the portfolio that can be cost-effective under the modified Total Resource Cost test, but
892
Exhibit B-1-1, Application, pp. 10-28 to 10-31. 893
Please see the Guide to the Demand-Side Measures Regulation, attached to Exhibit B-15, BCSEA IR 2.50.6, for a detailed discussion of the application of the regulation.
894 Section 4(5) of the Demand-Side Measures Regulation requires the Commission to assess the cost effectiveness of a public awareness program on a portfolio basis if satisfied it is likely (in summary) to increase public awareness of ways to increase energy conservation or efficiency, to encourage energy efficiency or conservation, or to increase participation in proposed measures.
895 Exhibit B-1-1, Application, Appendix V, Section 17, pp. 37 to 39.
896 Alternatively, a utility could demonstrate the non-energy benefits attributable to demand-side measures consistent with the Demand-Side Measures Regulation.
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not otherwise cost effective under the standard Total Resource Cost test. This limit is not, in
practice, a limitation for BC Hydro’s portfolio, since the portfolio and programs all pass the
standard Total Resource Cost test.
554. Subsection 4(1.8) of the Demand-Side Measures Regulation allows the
Commission to determine that a demand-side measure, other than specified types of measures
including a low income program, is not cost effective if the demand-side measure would not be
considered cost effective under the Utility Cost Test.
555. Subsection 4(6) of the Demand-Side Measures Regulation indicates that the
Commission cannot determine that a demand-side measure is not cost effective on the basis of
the results of a Ratepayer Impact Measure Test.
556. Finally, subsection 4(2) of the Demand-Side Measures Regulation requires the
Commission to use, in addition to any other analysis it considers appropriate, the Total
Resource Cost Test in determining whether demand-side measures intended specifically to
assist residents of low income households to reduce their energy consumption (such as BC
Hydro’s Low Income Program) are cost effective, and to increase the benefits of such demand-
side measures by 40 per cent.
(b) Test Results Presented in Accordance with Requirements of Demand-Side Measures Regulation
557. The cost benefit test results at the program and portfolio levels are reported in
Table 9 of Appendix W of the Application,897 including standard Total Resource Cost Test,
modified Total Resource Cost Test and Utility Cost Test results. The modified Total Resource
Cost Test results have been calculated in the prescribed manner using BC Hydro’s long run
marginal cost and the total avoided cost benefits have been increased by 15 per cent.
897
Updated in Exhibit B-1-2, Errata No. 1 to the Application.
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558. The long-run marginal cost used is the cost of acquiring greenfield clean or
renewable IPP resources, which is estimated at $100/MWh (fiscal 2015$).898 This is based upon
BC Hydro’s most recent resource options updates, reflecting recent wind cost estimates.899 BC
Hydro’s response to BCSEA IR 1.15.1 provides the derivation of the long-run marginal cost and
other supporting values shown in Appendix X of the Application.900
559. The Total Resource Cost Test result for the Low Income program includes the
prescribed addition of 40 per cent to the benefits.
560. As noted at the bottom of Table 9, BC Hydro’s supporting initiative costs have
been allocated to Rate Structures and Programs. As detailed in Appendix V of the Application,
BC Hydro’s two supporting initiatives have costs, but do not have specific savings attributed to
them due to their nature as being in support of other initiatives. As such, it is not possible to
assess the cost effectiveness of supporting initiatives on a stand-alone basis.
(c) Test Results Demonstrate Cost Effectiveness
561. BC Hydro makes its decisions on cost effectiveness at the portfolio and program
level,901 which provides a full view of cost-effectiveness.902 The test results in Table 9 of
Appendix W show the following:
The portfolio as a whole is cost effective under the standard and modified Total
Resource Cost Test and the Utility Cost Test, with and without savings from
Codes and Standards.
898
Or $102/MWH in fiscal 2016$. 899
Exhibit B-1-1, Application, p. 3-46 and 3-47. 900
Exhibit B-10, BCSEA IR 1.15.1. 901
Exhibit B-9, BCUC IR 1.175.3. As noted in BC Hydro’s response to BCUC IR 1.184.3, BC Hydro’s software is not able to produce an output of expenditures and energy savings at the measure level; expenditures and energy savings are provided at the program level. To the extent BC Hydro has measured cost-effectivness at the measure or offer level, only the Energy Conservation Assistance Program basic offer does not pass the modified Total Resource Cost test (Exhibit B-9, BCUC IR 1.175.2.2; Exhibit B-14, BCUC IR 2.315.1).
902 Exhibit B-13, BCUC IR 2.320.2.1.
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All Codes and Standards, Rate Structures and Programs (including costs of
supporting initiatives) are cost effective under the standard and modified Total
Resource Cost test and, with the exception of the Low Income program, under
the Utility Cost test.
562. As noted above, the Low Income Program cannot be determined to be not cost
effective under the Utility Cost test. BC Hydro submits that the Demand-Side Management Plan
is cost effective based on these results.
(d) Supporting Initiatives Are Part of Cost Effective Tools and Portfolio
563. Supporting initiatives should be assessed on a portfolio basis.
564. As noted above, Section 4(5) of the Demand-Side Measures Regulation requires
the Commission to assess the cost effectiveness of a public awareness program on a portfolio
basis if satisfied it is likely to increase public awareness of ways to increase energy conservation
or efficiency, to encourage energy efficiency or conservation, or to increase participation in
proposed measures. BC Hydro’s Public Awareness Initiative, as described in Appendix V of the
Application, will increase public awareness of energy conservation and efficiency and increase
participation in BC Hydro’s proposed demand-side management tools.903 On this basis, BC
Hydro submits that the cost effectiveness of the Public Awareness Initiative costs must be
determined on a portfolio basis as required under subsection 4(5) of the Demand-Side
Measures Regulation. As shown in Table 9 of Appendix W, the portfolio is cost effective as a
whole.
565. BC Hydro’s Indirect and Portfolio Enabling Supporting Initiative consists of
activities that are necessary for the delivery of demand-side management, but are not specific
to individual programs. These activities are described in Appendix V of the Application. Due to
the nature of these costs, they cannot be attributed with particular energy savings, so that it is
not possible to assess cost effectiveness on a stand-alone basis. The cost must therefore be
903
Exhibit B-1-1, Application, Appendix V, Section 17, p. 37 to 39.
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assessed on a portfolio basis. The portfolio is cost effective as a whole as shown in Table 9 of
Appendix W.
(e) Capacity Focused Demand-Side Management is Part of a Cost-Effective Portfolio
566. As discussed in detail in the Final Submission above, Capacity Focused Demand-
Side Management is a critical activity that is justified based on the significant potential benefits
for ratepayers. There is insufficient information to assess the Capacity Focused Demand-Side
Management activity on a stand-alone basis as the expenditures are for pilots, and benefits
cannot be calculated at this time. However, if assessed on a portfolio basis, the capacity
focused pilot activity is cost effective as the portfolio remains cost effective under the standard
Total Resource Cost test, modified Total Resource Cost test, and Utility Cost Test if the
expenditures for the pilot activities are included.904
(f) Evidence filed in Information Requests Supports Cost Effectiveness Test Results
567. BC Hydro provided detailed information in support of its cost effectiveness
results in its Application and BC Hydro’s response to information requests support the cost
effectiveness results of its Demand-Side Management Plan. For example:
The formulas used to calculate the Total Resource Cost and modified Total
Resource Cost and Utility Cost Test results are the same for all demand-side
management tools: Codes and Standards, Rate Structures, and Programs. For
each initiative, where applicable, estimates are made for energy savings,
capacity savings, non-incentive program costs, incentive costs, customer costs,
non-energy benefits, natural gas impacts, etc.905 BC Hydro’s response to CEA IR
1.24.1 includes the cost effectiveness formulas.906
904
Exhibit B-14, BCUC IR 2.320.2. 905
Exhibit B-9, BCUC IR 1.178.1. 906
Exhibit B-10.
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BC Hydro’s response to BCSEA IR 1.16.1 provides a working spreadsheet that
shows how the cost effectiveness results are derived.907
The table and excel spreadsheets attached to BCUC IR 1.184.1, 1.184.3 and
1.184.4 provide a detailed account of the costs, savings, assumptions, cost
benefit results and other information on BC Hydro’s Demand-Side Management
Plan, supporting the cost effectiveness results.908
BC Hydro response to BCUC IR 1.175.1.1 provides a breakdown of the types of
benefits for each programs in the Demand-Side Management Plan.
BC Hydro methodologies for energy savings reporting and evaluation ensure that
that there is no double counting of energy savings from rate design changes.909
568. BC Hydro submits that the evidence in the proceeding is comprehensive and
shows that the cost-effectiveness test results of its Demand-Side Management Plan are
reasonable and based on sound assumptions and methodologies.
I. BC HYDRO’S EVALUATION, MEASUREMENT AND VERIFICATION PROCESSES ARE GUIDED BY INDUSTRY STANDARDS AND PROTOCOLS AND ARE NEUTRAL AND UNBIASED
569. Evaluation, measurement and verification is an integral part of a demand-side
management program. Measurement and verification is the quantification of individual project
energy savings through analysis of actual project operating and performance data.910
Evaluation is the refining of the demand-side management savings estimates at the program or
initiative level and the identification of program improvements in a rigorous and neutral
manner.911 As discussed in Appendix Z of the Application, BC Hydro’s evaluation, measurement
907
Exhibit B-9, BCUC IR 1.178.1. 908
Exhibit B-9. 909
Exhibit B-14, BCUC IR 2.315.3. 910
Exhibit B-1-1, Application, p. 10-49. 911
Exhibit B-1-1, Application, p. 10-50.
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and verification activities are guided by six principles: Neutrality, Professional Standards,
Qualified Practitioners, Appropriate Coverage or Specified Selection Criteria, Business
Integration and Coordination. As guided by these principles, BC Hydro’s evaluation,
measurement and verification processes are guided by industry standards and protocols and
are neutral and unbiased.
(a) Planned Evaluation, Verification And Measurement Activities Guided by Industry Best Practice
570. BC Hydro evaluation, measurement and verification activities are described in
Appendix Z. An updated evaluation, measurement and verification schedule is provided in
response to BCUC IR 1.192.2, showing the primary evaluation, measurement and verification
deliverables and their timing and total evaluation, measurement and verification costs by
program for the test period. Approximately $4 million in expenditures are forecast annually
over the test period for these activities.912
571. In accordance with BC Hydro’s principle of Professional Standards, BC Hydro’s
evaluation, measurement and verification activities are guided by industry standards and
protocols.913 In carrying out its measurement and verification work, BC Hydro is guided by the
International Performance Measurement and Verification Protocol, which is an internationally
accepted protocol for measurement and verification of energy saving projects.914 BC Hydro’s
evaluation methods are guided by the California Evaluation Protocols and Framework
(published in 2004), but also more recent evaluation material, such as the US Department of
Energy Uniform Methods Project Protocols, the International Performance Measurement and
Verification Protocol and other relevant protocols and standards.915 The California Evaluation
Framework and Protocols and the U.S. Department of Energy Uniform Methods Project
912
Exhibit B-9, BCUC IR 1.192.2. Also see Exhibit B-14, BCUC IR 2.328.1 and BCUC IR 2.328.2. 913
Exhibit B-1-1, Application, Appendix Z, p. 2 and 7-8. 914
Exhibit B-1-1, Application, p. 10-49 and Appendix Z, p. 8. 915
Exhibit B-9, BCUC IR 1.191.1.
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Protocols are generally regarded as the leading protocols for demand-side management
evaluation in North America.916
572. Two particular practices that were the subject of information requests were the
evaluation of savings persistence and sampling. As discussed below, BC Hydro’s practices are
reasonable and align with industry practice:
BC Hydro evaluates savings persistence where the costs and customer impacts of
doing so are outweighed by the benefits of increased certainty regarding savings
persistence. For instance, BC Hydro evaluated savings persistence for two
programs where savings persistence was less certain and the data was available
to evaluate persistence at modest additional cost and no additional customer
impact (e.g. through surveys or site visits). For other programs, BC Hydro
measures, verifies and evaluates first year savings and thereafter follows the
common industry practice of applying standard persistence values based on
available research.917 As shown in BC Hydro’s Standard for Effective Measure
Life and Persistence, standard values reflect extensive work undertaken in the
industry.918
BC Hydro commonly uses census or near census study of consumption and other
data to get reliable low cost evaluation analysis. Where census studies are cost
prohibitive, BC Hydro’s relies on sampling. BC Hydro’s approach to sampling
aligns with the guidance provided in the California Protocol on Sampling and
Uncertainty (2006) and other relevant industry standards including the US
Department of Energy Uniform Methods Project, and the Northeast Energy
Efficiency Partnership Model EM&V Methods Standardized Reporting Forms for
916
Exhibit B-1-1, Application, p. 10-50. 917
Exhibit B-14, BCUC IR 2.329.2. 918
Exhibit B-14, BCUC IR 2.329.2 and BCUC IR 2.329.2 Attachment 1.
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Energy Efficiency. BC Hydro designs and delivers sampling based studies to
minimize the sources of sampling bias and error.919
573. As exemplified above, BC Hydro’s approach to evaluation, measurement and
verification activities are guided by industry standards and protocols and reflect a reasonable
and cost effective approach.
(b) Neutral and Unbiased Verification and Evaluation
574. In accordance with BC Hydro’s principle of Neutrality, BC Hydro’s measurement,
verification and evaluation processes are designed to be neutral and unbiased.920 BC Hydro
ensures independence in its evaluation function through its organization structure and
oversight process.921 Organizationally, the Evaluation, Measurement, and Verification
departments are separate from, and have different managers than, the departments
responsible for the development and management of demand-side management programs and
initiatives. Both evaluation, and measurement and verification have oversight processes to
verify that products are neutral and align with industry practice. These processes are described
in Appendix Z, pp. 12-13 and BC Hydro’s response to BCUC IR 1.191.3.
575. All evaluation reports are reviewed by external demand-side management
evaluation advisors and reviewed and approved by a cross-BC Hydro committee, with external
evaluation advisors present as a resource.922 In addition, an external measurement and
verification advisor reviews a selection of measurement and verification reports.923 BC Hydro
has two qualified external evaluation advisors under contract. BC Hydro requires that its
919
Exhibit B-9, BCUC IR 1.191.2. 920
Exhibit B-1-1, Application, Appendix Z, pp. 2 and 7. 921
Exhibit B-1-1, Application, Appendix Z, pp. 11 to 12. 922
Exhibit B-1-1, Application, p. 10-50; Exhibit B-9, BCUC IR 1.191.3. 923
Exhibit B-1-1, Application, Appendix Z, p. 13; Exhibit B-14, BCUC IR 2.327.2.
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advisors do no other work for BC Hydro so that they have no material interest in the results of
BC Hydro’s evaluations.924
576. The California Framework’s stipulation that program evaluations be conducted
only by independent firms or organizations is not appropriate in BC Hydro’s context. Unlike in
B.C., most electricity in California is delivered by investor owned utilities with shareholder
incentive mechanisms for demand-side management. In this context, utilities were in a conflict
of interest with respect to the evaluation of demand-side management programs, since
evaluation results impacted shareholder incentive payments.925 BC Hydro, however, is a Crown
corporation without an incentive mechanism for demand-side management and is not in a
conflict of interest with respect to the evaluation of demand-side management programs.
Without a demand-side management incentive mechanism, BC Hydro does not profit from the
over estimation of demand-side management savings. 926
577. Instead, BC Hydro conducts program evaluation using a mix of BC Hydro
employees and external consultants and contractors. This allocation of work helps BC Hydro
control evaluation costs by limiting higher cost consultants to where the evaluation work is too
infrequent to justify a full-time employee. Use of internal employees also enables information
exchange between program managers and evaluators, which improves program design and
management.927
J. CONCLUSION AND REQUESTED FINDINGS
578. The evidence outlined in this Part supports BC Hydro’s demand-side
management expenditure schedule for the test period. BC Hydro’s proposed Demand-Side
Management Plan reflects a broad, modernized and cost-effective range of demand-side
management initiatives that provide significant energy and capacity savings and promotes
924
Exhibit B-14, BCUC IR 2.327.1. 925
Exhibit B-9, BCUC IR 1.191.1. 926
Exhibit B-9, BCUC IR 1.191.1. 927
Exhibit B-9, BCUC IR 1.191.1.
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British Columbia’s Energy Objectives. The Demand-Side Management Plan appropriately
extends the moderation strategy recommended in the 2013 Integrated Resource Plan for three
more years, in light of the reduced rate of growth of demand for electricity in the short-term,
the requirements of the 2013 10 Year Rate Plan and other factors. Capacity Focused Demand-
Side Management is a critical investment, offering the potential for significant savings by
deferring the need for pumped storage generation capacity and upgrades to local
infrastructure, while offering customers the opportunity to control their costs. BC Hydro is
addressing barriers in non-integrated areas and First Nations communities. BC Hydro manages
the performance of the Demand-Side Management Plan in a comprehensive manner that
includes tracking performance metrics, identification of risk and mitigation, and neutral and
unbiased evaluation, measurement and verification processes. The Commission should accept
the expenditure schedule as being in the public interest.
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PART THIRTEEN: CONCLUSION AND ORDER SOUGHT
A. ADJUSTMENTS TO THE ORDERS SOUGHT IN THE APPLICATION
579. BC Hydro respectfully submits that the Commission should grant the approvals
sought. The approvals sought are generally described in Chapter 1 of the Application, with the
exception that:
There is a typographical error in Chapter 1, referring to the depreciation rates for
the Burrard Facility for fiscal 2015 and fiscal 2016, instead of identifying the
years of the test period.
