british columbia utilities commission british columbia ... · 5/23/2017 · matthew ghikas ....

Matthew Ghikas

Direct 604 631 3191 Facsimile 604 632 3191

[email protected]

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. 1-17.

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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


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, 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.1-16.

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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.1-22. 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.


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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


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, 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. 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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301539.00014/91303997.1

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.



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301539.00014/91303997.1

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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301539.00014/91303997.1

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.


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.



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.


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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.



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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301539.00014/91303997.1

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-15, AMPC IR 2.12.1; AMPC IR 2.13.4; AMPC IR 2.13.5. 94


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301539.00014/91303997.1

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-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.



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; BCOAPO IR 1.19.1. 103


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



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301539.00014/91303997.1

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-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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301539.00014/91303997.1

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-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.

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301539.00014/91303997.1

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-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-1-1, Application, p.3-10 and 3-11. 130


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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-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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301539.00014/91303997.1

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


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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301539.00014/91303997.1

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





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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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301539.00014/91303997.1

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-23 corrected the value provided in Exhibit B-22, CEABC IR 3.46.2 for the Large Industrial sector. 152


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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-14-2, 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-15, CEC IR 2.133.3; Exhibit B-9, BCUC IR 1.5.2. 162


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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




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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). 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.



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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); 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-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-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


CEABC Evidence, p.7. 184

Exhibit B-20, Rebuttal Evidence, p.30. 185


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, 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



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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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301539.00014/91303997.1

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


AMPC Evidence, p.10. 203


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-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-10, BCOAPO IR 1.25.3. Exhibit B-1-1, Application, section 4.2.2. 216



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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.


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-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



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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






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-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 1.14.2 246

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


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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-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




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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


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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


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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.


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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-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-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


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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.



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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


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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-15, NIARG IR 2.9.2. 293


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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-1-4, Application, Appendix P. 297


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.


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





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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 1.32.4.1. 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.





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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-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.


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.


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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





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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, 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.





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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. 5-41. 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.



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.


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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 1.48.5.1.1. 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.



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-1-1, Application, p. 5-66. A more detailed explanation of operating costs was provided in the individual

Key Business Unit descriptions.


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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




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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 1.51.2. 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.


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.



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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. A breakdown of the Business Unit Support costs was provided in Exhibit B-9, BCUC IR 1.56.1.


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-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



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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






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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. See also, Exhibit B-9, BCUC IR 1.61.5. 388




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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 1.40.4. 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.


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




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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



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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-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-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.





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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






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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-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.


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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


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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

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Distrib

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n

Ge

ne

ratio

n

Pro

pe

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s

Te

ch

no

lo

gy

Oth

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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

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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.


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.




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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. 6-11 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. 6-27. 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




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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. 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.



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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 1.64.3; 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. 6-15 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



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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




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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






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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-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-9, BCUC IR 1.76.2. BCUC IR 1.73.6 476


Exhibit B-14, BCUC IR 2.256.1.1. 478


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-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-1-1, Application, pp. 6-16 and 6-17. 486

Exhibit B-15, CEC IR 2.157.1. 487


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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





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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


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; 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.


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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”.


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.


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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.”


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



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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






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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



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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




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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






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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







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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


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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


538 Exhibit B-15, CEC IR 2.158.1.


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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



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



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.


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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


The Amortization of Capital Additions Regulatory Account and the Total Finance Charges Regulatory Account. 549


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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 1.134.3; 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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301539.00014/91303997.1

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-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


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301539.00014/91303997.1

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.


574 Exhibit B-1-1, Application, section 7.5.12; 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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301539.00014/91303997.1

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-9, BCOAPO 1.43.1; Exhibit B-14, BCUC IR 2.294.3.

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301539.00014/91303997.1

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




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301539.00014/91303997.1

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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301539.00014/91303997.1

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).


590 Application, pp.7-15 and 7-16.

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301539.00014/91303997.1

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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301539.00014/91303997.1

(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; Exhibit B-14, BCUC IRs 2.296.3 and 2.296.3.1. 595


Exhibit B-14, BCUC IR 2.296.3.1.

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301539.00014/91303997.1

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


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301539.00014/91303997.1

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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301539.00014/91303997.1

…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-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.


603 Exhibit B-1-1, Application, pp. 7-32- and 7-33, (ii) and (iii).

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301539.00014/91303997.1

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, 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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301539.00014/91303997.1

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. 7-48 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.


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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




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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.


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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.

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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. 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


Industrial

Leaders in Energy Management, Transmission

Thermo-Mechanical Pulp

Leaders in Energy Management, Distribution


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-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-1-1, Application, pp. 10-39 to 10-40 and Appendix V. 656


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


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




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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


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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-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


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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. 10-35. Exhibit B-9, BCUC IR 1.185.1. 674


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.


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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, 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-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-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.



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




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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. 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.


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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).


709 Exhibit B-10, BCSEA IR 1.28.1.


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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-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.


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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





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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


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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


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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


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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.


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, 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.


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-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.