BC Hydro indicated in its response to BCUC IR 1.131.3 that it would not be
opposed to a directive requiring the deferral to the Non-Heritage Deferral
Account of all test period variances attributable to Electricity Purchase
Agreements classified as finance leases that would not be transferred to existing
regulatory accounts pursuant to existing orders. BC Hydro has deferred
favourable variances in fiscal 2017 based on this approach, which benefitted
ratepayers.
BC Hydro clarified in response to BCUC IR 1.141.4.1 that it is seeking approval to
recover lump sum settlements to two First Nations that are not included in the
definition of First Nations settlements as set out in Direction No. 7. BC Hydro’s
proposed accounting treatment and recovery mechanism are included as part of
its proposals regarding the First Nations Costs Regulatory Account, and are
discussed in Part Nine E of the Final Submission.928
BC Hydro did not believe it was necessary to list in its draft order a specific
approval of the amount of the Heritage Payment Obligation or the baseline
forecast amounts of deferral and regulatory accounts, variances from which are
928
Exhibit B-9, BCUC IR 1.141.4.1, BCUC IR 1.141.7, BCUC IR 1.141.10, and confidential versions in Exhibit B-9-1; Exhibit B-14, BCUC IR 2.287.9.
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301539.00014/91303997.1
to be recorded in the relevant accounts.929 The approval of the proposed
revenue requirements includes the forecast Heritage Payment Obligation for
each test year. Approval to record any variance between the forecast and actual
Heritage Payment Obligation in the Heritage Deferral Account and to record
variances between forecast and actual amounts in other accounts is included in
the terms of the proposed deferral and regulatory accounts, as described in
Chapter 7 of the Application. However, if the Commission considers that such a
specific approval is warranted, Table 7-3 in the Application as corrected in Errata
No.2930 sets out the baseline forecasts that should be approved.931
As discussed in Part Nine, Sections E and F of this Final Argument, BC Hydro
clarifies that it is proposing to continue the attraction and recovery of interest
charges on the Storm Restoration Costs, Amortization of Capital Additions and
SMI Regulatory Accounts. The attraction and recovery of the interest on these
accounts is consistent with past treatment of these accounts and is reflected in
BC Hydro’s revenue requirements as shown in the Appendix A of the Application
and detailed in BC Hydro’s responses to information requests.932
The timing of BC Hydro’s forecast expenditures on the Thermo-Mechanical Pulp
program was updated in BC Hydro’s response to BCUC IR 2.314.3. The result is
that a total of $41.9 million in expenditures for this program is now forecast over
the test period, compared to the $55.8 million forecast at the time the
Application was filed. This reduces BC Hydro’s section 44.2 demand-side
929
Exhibit B-9, BCUC IR 1.127.1. 930
Exhibit B-1-3. The corrected version includes baseline forecast of Liquefied Natural Gas Revenue, variances from which are recorded in the Non-Heritage Deferral Account.
931 However, these amounts may change if the Commission does not approve other aspects of BC Hydro’s Application. E.g., if the Commission did not approve BC Hydro’s request to be at risk for the variance related to First Nations negotiating costs, then the updated Heritage Payment Obligation is provided in response to BCUC IR 2.287.6.
932 Exhibit B-1-1, Appendix A, Financial Schedules; Exhibit B-9, BCUC IR 1.124.11, p. 4-5 of 7 (re: SMI); Exhibit B-14, BCUC IR 2.276.1, p. 1 of 11 (re: Storm Restoration Costs); and Exhibit B-14, BCUC IR 2.276.1, p. 2 of 11 (re: Amortization of Capital Additions).
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management expenditure schedule by $13.9 million, to a total of $361.1
million.933
580. BC Hydro made a number of commitments to address matters in its Compliance
Filing for this Application. Specifically, BC Hydro will:
Correct land costs that were included, due to a clerical error, in certain capital
projects for the purpose of calculating amortization for the test period;934
Update Appendix A to include forecast revenues related to the Northwest
Transmission Line Supplemental Charge, for the benefit of ratepayers;935
Update Appendix A to reflect BC Hydro’s proposal in regards to the treatment of
Polychlorinated Biphenyl costs, which has no net effect on the revenue
requirements;936
Update Appendix A to account for minor reductions due to the fact that OIC No.
590 does not include decimal places (whereas BC Hydro’s financial schedules are
to the first decimal place);937
Reflect the the updated forecast expenditures on the Thermo-Mechanical Pulp
program referenced in BCUC IR 2.314.3;
Revise Appendix A to reflect the immaterial impact of the revised Maximum
Capacity Supply (MW) in Errata 1;938 and
933
Exhibit B-14, BCUC IR 2.314.3. 934
Exhibit B-9 BCUC 1.103.5, BCUC 2.264.1. 935
Exhibit B-10 MoveUP IR 2.1.1. 936
Exhibit B-9, BCUC 1.138.5, BCUC 2.282.1.1. 937
Exhibit B-2, Evidentiary Update. 938
Exhibit B-1-2, Errata No. 1 to the Application.
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Reflect in the Transmission Revenue Requirement the functionalization of
demand-side management costs approved in Order No. G-47-16.939
581. The items listed above will have an impact on the amounts to be transferred to
the Rate Smoothing Regulatory Account pursuant to Direction No. 7 and the rate of return
required to achieve the distributable surplus prescribed by Order-in Council No. 590. In its
Compliance Filing to the Commission, BC Hydro proposes to recalculate its revenue
requirements based on the updates, errata and commitments listed above, and any directives
from the Commission, and update the amounts to be transferred to the Rate Smoothing
Regulatory Account and rate of return required to achieve the prescribed distributable surplus.
B. RESTATED FORM OF ORDER
582. The specific form of Final Order, originally included in Appendix T of the
Application, has been restated below to reflect BC Hydro’s updates, errata and commitments
during the proceeding:
1. The requested final rate increases of 4 .0 per cent, 3.5 per cent and 3.0 per cent, to be applied as set out in Appendix T of the Application, are approved effective April 1, 2016, April 1, 2017 and April 1, 2018, respectively.
2. The requested final OATT rates for fiscal 2017, fiscal 2018, and fiscal 2019 as set out in Appendix T of the Application, as corrected in Errata No. 1 (Exhibit B1-2) are approved effective April 1, 2016, April 1, 2017 and April 1, 2018, respectively. The difference between the final OATT rates and the interim refundable OATT rates is to be collected from applicable OATT customers through a one-time charge as described in Chapter 9 of the Application.
3. BC Hydro is directed to re-calculate its revenue requirements, including its rate of return, based on the updates, errata and commitments made by BC Hydro as summarized in Part Thirteen of its Final Submission and any Commission directives in the proceeding.
939
Exhibit B-9, BCUC IR 1.161.2, and 1.162.1.
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4. Pursuant to Direction No. 7, BC Hydro is directed to record in the Rate Smoothing Regulatory account for each year of the test period the difference between BC Hydro’s recalculated revenue requirements and the revenues expected to be collected under the approved rates.
5. The requested depreciation rates for property, plant and equipment at the Burrard Synchronous Condense facility as set out in Table 8-1 of the Application are approved.
6. The requested changes to deferral and regulatory accounts and associated financial treatment, as described in Chapter 7, summarized in Table 7-9 of the Application and clarified in Part Nine E and F of the Final Submission, are approved.
7. The requested demand-side management expenditure schedule for fiscal 2017, fiscal 2018 and fiscal 2019, as set out in Table 10-1 of the Application and revised in BC Hydro’s response to BCUC IR 2.314.3, is accepted, for a total expenditure over the test period of $361.1 million.
8. BC Hydro will comply with all other directives in the Decision accompanying this Order.
9. BC Hydro is directed to file within 60 days of this order a revised Appendix A to the Application and updated rate schedules, reflecting the Commission’s Order and Decision and BC Hydro’s commitments articulated in Part Thirteen of its Final Submission.
C. RATES ARE JUST AND REASONABLE AND DEMAND-SIDE MANAGEMENT PLAN IS IN THE
PUBLIC INTEREST
583. The requested permanent rate increases are just and reasonable, reflecting the
rate caps specified in Direction No. 7. BC Hydro’s forecast revenue requirements reflect BC
Hydro’s significant effort to manage and control costs in order to deliver on the 2013 10 Year
Rates Plan. They represent BC Hydro’s reasonable cost of investing in the system and providing
safe and reliable service to customers in the test period. BC Hydro’s requested demand-side
management expenditure schedule is in the public interest. It reflects a modernized and more
cost effective Demand-Side Management Plan that continues broad demand-side management
and that is responsive to changing system needs and the 2013 10 Year Rates Plan, while
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retaining the ability to ramp up in the future as needed. Granting the orders sought will
position BC Hydro to deliver on the 2013 10 Year Rates Plan, balancing customers’ interests in
both low rates and re-investment in a safe and reliable service.
ALL OF WHICH IS RESPECTFULLY SUBMITTED.
Dated: May 23, 2017 [original signed by Matthew Ghikas]
Matthew Ghikas Counsel for BC Hydro
Dated: May 23, 2017 [original signed by Chris Bystrom]
Chris Bystrom Counsel for BC Hydro
Dated: May 23, 2017 [original signed by Tariq Ahmed]
Tariq Ahmed Counsel for BC Hydro
301539.00014/91305014.2
APPENDIX A:
EVIDENCE SUPPORTING CAPITAL PROJECTS ADDRESSED IN INFORMATION REQUESTS
301539.00014/91305014.2
TABLE OF CONTENTS
A. INTRODUCTION ........................................................................................................................... 1
B. HYDROELECTRIC GENERATION – GROWTH ................................................................................ 1
(a) Revelstoke Install Unit 6 Project .................................................................................... 1
C. HYDROELECTRIC GENERATION – REDEVELOPMENT ................................................................... 2
(a) Decommissioning of the Salmon River Diversion .......................................................... 2
(b) Clowhom Rehabilitate Generating Station .................................................................... 3
D. HYDROELECTRIC GENERATION – DAM SAFETY ........................................................................... 4
(a) W.A.C. Bennett Spillway Gate Upgrade and W.A.C. Bennett Dam
Recommission/Seal Spillway Sluice Gates ..................................................................... 4
(b) John Hart Dam Seismic Upgrade .................................................................................... 5
(c) Ladore Spillway Seismic Upgrade................................................................................... 8
E. HYDROELECTRIC GENERATION – SUSTAINING ............................................................................ 9
(a) Bridge River 2 Upgrade Units 5 and 6 Project, and Bridge River 2 Upgrade Units 7
and 8 Project .................................................................................................................. 9
(b) The Cheakamus Units 1 and 2 Generator Replacement Project and the
Cheakamus Upgrade Fire Protection Project ............................................................... 14
(c) GM Shrum 1–10 Control System Upgrade ................................................................... 15
(d) Mica Modernize Controls ............................................................................................. 16
(e) Mica Replace Units 1 to 4 Generator Transformers .................................................... 18
(f) Seven Mile Overhaul Units 1 to 3 Turbines .................................................................. 19
(a) Mica SF6 Gas-insulated Switchgear Replacement ....................................................... 20
(b) Alouette and Elko Generating Stations and Shuswap Unit 1 ....................................... 22
F. THERMAL - BURRARD FACILITY CONVERSION .......................................................................... 24
G. TRANSMISSION – GROWTH CAPITAL ........................................................................................ 24
(a) Horne Payne Substation Upgrade ................................................................................ 24
(b) Fort St. John and Taylor Electric Supply ....................................................................... 27
(c) West Kelowna Transmission Project and Westbank Substation Upgrade Project ...... 28
(d) Peace Region Electric Supply ....................................................................................... 30
(e) Project A and Project B ................................................................................................ 36
(f) Northwest Substation Upgrades Project and Customer Requested Projects .............. 39
301539.00014/91305014.2
(g) Peace Region to Kelly Lake 500kV Transmission Reinforcement................................. 40
(h) Big Bend Substation ..................................................................................................... 42
H. TRANSMISSION – SUSTAINING CAPITAL ................................................................................... 44
(a) Terrace to Kitimat Transmission .................................................................................. 44
(b) Mainwaring Substation Upgrade ................................................................................. 45
I. Distribution – Distribution Automation .................................................................................... 46
J. TECHNOLOGY ............................................................................................................................ 48
(a) Supply Chain Applications Project ............................................................................... 48
(b) Technology Projects Driven By North American Electric Reliability Corporation
Critical Infrastructure Protection Version 5 ................................................................. 49
(c) Enterprise Billing Infrastructure Project ...................................................................... 51
(d) Graphic Work Design Tool Project ............................................................................... 53
(e) Data Centre Refresh Project ........................................................................................ 55
(f) Sustainment of Smart Metering and Infrastructure Program Assets .......................... 55
K. PROPERTIES ............................................................................................................................... 56
(a) Vernon Field Building Project and Victoria Field Building Project ............................... 56
(b) Chilliwack Field Building Project .................................................................................. 56
(c) Construction Services/Lower Mainland Transmission Building Project and
Material Classification Facility Project ......................................................................... 58
L. OTHER CAPITAL ......................................................................................................................... 59
(a) Fleet/Vehicles/Materials Management ....................................................................... 59
M. SMALL PROJECTS (LESS THAN $5 MILLION) .............................................................................. 60
(a) Generation ................................................................................................................... 60
(b) Transmission ................................................................................................................ 60
(c) Distribution .................................................................................................................. 62
N. CONCLUSION ............................................................................................................................. 62
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APPENDIX A: EVIDENCE SUPPORTING CAPITAL PROJECTS ADDRESSED IN INFORMATION REQUESTS
A. INTRODUCTION
1. The Revenue Requirements Application proceeding has provided the
Commission and interveners with an opportunity to review BC Hydro’s capital portfolio in
considerable detail. This Appendix addresses a number of individual capital projects that were
the subject of multiple information requests, and consolidates the evidence for ease of review.
BC Hydro addressed all of the issues raised, providing complete and compelling responses. The
evidence, summarized below, demonstrates that BC Hydro is proceeding with its capital
projects in a reasonable manner and that the forecast additions associated with these capital
projects are in the public interest and reasonably included as part of BC Hydro’s test period
revenue requirements.
B. HYDROELECTRIC GENERATION – GROWTH
(a) Revelstoke Install Unit 6 Project
2. The Revelstoke Install Unit 6 Project is described on line 1 of page 1 of
Supplemental Appendix I-A1 and page 1 of Appendix J of the Application. The scope of this
project is to install a 500 MW unit in the existing empty unit 6 bay at Revelstoke. Revelstoke 6
is a unique low cost capacity option for BC Hydro.2 Pursuant to section 7 of the Clean Energy
Act, the project is exempt from sections 45 to 47 of the Utilities Commission Act, and the
Commission “must not exercise a power under the Utilities Commission Act in a way that would
directly or indirectly prevent the authority from [carrying out the Revelstoke Install Unit 6
Project]”.3
1 Exhibit B-6.
2 Exhibit B-9, BCUC IR 1.81.3.
3 Exhibit B-9, BCUC IR 1.81.10.
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3. The Revelstoke Install Unit 6 Project is not required to be in service during the
test period.4 Capital expenditures are planned, however, to advance the project as a
contingency resource for its earliest in-service date in fiscal 2022, or to meet load requirements
in fiscal 2027. Capital expenditures totaling $4 million are required during the test period to
complete the following activities:5
Prepare the Environmental Assessment Application, complete the related review
process and obtain the Environmental Assessment Certificate; and
Conduct stakeholder engagement and First Nations consultation related to the
Environmental Assessment Application.
4. The planned timing of the Environmental Assessment Application approximately
5 years before the earliest in-service date is consistent with BC Hydro’s experience with the
Revelstoke Unit 5 Project and Mica Unit 5 and 6 Project, which took between 4 and over 5 years
between the filing of the environmental assessment application and the in-service date.6 BC
Hydro’s response to BCUC IR 1.81.4 provides a summary of the other activities required to
support the earliest in-service date for the Revelstoke Install Unit 6 Project. Given the inclusion
of this project in Section 7 of the Clean Energy Act, BC Hydro’s expenditures over the test
period on this project must be included in the revenue requirements.
C. HYDROELECTRIC GENERATION – REDEVELOPMENT
(a) Decommissioning of the Salmon River Diversion
5. BC Hydro’s Certificate of Public Convenience and Necessity (“CPCN”) Application
for the John Hart Generating Station Replacement Project included Salmon River diversion
costs.7 BC Hydro decided, however, not to pursue the Salmon River diversion.8 BC Hydro has
4 Exhibit B-9, BCUC IR 1.81.1,
5 Exhibit B-9, BCUC IR 1.81.1.
6 Exhibit B-9, BCUC IR 1.81.4 and 1.81.5.
7 Exhibit B-15, CEA IR 2.40.2.
8 Exhibit B-10, CEA IR 1.16.1.
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filed an application to the Commission under section 41 of the Utilities Commission Act for
permission to cease operation of the Salmon River diversion in March 2017.9 As the section 41
application is currently before the Commission, BC Hydro will not address it further in this Final
Submission.
(b) Clowhom Rehabilitate Generating Station
6. The Clowhom Rehabilitate Generating Station Project is listed on line 4 of
Supplemental Appendix I-A,10 and described on page 7 of Appendix J of the Application. The
purpose of the project is to rehabilitate the Clowhom Generating Station to enable it to provide
reliable, dependable energy and capacity. The in-service date for the Clowhom Rehabilitate
Generating Station Project was delayed as a result of the reduction in planned capital additions
due to the cost pressures associated with meeting BC Hydro’s 2013 10 Year Rates Plan. There
are no capital additions forecast for the test period and the construction start date of the
project is expected to be outside the test period.11
7. As of September 30, 2016, the Project is still in the Identification Phase which
means that the project is not sufficiently advanced to have a preferred alternative and there is
insufficient information on the scope to establish a full project schedule.12 The $90.9 million
planning allowance represents a planning allowance forecast that is needed for capital planning
purposes when no formal cost estimate for the project is yet available.13 As the Project
progresses and an Authorized Amount is established, BC Hydro will confirm if the Project meets
the threshold in the Capital Project Filing Guidelines.14
9 Exhibit B-10, CEA IR 1.16.1.
10 Exhibit B-6.
11 Exhibit B-1-1, Appendix J, p. 7; Exhibit B-6, Supplemental Appendix I-A - Generation, line 4; Exhibit B-9, BCUC IR
1.84.2. 12
Exhibit B-9, BCUC IR 1.84.3. 13
Exhibit B-9, BCUC IR 1.84.2. 14
Exhibit B-9, BCUC IR 1.84.4.
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D. HYDROELECTRIC GENERATION – DAM SAFETY
(a) W.A.C. Bennett Spillway Gate Upgrade and W.A.C. Bennett Dam Recommission/Seal Spillway Sluice Gates
8. The W.A.C. Bennett Spillway Gate Upgrade Project is described on line 10 of
page 1 of Supplemental Appendix I-A15 and page 12 of Appendix J of the Application. The
W.A.C. Bennett Dam Recommission/Seal Spillway Sluice Gates Project is described on line 23 of
page 1 of Supplemental Appendix I-A.16 These two projects are different in scope and
justification and are in two very different phases of the project lifecycle. They are reasonably
proceeding as separate projects.
9. The two projects involve different sets of gates at the W.A.C. Bennett Dam. They
address different drivers, will involve significantly different scope of work, and have
independent justifications:17
The W.A.C. Bennett Spillway Gate Upgrade Project pertains to the three main
Spillway Gates. It addresses the more immediate concerns associated with
deteriorated conditions and potential common cause failures associated with
selected electrical, mechanical, protection and control equipment. It focuses on
the electrical, mechanical and protection and control equipment of the Spillway
Gates to ensure the gates operate safely and reliably when called upon for flood
control management.18 This project is currently in the Definition Phase. The
Definition Phase is forecast to be complete at the end of the first quarter of fiscal
2018.19
The W.A.C. Bennett Dam Recommission/Seal Spillway Sluice Gates Project
pertains to the nine sluice gates located lower in the dam below the spillway
15
Exhibit B-6. 16
Exhibit B-6. 17
Exhibit B-9, BCUC IR 1.85.1. 18
Exhibit B-9, BCUC IR 1.85.1. 19
Exhibit B-9, BCUC IR 1.85.3, 1.85.4.
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301539.00014/91305014.2
gates. The sluice gates are not required for flood control. The original purpose of
these gates was to provide compensation flows during construction. The sluice
gates are not currently in service and are not currently part of BC Hydro’s normal
operations. An engineering study is required to determine the future need for
the sluice gates and to determine whether or not some or all of the sluice gates
should be re-commissioned or decommissioned.20 As of September 30, 2016,
the W.A.C. Bennett Dam Recommission/Seal Spillway Sluice Gates project is still
in Future Phase.21
10. Since the scope of work, life cycle and risk profiles of the projects are
significantly different, there would be minimal benefits of grouping the two projects together.
Furthermore, grouping projects with different risk profiles could pose increased risk to the
operating facility by extending the time to address each hazard and risk leading to an extended
project in-service date.22
11. Based on the threshold for generation projects of $100 million in BC Hydro’s
Capital Project Filing Guidelines, the projects would not be expected to be submitted as a CPCN
or section 44.2 application, either separately or together.23 The higher range of costs for both
projects combined would not exceed $50 million.24
12. The two projects are therefore reasonably proceeding as separate projects and
should be reviewed in the revenue requirements process in the ordinary course.
(b) John Hart Dam Seismic Upgrade
13. The John Hart Dam Seismic Upgrade Project is listed on line 13 of page 1 of
Supplemental Appendix I-A,25 and described on pages 13-14 of Appendix J of the Application.
20
Exhibit B-9, BCUC IR 1.85.1. 21
Exhibit B-9, BCUC IR 1.85.2. 22
Exhibit B-9, BCUC IR 1.85.1. 23
Exhibit B-9, BCUC IR 1.85.7. 24
Exhibit B-9, BCUC IR 1.85.6. 25
Exhibit B-6.
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301539.00014/91305014.2
The purpose of the project is to upgrade the John Hart Dam to reliably withstand severe
earthquake loading. This project has a forecast in-service date of fiscal 2020. As of September
30, 2016, the project is still in the Identification Phase and has a planning allowance of $408.2
million.26 Given the need to seismically upgrade this Extreme consequence dam, the planned
expenditures to advance the project over the test period are reasonable and appropriately
included in BC Hydro’s test period revenue requirements. Based on the current Capital Filing
Guidelines, BC Hydro will file an application for acceptance of the capital expenditures for the
project under section 44.2 of the Utilities Commission Act.
14. The need for the John Hart Dam Seismic Upgrade Project is clear. The John Hart
Dam is classified as an Extreme consequence dam and the expected seismic performance under
the 2007 Canadian Dam Association Guidelines is for no uncontrolled release for the
“Maximum Design Earthquake ground motion”. The Deficiency Investigation Report completed
in 2012, and filed as BCUC IR 1.8.2.6 Attachment 1 and Attachment 2, identified that seismic
upgrades are required for the existing Intake Dam, the Middle Earthfill Dam, the Concrete Dam
and the North Earthfill Dam. The Deficiency Investigation Report also identified a number of
key uncertainties in the characterization of the foundation soils that could impact the option
development and selection (and costs) at both the Middle Earthfill and North Earthfill Dams.27
As stated in Appendix J:
The withstand of the various component dams and spillway gate system is significantly less than the Maximum Design Earthquake, and damage from a seismic event could lead to uncontrolled release of the reservoir. Therefore, seismic upgrades to the dams and spillway gates system are required. There is also a potential for overtopping of the facility due to a flow imbalance situation with the upstream Ladore plant. A free overflow spillway will be constructed to address this concern.28
15. BC Hydro initiated the project in 2011, starting with a field investigations
program to collect additional soil samples to better characterize the behaviour of the
26
Exhibit B-9, BCUC IR 1.82.1, BCUC IR 1.82.2, 1.82.4 and 1.82.5., Exhibit B-6, page 1, line 13. 27
Exhibit B-9, BCUC IR 1.82.6. 28
Exhibit B-1-1, Appendix J, p. 13.
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foundation soils. The John Hart Dam Seismic Upgrade Project was first included in a
Commission filing in the Fiscal 2012-Fiscal 2014 Revenue Requirements Application, which
described the need for seismic upgrades.29
16. BC Hydro plans for a total of approximately $24 million in expenditures over the
test period.30 The activities on the project anticipated to be completed during the test period
include:
(a) Complete feasibility level designs concluding the Identification Phase of the
project; and
(b) Advance project definition which consists primarily of preliminary level designs
and the regulatory approval process.
17. These activities include extensive field and laboratory investigations and analysis
such as surveying, borehole drilling, materials testing, and site inspections. In addition, project
management, construction planning, permitting, First Nations consultation, and stakeholder
engagement activities will also be performed.31
18. The John Hart Generating Station Replacement Project does not duplicate or
replace the scope of work included in the John Hart Dam Seismic Upgrade Project.32 The John
Hart Replacement Project and the John Hart Dam Seismic Upgrade Project are part of a suite of
projects contemplated on the Campbell River System. These projects will address Dam Safety
and seismic risks through the Campbell River System, and have been planned in the context of
the overall needs and risks on the Campbell River System. These risks were identified in
comprehensive reviews of the Campbell River System. The long term risk reduction strategy for
the Campbell River System being adopted by BC Hydro is based on these reviews.33
29
Exhibit B-9, BCUC IR 1.82.7. 30
Exhibit B-6, Supplemental Appendix I-A - Generation, page 1, line 13. 31
Exhibit B-9, BCUC IR 1.82.3. 32
Exhibit B-9, BCUC IR 1.82.8. 33
Exhibit B-9, BCUC IR 1.82.8.
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19. The planning allowance of over $400 million for the John Hart Dam Seismic
Upgrade Project indicates that the project will exceed the thresholds in BC Hydro’s current
Capital Project Filing Guidelines.34 The John Hart Dam Seismic Upgrade Project will therefore
be the subject of a separate application for review by the Commission.
(c) Ladore Spillway Seismic Upgrade
20. The Ladore Spillway Seismic Upgrade Project is listed on line 14 of page 1 of
Supplemental Appendix I-A,35 and described on page 15 of Appendix J of the Application and is
not expected to be in-service during the test period.36 BC Hydro’s approach to proceeding with
the project separate from other projects related to the Ladore Facility is reasonable and cost
effective.
21. The strategy for the Ladore Facility is to address the most pressing reliability risks
associated with major generating equipment and to address dam safety concerns identified by
the Dam Safety Investigation. The findings and recommendations of the most recent condition
assessments for the Ladore Facility, as summarized in BC Hydro’s response to BCUC IR 2.258.3,
shows that there is equipment with different heath ratings (Good to Fair), spillway components
with different condition assessments (Poor to Fair); and structures with differing seismic
withstands. BC Hydro’s investment strategy enables the replacement of equipment in Poor
condition while continuing to extract value from the equipment in Good and Fair condition. This
approach addresses the more urgent reliability risks, while preserving assets that do not require
further investment at this time.37
22. The Ladore Spillway Seismic Upgrade Project is for work associated with the
spillway gates and hoist structure of the Ladore Facility.38 A recently completed dam safety
34
Exhibit B-9, BCUC IR 1.82.1, BCUC IR 1.82.2, 1.82.4 and 1.82.5. 35
Exhibit B-6. 36
Exhibit B-1-1, Appendix I, page 1, line 14, Appendix J, page 15. 37
Exhibit B-9, BCUC IR 1.86.4, 1.86.4.1. The Facility Asset Plan for Ladore was provided as an attachment to BCUC IR 1.86.6.
38 Exhibit B-9, BCUC IR 1.86.2.
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investigation has confirmed the need for the project.39 The Ladore Spillway Seismic Upgrade
Project is in the Identification Phase and will design and construct upgrades to ensure reservoir
retention for the maximum design earthquake and to permit post-seismic gate operation to
pass any Campbell River System emergency drawdown flows, as well as annual inflows, in a
controlled manner. Spillway gate reliability improvements for normal operating conditions will
also be carried out.40
23. Grouping all the Ladore projects together and filing a single application with the
Commission would not be feasible, as the drivers and timeline for each of the Ladore projects
are different.41 For example, the Ladore Unit 1 Redevelopment Project is a future project. For
initial planning purposes, this project has a capital planning allowance of $45 million based on a
project scope that includes upgrading or replacing the generator, turbine, governor and
transformer. There is still a high degree of uncertainty with respect to the scope, cost and
schedule.42 Grouping this project with the Ladore Spillway Seismic Upgrade Project would
unnecessarily delay and complicate the needed seismic upgrade work at the Ladore Facility.
24. As various projects relate to the Ladore Facility proceed to the Implementation
Phase and an Authorized Amount for each of the projects becomes available, a determination
will be made as to the requirement for a CPCN or Section 44.2 filing, in accordance with the
Capital Project Filing Guidelines.43
E. HYDROELECTRIC GENERATION – SUSTAINING
(a) Bridge River 2 Upgrade Units 5 and 6 Project, and Bridge River 2 Upgrade Units 7 and 8 Project
25. The Bridge River 2 Upgrade Units 5 and 6 Project and Bridge River 2 Upgrade
Units 7 and 8 Project are listed on lines 34 and 44 of page 1 of Supplemental Appendix I-A, and
39
Exhibit B-14, BCUC IR 2.258.4. 40
Exhibit B-14, BCUC IR 2.258.4. 41
Exhibit B-14, BCUC IR 2.258.4. 42
Exhibit B-4, BCUC IR 2.258.2. 43
Exhibit B-14, BCUC IR 2.258.4.
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are described on pages 22 and 29 of Appendix J of the Application, respectively. The primary
drivers for these projects are the lost capacity, unacceptable condition and unreliability of the
Bridge River 2 generators and other major unit equipment.44 The two projects have different
scope and timing, and are appropriately being carried out as two separate projects. The
projects have historically been planned as separate projects due to differences in reliability of
the generating stations, and must continue in this fashion to minimize the length of overall
outages and the impacts on water management in the system.45
Timing and Scope Differences of Projects
26. The Bridge River 2 Upgrade Units 5 and 6 Project is currently in the Definition
Phase, and BC Hydro plans to seek Board of Director financial approval of the Implementation
Phase funding in 2017.46 The purpose of the Bridge River 2 Upgrade Units 5 and 6 Project is to
restore the reliability of the Units 5 and 6 generators, which will restore 54 MW of capacity and
31 GWh of average annual energy. The project currently includes replacing the generators,
governors, exciters, unit circuit breakers and other ancillary equipment. Work on the turbines is
not included in the scope of work for this Project, and is not anticipated to be considered.47 A
cost/benefit analysis completed during Definition Phase indicates that the Net Present Value is
$43 million (net benefit).48 The target in-service date is in fiscal 2019.49
27. In contrast, the Bridge River 2 Upgrade Units 7 and 8 Project started
Identification Phase in June 2016 and a preferred alternative has not yet been finalized. The
purpose of this project is to restore the reliability of the Unit 7 and 8 generators and their
ancillary systems, as well as the reliability of other major components such as the circuit
breakers.50 The components that are currently under consideration as part of this project
44
Exhibit B-9, BCUC IR 1.88.1. 45
Exhibit B-14, BCUC IR 2.261.1. 46
Exhibit B-9, BCUC IR 1.88.4. 47
Exhibit B-9, BCUC IR 1.88.1. 48
Exhibit B-15, BCOAPO IR 2.82.1. 49
Exhibit B-9, BCUC IR 1.88.5. 50
Exhibit B-1-1, Appendix J, p. 29.
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include the generators, unit circuit breakers, turbines and other ancillary equipment.51 During
the Definition Phase, which is planned to commence in fiscal 2019, BC Hydro will determine
when it will seek Board of Director financial approval for the Implementation Phase funding.52
The Two Projects are Driven by Different Reliability Needs
28. The Bridge River 2 facility has four generating units: Units 5, 6, 7 and 8.53 Design
differences between Units 5 and 6 and Units 7 and 8 have resulted in investments to address
reliability issues for each set of units, rather than a full plant approach. This investment
approach has resulted in differences in the overall reliability of the Units 5 and 6 versus the
Units 7 and 8.54
29. The two projects were planned separately due to the differences in the reliability
of Units 5 and 6, compared to Units 7 and 8. As explained below, the timing difference
between the two projects has now been compressed due to changing circumstances:55
Historically, the primary reason BC Hydro did not combine the generator replacements for Bridge River 2 Units 5 and 6 with Units 7 and 8, was due to the difference in reliability between the two sets of generators. The Unit 5 stator had failed twice prior to 1990, and it was expected that based on its condition, further failures were likely for Unit 5 and possibly Unit 6 (which is of the same age and design). The reliability of the Units 7 and 8 generators has historically been better than Units 5 and 6. This difference in reliability meant that investment in the Units 7 and 8 generators could be deferred.
The Bridge River 2 Units 5 and 6 Upgrade Project was started in March 2007 and deferred in April 2009 due to internal resource constraints. The Units 5 and 6 Upgrade Project was restarted in May 2013, following a stator winding failure on Unit 6 in fiscal 2012. At both times, in March 2007 and in May 2013, when work on the Units 5 and 6 Upgrade Project had commenced, the Units 7 and 8 generators continued to be in better condition than the Units 5 and 6
51
Exhibit B-9, BCUC IR 1.88.1. 52
Exhibit B-9, BCUC IR 1.88.4. 53
Exhibit B-9, BCUC IR 1.88.1. The Facility Asset Plan for Bridge River was provided as an attachment to BCUC IR 1.88.6
54 Exhibit B-9, BCUC IR 1.88.1.
55 Exhibit B-9, BCUC IR 1.88.7.
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generators, and a decision was made to continue deferring investment in the Units 7 and 8 generators.
In July 2015, the Unit 8 generator stator was damaged due to a bus fault. Following repair of the generator and investigation of the failure, the Bridge River 2 Units 7 and 8 Upgrade Project was started in June 2016, with an expected in-service date in fiscal 2023. At this time, the Units 5 and 6 Upgrade Project was well into the Definition Phase with a forecast in-service date in fiscal 2019.
30. As explained above, while the Bridge River 2 Upgrade Units 5 and 6 Project was
delayed, the Bridge River 2 Upgrade Units 7 and 8 Project was accelerated, bringing the projects
closer together. The projects, however, are still driven by separate reliability needs.
Water Management Needs Now Paramount
31. The opportunity to reliably move water through Units 5 and 6 by fiscal 2019, is
now the primary reason the Units 5 and 6 Upgrade Project is separate from the Units 7 and 8
Upgrade Project.56 As BC Hydro explained, the recent de-ratings of the Bridge River 2
generating stations, and the decision to lower the maximum elevation of the upstream
Downton Reservoir to manage dam safety risks at the La Joie Dam, have made it a challenge for
BC Hydro to meet its obligations contained in the Water License for the Bridge River System.
The only way to move water from Carpenter Reservoir to Seton Lake is through the Bridge River
1 and 2 generating units.57 Meeting the fiscal 2019 in-service date for the new Units 5 and 6
will ensure a reliable water flow through the units to produce 150 MW, which includes re-
instating approximately 54 MW of lost Bridge River 2 capability due to unit de-ratings. This will
improve the water management issues on the Bridge and Seton Rivers.
32. Proceeding with the Bridge River 2 Upgrade Units 5 and 6 Project in fiscal 2019
followed by Bridge River 2 Upgrade Units 7 and 8 Project in fiscal 2021 is necessary to manage
outages and water flows:58
56
Exhibit B-9, BCUC IR 1.88.7. 57
Exhibit B-9, BCUC IR 1.88.7. 58
Exhibit B-14, BCUC IR 2.261.2.