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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-1-1, Application, sections 10.4 and 10.7.4. 744



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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.


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.



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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-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



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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-15, BCSEA IR 2.60.8, Attachment 1. 763



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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


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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.


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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, Appendix V, p. 1. Exhibit B-10, BCSEA IR 1.41.3. 771


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





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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-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





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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-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.

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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.



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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-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





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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


804 Exhibit B-21, BCUC IR 3.339.2.2 and Exhibit B-22, BCSEA IR 3.66.1


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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-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



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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.



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




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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-20, p. 10. 823

Exhibit B-14, BCUC IR 2.319.2.1. 824




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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







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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-20, Rebuttal Evidence, p. 10; Exhibit B-21, BCUC IR 3.339.2. 835





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







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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


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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-14, CEC IR 1.104.2. 850


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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-14, BCUC IR 2.318.1.1. 854


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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.


859 Exhibit B-14, BCUC IR 2.319.2.1 Attachment 1, p. 4.


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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


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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-10

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301539.00014/91303997.1

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.



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-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.”




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-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


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-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-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. 909




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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


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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-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-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





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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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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-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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301539.00014/91303997.1

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-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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301539.00014/91303997.1

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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301539.00014/91303997.1

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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301539.00014/91303997.1

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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301539.00014/91305014.2

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.



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301539.00014/91305014.2

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,


6 Exhibit B-9, BCUC IR 1.81.4 and 1.81.5.



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301539.00014/91305014.2

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


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




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301539.00014/91305014.2

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 1.85.3, 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-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-1-1, Appendix J, p. 13.

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301539.00014/91305014.2

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-6, Supplemental Appendix I-A - Generation, page 1, line 13. 31




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301539.00014/91305014.2

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.


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301539.00014/91305014.2

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






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301539.00014/91305014.2

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








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301539.00014/91305014.2

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. The Facility Asset Plan for Bridge River was provided as an attachment to BCUC IR 1.88.6



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301539.00014/91305014.2

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




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301539.00014/91305014.2

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





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301539.00014/91305014.2

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



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301539.00014/91305014.2

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


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.


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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301539.00014/91305014.2

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-6.

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301539.00014/91305014.2

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



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301539.00014/91305014.2

(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.



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




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301539.00014/91305014.2

(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


purpose of this project is to overhaul Units 1 to 3 turbines in order to provide continued reliable

service.87



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-9, BCUC IR 1.93.1, 1.93.4, 1.93.4.1.

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301539.00014/91305014.2

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-6.

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301539.00014/91305014.2

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-15, BCOAPO IR 2.86.1.

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301539.00014/91305014.2

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 1.74.2. 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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301539.00014/91305014.2

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.


109 Exhibit B-9, BCUC IR 1.74.3 and Exhibit B-14, BCUC IR 2.233.2.

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301539.00014/91305014.2

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 1.94.2 and BCUC IR 1.94.5. 113

Application, p. 6-79. 114


Exhibit B-10, Landale IR 1.4.1. 116

Exhibit B-6.

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301539.00014/91305014.2

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-1-1, Application, Appendix J, p. 40. 120

Exhibit B-1-1, Application, Appendix J, page 40.

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301539.00014/91305014.2

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 1.66.1 Attachment 1, Capital Project Filing Guidelines, p. 1.

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301539.00014/91305014.2

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-6. 128



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301539.00014/91305014.2

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-6. 132

Exhibit B-6. 133


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301539.00014/91305014.2

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-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.



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301539.00014/91305014.2

(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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301539.00014/91305014.2

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


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301539.00014/91305014.2

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


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.)





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301539.00014/91305014.2

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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301539.00014/91305014.2

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 1.17.6; Exhibit B-15, AMPC IR 2.20.1.

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301539.00014/91305014.2

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.

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301539.00014/91305014.2

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-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.



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301539.00014/91305014.2

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-2, Evidentiary Update. 167



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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301539.00014/91305014.2

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




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301539.00014/91305014.2

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-6. 175


Exhibit B-15, BCOAPO IR 2.85.2 177


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301539.00014/91305014.2

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-6.

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301539.00014/91305014.2

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







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301539.00014/91305014.2

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-6. 192


Exhibit B-9, BCUC IR 1.108.1 and Exhibit B-14, BCUC IR 2.265.1, including attachments.

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301539.00014/91305014.2

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 1.84.2 Attachment 1. 196


Exhibit B-14, BCUC IR 2.265.1 Attachment 3. 198


Exhibit B-14, BCUC IR 2.265.1 Attachment 2, p. 6.

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301539.00014/91305014.2

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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301539.00014/91305014.2

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-6. 208


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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-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









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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-6. 225

E.g., Exhibit B-10, CEC IR 1.117.3. 226


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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-6. 231


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-6. 236


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



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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-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.


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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




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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.


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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-6. 258


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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






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301539.00014/91305014.2

(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 1.117.1 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.


269 Exhibit B-6.



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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 1.118.10. See also Exhibit B-14, BCUC IR 2.272.1. 274



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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





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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