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There are two penstocks supporting the four units, with a common penstock 1
for Units 5 and 6 and another common penstock 2 for Units 7 and 8. In order to
minimize overall outage time and minimize the impact to water management in
the system, BC Hydro plans to upgrade both units attached to a penstock at the
same time;59 and
To minimize water management impacts, the upgrades are planned during
maintenance outages already planned in fiscal 2019 and fiscal 2021 years.60
33. Due to the timing differences in the projects as discussed above, combining the
Units 5 and 6 Upgrade Project with the Units 7 and 8 Upgrade Project would delay the Units 5
and 6 in-service date by one or two years.61 This is not a feasible option.
No Efficiencies or Cost Savings from Combining
34. BC Hydro has analyzed various timing options for the projects and does not
believe that combining the Bridge River 2 Upgrade Units 7 and 8 Project and the Bridge River 2
Upgrade Units 7 and 8 Project would result in efficiencies or cost savings.62 Potential
opportunities to achieve efficiencies or cost savings by combining or aligning activities for both
projects were evaluated,63 and it was determined that certain efficiencies and cost savings
could be achieved through combined procurement and construction opportunities and utilizing
certain existing designs. However, these efficiencies can be achieved without combining the
two projects. Options to build the projects back-to-back either cost more or a not feasible.64
59
Exhibit B-14, BCUC IRs 2.261.2 and 2.261.3. 60
Exhibit B-14, BCUC IRs 2.261.2 and 2.261.3. 61
Exhibit B-9, BCUC IR 1.88.7. 62
Exhibit B-9, BCUC IR 1.88.5. 63
Exhibit B-9, BCUC IR 1.88.5. 64
Exhibit B-9, BCUC IR 1.88.5.
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Conclusion
35. BC Hydro is reasonably proceeding with the Bridge River 2 Upgrade Units 5 and 6
Project and the Bridge River 2 Upgrade Units 7 and 8 Project separately. The two projects have
different scopes and been planned separately due to different reliability needs, resulting in the
two projects being in very different parts of the project lifecycle. Combining these projects or
constructing them back to back would not be feasible due to water management issues and
would not be cost effective.
(b) The Cheakamus Units 1 and 2 Generator Replacement Project and the Cheakamus Upgrade Fire Protection Project
36. The Cheakamus Units 1 and 2 Generator Replacement Project and the
Cheakamus Upgrade Fire Protection Project are listed on lines 28 and 29 respectively, of page 1
of Supplemental Appendix I-A.65 These two projects appropriately proceeded as separate
projects. The Cheakamus Upgrade Fire Protection Project was completed prior to the test
period and has no material linkages to the Cheakamus Units 1 and 2 Generator Replacement
Project.
37. The Cheakamus Upgrade Fire Protection Project was to provide fire protection
systems for the Cheakamus powerhouse. The project in-service date was March 2016.
Replacement of the powerhouse fire protection systems was required prior to the generator
replacements to ensure adequate fire protection during construction, as the generator
installations will require “hot work” such as welding.66
38. The Cheakamus Units 1 and 2 Generator Replacement Project is described on
page 20 of Appendix J of the Application. The project will replace the two generators and will
reuse the majority of the existing generator deluge system, which includes fire detection
devices and water supply piping.67 The generators will be replaced one at a time due to the
need for one of the two units to remain in service to provide electricity and move water
65
Exhibit B-6. 66
Exhibit B-9, BCUC IR 1.89.2. 67
Exhibit B-9, BCUC IR 1.89.2.
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through the system. The planned outages for replacing the generators are November 2017 to
May 2018 for the first generator, and November 2018 to May 2019 for the second generator.68
39. Other than the need for the Cheakamus Upgrade Fire Protection Project to be
completed prior to the Cheakamus Units 1 and 2 Generator Replacement Project, there are no
material linkages to the requirements or benefits for the two projects and no material
construction efficiencies were expected from combining or more closely aligning the two
projects.69
(c) GM Shrum 1–10 Control System Upgrade
40. The GM Shrum 1–10 Control System Upgrade Project is described on line 35 of
page 1 of Supplemental Appendix I-A70 and page 24 of Appendix J of the Application. The
purpose of the project is to improve the reliability of G.M. Shrum by modernizing Units 1 to 10
control systems; replacing Units 6 to 10 governor control systems; replacing Units 9 and 10
exciters; replacing the controls for plant auxiliary systems; and replacing the G.M. Shrum
control room controls.71 The GM Shrum Unit 1 to Unit 10 Control System Upgrade project is a
ten year project that started in fiscal 2011, with a total forecast capital cost between $77.2
million and $58.4 million. The project has been divided into three tranches to address the scope
of work on a unit by unit basis.72 The project is required to address reliability issues and should
not be delayed.
41. The Project was initiated because the original analog controls in place at the
GMS Generating Station were being operated well past their intended life, maintenance was
difficult as availability of parts and expertise was declining, and deficiencies in the original
68
Exhibit B-9, BCUC IR 1.89.1. The Facility Asset Plan for Cheakamus was provided as an attachment to BCUC IR 1.89.4.
69 Exhibit B-9, BCUC IR 1.89.2.
70 Exhibit B-6.
71 Exhibit B-1-1, Appendix J, p. 24.
72 Exhibit B-9, BCUC IR 1.90.3 and BCUC IR 1.90.4.
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design presented safety and operability risks.73 Of the equipment being replaced, the control
equipment is in the poorest condition. The control equipment in-service at GM Shrum today
was originally installed in the 1960s and 1970s and is well beyond its expected life. Examples of
safety and reliability issues with the control equipment are provided in response to BCUC IR
1.90.2.74
42. While some equipment health ratings are “fair”, it is beneficial to replace the Fair
and Poor rated equipment at the same time. The control equipment, governors and the
exciters are an integrated system. If not replaced, interfaces must be designed and
implemented between the new and old equipment.75 This makes it more efficient to complete
the work at one time.
43. None of these replacements can be delayed outside of the test period while
maintaining an acceptable level of risk. The GM Shrum Control System Upgrade project
addresses a number of safety and reliability risks in three tranches over a 10 year period. Part
of Tranche 2 and Tranche 3 are already scheduled to be completed outside the test period and
represent a retained risk until the issues are addressed.76 In addition, the project takes
advantage of extended unit outages and efficiencies related to project management, design,
procurement and construction.77 BC Hydro has efficiently planned this safety and reliability
work over an extended period. Delay of any work would not be prudent.
(d) Mica Modernize Controls
44. The Mica Modernize Controls Project is described on line 52 of page 1 of
Supplemental Appendix I-A78 and page 31 of Appendix J of the Application. The purpose of the
project is to modernize the original Mica Unit 1 to 4 analog unit and control room controls,
73
Exhibit B-9, BCUC IR 1.90.4. 74
Exhibit B-9, BCUC IR 1.90.2. 75
Exhibit B-9, BCUC IR 1.90.2. 76
Exhibit B-9, BCUC IR 1.90.3. 77
Exhibit B-9, BCUC IR 1.90.2. 78
Exhibit B-6.
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alarms and metering; replace the excitation systems; upgrade the governor controls; and,
replace the unit protection equipment.79
45. BC Hydro responded to a number of information requests related to this project.
BC Hydro provided the following evidence in its responses:
BC Hydro Generation has a formal methodology, similar to Equipment Health
Rating, for evaluating the condition of control room controls or unit protection
and control equipment. Based on protection system condition evaluations in
2011 and 2012, a sequence of protection replacement was recommended.80
There are a limited number of spare parts available and some parts are no longer
being manufactured. Some similar assets exist across the fleet and these also
carry risks related to limited spare parts and obsolescence. As assets are
replaced, the retired equipment from Key facilities like Mica may be used to
provide a limited inventory of used parts for other stations while they await
upgrades of obsolete equipment. However, there can be differences between
different vintage equipment from the same supplier, so not all parts are usable
at other stations.81
46. As of September 30, 2016, the Mica Modernize Controls Project is still in the
Identification Phase which means that the project is not sufficiently advanced to have a
preferred alternative and there is insufficient information on the scope to establish a full
project schedule. No capital additions are forecast for this project over the test period.
7979
Exhibit B-1-1, Appendix J, p. 31. 80
Exhibit B-9, BCUC IR 1.91.1. 81
Exhibit B-9, BCUC IR 1.91.2.
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(e) Mica Replace Units 1 to 4 Generator Transformers
47. The Mica Replace Units 1 to 4 Generator Transformers Projects is described on
line 67 of page 1 of Supplemental Appendix I-A82 and page 34 of Appendix J of the Application.
The purpose of this project is to replace twelve single-phase generating unit transformers at the
Mica facility.
48. BC Hydro responded to a number of information requests related to this project.
BC Hydro provided the following evidence in its responses:
The biggest driver for replacing these transformers is safety. With the
transformers reaching their 40-year design life in 2016 and with eight of twelve
transformers rated as Poor, it was determined that replacing all the transformers
with modern explosion resistant transformers was the prudent approach at such
an important station that is underground and fully staffed.83
The transformers rated Fair suffer from oil leaks and BC Hydro is not planning to
address this prior to replacement. Minor interventions would not put these
transformers into acceptable condition. The transformers rated as Fair are also
the same type and vintage as those rated as Poor, and it is likely that the EHR
rating will be changed to Poor the next time the EHR is updated.84
49. As of September 30, 2016, the Mica Replace Units 1 to 4 Generator Transformers
Project is still in the Identification Phase which means that the Project is not sufficiently
advanced to have a preferred alternative and there is insufficient information on the scope to
establish a full project schedule.85 No capital additions for this project are forecast in the test
period.
82
Exhibit B-6. 83
Exhibit B-9, BCUC IR 1.92.2. 84
Exhibit B-9, BCUC IR 1.92.2. 85
Exhibit B-9, BCUC IR 1.92.3.
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(f) Seven Mile Overhaul Units 1 to 3 Turbines
50. The Seven Mile Overhaul Units 1 to 3 Turbines Project is described in line 69 of
page 1 of Supplemental Appendix I-A86 and page 35 of Appendix J of the Application. The
purpose of this project is to overhaul Units 1 to 3 turbines in order to provide continued reliable
service.87
51. BC Hydro responded to a number of information requests related to this project.
BC Hydro provided the following evidence in its responses:
The Project was released in fiscal 2017 to mitigate reliability risk and extend the
service life of the turbines, in consideration of the long lead time needed for the
runner replacement alternative.88
The primary driver of the Seven Mile Overhaul Units 1 to 3 Turbines project is to
mitigate reliability risk. While the turbines are currently rated as Fair, the units
have never been overhauled and there are known concerns with the ongoing
runner cavitation and erosion of the runner seals as well as unknown condition
of wicket gate components, as they can only be inspected with the machine
disassembled.89
Bi-annual weld repairs are done on each unit and are performed in situ to deal
with cavitation damage to the runner. Compared to the weld repair, this project
would be an extensive refurbishment or replacement of the turbines, and would
be more extensive than ongoing maintenance to manage runner cavitation.90
The expected service life for Francis turbines, before needing major intervention
to restore their condition and extend their service lives, is typically 20 to 35
86
Exhibit B-6. 87
Exhibit B-1-1, Appendix J, p. 35. 88
Exhibit B-9, BCUC IR 1.93.3. 89
Exhibit B-9, BCUC IR 1.93.1. 90
Exhibit B-9, BCUC IR 1.93.1, 1.93.4, 1.93.4.1.
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years. The Seven Mile Units 1 to 3 turbines have been in service for over 35 years
without a complete unit disassembly for any major work. Although the most
recent health assessments resulted in Fair ratings, they have documented severe
damage on the runner crown and band seals, in addition to the ongoing runner
cavitation problem. Because the turbines have never been disassembled, risks
include runner seal failure where pieces of metal could dislodge and become
stuck between rotating and stationary parts resulting in significant damage and
uneven runner seal erosion which could cause unit instability. Due to the
ongoing cavitation and weld repair, there is also a risk of runner failure from
fatigue cracking. As part of the Identification Phase, the Units will be inspected
and an updated condition assessment of the turbines will be completed in order
to support the evaluation of the alternatives and arrive at a recommendation to
proceed with or delay the project.91
52. The Seven Mile Overhaul Units 1 to 3 Turbines Project is currently in
Identification Phase. BC Hydro currently anticipates the costs to exceed $100 million, based on
updated cost information prepared in December 2016. This updated information was prepared
prior to the completion of the conceptual design stage and therefore will be subject to changes
as the design progresses.92 At this time, replacement is the leading alternative, although BC
Hydro is still considering the refurbishment option.93 The start date of construction is expected
to be outside of the test period.94 This project has no capital additions in the test period.
(a) Mica SF6 Gas-insulated Switchgear Replacement
53. The Mica Gas Insulated Switchgear Project is described on line 5 of page 1 of
Supplemental Appendix I-B.95 This project was placed into service in August 2014. BC Hydro
91
Exhibit B-9, BCUC IR 1.93.3; BCUC IR 1.93.4.3. 92
Exhibit B-14, BCUC IR 2.262.1. 93
Exhibit B-9, BCUC IR 1.93.5. 94
Exhibit B-9, BCUC IR 1.93.6. 95
Exhibit B-6.
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proceeded with this project prudently following the decision to proceed with Mica Units 5 and
6. The capital expenditure schedule for the project should be accepted into rates.96
54. The original Mica 500 kV gas insulated switchgear posed substantial reliability
risks. It was over 30 years old and was potentially the last equipment of its vintage still in
operation in North America. A failure of the gas insulated switchgear could have resulted in an
extended forced outage at Mica. The operation, maintenance, and repair of the gas insulated
switchgear also presented a number of safety risks; the Mica gas insulated switchgear leaked an
excessive amount of SF6 gas, which is a potent greenhouse gas.97 As a result, the project was
implemented to mitigate these reliability risks, improve safety, and realize environmental
benefits related to a reduction in greenhouse gas emissions.98
55. In March 2010, the Commission did not accept the Mica Gas Insulated
Switchgear Project as being in the public interest in the context of a section 44.2 filing due to
concern that Lead Shaft 3 was a pre-build for the proposed Mica Unit 5 and Unit 6 project and
could result in stranded costs.99 However, the risk of stranded costs was obviated as the Mica
Unit 5 and Unit 6 Project was approved by the BC Hydro Board of Directors in May 2010, and in
July 2010 the Mica Unit 5 and Unit 6 Project was exempted from Commission process under the
Clean Energy Act. With the implementation of the Mica Unit 5 and 6 Project, the Mica Gas
Insulated Switchgear Project would not result in a stranded asset.100
56. As further regulatory approvals were not required for the Mica Gas Insulated
Switchgear Project, BC Hydro did not reapply for approval, which also would have entailed
associated costs. However, Semi-Annual Progress Reports for the Project have been filed since
June 2010 updating the Commission on the project’s progress.101
96
Exhibit B-9, BCUC IR 1.122.1 97
Exhibit B-15, BCOAPO IR 2.86.1. 98
Exhibit B-15, BCOAPO IR 2.86.1. 99
Exhibit B-15, BCOAPO IR 2.86.1. 100
Exhibit B-15, BCOAPO IR 2.86.1. 101
Exhibit B-15, BCOAPO IR 2.86.1.
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57. As the risk of stranded assets was removed, BC Hydro proceeded prudently with
the project to address the substantial reliability risks of the original Mica 500 kV gas insulated
switchgear.
(b) Alouette and Elko Generating Stations and Shuswap Unit 1
58. The Alouette and Elko generating stations and Shuswap Unit 1 continue to
provide benefits and are used and useful for rate base purposes. These facilities are currently
out of service due to unsatisfactory equipment conditions, as BC Hydro is delaying investments
in the generation capability at these facilities until there is a greater need for energy, and to
stay on track with the 2013 10 Year Rates Plan.102 BC Hydro continues to maintain water
conveyance and some generation (in the case of Shuswap) at these facilities with the
expectation that future increases in both demand and electricity prices will create the economic
conditions to justify restoring full generation at these facilities.103
59. Each of the Alouette and Elko generating stations and Shuswap Unit 1 has a
roughly 90-year operating history and has reached, or is near, the point where significant
renewal investment is required.104 Due to BC Hydro’s substantial capital refurbishment
program underway and the need to prioritize sustaining investments in order to be consistent
with the 2013 10 Year Rates Plan, BC Hydro is delaying redevelopment, refurbishment or repair
of these facilities. As a result, Alouette, Elko and Shuswap Unit 1 will remain out of service in
the near-term.105 In the long-term, BC Hydro anticipates that increases in both demand and
electricity prices will create the economic conditions to justify restoring full generation at these
facilities so that they may operate for another 80 to 90 years.106
102
Exhibit B-1-1, Application, p. 6-21; Exhibit B-9, BCUC IR 1.74.5 and 1.74.6. 103
Exhibit B-9, BCUC IR 1.74.3 and BCUC IR 1.74.5. 104
Exhibit B-9, BCUC IR 1.74.3. 105
Exhibit B-9, BCUC IR 1.74.2. The most recent Facility Asset Plans for Alouette, Elko and Shuswap were provided in response to BCUC IR 1.74.1.
106 Exhibit B-9, BCUC IR 1.74.2. The most recent Facility Asset Plans for Alouette, Elko and Shuswap were provided in response to BCUC IR 1.74.1.
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60. The most recent Facility Asset Plans for each of the facilities is attached to BC
Hydro’s response to BCUC IR 1.74.1. BC Hydro’s near-term plan for the Alouette, Elko and
Shuswap facilities is to continue to safely convey water through the facilities and meet
requirements as set out in its water licenses.107 The facilities continue to provide the following
benefits:
(a) Shuswap Facility continues to generate electricity from one of two units and the
remainder of the overall facility continues to be used to convey water for
environmental, recreational and other purposes, required by BC Hydro’s water
license.108
(b) Alouette and Elko facilities are currently being used to convey water
downstream. Alouette Facility has a significant water management function.
Alouette is the first facility in the Stave River System, which also includes the
Stave Falls and Ruskin facilities downstream. The Alouette reservoir and Stave
reservoir provide the main storage for the system which is managed and
operated as a whole, with flows diverted at Alouette subsequently used at Stave
Falls and Ruskin for generation. The Aloutte facility also provides benefits for
fish, area recreation and flood mitigation. In the case of Elko facility, the short
term benefit is primarily in maintaining downstream water flows at required
minimum levels, which is necessary to preserve the site for the longer term.109
61. Over the test period, BC Hydro is planning seismic upgrades to the Alouette
Dam, which is classified as an extreme consequence dam according to the B.C. Dam Safety
Regulation. The project will include upgrades to the headworks tower, surge tower, and
equipment and upgrades to the slopes above the towers to reduce the rockfall hazard. These
107
Exhibit B-9, BCUC IR 1.74.2. The most recent Facility Asset Plans for Alouette, Elko and Shuswap were provided in response to BCUC IR 1.74.1.
108 Exhibit B-9, BCUC IR 1.74.3.
109 Exhibit B-9, BCUC IR 1.74.3 and Exhibit B-14, BCUC IR 2.233.2.
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upgrades are in support of BC Hydro’s risk management strategy to ensure that river flows can
continue to be safely handled after a seismic event.110
62. In summary, the facilities continue to provide generation and water conveyance
benefits, are being maintained for future use and are therefore used and useful for rate base
purposes.111
F. THERMAL - BURRARD FACILITY CONVERSION
63. The Burrard Convert Facility to Synchronous Condenser Only Operation Project,
which occurred in April 2016112, is listed on line 74 on page 2 Supplement Appendix I-1A. The
six units located at the Burrard Facility are no longer configured and maintained to generate
electricity. Four of the six units have been converted to function only in a synchronous
condenser capacity and remaining assets required for this function are included in Table 8-1 of
the Application. There is limited capital investment at Burrard in the test period.113 It is
focused on mitigating safety risk and environmental risk.114
64. Assets not required for synchronous condenser functionality were fully
depreciated by March 31, 2016.115 Depreciation rates for assets required for synchronous
condenser functions are addressed in Part Ten of the Final Submission.
G. TRANSMISSION – GROWTH CAPITAL
(a) Horne Payne Substation Upgrade
65. The Horne Payne Substation Upgrade Project is described on line 5 on page 3 of
Appendix I-A116 and page 40 to 41 of Appendix J. The Horne Payne Substation Upgrade includes
110
Exhibit B-1-1, Appendix I, page 1, line 11; Exhibit B-9, BCUC IR 1.74.7. 111
Exhibit B-9, BCUC IR 1.74.3. 112
Exhibit B-9, BCUC IR 1.94.2 and BCUC IR 1.94.5. 113
Application, p. 6-79. 114
Exhibit B-9, BCUC IR 1.94.4. 115
Exhibit B-10, Landale IR 1.4.1. 116
Exhibit B-6.
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the addition of two 230/25 kV, 150 MVA transformers and three 25 kV, 50 MVA indoor gas-
insulated feeder sections. A new control building will also be added, and the existing main
control building will be decommissioned.117 The project is forecast to be in service in fiscal 2019
with an Authorized Amount of $92.6 million.118 As the Authorized Amount for the project is
below the threshold of $100 million, a CPCN application is not required pursuant to BC Hydro’s
Capital Filing Guidelines. The Horne Payne Substation Upgrade Project is supported by the
results of the North Burnaby Area study and is in the public interest.
66. The issues being addressed by the Horne Payne Substation Upgrade are as
follows:
The existing firm capacity of Horne Payne is 190 MVA. The winter load demand is forecast to exceed the firm capacity in fiscal 2017. This project will increase the firm capacity, add much needed feeder positions, facilitate the gradual conversion of the area supply voltage from 12 kV to 25 kV, and allow for the implementation of an open-loop distribution topology. Conversion to 25 kV will eliminate the existing issue of high fault current on the distribution bus at Horne Payne and also reduce distribution losses. The additional capacity at Horne Payne will allow for the replacement of the 50/60 feeder section, as well as allow for the ageing Lougheed substation to be gradually offloaded to Horne Payne in preparation for its redevelopment in fiscal 2025.119
67. The Horne Payne Substation Upgrade is the first project resulting from the North
Burnaby Area study, which developed a 30-year plan for the Horne Payne, Lougheed and
Barnard substations and service areas.120 The North Burnaby Area Study considered all
emerging needs in this area related to both the forecasted load growth over the next 30 years
and declining asset health conditions. It also considered the opportunity to simultaneously
address the long term distribution need to convert the area load from 12 kV to 25 kV. Finally, it
117
Exhibit B-1-1, Application, Appendix J, p. 40. 118
Exhibit B-9, BCUC IR 1.97.3.1. 119
Exhibit B-1-1, Application, Appendix J, p. 40. 120
Exhibit B-1-1, Application, Appendix J, page 40.
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considered the potential impact beyond the 30-year period if some of the needs were not
addressed.121
68. The North Burnaby Area study considered a do nothing alternative, a delayed
investment alternative, a 12 kV alternative and a 25 kV alternative. The study recommended
the 25kV alternative. The 25 kV alternative consists of adding capacity, replacing end-of-life
assets and addressing the legacy deficiencies at the area substations in a timely way during the
30 year study period. It also includes converting the distribution voltage of the area to address
the long term distribution need to convert the area load from 12 kV to 25 kV.122 The
advantages of the recommended alternative include a smaller distribution footprint (about half
as many feeders would be required to serve the load) and support for the long-term need to
convert the area load from 12kV to 25kV.123
69. As noted above, the Horne Payne Substation Upgrade project is the first project
to result from the North Burnaby Area study. Further implementation steps are described in BC
Hydro’s response to BCUC IR 1.97.1.1 and the North Burnaby Area study, which is filed as BCUC
IR 1.97.1.1 Attachment 1.
70. The $92.6 million Authorized Amount for the Horne Payne Substation Upgrade
consists of the expected project cost plus project reserve. The expected project cost is a P50
estimate with an accuracy range of plus 15 per cent and minus 10 per cent. The addition of the
project reserve to the expected project cost provides a P90 estimate, which is defined as the
cost estimate that will not be exceeded 90 per cent of the time. There is no defined accuracy
range associated with a P90 estimate.124 Based on the Authorized Amount, the project does
not meet the $100 million threshold for generation and transmission (including substation
distribution asset components) projects in BC Hydro’s Capital Filing Guidelines.125
121
Exhibit B-9, BCUC IR 1.97.1. 122
Exhibit B-9, BCUC IR 1.97.1. 123
Exhibit B-9, BCUC IR 1.97.1.1. 124
Exhibit B-9, BCUC IR 1.97.3.1. 125
Exhibit B-9, BCUC IR 1.66.1 Attachment 1, Capital Project Filing Guidelines, p. 1.
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71. To mitigate construction risk, BC Hydro has split construction of the Horne Payne
Substation Upgrade Project into three key stages: Site preparation, General construction, and
Demolition of the existing main control building. Site preparation began in January 2016 and
contractor mobilization began in August 2016.126
72. The Horne Payne Substation Upgrade Project reflects the most beneficial
strategy to meet the required needs in the area and is in the public interest.
(b) Fort St. John and Taylor Electric Supply
73. The Fort St. John and Taylor Electric Supply Project is described on line 7 on page
3 of Appendix I-A127 and page 43 of Appendix J of the Application. Information requests
focused on the project’s relationship to the Site C Clean Energy Project and whether it met the
threshold in BC Hydro’s current Capital Project Filing Guidelines:
The Fort St. John and Taylor Electric Supply Project is not explicitly needed by the
Site C Clean Energy Project. The Site C Clean Energy Project generator
interconnection system impact study identified an opportunity for BC Hydro to
optimize the transmission system to more effectively serve the area loads and
reduce the overall BC Hydro footprint. As the Fort St. John and Taylor Electric
Supply Project results in transmission system benefits that exceed the estimated
project cost, it is funded separately as a system reinforcement initiative and not
included in the Site C Clean Energy Project Authorized Amount.128 As this project
is not part of the Site C Clean Energy Project, and it does not qualify to be funded
by Site C Clean Energy Project management reserves or from the Provincial
Treasury Board’s project reserve. 129
126
Exhibit B-9, BCUC IR 1.97.6. 127
Exhibit B-6. 128
Exhibit B-9, BCUC IR 1.99.1. 129
Exhibit B-9, BCUC IR 1.99.2.
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As indicated in Supplemental Appendix I-A, the Project is in the Implementation
Phase, with an Authorized Amount of $53.1 million. This Project does not meet
the expenditure threshold in BC Hydro’s current Capital Project Filing Guidelines.
Therefore, BC Hydro did not file a CPCN or section 44.2 application for this
Project.130
74. The Fort St. John and Taylor Electric Supply Project is appropriately being funded
separately as a system reinforcement initiative and does not meet the thresholds in the Capital
Filing Guidelines.
(c) West Kelowna Transmission Project and Westbank Substation Upgrade Project
75. The West Kelowna Transmission Project is described on line 9 on page 3 of
Appendix I-A131 and page 46 of Appendix J of the Application. The Westbank Substation
Upgrade is described on line 35 on page 3 of Appendix I-A132 and 62 of Appendix J. These two
projects are appropriately proceeding as two separate projects and BC Hydro is achieving
efficiencies by coordinating the project where possible. Neither of the projects currently meet
the thresholds in BC Hydro Capital Filing Guidelines based on the current planning allowances
for the projects.
76. The West Kelowna Transmission Project and the Westbank Substation Upgrade
project are listed as two projects because the business drivers, scope and timing are different:
The Westbank Substation Upgrade project will reconfigure the station and add
transformation capacity to supply the peak load at Westbank Substation. The
forecast peak loading on the station currently exceeds the transformation
capacity under certain contingencies and the project is needed as soon as it can
be implemented.133
130
Exhibit B-9, BCUC IR 1.99.5. 131
Exhibit B-6. 132
Exhibit B-6. 133
Exhibit B-9, BCUC IR 1.101.4.
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The West Kelowna Transmission Project will add a new transmission line to
provide redundancy to the West Kelowna area as it is currently supplied radially
by a single 85 km long 138 kV transmission line from Nicola Substation. The lead
time to add a new transmission line is anticipated to be much longer, particularly
due to public and First Nations consultations, the need to establish routing, and
to complete construction. 134
77. While the West Kelowna Transmission Project and the Westbank Substation
Upgrade Project are appropriately proceeding as two projects, BC Hydro is achieving benefits by
coordinating the two projects. The main efficiency will be obtained by the Westbank Substation
Upgrade project providing for the termination of future 138 kV lines at line positions at the
Westbank Substation. One of these line positions will be required for the West Kelowna
Transmission project.135 BC Hydro will also coordinate the delivery of the projects to achieve
efficiencies to the extent possible; this would include concurrent First Nations consultations,
stakeholder engagement, environmental assessment and engineering studies.136
78. The planning allowance for each of the West Kelowna Transmission project and
the Westbank Substation Upgrade project in Supplemental Appendix I-A indicate that these
projects would not meet the threshold in BC Hydro’s Capital Project Filing Guidelines for a CPCN
or section 44.2 application. Both of the projects are in the Identification Phase, are not
sufficiently advanced to have a preferred alternative and there is insufficient information on
the scope of each project to establish a complete total project estimate. As the projects
progress and Authorized Amounts are established for them, BC Hydro will confirm whether or
not each of the projects meets the threshold.137
134
Exhibit B-9, BCUC IR 1.101.4. 135
Exhibit B-15, BCOAPO IR 2.83.1. All alternatives for the West Kelowna Transmission Project require the same 138 kV line position at the Westbank Substation. Therefore, the transmission alternative chosen for the West Kelowna Transmission Project will not affect the scope or spending requirements for the new 138 kV line position at the Westbank Substation.
136 Exhibit B-9, BCUC IR 1.101.3.
137 Exhibit B-9, BCUC IR 1.101.6.
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(d) Peace Region Electric Supply
79. The Peace Region Electric Supply Project is described on line 10 on page 3 of
Appendix I-A138 and page 47 of Appendix J of the Application. The project will increase
transmission capacity to the South Peace area by providing a new supply to Dawson Creek and
Groundbirch area. There are no capital additions forecast during the test period for this
project. Pursuant to Order in Council No. 100, this project is a prescribed undertaking under
section 18 of the Clean Energy Act. This project is therefore exempt from Commission review in
this proceeding.
80. The following paragraphs describe the status of the Peace Region Electric Supply
Project in more detail and summarize the responses to information requests received on the
project.
Status of Project
81. As of September 30, 2016, the Peace Region Electric Supply Project is still in the
Identification Phase which means that the Project is not sufficiently advanced to have a
preferred alternative and there is insufficient information on the scope to establish a full
project schedule. The capital expenditures presented in Supplemental Appendix I-A are
planning allowances only.139 No capital additions are forecast during the test period.
A Section 18 Prescribed Undertaking
82. BC Hydro’s letter dated March 10, 2017 notified the Commission of the issuance
of Orders in Council No. 100 and 101.140 Order in Council 101 adds as prescribed undertakings
for the purpose of Section 18 of the Clean Energy Act investments in infrastructure in Northeast
British Columbia that primarily serve natural gas producers and processors. This will include BC
Hydro’s Peace Region Electricity Supply Project. Accordingly, should BC Hydro decide to
138
Exhibit B-6. 139
Exhibit B-9, BCUC IR 1.102.4; see also Exhibit B-10, CEA IR 1.18.2, 1.18.4. 140
Exhibit B-18.
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proceed with the Peace Region Electricity Supply Project, BC Hydro will not be filing an
application under section 45(5) of the Utilities Commission Act for a CPCN.
83. Section 18 of the Clean Energy Act provides that the Commission must allow BC
Hydro to recover the costs of prescribed undertakings and not prevent BC Hydro from carrying
out a prescribed undertaking, as follows:
(2) In setting rates under the Utilities Commission Act for a public utility carrying out a prescribed undertaking, the commission must set rates that allow the public utility to collect sufficient revenue in each fiscal year to enable it to recover its costs incurred with respect to the prescribed undertaking.
(3) The commission must not exercise a power under the Utilities Commission Act in a way that would directly or indirectly prevent a public utility referred to in subsection (2) from carrying out a prescribed undertaking.
84. The project is not forecast to be in-service over the test period and no capital
additions are forecast over the test period.
Need and Timing
85. The need and timing of the Peace Region Electricity Supply Project is driven by
the load in the Peace region, particularly in the Dawson Creek and Groundbirch areas.
Comparing the load forecast in the Application and the forecast in the 2013 IRP, there is still a
need for the Peace Region Electricity Supply Project to be energized as early as possible. The
ability of the transmission system to supply the growing load under normal conditions is
expected to be exceeded in the winter of fiscal 2025 (November 2024), compared to fiscal 2018
in the 2013 IRP.141
86. On August 19, 2016 the Province released its Climate Leadership Plan which
included potential initiatives to encourage the electrification of natural gas production and
processing facilities. Implementation of these Climate Leadership Plan initiatives could increase
forecast load in the region and accelerate the forecast timing of that load. Under the high load
141
Exhibit B-9, BCUC IR 1.102.5.
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scenario, the ability of the transmission system to supply the growing load under normal
conditions could be exceeded as early as fiscal 2018.142
Existing Service in Dawson Creek and Groundbirch Area
87. BC Hydro is using accepted utility practice to address system constraints until the
Peace Region Electricity Supply Project is in service. As the loads in the region are exceeding
the capacity added under the Dawson Creek/Chetwynd Area Transmission Project, new
customers are required to take service at an N-0 service level143 until the capacity of the
transmission system in the Dawson Creek/Chetwynd area is increased. Specifically, new
customers are required to participate in a protection and control scheme (Remedial Action
Scheme) that will shed their loads during system contingency events. This type of Remedial
Action Scheme is an accepted utility practice for addressing system constraints while more
permanent system upgrades are developed.144 While new customers have expressed concerns
regarding potential reliability impacts, customers have also accepted N-0 service as an interim
condition until capacity is added to the system.145 The Peace Region Electric Supply Project will
increase the capacity in the Peace region, particularly in the Dawson Creek and Groundbirch
areas.146
Customer Contributions not Known
88. The Peace Region Electricity Supply Project is still at an early stage and BC Hydro
has yet to determine how or when industrial customers (predominantly in the oil and gas
industry) will contribute towards the costs of the Project. Customer commitments may vary
depending on the customer’s stage of development and may include, for example, Letters of
Commitment or various forms of financial securities.147
142
Exhibit B-9, BCUC IR 1.102.5. 143
N-0 service means that the system cannot continue to supply customers when one major component of the transmission system is out of service. (Exhibit B-9, BCUC IR 1.102.2.)
144 Exhibit B-9, BCUC IR 1.102.2.
145 Exhibit B-9, BCUC IR 1.102.3.
146 Exhibit B-9, BCUC IR 1.102.3.
147 Exhibit B-9, BCUC IR 1.102.1.
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Alternatives Analysis
89. The alternatives under consideration for Peace Region Electricity Supply Project
are described on page 48 of Attachment J, as follows:
i. Provide additional 230 kV supply to the South Peace from the Site C Substation: This alternative would construct a 230 kV switchyard at the proposed Site C Substation (to be constructed as part of the Site C Clean Energy Project), and a new double circuit 230 kV transmission line between the new substation and the Shell Groundbirch Substation approximately 55 km to the south. This is the leading alternative;
ii. Provide additional 230 kV supply to the South Peace from G.M. Shrum generating station: This alternative would expand and rebuild the 230 kV switchyard and replace the existing 500/230 kV transformers at G.M. Shrum generating station, and provide new 230 kV transmission facilities. Transmission additions being considered include a new 230 kV line from G.M. Shrum generating station to Sundance Substation and upgrading the existing 230 kV lines from G.M. Shrum generating station to Sundance Substation; or a new double circuit 230 kV line from G.M. Shrum generating station to Sundance Substation;
iii. Provide additional 230 kV supply to the South Peace from a new substation: This alternative would construct a new 500/230 kV substation south of G.M. Shrum generating station, and provide new 230 kV transmission facilities. Transmission additions being considered include a new 230 kV line from this new substation to Sundance Substation and upgrading the existing 230 kV lines from G.M. Shrum generating station to Sundance Substation; or a new double circuit 230 kV line from the new substation to Sundance Substation;
iv. Non-wire alternatives: Non-wire alternatives, such as demand side management, would not materially change the planning analysis for the South Peace Area as the forecasted load growth in the region is too high. Non-wires alternatives, such as temporary generation, are being considered to assist with meeting the short term needs in the area until the Dawson Creek Chetwynd Area Transmission Project and Peace Region Electricity Supply projects are in service; and
v. Do Nothing: This alternative is not feasible as BC Hydro would not be able to serve load under system normal (N-0) or single contingency (N-1) system conditions. BC Hydro is restricting service to new industrial customers by
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requesting that they be prepared to be interrupted until a long-term transmission solution is in place.
90. In late 2015, evaluation of the Peace Region Electricity Supply Project
alternatives identified the supply to the South Peace from the Site C Substation as the leading
alternative.148 The Dokie Ridge and Pine Valley alternatives (alternative ii and iii above,
respectively) were both assessed to be more expensive, each with a cost differential of
approximately $100 million over the Site C Substation alternative.149 The higher costs are
mainly due to the following factors:
(a) The Dokie Ridge and Pine Valley alternatives require transmission circuits that
are approximately 25 km longer than the Site C Substation alternative; and
(b) The Dokie Ridge and Pine Valley alternatives require the construction of a new
500/230 kV substation compared to the Site C Substation alternative, which
requires a 500/230 kV expansion of the Site C Substation. 150
91. Although the Dokie Ridge alternative is forecast to cost less than the Pine Valley
alternative, some First Nations have expressed to BC Hydro that the site of the proposed
substation and nearby transmission lines in the Dokie Ridge alternative is part of an area of
significant cultural and spiritual importance to them. Additionally, the substation and
transmission line would also lie within the Peace-Moberly Tract, which is also of particular
importance to some First Nations and within the Saulteau First Nation Area of Critical
Community Interest. The Pine Valley alternative avoids all or the vast majority of these areas.151
92. Natural gas fired generation options have been considered as potential
alternatives.152 Preliminary analysis showed natural gas fired options to be at least $80 million
more than the Dokie Ridge option. These options would also be inconsistent with the Climate
148
Exhibit B-10, AMPC IR 1.17.5. 149
Exhibit B-15, AMPC IR 2.19.1. 150
Exhibit B-15, AMPC IR 2.19.1. 151
Exhibit B-10, AMPC IR 1.17.5. 152
Exhibit B-10, AMPC IR 1.17.6; Exhibit B-15, AMPC IR 2.20.1.
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Leadership Plan, which identifies the Peace Region Electricity Supply Project as a key project
that enables the use of clean electricity to electrify natural gas developments in the Montney
formation in Northeast British Columbia. The Climate Leadership Plan also states that going
forward 100 per cent of the electricity acquired by BC Hydro in British Columbia on the
integrated grid must be from renewable or clean sources, except where concerns regarding
reliability or costs must be addressed.153
93. A preferred alternative will be selected at the end of the Identification Phase.154
Consultation
94. The Peace Region Electricity Supply Project is entirely within the Treaty 8
territory, and all eight First Nations were identified as potentially impacted by the project. BC
Hydro has been engaging with all of these First Nations and the Treaty 8 Tribal Council since
2013. Six of the Treaty 8 Nations requested consultation on the project (Blueberry River First
Nation, Halfway River First Nation, McLeod Lake Indian Band, Saulteau First Nation, Doig River
First Nation, and West Moberly First Nations). Accordingly BC Hydro has shared project
information and sought and received input over the past three years, including on project
alternatives and options.155
95. Consultation and capacity funding agreements are in place with each of the six
First Nations referred to above. The agreements all include funding for participation in review
of the project and input into the project alternatives and options. So far, four of these
agreements also have funding for traditional use studies. BC Hydro currently negotiating
funding for traditional use studies with the remaining two First Nations.156
96. Each of the First Nations provided feedback and/or technical reviews of the
alternatives and BC Hydro’s studies, which helped inform the selection of a leading alternative
153
Exhibit B-10, AMPC IR 1.17.6; Exhibit B-15, AMPC IR 2.20.1. 154
Exhibit B-10, AMPC IR 1.17.5; Exhibit B-15, AMPC IR 2.19.1. 155
Exhibit B-10, CEA IR 1.18.1. 156
Exhibit B-10, CEA IR 1.18.1.
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and provided detail about First Nations concerns and values. BC Hydro continues to provide
First Nations with information and to seek their input as part of BC Hydro’s ongoing
consultation.157
Conclusion
97. Although BC Hydro has responded to a number of information requests on the
Peace Region Electricity Supply Project, the project has no capital additions forecast for the test
period and is exempt from Commission review pursuant to section 18 of the Clean Energy Act.
(e) Project A and Project B
98. Two land acquisitions identified as Project A and Project B are described in lines
11 and 12 on page 3 of Supplemental Appendix I-A158 and discussed on pages 49 and 50 of
Confidential Appendix J of the Application.159 Consistent with IFRS accounting principles, the
carrying costs of land that is held for future use (i.e., finance charges related to borrowings used
to purchase the land) are expensed as incurred and is a cost to ratepayers.160 BC Hydro is
considering fee simple purchase and leasing options. In either case, ratepayers will be kept
whole as any variances between forecast and actual finance costs will be captured in a
regulatory account and any increase in operating expense due to leasing property would be to
the account of the shareholder.161
99. The cost of land acquisitions will be included in the cost of future projects that
require the land for the purpose of determining whether a project meets the threshold for a
Certificate of Public Convenience and Necessity or section 44.2 application.162
157
Exhibit B-10, CEA IR 1.18.1. 158
Exhibit B-6. 159
Exhibit B-1-1-1. (The confidential pages address the potential acquisition of land and development of new facilities. Publication of information about these two projects would not be in the best interests of BC Hydro and its customers as it would compromise its ability to secure, and negotiate terms regarding, appropriate sites.)
160 Exhibit B-14, BCUC IR 2.264.2. See also Exhibit B-15, BCOAPO IR 2.84.1.
161 Exhibit B-14, BCUC IR 2.264.5.
162 Exhibit B-9, BCUC IR 1.103.1.
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BC Hydro Follows IFRS in Accounting for Land Acquisitions
100. The capital addition forecasts for Project A and Project B presented in
Supplemental Appendix I-A of the Application are planning allowances only.163 These amounts
are based on market research and information on comparable sites of suitable size, location,
zoning, and accessibility for the construction of new distribution substations in the Lower
Mainland.164
101. BC Hydro follows IFRS in accounting for land acquisitions. Land is recorded as a
tangible asset, however it does not get amortized for accounting purposes. The carrying costs
of land (i.e., interest costs related to borrowings used to purchase the land) are expensed until
the land is under development. Once the project which requires the land starts, carrying costs
of the land are charged to the project (i.e., capitalized) until the project is placed in-service.165
102. All land is included in BC Hydro’s rate base. However, pursuant to Order in
Council No 590,166 BC Hydro’s net income has been set for fiscal 2017 and subsequent years
and is therefore unaffected by rate base. 167
103. BC Hydro explained in response to information requests that the land costs were
incorrectly included in certain capital projects for the purpose of calculating amortization for
the test period. Also, in schedule 10 of Appendix A in the Application, land for Project A and
Project B was incorrectly classified as Transmission assets in-service. As these were projections
for purchased land, there should be no amortization expense associated with them.168 This
error will be corrected in the Compliance Filing, where amortization expense and transfers to
the Rate Smoothing Regulatory Account will be reduced accordingly.169
163
See Exhibit B-9, BCUC IR 1.84.2 for description of project cost information in different project phases. 164
Exhibit B-14, BCUC IR 2.264.4. 165
Exhibit B-9, BCUC IR 1.103.5. 166
Exhibit B-2, Evidentiary Update. 167
Exhibit B-9, BCUC IR 1.103.5. 168
Exhibit B-14, BCUC IR 2.264.1. 169
Exhibit B-9, BCUC IR 1.103.5 and Exhibit B-14, BCUC IR 2.264.1 and BCUC IR 2.264.2. See also Exhibit B-15, BCOAPO IR 2.84.1.
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Treatment of Variances from Forecast
104. BC Hydro is considering different means of procuring the required land rights,
including a fee simple land purchase, or an underground volumetric lease to construct, operate,
maintain and access the Projects.170 The treatment of variances between forecast and actual
costs ensures that ratepayers will kept whole:
Treatment for Land Purchase: The interest costs related to borrowings used to
purchase land is expensed and recovered from ratepayers, but the purchase cost
of land is not recovered from ratepayers. Any variance in interest expenses will
be deferred to the Total Finance Charges Regulatory Account in the test
period.171
Treatment for Land Lease: It is expected that these lease arrangements will be
treated as long-term assets (either pre-paid operating leases or finance leases).
The lease assets will be amortized (as either amortization expense or operating
expense depending on the accounting classification of the lease) evenly over the
term of the lease. Variances between actual and plan attributable to the
amortization expense of the lease assets will be treated as follows depending on
the accounting treatment of the lease assets:
If BC Hydro enters into a finance lease, any variance in amortization
would be captured by the Amortization of Capital Additions Regulatory
Account;
If BC Hydro enters into a pre-paid operating lease, the amortization
expense would be classified as operating expense, and any variances
between forecast and actual operating expense would be to the account
of the shareholder during the test period.172
170
Exhibit B-14, BCUC IR 2.264.5. 171
Exhibit B-14, BCUC IR 2.264.5. 172
Exhibit B-14, BCUC IR 2.264.5.
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105. In summary, any variance from forecast amortization or interest expense due to
an actual land purchase or lease, would be captured in a regulatory account, and any increase
in operating expense would be to the account of the shareholder during the test period. BC
Hydro will provide updates on costs associated with these projects in future revenue
requirements applications.173
(f) Northwest Substation Upgrades Project and Customer Requested Projects
106. The Northwest Substations Upgrades Project is described on line 16 of page 3 of
Supplemental Appendix I-A174 and on page 53 of Appendix J of the Application. The project
involves upgrades at Williston, Glenannen, Telkwa, Skeen and Miniette substations required to
meet forecast industrial load growth. The forecast in-service date is fiscal 2021. The cost
responsibility for the Northwest Substations Upgrades Project is dependent on whether a
Liquefied Natural Gas or non-Liquefied Natural Gas industrial project is the driver for the
required upgrades, and will be governed by either Tariff Supplement No. 6 or Order in Council
No. 612.175
107. The determination of which customer is the driver for a System Upgrade is based
on the order in which a customer enters the interconnection process under Tariff Supplement
No. 6. The interconnection process includes customer-specific interconnection studies to
identify the System Upgrades required to serve the specific new load request. The first
customer request in the interconnection process queue to trigger the need for an upgrade is
designated the driver of the upgrade.176
108. If a non-Liquefied Natural Gas industrial project is the driver for the required
upgrades, then Tariff Supplement No. 6 will be applied to the project to determine cost
responsibility between the customer and BC Hydro.177 In this case, the risk of stranded assets is
173
Exhibit B-14, BCUC IR 2.264.3. 174
Exhibit B-6. 175
Exhibit B-9, BCUC IR 1.105.1. 176
Exhibit B-15, BCOAPO IR 2.85.2 177
Exhibit B-9, BCUC IR 1.105.1.
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managed through the Tariff Supplement No. 6 cost allocation/security provisions. These
provisions require the customer to pay the full cost of the interconnection facilities and provide
security for the full cost of the System Reinforcements triggered by the addition of the
customer’s new load. Once the new load is in service, a portion of the security is released
annually based on the security release formula in Tariff Supplement No. 6.178
109. If a Liquefied Natural Gas project is the driver for the project, then Order in
Council No. 612 determines how system reinforcements costs associated with Liquefied Natural
Gas projects are treated. Order in Council No. 612 requires that Liquefied Natural Gas
customers being served at voltages of 60 kV or higher are responsible to “pay for full cost of
interconnecting with the authority’s transmission system and any system upgrades identified by
the authority as required to service the customer.”179
110. As of September 30, 2016, the Northwest Substation Upgrades Project is in the
Definition Phase. Based on the current planning assumption, this Project may meet the
expenditure threshold in BC Hydro’s Capital Project Filing Guidelines. As the Project progresses
and the costs are further defined, BC Hydro will confirm if the Project meets the threshold.180
(g) Peace Region to Kelly Lake 500kV Transmission Reinforcement
111. The Peace Region to Kelly Lake 500 kV Transmission Reinforcement Project is described
on line 17 of page 3 of Supplemental Appendix I-A181 and page 54 of Appendix J of the
Application. This project will increase the Peace Region to Kelly Lake 500 kV transmission
system transfer capacity to facilitate transmission of available generation from the Peace
Region to the load centers in the Lower Mainland and Vancouver Island regions. The project is
a System Plan Network Upgrade, for the benefits of all users of the transmission system. The
Project is still in the Identification Phase and not forecast to start construction in the test
178
Exhibit B-9, BCUC IR 1.105.1.1. See also Exhibit B-15, BCOAPO IR 2.85.1. 179
Exhibit B-9, BCUC IR 1.105.1 and BCUC IR 1.105.1.1. See also Exhibit B-15, BCOAPO IR 2.85.1. 180
Exhibit B-9, BCUC IR 1.105.4. 181
Exhibit B-6.
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period.182 Based on the planning allowance and current Capital Filing Guidelines, BC Hydro will
likely apply for a CPCN for the project.
System Plan Network Upgrades for the General Benefit of All Users of the Transmission System
112. The Peace Region to Kelly Lake 500 kV Transmission Reinforcement Project is
needed as additional generation in the Peace Region, including the Site C Clean Energy Project
and IPPs, will require increased transfer capability (i) of the Peace Region to Williston section to
supply the growing system load south of the Peace region and (ii) of the Williston to Kelly Lake
section to supply the growing load in the Lower Mainland.183 The existing power transfer peak
demand on the Peace Region to Kelly Lake 500 kV transmission system is approximately 95 per
cent of the transfer capacity; approximately 200 MW of transmission capacity is available for
future use. As a result, the Peace Region to Kelly Lake 500 kV transmission system will not be
able to transfer all the power generated by the Site C Clean Energy Project (1100 MW).184 Nor
would it be able to transfer all of the power generation from BC Hydro’s most recent
assessment of future Peace Region IPPs from the February 2016 Base Resource Plan, with a
total maximum power output of 1063.4 MW.185
113. The Peace Region to Kelly Lake 500 kV Transmission Reinforcement Project is for
the general benefit of all users of the Transmission System and is therefore defined as System
Plan Network Upgrades according to BC Hydro’s Open Access Transmission Tariff – Attachment
O.186 This is in contrast to the specific Interconnection Network Upgrades necessary to connect
the Site C Clean Energy Project, which are included in the Site C Clean Energy Project.187
182
Exhibit B-9, BCUC IR 1.106.1. 183
Exhibit B-1-1, Appendix J, p. 54. 184
Exhibit B-9, BCUC IR 1.106.2. 185
Exhibit B-9, BCUC IR 1.106.3. 186
Exhibit B-9, BCUC IR 1.106.2. 187
Exhibit B-9, BCUC IR 1.106.2.
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Still in Early Stages, but a CPCN Application is Likely
114. As of September 30, 2016, the Project is still in the Identification Phase which
means that the Project is not sufficiently advanced to have a preferred alternative and there is
insufficient information on the scope to establish a full project schedule. The capital
expenditures presented in Supplemental Appendix I-A are planning allowances only. The
Project is not expected to start construction in the test period, and there are minimal
expenditures and no capital additions forecast over the test period.188
115. As the project progresses and an Authorized Amount is established, BC Hydro
will confirm if the project meets the thresholds under the Capital Project Filing Guidelines.189
Assuming that the Authorized Amount exceeds the transmission project threshold in the Capital
Project Filing Guidelines in effect at the time, BC Hydro would file the Peace Region to Kelly
Lake 500 kV Transmission Reinforcement Project as a CPCN application.190
(h) Big Bend Substation
116. The Big Bend Substation Project is described on line 29 of page 3 of
Supplemental Appendix I-A191 and page 57 of Appendix J of the Application. This project
involves construction of a new 60/12 kV, 67 MVA substation in the Big Bend area of South
Burnaby to address the load growth of the area. The project will also reconfigure the 60 kV
supply to Annacis Island Substation.192 The Big Bend Substation Project has experienced cost
increases and delays due to factors including higher than anticipated market prices for
equipment and materials, higher than estimated costs for soil stabilization works as a result of
worse than expected ground conditions, and higher costs due to worse than expected
geotechnical conditions.193 The history of this project is outlined below. Although cost
188
Exhibit B-9, BCUC IR 1.106.1. 189
Exhibit B-9, BCUC IR 1.106.5. 190
Exhibit B-9, BCUC IR 1.106.6 and 1.106.7. 191
Exhibit B-6. 192
Exhibit B-1-1, Appendix J, p. 57. 193
Exhibit B-9, BCUC IR 1.108.1 and Exhibit B-14, BCUC IR 2.265.1, including attachments.
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increases have been experienced, the increased costs are required to complete the project and
the project remains in the public interest.
117. BC Hydro’s Fiscal 2012-Fiscal 2014 Amended Revenue Requirements Application
included a planning allowance of $33 million for the Big Bend Substation Project.194 As
described in BCUC IR 1.84.2 Attachment 1, a planning allowance is not a formal cost estimate,
as a preferred alternative has not been selected, and the scope, schedule and cost have not
been defined.195
118. The first cost estimate for the Implementation Phase for the full scope of the
project led to an Authorized Amount of $56.4 million approved in fiscal 2014.196 The
Investment Justification supporting this approval is included as BCUC IR 2.265.1 Attachment
3.197
119. During the Implementation Phase of the Project, as the detailed design was
completed and equipment and site preparation contracts were awarded, the Authorized
Amount increased to $67 million in fiscal 2016. This increase was due to higher than
anticipated market prices for equipment and materials and higher than estimated costs for soil
stabilization works as a result of worse than expected ground conditions.198 The Business
Justification for this revision to the Authorized Amount is included as BCUC IR 2.265.1
Attachment 2, which includes a more detailed description of the reasons for cost increases on
the Project. As detailed in the Business Justification, BC Hydro concluded that alternatives to
proceeding with the project were unacceptable. The consequences of delaying or cancelling
the project would be: inability to mitigate reliability risk for existing customers; no additional
substation capacity to meet load growth; and significant reliability, safety and financial risks.199
194
Exhibit B-9, BCUC IR 1.108.1. 195
Exhibit B-9, BCUC IR 1.84.2 Attachment 1. 196
Exhibit B-9, BCUC IR 1.108.1. 197
Exhibit B-14, BCUC IR 2.265.1 Attachment 3. 198
Exhibit B-9, BCUC IR 1.108.1. 199
Exhibit B-14, BCUC IR 2.265.1 Attachment 2, p. 6.
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120. In August 2016, the Authorized Amount increased to $72.1 million with no
change to the forecast in-service date. This cost increase was due to worse than anticipated
geotechnical conditions in portions of the site, such as boulders below 5 metres, higher pH
value of soil spoils, and additional disposal costs as a result of the larger volume of soil spoils.200
The Business Justification for this increase is included as BCUC IR 2.265.1 Attachment 1. BC
Hydro again reviewed alternatives and concluded that alternatives to proceeding with the
project were unacceptable.201
121. While the project has experienced cost increases outlined above, the increased
costs are required to complete the project (e.g. to address geotechnical conditions). The need
for the project has not changed and BC Hydro’s proceeding with the project is reasonable and
in the public interest.
H. TRANSMISSION – SUSTAINING CAPITAL
(a) Terrace to Kitimat Transmission
122. The Terrace to Kitimat Transmission Project is described on line 41 of page 3 of
Supplemental Appendix I-A202 and on page 67 of Appendix J. The project will replace the 59 km
transmission line 2L99 between Skeena Substation and Minette substation and the 2.5 km
transmission line 2L103 between Minette Substation and the Rio Tinto Alcan owned Kitimat
substation. The work on transmission line 2L99 is exempt from regulation by the Commission
pursuant to the Transmission Upgrade Exemption Regulation.203 The work on transmission line
2L103 is estimated to cost below $10 million, and included in the project for efficiency reasons.
123. The Transmission Upgrade Exemption Regulation includes the replacement of
the 59 km of transmission line 2L99 between Skeena and Minette Substations, but not the
replacement of the 2.5 km transmission line 2L103 between Minette Substation and the Rio
200
Exhibit B-9, BCUC IR 1.108.1, Exhibit B-14, BCUC IR 2.265.1 Attachments 1, 2 and 3 contain the business cases for this project.
201 Exhibit B-14, BCUC IR 2.265.1 Attachment 1.
202 Exhibit B-6.
203 B.C. Reg. 140/2013. Online at: http://www.bclaws.ca/civix/document/id/lc/statreg/140_2013
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Tinto Alcan owned substation. As such, the 2.5 km 2L103 transmission line replacement
component of the project is subject to Part 3 of the Utilities Commission Act.204 The prorated
(based on length of transmission line) cost estimate range for the non-exempt portion of the
Terrace to Kitimat Transmission project is $8.4 million to $4.8 million.205
124. BC Hydro has combined the two projects for efficiency purposes. The 2.5 km
transmission line 2L103 is a key radial line that is critical to support the North Coast system.
2L103 was constructed at the same time and to the same design as 2L99, and as such has the
same issues that are driving the replacement of 2L99. BC Hydro believes it is beneficial from a
project implementation perspective to bundle both replacements under a single project. 206
(b) Mainwaring Substation Upgrade
125. The Mainwaring Substation Upgrade Project is described on line 43 of page 3 of
Supplemental Appendix I-A207 and page 69 of Appendix J of the Application. This project will
replace the power transformers T1 and T3, the two 12 kV feeder sections and the control
building that have reached end of life at Mainwaring Substation. This project is required and in
the public interest.
126. The issues being addressed by the Mainwaring Substation Upgrade Project are
described in Appendix J as follows:208
Mainwaring Substation T1 and T3, two feeder sections and the control building have reached end of life, resulting in an increased reliability and safety risk. The electrical equipment in the two feeder sections (e.g., bulk oil breakers and disconnect switches) is in poor condition, and failures may cause safety hazards and long outages to a number of heavily loaded feeders. The design of the feeder sections is also obsolete, with Limits of Approach safety issue. Maintenance activities can no longer be performed safely without customer outages. The safety issue also prevents overhauling the existing equipment.
204
Exhibit B-9, BCUC IR 1.109.1. 205
Exhibit B-14, BCUC IR 2.266.1. 206
Exhibit B-9, BCUC IR 1.109.1. 207
Exhibit B-6. 208
Exhibit B-1-1, Appendix J, p. 69.
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127. Studies and reports supporting the need for the Mainwaring Substation Upgrade
Project are included in BC Hydro’s response to BCUC IR 2.267.1, including the Asset Plan for the
Mainwaring Substation, Asset Strategies for power transformers and circuit breakers, and the
2016 Mainwaring Substation Load Forecast.209 The Mainwaring Substation Asset Plan provides
asset health assessments for the T1 and T3 transformers, the 50/60 and 70/80 feeder sections,
and the control building to be replaced by the Mainwaring Substation Upgrade project.210 The
Mainwaring Substation Upgrade Project follows the recommendations in the Asset Plan.
128. The Mainwaring Substation Upgrade Project is currently in the Identification
Phase. Based on the planning allowance for this project of $92.9 million as of September 30,
2016, this project does not meet the thresholds in BC Hydro’s Capital Filing Guidelines.
However, as the project progresses to the Definition Phase and a preferred alternative is
identified, BC Hydro will assess whether a section 44.2 or CPCN application is required for the
project according to the Capital Filing Guidelines.211
I. Distribution – Distribution Automation
129. BC Hydro’s Transmission and Distribution group plans to spend a total of
approximately $125 million over the test period to address customer reliability, not related to
end-of-life replacements.212 Approximately $64 million of these expenditures is for the
installation of distribution automation devices, with the annual level of expenditures not
anticipated to exceed $22 million.213 The installation of distribution automation devices is part
209
Attachments 1, 2 and 3 to Exhibit B-14, BCUC IR 2.267.1. 210
Exhibit B-4, BCUC IR 2.267.1 Attachment 1, pages 7, 10 to 14, 16 to 20, 32 to 33, and 36. 211
Exhibit B-9, BCUC IR 1.110.3. 212
Exhibit B-1-1, Application, pp. 6-30. BC Hydro’s planned annual spending in this area is presented in response to BCUC IR 1.77.4 and broken down into categories of expenditures in response to BCUC IR 1.77.2 (Exhibit B-9).
213 Exhibit B-14, BCUC IR 2.257.1 and 2.257.2. Distribution automation expenditures are committed on an annual basis, based on a review of results and the prioritization of annual Distribution sustaining budgets. As the annual amounts have not exceeded $50 million, they have not required Board approval and have not met the thresholds in the Capital Filing Guidelines.
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of BC Hydro’s long term plan to design and build a more advanced grid,214 and will reduce
customer outages and provide other benefits such as increased power quality.215
130. The distribution automation capital expenditures in fiscal 2017 to fiscal 2019 will
focus on automation of reclosing and switching devices.216 The automation of distribution
devices provides operating personnel with remote visibility of system parameters and system
status, facilitates remote operability, and enables greater flexibility to efficiently operate the
system.217
131. The majority of benefits from these investments will be a reduction in
distribution system trouble events that result in customer outages and associated customer
hours lost. By providing remote switching capability by the Control Centre, distribution
automation on the overhead system eliminates 80 to 90 per cent of trouble calls on the
affected portions of the targeted circuits,218 and allows for faster customer restoration for the
remaining trouble events.219 BC Hydro projects that the forecast expenditures for the
deployment of automated reclosers alone will result in 77,000 fewer Customer Interruptions.220
132. Investments in distribution automation have proven to be effective:
BC Hydro has analyzed the effectiveness of past spending on Distribution automation. The analysis of 363 reclosers installed on 225 feeders that have a full calendar year of data demonstrated that the installed reclosers eliminated 88 per cent of the troubles on those feeders, thereby eliminating over 430,000 Customer Interruptions. The reclosers also allowed faster customer restoration for the remaining 12 per cent of the troubles.221
214
Exhibit B-1-1, Application, p. 5-60. 215
Exhibit B-9, BCUC IR 1.77.2; Exhibit B-14, BCUC IR 2.257.5. 216
Exhibit B-9, BCUC IR 1.77.2. 217
Exhibit B-9, BCUC IR 1.77.2. 218
Exhibit B-9, BCUC IR 1.77.3. 219
Exhibit B-14, BCUC IR 2.257.4. 220
Exhibit B-14, BCUC IR 2.257.5. 221
Exhibit B-14, BCUC IR 2.257.4.
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133. These customer reliability benefits are embedded in the SAIFI and SAIDI
reliability metrics.222
134. In addition to the reliability benefits that can be achieved, other benefits of
distribution automation include enabling remote operation, faster de-energization in the event
of unintended contact, increased visibility for theft detection, and improved power quality with
voltage and VAR control.223
135. In summary, BC Hydro’s planned investments in distribution automation are in
the public interest as they will increase customer reliability and provide other benefits.
J. TECHNOLOGY
(a) Supply Chain Applications Project
136. The Supply Chain Applications Project is described on line 2 of page 5 of
Supplemental Appendix I-A224 and page 75 of Appendix J of the Application, and in a number of
information requests related to the project.225 BC Hydro filed the Supply Chain Applications
Project Application on December 21, 2016, requesting acceptance of capital expenditures for
the Supply Chain Applications Project under section 44.2 of the Utilities Commission Act.226 As
this project is currently before the Commission in a separate proceeding, BC Hydro submits that
the Commission should delay consideration of the project to that proceeding. If the
expenditures on the project are not accepted by the Commission and BC Hydro were not to
proceed with the project, any differences between forecast and actual amortization of capital
additions on the project will be recorded in the Amortization of Capital Additions Regulatory
Account.
222
Exhibit B-14, BCUC IR 2.257.4. See BC Hydro’s response to BCUC IR 1.77.3 for reliability metrics. 223
Exhibit B-9, BCUC IR 1.77.2. 224
Exhibit B-6. 225
E.g., Exhibit B-10, CEC IR 1.117.3. 226
Exhibit B-15, CEC IR 2.165.4.
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(b) Technology Projects Driven By North American Electric Reliability Corporation Critical Infrastructure Protection Version 5
137. There are multiple components to BC Hydro’s North American Electric Reliability
Corporation (“NERC”) Critical Infrastructure Protection Version 5 work, including compliance
requirements for the Transmission & Distribution assets, Grid Operation Control Centers and
Generation assets. The investments for these various components of the Critical Infrastructure
Protection Version 5 work are included in the respective capital forecast of the groups
responsible for planning the work.227 This work is designed to ensure BC Hydro’s conformance
with Commission mandated guidelines for the protection of critical cyber infrastructure, and is
in the public interest.
138. Compliance with Critical Infrastructure Protection Version 5 standards affects a
range of BC Hydro’s assets. As explained in response to BCUC IR 2.268.1, an initial collaborative
analysis of the Critical Infrastructure Protection Version 5 standards identified a requirement to
implement electronic and physical security protection at 7 “high impact” Control Centres
(including associated Data Concentration Point facilities), 3 “medium impact” Generation
facilities and 46 “medium impact” substations.
139. BC Hydro provided the following breakdown of the NERC Critical Infrastructure
Protection Version 5 work for the test period:
($ thousands) F2017 F2018 F2019 Total
Generation Capital Expenditures 1,100 750 350 2,200
Capital Additions 2,200 2,200
Transmission and Distribution
Stations Capital Expenditures 2,400 14,700 7,700 24,800
Capital Additions 1,900 12,220 9,100 23,220
Grid Operations
Capital Expenditures 300 900 200 1,400
Capital Additions 1,400 1,400
Technology Capital Expenditures 1,000 1,000 900 2,900
Capital Additions 1,000 1,000 900 2,900
227
Exhibit B-9, BCUC IR 1.111.1. A breakdown for the NERC Critical Infrastructure Protection (CIP) v5 work for the test period was provided in Exhibit B-14, BCUC IR 2.268.1.
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140. These expenditures are to identify, design, and make needed modifications to:
Generation, Stations, and Grid Operations facilities, and associated maintenance standards and
operating procedures; and Technology owned existing systems.228 This work is designed to
ensure BC Hydro’s conformance with NERC Critical Infrastructure Protection Version 5,
including by providing a network and management system to support the development and
sustainability of the program and standards, the adaption of procedural and engineering
changes through change management programs, and the verification and certification of labour
resources.229
141. The Transmission & Distribution and Technology components of Critical
Infrastructure Protection Version 5 compliance is reflected in two projects listed in
Supplemental Appendix I-A. These projects are:
The NERC CIP v5 Compliance at Medium Impact Transmission and Distribution
Stations Project is listed on page 4, line 47 of Supplemental Appendix I-A,230 and
described in Appendix J, page 73. It is also noted on page 6-90 of the
Application. The project will upgrade electronic and physical security for critical
cyber assets at up to 43 medium impact Bulk Electric System stations.231 This
project reflects the compliance requirements for the Transmission & Distribution
assets.
The NERC CIP v5 Project is described on line 11 of page 5 of Supplemental
Appendix I-A.232 This project will address the general technology scope and
overall revisions to common cross-business Critical Infrastructure Protection
programs, policies and procedures. The technology project scope will also
include common technology tools that will be utilized across the business
228
Exhibit B-14, BCUC IR 2.268.1. 229
Exhibit B-14, BCUC IR 2.268.1. 230
Exhibit B-6. 231
Exhibit B-1-1, Appendix J, p. 73. 232
Exhibit B-6.
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groups. 233 This project reflects the compliance requirements addressed by the
Technology group.
142. Other small projects less than $5 million which are driven by mandatory
reliability standards are listed and described in response to BCUC IR 1.111.3. This includes
projects to address compliance at Generating Stations and Control Centres.234
143. BC Hydro’s capital expenditures for compliance with mandatory reliability
standards are necessary and in the public interest.
(c) Enterprise Billing Infrastructure Project
144. The Enterprise Billing Infrastructure Project is described on line 3, page 5 of
Supplemental Appendix I-A.235 The scope of this Enterprise Billing Infrastructure Project
includes two major components: enhancements to the residential and general service customer
bills (paper, online and call centre view); and necessary upgrades to the bill generating and
delivery infrastructure, including three major component system upgrades. 236 The Project
cannot be delayed without significant negative impacts.
145. The Project is intended to deliver the following outcomes and capabilities for BC
Hydro:237
A modern, stable bill generation architecture that provides greater assurance of
required service levels, and is more agile and flexible in support of anticipated
future bill content and design needs. Examples of anticipated future needs are
new rate types and services, electronic billing growth, additional billing features,
and improved services;
233
Exhibit B-1-1, Appendix J, p. 73, Additional Notes; Exhibit B-9, BCUC IR 1.111.1. 234
Exhibit B-9, BCUC IR 1.111.3 and Exhibit B-14, BCUC IR 2.268.1. 235
Exhibit B-6. 236
Exhibit B-9, BCUC IR 1.114.4. 237
Exhibit B-9, BCUC IR 1.114.4. See also, Exhibit B-10, CEC IR 1.116.4.
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A new and upgraded BC Hydro residential/general service customer bill,
discontinuing the existing bill which is no longer fulfilling customer needs; and
New billing capabilities such as improved bill formats, interactive digital
statements, an electronic version of collective invoices, and presentment of data
from systems other than SAP when available.
146. The Enterprise Billing Infrastructure Project could not be delaying without
significant negative impacts, including:238
Increased risk of bill production failure (the current technology foundation used
to generate bills is increasingly unreliable and has inadequate vendor support);
Increased costs for extended support for end-of-life infrastructure; and
Lack of capacity to meet the increasing demand for electronic billing (the existing
infrastructure will not scale to support the anticipated growth in electronic
billing).
147. The Enterprise Billing Infrastructure Project should therefore proceed as
planned.
148. The Project is now in Definition Phase and the total cost of the Enterprise Billing
Infrastructure Project is estimated to be approximately $18.2 million.239 Based on the current
capital cost estimate, a section 44.2 filing is not required. As the project proceeds and the
capital cost estimate is further refined, a determination will be made as to the requirement for
a section 44.2 filing, in accordance with the Guidelines. 240
238
Exhibit B-15, CEC IR 2.166.1. 239
Exhibit B-14, BCUC IR 2.269.2. 240
Exhibit B-9, BCUC IR 1.114.6.
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(d) Graphic Work Design Tool Project
149. The Graphic Work Design Tool Project is described on line 4, page 5 of
Supplemental Appendix I-A,241 but was subsequently cancelled by BC Hydro. BC Hydro is not
reducing its Technology capital forecast in the Application.242 No adjustment to BC Hydro
forecast Technology capita plan is required as BC Hydro has already made reductions on a
forecast basis for unplanned changes, and BC Hydro will manage its Technology capital budget
using the prioritization process described in section 6.3.7.4 of the Application.
150. The scope of the Graphic Work Design Tool project was to replace the current,
custom-developed Distribution and Analysis Design software solution, with a commercial
graphical software product tailored to the utility sector and configured for BC Hydro. The
Project was cancelled in October 2016 due to increased implementation risk and erosion of net
benefit.243 The total authorized funding for the Project was $6.1 million, and the total
estimated capital cost of the Project was $15 million.244
151. After the Graphic Work Design Tool Project was cancelled in October 2016, it
was removed from the information technology capital plan and the capital budget allocation for
the project was made available for other waitlisted technology investment priorities.245
However, BC Hydro is not reducing its Technology capital forecast in the Application.246
152. As discussed in section 6.3.7.4 of the Application, annual Technology capital
plans and actual expenditures are dynamic and are expected to differ from that presented in
the revenue requirements application for a number of reasons, such as emerging and changing
IT priorities; changes to program or project scope, schedule or cost; unplanned outages or
241
Exhibit B-6. 242
Exhibit B-14, BCUC IR 2.269.1. 243
Exhibit B-9, BCUC IR 1.114.4. 244
Exhibit B-10, CEC IR 1.114.1. 245
Exhibit B-15, BCUC IR 2.269.1. The technology capital planning process and the prioritization of investments is described in detail in the Application in section 6.3.7.4.
246 Exhibit B-14, BCUC IR 2.269.1.
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increased technology risks; or unexpected loss of vendor support for products or services. The
cancellation of the Graphic Work Design Tool Project is an example of such a change.
153. BC Hydro has managed changes to its Technology capital plan in two ways:
First, BC Hydro has made allowance for changes to its Technology capital plan by
adjusting its forecast expenditures downwards by 16 per cent in fiscal 2017 and
10 per cent in fiscal 2018. As BC Hydro has already made reductions to its
Technology capital plan, no further reduction should be made due to the
cancellation of the Graphic Work Design Tool Project.247
Second, to help manage emerging priorities, the Technology Group maintains a
waitlist of proposed investments. As discussed in the Application, BC Hydro uses
a capital portfolio management prioritization tool, which assesses and ranks
projects with respect to benefits, costs and risks.248 Capital and other resources
can be re-allocated to the next highest ranked projects as resources become
available. Monthly capital meetings are used to gauge program expenditures
relative to plan, and prioritize the re-allocation of available resources to existing
or waitlisted investments. The re-allocation seeks to optimize the use of
resources within the portfolio.249
154. BC Hydro’s forecast Technology capital expenditures should therefore not be
reduced due to the cancellation of the Graphic Work Design Tool Project. Any such reduction
would duplicate reductions BC Hydro has already made to its plan. Due to the dynamic nature
of the Technology capital portfolio, it is expected that there will be changes. BC Hydro should
continue to use its capital planning tools to proceed with the highest ranked projects in its
waitlist of proposed investments in accordance with its planning process.
247
Exhibit B-1-1, Application, p. 6-46. 248
Exhibit B-1-1, Application, p. 6-44. 249
Exhibit B-1-1, Application, p. 6-46.
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(e) Data Centre Refresh Project
155. The Data Centre Refresh Project is described at pages 6-111 and 6-112 of the
Application and is required in order to reduce reliability risk. The total cost of the Data Centre
Refresh Project is $6.4 million, of which $2.3 million is forecast during the test period.250 The
Data Centre Refresh Project will facilitate the refresh of infrastructure in the Kamloops Internet
Data Centre that was purchased in 2013 or earlier, and is generally refreshed every five to
seven years. The primary benefit of the Project is a reduction of information technology system
reliability risk. As the information technology assets in the data centre age, they become more
prone to failures that cause unplanned outages to business information systems.251
(f) Sustainment of Smart Metering and Infrastructure Program Assets
156. While the Smart Metering and Infrastructure Program was completed in fiscal
2016, ongoing capital expenditures are required to sustain the assets installed under the
Program.252
157. The capital expenditures planned in the test period to implement and sustain the
smart metering application platforms are reported in Table 6-25, page 6- 119, and in Table 6-
19, page 6-107 of the Application. A summary of the planned projects and the associated
capital expenditures to implement and sustain the Smart Metering enterprise-class application
platform is provided in BC Hydro’s response to BCUC IR 1.115.3. Capital additions over the test
period are approximately $2.8 million.253
158. The capital expenditures and additions required for ongoing sustainment of the
Smart Metering and Infrastructure Program are reported in the infrastructure,
telecommunications and applications line items in Tables 6-19 and 6-20 of the Application,
under the Technology Key Business Unit. Capital additions over the test period are
250
Exhibit B-10, CEC IR 1.119.1. 251
Exhibit B-10, CEC IR 1.119.2. 252
Exhibit B-9, BCUC IR 1.115.1. See also Exhibit B-15, BCOAPO IRs. 2.87.2 and 2.87.3 for further details of the capital additions.
253 Exhibit B-9, BCUC IR 1.115.3.
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approximately $16 million. BC Hydro’s response to BCUC IR 1.115.4 provides a summary of the
work associated with the expenditures.254
159. The expenditures described above are required to sustain the assets installed by
the Smart Metering and Infrastructure Program and are reasonably included in BC Hydro’s test
period revenue requirements.
K. PROPERTIES
(a) Vernon Field Building Project and Victoria Field Building Project
160. The Vernon Field Building Project and the Victoria Field Building Project are listed
on lines 5 and 6 of page 7 of Supplemental Appendix I-A255 and are described on pages 76 to 79
of Appendix J. These projects involve the construction of new facilities at the existing Vernon
Field Building site and Victoria Field Building site to address significant deficiencies and issues
with the existing facilities. The issues being addressed and alternatives considered are discussed
in Appendix J. The Authorized Amounts for the Vernon and Victoria Field Building Project is
$46.3 million and $41.6 million, respectively. Both projects are expected to go into service in
fiscal 2018. Both projects are currently under construction and on budget.256
(b) Chilliwack Field Building Project
161. The Chilliwack Field Building Project is listed on line 15 of page 7 of Supplemental
Appendix I-A257 and is described on pages 84-85 of Appendix J. The project involves the
construction of a new facility at a new site to address significant deficiencies and issues with
the existing facilities. The issues being addressed and the alternatives considered for this
project were described in Appendix J at pages 84-85.258 The cost estimate for the project is
appropriately included in BC Hydro’s test period revenue requirements.
254
Exhibit B-9, BCUC IR 1.115 series. 255
Exhibit B-6. 256
Exhibit B-9, BCUC IR 1.116.1. 257
Exhibit B-6. 258
Exhibit B-9, BCUC IR 1.116.3.
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162. As discussed in more detail in Appendix J, BC Hydro’s existing facilities have been
prioritized for redevelopment due to the combined issues of lack of adequate space for current
and projected business operations; the inability to expand either the Chilliwack facility, as it is
leased, or the Atchelitz location, as it is in close proximity to a substation; their strategic
location in a growing region; as well as the condition and associated seismic concerns of the
existing buildings.259 As clarified in response BCUC IR 1.116.5, the primary investment drivers
for the project related to the Atchelitz Field Building are not its condition, but are primarily
inadequate space and inability to expand. In addition, there is also inadequate fire suppression,
lack of sprinklers, the presence of hazardous materials, limited seismic withstand, and a lack of
an emergency generator.260
163. Construction on the Chilliwack Field Building Project is expected to commence in
late fiscal 2018. The capital expenditures included in Appendix I-A for fiscal 2017 and a portion
of fiscal 2018 for this project relate to Definition Phase activities which include the purchase of
land and the design fees for this project.261
164. The forecast costs are based on the leading alternative for the Chilliwack Field
Building Project, to acquire a new site and construct a new facility. The project cost estimate
for the Chilliwack Field Building Project includes all capital costs that are expected to be
incurred through to completion of the project, including design fees, land acquisition,
construction, project management, interest during construction, furniture & equipment, and
permits & insurance.262 The $29.3 million estimated cost of the Chilliwack Field Building Project
is less than the costs for field building project in Vernon ($46.3 million) and Victoria ($41.6
million) because the Vernon and Victoria Field Building Projects are larger than Chilliwack Field
Building Project, and accommodate more business units, employees, materials, equipment, and
vehicles. 263
259
Exhibit B-1-1, Appendix J, p. 84. 260
Exhibit B-9, BCUC IR 1.116.5. 261
Exhibit B-9, BCUC IR 1.116.2. 262
Exhibit B-9, BCUC IR 1.116.4. 263
Exhibit B-9, BCUC IR 1.116.4.
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(c) Construction Services/Lower Mainland Transmission Building Project and Material Classification Facility Project
165. The Construction Services/Lower Mainland Transmission Building Project is listed
on line and page 80-81 of Appendix J. The Material Classification Facility Project is listed on line
11 of page 7 of Supplemental Appendix I-A,264 and described on pages 82-83 of Appendix J of
the Application. These projects involve construction of new facilities to address significant
deficiencies and issues with the existing facilities. Appendix J discusses the issues to be
addressed and the alternatives considered. The preferred alternative is for the existing
Material Classification Facility and the existing Lower Mainland Transmission facility to swap
locations, which requires the two projects to be coordinated. As the two projects combined
have an Authorized Amount in excess of $50 million, BC Hydro plans to file a Construction
Services/Lower Mainland Transmission Project and the Materials Classification Facility Project
Transmission Project Application under section 44.2 of the Utilities Commission Act in fiscal
2018.
166. A swapping option is the leading alternative for both the Construction
Services/Lower Mainland Transmission Project and the Materials Classification Facility Project.
This alternative addresses the identified building code, environmental, and safety issues, and
provides efficient, functional and flexible facilities. This alternative also avoids the costs to
acquire new property. Of all the development options considered, this alternative also
represents the lowest total cost of ownership for both facilities.265
167. BC Hydro will be coordinating the two projects, not managing them as one
project. BC Hydro would not expect savings or efficiencies by managing both projects as one,
as each project has unique requirements for specialist designers, sub-consultants and
constructors. However, BC Hydro will be seeking purchasing economies of scale and
efficiencies where available. This would include requiring, where appropriate, the designers of
the two projects to seek opportunities to utilize similar systems and materials in each facility
264
Exhibit B-6. 265
Exhibit B-9, BCUC IR 1.117.2; see also Exhibit B-10, BCOAPO IR 1.64.5.
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and the Construction Managers to coordinate their tendering for common systems and
materials.266
168. BC Hydro has also commenced other projects on the BC Hydro Surrey Campus,
including the Materials Management Facility Project and the Fleet Facility project. These are
unique and independent projects that will be managed separately.267 However, as with the
other Surrey campus projects, BC Hydro will seek purchasing economies of scale and
efficiencies with other Surrey Campus projects where feasible, including utilizing similar
systems and materials and coordinating tendering for common systems and materials.268
L. OTHER CAPITAL
(a) Fleet/Vehicles/Materials Management
169. Cost estimates for Fleet capital expenditures and additions are described on
pages 6-118 and 6-119 of the Application and the cost estimate for capital expenditures is also
provided on line 8 of page 7 of Supplement Appendix I-A.269 Fleet capital additions are
expected to increase during fiscal 2017 to fiscal 2019 from the levels in fiscal 2015 and fiscal
2016 due to requirements to support field safety and productivity, improve response times
during trouble calls and increased work associated with delivering on the capital plan.270
170. BC Hydro follows fleet industry principles and practices, and also supplements
external guiding documents with internal ones.271 BC Hydro’s goal is to keep its vehicles in
good condition to meet safety and operational requirements throughout the vehicle’s life. BC
Hydro does not assess condition ratings for every vehicle in the fleet as it would not be cost-
effective and would be labor intensive. However, BC Hydro undertakes condition assessment
266
Exhibit B-9, BCUC IR 1.117.3. 267
Exhibit B-9, BCUC IR 1.117.1 and Exhibit B-14, BCUC IR 2.271.1. The existing Surrey Campus plan and the proposed Surrey Campus plan are included in the attachment to BCUC IR 2.71.2.
268 Exhibit B-14, BCUC IR 2.271.1.
269 Exhibit B-6.
270 Exhibit B-9, BCUC IR 1.118.2.
271 Exhibit B-9, BCUC IR 1.118.9.
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on the higher value vehicles and vehicles nearing their end-of-life when additional information
is required for retirement or investment decisions.272 BC Hydro’s vehicle replacement policy is
similar to that of FortisBC. Both companies take many factors into consideration when an
actual vehicle replacement decision is made. Factors such as suitability to meet current and
future business requirements, ability to maintain adequate safety, age, condition, and
compliance with regulations, are reviewed when vehicles are near the end of their planned
service life. Each replacement decision is evaluated on a unit-by-unit basis.273
M. SMALL PROJECTS (LESS THAN $5 MILLION)
(a) Generation
171. Tables showing capital additions for Generation projects less than $5 million or
in-service for the period fiscal 2015 to fiscal 2019 were provided in BC Hydro’s response to
BCUC IR 1.95.3. An increase in small capital expenditures over time for sustaining projects is
expected as equipment ages. Trends in respect of dam safety projects are influenced by when
assets are placed into service.274
172. The capital addition forecasts for these projects (i.e., projects less than $5
million) are developed in the same way as projects with a capital addition forecast of greater
than $5 million. The Project and Portfolio Management lifecycle is scalable, and can be used for
projects of different size and complexity. 275
(b) Transmission
173. A table summarizing capital additions for projects less than $5 million for
Transmission Growth and Sustaining for the fiscal 2015 to fiscal 2019 period was provided in BC
Hydro’s response to BCUC IR 1.112.3. The trend for additions for Transmission Growth projects
less than $5 million is mainly driven by the timing of Generator Interconnection and Customer
272
Exhibit B-9, BCUC IR 1.118.5. 273
Exhibit B-9, BCUC IR 1.118.10. See also Exhibit B-14, BCUC IR 2.272.1. 274
Exhibit B-9, BCUC IR 1.95.3. 275
Exhibit B-9, BCUC IR 1.95.2.
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Driven Requested projects. In fiscal 2017 there are a number of Transmission Load
Interconnection projects forecast to be placed in-service, resulting in a larger forecast for this
year as compared to fiscal 2016 and the remainder of the test period. 276 Transmission
Sustaining additions are higher in the fiscal 2016 to fiscal 2019 period compared to fiscal 2015
to address the increasing number of Transmission assets that are at or nearing end of life and
require replacement. 277
174. The Transmission capital addition forecasts for the less than $5 million projects
and programs are developed using either one of two methods:
For projects less than $5 million, additions are forecast on a bottom-up basis,
based on the forecast In-Service Date of individual projects and the forecast
capital expenditures/allowances up to and including the year the projects go into
service. Additions for the capital expenditures in the fiscal years following the
forecast In-Service Date are forecast in the fiscal year they are spent. This is the
same method used to forecast additions for projects greater than $5 million.
Transmission projects less than $5 million make up a relatively small proportion
of the Transmission portfolio and individual calculations for additions can be
reasonably forecast. 278
For programs, additions are forecast as a proportion of the forecast expenditures
for the fiscal year with the remainder forecast in the subsequent fiscal year. The
proportion is an approximation that recognizes that on-going programs will have
work completing into the subsequent fiscal year. 279
276
Exhibit B-9, BCUC IR 1.112.3. 277
Exhibit B-9, BCUC IR 1.112.3. 278
Exhibit B-9, BCUC IR 1.112.2. 279
Exhibit B-9, BCUC IR 1.112.2.
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(c) Distribution
175. A table summarizing the capital additions projects and programs less than $5
million for Distribution for the fiscal 2015 to fiscal 2019 period was provided in BC Hydro’s
response to BCUC IR 1.113.3. The capital additions less than $5 million are for Customer Driven
and System Expansion and Improvement. Annual customer driven growth additions are
increasing from fiscal 2017 to fiscal 2019 based on a 0.5 per cent predicted level of growth in
expenditures, and include a one-time increase in fiscal 2018 for customer meter inventory to
facilitate Measurement Canada meter testing requirements. There are no discernable trends
with respect to System Expansion and Improvement in both growth distribution and sustaining
distribution as year over year fluctuations are the result of the prioritization of work.
176. The Distribution capital addition forecasts for the less than $5 million projects
and programs are developed based on a proportion of the forecast expenditures for the fiscal
year. The proportion is an approximation that recognizes that ongoing programs will have work
completing into the subsequent fiscal year. For a portfolio consisting predominantly of small
projects and programs, estimating capital additions based on annual forecast capital
expenditures provides sufficient forecast accuracy.280 This method is different than the
Transmission capital addition forecast for projects less than $5 million, because Distribution
projects less than $5 million make up a relatively large proportion of the Distribution
portfolio.281
N. CONCLUSION
177. BC Hydro’s capital portfolio was reviewed thoroughly in this proceeding. BC
Hydro filed a significant amount of detailed evidence on projects and programs within the
portfolio. The evidence demonstrates that BC Hydro’s capital projects and programs over the
test period are in the public interest and should be approved by the Commission.
280
Exhibit B-9, BCUC IR 1.113.2. 281
Exhibit B-9, BCUC IR 1.113.2.